Vineyard Wind said it has obtained federal approval to resume construction of the wind farm – work that was suspended following the partial collapse of a previously installed turbine blade on July 13.

A press release issued at 7 a.m. Tuesday morning said the Bureau of Safety and Environmental Enforcement had given the developers of the wind farm permission to resume the installation of towers and nacelles (which sit atop the tower and convert wind energy into electricity), but a suspension remains in effect for turbine blades and power generation.

Vineyard Wind is a 62-turbine project and only 24 had been completed at the time of the accident. Work is resuming on the remaining 38 turbines but blades cannot be installed nor power produced under the terms of the revised suspension order. Of the 24 completed turbines, 11 were generating electricity at the time of the incident and 13, including the one that broke, were undergoing testing.

In a joint press release, Vineyard Wind and GE Vernova, the manufacturer of the wind turbines, said a barge departed the New Bedford Marine Commerce Terminal Tuesday morning for the wind farm carrying turbine components, including several tower sections and one nacelle.

“The vessel will also carry a rack of three blades solely for the purpose of ensuring safe and balanced composition for the transport,” the press release said, adding that the blades will not be installed and will be returned to New Bedford later in the week.  

The press release said the Bureau of Safety and Environmental Enforcement revised its suspension order after examining records and a structural load analysis conducted by a third party. The federal agency had no mention of a revised suspension order on its website Tuesday morning.

Vineyard Wind and GE Vernova also said “a substantial amount” of what remained of the damaged blade was cut away on Sunday and Monday.

“During the operations, Vineyard Wind and GE Vernova mobilized maritime crews on multiple vessels nearby to secure as much debris as possible for immediate containment and removal as well as land-based crews managing debris recovery,” the press release said. ”Vineyard Wind and GE Vernova are currently assessing next steps to complete any additional cutting necessary at the earliest opportunity, secure and remove the debris on the turbine platform, remove the blade root, and address the debris on the seabed.”

The blade incident at Vineyard Wind, a joint venture of Avangrid and Vineyard Offshore, has been a major setback for the first industrial scale wind farm in the United States. Foam and fiberglass from the turbine has washed up on Nantucket and other beaches on the Cape and Martha’s Vineyard and raised questions about wind energy at a time when the industry is trying to ramp up production.

A preliminary investigation by GE Vernova has suggested the blade breakdown was caused by a “manufacturing deviation” – specifically insufficient bonding of the blade materials. The company has indicated no problems with the design of the Haliade-X blade, which is 853 feet tall.

It was unclear when Nantucket officials were notified about the resumption of construction of the wind farm. Updates posted on the town website indicated the Select Board was aware of the efforts beginning on Sunday to remove more of the damaged turbine blade.

During an executive session on Thursday, the Select Board met to discuss “strategy with respect to potential litigation in connection with Vineyard Wind,” according to the agenda.

This article first appeared on CommonWealth Beacon and is republished here under a Creative Commons license.

U.S. wind installations produced 45.9 gigawatt hours (GWh) of electricity in March 2024, eclipsing the 38.4 GWh generated by coal-fired power plants. The following month, coal-fired generation dropped to 37.2 GWh while wind generation blew away its previous high mark, churning out 47.7 GWh.

EIA included this lovely chart which demonstrates the steady growth of wind generation and the slow decline of our reliance on coal:

Installed wind power generating capacity has grown from 2.4 GW in 2000 to 150.1 GW in April 2024, according to the EIA. By contrast, many coal plants have retired over the past 25 years, and coal capacity has been roughly cut in half, from 315.1 GW in 2000 to 177.1 GW by April 2024. 22.3 GW of U.S. coal-fired electric generating capacity has been retired over the past two years, and operators plan to retire 2.8 GW more in 2024, data from EIA’s July Monthly Energy Review show.

Other sources of electricity generation have also increased as coal-fired generation has declined, notes the EIA. Since 2000, electricity from solar power has increased by 99.1 GWh, and generation from natural gas, which is often more price competitive than coal in electricity market dispatch, has gone up by 287.6 GWh.

And all good things, they say, never last

Wind power typically produces the most electricity in the springtime in the United States, so it’s not likely wind will permanently remain ahead of coal generation (at least not yet). During the first four months of 2024, coal-fired generation was 15% greater than wind generation in the United States.

You may recall something like this happening last year- when U.S. wind generation exceeded coal-fired generation for the first time in April 2023. It took 11 months later for that to happen again. But if you’re searching for silver linings, this spring marks the first time U.S. wind generation has exceeded coal-fired generation for two months in a row.

And there’s more capacity on the way. Operators expect 7.1 GW of wind capacity to come online in the United States in 2024, according to EIA’s July Monthly Energy Review. That’s a substantial amount, albeit a far cry from the 14 GW+ added in both 2020 and 2021, which were record years for growth in the industry.

And finally- a parting gift for those who either didn’t get the headline or understood the reference and now have that Prince slow jam stuck in their heads:

“We are pleased to announce this important transaction with LS Power, which is the result of a highly competitive strategic sale process,” said Chris Huskilson, CEO of AQN. “This major milestone, coupled with our previously announced agreement to support the sale of our Atlantica shares, delivers on our plan to transform AQN into a pure play regulated utility, optimize our regulated business activities, strengthen our balance sheet, and enhance our quality of earnings. We are confident that our path towards a pure play regulated utility supports our objective to create long term value for our customers and shareholders.”

The sale is subject to the satisfaction of customary closing conditions, including the approval of the U.S. Federal Energy Regulatory Commission and approval under applicable competition laws. The Company expects the transaction to close in the fourth quarter of 2024 or the first quarter of 2025 and to receive estimated cash proceeds of approximately $1.6 billion (excluding the earn out) after repaying construction financing, and net of taxes, transaction fees, and other closing adjustments.

Algonquin Power & Utilities isn’t the only company to shed its utility-scale renewables business lately. Last year, Brookfield Renewable announced it would buy Duke Energy’s utility-scale renewable energy business for $2.8 billion.

Duke began shopping its renewables division in September 2022 as it sought to focus on the growth of its regulated businesses. The sale agreement included more than 3,400 MWac of utility-scale solar, wind, and battery storage across the U.S., net of joint venture partners ownership, in addition to operations, new project development, and current projects under construction.

Also last year, RWE AG finalized its $6.8 billion acquisition of all shares in Con Edison Clean Energy Businesses. The transaction made the newly dubbed RWE Clean Energy one of the five largest renewable energy companies in the U.S. and the country’s second-largest solar owner and operator.

The acquisition included a portfolio of 8 GW of renewable energy projects and a development platform of more than 24 GW. Around 60% of the portfolio is onshore wind and 40% solar. Con Edison said it continues to invest in clean energy transmission projects, building electrification, energy efficiency, electric vehicle infrastructure, battery storage, and other technologies. The utility said it also wants to invest in and operate renewable generation in New York.

Originally published in Renewable Energy World.

Top officials at GE Vernova said they believe a “manufacturing deviation” at a facility in Canada is the likely cause of a turbine blade breakdown at Vineyard Wind 1 that resulted in foam and fiberglass washing up on Nantucket.

Scott Strazik, the CEO of GE Vernova, said there is no indication of an engineering design flaw with the turbine blade. He said the company is re-inspecting all of the 150 blades that have been manufactured at a plant in Gaspe, Canada, to see if the problem occurred with other blades.

Strazik said the deviation — later identified as a “insufficient bonding” — should have been caught during the company’s quality assurance process. He said the re-inspection process will rely on ultrasound and other techniques to identify any problems. The Vineyard Wind 1 project will remain on pause while the investigation of what went wrong with the blade is conducted.

“I have a high degree of confidence we can do this,” Strazik said in a call with financial analysts in connection with the company’s second quarter earnings release. “We’re not going to talk about the timeline today. We have work to do.”

Strazik added: “We are going to be thorough instead of rushed.”

In a filing with the Securities and Exchange Commission, GE Vernova appeared to take full responsibility for the situation and the suspension of construction at Vineyard Wind 1 ordered by the US Bureau of Safety and Environmental Enforcement, or BSEE.

“We do not have an indication as to when BSEE will modify or lift its suspension order,” the filing states. “Under our contractual arrangement with the developer of Vineyard Wind, we may receive claims for damages, including liquidated damages for delayed completion, and other incremental or remedial costs. These amounts could be significant and adversely affect our cash collection timelines and contract profitability. We are currently unable to reasonably estimate what impact the event, any potential claims, or the related BSEE order would have on our financial position, results of operations, and cash flows.”

Strazik said the Cambridge-based company is continuing to install turbines at the Dogger Bank wind farm in the United Kingdom, which is using the same 13-megawatt Haliade-X turbines as Vineyard Wind 1. Previously, one of the blades there broke but that was blamed on a faulty installation.

The Nantucket Select Board met in executive session on Tuesday to discuss a legal strategy going forward with GE Vernova, the manufacturer of the turbines, and the wind farm developers, Avangrid and Copenhagen Infrastructure Partners. The board is expected to hold a public meeting where the situation will be discussed Wednesday evening.

This article first appeared on CommonWealth Beacon and is republished here under a Creative Commons license.

On Friday, the CPUC proposed an initial need determination of up to 7.6 GW of offshore wind, up to 1 GW of enhanced geothermal systems, up to 1 GW of multi-day long-duration energy storage (LDES), and up to 1 GW of LDES with a discharge period of at least 12 hours.

This proposal stems from provisions of Assembly Bill 1373 (Stats. 2023, Ch.367), signed by Governor Gavin Newsom in 2023. AB 1373 authorizes the CPUC to request that the Department of Water Resources (DWR) conduct centralized procurement of certain eligible long lead-time (LLT) resources on behalf of customers of all load-serving entities (LSEs) under the Commission’s integrated resource planning (IRP) purview. Those long lead-time resources include offshore wind.

The plan will be heard, at the earliest, at the Commission’s meeting on August 22, 2024. By September 1, the Commission is required to make an initial need determination for procurement using a centralized procurement mechanism. If a need is found, within six months the Commission may then request DWR to exercise the centralized procurement mechanism.

The amounts selected are maximum amounts, according to the CPUC. Once a procurement request is made, DWR will conduct solicitations and evaluate the quality of bids received, including costs and ratepayer risk provisions, and may procure anywhere between zero and the upper limits included in this decision. This flexibility will facilitate cost containment and minimize ratepayer risks.

The resources selected by CPUC will help California achieve its greenhouse gas (GHG) emissions reduction goals for 2045 and represent emerging technologies that need to achieve economies of scale to bring costs down, the Commission says. However, the cost of these investments will ultimately impact electricity bills. In its proposal, CPUC maintains all possible efforts should be made to contain costs, reduce ratepayer risk, and seek other sources of funding to reduce development costs and share in the long-term costs and benefits.

This proposal also requests that, for this LLT procurement, DWR convene a procurement group that includes representatives from LSEs. In addition, the decision sets a tentative schedule of solicitations, asking DWR to conduct two rounds of solicitations for LDES and EGS, beginning in 2026, and three rounds of solicitations for OSW beginning in 2027. The Commission will reevaluate the need determination for additional LLT resources in every IRP cycle when considering a Preferred System Plan portfolio. In the next IRP cycle, the Commission will specifically evaluate LSE progress toward LLT procurement requirements in D.21-06-035, and consider whether an additional need determination for conventional geothermal resources for CPE procurement is necessary.

Earlier this month, the California Energy Commission (CEC) adopted a comprehensive strategic plan guiding the development of offshore wind. The plan outlines analysis and strategies to deploy floating turbines off the state’s central and northern coasts with a goal of 25,000 MW of capacity by 2045, enough to power 25 million homes. There are nearly 35 GW of renewable resources on California’s grid today, but the state is believed to need an additional 148 GW to reach its 2045 goal, likely requiring ocean development.

I&M submitted the following plans to the Michigan Public Service Commission (MPSC):

• Elkhart County: Solar, 100 MW
• Hoosier Line: Solar, 180 MW
• Meadow Lake: Wind, 100 MW
• Lawrenceburg: Natural Gas. 143 MW

Lawrenceburg will serve as a capacity-only agreement, which enables I&M to buy capacity and not the energy produced. 143 MW represents a Michigan-specific contract value. Plans for these projects were also submitted by I&M to the Indiana Utility Regulatory Commission (IURC) in June 2024.

I&M will purchase the power generated from the independently operated wind and solar power plants. Both solar generation plants will be built by private developers.

Previously announced in 2022, the Elkhart County Solar Plant details have been updated for the 2024 filing. Plans before the MPSC would also provide I&M the ability to include 143 MW of generation capacity from an existing natural gas facility in Dearborn County, near Lawrenceburg, Ind.

“I&M is committed to fully supplying the energy needs of our customers now and into the future,” said Steve Baker, I&M president and chief operating officer. “Our goal is to develop and reliably operate a robust energy portfolio, with a focus on resource adequacy, affordability and environmental sustainability.”

I&M said it is in the process of a “major” generation transformation. If approved, these resources would complement I&M’s current clean-energy generation, which includes five solar power plants; wind power from four plants; six hydro-electric plants; and the Cook Nuclear Plant. I&M also continues the development of two additional solar facilities, totaling 469 MW, previously approved by both the IURC and MPSC. I&M’s coal-fueled plant in Rockport, Ind., will be fully retired in 2028. More than 85% of energy I&M generated in 2023 was carbon-emission free.

DEV will only consider proposals for facilities located within PJM territory, not including those located in the state of Virginia.

All electrical output from the facilities will be delivered to the PJM Dominion Transmission Zone. Facilities that achieved a commercial operations date (COD) after October 1, 2021, and facilities under construction that achieve COD prior to the end of calendar year 2035 are eligible.

All participating bidders must register by submitting an Intent to Bid Form and an executed confidentiality agreement by August 30. The proposal submission deadline is September 30.

The Intent to Bid Form, CA, and other additional information on the RFP can also be found on the company’s website. 

This week, Virginia Electric and Power Company, a wholly-owned subsidiary of Dominion Energy, agreed to acquire the Kitty Hawk North Wind offshore wind lease and associated developments from Avangrid for approximately $160 million, including a payment of roughly $3,000 per acre for the nearly 40,000-acre lease.

If approved by regulators and constructed, the former Kitty Hawk North Wind site, which will be known as CVOW-South, would connect to the company’s transmission grid and have a capacity of 800 MW. Avangrid retains the ownership and associated rights to Kitty Hawk South, and says it will continue the development of the area, which can potentially deliver up to 2.4 GW to North Carolina, Virginia, or other states or private companies. After receipt of necessary approvals from the Bureau of Ocean Energy Management and the City of Virginia Beach, Dominion Energy and Avangrid expect to close the transaction in the fourth quarter of 2024.

The firm’s latest analysis predicts developers will put more than 5.4 terawatts (TWac) of new solar and wind capacity online over the next decade, increasing the cumulative global total to 8 TWac.

Energy storage capacity (excluding pumped hydro) will grow by more than 600%, Wood Mackenzie predicts, as nearly 1 TW of new capacity is expected to come online from 2024-2033.

“Global demand for renewables has reached unprecedented levels, driven by country-level policy targets, technology innovation, and concerns over energy security,” stated Luke Lewandowski, vice president of global renewables research at Wood Mackenzie. “Integrated power technology solutions will continue to evolve, evidenced by a significant increase in storage-paired capacity growth, despite inflation, grid constraints, and permitting challenges.”

Annual capacity will increase from approximately 500 GW of new solar and wind capacity installed in 2023, and average 560 GW annually over the 10-year outlook. China will continue to dominate solar, energy storage, and wind uptake, with 3.5 TWac forecast to be grid-connected between 2024 and 2033, notes WoodMac’s analysis.

“Solar PV leads the deployment race, accounting for 59% of global capacity due to come online between 2024 and 2033. Energy storage will have the most balanced geographic footprint over the outlook due in part to its important role in helping to make renewable power available,” Lewandowski added.

Solar: Cumulative installed global solar PV capacity to nearly quadruple from 2024 to 2033

“Ultra-low module prices intensified the rate of solar deployments last year in Europe and China and will continue to do so in the near-term. But grid constraints and a return to lower power prices and subsequently lower capture rates will impact markets and other regions,” said Juan Monge, the principal analyst of distributed solar PV at Wood Mackenzie.

Wood Mackenzie’s global solar PV forecast projects 4.7 terawatts direct current (TWdc) will be built between 2024 and 2033, with China accounting for 50% of that capacity growth.

Monge added: “Ultimately, maximizing solar PV capacity, and wind power capacity for that matter, in the next 10 years will depend on additional technology developments: from expanding grid infrastructure to incentivizing flexibility solutions, transportation, and heating electrification.”

In 2023, drastic drops in Chinese module prices and tight deadlines to interconnect tendered projects triggered 150% annual growth for installations across all solar PV segments, the analysis explains. Year-on-year increases in annual installed capacity will continue until 2026, when Wood Mackenzie forecasts a two-year slowdown due to an expected pause in development activity before the next round of planned procurement drives higher deployment.

For installations in the first quarter, developers in the US installed more solar in the first quarter of 2024 than in all of 2019, installations in China were up 36% year-on-year, and new capacity in India through Q1 amounted to 85% total capacity installed in 2023. However, Europe’s distributed PV boom has started to weaken, with first quarter residential installations contracting more than 30% in Germany and over 50% in the Netherlands as retail rates come down.

Energy storage: Global cumulative capacity will increase sixfold by the end of 2033, passing 1 TW/3 TWh

“Global energy storage deployment in 2023 achieved record-breaking growth of 162% compared to 2022, installing 45 GW/100 GWh. While impressive, the growth represents just the start for a multi-TW market as policy support in terms of tax exemption and capacity and hybrid auctions accelerate storage buildout across all regions,” said Anna Darmani, principal analyst of energy storage at Wood Mackenzie.

The global energy storage market is on track to reach 159 GW/358 GWh by the end of 2024, according to Wood Mackenzie’s Q2 global energy storage market outlook update. Looking ahead, 926 GW/2789 GWh will be added between 2024 and 2033, marking a 636% increase.

China remains the global leader in energy storage due to its booming solar market, with an average of 42 GW/120 GWh annual capacity additions forecasted in the next 10 years.

In Europe, grid-scale projects are booming as developers aim to seize opportunities from emerging contracted revenues. Demand from the distributed segment has decreased by 23% in 2024 as retail rates stabilize. With lower system costs and regulatory changes, however, distributed market growth is expected to resume from 2026.

Wind: Global wind power industry to add more than 1.7 TW over the next 10 years

According to Wood Mackenzie’s Q2 global wind market outlook update, policy support from China’s central government drives the world’s largest wind market, with China forecasted to install 91.5 GW on average annually.

“China’s central government announced a plan in May to promote the energy transition and ensure the country meets carbon-neutral targets,” explained Lucas Stavole, senior research analyst at Wood Mackenzie. “Project development has been accelerated in the short-term and renewable energy investment will be a long-term economic driver.” 

Challenges with permitting, grid access, financing, and supply chain availability impact the 2024 to 2026 outlook, pushing capacity into 2027 to 2033 and beyond the 10-year horizon. These dynamics impacted countries primarily in North America, Western Europe, and Asia.

Outside of China, wind additions globally will average 85 GW per year, a robust increase compared to the prior 10-year average of 37 GW. Additions in the Americas region will total 230 GW through 2033, as the offshore wind sector gains a foothold in the region and government incentives continue to drive growth.

The offshore wind sector, after connecting 11 GW globally in 2023, will average 39 GW of connected capacity annually from 2024 to 2033, (386 GW total), culminating in 54 GW in 2033. More than 50% (199 GW) of the total offshore wind capacity installed over the outlook period will be installed in China.

Annual U.S. sales of electricity to commercial customers in 2023 totaled 14 billion kilowatt-hours (BkWh) more than in 2019, a 1% difference. According to a new study released by EPRI, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used. This could create regional supply challenges, among other issues.

Electricity demand has grown the most in Virginia, which added 14 BkWh, and. Texas, which added 13 BkWh. Commercial electricity demand in the 10 states with the most electricity demand growth increased by a combined 42 BkWh between 2019 and 2023, representing growth of 10% in those states over that four-year period.

On the other hand, demand in the forty other states decreased by 28 BkWh over the same period, a 3% decline, and commercial electricity consumption declined between 2022 and 2023 in a few states because of mild summer weather.

Virginia, the state with the highest growth in electricity demand, has become a major hub for data centers, with 94 new facilities connected since 2019 given the access to a densely packed fiber backbone and to four subsea fiber cables.

In Texas, relatively low costs for electricity and land have attracted a high concentration of data centers and cryptocurrency mining operations, the EIA said. North Dakota had the fastest relative growth at 37% (up 2.6 BkWh) between 2019 and 2023, which EIA attributed to the establishment of large computing facilities in the state.

Last month, Duke Energy announced agreements with tech giants Amazon, Google, Microsoft and Nucor to significantly accelerate clean energy deployments in the Carolinas.

In memorandums of understanding (MOUs) signed in May, the companies proposed developing new rate structures, or “tariffs,” designed specifically to lower the long-term costs of investing in clean energy technologies like new nuclear and long-duration energy storage through early commitments. 

The proposed Accelerating Clean Energy (ACE) tariffs would enable large customers like Amazon, Google, Microsoft and Nucor to directly support carbon-free energy generation investments through financing structures and contributions that address project risk to lower costs of emerging technologies. ACE tariffs would facilitate onsite generation at customer facilities, participation in load flexibility programs and investments in clean energy assets.

The EIA expects U.S. sales of electricity to the commercial sector will grow by 3% in 2024 and by 1% in 2025.

The growth of data centers has brought a slew of questions related to their development and potential co-location with generators. In a filing to the Federal Energy Regulatory Commission (FERC) this week, Exelon and American Electric Power (AEP) protested a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania.

The parties said the proposed Interconnection Service Agreement (ISA) raises unresolved questions and could result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

Most notably, Exelon and AEP asserted the pending ISA between PJM Interconnection, Susquehanna Nuclear and PPL Utilities would allow the data center to derive benefits from the transmission system without paying for them. Under the ISA as proposed, the parties said the co-located data center would not be classified as “network load” and therefore would not be required to pay PJM transmission fees.

In the investor update, PG&E laid out a data center pipeline that includes the requested load and the location of the request. The companies requesting load for data centers have not yet been named, but one customer requested more than 1.3 GW across the state. Requests range from 10 MW to 800 MW for individual projects, in areas like San Jose, Hayward, Fremont, San Francisco, and Sunnyvale, with installation dates between 2024 and 2029.

PG&E noted in the update that San Francisco is one of eight primary data center locations in the U.S. given its proximity to Silicon Valley, a growing tech customer base, a vast fiber network, and a clean energy supply. However, San Francisco only accounts for 70 MW of the requested load, from two projects: one 60 MW, and one 10 MW. San Jose accounts for over half of the requested load, with 1,635 MW requested.

At least 38 GW of peak demand growth is expected through 2028, driven by the development of data centers and industrial and manufacturing facilities, according to a recent report from Grid Strategies.

The report, The Era of Flat Power Demand is Over, cited forecasts from grid planners, who have doubled the five-year load growth forecast over the past year. The nationwide forecast of electricity demand jumped from 2.6% to 4.7% growth over the next five years, according to FERC filings – and these forecasts are likely an underestimate, Grid Strategies said. Recent updates have tacked on several GW to that forecast, and next year’s will likely show an even steeper growth rate.

Technology giants like Microsoft, Google, and Amazon are significantly driving electricity demand, primarily through extensive and rapidly expanding data center operations. These data centers are essential for supporting cloud services, AI development, and other digital operations. The facilities require vast amounts of power to run servers, cooling systems, and other infrastructure needed to store and process massive amounts of data.

According to a new study released by EPRI, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used. This could create regional supply challenges, among other issues.

AI queries require approximately ten times the electricity of traditional internet searches and the generation of original music, photos, and videos requires much more. With 5.3 billion internet users, rapid adoption of these new tools could increase power demands substantially. At the same time, computing facilities are becoming more concentrated, with single facilities now requesting power consumption that can range from the equivalent of 80,000 to 800,000 homes, exacerbating power delivery challenges.

Drawing on public information about existing data centers, estimates of industry growth, and private electricity demand forecasts by industry experts, EPRI outlined four scenarios of potential annual electricity consumption in U.S. data centers from 2023 to 2030, with annual growth rates ranging from 3.7% to 15%. The lowest scenario assumed limited public uptake of AI tools, coupled with high gains in data center efficiency, and the highest scenario combined rapid expansion of AI applications with fewer efficiency gains. These scenarios placed data center power ranges from 4.6%-9.1%.

Originally published in POWERGRID International.