How big power will keep control

By Nick Rosen, Off Grid


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The man who runs one of the largest energy retailers in America (and Britain) has signaled the death of the traditional utility company. He is typical of a new breed of energy executive which will try to take the mantle of environmentalism to keep the profits rolling in and keep control of the industry firmly away from end users.

Sam Laidlaw is boss of Direct Energy, which sells energy to five million customers in the United States and Canada. He has revolutionized Direct Energy, bringing in a scheme where American customers can pay extra $25 a month to ensure their electricity is generated from wind power.

So far the company has power purchase agreements totaling 813MW of wind power but that will increase as it wins more customers. Laidlaw provides energy and energy-related services to residential and business customers in Texas, and the north and east of the U.S., as well as across Canada. But he has no ideological commitment to renewables, Direct Energy owns and operates approximately 3,000 natural gas wells in Alberta, while in Texas it owns three gas-fired power plants.

He aims to sell every American and Brit a “warm, well-lit home” and in a carbon-constrained world, he argues, energy companies must reinvent themselves. No longer can they thrive simply by offering consumers an “all-you-can eat buffet” of cheap gas and electricity, with scant regard for emissions. Instead, “in future, we will sell you a warm, well-lit home and take care of everything else,” said Mr. Laidlaw, a former oil company executive who was educated at Eton and Insead and joined Centrica in 2006.

The companies will continue to sell gas and electricity “but we will sell more energy-efficiency products — insulation, heat pumps, solar panels.… And we will add valuable margin and pick up more customers along the way.”

As well as owning British Gas — one of the UK’s Big Six power companies Centrica owns Direct Energy, the American retail energy business, and three other wholesale energy production and storage businesses.

“We decided three years ago that in a world of climate change, carbon dioxide cuts and increased consumer enthusiasm for lower-carbon products, we wanted to turn all of those things into a business.” For Mr. Laidlaw, the answer to the challenge of carving a viable energy business out of reduced consumption lay in the unlikely form of the company’s boiler repair division, a hidden jewel — an army of experienced engineers.

Mr. Laidlaw’s plan was to transform this band into the shock troops of a green revolution, training the engineers to conduct home “energy audits” and to install a range of other products, from solar panels to smart meters. The strategy is reaping results already. “If you look at the revenue stream between selling energy and services, there is a change under way,” Mr. Laidlaw said.

“We are starting to see some of the potential benefits from that,” Mr. Laidlaw said, adding that this was only the start. He believes that gas demand could fall by up to 15 per cent over the next five years. “You could get nearly half of those cuts simply from energy efficiency,” he said.

Far from being a threat to utility companies, energy efficiency, Mr. Laidlaw believes, represents a vast untapped business opportunity, one that could be worth up to £150 billion in the UK.

“UK energy consumption is one of the highest in Europe because of the poor quality and age of our housing stock,” he said. “So, there is a huge opportunity.”

With a market value of £13 billion, 33,000 staff and 15.7 million customers, Centrica is applying the same strategy to Direct Energy, which sells energy to five million customers in the United States and Canada. And while Centrica’s traditional businesses of producing and selling gas and power still generate the lion’s share of group profits, Mr. Laidlaw believes that services will be increasingly important. New technology will broaden the opportunity and the company is preparing to launch a home-based fuel cell that generates electricity, as well as heat.

“You will have a boiler that will also generate electricity and you can export that to the grid and get paid for it,” Mr Laidlaw said.

Yet the real key to unlocking the opportunity will be the rollout of “smart meters” in all 26 million homes in the UK, plans for which the government is expected to unveil this week. Smart meters, monitoring household energy all day, will allow for more sophisticated services, including systems that allow people to control home appliances remotely or to turn the heating on automatically when their mobile phone indicates that they are near home.

Most importantly, they will let utilities control demand by giving discounts for off-peak energy use. By encouraging people to run their dishwashers and tumble dryers at night, utilities will be able to ease overall demand, allowing Britain to get by with less electricity and fewer emissions.

“Consumers will not have the agonies of estimated bills and we won’t need to build as many power stations,” Mr. Laidlaw said.

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Competition in Electricity Has Been Good for Consumers and Good for the Environment

Electricity Market Competition drives lower wholesale prices, stable retail rates, better grid reliability, and faster emissions cuts as deregulation and renewables adoption pressure utilities, improve efficiency, and enhance consumer choice in power markets.

 

Key Points

Electricity market competition opens supply to rivals, lowering prices, improving reliability, and reducing emissions.

✅ Wholesale prices fell faster in competitive markets

✅ Retail rates rose less than in monopoly states

✅ Fewer outages, shorter durations, improved reliability

 

By Bernard L. Weinstein

Electricity used to be boring.  Public utilities that provided power to homes and businesses were regulated monopolies and, by law, guaranteed a fixed rate-of-return on their generation, transmission, and distribution assets. Prices per kilowatt-hour were set by utility commissions after lengthy testimony from power companies, wanting higher rates, and consumer groups, wanting lower rates.

About 25 years ago, the electricity landscape started to change as economists and others argued that competition could lead to lower prices and stronger grid reliability. Opponents of competition argued that consumers weren’t knowledgeable enough about power markets to make intelligent choices in a competitive pricing environment. Nonetheless, today 20 states have total or partial competition for electricity, allowing independent power generators to compete in wholesale markets and retail electric providers (REPs) to compete for end-use customers, a dynamic echoed by the Alberta electricity market across North America. (Transmission, in all states, remains a regulated natural monopoly).

A recent study by the non-partisan Pacific Research Institute (PRI) provides compelling evidence that competition in power markets has been a boon for consumers. Using data from the U.S. Energy Information Administration (EIA), PRI’s researchers found that wholesale electricity prices in competitive markets have been generally declining or flat, prompting discussions of free electricity business models, over the last five years. For example, compared to 2015, wholesale power prices in New England have dropped more than 44 percent, those in most Mid-Atlantic States have fallen nearly 42 percent, and in New York City they’ve declined by nearly 45 percent. Wholesale power costs have also declined in monopoly states, but at a considerably slower rate.

As for end-users, states that have competitive retail electricity markets have seen smaller price increases, as consumers can shop for electricity in Texas more cheaply than in monopoly states. Again, using EIA data, PRI found that in 14 competitive jurisdictions, retail prices essentially remained flat between 2008 and 2020. By contrast, retail prices jumped an average of 21 percent in monopoly states.  The ten states with the largest retail price increases were all monopoly-based frameworks. A 2017 report from the Retail Energy Supply Association found customers in states that still have monopoly utilities saw their average energy prices increase nearly 19 percent from 2008 to 2017 while prices fell 7 percent in competitive markets over the same period.

The PRI study also observed that competition has improved grid reliability, the recent power disruptions in California and Texas, alongside disruptions in coal and nuclear sectors across the U.S., notwithstanding. Looking at two common measures of grid resiliency, PRI’s analysis found that power interruptions were 10.4 percent lower in competitive states while the duration of outages was 6.5 percent lower.

Citing data from the EIA between 2008 and 2018, PRI reports that greenhouse gas emissions in competitive states declined on average 12.1 percent compared to 7.3 percent in monopoly states. This result is not surprising, and debates over whether Israeli power supply competition can bring cheaper electricity mirror these dynamics.  In a competitive wholesale market, independent power producers have an incentive to seek out lower-cost options, including subsidized renewables like wind and solar. By contrast, generators in monopoly markets have no such incentive as they can pass on higher costs to end-users. Perhaps the most telling case is in the monopoly state of Georgia where the cost to build nuclear Plant Vogtle has doubled from its original estimate of $14 billion 12 years ago. Overruns are estimated to cost Georgia ratepayers an average of $854, and there is no definite date for this facility to come on line. This type of mismanagement doesn’t occur in competitive markets.

Unfortunately, some critics are attempting to halt the momentum for electricity competition and have pointed to last winter’s “deep freeze” in Texas that left several million customers without power for up to a week. But this example is misplaced. Power outages in February were the result of unprecedented and severe weather conditions affecting electricity generation and fuel supply, and numerous proposals to improve Texas grid reliability have focused on weatherization and fuel resilience; the state simply did not have enough access to natural gas and wind generation to meet demand. Competitive power markets were not a factor.

The benefits of wholesale and retail competition in power markets are incontrovertible. Evidence shows that households and businesses in competitive states are paying less for electricity while grid reliability has improved. The facts also suggest that wholesale and retail competition can lead to faster reductions in greenhouse gas emissions. In short, competition in power markets is good for consumers and good for the environment.

Bernard L. Weinstein is emeritus professor of applied economics at the University of North Texas, former associate director of the Maguire Energy Institute at Southern Methodist University, and a fellow of Goodenough College, London. He wrote this for InsideSources.com.

 

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Spain's power demand in April plummets under COVID-19 lockdown

Spain Electricity Demand April 2020 saw a 17.3% year-on-year drop as COVID-19 lockdown curbed activity; renewables and wind power lifted the emission-free share, while combined cycle plants dominated islands, per REE data.

 

Key Points

A 17.3% y/y decline amid COVID-19 lockdown, with 47.9% renewables and wind at 21.3% of the national power mix.

✅ Mainland demand -17%; Balearic -27.6%; Canary -20.3%.

✅ Emission-free share: 49.7% on the peninsula in April.

✅ Combined cycle led islands; coal absent in Balearics.

 

Demand for electricity in Spain dropped by 17.3% year-on-year to an estimated 17,104 GWh in April, aligning with a 15% global daily demand dip during the pandemic, while the country’s economy slowed down under the national state of emergency and lockdown measures imposed to curb the spread of COVID-19.

According to the latest estimates by Spanish grid operator Red Electrica de Espana (REE), the decline in demand was registered across Spain’s entire national territory, similar to a 10% UK drop during lockdown. On the mainland, it decreased by 17% to 16,191 GWh, while on the Balearic and the Canary Islands it plunged by 27.6% and 20.3%, respectively.

Renewables accounted for 47.9% of the total national electricity production in April, echoing Britain’s cleanest electricity trends during lockdown. Wind power production went down 20% year-on-year to 3,730 GWh, representing a 21.3% share in the total power mix.

During April, electricity generation in the peninsula was mostly based on emission-free technologies, reflecting an accelerated power-system transition across Europe, with renewables accounting for 49.7%. Wind farms produced 3,672 GWh, 20.1% less compared to April 2019, while contributing 22% to the power mix, even as global demand later surpassed pre-pandemic levels in subsequent periods.

In the Balearic Islands, electricity demand of 323,296 MWh was for the most part met by combined cycle power plants, even as some European demand held firm in later lockdowns, which accounted for 78.3% of the generation. Renewables and emission-free technologies had a combined share of 6.4%, while coal was again absent from the local power mix, completing now four consecutive months without contributing a single MWh.

In the Canary Islands system, demand for power decreased to 558,619 MWh, even as surging demand elsewhere strained power systems across the world. Renewables and emission-free technologies made up 14.3% of the mix, while combined cycle power plants led with a 45.3% share.

 

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Canada's Electricity Exports at Risk Amid Growing U.S.-Canada Trade Tensions

US-Canada Electricity Tariff Dispute intensifies as proposed tariffs spur Canadian threats to restrict hydroelectric exports, risking cross-border energy supply, grid reliability, higher electricity prices, and clean energy goals in the Northeast and Midwest.

 

Key Points

Trade clash over tariffs and hydroelectric exports that threatens power supply, prices, and grid reliability.

✅ Potential export curbs on Canadian hydro to US markets

✅ Risks: higher prices, strained grids, reduced clean energy

✅ Diplomacy urged to avoid retaliatory trade measures

 

In early February 2025, escalating trade tensions between the United States and Canada have raised concerns about the future of electricity exports from Canada to the U.S. The potential imposition of tariffs by the U.S. has prompted Canadian officials to consider retaliatory measures, including restricting electricity exports and pursuing high-level talks such as Ford's Washington meeting with federal counterparts.

Background of the Trade Dispute

In late November 2024, President-elect Donald Trump announced plans to impose a 25% tariff on all Canadian products, citing issues related to illegal immigration and drug trafficking. This proposal has been met with strong opposition from Canadian leaders, who view such tariffs as unjustified and detrimental to both economies, even as tariff threats boost support for Canadian energy projects among some stakeholders.

Canada's Response and Potential Retaliatory Measures

In response to the proposed tariffs, Canadian officials have discussed various countermeasures. Ontario Premier Doug Ford has threatened to cut electricity supplies to 1.5 million Americans and ban imports of U.S.-made beer and liquor. Other provinces, such as Quebec and Alberta, are also considering similar actions, though experts advise against cutting Quebec's energy exports due to reliability concerns.

Impact on U.S. Energy Supply

Canada is a significant supplier of electricity to the United States, particularly in regions like the Northeast and Midwest. A reduction or cessation of these exports could lead to energy shortages and increased electricity prices in affected U.S. states, with New York especially vulnerable according to regional assessments. For instance, Ontario exports substantial amounts of electricity to neighboring U.S. states, and any disruption could strain local energy grids.

Economic Implications

The imposition of tariffs and subsequent retaliatory measures could have far-reaching economic consequences. In Canada, industries such as agriculture, manufacturing, and energy could face significant challenges due to reduced access to the U.S. market, even as many Canadians support energy and mineral tariffs as leverage. Conversely, U.S. consumers might experience higher prices for goods and services that rely on Canadian imports, including energy products.

Environmental Considerations

Beyond economic factors, the trade dispute could impact environmental initiatives. Canada's hydroelectric power exports are a clean energy source that helps reduce carbon emissions in the U.S., where policymakers look to Canada for green power to meet targets. A reduction in these exports could lead to increased reliance on fossil fuels, potentially hindering environmental goals.

The escalating trade tensions between the United States and Canada, particularly concerning electricity exports, underscore the complex interdependence of the two nations. While the situation remains fluid, it highlights the need for diplomatic engagement to resolve disputes and maintain the stability of cross-border energy trade.

 

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Hydro One, Avista to ask U.S. regulator to reconsider order against acquisition

Hydro One Avista Takeover faces Washington UTC scrutiny as regulators deny approval; companies plan a reconsideration petition, citing acquisition terms, governance concerns, merger risks, EPS dilution, and balance sheet impacts across regulated utility operations.

 

Key Points

A $6.7B bid by Hydro One to buy Avista, denied by Washington UTC on governance risk, under reconsideration petition.

✅ UTC denied over potential provincial interference.

✅ Petition for reconsideration due by Dec. 17.

✅ Deal seen diluting EPS, weakening balance sheet.

 

Hydro One Ltd. and Avista Corp. say they plan to formally request that the Washington Utilities and Transportation Commission reconsider its order last week denying approval of the $6.7-billion takeover, which previously received U.S. antitrust clearance from federal regulators, of the U.S.-based energy utility.

The two companies say they will file a petition no later than Dec. 17 but haven't indicated on what grounds they are making the request, even as investor concerns about Hydro One persist.

Under Washington State law, the UTC has 20 days to consider the petition, otherwise it is deemed to be denied.

If it reconsiders its decision, the UTC can modify the prior order or take any actions it deems appropriate, similar to provincial rulings such as the OEB decision on Hydro One's first combined T&D rates, including extending deliberations.

Washington State regulators said they would not allow Ontario's largest utility to buy Avista for fear the provincial government, which owns 47 per cent of Hydro One's shares and recently prompted a CEO and board exit at the utility, might meddle in Avista's operations.

Hydro One's shares have risen since the order because the deal, announced in July 2017, would have eroded earnings per share and weakened Hydro One's balance sheet, according to analysts, even as the company reported a one-time-boosted Q2 profit earlier this year.

 

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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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Three New Solar Electricity Facilities in Alberta Contracted At Lower Cost than Natural Gas

Alberta Solar Energy Contracts secure low-cost photovoltaic PPAs for government operations, delivering renewable electricity at 4.8 cents/kWh, beating natural gas LCOE, enhancing summer grid efficiency across Hays, Tilley, and Jenner with Canadian Solar.

 

Key Points

Low-cost PV power agreements meeting 55% of Alberta government electricity demand via new Canadian Solar facilities.

✅ Price: 4.8 cents/kWh CAD, under gas-fired generation LCOE.

✅ Sites: Hays, Tilley, Jenner; 50% equity with Conklin Métis Local #193.

✅ Supplies 55% of provincial government electricity demand.

 

Three new solar electricity facilities to be built in south eastern Alberta (Canada) amid Alberta's solar growth have been selected through a competitive process to supply the Government of Alberta with 55 per cent of their annual electricity needs. The facilities will be built near Hays, Tilley, and Jenner, by Canadian Solar with Conklin Métis Local #193 as 50-percent equity owners.

The Government of Alberta's operations have been powered 100 per cent with wind power since 2007. Upon the expiration of some of these contracts, they have been renewed to switch from wind to solar energy. The average contract pricing will be $0.048 per kilowatt hour (3.6 cents/kWh USD), which is less than the average historical wholesale power pool price paid to natural gas-fired electricity in the province in years 2008 - 2018.

"The conversation about solar energy has long been fixated on its price competitiveness with fossil fuels," said John Gorman, CanSIA President & CEO. "Today's announcement demonstrates that low cost solar energy has arrived as a mainstream option in Alberta, even as demand for solar lags in Canada according to federal assessments. The conversation should next focus on how to optimize an all-of-the-above strategy for developing the province's renewable and non-renewable resources."

"This price discovery is monumental for the solar industry in Canada" said Patrick Bateman, CanSIA Director of Policy & Market Development. "At less than five cents per kilowatt hour, this solar electricity has a cost that is less than that of natural gas. Achieving Alberta's legislated 30 per cent by 2030 renewable electricity target just became a whole lot cheaper!".

 

Quick Facts:

  • The contract price of 4.8 cents/kWh CAD to be paid by Alberta Infrastructure for this solar electricity represents a lower Levelized Cost of Electricity (LCOE) than the average annual wholesale price paid by the power pool to combined-cycle and single-cycle natural gas-fired electricity generation which was 7.1 cents/kWh and 11.2 cents/kWh respectively from 2008 - 2018.
  • Alberta receives more hours of sunshine than Miami, Florida in the summer months. Alberta's electricity supply is most strained in summer, highlighting challenges for solar expansion when high temperatures increase the resistance of the distribution and transmission systems, and reduce the efficiency of cooling thermal power plants. For this reason, solar facilities sited near to electricity demand improves overall grid efficiency. Supply shortages are atypical in Alberta in winter when solar energy is least available. When they do occur, imports are increased and large loads are decreased.
  • In 2018, Alberta's solar electricity generation exceeded 50 MW. While representing much less than 1% of the province's electricity supply today, the Canadian Solar Industries Association (CanSIA) forecasts that solar energy could supply as much as 3 per cent of the province's electricity by 2030, supporting renewable energy job growth across Alberta. A recent supply chain study of the solar electricity sector in Alberta by Solas Energy Consulting Inc. found a potential of $4.1 billion in market value and a labour force rising to 10,000 in 2030.

 

To learn more about solar energy and the best way for consumers to go solar, please visit the Canadian Solar Industries Association at www.CanSIA.ca.

 

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