Hydro One wants to spend another $6-million to redesign bills


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Hydro One Bill Redesign Spending sparks debate over Ontario Energy Board regulation, rate applications, privatization, and digital billing upgrades, as surveys cite confusing invoices under the Fair Hydro Plan for residential, commercial, and industrial customers.

 

Key Points

$15M project to simplify Hydro One bills, upgrade systems, and improve digital billing for commercial customers.

✅ $9M spent; $6M proposed for C&I and large-account changes.

✅ OEB to rule amid rate application and privatization scrutiny.

✅ Survey: 40% of customers struggled to understand bills.

 

Ontario's largest and recently privatized electricity utility has spent $9-million to redesign bills and is proposing to spend an additional $6-million on the project.

Hydro One has come under fire for spending since the Liberal government sold more than half of the company, notably for its CEO's $4.5-million pay.

Now, the NDP is raising concerns with the $15-million bill redesign expense contained in a rate application from the formerly public utility.

"I don't think the problem we face is a bill that people can't understand, I think the problem is rates that are too high," said energy critic Peter Tabuns. "Fifteen million dollars seems awfully expensive to me."

But Hydro One says a 2016 survey of its customers indicated about 40 per cent had trouble understanding their bills.

Ferio Pugliese, the company's executive vice-president of customer care and corporate affairs, said the redesign was aimed at giving customers a simpler bill.

"The new format is a format that when tested and put in front of our customers has been designed to give customers the four or five salient items they want to see on their bill," he said.

About $9-million has already gone into redesigning bills, mostly for residential customers, Pugliese said. Cosmetic changes to bills account for about 25 per cent of the cost, with the rest of the money going toward updating information systems and improving digital billing platforms, he said.

The additional $6-million Hydro One is looking to spend would go toward bill changes mostly for its commercial, industrial and large distribution account customers.

Energy Minister Glenn Thibeault noted in a statement that the Ontario Energy Board has yet to decide on the expense, but he suggested he sees the bill redesign as necessary alongside legislation to lower electricity rates introduced by the province.

"With Ontarians wanting clearer bills that are easier to understand, Hydro One's bill redesign project is a necessary improvement that will help customers," he wrote.

"Reductions from the Fair Hydro Plan (the government's 25 per cent cut to bills last year) are important information for both households and businesses, and it's our job to provide clear, helpful answers whenever possible."

The OEB recently ordered Hydro One to lower a rate increase it had been seeking for this year to 0.2 per cent down from 4.8 per cent.

The regulator also rejected a Hydro One proposal to give shareholders all of the tax savings generated by the IPO in 2015 when the Liberal government first began partially privatizing the utility. The OEB instead mandated shareholders receive 62 per cent of the savings while ratepayers receive the remaining 38 per cent.

 

 

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Several Milestones Reached at Nuclear Power Projects Around the World

Nuclear Power Construction Milestones spotlight EPR builds, Hualong One steam generators, APR-1400 grid integration, and VVER startups, with hot functional testing, hydrostatic checks, and commissioning advancing toward fuel loading and commercial operation.

 

Key Points

Key reactor project steps, from testing and grid readiness to startup, marking progress toward safe commercial operation.

✅ EPR units advance through cold and hot functional testing

✅ Hualong One installs 365-ton steam generators at Fuqing 5

✅ APR-1400 and VVER projects progress toward grid connection

 

The world’s nuclear power industry has been busy in the new year, with several construction projects, including U.S. reactor builds, reaching key milestones as 2018 began.

 

EPR Units Making Progress

Four EPR nuclear units are under construction in three countries: Olkiluoto 3 in Finland began construction in August 2005, Flamanville 3 in France began construction in December 2007, and Taishan 1 and 2 in China began construction in November 2009. Each of the new units is behind schedule and over budget, but recent progress may signal an end to some of the construction difficulties.

EDF reported that cold functional tests were completed at Flamanville 3 on January 6. The main purpose of the testing was to confirm the integrity of primary systems, and verify that components important to reactor safety were properly installed and ready to operate. More than 500 welds were inspected while pressure was held greater than 240 bar (3,480 psi) during the hydrostatic testing, which was conducted under the supervision of the French Nuclear Safety Authority.

With cold testing successfully completed, EDF can now begin preparing for hot functional tests, which verify equipment performance under normal operating temperatures and pressures. Hot testing is expected to begin in July, with fuel loading and reactor startup possible by year end. The company also reported that the total cost for the unit is projected to be €10.5 billion (in 2015 Euros, excluding interim interest).

Olkiluoto 3 began hot functional testing in December. Teollisuuden Voima Oyj—owner and operator of the site—expects the unit to produce its first power by the end of this year, with commercial operation now slated to begin in May 2019.

Although work on Taishan 1 began years after Olkiluoto 3 and Flamanville 3, it is the furthest along of the EPR units. Reports surfaced on January 2 that China General Nuclear (CGN) had completed hot functional testing on Taishan 1, and that the company expects the unit to be the first EPR to startup. CGN said Taishan 1 would begin commercial operation later this year, with Taishan 2 following in 2019.

 

Hualong One Steam Generators Installed

Another Chinese project reached a notable milestone on January 8. China National Nuclear Corp. announced the third of three steam generators had been installed at the Hualong One demonstration project, which is being constructed as Unit 5 at the Fuqing nuclear power plant.

The Hualong One pressurized water reactor unit, also known as the HPR 1000, is a domestically developed design, part of China’s nuclear program, based on a French predecessor. It has a 1,090 MW capacity. The steam generators reportedly weigh 365 metric tons and stand more than 21 meters tall. The first steam generator was installed at Fuqing 5 on November 10, with the second placed on Christmas Eve.

 

Barakah Switchyard Energized

In the United Arab Emirates, more progress has been made on the four South Korean–designed APR-1400 units under construction at the Barakah nuclear power plant. On January 4, Emirates Nuclear Energy Corp. (ENEC) announced that the switchyard for Units 3 and 4 had been energized and connected to the power grid, a crucial step in Abu Dhabi toward completion. Unit 2’s main power transformer, excitation transformer, and auxiliary power transformer were also energized in preparation for hot functional testing on that unit.

“These milestones are a result of our extensive collaboration with our Prime Contractor and Joint Venture partner, the Korea Electric Power Corporation (KEPCO),” ENEC CEO Mohamed Al Hammadi said in a press release. “Working together and benefitting from the experience gained when conducting the same work on Unit 1, the teams continue to make significant progress while continuing to implement the highest international standards of safety, security and quality.”

In 2017, ENEC and KEPCO achieved several construction milestones including installation and concrete pouring for the reactor containment building liner dome section on Unit 3, and installation of the reactor containment liner plate rings, reactor vessel, steam generators, and condenser on Unit 4.

Construction began on the four units (Figure 1) in July 2012, May 2013, September 2014, and September 2015, respectively. Unit 1 is currently undergoing commissioning and testing activities while awaiting regulatory review and receipt of the unit’s operating license from the Federal Authority for Nuclear Regulation, before achieving 100% power in a later phase. According to ENEC, Unit 2 is 90% complete, Unit 3 is 79% complete, and Unit 4 is 60% complete.

 

VVER Units Power Up

On December 29, Russia’s latest reactor to commence operation—Rostov 4 near the city of Volgodonsk—reached criticality, as other projects like Leningrad II-1 advance across the fleet, and was operated at its minimum controlled reactor power (MCRP). Criticality is a term used in the nuclear industry to indicate that each fission event in the reactor is releasing a sufficient number of neutrons to sustain an ongoing series of reactions, which means the neutron population is constant and the chain reaction is stable.

“The transfer to the MCRP allows [specialists] to carry out all necessary physical experiments in the critical condition of [the] reactor unit (RU) to prove its design criteria,” Aleksey Deriy, vice president of Russian projects for ASE Engineering Co., said in a press release. “Upon the results of the experiments the specialists will decide on the RU powerup.”

Rostov 4 is a VVER-1000 reactor with a capacity of 1,000 MW. The site is home to three other VVER units: Unit 1 began commercial operation in 2001, Unit 2 in 2010, and Unit 3 in 2015.

 

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Opinion: Would we use Site C's electricity?

Site C Dam Electricity Demand underscores B.C.'s decarbonization path, enabling electrification of EVs, heat pumps, and industry, aligning with BC Hydro forecasts and 2030/2050 GHG targets to supply dependable, renewable baseload power.

 

Key Points

Projected clean power tied to Site C, driven by B.C. electrification to meet 2030 and 2050 greenhouse gas targets.

✅ Aligns with 25-30% by 2030 and 55-70% by 2050 GHG cuts

✅ Supports EVs, heat pumps, and industrial electrification

✅ Provides dependable baseload alongside efficiency gains

 

There are valid reasons not to build the Site C dam. There are also valid reasons to build it. One of the latter is the rapid increase in clean electricity needed to reduce B.C.’s greenhouse gas emissions from burning natural gas, gasoline, diesel and other harmful fossil fuel products.

Although former Premier Christy Clark casually avoided near-term emissions targets, Prime Minister Justin Trudeau has set Canadian targets for both 2030 and 2050, and cleaning up Canada's electricity is critical to meeting them. Studies by my research group at Simon Fraser University and other independent analysts show that B.C.’s cost-effective contribution to these national targets requires us to reduce our emissions 25 to 30 per cent by 2030 and 55 to 70 per cent by 2050 — an energy evolution involving, among other things, a much greater use of electricity in buildings, vehicles and industry.

Recent submissions to the Site C hearing have offered widely different estimates of B.C.’s electricity demand in the decade after the project’s completion in 2025, some arguing the dam’s output will be completely surplus to domestic need for years and perhaps decades, even though improved B.C.-Alberta grid links could help balance regional demand. Some of this variation in demand forecasts is understandable. Industrial demand is especially difficult to predict, dependent as it is on global economic conditions and shifting trade relations. And there are legitimate uncertainties about B.C. Hydro’s ability to reduce electricity demand by promoting efficient products and behaviour through its Power Smart program. But some of the forecasts appear to be deliberate exaggerations, designed to support fixed positions for or against Site C.

Our university-based research team models the energy system changes required to meet national and provincial emissions targets, and we have been comparing estimates of the electricity demand implications. These estimates are produced by academics, as well as by key institutions like B.C. Hydro, the National Energy Board, and the governments of Canada and B.C.

Most electricity forecasts for B.C., including the most recent by B.C. Hydro, do not assume that B.C. reduces its greenhouse gas emissions by 25 to 30 per cent by 2030 and 55 to 70 per cent by 2050. When we adjust Hydro’s forecast for just the low end of these targets, we find that in its latest, August 30, submission to the Site C hearing, which followed the premier’s over-budget go-ahead on the project, Hydro has underestimated the demand for its electricity by about three terawatt-hours in 2025, four in 2030 and 10 in 2035. Hydro’s forecast indicates that it will need the five terawatt-hours from Site C. Our research shows that even if Hydro’s demand forecast is too high, appropriate climate policy nationally and in B.C. will absorb all the electricity the dam can produce soon after its completion.

B.C. Hydro does not forecast electricity demand to 2050. But, studies by us and others show that B.C. electricity demand will be almost double today’s levels if we are to reduce emissions by 55 to 70 per cent, even amid a documented risk of missing the 2050 target, in just over three decades while our population, economy, buildings and equipment grow significantly. Most mid- and small-sized vehicles will be electric. Most buildings will be well insulated and heated by electric resistance or electric heat-pumps, either individually or via district heating systems. And many low temperature industrial applications will be electric.

Aggressive efforts to promote energy efficiency will make an important contribution, such that energy demand will not grow nearly as fast as the economy. But it is delusional to think that humans will stop using energy. Even climate policy scenarios in which we assume unprecedented success with energy efficiency show dramatic increases in the consumption of electricity, this being the most favoured zero-emission form of energy as a replacement for planet-destroying gasoline and natural gas.

The completion of the Site C dam is a complicated and challenging societal choice, and delay-related cost risks highlighted by the premier underscore the stakes. There is unbiased evidence and argument supporting either completion or cancellation. But let’s stick to the unbiased evidence. In the case of our 2030 and 2050 greenhouse gas reduction targets, such evidence shows that we must substantially increase our generation of dependable electricity. If the Site C dam is built, and if we are true to our climate goals, all its electricity will be used in B.C. soon after completion.

Mark Jaccard is a professor of sustainable energy in the School of Resource and Environmental Management at Simon Fraser University.

 

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Coal CEO blasts federal agency's decision on power grid

FERC Rejects Trump Coal Plan, denying subsidies for coal-fired and nuclear plants as energy policy shifts toward natural gas and renewables, citing no grid reliability threat and warning about electricity prices and market impacts.

 

Key Points

FERC unanimously rejected subsidies for coal and nuclear plants, finding no grid reliability risk from retirements.

✅ Unanimous FERC vote rejects coal and nuclear compensation

✅ Cites no threat to grid reliability from plant retirements

✅ Opponents warned subsidies would distort power markets and prices

 

A decision by an independent energy agency to reject the Trump administration’s electricity pricing plan to bolster the coal industry could lead to more closures of coal-fired power plants and the loss of thousands of jobs, a top coal executive said Tuesday.

Robert Murray, CEO of Ohio-based Murray Energy Corp., called the action by the Federal Energy Regulatory Commission “a bureaucratic cop-out” that will raise the cost of electricity and jeopardize the reliability and security of the nation’s electric grid.

“While FERC commissioners sit on their hands and refuse to take the action directed by Energy Secretary Rick Perry and President Donald Trump, the decommissioning of more coal-fired and nuclear plants could result, further jeopardizing the reliability, resiliency and security of America’s electric power grids,” Murray said. “It will also raise the cost of electricity for all Americans.”

The five-member energy commission voted unanimously Monday to reject Trump’s plan to reward nuclear and coal-fired power plants for adding reliability to the nation’s power grid. The plan would have made the plants eligible for billions of dollars in government subsidies and help reverse a tide of bankruptcies and loss of market share suffered by the once-dominant coal industry as utilities' shift to natural gas and renewable energy continues.

The Republican-controlled commission said there’s no evidence that any past or planned retirements of coal-fired power plants pose a threat to reliability of the nation’s electric grid.

Murray disputed that and said the recent cold snap that hit the East Coast showed coal’s value, as power users in the Southeast were asked to cut back on electricity usage because of a shortage of natural gas. “If it were not for the electricity generated by our nation’s coal-fired and nuclear power plants, we would be experiencing massive brownouts risk and blackouts in this country,” he said.

Murray Energy is the largest privately owned coal company in the United States, with mining operations in Ohio, Illinois, Kentucky, Utah and West Virginia. Robert Murray, a Trump friend and political supporter, has been pushing hard for federal assistance for his industry. The Associated Press reported last year that Murray asked the Trump administration to issue an emergency order protecting coal-fired power plants from closing. Murray warned that failure to act could cause thousands of coal miners to be laid off and force his largest customer, Ohio-based FirstEnergy Solutions, into bankruptcy.

Perry ultimately rejected Murray’s request, but later asked energy regulators to boost coal and nuclear plants as the administration moved to replace the Clean Power Plan with a more limited approach.

The plan drew widespread opposition from business and environmental groups that frequently disagree with each other, even as some coal and business interests backed the EPA's Affordable Clean Energy rule in court.

Jack Gerard, president and CEO of the American Petroleum Institute, said Tuesday that the Trump plan was “far too narrow” in its focus on power sources that maintain a 90-day fuel supply.

API, the largest lobbying group for oil and gas industry, supports coal and other energy sources, Gerard said, “but we should not put our eggs in an individual basket defined as a 90-day fuel supply (while) unnecessarily intervening in private markets.”

 

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UK Electricity prices hit 10-year high as cheap wind power wanes

UK Electricity Price Surge driven by wholesale gas costs, low wind output, and higher gas-fired generation, as National Grid boosts base load power to meet demand, lifting weekend prices toward decade highs.

 

Key Points

A sharp rise in UK power prices tied to gas spikes, waning wind, and higher reliance on gas-fired generation.

✅ Wholesale gas prices squeeze power, doubling weekend baseload.

✅ Wind generation falls to 3GW, forcing more gas-fired plants.

✅ Tariff hikes signal bill pressure and supplier strain.

 

The UK’s electricity market has followed the lead of surging wholesale gas prices this week to reach weekend highs, with UK peak power prices not seen in a decade across the market.

The power market has avoided the severe volatility which ripped through the gas market this week because strong winds helped to supply ample electricity to meet demand, reflecting recent record wind generation across the UK.

But as freezing winds begin to wane this weekend National Grid will need to use more gas-fired power plants to fill the gap, meaning the cost of generating electricity will surge.

Jamie Stewart, an energy expert at ICIS, said the price for base load power this weekend has already soared to around £80 per megawatt hour, almost double what one would expect to see for a weekend in March.

National Grid will increase its use of expensive gas-fired power by an extra 7GW to make up for low wind power, which is forecast to drop by two-thirds in the days ahead.

Wind speeds helped to protect the electricity system from huge price hikes on the neighbouring gas market on Thursday, by generating as much as 13GW by some estimates.

However, by the end of Friday this output will fall by almost half to 7GW and slump to lows of 3GW by Saturday, Mr Stewart said.

The power price was already higher than usual at £53/MWh last weekend even before the full force of the storms, including Storm Malik wind generation, hit Britain. That was still well above the more typical "mid-40s” price for this time of year, Mr Stewart added.

The twin price spikes across the UK’s energy markets has raised fears of household bill hikes in the months ahead, even as an emergency energy plan is not going ahead.

Late on Thursday Big Six supplier E.on quietly pushed through a dual-fuel tariff increase of 2.6%, to drive the average bill up to £1,153 from 19 April.

Energy supply minnow Bulb also increased prices by £24 a year for its 300,000 customers, blaming rising wholesale costs.

The UK has suffered two gas price shocks this winter, which is the first since the owner of British Gas shuttered the country’s largest gas storage facility at Rough off the Yorkshire coast.

A string of gas supply outages this week cut supplies to the UK just as freezing conditions drove demand for gas-heating a third higher than normal for this time of year.

It was the first time in almost ten years that National Grid was forced to issue a short supply warning to the market that supplies would fall short of demand unless factories agree to use less.

The twelve-year market price highs followed a pre-Christmas spike when the UK’s most important North Sea pipeline shut down at the same time as a deadly explosion at Europe’s most important gas hub, based in the Austrian town of Baumgarten.

 

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German Energy Demand Hits Historic Low Amid Economic Stagnation

Germany Energy Demand Decline reflects economic stagnation, IEA forecasts, and the Energiewende, as industrial output slips and efficiency gains, renewables growth, and cost-cutting reduce fossil fuel use while reshaping sustainability and energy security.

 

Key Points

A projected 7% drop in German energy use driven by industrial slowdown, efficiency gains, and renewables expansion.

✅ IEA projects up to 7% demand drop in the next year

✅ Industrial slowdown and efficiency programs cut consumption

✅ Energiewende shifts mix to wind, solar, and less fossil fuel

 

Germany is on the verge of experiencing a significant decline in energy demand, with forecasts suggesting that usage could hit a record low as the country grapples with economic stagnation. This shift highlights not only the immediate impacts of sluggish economic growth but also broader trends in energy consumption, Europe's electricity markets, sustainability, and the transition to renewable resources.

Recent data indicate that Germany's economy is facing substantial challenges, including high inflation and reduced industrial output. As companies struggle to maintain profitability amid nearly doubled power prices and rising costs, many have begun to cut back on energy consumption. This retrenchment is particularly pronounced in energy-intensive sectors such as manufacturing and chemical production, which are crucial to Germany's export-driven economy.

The International Energy Agency (IEA) has projected that German energy demand could decline by as much as 7% in the coming year, a stark contrast to the trends seen in previous decades. This decline is primarily driven by a combination of factors, including reduced industrial activity, increased energy efficiency measures, and a shift toward alternative energy sources, as well as mounting pressures on local utilities to stay solvent. The current economic landscape has led businesses to prioritize cost-cutting measures, including energy efficiency initiatives aimed at reducing consumption.

In the context of these developments, Germany’s energy transition—known as the "Energiewende"—is becoming increasingly significant. The country has made substantial investments in renewable energy sources such as wind, solar, and biomass in recent years. As energy efficiency improves and the share of renewables in the energy mix rises, traditional fossil fuel consumption has begun to wane. This transition is seen as both a response to climate change and a strategy for energy independence, particularly in light of geopolitical tensions and Europe's wake-up call to ditch fossil fuels across the continent.

However, the current stagnation presents a paradox for the German energy sector. While lower energy demand may ease some pressures on supply and prices, it also raises concerns about the long-term viability of investments in renewable energy infrastructure, even as debates continue over electricity subsidies for industry to support competitiveness. The economic slowdown has the potential to derail progress made in reducing carbon emissions and achieving energy targets, particularly if it leads to decreased investment in green technologies.

Another layer to this issue is the potential impact on employment within the energy sector. As energy demand decreases, there may be a ripple effect on jobs tied to traditional energy production and even in renewable energy sectors if investment slows. Policymakers are now tasked with balancing the immediate need for economic recovery, illustrated by the 200 billion-euro energy price shield, with the longer-term goal of achieving sustainability and energy security.

The effects of the stagnation are also being felt in the residential sector. As households face increased living costs and rising heating and electricity costs, many are becoming more conscious of their energy consumption. Initiatives to improve home energy efficiency, such as better insulation and energy-efficient appliances, are gaining traction among consumers looking to reduce their utility bills. This shift toward energy conservation aligns with broader national goals of reducing overall energy consumption and carbon emissions.

Despite the challenges, there is a silver lining. The current situation offers an opportunity for Germany to reassess its energy strategies and invest in technologies that promote sustainability while also addressing economic concerns. This could include increasing support for research and development in green technologies, enhancing energy efficiency programs, and incentivizing businesses to adopt cleaner energy practices.

Furthermore, Germany’s experience may serve as a case study for other nations grappling with similar issues. As economies around the world face the dual pressures of recovery and sustainability, the lessons learned from Germany’s current energy landscape could inform strategies for balancing these often conflicting priorities.

In conclusion, Germany is poised to witness a historic decline in energy demand as economic stagnation takes hold. While this trend poses challenges for the energy sector and economic growth, it also highlights the importance of sustainability and energy efficiency in shaping the future. As the nation navigates this complex landscape, the focus will need to be on fostering innovation and investment that aligns with both immediate economic needs and long-term environmental goals. The path forward will require a careful balancing act, but with the right strategies, Germany can emerge as a leader in sustainable energy practices even in challenging times.

 

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Yale Report on Western Grid Integration: Just Say Yes

Western Grid Integration aligns CAISO with a regional transmission operator under FERC oversight, boosting renewables, reliability, and cost savings while respecting state energy policy, emissions goals, and utility regulation across the West.

 

Key Points

Western Grid Integration lets CAISO operate under FERC to cut costs, boost reliability, and accelerate renewables.

✅ Lowers wholesale costs via wider dispatch and resource sharing

✅ Improves reliability with regional balancing and reserves

✅ Preserves state policy authority under FERC oversight

 

A strong and timely endorsement for western grid integration forcefully rebuts claims that moving from a balkanized system with 38 separate entities to a regional operation could introduce environmental problems, raise costs, or, as critics warn, export California’s energy policies to other western states, or open state energy and climate policies to challenge by federal regulators. In fact, Yale University’s Environmental Protection Clinic identifies numerous economic and environmental benefits from allowing the California Independent System Operator to become a regional grid operator.

The groundbreaking report comprehensively examines the policy and legal merits of allowing the California Independent System Operator (CAISO) to become a regional grid operator, open to any western utility or generator that wants to join, as similar market structure overhauls proceed in New England.

The Yale report identifies the increasing constraints that today’s fragmented western grid imposes on system-wide electricity costs and reliability, addresses the potential benefits of integration, and evaluates  potential legal risks for the states involved. California receives particular attention because its legislature is considering the first step in the grid integration process, which involves authorizing the CAISO to create a fully independent board, even as it examines revamping electricity rates to clean the grid (other western states are unlikely to approve joining an entity whose governance is determined solely by California’s governor and legislature, as is the case now).

 

Elements of the report

The analysis examined all of California’s key energy and climate policies, from its cap on carbon emissions to its renewable energy goals and its pollution standards for power plants, and concludes that none would face additional legal risks under a fully integrated western grid. The operator of such a grid would be regulated by an independent federal agency (the Federal Energy Regulatory Commission)—but so is the CAISO itself, now and since its inception, by virtue of its extended involvement in interstate electricity commerce throughout the West. 

And if empowered to serve the entire region, the CAISO would not interfere with the longstanding rights of California and other states to regulate their utilities’ investments or set energy and climate policies. The study points out that grid operators don’t set energy policies for the states they serve; they help those states minimize costs, enhance reliability in the wake of California blackouts across the state, and avoid unnecessary pollution.

And as to whether an integrated grid would help renewable energy or fossil fuels, the report finds that renewable resources would be the inevitable winners, thanks to their lower operating costs, although the most important winners would be western utility customers, through lower bills, expanded retail choice options, and improved reliability.

 

Call to action

The Yale report concludes with what amounts to a call to action for California’s legislators:

“In sum, enhanced Western grid integration in general, and the emergence of a regional system operator in particular, would not expose California’s clean energy policies to additional legal risks. Shifting to a regional grid operator would enable more efficient, affordable and reliable integration of renewable resources without increasing the legal risk to California’s clean energy policies.”

The authors of the analysis, from the Yale Law School and the Yale School of Forestry and Environmental Studies, are Juliana Brint, Josh Constanti, Franz Hochstrasser. and Lucy Kessler. They dedicated months to the project, consulted with a diverse group of reviewers, and made the trek from New Haven to Folsom, CA, to visit the California Independent System Operator and interview key staff members.

 

 

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