Page 1002 – RTO Insider

December 18, 2020

FERC Rejects PJM Stakeholder EOL Proposal

FERC on Thursday rejected a PJM joint stakeholder proposal regarding end-of-life (EOL) projects, siding with transmission owners who argued moving EOL projects under the RTO’s planning authority violated their rights (ER20-2308).

The commission also reaffirmed its August decision accepting the TO sector’s own Tariff amendments concerning EOL projects, rejecting arguments in rehearing requests by more than a dozen load-side stakeholders (ER20-2046). The rehearing request was automatically denied when the commission did not rule on it within 30 days. (See Rehearing Sought on PJM End-of-life Order.)

FERC said the proposed Operating Agreement amendments initiated by American Municipal Power (AMP) and Old Dominion Electric Cooperative (ODEC) and passed at the PJM Members Committee meeting on June 18, went “beyond the scope of planning responsibilities” delegated to PJM in the OA.

The June vote created lengthy and vigorous debates among stakeholders and a protest by the TOs, who claimed in a letter and discussions that the amendments violated their rights under the Consolidated Transmission Owners Agreement (CTOA). (See UPDATED: PJM Files EOL Proposal over TO Protest.)

“Consistent with the August 2020 order, we find here that the PJM Transmission Owners retain the right to ‘maintain’ their transmission facilities, and generally reserve all rights not specifically granted to PJM.”

FERC said PJM and the TOs originally signed the CTOA to “memorialize the division of responsibility” in planning between the RTO and the TOs. In its August order, the commission found that, under the terms of the CTOA, the TOs retain all rights that they did not specifically grant to PJM.

Specifically, FERC cited language in the CTOA that TOs agreed to “transfer to PJM … the responsibility to prepare a Regional Transmission Expansion Plan (RTEP) and to provide information reasonably requested by PJM to prepare the Regional Transmission Expansion Plan and shall otherwise cooperate with PJM in such preparation.” The commission said, “Pursuant to the CTOA, PJM is limited to ‘[conducting] its planning for the expansion and enhancement of transmission facilities.’” (See FERC Accepts PJM TOs’ End-of-life Revisions.)

PJM EOL Proposal — Crane lifts workers to top of transmission tower in Potomac, Md. | © *RTO Insider*

In its 279-page filing in July, the joint stakeholder proposal called for requiring TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and potentially opened to competitive bidding. It also sought to modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.

The commission ruled that the joint stakeholder proposal went too far in its scope, saying a transmission project addressing EOL conditions that is limited to replacing existing equipment or involving an incidental increase in transmission capacity does not involve expansion or enhancement of the regional transmission system.

“Such a replacement project does not fall under regional transmission planning under the PJM Operating Agreement as it relates solely to maintenance of existing facilities, and it does not ‘expand’ or ‘enhance’ the PJM grid as the CTOA requires for transmission planning responsibilities transferred to PJM,” FERC said.

In its order defending its August decision accepting the TO’s Tariff amendments, FERC said it disagreed with the arguments made by load-side stakeholders.

The stakeholders argued that the order was improper because it gives TOs unilateral authority to propose revisions related to transmission planning, veto authority over future planning methodologies, restricts PJM’s role as the regional planner and reduces transparency and the rights of other stakeholders.

The New Jersey Board of Public Utilities also filed a challenge, saying the order violates the transparency principles of Order 890 and ignores cost concerns over “unchecked transmission owner investment.”

FERC disagreed with the stakeholder arguments, citing its ruling in the August order.

“The PJM Transmission Owners’ proposal does not shift responsibility for planning asset management projects from PJM to the PJM Transmission Owners for the very reason that PJM never had this planning responsibility,” FERC said. “The filing merely provides that these projects would be planned according to Order No. 890 principles, making more transparent the procedures the PJM Transmission Owners would use to plan these projects.”

MOPR Rehearing Denied

Separately, the commission gave notice that it had also rejected a request to rehear its Oct. 15 ruling approving most of PJM’s compliance filing on its expanded minimum offer price rule (MOPR) (EL16-49-006). (See FERC Acts on PJM MOPR Filing.)

The rehearing request also was denied automatically when the commission did not act on it within 30 days. The commission said it would provide substantive responses to the rehearing arguments in a future order.

December 18, 2020

SPP Hires Wyo. PSC Chair Fornstrom as Policy Lead

In what may be a nod to its aspirations for regional markets in the Western Interconnection, SPP said Thursday it has hired Kara Fornstrom, chair of the Wyoming Public Service Commission, as its director of state regulatory policy.

Fornstrom will be responsible for leading SPP’s state regulatory policy efforts and supporting its efforts on related RTO policy matters. She will join the organization Jan. 19. Her last day at the PSC will be Jan. 15, according to a press release from Wyoming Gov. Mark Gordon.

“It’s an honor to join the SPP team of great professionals and work with stakeholders on the important state regulatory policy issues that are critical to the market’s success,” Fornstrom said in a statement. “I’m especially grateful for the opportunity given SPP’s exciting expansion into the Western Interconnection.”

NRG Energy’s Travis Kavulla, a former commissioner for eight years in neighboring Montana and one-time president of the National Association of Regulatory Utility Commissioners, tweeted his support for Fornstrom.

Wyoming PSC Chair Kara Fornstrom | *Wyoming Public Service Commission*

“She has been a champion for Wyoming in her role as chair of its PSC, and I’m glad to see she’ll be involved in the future of organized markets as they continue to evolve out West,” he said.

A former president of the Western Conference of Public Service Commissioners (WCPSC), Fornstrom has also served on NARUC’s Board of Directors. She has more than 20 years of experience advocating for natural resources and electricity issues.

She has represented Wyoming as chair of the Western Interconnection Regional Advisory Board, vice chair of the Energy Imbalance Market’s Body of State Regulators, a Class 5 Member of the WECC Advisory Committee, and a member of the Committee on Regional Electric Power Cooperation and the Northern Tier Transmission Group.

“Kara has extensive experience in state regulatory and policy matters involving the electric industry and will provide effective counsel for our organization,” SPP General Counsel Paul Suskie said.

An RTO spokesman said Fornstrom will be “very involved” in NARUC and other regional organizations, like the WCPSC and the Mid-America Regulatory Conference. She will also continue the RTO’s interactions with its Regional State Committee and state commissioners. Her hire won’t result any organizational structure changes in SPP’s legal or regulatory groups.

“I want to thank Kara for her dedication to Wyoming and her diligence and commitment to the ratepayers of the state,” Gordon said. “During her tenure she addressed a number of challenging issues and helped to set an agenda to provide reliable, consistent, affordable electricity to Wyoming consumers, while also recognizing our ability to do all of that and help reduce CO2 emissions with carbon capture.”

The governor said he would announce a replacement “shortly” to complete Fornstrom’s term, which ends in 2025.

December 18, 2020

Mixed Ruling for PJM on Fast-Start Pricing

FERC on Thursday ordered PJM to make an additional compliance filing on its rules for fast-start resources, saying the RTO’s proposal gave itself too much discretion (ER19-2722).

The commission found that PJM partially complied with its April 2019 ruling following a paper hearing, which concluded that the RTO’s fast-start pricing practices were unjust and unreasonable because they did not allow prices to reflect the marginal cost of serving load. (See FERC Orders Fast-start Rules for PJM, NYISO.)

FERC ordered PJM to submit an additional compliance filing within 60 days and a one-time informational report within five months on its progress on addressing long-term pricing and dispatch issues.

The paper hearing order contained eight directives, including that PJM implement software changes so that fast-start resources are considered dispatchable from zero to their economic maximum operating limits for the purpose of setting prices. It also required the RTO to apply fast-start pricing to all fast-start resources instead of only block-loaded resources and to revise its real-time energy market clearing process to consider fast-start resources consistent with minimizing production costs.

The commission accepted PJM’s responses on six of the directives, which were not challenged by intervenors.

More Detail Needed

But FERC said the RTO failed to provide sufficient detail in its proposed Tariff changes on its process for determining eligibility for fast-start resources.

The commission agreed with commenters that PJM’s proposed definition, which would have allowed the RTO’s Office of the Interconnection to deem a resource capable of meeting eligibility criteria based on its operating characteristics, would give PJM too much discretion.

“Specifically, PJM must provide the standards and process by which the PJM Office of Interconnection will deem a resource capable of meeting eligibility criteria including, for example, which operational characteristics may be considered as well as the conditions under which PJM may change a resource’s status as a fast-start resource,” FERC said. “While we acknowledge that PJM may need some amount of discretion in determining eligibility in order to prevent sellers from erroneously triggering fast-start pricing, the criteria and process that PJM uses to exercise this discretion should be transparent and clearly defined in the Tariff.”

It rejected PJM’s contention that its proposal was appropriate because it has broad authority to determine which units are physically capable of providing synchronized reserves. “Because fast-start resources are often the marginal unit and the eligibility to be considered a fast-start resource changes how that resource will affect prices, we find that fast-start resource eligibility is distinct from synchronous reserves in PJM,” FERC said.

PJM Fast-Start Pricing — PJM control room | *PJM*

‘Price Chasing’

The commission accepted PJM’s proposal to use lost-opportunity-cost payments to offset the incentive for over-generation or “price chasing,” rejecting protests by the Independent Market Monitor and consumer advocates from Illinois, Maryland, New Jersey, D.C., West Virginia and the PJM Industrial Customer Coalition (filing together as Joint Customer Advocates).

“PJM’s proposed Tariff revisions ensure that resources do not have an incentive to deviate from PJM’s dispatch instructions” to take advantage of higher prices that result from fast-start pricing, FERC said. “We are not persuaded by arguments made by Joint Customer Advocates and the Market Monitor that PJM’s proposal to pay dispatch differential lost opportunity credits would do so on a five-minute basis without regard to the overall profitability of the resource. We find that PJM’s proposal ensures that resources follow dispatch instructions and do not deviate for financial gain.”

The commission said it agreed with PJM that the introduction of distinct dispatch and pricing runs in the day-ahead market could result in cases in which the day-ahead scheduling reserve clearing price credit may not fully cover the opportunity cost associated with the day-ahead scheduling reserve commitment obtained from the dispatch run. It also agreed that fast-start pricing may change the incentives for virtual transactions, price-sensitive demand and dispatchable exports.

But it rejected as beyond the scope of the proceeding PJM’s proposal to provide additional uplift payments to address those issues. Instead, it said the RTO should “monitor these issues and work with its stakeholders to address whether uplift payments for virtual transactions, price-sensitive demand and dispatchable exports may be needed in the future.”

It also directed PJM to include in its compliance filing a proposed effective date for its Tariff changes that reflected its estimate of when software changes will be completed to implement the changes.

Offer Cap

The commission rejected PJM’s proposal to apply the offer cap requirements of Order 831 to the composite energy offers under its fast-start pricing proposal. (See New FERC Rule Will Double RTO Offer Caps.)

“We recognize, as PJM states, that such a proposal may be complex and may require an administrative solution. However, PJM must propose a solution that complies with Order No. 831’s requirements.”

It ordered PJM to provide Tariff revisions capping composite energy offers at the higher of $1,000/MWh or a resource’s verified composite energy offer and capping composite energy offers at $2,000/MWh for purposes of setting LMPs.

It accepted PJM’s proposal to trigger shortage pricing based on the results of the pricing run, rejecting the Monitor’s contention that it will result in false negatives. It agreed with PJM that its approach could introduce false positives, “but we find that the likelihood of such positives to be de minimis given the commission’s recent approval of PJM’s reforms to its reserve penalty factor provisions.”

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, 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.