Northwest National Marine Renewable Energy Center will support innovation in wave energy technologies
Source: New feed
DOE Announces $15 Million to Accelerate the Deployment of Energy Efficient Transportation Technologies
Today, the Energy Department (DOE) announced $15 million, subject to appropriations, to support community-based projects to accelerate the adoption of advanced and alternative fuel vehicles and demonstrate energy efficient mobility systems including connected and autonomous vehicles as well as new transportation system models.
Source: New feed
Green Mountain Power, the Vermont utility that’s already helping grid-connected customers install solar panels and backup batteries, now wants to extend its reach to homes that are completely off the grid — a first-of-a-kind move that could end up being a utility antidote to grid defection.
It’s starting small — only six customers are being sought for the first phase of the pilot project. Still, Tuesday’s launch of the “Off-Grid Package” marks the first time that a U.S. utility has offered customers the option of getting utility financing and technical assistance to generate their own power independent of the power grid.
Under the program, Green Mountain Power will offer a combination of efficiency upgrades, solar, batteries, home energy management and backup generators to customers building, or already living in, a home far from the grid — a not-uncommon scenario in the mostly rural state.
Instead of paying upfront for all that technology, customers will pay the utility a monthly fee. According to the filing with the Vermont Public Service Board describing the plan, that fee is expected to fall between $400 and $850 for homes with an average monthly energy consumption between 400 and 800 kilowatt-hours.
That may sound like a lot of money for electricity and heat. But it’s likely a lot less than it would cost for a homeowner to install and fuel their own systems of a similar size — or, alternatively, pay for the utility to extend its power lines to reach them. Green Mountain Power, for its part, will recover its fixed costs, plus a small margin that will flow back to the rest of its customer base.
That’s what makes the deal a win for customers and utility alike, Green Mountain Power CEO Mary Powell said. Beyond that, it’s an opportunity to keep ahead of the trends of falling solar and battery prices that are expected to put grid disconnection within reach of more and more homeowners over the coming years.
“I don’t know if we’re going to get hundreds of people pounding down our door to get this,” Powell said in a Tuesday interview. “But there are Vermonters who’ve had to cobble systems together on their own to get off the grid. This is our opportunity to streamline it for customers, and be the company that does energy as a service. Why should it all be about grid-connected energy?”
Green Mountain Power’s move into off-grid power grew out of some of its ongoing work in distributed energy, Powell said. Those include its Stafford Hill community microgrid project, which is designed to keep critical services running during weather-related power outages; its program to offer Tesla Powerwall batteries for lease to homeowners, for use as backup power and as grid assets; and most recently, its microgrid at Emerald Lake State Park.
The latter project, which replaced a long and outage-prone power line with solar and batteries that met the park’s needs at a lower cost, was the inspiration for the off-grid package project, Josh Castonguay, Green Mountain Power’s chief innovation executive, noted in a Tuesday interview.
“There are a good amount of off-grid homes in Vermont today, but they tend to have lead-acid batteries, and use propane for cooking and heating,” he said. Green Mountain Power’s off-grid packages, by contrast, will be designed to minimize the need for propane-fueled heating and cooking to a few winter months, or no more than 20 percent of the year. That should reduce carbon emissions by more than 30 percent, compared to a typical grid-connected home, he said.
Green Mountain Power is working with contractor Peck Electric for the first installations, and will use inverters and control systems from OutBack Power, and batteries from Aquion Energy, as well as the new version of the Tesla Powerwall, he said. The utility will use cellular connections to monitor and manage these connected devices, along with a home energy control system to keep usage within the limits of the energy being generated and stored at each home.
All in all, it’s an innovative way for the utility to get involved in a class of customers that could start expanding dramatically in coming years, as the price of solar PV and batteries continues to fall into ranges that make them an economically viable alternative to grid power. This scenario, known as “grid defection,” could become a potentially disruptive one for utilities in regions with high power costs and ample sunshine, starting with Hawaii, but potentially spreading to tens of millions of customers over the coming decade.
Lots of utilities are looking for ways to own distributed energy resources (DERs), but few if any have taken the step into off-grid solutions, as Green Mountain Power is doing. There are many regulatory challenges to utilities moving into this kind of behind-the-meter activity, of course. Green Mountain Power has benefited in this regard from Vermont’s unusual “alternative regulation” regime that allows it to try novel projects like these.
But in Powell’s view, this off-grid model is something that other utilities will increasingly be exploring in the coming years. “Half the states in the nation, at least, have not deregulated. There are energy companies on top of energy companies to which this model is completely available. [In the states] that have jumped more early to deregulation, we’re going to see a lot more interesting models emerging.”
Behind-the-meter batteries are going to become a much larger part of the energy storage landscape over the next five years — and that means that this infant industry will be doing a lot of growing up in that time.
So says GTM Research’s latest report, The Behind-the-Meter Energy Storage Landscape 2016-2021, which lays out the factors that will contribute to a gigawatt-scale market for batteries in buildings by decade's end. This growth will bring opportunity for companies in the field, ranging from startups to industrial giants, all serving different portions of the behind-the-meter value chain.
In particular, we’ve seen a rapid expansion of interest in batteries for commercial and industrial buildings for demand-charge management and grid services, a use case that’s expected to become cost-competitive in a growing number of U.S. states over the course of the decade.
But this growing field will also reveal which combinations of financing models, go-to-market approaches, and vertical and horizontal integration strategies are viable and which aren’t, according to GTM Research energy storage analyst and report author Brett Simon. This will become increasingly apparent as the incentives and subsidies that have helped boost deployments in a few key states give way to market-based forces.
This pressure will certainly apply to different models for behind-the-meter battery system financing, which has been critical in lowering the up-front cost of behind-the-meter battery systems for C&I customers. Through the first three quarter of 2016, the United States has seen a boom in project finance with $645 million raised for the sector, according to GTM Research.
“Energy storage financing, which still lacks standardized formats, particularly for the residential segment, is expected to undergo an evolution as the technology becomes better understood and financiers gain greater comfort,” Simon noted. “In particular, financiers are still hesitant to back residential projects, given a lack of monetizable value streams, along with higher customer acquisition and system costs compared to the non-residential segment.”
To date, three different financing models have dominated the market — shared savings, leases, and models based on the power-purchase agreements (PPAs) common to solar projects. Shared savings, used by startups such as Green Charge and Demand Energy, offer the advantage of reducing customers’ commitment to fixed payments, compared to leasing arrangements from companies like Stem and Advanced Microgrid Solutions. But they also lack the clear and predictable customer pricing and revenue streams for financing partners that lease models provide.
The PPA-esque model, which generally combines solar with storage, “offers customers familiarity, as PPAs have seen success in the solar PV market,” Simon noted. “However, solar-plus-storage PPAs are still relatively new and require the proper structure in order to offer a clear value proposition.”
The coming years will also shine light on which of several go-to-market strategies best suit an expanding market, Simon noted. Out of the 40 companies covered in the report, “each is exploring a different business model and varying suites of product and service offerings.”
Early entrants like Stem and Green Charge have adopted a direct-to-end-customer strategy, managing everything from customer origination and project development to system integration and asset management. Meanwhile, companies like Enphase, Sunverge and Tabuchi Electric have worked largely through solar distributors and installers, while companies like Schneider Electric, ABB, NEC and S&C Electric are bringing integrated battery systems to market through various channels.
But these demarcations can be expected to shift in coming years, Simon noted. This will include companies looking for vertical integration opportunities by integrating systems and services or moving into project development roles, as well as horizontal moves by solar developers or energy management service providers into the storage space.
As the market potential and popularity of community solar grows nationally, all eyes are on Minnesota and Xcel Energy’s Solar Rewards Community program. Why are so few projects up and running? How realistic and viable is the 800-megawatt queue? Is the program durable? At the two-year anniversary of Xcel Energy’s community solar program launch, we’re taking a deep dive on the health of the program today and its potential going forward.
First, the good: In the two years since Xcel launched its community solar program in Minnesota more than 2,000 garden applications have been submitted. The bad? Only four applications, totaling 400 kilowatts, are interconnected and producing power today.
At this time last year, stakeholders felt cautiously optimistic. The initial, arguably unexpected, cohort of applications which had created a bottleneck within Xcel’s administrative and engineering staff seemed to have come unstuck and started moving forward. Additionally, after disagreement and controversy over project co-location, in June 2015 the Public Utilities Commission came to a decision to cap existing co-located projects at 5 megawatts and temporarily limit new applications to 1 megawatt.
One year ago, with uncertainty about whether or not the 30 percent federal Investment Tax Credit would be renewed, stakeholders were ready to forget the bumpy program launch and focus on expediency through the final interconnection stages. Xcel was seemingly on board, predicting that they would approve projects “north of 250 megawatts” by the end of 2016.
But, as we near the end of 2016, Xcel is now predicting a fraction of that number — 55 megawatts — will be energized by year’s end. According to Xcel’s latest compliance report filed this month:
“To date, several delays have prevented previously scheduled in-service dates from occurring, including safety concerns due to insufficient grounding, solar-garden readiness, solar-garden equipment failures during testing, and other unspecified requests to move dates. Xcel is working to accommodate shifting schedules whenever possible for year-end completion, but timelines and crew availability [are] very tight at this time of year, and weather-related impacts are possible.”
What is the status of the 800-megawatt application queue?
Today’s interconnection queue is primarily composed of applications submitted well over a year ago, the majority of which are co-located gardens between 1 megawatt and 5 megawatts in size. The chart below shows the monthly progression of these applications over the last calendar year from the Early Application Stage (blue), through the Engineering Study Stage (red), into the Design & Construction Stage (green) and finally to a complete application and in service project (sliver of purple).
The first trend this chart shows is that projects are moving through the process, albeit slowly. Xcel’s latest compliance filing reports 178 megawatts across 49 project sites in the “construction phase,” and we expect many of those in-service dates are nearing.
The second trend is that the overall number of applications is generally declining as projects are canceled or downsized. We attribute this at least in part to:
- Unexpectedly high costs to interconnect revealed upon completion of the engineering study.
- First-in-queue applicants moving forward claiming existing interconnection capacity leaving those projects next in line without a viable. economical path to completion.
- Reasons unrelated to interconnection such as permitting authority disapproval, financing difficulties, easement challenges, etc.
Additionally, there have been 12 formal interconnection disputes filed by solar companies challenging Xcel’s methodology and/or study conclusions. In the dispute process, an independent engineer contracting with the state’s Department of Commerce reviews the complaint history and prepares a thorough report and recommended resolution. Most often the reports have then been appealed by one or both parties and escalated to the commission for final decision. These disagreements have contributed to project delay, not only for the disputed projects but for others in the queue that have opted to be placed on hold in anticipation of a precedent-setting resolution.
The third trend is that new application volume has declined significantly since the deadline to submit co-located projects up to 5 megawatts lapsed in September 2015, as illustrated by the chart below. When the temporary 1-megawatt cap was reconsidered by the commission in July 2016, it reached the same conclusion and the co-location cap of 1 megawatt remains in place going forward.
Finally, a national policy milestone was reached when the commission approved the value-of-solar (VOS) rate as the bill credit for Xcel’s solar garden program. While Minnesota’s VOS methodology has been in place since 2014, this is the first time it will be put into practice in Minnesota and the country. All existing applications are grandfathered in under the “applicable retail rate” (ARR), and new applications filed on or after January 1, 2017 will receive the VOS rate. The small uptick of new application volume in the last few months, as seen in the above chart, is likely made up of projects developed with the ARR bill credit in mind submitting prior to the year-end deadline.
More work to be done
Engineering studies and designs are being completed, city and county permitting hurdles are being cleared, patient customers are signing up as subscribers to the program, and garden construction is underway across the state. Locally hired laborers and electricians have enjoyed a long building season as temperatures remained mild through November. And because the extension of the federal tax credit took some pressure off of the firm end-of-2016 deadline, it is looking likely that we will have our first 100 megawatts of community solar energized within the first few months of 2017. Minnesota’s flagship CSG program with Xcel is still a national leader and is still poised to be the largest in the country — at least for the next year or two.
But it is critical that we continue the program momentum and stability to ensure the ongoing health and growth of the Minnesota solar market. To that end, Fresh Energy will be participating in three upcoming discussions.
1. VOS plus an adjusted bill-credit rate
Between now and March 1, the Department of Commerce has been tasked with consideration of whether the VOS bill-credit rate should be adjusted with a positive or negative adder that could help to either encourage or discourage things like residential subscribers, low-income residential subscribers, brownfield sites, rooftop locations, etc. The Department of Commerce will file its recommendations with the Public Utilities Commission and stakeholders this spring.
2. Updating the state Interconnection Standards
Improvements to Xcel’s interconnection process have been made in the last two years for community solar applications, yet outdated state rules continue to be challenged by this large pipeline of projects and the technical engineering disputes that have arisen. The commission and stakeholders recognize that the 12-year-old interconnection rules are insufficient, and Fresh Energy and our partners initiated a new docket to facilitate the adoption of national best practices for all projects moving forward.
3. Low-income garden access
The commission’s last order requires Xcel to develop a community solar garden proposal specifically for low-income customers, applying Low-Income Home Energy Assistance Program eligibility standards by March 2017.
Avoiding the terrible twos
The last two years have been, at times, a bit discouraging. But because of all the legwork and regulatory improvements, Xcel’s community solar program has unquestionably been a significant driver for investment and access in the state’s solar market. As the initial pioneering projects are commissioned, the utility and developers will benefit from the hard-earned postmortem learnings that will result in accelerated timelines and lower project costs. Looking ahead to year three, we’re optimistic that the program will find a more stable and healthy rhythm.
The Arizona Corporation Commission approved significant changes to the state’s distributed solar policies late Tuesday evening, which include lowering the credit residential solar customers receive for excess energy sent back to the grid and limiting how long customers can keep their rates.
The decision replaces Arizona’s current retail-rate net metering policy with export credits based on short-term valuation methods, which solar advocates say will undermine customer choice and could hurt solar jobs in the state.
Arizona regulators voted 4-1 in favor of a proposal to compensate distributed solar exports based on a five-year average of utility-scale solar PPA pricing. The “Resource Comparison Proxy” (RCP) methodology will be used to calculate the distributed energy export rate in all utility rate cases currently before the commission.
In future rate cases, export rates will either be determined by the RCP, or by an avoided-cost methodology that uses five-year forecasting to evaluate the costs and values of energy, capacity and other services delivered to the grid from distributed generation.
According to an amendment filed by Chairman Doug Little, opting for the RCP in the near term will give stakeholders time to further develop the implementation parameters of the alternative avoided-cost methodology. Regulators can opt to employ either methodology in future rate cases, or use a combination of the two.
The Tuesday decision also establishes rooftop solar customers as a separate rate class, and eliminates the “netting” or “banking” of solar power credits to offset usage in later months.
In addition, regulators approved keeping current distributed solar customers on their current rate plans for up to 20 years from their interconnection date. However, customers who interconnect after the RCP is applied will only have their rates guaranteed for up to 10 years.
While there’s still more work to do, yesterday’s vote closes a chapter in a contentious yearlong value-of-solar proceeding (E-00000J-14-0023) that culminated with hours of public testimony over the course of a two-day hearing. Arizona has one of the most robust residential solar markets in the country, but it’s also home to vicious solar policy battles that the proceeding sought to end.
Over the past two years, Arizona’s three investor-owned utilities — Arizona Public Service (APS), Tucson Electric Power and UNS Electric — have each filed proposals to raise rates on distributed solar customers in order to address the “cost shift” that utilities claim net metering creates. Regulators chose to delay ruling on these proposals until the overarching value-of-solar docket (that was triggered by APS last fall) came to a close.
The Arizona Corporation Commission will now collect utility data to determine the value of the RCP based on large-scale solar pricing in each utility territory, and apply the results to each rate case, likely by mid-2017.
According to earlier commission staff research, compensation for distributed solar exports using the RCP methodology would remain around 11 cents per kilowatt-hour for most customers, which is nearly on par with the current retail-rate net metering credit. However, updated assessments that include the latest utility-solar pricing could put the actual RCP credit rate significantly lower.
“There are a lot of 20-year utility-scale PPA’s signed that offer price certainty to utility-scale projects,” said Briana Kobor, program director for distributed energy policy at Vote Solar, in a phone interview. “Here we have a decision that benchmarks residential solar to utility-scale pricing, but without similar terms.”
The five-year timeframe applied to both the RCP and the avoided-cost methodology “inherently undervalues solar generation,” she added.
“Customers choose to make the investment for the 20+ year lifetime of their system, so it’s appropriate to analyze the impacts of solar over the amount of time it impacts the utility grid,” said Kobor. “Limiting the analysis to five years just doesn’t give you the full picture.”
Kim Malfacini, spokesperson for The Alliance for Solar Choice, said the solar advocacy group is “deeply disappointed” with the Arizona decision. Regulators not only disregarded the full, long-term value that residential solar brings to the state, but also created long-term uncertainty for potential solar customers by limiting rate stability to a 10-year period — which could severely dampen consumer interest in making a solar investment.
But Malfacini indicated that the debate isn’t entirely over yet. “We will continue to advocate for rates and policies that fairly compensate solar customers in Arizona,” she said.
While solar advocates are opposed to the outcome, APS, the state’s largest investor-owned utility, believes the commission’s decision is good for solar in the state.
“It makes solar fairer because all customers will begin to share more appropriately in the cost of the electrical grid,” according to a written statement from the utility. “It also enables solar to flourish and grow in Arizona, partly because it balances the economic benefits of grid-scale solar — which provides clean power to all of our customers at far less cost — with the desire of some customers to install solar on their rooftops.”
But even with yesterday’s decision, “subsidies and a cost shift still exist,” according to the utility. To properly address inequities between electricity customers, APS has proposed implementing mandatory residential demand charges on all customers as part of its current rate case.
As Arizona brings an end to net metering, other states, such as New York and California, have opted to retain the policy in the near term, while developing more granular ways to assess the value of distributed solar. Policymakers in Illinois, Louisiana and elsewhere have also acted to preserve and even enhance net metering this year.
More than a dozen states have conducted studies on the costs and benefits of distributed solar, and did not find evidence of a net negative impact on non-solar customers. However, utilities and regulators continue to re-evaluate their distributed energy solar policies as adoption rates increase. In the third quarter of 2016 alone, 22 states considered or enacted changes to their net metering policies, according to the N.C. Clean Energy Technology Center.
As a top U.S. solar market, Arizona's rate change is likely to set a worrisome tone for residential solar advocates heading into 2017 — particularly the country's leading solar leasing companies that have driven the most market growth to date.
“Over the past year, we've seen a wave of more complex net energy metering and rate reform proceedings reassess rooftop solar policies. With this decision, however, Arizona's residential solar market is at risk of falling out of the top 5 state markets,” said Cory Honeyman, associate director for U.S. solar at GTM Research. “Valuing residential PV exports primarily based on utility solar PPA pricing is the definition of an apples-to-oranges comparison. Full retail rate net metering has always been a band aid policy solution, but this reform sends a clear signal that the future of residential solar growth in Arizona will rest on optimizing self-consumption and pivoting towards a solar-plus-storage solution sooner rather than later.”
Following the election of Donald Trump, who has been critical of renewables, “It’s now up to the states to make greater advancements toward clean energy,” said Earthjustice attorney Michael Hiatt, in a statement. “Unfortunately, Arizona has numbered the days left for people to participate in a successful solar program. This decision casts serious doubts on the long-term viability of rooftop solar in Arizona.”
Check out these stories for more on Arizona's value-of-solar proceeding:
- Continued Uncertainty as Arizona’s Value-of-Solar Proceeding Nears an End
- Recommended Opinion & Order
- APS Proposes to Withdraw Fee Increase for Solar Customers
- Arizona’s Utility Regulator Adopts New Method of Crediting Rooftop Solar
It's been another year on the solar coaster, and Vote Solar has been following every twist and turn.
Here’s our view of the 10 top solar trends of 2016.
1) Utilities are losing on demand charges and fixed charges when advocates fight back
It’s not news that utilities around the country have been trying to change tariff structures in ways that undercut the economics of rooftop solar. What you might not know is that they are largely losing in this effort — especially when solar and consumer advocates fight back.
In Arizona, every utility filed general rate cases requesting mandatory demand charges for residential ratepayers. The judge in the first case, brought by UNS Electric, was persuaded by our testimony that mandatory demand charges are unjustified and bad public policy. We expect similar outcomes for Arizona Public Service and Tucson Electric Power, which will go a long way toward saving one of the country’s most important solar markets.
We also intervened in Massachusetts with Earthjustice when National Grid tried to increase fixed charges. The judge ruled that “the Department is not persuaded that a cost-shift from DG customers to non-DG customers, in fact, exists.” And in Illinois, Exelon and ComEd tried to pass a bill with mandatory demand charges for residential customers, only to drop that element after overwhelming pushback — and the governor’s spokesperson calling it “insane.”
The battle is far from over, and demand charges have had severe consequences for both solar progress and consumers in places where they’ve succeeded. In Kentucky, the state attorney general called Glasgow Electric Plant Board’s demand charges “harmful,” with the potential of forcing seniors to leave their homes and taking a toll on small businesses.
2) Nevada comes back from the ashes
Last year, the solar industry suffered its biggest loss ever when the Nevada Public Utilities Commission axed the state’s net metering program, leaving 32,000 solar owners underwater on their investments and triggering widespread layoffs in the state’s rooftop solar industry. Since then, we’ve made steady progress getting the Silver State’s solar back on track. After months of rallies, organizing and outraged headlines, the PUC agreed to a settlement reversing their decision and grandfathering existing solar owners onto net metering rates.
The next step is the 2017 legislative session, where the legislature has flipped and clean energy advocates are in leadership positions, the governor has agreed to sponsor legislation restoring net metering, and advocates will be pursuing community solar programs and a large increase to the state’s renewable energy standard.
3) Storage is the new solar
Similar to solar’s arc over the past decade, storage is moving from pilot programs to the business-model stage. Utilities in California are now procuring storage as part of meeting local capacity requirements. Massachusetts has stepped up in a big way, first with a report showing that the top 10 percent of hours made up 40 percent of electricity costs (which translates into a huge opportunity for ratepayer savings), then with a new 600-megawatt storage mandate. And FERC is getting in on the action too, with a recent proposal to guide how storage can participate in wholesale markets.
While EVs are helping bring down the cost of lithium-ion batteries, there’s a lot of interest in other storage technologies, especially as policies drill down on the question of what problems storage is meant to solve. Effective policy creates a transactive space connecting customer and utility problems with clean and effective solutions, and while that effort is still nascent, the potential is huge and it is happening now.
4) Rural co-ops come into the fold
Rural co-ops cover about 70 percent of America’s geography and serve 12 percent of ratepayers. That’s why it was such a big deal when a June ruling from the Federal Energy Regulatory Commission opened the door for member-owned co-operatives to buy local renewables instead of being forced to buy fossil power — according to the Rocky Mountain Institute, a potential 400-gigawatt market. Investor-owned utilities are driven by profit prerogatives, while co-ops answer to member-owners, which is one reason we’ve seen leadership with community solar, from Wisconsin to Texas. For bonus creativity and consumer-friendly points, check out Minnesota's Steele-Waseca co-op, which gives customers an 85 percent discount on solar if they participate in the co-op's hot-water-heating demand management program.
5) Sun rises in Florida
The Sunshine State has been a chronic underperformer when it comes to solar. But that may be about to change. One of the longstanding roadblocks in the state has been the fact that third-party PPAs, one of the most popular financing mechanisms, are banned. But there are other ways of financing solar, and they are coming to Florida. Rooftop heavyweights SolarCity and Vivint have both entered the state with loan products. And property-assessed clean energy (PACE) financing providers are launching programs — Renew Financial is open statewide, and Renovate America is in Leon County now, with availability in the whole state coming soon.
PACE financing programs have taken time to deliver on their promise, but in the past few years, they have funded ~$2 billion in residential clean energy upgrades in California. Florida is experiencing a sea change in finance options, making it easier for customers to invest in solar and energy efficiency.
There are some very interesting political developments, too. In August, voters passed a ballot initiative, by a 73 percent margin, in favor of property tax abatement for solar. It now goes to the legislature for implementation, and when it is in effect, it will mean about a 20 percent reduction in solar costs. And in November, voters defeated a deceptive anti-solar ballot initiative that utilities had spent $25 million promoting. It’s hard to overstate the impact of that victory — in a major expose, utility front groups were caught on tape bragging about fooling voters, and in the run-up to the vote, nearly every newspaper in the state editorialized against the utilities' shady practices. In a state where utilities are used to having their way, solar has established itself as a real political issue.
6) Solar becomes a real electoral force
Did you know that solar helped determine the outcome of Nevada’s Senate race? Polling shows that Nevada voters found that Joe Heck’s anti-solar views were a reason to vote against him. In two ballot initiatives in Florida, despite being massively outspent, solar came out the big winner. Supermajorities of Americans want to see more solar, and as state battles heat up, smart politicians are figuring out that solar is a winning issue.
7) Mega-solar for large corporates
Google. Facebook. Amazon. What do these companies have in common? They are some of the most admired and profitable companies in the world, they are massive energy users, and they all have commitments to 100 percent renewable energy. Increasingly, these companies are subverting the utility mix to access power from off-site solar farms via green tariffs. Amazon recently signed a 120-megawatt deal in Virginia. Facebook’s new data center in New Mexico will be served by three new solar farms. Google announced it will hit 100 percent in 2017.
This trend has major consequences for the industry, in terms of new sources of demand, and for regulatory structures, which are increasingly being reconfigured to accommodate energy choice.
After all, what’s good for the Google is good for the gander — why shouldn’t everyone be able to access 100 percent renewables?
8) De-reg and re-reg
There was a time when the proponents of deregulation included companies with a lot of fully amortized coal and nuclear assets, and renewable supporters preferred regulated markets where long-term public benefits could be considered by policymakers. This year, in a turnabout, we’ve seen coal and nuclear interests in previously competitive markets demand bailouts — and a return to regulated markets. The FirstEnergy CEO said: “We will exit competitive generation and become fully regulated.”
Meanwhile, wind is thriving in deregulated Texas. ERCOT expects as much of 27 gigawatts of solar over the next 15 years, and retail electricity suppliers who really understand (and are exposed to) volatility are voluntarily offering full retail net metering. In Nevada, casinos paid $127 million to divorce their utility and buy power competitively for the express purpose of accessing more renewables, and now other casinos and data centers are following suit. In November, Nevada voters overwhelmingly approved a ballot initiative to break up the monopoly utility (notably, the one that led the charge to shut down the rooftop solar industry in the state) in favor of retail choice. The times, they are a-changin'.
9) PURPA takes a few punches
There’s an emerging trend among utilities across the country to try to undermine a decades-old law called the Public Utility Regulatory Policies Act, or PURPA — a law that has paved the way for policies that have brought renewable energy into the mainstream in the U.S. PURPA was created to encourage states to reduce dependence on fossil fuels by requiring that utilities purchase renewable energy generation and efficient co-generation when those are equal to or cheaper than the cost of building a new power plant. As solar and wind have become increasingly cost-competitive with conventional fuels, PURPA is more relevant than ever. To date, PURPA has driven a whopping 16 gigawatts of new power capacity from qualified renewable and co-generation projects. Now that the law is working as intended, we’re seeing a lot of efforts to undermine it at the state level, such as reducing contracts to unfinanceable terms, suspending tariffs and denying contracts, and creating unnecessary interconnection hurdles. We’re gearing up to fight for PURPA’s principle, and the promising market it provides.
In a nation that’s growing more and more divided, the issue of expanding solar might well have the most overlap of support between Clinton and Trump supporters, polling at 91 percent and 84 percent, respectively. While Trump’s cabinet picks clearly don’t share the same outlook, this popular support does matter in the venues where most electricity policy is set: the states. If solar survives the upcoming comprehensive tax reform with the deal Congress struck last year to gradually reduce the ITC still intact, then the industry will be in good shape, with overwhelming popular support and very favorable economics and job-creating possibilities. But the industry will have to duke it out in statehouses and public utility commissions around the country. Trump’s election, then, means that state-level policies become even more important in 2017 and beyond.
The apocryphal Chinese curse “May you live in interesting times” seems particularly apt for the solar industry as we head into 2017. But really, is there anything else you’d rather be doing than this? We’re at the epicenter of radical changes in one of the biggest and most important industries on the globe, and there’s no other place we’d rather be.
The following is an excerpt from GTM Research's latest U.S. Solar Market Insight report.
While 2016 is expected to eclipse the 10-gigawatt annual mark for the first time ever, and by a wide margin, three trends are expected to shape the near-term U.S. solar market outlook. Looking ahead to 2017, each of these trends raises challenging questions that will shape to the extent to which utility, non-residential, and residential solar will grow (or fall) over the next few years.
Despite dirt-cheap PPA pricing, the utility PV segment is struggling to reboot procurement
Despite PPA pricing consistently ranging between $35 and $60 per megawatt-hour, the uptick in new utility offtakers has only partly countered the demand rollback from utilities that over-procured in the past couple of years. Most notably, California’s investor-owned utilities have already procured enough renewables to meet their RPS obligations through the end of this decade.
In turn, new development has increasingly focused on distinct sub-segments, for example, utilities with viable contracts offered via the Public Utility Regulatory Policies Act (PURPA). Another segment to watch is retail customers seeking offsite wholesale PPAs. Corporate customers have already procured more than 1.5 gigawatts (DC) of offsite wholesale solar for post-2016 installation dates. And in California, community-choice aggregation is gaining momentum, with an addressable market of more than 3 gigawatts (DC) through 2020 based on current and announced CCA programs.
Commercial solar's still struggling to scale onsite development, so demand is pivoting to offsite solutions
FIGURE: Share of Annual Commercial Solar Installations — Onsite vs. Offsite*
*Offsite includes community solar, virtual NEM, and offsite wholesale projects. Since offsite wholesale projects sell power directly into a wholesale electricity market, or to a utility and which then resells it via a green tariff, the percentages calculated in this figure include installations classified as utility PV.
As mentioned, large corporate customers have ramped up procurement of offsite wholesale solar projects, which are currently accounted for in the utility PV segment. This demand has largely come from Fortune 500 customers with large industrial loads or aggressive, near-term renewable energy procurement targets. By year’s end, GTM Research expects more than 800 megawatts (DC) of offsite wholesale solar to come on-line, growing fourfold over 2015.
On top of that, investment-grade commercial and municipal customers continue to serve as anchor subscribers to most community solar installations. Altogether, community solar is expected to add more than 200 megawatts (DC) on an annual basis in 2016, growing fourfold over last year. In turn, for the first time ever, more than half of annual solar PV capacity involving non-residential customers will come from offsite projects (i.e., virtual NEM, community solar and wholesale solar).
However, onsite development is expected to resume its position as the primary driver of development, given demand pull-in for offsite wholesale PPAs prior to the federal ITC extension. In the long term, large corporate customers’ demand for solar-plus-storage versus offsite wholesale PPAs will play a critical role in shaping the breakdown between onsite and offsite development.
As customer adoption ramps up in major state markets, it’s becoming harder and costlier to scale residential solar
FIGURE: Year-Over-Year Residential PV Installation Growth Rates: CA, NY, MA and AZ
Source: U.S. Solar Market Insight Report
In a number of major state markets, residential solar growth rates are slowing down. The reasons behind this slowdown all center on one question: How does residential solar scale when early-adopter customers begin to deplete?
Most notably, this question is being tested in residential solar’s largest state market, California. Conversations with installers confirm that it’s becoming harder and costlier to land new leads and to convert those leads into sales. As the funnel of early-adopter leads reduces, three trends within the competitive landscape compound this market fundamentals challenge.
First, a phenomenon termed “customer fatigue” has come up as a challenge in neighborhoods where homeowners are flooded with door-to-door sales pitches. Second, demand for cash sales and loans over leases and PPAs has picked up more quickly than expected, and portions of the installer landscape are still playing catchup in serving this change in demand. Third, publicly traded residential solar companies have struggled to continue growing while simultaneously seeking to become profitable.
To be clear, GTM Research does not expect all of the above trends to be permanent problems; rather, they are signs of a segment figuring out how to grow in a maturing customer environment. Over the remainder of this decade, continued cost reductions will position nearly all states in the U.S. to move past grid parity for residential solar under current policy conditions. But scaling that demand in major and emerging state markets will not only hinge on the policy outlook (i.e., NEM and rate reform outcomes). Equally important, a reboot in growth rates will rely on evolving sales strategies that lower the cost of customer acquisition, and continued proliferation of consumer loans to serve the change in customer demand.
The U.S. Solar Market Insight report is the definitive source of data and analysis on the U.S. solar market. Purchase the report or download the free executive summary here.
Norwegian state-owned oil company Statoil is the winning bidder for the right to build a wind farm across nearly 80,000 acres off the coast of New York.
The U.S. Department of the Interior's Bureau of Ocean Energy Management’s auction was for an area approximately 12 miles off the west end of Long Island, which should be able to accommodate up to about 800 megawatts of wind power. A wind farm that size would rival some of the largest offshore wind farms in Europe.
There were approximately a dozen bidders that were qualified to bid, but only six took part in the auction. The bidding went through 33 rounds before Statoil ultimately emerged victorious.
Statoil’s bid of $42.5 million is hardly the final price tag, as the Norwegian company still needs to go through various environmental and feasibility studies, as well as to find an offtaker for the power it will eventually produce.
The other bidder in the final rounds was the New York State Energy Research and Development Authority. NYSERDA hoped to lower the cost by winning the acreage and then bundling that with an offtake agreement. But Statoil’s win suggests that an individual developer thinks it can do it for cheaper than buying the bundled package from the government. NYSERDA’s approach was similar to how many offshore wind auctions work in Europe.
No matter the approach, the project will certainly be more expensive than similar ones in Europe, which has about 11 gigawatts of offshore wind. NYSERDA will also still be heavily involved, providing assistance with studies and permitting. Just last week, NYSERDA put out an RFP for expert consultants as the state finalizes its offshore wind master plan.
“We are excited to have submitted the most competitive bid in a highly attractive project, Statoil’s first offshore wind lease in the U.S.,” Irene Rummelhoff, Statoil´s executive vice president for New Energy Solutions, said in a statement. “We now look forward to working with New York’s state agencies and contributing to New York meeting its future energy needs by applying our offshore experience and engineering expertise.”
That expertise draws on Statoil’s growing interest in offshore wind and long history in offshore oil and gas. It is a joint developer for a handful of wind farms off of the coast of the U.K., and is developing a floating offshore wind farm that will also be paired with energy storage.
One of the U.K. projects is Dogger Bank Wind Farm, which is more than 100 miles offshore of Yorkshire and is expected to have a target installed capacity of at least 7 gigawatts of wind power, and potentially up to 13 gigawatts.
Although NYSERDA will not lead the project, it will be critical for getting buy-in from local communities, especially the fishing community.
“NYSERDA will continue to work closely with coastal community members, the fishing and maritime industries and advocates to identify additional offshore wind energy sites to be included in New York’s Offshore Wind Master Plan,” the agency said in a statement.
Enthusiasm and acceptance for the project is critical not only for Statoil and New York state, but also for the larger offshore wind industry in the U.S. Europe has gigawatts of offshore wind and some of those projects are now coming in at well under $100 per megawatt-hour. By comparison, the U.S. has only a single offshore wind farm off of Rhode Island, which is delivering 30 megawatts of power to Block Island.
New York, Massachusetts and other states, however, are getting more serious about offshore wind. Massachusetts has a goal of 1.6 gigawatts of offshore wind in the next decade and New York has a goal of getting half of its electricity from clean generation sources by 2030.
To get there, the U.S. offshore wind industry will have to scale up quickly from virtually nothing. It will require larger projects and more support from state governments for permitting. But with lessons learned from Europe, many in the industry feel the time is finally right for offshore wind to become a viable market in the U.S.
“Over the past decade, there has been consistent progress toward the realization of offshore wind power’s potential in America,” Nancy Sopko, the manager for advocacy and federal legislative affairs at the American Wind Energy Association, said in a statement. She added that the construction of the New York project alone could produce thousands of jobs.
Statoil said the project will be a phased development, with the first phase delivering 400 to 600 megawatts.