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How do we calculate the true cost of intermittent renewables?
The levelized cost of wind and solar are falling by the day. But how cheap are they, really? A recent study from the Brookings Institution concludes that their costs are higher than presumed when using a cost-benefit calculation model.
In this podcast, we'll debate the merits of the Brookings study and ask what assumptions one should make when evaluating the costs of different technologies.
(Don't forget to sign up for our live show in New York City on September 22!)
This podcast is sponsored by eGauge Systems, a manufacturer of next-generation energy meters for solar generation and building demand, submetering, performance contracts, LEED projects and net-zero buildings.
The Energy Gang is produced by Greentechmedia.com. The show features weekly discussion between energy futurist Jigar Shah, energy policy expert Katherine Hamilton and Greentech Media Editor Stephen Lacey.
Aside from hosting a majority of the nation's wind farms, the Midwestern U.S. is not known for aggressively pushing the agenda on clean energy issues. But that may be changing as Minnesota joins other leading states in the effort to remake the electricity sector.
Over the last year and a half, Minnesota has emerged as more than just a wind state. In May 2013, the state's legislature passed a bill that would expand the solar market by 450 megawatts. And in March of this year, regulators agreed to create a value-of-solar tariff to complement net metering.
Minnesota's solar targets aren't enough to threaten utility revenue or overload the distribution system quite yet, but it's set in motion a conversation about how the power sector should adapt to accommodate more distributed generation. And that means proactively thinking about the utility business model itself.
Throughout the next year, more than two dozen organizations, utilities and public officials in the state will be meeting to discuss new approaches to utility regulation that will create the framework for the concept of "utility 2.0."
The group, called the e21 Initiative, was formed by the Great Plains Institute. It brings together Xcel Energy, Minnesota Power, George Washington University Law School, the Center for Energy and Environment (CEE) and regulatory observers to proactively address the "changing nature of the electric energy system."
The process started after the Edison Electric Institute released a report last summer warning about the impact of distributed generation on utility revenue.
Mike Bull, the director of policy at CEE, had recently left a job at Xcel Energy, where he was a manager of public policy. He approached executives at Xcel and asked about their reaction to the report. Months of conversation ensued, and the utility eventually expressed interest in creating a formal process for addressing the long-term business model challenges. More organizations signed on, and the e21 Initiative was born earlier this year.
"We all came to the conclusion that if we were going to get further, faster, the regulatory framework would need to evolve," said Rolf Nordstrom, the executive director of the Great Plains Institute, the organization managing the initiative. "Are the way that utilities make money aligned with what society is demanding?"
The initiative is not part of a formal regulatory track, but there are regulators, local elected officials, environmental groups and trade groups that will act as observers. The process builds upon an earlier debate over creating a value-of-solar tariff in Minnesota.
"The value-of-solar issue is a larger symptom of a bigger problem. Our goal with this effort is to see if we can come up with a regulatory framework where we're all pulling from the same rope," said Nordstrom.
Minnesota now joins California, Hawaii, New York and Massachusetts in the quest to build an entirely new electricity system to boost solar, storage, demand response and other forms of distributed generation.
Source: GTM Research
So far, Hawaii, New York and Massachusetts are the only states to create an official process to tackle the issue. California regulators are close to setting the process in motion, but they have not fully embraced a discussion around the concept of utility 2.0.
Nordstrom is hopeful that e21 will influence discussions in a more formal setting when the year-long effort is complete.
"We're putting together a shared understanding of all the potential scenarios and developing recommendations for how to evolve the current regulatory system. We'll have many different options," he said.
Although Minnesota's process is not official, the e21 Initiative puts the state in the same league as other longstanding leaders in this space. Will other states soon follow?
Earlier this month in a new report, The Minimum Bill as a Net Metering Solution, GTM Research explored the potential impact of the proposed Massachusetts minimum bill. One of our key findings from the report is that a minimum bill is preferable to a fixed charge for the typical Massachusetts solar customer, assuming the minimum bill is set at the same level as the fixed charge.
In this report excerpt, we further illuminate the impact by comparing a typical Massachusetts solar customer’s annual bill to a bill with a minimum charge of less than $10.
In order to determine the impact of the minimum bill mechanism on a typical Massachusetts solar customer over the course of a calendar year, GTM Research analyzed the impact of a $10 minimum bill on an NStar customer with a 6.3-kilowatt rooftop solar system who has an energy consumption and production profile based on actual data from Genability. We assumed a volumetric retail electricity rate of 17.33 cents per kilowatt-hour and a fixed distribution charge of $7 per month.
Under the current billing mechanism the solar customer would pay $422.77 for the year.
Source: GTM Research and Genability
Under the $10 monthly minimum bill mechanism, the solar customer would pay $434.77 for the year.
A $10 minimum bill would result in the typical Massachusetts solar customer paying an additional $12 more each year. The customer would pay an additional $3 for each of the four months (March, April, May and September) that the minimum bill charge is activated.
While a $12 increase to the typical Massachusetts solar customer’s annual electricity bill may be tough for solar customers and industry participants to swallow, it is undoubtedly preferable to a $10 fixed charge.
Source: GTM Research
The report, available to GTM Research solar clients, also includes a comprehensive overview of how the proposed Massachusetts minimum bill mechanism would work. It analyzes the impact of the minimum bill on a typical Massachusetts solar customer’s electricity bill, the minimum bill’s effect on residential solar project economics, and the impact of a number of various minimum-bill charges.
If you have any questions or would like to gain access to the report, please contact firstname.lastname@example.org.
The debate goes on between fuel-cell vehicle (FCV) advocates and those who think electric vehicles will win the day. Toyota’s R&D chief disses electric vehicles because of poor range and long charging times, even as BMW’s new i3 pure electric is selling quite well and wows consumers.
We now have an apparent divide between major automakers, with Toyota, Honda and Hyundai pushing hard for FCVs as the future, and GM, Nissan, Tesla and BMW now offering impressive BEVs (pure electrics or plug-in hybrids) that clearly aren’t just compliance cars for the California market, as is the case for the new round of FCV offerings.
BMW also just began offering a very affordable and compact DC fast charger to BMW dealers; at $6,500, it's far cheaper than has historically been the case for fast chargers. This fast charger can bring the i3 to an 80 percent charge in 30 minutes, at no cost to the car owner through at least 2015.
Studies have found that FCVs are far less efficient at using electricity as a fuel than are battery electric vehicles (BEVs) or plug-in hybrid electric vehicles (PHEVs). For example, a recent UC Irvine analysis found that using electricity in BEVs directly is 2.5 times more efficient than using that same electricity to create hydrogen for use in FCVs (see the chart on page 2 of the link). The only other study I’ve found looking directly at this issue is a 2001 study that mirrors the UCI investigation’s conclusions, finding that about 80 percent of the energy is lost from converting electricity into hydrogen and then back into electricity in a fuel cell.
My last piece focused on this issue, identifying it as a major stumbling block for public policies that support FCVs. This follow-up article will examine a related argument that some FCV advocates have made. Essentially, the argument states that even if FCVs are less efficient at using renewable electricity than BEVs, the grid reliability issues associated with a higher penetration of BEVs and renewables will still justify use of FCVs. These advocates argue that using renewable electricity to create hydrogen will avoid curtailment and will mitigate overgeneration issues associated with, for example, the increasing availability of peaking solar power in California and other jurisdictions as solar power growth continues its meteoric rise. The hydrogen created from excess solar power, the argument goes, can then be used in FCVs as a fuel, while also providing grid support.
Here’s a simplified summary of my conclusions for those who don’t want to delve into the details of this kind of technical discussion: the "grid benefits" arguments in favor of FCVs don’t seem to hold much water. The more plausible view is that BEVs are actually better for the grid in terms of improved reliability, as well as increased efficiency and less cost.
Let’s look at each of the main claims of this pro-FCV argument.Claim 1: Using excess renewable electricity to electrolyze hydrogen is independent of travel demand and BEV battery capacity.
It is technically true that using excess renewable electricity to create hydrogen is, when considered alongside the alternative BEV approach, independent of vehicle travel demand and the available BEV battery capacity. However, this fact isn’t particularly relevant if state-level projections for BEV sales are accurate.
The California Energy Commission projects that up to 33,000 megawatts of EV (plug-ins and pure electrics) storage will be available to the grid by 2022 (see Figure 1). This won’t translate, of course, into usable grid storage at the same capacity. However, even if 10 percent of this projected capacity is made available to the grid through smart charging or “vehicle-to-grid” programs, this will be a major contributor to grid stability. Moreover, this aspect of BEV availability is a beneficial side effect of BEV sales more generally.
The California Public Utilities Commission is currently considering how best to incentivize smart charging, which the CPUC defines as the ability to turn the charging of BEVs on or off as the grid requires. With smart charging, there is no flow of power from the vehicle to the grid (known as V2G), but the end result is much the same as that from smart charging. This is the case because turning off a BEV that is currently charging has the same impact as a BEV sending power to the grid, but with the impact divided by two, because the battery cannot be discharged back to the grid. In other words, stopping power that is flowing into a BEV has much the same effect, but to a lesser degree, as sending power back into the grid.
FIGURE 1: California Energy Commission Projection for Grid Load From EVs and PHEVs
Source: CEC California Energy Demand 2012-2022 Final Forecast
The California Independent System Operator projects that very little storage will be required to balance variable renewables by 2020, which is the deadline for utilities to achieve the 33 percent renewable standard. The CPUC has also mandated that 1.3 gigawatts of stationary storage must be procured by the investor-owned utilities and brought on-line by 2024.
It's important to acknowledge that the degree to which BEVs will be able to provide grid stability will depend not only on how many owners can be induced to opt for smart charging, but also on how often and during what times of the day BEVs are connected to the grid. So while BEVs that are signed up for smart charging (or, better yet, V2G) will clearly provide grid reliability benefits, there may well still be overgeneration at times, even under optimistic BEV adoption rate scenarios. If that is the case, there may be a role for some other types of storage as alternatives to curtailment, which is probably the least attractive alternative for a variety of reasons.
A recent report from E3, a California-based energy consultancy that provides regular guidance to the CPUC, found that stationary long-term battery storage options, in a 40 percent renewables scenario, can save up to $300 million per year as an alternative to curtailment. If these calculations are at all accurate, investor-owned utilities will very likely benefit from substantial on-peak charging of BEVs, and also from on-peak charging of stationary storage facilities.
The relevant question now under discussion is whether adding the infrastructure necessary to use hydrogen as an additional electricity storage medium is justified by the economic benefits of hydrogen storage, including consideration of the large conversion losses from doing so.
In sum, through the 2020-2025 timeframe, it seems that a combination of limited requirements for storage on the grid by 2020, existing goals for energy storage beyond 2020, and the expected pace of BEV availability on the grid, will likely render moot any benefits derived from hydrogen creation from excess renewable electricity -- particularly when we remind ourselves that such use is 2.5 times less efficient than using that power directly in BEVs.
What about beyond 2025? Well, BEV sales are likely to increase even faster at that point, as new models come on the market and costs and technology improve. And as BEV owners learn more about the benefits of smart charging, it is likely that we’ll see higher levels of participation, providing further grid support as an incidental benefit of BEV sales.Claim 2: BEVs will require more renewable electricity on the grid, and that will require more backup power to balance out the variable renewables like solar and wind.
This argument seems to ignore the fact that California already has laws requiring that utilities achieve 33 percent renewable energy by 2020. There is also a growing push to create a new law requiring up to 51 percent renewables by 2030. So any grid reliability issues that stem from higher penetration of renewables are independent of policies that support BEVs. And as just discussed in detail above, BEVs actually provide major grid reliability benefits. In fact, the quantified grid benefits from a number of studies suggest that BEV owners could be compensated as much as $100 per month due to the grid reliability benefits from smart charging of their BEVs. This has prompted some intervenors in the CPUC proceeding examining these policies (R.13-11-007) to suggest that BEV owners could be provided free power for all driving in return for allowing smart charging of their vehicle. The CPUC has not yet issued a decision on this matter.Claim 3: Use of FCVs provides more inherent storage capacity than BEVs.
This argument also hinges on the ability to create as much hydrogen from grid electricity as one wants to, with storage being fairly easy compared to the battery storage alternative. However, again, it will require a large new infrastructure to create the hydrogen at issue, and the conversion losses of turning electricity into hydrogen and then back into electricity in fuel cells entails a loss of 70 percent to 80 percent of the energy. If we can, instead, use BEVs as already-existing energy storage facilities that can utilize this excess electricity at 2.5 times the efficiency of hydrogen production, why wouldn’t we pursue the BEV route?Claim 4: Using excess electricity to create hydrogen allows for more efficient gas generator operations.
Gas generators are still needed for the evening ramp as demand peaks from people returning home after work, while solar power production diminishes to zero. This is the “neck” of the famous “duck chart” (Figure 2), which projects the load curve out to 2020 as more and more solar and wind comes on-line. The duck chart suggests that there will also be an issue with overgeneration during midday periods because fossil generation is unable to turn down below a certain level. This is the “belly” of the duck. FCV advocates have argued that these two issues can better be addressed through H2 production from excess power than with BEVs.
FIGURE 2: The Duck Chart
In terms of the belly of the duck, BEVs are a well-fitted solution to flatten the belly if incentives for daytime charging are provided, as discussed above. The Clean Coalition’s “Flattening the Duck” presentation is available online and shows various ways, including using EVs to mitigate overgeneration, to reduce issues illustrated by the duck chart. The belly is already becoming real today (see Figure 3) as solar production grows quickly in California, mostly at the utility-scale level. Figure 3 shows CAISO’s grid from July 26, 2014, with about 4,000 megawatts of wholesale solar production on-line at times, during a peak grid-wide demand of almost 40,000 megawatts.
Another benefit: as the belly problem is solved, the neck problem becomes less severe as well, because the ramp is reduced in direct proportion to how much the belly is reduced. As such, solving the overgeneration issue would be a “two for the price of one” fix.
FIGURE 3: Recent Renewables Production Levels in California
Workplace charging for BEVs is expanding, and with the development of low-cost Level 2 and 3 chargers (like BMW’s fast charger), it is reasonable to believe that we are well on our way to a robust daytime BEV charging infrastructure being built out. California already has almost 2,000 EV charging stations with more than 5,000 outlets. Growth has been very rapid, with the large majority of these stations being built in the last five years.
If substantial incentives are provided to BEV owners for daytime charging, due to the grid benefits of doing so, it is reasonable to believe that we’ll see a steadily growing contribution from BEVs to reducing the belly of the duck. We’re already seeing firms get serious about coordinating these kinds of solutions; for example, EPRI’s Open EV Tech platform was recently announced. This new aggregation platform brings together eight different automakers under a single standard.
I agree that the neck of the duck is a problem that will require significant firm capacity to remain on-line until sufficient stationary or mobile storage is available. However, V2G (two-way charging) could mitigate this problem significantly in much the same manner as V1G can mitigate the belly problem. Moreover, because V1G provides the same (but at half the capacity) benefits of V2G, even if V2G doesn’t become reality in the next decade, we’ll still see a substantial contribution to the neck problem from BEVs as smart charging allows plugged-in BEVs to be stopped from charging during the neck.
Similarly, the 1.3 gigawatts of energy storage mandated by the CPUC, which includes mobile and stationary storage, will further help with the neck problem because all of this storage will, at least in theory, be available to produce power during the neck period.
Finally, and perhaps most importantly, it would probably make more sense to simply use natural gas in fuel cells directly (as with the Bloom Box stationary fuel cell), for grid stability purposes, rather than using natural gas to create electricity in a power plant, convert that excess power remotely to hydrogen and then convert the hydrogen back into electricity in a fuel cell to supply power back to the grid during ramp times. The efficiency losses of the latter pathway are staggering, not to mention the additional infrastructure required for hydrogen production, storage and energy production.
Clearly, my thoughts here are preliminary and sketchy. New data will require reassessing my conclusions. The same UC Irvine team that released the report I cited here is currently modeling the grid benefits of FCVs and BEVs. Their work is also preliminary at this point, but we should have complete results in the coming months. I’ll check back in on this issue once the results are made public.
A major new report from the Edison Electric Institute urges the U.S. utility industry to get serious about buying BEVs for their fleets, as the “point of the spear” for electrification of transportation. The report states: “Electrification of the transportation sector is a potential ‘quadruple win’ for electric utilities and society, and will enable companies to support environmental goals, build customer satisfaction, reduce operating costs and assure the future value of existing assets.” The report also highlights the fact that battery costs have come down 50% in the last four years.
This and many other similar reports are very encouraging regarding the degree to which BEVs are already being taken very seriously.
In sum, looking at the broader grid reliability issues associated with FCVs and BEVs doesn’t seem to offer much, if any, advantage for FCVs.
Tam Hunt is owner of Community Renewable Solutions LLC, a renewable energy project development and policy advocacy firm based in Santa Barbara, California and Hilo, Hawaii.
California, already the epicenter of distributed solar PV, is also a growth market for behind-the-meter energy storage. Companies like Stem, Green Charge Networks, Coda and the dynamic duo of SolarCity and Tesla are installing big batteries in buildings, mainly on the business case of reducing demand charges for commercial and industrial customers.
In the future, those batteries could also help store, stabilize and shift solar power -- if the mechanisms and markets for paying them for doing so can be established successfully. GTM Research reports that demand charge reduction is driving today’s energy storage economics, but that the growth of solar PV will open new, more lucrative applications and markets in years to come.
Japanese PV giant Sharp is targeting both applications with its SmartStorage energy solution, a managed energy storage technology package it launched this week. The system, using lithium-ion batteries from an as-yet-undisclosed set of providers, along with power electronics from Texas-based Ideal Power, is aimed at commercial and industrial customers. It is now available in California, with plans to roll out to other U.S. markets later this year.
Carl Mansfield, general manager of Sharp’s Energy Systems and Services Group, said in a Wednesday interview that the company was hoping to install more than 50 megawatts over the next three years, driven largely by the economics of demand charge reduction. That includes plenty of standalone projects in solar-free buildings, either because they’re unsuited for rooftop PV or just aren’t interested in it.
But Sharp, which shipped an estimated 1.6 gigawatts of PV modules last year to rank sixth in terms of global market share, is also interested in hybrid solar-storage applications, he said. Its pilot project in San Diego uses a 30-kilowatt, 40-kilowatt-hour energy storage system to help back up a 60-kilowatt rooftop solar array, for example.
Solar developers are among the half-dozen or so project partners it’s currently working with in California, Mansfield said. And Sharp’s ten-year service agreement and performance guarantee includes the capability to update its on-site and cloud-based servers with new software to perform new solar-management tasks as they arise, he said.
“This is a new business line for Sharp,” Mansfield said. “This is not an effort to sell more solar, but it’s very complementary to solar. […] We believe that this product does open up new customers who are interested in solar who would not buy standalone solar.”
A growing list of solar module manufacturers, installers, developers and third-party aggregators are bundling energy storage into their offerings. On the residential scale, LG demonstrated a solar-battery solution at this year’s Intersolar conference, while Panasonic and ABB have an integrated battery-inverter system (PDF). California is the target of Sacramento-based startup Sunverge and Germany’s Sonnenbatterie, as well as PV giant SunPower, which is putting batteries in new KB Home locations in the state.
But beyond backing up homes or businesses when the grid goes down, hybrid battery-solar systems don’t have many ways of turning their potential for smoothing and shifting grid-tied solar power. “There’s a lot of speculative value in these systems that there’s no way to monetize properly at this point,” Mansfield said.
California does provide lucrative incentives for on-site energy storage through its Self-Generation Incentive Program, which recently got re-authorized for $415 million to fund projects through 2019. Solar-connected energy storage now makes up for a majority of SGIP applications. While utilities had been blocking battery-backed solar grid interconnections, state regulators have ruled that they have to start connecting them.
Sharp hasn’t laid out specifics on its SmartStorage pricing and financing plans, or whether it’s going to compete with startups like Stem and Green Charge Networks by offering “no-money-down” financing programs. But Mansfield said that Sharp has “access to financing options if the end customer requires them,” backed by its ten-year performance guarantee.
Arizona Public Service has had a rocky relationship with the solar industry.
The utility has been criticized for funding a smear campaign against solar firms operating in Arizona, harangued by installers for pushing fees on net metering customers, and blasted for supporting property taxes on all solar projects in the state.
But after all the bickering and finger-pointing between APS and solar companies, the utility is doing something that few expected: getting into the rooftop solar business itself.
This week, APS filed a proposal with regulators asking for permission to develop 20 megawatts of solar PV systems on 3,000 rooftops through the end of 2015. The systems would be installed on the utility side of the meter and all electricity would be fed into the grid. Customers renting their rooftops would get a $30 credit each month on their bill for twenty years.
APS says the program, which will cost between $55 million and $75 million, gives the utility more flexibility by controlling the inverter and offering a wider variety of consumers a chance to put solar on their homes.
"Many customers are interested in rooftop solar, but either cannot afford to buy a system outright, or have insufficient credit to lease a system. AZ Sun DG provides a means for at least some of these customers to 'go solar,'" wrote the utility in its proposal. "Moreover, deploying utility-owned residential DG provides an exciting chance to explore the operational advantages of installing rooftop solar with advanced inverters."
If the plan is approved, the utility would use local installers for all the work through a competitive bidding process. The 20 megawatts up for grabs over the next fifteen months would be far lower than the 73 megawatts of residential systems installed in Arizona last year. But it still offers a much bigger market than most states in the country.
So a major utility seen by the solar community as antagonistic is now entering the rooftop solar business. That's a positive sign, right?
Not in the eyes of many advocates and national solar companies that have been working on solar policy in Arizona over the last couple of years.
"The irony here is that APS has spent two years complaining about how terrible solar is [and] how it’s a massive problem for the grid. But now they’re saying it’s fine, as long as they can control it entirely," said Will Craven, a spokesperson for the Alliance for Solar Choice (TASC), an advocacy group that represents solar service companies such as SolarCity, Sunrun and Sungevity.
The major concern for TASC is that APS will be able to rate-base the investment and make a guaranteed rate of return. Solar companies don't have that luxury.
The Solar Energy Industries Association (SEIA) echoed that sentiment, calling APS' proposal a "Trojan horse."
"This latest tactic by APS has a ‘Trojan horse’ smell to it. Our member companies welcome fair and equal competition, but this move would stack the deck in favor of a company which can rate-base solar with a guaranteed rate of return. How is that fair?" said SEIA spokesman Ken Johnson in a statement.
Not everyone is lining up to criticize APS. A handful of local installers about to get a big boost through the program are pleased with the sudden announcement.
"We're excited that such a large utility sees solar as an asset and is putting a strong focus on Arizona companies," said Joy Seitz, CEO of American Solar, a company based in Scottsdale.
American Solar installed about 3.5 megawatts in 2013, and Seitz said the company could potentially double that in 2015 by working with APS.
Will a regulated monopoly choosing a small number of companies be able to provide a competitive service? Cory Honeyman, a solar analyst with GTM Research, says it likely can.
"APS has expressed a preference to work with in-state installers, which puts SolarCity and other national players at a disadvantage as potential partners with APS in this program. But by offering a $30 monthly credit to solar customers, the AZ Sun's value proposition is a competitive offering compared to monthly lease terms offered by leading installers active in AZ," said Honeyman.
For its part, APS says it wants to be more creative and meet ongoing consumer demand for solar. Daniel Froetscher, a VP of transmission and distribution at the utility, told the Arizona Republic that it was all about proving the company has an entrepreneurial spirit.
"This is an effort to reassure our customers that this is not the staid, old, stodgy utility company," he said.
In mid-July, APS held a meeting with SunEdison founder Jigar Shah -- a solar advocate who has publicly quarreled with the utility -- to discuss the future of the solar industry. And over the last five weeks, the utility has been signaling to installers in the state that it is ready to get deeper into rooftop solar.
Still, there are a lot of upset companies that now feel shut out of a large piece of Arizona's solar market.
"Monopolies are intended to be rare things in American society, and monopoly rights are not extended where functioning markets already exist. If APS wants to compete on a level playing field then they need to do so through an unregulated subsidiary," said TASC's Craven.
But Honeyman said he expects more similar moves from utilities over the next year. With the solar market expected to grow 60 percent this year, power providers aren't going to sit on the sidelines.
"GTM Research expects this announcement will be the first of several over the coming year in which utilities pilot programs to actively capitalize on the residential market's boom, rather than focusing on the future of net metering and the value of distributed solar," he said.
Utilities like APS want to develop programs that are "fair" to them and their customers. But in the process, will they create a limited market that locks out competition?
The Edison Electric Institute, the power industry's main trade group, is calling on utilities to better promote electric cars in order to stimulate demand for electricity and help reverse trends that threaten the long-term viability of some in the industry.
Without a strategy to help connect more vehicles to the grid, utilities will continue to face slow growth and stagnant revenues, warns EEI in a new report. The organization calls electric vehicles a "quadruple win" for power companies looking to boost demand, find new ways to interact with customers, support environmental goals and mandates, and reduce operating costs through electrifying their own fleets.
"The bottom line is that the electric utility industry needs the electrification of the transportation sector to remain viable and sustainable in the long term," conclude the authors.
Some leading investor-owned utilities have rolled out programs to support charging stations, created pilots to test integration of new vehicle-to-grid technologies and have supported studies to model how lots of electric vehicles would interact with the distribution system. But there hasn't yet been a strategic, industry-wide effort to support the electrification of transportation as a way to boost demand.
To understand why EEI is now calling for more electric vehicles, consider where the industry is headed. As the chart below illustrates, growth in retail demand has come to a virtual standstill.
At the same time, the states with the biggest solar PV markets are seeing that technology slow electricity demand growth even further. This is adding additional pressure on utilities (creating borderline disruption in some markets), as third-party developers capture much of the value from developing solar.
"Stagnant growth, rising costs, and a need for even greater infrastructure investment represent major challenges to the utility industry," writes EEI. "Today’s electric utilities need a new source of load growth -- one that fits within the political, economic and social environment."
Part of the answer is electric vehicles, which could both grow electricity sales and help balance a future grid made up of much more distributed renewables.
Thus far, utilities have had a conflicted relationship with electric vehicles. Although sales continue to grow, consumer demand has been relatively low compared to initial estimates. That has prevented power companies from investing heavily in charging infrastructure. There are also legitimate concerns about how electric cars and trucks will impact circuits on local grids.
However, the potential upside is enormous. If the two charts above have utilities worried, the chart below should have them excited about the future.
As Opower pointed out in a recent analysis, owners of electric cars use nearly 60 percent more electricity than the average customer. And customers who own both a solar system and an electric car consume roughly the same amount of electricity from the grid as an average customer -- offsetting much of the excess solar that utilities must buy back through net metering.
If that's not enough to get utilities thinking more strategically about electric cars, they should consider the technology's influence on consumer behavior. According to data compiled by a utility member of EEI, consumers view their local power provider as the second-most trustworthy source of information about electric vehicles, just behind Consumer Reports. Utilities have double the credibility that auto manufacturers and dealers do with consumers.
And a 2010 study from the Electric Power Research Institute found that two-thirds of consumers wanted their utility to provide information on charging station locations and pricing. As the authority on electricity services, utilities have a unique opportunity to steer consumer adoption of EV technology.
In its report, EEI proposes that utilities boost rebate programs for residential and commercial customers, set up new information services for charging infrastructure, create new rate structures for charging, cultivate deeper relationships with auto manufacturers, and purchase more electric vehicles for their own use. The organization is calling on its members to invest 5 percent of their annual fleet purchases in plug-in vehicles to set an example.
"By developing our expertise in vehicle electrification now, we are more likely to be able to dictate our own compliance path," writes EEI.
Last week, contributor Elias Hinckley wrote a piece for GTM that pondered why utilities have done so little to promote electric cars. He proposed some similar ideas, including the creation of financing options for home-charging stations or partnerships between utilities and manufacturers to develop lending services that could be integrated into a customer's bill.
Electric vehicles are not yet a significant part of the grid mix. And until utilities figure out how to use their expertise to build demand, they likely won't be for a long time to come. That, argues EEI, wouldn't be just a simple missed business opportunity -- it could be a deciding factor in the profitability of utilities as they enter an era of declining electricity demand.
Bloom Energy just announced a new source of capital and a new customer for its natural-gas-powered fuel cells. The ten-year-old, billion-dollar-funded startup claims to have installed more than 130 megawatts of its Bloom boxes in the U.S.
Solid-oxide fuel cell maker Bloom doesn't really provide information to the public or press about its corporate doings -- unless that member of the press is prepared to play the role of an unctuous sycophant.
We've reported on Bloom's spectacularly negotiated deal with Delaware utility Delmarva Power. We've covered the debatable "greenness" of the Bloom fuel cell. We've profiled the fuel cell industry as a whole.
Recently, we've heard less-than-positive things from a number of sources about the reliability of the Bloom fuel cell stack. In fact, we've heard that the fuel cell stack has a lifetime of six months to a year before it needs to be serviced. And we've read more of the repeated promises of profitability that Bloom never fails to include in its investor presentations.
Bloom has an electricity sales business, Bloom Electrons, which eliminates much of the risk for the customer as well as a leasing and ownership structure.
Bloom's most recent funding source is Exelon, the Chicago-based competitive energy provider, which will seek to finance 21 megawatts of Bloom's fuel cell deployments in any state with a favorable subsidy regime. According to a release, "Exelon’s partnership with Bloom Energy builds upon the distributed generation business of Exelon subsidiary Constellation." Exelon had 2013 revenues of approximately $24.9 billion from providing electricity and natural gas to more than 7.8 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).
Exelon is the first energy firm to help finance Bloom's fuel cells.
Other recent fuel cell news:
Renewable energy companies in the United States might lose a friend in the coming months.
Conservative Republicans are trying to kill the Export-Import Bank, the independent and self-sustaining federal agency founded during the Great Depression that helps finance the purchase of American-made goods and services by overseas buyers. The bank’s current authorization expires at the close of business on September 30 if Congress doesn’t act.
The Ex-Im Bank is fairly obscure (at least, it was before Republicans targeted it), but it does drive a fair amount of business. It rang up 3,842 financing authorizations in the 2013 fiscal year -- loan guarantees, mostly, but also direct loans and export credit insurance -- backing exports worth $37.4 billion. Renewable energy had a $257 million piece of that pie.
And the cost to taxpayers? According to a recent report (PDF) from the Congressional Research Service, after covering operating expenses and loan loss reserves, “Ex-Im Bank provided $1.1 billion to the U.S. Treasury in FY2013.”
That’s right, the taxpayers actually made money off of the Ex-Im Bank.
Yet critics say the bank is an affront to free-market principles, rewarding the politically well-connected and even putting taxpayer dollars at grave risk. That critique is reflected in this statement from Rep. Jeb Hensarling (R-Texas), the leading voice in opposition to the bank’s continued existence, at a June hearing of the House Financial Services Committee, which he chairs: “The Bank ostensibly makes loans backed by taxpayers that the private sector is unwilling to make. If private creditors are unwilling to engage in these transactions...why should the American taxpayer?”
Supporters reply that one big reason is that companies from other countries are getting similar support. Renewable energy companies add that long project timelines and the nascent nature of many renewable energy technologies and applications can make obtaining financing nearly impossible overseas.
These arguments jibe with the experiences of Steve Wilburn, CEO of California-based FirmGreen, a player in a biogas project sited at a Brazilian landfill that was aided three years ago by a $48.6 million loan supported by the Ex-Im Bank. At a House hearing in June, Wilburn testified that with no financing assistance available from his commercial bank, he was advised by his Brazilian colleague to “contact his ECA” -- export credit agency.
“I was embarrassed,” Wilburn testified. “I had to ask him what 'ECA' meant.” Wilburn said he discovered that competitors on the project were boasting of finance support from their home country ECAs -- Air Liquide though France’s Compagnie Française d’Assurance pour le Commerce Extérieur, and Linde through Germany’s Euler Hermes Kreditversicherungs-AG.
The Novo Gramacho project was ultimately completed and is now operating, producing fuel-grade biomethane gas that helps power a local refinery as well as food-grade liquid CO2, all with the help of FirmGreen’s VerdeControls plant control software and VerdeWatts energy management system. FirmGreen estimates that the project generated 165 U.S. jobs, including those at FirmGreen itself and at other U.S. companies that were involved along the way.
Opponents have tried to focus the Ex-Im Bank debate on the bank’s support for big customers -- S&P recently estimated that the bank has supported up to 30 percent of Boeing’s jet deliveries in the past four years, according to a Wall Street Journal story. But Karl Gawell, executive director of the Geothermal Energy Association, said that ignores much of the bank’s work in renewable energy.
“Small U.S. firms involved in new energy technologies, like renewable energy and efficiency, are competing head-to-head against many foreign competitors to sell goods and services in international markets,” Gawell wrote in the National Journal’s Energy Insiders forum. “The Export-Import Bank plays an important role in the competitiveness of U.S. exports and the health, if not survival, of many of the firms that are developing and deploying the energy technologies expected to dominate the global energy markets of the future."
Renewable energy is a focus of the Ex-Im Bank’s activities in part because its charter requires it. Plus, early in the Obama administration, Congress specifically targeted 10 percent of the bank’s financing for renewables. At the time, it was kind of a crazy directive, since in 2009 just $13 million, or 0.4 percent of the bank’s financing, went to renewables. But the figure grew quickly, reaching $721 million in 2011, 2.2 percent of the bank’s authorizations.
Renewable energy authorizations have since fallen, but Craig O’Connor, director of the Ex-Im Bank’s Office of Renewable Energy, said that doesn’t reflect any backsliding on the bank’s commitment.
Renewable energy as a business “is a little lumpy,” O’Connor said in an interview. “In any one year, you could have a slip.” More fundamentally, “at the Ex-Im Bank, we’re not controlling our own destiny. We don’t go out and create demand; we reflect it.”
That said, O’Connor beats the bushes to find U.S. companies that might be able to sell goods or services overseas, and to get them in Ex-Im Bank programs if that’s what they need to make exports happen.
U.S.-based companies can also get assistance in undertaking projects overseas from the Overseas Private Investment Corporation. It operates similarly to the Ex-Im Bank, except its charge is to help U.S. companies invest in developing companies.
Just last month, OPIC approved a $230 million loan to help support Arizona-based First Solar’s Luz del Norte solar power plant in Chile. At 141 megawatts, it will be the largest photovoltaic solar plant in Latin America, according to First Solar.
What’s interesting in this case is that just a few years ago, several First Solar projects in India were supported by Ex-Im Bank financing aid. With those projects, there was an explicit guarantee that U.S.-made First Solar goods would be sold into India (the company has plants in Ohio and Malaysia). With OPIC doing the financing, there’s no such promise with the Chile project.
Camilo Patrignani, CEO of the renewable energy project developer Greenwood Energy, says help from multilateral lenders like OPIC is vital to making projects happen in Latin America as commercial lenders become more comfortable with the space. And he says that even though OPIC deals don’t come with an export guarantee, loans for overseas projects can be good for the United States.
“Of course, we all want to see the world turning to clean energy solutions,” Patrignani said in an interview. “Moreover, these are not subsidies. They pay for themselves. And there are direct and indirect benefits. Once you look at the multiplier effect of American companies focusing on Latin America, you see it’s really worthwhile.”
OPIC’s charter is also up for reauthorization this year, but the agency appears safe; a bill focused on electrifying Africa that includes a three-year reauthorization passed the House in May despite majority Republican opposition, and a bipartisan bill in the works in the Senate would re-up OPIC funding for five years.
As for the Ex-Im Bank, while Hensarling is continuing his crusade, there are signs that a campaign by the bank and its supporters in both the business and labor communities has begun to turn the tide in favor of the bank, particularly in the Senate. Still, according to a recent story published on political website The Hill, “the legislative path for a bill remains murky.”
Pete Danko is a writer for Breaking Energy. This piece was originally published at Breaking Energy and was republished with permission.
Today's acquisition of solar installer Astrum Solar for $54 million by energy services company Direct Energy (a subsidiary of Centrica) is another sign of the solar industry's health and dynamism. GTM Research expects the U.S. residential PV market to exceed 1 gigawatt for the first time in 2014.
This U.S. industry is in an extended period of strong growth -- and while leaders have emerged, the space remains volatile, with players jockeying for position via acquisition, vertical integration and establishing new channels. And as the industry grows, it gains attention from larger players looking to join this multi-billion-dollar market.
With this acquisition, Direct Energy's energy services group gains another product it can offer its customers, while the processes of scaling up and winning customers just got drastically accelerated for Astrum.What did Direct Energy buy for $54 million?
Founded in 2008, Astrum Solar has installed approximately 4,000 residential solar systems in the Northeast U.S., California and Arizona. Astrum took off in 2011 after an investment from Constellation Energy gave this East Coast installer a guaranteed SREC offtaker in certain markets and allowed it to begin offering a solar lease in six of its twelve active state markets, according to GTM Research.
As per the GTM Research Solar Leaderboard, Astrum was the No. 8 solar installer in the U.S. in 2013 with a 1.3 percent market share (the same as Roof Diagnostics). Astrum was No. 9 in Q1 2014 with 1 percent. In March of this year, NRG Energy acquired Roof Diagnostics, the eighth-largest solar installer in the U.S., for an undisclosed price.
Hudson Clean Energy recently announced a $100 million financing facility with Astrum.
A contact in the solar industry suggested that $54 million was "a really cheap price."How does Astrum Solar benefit?
Direct Energy's "deep relationships with over 6 million residential customers will be a winning combination in the growing U.S. residential solar market." said Vadim Polikov, president of Astrum. Direct Energy has customers in 46 states plus Washington, D.C., as well as ten provinces in Canada.
Cory Byzewski, vice president of home services at Direct Energy, told GTM that this is "an obvious and fantastic partnership," adding that it creates "a strong new player in the residential solar space -- a combination of Astrum plus the reach and scale of Direct Energy." He said there is a "great cultural fit...[because] both companies want the customer to gain control of their energy usage."
The VP noted that the energy services piece of the company enters millions of homes every year. While conceding that "solar is young," he noted that Direct Energy already offers "more mature services such as HVAC and plumbing" and understands how to acquire and service these clients at a low cost and "cross-sell solar services."
Byzewski suggests that he sees "incredible growth in the future" for the combined entity, which he believes will pose a "real threat to companies in this space."
SolarCity and Direct Energy have created an investment fund to finance $124 million in commercial and industrial solar projects with $50 million from Direct Energy. Direct Energy is working with SolarCity on a single-bill option and does not see a conflict between its arrangement with SolarCity and its ownership of Astrum.Which downstream solar company gets acquired next?
There is a consolidation of sorts happening in the residential solar installer market, with SolarCity and Vivint actually extending their market share lead over a long tail of smaller players.
Shayle Kann, VP of GTM Research, sums it up: "It makes a lot of sense. Astrum is strongest in markets that have competitive retail electricity -- markets where Direct Energy can operate."
Kann adds, "This is the biggest move in an ongoing trend of competitive retailers getting into solar. See also CPF/North American Power, SolarCity/Direct Energy and Viridian, Choose Energy/OneRoof, and Astrum/Ethical Electric (though that one's probably over now). But this is the first acquisition -- and maybe not the last."
An emerging energy storage player just received a very big chunk of capital.
Green Charge Networks, a startup deploying energy storage equipment for commercial customers, just raised $56 million from K Road DG to expand its no-money-down energy storage program. The firm claims that the $56 million round is "the largest amount of capital raised by any company in the intelligent energy storage space." (Tesla and SolarCity might take issue with that claim.)
In March, Green Charge and TIP Capital announced a $10 million fund, part of TIP Capital’s broader offering of fixed-rate monthly financing payments for lighting retrofits and HVAC upgrades. Green Charge has also tapped $12 million in stimulus grants, as well an undisclosed amount of funding from investors including ChargePoint founder Richard Lowenthal.
Can power-purchase agreements (PPAs) and power efficiency agreements (PEAs) spur the energy storage market to grow as fast as the residential solar industry has expanded?
Founded in 2009, Green Charge’s GreenStation has been installed by 7-Eleven, Walgreens, Levi's Stadium, UPS, school campuses, and cities across California, including Redwood City and Lancaster. Green Charge owns and operates the energy storage assets deployed at customer sites, with zero capital or maintenance costs for the customers. The company claims that it is already profitable and has more than 25 customers.
As with a solar PPA, the power efficiency agreement shifts the performance burden and technology risk onto Green Charge as the asset owner.
The $56 million includes some working capital, but most of the funding is intended to finance storage systems. The funding source, K Road DG, is launching a new distributed generation and smart grid business and operations platform "based on the conviction that renewable and distributive power generation will ultimately power much of the globe," according to a release. K Road DG includes executives William Kriegel, Gerrit Nicholas, Mark Friedland and Intel Capital founder George Coelho.
Although the company calls its program a "PPA," the fact is that it's a shared savings model that more closely resembles an ESCO arrangement. The company's innovation is the software that operates the battery and electronics and models customer usage in the context of utility rate structures. What’s really driving the first wave of building battery systems are demand charges -- the portions of utility bills that building owners pay when their total electricity consumption hits or exceeds certain thresholds at any moment in time. Because these “peaks” are hard to monitor or predict, they’re hard to prevent -- and in certain markets, like California or New York, they can add up to a significant portion of overall utility bills.
We spoke with Stephen Kelley, Senior VP at Green Charge. He called the power efficiency agreements "a true PPA instrument for energy storage" and gave the following example.
A California state college saved $120,000 in demand charges alone in the first year of using the Green Charge system. Under the shared-savings model, the college keeps 25 percent of that $120,000.
Kelley told GTM that Green Charge systems range in size from 30 kilowatt-hours to 300 kilowatt-hours and have three years of performance data behind them. The batteries are lithium-ion and are sourced from Samsung, which provides a ten-year warranty.
He said that the software has been "refined and proven" over the last 2 1/2 years, adding that Green Charge has a market presence advantage of more than a year over its competitors. Combined with the new financing arrangement, Kelley said it "will allow us to leapfrog our competition."
That competition would be Stem, SolarCity/Tesla, Sonnenbatterie, Greensmith, and others in the space.
Stem, another batteries-for-buildings startup, has launched a $5 million fund with Clean Fleet Investors to boost installations of its own building energy storage systems. Former EV maker Coda also offers a no-money-down energy storage play, this one financed internally by Fortress Investment Group (FIG), the multi-billion-dollar investment firm that picked up Coda’s assets for $25 million in June.
Kelley notes that he has "never seen Greensmith" involved in a competitive deal. He notes that Green Charge has a massive backlog of business and deep experience in interconnecting energy storage systems with major utilities across the nation, including California's investor-owned utilities.
GTM Research predicts the U.S. market for distributed energy storage will grow at a 34 percent cumulative annual growth rate to reach 720 megawatts by 2020, driven largely by the demand charge business case, but also boosted by solar integration needs.
Jeff St. John contributed to this article.
As the New York Public Service Commission debates a proposal to reform the state's distribution utilities, Central Hudson Gas & Electric is getting out in front of the coming changes.
The utility filed a $46 million rate case with the PSC last week, packaged under the title "Value for our Valley," which includes new distribution automation systems, community solar, expanded demand response, and a microgrid-as-a-service program.
The five-year rate plan is a direct response to the PSC’s REV proposal that was issued in April. The REV proceeding calls for New York’s distribution utilities to become distributed system platform providers (DSPPs) that enable systemwide efficiency and resiliency.
The DSPPs will upgrade the distribution network and then “create markets, tariffs and operational systems to enable behind-the-meter resource providers to monetize products and services,” according to the PSC. They will essentially become the purchaser and aggregator for distributed resources.
It will take years to transform utilities into DSPPs. There are various working groups designed to grapple with the difficult issues of building out the platforms themselves and integrating new energy systems at the grid edge to be leveraged in real time.
But the utilities are not sitting idle as these details get figured out. Consolidated Edison, for example, is looking at microgrids, energy efficiency and batteries to delay the construction of a new substation. It has also revamped its demand response program, offering far more money in congested areas where it needs the capacity most.
The plan from Central Hudson also calls for demand response in areas with capacity constraints, as well as a new distribution management system to enable applications such as conservation voltage reduction and fault location isolation and service restoration, or FLISR. The utility, which serves about 300,000 electric customers in the central Hudson Valley a few hours north of New York City, will install a mesh network for its distribution automation applications.
“Some of these proposed programs and investments in infrastructure are largely in response to the Public Service Commission’s REV,” Steven Lant, CEO of Central Hudson, said in a statement.
One of the more forward-looking proposals by Central Hudson is the request to build microgrids for resiliency, both in areas with critical facilities and in remote regions of its territory. The microgrids would be built and operated by the utility, and customers that are serviced by the microgrids would pay a fee on the utility bill.
In PSC testimony on the rate case proposal, Paul Haering, VP of engineering and system operations at Central Hudson, also said that the utility would like to build microgrids in more isolated areas. It already has a generator and islandable microgrid in Frost Valley, a remote region in the utility’s territory. Haering said the microgrid has provided reliable power through more than a dozen storms since 2010.
Central Hudson could be one of the first utilities to grapple with just how much a microgrid is worth, and what, if any, portion of a microgrid that serves community offsets should be rate-based. In Maryland, for example, the state’s PSC found that some portion of public-service microgrids that were owned and operated by utilities could be rate-based. Central Hudson also noted that the technological complexity and fuel source for the microgrids is an open question.
Aside from microgrids, Central Hudson also proposed community solar farms in sizes from 1 megawatt to 3 megawatts. “Under the proposal, customers may elect to purchase energy at a fixed electric supply rate over the period of their purchase agreement,” the utility said. “On a price-per-power-output basis, large-scale solar is less than half the cost of installing rooftop systems, and the locations of these facilities can be selected by Central Hudson to provide optimal support of the local electric grid.”
The $46 million rate plan also calls for upgrades to aging infrastructure and storm-hardening measures. The proposal, which comes after a two-year rate freeze, will raise residential rates by an average of about $4.78 per month. If the plan is approved by the PSC, it will go into effect on July 1, 2015.
Plug-in electric vehicles could be a real threat to future grid stability, overloading neighborhood circuits and causing major problems for utilities. Alternatively, they could be a “killer app” for the grid edge, able to delay charging to avoid local or systemwide peaks or absorbing excess solar and wind power to better integrate it into the grid.
But how are utilities supposed to harness thousands of customers’ EVs as grid assets, when each automaker and EV charging system has its own technology for connecting them to the utility? It would be much better if everyone could agree on a standard set of technologies that utilities could share and that plugged-in cars could receive no matter where they’re charging.
For more than a half-decade, the utility-funded Electric Power Research Institute has been working on this universal technology concept, via pilot projects with individual automakers and utilities. On Tuesday, EPRI announced it is taking this technology platform to the next level, working with eight automakers and fifteen U.S. utilities to connect EVs to a common tech platform.
EPRI’s cross-country demonstration will include Ford Motor Co., General Motors, Chrysler, BMW, Mercedes-Benz, Toyota, Honda and Mitsubishi as EV test partners. On the grid side, mid-Atlantic grid operator PJM will join utilities including Detroit’s DTE Energy, Texas’ CenterPoint Energy, CPS Energy and Austin Energy, California’s big three investor-owned utilities, Chicago’s Commonwealth Edison, federal power entity TVA, Canadian utility Manitoba Hydro, and multi-state utilities Duke Energy, Southern Company and Northeast Utilities.
The broader goal is to show that lots of different vehicles, plugged in anywhere that lacks a networked EV charging system, can be utilized as grid assets, Dave McCreadie, manager of electric vehicle infrastructure and smart grid for Ford Motor Co., said in a recent interview. Today, many of these EVs may not only be inaccessible to grid commands -- the utility may not know that they’re plugged in at all.
Using what’s being called an “OEM central server” platform, EPRI and its partners will be using multiple communications pathways to send signals to plugged-in EVs based on a common set of protocols, he said. Some utilities may use smart meters to communicate to cars via wireless protocols like Wi-Fi or ZigBee, or the HomePlug Green PHY powerline carrier standard, he said. Others may use cellular-network-linked, proprietary on-board systems like GM’s OnStar or Ford’s MyFord Mobile, he said.
“That’s the beauty of this cloud-based platform,” he said. “Even though there’s going to be a wide diversity on the OEM side as far as telematics, we will all end up communicating into this cloud that has a common interface and common APIs. […] This cloud-based solution will be able to reach all these vehicles, so that when the electric grid sends out a message to manage load, a wide spectrum of cars would be able to participate.”
Right now, Japan’s Sumitomo is setting up the OEM central server as a demonstration project, using several commonly accepted technologies to get relatively simple demand response messages to participating vehicles, he said. Those technologies include OpenADR 2.0b, now being used to send demand response data between utilities and customers, and Smart Energy Profile 2.0, a still-developing standard for home energy device communications.
Right now, EPRI and its partners are focusing on sending simple on/off commands to charging EVs, McCreadie said. That’s a lot less problematic than pulling electricity from EV batteries, which could prematurely wear down the battery and imperil vehicle warranties.
While the upcoming pilot will focus on simple demand response messages, “besides demand response, we will also be able to do frequency regulation; we’ll be able to do dynamic pricing,” all using simple on/off charging commands aggregated across lots of vehicles.
“Part of the functionality the central server is designed for is to do this aggregation,” he said. “Any utility that sends out a message, the central server would know how many cars are plugged in for that region, and how to access them for the program.” While this year’s pilot won’t be testing this aggregation capability quite yet, it will be an important focus of the group’s work next year, he said.
About 225,000 plug-in vehicles are on U.S. roads today, representing a tiny fraction of the country's total transportation fleet. But their effects on local grid stability are already being anticipated by utilities in California, the epicenter of EV growth, and in grid-constrained places like Hawaii. Finding a common way to know where these vehicles are, what they're doing, and how they can alter their behavior to help the grid is an important first step to preparing the infrastructure for their broader adoption.
Baltimore Gas & Electric has been involved in voltage conservation for more than four decades. But business as usual was no longer enough after the EmPOWER Maryland initiative was passed in 2008.
EmPOWER Maryland calls for the state's utilities to reduce energy consumption by 15 percent by 2015. As part of the program, the utilities were called upon to implement or accelerate their conservation voltage reduction (CVR) strategies, which involve bringing down and fine-tuning the voltage on circuits to save power.
BGE’s acceleration is still a multi-year endeavor, so it has not yet filed its full plan with the Maryland Public Service Commission. But part of the plan is in place.
The utility, owned by Exelon, has already piloted its house-developed software on six feeders and will expand that to ten to thirteen more later in 2014. Ultimately, it will deploy CVR across its entire distribution territory. The cost of the project and the voltage reduction factor have not been made public ahead of the PSC filing, which is expected soon.
"With approval, Baltimore Gas and Electric's CVR deployment will rival the largest projects in the United States to modernize monitoring and control of voltage and reactive power,” said Ben Kellison, director of grid research at GTM Research, adding that it will join the ranks of other utilities such as Duke's subsidiaries, California's investor-owned utilities, Oklahoma Gas and Electric and Dominion Virginia Power.
“It’s a little new for this space,” Michael Smith, lead engineer with BGE, said of writing software for distribution applications. Previously, most of the technology was deployed back at the substation, but BGE, like other utilities, is increasingly moving intelligence and sensoring onto the circuits and the end of the line.
"Moving sensors and intelligence further into the grid will certainly become a greater asset with time as the growth of distributed solar in BGE's territory will alter feeder characteristics, requiring more granular modeling and control of each phase on a feeder,” said Kellison.Going it alone
For many distribution automation applications, there are scores of vendors offering sophisticated solutions to help utilities meet operational challenges. GTM Research expects the soft grid market to double between now and 2020 to more than $20 billion. The largest portion of that will be grid analytics, including asset management, grid optimization and outage management.
Targeting investment in energy efficiency and distributed energy through new data streams and software is just one of the topics that will be discussed at Greentech Media’s Soft Grid conference in Menlo Park, Calif. on September 10-11. Kellison’s panel will discuss in more detail the merits of distributed and centralized computing platforms for distribution grid applications that enable greater integration of solar, increase efficiency and improve reliability.
Many utilities are rethinking conservation voltage reduction, but BGE has a unique approach. Although BGE is installing smart meters, the meters are not central to delivering the next-generation voltage control, as they are with some other utilities.
For the most part, BGE doesn’t use load tap changers for voltage control. Instead, it has transformer tap changers at the substation and feeder capacitor banks, and has installed additional sensors on its feeders for volt/VAR control.
For the pilot project, BGE developed its own voltage software, since most of the vendors offered solutions tailored for load tap changers. “It’s more of a substation-based algorithm,” said Smith.
The utility worked with Cooper Power Systems and a Yukon capacitor voltage control system that uses BGE’s in-house algorithms to monitor and provide real-time feedback to the volt/VAR application. The voltage reduction comes from operating the capacitor banks so that the average voltage across all sensors is at a minimum. For the approximately 10 percent of the territory that does have load tap changers, BGE is working with OSI.
Smart meters, while not central, are also a part of the package. The advanced metering system is used to confirm the voltage at the end of the line. For the utilities that are using their meters for CVR, many are taking 5- or 15-minute interval data, but BGE found the ideal approach for its software would be to use 1-minute data collection intervals. Smith wrote in an analysis of the pilot that 1-minute data might not be realistic from the AMI system, which was not built with granular voltage data collection in mind.
The utility is looking at a product from its AMI vendor, Silver Spring Networks, that would allow it to receive a report from meters that hit a predetermined voltage sag, rather than constantly pinging meters for voltage reads. “We’re only interested in the bad actors,” said Smith. Otherwise, the utility may use a meter extension that can provide the same information via a cellular backhaul.
As the pilot expands across the entire distribution territory, there will be other tweaks that have to be made. BGE has found that certain devices, such as plasma TVs, use more energy when there’s a reduction in voltage. “We’ll continue to monitor it,” said Smith, adding that the project would not be deployed and then just left to run in the background.
There are already some additional benefits to the software, even though it is barely out of pilot phase. Data analysis showed that “it was not uncommon” for power factors to deviate substantially from the desired range, said Smith.
Once the algorithms are fully deployed and BGE is doing analysis on the whole system, it will be able to correct power factors. The utility also expects to minimize the number of daily operations using voltage regulators and load tap changers.
Working through a full deployment of CVR is a considerable undertaking for BGE, but the engineering team is also looking at other software applications that can support investment planning.
Another project with GRIDiant, for example, evaluates where to put fault circuit indicators based on financial costs and benefits. As the years go on, Smith said BGE would likely add even more projects that shift technology and analytics out of central control and the substation and onto the grid. “We’re just starting to move this out,” he said. “It’s a totally new space.”
For more on how utilities are leveraging data and analytics for planning and operations, join Greentech Media’s Soft Grid conference September 10-11, 2014.
As the energy efficiency industry gets more sophisticated, building owners and managers are increasingly interested in optimizing energy use with new technology and state-of-the-art equipment. It's critical to understand, however, that while next-generation systems can certainly help support energy efficiency initiatives, they are essentially worthless if not properly managed.
I recently compared two buildings from FirstFuel's database of thousands of remote audits: a new LEED-certified structure with all the latest energy-efficiency bells and whistles and an office building from 1971 with dated but well-maintained infrastructure. The assets of the respective buildings hid a deeper truth about how well their energy use was being managed.
The new building, despite having a large solar PV array and natural gas-fired condensing boilers, was wasting thousands of dollars annually due to poor system management. In fact, I found that the building had the potential to save 15 percent of its annual energy costs by making simple operational adjustments. For instance, by turning off lights and computers after the workday, the building operators could save an impressive $3,000 per year.
Not only that, but operators could save an additional $3,650 annually by modifying the sequencing of their brand-new gas boilers. Improving setback scheduling would save an additional $2,600 in gas. Other operational changes involved tweaks to data center cooling, lighting controls, HVAC scheduling control, HVAC boiler sequencing, HVAC boiler plant operation and maintenance, HVAC efficiency testing and air fuel ratio.
The older building, which was operating with much more dated equipment, such as vintage T-8 lighting and a fifteen-year-old gas boiler, required far fewer operational changes. Advanced meter data analytics showed that the building had a faster shutdown time than the newer structure and demonstrated greater alignment between its systems operations.
For example, the ventilation was well tuned with the heating and cooling; the structure had the proper night setbacks; and the building used free cooling from outdoor air. The majority of the building’s real opportunity was in retrofits, as property owners chose to push out capital expenditures for a few years longer by doing the best they could with the equipment they had.
This comparison is not meant to cast blame on property managers who have invested in revolutionary energy equipment. Rather, it serves as a cautionary tale about how even the newest of buildings can consume unnecessary energy. No two buildings are exactly the same, but through innovative analytics solutions that track energy use habits in real time, property managers can gain insight into specific ways in which buildings are wasting energy. With this insight, those managers can easily and effectively take the actions necessary to eliminate unneeded usage and slash utility costs.
By being mindful of how a particular building operates, property managers can determine the best ways to unlock energy efficiency for that structure through easy and free operational changes. If property managers across the nation adopted a similar analytical approach to determine energy savings, just think of the millions we would all save and the climate benefits we would reap.
Domenic Armano is the vice president of client solutions at FirstFuel.
The council is now at more than 100 members from 60 companies and comprises a unique group of thought leaders that represent every aspect of the grid edge landscape. Utilities make up 20 percent of the council, with representation from various markets across the United States, Europe and Australia.
FIGURE: Grid Edge Executive Council Members
The council's first meeting, DG Integration and the Future of the Grid, focused on the challenges and opportunities with integrating higher penetration and distributed generation, not just solar, into the grid.
In March, we brought the council together in Boston for a session on microgrids. Topics included microgrid market dynamics, technologies, deployments, and future opportunities, with members sharing their experiences in assessing and participating in the market today. To close out the meeting, the council identified five game-changers for microgrid market acceleration.
Kicking off the summer with our flagship council meeting before the Grid Edge Live conference in San Diego, council members met for an interactive afternoon discussing the market evolution of the grid edge. We identified the market's key disruptors; technological, regulatory, and financial barriers; and the impact these factors would have on the electricity market.
The council meets eight times per year for four in-person meetings and four web meetings.
To foster collaboration and ongoing communication, the council stays in touch between in-person gatherings via web meetings. The council convened online in February for a business-oriented web meeting on the topic of cybersecurity, and again in May for a data-driven web meeting on the state and future of U.S. distributed solar.
The council will next meet in person on Tuesday, September 9 prior to Soft Grid 2014 on the topic of grid edge analytics, and again in December prior to Solar Market Insight 2014 for what is sure to be an animated meeting on next-generation business models and the utility of the future.
GTM Research is the backbone of the council, driving much of the content and discussions. Members have exclusive access to the grid analysts and their reports. Recent publications include Distributed Energy 2014, Advanced Grid Power Electronics for High Penetration PV Integration, and North American Microgrids 2014.
Council members should be on the lookout for reports on distributed energy resource management systems and the demand response market later this summer.
Allison Junkins is the program manager for GTM Research's Grid Edge Executive Council. She is the primary coordinator for council events and meetings and the bridge between the GTM Research analyst team and council members.
To learn more about the Grid Edge Executive Council, download the brochure here or contact Tate Ishimuro at email@example.com
California may have the world’s biggest grid-scale energy storage mandate -- but Canada’s Ontario province may have the world’s most varied one.
Last week, Ontario’s Independent Electricity System Operator (IESO) announced it had awarded five companies a total of 34 megawatts of energy storage projects. Winning projects include some large-scale batteries, similar to projects underway in California, New York, Hawaii and other states with energy storage mandates or incentives. But the awards also include flywheels, thermal energy storage, and what's described as North America’s first large-scale hydrogen energy storage project.
The projects are expected to cost about $14 million per year, or about $42 million over a three-year period, and are the first to be awarded under a broader mandate to bring 50 megawatts to the province by the end of 2014. IESO highlighted that it considers this cost "very competitive relative to comparable storage projects," but didn't break out the costs by individual project.
The participants will be required to provide one of two types of fast-reacting ancillary services for IESO. The first is frequency regulation, a service being provided by batteries, backup generators, variable loads and other non-traditional resources for grid operators like mid-Atlantic PJM.
The second is providing voltage control and reactive power support, a service that’s becoming increasingly important for Ontario and other regions with lots of intermittent wind and solar power to integrate into the grid.
These are different needs than those served by Ontario’s existing 170-megawatt pumped hydro storage system in Niagara, which pumps water with cheap off-peak energy and uses it to generate power during peak demand hours. IESO has already procured a small amount of faster-reacting energy storage, including a project developed by NRStor that has connected 2 megawatts of flywheels from Ontario-based Temporal Power to the province’s grid. Another 4-megawatt energy storage project being developed by Montreal-based Renewable Energy Systems Canada is expected to come on-line this year.
But IESO's new projects are part of a broader push to test out multiple technologies, and could provide important insight into how such different technologies compare to one another in terms of cost and effectiveness -- or, perhaps, can be combined in ways that add up to more than the sum of their parts. Here’s a breakdown of IESO’s selected projects (PDF), along with details on individual projects of note.
- 2 megawatts of hydrogen-based storage from Hydrogenics Corp., a Mississauga, Ontario maker of hydrogen-fueled PEM fuel cells, along with a hydrogen generator technology to turn water into hydrogen through electrolysis, thus creating an energy storage component. Hydrogenics joined German mega-utility E.ON in a 2-megawatt facility that came on-line last year, giving it a reference project to prove its technical capabilities. Its Ontario project will be carried out in partnership with natural gas giant Enbridge, which will jointly develop, build and operate the energy storage facility to provide regulation services to the IESO under contract. CEO Daryl Wilson said in last week’s press release that the new project, set for the greater Toronto area, will be the first of its kind in North America.
- 740 kilowatts of thermal energy storage from Dimplex North America Ltd., North America’s largest maker of electric heaters and equipment. Thermal energy storage involves getting water heaters and other electrical heating loads -- as well as air conditioners, refrigerators and electric-based cooling loads -- to alter their electricity consumption patterns to meet grid needs. That can include pre-heating and pre-cooling buildings or facilities to reduce peak power, or using faster-acting services, aggregating lots of thermal loads that can be switched on and off quickly. Dimplex is no stranger to grid integration -- it’s one of the partners in the wind-balancing PowerShift Atlantic project in Canada’s Maritime provinces.
- 12 megawatts of both batteries and flywheels from Convergent Energy + Power, a project developer highlighted in last year’s energy storage report from GTM Research. The New York-based company has partnerships with multi-billion-dollar real estate developer and manager Fisher Brothers and contractor Plaza Construction, and has a battery supply agreement with Eos Energy, a startup promising a zinc-air battery that can store hours of energy, something that’s hard for solid-state batteries to manage today. Convergent’s website cites the company's focus on “4- to 6-hour energy storage assets in high-value locations.” That’s a totally different realm of grid service than the fast-acting frequency regulation and voltage support that IESO is calling for. It’s possible that Convergent is putting fast-reacting flywheels together with batteries that offer longer-duration energy capacity, although the company didn’t provide any details on which batteries it was planning to use for its Ontario project.
- 14.8 megawatts of battery energy storage from Hecate Energy, a Nashville, Tenn.-based energy project, and 4 megawatts of battery energy storage from Canadian Solar Solutions, a North American subsidiary of Chinese solar PV company Canadian Solar, round out the project list. IESO’s announcement didn’t include details on what types of batteries would be used by both project developers, but it did note that it was considering a wide range of technologies, including flow batteries, as well as traditional closed electrochemical batteries. IESO’s new storage projects will include high-voltage transmission and distribution grid-connected system, though it didn’t clarify which projects would fit in each category. Ontario Power Generation, the public utility that generates about 60 percent of the province’s electricity, plans later this year to procure the remaining 16 megawatts or so required to meet the province’s 50-megawatt mandate.
Unofficially, it's another story.
These market-leading firms make their money with residential solar leases and power-purchase agreements (PPAs). And business is pretty good (see SolarCity's recent securitization).
Third-party ownership (TPO) remains the dominant model for financing a residential solar installation in the U.S., but that's changing. Direct ownership via loans and other mechanisms like PACE are gaining traction, because PV systems continue to get cheaper while financing options continue to improve.
If customers are moving toward loans, surely SolarCity, Sunrun and Vivint will as well.
Recently we reported that SolarCity, the leading residential solar installer and financier, would soon unveil a loan product, according to sources close to the firm. The program was to be open to applicants with FICO scores of 650 and higher with a 30-year option. The loan program was to be tested in a limited market to begin with, in order to better understand and codify the sales process.
And now SolarCity's 30-year loan product has been spotted in the wild by one of our sources. (They are everywhere.) "It looks like a hybrid PPA-loan," according to our contact, who called it "confusing" and "expensive."
GTM has also learned that SolarCity has started a pilot loan program in TPO-unfriendly Colorado and is financing the loans off its balance sheet.
Additionally, our contacts note that SunEdison's 20-year loan includes equipment but has an expensive dealer fee. Both the SolarCity and SunEdison loans are unsecured and have a relatively low rate of 4.5 percent to 6.5 percent, according to our sources.
Neither SolarCity nor Vivint offered an official comment in response to GTM's request.
Some detail about Sunrun's loan hopes can be found online, including a listing for a product manager position that will "develop and manage product financing offerings which will include secured and unsecured loans." Sunrun's Andrew Pontti notes, "We currently don't offer a loans, but we follow the consumer financing landscape closely and appreciate financial innovation that helps more homeowners go solar. Our view is that there will likely be a robust market for other financing methods over time, and their success will be determined by consumer interest."
A financial industry contact says that there are two products that are doing well in the market, both unsecured:
Our contact notes that unsecured loans are the dominant choice in the market.
In June, SunPower partnered with Admirals Bank on a $200 million loan program for residential solar installations over the next two years. Clean Power Finance and Sungevity are also in the loan business, and Kilowatt Financial, Sungage and Mosaic are moving into the solar loan transaction business. Look for NRG to enter the fray as well.
Nicole Litvak, a solar analyst at GTM Research, just authored a report on this topic, U.S. Residential Solar Financing 2014-2018. (For more information on the report, click here or contact Matt Casey at Casey@gtmresearch.com.) GTM Research is forecasting third-party ownership to peak at 68 percent of the residential PV market this year.
Litvak notes that a few banks, such as Admirals Bank and EnerBank, provide solar-specific bank loans with interest rates "typically between 5 percent and 10 percent depending on term (five to twenty years) and FICO score."
GTM's Matthias Krause reports that Mosaic will allow homeowners to take out a 20-year solar loan with no down payment and a 4.99 percent interest rate. "The loan is bundled with residential operations and maintenance services provided by Enphase along with its microinverters," according to the article. Mosaic's Billy Parish hopes that higher-quality loans will help the securitization process. "In Mosaic's experience, lenders and investors have historically viewed solar loans as riskier than leases because there is no assurance that the system will continue to produce energy after installation."
"According to an online survey of 1,031 California homeowners that was conducted by Mosaic in April, around 60 percent of respondents would prefer to own a residential rooftop system rather than lease it, assuming that savings and performance are similar. And, more importantly, among the 26 percent who still favor leases, more than half would choose a loan instead if a warranty was included," writes Krause.
GTM Research expects the U.S. residential PV market to exceed 1 gigawatt for the first time in 2014.
Last month, GTM Research published its latest report on residential solar along with an update on the leaders and trends in the industry landscape:
Market data is from the recently released report U.S. Residential Solar Financing 2014-2018. For more information on the report, see this page or contact Matt Casey at Casey@gtmresearch.com.
When it comes to resiliency, utilities are taking many different paths. Some are raising substations to protect them from flooding. Others are replacing wood utility poles with metal ones, and others still are investing in state-of-the-art software and hardware that allows the grid to automatically isolate faults.
The U.S. Department of Homeland Security, however, has other ideas about what a resilient grid might look like. As part of its aptly named Resilient Electric Grid, or REG, project, DHS is giving $60 million to AMSC (NSDQ: AMSC) and Commonwealth Edison to install a high-temperature superconductor cable to increase the resilience of ComEd’s system in Chicago.
The project will be both the first commercial application of a superconductor cable for resiliency in the U.S., and, at more than 3 miles long, the largest project of this type in the world. The cables will connect critical substations in the Chicago’s downtown business district.
“We view this project as a natural extension of the infrastructure improvements and technological upgrades that have been underway for the past two years as we develop and deploy the smart grid,” Anne Pramaggiore, president and CEO of ComEd, said in a statement.
So far, DHS has only put in $1.5 million for the first phase, which involves taking a draft scope of the work and turning it into a detailed implementation plan over the next six to nine months. Years before Sandy, DHS began looking at the reliability of urban grids in the wake of the September 11 attacks and the 2003 blackout, and the agency has plans to install up to three pilot projects.
“We’re trying to bring inherent reliability to the whole system,” said Daniel McGahn, president and CEO of AMSC. “The magic happens in the wire.”
Instead of building in redundancy, such as additional substations, the superconductor cable will provide enhanced capacity and reliability. The high-energy-density wire, which can carry about ten times the power of traditional cable, can automatically contain faults within the wire. The cables conduct electricity with near zero resistance at -320°F, compared to -460°F for traditional superconductor cables.
Superconductor cable projects have popped up worldwide in the past five years or so, but so far, they have yet to take off for grid applications. LS Cable and AMSC are working together in South Korea with KEPCO on a HVDC superconductor cable. In Germany, Nexans is replacing a high-voltage cable with a superconductor cable less than a mile long.
“Utilities around the world are investing tens of billions of dollars on smart grid technology designed in part to create a more redundant and resilient grid,” said McGahn. “We believe that the Resilient Electric Grid system, which is enabled by AMSC’s unique high-temperature superconductor technology, has the potential to play a significant role in protecting the infrastructure assets so vital to our electrical systems.”
McGahn describes the wires as a sandwich with a series of ceramics between an outer metal packaging. If a fault occurs as the power runs through the superconductor, the electrical path is moved to the outer metal, which acts as a resistor and quenches the fault before returning it to the system. “It’s a much more elegant solution” compared to other hardware and software solutions for fault protection, said McGahn. “But our competition isn’t FLISR or copper cables,” he added. “It’s [the prospect of] building another substation.”
Besides fault restoration, the wires can also carry more capacity than traditional wires so they could be used to deal with capacity constraints in certain parts of the grid if one substation does not have enough power to supply the neighborhoods it serves. As with energy-efficiency measures to defer substation upgrades, the appeal of superconductor cables is their ability to more fully leverage the capacity already on the grid.
The full project is expected to take about 3 1/2 years in Chicago, according to AMSC, although the company expects future deployments to move more quickly.
Sunrun, the No. 2 residential solar financier, named Michael Grasso as Chief Marketing Officer. Most recently, Grasso served as CMO of TXU Energy, the competitive retail electricity firm. Prior to TXU Energy, Grasso served as senior VP of brand management at USAA, the financial services provider. Sunrun also appointed Cameron Kinloch, formerly with Box and Netflix, as VP of financial planning & analysis. Antonio Cintra was appointed VP of distribution. Cintra was previously with Philips and United Technologies.
Anne Smart, the executive director of The Alliance for Solar Choice, a group formed by downstream solar players to preserve net energy metering, is moving to ChargePoint as director of government relations. A successor has not been named at TASC.
SolarBridge Technologies, which develops microinverters for integration with solar modules, named Mark Sandoval, formerly an executive at Intel, SunPower and Bloom, as executive VP of global strategy.
SkyFuel, a maker of solar parabolic trough systems used for electricity generation and industrial steam applications, promoted Kelly Beninga to the role of president from his previous position as the company's chief commercial officer.
Matt Cheney joined enACT Systems as executive chairman and board member. The company is developing a solar software sales platform. Cheney was the founder and CEO of MMA Renewable Ventures, an early U.S.-based solar independent power producer; he also serves on the board of ACORE and the Solar Electric Power Association.