MISO’s Independent Market Monitor found no major concerns with performance in MISO South over the summer and early fall, but it still wants the RTO to get a handle on short-notice and unreported generation outages in the region.
Potomac Economics’ Robert Sinclair delivered a MISO South operations report at the Entergy Regional State Committee’s annual meeting Wednesday. The report showed South prices for late summer and fall were significantly lower than in 2017 and 2018, holding to about $25/MWh, while natural gas prices hovered around $2.50/MMBtu.
“During the year, you see prices have been declining, and that’s the result of declining natural gas prices,” Sinclair said. Monitor staff also reported higher prices in the MISO portions of Texas in recent months because of transmission outages.
MISO South prices compared to natural gas prices | Potomac Economics
But Sinclair said the Monitor is keeping tabs on short-notice outages and extensions of planned generation outages, along with unreported outages and derates, which continue to be prevalent in South.
“A significant portion of resources continue to be unreported and short-notice,” Sinclair said.
MISO Director of Operations and External Affairs Liaison Tag Short said the RTO called a maximum generation warning in South in early June because of both high load and forced generation outages.
Short said South’s 32.2-GW summer peak occurring Aug. 12 came in lower than the 32.7-GW all-time peak on Aug. 10, 2015.
Sinclair also told Entergy executives that the regional dispatch transfer limit continues to provide South members with cost savings and the benefit of integration. He said the transfer limit bound much more frequently in the South-to-Midwest region August through October. MISO’s agreement to use SPP transmission to facilitate transfers stipulates a 2,500-MW South-to-Midwest limit and a 3,000-MW Midwest-to-South limit.
FOLSOM, Calif. — During a daylong planning session Monday, CAISO engineers examined options for transmission upgrades to resolve reliability concerns and reduce natural gas generation’s role in meeting local capacity requirements.
The ISO is in the second of its three-phase 2019/20 transmission planning process (TPP). On Monday, it held the third of four stakeholder meetings to go over its findings and proposals. The goal is to provide the Board of Governors with a transmission plan to approve by March.
The annual TPP looks ahead 10 years, assessing CAISO’s grid based on economic, policy and reliability considerations.
“In addition to those, we’re also doing this sidebar where we’re looking at potential [opportunities] for reducing reliance on gas-fired generation in local capacity areas,” said Neil Millar, CAISO’s executive director of infrastructure development. Reducing dependence on gas can create a need for economically beneficial transmission projects, he said.
California has a legal mandate to dramatically reduce its greenhouse gas emissions and increase its reliance on renewable energy sources by 2030. The 2019/20 TPP’s planning horizon extends through 2029.
Over the course of several hours, engineers presented the results of their detailed examination of the state to identify areas and subareas where transmission upgrades could cut local capacity requirements (LCRs) and eliminate or reduce the need for gas-fired generation. The long-term LCR assessment began in 2018.
In Southern California, billions of dollars in proposed projects could potentially reduce thousands of megawatts of LCRs, though planners questioned the cost-benefit ratio of many large projects and the potential adverse impacts on the sprawling, interconnected grid in Los Angeles and San Diego counties.
In Northern California, spending $30 million on the Tesla-Delta switchyard 230-kV line reconductor in the Contra Costa subarea would reduce the need for gas to meet local capacity needs from 1,207 MW to 299 MW, CAISO planners found.
In the Tesla-Bellota subarea of Stockton, reconductoring about 200 miles of overloaded 115-kV lines, at a cost of $143 million, could completely eliminate the need for 365 MW of gas generation to meet local demand.
Both those projects, and many others on the list, were submitted by CAISO.
Reliability Projects
Planners also presented proposals for reliability projects costing less than $50 million each that require only the approval of CAISO executives. Projects that cost more than $50 million require board approval and will be included in the draft transmission planning report due Jan 31.
The proposals are intended to meet NERC standards, Western Electricity Coordinating Council criteria or ISO planning standards, which can be stricter than NERC or WECC requirements.
Pacific Gas and Electric, for example, has proposed installing a 230/115-kV transformer bank in the San Francisco Bay Area, at an estimated cost of $3 million to $6 million to prevent overloads and meet NERC reliability requirements.
PG&E has also proposed reconductoring 9 circuit miles of the overloaded 115-kV Wilson Oro Loma line in the Fresno area to meet NERC reliability standards, with a price tag of $11.3 million to $22.7 million.
Written stakeholder comments on the presentations in Monday’s meeting are due Dec. 2.
RF Managing Enforcement Counsel Kristen Senk made the observation during a Compliance Committee presentation on 2019 enforcement activities at RF’s annual meeting Wednesday.
“I’m really proud of the team that’s here for the work that they’ve done. It’s getting harder to process violations,” Senk said. “I think entities probably realize this too. The violations themselves are getting more complicated. On the CIP [critical infrastructure protection] side, there’s some new technologies out there. Our [subject matter experts] are spending a lot of time trying to learn those technologies and working with the entities that understand [them].
“On the [operations] side, we’ve seen some really complicated … facility ratings issues. And also, the further we get into compliance, the more compliance history an entity has,” she continued. “So, for every new violation we process, we look at all the prior violations that were similar for that entity. So that list is just growing longer each year.”
2019 Statistics
RF had received 360 violations as of mid-November, so it may end the year with a slightly lower total than in 2018, Senk said. About 78% of this year’s violations were self-reports (vs. 76% for the ERO overall), with 22% resulting from audit findings.
Annual violation intake | ReliabilityFirst
“That’s good news,” Senk said. “We want to see mostly self-reports.”
RF and WECC receive and identify more potential violations than other NERC regions. | ReliabilityFirst
Senk noted that audit findings in 2019 more than doubled from the number in 2018. “That might sound alarming, but we’re actually not too concerned. … We did have a few more audits in 2019. … We also had some late audits in 2018 that kind of rolled over and we didn’t get the violations until 2019. And then we had a few entities that had multiple registrations, so when we audit them, the number would tend to go up.”
Three-quarters of the violations were for CIP, up from 72% last year. Like the ERO, about half the violations were in CIP-007 (patching) and CIP-010 (change management and baselining).
Senk said RF also is seeing an increase in CIP-004 violations. “Those really started increasing with the changeover to CIP version 5. CIP-004 violations are access management: So, some entities are revoking access too late. There’s a pretty strict timeline around those [requirements]. Also, not having the proper authorizations before granting access,” she said. “A lot of entities have kind of manual processes around this access management and they’re learning that those just aren’t sustainable for version 5.”
FERC announced Thursday it was rethinking its cybersecurity strategy by reorganizing two departments and directing its efforts at five “focus areas.”
FERC is directing its cybersecurity efforts at five “focus areas.” | FERC
The changes resulted from Chairman Neil Chatterjee’s directive that the Office of Electric Reliability (OER), the Office of Energy Infrastructure Security (OEIS) and the Office of Energy Projects (OEP) identify ways they can combine their cybersecurity efforts.
As a result of that review, OEP is creating a unit within the Division of Dam Safety and Inspections staffed by physical and cybersecurity specialists.
In addition, OER will reorganize based on functions effective Sunday, with the Division of Reliability Standards and Security and the Division of Compliance realigned into the Division of Operations and Planning Standards and the Division of Cybersecurity.
FERC also identified five subject areas that will guide FERC staff efforts:
Supply Chain/Insider Threat/Third-Party Authorized Access: Ways an attacker can bypass perimeter security controls.
Industry access to timely information on threats and vulnerabilities: A recognition that many entities have limited threat intelligence capabilities and access to information on threats.
Cloud/Managed Security Service Providers: A recognition that delegating trusted third parties to perform common services can have security benefits while also calling for more research to determine if the most critical systems, such as those used for real-time operations, could be moved to the cloud.
Adequacy of security controls: Although low-impact bulk electric system cyber systems (BCS) make up the majority of BES cyber assets, they are generally not subject to mandatory security controls. The simultaneous loss or degradation of a large number of these systems could have a significant impact. Many commission jurisdictional hydroelectric facilities and natural gas pipelines are not subject to mandatory cybersecurity controls.
Internal network monitoring and detection: Internal monitoring of protected networks is not required by NERC critical infrastructure protection (CIP) standards; a failure to conduct monitoring can allow attackers to move laterally within “trust zones.”
Staff identified the focus areas based on a review of public and nonpublic threat reports, significant cybersecurity events impacting industrial infrastructure and CIP standards.
“Staff will continue to monitor entities’ supply chain security implementation and use of trusted connections,” staffers said in a presentation at the commission’s open meeting Thursday. “Additionally, staff will monitor entities’ adoption of new technologies and services to address cyber infrastructure implementation [including] virtualization of systems and use of cloud-computing services. Staff will continue to gather information and work with regulated entities on these issues as well as potential modifications to the CIP standards, such as the security controls for low-impact BES cyber systems.”
Staff noted that OEIS offers voluntary network architecture assessments of electric, hydroelectric, natural gas and LNG facilities, working with other federal agencies such as the Department of Homeland Security, the Transportation Security Administration and the Coast Guard.
Hydro Security, Internal Monitoring
FERC said the additional security capabilities for OEP will build on the Security Program for Hydropower Projects, created in response to the Sept. 11, 2001, terrorist attacks and revised three times since.
David Capka, FERC Office of Energy Projects
“The program’s been enhanced over the years,” David Capka, director of the dam safety division, explained in response to a question from the chairman after the presentation. “However, when cybersecurity became part of the program, within OEP we had to rely heavily on experts outside our office. So, we relied on OEIS and OER to help us. And it quickly became clear that we needed in-house … expertise.”
Barry Kuehnle, FERC Office of Electric Reliability
Capka said the changes will have two benefits. “I think we’re going to have a much more robust security program with the expertise we’ve been able to bring on board. [And] we’re allowing our dam safety engineers to focus on dam safety now.”
OER’s Barry Kuehnle responded to a question from Commissioner Bernard McNamee about the need for internal network monitoring to prevent hackers from being able to make undetected lateral movement within a “trust zone.”
“If someone were to gain access [within a safety perimeter] — suppose they come in with a supply chain attack where you purchase a piece of equipment with a back door in it — you put that into the network, now it’s an authenticated piece of equipment … that potentially may end up … communicating with other equipment within that network,” Kuehnle said. “If you’re … looking for anomalies … you can catch that quicker and you’re able to address any type of security concerns.”
The standards drafting team revising the requirements for determining and communicating system operating limits (SOLs) told the Standards Committee on Wednesday it may have broken an impasse that has slowed progress and expects to post the standard for industry comment by February 2020 (Project 2015-09: FAC-010, FAC-011, FAC-014).
SDT Chair Vic Howell said most sticking points have been resolved, but the team is still considering how to deal with the burden placed on industry by the logging and communication requirements relating to SOL exceedance. The team has been working with FERC and industry operators over the last nine months to revise the relevant language and reach consensus with the affected stakeholders.
“We’ve come up with something this morning that we think will address the FERC concerns, as well as those commenters who have been very concerned about the logging and communications administrative burden,” Howell said, without elaborating on the proposed solution.
In response to questions about the collection of industry data to support the SDT’s work, Howell acknowledged that the entities surveyed have been reluctant to share relevant information. As a result, the team created measures to ensure anonymity for the industry participants. In addition, the organizations used a variety of methods to collect and store data, which created challenges with synthesizing information in a useful format.
Some committee members questioned whether the team should make sure it has enough data from all industry players before it posts the proposals for comment next year. However, others noted that this could result in even more delays.
“People would have to put things in place today to start collecting winter [data], and then you’d have to wait for summer, and then you’d have to select a couple of off-peak scenarios. So that really would drag out the process another year,” said Howard Gugel, NERC director of engineering and standards. “Hopefully the drafting team has come up with a solution that … addresses the problem, without having to burden industry with a tremendous amount of data collection and data reporting.”
Consultants Removed from SDT Nominee List
Following a proposal to nominate 10 members to the PRC-005-6 SAR drafting team, Dominion Resources Services’ Sean Bodkin asked that two of the nominees — who, like the others, were not identified by name during the discussion — be removed on the grounds that they were consultants.
“When I go back and look at the policy from last year for including consultants on drafting teams, they’re supposed to add some particular technical expertise or something that the team is lacking,” Bodkin said. “In this case I don’t see … any specific technical expertise that they are adding that the other members of the team do not have.”
NERC Manager of Standards Development Soo Jin Kim said that the nominating team had considered this objection but concluded the two candidates’ backgrounds in generation would provide the team with valuable insights. In addition, one had previous drafting team experience.
Kim said that if the full slate of nominees was not approved, another round of solicitation would likely be needed to fill the two gaps on the team. Committee members saw this as an acceptable way to fulfill the requirements regarding drafting team membership.
“If NERC thinks it can achieve its needs by having an additional solicitation for nominees, that would definitely be my preferred option, rather than adding the two consultants,” said Sean Cavote of Public Service Enterprise Group.
Bodkin’s motion passed unanimously, and all nominees except the two consultants, including the chair and vice chair, were approved.
Impact of New NERC Committee
Gugel updated the committee on the expected results of the NERC Board of Trustees’ decision to merge the Operating, Planning and Critical Infrastructure Protection Committees (See Board OKs Committees Merger.) The merger would create a new body, tentatively called the Reliability and Security Technical Committee (RSTC).
| NERC
Nominations for the new committee are currently being solicited. The RSTC will have 34 voting members: two each from sectors 1-10 and 12, 10 at-large members, and a chair and vice chair. The existing committees will conduct their scheduled meetings in December and March, with the new body taking over their functions by June.
“Probably the largest impact that has for us is that … the Standards Committee would be going to the RSTC for legal and technical support for SARs, as opposed to … the OC, PC or CIPC [as in the past],” Gugel said. “The standards [creation] process will [also] probably need to be revised to incorporate whatever methods the RSTC would like to set up.”
The Organization of MISO States will examine the revolving door policies of its member states after its president departed his position earlier this month to take a job with a wind energy trade association.
The move comes in response to Louisiana Public Service Commissioner Eric Skrmetta’s call to create a code of conduct among OMS representatives — all of whom are state utility commissioners — governing how they transition into jobs in the industry they regulate.
“We’re asking for the OMS to consider adopting a code of ethics or a code of conduct policy,” Skrmetta told fellow regulators during a Board of Directors meeting Nov. 19 as part of the National Association of Regulatory Utility Commissioners’ annual meeting in San Antonio.
OMS leaders said the organization will begin the effort by examining state rules on post-employment restrictions before it decides to move forward with developing any policy.
Skrmetta said he was raising the issue after former OMS President and Missouri Public Service Commissioner Daniel Hall left both posts to become the central region director for the American Wind Energy Association earlier this month. Skrmetta said he took issue with the fact that there was no downtime before the transition and that the move wasn’t announced ahead of time.
“The turnaround is instantaneous,” he said. “It’s pretty obvious we have to take some steps.”
OMS Executive Director Marcus Hawkins said the board was aware of Hall’s plans to leave the organization about a month before his departure. Hall did not respond to RTO Insider’s request for comment.
“Avoiding the appearance of impropriety is an important goal for this body,” Skrmetta said. He suggested OMS adopt a recusal mechanism or require members to disclose extracurricular tasks that might conflict with the aims of their offices.
Kentucky Public Service Commissioner Talina Mathews suggested OMS begin the effort by taking inventory and comparing each state’s existing code of ethics on post-employment policies, a task the board assigned to an informal board subcommittee.
But even that first step prompted pushback from other regulators.
Wisconsin Public Service Commissioner Mike Huebsch said he wasn’t certain cooling-off periods are constitutional. He argued requiring cooling-off periods negatively affects former commissioners’ ability to find jobs after their terms end, an already daunting task.
“It’s a tough thing because most of us can’t talk to anyone until we leave the state,” Huebsch said.
“There had to be some knowledge of the employment coming. … There has to be some acknowledgement that that’s going to happen, and there has to be some kind of drawing back,” Skrmetta responded.
Skrmetta said initiating a code of conduct would create protections for OMS and create an “absolute armor plate” for the organization. He also argued that as AWEA’s central region director, Hall was active in MISO states immediately after leaving OMS.
“Daniel Hall took certain views in his office, and those views haven’t changed. There was no influence,” Arkansas Public Service Commission Chairman Ted Thomas argued. “You can talk about motivations, but you can’t really separate it.”
Thomas suggested OMS might add some boilerplate language that directors are bound to their state’s individual code of ethics.
But Huebsch said state law and guidelines differ so drastically among states it would be impossible to create a single code of ethics for members.
“There are things I could do in other states that would put me in jail in Wisconsin. And vice versa,” he said.
OMS President Matt Schuerger asked the subcommittee to wrap up its research in time for the board’s January meeting.
“It’s a reasonable question that’s been put before us,” he said, promising more discussion.
SAN ANTONIO — State regulators working to improve MISO–SPP interregional planning processes and seams issues drew more than three dozen interested onlookers to their latest committee meeting on Sunday.
Continuing a trend for much of the last year, the SPP RSC/Organization of MISO States Liaison Committee held its meeting in conjunction with a conference of the National Association of Regulatory Utility Commissioners (NARUC). But that may soon be changing.
During a discussion on timelines, North Dakota Commissioner Julie Fedorchak echoed the frustration of several members when she said, “We don’t move quickly enough.”
Kansas Corporation Commissioner Shari Feist Albrecht, who leads the SPP side of the committee, agreed the group’s progress is slow, hampered in part by insufficient face-to-face time between the RSC and OMS members.
“It’s moving too slow,” she said. “I’m hoping we can develop a regular schedule of meetings going forward.”
The committee intends to rectify that situation by scheduling at least one meeting in early 2020, albeit possibly through the web, for an education session on SPP’s and MISO’s planning processes before NARUC’s next meeting.
FERC Commissioner Richard Glick was among those who sat in on the Nov. 17 meeting, being granted a seat at the table while others lined the walls. He declined to offer comments during the discussion but did address the session two days later during NARUC’s annual meeting.
“I appreciated being invited. It was a very interesting discussion,” Glick said during a Q&A session with outgoing NARUC President Nick Wagner. “It’s pretty apparent that we’re not necessarily building the transmission system that might be needed for the grid of the future. We’re not going to resolve those issues today. If we can do a better job of planning between regions, that would really be helpful.”
Three separate coordinated studies between the ISOs have failed to yield a joint project. Stakeholders have laid much of the blame on differences in modeling and criteria between the grid operators, which has led to market inefficiencies. (See MISO, SPP to Ease Interregional Project Criteria.)
While meeting irregularly since last year’s creation, the liaison committee has gathered stakeholder feedback and commissioned the RTOs’ market monitors to analyze the seams issues. (See RSC, OMS Approve Monitors’ Seams Study.)
SPP’s Market Monitoring Unit finished a draft report on rate pancaking and unreserved transmission use in time for the meeting.
MISO’s Independent Market Monitor is scheduled to wrap a study on joint dispatch before year’s end. The IMM is also working on suggested changes to the market-to-market framework with the SPP-MISO joint operating agreement. The latter report may not be finalized until spring 2020.
The MMU’s analysis indicated removing duplicate transmission charges (rate pancaking) has a very limited effect on import and export volumes. The SPP Monitor said most transactions are “inelastic” to the market-clearing price and the majority of these transactions are already taking advantage of market import service in the SPP footprint and a comparable service in MISO.
Its study of SPP unreserved use charges since 2016 revealed they are unaffected by the SPP-MISO seam. The MMU said it could not quantify an impact of these charges on interchange volumes and “abstained” from providing an opinion on the current processes.
The work that lies ahead prompted Dana Murphy, chair of the Oklahoma Corporation Commission, to ask for clarification on just who various studies’ stakeholders are?
“My concern in general is who is asking the RTOs to do this background work?” Murphy said. “We have to be thoughtful in our communicating and what we are communicating.”
New Jersey doubled its offshore wind goal on Tuesday, committing the Garden State to develop 7,500 MW of generation by 2035 in hopes of becoming the “nexus of the global offshore wind industry.”
Gov. Phil Murphy, flanked by First Lady Tammy Murphy and former Vice President Al Gore, signed the executive order at the Liberty Science Center in Jersey City — the latest development in the state’s march toward 100% clean energy by 2050.
“There is no other renewable energy resource that provides us with either the electric-generation or economic-growth potential of offshore wind,” Murphy said. “When we reach our goal of 7,500 megawatts, New Jersey’s offshore wind infrastructure will generate electricity to power more than 3.2 million homes and meet 50% of our state’s electric power need.”
Offshore wind | Avangrid
In June, the New Jersey Board of Public Utilities selected Ørsted to develop the first 1,100 MW of offshore wind planned for the state. (See Orsted Wins Record OSW Bid in NJ.) Regulators will solicit bids for two more 1,200-MW projects in 2020 and 2022.
“As our federal government abdicates its responsibility to confront the climate crisis, our transition to a clean energy future is being led by states like New Jersey,” Gore said. “Today’s announcement couldn’t be more timely and more needed, as climate-related extreme weather events continue to wreak havoc on our communities. With this executive order, Governor Murphy is unleashing the unprecedented economic and job creating opportunities of clean, wind energy.”
The projects represent just a fraction of the potential researchers say offshore wind development holds along the Mid-Atlantic coast. University of Delaware Professor Willett Kempton said in April his analysis concludes a hypothetical buildout from New Jersey to North Carolina could add as much as 80 GW to the grid. (See Big Prospects for Offshore Wind in PJM.)
Companies, however, struggle with the logistics of building offshore wind generation in PJM. Anbaric Development Partners asked FERC on Monday to order the RTO to allow developers of offshore transmission “platforms” to obtain injection rights, saying PJM’s Tariff violates the commission’s open access requirements and is discriminatory. (See Anbaric Seeks FERC Help on OSW Tx.)
The transmission developer said it was forced to file its complaint after a stakeholder initiative to consider changing PJM’s rules stalled in September. (See “PJM Recommends Sunsetting Offshore Wind Special Sessions” in PJM PC/TEAC Briefs: Sept. 12, 2019.)
Liz Burdock, CEO of the Business Network for Offshore Wind, said up to 8,240 MW of offshore wind projects are currently under development on the East Coast, with “steel in the water” promised by 2026. New Jersey’s latest commitment will further encourage investment in the industry’s component manufacturing inside the U.S. — a major boon for the national economy.
“This additional 3,500 MW will accelerate the development of the state’s offshore wind industry and supply chain, and will translate into more economic opportunities, and more jobs, up and down the New Jersey coastline,” she said.
Having become reliability coordinator of record for much of the West on Nov. 1, CAISO’s RC West is now taking on new responsibilities as time error and geomagnetic disturbance (GMD) monitor for the Western Electric Coordinating Council.
CAISO Operations Center | CAISO
“The transition [to RC of record] went very smooth,” Tim Beach, director of RC West operations, said Tuesday during a meeting of the RC West Oversight Committee. “We have not had any real events happen since then, so that’s good.”
“The communications with [balancing authorities] and [transmission operators] have been strong,” Beach added, noting that the RC now conducts a daily conference call with the Northwest region in addition to the one CAISO has held for the Southwest for years. The calls, which deal with path deratings, interconnection reliability operating limits (IROLs), major facility outages and remedial action scheme (RAS) outages, if they take place, “keeps everybody on the same page,” Beach said.
“It’s new to the folks in the Northwest. And a lot of times there isn’t a lot of discussion on these calls so there’s a question of value. But we are going to continue that call through the end of the year and we’ll reevaluate the process,” he continued. “We’ll always have some sort of call with regard to that because we do need to communicate those IROLs and path derates.
Beach said NERC became time error monitor for WECC at 10:30 a.m. on Nov. 18. “We haven’t had a manual time error for reliability reasons in the West in quite some time and frankly we don’t see that happening, but we have the process in place if it were to occur,” he said.
RC West will take its turn as the GMD monitor on Dec. 3 when SPP becomes RC of record for the remaining Peak Reliability area. It will serve in the role through 2020, with BC Hydro RC (BCRC) becoming the monitor for 2021. Transitions under the rotation, which will also include SPP and Alberta Electric System Operator, will occur at the same time as the Eastern Interconnection makes its switches, Beach said.
Proposed Metrics
Dede Subatki, director of operations engineering services, told members the deadline is Nov. 29 for comments on RC West’s proposed data metrics.
RC West has proposed continuing Peak Reliability’s practices of releasing some data publicly (such as state estimator quality and convergence) and keeping other data (e.g., load forecast accuracy) confidential.
Proposed metrics | West RC
The Real-Time Working Group will meet Dec. 5 to discuss the comments and Dec. 19 to finalize the metrics, with plans to start gathering data Jan. 1.
“I have a little bit of concern about whether [state estimator] quality should be public at this point given our confidence in it,” John Nierenberg of Tacoma Power said when Subatki opened the floor to comments.
Subatki said the public release would be a “generalized SE quality metric” for the RC West footprint. SE data for individual transmission operators, he said “is definitely confidential.”
That appeared to satisfy Nierenberg. “If we look at an overall generic [metric] maybe I’m not as concerned,” he said.
EHV Data Pool Closure, PMU Update
Officials warned members that companies needing to pull historical data from Peak must do so before Dec. 3, when it will shut down its IT infrastructure, including its EHV Data Sharing Pool. It is being replaced by the new Western Data Sharing Pool (WDSP), which has been available since the end of October.
PMU update | West RC
“The deadline is something that is beyond our control and is something that is not negotiable,” said Subatki. “I think it’s really important to get through the denial phase that some people think we can actually extend this beyond Dec. 3.”
Beach provided an update on the transition to the new Western Interconnection Synchrophasor Program (WISP), saying nine entities, including RC West, SPP, and BC Hydro have completed the transition with six others having completed circuits and ready for the cutover. PacifiCorp, Los Angeles Department of Water and Power and Tucson Electric Power are not yet ready.
Change to Leadership Terms
The committee agreed to eliminate staggered terms for its leadership to fix an unexpected problem.
Michelle Cathcart, BPA | BPA
Under the change, Chair Michelle Cathcart and Vice Chair Kristie Cocco will serve their terms through May 2020 instead of the original plan to have their terms end in March.
Cathcart, vice president of transmission system operations with the Bonneville Power Administration, was elected along with Vice Chair Steve Cobb, director of transmission and generation operations at Salt River Project (SRP), at the committee’s first meeting in March 2019.
Because Cobb is retiring at the end of the year, the committee at its last meeting elected Cocco, of Arizona Public Service, to replace him.
In June 2020, both the new chair and new vice chair will begin two-year terms.
“We realized that because we had said there were staggered terms, it made it so that the vice chair couldn’t become the chair because their term would be in the middle when the chair’s term started,” explained Cathcart. “Given the timeframe and making sure that Kristie has a little bit of time under her belt before she actually becomes chair, we thought that making the change in June would … give her a little bit of time. And then hopefully we can stay on a June schedule from here on out.”
Cathcart clarified after the meeting that “while Kristie is a strong candidate for chair at that point, there will be an election of both chair and vice chair.”
The committee also approved a resolution of appreciation for Cobb, who is retiring after almost 40 years with SRP.
Schedule
The committee will hold a webinar Dec. 17, at which it will review the wind down of Peak. The committee will meet quarterly or as needed in 2020. Meetings are currently set for: Feb. 27 (webinar); May 12 (in person and webinar); Aug. 19 (webinar) and Nov. 12 (in person and webinar).
Seven U.S. senators from New England on Monday urged ISO-NE to “return to the table with stakeholders” and more closely align its fuel security initiative with state policies seeking to speed the transition to renewable energy resources.
In a letter to the RTO, the senators criticized ISO-NE for “pursuing a patchwork of market reforms aimed at preserving the status quo of a fossil fuel-centered resource mix” and having “charted its own path forward and pursued unpopular initiatives” such as Competitive Auctions with Sponsored Policy Resources (CASPR) and the Inventoried Energy Program.
“ISO-NE should heed the call of the states, electricity generators and others to expand the dialogue beyond the current, too narrow fuel-security reforms to tackle the region’s pressing need to achieve the states’ ambitious climate goals,” they said. “To achieve these goals, ISO-NE should dedicate significant planning and markets resources in the coming months to evaluate, help develop and propose new electricity market structures that recognize, facilitate and are compatible with state policies.”
ISO-NE real-time data on Nov. 19 show 60% of the resource mix running on fossil fuels, predominantly natural gas. | ISO-NE
The signatories to the letter were Richard Blumenthal (D-Conn.); Ed Markey (D-Mass.); Chris Murphy (D-Conn.); Jack Reed (D-R.I.); Bernie Sanders (I-Vt.); Elizabeth Warren (D-Mass.); and Sheldon Whitehouse (D-R.I.).
State Climate Priorities
Dan Dolan, president of the New England Power Generators Association (NEPGA), said the senators’ correspondence follows two similar letters his organization has sent to ISO-NE in the last year.
“One area where we disagree with the senators’ letter, however, is … NEPGA believes that CASPR provides a viable pathway to integrate state-contracted electricity projects, while maintaining reliable though competitive markets,” Dolan said.
He said there are two important parts to reforming the region’s competitive electricity market to meet the needs of states, consumers and reliability criteria.
“First, state climate priorities should be integrated into the market through a meaningful price on carbon dioxide emissions on an economy-wide basis,” Dolan said. “This will both help support investments in clean electricity supplies, while also helping to drive needed electrification of the transportation and heating sectors, which together account for over two-thirds of all emissions in New England.
“Second, with large-scale state contracts driving increases in resources like offshore wind, the markets must be reformed to account for the changing nature of the electricity supply mix. The existing market design does not sufficiently value the performance that will be required to maintain reliability and resilience,” he said.
Collaborative Tradition
ISO-NE spokesperson Matt Kakley countered that the RTO is already heading in the direction advocated by the senators, including a move to allocate staff time and resources next year for stakeholder discussions on the future of the region’s power system — a measure set out in ISO-NE’s Annual Work Plan for 2020 presented to stakeholders in September.
“Over the past decade, ISO New England has worked tirelessly to incorporate renewable resources into system operations, short- and long-term planning procedures, and the region’s wholesale markets,” Kakley told RTO Insider. “These efforts have allowed the region to add thousands of megawatts of renewable energy, while maintaining reliable system operations, and have set New England up well to accommodate future renewable energy development.”
Kakley said those efforts required “countless hours” of stakeholder discussion “leveraging the region’s strong history of collaboration.”
