PJM announced Tuesday that it’s delaying the return to campus for employees and stakeholders because of “recent events” surrounding the rise of COVID-19 cases from the Omicron variant.
CEO Manu Asthana made the announcement in a message sent to members, saying the RTO originally expected to reopen the campus to employees in a phased-in approach beginning in January and return to in-person meetings for specified stakeholder committees in the first quarter.
But Asthana said “new guidance” from the U.S. Centers for Disease Control and Prevention and consultation with PJM’s epidemiologist have led the RTO to delay employee return until the middle of March and the start of most in-person stakeholder meetings “in a phased manner” to April through June.
“At PJM, the safety, security and reliability of the high-voltage electric system and the wellbeing of our employees and stakeholders are paramount,” Asthana said. “Since January 2020, we have taken a variety of actions to safeguard our people and the power grid against the risk posed by the coronavirus pandemic.”
In November, PJM mandated COVID-19 vaccines for its employees, contractors, vendors and stakeholders working at or attending meetings at the Valley Forge, Pa., campus or to attend RTO events on and off campus beginning Jan. 4. (See PJM to Mandate COVID-19 Vaccines.)
Asthana said the Liaison Committee, the first scheduled stakeholder meeting, will take place on April 19 as part of the Board of Managers’ meeting.
The PJM Annual Meeting, which is usually held at a remote location, will take place on the campus on May 17. Meetings of the board with the Transmission Owners Agreement-Administrative Committee and the Public Interest & Environmental Organizations User Group are scheduled for May 18.
An in-person meeting of the Markets and Reliability Committee is now scheduled for May 25.
Meetings for all standing committees and senior task forces will be held on campus beginning in June. Those include the MRC, and Members, Planning, Market Implementation, Operating and Risk Management committees.
Sometime in the fall, PJM will hold the MC and General Session at a remote location that will include a “reception and leisure activities,” Asthana said.
In-person state and member training events are scheduled to resume in March for the 2022 PJM Operator Seminar. Those include:
March 7 to 25, in Baltimore;
March 28 to April 22, in Columbus, Ohio; and
April 25 to May 13, on the PJM campus.
Asthana said PJM business travel is expected to resume in the spring. He said PJM plans on providing more detail on the campus reopening process, protocols and meeting logistics as the dates come closer.
“As always, we will continue to evaluate our plans based on the trajectory of the pandemic,” Asthana said.
New York’s Black, Puerto Rican, Hispanic and Asian (BPHA) Legislative Caucus wants to create a pathway for young adults to enter the energy and environment workforce through a program to make the state’s schools clean and resilient.
“School buildings are some of the highest polluters in our state,” Rep. Kenny Burgos said on Monday during a BPHA Caucus webinar on priorities for the next New York budget.
The 68-member caucus is proposing New York create a healthy school buildings program to support the goals of the Climate Leadership and Community Protection Act (CLCPA). The program would help young people acquire entry-level jobs retrofitting schools to transition away from fossil fuel and prepare them to withstand the stresses of climate change.
“Our schools need infrastructure updates that are going to create thousands of green jobs … and help bring money back to our communities,” Burgos said.
The program would emphasize investments in schools in marginalized and disadvantaged communities and supporting young people from those communities in job placement.
Gov. Kathy Hochul unveiled a $59 million initiative last fall to improve indoor air quality in pre-K-12 schools in disadvantaged communities. The program, which is slated to launch early this year, will provide the technical support schools need for energy efficiency and clean heating and cooling projects.
Hochul will release her full budget proposal this week, then move into budget negotiations with legislators before a final vote this spring. The school buildings program is one of 15 budget priorities the caucus is proposing for climate action, environmental justice and energy.
To further emission reductions in the state’s buildings sector, the caucus is supporting the All-Electric Building Act (S6843A) co-sponsored by caucus member Sen. Jabari Brisport. The bill would require municipalities to deny permits for new residential or commercial building construction if they are not all-electric, effective in 2024.
Climate Bills
One of the caucus’ top priorities is a bill that would establish a carbon tax to fund state climate investments.
“We’re proposing to meet the very strong, landmark goals of the [CLCPA] by mandating New York prioritize investments for up to $15 billion for well-paid jobs across the state, with 40% of these investments flowing to disadvantaged communities and workers most impacted by the pollution intensive fossil fuel economy,” Burgos said.
The Climate and Community Investment Act (S4264A), sponsored by caucus member Sen. Kevin Parker, would authorize the state to establish a fee for entities that emit greenhouse gases. Supporters of the bill estimate the fee could raise $10 billion to $15 billion over 10 years.
Also on the caucus’ priorities list are bills to end fossil fuel subsidies and expand the New York Power Authority’s ability to build renewable generation.
The Fossil Fuel Subsidy Elimination Act (S4816) would repeal $330 million in tax exemptions provided by the state to the fossil fuel industry. The bill, according to the caucus, would eliminate certain exemptions to the sales and use tax and the petroleum business tax.
The New York Build Public Renewables Act (S6453), sponsored by Parker, would eliminate the cap on the New York Power Authority’s portfolio of clean generation assets. Currently, NYPA cannot own more than six generation facilities at 25 MW each, which the caucus says is a “huge limitation.”
Adirondacks and Equity
The caucus also proposed celebrating New York’s Adirondack Park as a “cradle of the early civil rights movement” through the intersection of climate science education and environmental justice.
Adirondack Park is a 6-million-acre protected area of New York that includes forest preserves and private land, where Burgos says some communities are disproportionately affected by climate change.
One initiative would highlight an early suffrage settlement in the Adirondack Park, called Timbuctoo, where Black men received property that enabled them to vote. The Timbuctoo Pipeline would create a summer climate and careers institute through a partnership between Medgar Evers College and the State University of New York College of Environmental Science and Forestry.
The initiative “will help create an exploration of intersectional careers and address systemic issues of access to the Adirondack Park from an equity and justice perspective,” the caucus said.
PJM’s proposal regarding the development of new rules for the interconnection process won near unanimous support from stakeholders at last week’s Planning Committee meeting.
The proposal, developed in the Interconnection Process Reform Task Force, received 275 votes in support (99%), with only one member voting against it. In a vote asking stakeholders if they preferred the proposal over maintaining the status quo, the PJM proposal again received 275 yes votes (99%).
PJM’s new interconnection process framework overview. | PJM
Jack Thomas of PJM’s Knowledge Management Center reviewed the RTO’s proposal, first presented at the December PC meeting. (See “Interconnection Process Proposals,” PJM PC/RMC Briefs: Dec. 14, 2021.) Three other proposals originally presented at that meeting were pulled by their sponsors, leaving only the PJM proposal to be considered.
Thomas said the PJM proposal, which consisted of more than 90 design components in the matrix developed at the task force, includes moving away from the concept of “first come, first served” projects in the queue to a “first ready, first served” concept. The change will ensure projects that are ready to be built are prioritized instead of allowing speculative projects to fill the interconnection queue.
The proposal also adds language saying that if a facility study isn’t needed and no network upgrades are necessary for a project, then it could move to the final agreement stage early, speeding up the process. The study window for projects is also proposed to be scheduled for 710 days, or just under two years.
Jason Connell, director of infrastructure planning for PJM, said the RTO and stakeholders worked “very diligently” over the last several months to craft a solution that could receive majority support from members.
“I understand we weren’t able to incorporate everyone’s suggestions and changes throughout the entire process, but if feedback or input was provided, it was carefully considered,” Connell said.
Iker Chocarro of RWE Renewables, one of the sponsors of an alternative proposal, thanked PJM for all the work done on the issue over the last year. RWE decided to pull its proposal from consideration because most of its content was found in the PJM proposal except for additional details on affected systems, he said.
“We would like to encourage PJM to keep working on affected-system issues,” Chocarro said.
Arash Ghodsian of EDF Renewables called the process a “great collaboration effort” that brought a popular proposal forward for a vote.
“I think we’re in a good place,” Ghodsian said. “It was a great accomplishment.”
Paul Sotkiewicz of E-Cubed Policy Associates said PJM’s planning and interconnection teams did an “excellent job” in coming up with a proposal with widespread support among stakeholders. Sotkiewicz singled out Connell for his work, saying he went out his way to listen to concerns and would come back with “reasonable explanations” for the decisions that were made.
“Even if we didn’t get everything we wanted, PJM was extremely thoughtful,” Sotkiewicz said. “While this interconnection process was contentious, this is the way the stakeholder process should work.”
Interconnection Process Transition
Besides the vote on the interconnection process rules, stakeholders also heard plans on how PJM will transition into a new interconnection process.
Thomas provided a first read of two transition proposals from the work done at the Interconnection Process Reform Task Force.
An issue charge for work to be completed on the interconnection issue was approved at the April PC meeting, with task force meetings starting later that month. (See “Interconnection Process Reform Endorsed,” PJM PC/TEAC Briefs: April 6, 2021.) Thomas said that while PJM and stakeholders were working through the issues in the task force, they realized a transition process also needed to be discussed.
PJM held a nonbinding poll focusing on the interconnection transition proposals, with a total of 545 companies participated, including 290 RTO members. The PJM proposal received 92% support from all stakeholders and 93% support from members, while a proposal from National Grid Renewables received 13% support from all stakeholders and 18% support from members.
Thomas said the PJM proposal features an expedited interconnection process of “fast lane criteria” that includes projects with any cost allocations of $5 million or less, amounting to about 450 impacted projects with a completion date of 18 months. He said the $5 million cutoff should cover the bulk of substation and terminal equipment upgrades and, as a result, shorten durations for facilities to study the work needed to be done.
The National Grid proposal for fast lane criteria in the expedited process has no network upgrades or cost allocation set. The expedited process in the proposal would include around 300 projects with an estimated completion date of 12 months.
Thomas said the advantages of the PJM proposal is that it consolidates the transition into two distinct parts: the fast lane criteria and two transition cycles. He said the fast lane is bound by projects that can proceed upon completion of a facilities study, while the transition cycles include more complicated projects in the interconnection queue.
The PJM proposal also preserves the ability for backlogged projects that would have received an interconnection service agreement under the existing process if not for delays to remain in the queue, Thomas said, and it also reduces the time that the queue is closed for the transition.
Connell said the transition proposal was an “extremely controversial topic” for stakeholders, but compromises were agreed upon to push options forward.
One stakeholder said they were supportive of the PJM proposal, but his company had some small issues to address. The stakeholder asked PJM to reconsider the $5 million fixed limit in the fast lane criteria, calling it a “bit arbitrary,” and requested that if a limit is set, it should be done on a per-megawatt basis.
“There could be an issue of smaller projects being able to get through relative to larger projects,” the stakeholder said.
Carl Johnson of the PJM Public Power Coalition said he “did not imagine” that PJM and stakeholders would be able to come together on transition proposals when the process first started. Johnson said stakeholders understood that they needed to move forward and come to a compromise.
“We should all bask in the glow of a very successful stakeholder process and hope that when it gets to FERC it’s similarly successful,” Johnson said.
Stakeholders will be asked to vote on the proposals at the February PC meeting.
Deactivation Process Timing
David Egan, manager of PJM’s system planning modeling and support department, provided a first read of a proposed deactivation process timing update, presenting a problem statement, issue charge and revisions to Manual 14D and the tariff.
Egan said the current timing of 30 days in the tariff to complete deactivation studies “works fine” when there’s only a single deactivation notice in a period. But when multiple deactivation requests are received, the 30-day timetable is “insufficient” to determine any adverse impacts on reliability.
Trends in state energy policies could lead to more large volume deactivation notices in the future, Egan said, putting more pressure on PJM staff in the deactivation studies. Egan said the short duration puts “undue burden” on PJM’s planning and operations staff, along with the staff of transmission owners making deactivation requests, to make reliability evaluations and mitigation determinations.
“All this work is being stacked up on top of each other, and it’s very difficult to come up with holistic solutions,” Egan said.
The proposed issue charge calls for tariff and manual changes that “provide more time to complete analyses, allow additional and improved studies and provide the ability for more efficient work control and consistency regarding timing of deactivation studies,” Egan said.
PJM is proposing quarterly study times for deactivations, with study periods beginning Jan. 1, April 1, July 1 and Oct. 1. The RTO staff will study deactivations as a batch with reliability notifications to be made by end of February, May, August and September, respectively.
To request a deactivation, a generation owner must submit notice:
between Jan. 1 and March 31 to deactivate July 1 or later;
between April 1 and June 30 to deactivate Oct. 1 or later;
between July 1 and Sept. 30 to deactivate Jan. 1 of the subsequent year or later; or
between Oct. 1 and Dec. 31 to deactivate April 1 of the subsequent year or later.
Egan said the quarterly schedule will allow sufficient time for additional required seasonal, interim year and short-circuit analyses, scheduling upgrades and cost estimates. He said the new schedule would also allow PJM operations to identify additional needed operational measures.
PJM is seeking endorsement of the issue charge at the February PC meeting through the “quick fix” process because its “just targeting the current tariff timing” for deactivations, Egan said.
Sharon Midgley of Exelon said her company is “sympathetic” to the issues being raised by PJM, agreeing the problem should be discussed by stakeholders. But Exelon staff had concerns over using the quick-fix process on the issue because of the complexities in the deactivation process that could arise by modifying the schedule.
“We think the proposal does change the rules around a generator notice for deactivation, which is a pretty fundamental change,” Midgley said.
Johnson said he agreed with Exelon in trying to avoid the quick-fix process on the issue, saying it is a “pretty substantial change.”
Egan said PJM staff will discuss what stakeholder process to use before the next PC meeting.
Transmission Expansion Advisory Committee
Market Efficiency Update
Nick Dumitriu, principal engineer in PJM’s market simulation department, provided an update on the 2020/21 long-term market efficiency window at last week’s Transmission Expansion Advisory Committee meeting.
Dumitriu identified four projects that are ready for a final recommendation by the PJM Board of Managers. They included:
the 230-kV Juniata-Cumberland line reconductor, a $9 million upgrade in the PPL zone. The estimated in-service date is Dec. 1, 2023.
the 230-kV Charlottesville-Proffit line series reactor, a $11.38 million upgrade in Dominion. The estimated in-service date is June 1, 2023.
the 230-kV Plymouth Meeting-Whitpain terminal upgrades, a $620,000 project in PECO. The estimated in-service date is June 1, 2025.
the 138-kV French’s Mill-Junction terminal upgrades, a $770,000 project in APS. The estimated in-service date is April 1.
The board will vote on the projects at its upcoming meeting in February.
Generation Deactivation Notification
Phil Yum of PJM provided an update on recent generation deactivation notifications.
Yum said PJM completed its reliability analysis on two battery deactivation requests in the ComEd transmission zone, including the Joliet Energy Storage battery and the West Chicago Energy Storage battery, which are both six years old. No reliability violations were identified, and they can be deactivated by Feb. 8.
PJM also received three additional deactivation notices since its last TEAC meeting in November, including New Jersey’s last two remaining coal generation plants: the 219-MW Logan Generating Plant and the 240-MW Chambers Cogeneration, both owned by Starwood Energy and located in the Atlantic City Electric transmission zone. Starwood requested a deactivation date of April 1, and a reliability analysis is currently underway.
The 9.3-MW Orchard Hills Landfill in the ComEd transmission zone in Illinois made a requested deactivation date of March 31. A reliability analysis is currently being conducted by PJM.
PJM members endorsed an issue charge at last week’s Market Implementation Committee meeting to study the treatment of generation with co-located load after making modifications to its key work activities stemming from concerns over the scope of the issue.
The issue charge, sponsored by Exelon and Brookfield Renewable, received 207 votes in support (92%) with 29 abstentions. Jason Barker of Exelon reviewed the problem statement and issue charge first presented at the December MIC meeting. (See “Capacity Offer Opportunities,” PJM MIC Briefs: Dec. 1, 2021.)
Exelon has seen growing consumer interest in co-locating new, large interruptible commercial loads behind the meter of existing generation resources. Customers are asking for low-cost physical energy supply from generator resources with specific characteristics, such as carbon-free physical energy supply.
“We see a gap in the rules that could, if filled, both facilitate commercial transactions and customer choice,” Barker said. “The fast-curtailment capability of these resources is the innovation that is driving the need for rule reform.”
The issue charge includes investigating market rule changes to support new interconnection configurations for co-located load. Key work activities feature education regarding current capacity offer requirements for existing generation resources and interconnection requirements for “new, large, fast-response interruptible commercial load.”
Debate over the issue charge at the MIC meeting led to the addition of two more key work activities. They include examining federal and state “jurisdictional bounds” that could impact co-located load configurations and the potential impact of co-located load configurations on generator capacity capability.
The key work activities were also broken into two phases, with the examination of the potential provision of ancillary services facilitated by highly interruptible, co-located load coming in the second phase once work in the first phase is completed.
Work on the issue is expected to take six months at the MIC.
Independent Market Monitor Joe Bowring questioned the issue charge, saying he was “highly skeptical.” Bowring said the issue would represent a “really radical change” to the capacity market and should be considered as part of the work being done at the Resource Adequacy Senior Task Force.
He also said the thinking that this is a narrow issue that will make commercial opportunities available to a subset of customers is “not really relevant.” He said the potential also exists that all effective load-carrying capability (ELCC) calculations will have to be redone because the current calculations already account for the generation resources.
“One person’s benefit is another person’s cost,” Bowring said. “It’s changing the definition of capacity, converting a baseload resource to an interruptible resource. Should an interruptible resource have the same ELCC, the same capacity value to the market, as a baseload resource?”
Bowring also said by dedicating low-carbon nuclear output to a new load that would not otherwise exist, additional emitting resources would need to operate to meet PJM load, causing carbon emissions in the RTO to increase.
Barker said Exelon and Brookfield disagree that the issue charge presents a “radical change” in the capacity market and that it would not change the definition of capacity. Absent any changes, PJM could see the “loss of economic development” or a loss of emissions-free resources from the grid, he said.
“We just have to evolve with the changing needs of the customer base,” Barker said.
Aaron Breidenbaugh, director of regulatory affairs for Centrica Business Solutions, said that when he first brought the issue to his company, commenters said it “seems like a solution in search of a problem.” Breidenbaugh said what was being proposed in the issue charge could be done through the “existing demand response construct” in PJM’s capacity market or through the purchase of renewable energy credits.
“I’m wondering why we need to create this exception,” Breidenbaugh said.
Barker said customers have expressed a desire to move away from DR and have also asked for a physical supply of a clean energy resource, rather than just purchasing RECs. He added that customers with no grid interconnection are not permitted to participate in PJM’s DR programs.
“I strongly disagree that this is an exception,” Barker said. “This is a reform and an evolution because we haven’t seen these types of commercial loads seek this type of service before.”
De-energized Bus Replacement Revisions Endorsed
Stakeholders unanimously endorsed manual revisions related to five-minute dispatch and pricing.
Vijay Shah, lead engineer in PJM’s real-time market operations department, reviewed revisions to Manual 11: Energy and Ancillary Services Market Operations designed to incorporate enhancements to the dead bus replacement logic for assigning prices to de-energized pricing nodes (pnodes). The revisions were first discussed at the December MIC meeting. (See “De-energized Bus Replacement,” PJM MIC Briefs: Dec. 1, 2021.)
The revisions were intended to provide increased transparency in the logic and how it performs replacements for de-energized buses, Shah said. PJM is required to produce LMPs for all pnodes in the RTO’s network model for all intervals, including de-energized pnodes.
Shah said PJM wants to use new logic based on Dijkstra’s algorithm, an industry standard, to find a suitable replacement for de-energized pnodes. He said the algorithm uses the “least impedance path” to find a suitable source, and it’s to be implemented in both day-ahead and real-time market clearing engines.
The manual changes include updated language to reflect the new logic.
Shah highlighted a change to section 9.1.1: Intraday Offers Optionality that was not included in the first read at the December MIC, which clarifies language to state that a generation resource’s fuel-cost policy only needs to be updated when opting in to intraday updates for the cost-based schedule.
PJM will seek final endorsement at the Jan. 26 Markets and Reliability Committee meeting, and the new dead bus replacement logic would take effect March 1.
Minimum Run Time Guidance Endorsed
An issue charge addressing pseudo-modeled combined cycle minimum run time guidance won unanimous stakeholder support.
Hauske said PJM and the Monitor brought the issue forward as a result of the “disaggregation of many multiple block combined cycles” into individual pseudo-model market units, or virtual modeled combined cycle units. Market sellers can currently model a combined cycle unit as multiple pseudo units composed of a single combustion turbine and a portion of a steam turbine.
If the market units of a pseudo-modeled unit are dispatched at different times on parameter-limited schedules, Hauske said, the potential exists for one or more of the pseudo-modeled units to operate “for some period beyond the minimum run time parameter limit for an identical non-pseudo-modeled combined cycle unit.”
Key work activity in the issue charge included stakeholders developing guidance for market sellers regarding offering operating parameters for pseudo-modeled combined cycle units through education on the issue. Expected deliverables include revisions to Manual 11 or other relevant PJM governing documents.
Hauske said PJM wanted to use the CBIR (consensus-based issue resolution) Lite process in Manual 34 to develop any manual changes and have final endorsements by the March 23 MRC meeting because the RTO’s unit-specific parameter adjustment process starts on Feb. 28. PJM must provide a determination on the requests by April 15.
“We do want to have some sort of guidance in place during this period before it ends in case there’s any impact on any unit out there,” Hauske said. “We’re looking at a very limited-scope item.”
The committee began interest identification and the development of design components and solution options on the matrix after the vote.
Attendance was light last Thursday at a hearing on a bill to allocate funds to deal with probable upcoming droughts in Washington, but participants were unanimous in supporting the measure.
The state Senate’s Agriculture, Water, Natural Resources and Parks Committee held the hearing on the bipartisan Senate Bill 5746, introduced by Sen. Judy Warnick (R).
If passed, Warnick’s bill would allocate $2 million every two years to a new drought preparedness fund. Also, if Washington’s governor declares a drought emergency, another $3 million would be automatically transferred from the state general fund to a drought response fund.
This bill was prompted by Gov. Jay Inslee declaring a drought emergency in July 2021 for most of Washington. That declaration caught the legislature off guard with no money set aside for dealing with a drought emergency. Inslee’s declaration activated a special legislative drought committee, which was mostly helpless because it first met a few months after the legislative session — with accompanying appropriations— ended in May 2021. (See Drought Catches Wash. Officials Off Guard.)
“It was logistically very frustrating. … We need to be prepared next time,” Warnick said at last week’s hearing. In 2021, she was the chairwoman of the Joint Legislative Committee on Water Supply During Drought.
Last Thursday, representatives from the state Ecology and Agriculture departments testified in favor of the bill, saying a new drought is expected to be declared this year. State officials expect a drought to re-emerge in 2022 because Washington would require 150% of its regular rainfall through this spring just to recover the water lost in 2021 in the agricultural breadbasket of the Columbia River Basin.
Representatives from the Washington Farm Bureau and the Washington Association of Wheat Growers also supported the bill.
“Agriculture was especially impacted by heat and the drought,” testified Farm Bureau lobbyist Tom Davis. “We’ve had some growers with total crop loss,” testified Diana Carlen, representing potato and wheat growers’ associations.
Last year’s wheat crop was 46% of 2020’s harvest, the state’s lowest harvest since 1964. In 2021, the March-to-August temperatures were the third warmest in Washington history — 2.1 degrees Fahrenheit above average. Fifteen of Washington’s 39 counties posted their driest conditions ever. The easternmost quarter of the state underwent drought conditions that normally show up once or twice every 100 years.
SPP last week laid out the clearest explanation yet of its plan to expand its presence and establish an RTO in the Western Interconnection.
“We’re currently … seeking opportunities to expand existing services in the West,” Bruce Rew, SPP’s senior vice president of operations, told the Strategic Planning Committee during a discussion of its new five-year strategic plan Wednesday. “If you look at a couple of years from now, our goal is to be viewed as an attractive market service provider in the West.”
Under its five-year plan, SPP will first grow its existing services in the West, which include its real-time Western Energy Imbalance Service (WEIS) market, its role as a NERC-certified reliability coordinator and its RTO West proposal, which has attracted nine entities and is expected to become operational in 2024.
By then, SPP plans to be operating the Western Resource Adequacy Program, evaluating commitments to its Markets+ service and developing a strategy for the best expansion of transmission markets and transfer capability between the Western and Eastern Interconnections. Markets+ offers centralized day-ahead and real-time unit commitment and dispatch and “hurdle-free” transmission service to those not ready for full RTO membership. (See Implementation Underway for NWPP’s Western RA Market.)
In 2026, SPP plans to have an established RTO in the West, with business development and market initiatives ongoing in the Desert Southwest, Basin and Northwest regions.
David Kelley, director of seams and tariff services, said the plan is a living document, noting “themes are evolving quite rapidly.”
“As that continues to play out in the West, we’re going to need to be able to adapt, so this is certainly not written in stone,” Kelley said.
Board Chair Larry Altenbaumer said the plan’s metrics should focus on value created for both legacy members and the Western members. “I think it is certainly equally important that we focus on the value that our existing membership is deriving from the expansion in the West,” he said.
Several SPC members pointed out the challenges SPP may encounter in the West from entities leery of RTO membership. They also warned staff to counter fears that the Board of Directors will favor its Eastern members over the West.
“Certainly, there are concerns and challenges [in the West] and it’s dependent upon each party that you talk to and what their position is,” Rew said. “Part of the overall strategy and approach is to work through those challenges as we move forward, whether it’s the RTO expansion to expansion of the existing WEIS market or even working with the WRAP.”
Counterflow Optimization on Hold
Committee members sided with stakeholders and staff in deciding to keep the current market construct, rather than adding counterflow optimization to the congestion-hedging process, as recommended three years ago by the Holistic Integrated Tariff Team (HITT). (See SPP SPC Takes on Congestion Hedging Issues.)
The HITT’s recommendation to add counterflow optimization — limited to excess auction revenue — to SPP’s market mechanism that hedges load against congestion charges has become an issue with no solution since its board approval in 2019. The proposal, which would essentially keep system transmission flows between two points balanced, was meant to address stakeholders’ and staff’s concerns about how congestion rights instruments are awarded and the current process’s efficiency.
The Market Working Group was tasked with developing a policy paper. Education workshops were held for the board and SPC, which created an advisory team to move the recommendation forward. Last year, consulting firm Nexant was charged with providing a root-cause analysis that found it to be the “latitude and pattern of nominations submitted to the annual allocation.”
An SPP 2025 future study found market participants’ hedging positions will change in coming years thanks to new topology, HITT initiatives and the changing generation mix. The study indicated a net positive value for all load-serving entities with counterflow optimization.
SPP’s Market Monitoring Unit weighed in during the MWG discussions, saying it does not endorse counterflow optimization and the grid operator and stakeholders should identify alternatives to congestion-hedging issues that carry less risk.
“There are other options that are less complex, less risky, and easier to unwind to address counterflow optimization,” MMU Executive Director Keith Collins said.
The Monitor said the proposal doesn’t give participants a say in the amount of counterflow they receive and there is no way for them to avoid being affected by optimization even when they opt-out. It also said auction participants will adapt to the market changes, which will affect auction revenue. It also said auction participants will adapt to the market changes, which will affect auction revenue.
Arkansas Electric Cooperative Corp.’s Andrew Lachowsky recalled an MWG meeting at which the MMU’s John Luallen referred to the proposal as “a risky, expensive redistribution of wealth.”
“I hope I [got] the quote verbatim,” Lachowsky said.
In the end, the MWG was unable to reach consensus to approve counterflow optimization and voted in 2020 to keep the current market construct. Although they acknowledged that counterflow optimization would benefit LSEs, staff also recommended keeping the current construct, noting some market participants want to review the transmission service process for efficiencies.
Although the HITT recommendation was brought back to the MWG “time and time again,” SPP’s Micha Bailey said staff were unable to gather membership support.
“We can’t get the majority there, so that’s why we said we need to keep the current market construct,” Bailey said. “We need to move on and see what other efficiencies we can garner.”
“It was a pretty tough, complex subject,” the Nebraska Power Review Board’s Dennis Grennan, a member of the advisory group, told the SPC.
“This process is a stream of different processes,” Nexant’s Joseph Bright said.
SPC Chair Mark Crisson called for a “cooling-off period” to rethink counterflow optimization.
“I would request [that] sometime this year, we put our heads together … to talk about how we consider examining this issue again, and whether there are issues besides or in addition to counterflow optimization that we consider,” he said.
“We see the issues there. We just haven’t seen where the organization over the last couple of years has been able to coalesce around a solution or a change that would be agreeable to the organization,” Rew said. “We’ll probably be [able to reach consensus] at some point a year from now because that’s what the goal for this was.”
The SPC endorsed two other HITT recommendations: an effectiveness study of SPP’s new three-phase generator interconnection process that began in 2019, and a working group’s tariff language establishing cost allocation and rates for energy storage resources (ESR).
The new GI process addresses overwhelming demand for service by providing incentives to accelerate the study process and avoid multiple restudies. (See FERC OKs New SPP Interconnection Process.)
However, staff said only one cluster study of interconnection requests has been partially completed after restudies of previous clusters delayed full implementation. A second cluster is expected to finish its first phase this month.
Staff compared the three most recent clusters that went through the legacy process with the three-phase process’s first two studies. Principal engineer Steve Purdy said multiple restudies were avoided, with 41% of the IC requests remaining after two iterations, compared to 65 to 77% in the three legacy clusters.
“It appears the three-stage process had the desired effect,” Purdy said. “We were able to get a more stable group of requests in the cluster quicker, and we were able to move on to these later studies more efficiently.”
That said, the two studies currently being evaluated may be the only ones that go through the three-stage process. Purdy said the GI queue backlog mitigation procedure docket before FERC and SPP’s transmission-planning improvements will eventually supersede the three-phase study.
The Regional State Committee is reviewing tariff language for ESRs’ cost allocation and rates developed by the Cost Allocation Working Group
The Markets and Operations Policy Committee earlier approved a revision request (RR476) that will treat ESRs as transmission assets. The SPC conditioned its endorsement upon the RSC’s approval of RR476 in July.
Task Force Addressing Winter Storm Recs
COO Lanny Nickell told the committee that a task force has begun working on recommendations from SPP’s report on last year’s winter storm, when thermal plant outages forced the grid operator to order its first-ever load sheds. (See “Grid Operator Releases Report on Performance During Winter Storm,” SPP Board of Directors/Members Committee Briefs: July 26-27.)
The Improved Resource Availability Task Force (IRATF), comprising members and state regulators, is working to recommend policies that address the report’s 26 Tier 1 recommendations as well as fuel assurance, resource planning and availability issues. The group has completed two of the recommendations and another 17 are in progress.
“This effort is going to take a lot of work, and there’s a lot of debate. A lot of it has already begun with the task force,” Nickell said.
Southwestern Public Service’s Bill Grant asked that the group consider force majeure issues that arose during last February’s winter storm, when natural gas pipeline companies were unable to meet contractual terms and provide fuel to some gas plants. Nickell said the task force will address the issue when it next meets.
“We’re using the IRATF as that platform [between the electric and gas industries], as it touches both the regulatory committee and our membership,” Nickell said.
“I feel like we’re obligated to do it,” SPP CEO Barbara Sugg said. “If the IRATF is not the right group, we’ll take another tack. We can’t just wait for something to happen organically.”
The report also made 92 Tier 2 and 3 recommendations. Eight of those are complete and 13 are in progress.
Crisson Takes the Chair
The meeting marked the first for Crisson as SPC’s chair and the first for Oklahoma Gas and Electric’s Usha Turner and WAPA’s Sanders as committee members.
Board member Crisson took over the chairmanship role from Altenbaumer, who was quick to point out he left no open action items after his two years leading the committee.
“I just want to let you know I gave you a clean slate,” Altenbaumer said.
Daniel Brooks thinks the energy industry is going about resource adequacy the wrong way.
With hundreds of gigawatts of new renewable power, widespread electrification and an enormous buildout of transmission all expected in the next decade, “the question that gets asked often is how do we maintain the reliability and resiliency of the grid with such a massive transformation? And that is completely the wrong question,” said Brooks, vice president of integrated grid and energy systems at the Electric Power Research Institute (EPRI).
“Resiliency is not a barrier to achieving decarbonization; it is a prerequisite,” Brooks said during a Thursday press call. “The question that we have to be asking is not how to maintain the existing reliability, but how do we actually increase the reliability and resiliency with that massive increase in the dependence on the grid” as electricity provides more of the nation’s energy.
Brooks was one of four EPRI executives speaking on the call, highlighting the work of the organization and the trends and priorities that will drive the U.S. energy transition in 2022 and beyond.
For example, expanding and upgrading the grid will also be essential for developing and optimizing other low- and no-carbon technologies, said EPRI CEO Arshad Mansoor. “We need to make sure that the resources we have … the hydro, the nuclear, not only remain in operation but we are operating them so we are getting more from them,” he said.
Held three days after the Rhodium Group made headlines with its announcement that U.S. carbon emissions were up 6.2% last year, the EPRI call was nonetheless upbeat and optimistic about the country’s ability to cut its greenhouse gas emissions 50% by 2030.
Mansoor said that ambitious target, set by President Joe Biden at the UN Climate Change Conference (COP26) in Glasgow, was “a clear indication globally that our ambitions for a clean energy transition, our aspirations are becoming more tangible.”
“We’re seeing large industries that consume a lot of energy focusing on clean energy,” he said. “So now you’re bringing industry together with the electricity sector, just like they’re bringing the transportation sector [together] with the electricity sector, so collaboration and innovation become the theme of this transition.”
Thus, in the wake of recent extreme weather events and the resulting power outages in California and Texas, EPRI launched a new initiative on resource adequacy for a decarbonized future, enlisting a range of industry stakeholders, including NERC, to look at the metrics and methods used to assess risk.
“What’s clear is the way that we’ve actually conducted resource adequacy assessments in the past — with the changing resource mix and with the changing climate and extreme weather that we’re exposed to — those methods just may not expose the actual risks to the electricity grid going forward,” Brooks said.
The industry needs to rethink resource deployment, he said. “What are the right metrics? … How do we actually represent the performance of all of the different supply and demand resources under the context of that changing weather and climate? … How do you take that information, overlay that on to a particular utility grid and determine what the impacts are on the grid and then start to look at the investments that are needed to ensure that it is more resilient?”
Affordable, Equitable Transition
Along with grid resilience, Mansoor believes transportation electrification is going to be a key driver of the transition. It is, he said, “what will make this clean energy transition affordable and equitable.”
With U.S. automakers rolling out a range of electric vehicles, Mansoor sees EVs reaching price parity with gas-powered cars within the next three years. A family of four, spending a total of $4,500 per year on energy — including electricity, natural gas and gasoline — could save $1,000 a year by buying an EV, creating a major economic stimulus, he said.
The caveat is charging infrastructure, or the current lack of it, but Mansoor was again optimistic about state programs and the $7.5 billion for EV charging in the bipartisan Infrastructure Investment and Jobs Act.
At the same time, EPRI’s view of the energy transition encompasses nuclear, green hydrogen and the mitigation of coal and natural gas emissions, all technologies offering opportunities for the U.S. to innovate and compete in global markets. Neva Espinoza, vice president of energy supply and low-carbon resources, talked up a range of EPRI initiatives focused on accelerating the development and deployment of low-carbon technologies, including those that are not yet available. Just one example, the 2021 launch of EPRI and Georgia Power’s Ash Beneficial Use Center, which “allows for testing and validation of emerging policy or technologies that can help address residual coal products as we move forward,” Espinoza said.
The closing of coal plants has also led to a greater dependence on natural gas, Espinoza said. “We need to better understand methane, carbon, NOx emissions and other emissions profiles, how to characterize them, how to measure them and, of course, how to mitigate them,” she said.
Projects such as the New York Power Authority pilot on blending hydrogen with natural gas to generate power “will be critical as we think about integrating new low-carbon fuels into our energy system, understanding their operational profile, understanding overall air impacts, understanding overall safety impacts as we move forward to operationalize them and bring them into the energy system,” she said.
Multiple Paths to Decarbonization
Calling in from Abu Dhabi, Neil Wilmshurst, EPRI’s senior vice president for energy system resources, stressed the importance of looking beyond the energy transition in the U.S. and leveraging international collaboration as a “force multiplier.”
Tracking the energy transition in the Middle East is “a really, really educational thing,” Wilmshurst said. “You have tremendous solar installations. You’ve got countries entering into new-build nuclear issues. You’ve got people with oil-based economies thinking, ‘What does the future look like in 20, 30, 40 years?’”
Wilmshurst also focused on nuclear issues. First on keeping the existing U.S. fleet in operation “as much as possible, as much as feasible.” And second, on developing smaller, modular or micro reactors, particularly to produce hydrogen. Pointing to the advanced nuclear demonstration projects being supported by the Department of Energy, he said, “We need to have reactors being built, [and] hopefully operational in the next seven to eight years.” (See Strong Bipartisan Support for Advanced Nuclear at Senate Hearing.)
But the energy transition in the U.S., while irreversible, still faces political obstacles, most prominently the stalled Build Back Better Act and the federal tax incentives it contains for diverse clean technologies.
Confronting the current political landscape, Espinoza said, EPRI tries “to look above and beyond what those potential implications can be and what is required for different technologies.”
EPRI’s research has looked at mapping out multiple pathways to decarbonization, based on different assumptions and sensitivities, she said. “There will be different mixtures of technology. We know reliability and resiliency will be critically important; we know energy efficiency will be critically important; we know the electric sector decarbonization will enable economy-wide decarbonization,” she said.
“So, the sensitivities and the political and policy decisions can tweak the overall pathway,” Espinoza said. “But still those resounding, underlying findings remain the same.”
The Northwest Power Pool began forming committees last week to nominate directors and shape program design for its resource adequacy effort designed to serve much of the Western Interconnection.
The new stakeholder committees will start to prepare the program’s governance for an initial nonbinding “beta test” of the Western Resource Adequacy Program (WRAP) starting next winter and should be in place before NWPP seeks FERC approval for binding phases of the program in late 2023, organizers said.
In standing up the WRAP, NWPP has determined that it must meet FERC requirements for the group’s governance and committee structures as well as for the program’s design, including the appointment of an independent board of directors to replace its existing board staffed by member representatives. (See RA Program will Require Restructuring of NWPP.)
“We see the need ahead of the nonbinding program [and] ahead of the FERC filing … of setting up committees,” Sarah Edmonds, director of transmission services at Portland General Electric, said Wednesday during an NWPP meeting. “We see the need to get those committees going ahead of official approval of the governance structure, [and] we expect … that what we’re doing will be very easily translatable into the future FERC jurisdictional governance program with little to no changes.”
The two new committees — the Program Review Committee and the Nominating Committee — will be composed of representatives from various sectors, including independent power producers, public interest organizations and advocates for retail customers.
The Program Review Committee “will be charged with receiving, considering and proposing design changes to the WRAP and will serve as the clearing house for most recommended design changes,” NWPP said in a statement.
The Nominating Committee will help establish an independent board by working with an executive search firm to identify candidates.
In Wednesday’s meeting, NWPP Director of Reliability Programs Rebecca Sexton-Kelly asked sector representatives if they wanted to organize among themselves or needed NWPP’s help finding committee members.
Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, volunteered NIPPC to lead committee selection on behalf of independent power producers and marketers.
Nicole Hughes, executive director of Renewable Northwest, offered to head the public interest sector’s selection process. And Josh Weber, an attorney representing the Alliance of Western Energy Consumers, said AWEC would lead industrial sector organizing.
NWPP is planning to help the retail advocacy sector and a sector representing certain types of load-serving entities to find potential committee members.
‘Unacceptable Loss of Load’
NWPP began examining the idea of a Western RA program in 2019, as shortfalls loomed because of the retirement of fossil fuel plants, especially coal-fired plants, and the spread of weather-dependent wind and solar resources.
“Soon, areas in the West may face a capacity deficit of thousands of megawatts,” NWPP CEO Frank Afranji said in an April 2020 meeting hosted by the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body. “Deficits of that magnitude may result in both extraordinary price volatility and unacceptable loss of load.”
The WRAP is intended to increase visibility into existing RA conditions in the West, addressing concerns among industry stakeholders and state regulators that load-serving entities are unknowingly relying on the same capacity resources without realizing it, threatening system reliability during periods of scarcity.
The program is designed to provide participants a framework in which to access capacity resources when a participant is experiencing an extreme event.
In December, NWPP took its first steps in implementing WRAP by inviting participants to submit resource data for a nonbinding phase of the capacity market, which the organization says will serve as a “beta test” for a final program design. (See Implementation Underway for NWPP’s Western RA Market.)
NWPP noted that the move to implement the WRAP officially kicks off its working relationship with SPP, which has been retained to administer the program. (See SPP to Operate NWPP’s Resource Adequacy Program.)
Last week’s start to forming key committees was the next big step.
“The NWPP is looking forward to getting stakeholders engaged in governance and program design updates in this hands-on way,” COO Gregg Carrington said in a statement. “It’s an exciting evolution of the organization.”
Members Approve $1.04B 2021 ITP, Withhold $409M Project’s NTC
SPP stakeholders last week endorsed the grid operator’s latest transmission planning assessment, but not before withholding construction approval of a 345-kV, double-circuit project in West Texas.
The Markets and Operations Policy Committee on Jan. 10 agreed with a pair of working groups’ earlier recommendation to not issue notifications to construct (NTCs) to the 150-mile Crossroads-Phantom project.
The committee also withheld NTCs to a pair of transformer projects in New Mexico.
The 2021 Integrated Transmission Planning (ITP) report found the double-circuit project would provide twice the capacity of a single circuit, while “incrementally” increasing the engineering and construction (E&C) cost from $330.2 million to $409.9 million, a 23.9% increase. According to the 10-year assessment, the project would provide a low-resistance, parallel path for delivery of low-cost energy to Southwestern Public Service’s SPS South load pocket.
The 2021 ITP portfolio includes 28 projects costing more than $1 billion. | SPP
“For an additional cost increase, you’re getting two times the capacity and reserving some future options a little more effectively,” said ITC Holdings’ Alan Myers, chair of the Transmission Working Group (TWG).
The project is meant to address one of two targeted areas in the 2021 ITP where SPP found voltage-stability issues because of isolated load and above-average load projections, both related to oil and gas exploration: the Permian Basin in West Texas and eastern New Mexico, and the Bakken Formation oil fields in North Dakota.
However, load-projection errors, related to how load was allocated to individual substations, were discovered late in the process. Myers said the error was found in the 2022 ITP models, too late for staff to do a full impact analysis.
“So there was no time for staff to do like a full redo, if you will, of the analysis,” he said. “It was disproportionately, I believe, impactful to the loads down on that southern portion of the system.”
Myers said the TWG and Economic Studies Working Group spent a total of 7.5 hours in December discussing the NTCs for Crossroads-Phantom and the New Mexico transformers. Both groups endorsed the ITP in January but recommended the NTCs not be issued.
Staff, on the other hand, said they believe the Crossroads project is the best overall solution for the region. They requested the project still be considered for an NTC with conditions.
MOPC tabled and then un-tabled the proposal before finally approving the 2021 ITP by a vote of 56-5, with four abstentions. It recommended further evaluation of the Crossroads-Phantom project and that it be brought back to the committee during its July meeting.
The ITP portfolio includes 28 new projects and 380 miles of new 345-kV lines at an E&C cost of $1.04 billion. Staff said the projects would solve 185 system needs with a 5.3 to 5.7 benefit-to-cost ratio.
The committee also approved staff’s recommendation to re-baseline the delayed 2022 ITP by performing a reliability-only assessment, resuming full studies with the 2023 and 2024 ITPs.
SPP says its proposal to rebaseline the 2022 ITP will enable 2023 ITP work to begin early. | SPP
MOPC directed staff to work with the ESWG and TWG to review the tariff and scope documents to find further improvements to ensure timely completion of current and future ITP assessments. Staff are currently working on three ITPs, for 2021, 2022 and 2023. The 2022 plan is already behind schedule because of 2021 ITP constraints, and 2023 is at risk because of the previous two assessments’ delays.
SPP engineer Nick Parker said a task force that developed recommendations to improve the planning process “did a good job getting us close” and that staff were only a few months off, despite remote work during the COVID-19 pandemic and their other transmission-related requirements. (See SPP Strategic Planning Committee Briefs.)
“Certain stuff hit us all at once,” Parker said, adding that SPP has since added manpower to help manage the workload.
Casey Cathey, SPP’s system planning director, reminded members that ITP studies are on 27-month cycles so that a full assessment can be brought to MOPC every October.
“We did so in 2019 and 2020. The process is not broken,” Cathey said. “It’s really a 30-month process because of the contingencies that happen. Things happen. COVID happened, and that pushed things to where they’re at. Worst-case scenario, we do nothing and we have a 30-month process squeezed into a 27-month process, and you end up skipping an ITP once every four calendar years.”
MOPC also endorsed the 2021 ITP assessment report as having met the tariff’s requirement to complete the planning process.
Storage Accepted as Transmission
Stakeholders moved to accept storage resources as transmission assets in endorsing a recommendation (RR476) from the Electric Storage Resource Steering Committee (ESRSC).
The measure adds another acronym to SPP’s lexicon by defining the assets as “storage as transmission-only assets” (SATOAs). It requires SATOAs to register as market storage resources in the Integrated Marketplace to account for their injections and withdrawals. They will not be dispatched in the market and are only to receive charges and credits for the energy and over-collected losses; revenue or losses from the injections and withdrawals will be added back to the SATOA’s annual transmission revenue requirement.
EDP Renewables’ David Mindham said that while RR476 installs guardrails that prevent the assets from having an “overly burdensome” effect on the market, it “missed an opportunity.”
“By automatically assigning [SATOAs] to transmission owners, the developers could have provided a lot of experience in bringing these assets online,” Mindham said. “They could have provided this as a service and a competitive process probably more cheaply, especially for the limited uses that they’re intended for.”
He asked whether local issues outside the transmission-planning process would prevent the storage assets from coming online through the process.
“I don’t think that this process would prevent it from being put together,” SPP’s Joshua Pilgrim said. “The general consensus, since the device is only meant to run for post-contingency situations, is that their impact on local dispatch profiles would be minimal. They’re not designed to be run all the time. Most of the time, they’re waiting.”
MOPC Chair Denise Buffington, who also chaired the ESRSC, said storage devices’ multiple uses will demand a future conversation between staff and stakeholders.
“We need to get a baseline understanding out there for what the asset can do,” she said. “Once we get that baseline, we can start building on it. Part of the problem with some of the discussions we’ve had about the model is where do you start? Then, it starts to get circular.”
MOPC passed the measure by a 53-3 margin, with 10 abstentions. The Regional State Committee will have to weigh in on RR476’s rate sections.
The committee also endorsed an ESRSC policy paper that sets the methodology for accrediting hybrid generating facilities that qualify as capacity, SPP’s first such policy. The paper proposes that hybrid components (primarily wind, solar and storage) be studied and allocated separately, with four-, six- and eight-hour duration products. The proposal will consider a facility’s investment tax credit and its ability to charge from the grid, beginning with the 2023 summer season.
SPP defines a hybrid facility as two or more resources behind the same interconnection point, where at least one of the resources is not classified as storage.
Golden Spread Electric Cooperative’s Natasha Henderson, chair of the Supply Adequacy Working Group, said there are currently no hybrid facilities on the system, but they are expected to become more prevalent over the next five years. Given their multiple configuration possibilities, she said, the SAWG worked to ensure the facilities are not over or under accredited.
The stakeholder group will now work on criteria and develop tariff language. “That’s when we will debate the issue,” Henderson said.
“The policy’s basically been debated already,” American Electric Power’s Jim Jacoby said. “If people go out and make business decisions based on [the paper] and then you change the rules on them, they’re not going to be happy.”
Still, members approved the policy paper 49-7, with five abstentions.
Order 2222 Compliance Filing Endorsed
MOPC endorsed a revision request (RR468) that approves a compliance filing for FERC Order 2222 as SPP prepares to allow distributed energy resource aggregators to participate in its markets.
Members approved the measure by a 58-3 margin, with five abstentions, with some noting that did not mean they approved of FERC’s order itself.
“Our vote to approve is understanding that this is a compliance filing in response to a FERC order and not … endorsing the FERC order itself,” Oklahoma Gas & Electric’s Usha Turner said.
DeWayne Todd, with the Advanced Energy Management Alliance, said his organization remained concerned about the compliance proposal because “it does not really address some of the requirements of 2222 relative to reducing barriers [to DER participation].” He cited imposed telemetry requirements for every aggregation’s size, restrictions to single nodes and a registration process “that doesn’t provide a lot of value” because it’s duplicative to subsequent steps in the registration and participation process.
The compliance filing allows a DER aggregator to register its aggregation as a valid resource type if it meets technical and operational requirements, with the aggregator subject to the same service provision rules as other resources within that type. Aggregations must be at least 100 kW and can include a single DER. The aggregations must include real-time telemetry and settlement quality metering.
In what may be a nod to further pushback at FERC, SPP plans to keep alive the task force responsible for RR468’s tariff modifications until it receives the commission’s response. Assuming approval, staff plan to implement the tariff changes in early 2024.
The compliance filing was originally due last July, but FERC, noting the absence of opposing intervenors, granted SPP an extension until April 28 this year (RM18-9). (See FERC OKs Delay on Order 2222 Compliance.)
The committee also easily approved RR480, which gives the industry expert panel evaluating responses to SPP’s competitive transmission process the option to use incentive points in scoring the proposals. Members raised concerns that the expert panel could select a project other than the highest-scoring proposal, but they still gave the measure 93% approval.
JTIQ, Tx Value Staff Reports
David Kelley, SPP’s director of seams and tariff services, said the RTO’s collaborative work with MISO addressing their overflowing interconnection queues has identified a project portfolio that can relieve constraints on either side of the seam. Thirty-three of those constraints are in MISO’s footprint, and the other 17 are in SPP’s.
The grid operators began their joint targeted interconnection queue (JTIQ) study in September 2020, hoping to find interregional transmission projects to alleviate queues filled with renewable resource requests.
“The key theme was the development of generation along our seams and the difficulties many generation developers have found in accomplishing that,” Kelley said. “We happen to be very blessed in our part of the country with low-cost renewable generation; … the transmission system is at capacity along the seam.”
Kelley said the “optimized” portfolio has a preliminary combined load-adjusted-production-cost (APC)-to-cost ratio of 0.45. A report is being drafted for stakeholder review by the end of the month. The RTOs will schedule meetings with stakeholders to review the full results before seeking board approval for the plan.
A cost-allocation methodology is under development, Kelley said, and will reflect input from load-serving entities and generation developers. “We should reasonably assign those costs to those who will benefit,” he said.
Cathey told MOPC that an update to 2016’s value of transmission analysis determined that the $3.35 billion of installed transmission from 2015 to 2019 resulted in $27.2 billion in net present value of quantified benefits over 40 years and a 5.24 benefit-to-cost ratio.
The earlier study, dubbed by the Brattle Group as a “path-breaking effort,” found a net present value of $16.6 billion in benefits from projects installed from 2012 to 2014, a benefit-to-cost ratio of 3.5. (See SPP Begins Promotional Campaign to Tout Transmission Value.)
“I think that’s pretty reasonable if you think about what’s gone on in the last five years, especially with all the wind [resources] in our region,” Cathey said.
The new study simulated 57 days of production, compared to 38 in the earlier study, and captured benefits from line rebuilds and transformer additions in addition to the new infrastructure. Operations and engineering staff, “squeezing” in the analysis along with their other work, evaluated APC savings, reliability and resource adequacy benefits, increased wheeling revenues, reduced on-peak losses, and optimal wind generation development.
Cathey said the report is 95% complete. Staff will share the study and findings with other stakeholder groups before seeking endorsement from the Strategic Planning Committee in April. The report will then be shared with a wider audience.
Engineering Humor
A comedy routine (Or was it a comedy of errors?) broke out during MOPC’s final four-hour segment. Cathey, an engineer by trade, took advantage of a momentary pause before one of his presentations to try out his standup chops.
“Two investors were talking and one asked the other, ‘What do you think about this solar craze?’” Cathey said. “The other said, ‘Well, it’s not going to happen overnight.’”
Greeted by silence, he moved on. Cathey’s listeners, punch-drunk after hours of virtual conversation, didn’t.
“You just can’t hear all the laughter,” Lincoln Electric System’s Dennis Florom said in the virtual meeting app’s chat function.
Others chimed in with their own versions of “dad jokes.” Energy consultant Simon Mahan tweeted to SPP to “please let Casey know Energy Twitter loves him.”
MOPC’s New Faces
MOPC welcomed several new members, including two representing SPP’s newest members: Ray Bergmeier, with Sunflower Electric Cooperative’s competitive Konza Transmission, and Matt McCoy, with Southern Star Central Gas Pipeline. The pipeline company joined the RTO late last year as its 107th member. (See Southern Star Gas Pipeline Joins SPP.)
The committee’s other new members stepped in for their companies’ previous representatives. They are Western Area Power Administration’s Steve Sanders for Lloyd Linke; AEP-Southwestern Transmission Co.’s Brian Johnson for Chad Heitmeyer; Exelon’s Jason Barker for Chris Lyons; Walmart’s Jim Staggs for Holly Rachel Smith; Northeast Texas Electric Cooperative’s Ron Ray for Rick Tyler; and Mor-Gran-Sou Electric Cooperative’s Trisha Samuelson for Robert Kelly.
$73M Tab for 161-kV Rebuild
Members unanimously approved the consent agenda, which included the Project Cost Working Group’s recommendation to re-baseline the 31-mile, 161-kV Neosho-Riverton rebuild project’s costs from $48.3 million to $73.1 million. The line is historically SPP’s highest congested path, but rising steel costs and delivery issues threaten its in-service date of October 2023.
The agenda’s approval also resulted in MOPC’s endorsement of the Transmission Owner Selection Process (TOSP) Task Force’s suggestion to sunset next January. The TOSPTF has been evaluating improvements to SPP’s competitive transmission process, several of which were among the eight revision requests on the consent agenda:
RR450: provides guidance for using operating guides in the planning horizon.
RR469: corrects the Integrated Marketplace protocols’ settlements language defining the variables RtDesiredEn5minQty and RtOrigLmp5minPrc to clarify that the real-time desired energy five-minute quantity (RtDesiredEn5minQty) uses the dispatchable LMP and the real-time original locational five-minute price (RtOrigLmp5minPrc) uses the LMP.
RR470: corrects settlements language in the Marketplace protocols by removing an erroneous “minus” in section 4.5.9.35 (Real-Time Ramp Capability Non-Performance Amount) and correcting the variables in section 4.5.12 (Revenue Neutrality Uplift Distribution Amount).
RR471: automatically suspends the TOSP if a re-evaluation is approved equal to the days the re-evaluation requires.
RR472: requires that the TOSP’s industry expert panel Direction to Respondents document be created and published during a request for proposals response window.
RR473: cleans up the TOSP’s governing documents to more accurately capture their intent and execution.
RR478: adds flexibility to the resource planning process by allowing alternative methods outside of software, as required by the ITP manual.
RR479: clarifies staff’s steps when reviewing submitted detailed project proposal and determining if they qualify for incentive points under SPP’s competitive transmission process.
Just hours after taking office on Saturday, Virginia Gov. Glenn Youngkin (R) signed an executive order aimed at taking the state out of the Regional Greenhouse Gas Initiative, the 10-state cap-and-trade compact whose members have seen their carbon emissions decline by 50% since the program began in 2009.
The executive order sets up an expedited, 30-day process under which the departments of Environmental Quality (DEQ) and Natural Resources (DNR) will reanalyze the costs and benefits of RGGI and draft a proposed emergency regulation for the State Air Pollution Control Board to repeal its 2019 rules allowing the state to join the initiative.
Youngkin also ordered the departments to notify RGGI of the state’s intent to withdraw and “take all necessary steps so that any proposed regulation to the State Air Pollution Control Board can be immediately presented for consideration for approval for public comment.”
The order tacitly acknowledges what critics have argued since Youngkin first vowed to take Virginia out of the initiative during a speech in December: The governor does not have the authority to unilaterally order a withdrawal. (See Youngkin Vows to Pull Va. from RGGI.) He will have to work through a regulatory process that has some significant roadblocks built into it.
For example, Youngkin has based his argument against RGGI primarily on its cost to the state’s utilities and their customers. As part of its participation in RGGI, the Air Board has set a cap on carbon emissions in the state, which declines each year through 2030, and utilities must buy carbon allowances to cover emissions above the cap.
As noted in the executive order, Dominion Energy has estimated that it will have to pay $1 billion to $1.2 billion on allowances in the next four years, which has already raised residential rates $2.39/month. The utility had applied to the State Corporation Commission for an even higher add-on — $4.37/month beginning in September — to recover its costs for RGGI, but it pulled the application after Youngkin’s speech.
But how costs and benefits are calculated is sure to be a flashpoint for former EPA Administrator Andrew Wheeler and Michael Rolband, Youngkin’s picks to head the DNR and DEQ, respectively.
To date, Virginia has earned $227.6 million in proceeds from the auction of carbon allowances, as recorded on the RGGI website. That money is split between the state’s community flood preparedness program (45%) and energy efficiency measures for low-income households (50%). The remaining 5% covers administrative expenses.
In December, former Gov. Ralph Northam (D) announced that RGGI funds would provide $24.5 million to 22 local government organizations for flood preparedness projects. Another $15.2 million is filling a gap in state programs for weatherizing low-income housing, and $5.9 million is being used to preserve or build hundreds of affordable housing units, according to the Virginia Department of Housing and Community Development.
“Were Virginia to withdraw, we would lose hundreds of millions to help working-class families cut their electric bills,” said Harry Godfrey, executive director of Advanced Energy Economy Virginia.
Health benefits related to emission reductions produced by RGGI are also likely to be raised by environmental advocates. A 2020 study from Columbia University’s Mailman School of Public Health found that, in addition to carbon emissions, the initiative is cutting particulate matter, which is decreasing childhood asthma and premature birth rates. The study estimated the benefits at $191 million to $350 million across the RGGI states.
A Packed Board
Implementation of the executive order will also depend on leadership at the DNR and DEQ, which could be yet another hurdle.
Wheeler, who led EPA during the Trump administration, will first have to clear confirmation hearings in both houses of the Virginia General Assembly. Republicans now hold the House of Delegates, but Democrats have a slim majority in the Senate. (See Youngkin Taps Trump’s Former EPA Chief to Head Virginia DNR.) Similarly, because the Air Board is part of the DEQ, the less controversial Rolband might also face questions about RGGI at his confirmation hearings.
But the board itself could be the biggest obstacle to Youngkin’s effort to withdraw Virginia from RGGI, regardless of how fast he pushes for an emergency rollback. The original vote on the RGGI regulations was 5-2, and the seven-member board is now packed with Northam appointees. The new governor’s first opportunity to change the board’s composition will come in June, when Vice Chair Kajal B. Kapur’s and Gail Moore’s terms end. Youngkin might have to wait until 2024 to get a clear majority on the board.
Further, the DEQ successfully defended RGGI from a legal challenge from the Virginia Manufacturers Association. As reported in the Virginia Mercury, the Richmond Circuit Court in July rejected the association’s argument that RGGI is an illegal carbon tax on utility customers.
Virginia Democrats quickly voiced opposition to withdrawal. A statement on the state party’s Twitter feed declared that “Glenn Youngkin is already failing Virginia on climate change. His short-sighted decision to remove Virginia from the RGGI is purely partisan and it makes clear that he has no clear plan to combat climate change or invest in a clean energy future in Virginia.”
Nate Benforado, senior attorney at the Southern Environmental Law Center, called the executive order “a dead end.”
“For a new governor who has pledged to help Virginia communities struggling with climate change, this is a shocking and troubling first action out of step with what Virginia communities need,” Benforado said in an email statement.
Meanwhile, a tweet from the Richmond chapter of the Neoliberal Project noted that Del. James Morefield (R) recently introduced a bill (HB 5) that would cut the RGGI allocation for community flood preparedness from 45% to 40% and redirect that 5% to a flood relief fund that would compensate private property owners for flood damage.
