Green Energy

Almost a year ago, CleanTechnica reader Rich Blair walked into his local Tesla store to ask about rooftop solar system. He met up with Morgan Harding, who became his Tesla solar adviser. Within a short time, Blair had a 19.825 kilowatt solar array — 61 panels x 325 watts each — with 3 inverters on the roof of his home in Venice, Florida. Since then, 6 of his neighbors have installed Tesla rooftop solar systems of their own. That means 10% of the 70 homes in his Stonewalk community are now Tesla solar customers.

Why? Mostly it was pure economics. Blair, who owns a Tesla Model S, was sending $400 a month on average to Florida Power & Light, thanks to having two teenagers in the house and two 80-gallon electric hot water heaters. His monthly payment on the Tesla rooftop system comes to $308. That includes a Powerwall residential storage battery, which is on backorder due to high demand but should be installed shortly. The federal tax credit is sweet, too, wiping out Blair’s entire 2018 federal tax bill.

The utility company pays Blair for any electricity he feeds back into the grid. The reimbursement rate is only about 20% of the retail rate the utility charges its customers but, until his Powerwall gets installed, every little bit helps. As of January 20, his solar system has produced 167% more electricity than Blair’s home has used this month.

FP&L doesn’t pay solar customers for excess energy every month. Instead it maintains a “bank account” of excess production throughout the year, then zeroes out the account on December 31 each year. Any excess is refunded in the form of a credit on the January bill.

Rich Blair had been investigating rooftop solar systems for some time. He lives in sunny Florida, after all. Why did he end up doing business with Tesla? “I compared 4 different solar companies and went with Tesla because they offered a more turnkey solution. My decision to go solar was not only about reducing my carbon footprint, but also about what was economically feasible.”

The Tesla solar referral program was part of his decision. With 6 neighbors already purchasing systems from Tesla, it’s clear the referral system works. “But reducing my carbon footprint and the financial feasibility were also motivating factors,” Blair says. There are other advantages as well. As soon as his Powerwall gets installed, he will be better able to charge his Model S with solar power any time of day. Also, “The cost of my solar system is fixed while electricity rates goes up every year,” he adds.

Blair also has high praise for Florida Power & Light. “Our electric provider, unlike some utilities, was great to work with and swapped the net meter within a few days after the county inspection. The county inspector, who sees a lot of new solar systems, had nothing but praise for Tesla.”

If you are in the market for a rooftop solar system, you owe it to yourself to talk with a Tesla representative. Tell ’em a very happy Rich Blair sent you.

New Hampshire may soon join the handful of New England states actively pursuing offshore wind energy development.

On January 2, Governor Chris Sununu sent a letter to Walter Cruickshank, the acting director of the Bureau of Ocean Energy Management (BOEM), requesting that the agency establish an intergovernmental offshore renewable energy task force. The move is the first step in a multiyear process.

“The task force will mirror those in other states,” said Matthew Mailloux, an energy advisor with New Hampshire’s Office of Strategic Initiatives, in an email.

“Its purpose is to facilitate coordination with federal and New Hampshire stakeholders to determine the feasibility of offshore wind in federal waters off New Hampshire’s coast. This is a preliminary step in a lengthy process prior to any decision,” he said.

A group of lawmakers from the New Hampshire State Senate and House of Representatives filed a joint resolution for the 2019 legislative session “supporting efforts to develop wind power off the New Hampshire coast” and urging Gov. Sununu to ask BOEM to create the offshore wind task force.

The resolution noted that New Hampshire has committed to reduce greenhouse gas emissions by 80 percent by 2050 but “has yet to develop a plan to achieve that goal.”

BOEM is closed as a result of the partial U.S. federal government shutdown, so New Hampshire officials will have to wait before receiving a response from BOEM. The shutdown has already delayed two public meetings for the Vineyard Wind project planned for offshore Massachusetts, as GTM previously reported.

The opportunity in New Hampshire

Will Gov. Sununu’s letter to BOEM prompt project developers’ interest in New Hampshire?

“This was actually kind of a surprise, to see the governor requesting that this task force be formed,” Francis Pullaro, executive director of the non-profit RENEW Northeast, told Greentech Media in an interview.

“The industry has very much been focused on the southern New England states because there’s the existing leases and recently completed lease action,” he said. “But there’s no reason all the coastal states in New England can’t take advantage of this technology.”

Project developers active in the north Atlantic region have thus far focused their attention on states such as Massachusetts, New York, and New Jersey that have announced ambitious offshore wind deployment targets.

The record-breaking auction conducted by BOEM last month for lease areas offshore Massachusetts, New Hampshire’s neighbor to the south, was no doubt a wake-up call for New Hampshire officials.

That’s not to say that state policymakers are unaware of New Hampshire’s offshore wind potential. A 10-year state energy strategy released in September 2014 estimated the offshore wind resource potential in New Hampshire at nearly 3,500 megawatts.

The state lawmakers’ joint resolution cited a 2015 bipartisan New Hampshire legislative study committee report, which concluded that “the wind resource off of New Hampshire’s coast has the potential to generate significant amounts of electricity” and “offshore wind development has the potential to generate significant economic activity within Portsmouth Harbor.”

Pullaro observed that Portsmouth is no stranger to wind energy development, as components for onshore wind projects built in Northern New England have been shipped through the deep-water port.

Regional cooperation on offshore wind development

Because New Hampshire does not have a large electric load, there is the potential, said Pullaro, for electricity generated at offshore wind projects to be sold in Massachusetts, Connecticut, or even New York.

“For these projects to really make sense,” he said, “the New England states need to work together – particularly the northern New England states that don’t have a lot of electric demand.”

Offshore wind projects need to be built at scale in order to be cost effective. That’s why it’s important for New Hampshire to join forces with its neighbors, while recognizing that they’re going to want to pursue their own interests and local economic development, according to Pullaro.

“To get scale for the off-taker agreements,” he said, “they really need to work with the other New England states.”

In a major milestone for the sultanate’s renewable energy industry, the first two of total 13 turbines at the 50MW Dhofar Wind Farm have been installed.

Sultanate’s and Gulf region’s first large-scale commercial wind energy project, the Dhofar Wind Farm is expected to become operational by the third quarter of 2019 with all 13 turbines scheduled to be installed by March.

It will supply seven per cent of Dhofar governorate’s electricity demand, or enough clean energy to power an estimated 16,000 homes, while offsetting an estimated 110,000 tonnes of carbon dioxide emissions annually, according to project developer Masdar, the Abu Dhabi energy company.

The project is fully financed by Abu Dhabi Fund for Development (ADFD), and follows an agreement signed in 2014 between Masdar and the Rural Areas Electricity Company of Oman (Tanweer). A Masdar-led consortium including GE and Spain’s TSK is developing the wind farm.

Qais al Zakwani, executive director, Authority for Electricity Regulation (AER), visited the site in Dhofar last week to oversee the important developments of the ongoing project. Eng Saleh bin Nasser al Rumhi, chief executive officer of Tanweer said, “We are looking forward to the implementation of this initiative, which will be the first large-scale renewable project in Oman. Our team has worked closely with all the participants to bring this technology to the sultanate and to ensure knowledge transfer in the country.”

Once complete, the wind farm will be handed over to Tanweer, which will then operate the plant and supply the generated electricity to the local Dhofar power grid through an overhead power line managed by the Oman Electricity Transmission Company (OETC).

The Oman Power and Water Procurement Company (OPWP) will offtake the generated electricity from Tanweer in line with a power purchase agreement (PPA) signed on September 12, 2017. Dr Manar al Moneef, general manager, GE Renewable Energy for the Middle East, North Africa, and Turkey, said, “The wind farm features our 3.8-130 wind turbine customised to the desert conditions specific to the Gulf region.”

Mohamed Jameel al Ramahi, chief executive officer of Masdar, said, “As a global leader in wind energy technology, we are proud to support Oman in the realisation of its renewable energy ambitions, and deeply committed to our partnership with Abu Dhabi Fund for Development and the world-class consortium delivering this milestone wind energy project on schedule and to the highest operational standard.”

GE is providing the project’s 3.8MW wind turbines, while TSK is responsible for the rest of the wind farm’s infrastructure, which includes medium- and high-voltage substations and 13km of overhead transmission lines. Masdar is the project developer and implementation lead.

Australia’s wind and solar boom looks set to power through 2019 following a record year, despite grid constraints and extra scrutiny from network operators to make sure new projects don’t spark blackouts like ones that hit two years ago.

Abundant wind and sun, falling turbine and panel costs, and corporate demand for contracts to hedge against rising power tariffs have attracted dozens of international developers looking to build wind and solar farms Down Under.

Even though the developers have met with flip-flops on energy policy, a strained grid that has trouble integrating intermittent renewable power, and unexpected hook-up costs, they still see Australia as a growth market.

“We believe that we have a great future in Australia, because we have the right answers,” said Xavier Barbaro, Chief Executive of France’s Neoen (NEOEN.PA), whose biggest market is Australia.

Companies like Neoen, its compatriot Total-Eren (TOTF.PA), India’s Adani (ADEL.NS), U.S. utility AES Corp (AES.N) and Germany’s Sonnen are expanding in Australia, looking to fill a gap as ageing coal-fired plants are retired over the next two decades.

“Confidence is high as the industry enters 2019, with unprecedented levels of construction activity under way,” said Anna Freeman, a director at the Clean Energy Council, an industry group.

Australia generates nearly 20 percent of its electricity from renewables. This is forecast to jump to 75 percent over the next 20 years.

A total of 14.7 gigawatts (GW) of large-scale solar and wind projects worth A$20 billion ($14 billion) were under construction or reached financial close last year, more than double 2017’s record, according to the Clean Energy Council.

This rush of projects, with no clear guidance on where they best fit, led to an “element of anarchy”, but that is changing, said Simon Currie, founder of advisory firm Energy Estate. The Australian Energy Market Operator (AEMO), the energy council and network companies are working out clear guidelines on where to build plants and how to connect them to the grid.

“We’re moving from what was an opportunistic-based approach … into something that will be much more planned,” said Currie, whose company wants to develop Australia’s biggest renewable energy hub, with 4 GW of wind, solar and pumped hydro capacity in New South Wales.

Renewable projects added to the grid have grown from 22 with 1.2 GW of capacity in 2013 to a record 45 projects with 2.9 GW added in 2018, AEMO said. There are 114 more applications representing 15.9 GW pending, indicating plenty of potential congestion ahead.

The biggest challenge is that developers are all vying to connect to a grid running 5,000 km (3,100 miles) from Queensland in the north to South Australia and Tasmania.

This grid was designed to deliver power mainly from always-on coal-fired plants near three big mining areas, while wind and solar farms generate intermittent power from more remote sites, where network capacity can be limited.

To keep the grid stable, equipment such as “synchronous condensers” or batteries need to be added, which can increase costs by at least $20 million for a condenser alone. Batteries could be much higher.

Developers who failed to account for these issues have run into delays on project approvals or grid hook-up, bringing unanticipated costs, which in one case, led to the collapse of engineering firm RCR Tomlinson (RCR.AX) last November.

HOOK-UP HICCUPS

A Clean Energy Council survey of senior executives in December found grid connection is the biggest industry concern heading into 2019, Freeman said.

UK-based solar investor Octopus Investments said grid issues were what took it two years to choose its first investment in Australia. The Darlington Point solar farm is about to begin construction and will be the country’s largest.

“The grid is the biggest issue where assets fail in our project filter,” Octopus Managing Director Sam Reynolds told Reuters, declining to name projects the company rejected.

Developers and project lenders said they need to consider grid congestion, which can curtail power that gets to the network from any one plant; intermittency of wind and solar power, which affects current flow; and transmission losses, called marginal loss factors (MLFs).

“There’s a bit of nervousness around MLFs, curtailment, and then there’s construction and commissioning risk,” said Stephen Panizza, head of renewable energy at Federation Asset Management.

MLFs measure energy lost over power networks and have been increasing, with renewable projects being on the outer reaches of the grid, weakening returns for some operators.

Another factor is the cost of the extra technology to keep current steady on the grid as more intermittent power is added.

In November, France’s Total-Eren (TOTF.PA) agreed to buy a synchronous condenser to secure a connection agreement so it could build the A$330 million Kiamal solar farm in Victoria.

Delays due to talks with AEMO about the condenser, however, led to Total-Eren losing one of its power purchase agreements (PPAs).

Total-Eren’s Asia Pacific director, Michael Vawser, says other projects will face the same trouble.

“I do think there are other projects … caught off-guard by new grid regulations that will lose their PPAs through delays in being allowed to connect to the grid,” Vawser told Reuters in an interview in November.

Neoen, which has built 1 GW of wind and solar farms and the world’s biggest battery in Australia over the past four years, said in a recent prospectus it had collected 14 million euros ($16 million) in damages from a contractor building three solar farms because of hook-up delays.

Despite the challenges, Neoen, Total-Eren and their rivals are still scouring Australia for more opportunities.

“Australia is still an attractive market for us,” Vawser said.

How close is too close for a commercial solar installation?

For John and Cindy Falzon of Westtown, the answer is a little over 100 feet from their back deck on County Route 62.

A neighbor, Minisink town councilman Brian Ford, is leasing seven acres of his property to Solar Provider Group for an array to generate community solar energy, turning a field of tall grasses into a field of solar panels.

“We’re trying to oppose something that’s going to devalue our property,” John Falzon said Tuesday.

“We just want a setback,” Cindy Falzon said.

The Falzons say their requests to the planning board have brought backlash. John Falzon says people have yelled and cursed at him at board meetings.

From late October until this week, the Falzons say, Brian Ford, or someone, parked a manure spreader and a dump wagon directly behind their house, five feet from their property line.

“He has 85 acres. He’s never located it (farm equipment) in this position,” said Clifford Davis, a lawyer hired by the Falzons and two neighbors in the solar dispute. “It cannot be a coincidence.”

Within a couple days of the conversation, someone removed the farm equipment.

Although the Falzons have focused on Ford, it’s Solar Provider Group that’s negotiating the project design with the planning board.

Project manager Peter McMurtry said the company believes the proposal they’re putting forth is a reasonable compromise, and the studies done to date are sufficient, but they’re working with the planning board.

Their plan includes increasing the setback from 50 to 100 feet, with 107 mostly coniferous trees and possibly a small berm to screen the view. They’ve also made height adjustments to the panels.

Wetland and flood zones prevent putting the array elsewhere on the parcel.

“We really try to do the best job in keeping with industry standards,” McMurtry said.

Since 2016, 32 commercial solar installations have been built or proposed in Orange County, at least eight of them in Minisink, said county Planning Commissioner David Church.

Minisink Planning Board Chairman David Witkowski said the board is making sure the project abides by zoning, and is trying to mitigate the negatives for neighbors. The planning board hired a consultant to perform a visual analysis, he said.

“The planning board, in its broad powers, could require more setback if they determined there’s an adverse impact,” Davis said.

The Falzons said a promised visual impact study was supposed to be scheduled in early November, but wasn’t. Instead, in late October, the farm equipment showed up.

“This guy doesn’t want to compromise,” Cindy Falzon said on Tuesday, before the equipment was removed. “With all his land, we’ve got to see this.”

The Falzons have lived in their home for 15 years. The Ford family has been there for generations in Minisink, a town of about 4,500 that’s still mostly rural.

Brian Ford is on the town board, and Ralph Ford, a relative, is supervisor, as they were in 2016 when the town passed the solar zoning law.

Witkowski said planning board member Joseph Ford, a distant relative of Brian, abstains from any votes involving Fords.

The town is going through growing pains, Witkowski said, but planning board members still go out and walk the land for every proposal.

In the 1950s-1960s, the town boasted 74 dairy farms; now there are two.

“Minisink has to decide what it wants to be when it grows up,” he said. “And it’s not going to be dairy farming.”

Saint John Energy is looking for a developer to build a wind energy project in Spruce Lake Industrial Park.

“Quite frankly, this is a great project,” said Ray Robinson, the utility’s president and CEO.

“You can increase the amount of renewables on the system and reduce greenhouse gases … while significantly reducing the cost of energy.”

Robinson said Saint John Energy has already done about 10 years of research to support the project, including five years of wind data collection, business case analyses, environmental studies and market testing.

“All of those indicators are showing there’s a fantastic opportunity for wind development here in Saint John, Robinson said.

Robinson said the wind data indicates Spruce Lake Industrial Park in the western reaches of Saint John has a “very good wind regime,” so the output from the project should be “quite impressive.”

The development will likely be able to generate 20 to 40 megawatts of electricity, said Robinson, or eight to 16 per cent of the utility’s requirements.

Last year, 95 per cent of the customers who responded to a survey said they would support renewable generation, as long as it doesn’t increase rates, he said.

“We’re of the belief that this will be driving significant savings to the bottom line.”

The utility added that it would not sign a power purchase agreement if that’s not the case.

Forbidden from generating power

Much more preliminary work will be required before the project becomes a reality, including an environmental impact assessment and community consultation, said Robinson.

Saint John Energy is not currently allowed, under the Electricity Act, to generate electricity.

“We have aspirations for that, and we’re working with the Province of New Brunswick to see if that can happen sometime in the future.”

For now, they utility is looking for a third party to build and own the project. Saint John Energy would simply buy the power.

“The long-term play is having legislation changed,” said Robinson, “to enable Saint John Energy to effectively implement a growth strategy and through financial performance being able to flow dividends through to the owner, to the city.”

According to a timeline on the utility’s website it hopes to select a developer by summer and to see the project in operation by late 2021 or early 2022.

“The sooner something like this can be part of the mix the better — for our customers, for the utility, for the city and for the province,” said Robinson.

Tried wind before

This isn’t Saint John Energy’s first attempt at a wind energy project.

It was involved in a failed bid about a year ago, with two other municipalities, for a project under NB Power’s Locally Owned Renewable Energy Project, or LORESS, program.

No one at NB Power or Saint John Energy would say exactly why the project was not successful.

But Saint John Energy said it doesn’t need the approval of NB Power or the Energy and Utilities Board to proceed this time around.

NB Power said a total of 35 submissions were received under the LORESS program.

2 First Nations launch projects

It said the successful ones were chosen based on technical ability, finance capacity, terms, conditions, price and utility policy.

Two LORESS projects have been announced so far. One, involving Pabineau First Nation, near Bathurst, is being built in the Richibucto area. The other, called the Wocawson Energy Project, involves Tobique First Nation and is being built about 20 kilometres east of Sussex.

Both projects are through renewable energy developer Natural Forces NB Inc. and both are expected to be up and running by the end of this year.

Another LORESS project is expected to be announced in the coming weeks, said Marc Belliveau of NB Power media relations.

And submissions are under review now for a fourth and final 20-megawatt project, he said.

NB power has a goal of 40 per cent renewable energy by 2020. It has now signed power purchase agreements taking it to 37 per cent.

“As years go on, we are always approached and will discuss more potential renewable energy projects if they are a good economical fit with our generation fleet and in keeping our rates stable,” said Belliveau.

Not in NB Power’s mandate

Green Party leader David Coon suggested this week that if the province wants to develop more renewable energy for economic and environmental benefits it will need some other body besides NB Power to drive that development.

“Because it’s really not in their mandate,” Coon said, following what he described as a lengthy meeting with the chair of NB Power.

“In that light, they just do what the law tells them to do. And the law now tells them they’ve got a particular target to supply customers from renewable sources of energy by 2020 and they are on track.”