MISO state regulators are mulling over “postage stamp” rates, decarbonization goals and portfolio groupings as part of advice it will later send to the grid operator on the cost sharing of new transmission.
During a teleconference of OMS’ Cost Allocation Principles Committee on Monday, several regulators said that MISO should not socialize transmission benefits through a postage-stamp rate — one that is flat and footprint-wide and does not take geography into consideration. They said MISO should instead look for more specific beneficiaries to assign costs. The Transmission Owner sector has said the grid operator’s hourglass-shaped footprint means that such a blanket allocation will never make sense.
However, Minnesota Public Utilities Commissioner Matt Schuerger said he did not want stakeholders to preclude a subregional postage-stamp method. He asked other regulators to be cautious about “false precision and getting too granular.”
“We should be locking in as much as the analytical precision allows us. I think other conversations ignore that inputs are uncertain. The outputs are ‘roughly commensurate,’ not ‘exactly commensurate,’” Schuerger said, referencing FERC Order 1000’s principle of allocating project costs “in a manner that is at least roughly commensurate with their benefits.”
Indiana Utility Regulatory Commissioner Sarah Freeman said that OMS’ draft principles would urge MISO to use the “roughly commensurate” principles as the “bare minimum” standard for cost allocation.
“Postage stamping is essentially saying, ‘We don’t have the tools to get there,’” Michigan Public Service Commissioner Dan Scripps said.
| American Transmission Co.
OMS solicited cost allocation advice from stakeholders as part of the work. Several said MISO should explore the creation of new benefit metrics beyond adjusted production costs, avoided reliability projects and savings when a project can reduce dependency on the RTO’s Midwest-to-South transmission constraint. Others asked that MISO minimize free ridership on new transmission investment.
Clean Grid Alliance advised that evaluation of a cost-effective project should not “be overly conservative; otherwise consumers will not reap the economic benefits of new economic transmission infrastructure.”
Schuerger said MISO also should not foreclose the idea of approving projects by portfolio rather than on an individual basis. He said portfolios would be useful in regions where many transmission projects are needed. RTO executives have indicated that long-term transmission recommendations will come in annual Transmission Expansion Plans, not in a special portfolio.
“Those projects have to be put together thoughtfully and deliberately for it to make sense,” Wisconsin Public Service Commission Chair Rebecca Valcq said.
A few regulators said states should not pay for transmission to further the decarbonization goals of other states. MISO has said it needs to address its “rapidly worsening deliverability” so that members can achieve their decarbonization goals and renewable targets.
Scripps suggested MISO planners put a temporary “blindfold” on regarding public policy considerations and examine a project’s reliability and economic benefits first. He suggested that projects could be first allocated based on reliability and economic needs, and then any remaining costs divided up among states who want to pursue decarbonization.
A study published by MIT last week found that nationally coordinated transmission planning can reduce costs by as much as 46% when compared to standalone state decarbonization efforts.
The U.S. could nearly double its reliance on renewable energy in the next decade by building 10,000 miles of new transmission and taking other administrative actions under the incoming Biden administration, a study released by the American Wind Energy Association (AWEA) Wednesday said.
The effort would provide a major post-pandemic boost to the U.S. economy, the report by Wood Mackenzie and AWEA , which is merging into the American Clean Power Association on Jan. 1, concluded.
“Administrative action alone can enable a doubling of renewable energy penetration in the next decade,” from 19% to 37%, said John Hensley, vice president of research and analytics at AWEA. “Transmission-focused policies will really be critical and fundamental to unlocking renewable potential in this decade.”
Legislative action would be necessary to reach a more ambitious target of having half the grid powered by renewable resources by 2030. That scenario is less likely because of political divisions in the Congress and among state legislatures, but it would provide an even bigger economic boost, the study, “A Majority Renewables Future,” found.
Reaching 37% renewables nationwide would require at least $70 billion in transmission upgrades, a study found. | Wood Mackenzie
“Reaching a majority [renewables] grid by 2030 will deploy over a trillion dollars in capital investment in the American economy while supporting nearly a million direct renewable energy jobs,” Hensley said. “It’ll also stabilize wholesale power prices, reduce U.S. carbon emissions by over 60% and all the while deliver tens of billions of dollars in state and local payments to governments and landowners.”
A key to the administrative-only 37% scenario would be building 10,000 miles of transmission infrastructure at a cost of $70 billion or more, the report said. The new pathways the study proposes would link wind power in Wyoming and New Mexico to California and connect offshore wind in New England to western portions of ISO-NE, NYISO and PJM, among other projects.
The study also proposed building massive amounts of storage and sending Southwest solar power where it is needed.
It did not specify who would pay for the projects.
Reaching net-zero greenhouse gas emissions will require at least $2.5 trillion in additional capital investment into energy supply, industry, buildings and vehicles over the next decade, according to a major new study by Princeton University researchers.
“A successful net-zero transition could be accomplished with annual spending on energy that is comparable or lower as a percentage of GDP to what the nation spends annually on energy today. However, foresight and proactive policy and action are needed to achieve the lowest-cost outcomes,” the researchers said in their interim report, “Net-Zero America: Potential Pathways, Infrastructure and Impacts.” “Major investment decisions must start now, with levels of investments ramping up throughout the transition.”
Effectively eliminating GHG emissions economywide is widely considered the target needed to avoid the worst effects of climate change. A dozen states and numerous utilities and other major companies have pledged to eliminate their emissions by 2050.
A dozen states have pledged to have net-zero emissions by 2050. | Princeton University
5 Paths
The Princeton researchers looked at five paths for getting to the 2050 goal, all of which they said would keep energy spending in line with historical rates of 4 to 6% of GDP — but would require massive increases in transmission and renewable generation.
“We are agnostic as to which of these pathways is ‘best,’ and the final path the nation takes will no doubt differ from all of these,” they wrote. “Our goal is to provide confidence that the U.S. now has multiple genuine paths to net zero by 2050 and to provide a blueprint for priority actions for the next decade. These priorities include accelerating deployment at scale of technologies and solutions that are mature and affordable today and will have high value regardless of what path the nation takes, as well as a set of actions to build key enabling infrastructure and improve a set of less mature technologies that will help complete the transition to a net-zero America.”
Hurdles
The researchers said reaching the goal will require:
deployment of technology and infrastructure “at historically unprecedented rates across most sectors”;
mitigating the impacts on landscapes and communities to obtain sustained political support;
mobilization of large amounts of risk capital by government and private sectors;
rapid adoption of building and transportation electrification by consumers; and
the development of low-carbon industrial processes such as steel and cement manufacturing using electrification and hydrogen.
2030 Goals
To get on the trajectory to 2050, the study says the expansion of low-carbon technology must begin immediately, with the following goals hit by 2030:
put about 50 million electric vehicles on the road, with at least 3 million public charging ports to serve them;
increase the share of electric heat pumps for home heating to 23% from 10% today and triple heat pumps’ use in commercial buildings;
increase wind and solar generating capacity fourfold to 600 GW to supply half of U.S. electricity (vs. 10% today);
expand high-voltage transmission capacity by 60% to deliver renewable power to load centers;
increase annual uptake of carbon stored permanently in forests and agricultural soils by 200 million metric tons; and
reduce non-CO2 GHG emissions, including methane, nitrous oxides and hydrofluorocarbons, by at least 10%.
“It may seem like 2050 is a long way off. But if you think about the timelines for policies, business decisions and capital investments, it’s really more like the day after tomorrow,” Jesse Jenkins, an assistant professor at Princeton and one of the authors of the report, told The New York Times.
Total additional capital invested (2021-2030) by sector and subsector for a net-zero pathway vs. business as usual (billion 2018$) | Princeton University
The nation also will need to develop enabling infrastructure and innovative technologies during the next decade, the researchers said. Among the items on the to-do list are planning and permitting even more electric transmission, and planning and beginning construction of a nationwide CO2 transportation network and accompanying permanent underground storage basins to address industrial sectors that cannot be decarbonized.
Investments also will be required to speed the maturation and reduce the costs of options such as clean “firm” electricity technologies (advanced nuclear, advanced geothermal and hydrogen combustion turbines); advanced bioenergy conversion and high-yield bioenergy crops; hydrogen and synthetic fuel production from clean electricity and biomass; natural gas with carbon capture; and direct air capture of CO2.
The five scenarios studied are based on the Energy Information Administration’s projected energy demands for 2050 from the 2019 Annual Energy Outlook (AEO) and vary based on the extent of end-use electrification in transportation and buildings, solar and wind generation levels, and the contribution of biomass.
All but one of the scenarios assumes half of existing nuclear generation will run for an 80-year lifespan. All scenarios essentially eliminate coal use by 2030. “Overall, fossil fuels in the primary energy mix decline by 70 to 100% from 2020 to 2050 across scenarios,” it said, with oil and gas dropping 65 to 100%.
The study projects a net increase of 500,000 to 1 million jobs in the 2020s compared with the reference scenario in the AEO. Improved air quality would also prevent 200,000 to 300,000 premature deaths by 2050, according to the analysis.
Achieving the goals will require “coalitions of public support and political will” to enable massive infrastructure additions and address employment losses in particular communities, the study says. Policymakers also will have to overcome upfront cost premiums for EVs and heat pumps.
Reaction
The report — whose findings are similar to those in a study released in October by the U.N. Sustainable Development Solutions Network — attracted attention from those arguing for a continued role for fossil fuels.
The Carbon Capture Coalition cited the study in endorsing the Storing CO2 and Lowering Emissions (SCALE) Act, which was introduced Wednesday by Rep. Marc Veasey (D-Texas) with cosponsors David McKinley (R-W.Va.), Cheri Bustos (D-Ill.) and Pete Stauber (R-Minn.). “The infrastructure buildout enabled by the SCALE Act is consistent with what the Princeton analysis finds is necessary in the next five to 10 years,” the coalition said in a press release.
“Across every scenario the Princeton team examined, the scale of investment needed to achieve our climate goals is truly massive. But it is possible, especially if resources are deployed in a strategic way,” said Steven Schleimer, Calpine’s senior vice president for government and regulatory affairs. “The report doesn’t examine a nationwide price on carbon, but when you look at the complexity of the challenge, it’s clear that pricing carbon is the most effective option to drive change.”
Schleimer urged the incoming Biden administration to review the Princeton report along with recent analyses performed by the Energy Futures Initiatives and Energy and Environmental Economics, which he said “all recognize that gas capacity will remain vital for the reliability of a fast-growing grid, even as the role of those units shifts to filling the supply gaps inherent to greater reliance on intermittent, renewable sources.”
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.
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.”
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.
Jeffery Sweet, AEP | POWERGEN International
“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.”
“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.”
AEP and Southern Co. were among the first utilities to join Fortress Information Security in the Asset to Vendor Network to pool knowledge and reduce the costs of complying with supply chain rules. | Fortress Information Security
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.”
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-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.
Tier 1 and 2 planned resources projected through 2030 | NERC
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.
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 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.
Nicole Luckey, Invenergy | Missouri Energy Initiative
“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.
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.)
| 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.”
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.
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.
A map showing geothermal areas where lithium could be extracted | California Energy Commission
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.”
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’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 SPP WEIS market | SPP
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.)
