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December 20, 2020January 15, 2025

NY Climate Action Council Focuses Scoping Efforts

The New York State Climate Action Council (CAC) met Tuesday to discuss bioenergy, methane emissions and the formation of a utility consultation group while also receiving updates from its seven advisory groups.

The 22-member CAC is working toward a fall 2021 target for completing a scoping plan for achieving the state’s goals under the Climate Leadership and Community Protection Act (CLCPA).

The NY State Climate Action Council met via webinar Dec. 15, 2020. | NYDPS

Bioenergy

New York State Energy Research and Development Authority (NYSERDA) Interim CEO Doreen Harris, serving as CAC co-chair, said the council recommended the advisory panels conduct a study on the role bioenergy can play in meeting the state’s goals — switching to 100% zero-emission electricity by 2040 and reducing greenhouse gas emissions to 85% below 1990 levels by 2050.

The initial intent was to see where the CLCPA explicitly addresses bioenergy. Now it is up to the advisory panels to identify opportunities in the various bioenergy sectors, Harris said.

Harris highlighted that NYSERDA earlier this month issued a request for proposals seeking contractors to conduct site reuse planning studies for retired power plants, and that the state’s $226 billion pension plan announced it will divest from fossil fuels. (See NY Seeks ‘Just Transition’ in Decarbonization Plans.)

Utility Consultation Group

Harris invited the CEOs of the New York Power Authority (NYPA) and the Long Island Power Authority (LIPA) to participate in the utility consultation group along with representatives from each of the investor-owned utilities — National Grid, the Avangrid utilities, Central Hudson and Consolidated Edison.

“We see this group serving as a resource to the panels at large to help inform them of system considerations to account for in their strategy and recommendation development,” Harris said. “So, we see this group also becoming very helpful with cross-panel issues such as buildings and transportation electrification strategies … and through the scoping panel process, I welcome thoughts on where this utility information would help to promote our state investments and objectives.”

NYPA CEO Gil Quiniones | NYDPS

Gavin Donohue, CEO of the Independent Power Producers of New York (IPPNY), thanked the co-chairs for recognizing his efforts to get more utility involvement in the council’s proceedings at the working group level.

NYPA CEO Gil Quiniones said the authority’s strategic plan first focuses on “preserving and enhancing the value of our hydropower assets to serve as the base of our state’s renewable energy” as the country’s largest state-owned utility.

LIPA CEO Thomas Falcone | NYDPS

“We will also look to build priority transmission projects to integrate land-based and offshore wind renewables into our system,” Quiniones said.

LIPA CEO Thomas Falcone said the transmission cable permitting process for New York’s first OSW project, South Fork, is moving forward with the Public Service Commission and the federal Bureau of Ocean Energy Management. LIPA and Con Edison recently submitted to the PSC and NYSERDA a study of the transmission reinforcements necessary to deliver 9,000 MW of OSW.

Waste Not, Want Not

CAC Co-Chair and Department of Environmental Conservation (DEC) Commissioner Basil Seggos said that the DEC that day had finalized the regulations to reduce GHG emissions, the first regulatory requirement of the CLCPA.

The state in October completed its public hearing process on the proposed (Part 496) emissions limits. (See New York Holds Final CLCPA Emissions Hearings.)

The CLCPA directs the DEC to measure GHG emissions on a common scale using the carbon dioxide equivalence metric (CO₂e) and the 20-year global warming potential of each gas, as derived from the U.N.’s Intergovernmental Panel on Climate Change.

Martin Brand, DEC | NYDPS

DEC Deputy Commissioner Martin Brand said the waste emissions advisory panel has met twice since its founding in November and is focusing on methane emissions as well as collaborating with other panels on “a number of cross-cutting issues that we have to discuss.”

“All the goals are based on the goal of reducing methane emissions, primarily, and certainly there are a number of ancillary benefits for some of these programs,” Brand said. “A general theme is waste avoidance: Don’t create the waste in the first place. … Certainly, we’re going to focus on disposal avoidance, landfill avoidance, capture of resources and emissions from facilities for other use, and to reduce the impact of waste activities on host communities around the state.”

A recent study by Cornell University Professor Robert Howarth found that methane emissions have grown as CO₂ emissions have declined, leaving New York’s total emissions virtually unchanged from 1990. (See NY Study Highlights Rising Methane Emissions.)

Panel Updates

N.Y. DOT Commissioner Marie Therese Dominguez | *NYDPS*

Transportation Commissioner Marie Therese Dominguez said the Transmission Advisory Panel held public meetings this fall, including two roundtables in December that discussed electrification and green hydrogen, among other topics. (See NY Panel Examines Vehicle Electrification, Cleaner Fuels.)

Robert Howarth, Cornell University | NYDPS

Howarth, a professor of ecology and environmental biology, said he lived in a rural area and would like to see more electric buses in upstate New York, but was skeptical that significant amounts of green hydrogen could be generated through clean energy, and was concerned about generating hydrogen from natural gas.

“To the extent that we have surplus renewable electricity, there are far more efficient ways to store and use it than to generate hydrogen,” Howarth said.

Raya Salter, NY Renews | NYDPS

Raya Salter, lead policy organizer for environmental advocacy group NY Renews, said that she would like to see the state “get it right” in analyzing the lifecycle of co-pollutants so that there is strong guidance on these issues.

PSC Chair John Rhodes said that the Power Generation Advisory Panel he leads had organized itself into sub-groups:

The Equity Subgroup is developing recommendations to address community impacts relating to siting, health concerns and access to renewables and energy efficiency.
The Barriers Subgroup is focused on clean energy siting and energy delivery and hosting capacity.
The Solutions for the Future Subgroup is addressing technology and research needs and identifying market solutions to ensure system efficiency and send correct price signals to resources.
The Resource Mix Subgroup is focused on the growth of renewables and EE, transitioning away from fossil fuel generation and the deployment of energy storage and distributed energy resources.

The resource mix is “where a lot of the technical complexity really shows up,” Rhodes said.

Paul Shepson, dean of the College of Marine and Atmospheric Sciences at Stony Brook University, said he is “really fascinated by the distributed energy opportunity” and wanted to hear a comment on the analysis the power generation panel had done on small-scale, community-based power generation.

Paul Shepson, Stony Brook University | NYDPS

Rhodes said that while a 5-MW solar plant may be less efficient than a 100-MW solar plant, the former can still be valuable if it is close to load.

IPPNY’s Donohue said that while the generation working group is prioritizing a market solution, he didn’t hear any mention of carbon pricing, which his organization believes “could be the next iteration of a market outcome.”

Rhodes said the panel discussed it, and that it’s also a CAC agenda topic. “It’s hard to imagine us getting through this process without figuring out a position to recommend on carbon pricing,” he agreed.

Anne Reynolds, ACE NY | NYDPS

Anne Reynolds, executive director of the Alliance for Clean Energy (ACE NY), said that the barriers to getting renewable energy built include establishing uniform property tax rates statewide instead of developers negotiating agreements with every local government. While some people “believe that the main problems are behind us, from developers’ view that is not necessarily true,” Reynolds said. “We’re not all the way through fixing permitting.”

Labor Commissioner Roberta Reardon, co-chair of the Just Transition Working Group, which addresses environmental justice and social equity issues, said that the jobs being created in the clean energy transition “are not simply in the construction trades and in the flow of energy, but in all the support industries that go into it. There’s really a much larger area for workforce development than people tend to think.”

N.Y. Labor Commissioner Roberta Reardon | NYDPS

DEC Deputy Commissioner Jared Snyder said the next step in the scoping process would be for consultants Energy and Environmental Economics (E3) to complete technical analyses of the new state targets and standards and for the council to deliberate over recommendations from the advisory panels.

Peter Iwanowicz, executive director of Environmental Advocates NY asked if NYSERDA and DEC were still looking for someone to help run the CAC. Harris replied yes, saying the agencies “hope to have an announcement sooner than later.”

December 20, 2020

FERC Orders Follow-up NERC Cloud Filing

Citing “general agreement” within the electric industry about the potential benefits of virtualization and cloud computing services, FERC on Thursday ordered NERC to make an informational filing on possible modifications to the critical infrastructure protection (CIP) reliability standards to allow their use (RM20-8).

Thursday’s order follows a Notice of Inquiry issued by FERC in February and a separate order requiring NERC to provide regular updates on two existing standard development projects — 2016-02 (Modifications to CIP standards) and 2019-02 (BES cyber system information access management) — relating to the same issues (RD20-2). (See FERC Sets Inquiry on Virtualization, Cloud Services.)

The commission requested comment from industry players on four topics:

The scope of potential use of virtualization and cloud computing services;
Potential benefits and risks associated with these services;
Potential obstacles to adopting virtualization and cloud computing, including barriers posed by existing CIP standards; and
Potential use of new and emerging technologies in the current CIP standard framework.

FERC said the 26 comments and three reply comments “generally [supported] the voluntary use of virtualization and cloud computing services provided the risks associated with these technologies are mitigated.” It also said it was satisfied that projects 2016-02 and 2019-02 will “facilitate [their use] by clarifying their compliance treatment” in the CIP standards.

However, the commission questioned whether applications that the standard drafting teams (SDTs) for the projects are considering permitting would meet the needs that respondents envisioned.

Industry Wants Freer Hand in Cloud

In particular, industry participants indicated they would like to use third-party cloud services “for purposes beyond data storage (i.e., to perform [bulk electric system] reliability operating services).” But many complained that their ability to utilize such services is hampered by the current CIP standards, and is likely to remain so even after the SDTs complete their work.

For example, the American Public Power Association and the Large Public Power Council said in a joint filing that their members have “experienced objections by certain regional entities at the compliance level to evidence of security practices undertaken by CSPs [cloud service providers],” on the grounds that the CSPs are outside the members’ control. The organizations urged NERC to consider expanding the scope of the CIP standards to provide entities more flexibility in the tools they can use.

The National Rural Electric Cooperative Association (NRECA) agreed that “many … support services could be implemented in a cloud computing environment” beyond data storage. Examples include electronic access control or monitoring systems and physical access control and monitoring systems, endpoint detection and response tools, and security information and event management tools.

NRECA acknowledged risks associated with the use of cloud computing for these purposes — most notably the potential to expose an entity’s network assets to outside risks. It also acknowledged the potential loss of control over the CSP’s services, reliance on internet connectivity and the possibility of increased outage time when a cloud-based system goes down. However, the organization said many of its members believed that with appropriate infrastructure and security measures they “could utilize the cloud at least as effectively as private infrastructure, if not more so.”

NERC and the regional entities filed a joint comment recognizing that there “may be benefits to using these technologies,” though they also reminded the commission that many risks would need to be mitigated before they are implemented, “particularly with respect to BES reliability operating services.” The ERO emphasized its willingness to work with industry groups to improve reliability standards and said the NOI comments should help with these efforts.

Commission Seeks More Information

In its order, FERC agreed that expanding cloud computing services to include BES reliability operating services and other uses could bring benefits including “cost savings and enhanced security and resilience features” that registered entities may not be able to achieve otherwise. But it also agreed with NERC that the risks and benefits of permitting such use should be fully evaluated before any serious attempts to facilitate them are made.

As a result, the commission ordered NERC to “assess the feasibility of voluntarily conducting BES operations in the cloud in a secure manner” and how the CIP standards could be modified to allow this. Commissioners urged NERC to take the NOI comments into consideration — including potential security benefits of off-site virtualization and cloud computing, risks of storage of bulk electric system cyber system information outside a registered entity’s country, and allowing entities to conduct their own reliability risk assessments related to cloud computing. FERC also told NERC to consider whether a new audit process may be necessary to ensure that entities using CSPs are still in compliance with CIP standards.

The informational filing is due to the commission by Jan. 1, 2022.

December 20, 2020

DOE Issues China BPS Equipment Ban

The Department of Energy on Thursday issued a prohibition order barring some U.S. utilities from acquiring equipment from China, citing concerns that the Chinese government “is equipped and actively planning to undermine the [bulk power system].”

Affected by the order are utilities that supply critical defense facilities (CDFs), defined by Congress as facilities that are “critical to the defense of the United States” and “vulnerable to a disruption of the supply of electric energy” from external providers. Entities that meet this definition will be forbidden from “acquiring, importing, transferring or installing” the following equipment manufactured or supplied by entities “owned by, controlled by, or subject to the jurisdiction or direction of … China”:

power transformers with low-side voltage of 69 kV or higher, along with associated control and protection systems;
generator step-up transformers with high-side voltage rating of 69 kV or higher and associated control and protection systems;
circuit breakers operating at 69 kV or higher;
reactive power equipment, including reactors and capacitors, of 69 kV or higher; and
associated software and firmware installed in any equipment or used in the operation of the previous items.

The order will take effect Jan. 16. Entities affected will be notified no later than five business days after its issuance and will be required to certify with DOE by March 17 that they have not entered into a prohibited transaction and have internal monitoring processes to ensure future compliance. Certification must be performed every three years as long as the prohibition order is in effect.

In addition, the order requires affected entities to certify by Feb. 15 that they have “designated (or taken all action reasonably available … to cause the relevant regional entity to designate)” relevant CDFs as priority loads in system load shedding and restoration plans.

“This order is one of several steps this administration is taking to greatly diminish the ability of our foreign adversaries to target our critical electric infrastructure,” Energy Secretary Dan Brouillette said in a statement.

A media release from NERC called the order “an important next step to further protect defense critical electric infrastructure” and pledged to “continue to work with industry, DOE and other government partners … to protect grid security.”

DOE BPS Equipment Ban — Energy Secretary Dan Brouillette (center) | *International Atomic Energy Agency*

Order Builds on Foreign Cyber Fears

The order is the latest in a series of actions by the government this year aimed at blocking foreign interference in the North American electric grid.

President Trump set the tone in May with executive order 13920, which declared a national emergency regarding foreign threats to the BPS and gave Brouillette authority to ban purchases of equipment that posed a risk to the grid from entities connected to “foreign adversaries.” (See Trump Declares BPS Supply Chain Emergency.) DOE invoked this authority in Thursday’s order.

Trump’s declaration did not specify which countries were in mind. In a subsequent request for information, DOE identified China, Russia, Iran, Cuba, North Korea and Venezuela as foreign adversaries subject to the order. (See NERC Issues Level 2 Supply Chain Alert.)

Cybersecurity experts have expressed concern that China’s national security laws allow the government to compel individuals and companies to assist the country’s intelligence services. In June, the Federal Communications Commission designated Chinese hardware manufacturers Huawei Technologies and ZTE as national security threats. Communication equipment made by the two companies is widespread not only in the North American BPS, but also those in countries around the world.

The focus on Chinese equipment has sparked concern among industry representatives about the difficulty of tracking down manufacturers of specific equipment in the event of wider prohibitions on systems or even subcomponents from blacklisted countries or manufacturers.

“It’s one thing for us to recognize and figure out who we bought from. … We probably have those records going back 10 years,” Mike Kormos, senior vice president of transmission and compliance at Exelon, said at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit in July. (See Industry Seeks Clarity on Supply Chain Orders.) “But when you start talking about potential subcomponents of these systems … [we] might have bought a transformer from one vendor, [and] who that vendor was using for subcomponents in that is something we don’t have, quite frankly.”

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.”