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December 18, 2020

FERC Won’t Meddle in CAISO Resource Adequacy, Yet

FERC on Thursday rejected an effort by Chairman James Danly to take CAISO to task for the rolling blackouts of mid-August by using the commission’s authority under Section 206 of the Federal Power Act (EL21-19).

In a rare occurrence, the commission voted 2-1 against a proposed order, which could have required CAISO to show it can meet demand during extreme heat events.

Amid a Western heat wave Aug. 14-15, CAISO ordered rolling blackouts as solar power waned in the evenings but demand remained high. More than a million residents lost power for short periods. (See CAISO: Blackouts May Continue, Calls Emergency Meetings.) CAISO narrowly avoided blackouts over Labor Day weekend during another heat wave.

“The draft order finds that the heat events of Aug. 14-19, 2020, may indicate that CAISO’s existing Tariff may be inadequate to ensure that sufficient resources are available to meet load and maintain system reliability,” FERC Managing Attorney Michael Haddad told the commissioners in a presentation at their monthly open meeting.

Danly said he felt it was important for FERC to open a Section 206 proceeding to ensure CAISO’s rates are just and reasonable under the circumstances.

“I think that there is an urgent need for action in CAISO,” he said. “CAISO shed load on two days in August. It’s not merely that there was a load-shedding event. It’s the fact that the events that led to it are not unlikely to be replicated. The heat and the wildfires [in the West] seem to be increasingly common. We’ve had ever growing reliance on intermittent resources, and we apparently had only two-thirds of demand response that was called upon actually available.

“When you add that to the increasing drop-off in solar availability as the evening approached … that produced a series of events all of which culminated in a real crisis that CAISO had to actively manage and manage with ever escalating aggression.”

Danly urged FERC to act quickly to head off problems next summer. CAISO has acknowledged a repeat is possible, though it is taking steps to avoid future shortfalls. (See CAISO CEO Defends Blackouts Response.)

Commissioner Neil Chatterjee said he agreed that CAISO needs “serious work” but disagreed that FERC should get involved, at least not yet.

“A broad 206 proceeding at this time would distract from the current efforts that CAISO and its stakeholders are making,” he said. “What’s more, due to our ex parte rules, it would also reduce FERC’s effectiveness by prohibiting commissioners and staff from providing assistance to, and engaging in an open dialogue with, CAISO as it works on solutions.”

CAISO Resource Adequacy — | *Shutterstock*

CAISO has proposed an increase in the state’s planning reserve margin and undertaken reviews of scarcity pricing and resource adequacy rules, he noted.

Commissioner Richard Glick called the proposed order “ill advised.”

“The last thing this commission should be doing is using Section 206 of the Federal Power Act to say to the states, ‘We’re from the federal government, and we know better than you do,’” he said. “This commission’s bungling efforts have already made a complete mess of the resource adequacy construct in the three Eastern RTOs. Are we really now going to do the same thing to the West?”

More regional cooperation, including an RTO, would help the West, he said. The reluctance of California and other states to join forces has thwarted those efforts, but CAISO’s Western Energy Imbalance Market and other regional partnerships are “baby steps” in the right direction, he said.

“What do we think’s going to happen now that we have this draft order, if it were to go forward?” Glick said. “Everybody is going to run back to their corners and not emerge again for years.”

Glick said FERC could help the West by other means. He proposed a technical conference, which would bring together stakeholders and state regulators, to discuss how the region could resolve concerns about resource adequacy.

Danly said he was “perfectly fine” with a technical conference because it would bring much needed attention. It should happen as soon as possible, he said.

It is rare for a FERC chair to bring a proposal to a vote on an order likely to fail. It’s “definitely happened in the history of FERC, but not recently,” observed Jeff Dennis, general counsel of Advanced Energy Economy and former director of FERC’s Division of Policy Development.

“Danly gets to show that he would’ve taken action on California. Chatterjee gets to occupy the political middle of the commission. Glick gets to signal deference to states,” tweeted Travis Kavulla, vice president of regulation for NRG Energy and former vice chairman of the Montana Public Service Commission.

Danly, however, has brought to a vote at least one other order — albeit routine — on which he was in the minority. On Nov. 30, FERC reversed itself and approved a request by NYC ENERGY, a New York-based storage developer, for a waiver of NYISO interconnection procedures.

The chairman acknowledged that the company “explained why its waiver request was submitted in good faith and has presented sympathetic facts in support of its request,” but he maintains that such waivers exceed the commission’s authority under the filed-rate doctrine and the rule against retroactive ratemaking (ER20-629-001). He had more fully explained his reasoning for dissenting on such requests as a commissioner in previous orders. (See Chatterjee, Danly Clash over ‘Regulatory Flexibility’.)

It is up to the chairman’s discretion as to what items the commission votes on, and when. During his time as chair, Chatterjee regularly removed gas items from open meeting agendas to avoid having them voted down or nullified by a tie vote.

“I don’t know that I’ve ever done this before,” Chatterjee said before casting his “no” vote Thursday.

“It gets easier the more you do it,” joked Glick, a frequent dissenter at open meetings.

The vote came after a 25-minute discussion of the facts surrounding the Western “heat storm” in mid-August and CAISO’s handling of strained grid conditions (AD21-3).

As of press time, the proposed order had not been posted to FERC’s website. Commissioner Allison Clements, who joined the commission Dec. 8, did not vote on the order, nor on any of the items during the meeting.

Michael Brooks contributed to this report.

December 18, 2020

Record $14.63M M2M Settlement for SPP, MISO

SPP and MISO in October registered a record $14.63 million in market-to-market (M2M) settlements, more than doubling the amount set just the month before.

“It was a very big month,” SPP’s Jack Williamson told the Seams Steering Committee (SSC) on Wednesday.

In September, the RTOs recorded $7.19 million in M2M settlements. Both amounts accrued in SPP’s favor, as they have for 12 of the previous 13 months and 51 times in the 68 months since the two began the M2M process in March 2015.

SPP MISO Settlement — Market-to-market settlements between SPP and MISO since March 2015 | *SPP*

MISO has now accrued $117.36 million to compensate SPP for redispatching transmission around congested flowgates on the former’s side of the seam.

“The upward trend in net [M2M] settlements is an indicator of underlying circumstances including real-time congestion and, ultimately, transmission constraints along our seam with MISO,” SPP spokesman Derek Wingfield said.

Staff said wind resources on the MISO side and various outages led to much of the congestion in October. Twelve permanent flowgates were binding for 412 hours, resulting in $6.92 million in M2M settlements, while 50 temporary flowgates bound for 1,359 hours, accounting for $7.71 million in payments.

The 161-kV Neosho-Riverton permanent flowgate in eastern Kansas is responsible for almost a third of the M2M settlements, with $35.68 million in SPP’s favor. That point was not lost on Adam McKinnie, an economist with the Missouri Public Service Commission.

“Every year we don’t work on a fix for the Neosho-Riverton flowgate is another year SPP is going to pay for a problem,” he said during the SSC meeting.

The RTOs say the process benefits customers in both footprints by providing a “more optimal solution to congestion than either party could have obtained on its own.” That hasn’t stopped SPP and MISO from working together to improve the M2M coordination processes and ensure that subsequent settlements between the regions are appropriate.

Wingfield said SPP is hopeful of finding “effective ways to create additional transmission capacity” to relieve congestion and ensure the M2M coordination processes “continue to provide significant reliability and economic benefits to both regions.”

SPP said it is evaluating solutions to the M2M issues through its generator interconnection and interregional planning processes. The recently announced targeted joint study with MISO is focused on the Upper Midwest seam where much of the congestion occurs between the RTOs. (See MISO, SPP Stakeholders Applaud New Joint Study.)

Regulators of both RTOs are also trying to address the issue through their SPP Regional State Committee-Organization of MISO States Seams Liaison Committee.

December 18, 2020

FERC OKs Fuel Cells as Cogen Under PURPA

FERC ruled unanimously Thursday that all fuel cells that use waste heat in an integrated fuel reforming process qualify as cogeneration facilities under the Public Utility Regulatory Policies Act of 1978 (RM21-2, RM20-20).

The commission’s rulemaking, initiated in an October order, was prompted by a petition from fuel cell manufacturer Bloom Energy, which had sought approval for its solid oxide fuel cell (SOFCs) technology. (See FERC Proposes Updating PURPA Regs for Fuel Cells.)

In Thursday’s final order, however, the commission said its new rule would also apply to carbonate fuel cells manufactured by Bloom Energy competitor FuelCell Energy in addition to SOFCs.

Fuel cells convert the chemical energy in hydrogen directly to electrical energy without combustion. SOFCs use a solid oxide ceramic material as their electrolyte — a substance that produces an electrically conducting solution — unlike fuel cells that use platinum or other precious metals. The electrolyte oxidizes hydrogen, converting it to water vapor (H2O) while producing electricity.

FERC Fuel Cells — Bloom Box energy servers using solid oxide fuel cells | *Bloom Energy*

FuelCell Energy said its fuel cells use waste heat to produce hydrogen in a manner similar to Bloom’s.

The commission agreed with FuelCell Energy’s argument that its original proposal was improper because it endorsed a specific technology rather than establishing standards that would apply to all similar fuel cells. “The commission has not endorsed specific types of solar panels, for example, in defining small power production facilities. Here, as FuelCell Energy recognizes, the focus should be on the integrated use of waste heat for reforming hydrocarbons to produce hydrogen to fuel a fuel cell, instead of the specific fuel cell technology utilized to accomplish that goal.”

The commission rejected arguments by the Edison Electric Institute, which said Bloom’s request constituted an expansion of the statutory definition of a cogeneration facility.

The Federal Power Act defined a cogeneration facility as a facility that produces electric energy and steam or forms of useful energy, such as heat, which are used for industrial, commercial, heating or cooling purpose.

“Because … a fuel cell system with an integrated hydrocarbon reformation process creates useful thermal energy in that it is used for an industrial purpose — here, producing a commercially valuable fuel, hydrogen — it fits within” the legal definition of cogeneration, the commission said.

FERC cited Bloom’s filing of a declaration from former FERC Commissioners Vicky A. Bailey, Norman Bay, Nora Mead Brownell, Suedeen Kelly and William Massey, who said they supported the rulemaking as “consistent with the statutory text of PURPA and the definition of ‘cogeneration facility’” in the FPA.

EEI contended that FERC’s Order 70, which implemented PURPA in 1980, said facilities eligible for qualifying-facility status did not include natural gas-fired combined cycle combustion plants, even though the sequential use of heat is used to produce more electricity. EEI said the fact that combined cycle plants produce electricity from natural gas through a chemical reaction instead of combustion was not a meaningful distinction.

The commission disagreed. “Combined cycle electric generation, while admittedly a more efficient form of electric generation than, for example, a combustion turbine, is still not the same thing as a fuel cell system with an integrated steam hydrocarbon reformation process and does not warrant being identified as a qualifying facility,” it said.

Commissioner Richard Glick joined with Chair James Danly and Commissioner Neil Chatterjee in the 3-0 vote. New Commissioner Allison Clements did not participate in the vote.

“Even though these fuel cell systems will be deemed to be qualifying facilities, the order makes clear that they still must pass the fundamental use test before utilities will be required to purchase the output from these projects,” Glick said during the open meeting.

The fundamental use test narrowed the facilities that can invoke a utility’s must-purchase obligation to include only cogeneration facilities for which at least 50% of their “electrical, thermal, chemical and mechanical output” is used for industrial, commercial or institutional purposes, and not intended fundamentally for sale to an electric utility.

December 18, 2020

FERC Seeks More Participation in Gas Price Indices

FERC on Thursday proposed revisions to its policy statement on natural gas price indices, and a new rule, to improve the participation in and formation of the indices.

The policy statement revisions would affect natural gas index developers and those who report prices to them (PL20-3). FERC staff said the changes are meant to bring stability and transparency to the indices, which are used as a locational cost proxy in the daily and monthly trading markets.

“Natural gas price indices play a vital role in the energy industry, as they are used to price billions of dollars of natural gas and electricity transactions annually in both the physical and financial markets,” Eric Primosch, of FERC’s Office of Energy Policy and Innovation, told commissioners during their monthly open meeting. “Natural gas markets depend on robust and accurate indices in order to ensure just and reasonable prices.” He noted that along with gas pipelines and utilities, RTOs and ISOs also reference the indices in their tariffs for various terms and conditions.

Staff said the changes are meant to reduce “perceived reporting burdens” and “increase confidence in the accuracy and reliability of wholesale natural gas prices.”

The commission created the policy statement in 2003 to encourage market participants’ reporting of their fixed-priced natural gas transactions to index developers. Since 2010, FERC said, voluntary reporting of transactions has declined 54%, even though the percentage of transactions referencing a price index in the U.S. physical natural gas market increased to 82% in 2019.

FERC proposed allowing market participants sending transaction data to report either their non-index-based next-day natural gas transactions or their non-index-based next-month natural gas transactions, or both, to price index developers. It would also allow market participants to self-audit the transactions they provide to price index developers on a biennial basis, instead of an annual basis.

The commission also proposed requiring index developers to re-up commission approval for their indices to continue to be included in tariffs.

The policy statement covers both natural gas and electricity price indices; FERC’s proposed changes only apply to those for natural gas, but staff said they will “conduct outreach to explore the need for, and scope of, any potential policy updates for the electric industry.”

Safe Harbor NOPR

FERC also issued a Notice of Proposed Rulemaking that seeks to add a safe harbor provision to its regulations to protect those who report natural gas trades to price index developers (RM20-7).

Max Multer, of the Office of Enforcement, told commissioners that a market participant who reports transactions would be “afforded a rebuttable presumption that its transaction data is accurate, timely and submitted in good faith,” provided it followed the reporting standards in the policy statement. Multer said that “inadvertent reporting errors by such data providers will not constitute violations of those regulations.”

The provision is already spelled out in the policy statement, but the proposal would make it legally part of the commission’s regulations.

“The proposed change does not modify the existing policy. It is intended to promote voluntary reporting of wholesale natural gas and electricity transactions to price index developers by alleviating market participant concerns that the safe harbor policy is not binding on the commission,” staff said.

Comments on both proposals are due 90 days after their publication in the Federal Register.

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.”