I got lucky with my predictions for rooftop solar in 2016 — pretty much on target with nine out of the 10 darts that I threw. But this year is shaping up to be much more challenging, with routine solar-coaster turmoil combined with political uncertainty. Looking forward to 2017, my list no longer includes the benefits of the Clean Power Plan and 500 million solar panels (along with the EPA and half the equity in the remaining solar module companies). Nevertheless, I remain very optimistic about the future of clean technology industries simply because their economic benefits have been proven. So here are my 10 predictions for rooftop solar in 2017.
1. Module prices will stay at current low levels, roughly 35 cents for megawatt orders, roughly 45 cents for container quantities and roughly 55 cents for small orders. Manufacturers prefer to operate their production lines at full capacity (and full employment), even if they are selling at breakeven or less. As the year progresses, these low prices will apply to higher and higher efficiency modules. Differentiated modules — those with integrated electronics, simplified installation technology or 20+ percent efficiency — will command higher price points and margins simply because they provide more value to installers and homeowners.
2. U.S. solar manufacturing will continue to decline. Sadly, the module supply chain is almost entirely from Asia: wafers, cells, backsheets, EVA, junction boxes, glass and aluminum frames are all cheaper in China with comparable quality. Political rhetoric will not bring manufacturing back without a good plan to address the supply of key components in the U.S. Ironically, tariffs have made things much worse for U.S. manufacturers — removing tariffs on cells and extruded aluminum for solar would go a long way toward improving the economics for the remaining U.S. module manufacturers.
3. Community solar will struggle to get traction. Customers want both clean and cheap solar power. But when community solar is developed by utilities, they charge a premium for solar, so customers don’t buy. When lower per kilowatt-hour cost community solar projects are developed independently, utilities act to delay projects or increase costs in order to protect their monopoly. More local governments will step in with community-choice Aggregation programs. These CCA programs break the utility electricity sales monopoly, providing clean and cheap power to customers.
4. State solar organizations will gain membership and influence throughout the U.S. as net energy metering and rate design issues are tackled by state public utility commissions. Meanwhile, the Solar Energy Industries Association will fight a rear-guard action in Washington, D.C. to preserve the most precious TLAs (three-letter acronyms): ITC, DOE and EPA.
5. The TLA for 2017 is “BTM.” The divide between utility-scale solar and behind-the-meter (BTM) solar will become more apparent as the zero-sum game for selling electricity intensifies. The cost difference between utility PPAs (about $0.04 per kilowatt-hour) and customer-owned residential solar (about $0.06 per kilowatt-hour) will continue to narrow, eliminating the argument that bigger is better when it comes to solar deployments.
6. Small local and medium-sized regional rooftop solar companies will continue to thrive. Bigger is badder in the solar business. Companies that use debt to claw to the top of the revenue hill are inevitably knocked off and out. Stubbornly high customer-acquisition costs will make it cost-prohibitive for any installation company to pursue a fast growth strategy without outside investors. More simplified solar financing options will become available to small and medium-sized installers — and companies providing these independent financing products will thrive. Meanwhile, high-pressure sales installers/deal originators who were hooked on no-money-down financing and naive customers will discover they have no referral business and cannot continue to pay high customer-acquisition costs.
7. Utility deployments of battery storage system will grow rapidly in the U.S. Trial programs will drive this initial demand, and income from rate-basing these installations will improve the bottom lines of utilities and vendors. Meanwhile, customers will see zero impact other than higher rates. BTM energy storage systems will continue to be deployed gradually in Hawaii and to a lesser degree in California. Residential BTM deployments need better economic drivers (lower equipment costs, incentives and even demand charges) before deployments begin to take off. BTM energy storage systems are still at the stage that rooftop solar was in 2000.
8. Customers will not install technology that provides services to utilities — even if products are free with a small return value stream — because utilities will not make the value stream significant enough. Customers learned their lessons with smart meters: cool technology that benefits utilities tends to raise rates, provides negligible access to customer data, and enables customer-unfriendly services (demand charges and dynamic TOU rates). As we saw with rooftop solar and smart thermostats, customers would rather invest in energy-saving technology themselves and follow price signals to reap the benefits. On the other hand, utilities prefer to build this infrastructure and rate-base these investments — thereby guaranteeing a profit. Utilities and PUCs like the intellectual concept of distributed energy resources, but the value to customers is too low and intangible, especially when customers can invest in similar technology themselves.
9. Storage equipment companies will continue to underestimate the true cost of their new products in order to generate buzz and initial sales. These true costs include diverse component integration, software configuration, permitting, installation, troubleshooting and service. Companies that provide a fully integrated solution, including all required hardware and software in a single plug-and-play box, will get the most initial traction from experienced installers.
10. President Trump will embrace solar because it is cheaper and continues to be a jobs engine. He will follow in Obama’s footsteps as he welcomes a solar system on the top of his new house for the next four to eight years.
The Public Utilities Commission of Nevada (PUCN) has voted to restore favorable rates for residential solar customers in NV Energy’s Sierra Pacific Power Company’s service territory — exactly one year after the commission passed a controversial fee increase that brought the state’s residential solar market to a halt.
In the draft order approved Thursday, Chairman Joseph Reynolds wrote: “Abraham Lincoln once said that ‘Bad promises are better broken than kept.’ The PUCN’s prior decisions on [net energy metering], in several respects, maybe best viewed as a promise better left unkept. The PUCN is free to apply a new approach.”
Advocates for distributed solar cheered the rate change, which they say will revive the solar industry and bring back energy options for customers in northern Nevada.
The December 2015 decision phased out retail-rate net metering for the excess generation solar customers send back to the grid, and tripled fixed charges for solar customers over a four-year period. The timeline was later stretched to 12-years. The ruling was applied to both new and current solar customers, sparking outrage among ratepayers who saw their expected savings from investing in solar all but disappear. While the PUCN later decided to grandfather in current solar customers on their existing rates, the rate change for new solar customers put Nevada’s residential solar market at a standstill.
The new order, approved as a part of Sierra Pacific’s general rate case, reverses last year’s decision, recognizing that the previous order “all but crushed the rooftop solar industry in northern Nevada.” Regulators determined that additional deployments of rooftop solar are “reasonable,” recognizing that locally generated power can benefit the grid system.
Regulators voted 3-0 to restore net metering for up to 6 megawatts of rooftop solar (approximately 1,500 customers) beginning on January 1, 2017. “Under this order, the average Nevada ratepayer will see a decrease of $0.01 per month on monthly utility bills,” according to the draft order.
The ruling will jump-start the rooftop solar market in the near term, and leaves open the possibility of another net metering cap extension in future. However, regulators did not offer a long-term solution to the state’s solar policy debate.
The cap increase is only likely to sustain the industry in northern Nevada for roughly a year. Nonetheless, it’s welcome news for rooftop solar providers that shut down their Nevada operations following last year’s rate change, including SolarCity, now owned by Tesla, as well as Sunrun and Vivint. Local installers, unable to make home solar pencil out with the new fees, were also forced to cut staff.
Jon Wellinghoff, chief policy officer for SolarCity, commended regulators for restoring net metering “and affirming that whether solar customers are providing clean solar energy for their own homes, or supplying it to their neighbors, the benefits of that local generation outweigh the costs.”
In June, the PUCN is expected to address net metering in the general rate case for Nevada Power, NV Energy’s subsidiary serving the southern, more populous portion of the state, where the majority of residential solar customers are currently located.
Nevada utility regulators also approved changes Thursday that will boost the deployment of utility-scale solar projects on as a part of Sierra Pacific’s integrated resource plan. According to Vote Solar, the commission specifically required Sierra Pacific to offer to buy solar power based on the savings delivered to ratepayers of not building and running more expensive fossil fueled generation.
The PUCN also required the utility to sign 25-year contracts for clean energy, instead of the 10-year contracts Sierra Pacific requested.
“Clearing the way for investment in solar power of all sizes, whether on rooftops or in utility-scale plants, builds healthier communities, creates good local jobs, avoids sending ratepayer money to out-of-state coal miners and frackers, and helps make Nevada the clean energy leader it should be,” said David Bender, clean energy attorney at Earthjustice.
Since last year’s net metering decision, two new commissioners have been appointed to the three-person PUCN, and Governor Brian Sandoval put together an energy task force that recommended restoring net metering in 2017. Nevada’s Democratic-controlled chambers are expected to support legislation allowing for more net metering. Lawmakers could also take up a bill to deregulate Nevada’s retail electricity market, after voters passed a ballot initiative in November in support of market reform.
The PUCN’s decision to restore net metering comes the same week Arizona utility regulators voted to end the policy, and replace the credit for residential solar exports with a credit based on a five-year average of utility-scale solar PPA pricing. In the near term, this proxy credit calculation is expected to keep the solar export credit around 11 cents per kilowatt-hour — which is close to the retail electricity rate.
Eventually, the Arizona PUC plans to introduce an avoided-cost methodology that will take into account an array of costs and benefits associated in determining how to compensate distributed solar exports. While the credit is expected to be lower than the retail rate, Arizona regulators, like Nevada regulators, have acknowledged that distributed solar can offer grid benefits, which could result in a more favorable rate outcome for the residential solar industry.
Energy Department Announces $18 Million Investment to Accelerate the Development Plug-In Electric Vehicles and Use of Other Alternative Fuels
WASHINGTON – Today, the Energy Department (DOE) announced $18 million in support of five projects for research, development, and demonstration of innovative plug-in electric vehicle (PEV) and direct injection propane engine technologies, as well as community-based projects to accelerate the adoption of light, medium and heavy duty vehicles that operate on fuels such as biodiesel, electricity, E85, hydrogen, natural gas, and propane.
Source: New feed
8minutenergy Renewables claims to have “the first operational solar PV installation to beat fossil fuel prices in California.” The recently commissioned 155-megawatt (AC) Springbok 2 Solar Farm in Kern County will provide electricity to the Los Angeles Department of Water and Power at $35 to $38 per megawatt-hour (adjusted for inflation) over the PPA term.
Is that the lowest-cost PPA ever?
The math is a little fuzzy, and 3.5 cents per kilowatt-hour might not be the lowest PPA price ever, but it's in the ballpark, and a real sign of things to come.
Vital stats of Springbok 2
- 8minutenergy developed the solar farm and D. E. Shaw Renewable Investments put in the majority of the equity. 8minutenergy began developing the project in 2011.
- It is generating power at $58 per megawatt-hour for the Los Angeles Department of Water and Power (LADWP) with a 30-year PPA.
- The power offtake partner is Southern California Public Power Authority on behalf of the LADWP.
- Swinerton Renewable Energy was the engineering, procurement and construction contractor.
- The power plant is located on approximately “700 acres of abandoned farmland taken out of production more than 20 years ago.”
According to GTM Research solar analyst Colin Smith, when GTM calculates PPA prices, it doesn't adjust for inflation, which is what 8minutenergy is doing here. 8minutenergy used the “average U.S. inflation rate over the past 40 years to calculate the equivalent first year price (with inflation as escalator) to Springbok 2’s PPA price and levelized cost of energy (using LADWP’s weighted average cost of capital).”
Smith notes, “That being said, when we compare this to others, it is one of the lowest PPA prices for operating projects — but not the lowest. For instance, NextEra brought its Chaves County project on-line in October, which we calculated to have an average PPA price of $42.08 per megawatt-hour, with a $36.44 year-one price and a 2 percent escalator.”
“We are continuing to see declining prices and have seen sub-$40 per megawatt-hour PPAs before and are going to see more soon,” he added. “I wouldn't be shocked to see year-one pricing below $30 per megawatt-hour soon, too. In short, we are going to see PPA prices continue to decline along with declining all-in utility PV costs, driven primarily by declining balance-of-system and module prices.”
The biggest risk is the possible rise in interest rates, according to Smith.
Lazard's LCOE numbers
Financial analysts at Lazard recently released the latest version of their levelized cost of electricity (LCOE) analysis.
- Natural gas, the lowest-cost conventional electricity source, costs $52 to $78 per megawatt-hour for a gas-combined cycle plant
- Wind ranges from $32 to $77 per megawatt-hour
- Thin-film utility scale solar PV (from First Solar) produces power at $43 to $60 per megawatt-hour
These are unsubsidized prices.
“Ridiculously low PPA prices”
Shayle Kann, the senior VP of GTM Research, in a keynote address at the recent Solar Market Insight Conference in San Diego said, “This is going to be a banner year for solar capacity being added to the grid in the U.S. When all is said and done, solar may well be the top — if not one of the top two or three — sources of new electricity generating capacity and, potentially, new generation in the U.S.”
“You could see a standard, best-in-class, turnkey, utility-scale project under a $1.00 per watt, this benchmark we've been talking about for almost a decade now, by 2018 — well before the 2020 SunShot goal,” he added.
“2016 is the first year in which the average PPA price for a new utility-scale project in the U.S. is below 5 cents per kilowatt-hour,” Kann continued.
“You're probably going to start to see, over the next couple of years, what feel like ridiculously low PPA prices,” he said. “You're starting to see this in some international markets. We've seen sub-3 cents per kilowatt-hour PPAs signed in places like Chile, Mexico and the Middle East. You'll start to see that coming in the U.S. as well.”
In an earlier interview Jim Hughes, former CEO of First Solar, said, “I fully believe that within 10 years we'll be talking about low-3-cent power on a peak basis.”
It looks like Hughes' prediction is going to happen even sooner than he expected.
U.K. energy firm Geo hopes to install batteries in 50,000 new homes a year by 2020 amid growing energy storage interest in the homebuilding sector.
The figure represents half of all new-build homes in the U.K., but Geo chief strategy officer Simon Anderson said it is realistic, based on European Union moves to promote smart buildings. Despite Brexit, “My view is what goes on in Europe will still affect the U.K.,” he said.
Geo started out 10 years ago in the smart thermostat field and has since extended its offering into what Anderson calls the “hybrid house,” which combines smart monitoring technology with energy storage and demand management.
This month, the company is hoping to launch a prototype hybrid house, with field trials in the summer of 2017 and a commercial launch in 2018.
The concept is based on the hybrid vehicle idea of using storage to improve the efficiency of traditional power systems, and could lead to a one-third reduction in energy costs for traditional homes and two-thirds for households with residential solar.
“There will always be 10 percent to 20 percent [consumption] from the grid, even with solar,” said Anderson.
Geo's energy storage solution will not be something that individual homeowners can opt for, however, since the idea is to offer it as an existing asset with new homes. Geo is looking to provide hybrid home packages as an optional extra that property developers can use to sweeten the deal for homebuyers and, increasingly, meet regulatory requirements.
“We are focusing on new build,” confirmed Anderson. “Our customers will be housing developers and utilities.”
The utilities are also part of the picture because “property companies have to hand over the energy system,” he said.
Geo expects utilities to be able to offer a hybrid home tariff that reflects the greater efficiency of the system, which will include an 8-kilowatt-hour battery from an unspecified vendor.
Anderson said residential property developers in places such as London are “very interested” because it can help them meet mandated and voluntary energy efficiency targets.
Sonnen and Moixa target builders
Besides the U.K., Geo is active in the Nordics and “making inroads into Benelux,” said Anderson, “because they have a local data port on the meter. Having a smart meter with local live data is fundamental.”
However, Geo will face increasing competition on the home front. The German battery maker Sonnen, for example, is actively targeting house builders with its Eco Compact product, launched earlier this year.
“Builders could use Sonnen to roll out battery solutions across a range of homes,” reports TecHome Builder.
In the U.K., the energy storage firm Moixa is looking to sell a GBP£4,995 ($6,240) 2 kilowatt-hour smart battery system and 2-kilowatt solar system to housing associations and landlords, as well as homeowners.
Residential customers will typically benefit by around £350 ($440) per year in electricity savings from their solar panels and battery and from feed-in tariff payments, said the company in a press release.
They will also receive £50 ($60) in annual payments for making their battery capacity available through Moixa’s GridShare aggregation platform.
Stroomversnelling's net-zero-energy homes
Meanwhile in the Netherlands, an organization formed by four construction companies, called Stroomversnelling, is looking to create a portfolio of net-zero-energy homes by 2020.
The collective aims to use solar panels in place of roof tiles in order to halve rooftop PV installation costs. The roofs will be installed in a week's time or less and will come with a 30-year guarantee.
Along with thermal recovery and low-power-consumption devices, Stroomversnelling believes it can reduce the effective energy use of households to virtually zero.
Batteries are not presently part of the equation, although Stroomversnelling has reported conversations with LG.
Like Geo, Stroomversnelling does not anticipate selling the concept directly to homeowners, since many would shy away from the upfront cost for fear of losing their investment if they move away.
Instead, Stroomversnelling envisions working with developers to offer homeowners a fixed-fee energy tariff that represents savings on utility supplies and includes with a 5 percent payback for the building developer.
Stroomversnelling already has a deal to create 111,000 net-zero-energy homes for six Dutch housing associations by 2020.
After that, it hopes to install PV as standard on all new-build construction, as well as refurbishing 50,000 homes a year, in order to meet the Dutch government’s target of having 60 percent net-zero-energy homes by 2050.
A U.K. startup called Electron is proposing a blockchain-based electricity and gas meter registration system to help consumers switch between utilities more easily.
“Blockchain technology enables reliable coordination between multiple parties without the need for a central coordinating entity,” said Electron in a press release. “The company sees this platform as a first step in harnessing blockchain technology to transform the virtual infrastructure of the energy industry.”
Registering meter details on a blockchain could help U.K. utilities comply with upcoming regulation that is expected to allow consumers to change from one energy provider to another in a single day, said Electron chief operating officer Joanna Hubbard. Currently, because there is no central register of all electricity and gas meters, it can take between 17 and 20 days to change utilities in the U.K. A blockchain could cut this time to “mere minutes,” Electron believes.
The U.K. energy regulator, Ofgem, launched the next-day switching proposal in February 2015. The consultation period for the proposal has now closed and utilities are awaiting a final decision. “We propose to lead a program of work to deliver these policy proposals for consumers by 2019,” Ofgem says on its website.
Ofgem believes the measure can be achieved “by replacing the existing network-run gas and electricity switching services with a new centralized switching service.” If created in a traditional manner, though, the switching service would need to build and maintain a massive database of meter information, which Hubbard says would be costly and unwieldy. Using a blockchain would be “millions cheaper,” she said.
With the advent of blockchain technology, “a central database sounds very inefficient now,” she commented. Furthermore, she said, the blockchain approach would make it easier to integrate the meter data into applications such as demand response or peer-to-peer energy trading. This is where the real interest lies as far as Electron is concerned.
The company intends to offer the meter registration blockchain as a free platform to utilities, and then create value-added services around it. “We’re not looking to commercialize this,” Hubbard said. “We’re looking to deliver it to the industry; then we are well placed to build on it.”
For now, however, Electron still has a long way to go before making this plan a reality. The company has shown its concept could work in theory, by creating an Ethereum blockchain and filling it with simulated data from 53 million metering points and 60 energy suppliers. However, the company needs to get the U.K. electricity sector on board, starting with utilities, and “we’d have to get buy-in from Ofgem,” said Hubbard.
She said Electron was already in talks with potential utility partners and “the reception has been very warm,” although none had yet signed up for the concept.
Smaller energy providers were interested because faster switching might allow them to pick up new customers more quickly, she noted. For larger energy companies, the interest was more around the development of blockchain-based applications such as demand response.
With the right partnerships in place, Hubbard said Electron, which is backed by £500,000 ($617,000) from private investors and £150,000 ($185,000) from two Innovate U.K. grants, could roll out the blockchain registry within 18 to 24 months.
Electron’s proposal comes amid growing interest in the use of blockchains across the energy sector. Siemens recently announced it would be collaborating with a U.S. company called LO3 Energy on a peer-to-peer energy trading blockchain project in New York.
And in a February 2016 forum moderated by GTM CEO Scott Clavenna, Joi Ito, the director of Massachusetts Institute of Technology's media lab, declared: “It would be a waste to use the blockchain to just do meter billing.” Hubbard acknowledges that blockchain’s potential goes far beyond meter data, but said someone needs to provide the infrastructure to aggregate metering information in the first place. “We’re the only people doing this top-down approach,” she said.
The idea is that other blockchains (for example for tokens or peer-to-peer trading) will be interoperable with Electron’s platform, and that all told this could have a transformational effect.
For now, in the U.K, “This industry still takes 14 months to settle financial transactions,” said Hubbard. “There’s a lot that has to change.”
Back in January, I suggested 2016 was the year for wholesale power market reform. So, was it? While shifts in these kinds of institutions take longer than one year, we’ve seen real progress on the four factors that made 2016 a turning point, and we believe progress will continue in 2017.
America’s electricity mix continues to churn. A trend of less-energy-intensive economic growth is combining with policy support for wind and solar to produce an oversupply situation. Markets are adjusting by pushing out more expensive nuclear and coal plants, and in 2016 some regulators gave in to the temptation of supporting old facilities in wholesale markets. Take FirstEnergy’s bid to re-regulate in the face of stiff wholesale market competition for its coal and nuclear facilities, for example. But the whole idea of competitive markets, promoted by the likes of FirstEnergy themselves, was to shift risk onto independent power producers and allow them to earn upside — or face downside.
During this period of transition, policymakers must pay particularly close attention to proposed wholesale power market changes. Most proposals will invoke reliability, but forward-looking market improvements for reliability will expose the value of grid services we’re likely to need in the future while finding ways to pay whichever resources are capable of providing them. These market improvements may cause some old plants to retire, but they will also create new revenue streams for existing units — and cost-effective new resources capable of providing valuable grid services.
The Federal Energy Regulatory Commission (FERC, the agency that governs America’s wholesale markets) and some of the forward-thinking regional markets are making moves to build new ways to support system reliability and flexibility during this transition period. But plenty more can be done to build markets optimizing a clean portfolio of energy resources at least cost. Despite three of five FERC seats being open in 2017, we remain optimistic the new commissioners will stay true to the FERC charter and uphold the free market principles that make these markets work.
2016’s four factors are still quite relevant, and will continue driving change in 2017:
The opportunity: Markets can expose the value of optimizing both power supply and demand
The ability to balance supply and demand will grow in importance as variable renewables become a larger share of the electricity mix. Time-shifting resources like demand response and storage can help tremendously as the power system syncs with the rhythm of natural weather systems.
FERC took two big steps in 2016 to co-optimize supply and demand. First, the commission issued a rule requiring wholesale markets to settle every 5 minutes. This bolsters flexibility since dispatching and paying market participants on shorter intervals values flexible resources able to quickly respond to price signals. Second, FERC proposed a new rule last month to knock down barriers preventing distributed resource participation in wholesale markets. This proposed rule highlights the need to update outdated market design details prohibiting certain resources like energy storage and demand response from participating in markets and getting paid for the valuable services they can provide.
Still, more work remains to be done. For example, dispatchable demand response is not yet fully integrated into real-time grid operations anywhere in the country. In 2014, Texas market operators began enumerating the challenges to overcome to get demand-response into traditional real-time dispatch algorithms. Since then, California and New York market operators have taken initial steps toward building demand response into real-time operations. Hopefully, given today’s big data capabilities and the growth of businesses able to provide reliable, dispatchable demand response, market operators can solve this challenge in 2017.
The threat: New technology is hitting the grid — if markets don’t capture the opportunity now, they’ll have to cope later
Many parts of the U.S. are oversupplied with capacity right now, putting downward pressure on wholesale market prices. As a result, well-functioning markets will edge certain uneconomic plants out of the system. Wholesale market operators may be tempted to change market products or market designs to ensure “sufficient” revenue flows to those old plants, but this is a Sisyphean battle.
Rather than adjusting market rules to prop up costly facilities no longer serving the system, markets must begin to define and expose the value of specific services needed on the grid (fast start, fast ramping, etc.), allowing all resources to compete evenly and provide those services at least cost. This will pay for the system attributes needed in the future, creating a forward-looking market with solid potential for growth, rather than contorting existing markets to support unneeded and uneconomic plants. Existing plants able to provide valuable services will survive, provided they are cost competitive with new technology options.
Innovative market products are enabling market operators to value the capabilities needed as the energy mix evolves. For example, PJM’s Regulation D product (originally created in 2012) creates a separate frequency regulation product for resources that can respond very quickly but may not be able to sustain energy output over long periods. Other RTOs are now considering adopting similar products. And California’s Flexible Ramping Product, implemented just last month, exemplifies another approach: This new product is designed to improve reliability while ensuring resources capable of ramping quickly get paid for that valuable service.
Of course, as markets adjust to oversupply by leaving behind some generators, policymakers must consider reliability and transition assistance for workers and communities affected by plant closures. Luckily, evidence is growing that markets will be quite capable of maintaining reliability as old units shut down and are replaced by portfolios of cleaner resources.
A recent Brattle analysis shows upcoming coal retirements are unlikely to affect reliability in Texas (even though the state has one of the lowest reserve margins in the nation), because of other resources under construction, planned, or possible in the near-term. And, providing future-oriented job training programs or pensions for displaced workers is a less expensive way to support affected workers and communities than continuing to use ratepayer funds to prop up overall operations of uneconomic plants.
The need for collaboration: Utilities are grappling with new business models — understanding the value of new services can help
Given FERC’s newest proposed rule to better integrate storage and aggregated distributed resources, the question about the interface between the utility and the market operator is more critical than ever. Some utilities are making progress defining their role and business model given all the changes we are witnessing, but more specific and clear proposals are badly needed.
New York and California are have begun running up against some of these questions. In New York, the Public Service Commission began a process to turn utilities into market platform providers for distributed energy resources. Since New York prohibits utilities from owning these resources, the commission plans to optimize the system via market-based pricing that will interact with wholesale market prices. We can expect more of the details of those interactions between distribution and bulk transmission level prices to be worked out in 2017. California utilities are also piloting distributed energy resource auctions to compete with centralized generation in providing local capacity, but exactly how the resulting revenue streams couple with wholesale market bidding remains to be seen.
Signs point to 2017 being the year for more concrete proposals on how to divide responsibility and activities related to integrating and pricing resources across the transmission-distribution interface.
The why now: Pilots, policies and today’s plans will shape the next decade or more
Progress in wholesale markets can seem slow, but momentum is building for changes enabling more resources to participate in the markets and trade more flexibility. One change already helping reward flexible resources is Texas’ “operating reserve demand curve,” which increases real-time market prices in advance of triggering an official scarcity event. This has proven to be effective, and the mechanism is now spreading across the nation, especially as regional market operators look to implement FERC’s 5-minute settlement rule.
Out west, the Energy Imbalance Market now enables six of the region’s largest utilities to trade certain balancing services, increasing the flexibility of the region’s grid. Market benefits have topped $110 million just two years after the program first launched, and several more utilities have stated their intention to join.
And what should we expect in 2017?
If FERC’s proposed rule for storage and aggregated distributed resources is finalized early next year as expected, implementation will move to the regional markets. Each will then propose their own specific changes to their products and operations to enable more resources to participate and get paid in the market.
These steps will each advance the conversation about balancing supply and demand, valuing flexibility, and enabling a more diverse set of resources to participate in the market. 2016 saw many positive steps forward, but far more progress is needed in 2017 (and beyond) to future-proof America’s power markets.
Sonia Aggarwal directs America’s Power Plan.
EERE announces up to $35 million in available funding to support early-stage, innovative technologies and solutions in advanced manufacturing that are not significantly represented in EERE’s current portfolio.
Source: New feed
Utility-scale solar photovoltaic power added more than 9 gigawatts (AC) of capacity to the U.S. power grid in 2016, making it the most dominant new fuel source for the first time in a calendar year, according to the U.S. Energy Information Administration.
Natural gas was not far behind at 8 gigawatts of new capacity and wind added nearly 7 gigawatts, according to the EIA. Wind, solar and natural gas made up 93 percent of new capacity, with some hydropower and nuclear rounding out the fuel mix of new additions.
When distributed solar is included in the tally, solar’s role in new U.S. capacity is even stronger. GTM Research forecasts about 2.5 gigawatts (DC) of distributed residential solar PV projects in 2016, and an estimated total for the year of 14 gigawatts (DC) — or 11.2 gigawatts (AC) to use EIA terms — when utility, commercial and residential solar projects are tallied.
EIA acknowledges that its annual total could be a little low given that it's only based on reported additions and not projections. There are discrepancies that might not put solar ahead of natural gas in the end. “This year, as is the case in many years, expected capacity additions in December are much higher than in any other month,” EIA states.
In past years, the rush of December additions has been because of the looming expiration of tax credits at the end of the year. With the extension of the federal solar Investment Tax Credit at the end of 2015, however, there could be fewer clean energy projects rushing to come on-line by year’s end. In fact, there is already quite a bit of spillover of solar projects from 2016 into 2017.
There is also a matter of reporting. GTM Research tracks additions in DC, while EIA uses AC. GTMR forecasts 10.2 gigawatts (DC) of utility-scale solar capacity will be added in 2016. When converted from DC to AC, that figure is just under 8 gigawatts (AC), which is lower than EIA's 9.5 gigawatt (AC) number.
While the final figures are up for debate in the last days of December, the surge of solar in 2016 is undeniable. Solar’s dominance as a source of new energy is not limited to California, although it does make up the majority of additions. North Carolina installed more than a gigawatt of utility-scale solar, with Nevada, Texas and Georgia ranking in the top five. The amount of utility-scale solar installed in 2016 in the U.S. is more than the past three years combined, according to EIA.
Wind additions were slightly lower than last year, although the U.S. did see its first offshore wind farm come on-line. Nuclear also made the list for the first time in decades when Tennessee Valley Authority's Watts Bar 2 came on-line, 43 years after it began construction.