Alabama Power not cutting rates

Cyprus Electricity Interconnectors link the island to the EU grid via EuroAsia and EuroAfrica projects, enabling renewable energy trade, subsea transmission, market liberalization, and stronger energy security and diplomacy across the region.

Key Points

Subsea links connecting Cyprus to Greece, Israel and Egypt for EU grid integration, renewable trade and energy security.

✅ Connects EU, Israel, Egypt via EuroAsia and EuroAfrica

✅ Enables renewables integration and market liberalization

✅ Strengthens energy security, investment, and diplomacy

Electricity interconnectors bridging Cyprus with the broader geographical region, mirroring projects like the Ireland-France grid link already underway in Europe, are crucial for its diplomacy while improving its game to become a clean energy hub.

In an interview with Phileleftheros daily, Andreas Poullikkas, chairman of the Cyprus Energy Regulatory Authority (CERA), said electricity cables such as the EuroAsia Interconnector and the EuroAfrica Interconnector, could turn the island into an energy hub, creating investment opportunities.

“Cyprus, with proper planning, can make the most of its energy potential, turning Cyprus into an electricity producer-state and hub by establishing electrical interconnections, such as the EuroAsia Interconnector and the EuroAfrica Interconnector,” said Poullikkas.

He said these electricity interconnectors, “will enable the island to become a hub for electricity transmission between the European Union, Israel and Egypt, with developments such as the Israel Electric Corporation settlement highlighting regional dynamics, while increasing our energy security”.

Poullikkas argued it will have beneficial consequences in shaping healthy conditions for liberalising the country’s electricity market and economy, facilitating the production of electricity with Renewable Energy Sources and supporting broader efforts like the UK grid transformation toward net zero.

“Electricity interconnections are an excellent opportunity for greater business flexibility in Cyprus, ushering new investment opportunities, as seen with the Lake Erie Connector investment across North America, either in electricity generation or other sectors. Especially at a time when any investment or financial opportunity is welcomed.”

He said Cyprus’ energy resources are a combination of hydrocarbon deposits and renewable energy sources, such as solar.

This combination offers the country a comparative advantage in the energy sector.

Cyprus can take advantage of the development of alternative supply routes of the EU, as more links such as new UK interconnectors come online.

Poullikkas argued that as energy networks are developing rapidly throughout the bloc, serving the ever-increasing needs for electricity, and aligning with the global energy interconnection vision highlighted in recent assessments, the need to connect Cyprus with its wider geographical area is a matter of urgency.

He argues the development of important energy infrastructure, especially electricity interconnections, is an important catalyst in the implementation of Cyprus goals, while recognising how rule changes like Australia's big battery market shift can affect storage strategies.

“It should also be a national political priority, as this will help strengthen diplomatic relations,” added Poullikkas.

Implementing the electricity interconnectors between Israel, Cyprus and Greece through Crete and Attica (EuroAsia Interconnector) has been delayed by two years.

He said the delay was brought about after Greece decided to separate the Crete-Attica section of the interconnection and treat as a national project.

Poullikkas stressed the Greek authorities are committed to ensuring the connection of Cyprus with the electricity market of the EU.

“All the required permits have been obtained from the competent authorities in Cyprus and upon the completion of the procedures with the preferred manufacturers, construction of the Cyprus-Crete electrical interconnection will begin before the end of this year. Based on current data, the entire interconnection is expected to be implemented in 2023”.

“The EuroAfrica Interconnector is in the pre-works stage, all project implementation studies have already been completed and submitted to the competent authorities, including cost and benefit studies”.

EuroAsia Interconnector is a leading EU project of common interest (PCI), also labelled as an “electricity highway” by the European Commission.

It connects the national grids of Israel, Cyprus and Greece, creating a reliable energy bridge between the continents of Asia and Europe allowing bi-directional transmission of electricity.

The cost of the entire subsea cable system, at 1,208km, the longest in the world and the deepest at 3,000m below sea level, is estimated at €2.5 bln.

Construction costs for the first phase of the Egypt-Cyprus interconnection (EuroAfrica) with a Stage 1 transmission capacity of 1,000MW is estimated at €1bln.

The Cyprus-Greece (Crete) interconnection, as well as the Egypt-Cyprus electricity interconnector, will both be commissioned by December 2023.

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Nova Scotia Clean Power Plan 2030 pivots from the Atlantic Loop, scaling wind and solar, leveraging Muskrat Falls via the Maritime Link, adding battery storage and transmission upgrades to decarbonize grid and retire coal.

Key Points

Nova Scotia's 2030 roadmap to replace coal with wind, solar, hydro imports, storage, and grid upgrades.

✅ 1,000 MW onshore wind to supply 50% by 2030

✅ Battery storage sites and New Brunswick transmission upgrades

✅ Continued Muskrat Falls imports via Maritime Link

Nova Scotia is abandoning the proposed Atlantic Loop in its plan to decarbonize its electrical grid by 2030 amid broader discussions about independent grid planning nationwide, Natural Resources and Renewables Minister Tory Rushton has announced.

The province unveiled its clean power plan calling for 30 per cent more wind power and five per cent more solar energy in the Nova Scotia power grid over the coming years. Nova Scotia's plan relies on continued imports of hydroelectricity from the Muskrat Falls project in Labrador via the Emera-owned Maritime Link.

Right now Nova Scotia generates 60 per cent of its electricity by burning fossil fuels, mostly coal, and some increased use of biomass has also factored into the mix. Nova Scotia Power must close its coal plants by 2030 when 80 per cent of electricity must come from renewable sources in order reduce greenhouse gas emissions causing climate changes.

Critics have urged reducing biomass use in electricity generation across the province.

The clean power plan calls for an additional 1,000 megawatts of onshore wind by 2030 which would then generate 50 per cent of the the province's electricity, while also advancing tidal energy in the Bay of Fundy as a complementary source.    

"We're taking the things already know and can capitalize on while we build them here in Nova Scotia," said Rushton, "More importantly, we're doing it at a lower rate so the ratepayers of Nova Scotia aren't going to bear the brunt of a piece of equipment that's designed and built and staying in Quebec."

The province says it can meet its green energy targets without importing Quebec hydro through the Atlantic loop. It would have brought hydroelectric power from Quebec into New Brunswick and Nova Scotia via upgraded transmission links. But the government said the cost is prohibitive, jumping to $9 billion from nearly $3 billion three years ago with no guarantee of a secure supply of power from Quebec.

"The loop is not viable for 2030. It is not necessary to achieve our goal," said David Miller, the provincial clean energy director. 

Miller said the cost of $250 to $300 per megawatt hour was five times higher than domestic wind supply.

Some of the provincial plan includes three new battery storage sites and expanding the transmission link with New Brunswick. Both were Nova Scotia Power projects paused by the company after the Houston government imposed a cap on the utility's rate increased in the fall of 2022.

The province said building the 345-kilovolt transmission line between Truro, N.S., and Salisbury, N.B., and an extension to the Point Lepreau Nuclear Generating Station, as well as aligning with NB Power deals for Quebec electricity underway, would enable greater access to energy markets.

Miller says Nova Scotia Power has revived both.

Nova Scotia Power did not comment on the new plan, but Rushton spoke for the company.

"All indications I've had is Nova Scotia Power is on board for what is taking place here today," he said.

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Muskrat Falls rate mitigation progresses as Newfoundland and Labrador and Ottawa align under the updated Atlantic Accord, targeting affordable electricity rates through federal involvement, PUB input, and potential financing solutions with Nalcor, Emera, and lenders.

Key Points

An initiative by NL and Ottawa to keep electricity rates affordable via federal support, PUB input, and financing options.

✅ Federal-provincial talks under the updated Atlantic Accord

✅ PUB process integrated for independent oversight

✅ Possible roles for Nalcor, Emera, and project lenders

At the announcement of an updated Atlantic Accord between the provincial and federal governments, Newfoundland and Larbrador Premier Dwight Ball gave notice federal Finance Minister Bill Morneau will be in St. John’s to talk about the cost of Muskrat Falls and how Labrador power flows through Quebec to market.

“We look forward to welcoming Minister Morneau and his team to advance discussions on federal financing and rate mitigation,” read a statement from the premier’s office Tuesday, in response to questions about that coming meeting and federal-provincial work on rate mitigation.

At the announcement, Ball specifically said the plan is to “finalize federal involvement for making sure electricity rates remain affordable,” such as shielding ratepayers from overruns through federal-provincial measures, with Ball and MP Seamus O’Regan trumpeting the provincial-federal relationship.

The provincial and federal governments are not the only two parties involved in provincial power rates and handling of Muskrat Falls, even as electricity users have started paying for the project across Newfoundland and Labrador, but The Telegram is told details of meetings on rate mitigation are not being released, down to the list of attendees.

The premier’s office was asked specifically about the involvement of Nalcor Energy, including a recent financial update during the pandemic, Emera, Goldman, TD or any others involved in project financing. The response was that the plan is not to indicate what is being explored and who might be involved, until there is something more concrete to speak about.

The government’s plan is to have something to feed into the ongoing work of the Public Utilities Board, to develop a more complete response for rate mitigation, including lump-sum credits on electricity bills and other tools, for the PUB’s final report, due in 2020, even as regulators in Nova Scotia weigh a 14% rate hike in a separate proceeding.

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Hydro One-Avista acquisition sparks Idaho regulatory scrutiny over foreign ownership, utility merger impacts, rate credits, and public interest, as FERC and FCC approvals advance and consumers question governance, service reliability, and long-term rate stability.

Key Points

A cross-border utility merger proposal with Idaho oversight, weighing foreign ownership, rates, and reliability.

✅ Idaho PUC review centers on public interest and rate impacts.

✅ FERC and FCC approvals granted; state decisions pending.

✅ Avista to retain name and Spokane HQ post-transaction.

“Please don’t sell us to Canada.” That refrain, or versions of it, is on full display at the Idaho Public Utilities Commission, which admittedly isn’t everyone’s go-to entertainment site. But it is vitally important for this reason: the first big test of the expansionist dreams of the politically tempest-tossed Hydro One, facing political risk as it navigates markets, rests with its successful acquisition of Avista Corp., provider of electric generation, transmission and distribution to retail customers spread from Oregon to Washington to Montana and Idaho and up into Alaska.

The proposed deal — announced last summer, but not yet consummated — marks the first time the publicly traded Hydro One has embarked upon the acquisition of a U.S. utility. And if Idahoans spread from Boise to Coeur d’Alene to Hayden are any indication, they are not at all happy with the idea of foreign ownership. Here’s Lisa McCumber, resident of Hayden: “I am stating my objection to this outrageous merger/takeover. Hydro One charges excessive fees to the people it provides for, this is a monopoly beyond even what we are used to. I, in no way, support or as a customer, agree with the merger of this multi-billion-dollar, foreign, company.”

#google#

Or here’s Debra Bentley from Coeur d’Alene: “Fewer things have more control over a nation than its power source. In an age where we are desperately trying to bring American companies back home and ‘Buy American’ is somewhat of a battle cry, how is it even possible that it would or could be allowed for this vital necessity … to be controlled by a foreign entity?”

Or here’s Spencer Hutchings from Sagle: “This is an incredibly bad idea.”

There are legion of similar emails from concerned consumers, and the Maine transmission line debate offers a parallel in public opposition.

The rationale for the deal? Last fall Hydro One CEO Mayo Schmidt testified before the Idaho commission, which regulates all gas, water and electricity providers in the state. “Hydro One is a pure-play transmission and distribution utility located solely within Ontario,” Schmidt told commissioners. “It seeks diversification both in terms of jurisdictions and service areas. The proposed Transaction with Avista achieves both goals by expanding Hydro One into the U.S. Pacific Northwest and expanding its operations to natural gas distribution and electric generation. The proposed Transaction with Avista will deliver the increased scale and benefits that come from being a larger player in the utility industry.”

Translation: now that it is a publicly traded entity, Hydro needs to demonstrate a growth curve to the investment community. The value to you and me? Arguable. This is a transaction framed as a benefit to shareholders, one that won’t cause harm to customers. Premier Kathleen Wynne is feeling the pain of selling off control of an essential asset. In his testimony to the commission, Schmidt noted that the Avista acquisition would take the province’s Hydro ownership to under 45 per cent. (The Electricity Act technically prevents the sale of shares that would take the government’s ownership position below 40 per cent, though acquisitions appear to allow further dilution. )

Stratospheric compensation, bench-marked against other chief executives who enjoy similarly outsized rewards, is part of this game. I have written about Schmidt’s unconscionable compensation before, but that was when he was making a relatively modest $4 million. Relative, that is, to his $6.2 million in 2017 compensation ($3.5 million of that is in the form of share based awards).

Should the acquisition of Avista be approved, amendments to the CIC, or change in control agreements, for certain named Avista executive officers will allow them to voluntarily terminate their employment without “good reason.” That includes Scott Morris, the company’s CEO, who will exit with severance of $6.9 million (U.S.) and additional benefits taking the total to a potential $15.7 million.

Back to the deal: cost savings over time could be achieved, Schmidt continued in his testimony, though he was unable to quantify those. The integration between the two companies, he promised, will be “seamless.” Retail customers in Idaho, Washington and Oregon would benefit from proposed “Rate Credits” equalling an estimated $15.8 million across five years, even as Hydro One seeks to redesign its bills in Ontario. Idahoans would see a one per cent rate decrease through that period.

While Avista would become a wholly owned Hydro subsidiary, it would retain its name, and its headquarters in Spokane, Wash. In the case of Idaho specifically, a proposed settlement in April, subject to final approval by the commission, stipulates agreements on everything from staffing to governance to community contributions.

Will that meet the test? It’s up to the commission to determine whether the proposed transaction will keep a lid on rates and is “consistent with the public interest.” Hydro One is hoping for a decision from regulatory agencies in all the named states by mid-August and a closing date by the end of September, though U.S. regulators can ultimately determine the fate of such deals. The Federal Energy Regulatory Commission granted its approval in January, followed last week by the Federal Communications Commission. Washington and Alaska have reached settlement agreements. These too are pending final state approvals.

The $5.3-billion deal (or $6.7 billion Canadian) is subject to ongoing hearings in Idaho, and elsewhere rate hikes face opposition as hearings begin. Members of the public are encouraged to have their say. The public comment deadline is June 27.

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AI-Powered Utility Customer Experience enables transparency, real-time pricing, smart thermostats, demand response, and billing optimization, helping utilities integrate distributed energy resources, battery storage, and microgrids while boosting customer satisfaction and reducing costs.

Key Points

An approach where utilities use AI and real-time data to personalize service, optimize billing, and cut energy costs.

✅ Real-time pricing aligns retail and wholesale market signals

✅ Device control via smart thermostats and home energy management

✅ Analytics reveal appliance-level usage and personalized savings

The latest electric utility customer satisfaction survey results from the American Customer Satisfaction Index (ACSI) Energy Utilities report reveal that nearly every investor-owned utility saw customer satisfaction go down from 2018 to 2019. Residential customers are sending a clear message in the report: They want more transparency and control over energy usage, billing and ways to reduce costs.

With both customer satisfaction and utility revenues on the decline, utilities are facing daunting challenges to their traditional business models amid flat electricity demand across many markets today. That said, it is the utilities that see these changing times as an opportunity to evolve that will become the energy leaders of tomorrow, where the customer relationship is no longer defined by sales volume but instead by a utility company's ability to optimize service and deliver meaningful customer solutions.

We have seen how the proliferation of centralized and distributed renewables on the grid has already dramatically changed the cost profile of traditional generation and variability of wholesale energy prices. This signals the real cost drivers in the future will come from optimizing energy service with things like batteries, microgrids and peer-to-peer trading networks. In the foreseeable future, flat electricity rates may be the norm, or electricity might even become entirely free as services become the primary source of utility revenue.

The key to this future is technological innovation that allows utilities to better understand a customer’s unique needs and priorities and then deliver personalized, well-timed solutions that make customers feel valued and appreciated as their utility helps them save and alleviates their greatest pain points.

I predict utilities that adopt new technologies focused on customer experience, aligned with key utility trends shaping the sector, and deliver continual service improvements and optimization will earn the most satisfied, most loyal customers.

To illustrate this, look at how fixed pricing today is applied for most residential customers. Unless you live in one of the states with deregulated utilities where most customers are free to choose a service provider in a competitive marketplace, as consumers in power markets increasingly reshape offerings, fixed-rate tariffs or time-of-use tariffs might be the only rate structures you have ever known, though new utility rate designs are being tested nationwide today. These tariffs are often market distortions, bearing little relation to the real-time price that the utility pays on the wholesale market.

It can be easy enough to compare the rate you pay as a consumer and the market rate that utilities pay. The California ISO has a public dashboard -- as do other grid operators -- that shows the real-time marginal cost of energy. On a recent Friday, for example, a buyer in San Francisco could go to the real-time market and procure electricity at a rate of around 9.5 cents per kilowatt-hour (kWh), yet a residential customer can pay the utility PG&E between 22 cents and 49 cents per kWh amid major changes to electric bills being debated, depending on usage.

The problem is that utility customers do not usually see this data or know how to interpret it in a way that helps add value to their service or drive down the cost.

This is a scenario ripe for innovation. Artificial intelligence (AI) technologies are beginning to be applied to give customers the transparency and control over the energy they desire, and a new type of utility is emerging using real-time pricing signals from wholesale markets to give households hassle-free energy savings. Evolve Energy in Texas is developing a utility service model, even as Texas utilities revisit smart home network strategies, that delivers electricity to consumers at real-time market prices and connects to smart thermostats and other connected devices in the home for simple monitoring and control -- all managed via an intuitive consumer app.

My company, Bidgely, partners with utilities and energy retailers all over the world to apply artificial intelligence and machine learning algorithms to customer data in order to bring transparency to their electricity bills, showing exactly where the customers’ money is going down to the appliance and offering personalized, actionable advice on how to save.

Another example is from energy management company Keewi. Its wireless outlet adaptors are revealing real-time energy usage information to Texas A&M dorm residents as well as providing students the ability to conserve energy through controlling items in their rooms from their smartphones.

These are but a few examples of innovations among many in play that answer the consumer demand for increased transparency and control over energy usage.

Electric service providers will be closely watching how consumers respond to AI-driven innovation, including providers in traditionally regulated markets that are exploring equitable regulation approaches now, to stay aligned with policy and customer expectations. While regulated utilities have no reason to fear that their customers might sign up with a competitor, they understand that the revenues from electricity sales are going down and the deployment of distributed energy resources is going up. Both trends were reflected in a March report from Bloomberg New Energy Finance (via ThinkProgress) that claimed unsubsidized storage projects co-located with solar or wind are starting to compete with coal and gas for dispatchable power. Change is coming to regulated markets, and some of that change can be attributed to customer dissatisfaction with utility service.

Like so many industries before, the utility-customer relationship is on track to become less about measuring unit sales and more about driving revenue through services and delivering the best customer value. Loyal customers are most likely to listen and follow through on the utility’s advice and to trust the utility for a wide range of energy-related products and services. Utilities that make customer experience the highest priority today will emerge tomorrow as the leaders of a new energy service era.

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Great Northern Transmission Line delivers 250 MW of carbon-free hydropower from Manitoba Hydro, strengthening Midwest grid reliability, enabling wind storage balancing, and advancing Minnesota Power's EnergyForward strategy for cleaner, renewable energy across the region.

Key Points

A 500 kV cross-border line delivering 250 MW of carbon-free hydropower, strengthening reliability and enabling renewables.

✅ 500 kV, 224-mile line from Manitoba to Minnesota

✅ Delivers 250 MW hydropower via ALLETE-Minnesota Power

✅ Enables wind storage and grid balancing with Manitoba Hydro

Minnesota Power, a utility division of ALLETE Inc. (NYSE:ALE), has energized its Great Northern Transmission Line, bringing online an innovative delivery and storage system for renewable energy that spans two states and one Canadian province, similar to the Maritime Link project in Atlantic Canada.

The 500 kV line is now delivering 250 megawatts of carbon-free hydropower from Manitoba, Canada, to Minnesota Power customers.

Minnesota Power completed the Great Northern Transmission Line (GNTL) in February 2020, ahead of schedule and under budget. The 224-mile line runs from the Canadian border in Roseau County to a substation near Grand Rapids, Minnesota. It consists of 800 tower structures which were fabricated in the United States and used 10,000 tons of North American steel. About 2,200 miles of wire were required to install the line's conductors. The GNTL also is contributing significant property tax revenue to local communities along the route.

"This is such an incredible achievement for Minnesota Power, ALLETE, and our region, and is the culmination of a decade-long vision brought to life by our talented and dedicated employees," said ALLETE President and CEO Bethany Owen. "The GNTL will help Minnesota Power to provide our customers with 50 percent renewable energy less than a year from now. As part of our EnergyForward strategy, it also strengthens the grid across the Midwest and in Canada, enhancing reliability for all of our customers."

With the GNTL energized and connected to Manitoba Hydro's recently completed Manitoba-Minnesota Transmission Project at the border, the companies now have a unique "wind storage" mechanism that quickly balances energy supply and demand in Minnesota and Manitoba, and enables a larger role for renewables in the North American energy grid.

The GNTL and its delivery of carbon-free hydropower are important components of Minnesota Power's EnergyForward strategy to transition away from coal and add renewable power sources while maintaining reliable and affordable service for customers, echoing interties like the Maritime Link that facilitate regional power flows. It also is part of a broader ALLETE strategy to advance and invest in critical regional transmission and distribution infrastructure, such as the TransWest Express transmission project, to ensure grid integrity and enable cleaner energy to reduce carbon emissions.

"The seed for this renewable energy initiative was planted in 2008 when Minnesota Power proposed purchasing 250 megawatts of hydropower from Manitoba Hydro. Beyond the transmission line, it also included a creative asset swap to move wind power from North Dakota to Minnesota, innovative power purchase agreements, and a remarkable advocacy process to find an acceptable route for the GNTL," said ALLETE Executive Chairman Al Hodnik. "It marries wind and water in a unique connection that will help transform the energy landscape of North America and reduce carbon emissions related to the existential threat of climate change."

Minnesota Power and Manitoba Hydro, a provincial Crown Corporation, coordinated on the project from the beginning, navigating National Energy Board reviews along the way. It is based on the companies' shared values of integrity, environmental stewardship and community engagement.

"The completion of Minnesota Power's Great Northern Transmission Line and our Manitoba-Minnesota Transmission Project is a testament to the creativity, perseverance, cooperation and skills of hundreds of people over so many years on both sides of the border," said Jay Grewal, president and CEO of Manitoba Hydro. "Perhaps even more importantly, it is a testament to the wonderful, longstanding relationship between our two companies and two countries. It shows just how much we can accomplish when we all work together toward a common goal."

Minnesota Power engaged federal, state and local agencies; the sovereign Red Lake Nation and other tribes, reflecting First Nations involvement in major transmission planning; and landowners along the proposed routes beginning in 2012. Through 75 voluntary meetings and other outreach forums, a preferred route was selected with strong support from stakeholders that was approved by the Minnesota Public Utilities Commission in April 2016.

A four-year state and federal regulatory process culminated in late 2016 when the federal Department of Energy approved a Presidential Permit for the GNTL, similar to the New England Clean Power Link process, needed because of the international border crossing. Construction of the line began in early 2017.

"A robust stakeholder process is essential to the success of any project, but especially when building a project of this scope," Owen said. "We appreciated the early engagement and support from stakeholders, local communities and tribes, agencies and regulators through the many approval milestones to the completion of the GNTL."

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