The Electric Power Research Institute EPRI has published a basic consumer guide that addresses questions about electric vehicle technology and performance.
With a variety of electric and hybrid technologies now available commercially, potential buyers are looking to understand which options might best match their needs.
The eight-page guide, “Plugging In: A Consumer’s Guide to the Electric Vehicle,” defines and briefly compares driving range, charging times, fuel requirements and effects of weather and driving conditions. It also highlights vehicles available for purchase today and models scheduled to be available later in 2011 and in 2012.
A question and answer section explores and answers a number of the most common questions asked about electric vehicle technology compared to hybrid and plug-in hybrid electric vehicles. Charging and purchasing considerations are among the topics covered in this section.
The guide offers a basic overview of hybrid vehicles, plug-in hybrids and electric vehicles, and is not intended to be an exhaustive report about the technologies or the manufacturers and vendors supporting this industry.
“Consumers need a starting point –basic information to help them evaluate their options as they consider purchasing electric vehicles,” said Mark Duvall, director of EPRI’s Electric Transportation Program. “This guide is intended to answer some of the most common questions that may help them with their decision.”
U.S. Power Grid Supply Shortages strain reliability as heat waves, hurricanes, and drought drive peak demand; transformer scarcity, gas constraints, and renewable delays raise outage risks across ERCOT and MISO, prompting FERC warnings.
Key Points
They are equipment and fuel constraints that, amid extreme weather and peak demand, elevate outage risks.
✅ Transformer shortages delay storm recovery and repairs.
✅ Record gas burn, low hydro tighten generation capacity.
✅ ERCOT and MISO warn of rolling outages in heat waves.
U.S. power companies are facing supply crunches amid the U.S. energy crisis that may hamper their ability to keep the lights on as the nation heads into the heat of summer and the peak hurricane season.
Extreme weather events such as storms, wildfires and drought are becoming more common in the United States. Consumer power use is expected to hit all-time highs this summer, reflecting unprecedented electricity demand across the Eastern U.S., which could strain electric grids at a time when federal agencies are warning the weather could pose reliability issues.
Utilities are warning of supply constraints for equipment, which could hamper efforts to restore power during outages. They are also having a tougher time rebuilding natural gas stockpiles for next winter, after the Texas power system failure highlighted cold-weather vulnerabilities, as power generators burn record amounts of gas following the shutdown of dozens of coal plants in recent years and extreme drought cuts hydropower supplies in many Western states.
"Increasingly frequent cold snaps, heat waves, drought and major storms continue to challenge the ability of our nation’s electric infrastructure to deliver reliable affordable energy to consumers," Richard Glick, chairman of the U.S. Federal Energy Regulatory Commission (FERC), said earlier this month.
Federal agencies responsible for power reliability like FERC have warned that grids in the western half of the country could face reliability issues this summer as consumers crank up air conditioners to escape the heat, with nationwide blackout risks not limited to Texas. read more
Some utilities have already experienced problems due to the heat. Texas' grid operator, the Electric Reliability Council of Texas (ERCOT), was forced to urge customers to conserve energy as the Texas power grid faced another crisis after several plants shut unexpectedly during an early heat wave in mid-May. read more
In mid-June, Ohio-based American Electric Power Co (AEP.O) imposed rolling outages during a heat wave after a storm damaged transmission lines and knocked out power to over 200,000 homes and businesses.
The U.S. Midwest faces the most severe risk because demand is rising while nuclear and coal power supplies have declined. read more
The Midcontinent Independent System Operator (MISO), which operates the grid from Minnesota to Louisiana, warned that parts of its coverage area are at increased risk of temporary outages to preserve the integrity of the grid.
Supply-chain issues have already delayed the construction of renewable energy projects across the country, and the aging U.S. grid is threatening progress on renewables and EVs. Those renewable delays coupled with tight power in the Midwest prompted Wisconsin's WEC Energy Group Inc (WEC.N) and Indiana's NiSource Inc (NI.N) to delay planned coal plant shutdowns in recent months.
BRACING FOR SUPPLY SHORTAGES Utility operators are conserving their inventory of parts and equipment as they plan to prevent summer power outages during severe storms. Over the last several months, that means operators have been getting creative.
"We’re doing a lot more splicing, putting cables together, instead of laying new cable because we're trying to maintain our new cable for inventory when we need it," Nick Akins, chief executive of AEP, said at the CERAWeek energy conference in March.
Transformers, which often sit on top of electrical poles and convert high-voltage energy to the power used in homes, are in short supply.
New Jersey-based Public Service Enterprise Group Inc (PSEG) (PEG.N) Chief Executive Ralph Izzo told Reuters the company has had to look at alternate supply options for low voltage transformers.
"You don’t want to deplete your inventory because you don't know when that storm is coming, but you know it's coming," Izzo said.
Some utilities are facing waiting times of more than a year for transformer parts, the National Rural Electric Cooperative Association and the American Public Power Association told U.S. Energy Secretary Jennifer Granholm in a May letter.
Summer is just starting, but U.S. weather so far this year has already been about 21% warmer than the 30-year norm, according to data provider Refinitiv.
"If we have successive days of 100-degree-heat, those pole top transformers, they start popping like Rice Krispies, and we would not have the supply stack to replace them," Izzo said.
SM-1A Nuclear Plant Decommissioning details the US Army Corps of Engineers' removal of the Fort Greely reactor, Cold War facility dismantling, environmental monitoring, remote-site power history, and timeline to 2026 under a deactivated nuclear program.
Key Points
Army Corps plan to dismantle Fort Greely's SM-1A reactor and complete decommissioning of remaining systems by 2026.
✅ Built for remote Arctic radar support during the Cold War
✅ High costs beat diesel; program later deemed impractical
✅ Reactor parts removed; residuals monitored; removal by 2026
The US Army Corps of Engineers has begun decommissioning Alaska’s only nuclear power plant, SM-1A, which is located at Fort Greely, even as new US reactors continue to take shape nationwide. The $17m plant closed in 1972 after ten years of sporadic operation. It was out of commission from 1967 to 1969 for extensive repairs. Much of has already been dismantled and sent for disposal, and the rest, which is encased in concrete, is now to be removed.
The plant was built as part of an experimental programme to determine whether nuclear facilities, akin to next-generation nuclear concepts, could be built and operated at remote sites more cheaply than diesel-fuelled plants.
"The main approach was to reduce significant fuel-transportation costs by having a nuclear reactor that could operate for long terms, a concept echoed in the NuScale SMR safety evaluation process, with just one nuclear core," Brian Hearty said. Hearty manages the Army Corps of Engineers’ Deactivated Nuclear Power Plant Program.
#google#
He said the Army built SM-1A in 1962 hoping to provide power reliably at remote Arctic radar sites, where in similarly isolated regions today new US coal plants may still be considered, intended to detect incoming missiles from the Soviet Union at the height of the Cold War. He added that the programme worked but not as well as Pentagon officials had hoped. While SM-1A could be built and operated in a cold and remote location, its upfront costs were much higher than anticipated, and it costs more to maintain than a diesel power plant. Moreover, the programme became irrelevant because of advances in Soviet rocket science and the development of intercontinental ballistic missiles.
Hearty said the reactor was partially dismantled soon after it was shut down. “All of the fuel in the reactor core was removed and shipped back to the Atomic Energy Commission (AEC) for them to either reprocess or dispose of,” he noted. “The highly activated control and absorber rods were also removed and shipped back to the AEC.”
The SM-1A plant produced 1.8MWe and 20MWt, including steam, which was used to heat the post. Because that part of the system was still needed, Army officials removed most of the nuclear-power system and linked the heat and steam components to a diesel-fired boiler. However, several parts of the nuclear system remained, including the reactor pressure vessel and reactor coolant pumps. “Those were either kept in place, or they were cut off and laid down in the tall vapour-containment building there,” Hearty said. “And then they were grouted and concreted in place.” The Corps of Engineers wants to remove all that remains of the plant, but it is as yet unclear whether that will be feasible.
Meanwhile, monitoring for radioactivity around the facility shows that it remains at acceptable levels. “It would be safe to say there’s no threat to human health in the environment,” said Brenda Barber, project manager for the decommissioning. Work is still in its early stages and is due to be completed in 2026 at the earliest. Barber said the Corps awarded the $4.6m contract in December to a Virginia-based firm to develop a long-range plan for the project, similar in scope to large reactor refurbishment efforts elsewhere. Among other things, this will help officials determine how much of the SM-1A will remain after it’s decommissioned. “There will still be buildings there,” she said. “There will still be components of some of the old structure there that may likely remain.”
Hydro One Leadership Shakeup unsettles investors as Ontario government ousts CEO and board, pressuring shares; analysts cite political and regulatory risk, stock volatility, trimmed price targets, and dividend stability at the regulated utility.
Key Points
An abrupt CEO exit and board overhaul at Hydro One, driving share declines and raising political and regulatory risk.
✅ Shares fall as CEO retires and board resigns under provincial pressure.
✅ Analysts cut price targets; warn of political, regulatory risks.
✅ New board to pick CEO; province consults on compensation.
Hydro One Ltd. shares slid Thursday with some analysts sounding warnings of greater uncertainty after the new Ontario government announced the retirement of the electrical utility's chief executive and the replacement of its board of directors.
After sagging by almost eight per cent in early trading on the Toronto Stock Exchange, following news that Q2 profit plunged 23% amid weaker electricity revenue, shares of the company were later down four per cent, or 81 cents, at $19.36 as of 11:42 a.m. ET.
On Wednesday, after stock markets had closed for the day, Ontario Premier Doug Ford announced the immediate retirement of Hydro One CEO Mayo Schmidt. He leaves with a $400,000 payout in lieu of post-retirement benefits and allowances, Hydro One said.
Doug Ford's government forces out Hydro One '$6-million man'
During the recent provincial election campaign, Ford vowed to fire Schmidt, who earned $6.2 million last year and whose salary wouldn't be reduced despite calls to cut electricity costs.
Paul Dobson, Hydro One's chief financial officer, will serve as acting CEO until a new top executive is selected.
Ford also said the entire board of directors of the utility would resign. Hydro One said a new board — four members of which will be nominated by the province — will select the company's next CEO, and the province will be consulted on the next leader's compensation.
A new board is expected to be formed by mid-August.
The provincial government is the largest single investor in Hydro One, holding a 47 per cent stake. The company was partly privatized by the former Liberal government in 2015, while the NDP has proposed to make hydro public again in Ontario to change course.
Doug Ford promises to keep Pickering nuclear plant open until 2024
In response to the government's move to supplant the utility's board and CEO, some analysts cautioned investors about too many unknowns in the near-term outlook, citing raised political or regulatory risks.
Analyst Jeremy Rosenfield of iA Securities cut his rating on Hydro One shares to hold from buy, and reduced his 12-month price target for the stock to $24 from $26.
Rosenfield said the stock is still a defensive investment supported by stable earnings and cash flows, good earnings growth and healthy dividend.
However, he said in a research note that "the heightened potential for further political interference in the province's electricity market and regulated utility framework represent key risk factors that are likely to outweigh Hydro One's fundamentals over the near term."
Potential challenge to find new CEO
Laurentian Bank Securities analyst Mona Nazir said in a research note that the magnitude of change all at once was "surprising but not shocking."
She said the agreement that will see Hydro One consult with the provincial government on matters involving executive pay could have an impact on the hiring of a new CEO for the utility.
"Given the government's open and public criticism of the company and a potential ceiling on compensation, it may be challenging to attract top talent to the position," she wrote.
Laurentian cut its rating on the Hydro One to hold and reduced its price target to $21 from $24.
Analysts at CIBC World Markets said investors face an uncertain future, noting parallels with debates at Manitoba Hydro over political direction.
"In particular, we are are concerned about the government meddling in with [power] rates," wrote Robert Catellier and Archit Kshetrapal in a research note, adding they believe the new provincial government is aiming for a 12 per cent reduction in customers' power bills.
CIBC reduced its price target on Hydro One's shares to $20.50 from its previous target of $24.
ITER Nuclear Fusion advances tokamak magnetic confinement, heating deuterium-tritium plasma with superconducting magnets, targeting net energy gain, tritium breeding, and steam-turbine power, while complementing laser inertial confinement milestones for grid-scale electricity and 2025 startup goals.
Key Points
ITER Nuclear Fusion is a tokamak project confining D-T plasma with magnets to achieve net energy gain and clean power.
✅ Tokamak magnetic confinement with high-temp superconducting coils
✅ Deuterium-tritium fuel cycle with on-site tritium breeding
✅ Targets net energy gain and grid-scale, low-carbon electricity
It sounds like the stuff of dreams: a virtually limitless source of energy that doesn’t produce greenhouse gases or radioactive waste. That’s the promise of nuclear fusion, often described as the holy grail of clean energy by proponents, which for decades has been nothing more than a fantasy due to insurmountable technical challenges. But things are heating up in what has turned into a race to create what amounts to an artificial sun here on Earth, one that can provide power for our kettles, cars and light bulbs.
Today’s nuclear power plants create electricity through nuclear fission, in which atoms are split, with next-gen nuclear power exploring smaller, cheaper, safer designs that remain distinct from fusion. Nuclear fusion however, involves combining atomic nuclei to release energy. It’s the same reaction that’s taking place at the Sun’s core. But overcoming the natural repulsion between atomic nuclei and maintaining the right conditions for fusion to occur isn’t straightforward. And doing so in a way that produces more energy than the reaction consumes has been beyond the grasp of the finest minds in physics for decades.
But perhaps not for much longer. Some major technical challenges have been overcome in the past few years and governments around the world have been pouring money into fusion power research as part of a broader green industrial revolution under way in several regions. There are also over 20 private ventures in the UK, US, Europe, China and Australia vying to be the first to make fusion energy production a reality.
“People are saying, ‘If it really is the ultimate solution, let’s find out whether it works or not,’” says Dr Tim Luce, head of science and operation at the International Thermonuclear Experimental Reactor (ITER), being built in southeast France. ITER is the biggest throw of the fusion dice yet.
Its $22bn (£15.9bn) build cost is being met by the governments of two-thirds of the world’s population, including the EU, the US, China and Russia, at a time when Europe is losing nuclear power and needs energy, and when it’s fired up in 2025 it’ll be the world’s largest fusion reactor. If it works, ITER will transform fusion power from being the stuff of dreams into a viable energy source.
Constructing a nuclear fusion reactor ITER will be a tokamak reactor – thought to be the best hope for fusion power. Inside a tokamak, a gas, often a hydrogen isotope called deuterium, is subjected to intense heat and pressure, forcing electrons out of the atoms. This creates a plasma – a superheated, ionised gas – that has to be contained by intense magnetic fields.
The containment is vital, as no material on Earth could withstand the intense heat (100,000,000°C and above) that the plasma has to reach so that fusion can begin. It’s close to 10 times the heat at the Sun’s core, and temperatures like that are needed in a tokamak because the gravitational pressure within the Sun can’t be recreated.
When atomic nuclei do start to fuse, vast amounts of energy are released. While the experimental reactors currently in operation release that energy as heat, in a fusion reactor power plant, the heat would be used to produce steam that would drive turbines to generate electricity, even as some envision nuclear beyond electricity for industrial heat and fuels.
Tokamaks aren’t the only fusion reactors being tried. Another type of reactor uses lasers to heat and compress a hydrogen fuel to initiate fusion. In August 2021, one such device at the National Ignition Facility, at the Lawrence Livermore National Laboratory in California, generated 1.35 megajoules of energy. This record-breaking figure brings fusion power a step closer to net energy gain, but most hopes are still pinned on tokamak reactors rather than lasers.
In June 2021, China’s Experimental Advanced Superconducting Tokamak (EAST) reactor maintained a plasma for 101 seconds at 120,000,000°C. Before that, the record was 20 seconds. Ultimately, a fusion reactor would need to sustain the plasma indefinitely – or at least for eight-hour ‘pulses’ during periods of peak electricity demand.
A real game-changer for tokamaks has been the magnets used to produce the magnetic field. “We know how to make magnets that generate a very high magnetic field from copper or other kinds of metal, but you would pay a fortune for the electricity. It wouldn’t be a net energy gain from the plant,” says Luce.
One route for nuclear fusion is to use atoms of deuterium and tritium, both isotopes of hydrogen. They fuse under incredible heat and pressure, and the resulting products release energy as heat
The solution is to use high-temperature, superconducting magnets made from superconducting wire, or ‘tape’, that has no electrical resistance. These magnets can create intense magnetic fields and don’t lose energy as heat.
“High temperature superconductivity has been known about for 35 years. But the manufacturing capability to make tape in the lengths that would be required to make a reasonable fusion coil has just recently been developed,” says Luce. One of ITER’s magnets, the central solenoid, will produce a field of 13 tesla – 280,000 times Earth’s magnetic field.
The inner walls of ITER’s vacuum vessel, where the fusion will occur, will be lined with beryllium, a metal that won’t contaminate the plasma much if they touch. At the bottom is the divertor that will keep the temperature inside the reactor under control.
“The heat load on the divertor can be as large as in a rocket nozzle,” says Luce. “Rocket nozzles work because you can get into orbit within minutes and in space it’s really cold.” In a fusion reactor, a divertor would need to withstand this heat indefinitely and at ITER they’ll be testing one made out of tungsten.
Meanwhile, in the US, the National Spherical Torus Experiment – Upgrade (NSTX-U) fusion reactor will be fired up in the autumn of 2022, while efforts in advanced fission such as a mini-reactor design are also progressing. One of its priorities will be to see whether lining the reactor with lithium helps to keep the plasma stable.
Choosing a fuel Instead of just using deuterium as the fusion fuel, ITER will use deuterium mixed with tritium, another hydrogen isotope. The deuterium-tritium blend offers the best chance of getting significantly more power out than is put in. Proponents of fusion power say one reason the technology is safe is that the fuel needs to be constantly fed into the reactor to keep fusion happening, making a runaway reaction impossible.
Deuterium can be extracted from seawater, so there’s a virtually limitless supply of it. But only 20kg of tritium are thought to exist worldwide, so fusion power plants will have to produce it (ITER will develop technology to ‘breed’ tritium). While some radioactive waste will be produced in a fusion plant, it’ll have a lifetime of around 100 years, rather than the thousands of years from fission.
At the time of writing in September, researchers at the Joint European Torus (JET) fusion reactor in Oxfordshire were due to start their deuterium-tritium fusion reactions. “JET will help ITER prepare a choice of machine parameters to optimise the fusion power,” says Dr Joelle Mailloux, one of the scientific programme leaders at JET. These parameters will include finding the best combination of deuterium and tritium, and establishing how the current is increased in the magnets before fusion starts.
The groundwork laid down at JET should accelerate ITER’s efforts to accomplish net energy gain. ITER will produce ‘first plasma’ in December 2025 and be cranked up to full power over the following decade. Its plasma temperature will reach 150,000,000°C and its target is to produce 500 megawatts of fusion power for every 50 megawatts of input heating power.
“If ITER is successful, it’ll eliminate most, if not all, doubts about the science and liberate money for technology development,” says Luce. That technology development will be demonstration fusion power plants that actually produce electricity, where advanced reactors can build on decades of expertise. “ITER is opening the door and saying, yeah, this works – the science is there.”
CPUC Exit Fee Increase for CCAs adjusts the PCIA, affecting utilities, San Diego ratepayers, renewable energy procurement, customer equity, and cost allocation, while providing regulatory certainty for Community Choice Aggregation programs and clean energy goals.
Key Points
A CPUC-approved change raising PCIA exit fees paid by CCAs to utilities, balancing cost shifts and customer equity.
✅ PCIA rises from about 2.5c to roughly 4.25c per kWh in San Diego
✅ Aims to reduce cost shifts and protect non-CCA customers
✅ Offers regulatory certainty for CCA launches and clean energy goals
The California Public Utilities Commission approved an increase on the exit fees charged to customers who take part in Community Choice Aggregation -- government-run alternatives to traditional utilities like San Diego Gas & Electric.
After reviewing two competing exit fee proposals, all five commissioners voted Thursday in favor of an adjustment that many CCA advocates predicted could hamper the growth of the community choice movement.
But minutes after the vote was announced, one of the leading voices in favor of the city San Diego establishing its own CCA said the decision was good news because it provides some regulatory certainty.
"For us in San Diego, it's a green light to move forward with community choice," said Nicole Capretz, executive director of the Climate Action Campaign. "For us, it's let's go, let's launch and let's give families a choice. We no longer have to wait."
Under the CCA model, utilities still maintain transmission and distribution lines (poles and wires, etc.) and handle customer billing. But officials in a given local government entity make the final decisions about what kind of power sources are purchased.
Once a CCA is formed, its customers must pay an exit fee -- called a Power Charge Indifference Adjustment -- to the legacy utility serving that particular region. The fee is included in customers' monthly bills.
The fee is required to offset the costs of the investments utilities made over the years for things like natural gas power plants, renewable energy facilities and other infrastructure.
Utilities argue if the exit fee is set too low, it does not fairly compensate them for their investments; if it's too high, CCAs complain it reduces the financial incentive for their potential customers.
The Public Utilities Commission chose to adopt a proposal that some said was more favorable to utilities, leading to complaints from CCA boosters.
"We see this will really throw sand in the gears in our ability to do things that can move us toward (climate change) goals," Jim Parks, staff member of Valley Clean Energy, a CCA based in Davis, said before the vote.
Commissioner Carla Peterman, who authored the proposal that passed, said she supports CCAs but stressed the commission has a "legal obligation" to make sure increased costs are not shouldered by "customers who do not, or cannot, join a CCA. Today's proposal ensures a more level playing field between customers."
As for what the vote means for the exit fee in San Diego, Peterman's office earlier in the week estimated the charge would rise from 2.5 cents a kilowatt-hour to about 4.25 cents.
The Clear the Air Coaltion, a San Diego County group critical of CCAs, said the newly established exit fee -- which goes into effect starting next year -- is "a step in the direction."
But the group, which includes the San Diego Regional Chamber of Commerce, the San Diego County Taxpayers Association and lobbyists for Sempra Energy (the parent company of SDG&E), repeated concerns it has brought up before.
"If the city of San Diego decides to get into the energy business this decision means ratepayers in National City, Chula Vista, Carlsbad, Imperial Beach, La Mesa, El Cajon and all other neighboring communities would see higher energy bills, and San Diego taxpayers would be faced with mounting debt," coalition spokesman Tony Manolatos said in an email.
CCA supporters say community choice is critical in ensuring San Diego meets the pledge made by Mayor Kevin Faulconer to adopt the city's Climate Action Plan, mandating 100 percent of the city's electricity needs must come from renewable sources by 2035.
Now attention turns to Faulconer, who promised to make a decision on bringing a CCA proposal to the San Diego City Council only after the utilities commission made its decision.
A Faulconer spokesman said Thursday afternoon that the vote "provides the clarity we've been waiting for to move forward" but did not offer a specific time table.
"We're on schedule to reach Mayor Faulconer's goal of choosing a pathway that achieves our renewable energy goals while also protecting ratepayers, and the mayor looks forward to making his recommendation in the next few weeks," said Craig Gustafson, a Faulconer spokesman, in an email.
A feasibility study released last year predicted a CCA in San Diego has the potential to deliver cheaper rates over time than SDG&E's current service, while providing as much as 50 percent renewable energy by 2023 and 80 percent by 2027.
"The city has already figured out we are still capable of launching a program, having competitive, affordable rates and finally offering families a choice as to who their energy provider is," said Capretz, who helped draft an initial blueprint of the climate plan as a city staffer.
SDG&E has come to the city with a counterproposal that offers 100 percent renewables by 2035.
Thus far, the utility has produced a rough outline for a "tariff" program that would charge ratepayers the cost of delivering more clean sources of energy over time.
Some council members have expressed frustration more specifics have not been sketched out.
SDG&E officials said they will take the new exit fee into account as they go forward with their counterproposal to the city council.
Speaking in general about the utility commission's decision, SDG&E spokeswoman Helen Gao called it "a victory for our customers, as it minimizes the cost shifts that they have been burdened with under the existing fee formula.
"As commissioners noted in rendering their decision, reforming the (exit fee) addresses a customer-to-customer equity issue and has nothing to do with increasing profits for investor-owned utilities," Gao said in an email.
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.”
Whether you would prefer Live Online or In-Person
instruction, our electrical training courses can be
tailored to meet your company's specific requirements
and delivered to your employees in one location or at
various locations.
