It’s been a busy week at the grid edge. In California alone, we’ve seen the state’s premiere behind-the-meter battery program hit capacity, a rare emergency alert for demand response, and a conflict brewing between Southern California Edison and solar advocates over its grid modernization plans.
Across the country, the Federal Energy Regulatory Commission (FERC) held a high-profile workshop this week on the daunting task of how to balance state policies with carbon-reduction goals and the fair operation of interstate energy markets. Plus, we saw corporate news from Itron, Landis+Gyr and ABB.
Here's this week's grid edge news.
SGIP tapped out for 2017
Let’s start with the Self-Generation Incentive Program (SGIP) -- the country’s single biggest energy storage incentive -- which announced this week that last week’s Step 1 application has already yielded enough storage projects to close out its large-scale storage categories across the state’s big three investor-owned utilities. In fact, with oversubscription for these categories, as well as small-scale storage for Southern California Gas and San Diego Gas & Electric’s program administrator, the state is now turning to a lottery to determine who gets money and who doesn’t.
“A lottery and Pause Period is triggered in the event that applications submitted on a single day exceed funds available for a given budget and step,” the California Public Utilities Commission announced this week. “Applicants and Host Customers will receive a notification of the lottery results for their application when the lottery results are finalized.” Julian Spector gives you the deep dive in this week’s Storage+ column, and explains just how big of a deal SGIP is for the country's energy storage providers.
SCE’s grid mod plan draws solar fire
We’ve seen quite a bit of utility-solar conflict in California over time-of-use rates and net metering. Now the solar industry is taking aim at utility grid investment plans -- specifically, Southern California Edison’s multibillion-dollar grid modernization plan.
This week, the Solar Energy Industries Association (SEIA) and Vote Solar filed testimony with the CPUC in advance of public hearings on the rate case to be held next week. In simple terms, solar advocates worry that SCE wants to spend too much on old-fashioned infrastructure, mainly by overestimating the negative effects of distributed energy on its grid.
”SCE is underestimating the positive and exaggerating the negative impact of distributed energy,” Sean Gallagher, SEIA's Vice President of State Affairs, wrote in a statement this week. These underlying assumptions have led to a distribution grid investment plan that includes more than a billion dollars in grid reinforcements, while failing to consider the ways that rooftop solar -- combined with batteries, smart inverters, demand response and other distributed balancing agents -- could help avoid expensive grid upgrades.
“Edison’s proposal is extremely costly and would not take full advantage of distributed energy resources to limit costs to ratepayers, the worst of both worlds for Californians in its territory,” Gallagher wrote. “It’s important for the commission to get this right, because grid modernization investments will continue to be a significant part of future utility rate cases in California.” Specifically, the CPUC’s distribution resource plan (DRP) and integrated distributed energy resources (IDER) proceedings are asking utilities to create values for DERs as part of their distribution grid investment plans.
CAISO's first-in-a-decade DR event
On Wednesday, state grid operator CAISO did something it hasn’t done since 2007 -- issued a Stage 1 emergency across the state to cover a shortfall in its energy reserves. “That sounds a lot worse than what it is,” CAISO spokesperson Steven Greenlee explained in a call the day after. Still, it represented a rare instance in which old-fashioned interruptible demand response showed that it’s worthwhile, even if it otherwise sits around idle most of the time.
“What we saw yesterday evening at 7 p.m. is that we were unable to maintain our operating reserve,” he said. “The issues that contributed to that capacity deficiency is that our load was about 2,000 megawatts above forecast,” due to a hotter-than-expected day driving up air conditioner electricity demand. This added an unexpected bump to the peak of about 35,800 megawatts CAISO was expecting, and because CAISO procures in day-ahead markets, it found itself facing a day-of shortfall.
On top of that, “we had about 1,100 megawatts of expected energy that became unavailable to us -- [due to] plant outages and imports that we had expected had not materialized,” he said. “We will have to look into that, to see what occurred there.”
But what really drove the 7 p.m. emergency call -- and what differentiates this week’s call from its last one in 2007 -- was the ramp-down in solar generation starting in the late afternoon, he said. “Solar ramps quicker, and in this particular case it was ramping down quick. Again, according to the criteria of the Stage 1, we were dipping into our reserves and forecasted additional dipping into our reserves.”
In response, the state’s three IOUs turned around and activated more than 800 megawatts of rarely called-upon reliability demand response -- largely industrial and commercial customers that have been paid in advance to shut down.
“We needed it -- we would have never have called it if we couldn’t use it,” Greenlee said. “That got us through until the market started balancing itself out” around 9 p.m., and prevented the need to call a Stage 2 emergency, a much bigger deal that can call on utility “interruptible” programs to shut down commercial and industrial customers who receive a lower electricity rate in exchange for this eventuality.
California's grid can expect to see continued imbalances of this nature as solar grows. This week's DR call is a more traditional, though more time-sensitive, challenge, at least compared to the more novel challenge of creating incentives for customers to consume more energy to deal with the excess wind and solar that have forced CAISO to issue curtailments this spring, he noted. But both are centered on solar power’s increasing share of the state’s energy mix, and its duck-shaped influences on grid supply-demand balance.
At FERC, a clash over state energy policies and market pricing
The role of the federal government in state green energy policies was recently thrust into the limelight with Energy Secretary Rick Perry’s expression of interest in federal pre-emption of state energy policies to support baseload power. But the nitty-gritty work of balancing state renewable and carbon policies with fair operation of interstate energy markets was being done earlier this week, at a two-day technical conference hosted by the Federal Energy Regulatory Commission.
FERC heard from state regulators and independent system operators (ISO), as well as the power plant owners who are complaining that state incentives are distorting the market. The latest complaints are over zero emissions credits being given to nuclear power plants by New York and other states. Though generators have long complained that alternatives such as demand response and preferred wind and solar power are unfairly privileged over traditional, fossil-fuel-fired power plants.
One of the terms being tossed around with some abandon during the two-day session was MOPR, or minimum offer price rule -- a set of regulations that set minimum prices on market participants to avoid manipulation. Several of the ideas put forward at the conference included using a MOPR to deal with low-price, zero-marginal cost clean energy resources. But there are important differences between the options put forward by regulators who use the term.
The five scenarios discussed “range from do nothing on one end, to the other end of the spectrum -- let’s apply the MOPR to everything,” Michael Panfil, director of federal energy policy for the Environmental Defense Fund, told me this week. His organization is getting behind a “limited MOPR," one that's within the bounds of what it was designed to do (i.e., provide a pricing floor to address a market imbalance).
The “expanded MOPR,” by contrast, would be a MOPR that goes beyond the bounds of what it was designed to do, according to Panfil. "I think you heard the commission being skeptical about that offer.” The problem is that rules designed to prevent market manipulation aren’t the right tools to guide energy policy, he said.
Instead, EDF would like to see FERC take an approach that includes other big market forces, such as cheap natural gas, plentiful reserve capacity in the eastern U.S., and the tangible benefits of more efficient use of energy at the customer level. "There’s a larger forest, and that forest includes things like oversupply, or the way these wholesale markets have been designed," Panfil said.
As for where FERC takes things next, “that’s the million-dollar question.” Right now FERC lacks a quorum to make rulings, with only two commissioners, acting chairwoman Cheryl LaFleur and Colette D. Honorable, and Honorable is expected to step down in June. “But you will see action at the ISOs,” Panfil said. PJM put forward two proposals on the second day of the conference, and ISO New England talked at some length about proposed approaches, such as a two-tier auction for clean energy.
Corporate moves: Itron’s quarterly beat, Toshiba’s Landis+Gyr target for buyouts, ABB’s grid-to-cloud package
In corporate news, smart metering giant Itron is seeing light at the end of the financial tunnel. The Liberty Lake, Wash.-based company reported first-quarter 2017 results this week, with revenues of $477.6 million beating market forecasts of about $470 million. Itron's electricity segment, where the company has undergone an effort to drop less profitable legacy product lines and focus on its next-generation Riva platform, saw stronger than expected sales of $238.8 million, up nearly 10 percent from the previous year. Operating expenses also fell, showing results of Itron’s years-long cost saving initiatives.
Toshiba, the energy giant that’s facing bankruptcy of its Westinghouse nuclear power business, is now facing buyout attempts aimed at its smart grid subsidiary Landis+Gyr. According to Reuters, which cited unnamed sources, rival Japanese industrial giant Hitachi and buyout group CVC both recently sought to acquire the Swiss-based metering giant for almost $2 billion -- a little less than what Toshiba paid for it in 2011. These offers were rebuffed, but Toshiba is said to be open to tentative offers under a May 22 deadline.
Swiss grid giant ABB had some more positive news to report, with the launch of its Ability suite of cloud-based software connected smart circuit breaker platform -- Electrical Distribution Control System. It’s a remote supervision and diagnostics platform for ABB’s circuit breaker, which come with sensing and connectivity nowadays that can be quite useful for grid operations. From a business perspective, it’s one of the small but growing number of offerings from big distribution management system (DMS) vendors like ABB into the Internet of things, such as it is.
The utility death spiral research files
Finally, reminiscent of debates over the utility death spiral, Accenture's annual Digitally Enabled Grid research report found that distributed generation (DG) “poses the single greatest risk of lost revenues to utilities’ business.” Utilities surveyed reported significant fears over the impact of rooftop solar today, and potentially energy storage, electric vehicles and net-zero energy buildings in the future. On their grid operations side, concerns were raised about a rapid rise in grid faults to “fears of soon exhausting their DG hosting capacity entirely.” The report concludes that new models, technologies and smart grid solutions are required to drive much-needed new revenue during a period of tremendous change.
