by Jeff St. John
October 17, 2017

We hope you’re not tired of reading about Energy Secretary Rick Perry’s contentious NOPR asking FERC to provide cost recovery for stockpiling coal and nuclear fuel, because last week brought some important additions to the debate over how to foster a secure, resilient and flexible grid. 

Adding the f-word to the reliability and resiliency lexicon

The DOE’s notice of proposed rulemaking has seen nearly as much criticism about what it lacks as what it contains. We’ve already covered how July’s DOE grid reliability report, ordered by Perry to investigate the coal and nuclear-retirements-equals-grid-vulnerability hypothesis, failed to mention how renewable energy, energy storage, demand response and other technologies could play a role in keeping the grid safe from big storms, cyberattacks and other threats. 

Last week, research group Energy Innovation published a report that fills out what’s missing from the policy side, including a critical term that’s absent from the NOPR’s text filed with the Federal Registry last week (save for reference to federal legislation): flexibility. 

The biggest problem facing utilities and grid operators today isn’t the retirement of coal and nuclear plants; it’s managing ”the unpredictable variations in supply associated with higher penetrations of variable resources,” authors Robbie Orvis and Sonia Aggarwal write. That includes distributed energy resources like rooftop solar that are largely invisible to grid operators. 

But technology has also given independent system operators (ISOs) and utilities the tools to harness the flexibility of these resources, from electric water heaters and smart thermostats to plug-in electric vehicles and behind-the-meter batteries, they write. Unfortunately, “Flexibility varies widely across power plant types, but is not something market operators have typically considered when designing products or procuring new resources." 

“The best way to create value for flexibility is to enhance pricing signals in energy markets," they continue. "Examples include higher scarcity prices, which incent resources to produce during times of need, and reserve shortage adders, which better reflect the value of resources to the system as it approaches a shortage.”

Many paths to uncorking the grid's "latent flexibility"

These are just a few of the bevy of policy prescriptions EI’s paper has to offer, none of which comes without its risk of displeasing one or another faction in the energy landscape. 

Take the suggestion that all generators be required to participate in economic dispatch, a move that would convert must-take solar and wind into market players alongside fossil-fuel-fired generators and sophisticated energy services providers.

To be fair, the idea comes with an important caveat: “This doesn’t mean variable renewables ought to or need to be exposed to market fluctuations; bilateral contracting should continue to be leaned on to mitigate market volatility.” 

A more renewables-friendly option is to open ISO and regional transmission organization (RTO) markets to distributed energy resources. Right now, most distributed energy resources (DERs) are forced either to register as a generator, a process that comes with high costs and complexity, or participate in demand response markets that don’t allow for any generation at all, the paper noted. 

Some ISOs are taking steps forward on this front, under the directive of one of the Obama-era FERC's last orders, but progress is slow. California grid operator CAISO has started allowing DERs to participate in its energy markets, albeit with a very small number of participants to date, and New York grid operator NYISO is working on a pilot as part of the state’s Reforming the Energy Vision initiative. 

Energy Innovation slips in its longtime policy prescription of expanding CAISO’s energy imbalance market into a pan-Western day-ahead energy trading regime, to bring in a broader set of energy importers, and reduce the impact of self-scheduled imports on reducing the state’s grid flexibility.

This idea is controversial, since it could also limit California’s carbon reduction efforts by linking its energy markets to coal-majority grids like PacifiCorp's, which is why it has failed to move ahead in the state legislature to date. 

Then there’s the problem of natural-gas-fired power plants having to purchase their fuel supplies mostly in day-ahead commitments, limiting their flexibility. Under the rules in force at most ISOs until the recent past, “Power plants had to guess how much of their output would clear in the day-ahead electricity market and purchase an equivalent amount of gas,” making it difficult to adjust output on days when system supply and demand failed to stay in balance.

In fact, this imbalance accounted for up to 70 percent of the lack of operating reserves during part of the 2014 polar vortex, one of the key events cited by DOE as justification for moving ahead quickly on its proposal. 

FERC recently took aim at these issues with Order 809, which pushed back the day-ahead natural-gas nomination deadline to later in the day. Five of the seven RTOs have implemented it: PJM, MISO, ISO-NE, NYISO and ERCOT.

However, only NYISO wins EI’s approval for giving market participants “a reasonable amount of time to estimate and submit gas purchase orders.” It might be better to move to 12 intraday trading periods, as the Environmental Defense Fund suggested in comments to FERC, the report noted.

Finally, good old spinning mass -- turbines that provide frequency response through inertia and governor response -- should be compensated for that value in some way, EI noted.

“Using now-standard power electronics, wind, solar and battery resources can provide frequency response," the report says. "However, an opportunity cost can exist for plants to provide this service, so a product should be defined and market mechanisms should be created to encourage provision of the service from whichever resources can do so at the lowest cost.” 

What Neil Chatterjee said

Last week, two of five FERC commissioners came out publicly against moving forward with any rule that would “blow up the markets.” On Friday, acting chairman Neil Chatterjee, who’s gone on the record supporting market changes to keep baseload coal and nuclear plants running, spoke publicly for the first time about his approach to what DOE has asked the agency to do. 

"Compensating for baseload generation does not equate to destruction of the markets," the former aide to Senate Majority Leader Mitch McConnell said during a conversation with reporters, Utility Dive reported. "On the contrary, I think it's a step toward accurately pricing the contribution of all market participants.” 

But as The Hill reported, he also said that the U.S. has "invested nearly two decades and billions upon billions of dollars in our existing market structure, and I don’t want to do anything to disrupt that market structure. And I also want to ensure that whatever steps the commission takes withstand legal scrutiny and are legally viable.”

And despite FERC’s decision last week to stick to DOE’s 60-day timeline for public comment and rulemaking, FERC has lots of options beyond implementing the rule as written by DOE, he said.

"We could do an advanced notice of proposed rulemaking; we could do a notice of proposed rulemaking superseding the DOE NOPR; we could issue a final rule or an extension of the comment period and a solicitation of further comments," he said. "We could convene technical conferences; we could do a notice of inquiry; we could initiate Federal Power Act Section 206 review proceedings -- so there are many tools available to the commission to act within 60 days.”

California policy update: SGIP low-income set-asides; tax yourself to combat climate change

Low-income California residents and businesses in “environmentally burdened” communities may see a lot more energy storage vendors knocking on their doors soon.

On Thursday, the California Public Utilities Commission adopted a mandate that 25 percent of the funds coming from its Self-Generation Incentive Program over the next four years, about $55 million, be directed to these communities throughout the state. Homeowners aren’t the only target -- state and local government agencies, educational institutions, nonprofits and small businesses can also apply. 

CPUC’s move helps soften the blow to low-income community advocates of seeing an even bigger energy storage boost fail to move forward in the California state legislature this year. SB 700 would have created a 10-year rebate program with step-downs as storage penetration increases, much as the California Solar Initiative did for rooftop PV. The bill included a 30-percent carve-out for low-income communities.

California lawmakers also balked on a 100 percent renewables mandate this year -- but they did pass some less glamorous legislation that will free up local governments to tax themselves to combat climate change.

AB 733, written by Assemblymember Marc Berman (D-Palo Alto), allows local governments to use Enhanced Infrastructure Financing Districts, special districts now used to finance public facilities, to be turned to use to invest in infrastructure such as highways and bridges, levees and sewage treatment plants that are at risk due to the impacts of climate change. 

Those risks “include, but are not limited to,” higher average temperatures, decreased air and water quality, the spread of infectious and vector-borne diseases or other public health impacts, extreme weather events, sea-level rise, flooding, heat waves, drought and, of course, wildfires like those that have devastated Northern California’s wine country this month.

“As communities begin to rebuild, and as others look to become more resilient, AB 733 provides a critical funding tool to address infrastructure impacted by or vulnerable to climate change,” Berman said in a statement. 

Utility innovation report of the week

We get a lot of reports on how utilities can innovate their way to the future. On Thursday, Oracle and Navigant published their latest contribution to the genre with a research paper titled, “Utility Innovation Blueprint: How to Manage the Challenge of Dual Transformation,” based on interviews with executives from electric, gas and water utilities including Exelon, National Grid, U.K. Power Networks, Avista, Estonia’s Eesti Energia and Melbourne, Australia’s Yarra Valley Water. 

The top-line guidance for utilities is to approach the problem of flat load growth and disruptive technologies like solar, batteries and EVs in two steps.

First, they should “automate the core business,” to save money, and second, they should “develop new business models,” to make more money. That basic advice is layered with case studies on the positive side, and cautions on the negative side.  

For example: “Innovation without governance is risky. Project costs can overrun, and it becomes harder to incorporate innovation into business operations. The Utility Innovation Blueprint recommends a staged approach to project governance. Project success will be optimized by assigning appropriate responsibility for different project types by adopting a flexible approach to funding, and by regularly reviewing each project’s progress.” 

As for technology, it’s great and necessary, and utilities should “never stop asking” how they can improve business processes or customer experience.

“However, utilities will also have to strike a balance between technologies that help improve existing business processes and those that will help create new business models," the report states. "In a similar vein, innovation projects should strike a balance between nascent and mature technologies.” 

Finally, a word to the C-level executives: “Only the executive can change a company’s business models and create a culture in which innovation can thrive. Corporate change never begins from the bottom. Conversely, idea creation should be bottom-up: Many great ideas will come from the shop floor, so employees must be encouraged to innovate.”