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December 18, 2020

FERC Pushes Cybersecurity Incentives

FERC on Thursday proposed incentives to encourage public utilities to make cybersecurity investments above and beyond the requirements of NERC’s Critical Infrastructure Protection (CIP) standards.

“As we’ve seen recently in the news this rulemaking cannot be more timely,” FERC Chairman James Danly said at the commission’s open meeting Thursday, referring to the wave of cyberattacks against U.S. government computer networks linked to SolarWinds’ Orion products that the FBI and the Cybersecurity and Infrastructure Security Agency (CISA) had acknowledged just the day before.

Within hours of the FERC meeting, POLITICO reported that FERC and the Department of Energy had been targeted in the attacks as well. Officials with DOE indicated that FERC had suffered more damage than other agencies, without elaborating, POLITICO reported. FERC did not immediately respond to a request for comment on the report.

FERC Cybersecurity Incentives — | *Shutterstock*

NOPR Follows Hybrid Approach

The Notice of Proposed Rulemaking (NOPR) approved by FERC Thursday builds on a commission white paper published in June that sought to build a complement to the current CIP standards (AD20-19). FERC called the standards an “effective technical baseline” that utilities would need to supplement with additional innovative solutions. (See FERC Seeks Comments on Cyber Investment Incentives.)

“[The] energy sector faces numerous and complex cybersecurity challenges at a time of both great change in the operation of the transmission system and an increase in the number and nature of attack methods,” FERC said in a press release. “These ever-expanding risks create challenges in defending the digitally interconnected components of the grid from cyber exploitation.”

Andres Lopez, of FERC’s Office of Electric Reliability, told the commissioners that the incentives will encourage utilities to respond to evolving threats more quickly than the lengthy NERC standard development process allows. “The cybersecurity threats public utilities face evolve and arise on their own time frame,” Lopez said. “That time frame may not coincide with the NERC standards development process, which can take months for new reliability standards to be developed and … months or years before a new reliability standard is fully implemented and enforceable.”

The NOPR incorporates industry players’ responses to the white paper, which revealed widespread misgivings about the planned framework. (See Industry Pushes Back on FERC Cyber Incentives.) In particular, FERC’s proposal unifies the two approaches it originally put forward as alternatives, as suggested by many commenters.

The first of these, which FERC staff called the “NERC CIP incentives” approach in their presentation, would permit public utilities to receive incentive rate treatment for applying the CIP standards to “facilities that are not currently subject to those requirements.”

This would be achieved by:

voluntarily applying the requirements for medium- or high-impact bulk electric system (BES) cyber systems to low-impact systems, and/or the requirements for high-impact systems to medium-impact systems; and/or
voluntarily connecting all external routable connectivity to and from a low-impact BES cyber system to a high- or medium-impact system, which FERC termed the “Hub-Spoke” incentive.

FERC’s second approach would allow incentive rate treatment to be provided to public utilities that implement elements of the National Institute of Standards and Technology’s (NIST) Cybersecurity Framework, specifically automated and continuous monitoring. The commission calls this the NIST Framework approach.

In its white paper, FERC asked for industry participants to indicate which approach they preferred, or if a combination of both would be best. Commenters overwhelmingly preferred a combined approach; therefore, either the NERC CIP incentives approach or the NIST Framework approach will qualify public utilities for one of the following incentives:

Cybersecurity return on investment: Applies a 200 basis-point adder to the return on equity for eligible cybersecurity capital investments.
Regulatory asset: Allows utilities to seek deferred cost recovery for certain cybersecurity-related investment expenses.

Expenses qualifying for deferred cost recovery include those associated with third-party provision of hardware, software and networking services; expenses for training to implement new cybersecurity enhancements in pursuit of the new policy; and other implementation expenses such as risk assessments by third parties or internal system reviews. “Prior or continuing costs” would not qualify. Incentives will be continued until one of four categories is reached:

The depreciation life of the underlying asset;
10 years from when the relevant cybersecurity improvement enters service;
when the investment is mandated by FERC-approved reliability standards and thus no longer voluntary; or
when a public utility no longer meets the requirements for the incentive.

Commissioners Urge More Action on Cyber Threats

Commissioners Neil Chatterjee and Richard Glick joined Danly in calling the NOPR a timely response to recent cybersecurity concerns.

Glick called on “the commission and the entire federal government” to keep raising national awareness of cybersecurity threats.

“[The] commission needs to inquire why these types of investments are not being made today, if in fact they aren’t,” Glick said. “We should only be providing incentives to the extent they cause utilities to change their behavior. That’s what the term ‘incentives’ means. Unless the commission determines that utilities aren’t making these cybersecurity investments because the return [is] insufficient, there’s no point to raising those returns.”

December 18, 2020

NERC RSTC Briefs: Dec. 16, 2020

NERC’s Reliability and Security Technical Committee (RSTC) held its final meeting of the year via conference call on Wednesday.

Only the committee’s inaugural meeting in March was held in person, since then all of its meetings have been held remotely. (See RSTC Tackles Organization Issues in First Meeting.) This arrangement is set to continue into next year, as Chair Greg Ford of Georgia System Operations confirmed the committee’s first three quarterly meetings will be held online. The committee has not reached a decision on the last meeting of 2021, currently scheduled for Dec. 14-15.

Approvals

The committee accepted several documents to be posted for a 45-day comment period:

Revisions by the Real Time Operating Subcommittee (RTOS) and Electric Gas Working Group to NERC’s reliability guideline for gas and electrical operational coordination considerations
Reliability guideline on battery energy storage systems and hybrid power plant modeling and performance developed by the Inverter-based Resources Performance Working Group
Security guideline for the electricity sector on assessing and reducing risk developed by the Security Working Group
Three-year reviews by the Resources Subcommittee of two reliability guidelines — relating to area control error diversity interchange and operating reserve management — as well as the reference document on balancing and frequency control

The committee also approved revisions to the reliability guideline for generating unit winter weather readiness. The Event Analysis Subcommittee updated the guideline, which was posted for industry comment in August. (See Reliability Guidelines, Standards Posted for Comment.) In addition, the Supply Chain Working Group (SCWG) gained approval for a guideline on supply chain procurement language that was posted for comment at the same time.

NERC RSTC — ERO risk management process | *NERC*

Progress on RSTC Transition

The committee moved toward finalizing its takeover of the business previously handled by the Planning, Operating, and Critical Infrastructure Planning committees, which disbanded in March. (See NERC OC, PC, and CIPC Briefs: March 3-4, 2020.) Scope documents for the SCWG, the EMP Working Group (EMPWG) (formerly they EMP Task Force), the RTOS, the Reliability Assessments Subcommittee and the Probabilistic Assessments Working Group were approved by the full committee as called for in the transition plan, along with the 2021 work plan for the EMPWG.

Also approved at Wednesday’s meeting was the revised scope document for the Security Integration and Technology Enablement Subcommittee (SITES). The SITES scope document was originally presented at the committee’s September meeting but was tabled for further revisions. (See “Decisions Delayed by Transition Plan Debate,” NERC RSTC Briefs: Sept. 15, 2020.) Several members had expressed surprise at its focus on cybersecurity at the expense of transformative business applications, which they had understood to be the subcommittee’s purpose.

RSTC Vice Chair David Zwergel of MISO, who led a volunteer team to revise the document, presented the changes for approval, which was received. The revisions emphasize the subcommittee’s goal of “proactively [supporting] industry in integration of new technologies.”

Carl Turner, engineering services director at Florida Municipal Power Agency and one of the members who objected to the original document, thanked leadership for their patience and willingness to allow members to contribute to the document.

“I’m sure some folks feel like it may have delayed a meeting, doing that, but I think it was valuable. And I’d like us to think about, when we have … major things in the future, having some sort of a process like that planned to get more people on board from an early stage,” Turner said.

Zwergel also presented SITES’ draft work plan, which will be presented for approval at the next RSTC meeting in March.

Committee Endorses Risk Framework

NERC Chief Engineer Mark Lauby presented the final version of NERC’s planned Framework to Address Known and Emerging Reliability and Security Risks, which the Reliability Issues Steering Committee (RISC) began developing earlier this year, to the committee, which endorsed the document. NERC’s Board of Trustees is expected to endorse the framework at its upcoming meeting in February.

The latest revisions aim to clarify the role of the RISC, RSTC, Standards Committee and Compliance and Certification Committee in NERC’s risk mitigation process. Previous iterations primarily focused on the RISC and RSTC. Also added to the new document is language acknowledging the role of regional entities, trade groups and other industry participants in recognizing and responding to emerging risks. The revisions were mainly undertaken in response to industry comments received after the framework was included in the Policy Input Letter for NERC’s Board of Trustees in October.

December 17, 2020

Solar Power Boosts ERCOT’s Reserve Margins

ERCOT has met record demand in recent summers with only single-digit planning reserve margins. Thanks to the apparently never-ending stream of renewable projects, that margin will climb to 15.5% in 2021 and 27.3% the year after, where it will stay for the foreseeable future.

“It’s a slightly different situation, isn’t it?” Pete Warnken, the grid operator’s manager of resource adequacy, said during a media conference call Wednesday. “It’s cyclical. Boom or bust.”

The Texas grid operator said that according to its latest capacity, demand and reserves (CDR) report, generator owners have added 5.6 GW of summer-rated capacity for 2021, which includes more than 3 GW of utility-scale solar resources and 1.8 GW of wind resources. Another 9.3 GW of summer-rated solar capacity is expected to be added by June 2022, further cementing the state’s status as a solar powerhouse.

ERCOT Solar Power — Solar resources, like the Permian Solar Center, account for much of ERCOT’s recent additional capacity. | *Ørsted*

Warnken said ERCOT this year has more than doubled the solar capacity brought online in 2018-2019. “Certainly, that’s going to continue in 2022 and 2023,” he said.

Charlie Hemmeline, executive director of the Texas Solar Power Association, said during the Texas Energy Summit last month that solar developers in the state had expected 2020 to be their best year yet — an expectation that proved too strong following the COVID-19 pandemic.

“There’s a giant solar resource here. The demand has never been better,” Hemmeline said.

The grid operator is also seeing accelerated growth in rooftop solar projects. It included its first separate rooftop solar PV forecast in the CDR to show the incremental capacity growth beyond the historical growth trend reflected in the load forecast.

The additional solar and wind capacity has helped negate the effects of fossil fuel retirements. Just last May, ERCOT’s CDR projected planning reserve margins of 19.7% in 2022, dropping to 14.1% in 2025. The grid operator now foresees a 25.4% reserve margin in 2025.

ERCOT’s footprint continues to see growth in customer demand. Using revised economic data released by Moody’s Analytics in August, staff are forecasting a 2021 summer peak of 77.2 GW. That would smash the peak demand record of 74.8 GW set in 2019.

This June, ERCOT will also begin serving some 470 MW of Lubbock Power and Light’s load. (See Texas PUC Approves LP&L Integration Project.)

The grid operator expects to have 86.8 GW of capacity available to meet summer demand next year. Capacity is expected to jump to 97.6 GW in 2022 and flirt with 100 GW in 2025, when peak demand is expected to hit 82.1 GW.

December 17, 2020

OMS Debates MISO Long-term Tx Cost Allocation

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.

The Organization of MISO States is putting together a list of guiding principles for allocating the costs of MISO’s upcoming long-term transmission plan. (See MISO Prepares Members for Pricey Transmission Expansion.)

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.

MISO Transmission Costs — | *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.

December 17, 2020March 9, 2025

AWEA: Biden Tx Buildout Could Double Renewables

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.

December 17, 2020January 15, 2025

Net Zero Price Tag: $2.5 Trillion

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.”

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

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.)