Canadians will see lower energy prices this summer

Ontario Natural Gas Moratorium gains momentum as IESO weighs energy storage, renewables, and demand management to meet rising electricity demand, ensure grid reliability, and advance zero-emissions goals while long-term capacity procurements proceed.

Key Points

A proposed halt on new gas plants as IESO assesses storage and renewables to maintain reliability and cut emissions.

✅ Minister seeks interim IESO report by Oct. 7

✅ Near-term contracts extend existing gas plants for reliability

✅ Long-term procurements emphasize storage, renewables, conservation

Ontario's energy minister says he doesn't think the province needs any more natural gas generation and has asked the electricity system regulator to speed up a report exploring a moratorium.

Todd Smith had previously asked the Independent Electricity System Operator (IESO) to report back by November on the feasibility of a moratorium and a plan to get to zero emissions in the electricity sector.

He has asked them today for an interim report by Oct. 7 so he can make a decision on a moratorium before the IESO secures contracts over the long term for new power generation.

"I've asked the IESO to speed up that report back to us so that we can get the information from them as to what the results would be for our grid here in Ontario and whether or not we actually need more natural gas," Smith said Tuesday after question period.

"I don't believe that we do."

Smith said that is because of the "huge success" of two updates provided Tuesday by the IESO to its attempts to secure more electricity supply for both the near term and long term. Demand is growing by nearly two per cent a year, while Ontario is set to lose a significant amount of nuclear generation, including the planned shutdown of the Pickering nuclear station over the next few years.

'For the near term, we need them,' regulator says
The regulator today released a list of 55 qualified proponents for those long-term bids and while it says there is a significant amount of proposed energy storage projects on that list, there are some new gas plants on it as well.

Chuck Farmer, the vice-president of planning, conservation and resource adequacy at the IESO, said it's hoped that the minister makes a decision on whether or not to issue a moratorium on new gas generation before the regulator proceeds with a request for proposals for long-term contracts.

The IESO also announced six new contracts — largely natural gas, with a small amount of wind power and storage — to start in the next few years. Farmer noted that these contracts were specifically for existing generators whose contracts were ending, while the province is exploring new nuclear plants for the longer term.

"When you look at the pool of generation resources that were in that situation, the reality is most of them were actually natural gas plants, and that we are relying on the continued use of the natural gas plants in the transition," he said in an interview. 

"So for the near term, we need them for the reliability of the system."

The upcoming request for proposals for more long-term contracts hopes to secure 3,500 megawatts of capacity, as Ontario faces an electricity shortfall in the coming years, and Farmer said the IESO plans to run a series of procurements over the next few years.

Opposition slams reliance on natural gas
The NDP and Greens on Tuesday criticized Ontario's reliance in the near term on natural gas because of its environmental implications.

The IESO has said that due to natural gas, greenhouse gas emissions from the electricity sector are set to increase for the next two decades, but by about 2038 it projects the net reductions from electric vehicles will offset electricity sector emissions.

Green Party Leader Mike Schreiner said it makes no sense to ramp up natural gas, both for the climate and for people's wallets.

"The cost of wind and solar power is much lower than gas," he said.

Ontario quietly revises its plan for hitting climate change targets
"We're in a now-or-never moment to address the climate crisis and the government is failing to meet this moment."

Interim NDP Leader Peter Tabuns said Ontario wouldn't be in as much of a supply crunch if the Progressive Conservative government hadn't cancelled 750 green energy contracts during their first term.

The Tories argued the province didn't need the power and the contracts were driving up costs for ratepayers, amid debate over whether greening the grid would be affordable.

The IESO said it is also proposing expanding conservation and demand management programs, as a "highly cost-effective" way to reduce strain on the system, though it couldn't say exactly what is on the table until the minister accepts the recommendation.

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TransAlta Renewables US wind farms achieved commercial operation, adding 119 MW of wind energy capacity in Pennsylvania and New Hampshire, backed by PPAs with Microsoft, Partners Healthcare, and NHEC, and supported by tax equity financing.

Key Points

Two US wind projects totaling 119 MW, now online under PPAs and supported by tax equity financing.

✅ 119 MW online in Pennsylvania and New Hampshire

✅ PPAs with Microsoft, Partners Healthcare, and NHEC

✅ About USD 126 million raised via tax equity

TransAlta Renewables Inc says two US wind farms, with a total capacity of 119 MW and operated by its parent TransAlta Corp, became operational in December, amid broader build-outs such as Enel's 450-MW U.S. project coming online and, in Canada, Acciona's 280-MW Alberta wind farm advancing as well.

The 90-MW Big Level wind park in Pennsylvania started commercial operation on December 19. It sells power to technology giant Microsoft Corporation under a 15-year contract, reflecting big-tech procurement alongside Amazon's clean energy projects in multiple markets.

The 29-MW Antrim wind facility in New Hampshire is operational since December 24. It is selling power under 20-year contracts with Boston-based non-profit hospital and physicians network Partners Healthcare and New Hampshire Electric Co-op, mirroring East Coast activity at Amazon Wind Farm US East now fully operational.

The Canadian renewable power producer, which has economic interest in the two wind parks, said that upon their reaching commercial operations, it raised about USD 126 million (EUR 113m) of tax equity to partially fund the projects, as mega-deployments like Invenergy and GE's record North American project and capital plans such as a $200 million Alberta build by a Buffett-linked company underscore financing momentum.

"We continue to pursue additional growth opportunities, including potential drop-down transactions with TransAlta Corp," TransAlta Renewables president John Kousinioris commented.

The comment comes as TransAlta scrapped an Alberta wind project amid Alberta policy shifts.

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Pinghai Bay Offshore Wind Farm MWS advances marine warranty survey best practices, risk management, and international standards in Fujian, with Haixia Goldenbridge Insurance and reinsurer-aligned audits supporting safer offshore wind construction and logistics.

Key Points

An MWS program ensuring Pinghai Bay Phase 2 meets standards via audits, risk controls, and vetted procedures.

✅ First MWS delivered in China's offshore wind market

✅ Audits, risk consultancy, and reinsurer-aligned standards

✅ Supports 250MW Phase 2 at Pinghai Bay, Fujian

LOC Renewables has announced it is to carry out marine warranty survey (MWS) services for the second phase of the Pinghai Bay Offshore Wind Farm near Putian, Fujian province, China, on behalf of Haixia Goldenbridge Insurance Co., Ltd. The agreement represents the first time MWS services have been delivered to the Chinese offshore wind market.

China’s installed offshore capacity jumped more than 60% in 2017, and its growing offshore market is aiming for a total grid-connected capacity of 5GW by 2020, as the sector globally advances toward a $1 trillion industry over the coming decades. Much of this future offshore development is slated to take place in Jiangsu, Zhejiang, Guangdong and Fujian provinces. As developers becoming increasingly aware of the need for stringent risk management and value that internationally accepted standards can bring to projects, Pinghai Bay will be the first Chinese offshore wind farm to employ MWS to ensure it meets the highest technical standards and minimise project risk. The agreement will see LOC Renewables carry out audit and risk consultancy services for the project from March until the end of 2018.

#google#

In recent years, as Chinese offshore wind projects have grown in scale and complexity the need for international expertise in the market has increased, with World Bank support for emerging markets underscoring global momentum. In response, domestic insurers are partnering with international reinsurers to manage and mitigate the associated larger risks. Applying the higher standards required by international reinsurers, LOC Renewables will draw on its extensive experience in European, US and Asian offshore wind markets to provide MWS services on the Pinghai project from its Tianjin office.

“As offshore wind technology continues to proliferate across Asia, driven by declining global costs, successful knowledge transfer based on best practices and lessons learned in the established offshore wind markets becomes ever more important,” said Ke Wan, Managing Director, LOC China.

“With a wealth of experience in Europe and the US, where UK offshore wind growth has accelerated, we’re increasingly working on projects across Asia, and are delighted to now be providing the first MWS services to China’s offshore wind market – services that bring real value in lower risk and will enable the project to achieve its full potential.”

“At 250MW, phase two of the Pinghai Bay Wind Farm represents a significant expansion on phase one, and we wanted to ensure that it met the highest technical and risk mitigation standards, informed by regional learnings such as Korean installation vessels analyses,” said Fan Ming, Business Director at Haixia Goldenbridge Insurance.

“In addition to their global experience, LOC Renewables’ familiarity with and presence in the local market was very important to us, and we’re looking forward to working closely with them to help bring this project to fruition and make a significant contribution to China’s expanding offshore wind market.”

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Idaho Power Valmy Settlement outlines early closure of the North Valmy coal-fired plant in Nevada, accelerated depreciation recovery, a 1.17% base-rate increase, and impacts for customers, NV Energy co-ownership, and Idaho Public Utilities Commission review.

Key Points

A proposed agreement to close North Valmy early, recover costs via a 1.17% rate hike, and seek PUC approval.

✅ Unit 1 closes 2019; Unit 2 closes 2025 in Nevada.

✅ 1.17% base-rate hike; about $1.20 per 1,000 kWh monthly bill.

✅ Idaho PUC comment deadline May 25; NV Energy co-owner.

State regulators have set a May 25 deadline for public comment on a proposed settlement related to the early closure of a coal-fired plant co-owned by Idaho Power, even as some utilities plan to keep a U.S. coal plant running indefinitely in other jurisdictions.

The settlement calls for shuttering Unit 1 of the North Valmy Power Plant in Nevada in 2019, with Unit 2 closing in 2025, amid regional coal unit retirements debates. The units had been slated for closure in 2031 and 2035, respectively.

If approved by the Idaho Public Utilities Commission, the settlement would increase base rates by approximately $13.3 million, or 1.17 percent, in order to allow the company to recover its investment in the plant on an accelerated basis.

That equates to an additional $1.20 on the monthly bill of the typical residential customer using 1,000 kilowatt-hours of energy per month.

Idaho Power, which co-owns the plant with NV Energy, maintains that closing Valmy early rather than continuing to operate it until it is fully depreciated in 2035, will ultimately save customers $103 million in today's dollars.

The company said a significant decrease in market prices for electricity has made it uneconomic to operate the plant except during extremely cold or hot weather, when the demand for energy peaks, a trend underscored by transactions involving the San Juan Generating Station deal elsewhere. The company also said plant balances have increased by approximately $70 million since its last general rate case in 2011, due to routine maintenance and repairs, as well as investments required to meet environmental regulations.

The proposed settlement reflects a number of changes to Idaho Power's original proposal regarding Valmy, and comes in the wake of discussions with interested parties in February and April, against the backdrop of a broader energy debate over plant closures and reliability.

In its initial application, filed in October, Idaho Power proposed closing both units in 2025. The original proposal would have increased base rates by $28.5 million, or about 2.5 percent, in order to allow the company to recover its costs associated with the plant's accelerated depreciation, decommissioning and anticipated investments, with cautionary examples such as the Kemper power plant costs illustrating potential risks.

Concurrently, Idaho Power asked for commission approval to adjust depreciation rates for its other plants and equipment based on the result of a study it conducts every five years, as outlined in Case IPC-E-16-23. The adjustment would have led to a $6.7 million increase to base rates.

The two requests filed in October would have increased customer costs by a total of $35.2 million or 3.1 percent, leading to a $3.08 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

The proposed settlement submitted to the Commission on May 4 calls for $13,285,285 to be recovered from all customer classes through base rates until 2028, all related to the Valmy shutdown. That is an increase of 1.17 percent and would result in a $1.20 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

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Renewable Energy Tax Incentive Extensions urged by US trade groups to offset COVID-19 supply chain delays, tax equity shortages, and financing risks, enabling direct pay, PTC and ITC qualification, and standalone energy storage credits.

Key Points

Policy measures that extend and monetize clean energy credits to counter COVID-19 disruptions and financing shortfalls.

✅ Extend start construction and safe harbor deadlines

✅ Enable direct pay to offset reduced tax equity

✅ Add a standalone energy storage credit

Renewable energy and other trade bodies in the US are calling on Capitol Hill to extend provision of tax incentives to help the sector “surmount the impacts” of the COVID-19 crisis facing clean energy.

In a signed joint letter, the American Council on Renewable Energy (ACORE), American Wind Energy Association (AWEA), Energy Storage Association (ESA), National Hydropower Association (NHA), Renewable Energy Buyers Alliance (REBA), and the Solar Energy Industries Association (SEIA) stated: “With over $50bn in annual investment over each of the past five years, the clean energy sector is one of the nation’s most important economic drivers. But that growth is placed at risk by a range of COVID-19 related impacts”.

These include “supply chain disruptions that have the potential to delay utility solar construction timetables and undermine the ability of wind, solar and hydropower developers to qualify for time-sensitive tax credits, and a sudden reduction in the availability of tax equity, which is crucial to monetising tax credits and financing clean energy projects of all types.”
The letter goes onto state: “Like all sectors of our economy the renewable and clean grid industry – including developers, manufacturers, construction workers, electric utilities, investors and major corporate consumers of renewable power – needs stability.

“The current uncertainty about the ability to qualify for and monetise tax incentives will have real and substantial negative impacts to the entire economy.

On behalf of the thousands of companies that participate in America’s renewable and clean energy economy, the coalition of organisations is requesting the US Government, echoing Senate calls to support clean energy, take three “critical” steps to address pandemic-related disruptions.

The first is an extension of start construction and safe harbour deadlines to ensure that renewable projects can qualify for renewable tax credits amid the Solar ITC extension debate and despite delays associated with supply chain disruptions.

The second is the implementation of provisions that will allow renewable tax credits to be available for direct pay to facilitate their monetisation, supporting U.S. solar and wind growth in the face of reduced availability of tax equity.

Thirdly, the signatories have requested the enactment of a direct pay tax credit for standalone energy storage to foster renewable growth as the industry sets sights on market majority and help secure a more resilient grid.

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US January power generation climbed to 373.2 TWh, EIA data shows, with coal edging natural gas, record wind output, record nuclear generation, rising hydro, and stable utility-scale solar amid higher Henry Hub prices.

Key Points

US January power generation hit 373.2 TWh; coal led gas, wind and nuclear set records, with solar edging higher.

✅ Coal 31.8% share; gas 29.4%; coal output 118.7 TWh, gas 109.6 TWh.

✅ Wind hit record 26.8 TWh; nuclear record 74.6 TWh.

✅ Total generation 373.2 TWh, highest January since 2014.

The US generated 373.2 TWh of power in January, up 7.9% from 345.9 TWh in December and 9.3% higher than the same month in 2017, Energy Information Administration data shows.

The monthly total was the highest amount in January since 377.3 TWh was generated in January 2014.

Coal generation totaled 118.7 TWh in January, up 11.4% from 106.58 TWh in December and up 2.8% from the year-ago month, consistent with projections of a coal-fired generation increase for the first time since 2014. It was also the highest amount generated in January since 132.4 TWh in 2015.

For the second straight month, more power was generated from coal than natural gas, as 109.6 TWh came from gas, up 3.3% from 106.14 TWh in December and up 19.9% on the year.

However, the 118.7 TWh generated from coal was down 9.6% from the five-year average for the month, due to the higher usage of gas and renewables and a rising share of non-fossil generation in the overall mix.

#google#

Coal made up 31.8% of the total US power generation in January, up from 30.8% in December but down from 33.8% in January 2017.

Gas` generation share was at 29.4% in the latest month, with momentum from record gas-fired electricity earlier in the period, down from 30.7% in December but up from 26.8% in the year-ago month.

In January, the NYMEX Henry Hub gas futures price averaged $3.16/MMBtu, up 13.9% from $2.78/MMBtu averaged in December but down 4% from $3.29/MMBtu averaged in the year-ago month.

WIND, NUCLEAR GENERATION AT RECORD HIGHS

Wind generation was at a record-high 26.8 TWh in January, up 29.3% from 22.8 TWh in December and the highest amount on record, according to EIA data going back to January 2001. Wind generated 7.2% of the nation`s power in January, as an EIA summer outlook anticipates larger wind and solar contributions, up from 6.6% in December and 6.1% in the year-ago month.

Utility-scale solar generated 3.3 TWh in January, up 1.3% from 3.1 TWh in December and up 51.6% on the year. In January, utility-scale solar generation made up 0.9% of US power generation, during a period when solar and wind supplied 10% of US electricity in early 2018, flat from December but up from 0.6% in January 2017.

Nuclear generation was also at a record-high 74.6 TWh in January, up 1.3% month on month and the highest monthly total since the EIA started tracking it in January 2001, eclipsing the previous record of 74.3 TWh set in July 2008. Nuclear generation made up 20% of the US power in January, down from 21.3% in December and 21.4% in the year-ago month.

Hydro power totaled 25.4 TWh in January, making up 6.8% of US power generation during the month, up from 6.5% in December but down from 8.2% in January 2017.

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