Report endorses clean-energy economy for Midwest

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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California Rolling Blackouts expose grid reliability risks amid a heatwave, as CAISO curtails power while solar output fades at sunset, wind stalls, and scarce natural gas and nuclear capacity plus PG&E issues strain imports.

Key Points

Grid outages during heatwaves from low reserves, fading solar, weak wind, and limited firm capacity.

✅ Heatwave demand rose as solar output dropped at sunset

✅ Limited imports and gas, nuclear shortfalls cut reserves

✅ Policy, pricing, and maintenance gaps increased outage risk

Millions of Californians were denied electrical power and thus air conditioning during a heatwave, raising the risk of heatstroke and death, particularly among the elderly and sick. 

The blackouts come at a time when people, particularly the elderly, are forced to remain indoors due to Covid-19, and as later heat waves would test the grid again statewide.

At first, the state’s electrical grid operator last night asked customers to voluntarily reduce electricity use. But after lapses in power supply pushed reserves to dangerous levels it declared a “Stage 3 emergency” cutting off power to people across the state at 6:30 pm.

The immediate reason for the black-outs was the failure of a 500-megawatt power plant and an out-of-service 750-megawatt unit not being available. “There is nothing nefarious going on here,” said a spokeswoman for California Independent System Operator (CAISO). “We are just trying to run the grid.”

But the underlying reasons that California is experiencing rolling black-outs for the second time in less than a year stem from the state’s climate policies, which California policymakers have justified as necessary to prevent deaths from heatwaves, and which it is increasingly exporting to Western states as a model.

In October, Pacific Gas and Electric cut off power to homes across California to avoid starting forest fires after reports that its power lines may have started fires in recent seasons. The utility and California’s leaders had over the previous decade diverted billions meant for grid maintenance to renewables. 

And yesterday, California had to impose rolling blackouts because it had failed to maintain sufficient reliable power from natural gas and nuclear plants, or pay in advance for enough guaranteed electricity imports from other states.

It may be that California’s utilities and their regulator, the California Public Utilities Commission, which is also controlled by Gov. Newsom, didn’t want to spend the extra money to guarantee the additional electricity out of fears of raising California’s electricity prices even more than they had already raised them.

California saw its electricity prices rise six times more than the rest of the United States from 2011 to 2019, helping explain why electricity prices are soaring across the state, due to its huge expansion of renewables. Republicans in the U.S. Congress point to that massive increase to challenge justifications by Democrats to spend $2 trillion on renewables in the name of climate change.

Even though the cost of solar panels declined dramatically between 2011 and 2019, their unreliable and weather-dependent nature meant that they imposed large new costs in the form of storage and transmission to keep electricity as reliable. California’s solar panels and farms were all turning off as the blackouts began, with no help available from the states to the East already in nightfall.

Electricity from solar goes away at the very moment when the demand for electricity rises. “The peak demand was steady in late hours,” said the spokesperson for CAISO, which is controlled by Gov. Gavin Newsom, “and we had thousands of megawatts of solar reducing their output as the sunset.”

The two blackouts in less than a year are strong evidence that the tens of billions that Californians have spent on renewables come with high human, economic, and environmental costs.

Last December, a report by done for PG&E concluded that the utility’s customers could see blackouts double over the next 15 years and quadruple over the next 30.

California’s anti-nuclear policies also contributed to the blackouts. In 2013, Gov. Jerry Brown forced a nuclear power plant, San Onofre, in southern California to close.

Had San Onofre still been operating, there almost certainly would not have been blackouts on Friday as the reserve margin would have been significantly larger. The capacity of San Onofre was double that of the lost generation capacity that triggered the blackout.

California's current and former large nuclear plants are located on the coast, which allows for their electricity to travel shorter distances, and through less-constrained transmission lines than the state’s industrial solar farms, to get to the coastal cities where electricity is in highest demand.

There has been very little electricity from wind during the summer heatwave in California and the broader western U.S., further driving up demand. In fact, the same weather pattern, a stable high-pressure bubble, is the cause of heatwaves, since it brought very low wind for days on end along with very high temperatures.

Things won’t be any better, and may be worse, in the winter, with a looming shortage as it produces far less solar electricity than the summer. Solar plus storage, an expensive attempt to fix problems like what led to this blackout, cannot help through long winters of low output.

California’s electricity prices will continue to rise if it continues to add more renewables to its grid, and goes forward with plans to shut down its last nuclear plant, Diablo Canyon, in 2025.

Had California spent an estimated $100 billion on nuclear instead of on wind and solar, it would have had enough energy to replace all fossil fuels in its in-state electricity mix.

To manage the increasingly unreliable grid, California will either need to keep its nuclear plant operating, build more natural gas plants, underscoring its reliance on fossil fuels for reliability, or pay ever more money annually to reserve emergency electricity supplies from its neighbors.

After the blackouts last October, Gov. Newsom attacked PG&E Corp. for “greed and mismanagement” and named a top aide, Ana Matosantos, to be his “energy czar.” 

“This is not the new normal, and this does not take 10 years to solve,” Newsom said. “The entire system needs to be reimagined.”

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PG&E Public Safety Power Shutoff reduces wildfire risk during extreme winds, triggering de-energization across the North Bay and Sierra Foothills under red flag warnings, with safety inspections and staged restoration to improve grid resilience.

Key Points

A utility protocol to de-energize lines during extreme fire weather, reducing ignition risks and improving grid safety.

✅ Triggered by red flag warnings, humidity, wind, terrain

✅ Temporary de-energization of transmission and distribution lines

✅ Inspections precede phased restoration to minimize wildfire risk

PG&E purposefully shut off electricity to nearly 60,000 Northern California customers Sunday night, aiming to mitigate wildfire risks from power lines during extreme winds.

Pacific Gas and Electric planned to restore power to 70 percent of affected customers in the North Bay and Sierra Foothills late Monday night. As crews inspect lines for safety by helicopter, vehicles and on foot, the remainder will have power sometime Tuesday.

While it was the first time the company shut off power for public safety, PG&E announced its criteria and procedures for such an event in June, said spokesperson Paul Doherty. After wildfires devastated Northern California's wine country last October, he added, PG&E developed its community wildfire safety program division to make power grids and communities more resilient, and prepares for winter storm season through enhanced local response. 

Two sagging PG&E power lines caused one of those wildfires during heavy winds, killing four people and injuring a firefighter, the California Department of Forestry and Fire Protection determined earlier this month. Trees or tree branches hitting PG&E power lines started another four wildfires in October 2017. Altogether, the power company has been blamed for igniting 13 wildfires last year.

"We're adapting our electric system our operating practices to improve safety and reliability," Doherty said of the safety program. "That's really the bottom line for us."

Turning off power to so many customers was a "last resort given the extreme fire danger conditions these communities are experiencing," Pat Hogan, senior vice president of electric operations, said in a statement. Conditions that led the company to shut off power included the National Weather Service's red flag fire warnings, humidity levels, sustained winds, temperature, dry fuel and local terrain, Doherty said, amid possible rolling blackouts during grid strain.

The company de-energized more than 78 miles of transmission lines and more than 2,150 miles of distribution power lines Sunday night. Many schools in the area were closed Monday because of the planned power outage, highlighting unequal access to electricity across communities.

Late Saturday and early Sunday, PG&E warned 97,000 customers in 12 counties that the shut off might go into effect. Through automated calls, texts and emails, the company encouraged customers to have drinking water, canned food, flashlights, prescriptions and baby supplies on hand.

Power was also turned off in Southern California on Monday.

San Diego Gas & Electric turned off service to about 360 customers near Cleveland National Forest, where multiple fires have scorched large swaths of land in recent years.

SDG&E has pre-emptively shut off power to customers in the past, most recently in December when 14,000 customers went without power.

Southern California Edison, the primary electric provider across Southern California — including Los Angeles — has a similar power shutoff program. As of Monday night, SCE had yet to turn off power in any of its service areas, a spokesperson told USA TODAY.

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UK Market Stability Outlook remains febrile as the Bank of England, Treasury, and OBR forecasts shape fiscal policy, interest rates, gilt yields, inflation, energy bills, and pound sterling, with Oct. 31 guidance to reassure investors.

Key Points

A view of investor confidence as BOE policy, fiscal plans, and energy aid shape inflation and interest rates.

✅ Markets await Oct. 31 fiscal statement and OBR projections

✅ Energy support design drives inflation and disposable income

✅ Pound weakness adds imported inflation; rates seen up 75 bps

Bank of England Deputy Governor Dave Ramsden said financial markets are still unsettled about the outlook for the UK and that a Treasury statement due on Oct. 31 may provide some reassurance.

Speaking to the Treasury Committee in Parliament, Ramsden said officials in government and the central bank are dealing with huge economic shocks, notably the surge in energy prices that came with Russia’s attack on Ukraine. Investors are reassessing where interest rates and the fiscal stance are headed.

“Markets remain quite febrile,” Ramsden told members of Parliament in London on Monday. “Things have not settled down yet.”

He described the events following Prime Minister Liz Truss’s ill-fated fiscal statement on Sept. 23, which set out a series of tax cuts funded by borrowing that spooked investors and triggered a rout in UK assets. Ramsden said those events damaged the UK’s credibility among investors, but reversing that program and Truss’s decision to step aside have helped the nation regain confidence.

“Credibility is hard won and easily lost,” Ramsden said. “That credibility is being recovered. That has to be followed through. A return to the kind of stability around policy making and around the framing of fiscal events will be really important.”

He said the issue with the Sept. 23 statement was that “it had one side of the fiscal arithmetic in it” and that the decision to include forecasts from the Office for Budget Responsibility will help underpin the confidence investors have in assessing the UK budget due out next week, including potential moves to end the link between gas and electricity prices for consumers.

“What we are going to get on Oct. 31 will be very important,” Ramsden said, “as it will address measures such as the price cap on household energy bills and other fiscal choices.”

“My sense is that will take account of all the statements on both the revenue and on the spending side.”

The central bank already was getting some information from Chancellor of the Exchequer Jeremy Hunt’s team about the fiscal statement due. Hunt said last week he’d curtail government plans to subsidize household fuel bills in April, when a 16% decrease in energy bills is anticipated, instead of letting it run as long as planned and replace it with a more targeted program. 

“To the extent possible, we will obviously have a little bit of time to take account of that before we make our decisions later next week,” Ramsden said.

With Truss stepping down in the next day and handing power to Rishi Sunak, it isn’t certain the Oct. 31 statement will go ahead as planned. Ramsden’s remarks confirm reports that Hunt is preparing to make the statement, amid a free electricity debate in the industry, even before Sunak names his team.

Any hint about what sort of package Hunt will offer on energy is crucial to the BOE’s forecasts. Without aid for energy, consumers will be exposed to high winter heating and electricity costs and to the full force of whatever happens in natural gas and electricity markets, and that will have a big impact on how much disposable income is available to households.

The energy plan, alongside the energy security bill, “will be a key element, as obviously it will have a bearing on the path for inflation, which is critical, but also how much additional support relative to what we were assuming at the time of the September MPC there will be for households at different points in the income distribution,” Ramsden added.

Investors currently expect the BOE to hike rates by 75 basis points next week.

Ramsden also said the BOE is watching the pound’s decline to assess how that changes the outlook for inflation.

“We have to take account of it,” Ramsden said. “When sterling deprreciaties that feeds through to imported inflation. It’s fallen quite significantly. The overall trend is down.”

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Hydro-Québec $185-Billion Clean Energy Plan accelerates hydroelectric upgrades, wind power expansion, solar and battery storage, pumped storage, and 5,000 km transmission lines to decarbonize Quebec, boost grid resilience, and attract bond financing and Indigenous partnerships.

Key Points

Plan to grow renewables, harden the grid, and fund Quebec's decarbonization with major investments.

✅ $110B new generation, $50B grid resilience by 2035

✅ Triple wind, add solar, batteries, and pumped storage

✅ 5,000 km lines, bond financing, Indigenous partnerships

Hydro-Québec is in the preliminary stages of dialogue with various financiers and potential collaborators to strategize the implementation of a $185-billion initiative aimed at transitioning Quebec away from fossil fuel dependency.

As the leading hydroelectric power producer in Canada, Hydro-Québec is set to allocate up to $110 billion by 2035 towards the development of new clean energy facilities, building on its hydropower capacity expansion in recent years, with an additional $50 billion dedicated to enhancing the resilience of its power grid, as revealed in a strategy announced last November. The remainder of the projected expenditure will cover operational costs.

This ambitious initiative has garnered significant interest from the financial sector, with the province's recent electricity for industrial projects also drawing attention, as noted by CEO Michael Sabia during a conference call with journalists where the utility's annual financial outcomes were discussed. Sabia reported receiving various proposals to fund the initiative, though specific partners were not disclosed. He expressed confidence in securing the necessary capital for the project's success.

Sabia highlighted three immediate strategies to increase power output: identifying new sites for hydroelectric projects while upgrading turbines at existing facilities, such as the Carillon Generating Station upgrade now underway for enhanced efficiency, expanding wind energy production threefold, and promoting energy conservation among consumers to optimize current power usage.

Additionally, Hydro-Québec aims to augment its solar and battery energy production and is planning to establish a pumped-storage hydroelectric plant to support peak demand periods. The utility also intends to construct 5,000 kilometers of new transmission lines, address Quebec-to-U.S. transmission constraints where feasible, and is set to double its capital expenditure to $16 billion annually, a significant increase from the investment levels during the James Bay hydropower project construction in the 1970s and 1980s.

To fund part of this expansive plan, Hydro-Québec will continue to access the bond market, having issued $3.7 billion in notes to investors last year despite facing several operational hurdles due to adverse weather conditions.

For the year 2023, Hydro-Québec reported a net income of $3.3 billion, marking a 28% decrease from the previous year's record of $4.56 billion. Factors such as insufficient snow cover, reduced spring runoff, and higher temperatures resulted in lower water levels in reservoirs, leading to a reduction in power exports and a $547-million decrease in external market sales compared to the previous year.

The utility experienced its lowest export volume in a decade but managed to leverage hedging strategies to secure 10.3 cents per kWh for exported power to markets including New Brunswick via recent NB Power agreements that expand interprovincial deliveries, nearly twice the average market rate, through forward contracts that cover up to half of its export volume for about a year in advance.

The success of Sabia's plan will partly depend on the cooperation of First Nations communities, as the proposed infrastructure developments are likely to traverse their ancestral territories. Relationships with some communities are currently tense, exemplified by the Innu of Labrador's $4-billion lawsuit against Hydro-Québec for damages related to land flooding for reservoir construction, and broader regional tensions in Newfoundland and Labrador that persist in the power sector.

Sabia has committed to involving First Nations and Inuit communities as partners in clean energy ventures, offering them ongoing financial benefits rather than one-off settlements, a principle he refers to as "economic reconciliation."

Recently, the Quebec government reached an agreement with the Innu of Pessamit, pledging $45 million to support local community development. This agreement outlines solutions for managing a nearby hydropower reservoir, such as the La Romaine complex in the region, and includes commitments for wind energy development.

Sabia is optimistic about building stronger, more positive relationships with various Indigenous communities, anticipating significant progress in the coming months and viewing this year as a potential milestone in transforming these relationships for the better.

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CO2 Tax for UK Offshore Energy Efficiency can accelerate adoption of aero-derivative gas turbines, flare gas recovery, and combined cycle power, reducing emissions on platforms like Equinor's Mariner and supporting net zero goals.

Key Points

A carbon price pushing operators to adopt efficient turbines, flare recovery, and combined cycle to cut emissions.

✅ Aero-derivative turbines beat industrial units on efficiency

✅ Flare gas recovery cuts routine flaring and fuel waste

✅ Combined cycle raises efficiency and lowers emissions

By Tom Baxter

The recent Energy Voice article from the Equinor chairman concerning the Mariner project heralding a ‘significant point of reference’ for growth highlighted the energy efficiency achievements associated with the platform.

I view energy efficiency as a key enabler to net zero, and alongside this the UK must start large-scale storage to meet system needs; it is a topic I have been involved with for many years.

As part of my energy efficiency work, I investigated Norwegian practices and compared them with the UK.

There were many differences, here are three;

1. Power for offshore installations is usually supplied from gas turbines burning fuel from the oil and gas processing plant, and even as the UK's offshore wind supply accelerates, installations convert that to electricity or couple the gas turbine to a machine such as a gas compressor.

There are two main generic types of gas turbine – aero-derivative and industrial. As the name implies aero-derivatives are aviation engines used in a static environment. Aero-derivative turbines are designed to be energy efficient as that is very import for the aviation industry.

Not so with industrial type gas turbines; they are typically 5-10% less efficient than a comparable aero-derivative.

Industrial machines do have some advantages – they can be cheaper, require less frequent maintenance, they have a wide fuel composition tolerance and they can be procured within a shorter time frame.

My comparison showed that aero-derivative machines prevailed in Norway because of the energy efficiency advantages – not the case in the UK where there are many more offshore industrial gas turbines.

Tom Baxter is visiting professor of chemical engineering at Strathclyde University and a retired technical director at Genesis Oil and Gas Consultants

2. Offshore gas flaring is probably the most obvious source of inefficient use of energy with consequent greenhouse gas emissions.

On UK installations gas is always flared due to the design of the oil and gas processing plant.

Though not a large quantity of gas, a continuous flow of gas is routinely sent to flare from some of the process plant.

In addition the flare requires pilot flames to be maintained burning at all times and, while Europe explores electricity storage in gas pipes, a purge of hydrocarbon gas is introduced into the pipes to prevent unsafe air ingress that could lead to an explosive mixture.

On many Norwegian installations the flare system is designed differently. Flare gas recovery systems are deployed which results in no flaring during continuous operations.

Flare gas recovery systems improve energy efficiency but they are costly and add additional operational complexity.

3. Returning to gas turbines, all UK offshore gas turbines are open cycle – gas is burned to produce energy and the very hot exhaust gases are vented to the atmosphere. Around 60 -70% of the energy is lost in the exhaust gases.

Some UK fields use this hot gas as a heat source for some of the oil and gas treatment operations hence improving energy efficiency.

There is another option for gas turbines that will significantly improve energy efficiency – combined cycle, and in parallel plans for nuclear power under the green industrial revolution aim to decarbonise supply.

Here the exhaust gases from an open cycle machine are taken to a separate turbine. This additional turbine utilises exhaust heat to produce steam with the steam used to drive a second turbine to generate supplementary electricity. It is the system used in most UK power stations, even as UK low-carbon generation stalled in 2019 across the grid.

Open cycle gas turbines are around 30 – 40% efficient whereas combined cycle turbines are typically 50 – 60%. Clearly deploying a combined cycle will result in a huge greenhouse gas saving.

I have worked on the development of many UK oil and gas fields and combined cycle has rarely been considered.

The reason being is that, despite the clear energy saving, they are too costly and complex to justify deploying offshore.

However that is not the case in Norway where combined cycle is used on Oseberg, Snorre and Eldfisk.

What makes the improved Norwegian energy efficiency practices different from the UK – the answer is clear; the Norwegian CO2 tax.

A tax that makes CO2 a significant part of offshore operating costs.

The consequence being that deploying energy efficient technology is much easier to justify in Norway when compared to the UK.

Do we need a CO2 tax in the UK to meet net zero – I am convinced we do. I am in good company. BP, Shell, ExxonMobil and Total are supporting a carbon tax.

Not without justification there has been much criticism of Labour’s recent oil tax plans, alongside proposals for state-owned electricity generation that aim to reshape the power market.

To my mind Labour’s laudable aims to tackle the Climate Emergency would be much better served by supporting a CO2 tax that complements the UK's coal-free energy record by strengthening renewable investment.

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