Chinese power producer to cut spending

Texas Power Grid Reliability faces record peak demand as ERCOT balances renewable energy, wind and solar variability, gas-fired generation, demand response, and transmission limits to prevent blackouts during heat waves and extreme weather.

Key Points

Texas Power Grid Reliability is ERCOT's capacity to meet peak demand with diverse resources while limiting outages.

✅ Record heat drives peak demand across ERCOT.

✅ Variable wind/solar need firm, flexible capacity.

✅ Demand response and reserves reduce blackout risk.

The electric power grid in Texas, which collapsed dramatically during the 2021 winter storm across the state, is being tested again as the state suffers unusually hot summer weather. Demand for electricity has reached new records at a time of rapid change in the mix of power sources as wind and solar ramp up. That’s feeding a debate about the dependability of the state’s power. 

1. Why is the Texas grid under threat again? 

Already the biggest power user in the nation, electricity use in the second most-populous state surged to record levels during heat waves this summer. The jump in demand comes as the state becomes more dependent on intermittent renewable power sources, raising concerns among some critics that more reliance on wind and solar will leave the grid more vulnerable to disruption. Green sources will produce almost 40% of the power in Texas this year, US Energy Information Administration data show. While that trails California’s 52%, Texas is a bigger market. It’s already No. 1 in wind, making it the largest clean energy market in the US. 

2. How is Texas unique? 

The spirit of defiance of the Lone Star State extends to its power grid as well. The Electric Reliability Council of Texas, or Ercot as the grid operator is known, serves about 90% of the state’s electricity needs and has very few high-voltage transmission lines connecting to nearby grids. It’s a deliberate move to avoid federal oversight of the power market. That means Texas has to be mainly self-reliant and cannot depend on neighbors during extreme conditions. That vulnerability is a dramatic twist for a state that’s also the energy capital of the US, thanks to vast oil and natural gas producing fields. Favorable regulations are also driving a wind and solar boom in Texas. 

3. Why the worry? 

The summer of 2023 will mark the first time all of the state’s needs cannot be met by traditional power plants, like nuclear, coal and gas. A sign of potential trouble came on June 20 when state officials urged residents to conserve power because of low supplies from wind farms and unexpected closures of fossil-fuel generators amid supply-chain constraints that limited availability. As of late July, the grid was holding up, thanks to the help of renewable sources. Solar generation has been coming in close to expected summer capacity, or exceeding it on most days. This has helped offset the hours in the middle of the day when wind speeds died down in West Texas. 

4. Why didn’t the grid’s problems get fixed? 

There is no easy fix. The Texas system allows the price of electricity to swing to match supply and demand. That means high prices — and high profits — drive the development of new power plants. At times spot power prices have been as low as $20-$50 a megawatt-hour versus more than $4,000 during periods of stress. The limitation of this pricing structure was laid bare by the 2021 winter blackouts. Since then, state lawmakers have passed market reforms that require weatherization of critical infrastructure and changed rules to put more money in the pockets of the owners of power generation.  

5. What’s the big challenge? 

There’s a real clash going on over what the grid of the future should look like in Texas and across the country, especially as severe heat raises blackout risks nationally. The challenge is to make sure nuclear and fossil fuel plants that are needed right now don’t retire too early and still allow newer, cleaner technologies to flourish. Some conservative Republicans have blamed renewable energy for destabilizing the grid and have pushed for more fossil-fuel powered generators. Lawmakers passed a controversial $10 billion program providing low-interest loans and grants to build new gas-fired plants using taxpayer money, but Texans ultimately have to vote on the subsidy. 

6. Why do improvements take so long? 

Figuring out how to keep the lights on without overburdening consumers is becoming a greater challenge amid more extreme weather fueled by climate change. As such, changing the rules is often a hotly contested process pitting utilities, generators, manufacturers, electricity retailers and other groups against one another. The process became more politicized after the storm in 2021 with Republican Gov. Greg Abbott and lawmakers ordering Ercot to make changes. Building more transmission lines and connecting to other states can help, but such projects are typically tied up for years in red tape.

7. What can be done? 

The price cap for electricity was cut from $9,000/MWh to $5,000 to help avoid the punitive costs seen in the 2021 storm, though prices are allowed to spike more easily. Ercot is also contracting for more reserves to be online to help avoid supply shortfalls and improve reliability for customers, which added $1.7 billion in consumer costs alone last year. Another rule helps some gas generators pay for their fuel costs, while a more recent reform put in price floors when reserves fall to certain levels. Many power experts say that the easiest solution is to pay people to reduce their energy consumption during times of grid stress through so-called demand response programs. Factories, Bitcoin miners and other large users are already compensated to conserve during tight grid conditions.

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Israel Electricity Reform Competition opens the supply segment to private suppliers, challenges IEC price controls, and promises consumer choice, marginal discounts, and market liberalization amid natural gas generation and infrastructure remaining with IEC.

Key Points

Policy opening 40% of supply to private vendors, enabling consumer choice and small discounts while IEC retains the grid.

✅ 40% of retail supply opened to private electricity suppliers

✅ IEC keeps meters, lines; tariffs still regulated by the authority

✅ Expected discounts near 7%, not dramatic price cuts initially

"See the pseudo-reform in the electricity sector: no lower prices, no opening the market to competition, and no choice of electricity suppliers, with a high rate for consumers despite natural gas." This is an advertisement by the Private Power Producers Forum that is appearing everywhere: Facebook, the Internet, billboards, and the press.

Is it possible that the biggest reform in the economy with a cost estimated by Israel Electric Corporation (IEC) (TASE: ELEC.B22) at NIS 7 billion is really a pseudo-reform? In contrast to the assertions by the private electricity producers, who are supposedly worried about our wallets and want to bring down the cost of electricity for us, the reform will open a segment of electricity supply to competition, as agreed in the final discussions about the reform. No less than 40% of this segment will be removed from IEC's exclusive responsibility and pass to private hands.

This means that in the not-too-distant future, one million households in Israel will be able to choose between different electricity suppliers. IEC will retain the infrastructure, with its meter and power lines, but for the first time, the supplier who sends the monthly bill to our home can be a private concern.

Up until now, the only regulatory agency determining the electricity rate in Israel was the Public Utilities Authority (electricity), i.e. the state. Now, in the framework of the reform, as a result of opening the supply segment to competition, private electricity producers will be able to offer a lower rate than IEC's, with mechanisms like electricity auctions shown to cut costs in some markets, while IEC's rate will still be controlled by the Public Utilities Authority (electricity).

This situation differs from the situation in almost all European countries, where the electricity market is fully open to competition and the EU is pursuing an electricity market revamp to address pricing challenges, with no electricity price controls and free switching by consumers between electricity producers, just as in the mobile phone market. This measure has not lowered electricity prices in Europe, where rates are higher than in Israel, which is in the bottom third of OECD countries in its electricity rate.

Regardless of reports, supply will be opened to competition and we will be able to choose between electricity suppliers in the future. Are the private electricity producers nevertheless right when they say that the electricity sector will not be opened to "real competition"?

What is obviously necessary is for the private producers to offer a substantially lower rate than IEC in order to attract as many new customers as possible and win their trust. Can the private producers offer a significantly lower rate than IEC? The answer is no, at least not in the near future. The teams handling the negotiations are aware of this. "The private supplier's price will not be significantly cheaper than IEC's controlled price; there will be marginal discounts," a senior government source explains. "What is involved here is another electricity intermediary, so it will not contribute to competition and lowering the price," he added.

There are already private electricity producers supplying electricity to large business customers - factories, shopping malls, and so forth - at a 7% discount. The rest of the electricity that they produce is sold to the system manager. When supply is opened to competition, it can be assumed that the private suppliers will also be able to offer a similar discount to private consumers.

Will a 7% discount cause a home consumer to leave reliable and familiar IEC for a private producer, given evidence from retail electricity competition in other markets? This is hard to know.

#google#

Why cannot private electricity producers offer a larger discount that will really break the monopoly, as their advertisement says they want to do? Chen Herzog, chief economist and partner at BDO Consulting, which is advising the Private Power Producers Forum, says, "Competition in supply requires the construction of competitive power plants that can compete and offer cheaper electricity.

"The power plants that IEC will sell in the reform, which will go on selling electricity to IEC, are outmoded, inefficient, and non-competitive. In addition, the producer will have to continue employing IEC workers in the purchased plants for at least five years. The producer will generate electricity in IEC power stations with IEC employees and additional overhead of a private producer, with factors such as cost allocation further shaping end-user rates. This amounts to being an IEC subcontractor in production. There is no saving on costs, so there will be no surplus to deduct from the consumer price," he adds.

The idea of opening supply to electricity market competition on such a large scale sounds promising, but saving on electricity for consumers still looks a long way off.

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EDP Takeover Bid Rejection signals pushback on China Three Gorges' acquisition bid, as investors, shareholders, and analysts cite low premium, valuation concerns, and strategic renewables assets across Portugal, the US, Brazil, and Europe utilities.

Key Points

EDP's board views China Three Gorges' 3.26 euro per share offer as too low, citing valuation and renewables exposure.

✅ Bid premium 4.8% above close seen as inadequate.

✅ Stock surged above offer; market expects higher price.

✅ Advisors UBS and Morgan Stanley guiding EDP.

EDP-Energias de Portugal SA is poised to reject a 9.1 billion euro ($10.9 billion) takeover offer from China Three Gorges Corp. on the grounds that it undervalues Portugal’s biggest energy company, according to people with knowledge of the matter.

The board of EDP, which may meet as early as this week, views the current bid of 3.26 euros a share as too low as it indicates a premium of 4.8 percent over Friday’s close, said the people, asking not to be identified because the discussions are private. EDP is also working with advisers including UBS Group AG and Morgan Stanley on the potential deal, they said.

Representatives for EDP, UBS and Morgan Stanley declined to comment. Representatives for Three Gorges didn’t immediately respond to requests for comment.

#google#

Shares of EDP surged the most in a decade to above the bid level on Monday, signaling that investors expect the Chinese utility, which is its biggest investor, to sweeten the offer to gain full control. For Three Gorges, which spent two decades building a hydro-power plant spanning China’s Yangtze River, the deal would bolster its efforts to expand abroad and give it deeper access to markets in Europe, the U.S. and Brazil.

China’s biggest renewable-energy developer already is the largest shareholder of EDP with a 23 percent stake and now is seeking more than 50 percent. While the government in Lisbon has indicated it’s comfortable with the Chinese offer, EDF electricity price deal illustrates policy dynamics in the region and it holds out little incentive for shareholders to tender their stock.

Stock Jumps

Shares of EDP rose 9.3 percent to 3.40 euros in Lisbon on Monday, even as rolling back European electricity prices remains challenging, after earlier jumping by the most since October 2008.

“We believe the price offered is too low for China Three Gorges to achieve full control of a vehicle that provides, among other things, a strategic footprint into U.S. renewables,” Javier Garrido, an analyst at JPMorgan Chase & Co., said in a note. “We expect management and minorities to claim a higher price.”

The offer adds to a wave of investments China has made overseas, both to earn a yield on its cash and to gain expertise in industries ranging from energy to telecommunications and transport. Concern about those deals has been mounting in the U.S. regulatory arena recently. European Union governments have been divided in their response, with Portugal among those most supportive of inward investment.

“China Three Gorges is an ambitious company, with expansion already in international hydro, Chinese onshore wind and floating solar, and European offshore wind,” said Angus McCrone, a senior analyst at Bloomberg New Energy Finance in London. “It may have to do better on bid price than the 5 percent premium so far offered for EDP.”

Fortum’s Troubles

The low premium offered by Three Gorges echoes the struggle Fortum Oyj had in winning over investors in its bid for Uniper SE last year, while North American deals such as Hydro One’s Avista bid faced customer backlash as well, highlighting parallels. The Finnish utility offered 8 billion euros to buy out the remainder of Uniper in September, immediately sending shares of the German power generator above the offer prices. At least for now, Fortum has settled for a 47 percent stake it bought in Uniper from EON SE, and most other shareholders decided to keep their stake.

The EDP transaction would advance a wave of consolidation among Europe’s leading utilities, which are acquiring assets and development skills in renewables as governments across the region crack down on pollution. EDP is one of Europe’s leading developers of renewable energy, building mainly wind farms and hydro plants, and has expanded in markets including Brazil and the U.S. electrification market.

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Canada Electrification Costs: report estimates $580B-$1.4T to scale renewable energy, wind, solar, and storage capacity to 2050, shifting from natural gas toward net-zero emissions and raising average household energy spending by $1,300-$3,200 annually.

Key Points

Projected national expense to expand renewables and electrify energy systems by 2050, impacting household energy bills.

✅ $580B-$1.4T forecast for 2020-2050 energy transition

✅ 278-422 GW wind, solar, storage capacity by 2050

✅ Household costs up $1,300-$3,200 per year on average

The Canadian Gas Association says building renewable electricity capacity to replace just half of Canada's current fossil fuel-generated energy, a shift with significant policy implications for grids across provinces, could increase national costs by as much as $1.4 trillion over the next 30 years.

In a report, it contends, echoing an IEA report on net-zero, that growing electricity's contribution to Canada's energy mix from its current 19 per cent to about 60 per cent, a step critical to meeting climate pledges that policymakers emphasize, will require an expansion from 141 gigawatts today to between 278 and 422 GW of renewable wind, solar and storage capacity by 2050.

It says that will increase national energy costs by between $580 billion and $1.4 trillion between 2020 and 2050, a projection consistent with recent reports of higher electricity prices in Alberta amid policy shifts, translating into an average increase in Canadian household spending of $1,300 to $3,200 per year.

The study, prepared by consulting firm ICF for the association, assumes electrification begins in 2020 and is applied in all feasible applications by 2050, with investments in the electricity system, guided by the implications of decarbonizing the grid for reliability and cost, proceeding as existing natural gas and electric end use equipment reaches normal end of life.

Association CEO Tim Egan says the numbers are "pretty daunting" and support the integration of natural gas with electric, amid Canada's race to net-zero commitments, instead of using an electric-only option as the most cost-efficient way for Canada to reach environmental policy goals.

But Keith Stewart, senior energy strategist with Greenpeace Canada, says scientists are calling for the world to get to net-zero emissions by 2050, and Canada's net-zero by 2050 target underscores that urgency to avoid "catastrophic" levels of warming, so investing in natural gas infrastructure to then shut it down seems a "very expensive option."

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US Electricity Demand Outlook examines EIA forecasts, GDP decoupling, energy efficiency, electrification, electric vehicles, grid load growth, and weather variability to frame long term demand trends and utility planning scenarios.

Key Points

An analysis of EIA projections showing demand decoupling from GDP, with EV adoption and efficiency shaping future grid load.

✅ EIA lowers load growth; demand decouples from GDP.

✅ Efficiency and sector shifts depress kWh sales.

✅ EV adoption could revive load and capacity needs.

Electricity producers and distributors are in an unusual business. The product they provide is available to all customers instantaneously, literally at the flip of a switch. But the large amount of equipment, both hardware and software to do this takes years to design, site and install.

From a long range planning perspective, just as important as a good engineering design is an accurate sales projections. For the US electric utility industry the most authoritative electricity demand projec-tions come from the Department of Energy’s Energy Information Administration (EIA). EIA's compre-hensive reports combine econometric analysis with judgment calls on social and economic trends like the adoption rate of new technologies that could affect future electricity demand, things like LED light-ing and battery powered cars, and the rise of renewables overtaking coal in generation.

Before the Great Recession almost a decade ago, the EIA projected annual growth in US electricity production at roughly 1.5 percent per year. After the Great Recession began, the EIA lowered its projections of US electricity consumption growth to below 1 percent. Actual growth has been closer to zero. While the EIA did not antici-pate the last recession or its aftermath, we cannot fault them on that.

After the event, though, the EIA also trimmed its estimates of economic growth. For the 2015-2030 period it now predicts 2.1 percent economic and 0.3 percent electricity growth, down from previously projections of 2.7 percent and 1.3 percent respectively. (See Figures 1 and 2.)

Table 1. EIA electric generation projections by year of forecast (kWh billions)

Table 2. EIA forecast of GDP by year of forecast (billion 2009 $)

Back in 2007, the EIA figured that every one percent increase in economic activity required a 0.48 percent in-crease in electric generation to support it. By 2017, the EIA calculated that a 1 percent growth in economic activity now only required a 0.14 percent increase in electric output. What accounts for such a downgrade or disconnect between electricity usage and economic growth? And what factors might turn the numbers 
around?

First, the US economy lost energy intensive heavy industry like smelting, steel mills and refineries; patterns in China's electricity sector highlight how industrial shifts can reshape power demand. A more service oriented economy (think health care) relies more heavily on the movement of data or information and uses far less power than a manufacturing-oriented economy.

A small volcano in Argentina is about to fuel the next tech boom – and a little known company is going to be right at the center. Early investors stand to gain incredible profits and you can too. Read the report.

Second, internet shopping has hurt so-called "brick and mortar" retailers. Despite the departure of heavy industry, in years past a burgeoning US commercial sector increased its demand and usage of electricity to offset the industrial decline. But not anymore. Energy efficiency measures as well as per-haps greater concern about global warming and greenhouse gas emissions and have cut into electricity sales. “Do more with less” has the right ring to it.

But there may be other components to the ongoing decline in electricity usage. Academic studies show that electricity usage seems to increase with income along an S curve, and flattens out after a certain income level. That is, if you earn $1 billion per year you do not (or cannot) use ten times a much electricity as someone earning only $100 million.

But people at typical, middle income levels increase or decrease electricity usage when incomes rise or fall. The squeeze on middle income families was discussed often in the late presidential campaign. In recent decades an increasing percentage of income has gone to a small percentage of the population at the top of the income scale. This trend probably accounts for some weakness in residential sales. This suggests that government policy addressing income inequality would also boost electricity sales.

Population growth affects demand for electricity as well as the economy as a whole. The EIA has made few changes in its projections, showing 0.7 percent per year population growth in 2015- 2030 in both the 2007 and 2017 forecasts. Recent studies, however, have shown a drop in the birth rate to record lows. More troubling, from a national health perspective is that the average age of death may have stopped rising. Those two factors point to lower population growth, especially if the government also restricts immi-gration. Thus, the US may be approaching a period of rather modest population growth.

All of the above factors point to minimal sales growth for electricity producers in the US--perhaps even lower than the seemingly conservative EIA estimates. But the cloud on the horizon has a silver lining in the shape of an electric car. Both the United Kingdom and France have set dates to end of production of automobiles with internal combustion engines. Several European car makers have declared that 20 percent of their output will be electric vehicles by the early 2020s. If we adopt automobiles powered by electricity and not gasoline or diesel, electricity sales would increase by one third. For the power indus-try, electric vehicles represent the next big thing.

We don’t pretend to know how electric car sales will progress. But assume vehicle turnover rates re-main at the current 7 percent per year and electric cars account for 5 percent of sales in the first five years (as op-posed to 1 percent now), 20 percent in the next five years and 50 percent in the third five year period. Wildly optimistic assumptions? Maybe. By 2030, electric cars would constitute 28 percent of the vehicle fleet. They would add about 10 percent to kilowatt hour sales by that date, assuming that battery efficiencies do not improved by then. Those added sales would require increased electric generation output, with low-emissions sources expected to cover almost all the growth globally. They would also raise long term growth rates for 2015-2030 from the present 0.3 percent to 1.0 percent. The slow upturn in demand should give the electric companies time to gear up so to speak.

In the meantime, weather will continue to play a big role in electricity consumption. Record heat-induced demand peaks are being set here in the US even as surging global demand puts power systems under strain worldwide.

Can we discern a pattern in weather conditions 15 years out? Maybe we can, but that is one topic we don’t expect a government agency to tackle in public right now. Meantime, weather will affect sales more than anything else and we cannot predict the weather. Or can we?

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BC Energy Debate: Nuclear Power and LNG divides British Columbia, as a new survey weighs zero-emission clean energy, hydroelectric capacity, the Site C dam, EV mandates, energy security, rising costs, and blackout risks.

Key Points

A BC-wide debate on power choices balancing nuclear, LNG, hydro, costs, climate goals, EVs, and grid reliability.

✅ Survey: 43% support nuclear, 40% oppose in BC

✅ 55% back LNG expansion, led by Southern BC

✅ Hydro at 90%; Site C adds 1,100 MW by 2025

There is a long-term need to produce more electricity to meet population and economic growth needs and, in particular, create new clean energy sources, with two new BC generating stations recently commissioned contributing to capacity.

Increasingly, in the worldwide discourse on climate change, nuclear power plants are being touted as a zero-emission clean energy source, with Ontario exploring large-scale nuclear to expand capacity, and a key solution towards meeting reduced emissions goals. New technological advancements could make nuclear power far safer than existing plant designs.

When queried on whether British Columbia should support nuclear power for electricity generation, respondents in a new province-wide survey by Research Co. were split, with 43% in favour and 40% against.

Levels of support reached 46% in Metro Vancouver, 41% in the Fraser Valley, 44% in Southern BC, 39% in Northern BC, and 36% on Vancouver Island.

The closest nuclear power plant to BC is the Columbia Generating Station, located in southern Washington State.

The safe use of nuclear power came to the forefront following the 2011 Fukushima nuclear disaster when the most powerful earthquake ever recorded in Japan triggered a large tsunami that damaged the plant’s emergency generators. Japan subsequently shut off many of its nuclear power plants and increased its reliance on fossil fuel imports, but in recent years there has been a policy reversal to restart shuttered nuclear plants to provide the nation with improved energy security.

Over the past decade, Germany has also been undergoing a transition away from nuclear power. But in an effort to replace Russian natural gas, Germany is now using more coal for power generation than ever before in decades, while Ontario’s electricity outlook suggests a shift to a dirtier mix, and it is looking to expand its use of liquefied natural gas (LNG).

Last summer, German chancellor Olaf Scholz told the CBC he wants Canada to increase its shipments of LNG gas to Europe. LNG, which is greener compared to coal and oil, is generally seen as a transitionary fuel source for parts of the world that currently depend on heavy polluting fuels for power generation.

When the Research Co. survey asked BC residents whether they support the further development of the province’s LNG industry, including LNG electricity demand that BC Hydro says justifies Site C, 55% of respondents were supportive, while 29% were opposed and 17% undecided.

Support for the expansion of the LNG is highest in Southern BC (67%), followed by the Fraser Valley (56%), Metro Vancouver (also 56%), Northern BC (55%), and Vancouver Island (41%).

A larger proportion of BC residents are against any idea of the provincial government moving to ban the use of natural gas for stoves and heating in new buildings, with 45% opposed and 39% in support.

Significant majorities of BC residents are concerned that energy costs could become too expensive, and a report on coal phase-outs underscores potential cost and effectiveness concerns, with 84% expressing concern for residents and 66% for businesses. As well, 70% are concerned that energy shortages could lead to measures such as rationing and rolling blackouts.

Currently, about 90% of BC’s electricity is produced by hydroelectric dams, but this fluctuates throughout the year — at times, BC imports coal- and gas-generated power from the United States when hydro output is low.

According to BC Hydro’s five-year electrification plan released in September 2021, it is estimated BC has a sufficient supply of clean electricity only by 2030, including the capacity of the Site C dam, which is slated to open in 2025. The $16 billion dam will have an output capacity of 1,100 megawatts or enough power for the equivalent of 450,000 homes.

The provincial government’s strategy for pushing vehicles towards becoming dependent on the electrical grid also necessitates a reliable supply of power, prompting BC Hydro’s first call for power in 15 years to prepare for electrification. Most BC residents support the provincial government’s requirement for all new car and passenger truck sales to be zero-emission by 2035, with 75% supporting the goal and 21% opposed.
 

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