Deepwater Wind Eyeing Massachusetts’ South Coast for Major Offshore Wind Construction Activity

TransWest Express Power Line will deliver Wyoming wind energy to California via a 730-mile high-voltage corridor, integrating 3,000 MW from the Chokecherry and Sierra Madre project to strengthen the Western grid and decarbonization goals.

Key Points

A 730-mile line delivering up to 3,000 MW of Wyoming wind to Western states, improving clean energy reliability.

✅ 3,000 MW from Chokecherry and Sierra Madre turbines

✅ 730-mile route linking Wyoming to CA, AZ, NV markets

✅ Supports 60% by 2030, 100% by 2045 clean mandates

A conservative billionaire wants to build America's biggest wind farm in Wyoming and send the clean electricity to California.

Federal officials have approved another section of the 730-mile TransWest Express power line, in line with a renewable transmission rule aimed at speeding upgrades, which would carry energy from Philip Anschutz's Chokecherry and Sierra Madre wind farm to potential customers in California, Arizona and Nevada. The 1,000-turbine, 3,000-megawatt wind project, which has been in the works for a decade, would be built in south-central Wyoming, in one of the windiest spots in the continental U.S.

Supporters say the massive power project would help California meet its clean energy goals, in part because Wyoming winds tend to blow strong into the evening, as the sun sets over the Pacific and the Golden State's many solar farms go offline, though expanding battery storage is starting to fill that gap. Under California law, electric utilities are required to get 50% of their power from renewable sources by 2030. The state Senate passed a bill Wednesday that would raise the clean energy mandate to 60% by 2030 and 100% by 2045.

The Denver-based Anschutz Corporation hasn't inked any contracts to sell the electricity its Wyoming wind farm would generate. But company officials are confident demand will materialize by the time they're ready to build turbines. Construction of roads and other project infrastructure started last year and picked back up in April after a winter hiatus.

The developer has already spent $100 million developing the wind farm and power line, and expects to spend a combined $8 billion on the two projects.

Bill Miller oversees the development of the Anschutz Corporation's Chokecherry and Sierra Madre wind farm in Wyoming, which would send as much as 3,000 megawatts of wind power to California. (Photo: Jay Calderon/The Desert Sun)

After an extensive environmental review, the U.S. Forest Service issued a permit Wednesday for portions of the TransWest Express transmission line that would cross through 19 miles of the Uinta-Wasatch-Cache and Manti-La Sal national forests in Utah.

"It's another step forward in the process of making this line a reality, and being able to provide a path that allows California, Arizona and Nevada to access the high volumes of renewable energy supplies that are available in Wyoming," said Kara Choquette, a spokesperson for the Anschutz subsidiaries developing the power project.

Between the Forest Service approval and a Bureau of Land Management permit issued in December, the developer now has the go-ahead to build about two-thirds of the 730-mile route, Choquette said, progress that comes as the U.S. grid overhaul for renewables accelerates nationwide. Company officials are reaching out to the roughly 450 private landowners along the proposed route. They must also apply for a state permit in Wyoming, and 14 county-level permits in Wyoming, Colorado, Utah and Nevada.

But Anschutz's Chokecherry and Sierra Madre wind farm is a reminder that Trump can't stop the ongoing transition from coal to cleaner sources of energy, which is being driven largely by market forces. Solar, wind and natural gas, which burns more cleanly than coal, are now the cheapest sources of new electricity across much of the country, even as Texas grid constraints sometimes force High Plains turbines to shut down during oversupply. Utility industry executives are abandoning coal and embracing renewable energy. And the American solar industry employs more people than coal or natural gas.

States and local governments in California, New York and elsewhere have also forged ahead with policies to reduce climate emissions, including New York's largest offshore wind project recently approved. So have major companies like Apple, Facebook and Google, which have invested billions of dollars in renewable energy.

"The (Trump) administration is so out of step with reality right now. The trend is powerful, whether it's coming the cities or corporations, or from the coastal states," said Don Furman, a former utility executive who now advocates for greater sharing of renewable energy across state lines in the West.

Turbines at Duke Energy's Happy Jack wind farm near Cheyenne, Wyoming generate electricity on Dec. 6, 2016. (Photo: Jay Calderon/The Desert Sun)

Clean energy advocates say the 3,000-megawatt Wyoming wind farm is an especially powerful example of the economic case for renewable energy, because its proprietor is Anschutz, a longtime fossil fuel magnate and major donor to Republican politicians.

"I don't think Philip Anschutz would be putting his money here if he thought this was a bad business bet," Furman said.

The Forest Service also issued a permit Wednesday for the 416-mile Energy Gateway South power line, which would run through Wyoming, Colorado and Utah, traversing nine miles of the same national forests TransWest Express would cross. Gateway South is part of the 1,900-mile Energy Gateway transmission project being developed by Warren Buffett's PacifiCorp utility, which serves customers across six western states.

PacifiCorp officials say the $6 billion transmission project is needed to meet growing electricity demand. They've also pitched the power lines as another opportunity to transmit wind power from Wyoming to California and other coastal states. Critics, though, see Energy Gateway as costly and unnecessary — and they're worried Californians would end up paying the price through higher electricity rates.

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Vancouver 100% EV-Ready Policy mandates EV charging in new multi-unit residential buildings, expands DC fast charging, and supports zero-emission vehicles, reducing carbon pollution and improving air quality with BC Hydro and citywide infrastructure upgrades.

Key Points

A city rule making new multi-unit homes EV-ready and expanding DC fast charging to accelerate zero-emission adoption.

✅ 100% EV-ready stalls in all new multi-unit residential builds

✅ Citywide DC fast charging within 10 minutes by 2021

✅ Preferential parking policies for zero-emission vehicles

Vancouver is now one of the first cities in North America to adopt a 100 per cent Electric Vehicle (EV)-ready policy for all new multi-unit residential buildings, aligning with B.C.'s EV expansion efforts across the province.

Vancouver City Council approved the recommendations made in the EV Ecosystem Program Update last week. The previous requirement of 20 per cent EV parking spots meant a limited number of residents had access to an outlet, reflecting charging challenges in MURBs across Canada. The actions will help reduce carbon pollution and improve air quality by increasing opportunities for residents to move away from fossil fuel vehicles.

Vancouver is also expanding charging station infrastructure across the city, and developing a preferential parking policy for zero emissions vehicles, while residents can tap EV charger rebates to support home and workplace charging. Plans are to add more DC fast charging points, which can provide up to 200 kilometres of range in an hour. The goal is to put all Vancouver residents within a 10 minute drive of a DC fast-charging station by 2021.

#google#

A DC fast charger will be installed at Science World, and the number of DC fast chargers available at Empire Fields in east Vancouver will be expanded. BC Hydro will also add DC fast chargers at their head office and in Kerrisdale, as part of a faster charging rollout across the network.

The cost of adding charging infrastructure in the construction phase of a building is much lower than retrofitting a building later on, and EV owners can access home and workplace charging rebates to offset costs, which will save residents up to $3,300 and avoid the more complex process of increasing electrical capacity in the future. Since 2014, the existing requirements have resulted in approximately 20,000 EV-ready stalls in buildings.

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St. Albert electric buses debut as zero-emission, quiet public transit, featuring BYD technology, long-range batteries, and charging stations, serving Edmonton routes while advancing sustainable transportation goals and a future fleet expansion.

Key Points

They are zero-emission BYD transit buses that cut noise and air pollution, with long-range batteries and city charging.

✅ Up to 250-280 km range per charge

✅ Quiet, zero-emission operations reduce urban pollution

✅ Backed by provincial GreenTRIP funding and BYD tech

The city of St. Albert is going green — both literally and esthetically — with three electric buses on routes in and around the city this week.

"They're virtually silent," Wes Brodhead, chair of the Capital Region Board transit committee and a St. Albert city councillor, said. "This, as opposed to the diesel buses and the roar that accompanies them as they drive down the street."

You may not hear them coming but you'll definitely see them, as electric school buses in B.C. hit the road as well.

The 35-foot electric buses are painted bright green to represent the city's goal of adopting sustainable transportation.

"There's no noise pollution, there's no air pollution, and it just kind of fit with the whole theme of the city," said St. Albert Transit director Kevin Bamber.

'The conversation around the conference was not if but when the industry will fully embrace electrification,' - Wes Brodhead, St. Albert city councillor

The buses cost about $970,000 each. Adding in the required infrastructure, including charging stations, the project cost a total of $3.1 million, with two-thirds of the funding coming from the provincial government's Green Transit Incentives Program. 

The electric buses are estimated to go between 250 and 280 kilometres on a single charge.

"That would mean any of the routes that we currently have through St. Albert or into Edmonton, an electric bus could do the morning route, come back, park in the afternoon and go back out and do the afternoon route without a charge," Bamber said. 

St. Albert councillor Wes Brodhead envisions having a full fleet of 60 electric buses in years to come, a scale informed by examples like the TTC's electric bus fleet operating in North America. (Supplied)

Brodhead went to an international transit conference in Montreal, where STM electric buses have begun rolling out and he said manufacturers presented various electric bus designs. 

"The conversation around the conference was not if but when the industry will fully embrace electrification," Brodhead said.

The vehicles were built in California by BYD Ltd., one of only two companies making the long-endurance electric buses.

The city has ordered four more of the buses and hopes to be running all seven by the end of the year, as battery-electric buses in Metro Vancouver continue to hit the roads nationwide.

Eventually, Brodhead envisions having a full fleet of 60 electric buses in St. Albert.

Edmonton is expected to operate as many as 40 electric buses, and while city staff are still in the planning stages, Edmonton's first electric bus has already hit city streets.

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Kemper County power plant costs and delays highlight lignite coal gasification, syngas production, carbon capture targets, and looming rate plans as Mississippi Power navigates Public Service Commission oversight and shareholder-ratepayer risk.

Key Points

Costs exceed $7.5B with repeated delays; rate impacts loom as syngas, lignite, and carbon capture systems mature.

✅ Estimate tops $7.5B; customers could fund about $4.3B

✅ Carbon capture target: 65% CO2 via syngas from lignite

✅ Rate plans pending before the Public Service Commission

A Mississippi utility on Monday delayed making proposals for how its customers should pay for an ever-more-expensive power plant, even as the estimated cost of the facility crossed $7.5 billion.

The Kemper County power plant will be tasked with mining lignite coal a few hundred yards away from the plant. That coal is moved through a process that will convert it to syngas. The syngas is then used to drive the energy output of the plant, and the resulting electricity is then moved into the grid, where transmission projects influence regional reliability and capacity.

Thomas Fanning, CEO of parent Southern Co., told shareholders in May that Mississippi Power would file rate plans for its Kemper County power plant this month. But still unable to operate the plant steadily enough to declare it finished, Mississippi Power punted, instead asking to hold rates level for 11 months to pay off costs that have already been approved by regulators.

Mississippi Power says it now hopes to reach commercial operation in June. The plant is more than three years behind schedule, with 10 delays announced in the past 18 months. It was originally supposed to cost $2.9 billion.

The company also said monday that it will have to replace troublesome parts of the facility much sooner than expected, including units that cool the synthetic gas produced from soft lignite coal by two gasifier units, plus ash handling systems in the gasifiers.

Kemper is designed to take synthetic gas, pipe it through a chemical plant to remove carbon dioxide and other chemicals, and then burn the gas in turbines to generate electricity. It’s designed to capture 65 percent of carbon dioxide from the coal, releasing only as much of the climate-warming gas as a typical natural gas plant. It’s a key effort nationally to maintain coal as a viable fuel source, even as coal unit retirements proceed in other states.

Mississippi Power raised its estimate of Kemper’s cost by $209.4 million, with shareholders absorbing $185.9 million, while ratepayers could be asked to pay $23.5 million. Overall, customers could be asked to pay $4.3 billion. Southern shareholders have agreed to absorb $3.1 billion, which has risen by $500 million since November.

The elected three-member Public Service Commission in 2015 allowed the company to raise rates on its 188,000 customers by $126 million a year. That paid for $840 million in Kemper work, which began generating electricity in 2014 using piped-in natural gas. Some items covered by that 15 percent rate increase will be paid off in coming months, but Mississippi Power now proposes to repay costs from regulatory proceedings earlier than originally projected.

In testimony filed with the Public Service Commission, Mississippi Power Chief Financial Officer Moses Fagin said that keeping rates level would reduce whiplash to customers when rates rise later to pay for Kemper, would pay off accumulated costs more quickly and would help the company wean itself off financial support from Southern Co. while maintaining credit ratings and positioning for a possible bond rating upgrade over time.

“Cash flow is important to the company in maintaining its current ratings and beginning to rebuild its credit strength on a more independent basis apart from the extraordinary parental support that has been required in recent years to maintain financial integrity,” Fagin testified.

Spokesman Jeff Shepard said Mississippi Power is still drawing up two rate plans — one requiring a sharp, immediate rate increase, and a “rate mitigation plan” that might cushion increases amid declining returns in coal markets. He said the company isn’t sure when it will file them. Fagin suggested the Public Service Commission set a new deadline of March 2, 2018.

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Alberta Electricity Rate Cap shields RRO customers with a 6.8 cents/kWh price ceiling, stabilizing power bills amid capacity market transition, using carbon tax funding to offset spikes and enhance consumer protection from volatility.

Key Points

A four-year 6.8 cents/kWh ceiling on Alberta's RRO power price, backed by carbon tax to stabilize bills.

✅ Applies to RRO customers from Jun 2017 to May 2021

✅ Caps rates at 6.8 cents/kWh; lower RRO still applies

✅ Funded by carbon tax when market prices exceed cap

The Alberta government introduced a bill Tuesday, part of new electricity rules that will allow it to place a cap on regulated electricity rates for the next four years.

The move to cap consumer power rates at a maximum of 6.8 cents per kilowatt-hour for four years was announced in November 2016 by Premier Rachel Notley, although it was later scrapped by the UCP during a subsequent policy shift.

The cap is intended to protect consumers from price fluctuations from June 1, 2017, to May 31, 2021, as the province moves from a deregulated to a capacity power market amid a power market overhaul that is underway.

The price ceiling will apply to people with a regulated rate option. If the RRO is below 6.8 cents, they will still pay the lower rate.

The government isn't forecasting price fluctuations above 6.8 cents in this four-year period. If the price goes above that amount, funding would come from the carbon tax if required.

Funding may come from carbon tax

"We're taking a number of steps to keep prices low," said Energy Minister Marg McCuaig-Boyd. "But in the event that prices were to spike, the cap would automatically prevent the energy rate from going over 6.8 cents to give Albertans even more peace of mind." 

The government isn't forecasting price fluctuations above 6.8 cents in this four-year period. If the price goes above that amount, funding would come from the carbon tax.

McCuaig-Boyd said this would be an appropriate use for the carbon tax as the cap helps Albertans move to a greener energy system and change how the province produces and pays for electricity without relying as much on coal-fired electricity. 

The government estimates the program will cost $10 million a month for each cent the rate goes above 6.8 cents per kilowatt-hour. If rates remain below that amount, the program may not cost anything.

Wildrose electricity and renewables critic Don MacInytre said the move shows the government expects retail electricity rates will double over the next four years. 

MacIntyre argued a rate cap simply shifts increasing electricity costs away from consumers to the Alberta government. But ultimately everyone pays. 

"It's simply a shift of a burden from the ratepayer to the taxpayer, which is essentially the same person," he said. 

The City of Medicine Hat runs its own electrical system without a regulated rate option. The government will talk with the city to see if it is interested in taking part in the price cap protection.

About 60 per cent of eligible Albertans or one million households use the regulated rate option in their electricity contracts.

The current regulated rate option averages less than three cents per kilowatt-hour.

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EV Opportunity for Utilities spans EV charging infrastructure, grid modernization, demand response, time-of-use rates, and customer engagement, enabling predictable load growth, flexible charging, and stronger utility branding amid electrification and resilience challenges.

Key Points

It is the strategy to leverage EV adoption for load growth, grid flexibility, and branded charging services.

✅ Monetizes EV load via TOU rates, managed charging, and V2G.

✅ Uses rate-based infrastructure to expand equitable charging access.

✅ Enhances resilience and DER integration through smart grid upgrades.

Tesla recently announced delivery of the first 30 production units of its Model 3 electric vehicle (EV). EV technology has generated plenty of buzz in the electric utility industry over the past decade and, with last week’s announcement, it would appear that projections of a significant market presence for EVs could give way to rapid growth.

Tesla’s announcement could not have come at a more critical time for utilities, which face unprecedented challenges. For the past 15 years, utilities have been grappling with increasingly frequent “100-year storms,” including hurricanes, snowstorms and windstorms, underscoring the reality that the grid’s aging infrastructure is not fit to withstand increasingly extreme weather, along with other threats, such as cyber attacks.

Coupled with flat or declining load growth, changing regulations, increasing customer demand, and new technology penetration, these challenges have given the electric utility industry good reason to describe its future as “threatened.” These trends, each exacerbating the others, mean essentially that utilities can no longer rely on traditional ways of doing business.

EVs have significant potential to help relieve the industry’s pessimistic outlook. This article will explore what EV growth could mean for utilities and how they can begin establishing critical foundations today to help ensure their ability to exploit this opportunity.

The opportunity

At the Bloomberg New Energy Finance (BNEF) Global Summit 2017, BNEF Advisory Board Chairman Michael Liebreich announced the group’s prediction that electric vehicles will comprise 35-47 percent of new vehicle sales globally by 2040.

U.S. utilities have good reason to be optimistic about this potential new revenue source, as EV-driven demand growth could be substantial according to federal lab analyses. If all 236 million gas-powered cars in the U.S. — average miles driven per year: 12,000 — were replaced with electric vehicles, which travel an average of 100 miles on 34 kWh, they would require 956 billion kWh each year. At a national average cost of $0.12 / kWh, the incremental energy sold by utilities in the U.S. would bring in around $115 billion per year in new revenues. A variety of factors could increase or decrease this number, but it still represents an attractive opportunity for the utility sector.

Capturing this burgeoning market is not simply a matter of increased demand; it will also require utilities to be predictable, adaptable and brandable. Moreover, while the aggregate increase in demand might be only 3-4 percent, demand can come as a flexible and adaptable load through targeted programming. Also, if utilities target the appropriate customer groups, they can brand themselves as the providers of choice for EV charging. The power of stronger branding, in a sector that’s experiencing significant third-party encroachment, could be critical to the ongoing financial health of U.S. utilities.

Many utilities are already keenly aware of the EV opportunity and are speeding down this road (no pun intended) as part of their plans for utility business model reinvention. Following are several questions to be asked when evaluating the EV opportunity.

Is the EV opportunity feasible with today’s existing grid?

According to a study conducted by the U.S. Department of Energy’s Pacific Northwest National Laboratory, the grid is already capable of supporting more than 150 million pure electric vehicles, even as electric cars could challenge state grids in the years ahead, a number equal to at least 63 percent of all gas-powered cars on the road today. This is significant, considering that a single EV plugged into a Level 2 charger can double a home’s peak electricity demand. Assuming all 236 million car owners eventually convert to EVs, utilities will need to increase grid capacity. However, today’s grid already has the capacity to accommodate the most optimistic prediction of 35-47 percent EV penetration by 2040, which is great news.

Should the EV opportunity be owned by utilities?

There’s significant ongoing debate among regulators and consumer advocacy groups as to whether utilities should own the EV charging infrastructure, with fights for control over charging reflecting broader market concerns today. Those who are opposed to this believe that the utilities will have an unfair pricing advantage that will inhibit competition. Similarly, if the infrastructure is incorporated into the rate base, those who do not own electric vehicles would be subsidizing the cost for those who do.

If the country is going to meet the future demands of electric cars, the charging infrastructure and power grid will need help, and electric utilities are in the best position to address the problem, as states like California explore EVs for grid stability through utility-led initiatives that can scale. By rate basing the charging infrastructure, utilities can provide charging services to a wider range of customers. This would not favor one economic group over another, which many fear would happen if the private sector were to control the EV charging market.

If you build it, will they come?

At this point, we can conclude that growth in EV market penetration is a tremendous opportunity for utilities, one that’s most advantageous to electricity customers if utilities own some, if not all, of the charging infrastructure. The question is, if you build it, will they come — and what are the consequences if they don’t?

With any new technology, there’s always a debate centered around adoption timing — in this case, whether to build the infrastructure ahead of demand for EV or wait for adoption to spike. Either choice could have disastrous consequences if not considered properly. If utilities wait for the adoption to spike, their lack of EV charging infrastructure could stunt the growth of the EV sector and leave an opening for third-party providers. Moreover, waiting too long will inhibit GHG emissions reduction efforts and generally complicate EV technology adoption. On the other hand, building too soon could lead to costly stranded assets. Both problems are rooted in the inability to control adoption timing, and, until recently, utilities didn’t have the means or the savvy to influence adoption directly.

How should utilities prepare for the EV?

Beyond the challenges of developing the hardware, partnerships and operational programs to accommodate EV, including leveraging energy storage and mobile chargers for added flexibility, influencing the adoption of the infrastructure will be a large part of the challenge. A compelling solution to this problem is to develop an engaged customer base.

A more engaged customer base will enable utilities to brand themselves as preferred EV infrastructure providers and, similarly, empower them to influence the adoption rate. There are five key factors in any sector that influence innovation adoption:

1. Relative advantage – how improved an innovation is over the previous generation.

2. Compatibility – the level of compatibility an innovation has with an individual’s life.

3. Complexity – if the innovation is to difficult to use, individuals will not likely adopt it.

4. Trialability – how easily an innovation can be experimented with as it’s being adopted.

5. Observability – the extent that an innovation is visible to others.

Although much of EV adoption will depend on the private vehicle sector influencing these five factors, there’s a huge opportunity for utilities to control the compatibility, complexity and observability of the EV. According to  “The New Energy Consumer: Unleashing Business Value in a Digital World,” utilities can influence customers’ EV adoption through digital customer engagement. Studies show that digitally engaged customers:

• have stronger interest and greater likelihood to be early EV adopters;

• are 16 percent more likely to purchase home-based electric vehicle charging stations and installation services;

• are 17 percent more likely to sign up for financing for home-based electric vehicle charging stations; and

• increase the adoption of consumer-focused programs.

These findings suggest that if utilities are going to seize the full potential of the EV opportunity, they must start engaging customers now so they can appropriately influence the timing and branding of EV charging assets.

How can utilities engage consumers in preparation?

If utilities establish the groundwork to engage customers effectively, they can reduce the risks of waiting for an adoption spike and of building and investing in the asset too soon. To improve customer engagement, utilities need to:

1. Change their customer conversations from bills, kWh, and outages, to personalized, interesting topics, communicated at appropriate intervals and via appropriate communication channels, to gain customers’ attention.

2. Establish their roles as trusted advisors by presenting useful, personalized recommendations that benefit customers. These tips should change dynamically with changing customer behavior, or they risk becoming stagnant and redundant, thereby causing customers to lose interest.

3. Convert the perception of the utility as a monopolistic, inflexible entity to a desirable, consumer-oriented brand through appropriate EV marketing.

It’s critical to understand that this type of engagement strategy doesn’t even have to provide EV-specific messaging at first. It can start by engaging customers through topics that are relevant and unique, through established or evolving customer-facing programs, such as EE, BDR, TOU, HER.

As lines of communication open up between utility and users, utilities can begin to understand their customers’ energy habits on a more granular level. This intelligence can be used by business analysts to help educate program developers on the optimal EV program timing. For example, as customers become interested in services in which EV owners typically enlist, utilities can target them for EV program marketing. As the number of these customers grows, the window for program development opens, and their levels of interest can be used to inform program and marketing timelines.

While all this may seem like an added nuisance to an EV asset development strategy, there’s significant risk of losing this new asset to third-party providers. This is a much greater burden to utilities than spending the time to properly own the EV opportunity.

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