Electricity News in February 2019
Three New Solar Electricity Facilities in Alberta Contracted At Lower Cost than Natural Gas
Alberta Solar Energy Contracts secure low-cost photovoltaic PPAs for government operations, delivering renewable electricity at 4.8 cents/kWh, beating natural gas LCOE, enhancing summer grid efficiency across Hays, Tilley, and Jenner with Canadian Solar.
Key Points
Low-cost PV power agreements meeting 55% of Alberta government electricity demand via new Canadian Solar facilities.
✅ Price: 4.8 cents/kWh CAD, under gas-fired generation LCOE.
✅ Sites: Hays, Tilley, Jenner; 50% equity with Conklin Métis Local #193.
✅ Supplies 55% of provincial government electricity demand.
Three new solar electricity facilities to be built in south eastern Alberta (Canada) amid Alberta's solar growth have been selected through a competitive process to supply the Government of Alberta with 55 per cent of their annual electricity needs. The facilities will be built near Hays, Tilley, and Jenner, by Canadian Solar with Conklin Métis Local #193 as 50-percent equity owners.
The Government of Alberta's operations have been powered 100 per cent with wind power since 2007. Upon the expiration of some of these contracts, they have been renewed to switch from wind to solar energy. The average contract pricing will be $0.048 per kilowatt hour (3.6 cents/kWh USD), which is less than the average historical wholesale power pool price paid to natural gas-fired electricity in the province in years 2008 - 2018.
"The conversation about solar energy has long been fixated on its price competitiveness with fossil fuels," said John Gorman, CanSIA President & CEO. "Today's announcement demonstrates that low cost solar energy has arrived as a mainstream option in Alberta, even as demand for solar lags in Canada according to federal assessments. The conversation should next focus on how to optimize an all-of-the-above strategy for developing the province's renewable and non-renewable resources."
"This price discovery is monumental for the solar industry in Canada" said Patrick Bateman, CanSIA Director of Policy & Market Development. "At less than five cents per kilowatt hour, this solar electricity has a cost that is less than that of natural gas. Achieving Alberta's legislated 30 per cent by 2030 renewable electricity target just became a whole lot cheaper!".
Quick Facts:
- The contract price of 4.8 cents/kWh CAD to be paid by Alberta Infrastructure for this solar electricity represents a lower Levelized Cost of Electricity (LCOE) than the average annual wholesale price paid by the power pool to combined-cycle and single-cycle natural gas-fired electricity generation which was 7.1 cents/kWh and 11.2 cents/kWh respectively from 2008 - 2018.
- Alberta receives more hours of sunshine than Miami, Florida in the summer months. Alberta's electricity supply is most strained in summer, highlighting challenges for solar expansion when high temperatures increase the resistance of the distribution and transmission systems, and reduce the efficiency of cooling thermal power plants. For this reason, solar facilities sited near to electricity demand improves overall grid efficiency. Supply shortages are atypical in Alberta in winter when solar energy is least available. When they do occur, imports are increased and large loads are decreased.
- In 2018, Alberta's solar electricity generation exceeded 50 MW. While representing much less than 1% of the province's electricity supply today, the Canadian Solar Industries Association (CanSIA) forecasts that solar energy could supply as much as 3 per cent of the province's electricity by 2030, supporting renewable energy job growth across Alberta. A recent supply chain study of the solar electricity sector in Alberta by Solas Energy Consulting Inc. found a potential of $4.1 billion in market value and a labour force rising to 10,000 in 2030.
To learn more about solar energy and the best way for consumers to go solar, please visit the Canadian Solar Industries Association at www.CanSIA.ca.
Related News
First US coal plant in years opens where no options exist
Alaska Coal-Fired CHP Plant opens near Usibelli mine, supplying electricity and district heat to UAF; remote location without gas pipelines, low wind and solar potential, and high heating demand shaped fuel choice.
Key Points
A 17 MW coal CHP at UAF producing power and campus heat, chosen for remoteness and lack of gas pipelines.
✅ 17 MW generator supplying electricity and district heat
✅ Near Usibelli mine; limited pipeline access shapes fuel
✅ Alternative options like LNG, wind, solar not cost-effective
One way to boost coal in the US: Find a spot near a mine with no access to oil or natural gas pipelines, where it’s not particularly windy and it’s dark much of the year.
That’s how the first coal-fired plant to open in the U.S. since 2015 bucked the trend in an industry that’s seen scores of facilities close in recent years. A 17-megawatt generator, built for $245 million, is set to open in April at the University of Alaska Fairbanks, just 100 miles from the state’s only coal mine.
“Geography really drove what options are available to us,” said Kari Burrell, the university’s vice chancellor for administrative services, in an interview. “We are not saying this is ideal by any means.”
The new plant is arriving as coal fuels about 25 percent of electrical generation in the U.S., down from 45 percent a decade earlier, even as some forecasts point to a near-term increase in coal-fired generation in 2021. A near-record 18 coal plants closed in 2018, and 14 more are expected to follow this year, according to BloombergNEF.
The biggest bright spot for U.S. coal miners recently has been exports to overseas power plants. At home, one of the few growth areas has been in pizza ovens.
There are a handful of other U.S. coal power projects that have been proposed, including plans to build an 850 megawatt facility in Georgia and an 895 megawatt plant in Kansas, even as a Minnesota utility reports declining coal returns across parts of its portfolio. But Ashley Burke, a spokeswoman for the National Mining Association, said she’s unaware of any U.S. plants actively under development besides the one in Alaska.
Future of power
“The future of power in the U.S. does not include coal,” Tessie Petion, an analyst for HSBC Holdings Plc, said in a research note, a view echoed by regions such as Alberta retiring coal power early in their transition.
Fairbanks sits on the banks of the Chena River, amid the vast subarctic forests in the heart of Alaska. The oil and gas fields of the state’s North slope are 500 miles north. The nearest major port is in Anchorage, 350 miles south.
The university’s new plant is a combined heat and power generator, which will create steam both to generate electricity and heat campus buildings. Before opting for coal, the school looked into using liquid natural gas, wind and solar, bio-mass and a host of other options, as new projects in Southeast Alaska seek lower electricity costs across the region. None of them penciled out, said Mike Ruckhaus, a senior project manager at the university.
The project, financed with university and state-municipal bonds, replaces a coal plant that went into service in 1964. University spokeswoman Marmian Grimes said it’s worth noting that the new plant will emit fewer emissions.
The coal will come from Usibelli Coal Mine Inc., a family-owned business that produces between 1.2 and 2 million tons per year from a mine along the Alaska railroad, according to the company’s website.
While any new plant is good news for coal miners, Clarksons Platou Securities Inc. analyst Jeremy Sussman said this one is "an isolated situation."
“We think the best producers can hope for domestically is a slow down in plant closures,” he said, even as jurisdictions like Alberta close their last coal plant entirely.
Related News
Congressional Democrats push FERC to act on aggregated DERs
FERC DER Aggregation advances debates over distributed energy resources as Congress presses action on Order 841, grid resilience, and wholesale market access, including rooftop solar, storage, and virtual power plant participation across PJM and ISO-NE.
Key Points
FERC DER Aggregation enables grouped distributed resources to join wholesale markets, providing capacity and flexibility.
✅ Opens wholesale market access for aggregated DER portfolios
✅ Aligns with Order 841, storage, and grid resilience goals
✅ Raises jurisdictional questions between FERC and state regulators
The Monday letter from Congressional Democrats illustrates growing frustration in Washington over the lack of FERC action on multiple power sector issues, including the aging U.S. grid and related challenges.
Last May, after the FERC technical conference, 16 Democratic Senators wrote to then-Chairman Kevin McIntyre urging him to develop guidance for grid operators on aggregated DERs.
In July, McIntyre responded, saying that FERC was "diligently reviewing the record," but the commission has taken no action since.
Since then, "DER adoption and renewable energy aggregation have continued to grow," House and Senate lawmakers wrote in their identical Monday letters, "driven not only by state and federal policies, but consumer interest in choosing cost-competitive technologies such as rooftop solar, smart thermostats and customer-sited energy generation and storage, reflecting key utility trends in the sector."
The lawmakers wrote they were "encouraged" by FERC Chairman Neil Chatterjee's comments in June 2018, writing that he "specifically cited the role DERs will play in our continued grid transition."
In that speech at the S&P Global Platts 2018 Transmission Planning and Development Conference, Chatterjee noted "growing interest" in non-transmission alternatives, including "DERs and storage."
"How the Commission treats filings associated with those first-of-kind projects could prove an important factor in investors’ assessments of whether similar non-traditional projects are bankable or not — and more broadly signal whether FERC is open to innovation in the transmission sector,” he said.
In addition to the DER order and rehearing decision on Order 841, FERC has multiple other power sector initiatives that have not seen official action in months, even as major changes to electricity pricing are debated by stakeholders.
The highest profile is its open proceeding on grid resilience, set up last January after FERC rejected a coal and nuclear bailout proposal from the Department of Energy. In October, the CEO of the PJM Interconnection, the nation’s largest wholesale power market, urged FERC to issue a final order in the docket, calling for "leadership" from the commission.
Chatterjee, however, has not indicated when FERC could decide on the case. In December, Commissioner Rich Glick told a Washington audience he is "not entirely sure where the chairman wants to go with that proceeding yet."
Outside of resilience, FERC also has open reviews of both its pipeline certificate policy and implementation of the Public Utilities Regulatory Policy Act, a key law supporting renewable energy. McIntrye set those reviews in motion during his tenure as chairman, but after his death in January the timing of both remains unclear.
In recent months, Chatterjee has also delayed FERC votes on major export facilities for liquefied natural gas and a political spending case involving PJM after impasses between Republicans and Democrats on FERC.
Two members from each party currently sit on the commission. That allows Democrats to deadlock commission votes on natural gas facilities and other issues — a partisan divide on display this week when they clashed with the chairman over offshore wind.
As the commission considers final guidance on DERs, the boundaries of federal jurisdiction are likely to be a key issue. At the technical conference, states from the Midcontinent ISO argued FERC should allow them to choose whether to let aggregated DERs participate in retail and wholesale markets. Other states argued the value proposition of distributed resources may rely on that sort of dual participation.
Despite the lack of action from FERC, some grid operators are moving forward with aggregated distributed resources in New England market reform efforts and elsewhere, demonstrating momentum. Last week, a residential solar-plus-storage aggregation cleared the ISO-NE capacity auction for the first time, committing to provide 20 MW of capacity beginning in 2022.
On the Senate side, Sens. Sheldon Whitehouse, R.I., and Ed Markey, Mass., led the letter to FERC. In the House, Reps. Peter Welch, Vt., and Mike Levin, Calif., led the signatories.
Related News
Michigan Public Service Commission grants Consumers Energy request for more wind generation
Consumers Energy Wind Expansion gains MPSC approval in Michigan, adding up to 525 MW of wind power, including Gratiot Farms, while solar capacity requests face delays over cost projections under the renewable portfolio standard targets.
Key Points
A regulatory-approved plan enabling Consumers Energy to add 525 MW of wind while solar additions await cost review.
✅ MPSC approves up to 525 MW in new wind projects
✅ Gratiot Farms purchase allowed before May 1
✅ Solar request delayed over high cost projections
Consumers Energy Co.’s efforts to expand its renewable offerings gained some traction this week when the Michigan Public Service Commission (MPSC) approved a request for additional wind generation capacity.
Consumers had argued that both more wind and solar facilities are needed to meet the state’s renewable portfolio standard, which was expanded in 2016 to encompass 12.5 percent of the retail power of each Michigan electric provider. Those figures will continue to rise under the law through 2021 when the figure reaches 15 percent, alongside ongoing electricity market reforms discussions. However, Consumers’ request for additional solar facilities was delayed at this time due to what the Commission labeled unrealistically high-cost projections.
Consumers will be able to add as much as 525 megawatts of new wind projects amid a shifting wind market, including two proposed 175-megawatt wind projects slated to begin operation this year and next. Consumers has also been allowed to purchase the Gratiot Farms Wind Project before May 1.
The MPSC said a final determination would be made on Consumers’ solar requests during a decision in April. Consumers had sought an additional 100 megawatts of solar facilities, hoping to get them online sometime in 2024 and 2025.
Related News
Biggest offshore windfarm to start UK supply this week
Hornsea One Offshore Wind Farm delivers first power to the UK grid, scaling renewable energy with 1.2GW capacity, giant offshore turbines, and Yorkshire coast infrastructure to replace delayed nuclear and cut fossil fuel emissions.
Key Points
Hornsea One Offshore Wind Farm is a 1.2GW UK project delivering offshore renewable power to about 1 million homes.
✅ 174 turbines over 407 km2; Siemens Gamesa supply chain in the UK
✅ 1.2GW capacity can power ~1m homes; phases scale with 10MW+ turbines
✅ Supports UK grid, replaces delayed nuclear, cuts fossil generation
An offshore windfarm on the Yorkshire coast that will dwarf the world’s largest when completed is to supply its first power to the UK electricity grid this week, mirroring advances in tidal electricity projects delivering to the grid as well.
The Danish developer Ørsted, which has installed the first of 174 turbines at Hornsea One, said it was ready to step up its plans and fill the gap left by failed nuclear power schemes.
The size of the project takes the burgeoning offshore wind power sector to a new scale, on a par with conventional fossil fuel-fired power stations.
Hornsea One will cover 407 square kilometres, five times the size of the nearby city of Hull. At 1.2GW of capacity it will power 1m homes, making it about twice as powerful as today’s biggest offshore windfarm once it is completed in the second half of this year.
“The ability to generate clean electricity offshore at this scale is a globally significant milestone at a time when urgent action needs to be taken to tackle climate change,” said Matthew Wright, UK managing director of Ørsted, the world’s biggest offshore windfarm builder.
The power station is only the first of four planned in the area, with a green light and subsidies already awarded to a second stage due for completion in the early 2020s, and interest from Japanese utilities underscoring growing investor appetite.
The first two phases will use 7MW turbines, which are taller than London’s Gherkin building.
But the latter stages of the Hornsea development could use even more powerful, 10MW-plus turbines. Bigger turbines will capture more of the energy from the wind and should lower costs by reducing the number of foundations and amount of cabling firms need to put into the water, with developers noting that offshore wind can compete with gas in the U.S. as costs fall.
Henrik Poulsen, Ørsted’s chief executive, said he was in close dialogue with major manufacturers to use the new generation of turbines, some of which are expected to approach the height of the Shard in London, the tallest building in the EU.
The UK has a great wind resource and shallow enough seabed to exploit it, and could even “power most of Europe if it [the UK] went to the extreme with offshore”, he said.
Offshore windfarms could help ministers fill the low carbon power gap created by Hitachi and Toshiba scrapping nuclear plants, the executive suggested. “If nuclear should play less of a role than expected, I believe offshore wind can step up,” he said.
New nuclear projects in Europe had been “dramatically delayed and over budget”, he added, in comparison to “the strong track record for delivering offshore [wind]”.
The UK and Germany installed 85% of new offshore wind power capacity in the EU last year, according to industry data, with wind leading power across several markets. The average power rating of the turbines is getting bigger too, up 15% in 2018.
The turbines for Hornsea One are built and shipped from Siemens Gamesa’s factory in Hull, part of a web of UK-based suppliers that has sprung up around the growing sector, such as Prysmian UK's land cables supporting grid connections.
Around half of the project’s transition pieces, the yellow part of the structure that connects the foundation to the tower, are made in Teeside. Many of the towers themselves are made by a firm in Campbeltown in the Scottish highlands. Altogether, about half of the components for the project are made in the UK.
Ørsted is not yet ready to bid for a share of a £60m pot of further offshore windfarm subsidies, to be auctioned by the government this summer, but expects the price to reach even more competitive levels than those seen in 2017.
Like other international energy companies, Ørsted has put in place contingency planning in event of a no-deal Brexit – but the hope is that will not come to pass. “We want a Brexit deal that will facilitate an orderly transition out of the union,” said Poulsen.
Related News
Dubai Planning Large-Scale Solar Powered Hydrogen Production
Dubai Green Hydrogen advances electrolysis at the Mohammed Bin Rashid Al Maktoum Solar Park, with DEWA and Siemens enabling clean energy storage, re-electrification, and fuel-cell mobility for Expo 2020 Dubai and public transport.
Key Points
Dubai Green Hydrogen is a DEWA-Siemens project making solar hydrogen for storage, mobility, and reelectrification.
✅ Electrolysis at Mohammed Bin Rashid Al Maktoum Solar Park
✅ Partners: DEWA and Siemens; public-private demonstration plant
✅ Hydrogen for buses, re-electrification, and energy storage
Something you hear frequently if you are a clean tech aficionado is that excess solar and wind power can be used to split water into oxygen and hydrogen. The Dubai Supreme Council of Energy, the 2020 Dubai Higher Committee and the Dubai Electricity and Water Authority broke ground in early February on a solar power hydrogen electrolysis facility located in the Mohammed Bin Rashid Al Maktoum Solar Park, and related initiatives like the Solar Decathlon Middle East underscore Dubai's clean energy focus. Sheikh Ahmed bin Saeed Al Maktoum, chairman of the Dubai Supreme Council of Energy and chairman of the Expo 2020 Dubai Higher Committee, participated in the groundbreaking ceremony, according to a report by Khaleej Times.
Saeed Mohammed Al Tayer, CEO of DEWA, said at the groundbreaking ceremony the project is important to understanding the limits of green hydrogen technology and how it can contribute to the UAE’s vision of clean energy, and aligns with DEWA's latest renewable initiatives now progressing in the emirate. “This pioneering project is a role model for strategic partnerships between the public and private sectors. It will contribute to developing the green economy concept in the UAE and explore the potential of green hydrogen technology. The hydrogen produced at the facility will be stored and deployed for re-electrification, transportation and other uses.”
Siemens is providing much of the technology that will be used at the demonstration facility, while DEWA expands its China outreach to woo renewable energy firms that can contribute to the ecosystem. Joe Kaeser, president and CEO of Siemens, said the UAE was the perfect location for Siemens to test the technology, building on advances in offshore green hydrogen the company is pursuing. One of the primary uses of the hydrogen produced will be to power Dubai’s public transportation system.
“We are aware of the stress that is placed on vehicles in this region due to the high levels of heat; with hydrogen cells, you are not putting as much strain on the vehicle and that improves its longevity,” Kaeser said. “However, this is only the first step and we are eager to explore more ways in which we can adapt the technology to other sectors. The interest from various companies and partners has been immense and we are eager to work with all interested parties.”
“Dewa, Expo 2020 Dubai and Siemens are working together to help realize His Highness Sheikh Mohammed bin Rashid Al Maktoum, Vice-President and Prime Minister of the UAE and Ruler of Dubai’s, vision to identify new energy resources and provide sustainable power as part of a balanced approach that prioritizes the environment. Our aim is to make Dubai a model of energy efficiency and safety,” said Sheikh Ahmed.
Expo 2020 Dubai intends to use the hydrogen generated at the facility to transport visitors to the Expo 2020 Dubai and the Mohammed bin Rashid Al Maktoum Solar Park, reflecting regional momentum such as Saudi Arabia's clean energy plans over the next decade, in hydrogen fuel cell powered vehicles. Live data of the green hydrogen electrolysis will be displayed at Expo 2020 Dubai to help inform broader efforts like hydrogen hubs in the United States.
Related News
WY Utility's First Wind Farm Faces Replacement
Foote Creek I Wind Farm Repowering upgrades Wyoming turbines with new nacelles, towers, and blades, cutting 68 units to 12 while sustaining 41.6 MW, under PacifiCorp and Rocky Mountain Power's Energy Vision 2020 plan.
Key Points
Replacement at Foote Creek Rim I, cutting to 12 turbines while sustaining about 41.6 MW using modern 2-4.2 MW units.
✅ 12 turbines replace 68, output steady near 41.6 MW
✅ New nacelles, towers, blades; taller 500 ft turbines
✅ Part of PacifiCorp Energy Vision 2020 and Gateway West
A Wyoming utility company has filed a permit to replace its first wind farm—originally commissioned in 1998, composed of over 65 turbines—amid new gas capacity competing with nuclear in Ohio, located at Foote Creek Rim I. The replacement would downsize the number of turbines to 12, which would still generate roughly the same energy output.
According to the Star Tribune, PacifiCorp’s new installation would involve new nacelles, new towers and new blades. The permit was filed with Carbon County.
New WY Wind Farm
The replacement wind turbines will stand more than twice as tall as the old: Those currently installed stand 200 feet tall, whereas their replacements will tower closer to 500 feet. Though this move is part of the company’s overall plan to expand its state wind fleet as some utilities respond to declining coal returns in the Midwest, the work going into the Foote Creek site is somewhat special, noted David Eskelsen, spokesperson for Rocky Mountain Power, the western arm of PacifiCorp.
“Foote Creek I repowering is somewhat different from the repowering projects announced in the (Energy Vision) 2020 initiative,” he said. “Foote Creek is a complete replacement of the existing 68 foundations, towers, turbine nacelles and rotors (blades).”
Currently, the turbines at Foote Creek have 600 kilowatts capacity each; the replacements’ maximum production ranges from 2 megawatts to 4.2 megawatts each, with the total output remaining steady at 41.4 megawatts, a scale similar to a 30-megawatt wind expansion in Eastern Kings, though there will be a slight capacity increase to 41.6 megawatts, according to the Star Tribune.
As part of the wind farm repowering initiative, PacifiCorp is to become full owner and operator of the Foote Creek site. When the farm was originally built, an Oregon-based water and electric board was 21 percent owner; 37 percent of the project’s output was tied into a contract with the Bonneville Power Administration.
Otherwise, PacifiCorp is moving to further expand its state wind fleet in line with initiatives like doubling renewable electricity by 2030 in Saskatchewan, with the addition of three new wind farms—to be located in Carbon, Albany and Converse counties—which may add up to 1,150 megawatts of power.
According to PacifiCorp, the company has more than 1,000 megawatts of owned wind generation capability, along with long-term purchase agreements for more than 600 megawatts from other wind farms owned by other entities. Energy Vision 2020 refers to a $3.5 billion investment and company move that is looking to upgrade the company's existing wind fleet with newer technology, adding 1,150 megawatts of new wind resources by 2020 and a a new 140-mile Gateway West transmission segment in Wyoming, comparable to a transmission project in Missouri just energized.
Related News
Cooperation agreement for Rosatom and Russian Academy
Rosatom-RAS Cooperation drives joint R&D in nuclear energy, nuclear medicine, fusion, particle accelerators, laser technologies, fuel cycle safety, radioactive waste management, and supercomputing, aligning strategic planning and standards to accelerate innovation across Russia's nuclear sector.
Key Points
A pact uniting Rosatom and RAS on nuclear R&D, fusion, and medicine to advance nuclear technologies across Russia.
✅ Joint R&D in fusion, accelerators, lasers, and new materials
✅ Focus on fuel cycle closure, safety, and waste management
✅ Shared strategic planning, standards, and expert evaluation
Russian state atomic energy corporation Rosatom and the Russian State Academy of Sciences are to cooperate on joint scientific, technical and innovative activities in areas including nuclear energy, nuclear medicine and other areas of the electricity sector under an agreement signed in Moscow on 7 February.
The cooperation agreement was signed by Rosatom Director General Alexei Likhachov and President of the Russian Academy of Sciences Alexander Sergeev during a joint meeting to mark Russian Science Day. Under its terms, the partners will cooperate in organising research and development activities aimed at providing technological advantages in various sectors of the domestic industry, as well as creating and developing interdisciplinary scientific and technological centres and organisations supporting energy sector training and innovation. They will also jointly develop strategic planning documents, improve the technical and scientific regulatory and legal framework, and carry out expert evaluations of scientific and technical projects and scientific consultations.
Rosatom said the main areas of cooperation in the agreement are: the development of laser technologies and particle accelerators; the creation of modern diagnostic equipment, nuclear medicine and radiation therapy; controlled thermonuclear fusion; nuclear energy of the future; new materials; the nuclear fuel cycle and its closure; safety of nuclear energy and power sector pandemic response preparedness; environmental aspects of radioactive waste management; modern supercomputers, databases, application packages, and import-substituting codes; and also X-ray astronomy and nuclear planetology.
Likhachov said joint activities between Rosatom and the Academy would strengthen the Russian nuclear industry's "leadership" in the world and allow the creation of new technologies that would shape the future image of the nuclear industry in Russia. "Within the framework of the Agreement, we intend to expand work on the entire spectrum of advanced scientific research. The most important direction of our cooperation will be the integration of fundamental, exploratory and applied scientific research, including in the interests of the development of the nuclear industry. We will work together to form the nuclear energy industry of the future, and enhance grid resilience, to create new materials, new radiation technologies,” he said.
Sergeyev noted the "rich history" of cooperation between the Academy of Sciences and the nuclear industry, including modern safety practices such as arc flash training that support operations. “All major projects in the field of military and peaceful nuclear energy were carried out jointly by scientists and specialists of our organisations, which largely ensured their timeliness and success," he said.
Related News
Indian government takes steps to get nuclear back on track
India Nuclear Generation Shortfall highlights missed five-year plan targets due to uranium fuel scarcity, commissioning delays at Kudankulam, PFBR slippage, and PHWR equipment bottlenecks under IAEA safeguards and domestic supply constraints.
Key Points
A gap between planned and actual nuclear output due to fuel shortages, reactor delays, and first-of-a-kind hurdles.
✅ Fuel scarcity pre-2009-10 constrained unsafeguarded reactors.
✅ Kudankulam delays from protests, litigation, and remobilisation.
✅ FOAK PHWR equipment bottlenecks and PFBR slippage.
A lack of available domestically produced nuclear fuel and delays in constructing and commissioning nuclear power plants, including first-of-a-kind plants and the Prototype Fast Breeder Reactor (PFBR), meant that India failed to meet its nuclear generation targets under the governmental plans over the decade to 2017, even as global project milestones were being recorded elsewhere.
India's nuclear generation target under its 11th five-year plan, covering the period 2007-2012, was 163,395 million units (MUs) and the 12th five-year Plan (2012-17) was 241,748 MUs, Minister of state for the Department of Atomic Energy and the Prime Minister's Office Jitendra Singh told parliament on 6 February. Actual nuclear generation in those periods was 109,642 MUs and 183,488 MUs respectively, Singh said in a written answer to questions in the Lok Sabah.
Singh attributed the shortfall in generation to a lack of availability of the necessary quantities of domestically produced fuel during the three years before 2009-2010; delays to the commissioning of two 1000 MWe nuclear power plants at Kudankulam due to local protests and legal challenges; and delays in the completion of two indigenously designed pressurised heavy water reactors and the PFBR.
Kudankulam 1 and 2 are VVER-1000 pressurised water reactors (PWRs) supplied by Russia's Atomstroyexport under a Russian-financed contract. The units were built by Nuclear Power Corporation of India Ltd (NPCIL) and were commissioned and are operated by NPCIL under International Atomic Energy Agency (IAEA) safeguards, with supervision from Russian specialists, while China's nuclear program advanced on a steady development track in the same period. Construction of the units - the first PWRs to enter operation in India - began in 2002.
Singh said local protests resulted in the halt of commissioning work at Kudankulam for nine months from September 2011 to March 2012, when he said project commissioning had been at its peak. As a consequence, additional time was needed to remobilise the workforce and contractors, he said. Litigation by anti-nuclear groups, and compliance with supreme court directives, impacted commissioning in 2013, he said. Unit 1 entered commercial operation in December 2014 and unit 2 in April 2017.
Delays in the manufacture and supply by domestic industry of critical equipment for first-of-a-kind 700 MWe pressurised heavy water reactors - Kakrapar units 3 and 4, and Rajasthan units 7 and 8 - has led to delays in the completion of those units, the minister said, as well as noting the delay in completion of the PFBR, which is being built at Kalpakkam by Bhavini. In answer to a separate question, Singh said the PFBR is in an "advance stage of integrated commissioning" and is "expected to approach first criticality by the year 2020."
Eight of India's operating nuclear power plants are not under IAEA safeguards and can therefore only use indigenously-sourced uranium. The other 14 units operate under IAEA safeguards and can use imported uranium. The Indian government has taken several measures to secure fuel supplies for reactors in operation and under construction, amid coal supply rationing pressures elsewhere in the power sector, concluding fuel supply contracts with several countries for existing and future reactors under IAEA Safeguards and by "augmentation" of fuel supplies from domestic sources, Singh said.
Kakrapar 3 and 4, with Kakrapar 3 criticality already reported, and Rajasthan 7 and 8 are all currently expected to enter service in 2022, according to World Nuclear Association information.
Joint venture discussions
In February 2016 the government amended the Atomic Energy Act to allow NPCIL to form joint venture companies with other public sector undertakings (PSUs) for involvement in nuclear power generation and possibly other aspects of the fuel cycle, reflecting green industrial strategies shaping future reactor waves globally. In answer to another question, Singh confirmed that NPCIL has entered into joint ventures with NTPC Limited (National Thermal Power Corporation, India's largest power company) and Indian Oil Corporation Limited. Two joint venture companies - Anushakti Vidhyut Nigam Limited and NPCIL-Indian Oil Nuclear Energy Corporation Limited - have been incorporated, and discussions on possible projects to be set up by the joint venture companies are in progress.
An exploratory discussion had also been held with Oil & Natural Gas Corporation, Singh said. Indian Railways - which has in the past been identified as a potential joint venture partner for NPCIL - had "conveyed that they were not contemplating entering into an MoU for setting up of nuclear power plants," Singh said.
Related News
Price Spikes in Ireland Fuel Concerns Over Dispatachable Power Shortages in Europe
ISEM Price Volatility reflects Ireland-Northern Ireland grid balancing pressures, driven by dispatchable power shortages, day-ahead market dynamics, renewable shortfalls, and interconnector constraints, affecting intraday trading, operational reserves, and cross-border electricity flows.
Key Points
ISEM price volatility is Irish power price swings from grid balancing stress and limited dispatchable capacity.
✅ One-off spike linked to plant outage and low renewables
✅ Day-ahead market settling; intraday trading integration pending
✅ Interconnectors and reserves vital to manage adequacy
Irish grid-balancing prices soared to €3,774 ($4,284) per megawatt-hour last month amid growing concerns over dispatchable power capacity across Europe.
The price spike, triggered by an alert regarding generation losses, came only four months after Ireland and Northern Ireland launched an Integrated Single Electricity Market (ISEM) designed to make trading more competitive and improve power distribution across the island.
Evie Doherty, senior consultant for Ireland at Cornwall Insight, a U.K.-based energy consultancy, said significant price volatility was to be expected while ISEM is still settling down, aligning with broader 2019 grid edge trends seen across markets.
When the U.K. introduced a single market for Great Britain, called British Electricity Trading and Transmission Arrangements, in 2005, it took at least six months for volatility to subside, Doherty said.
In the case of ISEM, “it will take more time to ascertain the exact drivers behind the high prices,” she said. “We are being told that the day-ahead market is functioning as expected, but it will take time to really be able to draw conclusions on efficiency.”
Ireland and Northern Ireland have been operating with a single market “very successfully” since 2007, said Doherty. Although each jurisdiction has its own regulatory authority, they make joint decisions regarding the single market.
ISEM, launched in October 2018, was designed to help include Ireland and Northern Ireland day-ahead electricity prices in a market pricing system called the European Union Pan-European Hybrid Electricity Market Integration Algorithm.
In time, ISEM should also allow the Irish grids to participate in European intraday markets, and recent examples like Ukraine's grid connection underline the pace of integration efforts across Europe. At present, they are only able to do so with Great Britain. “The idea was to...integrate energy use and create more efficient flows between jurisdictions,” Doherty said.
EirGrid, the Irish transmission system operator, has reported that flows on its interconnector with Northern Ireland are more efficient than before, she said.
The price spike happened when the System Operator for Northern Ireland issued an alert for an unplanned plant outage at a time of low renewable output and constraints on the north-south tie-line with Ireland, according to a Cornwall Insight analysis.
Not an isolated event
Although it appears to have been a one-off event, there are increasing worries that a shortage of dispatchable power could lead to similar situations elsewhere across Europe, as seen in Nordic grid constraints recently.
Last month, newspaper Frankfurter Allgemeine Zeitung (FAZ) reported that German industrial concerns had been forced to curtail more than a gigawatt of power consumption to maintain operational reserves on the grid in December, after renewable production fell short of expectations and harsh weather impacts strained systems elsewhere.
Paul-Frederik Bach, a Danish energy consultant, has collected data showing that this was not an isolated incident. The FAZ report said German aluminum smelters had been forced to cut back on energy use 78 times in 2018, he noted.
Energy availability was also a concern last year in Belgium, where six out of seven nuclear reactors had been closed for maintenance. The closures forced Belgium to import 23 percent of its electricity from neighboring countries, Bach reported.
In a separate note, Bach revealed that 11 European countries that were net importers of energy had boosted their imports by 26 percent between 2017 and 2018. It is important to note that electricity imports do not necessarily imply a shortage of power, he stated.
However, it is also true that many European grid operators are girding themselves for a future in which dispatchable power is scarcer than today.
EirGrid, for example, expects dispatchable generation and interconnection capacity to drop from 10.6 gigawatts in 2018 to 9 gigawatts in 2027.
The Swedish transmission system operator Svenska Kraftnät, meanwhile, is forecasting winter peak power deficits could rise from 400 megawatts currently to 2.5 gigawatts in 2020-21.
Research conducted by the European Network of Transmission System Operators for Electricity, suggests power adequacy will fall across most of Europe up to 2025, although perhaps not to a critical degree.
The continent’s ability to deal with the problem will be helped by having more efficient trading systems, Bach told GTM. That means developments such as ISEM could be a step in the right direction, despite initial price volatility.
In the long run, however, Europe will need to make sure market improvements are accompanied by investments in HVDC technology and interconnectors and reserve capacity. “Somewhere there must be a production of electricity, even when there is no wind,” said Bach.
Related News
As Maine debates 145-mile electric line, energy giant with billions at stake is absent
Hydro-Quebec NECEC Transmission Line faces Maine PUC scrutiny over clean energy claims, greenhouse gas emissions, spillage capacity, resource shuffling, and Massachusetts contracts, amid opposition from natural gas generators and environmental groups debating public need.
Key Points
A $1B Maine corridor for Quebec hydropower to Massachusetts, debated over emissions, spillage, and public need.
✅ Maine PUC weighing public need and ratepayer benefits
✅ Emissions impact disputed: resource shuffling vs new supply
✅ Hydro-Quebec spillage claims questioned without data
As Maine regulators are deciding whether to approve construction of a $1 billion electricity corridor across much of western Maine, the Canadian hydroelectric utility poised to make billions of dollars from the project has been absent from the process.
This has left both opponents and supporters of the line arguing about how much available energy the utility has to send through a completed line, and whether that energy will help fulfill the mission of the project: fighting climate change.
And while the utility has avoided making its case before regulators, which requires submitting to cross-examination and discovery, it has engaged in a public relations campaign to try and win support from the region's newspapers.
Government-owned Hydro-Quebec controls dams and reservoirs generating hydroelectricity throughout its namesake province. It recently signed agreements to sell electricity across the proposed line, named the New England Clean Energy Connect, to Massachusetts as part of the state's effort to reduce its dependence on fossil fuels, including natural gas.
At the Maine Public Utilities Commission, attorneys for Central Maine Power Co., which would build and maintain the line, have been sparring with the opposition over the line's potential impact on Maine and its electricity consumers. Leading the opposition is a coalition of natural gas electricity generators that stand to lose business should the line be built, as well as the Natural Resources Council of Maine, an environmental group.
That unusual alliance of environmental and business groups wants Hydro-Quebec to answer questions about its hydroelectric system, which they argue can't deliver the amount of electricity promised to Massachusetts without diverting energy from other regions.
In that scenario, critics say the line would not produce the reduction in greenhouse gas emissions that CMP and Hydro-Quebec have made a central part of their pitch for the project. Instead, other markets currently buying energy from Hydro-Quebec, such as New York, Ontario and New Brunswick, would see hydroelectricity imports decrease and have to rely on other sources of energy, including coal or oil, to make up the difference. If that happened, the total amount of clean energy in the world would remain the same.
Opponents call this possibility "greenwashing." Massachusetts regulators have described these circumstances as "resource shuffling."
But CMP spokesperson John Carroll said that if hydropower was diverted from nearby markets to power Massachusetts, those markets would not turn to fossil fuels. Rather they would seek to develop other forms of renewable energy "leading to further reductions in greenhouse gas emissions in the region."
Hydro-Quebec said it has plenty of capacity to increase its electricity exports to Massachusetts without diverting energy from other places.
However, Hydro-Quebec is not required to participate -- and has not voluntarily participated -- in regulatory hearings where it would be subject to cross examinations and have to testify under oath. Some participants wish it would.
At a January hearing at the Maine Public Utilities Commission, hearing examiner Mitchell Tannenbaum had to warn experts giving testimony to "refrain from commentary regarding whether Hydro-Quebec is here or not" after they complained about its absence when trying to predict potential ramifications of the line.
"I would have hoped they would have been visible and available to answer legitimate questions in all of these states through which their power is going to be flowing," said Dot Kelly, a member of the executive committee at the Maine Chapter of the Sierra Club who has participated in the line's regulatory proceedings as an individual. "If you're going to have a full and fair process, they have to be there."
[What you need to know about the CMP transmission line proposed for Maine]
While Hydro-Quebec has not presented data on its system directly to Maine regulators, it has brought its case to the press. Central to that case is the fact that it's "spilling" water from its reservoirs because it is limited by how much electricity it can export. It said that it could send more water through its turbines and lower reservoir levels, eliminating spillage and creating more energy, if only it had a way to get that energy to market. Hydro-Quebec said the line would make that possible, and, in doing so, help lower emissions and fight climate change.
"We have that excess potential that we need to use. Essentially, it's a good problem to have so long as you can find an export market," Hydro-Quebec spokesperson Serge Abergel told the Bangor Daily News.
Hydro-Quebec made its "spillage" case to the editorial boards of The Boston Globe, The Portland Press Herald and the BDN, winning qualified endorsements from the Globe and Press Herald. (The BDN editorial board has not weighed in on the project).
Opponents have questioned why Hydro-Quebec is willing to present their case to the press but not regulators.
"We need a better answer than 'just trust us,'" Natural Resources Council of Maine attorney Sue Ely said. "What's clear is that CMP and HQ are engaging in a full-court publicity tour peddling false transparency in an attempt to sell their claims of greenhouse gas benefits."
Energy generators aren't typically parties to public utility commission proceedings involving the building of transmission lines, but Maine regulators don't typically evaluate projects that will help customers in another state buy energy generated in a foreign country.
"It's a unique case," said Maine Public Advocate and former Democratic Senate Minority Leader Barry Hobbins, who has neither endorsed nor opposed the project. Hobbins noted the project was not proposed to improve reliability for Maine electricity customers, which is typically the point of new transmission line proposals evaluated by the commission. Instead, the project "is a straight shot to Massachusetts," Hobbins said.
Maine Public Utilities Commission spokesperson Harry Lanphear agreed. "The Commission has never considered this type of project before," he said in an email.
In order to proceed with the project, CMP must convince the Maine Public Utilities Commission that the proposed line would fill a "public need" and benefit Mainers. Among other benefits, CMP said it will help lower electricity costs and create jobs in Maine. A decision is expected in the spring.
Given the uniqueness of the case, even the commission seems unsure about how to apply the vague "public need" standard. On Jan. 14, commission staff asked case participants to weigh in on how it should apply Maine law when evaluating the project, including whether the hydroelectricity that would travel over the line should be considered "renewable" and whether Maine's own carbon reduction goals are relevant to the case.
James Speyer, an energy consultant whose firm was hired by natural gas company and project opponent Calpine to analyze the market impacts of the line, said he has testified before roughly 20 state public utility commissions and has never seen a proceeding like this one.
"I've never been in a case where one of the major beneficiaries of the PUC decision is not in the case, never has filed a report, has never had to provide any data to support its assertions, and never has been subject to cross examination," Speyer said. "Hydro-Quebec is like a black box."
Hydro-Quebec would gladly appear before the Maine Public Utilities Commission, but it has not been invited, said spokesperson Abergel.
"The PUC is doing its own process," Abergel said. "If the PUC were to invite us, we'd gladly intervene. We're very willing to collaborate in that sense."
But that's not how the commission process works. Individuals and organizations can intervene in cases, but the commission does not invite them to the proceedings, commission spokesperson Lanphear said.
CMP spokesperson Carroll dismissed concerns over emissions, noting that Hydro-Quebec is near the end of completing a more than 15-year effort to develop its clean energy resources. "They will have capacity to satisfy the contract with Massachusetts in their reservoirs," Carroll said.
While Maine regulators are evaluating the transmission line, Massachusetts' Department of Public Utilities is deciding whether to approve 20-year contracts between Hydro-Quebec and that state's electric utilities. Those contracts, which Hydro-Quebec has estimated could be worth close to $8 billion, govern how the utility sells electricity over the line.
Dean Murphy, a consultant hired by the Massachusetts Attorney General's office to review the contracts, testified before Massachusetts regulators that the agreements do not require a reduction in global greenhouse gas emissions. Murphy also warned the contracts don't actually require Hydro-Quebec to increase the total amount of energy it sends to New England, as energy could be shuffled from established lines to the proposed CMP line to satisfy the contracts.
Parties in the Massachusetts proceeding are also trying to get more information from Hydro-Quebec. Energy giant NextEra is currently trying to convince Massachusetts regulators to issue a subpoena to force Hydro-Quebec to answer questions about how its exports might change with the construction of the transmission line. Hydro-Quebec and CMP have opposed the motion.
Hydro-Quebec has a reputation for guarding its privacy, according to Hobbins.
"It would have been easier to not have to play Sherlock Holmes and try to guess or try to calculate without having a direct 'yes' or 'no' response from the entity itself," Hobbins said.
Ultimately, the burden of proving that Maine needs the line falls on CMP, which is also responsible for making sure regulators have all the information they need to make a decision on the project, said former Maine Public Utilities Commission Chairman Kurt Adams.
"Central Maine Power should provide the PUC with all the info that it needs," Adams said. "If CMP can't, then one might argue that they haven't met their burden."
'They treat HQ with nothing but distrust'
If completed, the line would bring 9.45 terawatt hours of electricity from Quebec to Massachusetts annually, or about a sixth of the total amount of electricity Massachusetts currently uses every year (and roughly 80 percent of Maine's annual load). CMP's parent company Avangrid would make an estimated $60 million a year from the line, according to financial analysts.
As part of its legally mandated efforts to reduce carbon emissions and fight climate change, Massachusetts would pay the $950 million cost of constructing the line. The state currently relies on natural gas, a fossil fuel, for nearly 70 percent of its electricity, a figure that helps explain natural gas companies' opposition to the project.
A panel of experts recently warned that humanity has 12 years to keep global temperatures from rising above 1.5 degrees Celsius and prevent the worst effects of climate change, which include floods, droughts and extreme heat.
The line could lower New England's annual carbon emissions by as much as 3 million metric tons, an amount roughly equal to Washington D.C.'s annual emissions. Opponents worry that reduction could be mostly offset by increases in other markets.
But while both sides have claimed they are fighting for the environment, much of the debate features giant corporations with headquarters outside of New England fighting over the future of the region's electricity market, echoing customer backlash seen in other utility takeovers.
Hydro-Quebec is owned by the people of Quebec, and CMP is owned by Avangrid, which is in turn owned by Spanish energy giant Iberdrola. Leading the charge against the line are several energy companies in the Fortune 500, including Houston-based Calpine and Florida-based NextEra Energy.
However, only one side of the debate counts environmental groups as part of its coalition, and, curiously enough, that's the side with fossil fuel companies.
Some environmental groups, including the Natural Resources Council of Maine and Environment Maine, have come out against the line, while others, including the Acadia Center and the Conservation Law Foundation, are still deciding whether to support or oppose the project. So far, none have endorsed the line.
"It is discouraging that some of the environmental groups are so opposed, but it seems the best is the enemy of the good," said CMP's Carroll in an email. "They seem to have no sense of urgency; and they treat HQ with nothing but distrust."
Much of the environmentally minded opposition to the project focuses on the impact the line would have on local wildlife and tourism.
Sandi Howard administers the Say NO To NECEC Facebook page and lives in Caratunk, one of the communities along the proposed path of the line. She said opposition to the line might change if it was proven to reduce emissions.
"If it were going to truly reduce global CO2 emissions, I think it would be be a different conversation," Howard said.
Not the first choice
Before Maine, New Hampshire had its own debate over whether it should serve as a conduit between Quebec and Massachusetts. The proposed Northern Pass transmission line would have run the length of the state. It was Massachusetts' first choice to bring Quebec hydropower to its residents.
But New Hampshire's Site Evaluation Committee unanimously voted to reject the Northern Pass project in February 2018 on the grounds that the project's sponsor, Eversource, had failed to prove the project would not interfere with local business and tourism. Though it was the source of the electricity that would have traveled over the line, Hydro-Quebec was not a party to the proceedings.
In its decision, the committee noted the project would not reduce emissions if it was not coupled with a "new source of hydropower" and the power delivered across the line was "diverted from Ontario and New York." The committee added that it was unclear if the power would be new or diverted.
The next month, Massachusetts replaced Northern Pass by selecting CMP's proposed line. As the project came before Maine regulators, questions about Hydro-Quebec and emissions persisted. Two different analyses of CMP's proposed line, including one by the Maine Public Utility Commission's independent consultant, found the line would greatly reduce New England's emissions.
But neither of those studies took into account the line's impact on emissions outside of New England. A study by Calpine's consultant, Energyzt, found New England's emissions reduction could be mostly offset by increased emissions in other areas, including New Brunswick and New York, that would see hydroelectricity imports shrink as energy was redirected to fulfill the contract with Massachusetts.
'They failed in any way to back up those spillage claims'
Hydro-Quebec seemed content to let CMP fight for the project alone before regulators for much of 2018. But at the end of the year, the utility took a more proactive approach, meeting with editorial boards and providing a two-page letter detailing its "spillage" issues to CMP, which entered it into the record at the Maine Public Utilities Commission.
The letter provided figures on the amount of water the utility spilled that could have been converted into sellable energy, if only Hydro-Quebec had a way to get it to market. Instead, by "spilling" the water, the company essentially wasted it.
Instead of sending water through turbines or storing it in reservoirs, hydroelectric operators sometimes discharge water held behind dams down spillways. This can be done for environmental reasons. Other times it is done because the operator has so much water it cannot convert it into electricity or store it, which is usually a seasonal issue: Reservoirs often contain the most water in the spring as temperatures warm and ice melts.
Hydro-Quebec said that, in 2017, it spilled water that could have produced 4.5 terawatt hours of electricity, or slightly more than half the energy needed to fulfill the Massachusetts contracts. In 2018, the letter continued, Hydro-Quebec spilled water that could have been converted into 10.4 terawatts worth of energy. The company said it didn't spill at all due to transmission constraints prior to 2017.
The contracts Hydro-Quebec signed with the Massachusetts utilities are for 9.45 terawatt hours annually for 20 years. In its letter, the utility essentially showed it had only one year of data to show it could cover the terms of the contract with "spilled" energy.
"Reservoir levels have been increasing in the last 15 years. Having reached their maximum levels, spillage maneuvers became necessary in 2017 and 2018," said Hydro-Quebec spokesperson Lynn St. Laurent.
By providing the letter through CMP, Hydro-Quebec did not have to subject its spillage figures to cross examination.
Dr. Shaleen Jain, a civil and environmental engineering professor at the University of Maine, said that, while spilled water could be converted into power generation in some circumstances, spills happen for many different reasons. Knowing whether spillage can be translated into energy requires a great deal of analysis.
"Not all of it can be repurposed or used for hydropower," Jain said.
In December, one of the Maine Public Utility Commission's independent consultants, Gabrielle Roumy, told the commission that there's "no way" to "predict how much water would be spilled each and every year." Roumy, who previously worked for Hydro-Quebec, added that even after seeing the utility's spillage figures, he believed it would need to divert energy from other markets to fulfill its commitment to Massachusetts.
"I think at this point we're still comfortable with our assumptions that, you know, energy would generally be redirected from other markets to NECEC if it were built," Roumy said.
In January, Tanya Bodell, the founder and executive director of consultant Energyzt, testified before the commission on behalf of Calpine that it was impossible to know why Hydro-Quebec was spilling without more data.
"There's a lot of details you'd have to look at in order to properly assess what the reason for the spillage is," Bodell said. "And you have to go into an hourly level because the flows vary across the year, within the month, the week, the days. ...And, frankly, it would have been nice if Hydro-Quebec was here and brought their model and allowed us to see how this could help them to sell more."
Even though CMP and Hydro-Quebec's path to securing approval of the project does not go through the Legislature, and despite a Maine court ruling that energized Hydro-Quebec's export bid, lawmakers have taken notice of Hydro-Quebec's absence. Rep. Seth Berry, D-Bowdoinham, the House chairman of the Joint Committee On Energy Utilities and Technology and a frequent critic of CMP, said he would like to see Hydro-Quebec "show up and subject their proposal to examination and full analysis and public examination by the regulators and the people of Maine."
"They're trying to sell an incredibly lucrative proposal, and they failed in any way to back up those spillage claims with defensible numbers and defensible analysis," Berry said.
Berry was part of a bipartisan group of Maine lawmakers that wrote a letter to Massachusetts regulators last year expressing concerns about the project, which included doubts about whether the line would actually reduce global gas emissions. On Monday, he announced legislation that would direct the state to create an independent entity to buy out CMP from its foreign investors.
'No benefit to remaining quiet'
Hydro-Quebec would like to provide answers, but "there is always a commercially sensitive information concern when we do these things," said spokesperson Abergel.
"There might be stuff we can do, having an independent study that looks at all of this. I'm not worried about the conclusion," Abergel said. "I'm worried about how long it takes."
Instead of asking Hydro-Quebec questions directly, participants in both Maine and Massachusetts regulatory proceedings have had to direct questions for Hydro-Quebec to CMP. That arrangement may be part of Hydro-Quebec's strategy to control its information, said former Maine Public Utilities Commissioner David Littell.
"From a tactical point of view, it may be more beneficial for the evidence to be put through Avangrid and CMP, which actually doesn't have that back-up info, so can't provide it," Littell said.
Getting information about the line from CMP, and its parent company Avangrid, has at times been difficult, opponents say.
In August 2018, the commission's staff warned CMP in a legal filing that it was concerned "about what appears to be a lack of completeness and timeliness by CMP/Avangrid in responding to data requests in this proceeding."
The trouble in getting information from Hydro-Quebec and CMP only creates more questions for Hydro-Quebec, said Jeremy Payne, executive director of the Maine Renewable Energy Association, which opposes the line in favor of Maine-based renewables.
"There's a few questions that should have relatively simple answers. But not answering a couple of those questions creates more questions," Payne said. "Why didn't you intervene in the docket? Why are you not a party to the case? Why won't you respond to these concerns? Why wouldn't you open yourself up to discovery?"
"I don't understand why they won't put it to bed," Payne said. "If you've got the proof to back it up, then there's no benefit to remaining quiet."
Related News
Hydro Quebec to increase hydropower capacity to more than 37,000 MW in 2021
Hydro Quebec transmission expansion aims to move surplus hydroelectric capacity from record reservoirs to the US grid via new interties, increasing exports to New England and New York amid rising winter peak demand.
Key Points
A plan to add capacity and intertie links to export surplus hydro power from Quebec's reservoirs to the US grid.
✅ 245 MW added in 2021; portfolio reaches 37,012 MW
✅ Reservoirs at unprecedented levels; export potential high
✅ Lacks US transmission; working on new interties
Hydro Quebec plans to add an incremental 245 MW of hydro-electric generation capacity in 2021 to its expansive portfolio in the north of the province, while Quebec authorized nearly 1,000 MW for industrial projects across the region, bringing the total capacity to 37,012 MW, an official said Friday
Quebec`s highest peak demand of 39,240 MW occurred on January 22, 2014.
A little over 75% of Quebec`s population heat their homes with electricity, Sutherland said, aligning with Hydro Quebec's strategy to wean the province off fossil fuels over time.
The province-owned company produced 205.1 TWh of power in 2017 and its net exports were 34.4 TWh that year, while Ontario chose not to renew a power deal in a separate development.
Sutherland said Hydro Quebec`s reservoirs are currently at "unprecedented levels" and the company could export more of its electricity to New England and New York, but faces transmission constraints that limit its ability to do so.
Hydro Quebec is working with US transmission developers, electric distribution companies, independent system operators and state government agencies to expand that transmission capacity in order to delivery more power from its hydro system to the US, Sutherland said.
Separately, NB Power signed three deals to bring more Quebec electricity into the province, reflecting growing regional demand.
The last major intertie connection between Quebec and the US was completed close to 30 years ago. The roughly 2,000 MW capacity transmission line that connects into the Boston area was completed in the late 1990s, according to Hydro Quebec spokeswoman Lynn St-Laurent.
Related News
Transmission constraints impede incremental Quebec-to-US power deliveries
Hydro-Québec Northeast Clean Energy Transmission delivers surplus hydropower via HVDC interconnections to New York and New England, leveraging long-term contracts and projects like CHPE and NECEC to support carbon-free goals, GHG cuts, and grid reliability.
Key Points
An initiative to expand HVDC links for Quebec hydropower exports, aiding New York and New England decarbonization.
✅ 37,000 MW hydro capacity enables firm, low-carbon exports
✅ Targets NY and NE via CHPE, NECEC, and upgraded interfaces
✅ Backed by long-term PPAs to reduce merchant transmission risk
With roughly 37,000 MW of installed hydro power capacity, Quebec has ample spare capacity that it would like to deliver into Northeastern US markets where ambitious clean energy goals have been announced, but expanding transmission infrastructure is challenging.
Register Now New York recently announced a goal of receiving 100% carbon-free energy by 2040 and the New England states all have ambitious greenhouse gas reduction goals, including a Massachusetts law requiring GHG emissions be 80% below 1990 levels by 2050.
The province-owned company, Hydro Quebec, supplies power to the provinces of Quebec, Ontario and New Brunswick in particular, as well as sending electricity directly into New York and New England. The power transmission interconnections between New York and New England have reached capacity and in order to increase export volumes into the US, "we need to build more transmission infrastructure," Gary Sutherland, relationship manager in business development, recently said during a presentation to reporters in Montreal.
TRANSMISSION OPTIONS
Hydro Quebec is working with US transmission developers, electric distribution companies, independent system operators and state government agencies to expand that transmission capacity in order to delivery more power from its hydro system to the US, as the province has closed the door on nuclear power and continues to prioritize hydropower, Sutherland said.
The company is looking to sign long-term power supply contracts that could help alleviate some of the investment risk associated with these large infrastructure projects.
"It`s interesting to recall that in the 1980s, two decade-long contracts paved the way for construction of Phase II of the multi-terminal direct-current system (MTDCS), a cross-border line that delivers up to 2,000 MW from northern Quebec to New England," Hydro Quebec spokeswoman Lynn St-Laurent said in an email.
Long-term prices have been persistently low since 2012, following the shale gas boom and the economic decline in 2008-2009, St-Laurent said. "As such, investment risks are too high for merchant transmission projects," she said.
Northeast power market fundamentals "remain strong for long-term contracts," on transmission projects or equipment upgrades that can deliver clean power from Quebec and "help our neighbors reach their ambitious clean energy goals," St-Laurent said.
NEW ENGLAND
In March 2017 an HQ proposal was selected by Massachusetts regulators to supply 9.45 TWh of firm energy to be delivered for 20 years. HQ`s proposal consisted of hydro power supply and possible transmission scenarios developed in conjunction with US partners.
The two leading options include a route through New Hampshire called Northern Pass and New England Clean Energy Connect through Maine.
The New Hampshire Site Evaluation Committee in March 2018 voted unanimously to deny approval of the $1.6 billion Northern Pass Transmission project, which is a joint venture between HQ and Eversource Energy`s transmission business. Eversource has been fighting the decision, with the New Hampshire Supreme Court accepting the company`s appeal of the NHSEC decision in October.
Briefs are being filed and oral arguments are likely to begin late spring or early summer, spokesman William Hinkle said in an email Tuesday.
After the Northern Pass permitting delay, Massachusetts chose the New England Clean Energy Connect project, which is a projected 1,200 MW transmission line, with 1,090 MW contracted to Massachusetts, leaving 110 MW for use on a merchant basis, according to St-Laurent.
NECEC is a joint venture between HQ and Central Maine Power, which is a subsidiary of Avangrid, a company affiliated with Spain`s Iberdrola. The NECEC project has received opposition from some environmental groups and still needs several state and federal permits.
NEW YORK
"The 5% of New York`s load that we furnish year in and year out ... is mostly going into the north of the state, it`s not coming down here," Sutherland said during a discussion at Pace University in New York City in 2017.
One potential project moving through the permitting phase, is the $2.2 billion, 1,000-MW Champlain Hudson Power Express transmission line being pursued by Transmission Developers -- a Blackstone portfolio company -- that would transport power from Quebec to Queens, New York.
Under New York`s proposed Climate Leadership Act which calls for the 100% carbon-free energy goal, renewable generation eligibility would be determined by the Public Service Commission. The PSC did not respond to a question about whether hydro power from Quebec is being considered as a potential option for meeting the state`s clean energy goal.
Related News
Customers on the hook for $5.5 billion in deferred BC Hydro operating costs: report
BC Hydro Deferred Regulatory Assets detail $5.5 billion in costs under rate-regulated accounting, to be recovered from ratepayers, highlighting B.C. Utilities Commission oversight, audit scrutiny, financial reporting impacts, and public utility governance.
Key Points
BC Hydro defers costs as regulatory assets to recover from ratepayers, influencing rates and financial reporting.
✅ $5.5B in deferred costs recorded as net regulatory assets
✅ Rate impacts tied to B.C. Utilities Commission oversight
✅ Auditor General to assess accounting and governance
Auditor General Carol Bellringer says BC Hydro has deferred $5.5 billion in expenses that it plans to recover from ratepayers in the future, as rates to rise by 3.75% over two years.
Bellringer focuses on the deferred expenses in a report on the public utility's use of rate-regulated accounting to control electricity rates for customers.
"As of March 31, 2018, BC Hydro reported a total net regulatory asset of $5.455 billion, which is what ratepayers owe," says the report. "BC Hydro expects to recover this from ratepayers in the future. For BC Hydro, this is an asset. For ratepayers, this is a debt."
She says rate-regulated accounting is used widely across North America, but cautions that Hydro has largely overridden the role of the independent B.C. Utilities Commission to regulate rates.
"We think it's important for the people of B.C. and our members of the legislative assembly to better understand rate-regulated accounting in order to appreciate the impact it has on the bottom line for BC Hydro, for government as a whole, for ratepayers and for taxpayers, especially following a three per cent rate increase in April 2018," Bellringer said in a conference call with reporters.
Last June, the B.C. government launched a two-phase review of BC Hydro to find cost savings and look at the direction of the Crown utility, amid calls for change from advocates.
The review came shortly after a planned government rate freeze was overturned by the utilities commission, which resulted in a three per cent rate increase in April 2018.
A statement by BC Hydro and the government says a key objective of the review due this month is to enhance the regulatory oversight of the commission.
Bellringer's office will become BC Hydro's auditor next year — and will be assessing the impact of regulation on the utility's financial reporting.
"It is a complex area and confidence in the regulatory system is critical to protect the public interest," wrote Bellringer.
Related News
Federal government spends $11.8M for smart grid technology in Sault Ste. Marie
Sault Ste. Marie Smart Grid Investment upgrades PUC Distribution infrastructure with federal funding, clean energy tech, outage reduction, customer insights, and reliability gains, creating 140 jobs and attracting industry to a resilient, efficient grid.
Key Points
A federally funded PUC Distribution project to modernize the citywide grid, cut outages, boost efficiency, and create jobs.
✅ $11.8M federal funding to PUC Distribution
✅ Citywide smart grid cuts outages and energy loss
✅ 140 jobs; attracts clean tech and industry
PUC Distribution Inc. in Sault Ste. Marie is receiving $11.8 million from the federal government to invest in infrastructure, as utilities nationwide have faced pandemic-related losses that underscore the need for resilient systems.
The MP for the riding, Terry Sheehan, made the announcement on Monday.
The money will go to the utility's smart grid project, where technologies like a centralized SCADA system can enhance situational awareness and control.
"This smart grid project offers a glimpse into our clean energy future and represents a new wave of economic activity for the region," Sheehan said.
"Along with job creation, new industries will be attracted to a modern grid, supported by stable electricity pricing that helps competitiveness, all while helping the environment."
His office says the investment will allow the utility to reduce outages, provide more information to customers to help make smarter electricity use choices, aligned with Ontario's energy-efficiency programs that encourage conservation, and offer more services.
"This is an innovative project that makes Sault Ste. Marie a leader," mayor Christian Provenzano said.
"We will be the first city in our country to implement a community-wide smart grid. Once it is complete, the smart grid will make our energy infrastructure more reliable, reduce energy loss and lead to a more innovative economy for our community."
The project will also create 140 new jobs.
"As a community-focused utility, we are always looking for innovative ways to help our customers save money amid concerns about hydro disconnections during winter, and reduce their carbon footprint," Rob Brewster, president and CEO of PUC Distribution said.
"The investment the government has made in our community will not only help modernize our city's electrical distribution system [as] once the project is complete, Sault Ste. Marie will have access to an electricity grid that can handle the growing demands of a city in the 21st century."
