Harvey’s swath of destruction along the gulf coast regions of Texas and Louisiana has taken 46 lives as of Friday afternoon, and left tens of thousands stranded and homeless amidst record-breaking flood waters. The physical destruction has also left hundreds of thousands without power, perhaps for a week or more, as rescuers concentrate on saving lives.
Our hearts go out to those grieving and displaced by Harvey and its aftermath. At Greentech Media, we’ve been covering the storm’s effects on the power grid, with an eye on how distributed energy resources (DERs), in the form of grid resiliency systems and microgrids, are performing through the crisis. We’ve also tracked the developing emergency at the Arkema chemical storage site in Crosby, Texas, and how the failure of backup power systems can be hazardous to health -- particularly in a flood-prone region home to about one-third of the country’s refineries and nearly half its petrochemical plants.
We've also discussed the painful policy decisions forced by Harvey upon utilities, grid operators and regulators to address the issue of grid resiliency. This term stands in for the the assets, capabilities, and structures meant to keep the grid up and running amidst extreme weather, defend it against physical or cyber attacks, and get it restarted after widespread blackouts. This set of values can’t fully be quantified in terms of kilowatt-hours of electricity sold or megawatts of capacity provided. Usually investments in resiliency are tied up in overall grid investment and operations costs for utilities, or expressed through specialized markets at the grid operator level.
In the past decade, a series of storms has supercharged investment and R&D into grid resiliency, from the post-Sandy work in New York, New England and mid-Atlantic states, to the floodgates and centralized cogen system that has kept Houston’s biggest hospital running throughout Harvey's destruction. But for utilities, regulators and customers across the country, the challenge remains linking the here-and-now costs of preparing for disaster to the unlikely, yet devastating, costs of failing to prepare.
NREL: Smart solar inverters can help Hawaii’s grid today -- at a minimal cost
The natural resiliency provided by a grid that’s more distributed depends very much on how DERs are integrated with the grid, starting with technical details like grid interconnection regulations. For starters, under IEEE 1547, the vast majority of rooftop solar systems aren’t allowed to keep running when the grid goes down. Instead, their inverters are set to a standard safe range of grid frequencies and voltages, and they must trip off if the grid exceeds those boundaries.
But an increasing number of key solar markets are requiring "smart" solar inverters to serve a broader set of tasks, including low-voltage ride-through capability -- limiting trip-offs during momentary voltage “blips” to avoid making a minor grid problem much worse. And in a few high-penetration PV markets, utilities and researchers are testing more active countermeasures.
The Department of Energy’s National Renewable Energy Laboratory (NREL) has been spending a good deal of time studying how smart inverters can help mitigate the imbalances that can come with high-penetration solar PV -- or even do part of the grid-balancing job normally done by utility or grid operator-controlled assets.
Some of the most interesting work has been going on in Hawaii, where projects involving Hawaiian Electric (HECO), SolarCity and other parties are showing that smart inverter functionality at customer-owned solar sites could allow it to double the amount of PV installed on heavily impacted circuits.
This week, NREL released two reports on the subject, including one (PDF) that represents “the first known study to quantify the impacts of inverter-based voltage regulation using detailed annual simulations of full real-world feeder models including entire distribution secondary circuits.” In other words, it has digitized data on Hawaiian grids down to the lines that serve individual homes, taken the near-term projections for solar PV penetration on these lines, and then run it all through a simulation that includes different inverter settings as a variable in voltage regulation -- keeping voltages low for efficiency’s sake, but within minimum operating boundaries to maintain stability.
The report examines the use of advanced inverters that can ride through voltage disturbances first (they can’t help if they’re off), and then adapt their output to support grid voltage. It found that according to the latest near-term projections, advanced inverters actually helped with voltage control, by increasing their reactive power output, which “resulted in a lower feeder demand for reactive power.”
It also found that most inverters could do this automatically without reducing too much of the real power they’re paid for. For 95 percent of the customers, annual energy curtailments would add up to less than half a percent of their overall solar output. But the costs rose, albeit by “less than 5 percent,” for the final 5 percent of customers -- presumably those at the nexus of whatever grid problems they were being asked to help solve.
That’s an important finding, addressing the fear of solar companies that turning on features that tap a smart inverter’s reactive power capacities could reduce real power output. It also underscores the fact that Hawaii’s solar inverter fleet could already be helping the utility manage the grid disruptions it’s facing as it moves toward its goal of 100 percent renewables by 2045. This is a complicated task, as demonstrated by HECO’s final grid modernization plan released this week, in a form unchanged from its draft report in June.
California faces summer peaks under Aliso Canyon shutdown constraints
Solar PV alone can meet a portion of a home or business' electricity needs. But it can’t keep big motors spinning, or pumps running, or carry other big loads without some form of steady power output. That’s usually a diesel or natural-gas-fired generator, but batteries are starting to take up a sliver of the home backup power market, and are making their appearance in commercial and industrial settings as well, beyond their traditional role as emergency ride-through.
The key metric for any microgrid is how much energy it can provide for how long. In this regard, batteries have some clear limits compared to diesel generators, which can run as long as there’s fuel, and natural-gas generators, which can run as long as gas pipelines are intact -- as they’ve been doing so far in parts of Texas affected by Harvey’s flooding. But that may not be the case after an earthquake in California.
This summer, California faces a manmade natural-gas shortage in the form of the Aliso Canyon shutdown. The massive Southern California gas injection and storage site was closed late last year, after months of leaking methane forced nearby residents to evacuate and sent several to the hospital. While the site has been reopened on a very limited scale, Gov. Jerry Brown, who gave the site state emergency status in January, has since called for its permanent closure.
This weekend is expected to be the hottest so far this summer, and California grid operator CAISO is preparing for a shortage of gas, as well as power, that would be necessary to keep air conditioners running at peak loads. In response, CAISO issued a “flex alert” asking customers to conserve energy on Friday afternoon and evening, by “turning off all unnecessary lights, using major appliances before 1 p.m. and after 10 p.m., and setting air conditioners to 78 degrees or higher.”
In the meantime, CAISO and Southern California Gas are “following the processes established to manage gas supply in the L.A. Basin during the limitations placed on the Aliso Canyon natural gas storage facility,” it wrote.
The DER response to Aliso Canyon is a testament to how quickly distributed energy can be enlisted to support grid resiliency. Southern California Edison was able to bring more than 70 megawatts of energy storage from Tesla, Greensmith Energy and AES Energy Storage on-line within six months. Whether it will be needed this weekend is unclear, since CAISO reported that the “generation fleet has performed well so far during this prolonged heat wave without any major outages.”
This weekend’s heat wave will reliably enlist another source of behind-the-meter energy flexibility -- tens of thousands of thermostats, quietly adjusting temperature and timing to shave percentage points from each customers’ electricity and gas usage, and aggregating it to megawatt scale. This subtle form of grid resource is being provided by a number of startups, including one with a larger-than-usual share, OhmConnect.
Nest's new thermostat
Nest is also demonstrating that behind-the-meter assets can serve as a grid resource. Last fall, the smart thermostat, smoke detector and security webcam company announced its own Aliso Canyon contract, a deal to tap up to 50,000 of its customers’ thermostats to provide load reduction for Southern California Edison. Since then, it’s managed its existing “fleet” of thermostats to engage customers in power-saving programs for SCE and Southern California Gas, it has showed it can save energy in the winter, and it is now in the midst of its first big summer test.
Nest has long reported that its thermostats can shave an average of 10 to 12 percent off a customer’s energy bills, all without the knowledge of the owners. About 750,000 people were able to participate in a special “Solar Eclipse Rush Hour” event during the solar eclipse, reducing energy demand by 700 megawatts during that period.
This week, Nest released its latest thermostat, the Nest E. Besides looking less like an iPod and more like a thermostat, the Nest E is mainly distinguishable by its price, $169 instead of $249. But Wired reports that the new device is “functionally identical” to the old version, albeit in a package designed to get users to notice it less, not more -- a nod to the company’s insistence that it doesn’t want to ask anything of its customers.
At the same time, Nest has gotten its customers engaged in public opportunities for energy saving, as with its 700,000-home solar eclipse promotion asking customers located in the path of the shade of the passing moon to use less energy while it passed. Utility rebates can also help make up a significant portion of a Nest’s upfront cost, with 55 percent of homes, or about 64 million, open to qualify for a rebate or reward on its latest model. It’s an incentive not just for the customer, but for Nest to get more actively engaged in customers’ financial and behavioral relationship to energy.
CPUC sets time-of-use hours, solar advocates cry foul
Weeks ago we covered the issue of San Diego Gas & Electric’s proposal for implementing time-of-use (TOU) rates, and how solar advocates were protesting a last-minute CPUC decision to allow peak hours to start at 4 p.m., not 5 p.m. The Solar Energy Industries Association, CALSEIA and others said the change, which went against the CPUC’s own methodology for TOU, would steepen the already significant drop in value under rate plans that shift the value of net-metered solar into later and later evening hours.
Last week, the CPUC went ahead and approved SDG&E’s plan despite these concerns. “During hot summer months, our peak period during late afternoons has also changed significantly. The best evidence shows that the optimum time to avoid using electricity is now from 4 to 9 p.m.,” CPUC President Michael Picker, the commissioner assigned to the proceeding, wrote in a statement.
But solar advocates are crying foul. “The Commission has decided not to apply its new TOU methodology in this rate case,” said Brad Heavner, policy director for the California Solar Energy Industries Association (CALSEIA), wrote in a statement. “It is shocking that the Commission purposefully avoided considering data that was solidly on the record.”
Solar parties are demanding a “more thorough analysis of data in the forthcoming TOU decisions for SCE and PG&E,” which are much bigger utilities with a much greater potential impact from upcoming TOU brackets. Here’s a link to a redlined copy of the decision (PDF), showing how it changed between earlier and final version.
Xcel Energy and Colorado PUC look at gigawatts of wind, solar and “natural gas and/or storage”
We’ve been covering state-by-state developments in replacing financially struggling nuclear and coal power plants with either rate hikes to customers, as with Duke Energy’s proposal to manage the wind-down of its Lee nuclear project in North Carolina, or with greener alternatives, like Duke Energy Florida's $6 billion plan for solar, energy storage and EVs.
Another big deal to add to this week’s list is Xcel Energy’s agreement in Colorado with energy, industry, environmental and consumer groups. Under the deal awaiting approval by the Colorado Public Utilities Commission, the plan could lead to $2.5 billion in clean energy investments to replace 660 megawatts of coal-fired power that will be retired earlier than first scheduled -- 2022 and 2025, respectively.
To help replace it, Xcel would issue RFPs for up to 1,000 megawatts of wind, up to 700 megawatts of solar, and up to 700 megawatts of “natural gas and/or storage” -- a nod to the potential to replace flexible gas-fired power plants with batteries, thermal energy storage or other resources. But Xcel also wants a piece of the action, with “utility ownership targets of 50 percent renewable generation resources and 75 percent of natural-gas-fired, storage, or renewable with storage generation resources in the portfolio.”
Utility vs. third-party EV charging debate heats up in Oregon
In December, Portland General Electric (PGE) and PacifiCorp subsidiary Pacific Power submitted their Transportation Electrification Plans to the Public Utility Commission of Oregon. It called for PGE to invest $2.6 million for six charging pods in downtown Portland, and for PacifiCorp to spend $1.85 million for up to seven charging pods.
But independent EV charging technology and platform provider ChargePoint doesn’t like the proposals, saying they “will dampen innovation, competition, and customer choice in EV charging services and equipment.” The Campbell, Calif.-based startup, which has raised $279 million to date, has made similar complaints about utility EV infrastructure plans in its home state, largely based on their lack of open third-party access to the technology platforms that will be connecting EV chargers in their territories.
Odds and ends: PJM examined summer-only demand response options, Tantalus buys Energate
Speaking of summer peak, mid-Atlantic grid operator PJM is looking at ways that its new seasonal capacity rules could be augmented to keep its key summer-only demand response resources in the market. Stakeholders at PJM's Markets and Reliability Committee meeting on August 24 endorsed the creation of a new senior task force to study how summer-only demand response may be valued within the PJM marketplace outside of the capacity market.
PJM fully switched to a seasonal capacity market this year, moving away from a decade-old structure that rewarded power plants, demand response assets, and other must-deliver resources for being there during hot summer peaks. Instead, PJM has broken the market into winter and summer peaks -- and just as demand response and renewables industry groups predicted, it found a shortage of winter resources, and had to turn many summer resources away.
And in a smart grid-smart home acquisition note, Canadian smart metering and distribution grid equipment and networking provider Tantalus Systems bought Energate, another Canadian company offering smart thermostats and “interactive demand management solutions” to engage customers in energy management. “The acquisition expands Tantalus’ smart grid application portfolio to include a comprehensive solution which empowers utilities and energy service providers to control load at the edge of the distribution network.”
