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December 16, 2020March 9, 2025

Report Explores Federal Authority for Tx Buildout

The authors of a new report detailed on Monday how, in the absence of action by Congress, the U.S. can build the transmission lines needed to accommodate the thousands of gigawatts in new renewable generation coming online in the next few decades.

Columbia University’s Center on Global Energy Policy (CGEP) hosted a webinar on the paper it published jointly with the New York University School of Law’s Institute for Policy Integrity.

Michael Gerrard, founder and faculty director of Columbia’s Sabin Center for Climate Change Law, moderated the discussion. He noted that President-elect Joe Biden campaigned on a goal of a carbon pollution-free power sector by 2035, and the U.S. power sector is now 38% carbon free, about half from renewable and half from nuclear.

Clockwise from top left: Michael Gerrard, Columbia University; Sam Walsh, Harris, Wiltshire & Grannis; and Justin Gundlach, Institute for Policy Integrity | Center on Global Energy Policy

“Moving from 38% to 100% will require an enormous increase in renewable generation capacity from the current 1,100 GW, to about 3,000 GW,” Gerrard said. “Much of this new generation will be in areas that are far from where the power is needed, so the massive program of renewables construction will have to be accompanied by a massive program of new transmission, and we need the grid to have much greater functionality in many ways than it does now.”

Melissa Lott, CGEP senior research scholar, said investments in the grid have been lagging, despite the need.

“If we take away all the noise and just focus on the [market] signal, the reality is that we need new, long-distance transmission lines if we want to keep this transition affordable and if we want to do it on a timeline that’s going to both mitigate climate change and protect public health,” Lott said.

States’ Rights vs Federal Authority

If these long-distance transmission lines are so great, then why are they not getting built today? report co-author Sam Walsh, an attorney with Harris, Wiltshire & Grannis posed.

“One important reason, and which is partly the subject of our paper, has to do with state siting laws,” Walsh said. “In general, if you want to build a transmission line, you need regulatory approval from each state that the line traverses, and this state-by-state requirement has proven to be a significant hindrance for long-distance transmission lines that cross multiple states.”

In some cases, this has proven to be an insurmountable barrier when one state has denied approval outright, Walsh said.

Map and chart show the value of inter-regional coordination and transmission in decarbonizing the U.S. power grid. | Center on Global Energy Policy

“The problem is especially acute in the states that are traversed by a transmission line, but which are neither at the source nor the sink of the line,” Walsh said. “Regulators in those states may see little reason to approve a project or to authorize eminent domain for a project if their state is neither going to get the economic benefit of hosting the generation, nor the power itself.”

Congress recognized this problem in the Energy Policy Act of 2005, which created two pathways to get transmission built that do not require state approval. The first pathway is the so-called “backstop” siting authority, said co-author Justin Gundlach of NYU.

Federal siting authority is provided for in Section 216 of the Federal Power Act, which empowers FERC to permit construction of a transmission project where a state agency would not do so, Gundlach said, noting two key features of the regulation.

“The first directs the Department of Energy to designate National Interest Energy Transmission Corridors in appropriate locations, and the second gives FERC backstop permitting authority within those borders, meaning there — and only there — FERC can displace a state’s permitting authority,” Gundlach said.

Congress also limited the commission’s authority by requiring that it must establish that a project meets various public interest criteria.

DOE designated two corridors in 2007: one in the southwest and one in the mid-Atlantic. Their legality was challenged by states, their utilities and their utility regulators. In 2011 the 9th U.S. Circuit Court of Appeals vacated both designations, saying the department erred in not consulting the states about its study of the issue prior to the designations.

Since 2011, DOE has not recommended any further corridor designations, so the authority has sat dormant, Gundlach said.

The authors make 20 recommendations. “First, DOE should revise or supplement the 2020 congestion study that it just issued in the fall,” Gundlach said. “For instance, the initial version of this study only identifies instances of present congestion, whereas we think it ought to identify instances of both present and foreseeable future congestion.”

The authors also recommend that the department should designate one or several new corridors.

“When doing so, DOE should prioritize corridors that connect large, constrained renewable resources or potential to load, and recognizing that even just designating an area can make parties with an interest nervous, we think DOE should try to confine its corridor designations, in contrast to the two from 2007, to avoid a groundswell of opposition in locations where it’s unlikely that you’re actually going to see a project.”

Insiders’ View

David Hill, CGEP fellow and a member of the NYISO Board of Directors, found the paper well researched and liked its overall approach. “It doesn’t just complain; it’s got very detailed recommendations, and I think that’s excellent and that it deserves serious consideration.”

Hill said that relevant sections of EPAct05 “are very powerful authorities, and they haven’t been used to their full extent, and there’s a lot more that they could be used for and should be used for.”

He recalled that he was involved in the designation of the two transmission corridors when he was general counsel at DOE.

“I know the courts decided that we didn’t do that right, but we thought very carefully about” designating such broad corridors, Hill said. It ended up being problematic, but narrow corridors would have entailed other significant difficulties, he said.

While the authors suggest that the DOE ought to delegate its authority to FERC to help expedite the process, it’s clear that is not what Congress wanted, Hill said. Congress “knew very well what the functions of DOE were” and separated them from those of FERC, he said.

Former FERC Commissioner Cheryl LaFleur, now a CGEP fellow and member of the ISO-NE Board of Directors, agreed that more transmission is needed and that state siting and permitting authority — coupled with the influence of incumbent utilities that may oppose new lines coming through their territory — have been a major barrier to long-distance transmission across multiple states.

Clockwise from top left: Michael Gerrard, Columbia University; Consultant Lauren Azar; Cheryl LaFleur, ISO-NE; Rob Gramlich, Grid Strategies; and David Hill, NYISO | Center on Global Energy Policy

“I have testified in Congress more than once that Congress should rewrite Section 216 to restore effective FERC backstop siting authority, so you can see how effective that has been,” LaFleur said. “Given the unlikelihood of congressional action, I think this paper could not be more timely.”

While effective backstop authority could help new transmission get sited and built, even the mere threat of exercising such authority could encourage states to work together, she said.

“I do think, however, that FERC backstop authority would not be a silver bullet … and we can expect that states that are opposed to transmission lines will find a way to use their existing authority … to make life very difficult for project sponsors,” LaFleur said. “All of this points to the continuing need to satisfy state authorities and citizens that the proposed facilities are in their best interests to really get them on board.”

With a new administration, it’s important that any steps it takes to improve environmental reviews for natural gas pipelines not “spill over and make it harder to build transmission lines for renewable projects,” she said, citing “schizophrenia” on the issue, with people wanting to slow down National Environmental Policy Act reviews for gas pipelines but speed up permitting for renewables.

Grid Strategies President Rob Gramlich said that the country will need two to three times more transmission than it has now, which doesn’t necessarily mean all that many new lines.

“Solar can be done closer to load, so you don’t see much congestion, but that is a temporary dynamic. … Soon you’ll see solar congestion,” Gramlich said. “We need these lines built now for the end of the decade when we’ll really need it.”

Independent consultant Lauren Azar said that beside the siting challenges, “one of the key problems we have now is the weak nexus between the parties who would like to develop a national transmission plan and those who could actually get it built,” suggesting that President-elect Biden convene the grid operators, FERC commissioners and state governors to work on the issue.

December 16, 2020

Supply Chain Rules Increasing Costs

Supply chain rules from NERC and the federal government are increasing costs and procurement cycles for utilities and technology vendors, cybersecurity experts said yesterday.

The recent cyber breach of SolarWinds’ Orion product, which gave Russian hackers access to multiple federal agencies, “really is a wakeup call,” Tom McDonnell, power generation and energy industry leader at Rockwell Automation, said during a webinar sponsored by POWERGEN International. “That vendor-regulated [entity] relationship has to be a lot tighter than before.”

But McDonnell had a plea to his fellow panelists, who were from American Electric Power and NERC. “The one thing we ask is, don’t overcomplicate things for vendors. … Clear communication and common sense are really critical.”

Tom McDonnell, Rockwell Automation | *POWERGEN International*

He said he feared the electric industry will face the kind of overkill found in some Food and Drug Administration regulations. “The joke that we would always make in that space is you create 8 pounds of paper for 1 pound of drug.”

Jeffrey Sweet, director of security assessments for AEP, said the utility’s costs and workload have increased as a result of supply chain requirements from NERC standards, presidential executive order 13920 and Section 889 of the National Defense Authorization Act.

“It’s increasing the need for us to assess our vendors and the [security] of our products and services,” Sweet said. “Because of the increased assessment time, it takes longer for us to get through the purchasing process.”

Sweet said the SolarWinds breach could affect utilities. “It very possibly can, based on what I understand and what the investigations have turned out so far. … The code base for SolarWinds, certain versions, was in fact compromised. … Some entities have claimed that they have actually seen callouts going from their SolarWinds to some command-and-control centers. So please, definitely check your environment and make sure you don’t have those versions of SolarWinds.”

Supply Chain Rules — Howard Gugel, NERC | *POWERGEN International*

Howard Gugel, NERC’s vice president of standards and engineering, discussed the organization’s supply chain work to date and several issues it will confront in the future, including gaining an understanding of interactions between the bulk electric system and behind-the-meter generation and other distributed energy resources, referring to them as “the great unknown.”

He also said system planners must eliminate siloed thinking. “We’ve planned the system just thinking about physical assets, and then the IT issues would be left to the IT folks. I think as we go into the future, we’re going to have to get those two groups talking much more together and ensuring that as we plan the system, we think about the cyber impacts on IT; and then as we begin to roll out the connectivity of things in the future, that they link back into the planners and make sure that there’s a good handshake that occurs there.”

Gugel also cited issues over virtualization and cloud computing. “We’re beginning to tackle that right now with our cyber standards team looking at those issues. How do you implement that? How do you practically roll that out in the field?”

Sharing Assessments

Sweet noted the need for continuous monitoring of vendors.

“Just because everything was good when you first assessed them doesn’t mean it stays good for the rest of the term of that contract,” he said. “Many of our contracts may be three or five years or even longer. … Things change. How are they conducting the business? Who’s influencing their business? Have they moved operations overseas, or is there another company that’s purchased their operations? … Even if the ownership doesn’t change, things change within a company. And so, the policies and standards that … they had in place may have changed, and now they may not be as effective as they once were.”

McDonnell said Rockwell, a multinational manufacturer and technology and solutions company, is “constantly changing where we manufacture things. … We’ve got to have that relationship with the vendor that is a very open and transparent relationship that you have to revisit on a timely basis.”

AEP joined with Fortress Security in 2019 to create the Asset to Vendor Network to reduce the costs of assessing vendors. The network now also includes Southern Co., Hitachi ABB and NiSource. (See CIP Compliance: Don’t ‘Boil the Ocean.’)

“We’ve matured our program, and now we’re trying to help the rest of the industry by providing them a lower cost of getting that assessment data, including the foreign ownership control and investment entities; the provenance reports and stuff of that nature,” Sweet said. “We’re trying to get that out there so that even a small utility can afford to have that.”

Impact on Competition?

Moderator Scott Affelt, president of XMPLR Energy, asked whether the supply chain rules could reduce competition by forcing some vendors out of business.

“If the vendor is actually doing what we’re asking them to do and shows us they’re doing it, then it won’t have an impact,” Sweet said. “But if the vendor refuses to comply with the standards or meet the requirements of the standards, then they’re probably going to get put to the side, at least by those who are regulated.”

Gugel said if some vendors exit the business, others will likely rush to fill the vacuum.

As for the costs of compliance? “Bearing an appropriate amount of cost for an appropriate reduction of risk is probably a good thing,” Gugel said. “As a consumer, I would expect that.”

December 16, 2020

NERC: Grid Operations ‘Fundamentally Changing’

The expansion of renewable energy resources and retirement of conventional generation over the next decade is expected to “fundamentally [change] how the [bulk power system] is planned and operated,” according to NERC’s 2020 Long-Term Reliability Assessment (LTRA), released Tuesday.

NERC produces the LTRA each year to assess North American resource adequacy in the next decade, and identify trends that could affect grid reliability and security both in individual regions and in the continent overall. Preparation of this year’s report began in 2019, John Moura, NERC’s director of reliability assessment and performance analysis, said at a media event on Thursday.

NERC Grid Operations — NERC-wide cumulative distributed solar PV capacity, 2020-2030 | *NERC*

Most areas are expected to have sufficient resource capacity for annual peak demands between 2020 and 2025. A major exception is Ontario, which is projected to have a 2025 peak anticipated reserve margin of 2% against a reference margin level of 15.9%. MISO was also called out as “marginal,” with 2025 peak anticipated reserve margin of 17% against an 18% reference margin. All other areas were classified as “adequate,” though the Maritimes were noted to have a relatively small capacity surplus of 36 MW with the potential for shortfalls in 2022 and 2023.

Renewable Output Forecasting

But NERC cautioned that resource adequacy is only part of the story. With the resource mix more varied than ever before, the type of generation must be considered as well. And some areas with sufficient capacity on the surface were found to have more risk than meets the eye.

NERC assessment areas with solar and wind capacity greater than 5% of on-peak demand | *NERC*

The report noted that the output of variable energy resources, such as wind, solar and run-of-river hydroelectric plants, are to blame, “can change according to the primary [driver] … resulting in plant output fluctuations on all time scales.” The report noted a number of assessment areas where solar and wind resources form more than 5% of peak demand for 2020 or are projected to do so by 2025.

ERCOT is the standout, with solar and wind generation expected to account for 11.9% of net internal demand five years from now. WECC’s CAMX region (California and Baja California Norte, Mexico) also currently draws on solar and wind resources to meet internal demand, though not to the same extent as ERCOT. PJM and MISO are also expecting significant growth in wind and solar assets planned for addition over the next 10 years, with PJM to have 98.3 GW by 2030, up from 10.9 GW today, and MISO set to grow from 22.3 GW to 106.6 GW.

These additions are part of strong growth in renewables expected across the BPS; wind and solar resources are expected to make up 57% of new capacity by 2024. This can lead to uncertainty in grid planning, as weather conditions are not always predictable — a problem compounded by many utilities’ use of outdated models for solar and wind generation, or none at all, as a joint report by NERC and WECC warned earlier this year. (See NERC, WECC Warn of Inverter Modeling Gaps.)

NERC recommended that the industry “verify that inverter-based resource models … agree with the as-built, plant-specific settings, controls and behaviors of the facility,” and that the ERO improve reliability standards “to account for inverter-based resource performance and characteristics.” In addition, the ERO should work with industry to review data needs for distributed energy resources such as battery storage and rooftop solar panels to improve performance of these resources.

Uncertain Impacts from Pandemic

NERC did not attempt to incorporate the impacts of the COVID-19 pandemic into the LTRA, citing uncertainty about the duration of the crisis. However, the organization noted “increased uncertainty” in demand projections that began to be felt amid stay-at-home and remote work policies adopted earlier this year in many areas. (See Sagging Demand Cushions NPCC’s Summer Outlook.) NERC also observed that changes in industrial load “can affect the availability of [demand response] programs that rely on curtailment of industrial customers during periods of high demand.”

While no “specific threats or degradation to the reliable operation of the BPS” were flagged in the report, NERC did warn that cybersecurity risk remains heightened because of the remote work postures continuing at many utilities. Entities will also continue to face challenges obtaining personal protective equipment for operators and field personnel for the foreseeable future, and they may have to continue reckoning with the consequences of deferring maintenance.

December 15, 2020

Pa. Eyes EE, Renewables for RGGI Funding

Pennsylvania is considering spending some of its carbon credit proceeds on energy efficiency and renewable energy development, a state official told Infocast’s Mid-Atlantic Renewable Energy Summit last week.

The state Department of Environmental Protection (DEP) estimates that carbon credit auctions under the Regional Greenhouse Gas Initiative (RGGI) will yield annual revenues of between $179 million and $320 million through 2030 once Pennsylvania joins the 10-state compact. (Virginia will become the 11th state to join in January.)

Pennsylvania RGGI — Allen Landis, Pennsylvania DEP | *Infocast*

Allen Landis, executive director of DEP’s Pennsylvania Energy Development Authority, said state officials intend to spend RGGI auction funds on eliminating air pollution because they are relying on the state Air Pollution Control Act as the legal basis for joining the compact.

He said the state expects energy efficiency to be a “major piece” in the spending plans, adding that efficiency would provide “tremendous dividends” for grid reliability, energy rates and job creation.

Renewable energy development in the state is also likely to receive funding, Landis said, because increasing Pennsylvania’s renewable capacity is essential to meeting Gov. Tom Wolf’s goal of a 26% reduction in statewide greenhouse gas emissions by 2025 while ensuring its electricity sector stays competitive in the long term. (See Pennsylvania Joins US Climate Alliance.)

Wolf, a Democrat, has been battling with the Republican majority legislature over the state’s entrance into RGGI since he signed an executive order in 2019 directing DEP to draft a rulemaking for joining the compact. (See Pennsylvania Governor Signs RGGI Executive Order.)

In September, the General Assembly passed a bill barring the state from joining RGGI or taking any action to control carbon dioxide emissions without legislative approval, but Wolf vetoed it. (See Pa. House Passes Bill Limiting RGGI Entry.)

Landis said the “greenhouse gas abatement” piece of the proposed RGGI regulations include programs ranging from electric vehicle charging stations to curtailing leaking emissions at abandoned oil and gas wells.

Clockwise from top left: Kathleen Robertson, Exelon; Flora Cardoni, PennEnvironment; Allen Landis, Pennsylvania DEP; and Pennsylvania Rep. Chris Rabb (D). | *Infocast*

“The first and most important thing for us right now is to put the process out there, get input, draft out the plan and let people weigh in on it and make sure their voice is heard so everyone can contribute as to how those funds are spent,” Landis said in response to a question from moderator Flora Cardoni, field director at PennEnvironment.

The state Environmental Quality Board is accepting comments until Jan. 14 on the proposed regulations, which were published last month. Comments may be submitted through the eComment system. The board also held a series of virtual public hearings on the regulations.

Protecting Communities

State Rep. Chris Rabb (D) told the conference that regulators and the legislature needs to have a “laser focus on the hot spots” of environmental damage in Pennsylvania and use RGGI funds to correct “egregious” negative impacts on the environment in vulnerable communities. There is not much precedent for doing the type of work laid out in RGGI, he said, which makes it difficult for politicians and regulators to find the right mix for the program to succeed.

Rabb said politicians focus too much effort on “symptom chasing,” especially when they deal with environmental issues: They’re willing to address the symptoms of problems but don’t have the courage to go to the heart of systemic issues that create the problems.

RGGI is not the “universal solution” for all the environmental problems in Pennsylvania, Rabb said, but its goals are a step in the right direction. He said it is important right now for regulators to make sure the direction of the program is “sound” while addressing the needs of communities that will be impacted by the new regulations.

The state has to look at creating opportunities for “regenerative effects” by creating new green jobs and entrepreneurial opportunities for fossil fuel industry workers whose livelihoods are at risk, he said.

“These are frontline communities that we have to take care of,” Rabb said during the Dec. 8 session, which also featured discussion on how the state can further its renewable policies by increasing the goals in the 2004 Alternative Energy Portfolio Standards law. “This is about how we can transition them into a new reality where there are business opportunities and other community-centered efforts that will help make us whole.”

Industry Perspective

Kathleen Robertson, director of strategic initiatives and environmental policy at Exelon, said she appreciated the idea of job training being included in possible uses for RGGI funds. She said she believes an argument can be made that job training can be linked to improving air quality by focusing on careers like oil and gas well abatement, weatherization of buildings and the installation of energy efficiency projects. Weatherization provides opportunities for local workers because the jobs cannot be outsourced to cheaper foreign labor, she said.

Community support will be important as some of the existing generation plants transition or close, Robertson said, pointing to the shuttering of Three Mile Island nuclear plant in central Pennsylvania in 2019. (See Exelon to Close Three Mile Island.) She said the closure of generation plants can be devastating to communities’ tax revenues and employment base.

“Given the amount of money RGGI can raise, I think one of the really good opportunity areas is transitioning both the workers and the communities into the clean energy economy and making sure everyone has a leg up in that,” Robertson said.

Legislative Action

Cardoni asked Rabb how likely Pennsylvania’s legislature is to approve RGGI given the Republican resistance. (See GOP Continues Opposition to Pa. RGGI Plans.)

Rabb said Republican legislators will fight RGGI “tooth and nail” because they don’t want to lose fossil fuel jobs or the industry’s campaign contributions. The lack of limits on campaign donations in Pennsylvania makes it even more difficult to get controversial legislation passed, he said.

The oil and gas industry in Pennsylvania has more lobbyists than there are state legislators, Rabb said, which is an enormous number considering the state has the largest full-time legislative body in the country, with 253 members in the General Assembly. Rabb said the money in campaigns goes beyond partisan politics and is a problem of both Republicans and Democrats.

“The largest industries with the deepest pockets win,” Rabb said. “They win in a very cynical way. They win by influencing incumbents and candidates by cutting very big checks.”

December 15, 2020

ERCOT Board of Directors Briefs: Dec. 8, 2020

ERCOT’s Board of Directors last week approved a package of nearly three dozen revision requests that included the final work of two task forces developing policies and principles for energy storage resources (ESRs) and the real-time co-optimization (RTC) of energy and ancillary services.

Board Chair Craven Crowell called the work a “major milestone” in the development of ERCOT’s Passport Program, which is designed to allow emerging technologies to expand their participation in the market. Staff and stakeholders will spend the next four years aligning the task forces’ work with an upgrade of the Texas grid operator’s energy management system that also incorporates distribution generation resources (DGRs) into its systems.

“That’s a huge win for us, but work still needs to be done to button up some of the details,” chair of ERCOT’s RTC task force Matt Mereness said.

That work will begin in February during the board’s next meeting, when staff will begin updates on Passport’s schedule and status. ERCOT said it will have one of the world’s most sophisticated market designs when the program is completed in 2024.

ERCOT Board of Directors — The Passport Program’s timeline. | *ERCOT*

“I look at what was done there as world class,” said Engie’s Bob Helton, who chairs the Technical Advisory Committee that oversaw the task forces. “I would really like to see other RTOs follow the same process.”

Staff and stakeholders have drafted more than 700 pages of new and/or revised protocols and market rules for ESRs, DGRs and RTC. Now that they are approved, they will be used to draft business requirements for implementation.

ERCOT CEO Bill Magness said Passport represents “the most major changes in our system we’ve seen in a number of years.” The program, which staff expect to cost as much as $55 billion, will touch nearly every single ISO system, as well as those stakeholders use to communicate with ERCOT.

“We are in a good position to start taking on the work in 2021,” Magness said, noting much of what has been accomplished was done with staff and stakeholders working remotely from their homes.

“This is unprecedented how well this has gone,” Public Utility Commission Chair DeAnn Walker said.

The PUC directed ERCOT to add RTC to its market in 2018. The market tool will award ancillary services every five minutes during the operating day, allowing the market to adjust to changing grid conditions. The commission recently opened a rulemaking to implement RTC in the market (51588).

Crowell, Walsh, Pfirrmann Honored

In a virtual sendoff, staff and stakeholders honored Crowell, his vice chair, Judy Walsh, and Karl Pfirrmann for their nine years of service together on the board.

The three unaffiliated directors joined the board in 2012 for the first of three three-year terms. Crowell and Walsh have held their leadership positions ever since; ERCOT bylaws require the chair and vice chair be unaffiliated directors. Pfirrmann chaired the Human Resources and Governance Committee.

“Well, I guess this day had to come,” Magness said in kicking off the honors. “In 2020, we talk about how we miss people, how we miss being in person. Some days, it’s just good to be in sweatpants and not drive anywhere. This really would be a good day to have handshakes and hugs available, to really send our friends off, but words are going to need to do today.”

Staff presented a video with words of praise for Crowell, Walsh and Pfirrmann from the PUC’s three regulators, previous PUC Chairs Donna Nelson and Pat Wood, and fellow directors. In his comments, Commissioner Arthur D’Andrea made the three honorary Texans for life “through the power invested in me” by the state’s Public Utility Regulatory Act. They will all receive state flags flown over the Capitol in recognition of their service and honorary resolutions from the Texas Senate Committee of Business and Commerce.

“I’ve looked at PURA before and I’m not sure [D’Andrea’s power] is in there, but Arthur knows the law, and I trust him,” Magness said.

“I will miss working with Judy and Karl. I’ve always felt a special bond with the two of them,” Crowell said. He thanked Nelson for encouraging him to apply for an ERCOT board position while he was still on the Texas Reliability Entity’s board and ERCOT staff for being some of brightest people in the industry.

Walsh recalled her time on the PUC with Wood, when they helped deregulate the Texas electric industry and usher in “the best wholesale and retail market anywhere.”

“Who would have believed two little ol’ regulators could or would do a thing like that,” Walsh said.

Pfirrmann, who is celebrating 50 years in the industry this month, harkened back to a time when televisions were black and white and Saturday mornings were reserved for “Sky King,” Roy Rogers and Dale Evans.

“Google their names to figure it out,” he said, before referencing Rogers and Evans signature song, “Happy Trails to y’all.”

Members approved in a voice vote former Consolidated Edison CEO Craig Ivey’s nomination to the board’s last remaining open unaffiliated director’s slot. His name has been sent to the PUC for final approval. (See “Con Ed CEO Nominated to Board,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)

“This usually takes a lot longer when we sit down to eat,” Magness said.

The commission in November approved the elections of Michigan Public Service Commissioner Sally Talberg, retired Texas PUC Approves ERCOT Board Members.)

The board and its committees will nominate and elect their chairs and vice chairs during their February meetings.

Record Solar Generation Installed

Magness said ERCOT integrated a record 2,849 MW of utility-scale solar projects over the last 12 months, along with 4,777 MW of wind capacity, despite the COVID-19 pandemic. The ISO also saw 14 days of more than 20 GW of wind energy on the system. It currently has more than 25 GW of installed wind capacity and 3.8 GW of installed solar capacity after having shed more than 5.6 GW of coal generation since 2014.

“There are a lot of changes in the resource mix,” Magness said during his CEO update.

ERCOT is on track to finish the year $28.5 million over budget, driven primarily by shortfalls in the administrative fee ($10.6 million) and interest expense ($15.7 million). The ISO’s expenditures are projected to be $2.6 million over budget.

“The [weather] forecast was about right. It was the [pandemic’s] economic forecast that brought [the administrative fee] down a little bit,” Magness said.

Directors Approve Opposed NPRRs

Helton celebrated the end of three years as TAC’s chair by bringing forward a pair of revision requests that he said were among the “most divisive” he has seen.

“So I’m going out on a high point,” he joked.

Both nodal protocol revision requests (NPRRs) received opposing votes during recent TAC meetings on their way to comfortable endorsements.

The board passed NPRR1055 by an 11-4 margin in a roll call vote, raising similar concerns as did TAC members over staff’s decision to sponsor the measure on behalf of non-opt-in entities (NOIEs). (See “REPs, NOIEs Debate Revision Change,” ERCOT Technical Advisory Committee Briefs: Nov. 18, 2020.)

Two unaffiliated directors and members representing the independent retail electric provider and independent power marketer segments voted against the change.

“This should have been sponsored by the NOIE community because this is an exception for them,” DC Energy’s Seth Cochran said.

The revision gives ERCOT the discretion to accept for good cause NOIEs’ late submissions that they own or control their generation resources serving as a source resource node, or that the resource has a contractual commitment for capacity and/or energy with the NOIE. The attestation allows the ISO to certify congestion-hedging instruments granted to NOIEs.

The change also requires ERCOT to post a market notice by Sept. 1 of each year, reminding NOIEs of the annual deadline.

“We were approached by some of the NOIEs who missed this deadline. … There were issues around timing being coincident with when people were moving to remote work,” Magness said. “We needed to ask the market to approve [NPRR1055] because we don’t have it in the protocols. We don’t think it harms our ability to get the work done in this very limited situation.”

The board approved NPRR945 with only one dissenting vote from Brazos Electric Power Cooperative’s Clifton Karnei. Representing the cooperative market, Karnie sided with fellow sector members that opposed the measure at TAC, saying it could shift transmission costs to entities that cannot shift their load. (See ERCOT Technical Advisory Committee Briefs: Oct. 28, 2020.)

The NPRR removes the “associated load” term that some proponents say has been interpreted in some instances to restrict net-metered private-service arrangements to the same entity that owns the load and generation. The revision requires that entities be behind the same interconnection point.

Board Confirms 2021 TAC Reps

The board confirmed the 2021 TAC representatives, which includes three new members along with 2021’s holdovers: Avangrid Renewables’ Thresa Allen in the independent generator segment; EDF Trading North America’s Kevin Bunch in the independent power marketers segment; and CenterPoint Energy’s Eric Easton in the investor-owned utilities segment.

TAC will choose its leadership when it meets again in January.

The directors also signed off on a pair of measures endorsed last month by TAC: ramp-rate restrictions for the Southern Cross DC tie to clarify ERCOT will curtail schedules when necessary to conform with the system’s ramp capability, and staff’s recommendation to change the methodologies used to compute non-spinning reserve and regulation reserve service in response to incoming solar generation’s additional variability and uncertainty. (See “New Interconnection Process for Sub-10-MW Generator,” ERCOT Technical Advisory Committee Briefs: Nov. 18, 2020.)

In other actions, the board:

approved an adjunct membership for Solar Prime. A corporate member when 2020 began, the solar developer lost its status upon the sale of generation assets but expects to meet membership criteria early next year.
accepted Schellman & Co.’s 2020 system and organization control audit with no testing exceptions.
agreed with the Human Resource and Governance Committee’s recommendation to approve the 2021 ERCOT key performance indicators.

Consent Agenda Includes 32 Changes

The directors unanimously approved a consent agenda comprised of 20 NPRRs, a change to the Commercial Operations Market Guide (COPMGRR), three revisions to the Nodal Operating Guide (NOGRRs), an Other Binding Document (OBDRR) modification, four revisions to the Planning Guide (PGRRs), one system change request (SCR) and single changes to the Resource Registration Guide (RRGRR) and Verifiable Cost Manual (VCMRR):

NPRR1001: clarifies that ERCOT will issue an “emergency notice” when it is operating in an “emergency condition,” but issuing an “operating condition notice,” “advisory” or “watch” does not mean that ERCOT is operating in an “emergency condition.”
NPRR1007: updates the ERCOT system’s management activities in the protocols to address changes associated with RTC’s implementation.
NPRR1008: updates day-ahead operations in the protocols to address changes associated with RTC’s implementation.
NPRR1009: updates transmission security analysis and reliability unit commitment to address changes associated with RTC’s implementation.
NPRR1010: updates the adjustment period and real-time operations in the protocols to address changes associated with RTC’s implementation.
NPRR1011: updates performance monitoring in the protocols to address changes associated with RTC’s implementation.
NPRR1012: updates settlement and billing in the protocols to address changes associated with RTC’s implementation.
NPRR1013: updates the protected information provisions, definitions and acronyms, market participants’ registration and qualification, and market suspension and restart in the protocols to address changes associated with RTC’s implementation.
NPRR1014: enables ESRs’ integration into the ERCOT core systems as a single-model resource, replacing the existing “combination model” paradigm where ESRs are treated as two resources — a generation resource and a controllable-load resource. This NPRR will be implemented simultaneously with other RTC-related changes and with the upgrade to the ERCOT EMS in 2024.
NPRR1026: establishes rules for and enables self-limiting facilities’ integration into the ERCOT markets and core systems.
NPRR1028: requires qualified scheduling entities to notify ERCOT of physical limitations on their resources’ starting ability that are not modeled in the reliability unit commitment software and excuses compliance with parts of RUC dispatch instructions that violate a notified resource’s physical limitations. The NPRR also establishes a requirement that ERCOT extend a RUC commitment to honor a resource’s minimum run-time limitation when a physical limitation delays its ability to reach its low sustained limit.
NPRR1029: enables DC-coupled resources’ (defined as an ESR type required to follow all rules associated with ESRs in addition to meeting this change’s requirement) integration into ERCOT’s core systems. The NPRR applies to both the current combo model era and the future single model era.
NPRR1031: requires ERCOT to post operations messages informing market participants when load is curtailed because of a transmission problem.
NPRR1032: limits the DC tie schedules used in RUC optimization and settlements to the ties’ physical rating.
NPRR1039: removes the defined term “market information system public area” from the protocols and replaces it with “ERCOT website.”
NPRR1041: adjusts the expiration of the protected information status of wholesale storage load data from 180 days to 60 days, aligning the disclosure of real power consumption and metered generation output to 60 days after each operating day.
NPRR1042: adjusts the planned capacity in the Capacity, Demand and Reserves report to remove previously mothballed or retired generation resources that may be repowered but do not have an owner that intends to operate them.
NPRR1043: clarifies that ESRs’ withdrawn charging load (excluding auxiliary load) will be settled based on the nodal price similar to its injections, even if the ESR does not seek or cannot qualify for wholesale storage load (WSL) treatment by replacing the term “ESR load that is not WSL” with the defined term, “non-WSL ESR charging load.” The latter load will be priced at nodal but, unlike ESRs receiving WSL treatment, will be subject to applicable load ratio share-based charges.
NPRR1046: removes additional uses of “dynamically scheduled resource” to align with NPRR1000.
NPRR1047: consolidates gray-box language related to NPRR973 and NPRR1016.
COPMGRR048: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website” and removes references to the “ERCOT market information list.”
NOGRR207: clarifies that ERCOT’s issuance of an “operating condition notice,” “advisory” or “watch” does not mean that ERCOT is operating in an emergency condition.
NOGRR211: updates language related to supplemental ancillary service markets, ancillary service deployment and ancillary service responsibilities and obligations to address changes associated with RTC’s implementation.
NOGRR217: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website.”
OBDRR020: updates the methodology for setting maximum shadow prices for network and power balance constraints to address changes associated with RTC’s implementation.
PGRR081: describes how self-limiting facilities will be evaluated in the generation resource interconnection or change request process.
PGRR082: extends the interconnection process to distribution-connected resources and settlement-only generators (SOGs) and clarifies the roles of ERCOT and transmission and/or distribution service providers.
PGRR083: requires a Regional Planning Group (RPG) project number for projects submitted for RPG review and removes the specification of transmission project information tracking information from the Planning Guide.
PGRR084: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website.”
RRGRR023: establishes provisions and requirements in the guide for ESRs that are identical to those already in place for generation resources and SOGs.
SCR812: creates an Intermittent Renewable Generation Integration report similar to wind and solar power production integration reports.
VCMRR030: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website.”

December 15, 2020

Industry Eager for New Leadership on Tx, Climate

Panelists during last week’s fourth annual gridCONNEXT conference expressed tepid hope that the incoming Biden administration will be able to advance some of the policies they say are needed to integrate the surge of renewables coming online and address climate change.

Tepid because, as many noted, regardless of the results of the Jan. 5 special elections in Georgia that will decide which party controls the Senate, Congress will remain bitterly divided for at least the next two years. Many speakers listed off the issues that the two parties can come to some agreement on, such as energy efficiency, research and development funding, and enhancing grid cybersecurity.

But as they did so, there were notable hints of doubt, or even fatigue, in their voices.

“Can we reconfigure the grid in a way that allows us to take advantage of these [renewable] resources … and take advantage of this changing energy landscape?” posited Tracy Warren, director of the American Council on Renewable Energy’s Macro Grid Initiative, which seeks to expand transmission nationwide, on Dec. 8, the first day of the online conference. (See ‘Macro Grid’ Seeks to Connect Grid’s Regions.)

“I think it is a serious question [of] ‘can we do this?’” she continued. “As many of you know, we’ve been talking about infrastructure for a long time. ‘Infrastructure Week in Washington’ is a punchline to unfunny jokes. Look at what’s happening now: Congress is having difficulty passing a COVID relief bill in the middle of a pandemic.”

renewables transmission — Stitching together the power system’s major regions would allow the U.S. to fully harness its renewable resources, ACORE and other groups argue, citing NREL’s Interconnections Seams Study. | *NREL*

The need for more transmission pervaded nearly every discussion during the conference, regardless of whether it was a panel topic. But past failures of ambitious, interstate transmission providers, such as Clean Line Energy Partners, also frequently came up.

“I was looking over some notes from a transmission conference I spoke at about 12 years ago, and unfortunately the three points haven’t changed,” Jonathan Weisgall, vice president for legislative and regulatory affairs at Berkshire Hathaway Energy, said Wednesday. “I once joked [that] we better hire eighth-graders for our transmission department so they can actually see projects finished before they retire.”

“We need some direction; we need some leadership at the federal level,” said Jay Caspary, vice president at Grid Strategies. “I don’t think the existing planning processes, at least at the regional level, are looking out far enough and reflecting what we expect to happen [in] 20, 30, 40 years. They’re more short-term and looking at the reliability problems in the next few years.”

But even that approach, Caspary noted, failed this year during a record heat wave in the Western U.S. that led to rolling blackouts in California. One of the main problems that led to them was the state’s lack of import capability. “There was 12,000 MW of wind in the [Great Plains] that couldn’t get there,” Caspary said. “We need to think differently.”

Weisgall, Caspary and others called for FERC to revisit Order 1000 after President-elect Joe Biden takes office and names a new chairman. They also expressed hope that it would continue to direct the integration of new technologies into RTO markets, similar to Orders 841 and 2222.

“We’ve got to improve the business case for more transmission investment,” Weisgall said. “We’ve got to do that at FERC, in Congress and in the states.” He also called for Congress to designate an agency — either FERC or the Department of Energy — as a single point of contact for transmission planning.

Weisgall noted that Berkshire’s Iowa-based MidAmerican Energy joined MISO, and NV Energy and PacifiCorp the Western Energy Imbalance Market (EIM), without any legislative or regulatory mandates. But despite the EIM’s success, and the expected benefits of its upcoming extended day-ahead market, a full-fledged RTO would provide even more, such as more efficient dispatch of renewables, he said. “Nobody disagrees with that. Nobody disagrees with the goal of trying to minimize the number of seams and maximizing markets. We really do need a full regional market to do that.”

The main problem? “Cali-phobia.”

Weisgall shared the panel with CAISO Board of Governors Chair Angelina Galiteva and NYISO CEO Richard Dewey. He noted that while both represented the U.S.’ two ISOs, NYISO is unlike CAISO in that the latter was formed by California law with a board appointed by the state’s governor. “You’re not going to get to a West-wide RTO if the California governor appoints that board,” requiring a change to state law or even the Federal Power Act, he said. “It’s going to be incredibly difficult” given the political diversity in the West and dysfunction in Washington.

‘Dysfunctional and Unfixable’

Government dysfunction was the main topic of a keynote address on the last day of the conference by John Hofmeister, CEO of Citizens for Affordable Energy and former president of Shell Oil. He took the pessimism about Congress at the conference to the next level.

“The governance of energy [in the U.S.] is broken and dysfunctional and unfixable in its current form,” Hofmeister said. “Twenty years into the 21st century, and we are still stumbling along as a society” in addressing climate change. “Nine presidents, from Richard Nixon to Donald Trump, have failed to fix this problem.”

Hofmeister’s message was less about the urgency of the problem than its magnitude and the inherent inability of the U.S. government to solve it. Two-year election cycles lead Congress to focus only on short-term problems, while the multitude of federal agencies and congressional committees responsible for energy policy each have their own priorities, making it impossible for the government to be “on the same page” about global problems, he argued.

The one system “that sustains us through thick and thin, regardless of election cycle,” has been the Federal Reserve, whose Board of Governors comprises seven members nominated by the president and confirmed by the Senate for staggered 14-year terms. He called for a similar body dedicated to setting policy on climate change, but he acknowledged it was unlikely.

“From my standpoint, I’m less optimistic than I was 10 years ago … that we can [solve climate change] rationally and pragmatically.”

December 15, 2020

Invenergy Renewing Push for Grain Belt Express

Invenergy Vice President for Regulatory Affairs Nicole Luckey last week provided an update on her company’s efforts to win approval of the Grain Belt Express, which the company acquired this year after Clean Line Energy Partners abandoned it in the face of regulatory, legal and political hurdles.

Invenergy is making a revitalized push for the approximately 800-mile HVDC transmission line that would carry 4,000 MW of wind energy from western Kansas through Missouri and Illinois to the Indiana border, Luckey told the Missouri Energy Initiative’s Midwest Energy Policy Series on energy infrastructure and economic development.

She said that because wind and solar resources “require quite a bit of land … we have to build transmission lines to access them.”

The main political obstacle has been the potential use of eminent domain, which has stoked landowner opposition in Missouri. State courts have upheld regulators’ approval of the project and its subsequent sale to Invenergy, though the state legislature introduced a bill this year to block the project’s use of eminent domain.

“The existing infrastructure in these areas, because they’re sparsely populated, just isn’t there, so think of it like building an interstate highway system,” Luckey said. Projects like Grain Belt are needed “to decarbonize our electricity system along the timeline that many investors and customers are pushing their utilities to follow.

“This is not an either-or proposition,” she said.

According to a market analysis done by PA Consulting Group for Invenergy, the $2.3 billion project will enable up to $7 billion in electricity cost savings for the SPP and MISO regions of Kansas and Missouri between 2024 and 2045. The average residential customer would save $50/year, which accounts for the full cost to build the project.

PA’s analysis also found that Grain Belt would lower wholesale power prices in the states’ RTO regions. Around-the-clock power prices in western Kansas would be 38% lower in SPP and 45% lower than prices in Missouri’s MISO region from 2024 to 2039 on an average annual basis during off-peak hours. These pre-project price differences translate to average annual price spreads of $16.81/MWh for Kansas and Missouri’s SPP areas and $22.21/MWh for Missouri’s MISO section.

“It’s no secret that the best wind resource in the United States is located in western Kansas,” Luckey said. “Actually, western Kansas also has a really excellent solar resource, and getting access to the best resource means that you end up significantly lowering the cost of the energy that is produced by your wind or solar project.”

Invenergy Grain Belt Express — Invenergy says the Grain Belt Express will unlock the strong wind and solar energy resources in western Kansas. | *Invenergy*

Missouri Rep. Travis Fitzwater (R) mentioned Grain Belt during a legislative panel and said “getting renewable energy across the state would be fascinating” but that the previous Clean Line project iteration was only going to deliver “a small percentage of the power” to the state.

The Invenergy iteration would deliver 2,500 MW of wind energy to Kansas and Missouri from the line’s 4,000-MW capacity. Previously, 500 MW of the transmission line’s capacity was slated for delivery to Missouri. With increased delivery to Missouri, including an expanded DC-to-AC converter station, Grain Belt would make as much as half or more of its total capacity available to Missouri.

“DC lines are just more efficient at moving large amounts of power long distances. You have fewer line losses than you do with AC lines, which again helps to ensure that you’re delivering energy at the lowest cost,” Luckey said. “There are definitely operational and reliability benefits associated with DC lines, which use a narrower right of way and fewer conductors than comparable AC lines, making more efficient use of transmission corridors and minimizing visual and land-use impacts that I know is a priority to landowners, local county officials and to elected officials in those areas.”

The project, which would stretch across 200 miles in Missouri, reached an agreement with the state’s Joint Municipal Electric Utility Commission to serve 39 cities. Luckey added that Missouri retail customers are expected to save $12.8 million annually on their electricity costs.

“We obviously cannot force our project on anyone. Incumbent utilities are the folks we’re talking to about taking service on the project, but they have to carefully weigh their options; [for example,] does it make more sense for their ratepayers or for reliability for them to have locally sourced projects versus taking power off Grain Belt?” Luckey said. She said Invenergy is engaged in Missouri utilities’ integrated resources planning processes that they go through and “talking to them about how we think the project could fit into their plans for decarbonization.”

Grain Belt has gained regulatory approval in Kansas and Indiana, but Illinois’ previous approval was overturned by the courts. Invenergy will seek approvals for expanded delivery to Kansas and Missouri and begin the first phase of project construction before Illinois regulatory approval, which Luckey said the company will pursue next year.

“Engineering design and environmental field studies are ongoing so that we can hopefully begin site work in mid-2022 and bring the project online by the end of 2024,” Luckey said.

December 15, 2020

Hydrogen for FCEVs Gets Big Boost in California

The California Energy Commission allocated up to $116 million on Wednesday to install fueling stations for hydrogen-powered fuel cell electric vehicles with the goal of having 200 stations supporting 230,000 vehicles in the next decade.

The grants to three companies — Iwatani Corp. of America, FirstElement Fuel and Equilon Enterprises — could bring the total to 179 stations in the coming years, the CEC said.

Building hydrogen fueling infrastructure will help solve the “chicken-and-egg problem” of increasing the number hydrogen-powered vehicles, Commissioner Patty Monahan said. Hydrogen-powered cars from makers such as Toyota have been slow to arrive, but that is partly due to a lack of fueling infrastructure.

“What we’re seeing in California right now is, ‘Well, here’s your chicken, where’s the egg?’” Monahan said. “We want to see more fuel cell vehicles on the road.”

“We’ve got the infrastructure,” she said. “Now … show us the vehicles.”

Even with the new funding, hydrogen fueling stations and fuel cell electric vehicles likely will continue to make up only a small part of the state’s bid to get rid of polluting cars and trucks. California already has hundreds of thousands of plug-in electric vehicles and thousands of high-speed chargers available.

The state is aiming to have 5 million EVs on the road by 2030, requiring hundreds of thousands additional chargers in workplaces and public spaces such as shopping centers. (See California Needs Huge Number of EV Chargers.)

hydrogen fuel cell vehicles — | *Toyota USA*

The CEC said, however, that the hydrogen stations will help meet Gov. Gavin Newsom’s order that all new passenger vehicles sold in the state must be zero-emissions vehicles by 2035.

Currently 45 hydrogen stations exist, mainly in Southern California, and 16 more are in development, the agency said. The grants will help build 111 new stations, bringing the total to 172. Seven more stations are under development using only private funds.

The $116 million, to be distributed in batches as the grantees meet specific milestones, will be paired with $131 million in private matching funds.

The new stations will also serve medium- and heavy-duty vehicles, potentially a big advance in reducing emissions, Monahan said.

Hydrogen fuel cell vehicles, which use oxygen and hydrogen to create electricity, have the advantage of being able to be fueled quickly on the road, much like gasoline-powered vehicles. But the expense of making hydrogen, which requires large amounts of electricity, and the difficulty of obtaining the rare and pricey vehicles, has thwarted widespread adoption.

Monahan said that could change if nations, including China and members of the European Union, support a “global scale-up.”

“We need a global transition to fuel cell electric vehicles to really be able to drive down costs and build up scale,” she said. “We’re trying to show in California how to do it.”

December 15, 2020

California Lithium Extraction Plan Advances

A proposal to extract lithium for battery production from geothermal wells in California moved forward Wednesday when the state’s Energy Commission named most of the members of a new blue-ribbon panel to address the plan.

Energy commissioners said the idea of having a “Lithium Valley” in far Southern California could promote the state’s goals of adopting utility-scale battery storage and electric vehicles while reversing the fortunes of the imperiled Salton Sea and its surrounding communities.

Created by a state statute earlier this year, the Blue Ribbon Commission on Lithium Extraction in California, commonly called the Lithium Valley Commission, is intended to foster that plan.

“I am really excited about this,” CEC Commissioner Karen Douglas said. “We have a real opportunity to put Lithium Valley … on the map in a way that also supports local economic development and is the most environmentally positive way of getting bulk amounts of lithium … that I know of.”

Most lithium for lithium-ion batteries comes from South America, Australia and China. Hard-rock mining, which pollutes water, and evaporation ponds, which are depleting the scarce supply of water in Chile’s Atacama Desert, are the main methods of obtaining lithium today.

The Salton Sea, a vast lake created accidentally in 1905 by a levee breach, is drying up and becoming more saline. Rotting fish carcasses line its shores. Dust storms blow toxins from a century of agricultural runoff. Imperial County, which encompasses the proposed area of lithium development, is among the state’s poorest regions.

California Lithium Extraction — The Salton Sea is drying up, but some see a potential windfall in lithium extraction for batteries. | *University of California*

Geothermal energy is abundant, however, and the existing generating stations and surrounding areas are potential sources of lithium. Geothermal brine — subterranean waters awash in minerals and naturally heated to 500 degrees Fahrenheit — contain huge amounts of lithium. The problem is extracting it in bulk at competitive prices.

“It’s not alchemy,” said Jonathan Weisgall, a new blue-ribbon panel member and vice president of legislative and regulatory affairs at Berkshire Hathaway Energy, which hopes to be a major player in the field. “The lithium is there. We’ve recovered it in the laboratory. The question is, can it be done in a commercial way? That’s what this commission needs to promote to get California on the global map for lithium production.”

Efforts to extract lithium have sputtered and died before, but a bill enacted this year, AB 1657, established the Lithium Valley Commission to explore the possibilities and report to the state by October 2022. The 14-person commission — nine of whom are CEC-appointed members — consists of representatives from lithium extraction firms, EV makers, local tribes, utilities and environmental groups. Five other members are appointed by the California Public Utilities Commission, the governor, lawmakers and the secretary of the state’s Natural Resources Agency.

“The Lithium Valley Commission is charged with reviewing, investigating and analyzing certain issues and potential incentives regarding lithium extraction and use in California, and to consult, when feasible, with the United States Environmental Protection Agency and the United States Department of Energy in performing these tasks,” the CEC said in its background memorandum.

Gov. Gavin Newsom’s order for all new cars sold in California to be zero-emission vehicles by 2035 is expected to give the EV market a huge boost, while the state’s mandate to rely on 100% clean energy by 2045 will require thousands of megawatts of batteries to store solar and wind energy for later use.

The CEC devoted $14 million earlier this year to lithium extraction innovation projects, Chair David Hochschild noted.

The new commission “dovetails beautifully with what’s happening in the energy storage and electric vehicle markets,” Hochschild said. “We are going to see a tenfold increase in the amount of energy storage coming online in California in the next year and electric vehicles, of course. Everyone is seeing what’s going on. … There’s just incredible momentum, and so demand for lithium is going to grow at a healthy clip.”

December 15, 2020

SPP Stakeholders Dig into WEIS Market Study

SPP last week offered stakeholders a deep dive into a Brattle Group analysis of the RTO’s Western regional market that projects $49 million in annual savings for current and new members.

According to the study, utilities participating as full RTO members in SPP’s Western Energy Imbalance Service (WEIS) market, scheduled to launch in February, would receive $25 million a year in adjusted production cost (APC) savings and revenue from off-system sales. Members in the RTO’s Eastern Interconnection footprint will benefit from $24 million in savings because of the market’s expansion, transmission network and generation fleet.

Brattle said SPP’s expanded RTO footprint will allow market participants to sell power into Arizona, New Mexico, Utah and elsewhere in the Western Interconnection while only paying a single wheeling fee, “which creates opportunity for increased market sales.”

SPP WEIS — SPP’s expanded RTO footprint | *SPP*

The study analyzed the benefits of WEIS market utilities and the SPP RTO interacting across the DC ties in two future scenarios: an expanded RTO and the WEIS market. It looked far enough in the future to assume recently announced renewable energy projects would be energized, staff said during the Dec. 9 call.

The expanded RTO study integrated WEIS utilities into SPP RTO over the DC ties, with a unified Tariff for the entire footprint and optimized day-ahead and real-time DC ties. Brattle found extending SPP RTO to the WEIS footprint would reduce APC by $33 million/year and generate over $16 million/year of additional wheeling revenues. WEIS members would experience an APC reduction of $8.5 million/year and receive the $16 million/year of additional wheeling revenues; current SPP members would receive an APC reduction of $24.2 million/year.

An increase in market sales, mostly sold off-system to neighboring entities in the WECC, would account for much of the APC reduction, the consulting firm said.

Under the WEIS scenario, Brattle staff allowed coordinated real-time trading over the four DC ties in the WEIS footprint. Increased flows of low-cost power from SPP into the WEIS footprint would reduce APC by $16.1 million/year in the combined footprint; $9 million/year would accrue to WEIS members and $7.1 million/year to current SPP members.

The cheaper power would allow WEIS members to reduce production from higher-cost resources. SPP members would benefit from making more sales across the DC ties, and WEIS members would be able to substitute high-cost production for lower-cost purchases from SPP.

Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, the Western Area Power Administration and the Wyoming Municipal Power Agency (WMPA) will participate in the WEIS contract. With the exception of the WMPA, the utilities have said they are interested in placing their Western Interconnection facilities under the terms and conditions of SPP’s Tariff and becoming RTO members. (See Western Utilities Eye RTO Membership in SPP.)

Also last week, WEIS market participants briefly discussed a list of service flow constraints (SFCs) that raised concerns with SPP’s Market Monitoring Unit.

Staff told the Western Market Working Group (WMWG) during its meeting Dec. 10 that a list of SFCs, to be posted online, will only include the constraint’s name, its rating limit and the shadow price. The data will be a direct output from the economic dispatch engine.

The Western Market Executive Committee remanded a revision request back to the WMWG when the MMU said it would be difficult to post “on-the-fly” SFCs in real time. (See “WMEC Approves 6 WRRs,” SPP WEIS Stakeholders OK Final Test.)