Wind farmer REG grows by remaining small

By The Daily Mail


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Wind farms arouse mixed emotions. For environmentalists and politicians, they are unquestionably beneficial. They use what is freely available — wind — to generate something that everybody needs — electricity. But for many ordinary people, wind turbines are a blot on the landscape to be avoided at all costs.

The widespread antipathy towards wind farms, particularly large ones, has been a major setback for the industry in this country. Planning permission is costly and time-consuming to obtain and is frequently refused. Over the past year or so, developers have also been hit by falling wholesale electricity prices, which makes the energy they produce or hope to produce less valuable. Meanwhile, a scarcity of credit has mad it difficult for them to fund their businesses.

In this context, Renewable Energy Generation (REG) stands out from the pack. The company focuses on small developments of just a few turbines. These are easier to finance and tend to receive planning permission at a slightly speedier rate.

The company is already operating several small wind farms that generate 21 megawatts of electricity in total - enough to power about 10,000 homes - and it has received approval for developments that will give it a further 15 megawatts of capacity.

There is also a string of projects in the pipeline that could, if approved, add a further 300 megawatts of capacity to Renewable Energy's portfolio.

Separately, the company operates a business that turns used cooking oil into electricity. The division expects that by the end of 2010 it will have the ability to generate 13 megawatts of electricity this way.

More immediately, Renewable chief executive Andrew Whalley has just agreed to sell the company's Canadian subsidiary to International Power Canada for £69 million. The deal needs the approval of shareholders, but they are highly likely to agree to it because the transaction will enable Renewable to pay off all its debts and leave about £50 million in the bank.

Whalley intends to use the money to develop the wind farms and the cooking oil division, focusing the company entirely on the UK, rather than splitting his time between here and Canada.

Today, REG shares are trading at 60p, making the company worth £60 million on the stock market — a substantial discount to the value of its assets.

Unusually for a business of this nature, there is even an annual dividend. Last year, Whalley paid out 0.5p and he has committed to pay a dividend for 2009 as well. The shares are undervalued. Buy.

Brokers estimate that the farms that REG already runs are worth £30 million while those it intends to construct in the next few months are valued, even now, at about £13 million. Add in the £50 million-of cash that the company will have once the Canadian sale is completed and REG is worth some £93 million, even without ascribing any value to the oil business or the sites for which REG hopes to receive planning permission.

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Ontario Extends Off-Peak Electricity Rates to Provide Relief for Families, Small Businesses and Farms

Ontario Off-Peak Electricity Rate Relief extends 8.5 cents/kWh pricing 24/7 for residential, small business, and farm customers, covering Time-Of-Use and tiered plans to stabilize utility bills during COVID-19 Stay-at-Home measures across Ontario.

 

Key Points

A province-wide 8.5 cents/kWh price applied 24/7 until Feb 22, 2021 for TOU and tiered users to reduce electricity bills

✅ 8.5 cents/kWh, applied 24/7 through Feb 22, 2021

✅ Available to TOU and tiered OEB-regulated customers

✅ Automatic on bills for homes, small businesses, farms

 

The Ontario government is once again extending electricity rate relief for families, small businesses and farms to support those spending more time at home while the province maintains the Stay-at-Home Order in the majority of public health regions. The government will continue to hold electricity prices to the off-peak rate of 8.5 cents per kilowatt-hour, compared with higher peak rates elsewhere in the day, until February 22, 2021. This lower rate is available 24 hours per day, seven days a week for Time-Of-Use and tiered customers.

"We know staying at home means using more electricity during the day when electricity prices are higher, that's why we are once again extending the off-peak electricity rate to provide households, small businesses and farms with stable and predictable electricity bills when they need it most," said Greg Rickford, Minister of Energy, Northern Development and Mines, Minister of Indigenous Affairs. "We thank Ontarians for continuing to follow regional Stay-at-Home orders to help stop the spread of COVID-19."

The off-peak rate came into effect January 1, 2021, providing families, farms and small businesses with immediate electricity rate relief, and for industrial and commercial companies, stable pricing initiatives have provided additional certainty. The off-peak rate will now be extended until the end of day February 22, 2021, for a total of 53 days of emergency rate relief. During this period, and alongside temporary disconnect moratoriums for residential customers, the off-peak price will continue to be automatically applied to electricity bills of all residential, small business, and farm customers who pay regulated rates set by the Ontario Energy Board and get a bill from a utility.

"We extend our thanks to the Ontario Energy Board and local distribution companies across the province, including Hydro One, for implementing this extended emergency rate relief and supporting Ontarians as they continue to work and learn from home," said Bill Walker, Associate Minister of Energy.

 

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The Need for Electricity During the COVID-19 Pandemic

US utilities COVID-19 resilience shows electric utilities maintaining demand stability, reaffirming earnings guidance, and accessing the bond market for low-cost financing, as Dominion, NextEra, and Con Edison manage recession risks.

 

Key Points

It is the sector's capacity to sustain demand, financing access, and guidance despite pandemic recession pressures.

✅ Bond market access locks in low-cost, long-term debt

✅ Stable residential load offsets industrial weakness

✅ Guidance largely reaffirmed by major utilities

 

Dominion Energy (D) expects "incremental residential load" gains, consistent with COVID-19 electricity demand patterns, as a result of COVID-19 fallout. Southern Company CEO Tom Fanning says his company is "nowhere near" a need to review earnings guidance because of a potential recession, in a region where efficiency and demand response can help level electricity demand for years.

Sempra Energy (SRE) has reaffirmed earnings per share guidance for 2020 and 2021, as well timing for the sale of assets in Chile and Peru, and peers such as Duke Energy's renewables plan have reaffirmed capital investments to deliver cleaner energy and economic growth. And Xcel Energy (XEL) says it still "hasn’t seen material impact on its business."

Several electric utilities have demonstrated ability to tap the bond market, in line with utility sector trends in recent years, to lock in low-cost financing, as America moves toward broader electrification, despite ongoing turmoil. Their ranks include Dominion Energy, renewable energy leader NextEra Energy (NEE) and Consolidated Edison (ED), which last week sold $1 billion of 30-year bonds at a coupon rate of just 3.95 percent.

It’s still early days for US COVID-19 fallout. And most electric companies have yet to issue guidance. That’s understandable, since so much is still unknown about the virus and the damage it will ultimately do to human health and the global economy. But so far, the US power industry is showing typical resilience in tough times, as it coordinates closely with federal partners to maintain reliability.

Will it last? We won’t know for certain until there’s a lot more data. NextEra is usually first to report its Q1 earnings reports and detailed guidance. But that’s not expected until April 23. And companies may delay financials further, should the virus and efforts to control it impede collection and analysis of data, and as they address electricity shut-off risks affecting customers.

 

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Salmon and electricity at center of Columbia River treaty negotiations

Columbia River Treaty Negotiations involve Canada-U.S. talks on B.C. dams, flood control, hydropower sharing, and downstream benefits, prioritizing ecosystem health, First Nations rights, and salmon restoration while balancing affordable electricity for northwest consumers.

 

Key Points

Talks to update flood control, hydropower, and ecosystem terms for fair benefits to B.C. and U.S. communities.

✅ Public consultations across B.C.'s Columbia Basin

✅ First Nations priorities include salmon restoration

✅ U.S. seeks cheaper power; B.C. defends downstream benefits

 

With talks underway between Canada and the U.S. on the future of the Columbia River Treaty, the B.C. New Democrats have launched public consultations in the region most affected by the high-stakes negotiation.

“We want to ensure Columbia basin communities are consulted, kept informed and have their voices heard,” said provincial cabinet minister Katrine Conroy via a press release announcing meetings this month in Castlegar, Golden, Revelstoke, Nakusp, Nelson and other communities.

As well as having cabinet responsibility for the talks, Conroy’s Kootenay West riding includes several places that were inundated under the terms of the 1964 flood control and power generation treaty.

“We will continue to work closely with First Nations affected by the treaty, to ensure Indigenous interests are reflected in the negotiations,” she added by way of consolation to Indigenous people who’ve been excluded from the negotiating teams on both sides of the border.

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The stakes are also significant for the province as a whole. The basics of the treaty saw B.C. build dams to store water on this side of the border, easing the flood risk in the U.S. and allowing the flow to be evened out through the year. In exchange, B.C. was entitled to a share of the additional hydro power that could be generated in dams on the U.S. side.

B.C.’s sale of those downstream benefits to the U.S has poured almost $1.4 billion into provincial coffers over the past 10 years, albeit at a declining rate these days amid scrutiny from a regulator report on BC Hydro that raised concerns, because of depressed prices for cross-border electricity sales.

Politicians on the U.S. side have long sought to reopen the treaty, believing there was now a case for reducing B.C.’s entitlement.

They did not get across the threshold under President Barack Obama.

Then, last fall his successor Donald Trump served notice of intent, initiating the formal negotiations that commenced with a two day session last week in Washington, D.C. The next round is set for mid-August in B.C.

American objectives in the talks include “continued, careful management of flood risk; ensuring a reliable and economical power supply; and better addressing ecosystem concerns,” with recognition of recent BC Hydro demand declines during the pandemic.

“Economical power supply,” being a diplomatic euphemism for “cheaper electricity for consumers in the northwest states,” achievable by clawing back most of B.C.’s treaty entitlement.

On taking office last summer, the NDP inherited a 14-point statement of principles setting out B.C. hopes for negotiations to “continue the treaty” while “seeking improvements within the existing framework” of the 54-year-old agreement.

The New Democrats have endorsed those principles in a spirit of bipartisanship, even as Manitoba Hydro governance disputes play out elsewhere in Canada.

“Those principles were developed with consultation from throughout the region,” as Conroy advised the legislature this spring. “So I was involved, as well, in the process and knew what the issues were, right as they would come up.”

The New Democrats did chose to put additional emphasis on some concerns.

“There is an increase in discussion with Canada and First Nations on the return of salmon to the river,” she advised the house, recalling how construction of the enormous Grand Coulee Dam on the U.S. side in the 1930s wiped out salmon runs on the upper Columbia River.

“There was no consideration then for how incredibly important salmon was, especially to the First Nations people in our region. We have an advisory table that is made up of Indigenous representation from our region, and also we are discussing with Canada that we need to see if there’s feasibility here.”

As to feasibility, the obstacles to salmon migration in the upper reaches of the Columbia include the 168-metre high Grand Coulee and the 72-metre Chief Joseph dams on the U.S. side, plus the Keenleyside (52 metres), Revelstoke (175 metres) and Mica (240 metres) dams on the Canadian side.

Still, says Conroy “the First Nations from Canada and the tribes from the United States, have been working on scientific and technical documents and research to see if, first of all, the salmon can come up, how they can come up, and what the things are that have to be done to ensure that happens.”

The New Democrats also put more emphasis on preserving the ecosystem, aligning with clean-energy efforts with First Nations that support regional sustainability.

“I know that certainly didn’t happen in 1964, but that is something that’s very much on the minds of people in the Columbia basin,” said Conroy. “If we are going to tweak the treaty, what can we do to make sure the voices of the basin are heard and that things that were under no consideration in the ’60s are now a topic for consideration?”

With those new considerations, there’s still the status quo concern of preserving the downstream benefits as a trade off for the flooding and other impacts on this side of the border.

The B.C. position on that score is the same under the New Democrats as it was under the Liberals, despite a B.C. auditor general report on deferred BC Hydro costs.

“The level of benefits to B.C., which is currently solely in the form of the (electricity) entitlement, does not account for the full range of benefits in the U.S. or the impacts in B.C.,” says the statement of principle.

“All downstream U.S. benefits such as flood risk management, hydropower, ecosystems, water supply (including municipal, industrial and agricultural uses), recreation, navigation and other related benefits should be accounted for and such value created should be shared equitably between the two countries.”

No surprise if the Americans do not see it the same way.  But that is a topic for another day.

 

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Aging U.S. power grid threatens progress on renewables, EVs

U.S. Grid Modernization is critical for renewable energy integration, EV adoption, climate resilience, and reliability, requiring transmission upgrades, inter-regional links, hardened substations, and smart grid investments to handle extreme weather and decarbonization targets.

 

Key Points

U.S. Grid Modernization upgrades power networks to improve reliability, integrate renewables, and support EV demand.

✅ $2T+ investment needed for transmission upgrades

✅ Extreme weather doubling outages since 2017

✅ Regulatory fragmentation slows inter-regional lines

 

After decades of struggle, the U.S. clean-energy business is booming, with soaring electric-car sales and fast growth in wind and solar power. That’s raising hopes for the fight against climate change.

All this progress, however, could be derailed, as the green revolution stalls without a massive overhaul of America’s antiquated electric infrastructure – a task some industry experts say requires more than $2 trillion. The current network of transmission wires, substations and transformers is decaying with age and underinvestment, a condition highlighted by catastrophic failures during increasingly frequent and severe weather events.

Power outages over the last six years have more than doubled in number compared to the previous six years, according to a Reuters examination of federal data. In the past two years, power systems have collapsed in Gulf Coast hurricanes, West Coast wildfires, Midwest heat waves and a Texas deep freeze and recurring Texas grid crisis risks, causing long and sometimes deadly outages.

Compounding the problem, the seven regional grid operators in the United States are underestimating the growing threat of severe weather caused by climate change, Reuters found in a review of more than 10,000 pages of regulatory documents and operators’ public disclosures. Their risk models, used to guide transmission-network investments, consider historical weather patterns extending as far back as the 1970s. None account for scientific research documenting today’s more extreme weather and how it can disrupt grid generation, transmission and fuel supplies simultaneously.

The decrepit power infrastructure of the world’s largest economy is among the biggest obstacles to expanding clean energy and combating climate change on the ambitious schedule laid out by U.S. President Joe Biden. His administration promises to eliminate or offset carbon emissions from the power sector by 2035 and from the entire U.S. economy by 2050. Such rapid clean-energy growth would pressure the nation’s grid in two ways: Widespread EV adoption will spark a huge surge in power demand; and increasing dependence on renewable power creates reliability problems on days with less sun or wind, as seen in Texas, where experts have outlined reliability improvements that address these challenges.

The U.S. transmission network has seen outages double in recent years amid more frequent and severe weather events, driven by climate change and a utility supply-chain crunch that slows critical repairs. The system needs a massive upgrade to handle expected growth in clean energy and electric cars. 

“Competition from renewables is being strangled without adequate and necessary upgrades to the transmission network,” said Simon Mahan, executive director of the Southern Renewable Energy Association, which represents solar and wind companies.

The federal government, however, lacks the authority to push through the massive grid expansion and modernization needed to withstand wilder weather and accommodate EVs and renewable power. Under the current regulatory regime, and amid contentious electricity pricing proposals in recent years, the needed infrastructure investments are instead controlled by a Byzantine web of local, state and regional regulators who have strong political incentives to hold down spending, according to Reuters interviews with grid operators, federal and state regulators, and executives from utilities and construction firms.

“Competition from renewables is being strangled without adequate and necessary upgrades to the transmission network.”

Paying for major grid upgrades would require these regulators to sign off on rate increases likely to spark strong opposition from consumers and local and state politicians, who are keen to keep utility bills low. In addition, utility companies often fight investments in transmission-network improvements because they can result in new connections to other regional grids that could allow rival companies to compete on their turf, even as coal and nuclear disruptions raise brownout risks in some regions. With the advance of green energy, those inter-regional connections will become ever more essential to move power from far-flung solar and wind installations to population centers.

The power-sharing among states and regions with often conflicting interests makes it extremely challenging to coordinate any national strategy to modernize the grid, said Alison Silverstein, an independent industry consultant and former senior adviser to the U.S. Federal Energy Regulatory Commission (FERC).

“The politics are a freakin’ nightmare,” she said.

The FERC declined to comment for this story. FERC Commissioner Mark Christie, a Republican, acknowledged the limitations of the agency’s power over the U.S. grid in an April 21 agency meeting involving transmission planning and costs.

“We can’t force states to do anything,” Christie said.

The White House and Energy Department did not comment in response to detailed questions from Reuters on the Biden administration’s plans to tackle U.S. grid problems and their impact on green-energy expansion.

The administration said in an April news release that it plans to offer $2.5 billion in grants for grid-modernization projects as part of Biden’s $1 trillion infrastructure package, complementing a proposed clean electricity standard to accelerate decarbonization over the next decade. A modernized grid, the release said, is the “linchpin” of Biden’s clean-energy agenda.

 

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First Reactor Installed at the UK’s Latest Nuclear Power Station

Hinkley Point C Reactor Installation signals UK energy security, nuclear power expansion, and low-carbon baseload, featuring EPR technology in Somerset to cut emissions, support net-zero goals, and deliver reliable electricity for homes and businesses.

 

Key Points

First EPR unit fitted at Hinkley Point C, boosting low-carbon baseload, grid reliability, and UK energy security.

✅ Generates 3.2 GW across two EPRs for 7% of UK electricity.

✅ Provides low-carbon baseload to complement wind and solar.

✅ Creates jobs and strengthens supply chains during construction.

 

The United Kingdom has made a significant stride toward securing its energy future with the installation of the first reactor at its newest nuclear power station. This development marks an important milestone in the nation’s efforts to combat climate change, reduce carbon emissions, and ensure a stable and sustainable energy supply. As the world moves towards greener alternatives to fossil fuels, nuclear power remains a key part of the UK's green industrial revolution and low-carbon energy strategy.

The new power station, located at Hinkley Point C in Somerset, is set to be one of the most advanced nuclear facilities in the country. The installation of its reactor represents a crucial step in the construction of the plant, with earlier milestones like the reactor roof lifted into place underscoring steady progress, which is expected to provide reliable, low-carbon electricity for millions of homes and businesses across the UK. The completion of the first reactor is seen as a pivotal moment in the journey to bring the station online, with the second reactor expected to follow shortly after.

A Historic Milestone

Hinkley Point C will be the UK’s first nuclear power station built in over two decades. The plant, once fully operational, will play a key role in the country's energy transition. The reactors at Hinkley Point C are designed to be state-of-the-art, using advanced technology that is both safer and more efficient than older nuclear reactors. Each of the two reactors will have the capacity to generate 1.6 gigawatts of electricity, enough to power approximately six million homes. Together, they will contribute about 7% of the UK’s electricity needs, providing a steady, reliable source of energy even during periods of high demand.

The installation of the first reactor at Hinkley Point C is not just a technical achievement; it is also symbolic of the UK’s commitment to energy security and its goal to achieve net-zero carbon emissions by 2050, a target that industry leaders say multiple new stations will be needed to meet effectively. Nuclear power is a crucial part of this equation, as it provides a stable, baseload source of energy that does not rely on weather conditions, unlike wind or solar power.

Boosting the UK’s Energy Capacity

The addition of Hinkley Point C to the UK’s energy infrastructure is expected to significantly boost the country’s energy capacity and reduce its reliance on fossil fuels. The UK government has been focused on increasing the share of renewable energy in its mix, and nuclear power is seen as an essential complement to intermittent renewable sources, especially as wind and solar have surpassed nuclear in generation at times. Nuclear energy is considered a low-carbon, reliable energy source that can fill the gaps when renewable generation is insufficient, such as on cloudy or calm days when solar and wind energy output may be low.

With the aging of the UK’s existing nuclear fleet and the gradual phase-out of coal-fired power plants, Hinkley Point C will help ensure that the country does not face an energy shortage as it transitions to cleaner energy sources. The plant will help to bridge the gap between the current energy infrastructure and the future, enabling the UK to phase out coal while maintaining a steady, low-carbon energy supply.

Safety and Technological Innovation

The reactors at Hinkley Point C are being constructed using the latest in nuclear technology. They are based on the European Pressurized Reactor (EPR) design, which is known for its enhanced safety features and efficiency, and has been deployed in projects within China's nuclear program as well, making it a proven platform. These reactors are designed to withstand extreme conditions, including earthquakes and flooding, making them highly resilient. Additionally, the EPR technology ensures that the reactors have a low environmental impact, producing minimal waste and offering the potential for increased sustainability compared to older reactor designs.

One of the key innovations in the Hinkley Point C reactors is their advanced cooling system, which is designed to be more efficient and environmentally friendly than previous generations. This system ensures that the reactors operate at optimal temperatures while minimizing the environmental footprint of the plant.

Economic and Job Creation Benefits

The construction of Hinkley Point C has already provided a significant boost to the local economy. Thousands of jobs have been created, not only in the construction phase but also in the ongoing operation and maintenance of the facility. The plant is expected to create more than 25,000 jobs during its construction and around 900 permanent jobs once it is operational.

The project is also expected to have a positive impact on the wider UK economy. As a major infrastructure project, Hinkley Point C will provide long-term economic benefits, including boosting supply chains and providing opportunities for local businesses.

Challenges and the Road Ahead

Despite the progress, the construction of Hinkley Point C has not been without its challenges. The project has faced delays and cost overruns, with setbacks at Hinkley Point C documented by industry observers, and the total estimated cost now standing at around £22 billion. However, the successful installation of the first reactor is a step toward overcoming these hurdles and completing the project on schedule.

Looking ahead, Hinkley Point C’s successful operation could pave the way for future nuclear developments in the UK, including next-gen nuclear designs that aim to be smaller, cheaper, and safer. As the world grapples with the pressing need to reduce greenhouse gas emissions, nuclear energy may play an even more critical role in ensuring a clean, reliable energy future.

The installation of the first reactor at Hinkley Point C marks a crucial moment in the UK’s energy journey. As the country seeks to meet its carbon reduction targets and bolster its energy security, the new nuclear power station will be a cornerstone of its efforts. With its advanced technology, safety features, and potential to provide low-carbon energy for decades to come, Hinkley Point C offers a glimpse into the future of energy production in the UK and beyond.

 

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Fixing California's electric grid is like repairing a car while driving

CAISO Clean Energy Transition outlines California's path to 100% carbon-free power by 2045, scaling renewables, battery storage, and offshore wind while safeguarding grid reliability, managing natural gas, and leveraging Western markets like EDAM.

 

Key Points

CAISO Clean Energy Transition is the plan to reach 100% carbon-free power by 2045 while maintaining grid reliability.

✅ Target: add 7 GW/year to reach 120 GW capacity by 2045

✅ Battery storage up 30x; smooths intermittent solar and wind

✅ EDAM and WEIM enhance imports, savings, and reliability

 

Mark Rothleder, Chief Operating Officer and Senior Vice President at the California Independent System Operator (CAISO), which manages roughly 80% of California’s electric grid, has expressed cautious optimism about meeting the state's ambitious clean energy targets while keeping the lights on across the grid. However, he acknowledges that this journey will not be without its challenges.

California aims to transition its power system to 100% carbon-free sources by 2045, ensuring a reliable electricity supply at reasonable costs for consumers. Rothleder, aware of the task's enormity, likens it to a complex car repair performed while the vehicle is in motion.

Recent achievements have demonstrated California's ability to temporarily sustain its grid using clean energy sources. According to Rothleder, the real challenge lies in maintaining this performance round the clock, every day of the year.

Adding thousands of megawatts of renewable energy into California’s existing 50-gigawatt system, which needs to expand to 120 gigawatts to meet the 2045 goal, poses a significant challenge, though recent grid upgrade funding offers some support for needed infrastructure. CAISO estimates that an addition of 7 gigawatts of clean power per year for the next two decades is necessary, all while ensuring uninterrupted power delivery.

While natural gas currently constitutes California's largest single source of power, Rothleder notes the need to gradually decrease reliance on it, even as it remains an operational necessity in the transition phase.

In 2023, CAISO added 5,660 megawatts of new power to the grid, with plans to integrate over 1,100 additional megawatts in the next six to eight months of 2024. Battery storage, crucial for mitigating the intermittent nature of wind and solar power, has seen substantial growth as California turns to batteries for grid support, increasing 30-fold in three years.

Rothleder emphasizes that electricity reliability is paramount, as consumers always expect power availability. He also highlights the potential of offshore wind projects to significantly contribute to California's power mix by 2045.

The offshore wind industry faces financial and supply chain challenges despite these plans. CAISO’s 20-year outlook indicates a significant increase in utility-scale solar, requiring extensive land use and wider deployment of advanced inverters for grid stability.

Addressing affordability is vital, especially as California residents face increasing utility bills. Rothleder suggests a broader energy cost perspective, encompassing utility and transportation expenses.

Despite smooth grid operations in 2023, challenges in previous years, including extreme weather-induced power outages driven by climate change, underscore the need for a robust, adaptable grid. California imports about a quarter of its power from neighbouring states and participates in the Western Energy Imbalance Market, which has yielded significant savings.

CAISO is also working on establishing an extended day-ahead electricity market (EDAM) to enhance the current energy market's success, building on insights from a Western grid integration report that supports expanded coordination.

Rothleder believes that a thoughtfully designed, diverse power system can offer greater reliability and resilience in the long run. A future grid reliant on multiple, smaller power sources such as microgrids could better absorb potential losses, ensuring a more reliable electricity supply for California.

 

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