Entergy to be split at Louisiana-Texas line

OPG Credit Rating affirmed by DBRS at A (low) issuer and unsecured debt, R-1 (low) CP, Stable trends, backed by a supportive regulatory regime, strong leverage metrics, and provincial support; monitor Darlington Refurbishment costs.

Key Points

It is DBRS's confirmation of OPG at A (low) issuer and unsecured, R-1 (low) CP, with Stable outlooks.

✅ Stable trends; strong cash flow-to-debt and capital ratios

✅ Provincial financing via OEFC; Fair Hydro Trust ring-fenced

✅ Darlington Refurbishment on budget; cost overruns remain risk

DBRS Limited (DBRS) confirmed the Issuer Rating and the Unsecured Debt rating of Ontario Power Generation Inc. (OPG or the Company) at A (low) and the Commercial Paper (CP) rating at R-1 (low), amid sector developments such as Hydro One leadership efforts to repair government relations and measures like staff lockdowns at critical sites.

All trends are Stable. The ratings of OPG continue to be supported by (1) the reasonable regulatory regime in place for the Company's regulated generation facilities, including stable pricing signals for large users, (2) strong cash flow-to-debt and debt-to-capital ratios and (3) continuing financial support from its shareholder, the Province of Ontario (the Province; rated AA (low) with a Stable trend by DBRS). The Province, through its agent, the Ontario Electricity Financial Corporation (rated AA (low) with a Stable trend by DBRS), provides most of OPG's financing (approximately 43% of consolidated debt). The Company's remaining debt includes project financing (31%), including projects such as a battery energy storage system proposed near Woodstock, non-recourse debt issued by Fair Hydro Trust (Senior Notes rated AAA (sf), Under Review with Negative Implications by DBRS; 11%), CP (2%) and Senior Notes issued under the Medium Term Note Program (12%).

In March 2019, the Province introduced 'Bill 87, Fixing the Hydro Mess Act, 2019' which includes winding down the Fair Hydro Plan, and later introduced electricity relief to mitigate customer bills during the COVID-19 pandemic. OPG will remain as the Financial Services Manager for the outstanding Fair Hydro Trust debt, which will become obligations of the Province. DBRS does not expect this development to have a material impact on the Company as (1) the Fair Hydro Trust debt will continue to be bankruptcy-remote and ring-fenced from OPG (all debt is non-recourse to the Company) and (2) the credit rating on the Company's investment in the Subordinated Notes (rated AA (sf), Under Review with Negative Implications by DBRS) will likely remain investment grade while the Junior Subordinated Notes (rated A (sf), Under Review with Developing Implications by DBRS) will not necessarily be negatively affected by this change (see the DBRS press release, 'DBRS Maintains Fair Hydro Trust, Series 2018-1 and Series 2018-2 Notes Under Review,' dated March 26, 2019, for more details).

OPG's key credit metrics improved in 2018, following the approval of its 2017-2021 rates application by the Ontario Energy Board in December 2017, alongside the Province's energy-efficiency programs that shape demand. The Company's profitability strengthened significantly, with corporate return on equity (ROE) of 7.8% (adjusted for a $205 million gain on sale of property; 5.1% in 2017) closer to the regulatory allowed ROE of 8.78%. However, DBRS continues to view a positive rating action as unlikely in the short term because of the ongoing large capital expenditures program, including the $12.8 billion Darlington Refurbishment project, amid ongoing oversight following the nuclear alert investigation in Ontario. However, a downgrade could occur should there be significant cost overruns with the Darlington Refurbishment project that result in stranded costs. DBRS notes that the Darlington Refurbishment project is currently on budget and on schedule.

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Clean Energy Industry Support includes tax credits, refundability, safe harbor extensions, EV incentives, and stimulus measures to stabilize renewable energy projects, protect the workforce, and ensure financing continuity during economic recovery.

Key Points

Policies and funding to stabilize renewables, protect jobs, and extend tax incentives for workforce continuity.

✅ Extend PTC/ITC and remove phase-outs to sustain projects

✅ Enable direct pay or refundability to unlock financing

✅ Preserve safe harbor timelines disrupted by supply chains

U.S. Senator Catherine Cortez Masto (D-Nev.) led 17 Senate colleagues, as the Senate moves to modernize public-land renewables, in sending a letter calling on Congress to include support for the United States' clean energy industry and workforce in any economic aid packages.

"As Congress takes steps to ensure that our nation's workforce is prepared to emerge stronger from the coronavirus health and economic crisis, we must act to shore up clean energy businesses and workers who are uniquely impacted by the crisis, echoing a power-sector call for action from industry groups," said the senators. "This action, which has precedent in prior financial recovery efforts, could take several forms, including tax credit extensions or removal of the current phase-out schedule, direct payment or refundability, or extensions of safe harbor continuity."

"We need to make sure that any package protects workers and helps families stay afloat in these challenging times. Providing support to the clean energy industry will give much-needed certainty and confidence, as the sector targets a market majority, for those workers that they will be able to keep their paychecks and their jobs in this critical industry," the senators also said.

In addition to Senator Cortez Masto, the letter was also signed by Senators Ed Markey (D-Mass.), Martin Heinrich (D-N.M), Sheldon Whitehouse (D-R.I.), Debbie Stabenow (D-Mich.), Tina Smith (D-Minn.), Jack Reed (D-R.I.), Cory Booker (D-N.J.), Richard Blumenthal (D-Conn.), Amy Klobuchar (D-Minn.), Chris Van Hollen (D-Md.), Dianne Feinstein (D-Calif.), Jacky Rosen (D-Nev.), Tammy Duckworth (D-Ill.), Chris Coons (D-Del.), Mazie Hirono (D-Hawaii), Dick Durbin (D-Ill.), and Kyrsten Sinema (D-Ariz.).

Dear Leader McConnell, Leader Schumer, Chairman Grassley, Ranking Member Wyden:

As Congress takes steps to ensure that our nation's workforce is prepared to emerge stronger from the coronavirus health and economic crisis, we must act to shore up clean energy businesses and workers who are uniquely impacted by the crisis, with wind investments at risk amid the pandemic. This action, which has precedent in prior financial recovery efforts, could take several forms, including tax credit extensions or removal of the current phase-out schedule, direct payment or refundability, or extensions of safe harbor continuity.

First and foremost, we need to take care of workers' health and immediate needs to stay in their homes and provide for their families, and the Families First Coronavirus Response Act is a critical down payment. Now, we must make sure the workforce has jobs to return to and that employers remain able to pay for critical benefits like paid sick and family leave, healthcare, and Unemployment Insurance.

The renewable energy industry employs over 800,000 people across every state in the United States. This industry and its workers could suffer significant harms as a result of the coronavirus emergency and resulting financial impact. Renewable energy businesses are already seeing project cancellations or delays, as the Covid-19 crisis hits solar and wind across the sector, with the solar industry reporting delays of 30 percent. Likewise, the energy efficiency sector is susceptible to similar impacts. As the coronavirus pandemic intensifies in the United States, that rate of delay or cancellations will only continue to skyrocket. Global and domestic supply chains are already facing chaotic changes, with equipment delays of three to four months for parts of the industry. A major collapse in financing is all but certain as investment firms' profits turn to losses and capital is suddenly unavailable for large labor-intensive investments.

To ensure that we do not lose years of progress on clean energy and the source of employment for tens of thousands of renewable energy workers, Congress should look to previous relief packages as an example for how to support this sector and the broader American economy. The American Recovery and Reinvestment Act of 2009 (also known as the Recovery Act or ARRA) provided over $90 billion in funding for clean energy and grid modernization, along with emergency relief programs. Specifically, ARRA provided immediate funding streams like the 1603 Cash Grant program for renewables and the 30 percent clean energy manufacturing tax credit to give immediate relief for the clean energy industry. As Congress develops this new package, it should consider these immediate relief programs for the renewable and clean energy industry, especially as analyses suggest green energy could drive Covid-19 recovery at scale. This could include direct payment or refundability, extensions of safe harbor continuity, tax credit extensions, electric vehicle credit expansion, or removal of the current phase-out schedules for the clean energy industry.

We need to make sure that any package protects workers and helps families stay afloat in these challenging times. Providing support to the clean energy industry will give much-needed certainty and confidence for those workers that they will be able to keep their paychecks and their jobs in this critical industry.

These strategies to provide assistance to the clean energy industry must be included in any financial recovery discussions, particularly if the Trump Administration continues its push to aid the oil industry, even as some advocate a total fossil fuel lockdown to accelerate climate action. We appreciate your consideration and collaboration as we do everything in our power to quickly recover from this health and economic emergency.

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Summer Power Grid Reliability and Climate Risk drives urgent planning as extreme heat, peak demand, drought, and aging infrastructure strain ERCOT, NERC regions, risking outages without renewables integration and climate-informed grid modeling.

Key Points

Assessment of how extreme weather and demand stress the US grid, informing climate-smart planning to reduce outages.

✅ Many operators rely on historical weather, not climate projections

✅ NERC flags elevated blackout risk amid extreme heat and drought

✅ Renewables and storage can boost capacity and cut emissions

As heat ramps up ahead of what forecasters say will be a hotter than normal summer, electricity experts and officials are warning that states may not have enough power to meet demand in the coming months. And many of the nation's grid operators are also not taking climate change into account in their planning, despite available grid resilience guidance that could inform upgrades, even as extreme weather becomes more frequent and more severe.

Power operators in the Central US, in their summer readiness report, have already predicted "insufficient firm resources to cover summer peak forecasts." That assessment accounted for historical weather and the latest NOAA outlook that projects for more extreme weather this summer.

But energy experts say that some power grid operators are not considering how the climate crisis is changing our weather — including more frequent extreme events — and that is a problem if the intent is to build a reliable power grid while accelerating investing in carbon-free electricity across markets.

"The reality is the electricity system is old and a lot of the infrastructure was built before we started thinking about climate change," said Romany Webb, a researcher at Columbia University's Sabin Center for Climate Change Law. "It's not designed to withstand the impacts of climate change."

Webb says many power grid operators use historical weather to make investment decisions, rather than the more dire climate projections, simply because they want to avoid the possibility of financial loss, even as climate-related credit risks for nuclear plants are being flagged, for investing in what might happen versus what has already happened. She said it's the wrong approach and it makes the grid vulnerable.

"We have seen a reluctance on the part of many utilities to factor climate change into their planning processes because they say the science around climate change is too uncertain," Webb said. "The reality is we know climate change is happening, we know the impact it has in terms of more severe heatwaves, hurricanes, drought, with recent hydropower constraints in British Columbia illustrating the risks, and we know that all of those things affect the electricity system so ignoring those impacts just makes the problems worse."

An early heatwave knocked six power plants offline in Texas earlier this month. Residents were asked to limit electricity use, keeping thermostats at 78 degrees or higher and, as extreme heat boosts electricity bills for consumers, avoid using large appliances at peak times. The Electric Reliability Council of Texas, or ERCOT, in its seasonal reliability report, said the state's power grid is prepared for the summer and has "sufficient" power for "normal" summer conditions, based on average weather from 2006 to 2020.

But NOAA's recently released summer outlook forecasts above average temperatures for every county in the nation.

"We are continuing to design and site facilities based on historical weather patterns that we know in the age of climate change are not a good proxy for future conditions," Webb said.

When asked if the agency is creating a blind spot for itself by not accounting for extreme weather predictions, an ERCOT spokesperson said the report "uses a scenario approach to illustrate a range of resource adequacy outcomes based on extreme system conditions, including some extreme weather scenarios."

The North American Electric Reliability Corporation, or NERC — a regulating authority that oversees the health of the nation's electrical infrastructure — has a less optimistic projection.

In a recent seasonal reliability report, NERC placed Texas at "elevated risk" for blackouts this summer. It also reported that while much of the nation will have adequate electricity this summer, several markets are at risk of energy emergencies.

California grid operators, who recently avoided widespread rolling blackouts as heat strained the grid, in its summer reliability report also based its readiness analysis on "the most recent 20 years of historical weather data." The report also notes the assessment "does not fully reflect more extreme climate induced load and supply uncertainties."

Compounding the US power grid's supply and demand problem is drought: NERC says there's been a 2% loss of reliable hydropower from the nation's power-producing dams. Add to that the rapid retirement of many coal power plants — all while nearly everything from toothbrushes to cars are now electrified. Energy experts say adding more renewables into the mix will have the dual impact of cutting climate change inducing greenhouse gas emissions but also increasing the nation's power supply, aligning with efforts such as California's 100% carbon-free mandate that aim to speed the transition.
 

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Cabin Creek Solar Project Montana delivers 150 MW of utility-scale solar under a Power Purchase Agreement, with Basin Electric and Clenera supplying renewable energy, enhancing grid reliability, and reducing carbon emissions for 30,000 homes.

Key Points

A 150 MW solar PPA near Baker by Basin Electric and Clenera, delivering reliable renewable power and carbon reduction.

✅ 150 MW across two 75 MW sites near Baker, Montana

✅ PPA supports Basin Electric's diverse, cost-effective portfolio

✅ Cuts 265,000 tons CO2 and powers 30,000 homes

A new solar project in Montana will provide another 150 megawatts (MW) of affordable, renewable power to Basin Electric customers and co-op members across the region.

Basin Electric Power Cooperative (Basin Electric) and Clenera Renewable Energy, announced today the execution of a Power Purchase Agreement (PPA) for the Cabin Creek Solar Project. Cabin Creek is Basin Electric's second solar PPA, and the result of the cooperative's continuing goal of providing a diverse mix of energy sources that are cost-effective for its members.

When completed, Cabin Creek will consist of two, 75-MW projects in southeastern Montana, five miles west of Baker. According to Clenera, the project will eliminate 265,000 tons of carbon dioxide per year and power 30,000 homes, while communities such as the Ermineskin First Nation advance their own generation efforts.

"Renewable technology has advanced dramatically in recent years, with rapid growth in Alberta underscoring broader trends, which means even more affordable power for Basin Electric's customers," said Paul Sukut, CEO and general manager of Basin Electric. "Basin Electric is excited to purchase the output from this project to help serve our members' growing energy needs. Adding solar further promotes our all-of-the-above energy solution as we generate energy using a diverse resource portfolio including coal, natural gas, and other renewable resources to provide reliable, affordable, and environmentally safe generation.

"Clenera is proud to partner with Basin Electric Power Cooperative to support the construction of the Cabin Creek Solar projects in Montana," said Jared McKee, Clenera's director of Business Development. "We truly believe that Basin Electric will be a valuable partner as we aim to deliver today's new era of reliable, battery storage increasingly enabling round-the-clock service, affordable, and clean energy."

"We're pleased that Southeast Electric will be home to the Cabin Creek Solar Project," said Jack Hamblin, manager of Southeast Electric Cooperative, a Basin Electric Class C member headquartered in Ekalaka, Montana. "This project is one more example of cooperatives working together to use economies of scale to add affordable generation for all their members - similar to what was done 70 years ago when cooperatives were first built."

Basin Electric Class A member Upper Missouri Power Cooperative, headquartered in Sidney, Montana, provides wholesale power to Southeast Electric and 10 other distribution cooperatives in western North Dakota and eastern Montana. "It is encouraging to witness the development of cost-competitive energy, including projects in Alberta contracted at lower cost than natural gas that demonstrate market shifts, like the Cabin Creek Solar Project, which will be part of the energy mix we purchase from Basin Electric for our member systems, said Claire Vigesaa, Upper Missouri's general manager. "The energy needs in our region are growing and this project will help us serve both our members, and our communities as a whole."

Cabin Creek will bring significant economic benefits to the local area. According to Clenera, the project will contribute $8 million in property taxes to Fallon County and $5 million for the state of Montana over 35 years. They say it will also create approximately 300 construction jobs and two to three full-time jobs.

"This project underscores the efforts by Montana's electric cooperatives to continue to embrace more carbon-free technology," said Gary Wiens, CEO of Montana Electric Cooperatives' Association. "It also demonstrates Basin Electric's commitment to seek development of renewable energy projects in our state. It's exciting that these two projects combined are 50 times larger than our current largest solar array in Montana."

Cabin Creek is anticipated to begin operations in late 2023.

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National Grid Demand Flexibility Service helps stabilise the UK grid during tight supply, offering discounts for smart meter users who shift peak-time electricity use, reducing power cut risks amid low wind and import constraints.

Key Points

A National Grid scheme paying smart homes to cut peak-time use, easing supply pressure and avoiding power cuts.

✅ Pays volunteers with smart meters to reduce peak demand.

✅ Credits discounts for shifting use to off-peak windows.

✅ Manages tight margins and helps avert UK power cuts.

National Grid has decided not to activate a scheme on Tuesday to help the UK avoid power cuts after being poised to do so.

It would have seen some households offered discounts on their electricity bills if they cut peak-time use.

National Grid had been ready to trigger the scheme following a warning that Britain's energy supplies were looking tighter than usual this week.

However, it decided that the measure was not required.

Alerts are sent out automatically when expected supplies drop below a certain level. But they do not mean that blackouts are likely, or that the situation is critical.

National Grid said it was "confident" it would be able to manage margins and "demand is not at risk".

Discounts
Earlier on Monday, the grid operator said it was considering whether to pay households across Britain to reduce their energy use to help out on Tuesday evening.

Under the Demand Flexibility Service (DFS), announced earlier this month, customers that have signed up could get discounts on their bills if they use less electricity in a given window of time.

That could mean delaying the use of a tumble-dryer or washing machine, or cooking dinner in the microwave rather than the oven.

Major suppliers such as Octopus and British Gas are taking part, but only customers that have an electricity smart meter and that have volunteered are eligible. About 14 million UK homes have an electricity smart meter.

The DFS has already been tested twice but has not yet run live.

Octopus, the supplier with the most customers signed up, said that some households had earned more than £4 during the hour-long tests, while the average saving was "well over £1".

It came after forecasts projected a large drop in the amount of power that Britain will be able to import from French nuclear power stations on Monday and Tuesday evenings.

The lack of strong winds to power turbines has also affected how much power can be generated within the UK, and efforts to fast-track grid connections aim to ease constraints.

Such warnings are not unusual - around 12 have been issued and cancelled without issue in the last six years, and other regions such as Canada are seeing grids strained by harsh weather as well.

However, they have become more common this year due to the energy crisis, and the most recent notice was sent out last week.

The situation means that the UK will have to import electricity from other sources on Monday and Tuesday evening.

Supplies are also expected be tight in France, forecasters say.

France has been facing months of problems with its nuclear power plants, which generate around three-quarters of the country's electricity.

More than half of the nuclear reactors run by state energy company EDF have closed due to maintenance problems and technical issues.

It has added to a massive energy crisis in Europe which is facing a winter without gas supplies from Russia.

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Nova Scotia Integrated Resource Plan evaluates NSPI supply options, UARB oversight, Muskrat Falls imports, coal retirements, wind and biomass expansion, transmission upgrades, storage, and least-cost pathways to decarbonize the grid for ratepayers.

Key Points

A 25-year roadmap assessing supply, imports, costs, and emissions to guide least-cost decarbonization for Nova Scotia.

✅ Compares wind, biomass, gas, imports, and storage costs

✅ Addresses coal retirements, emissions caps, and reliability

✅ Recommends transmission upgrades and Muskrat Falls utilization

Maintaining a viable electricity network requires good long-term planning and, as a recent grid operations report notes, ongoing operational improvements. The existing stock of generating assets can become obsolete through aging, changes in fuel prices or environmental considerations. Future changes in demand must be anticipated.

Periodically, an integrated resource plan is created to predict how all this will add up during the ensuing 25 years. That process is currently underway and is led by Nova Scotia Power Inc. (NSPI) and will be submitted for approval to the Utilities and Review Board (UARB).

Coal-fired plants are still the largest single source of electricity in Nova Scotia. They need to be replaced with more environmentally friendly sources when they reach the end of their useful lives. Other sources include wind, hydroelectricity from rivers, biomass, as seen in increased biomass use by NS Power, natural gas and imports from other jurisdictions.

Imports are used sparingly today but will be an important source when the electricity from Muskrat Falls comes on stream. That project has big capacity. It can produce all the power needed in Newfoundland and Labrador (NL), where Quebec's power ambitions influence regional flows, plus the amount already committed to Nova Scotia, and still have a lot left over.

Some sources of electricity are more valuable than others. The daily amount of power from wind and solar cannot be controlled. Fuel-based sources and hydro can.

Utilities make their profits by providing the capital necessary to build infrastructure. Most of the money is borrowed but a portion, typically 30 per cent, usually comes from NSPI or a sister company. On that they receive a rate of return of nine per cent. Nova Scotia can borrow money today at less than two per cent.

The largest single investment of that type is the $1.577-billion Maritime Link connecting power from Newfoundland to Nova Scotia. It continues through to the New Brunswick border to facilitate exports to the United States. NSPI’s sister company, NSP Maritime Link Inc. (NSPML), is making nine per cent on $473 million of the cost.

There is little unexploited hydro capacity in Nova Scotia and there will not be any new coal-fired plants. Large-scale solar is not competitive in Nova Scotia’s climate. Nova Scotia’s needs would not accommodate the amount of nuclear capacity needed to be cost-effective, even as New Brunswick explores small reactors in its strategy.

So the candidates for future generating resources are wind, natural gas, biomass (though biomass criticism remains) and imports from other jurisdictions. Tidal is a promising opportunity but is still searching for a commercially viable technology. 

NSPI is commendably transparent about its process (irp.nspower.ca). At this stage there is little indication of the conclusions they are reaching but that will presumably appear in due course.

The mountains of detail might obscure the fact that NSPI is not an unbiased arbiter of choices for the future.

It is reported that they want to prematurely close the Trenton 5 coal plant in 2023-25. It is valued at $88.5 million. If it is closed early, ratepayers will still have to pay off the remaining value even though the plant will be idle. NSPI wants to plan a decommissioning of five of its other seven plants. There is a federal emissions constraint but retiring coal plants earlier than needed will cost ratepayers a lot.

Whenever those plants are closed, there will be a need for new sources of power. NSPI is proposing to plan for new investments in new transmission infrastructure to facilitate imports. Other possibilities would be additional wind farms, consistent with the shift to more wind and solar projects, thermal plants that burn natural gas or biomass, or storage for excess wind power that arrives before it can be used. The investment in storage could be anywhere from $20 million to $200 million.

These will add to the asset burden funded by ratepayers, even as industrial customers seek discounts while still paying for shuttered coal infrastructure.

External sources of new power will not provide NSPI the same opportunity: wind power by independent producers might be less expensive because they are willing to settle for less than nine per cent or because they are more efficient. Buying more power from Muskrat Falls will use transmission infrastructure we are already paying for. If a successful tidal technology is found, it will not be owned by NSPI or a sister company, which are no longer trying to perfect the technology.

This is not to suggest that NSPI would misrepresent the alternatives. But they can tilt the discussion in their favour. How tough will they be negotiating for additional Muskrat Falls power when it hurts their profits? Arguing for premature coal retirement on environmental grounds is fair game but whether the cost should be accepted is a political choice. 

NSPI is in a conflict of interest. We need a different process. An independent body should author the integrated resource plan. They should be fully informed about NSPI’s views.

They should communicate directly with Newfoundland and Labrador for Muskrat power, with independent wind producers, and with tidal power companies. The UARB cannot do any of these things.

The resulting plan should undergo the same UARB review that NSPI’s version would. This enhances the likelihood that Nova Scotians will get the least-cost alternative.

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