SPP may ask FERC to lower its exit fee in response to the commission’s April order that the RTO eliminate the fee for members who are not transmission owners or load-serving entities.
Staff told the Corporate Governance Committee on June 17 that they believe FERC’s order (EL19-11) suggested the commission may approve a lower amount. SPP faces an Aug. 1 deadline to make a compliance filing and has already submitted a rehearing request to clarify the definitions of TOs and non-TOs. (See FERC Tells SPP to End Exit Fee for Non-TOs.)
The committee agreed in executive session to recommend a fixed $100,000 exit fee to the Board of Directors when it meets on July 30. The current exit fee is estimated at $631,915, nearly twice the $327,191 fee that FERC approved in 2006, when it last required the RTO to impose an exit fee on all members.
Load-serving members would be subject to an additional share of SPP’s financial obligations and future interest based on their net energy for load percentage. LSEs would be defined as distribution or electric utilities that have a service obligation and/or secures energy and transmission service to serve its end-use customers’ demand and energy requirements.
Staff noted the commission’s order said “some level of exit fee that does not act as a barrier to membership and is not excessive could be appropriate in SPP.”
By making the fee a fixed amount, SPP said it would be addressing the commission’s concern that the exit fee can move up or down.
FERC’s order came in response to a complaint filed by the American Wind Energy Association and Advanced Power Alliance, formerly the Wind Coalition. The groups charged that SPP’s exit fee results in unjust and unreasonable rates and creates “a barrier to membership” for non-TOs and non-LSEs.
“What’s being proposed here does not seem to track with cost-causation principles. Such an exit fee that’s not based on any … principles would likely be opposed,” APA’s Steve Gaw said. “We would like to see something that is more in line with what other RTOs have found to be appropriate for membership and stakeholder participation.”
CGC member Denise Buffington, director of federal regulatory affairs with Evergy companies Kansas City Power & Light and Westar, cautioned against the move considering the pending rehearing request.
“If FERC gets this as an alternative … it’s an easy pass for them not to deal with this issue. My preference would be to wait until we get an order on the rehearing request,” she said. “If I were giving legal advice on behalf of the client, I would stick close to what FERC has ordered.”
SPP CEO Nick Brown said staff debated the timing of the alternative proposal but said the recommendation was “to help FERC get the right answer.”
“We’ve continued to debate this [issue] at the request of non-members or members who wished to withdraw but couldn’t afford the exit fee,” he said. “In putting this proposal on the table, we specifically wanted to influence FERC’s thinking and help them to make a decision. We consider this just and reasonable.”
Other committee members favored the lower exit fee. Dogwood Energy’s Rob Janssen said the reduced fee would solve the problem of “zombie members”: those who stayed members “because it was easier than paying the exit fee.”
“I think this change will make them come out of the woodwork and make a decision one way or the other,” Janssen said.
The CGC will also recommend approving the compliance filing, which would change SPP’s governing documents in response to FERC’s order. Staff said it will include what it believes are errors in FERC’s order, for which they are seeking rehearing.
If the board approves the committee’s recommendations in July, they will be promptly filed at FERC to meet the Aug. 1 deadline.
RENSSELAER, N.Y. — NYISO presented the Business Issues Committee the final market design for pricing carbon emissions into its wholesale electricity markets on Thursday, the same day the New York State Assembly passed a bill that will put many of Gov. Andrew Cuomo’s environmental targets into statute.
The Climate Leadership and Community Protection Act (A8429) will require 70% of the state’s electricity be generated by renewable resources by 2030, nearly quadruple its offshore wind energy goal to 9 GW by 2035 and require the economy to be carbon-neutral by 2040. The law also doubles the distributed solar generation goal to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)
| NYISO
Stakeholders were divided on whether the bill — expected to be signed into law by Cuomo — necessitates increased skepticism on carbon pricing or urgency on the effort.
“It will take time to digest the new information, but having carbon pricing helps reach these goals, said Rana Mukerji, NYISO senior vice president for market structures. “If [load-serving entities] are required to buy renewables, the procurement prices will reflect the benefit renewables derive from having carbon priced into the energy market.”
Representing the Independent Power Producers of New York, Matt Schwall said, “IPPNY continues to be very supportive. … Carbon pricing is now more important than ever. There’s been a lot of time spent developing the idea, and this will help us reach the targets.”
Luthin Associates’ Aaron Breidenbaugh, representing Consumer Power Advocates, an unincorporated group of nonprofit institutional customers, said he was “skeptical” of how consumers could benefit from carbon pricing under the new law.
Couch White attorney Kevin Lang, speaking for New York City, said he shared Breidenbaugh’s concerns: “Carbon pricing isn’t going to get us incrementally more generation … and I agree that NYISO needs to look at the new law before moving forward.”
Mark Younger of Hudson Energy Economics said, “You can put targets, but that doesn’t mean they’re effective. You can put 7,000 MW of wind in the North Country and meet a target of 7,000 MW of additions, but not get much benefit of zero-carbon megawatt-hours in the state.”
“Action needs to start happening immediately, and we need to be sending price signals that reflect the value, or the damage, of carbon emissions,” said Howard Fromer, director of market policy for PSEG Power New York. “How? The closest thing is the mechanism we’ve come up with here, and carbon pricing is even more important now than it was a year ago.”
Robert Pike, NYISO director for market design and product management, said, “We’re here today just to recognize the culmination of the work that’s taken place over a considerable amount of time.”
Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), said, “A long time ago, we said that a market without a carbon component is inconsistent with our environmental goals. Carbon pricing can help the state reach its goals.”
On Monday, third-party consultant Analysis Group presented to the Installed Capacity/Market Issues Working Group preliminary results of a supplemental analysis examining the impacts of pricing carbon. The study is intended to augment the Brattle Group report process that concluded in December. (See More Details Divulged on New NYISO Carbon Pricing Study.)
Broader Regional Markets Update
Pike presented the monthly Broader Regional Markets report and highlighted item No. 26, noting that the Management Committee in May approved a new external supplemental resource evaluation (SRE) penalty regime.
Approved by the BIC in April, the SRE penalty provisions will boost the ISO’s ability to call on external resources that have sold capacity to New York. Pending FERC approval, the proposal is anticipated to become effective in August.
Pike also highlighted BIC and MC approval last month of revisions to the NYISO-PJM joint operating agreement to address coordination on flowgates similar to the East Towanda-Hillside Tie Line.
Manual Revisions
The BIC approved revisions to several manuals, with most of the changes required by implementation of the Zone J (New York City) reserve region.
Ashley Ferrer, NYISO energy market design specialist, reported that the changes would affect the Ancillary Services, Day-Ahead Scheduling and Transmission & Dispatch Operations manuals.
ISO staff engineer Harris Miller detailed additional revisions unrelated to the Zone J reserve requirements being proposed within the affected manuals.
Ferrer said the proposed New York City reserves would go into effect Wednesday, assuming approval by FERC.
LBMPs, Gas Prices Drop
NYISO locational-based marginal prices averaged $23.10/MWh in May, down about 17.5% from April and about 19.7% from the same month a year ago, Pike said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $37.57/MWh, a 25% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in lower compared to April. Average daily sendout was 373 GWh/day in May, higher than 371 GWh/day in April and lower than 397 GWh/day in the same month a year ago.
Transco Z6 hub natural gas prices averaged $2.27/MMBtu for the month, off slightly from April and down 11% from a year ago.
Distillate prices were down 8.5% year over year and mixed from the previous month, with Jet Kerosene Gulf Coast averaging $14.64/MMBtu, up a penny from April, while Ultra Low Sulfur No. 2 Diesel NY Harbor dropped to $14.54/MMBtu from $14.72/MMBtu in April.
May uplift increased to 13 cents/MWh from -15 cents in April, while total uplift costs, including NYISO’s cost of operations, came in higher than the previous month.
The ISO’s 23 cents/MWh local reliability share in May was up from 20 cents the previous month, while the statewide share climbed to -11 cents/MWh from -35 cents in April.
The Thunderstorm Alert cost was 19 cents/MWh, up from the usual zero to 1 cent.
Phase 2 of NERC’s Standards Efficiency Review has narrowed its focus to four tasks, tabling two others for potential work by other committees, members of the Phase 2 team said last week.
In a June 17 conference call, the team said it would focus its work on the four initiatives that received the highest response from stakeholders in polling that concluded March 22. (See “Team Reviewing Feedback on SER Phase 2,” NERC Standards News Briefs: May 8-9, 2019.)
The team’s decision followed a June 11 meeting with the SER Advisory Group and FERC staff.
“There was a discussion with the Advisory Group on how [SER] Phase 2 is much different than Phase 1. We’re looking more holistically and long-term at ideas that can streamline things going forward, not necessarily individually at the requirement level,” said SER Phase 2 Chair John Allen, manager of reliability compliance for the City Utilities of Springfield (Mo.). “I thought there was good support from the Advisory Group and at least no indication from FERC staff that we were heading down a road that was not viable.”
The top two priorities — changes to the evidence-retention rules and consolidating information/data exchange requirements — are expected to be completed this year.
The team also will tackle a proposal to move “competency-based” requirements from standards to guidance documents and developing a risk-based standards template; those efforts are likely to extend into 2020, team members said.
“There’s a lot of work that was already done on … evidence retention, so there was a good baseline to start on that. On the data and information consolidation, it’s pretty cut and dried, straightforward,” Allen said.
“These other two are shifts. We’re putting these ideas out there to say, ‘Here’s how we do it today. How can we do it more efficiently going forward?’ To make that successful, we’ve got to get all the right stakeholders together.”
The SER team declined to work on relocating competency-based requirements to the certification program/controls review process, which will be transitioned to the Compliance Certification Committee or the Organization Registration and Certification Programs (ORCP).
It also is dropping an initiative on consolidating and simplifying training requirements. A subgroup of the Phase 2 team “is talking about potentially drafting a [standards authorization request] for the training concept,” said Chris Larson, NERC manager of standards information.
Reducing the Scope of Work
In working on the prototype standards, Allen said, the SER team should “find some way to try to reduce the need or the scope of the work for a future Standards Efficiency Review or Paragraph 81 or whatever you want to call it — a cleaning up of the standards.”
Paragraph 81 is a reference to FERC’s March 2012 order on NERC’s Find, Fix and Track process, in which the commission told NERC it would welcome proposals to revise or remove reliability standards or requirements that are redundant or add little protection to system reliability (RC11-6, et al.).
“If we can put ourselves on a better path going forward where we don’t have to do this every five years, we’ve done some good work,” Allen continued. “That’s really what we’re going to look to in the prototype standard — is how to put some tools out there going forward to help have a more efficient product where we don’t have to go and clean them up every few years.”
“I’ll second that concern,” said John Pespisa, an Advisory Group member from Southern California Edison. “[The] key to not doing this again in the near future is bringing that key concept into this process.”
Randy Crissman, senior reliability and resilience specialist for utility operations at the New York Power Authority, said there is a need for a “communications strategy.”
“How do we help facilitate the adoption and implementation of that type of an approach? It’s going to be a pretty big lift, but if we don’t try it, it will never happen.”
The Pacific Northwest’s March 1 price spike “should serve as a wake-up call” of the region’s coming capacity shortage, power industry consultant and former Bonneville Power Administration chief Randy Hardy warned in April.
Hardy reported that bilateral March 1 day-ahead peak prices at the Mid-Columbia trading hub broke $900/MWh, driven by natural gas prices of $160/MMBtu. By comparison, CAISO day-ahead prices that day ranged from about $38 to $82/MWh, holding that high for only one evening interval. (See Cold Forces NW to Dip More Deeply into EIM as Avista Joins.)
On Wednesday, the Western Electricity Coordinating Council Board of Directors received a briefing from Operating Committee Chair Richard Hydzik on preliminary findings of the OC and the Market Interface Committee regarding the event. “The question was, was there a capacity issue related to this?” asked Hydzik, principal transmission operations engineer with Avista.
The answer is still up in the air. Hydzik noted the region had adequate reserves during the event, and his presentation focused on the temporary supply constraints.
The event occurred during the first week of March, with unusually low temperatures that were closer to those in a typical January. The cold snap led to high demand for natural gas and electricity. At the same time, utilities were doing maintenance or had taken assets out of service during a time that normally sees lower demand.
Hardy’s report noted that the high prices “and the capacity shortage that they reflected, occurred despite all the soon-to-be retired PNW coal plants operating at maximum capacity.”
Hardy cited research by analysts E3 that predicts load growth and announced coal plant retirements could leave the PNW with an 8-GW capacity deficit by 2030 without new dispatchable capacity. That would increase the region’s loss-of-load probability (LOLP) to 48%, he said, noting that WECC utilities’ normal reliability standard is a 5% LOLP.
Hardy said the situation is complicated by moves by Oregon and Washington lawmakers to prevent the building of new gas-fired generation. Hardy said the region could be limited to wind and solar for new energy resources and batteries and pumped storage for new capacity.
Shoulder Month Surprise
Hydzik told the WECC board the March 1 price spike was attributable in part to a lack of south-to-north transfers on the DC Pacific Intertie, which was down for maintenance. A major gas pipeline moving fuel from British Columbia into Washington was running at 80% capacity because of an explosion last fall, and one 730-MW unit at the coal-fired Centralia (Wa.) plant had been taken offline. Balancing authorities were serving native demand and limiting exports.
“So, this is March. Typically, it’s a shoulder month,” Hydzik said. “Six months earlier you plan all of your maintenance to be out of this stuff [before summer demand hits]. Once you take some of these facilities down, you cannot quickly restore them, and you’re simply out of service.”
But the BAs and the Northwest Power Pool Reserve Sharing Group had ample reserves. No emergency alerts were called, and transfers were flowing into the region. BC Hydro “saw this coming,” Hydzik said, and sent an additional 2,000 MW into the U.S. from Canada, reversing the predominant flows on the BC Intertie as the utility’s Powerex marketing arm reduced purchases and boosted exports to take advantage of the surging market.
“Good for them,” he said. “Maybe not so good if you’re south of the border. …
“So, what did we find so far?” he said. “Everyone in the Northwest had more than adequate reserves. … Just because something was expensive doesn’t mean it wasn’t available.”
Gas supplies were constrained, and coal plants and other resources have been retired. Additional findings will be presented at a future meeting, he said.
Director Jim Avery said the situation had raised concern at WECC and may be a sign of things to come.
“Here we are in the shoulder months experiencing some of the bigger problems,” Avery said. “These are going to become the new norms.
“We’re going to have different resources that perform differently in different seasons,” he said. “And yet we’ve been operating the system the same, and that is, ‘Well, shoulder months, that’s when we do our maintenance.’ We’re going to have to rethink that because during peak load conditions in the middle of the day, we may have an abundance of resources [such as solar] that we’ve never had before. And that’s just the new norm.”
Hydzik said he agreed with Avery’s comments.
Hardy offered several potential actions to respond to the capacity shortage, including adding transmission to access Montana or Wyoming wind power; an overhaul of “fossil fuel era” planning and operating metrics; and incentives for ramping resources.
A lack of action would leave the region praying “for rain and mild weather,” Hardy said.
“Murphy’s law predicts that the next low water year in the PNW will arrive in 2025 as peak coal plant retirement occurs and the PNW [integrated resource plans] defer decisions on construction of new resources waiting for the next cost reduction in carbon-free capacity.”
TORONTO — Facing many of the same challenges as its counterparts in the U.S., Ontario’s Independent Electricity System Operator (IESO) is reshaping its markets to handle an influx of renewable and distributed energy resources.
That transformation was a key topic of discussion at the IESO’s annual Electricity Summit held June 18-19. Billed as the “Electricity Market of the Future,” the event drew nearly 1,000 attendees. Here’s some of what we heard.
In his opening remarks kicking off the summit, IESO CEO Peter Gregg said his staff will spend the next six to 12 months focused on finalizing the “Energy Stream” initiative within the grid operator’s broader Market Renewal Project (MRP), an ambitious multiyear effort to overhaul its markets.
The initiative will close the timing gap between IESO’s pricing and dispatch runs by introducing a single-schedule market to ensure prices better reflect actual system conditions at the point of dispatch. The effort will also refine real-time processes while introducing a new day-ahead market and an incremental capacity auction intended to replace the existing demand response auction. (See Stressed in US, Capacity Markets Come to Ontario, Alberta.)
Gregg said IESO is working to address concerns among DR providers about the upcoming capacity auction changes that will enable competition between additional resource types.
“We will also be focused on running the next two auctions in December of this year and June of next year and making ineligible [for participation] additional resources such as generators who are without a contract — and also including imports,” said Gregg, who is also on NERC’s Member Representatives Committee.
Brattle Group principal Kathleen Spees said MRP’s main benefit will be to give customers choices on energy prices and services. It will also provide “much more efficient pricing, at every time scale, in the energy and ancillary services markets so that the supply side of the market knows how to react.”
“These markets allow us to achieve reliability in an efficient manner … they don’t exist for the sake of having markets,” IESO COO Leonard Kula said.
Kula noted that when IESO opened its wholesale electricity market in 2002, it moved from an Ontario Hydro command-and-control structure to a system based on a five-minute, financially binding price.
“And we were able to make that transition because we provided a whole lot of information and data in support of it, so we had daily security inadequacy assessments, 18-month outlooks and a whole variety of products,” Kula said. “That data supports a distributed decision-making model that allows different people to go in, read that information and respond accordingly.”
MRP represents a greater opportunity for participation in Ontario’s electricity markets, IESO Board Chair Joe Oliver said.
“What started as a small club has now grown to almost 600 market participants,” Oliver said. “Last year, nuclear and hydro met 86% of the province’s electricity needs, but other resources were important, too, including non-hydro renewables and demand response resources, with wind at 7%, gas at 6%, and solar and biomass at 0.7%.”
The result is that Ontario’s electricity system was more than 93% carbon-free in 2018, compared to 56% in New York, 49% in New England, 40% in PJM and 24% in MISO, he said.
But creating such an exceptionally green system “has exacted a financial toll on ratepayers,” Oliver said. “The so-called Fair Hydro Plan artificially lowered costs for residential customers by about a quarter by pushing costs to taxpayers now, and potentially to ratepayers in the future. Still, affordability remains a problem for too many families of lesser means.”
The federal government authorized the bill-reduction plan in 2017 through the Ministry of Energy, Northern Development and Mines, but the reduced rates do not apply to industrial users.
Oliver cited a study by Hydro-Québec that found industrial customers in Toronto paid an average 10.66 cents/kWh (about 8.1 cents U.S.), higher than in other Canadian cities and 20 to 25% more than companies in U.S. cities.
Nuclear and hydro in Ontario cost 7.5 cents/kWh, while new resources in the province cost an average 40 cents/kWh, which is why residents pay on average 12 cents/kWh, he said.
“Happily, wind and solar prices will decline … and that’s relevant because the IESO is now agnostic about the sources of power and it values the competition,” Oliver said.
In his opening comments, Gregg also highlighted a report issued this month by the Energy Transformation Network of Ontario (ETNO) on the structure of the grid with increasing penetration of DERs.
The report acknowledges “strong differences of opinion” among stakeholders as to what market model will work best for both consumers and private industry, and that IESO will have to balance between a “natural monopoly” in areas such as grid operations and local distribution, and open competition in new, value-added services.
During a panel on the subject, ETNO Vice Chair David McFadden, president of Generation Four Capital, noted that while consumers value reliability ahead of price, they are still sensitive to price. If new products and services “generate customer benefit in terms of price, then we’ve delivered what customers are interested in,” he said.
Independent consultant Lorenzo Kristov, a former CAISO market designer, posed a basic question that he said industrial customers will be asking themselves: Why stay connected to the grid?
“If the costs of being part of the grid outweigh the benefits, then we’ll have real equity problems,” Kristov said. “It will be the more financially capable and larger customers that are going to leave the grid first, and leave the cost of that to everyone else.”
He pointed to one reason to stay connected: market opportunities.
“In particular, if you can install equipment behind the meter, and then be a participant in the market, providing grid services, getting compensated for non-wires alternatives, engaging in energy transactions — creating that marketplace is also a way to realize customer value and reduce rates,” Kristov said.
Role for Storage
Christy Walsh, director of FERC’s Office of Energy Policy and Innovation, discussed the commission’s efforts to overcome market barriers for energy storage. She said storage posed a challenge for policymakers because it blurs the lines between transmission and generation, and between market-based energy and ancillary services.
FERC Order 841 directed U.S. RTOs and ISOs to remove barriers to the participation of electric storage resources in their capacity, energy and ancillary services markets, and set a Dec. 3, 2019, deadline for them to comply.
One major issue that “we issued an order on last month was jurisdiction, which essentially means that any storage resource that met our definition … can participate in the wholesale markets, and it didn’t matter whether that storage resource was connected at transmission, at distribution or behind the meter,” Walsh said. (See FERC Upholds Electric Storage Order.)
Industry stakeholders had protested that FERC lacked jurisdiction to make rules on distribution-level or BTM storage.
“What we essentially said was, ‘We disagree with you,’” Walsh said. “All we’re saying is, if they participate at retail, they can participate in our markets. We’re not saying how or whether they can participate in retail markets.”
Increased penetration of inverter-based technologies presents a special challenge to IESO because inverters represent a different system impact in terms of inertia, Kula said.
“Many technologies can provide multiple services,” Kula said. “The question is, who should decide what services those resources should provide? From our perspective, we favor a model that says, here are the reliability services that we need. We can’t anticipate all the different ways that people can use those technologies, so we would prefer that the people who own the assets and do know those technologies can go ahead and target their operations to meet what the system needs.”
“We really do need to be more creative in performance,” said Annette Verschuren, CEO of storage company NRStor. “We have a little flywheel facility with the IESO … and it can produce frequency regulation two-and-a-third times faster than a traditional generation facility.”
“We have too much surplus energy in our system,” Verschuren said. “And energy storage is not the [only] answer; it’s also demand-side, all kinds of energy efficiencies. Look, we invented basketball in Canada, and we also had the first NBA game with the Huskies here in Toronto in 1946 … and I think we should own innovation.”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
1. Fuel Security Senior Task Force Charter (9:20-9:35)
PJM will ask the Markets and Reliability Committee to approve the charter for its controversial Fuel Security Senior Task Force on Thursday.
Stakeholders reluctantly endorsed a problem statement and issue charge in March after some doubted the necessity of the conversation and even inferred that PJM already had a solution in mind. (See PJM Stakeholders Reluctantly OK Fuel Security Initiative.)
If approved, the task force will report back to the MRC in September with any possible recommendations for addressing the first four key work activities outlined in the issue charge: providing education on the issue; quantifying the risk of selected scenarios that could risk fuel security; defining fuel/energy security; and determining whether there is a quantifiable and/or locational requirement for fuel/energy security. The MRC will provide a timeline for completion of the remaining goals at the September meeting.
2. Manual 6 Amendments (9:35-9:50)
Staff will seek endorsement of revisions to Manual 6: Financial Transmission Rights as part of their cover-to-cover review.
The revisions contain language reflecting recent and upcoming FTR market changes. They would remove all details on FTR credit policy, providing a reference to credit rules in the RTO’s Credit Policy and Attachment Q of the Tariff, which address the recently added mark-to-auction requirement.
Brian Chmielewski, manager of market simulation, said at last month’s MRC that staff are continuing their look into rule changes around FTR mark-to-auction credit requirements detailed in Section 6.7, but they’re moving ahead with default settlement rule updates, realignments to the OASIS refresh and the hourly cost component change, pending FERC approval.
3. Manual 14B Amendments (9:50-10:30)
LS Power’s proposed Manual 14B revisions are scheduled for a vote after two deferrals back to the Planning Committee for further work.
During the June PC meeting, PJM Manager of Transmission Planning Aaron Berner said stakeholders appeared close to agreeing on tweaks to the language and would be ready for an MRC discussion later that month.
Sharon Segner, vice president of LS Power, first offered the revisions at the January MRC meeting after expressing concern over the growing number of supplemental projects languishing in the Regional Transmission Expansion Plan. Supplemental projects are proposed by transmission owners and are not required for compliance with PJM’s reliability, operational performance or economic criteria.
Segner’s proposed language specifies that a TO’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting it. A special session of the Planning Committee has been meeting over the last three months to review a variety of legal issues related to FERC Orders 890 and 1000. (See “RTEP Removal Language Vote Deferred, Again,” PJM MRC/MC Briefs: April 25, 2019.)
Berner will also present feedback received from stakeholders about the direction of the special PC discussion on the RTEP language. (See “RTEP Poll,” PJM PC/TEAC Briefs: June 13, 2019.)
Members Committee
1. Must-offer Exception Process (1:25-1:45)
The Members Committee will be asked to endorse rule changes for PJM’s must-offer exception process after months of debate among stakeholders.
The MRC endorsed a joint plan from PJM and the Independent Market Monitor in April that would strip capacity interconnection rights (CIRs) from generators seeking must-offer exceptions without a plan to become capable of meeting Capacity Performance requirements.
Stakeholders approved the proposal in a sector-weighted vote of 3.74 to 1.26, with unanimous support from both electric distributors and end-use customers. The two sectors shot down PJM’s original plan to take CIRs from resources after a three-year period of lost CP capability, which had been approved by 79% of the Market Implementation Committee in November. The sectors also rejected an alternative from Exelon that would have allowed capacity resources to switch voluntarily to energy-only status and disallowed PJM to force such a switch. (See Load Interests Endorse PJM-IMM Must-offer Proposal.)
TRAVERSE CITY, Mich. — MISO executives last week said they continue to seek ways to improve the RTO’s response to an increasing number of emergency events.
The issue became a point of discussion at a June 18 meeting of the MISO Board of Directors’ Markets Committee when the RTO and its Independent Market Monitor expressed different conclusions about the management of a mid-May emergency in MISO South.
Executive Director of System Operations Renuka Chatterjee said MISO experienced tight operating conditions in its southern region because of multiple forced outages coinciding with above-average temperatures. Planned outages totaled about 9 GW in MISO South on May 16 and unplanned outages and derates took another 7 GW offline.
“When we lose that many megawatts in such a short period of time, that’s outside of our band of tolerance,” Chatterjee said.
“We’re not aware of the reasons behind these forced outages yet. Operators have until the end of June to let us know,” she said, adding that MISO is considering requiring operators to more quickly report the reasons behind forced outages.
But Monitor David Patton also pointed out that multiple generators extended their planned outages in May, exacerbating the situation.
“The planned outages that were supposed to go away get extended,” Patton explained. “If your outages don’t ramp down as quickly as you hoped, you get these tighter operating conditions in May.”
Altogether, the RTO said projected capacity shortages in mid-May “were reliably mitigated with good coordination and communication between MISO and its members in the southern region.”
But Patton has said he disagrees with the RTO’s decision to call an alert and deploy load-modifying resources in MISO South on May 16. (See “MISO South May Emergency,” Stakeholders: MISO System Fix Too Late for Summer.)
“Our conclusion is not quite the same as MISO’s,” Patton said at this month’s Market Subcommittee meeting.
During the emergency, MISO ended up retracting a call for LMRs with 12-hour lead times.
MISO’s decision-making behind conservative operations and emergency declarations has been “inconsistent,” Patton said. “We want to work with MISO to clarify what the triggers are so costs are reasonable event-to-event.”
Chatterjee said MISO has been declaring emergencies to access LMRs with some regularity since 2017.
MISO President Clair Moeller also pointed out the RTO used LMRs once in 2017, twice in 2018 and three times already in 2019. He said MISO will naturally find ways to improve the process as emergencies “dramatically increase.”
“We’re gaining experience by having experiences,” he said with a smile.
Moeller also pointed out that LMR operators that signed up to modify load might have to delay action to “become safe.” For instance, plant operators with a “crucible full of steel” can’t immediately work to shave load, he said.
“There’s turbulence behind the operating environment,” Moeller added.
The 5-Year Supply Picture
Despite the emergencies, MISO now doesn’t expect a capacity shortfall until 2023 or 2024 and predicts a generation surplus of about 3 to 6 GW in 2020, according to the most recent annual resource adequacy survey produced jointly by the RTO and the Organization of MISO States. (See Supply Future Brighter, OMS-MISO Survey Shows.) In four to five years, MISO could see anything from a 7-GW surplus to a 1.3- to 2.3-GW deficit.
“It’s not uncommon to see this kind of imbalance in the further-out years,” Chatterjee said, pointing out the difficulty of identifying long-term capacity deficiencies.
“Is this causing any raised eyebrows? Is this similar to what we’ve seen in prior years?” Director Barbara Krumsiek asked.
Chatterjee responded that MISO must rely more heavily on intermittent resources and LMRs in the future. But she also noted recent implementation of three new short-term resource availability and need rulesets that impose stricter outage scheduling, tighten LMR availability requirements and enforce annual real power testing for demand response. (See FERC OKs MISO Outage Scheduling Rules, DR Testing.) The RTO will gauge the impact of the new rules over the next year and expects the associated “incentives” to improve supply, she said.
“I have a bit of a problem with the word ‘incentive.’ It’s more of a carrot than a stick, isn’t it?” Krumsiek asked. Chatterjee agreed.
Summertime Adequacy?
MISO foresees a 70% probability that it will declare an emergency to call on LMRs this summer despite having an estimated 149 GW of resources on hand to cover a 125-GW projected peak.
But Patton sees the summertime supply picture differently, predicting just 137 GW of available resources to manage a 124.7-GW peak — and just 129 GW in a realistic scenario with the usual emergency no-shows and unforeseen outages. He criticized as unrealistic MISO’s forecasting assumptions of unequivocal availability of emergency resources and no unforced outages.
“It’s frequent that we don’t see emergencies coming more than two hours in advance,” Patton said, noting that time constraints effectively disqualify many emergency resources. “If you don’t see the emergency coming, it’s almost useless to you.”
However, he said MISO’s ample import capability and willing neighbors make up for already tight margins.
Krumsiek inquired about MISO’s estimate that it was only able to access about 75% of LMRs that committed to being available last summer.
Chatterjee said MISO is expecting a similar response this summer as well, adding that “75 to 80% is actually a pretty good number.” She said the RTO may not always be able to call on LMRs in excess of their required start-up commitments.
Patton offered the prediction that capacity margins will likely fall as “fossil resources retire and suppliers continue to export capacity to PJM.” The Monitor said he remains concerned that capacity is increasingly being supplied by LMRs, which require an emergency declaration in order to be accessed. He said it is “increasingly important” that MISO begin making changes to its capacity market so the auction sends more efficient economic signals “to maintain an adequate resource base.”
Low Auction Prices, Again
Any changes in emergency declaration protocols must be considered in tandem with measures that make the capacity market more economic, Patton argued.
The bulk of MISO planning resources cleared at $2.99/MW-day in this year’s capacity auction; last year, most of the footprint cleared at $10/MW-day. (See Most MISO Zones Clear at $3/MW-day in 2019/20 PRA.)
Unsurprisingly, Patton again derided those prices as “close to zero.” He said the price is “well below” the $200/MW-day he estimates would motivate new generation investment or the $100/MW-day needed to keep older existing units in operation.
“I have to say that,” he said wryly. “It’s probably the biggest issue in MISO.”
MISO zonal resource adequacy projections | MISO
Patton also said MISO cleared a large generator in Michigan that will be unavailable for the entire 2019/20 planning year. If MISO disqualified the generator from the auction, prices in the Michigan’s Zone 7 might have hit $243.37/MW-day — right around the cost of new entry benchmark — instead of the $24.30/MW-day clearing price.
“We’re counting on a unit that’s on an approved planned outage for the entirety of the planning year,” Patton said.
“That to me says something is broken in MISO resource adequacy,” Independent Power Producers representative Mark Volpe said a day later at an Advisory Committee meeting.
Meanwhile, MISO reported an average 69.7 GW of load from March through May, with the 97.7-GW spring peak occurring March 5. Energy prices averaged $25.78/MWh, a 7% decline from last spring.
FERC last week rejected contested settlements filed by SPP regarding the annual transmission revenue requirements (ATRRs) for two cooperatives.
The commission said that as the settlements were contested, they couldn’t be approved under its guidelines and precedent set by a 1999 case involving Trailblazer Pipeline Co. It remanded both proceedings to the chief administrative law judge to resume hearings.
The first settlement, involving SPP, Corn Belt Power Cooperative, MidAmerican Energy, Basin Electric Power Cooperative, Alliant Energy Corporate Services and the Missouri Public Service Commission, revolves around the RTO’s 2015 Tariff revisions to accommodate Corn Belt’s ATRR as an incoming transmission-owning member (ER15-2028).
The commission accepted the proposed revisions, effective Oct. 1, 2015, and established hearing and settlement procedures. SPP submitted the settlement agreement in July 2017.
The agreement was initially opposed by FERC staff, Missouri River Energy Services (MRES) and the Western Area Power Administration on the grounds that the rate treatment for three Corn Belt grandfathered agreements (GFAs) was unjust and unreasonable and inconsistent with commission precedent. The GFAs provide in-kind transmission service to each of the settlement’s parties. (See “FERC Accepts ITC Midwest’s Interconnection Agreement,” FERC Approves Change to Eliminate Gaming in SPP Markets.)
The supporting parties argued that the GFA’s rate treatment, which credits all GFA revenues against Corn Belt’s revenue requirement, is consistent with the SPP Tariff. They said any attempt by non-settling parties to seek relief inconsistent with the Tariff provisions would amount to “collateral attacks on the SPP Tariff.”
Corn Belt’s headquarters in Humboldt, Iowa | Corn Belt Power Cooperative
FERC noted its regulations provide that it may decide a contested settlement’s merits only if “the record contains substantial evidence upon which to base a reasoned decision or the commission determines that there is no genuine issue of material fact.”
The commission said it couldn’t approve the settlement under any of the first three approaches for reviewing contested settlements under its Trailblazer ruling, nor could it sever the contesting parties or contested issues under the fourth.
Under the first Trailblazer approach, “if there is an adequate record, the commission can address the contentions of the contesting parties on the merits,” which requires a merits determination on each contested issue. FERC found the supporting parties’ argument that Corn Belt has adhered to the Tariff because it is crediting the revenues from the GFAs against its revenue requirement to be unsupported.
Under the second Trailblazer approach, FERC may “approve a contested settlement as a package on the grounds that the overall result of the settlement is just and reasonable.” The commission said such a finding in this case “does not appear possible because certain crucial information needed to evaluate Corn Belt’s proposed revenue requirement is absent.”
It said there were two obstacles to the third Trailblazer approach: The record is insufficient to determine whether the settlement’s benefits outweigh the objections to it; and the contesting parties are located in Corn Belt’s zone and share a direct interest in the provisions relating to the utility’s revenue requirement.
FERC also used Trailblazer precedent in rejecting a contested settlement involving Northwest Iowa Power Cooperative (NIPCO), SPP, Basin Electric, MidAmerican and the Missouri PSC (ER15-2115).
NIPCO towers over Western Iowa’s landscape | NIPCO
As in the Corn Belt case, SPP filed Tariff revisions in 2015 to allow for NIPCO’s ATRR when it joined the RTO as a transmission-owning member. The commission accepted the proposed revisions, effective Oct. 1, 2015, and set hearing and settlement procedures. SPP submitted the settlement agreement in July 2017.
MRES and WAPA opposed that settlement as well, objecting to its rate treatment of two NIPCO GFAs. The intervenors said other transmission owners will essentially subsidize transmission loads and shift the cost from NIPCO and its customers to the TOs.
The commission said it couldn’t approve the contested settlement under any of the first three Trailblazer approaches. It also said it couldn’t sever the contesting parties or contested issues under the fourth Trailblazer approach.
FERC last week rejected a set of rehearing requests by PJM merchant transmission owners, New Jersey regulators and the New York Power Authority contesting the cost allocations for several cross-seams projects.
The commission’s ruling Thursday reaffirmed a July 2018 order that directed PJM and its TOs to submit compliance filings revising Tariff provisions regarding cost responsibility assignments for four targeted market efficiency projects (TMEPs) with MISO included in PJM’s Regional Transmission Expansion Plan (ER18–614).
FERC had approved 41 PJM transmission projects but rejected the allocations for TMEPs b2971, b2973, b2974 and b2975, instituting a Section 206 proceeding to resolve the matter and ensure the Tariff contained clear language regarding allocations for the future. (See FERC OKs PJM RTEP Allocations, Sets TMEP 206 Proceeding.) The PJM TOs had argued that the RTO erred in not allocating project costs to Hudson Transmission Partners and Linden VFT, which operate merchant lines into New York City and had recently converted their firm transmission withdrawal rights to non-firm. Those lines would benefit from the TMEPs, the other TOs contended.
On July 31, 2018, PJM submitted a compliance filing updating the cost responsibility assignments to reflect Hudson and Linden, while the PJM TOs the next day submitted a separate filing clarifying that TMEP allocations would be assigned to merchant facilities.
Hudson, Linden and NYPA contested FERC’s rejection of the original cost allocations excluding merchant owners from the TMEP assignments. They argued that the commission misinterpreted PJM Tariff language that “limits all cost allocations … based on their actual firm transmission withdrawal rights.”
FERC rejected that argument, noting that the basis for cost allocation under the TMEP provision “is the net congestion incurred in PJM zones” regardless of merchant transmission facility contracts for firm or non-firm withdrawals rights.
“Customers of merchant transmission facilities without firm transmission withdrawal rights still receive benefits from TMEPs in the form of lower congestion costs,” the commission said. “PJM transmission owners make clear that the intent of the TMEP provision was to assign costs to merchant transmission facilities based on the net congestion relieved by the project.”
BPU Rebuffed
The commission also rejected the New Jersey Board of Public Utilities’ contention that FERC erred in accepting TMEPs b2955 and b2956 because the projects were no longer necessary after Hudson and Linden relinquished their firm withdrawal rights. The BPU argued that PJM should have therefore withdrawn the projects from the RTEP.
But FERC pointed out that PJM re-evaluated the projects after the merchant owners relinquished their firm withdrawal rights, citing an affidavit from Aaron Berner, the RTO’s manager of transmission planning, that explained why that move did not change the results of the RTO’s reliability studies that determined the rejected projects to still be “necessary.”
“Mr. Berner explained … that the analysis showed that injections of electricity by the merchant transmission facilities, not withdrawal from these facilities, contributed to the need for the projects. Because firm transmission withdrawal rights relate only to withdrawals from PJM, the relinquishments of the firm transmission withdrawal rights have no bearing on the need for projects b2955 and b2956,” FERC said.
The commission further accepted the cost allocation revisions submitted in PJM’s July 31, 2018, compliance filing that reflected Hudson and Linden’s pro rata share of the sum of the net transmission congestion charges paid by market buyers, as identified in the TMEP study. It also approved the PJM TOs’ Aug. 1, 2018, compliance filing clarifying the language regarding TMEP cost allocations.
FERC last week denied a request to reconsider its decision to revoke the license for a small Michigan hydroelectric project over significant safety concerns.
The commission also rejected Boyce Hydro’s motion to transfer the license for its 4.8-MW Edenville Dam to another operator, Wolverine Hydro, calling the request moot in light of the revocation (P–10808).
FERC ordered Edenville closed in February 2018, then revoked the dam’s license the following month after finding it had insufficient spillway capacity and that Boyce had a longstanding history of noncompliance with other safety measures. The commission denied Boyce’s request for rehearing on the closure early this year. (See Closed Michigan Dam Loses Rehearing Bid.)
Edenville Dam spillway
In the order issued Thursday, FERC said it only entertains motions for reconsideration when a party can assert the commission “may have erred by overlooking or misunderstanding facts or arguments set forth in the party’s rehearing request.” Boyce didn’t pose that argument in its request for rehearing over the license, and its other arguments were “unconvincing,” the commission wrote.
“Here, Boyce Hydro does not claim that the commission misunderstood or misinterpreted its prior arguments. Thus, its pleading is not a proper request for reconsideration and we will not consider it as such. … To the extent that Boyce Hydro seeks to introduce new facts and arguments into the record, it is making an untimely, collateral attack on the now final revocation order.”
FERC made clear that revocation of the license was not up for negotiation and that Boyce’s only recourse now is to seek a new license.
“In any event, we have no ability to grant the relief that Boyce Hydro seeks. We have revoked the license for the Edenville Project, in orders that are now final. Accordingly, we currently have no jurisdiction over the Edenville project works. Should Boyce Hydro or any other entity wish to operate the project to generate electricity, they would need to seek a license to do so,” FERC said.
And because it could not reinstate the Edenville license, FERC said it also could not grant the request to transfer the license to Wolverine.
Boyce had claimed that it could secure a new power purchase agreement with Consumers Energy at a higher rate that would have allowed it to obtain a loan to “fund construction of auxiliary spillway capacity sufficient to pass the entire [probable maximum flood]” requirement, then pass the license to Wolverine.
But FERC said Boyce brought no “firm proof” that such a situation will play out.
