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November 24, 2020

FERC, DOE, Interior Seen as Keys to Biden Climate Plan

With a narrow Democratic lead in the House and Senate control in doubt, FERC and the departments of Energy (DOE) and Interior will have central roles in advancing President-elect Joe Biden’s climate goals, speakers told the American Council on Renewable Energy’s (ACORE) Grid Forum last week.

Rep. Sean Casten (D-Ill.), a former clean energy entrepreneur, said the “just and reasonable” clause in the 1935 Federal Power Act that created FERC was not limited to price.

“Couple that with [EPA’s 2009 finding that CO2 emissions endanger public health] and I think there is a very strong legal argument to be made that FERC has not only the authority, but the obligation, to factor carbon prices into the way they regulate power markets,” said Casten, who serves on the House Select Committee on Climate Change and the New Democrat Coalition Climate Change Task Force.

“Pricing carbon doesn’t provide any cash flow to government. That makes it hard to pass in a democratic body when everybody wants to play Santa,” he said during a keynote speech. “But it makes it much easier to think about how to do that in the context of a FERC hearing that’s saying let’s examine all the equities here. FERC actually structurally is much better suited to deal with carbon policy. My hope is with a fully constituted FERC and a Biden White House, there’s way to really do some things even if we still have a [Mitch] McConnell-led Senate.” (See related story, ‘No Time for Unicorns’ on Climate Ill. Rep. Says)

Fixing Order 1000

The Natural Resource Defense Council’s John Moore said his top recommendation for the new administration is to have FERC advance a transmission rule that addresses the holes in Order 1000, “which everyone at this point knows has not fulfilled its promise.”

Moore, director of the NRDC’s Sustainable FERC program and Climate and Clean Energy program, cited “shortcomings in competition, in cost allocation, in siting large projects vs. small projects.”

“There’s a whole set of topics we could talk about there that I think a new FERC could really robustly address,” Moore said in a discussion moderated by ACORE CEO Gregory Wetstone. “This is the best opportunity we’ve ever seen for DOE [and] the Department of Interior — especially with offshore wind permitting issues — to come together and work cooperatively with FERC on a shared agenda. I think that’s true on a number of different issues, and it’s true in a way that we have not seen with certainly any administration at least since I started [working on] this.”

‘Climate Change Lens’

Ana Unruh Cohen, House Select Committee on the Climate Crisis | *ACORE*

Also participating in the discussion was Ana Unruh Cohen, staff director of the House Select Committee on Climate Crisis, who said every decision by the new administration “is going to go through a climate change lens.”

“My expectation is that all the agencies that are responsible for making these long-term infrastructure siting decisions and permitting are going to put that through the climate scenarios that we know are real possibilities,” she said.

Casten said he was encouraged by reports that the Biden administration will create a central clearinghouse for climate policy to ensure cooperation among FERC, EPA and DOE. Each of the agencies “do little corners of [climate policy and we need to] have them pitch together,” Casten said. “We’ve got to prioritize climate change above all else and stop tolerating the excuses for why we can’t act.”

Legislative Options Limited

During the campaign Biden outlined a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production. But a Republican-controlled Senate and a narrower Democratic edge in the House would likely prevent him from winning approval of such a plan and diminish his ability to include incentives for renewable energy in a new economic recovery package.

Democrats still have a chance at winning effective control of the upper house, with two Senate races in Georgia headed to runoff elections on Jan. 5. Winning both seats would result in a 50-50 tie that would be broken by Vice President-elect Kamala Harris. (See GOP Senate May Limit Biden Climate Ambitions.)

National Vision Needed

Moore said DOE should begin work immediately on “the HVDC moonshot” — a system of HVDC converter and inverter stations to link the interconnections and provide power for EV charging. He said the National Renewable Energy Laboratory and the other DOE labs should help FERC identify “what the real needs are.”

The Eastern and Western interconnection grid studies funded by the America Recovery and Reinvestment Act (ARRA) during the 2007-2009 recession “were great collaborations among many different interest groups that developed plans for … a lower carbon future,” Moore said. “But they really didn’t go anywhere because those plans were completely divorced from existing grid planning. So, I think the next round of grid studies needs to be linked to actionable outcomes through the existing regional transmission organizations and FERC. FERC and DOE could work on portfolio analysis, looking at the areas with the best resources around the country and thinking about what could be done there.”

Biden could also ask FERC to create a new office of transmission planning and oversight “to get more cohesion and control over the planning process so we could integrate more of the Biden administration plans with the FERC-regulated entities of the RTOs,” Moore said. “We need a more coordinated national system for doing this because the worst possible outcome is to have fights over eminent domain in local and regional projects that aren’t really connected to a larger grid vision. That to me is a waste of time”

Macro Grid Studies

During the conference, Americans for a Clean Energy Grid (ACEG) released an international su rvey of “macro grids,” authored by two Iowa State University researchers, which shows that the U.S.’ development of interregional transmission lags far behind that of China, India and the European Union. It followed an ACEG study in October that projected a macro grid that allowed transmission of cheap renewable energy throughout the Eastern Interconnection would create 6 million jobs, cut carbon emissions and save consumers more than $100 billion. (See ‘Macro Grid’ Study Promises Cost Savings, Emission Cuts.)

The studies were part of the Macro Grid Initiative, a joint project of ACEG and ACORE funded by Microsoft founder Bill Gates’ Breakthrough Energ y Ventures, a $1 billion fund whose board members and investors include Amazon founder Jeff Bezos, former New York Mayor Michael Bloomberg, Virgin Group founder Richard Branson and LinkedIn founder Reid Hoffman.

“At the heart of this effort is the reality that the 15 states between the Rockies and Mississippi River account for 88% of the nation’s [onshore] wind potential while 56% of our solar potential is located in that same area. Meanwhile, this region is home to less than a third of the projected 2050 electric demand,” Wetstone explained. “Hence the obvious necessity of moving renewable power from the renewable resource rich part of the country to where the people live. We can do that with a macro grid. We can enhance grid resilience, lower costs and reduce carbon.”

The House Climate committee endorsed the macro grid concept, although it referred to a “national super grid,” Unruh Cohen said.

“To unleash the ambitious plans that the states and utilities already have to shift to clean energy, they really needed the support of an enhanced grid of new lines in some places to bring new resources to demand centers, but also upgrades on the existing footprint in other places to just be able to deal with the dynamism that we see in the grid now, [to] bring on storage, all of those things,” Unruh Cohen said. “And of course, the very important task of resilience, both to climate impacts and other [threats].”

Moore said a larger grid will be needed to support the “tens of millions of distributed energy resources in the forms of cars, trucks and buildings that we see in our future.”

He noted the growth of renewables in the last 20 years from a “niche” to the “huge” presence it now has in SPP, which boosted its record for wind energy with a new peak of 18,442 MW on Nov. 14.

Dying on the Vine

Without substantial new transmission in MISO West Risks Becoming ‘Dead Zone,’ Stakeholders Warn.)

Unruh Cohen said grid improvements “will be right in the mix as we put an infrastructure package together, and I think we can hopefully have some bipartisan support going forward.”

“There are other good reasons to build a grid,” Wetstone added, citing the National Commission on Grid Resilience’s report in August that “has recommendations that are very sympatico” with those who want grid expansions to support climate efforts. Wetstone noted that the commission is co-chaired by Rep.-elect Darrell Issa, a California Republican who will return to Congress in January. (See related story, Retired General Sounds Alarm on Grid Security.)

“When you look at the maps where a lot of these projects are popping up, they don’t look like they’re all in red or blue districts. This is real in a way that we haven’t seen in the past,” said Moore. “So that, plus the COVID crisis, I think, could produce the best possible scenario for something to happen that’s big.”

In the meantime, he said, progress could be made through investment tax credits for transmission and by directing the federal power marketing agencies in the West — Bonneville Power Administration and the Western Area Power Administration — to use their authority to expand the grid.

Moore said the Senate Appropriations Committee bill for 2021 has a section on renewable energy grid integration that includes $10 million for the development of an “energyshed” model to address transmission constraints in renewable-rich areas based on Texas’ Competitive Renewable Energy Zones (CREZ) buildout. “That’s the kind of exciting thing you might see go through even while we’re waiting for the big, comprehensive legislation,” he said.

Coalitions Needed

Unruh Cohen said passing energy legislation will require the kind of broad coalitions that backed the 2007 Energy Independence and Security Act and the Waxman-Markey cap-and-trade bill that cleared the House in 2009 but stalled in the Senate.

Bringing together “clean energy, the environmental community, agriculture — for both of those bills, having the farmers and ranchers who were benefitting from hosting renewable energy — was really critical to putting together a winning strategy,” she said.

November 24, 2020

Texas PUC Briefs: Nov. 19, 2020

The Texas Public Utility Commission last week threatened Texas-New Mexico Power (TNMP) with a “comprehensive” rate case if the utility didn’t remove proposed Tariff language from a proceeding before the commission.

The PUC in August approved TNMP’s settlement agreement for an annual increase of $14.29 million in its distribution cost recovery factor (DCRF). Two months later, it filed in the same docket revisions to its wholesale Tariff for transmission service to correct errors in it (50731).

On Nov. 6, energy storage developer Broad Reach Power filed for relief from TNMP’s distribution service charges being assessed to wholesale storage entities as a result of the utility’s proposed correction. Broad Reach said the changes tucked into TNMP’s proposed correction were “inconsistent” with commission rules and applicable legal standards and asked the PUC for declaratory and injunctive relief and a rulemaking to address the issues (51501).

The developer found a sympathetic ear in PUC Chair DeAnn Walker.

“DCRF proceedings are meant to provide periodic changes to rates to cover distribution investment. This is not what occurred in this instance,” Walker said during the commission’s open meeting Thursday. “The manner in which TNMP chose to try to address it in filing a new Tariff two months later does not comply with the commission’s order. They should have filed a new case to change the Tariff back to what it should have been.

“Now we have pending this new docket, which sets forth various alternatives, none of which I believe the commission has the legal ability to implement, except maybe the rulemaking. We have two dockets that are spending a lot of the commission’s time that are not our core mission.”

Socially distanced PUC staff during the commission’s open meeting | *Texas PUC*

TNMP’s correction added language that would separately meter a storage facility from all other facilities and set the interconnection point at the distribution level.

“The changes proposed to the Tariff for transmission service go well beyond the intent of the statue and the rules allowing a DCRF,” Walker said. She suggested that TNMP and other parties in the Broad Reach proceeding file a petition by Dec. 8 that would remove the troublesome language. If not, she said, she would use the PUC’s Dec. 17 open meeting to require TNMP to file a rate case to address the issue and any others “that may be out there.”

“I want to be clear to all utilities that they are not to abuse the DRCF process or any of these other processes they have gotten through the legislature and through us to give them quick relief,” Walker said.

She also had harsh words for other parties in the proceedings and PUC staff, saying the commission was caught off-guard by the dockets.

“In my view, the system failed the commissioners on this issue. [TNMP] should never have included this request in their application, and the other parties and staff should not have included this change in the Tariff,” Walker said. “I do not believe based on the record of this case that the commissioners were in a position to identify the issue without the input from the parties and the staff. There’s no way the three of us could have ever caught this issue and said, ‘This shouldn’t be in a DCRF.’”

“You can’t sneak it through the way it was sneaked through here,” Commissioner Arthur D’Andrea said. “It embarrasses me that I missed it. It’s still our job. We still signed [the order].”

Hearing on Proposed Entergy Rider

The commission agreed to hold a hearing in December or January on a proposed rider by Entergy Texas for a new gas-fired power plant north of Houston (51381).

Entergy in October filed a request for a generation cost recovery rider to begin recovering a return of and on its capital investment in the Montgomery County Power Station, a 993-MW, combined cycle natural gas plant near Willis. Entergy, which has said the plant’s construction costs will be $937 million, is attempting to collect about $91 million annually from its Texas customers.

The plant was originally expected to be placed in service next June. Entergy now projects the in-service date to be moved up, leading to the PUC’s decision to quickly hold a hearing on the rider.

Walker said she was concerned that in reviewing the case, the utility might have included costs in the rider “more appropriately defined” as operations and maintenance costs.

“I want to be clear to Entergy that they better scrub before the hearing any costs they are requesting,” Walker said. “If they are getting a rider with inappropriate carrying costs, they will have to refund those amounts, and they will have to refund them with carrying costs.”

The plant’s expenses and costs will be part of a future rate case, she said.

Texas Industrial Energy Consumers, the Office of Public Utility Counsel and a coalition of Houston-area cities all requested the PUC hold a hearing on Entergy’s application.

Staff File Enforcement Report

PUC staff filed its annual report on customer complaints and enforcement activities on Nov. 10, listing 6,805 electric complaints during fiscal year 2020. According to the report, staff opened 152 investigations and closed 110, approving orders that resulted in $2.2 million in administrative penalties and $225,000 in refunds.

The commission recently ended Texas Reliability Entity’s reliability monitor contract for the PUC Cancels Texas RE as ERCOT’s Reliability Monitor.)

November 24, 2020April 9, 2024

Overheard at ACORE Virtual Grid Forum

The American Council on Renewable Energy (ACORE) held its 2020 Virtual Grid Forum last week. The two-day event examined the role of regulators, grid operators, electric service providers and the renewable sector as states progress toward their clean energy goals. It also explored the policy and regulatory issues and technology challenges associated with integrating increasingly high penetrations of renewable electricity on the grid.

Following is some of what we heard.

Tackling MOPR Issues

During a panel on capacity market design and the future of resource adequacy Nov. 17, panelists discussed at length the minimum offer price rule (MOPR) as a symptom of outdated design.

Grid Strategies President Rob Gramlich said several states have threatened to back out of capacity markets and that MOPR is not viewed as a “long-term, sustainable approach,” according to PJM, which is “trying to get back into a way that works with states rather than contravening [their] wishes and goals.”

Abe Silverman, general counsel for the New Jersey Board of Public Utilities, said that clean energy policies “are non-negotiable in New Jersey, and we’re not backing off; we’re not slowing down.” Silverman noted New Jersey is also “very active” in current MOPR litigation.

“I think we see MOPR as a symptom of a market design that’s about 20 years out of date,” Silverman said. “These markets were put into place in the early 2000s, and they were great at optimizing cost and maximizing reliability. … They’re very effective at that, but they haven’t been tweaked a lot.”

Clockwise from top left to right: Abe Silverman, New Jersey Board of Public Utilities; Casey Roberts, Sierra Club; Lloyd MacNeil, McDermott Will & Emery; Rob Gramlich, Grid Strategies; and Nora Mead Brownell, EPSY Energy Solutions | ACORE

Silverman said “fundamentally” the question should be: What are these markets doing for states?

“We’re putting band-aids on band-aids, and MOPR is the ultimate band-aid, and it’s not a good one,” Silverman said.

Former FERC Commissioner and Pacific Gas and Electric board Chair Nora Mead Brownell added that capacity markets were supposed to be “a short-term solution.” According to Brownell, another quick fix is additional responsibilities for the RTOs, which have created administrative solutions like MOPR.

“They’re going to be imperfect,” Brownell said. “We can dance on the head of a pin all we want. At some point, there’s going to have to be compromises.”

Brownell said that it needs to be clear that if RTOs are going to have a stakeholder process, “You don’t get everything you want. You look for everything you need. How do we get to a place where we are more market-driven, rather than these endless, litigated, imperfect administrative solutions?”

Silverman said New Jersey also has an ongoing proceeding about whether it should take back resource adequacy from PJM.

“It’s about MOPR, frankly, but it’s also about cost and achieving our clean energy goals faster and at the least cost to our consumers,” Silverman said. “We look to California as obviously the gold standard for driving a clean energy agenda. But it is daunting, and it’s an amazing thing that they’ve done that their reliability has been so good while they’ve been pioneering so many different new technologies and driving the investment.”

ERCOT Example

“Probably the best part of the ERCOT market is that it does allow, or encourages, consumers to moderate their energy behavior,” Silverman said.

Silverman added there is no default service provider in ERCOT, which makes “all things become possible because you have third-party suppliers … who have a million customers so that they can make those kinds of long-term hedging arrangements.” Silverman said most New Jersey customers stay with the default service provider, which was included in restructuring the state’s markets.

“ERCOT took that very bold step 20 years ago of forcing the baby birdie out of the nest, and other states were not willing to go that direction,” Silverman said.

Brownell said she agreed with Silverman that ERCOT took a bold step, but it also had “very strong political and business leaders who made the decision to go to markets fully and stuck with it; they didn’t back off.”

“It’s unbelievable to me in this day and age, and this isn’t this isn’t a knock on New Jersey, [that] the Northeast largely hasn’t deployed [smart] meters and acts as if it needs, you know, one more death-by-pilot [program]. What don’t we know about the value of meters and the data that they produce? It’s a mystery to me.”

Sierra Club Senior Attorney Casey Roberts said it’s tough to get other states to make that ERCOT-type leap. She said PJM recently approved more revenue being recovered through energy and ancillary services (EAS) and less through the capacity market.

“Because of the way the capacity market works as a missing money mechanism, that [decline in capacity costs] should naturally happen as you increase the energy revenues, but less is coming through the capacity market” Roberts said. “So it’s going to be a more slow and painful transition without that kind of the political and business leadership that Nora was talking about. There is already the framework in place to move away from mandatory capacity markets, or at least reduce their relevance in those Eastern markets.”

Gramlich said it does not have to be an all-or-nothing approach. There can be incremental shifts to have more EAS revenue relative to the capacity market with design changes over time.

Roberts added that FERC needs to lead on market design as “people just get stuck in their corners and don’t see how a series of tradeoffs could ultimately lead to a more optimal design.”

Supporting Renewable Expansion

A panel on Nov. 17 led by Heather Curlee, senior counsel of Wilson, Sonsini, Goodrich, & Rosati, explored the concept of establishing power markets to support the expansion of renewable resources.

Robert Stoddard, managing director of Berkeley Research Group, was asked if expanding RTOs and ISOs would be the right approach for continued renewable integration into the system. Stoddard said markets have performed “extremely well” in helping attract and retain investment in a way that has been “sensibly done” and conducted at the risk of the investors instead of ratepayers.

When RTOs and ISOs were created in their current form by FERC Order 2000 in 1999, Stoddard said, it was done as a response to concerns that utilities owning generation and controlling the transmission lines led to “no nondiscriminatory open access to the grid.” Innovation had to come from the utilities, Stoddard said, leaving little room for innovation or risk-taking from outside investors.

Stoddard said markets can create conditions for innovation, and there are many functions of RTOs and ISOs to ensure the open access that allows outside companies to come forward and take risks. He said markets operate through prices, and the prices tell people what is valuable and allow an innovator to look for changes in generation or transmission to create value.

The challenge with RTOs and ISOs, Stoddard said, has been figuring out the best way to put together market prices with the necessity of long-term planning.

“The RTO markets are really good at wresting all of the small efficiencies out of day-to-day operations,” Stoddard said. “Where we’ve had bigger challenges is [in whether] these markets provide the long-term signals not only for generation, but wise transmission expansion.”

Joe Hoerner, senior vice president of regional grid solutions for Portland, Ore.-based Pacific Power, was asked how carbon pricing fits in to help accommodate existing or future state renewable energy goals and whether more transmission is needed to integrate renewables on the West Coast.

Hoerner said CAISO has been “struggling with” the best way to approach carbon pricing. Absent a standardized approach to carbon pricing, a “hodge-podge approach” to pricing could lead to unintended consequences, he said.

As more solar resources are being built in the Southwest, Hoerner said, there are “a lot of eggs in one basket” in the renewable generation mix. He said the reliance on solar is starting to create reliability concerns.

“There’s not enough transmission to make that connection and build that new backbone throughout the West to interconnect all of the solar resources,” Hoerner said. “You really do need to diversify; you need to be able to get to those different assets, and you need the transmission to be able to interconnect all of that”

The panelists were also asked if RTO membership should be mandated on a federal level to create more efficient markets.

Stoddard said the market would work more efficiently if there was mandatory RTO membership, but efficiency would come at some costs. He said one of the biggest sacrifices would come with the loss of local control and oversight of long-term planning.

“A well-designed integrated resource plan is a great thing, but it does put a lot of risk on ratepayers,” Stoddard said.

Bob Helton of ERCOT’s Technical Advisory Committee said he agreed with Stoddard’s description of an RTO mandate, saying states presently get to “pick their own poison” when it comes to deciding whether to join an RTO or ISO or to go out on their own.

Helton said there are pros and cons to each idea, but it’s a decision best made on a local level rather than a dictate from above.

“It would be hard for me to say to mandate anything on anybody at this point,” Helton said.

Hoerner said he doesn’t think RTO membership should be mandated. He said decisions for a “pursuit of perfection” toward a market design can lead to a market implosion and cause more problems.

“When you mandate something, there’s the risk that it gets jammed in or doesn’t get designed properly, and you end up with something that isn’t well-functioning,” Hoerner said.

November 24, 2020

CPUC Tries to Head off Summer Blackouts

The California Public Utilities Commission opened a proceeding Thursday to help prevent energy emergencies next summer like those that occurred in August and September.

The rulemaking is intended to identify and institute near-term measures that could limit energy consumption and boost generation during heat waves that strain the Western grid. California’s rolling blackouts in mid-August were the first since the energy crisis of 2000/01. (See CAISO Blames Blackouts on Inadequate Resources, CPUC.)

“Through this proceeding we will identify measures that can be implemented as soon as possible to address reliability for next summer,” Commissioner Liane Randolph said. The CPUC, CAISO and the California Energy Commission (CEC) are working together to ensure reliability going forward, she continued.

Load-serving entities under the CPUC’s jurisdiction are procuring 2,400 MW of new capacity to come online by summer. But the CPUC said additional measures, including enhanced demand response programs, are needed to ensure the state has enough energy to meet demand and maintain reserves intended to prevent a larger grid failure.

CPUC blackouts — CPUC headquarters in San Francisco | © *RTO Insider*

The rulemaking will consider compensating customers for switching to back-up generators during times of strained supply. It will try to reach more residents through advertising and social media to urge them to conserve energy during heat waves. And it will seek increased capacity from the state’s investor-owned utilities by retrofitting generators and increasing efficiency for greater output.

The measures must be approved by April 2021 so they can be implemented by the summer, the CPUC said.

A preliminary root-cause analysis of the August blackouts by the CPUC, CAISO and the CEC recommended that the CPUC update its resource and reliability planning targets to account for extreme heat waves and expedite the development of resources that can come online by summer. (See CAISO Says Constrained Tx Contributed to Blackouts.)

The retirement of fossil-fuel plants and switch to renewable energy left the state short of capacity as solar power waned in the evenings during the summer heat waves. More storage for renewable resources is needed to compensate for shortfalls, CAISO and the CPUC said.

“With respect to updating resource and reliability planning targets to increase supply and account for the state’s transitioning energy mix, this [order instituting rulemaking] will evaluate whether it is possible to increase the month-ahead RA procurement requirement, outside of the current multi-year process, using information provided in the prospective summer assessment report,” the commission’s decision said.

After the blackouts of Aug. 14-15, CAISO reported that large amounts of electricity had been exported on those days. The root-cause report acknowledged the error.

“Under-scheduling of load [by LSEs’ scheduling coordinators] and convergence bidding clearing net supply signaled that more exports were supportable.”

Some critics, including former CPUC president Loretta Lynch, questioned why the ISO had allowed the exports to occur. (See Former CPUC President Calls for CAISO Probe.)

The CPUC said it will address the issue in its rulemaking.

“For purposes of determining when capacity can be exported from the CAISO-controlled grid, particularly during reliability events, a resource that provides RA capacity can be tagged such that it would not be exported during these critical times,” it said.

November 24, 2020January 15, 2025

Experts Urge West to Address RA Shortfall Immediately

Western utility regulators have no time to waste in addressing the region’s looming resource adequacy shortfalls, industry experts said last week.

“Yes, there is a problem, and it’s happening now,” WECC Manager of Performance Analysis and Resource Adequacy Matt Elkins said during the regional entity’s second Resource Adequacy Forum on Wednesday. (See WECC Seeks to ‘Invent’ Future with RA Forum.)

“We saw it in 2020. Our models started seeing this coming a couple years ago. I think everyone started talking about this — ‘Hey, variability is growing’ — and I think we’re there now. I think we need to come together and really figure out how to do this as an interconnection,” Elkins said.

Arne Olsen, senior partner with Energy and Environmental Economics, agreed about the urgency: “It’s a right-now problem, not a five-years-from-now problem.

“All the modeling shows it in California. Our Northwest studies show that the Northwest has a problem. … I don’t know about the Southwest and the Front Range areas, because I haven’t looked at those specifically, but West-wide I think we have a problem,” Olsen said.

California and the Northwest both face immediate capacity needs, experts said during WECC’s Resource Adequacy Forum. | WECC

“In California … our problem is now and is going to get much worse in the future” with the loss of the 24/7 baseload capacity from the 2,256-MW Diablo Canyon nuclear plant, slated for closure in 2025, said Karl Meeusen, CAISO senior adviser for infrastructure and regulatory policy.

What should a regulator do?

“I guess my first advice would be [to] examine very closely the [integrated resource plan] practices of the utilities that are under your jurisdiction. And if you see one of your utilities with a very large short position, then you should be aware that it’s going to be difficult — and perhaps expensive — for them to fill that position over the next couple of years,” Olsen said.

Over the long run, regulators should be looking at what resources their utilities need to serve load “reliably and at a reasonable cost,” he said.

Olsen said that all resources contribute to RA but do so in different ways. While fully dispatchable resources are rated at their nameplate capacity, dispatch-limited variable resources are rated based on their effective load-carrying capability, a measure of a resource’s ability to perform during intervals with a high loss-of-load probability (LOLP).

“The more you have of a non-dispatchable resource, the more apparent their limitations become,” Olsen said, adding that it is best to pair resources such as wind and solar with battery storage, for example.

‘Summer-needy’ Northwest

John Fazio, senior analyst with the Northwest Power and Conservation Council, said his organization has a mandate to produce a five-year regional power plan for Idaho, Montana, Oregon and Washington, the region covered by the Bonneville Power Administration’s hydroelectric system. The council uses annual LOLP as its RA standard, with an expectation of no more than one shortfall every 20 years — which, Fazio clarified, refers to a need for balancing authorities to take emergency actions, but not necessarily initiate blackouts.

With climate change bringing higher temperatures, “we anticipate that during winter, we will see less demand, which is a good thing, and we will also see more snowfall and rain in the system, which is good thing,” Fazio said. On the flip side, earlier snowmelt means the hydro system will have less water in the summer, leaving the Northwest with less energy to export to California. Meanwhile, retirements of coal-fired plants in the region will translate into an increasing LOLP heading into the next decade.

Fazio said the council’s RA standard counts some imports on top of the resources within the Northwest region. “And we’ve had debates about how much we should rely on that — and that is a policy question; that’s not an assessment of what’s physically available, but it’s a question of how much the region wants to rely on that,” he said.

“The challenges that we’re facing now is that we’re seeing this general trend toward warming temperatures, which means that, even though our summer loads may not be as high as our winter loads, the more important thing for us is the gap between the loads and the resources,” Fazio said. “And it looks like the Northwest is moving toward becoming more of a summer-needy region, which means there will be a challenge in the future because both the Northwest and the Southwest may be competing for the resources at the same time.”

Fazio said the council is shifting from using a historical model in its power plans to one based on climate change trends.

Meeusen said California’s approach to RA entails “making sure that resources are not just there but contracted and offered into the market” through month-ahead and year-ahead contracts.

“We really don’t know until 45 days prior to the month which resources we’re going to be relying on,” Meeusen said.

CAISO relies on a stochastic production simulation that allows the ISO to look at load, wind, solar and outages and “see how they work together” and determine risk “if something drops off.”

“The hard part of this stochastic model is, do we have enough,” and if not, what does the ISO need to procure using its backstop authority?

Olsen said regional reserve sharing has the potential to yield “significant benefits.”

“In effect, we’ve kind of been counting on that regional coordination already as we’ve got resource planning throughout the West, but largely in an uncoordinated manner,” Olsen said. Each system performs its own estimate of how much capacity might be available in the market, but it’s difficult to ascertain whether there’s enough available for everyone in the Western Interconnection, he said.

“And that has gotten us into a little bit of trouble. I think this was a good assumption as long as the system had surplus capacity, which it has had for 20 years, but now as we move towards a system with less and less capacity available and some resources are getting retired … it’s difficult to know how much capacity might be available,” Olsen said.

“Which is to say that the way we’ve been doing things for the past several years, really a couple of decades, may not be sufficient to maintain reliability going forward.”

Olsen said he likes the direction the Northwest Power Pool is moving in developing its RA program, noting that it fits with the region’s system of bilateral trading among largely vertically integrated utilities. (See NWPP RA Effort Quickly Ramping Up.)

“If we had just four of those entities, each of them looking after its own region [in the West], and then they could all get together and talk about how much they can lean on each other on a broad regional basis — under the auspices of a WECC task force, for example — that would feel like a good long-term direction.”

November 24, 2020March 9, 2025

NERC Warns of Fuel Bottlenecks in Coming Cold Months

Extreme weather poses the greatest risk to the reliability of North America’s electric grid for the winter months, according to NERC’s Winter Reliability Assessment (WRA) released Wednesday, although regional entities are generally well provisioned for the cold season. Additional concerns include fuel-supply and energy-assurance risks and the ongoing COVID-19 pandemic.

The annual WRA covers the months of December through February, aiming to identify potential reliability issues along with evaluating generation resource and transmission system adequacy.

For winter 2020/21, the ERO found that the anticipated reserve margin in all areas meets or exceeds the reference margin level. This indicates that “existing and planned resources … are adequate to manage risk of a capacity deficiency under normal conditions,” though NERC did acknowledge “noticeable reductions” in anticipated reserve margins compared to the prior year in MRO-Manitoba Hydro and SERC-Central, which covers all of Tennessee and portions of surrounding states.

Year-on-year changes in winter 2019/20 and winter 2020/21 anticipated reserve margins | NERC

Fuel Supply Presents Pain Points

Within this upbeat assessment, NERC offered some words of warning. The organization noted potential pain points with fuel supply, stating particularly that “New England generation continues to be limited by the availability of natural gas,” in line with COVID-19, Weather Drive FERC Winter Outlook.)

This is because of the use of gas in the region for both electric generation and heating. While under normal weather conditions such dual use should not pose a problem, a “more severe and prolonged winter event” that drains heating oil supplies more quickly than expected could lead to problems delivering enough natural gas to supply generators. The report points to the cold s nap of January 2018 as the type of event that might create such a circumstance.

The southwest area of the Western Interconnection, including California, is also vulnerable to natural gas bottlenecks because of “limited natural gas storage and [lack of] redundancy in supply infrastructure.” As a result, extreme events such as pipeline disruptions or freezing temperatures at wellheads that affect production could limit the supply of gas available for the region, leading to energy emergencies.

Extreme weather poses a direct risk to reliability in several other regions: WECC, Texas Reliability Entity, MISO and NPCC-Maritimes are all advised that they “may need resource assistance in the form of transfers” during energy emergency alerts.

Transfer curtailment extreme scenarios for ISO-NE (left) and SERC-E | NERC

Widespread winter weather covering multiple assessment areas may also limit the availability of emergency imports. NERC provided operational risk scenarios involving ISO-NE and SERC-East, which covers North and South Carolina, to demonstrate how periods of extreme peak demand and high outage rates could lead to cancellation of transfers because of contracts allowing exporting entities to “prioritize serving native load.”

“These areas are selected because capacity transfers can be an important resource contribution toward meeting operating reserves,” NERC said.

COVID-19, Hurricane Impacts Continue

On the subject of the coronavirus, the report noted “increased uncertainty in electricity demand projections [along with] cybersecurity and operating risks,” but it could not identify any specific risks to the bulk power system likely to arise in the assessment period beyond the continuing need to protect system operators and field crews from infection. The report also recommended that operators pay close attention to generator maintenance scheduling and outage coordination, as many are still dealing with a backlog in planned maintenance delayed from spring and autumn.

Ongoing repair work from the 2020 hurricane season could complicate maintenance schedules as well. Despite intense effort to address the damage from Hurricanes Laura and Delta, and the completion of most major tasks, restoration activities are still unfinished in some parts of Louisiana. (See Industry Cooperation Key to Hurricane Recovery.)

NERC is still working on the 2020 Long-Term Reliability Assessment, which is planned for release in December. At this month’s meeting of the Board of Trustees, NERC Senior Engineer Mark Olson said most areas are expected to have sufficient on-peak capacity for the next five years, with potential trouble spots in Ontario and MISO. The team also previewed trends that bear watching over the long term, including the rapid projected growth of wind, solar and distributed energy resources across the North American grid. (See “Winter, Long-term Assessments Previewed,” NERC Board of Trustees/MRC Briefs: Nov. 5, 2020.)

November 22, 2020

FERC Defends CASPR Order

FERC on Thursday defended its Competitive Auctions with Sponsored Policy Resources (CASPR) order, which permitted ISO-NE to create a two-stage capacity auction to accommodate state renewable energy procurements (ER18-619).

The commission voted 2-1 along party lines, with Republicans James Danly, newly installed as chair, and Neil Chatterjee, recently demoted from it, affirming the March 2018 order and addressing complaints in numerous rehearing requests. The rehearing requests were automatically denied when the commission failed to act within 30 days. In the meantime, the Sierra Club, Natural Resources Defense Council, RENEW Northeast and the Conservation Law Foundation petitioned the D.C. Circuit Court of Appeals on Aug. 31 to review FERC’s decision.

Filing as “Clean Energy Advocates,” the groups had said that rather than attempting the “impossible and misguided” effort to create a “pure” market free from the impacts of state policy choices, FERC should reject CASPR as not just and reasonable.

FERC said it continued “to find the economic principles underlying CASPR to be sound” and agreed with the RTO’s recommendation to prioritize the preservation of a competitive Forward Capacity Auction price to ensure investor confidence. That helps sustain resource adequacy, the commission said, after weighing the cost of excess capacity that could result by exempting sponsored-policy resources (SPRs) from the minimum offer price rule (MOPR).

FERC CASPR — FERC headquarters | © *RTO Insider*

The commission also reiterated that ISO-NE did not propose eliminating the MOPR as applied to SPRs.

FERC also rejected the groups’ request that it at least reinstate the 200-MW renewable technology resource (RTR) exemption.

“ISO-NE has justified phasing out the renewables exemption because this administratively based mechanism conflicts with and potentially undermines CASPR’s market-based approach,” the commission said. “Implementing a perpetual, annual 200-MW ‘backstop’ would exacerbate this situation, as renewable resources would tend to favor the exemption approach to entering the FCM [Forward Capacity Market], potentially diminishing a well functioning and robust substitution auction.”

Glick Dissents

Democrat Richard Glick dissented, as he had on the 2018 order. (See Split FERC Approves ISO-NE CASPR Plan.)

Glick — who may become commission chair under the Biden administration — said he does not believe that CASPR “is a just and reasonable means of accommodating state public policies” in the FCM.

“The record demonstrates that CASPR is failing miserably at accommodating those policies,” he said during the monthly open meeting.

“Although CASPR had some theoretical appeal, the nearly three years since the commission accepted the filing have made clear that, in practice, CASPR simply is not up to the task of accommodating the New England states’ efforts to decarbonize their electricity sector and address the threat of climate change,” Glick said in his 13-page dissent. “It is time to go back to the drawing board. …

“Electricity markets are, and always have been, the product of public policy,” Glick said. “Pretending otherwise or trying to mitigate our way to a market free from the effects of certain public policies will only harm customers, create needless federal-state tensions and undermine faith in the regional markets whose development has been this commission’s crowning achievement. We must move beyond the MOPR.”

Glick added that he recognized reforming electricity markets to manage the ongoing transition to a clean energy future is a complicated question, and “the right answer will likely vary among the different RTOs.”

“But that is all the more reason to begin putting those structures in place now, rather than searching for ways to keep MOPR-based approaches on life support,” Glick said.

Glick added that he does not believe that the current FCM is working for ISO-NE.

“In New England, as in the other Eastern RTOs, it has become clear that the principles and assumptions that underlay the creation of the current capacity market constructs no longer hold,” Glick said. “In particular, the days when the procurement of a single, undifferentiated ‘capacity’ product could serve as an effective guide for efficient resource entry and exit are over.”

Glick said concerns about “consequences that resource entry and exit decisions have for climate change, among other things, are likely to play a more important role in resource entry and exit than the FCM clearing price,” especially in New England.

“It is past time for the resource adequacy paradigms to evolve accordingly,” Glick said. The longer FERC “waits to take those inevitable steps, the more harm it will do to RTO markets and the customers we are supposed to protect.”

“It will eventually require that all the relevant elements of an RTO — including not just the resource adequacy construct, but also the procurement of energy and ancillary services, as well as the planning and development of new transmission facilities — work in concert to accommodate the changing electricity sector,” Glick said. “That will be no mean feat.”

November 22, 2020

FERC: No Need for Waiver on MISO Make-whole Payments

FERC said last week that MISO does not need a waiver of its Tariff requirements in order to provide Entergy Texas with make-whole payments.

The commission decided MISO is free to determine whether to give Entergy about $4,000 in make-whole payments for a late 2018 manual redispatch of its Sabine 5 natural gas plant without FERC approval. The commission dismissed the waiver request as unnecessary (ER20-1901).

The Sabine facility initially had a day-ahead volume award of 450 MW with a ramp rate of 3 MW/minute. According to MISO, its system dispatched the unit below its day-ahead volume to only 191 MW at 6 p.m. A few minutes later, the grid operator manually redispatched Sabine 5 to return to its day-ahead schedule volume, which took the plant three five-minute intervals to reach. MISO then denied Entergy day-ahead margin assurance payments for the three intervals while the plant was ramping.

MISO Make-whole Payments — MISO’s Carmel, Ind., headquarters | *MISO*

The RTO said its system is currently incapable of taking a resource’s offered ramp rate into consideration during a manual redispatch setpoint directive. It also said its rules don’t allow it to pay out day-ahead margin assurance compensation based on after-the-fact adjustments to manual redispatch setpoint instructions.

Entergy sought informal alternative dispute resolution over the partially paid ramping intervals. MISO concluded it should reimburse the utility $4,064.74, the amount it would have received had it been allowed day-ahead margin assurance payments for the three intervals in question.

The RTO said Entergy “should not be harmed for following MISO’s instructions” but that it needed to seek a Tariff waiver in order to issue the payment.

The commission disagreed, saying MISO is authorized to make the payment without a waiver.

“After reviewing MISO’s filing and Tariff, we find that it is not necessary to revise, alter or waive any provision of the Tariff to implement the ADR determination. Instead, consistent with the ADR determination, MISO can update the manual redispatch setpoint … instructions to take into account a resource’s offered ramp rate for resettlement purposes,” FERC said.

November 22, 2020

CAISO Governors Honor Olsen

The CAISO Board of Governors praised the work of retiring colleague David Olsen on Wednesday and adopted the second part of a plan to speed the interconnection of storage resources to avoid future blackouts.

The governors and new CEO Elliot Mainzer recognized former Chair Olsen for his efforts to bring renewable power into the mainstream over the past four decades, including nearly nine years on the CAISO board.

“You are truly a titan in the energy field,” Chair Angelina Galiteva said. “Your wisdom, dedication and commitment to the decarbonization of the grid … especially to elevating the ISO to an international and global leader in the field of integrating renewables … is greatly appreciated and cherished.”

Mainzer read a resolution from the governors honoring Olsen and presented him, in an online meeting, with a commemorative plaque. The resolution recognized Olsen’s many achievements, including ushering in an era of corporate sustainability as president of Patagonia in the late-1990s. He led the outdoor-gear company’s carbon-reduction efforts, making it the first U.S. corporation to get its electricity from wind and solar power. (See Ex-CAISO Board Chair to Retire.)

Olsen, 74, served as CAISO board chair from February 2018 to Oct. 1. Earlier this month, he announced he would retire Nov. 30 with more than a year left in his term.

“I’ll be 75 years old soon and have been on the CAISO board for almost nine years,” Olsen said in an email. “That’s long enough on both fronts.”

Hybrid Resources Initiative

The board unanimously approved the second phase of CAISO’s hybrid resources initiative, letting co-located storage and generation resources operate under a single resource ID.

“The hybrid model allows for the underlying resources to be managed by the resource operator as opposed to the ISO,” CAISO COO Mark Rothleder said in a memo to the board. New provisions would allow hybrid resources to provide energy and ancillary services, he said.

“The proposal also includes a dynamic limit tool that will enable the resource operators to communicate their maximum and minimum operating limits to the ISO in real time,” Rothleder wrote. “This tool will help the ISO ensure it is issuing feasible dispatches to hybrid resources participating in the market.”

The board approved the first phase of the hybrid resources initiative in July. It laid out new rules for co-located resources that operate under separate resource IDs for dispatch purposes. FERC approved those Tariff changes Thursday, allowing them to take effect in December. (See related story, FERC Accepts CAISO Co-Located Resources Plan.) The ISO’s second-phase proposal also requires FERC approval.

Both phases are intended to better integrate storage coupled with solar and wind generation. CAISO needs thousands of megawatts of storage to transition to 100% clean energy by 2045, as state law requires. It has about 200 MW of storage now.

In the near term, the ISO is urgently trying to interconnect more storage before summer 2021. Resource shortfalls next summer are forecasted to exceed those in August and September, when CAISO declared energy emergencies, including rolling blackouts, in mid-August.

November 22, 2020March 9, 2025

FERC Rejects Challenges on PURPA Changes

FERC on Thursday rejected challenges to its July order revising how it enforces the Public Utility Regulatory Policies Act but granted clarification on several points (RM19-15-001, AD16-16-001).

Order 872 allowed state regulatory commissions more flexibility in how they establish avoided-cost rates for qualifying facilities and said they could require the rates to vary over the span of a QF’s contract. It also modified the “1-mile rule” and reduced the rebuttable presumption for nondiscriminatory access to power markets, from 20 MW to 5 MW, for small power production, but not cogeneration, facilities. (See FERC Issues Final Rule to ‘Modernize’ PURPA.)

Numerous stakeholders requested rehearing on Aug. 17, including California’s three investor-owned utilities, the Electric Power Supply Association, the Northwest and Intermountain Independent Power Producers Association, the Sierra Club, the Sustainable FERC Project and the Solar Energy Industries Association.

The requests were automatically denied when the commission failed to act within 30 days. In Thursday’s order, FERC explained why the challengers were wrong while also offering some clarifications. The order was supported by Chair James Danly and Commissioner Neil Chatterjee, both Republicans, but opposed by Commissioner Richard Glick, a Democrat, who had dissented in July.

‘Tiered’ Pricing, Variable Energy Rates

The commission rejected a request by Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison to clarify that it is no longer commission policy to permit states to subsidize QFs by the use of “tiered” avoided costs — the costs of a subset of facilities from which a state has mandated purchases or facilities that meet state requirements such as use of renewable fuel.

“PURPA neither requires nor prohibits states from establishing tiered procurement (and thus tiered pricing), such as California does,” the commission said.

FERC granted SEIA’s request for clarification that a state may only use variable rates to set avoided energy costs if the utility has fulfilled its obligations to disclose avoided-cost data as required under PURPA regulations.

FERC ruled in 2016 that Entergy did not have to purchase power from Occidental Chemical’s Taft plant in Louisiana because the PURPA generator had unconstrained transmission access and could sell its output in the MISO wholesale market. | Occidental Chemical

“We do not find the disclosure of such information unreasonable as the commission’s PURPA regulations already require its disclosure,” FERC said. “In addition, although electric utilities are required to disclose this data generally, it is especially important when a state has selected the fixed capacity/variable energy rate construct to ensure that QFs have this data from the purchasing electric utility to provide transparency with regard to a utility’s avoided costs.”

Competitive Solicitations

The commission also clarified the rules regarding the use of competitive solicitations to set QF rates.

“If a competitive solicitation is not conducted in accordance with the requirements of the final rule guidelines, then an aggrieved entity may challenge the competitive solicitation before the commission or in the appropriate fora,” FERC said.

Order 872 allows competitive solicitations as long as they are the result of a transparent process open to all sources, conducted at regular intervals and overseen by an independent administrator.

Rebuttable Presumption of Separate Sites

The commission offered clarification on several aspects of its requirement that the capacity of all small power production facilities “located at the same site” not exceed 80 MW.

“If a hydroelectric generating facility is more than a mile apart (but less than 10 miles apart) from an affiliated facility, yet on the same impoundment, the rebuttable presumption would be that they are at separate sites. We further clarify that, although the second sentence of footnote 769 [in Order 872] suggested that a hydroelectric generating facility in this circumstance was free to seek waiver (most likely in order to eliminate any uncertainty as to its status), it would be unlikely that any such a facility would, in practice, need to request such waiver.”

It also clarified that “the factors that may be used by an applicant to pre-emptively defend against rebuttal include the example factors identified in … paragraph 509 of the final rule.”

Paragraph 509 cited “physical characteristics, including such common characteristics as: infrastructure, property ownership, property leases, control facilities” and “whether the facilities in question are: owned or controlled by the same person(s) or affiliated persons(s), operated and maintained by the same or affiliated entity(ies).”

Rebuttable Presumption of Nondiscriminatory Access to Markets

FERC declined to rule on the argument by wind developer One Energy Enterprises that a behind-the-meter distributed energy resource’s primary purpose is to generate electricity for its host and any potential sale is secondary like cogeneration facilities.

But it clarified that behind-the-meter DERs such as municipal solid waste facilities and biogas facilities may argue that having “‘a predominant purpose other than selling electricity which would warrant the small power QF being treated similarly to cogenerators’ … supports their argument that they lack nondiscriminatory access to markets.”

“We will rule on any such arguments on a case-by-case basis taking into account the specific facts of the DER making the argument,” the commission said.

It also granted a request for clarification “that the list of factors in section 18 CFR 292.309(c) that small power production facilities between 5 and 20 MW can point to in seeking to rebut the presumption that they have nondiscriminatory access was not — but should be — added to 18 CFR 292.309(e) that applies to QFs in ISO-NE, MISO, NYISO and PJM, and also to 18 CFR 292.309(f) that applies to QFs in ERCOT. In order to avoid confusion, we hereby incorporate the factors listed in 18 CFR 292.309(c) into both (e) and (f).”

Glick’s Dissent

Commissioner Glick opposed Thursday’s ruling, saying during the monthly open meeting that the commission’s record was “insufficient to support several of the key changes” in Order 872. Glick said he requested a technical conference to create such a record but was denied by former Chair Chatterjee.

Glick said the commission “is administratively gutting PURPA” in response to utilities and others who had been unsuccessful in getting Congress to revise the law, which was last amended in 2005.

“It doesn’t matter whether you believe PURPA offers substantial benefits or whether you think it’s bad public policy,” he said. “The fact is these are matters for our elected representatives in Congress to decide. We should not be using our regulatory authority just because some might be frustrated by Congress’ inaction.”

The rulemaking eliminates QFs’ guarantee of obtaining a fixed-term, fixed-rate contract, undermining their ability to obtain financing, Glick said. “At the same time, utilities in vertically integrated states can depend on the guarantee that their ratepayers will pay for a generating plant over the life of the facility,” he said. “How is that not discrimination?”

Danly and Chatterjee, however, said claims that the rulemaking discriminates against QFs are “based on the incorrect assumption that electric utilities have not been required to lower their energy rates as prices have declined. The commission found, to the contrary, that utilities typically charge their customers cost-based rates, and, as their fuel and purchased power costs have declined, they typically have been required to provide corresponding reductions in the energy portion of their rates to their customers. …

“Requiring QF avoided-cost energy rates to likewise change as purchasing electric utilities’ avoided energy costs change does not create a discriminatory difference, but rather puts QF rates on par with utility rates,” they added.

Glick also criticized the commission for presumptively authorizing states to use LMPs to set avoided costs, “even though LMP may not fully represent the utility’s avoided costs. This leaves utility generation with a distinct advantage — exactly the opposite of the role Congress intended PURPA to play.”

Danly and Chatterjee rejected arguments that precedent prohibits establishing a rebuttable presumption that LMP reflects avoided costs for as-available energy.

“Because LMP is likely to reflect the true marginal cost of energy in the vast majority of cases … it is ‘so probable that it is sensible and timesaving to assume’ that LMP for a particular utility is an appropriate measure of the utility’s avoided costs for as-available energy, unless disproven in a particular case,” they said. “We leave open for specific cases to determine the appropriateness of using a particular LMP such that a QF could rebut the presumption that LMP is appropriate.”