FERC last week again declined to modify MISO’s interconnection queue rules, rejecting rehearing requests from wind developers who say the RTO is moving too slowly for them to meet the federal production tax credit deadline.
The Oct. 31 order is the second time FERC has denied EDF Renewable Energy’s request that MISO be required to devise a fast-track option in its interconnection queue for projects that can demonstrate readiness for development (EL18-55-001). (See FERC Sides with MISO in Queue Design Dispute.)
FERC once again declined to modify MISO’s interconnection queue rules | E.ON Climate and Renewables
E.ON Climate and Renewables, Invenergy, Tenaska Wind Holdings and Project Resources Corp. had joined EDF in seeking rehearing. The companies argued that FERC rendered a decision without addressing the situation’s harm to consumers or analyzing the need for a one-time departure from queue rules considering the 2020 PTC deadline.
But FERC said EDF still has not met its burden of proof to show that that MISO’s queue design is unreasonable, unjust or discriminatory. The commission also said “some of EDF’s claims about queue delays were overstated,” as the RTO said that most interconnection customers would complete the queue in time to begin commercial operation before Dec. 31, 2020, the deadline for receiving the full PTC. In any case, FERC said queue delays that might preclude some interconnection customers from the full advantage of a tax credit “does not amount to MISO’s failure to make reasonable efforts under its Tariff.”
“Delays in the interconnection process can be due to actions outside of MISO’s control, such as customer withdrawals and actions of affected systems,” FERC pointed out.
But, as with the last order, the commission ended with a warning for the RTO to improve its queue practices: “We strongly urge MISO, along with its stakeholders, to make addressing MISO’s interconnection queue processing delays a priority. We urge MISO to look to the other RTOs for best practices, closely examine the resources it is dedicating to the interconnection study process and consider whether additional resources would alleviate queue delays, as well as fully consider other approaches for improvement.”
MISO’s queue contains about 490 projects totaling more than 80 GW, down from 90 GW earlier in the fall.
The RTO has been working to speed up the queue through more stringent site control requirements and increased milestone payments. Staff say the changes will encourage stalled projects to withdraw from the queue earlier in the process. (See “MISO to File Queue Changes,” MISO Queues up Interconnection Options.)
The RTO has also eliminated the dynamic stability, short-circuit and affected-system analyses from the first phase of the queue’s definitive planning phase. The studies are repeated in the queue’s later phases. (See MISO Plan to Reduce Queue Studies Gets FERC Nod.)
WASHINGTON — The Energy Bar Association’s Mid-Year Energy Forum last week rekindled long-running debates over FERC Order 1000, state-federal jurisdiction, utility rate structures and the Public Utility Regulatory Policies Act. And this year, there was a relatively new issue of contention: grid resilience.
Kim Smaczniak, an attorney for Earthjustice, debated attorney William Scherman over whether the retirement of coal and nuclear generation is undermining the grid’s resilience.
“Is there a resilience crisis in the bulk power system? The answer is no,” Smaczniak said. “There is no data that has demonstrated a crisis on the bulk power system today.”
She contended the grid’s biggest resilience threat is climate change, citing National Oceanic and Atmospheric Administration data that seven of the 10 costliest storms in U.S. history occurred in the last 10 years. “That’s not going away,” she said. “That’s climate change.”
Scherman, a former FERC general counsel who now represents natural gas pipelines and utilities such as FirstEnergy at Gibson, Dunn & Crutcher, said policymakers must practice the “electric utility version of the Hippocratic Oath” in ensuring reliable service above all else.
“We are losing fuel-secure, diverse generation in the country every day, and nothing is being done about it because the mantra is ‘That is the will of the market. We should allow the markets to operate.’ … I sure hope these damn markets are right, because when we finally get to the point of figuring out that they’re not, it will be too late to do anything about it.”
Scherman praised FERC’s ruling declaring PJM’s capacity market not just and reasonable because of price suppression from subsidized renewables and nuclear power. (See FERC Orders PJM Capacity Market Revamp.)
But he said the commission should also have required changes to the RTO’s ancillary services and energy markets because they are interrelated — and that other regions should do similar examinations.
“We have to have a full, comprehensive and holistic review of whether these markets are continuing to work,” he said.
Candice Castaneda, a legal and regulatory counsel for NERC, also sparred with Scherman over his contention that reliability is different from resilience.
“Resilience is an inherent characteristic of reliability. … Resilience is a time-based component of reliability,” she said.
“I know of no NERC standard that assesses and defines resiliency standards,” Scherman responded.
Another Plea for PURPA Reform
Idaho Public Utilities Commissioner Kristine Raper and Adam Benshoff, executive director of regulatory affairs for the Edison Electric Institute, called on FERC to address above-market costs and gaming by qualifying facilities under PURPA. FERC in May said it would review how it enforces the 1978 law. (See FERC Sets PURPA Review; Powelson Targets 1-Mile Rule.)
He said FERC should reduce the 20-MW limit on QFs in organized markets and change the burden of proof, which is currently on challengers to QF self-certifications. “We’re not advocating for a specific number. … Something less than 20, something higher than zero probably makes sense right now given open access, given the sophistication of the folks that are participating in this process.”
Raper said that although half of Idaho Power’s generation mix is hydro, it must curtail that energy during the shoulder months when its peak is 1,300 MW or less. “They have more PURPA [resources] on the system than that. And this is must-purchase energy. … You’re not utilizing hydro, which is a virtually free resource, and you’re paying anywhere between $30 and $200[/MWh] for PURPA generators. It totally blows away the resource stack and the whole theory of running the least-cost resource. … It’s not fair to ratepayers.”
She said FERC’s 1-mile rule is a “red herring” because QF developers are also disaggregating projects to drop below the PURPA limit by registering them as multiple limited liability companies.
She said FERC should allow states more discretion in blocking such gambits by allowing them to treat as a single project those sharing owners, interconnection agreements, facilities, contractors and financing.
In a separate panel, Amanda Rome, Xcel Energy’s managing attorney for federal and state regulatory policy, touted Colorado regulators’ policy, which frees utilities from must-purchase requirements for PURPA projects larger than 100 kW unless the project wins a competitive solicitation. The policy is the subject of a federal court challenge.
The most recent PURPA applications, filed last month, sought prices as high as $34/MWh for wind and $63/MWh for solar, she said. In contrast, Public Service Company of Colorado’s most recent all-source solicitation produced 350 renewable bids with median prices of $19.30/MWh for wind and $30.96/MWh for solar.
The solicitation will give the utility a total of more than 5,000 MW of renewables, “and 70% of those are projects that could qualify as QF,” she said.
FERC General Counsel James Danly had some advice for his colleagues: Don’t count on the Supreme Court’s Hughes v. Talen ruling for jurisdictional challenges to state energy policies.
The 2016 ruling rejected Maryland regulators’ attempt to subsidize a combined cycle plant, saying it interfered with FERC’s jurisdiction. But the court also said its ruling should not be interpreted as preventing states from supporting generation resources through measures “untethered to a generator’s wholesale market participation.”
“A lot of people enjoy hanging their hat on Hughes. Hughes shouldn’t be read for much more than it really states,” Danly said, echoing an interpretation former General Counsel Max Minzner shared with EBA attendees in 2016. (See Court’s Reticence Frustrates Energy Bar.)
Former FERC Commissioner Colette Honorable, now a partner with Reed Smith, noted states’ increasing activism on energy policy. “It’s not just New York and California anymore,” she said.
In Washington state, for example, voters will be asked Nov. 6 whether they support imposing a $15/metric ton charge on carbon emissions by large emitters such as refineries, power generators, and oil and gas producers.
Honorable said she is not optimistic that federal policymakers will adopt carbon pricing. “I’m really a positive person, but I will say I don’t see it on the horizon any time soon,” she said. “We desperately need it.”
She agreed with MISO General Counsel Andre Porter on the need for collaboration among states, RTOs and federal officials. With the threat of year-round forest fires in the West and cyberattacks on utilities, “it’s a new day. It requires our collective thinking,” she said.
Porter said issues as important as reliability, resource adequacy and market efficiency should not be decided in the courts through adversarial processes. “I think there’s a more collaborative, and likely better, way to go about addressing these issues,” he said, citing MISO’s “abundantly transparent” stakeholder process and its work with FERC and the Organization of MISO States.
He cited as an example jurisdiction over sales for resale on the distribution grid. “I’ve often heard people say, ‘Who wins in this debate over federal and state jurisdiction?’ I actually hope no one wins. … It’s not a competition. … The focus through all this has to be continued collaboration to ensure we’ve got a reliable, efficient and adequate grid.”
RENSSELAER, N.Y. — NYISO’s Board of Directors continues to perform due diligence on the AC Public Policy Transmission Project and could issue a decision at its Dec. 6 meeting or early next year, interim CEO Robert Fernandez told the Management Committee on Wednesday.
The MC in June approved a staff report that recommended joint proposals by North America Transmission and the New York Power Authority to build two 345-kV transmission projects that could cost $900 million to $1.1 billion. (See NYISO MC Supports AC Transmission Projects.)
Any board amendments to the report would require stakeholder review, Fernandez said. Former CEO Brad Jones informed the MC last month that the board had asked for additional data on the project.
Fernandez also announced that Deputy General Counsel Karen G. Gach is now the ISO’s acting general counsel.
Rich Dewey, NYISO executive vice president, asked MC participants for feedback on the ISO’s five-year strategic plan, “which is illustrative of NYISO’s plans to respond to industry changes including evolving policies and disruption brought on by new technologies.”
“Front and center to the discussion was how do we prioritize these changes,” Dewey said.
The plan identifies six strategic initiatives to address the evolving nature of New York’s power grid as large-scale renewables and distributed energy resources connect and place new demands on electricity markets and grid operations, Dewey said.
The initiatives are: grid reliability and resilience; efficient markets; new resource integration; integration of public policy; technology and infrastructure investment; and an efficient and flexible business model.
“This plan is a confirmation by the board that energy markets are more effective in setting the price signals needed to incent new investment,” Dewey said.
Takeaways from a June 12 joint board/MC meeting were to continue exploring fuel security issues and how DER and storage can help provide resilience, as well as to consider what alternative market changes might protect system reliability and revenue adequacy in the event that the cost of carbon is not incorporated into the wholesale energy markets.
Con Ed’s Quin New MC Vice Chair
The MC elected Jane Quin, director of the energy markets policy group for Consolidated Edison, as vice chair.
“I view the stakeholder process as a keystone of NYISO’s success and am looking forward to playing a more significant role in contributing to that success,” Quin said.
Before serving in her current role, Quin was executive assistant to the CEO of Con Ed from 2013 to 2015.
2019 Budget
The MC approved a 2019 budget totaling $168.2 million, including an 8.03% increase in revenue requirement from this year’s budget and a 0.45% decrease in projected megawatt-hours, for an overall Rate Schedule 1 increase of 8.51%.
Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the budget, which the board will consider Nov. 13.
Repayment of a $30 million loan to finance an energy management system/business management system upgrade project is driving up spending, Ackerman said. The ISO plans to add 15 new positions over the coming year.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said the group had decided “with regret” to oppose the 2019 budget because it “could not get comfortable” with a budget increase of more than 8.5%.
Improving Public Policy Tx Planning
The MC approved Tariff revisions to improve the efficiency of the ISO’s short-term Comprehensive System Planning Process, with the board expected to vote on the issue at its Nov. 13 meeting.
The revisions would eliminate the requirement that the Public Service Commission issue an order before the ISO begins evaluating transmission solutions, a regulatory “pause” that is often too long, according to the grid operator.
Yachi Lin, senior transmission planning manager, presented the same report she did at the Business Issues Committee meeting earlier in October. (See “Improving Public Policy Tx Planning,” NYISO Business Issues Committee Briefs: Oct. 10, 2018.)
Multiple Intervenors and the city of New York opposed the changes.
Under the proposal, the PSC continues to retain the ability to cancel or modify an identified public policy transmission need prior to the ISO’s selection of the more efficient or cost-effective solution, which would halt the evaluation or result in an out-of-cycle process to address the modified need.
Having successfully met system demand this summer despite tight reserve margins, ERCOT said Thursday it will have “sufficient” generation to meet smaller load during the upcoming winter and spring.
According to the grid operator’s final seasonal assessment of resource adequacy (SARA) for winter (December-February), operators will have almost 80 GW of capacity available to meet a projected peak of 61.8 GW. The forecast is based on normal weather conditions during peak periods from 2002 to 2016.
ERCOT has added 325 MW of capacity since its last SARA, including 72 MW of winter capacity from two wind farms and 219 MW of gas-fired generation expected to be in service for the winter.
Pete Warnken, ERCOT’s manager of resource adequacy, cautioned reporters during a conference call against taking a rosy outlook based on reserve generation. In 2011, the grid operator was forced to resort to rolling blackouts when freezing temperatures knocked generation offline in the face of increasing demand.
“Winter can be very volatile, as far as temperatures and demand, and we account for that in our extreme [planning] scenarios,” Warnken said.
ERCOT’s preliminary spring SARA (March-May) forecasts a seasonal peak of 61.6 GW, with an additional 1.1 GW of capacity from a mixture of gas, wind and solar projects expected to be available. The final spring SARA will be released in early March.
System demand peaked at a spring record of 67.3 GW on May 29. The grid operator was also able to meet a record system demand of 73.3 GW this summer.
| ERCOT
“We look to the market to add generation resources in response to increasing load,” Warnken said.
The SARA report is based on an assessment of generation availability and expected peak demand conditions. It takes into account expected generation outages that typically occur during each season for routine maintenance, as well as a range of generation outage scenarios and weather conditions that could affect seasonal demand.
WASHINGTON — PJM on Thursday began its campaign to compensate generators based on their “fuel security,” releasing an eight-page summary of a study that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements.
The study, which evaluated more than 300 winter scenarios, was a “stress test … intended to discover the tipping point when the PJM system begins to be impacted,” the RTO said.
“It is clear that key elements, such as availability of non-firm gas service, oil deliverability, pipeline design, reserve level, method of dispatch and availability of demand response become increasingly important as the system comes under more stress,” it said.
PJM said it will publish a paper detailing the study in December and plans to introduce a problem statement and issue charge in the first quarter of 2019, with the filing of any proposed market rule changes with FERC in early 2020.
At a press conference at the National Press Building, CEO Andy Ott said the study was intended to address the concerns of governors and other policymakers about how soon the continued retirement of coal and nuclear units and the increasing reliance on natural gas could result in reliability risks.
Ott said the RTO could consider compensating fuel security through either the capacity market or as a winter reserve product in the energy market. “We feel strongly that … solutions to any dependency or any risk that we see is best done through defining it as an attribute in the markets. We think government intervention is unnecessary … it would be inefficient and more costly. We think a market solution would be best.”
RTO officials on Thursday also gave a briefing on the study during a three-and-a-half-hour special meeting of the Markets and Reliability Committee in Valley Forge, Pa., where several stakeholders urged consideration of the potential costs of the proposal. The study received forceful pushback from former PJM Chief Economist Paul Sotkiewicz, who called the RTO’s plan to offer a problem statement “premature” because the study failed to model existing market rules and operational capabilities that could address the risks, including reserve shortage pricing, industrial load reductions in response to higher prices or increased new resource entry.
“Without any showing that the market rules themselves have failed us — which there is none at this point — why would we go through a problem statement?” he said. “In fact, I can argue that [with] the market design, if allowed to work, we don’t have to worry about any of these issues.”
PJM CFO Suzanne Daugherty, who led the MRC meeting, responded that the RTO was not saying its “market rules are broken.” Ott, however, said the RTO must consider rule changes now that it has evidence that an unpriced attribute such as fuel security can affect reliability. Officials noted that 16,000 MW of the RTO’s 70,000 MW of gas-fired capacity lacks firm gas contracts. PJM’s Capacity Performance rules have encouraged such generators to maintain up to three days of fuel but don’t provide enough revenue to guarantee the two-week span envisioned in the study, Ott said.
“Hope is not a good strategic plan,” he said. “These are attributes that we depend on in [operations] and we’re not paying for them. I don’t think that’s sustainable.”
Ott also said the study would provide insights for the resilience docket FERC opened in January (AD18-7). (See Don’t Rush on Resilience, Commenters Urge.) “We really have no specific standard for this term ‘resilience’ in the industry,” Ott said. “There’s nothing in the [NERC] reliability standards that says I have to look at these scenarios today.”
FERC may say “you’re way overemphasizing these risks. … On the other hand, people could say these risks are more severe than you’re accounting for. That’s the conversation we’re going to have. We’re going to have more scenarios that we run. We’re going to have more dialogue. Our point is, engaging this conversation — getting ahead of the game — is in my opinion the prudent way to go.”
RTO officials said the study, which simulated a two-week cold spell in winter 2023/24, found that PJM would remain reliable during typical winter loads (a 50/50 peak of 134,976 MW) under both the 12,652 MW of retirements announced as of Oct. 1, 2018, and under “escalated” retirements cases.
Both escalated retirement scenarios envisioned an installed reserve margin (IRM) of 15.8%: one assumed an additional 32,216 MW of retirements by 2023, with 16,788 MW of capacity added to meet the IRM; the second assumed that no replacement capacity is added but there were an additional 15,618 MW of retirements, which reduced the IRM to 15.8%.
The RTO also remained reliable in the announced retirements case under all extreme winter load scenarios, a one-in-20 year (95/5) peak load of 147,721 MW. (PJM’s all-time winter peak load of 143,338 MW was set in 2015.)
But combining the extreme load, escalated retirements and pipeline outages resulted in numerous scenarios with voltage reductions, reserve shortages and load sheds of as much as 83 hours — about 3.5 days. The location of the outages would depend on that of the pipeline outages, PJM said.
PJM said a combination of extreme load, escalated retirements and pipeline outages resulted in numerous scenarios with voltage reductions, reserve shortages and load sheds. | PJM
What are the Odds?
RTO officials said they had not looked at the probabilities of the most severe events coinciding over a 14-day span. They are “extreme but plausible scenarios,” Ott said. “‘Extreme’ means relatively rare.”
The RTO modeled disruptions to both single, or radial, gas pipelines (up to 5,051 MW of capacity lost) and parallel or “looped” lines (up to 13,715 MW lost).
The extreme weather, medium-impact disruption assumed the loss of 50 to 100% of the pipeline capacity for five days. The extreme, high-impact break would knock out the line for five days with a 20% derating for the remaining nine days.
Oil refueling was modeled at 10 to 40 truck deliveries per day for sites larger than 100 MW and zero to 10 trucks daily for sites less than 100 MW.
Reaction
The study is certain to be debated by partisans on all sides of the “fuel wars” debate that has raged since the Trump administration proposed price supports for at-risk coal and nuclear plants.
“PJM is doing the kind of analysis that other grid operators should do too,” said Michelle Bloodworth, CEO of coal lobby American Coalition for Clean Coal Energy. “PJM’s analysis shows that accelerated coal retirements could lead to periods when demand for electricity exceeds supply. This should worry electricity consumers in other parts of the country, not just in PJM.”
Renewable advocates said the study was overly narrow.
The American Council on Renewable Energy (ACORE) faulted PJM for its focus “on resource attributes rather than actual performance when it comes to providing needed reliability services.”
“A more comprehensive study would have recognized how renewable energy technologies provide a range of resiliency and reliability attributes to the grid, including flexibility, dispatchability and other essential reliability services,” said Todd Foley, ACORE’s senior vice president for policy and government affairs.
PJM “should not presuppose a fuel supply solution when other options such as transmission enhancement exist,” said Amy Farrell, senior vice president for government and public affairs for the American Wind Energy Association.
Rob Gramlich, a consultant to clean energy groups, said he was pleased to hear Ott indicate a preference for providing compensation through the energy markets. “Really what these power markets need is flexibility, and capacity markets are so crudely defined that they don’t distinguish between flexible and inflexible resources,” he said.
But he said he opposed defining the product as “fuel security.”
“What they’re saying to me is they want winter-peak energy during extreme cold scenarios. That’s a technology-neutral product. ‘Fuel-secure resource’ is not a technology-neutral product. And the difference is, things like wind, which is usually screaming hard during these situations, is providing winter-peak energy.”
Attorney Susan Bruce, who represents the PJM Industrial Customer Coalition, echoed Sotkiewicz’s concern that the study did not account for how industrial customers might reduce demand under the high LMPs that would result under the most stressed scenarios. She said PJM also should consider stakeholders’ “broader conversations about energy price formation.”
Sotkiewicz, who now heads E-cubed Policy Associates, complained that PJM had “stacked” the analysis by using economics to predict generation retirements while ignoring the economics of how the market would replace them.
He cited the wave of coal retirements PJM experienced several years ago after EPA’s Mercury and Air Toxics Standards rule went into effect.
“That turned into an absolute non-event for PJM because of all the new entry that came in through various quarters, whether it was demand response or energy efficiency or new combined cycle gas,” he said. “I’m afraid you’re going to have people with certain agendas taking these results for their own purposes and saying the sky is falling.”
PJM’s Daugherty acknowledged that risk. “We’re trying to make sure as hard as we can [that] the facts of what we did are out there,” she said. “We do recognize … that different pieces of the information could be taken out of context by folks if they choose to do so.”
Next Steps
PJM will continue discussion of the study at a special MRC conference call Nov. 26, and a special MRC in-person meeting Dec. 20.
The RTO also will develop a “frequently asked questions” document. Questions should be sent to natalie.tacka@pjm.com.
Edison International’s president said in an earnings call Tuesday that equipment owned by its Southern California Edison subsidiary was at least one cause of a December 2017 wildfire that burned nearly 282,000 acres and resulted in multiple deaths.
Southern California Edison said its equipment was partly to blame for the Thomas fire near Santa Barbara, Calif., in December 2017. | U.S. Forest Service
The Thomas Fire in Santa Barbara and Ventura counties was the state’s largest wildfire in modern history until a combined series of Northern California blazes, the Mendocino Complex, greatly exceeded it this year. The Thomas Fire was directly blamed for the death of a firefighter and a civilian. Mud and debris flows in its aftermath killed 21 others when heavy rain drenched scarred mountain slopes.
“Based on the progress of our ongoing work in these areas with the information currently available to us, we believe that the Thomas Fire … had at least two separate ignition points,” Pedro J. Pizarro, Edison’s president and CEO, said during the earnings call. “With respect to one of these ignition points, Koenigstein Road, SCE believes that its equipment was associated with this ignition.”
The company hasn’t determined if a second ignition point in the Anlauf Canyon area also involved its equipment, Pizarro said. The California Department of Forestry and Fire Protection is also investigating the fire.
Fanned by Santa Ana winds, the Thomas Fire tore through a huge swath of Ventura and Santa Barbara counties, killing two. | NASA Earth Observatory
As with other California utilities’ wildfire liabilities, Edison’s could prove costly. California employs a unique system of holding electric providers strictly liable for property damage if their equipment sparks wildfires, even if they followed all rules and regulations. Pacific Gas and Electric is facing billions of dollars in liability for Northern California fires last year, which has undermined its stock price.
Edison may face similar problems. The company reported third-quarter earnings of $513 million ($1.57/share) on Tuesday, compared with $470 million ($1.43/share) in the third quarter of 2017 — the increase largely attributed to deferral of operations and maintenance costs and tax benefits at SCE. But it also discussed its potential financial exposure from the Thomas Fire and highlighted its wildfire prevention efforts with investors.
“Mitigation and prevention are the best defenses against future wildfires,” Pizarro said.
The company’s California plans call for spending $407 million on grid hardening, enhanced operations and “situational awareness” of wildfire risks, he said.
Much of the money will be used to replace 600 circuit miles of bare wire with insulated wire over the next two years in areas at high risk from wildfires, the CEO said. SCE has identified another 3,400 circuit miles of bare overhead conductors in fire-prone regions, he said.
The company’s plans are in line with the goals of SB 901, a bill the California legislature passed this year that requires utilities to file wildfire mitigation plans with the state, he noted. (See California Wildfire Bill Goes to Governor.)
Pizarro said Edison is also seeking to comply with another landmark bill, SB 100, which requires the state to rely entirely on renewable and other zero-carbon energy sources by 2045. The measure sets goals along the way, including achieving 60% renewable energy reliance by 2030. (See California Gov. Signs Clean Energy Act Before Climate Summit.)
“We found the most feasible pathway to reach the state’s 2030 goals to be an electric grid supplied by 80% carbon-free energy made reliable by up to 10 GW of energy storage,” Pizarro said on the call.
“This will support at least 7 million electric vehicles on California roads and nearly one-third of space and water heaters powered by electricity,” he added.
CAISO said Monday its Western Energy Imbalance Market has produced more than a half-billion dollars in benefits for participants since its founding five years ago, including more than $100 million in benefits in the third quarter of 2018.
Those third-quarter benefits, driven by high demand and fuel costs in July and August, were the most for any quarter since CAISO started the EIM in November 2014, the ISO said. In Q3, the EIM produced $100.58 million in savings, with its total benefits reaching $502.31 million, it said.
“This clearly illustrates the value of markets to the customers in California and the region,” Steve Berberich, CAISO’s president and CEO, said in a statement.
This table shows the Western EIM’s Q3 2018 gross benefits by participant. | CAISO
CAISO and Arizona Public Service (APS) claimed the largest share of third-quarter benefits ($21.02 million and $20.78 million, respectively), followed by PacifiCorp ($17.82 million), Idaho Power ($13.31 million), NV Energy ($11.09 million), Portland General Electric ($9.47 million), Puget Sound Energy ($4.44 million) and Powerex ($2.65 million).
CAISO was by far the biggest net importer of energy during the quarter at nearly 1.336 million MWh, with NV Energy a distant second at 285,971 MWh. By comparison, CAISO’s net imports were just 355,549 MWh during the second quarter, while net exports surged above 1.9 million MWh in the face of solar surpluses.
APS facilitated the largest volume of wheel-through transfers last quarter (364,046 MWh), followed by PacifiCorp’s West balancing area (350,170 MWh) and NV Energy (312,593 MWh). EIM members derive no financial benefit from wheel-throughs, and CAISO said it will continue to examine whether “there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits.”
The EIM real-time wholesale market allows CAISO and non-ISO participants to trade energy across the West, often reducing costs and curtailment of renewable resources including solar, wind and hydroelectric power.
Many industry leaders have praised its benefits, including those who oppose the idea of a Western RTO led by CAISO. (See Overheard at Transmission Summit West.) Unlike an RTO, the EIM’s transmission-owning entities retain operational control over their assets, while member generators participate in the real-time market on a voluntary basis.
A CAISO proposal to extend the EIM to include a day-ahead market has been the subject of discussion at industry conferences throughout the West this year. (See CAISO Day-ahead Could be Tailored for West.)
Meanwhile the EIM has been expanding, increasing its reported benefits.
Notably, Idaho Power and Powerex began transacting in the market in April, bringing to eight the number of members participating in the EIM. (See .) That expansion equipped the EIM to serve imbalances for about 55% of load in the Western Interconnection, according to the ISO.
The Western EIM is expanding with new and planned participants. | CAISO
Market participants serve more than 42 million customers in an area that stretches from Canada to the Mexican border, including large swaths of Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming.
NV Energy, APS, PacifiCorp, Puget Sound Energy and Portland General Electric are already participants.
Five more entities are slated to join the EIM in the next two years. The Balancing Authority of Northern California and the Sacramento Municipal Utility District plan to begin participating in April 2019. The Los Angeles Department of Water and Power, Arizona’s Salt River Project and Seattle City Light are scheduled to begin participating in April 2020.
Public Service Company of New Mexico, the state’s largest utility, is seeking permission from its regulators to join the EIM by 2021, officials announced in August. (See .)
The Bonneville Power Administration has been discussing joining the EIM, most recently in a stakeholder call on Oct. 11. BPA would likely bring its “big-ten” resources to the EIM, officials said on that call, including the Grand Coulee, Chief Joseph and The Dalles hydroelectric projects on the Columbia River. The Columbia basin covers an area roughly the size of France, they noted.
Officials on the call said the BPA could sign an agreement with the EIM as early as the end of 2019.
CARMEL, Ind. — While MISO expects to have ample resources on hand to manage what should be a warmer-than-normal winter, it is still preparing for the possibility of entering emergency procedures.
The RTO is forecasting a 103-GW peak this winter, 6 GW short of the all-time winter record of 109 GW, set Jan. 6, 2014, during the polar vortex. With 140 GW in total available capacity to meet demand, the RTO foresees having a 36% systemwide reserve margin this winter, more than double the current annual level.
Rob Benbow | RTO Insider
But Executive Director of Energy Rob Benbow told an Oct. 29 winter readiness workshop that MISO is preparing for the possibility of extreme winter conditions and estimates a 40% probability of having to call on load-modifying resources (LMRs) at least one time during the season.
“While we project ample resources under normal operating conditions, MISO is also prepared to proactively manage potential challenges created by periods of extreme weather, generation and transmission outages and other developments,” Benbow said.
MISO’s most probable operating scenario shows about 25.1 GW of outages with 18.8 GW in reserves. But in a high load and extreme outage scenario, outages could reach 38.6 GW, resulting in an almost 2-GW shortfall in reserves.
Resource Adequacy Coordination Engineer Eric Rodriguez said it’s “critical” that LMR owners update their wintertime availability in MISO’s nonpublic communication system to ensure readiness in the face of above-normal load or outages.
Eric Rodriguez | RTO Insider
“We’re showing a challenging winter if a high-load, high-outage scenario is realized,” Rodriguez said.
MISO’s biannual coordinated seasonal assessment, which simulates stressors on the transmission system, showed no unanticipated thermal, voltage or phase angle issues this winter.
“Our transmission system also looks like it’s in good shape for this winter,” Benbow said.
However, MISO said it could experience delayed injections in the natural gas pipeline system and the region is experiencing the lowest gas storage levels in a decade due to a long cold snap in spring and high summertime demand.
But the RTO also predicts current high gas production will offset the low storage levels this winter, likely keeping prices flat. It also noted two new large pipelines from the Marcellus and Utica basins were placed into service last month and are increasing takeaway capacity.
“We have two new pipelines to offset the storage and we’re looking pretty good heading into winter,” said Trevor Hines, MISO operations communications lead.
More Precautions
This marks the first winter MISO will use its new capacity advisory notification, an intermediary step before declaring a maximum generation alert and used only when all-in capacity is forecast to be less than 5% above operating needs. (See MISO: Sept. Emergency Response Improved by Jan. Event.)
Benbow said MISO has been working through drills and training on emergency purchases with suppliers outside the footprint. MISO has also clarified its emergency operating procedures to ensure public appeals for energy conservation occur before MISO makes emergency energy purchases from external suppliers, a revision some members had advocated.
In response to the Jan. 17 MISO South emergency, MISO and SPP have been collaborating on both emergency protocols and the use of SPP’s contract path linking MISO’s Midwest and South regions, “making sure we understand when they’re having challenging times … and also making sure they understand our [emergency] process,” Benbow said.
“Ever since we’ve got out of the Jan. 17 event, we’ve met with the joint parties and our neighboring reliability coordinators to the South … to work on the management of the regional dispatch transfer,” he said.
5th Waiver
For the fifth straight winter, MISO is seeking a Tariff waiver to allow resources to recover energy costs in excess of the current $1,000/MWh offer cap.
In early October, FERC granted MISO an October 2020 deadline to implement a new $2,000/MWh hard cap for verified cost-based incremental energy offers. MISO said it needed the extra time to work the new offer caps into its fast-start pricing and extended locational marginal price. (See MISO Granted Longer Deadline for Offer Caps.)
MISO market adviser Chuck Hansen said if FERC approves the waiver, generator offers greater than $1,000/MWh will again be subject to the RTO’s verification process.
“They won’t be able to directly submit those offers, but they will be able to recover those costs after the fact through uplift costs,” Hansen said.
WASHINGTON — It was little more than a year ago that FERC Chairman Neil Chatterjee gathered reporters at commission headquarters to assuage worries that Energy Secretary Rick Perry’s recent proposal to compensate coal and nuclear plants would destroy the markets. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)
Much has happened since: Kevin McIntyre took over as chair; the commission unanimously rejected Perry’s proposal; and, last week, McIntyre relinquished the chair back to Chatterjee while staying on as a commissioner.
On Wednesday, Chatterjee once again met with reporters at FERC headquarters, where he struck a more muted, sober tone in explaining the commission’s work under his leadership while McIntyre struggles with what he called a “serious setback” in his battle with a brain tumor. (See McIntyre Steps Down; Chatterjee Named FERC Chair.)
“Kevin McIntyre is not just my colleague; he is my friend,” Chatterjee said. “I think it is important that he is focusing his energies on his health and his family. This situation is certainly not something I sought, and I most definitely do not relish it. But we have important work to do, and Kevin wants me to be a strong leader for him and for the agency that he cares so deeply about. And I am committed to working with my colleagues to live up to that expectation.”
Chatterjee said he would not discuss McIntyre’s health, saying he wanted to give him and his family privacy. But he spoke extensively about McIntyre’s leadership at the commission, and the influence McIntyre has had on him.
“I thought Chairman McIntyre was exemplary in his leadership,” he said. “I had time to meet with stakeholders, with staff in the building, with my colleagues and folks around the country to learn the importance of the commission’s processes, and culture, and mores, and traditions. And I think the individual who is … most responsible for my growth in this position is Kevin McIntyre. …
“He so emphasized the importance of the rule of the law … of adhering to [the record]; he could not be more strenuous in saying that politics could not be allowed to interfere with the work of the commission. And that has really helped me grow in my role as I made the transition from formerly partisan legislative aide to independent regulator. … I hope to lead in the same way. But I have big, big shoes to fill.”
Resilience and Avoiding Politicization
Chatterjee joined the commission as chair in August 2017, holding it until McIntyre joined later in December.
“The circumstances in which I stepped into the chairman role last time were not ideal,” he said Wednesday. But “quite frankly, they were a dream compared to this circumstance.”
Before being replaced by McIntyre, Chatterjee appeared supportive of Perry’s Notice of Proposed Rulemaking for FERC to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel. The commission unanimously rejected the NOPR in January, opening its own docket to explore grid resilience (AD18-7). (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
On Wednesday, Chatterjee was asked whether he felt FERC was doing enough on the resilience issue. A former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) and Kentucky native, he again brought up his partisan background.
“Again, this is where my growing into this role has been significant. I first came to the commission last fall, coming from a partisan legislative role in which I worked on behalf of my boss to fight against the retirement of coal-fired generation. Initially I was sympathetic to Secretary Perry’s proposal because of my concern for these rural communities, because of my concern about what the retirement of nuclear units might mean for mitigating carbon emissions.
“But as I evolved into the role, I realized that that is not part of our record. That doesn’t factor into the statutes that govern us. And I had to make a decision on the DOE NOPR based on the record that was before us. I have been thus far satisfied with the record that is being formed since we opened that new docket in January. And I’m going to review that docket and see what could the facts bear out. …
“So, it’s premature for me to say we’re doing enough or we’re not doing enough until I’ve really had the opportunity to work with my colleagues and analyze that record. … This will not be a politically influenced decision.”
Chief of Staff
Chatterjee said he had not given any thought to personnel changes. “In light of the difficult circumstances in which this transition is occurring, I think it is important for all stakeholders of the commission, as well as us inside the commission, that we have some continuity moving forward.”
Chatterjee praised Chief of Staff Anthony Pugliese. “There [are] tremendous administrative responsibilities in the chairman’s office, and as someone who has been a commissioner for the past year, from what I’ve seen, Anthony has managed the administrative capabilities of the agency very well.”
Speaking at the Energy Bar Association’s Mid-Year Energy Forum on Tuesday, however, Commissioner Richard Glick said Pugliese’s appearance in July on the conservative “Breitbart Radio Show” was “ill-advised.” (See Democrats Call Out ‘Partisan’ Remarks by FERC Chief.)
“To go on various radio shows and make attacks against the governor of New York and then to … take certain positions that were more in line with … the administration than the commissioners I think is not a wise strategy,” Glick said. “I’ve had this conversation with the chief of staff; I’m sure others have as well. And I’m hoping that we won’t see that anymore. I thinks it’s very important that we demonstrate that we truly are independent and that we’re acting on what we think is in the best interest [of the public and] … make sure that we’re not either doing the [bidding] of the Trump administration, or … [House Minority] Leader [Nancy] Pelosi [D-Calif].”
“I agree completely with Commissioner Glick that we should be separate and apart from any political influence on either side,” Chatterjee said Wednesday. “No one was more committed to ensuring the depoliticization of the agency and not allowing political interference than Kevin McIntyre. And I think that if you look at the record under Chairman McIntyre’s leadership, there’s no evidence that there’s been political influence or interference at the agency. … And I’ve made very clear to all of the staff at the agency, including the chief of staff, that the agency’s independence from political influence will continue.”
The chair downplayed recent 3-2 rulings by the commission on natural gas pipeline certificates, in which Glick and Commissioner Cheryl LaFleur have insisted the commission’s analyses include consideration of downstream greenhouse gas emissions.
“While much has been made of the fact that we’ve been having 3-2 votes and it appears to be political, I think there’s some genuine disagreements on policy, but my colleagues have been narrow and discreet in their dissents. And I view that as an opportunity to build consensus.”
He said he wasn’t concerned about 2-2 ties since the departure of Commissioner Robert Powelson in August. He also noted that in his resignation letter to President Trump, McIntyre said he felt he could fulfill his duties as commissioner. “I expect he will do that,” Chatterjee said. “In terms of votes that he will cast, that is entirely his determination and decision. … I am not empowered to deny him his vote.”
Going Forward
Chatterjee said his priorities as chairman will be the same as they were when he was a commissioner. He listed the reliability and resilience of the grid, processing LNG facility applications, breaking down barriers to entry for new technology, and cybersecurity, the last of which “continues to be foremost on my mind.”
He declined to give a timeline on the commission’s resilience proceeding, nor on its work on updating its policy statement on pipeline certificates.
Asked what he thought could accomplish before the end of the year, he half-jokingly said, “I think my first and most significant priority that I know I have the support of my colleagues on — but I’m not sure whether I’ll be able to achieve it — is to fix eLibrary.”
Earlier this month, Trump nominated Bernard McNamee, DOE executive director of the Office of Policy, to the commission. Chatterjee said the commission’s work would proceed without regard for McNamee’s confirmation process. That includes a disregard for the date of McNamee’s hearing before the Senate Energy and Natural Resources Committee: He seemed unaware that it had been scheduled for Nov. 15, the same as the commission’s next open meeting.
“There’s so much on the commission’s plate right now that we need to take action on.”
Based on his career as McConnell’s aide and his own nomination, he said he knew that the road to confirmation “is an unpredictable one.”
RENSSELAER, N.Y. — NYISO on Monday floated a plan to calculate the carbon pricing impact on locational-based marginal prices (LBMPc) using the social cost of carbon (SCC) as determined by the New York Public Service Commission, while also altering its recommendation for allocating carbon charge residuals.
Both proposals came up as part of New York’s ongoing effort to explore how to incorporate carbon pricing into the state’s wholesale electricity market through the multi-agency Integrating Public Policy Task Force (IPPTF).
A post-carbon pricing project with a hedge must pay the LBMP with carbon despite the carbon having been removed. | Calpine
Ethan D. Avallone, ISO senior market design specialist, told the IPPTF that the market would generally use the net SCC to determine the carbon reference level for a CO2-emitting generator that functions as the marginal resource.
While the grid operator needs to calculate the LBMPc in order to allocate carbon credits to load-serving entities, most internal generators would not be charged the LBMPc, instead being charged for their actual emissions.
The NYISO straw proposal envisions including carbon pricing in the market using the existing offer structure, Avallone said. During intervals when there are too few marginal resources to calculate LBMPc, the ISO proposes “to persist” the last carbon impact to the LBMP from the prior interval.
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said, “In practice, we back into the marginal units by looking at whether resources have their offer equal to the LBMP at their location. Given that, when the demand curves are active, we can’t use that method to back into what resources are marginal.”
Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, said that while that approach seems most convenient, it “would have pretty significant implications and you would get very different results from what was presented in the consumer impact studies on this.”
One reason is that hydro units are on the margin nearly 50% of the time in New York, which eventually reflects an energy storage problem, LeeVanSchaick said. “If you back down hydro in one hour, you’re going to get more hydro in another hour, which is likely to reduce output from a carbon-emitting generator.”
“The idea generally is that if you do have to use the next unit on the margin, that’s a change,” Avallone said. “So we’ll take that back and think about it.”
“I’m glad you’re taking it back,” said Warren Myers, director of market and regulatory economics for the state’s Department of Public Service. “This has always been a really big issue conceptually for us — what you do about the storage hydro that’s limited over the course of a year. We know that in a given hour it does not have zero carbon consequences. If it ramps up or down, it affects the carbon in other hours.
“It’s not a trivial implementation, in-the-weeds issue. It’s a big deal.
“With respect to the harmonizing with state policy,” Myers continued, “whenever DPS has tried to figure out what the [carbon] content on the margin is, we do not treat these hours as if they’re zero carbon. We try to somehow, heuristically or however … treat these resources as if they’re combined cycle gas units.”
LeeVanSchaick said the MMU takes a similar view of the opportunity costs for hydro units. He recommended the ISO “consider alternatives to just using the real-time market software’s flags” to determine which fuel is on the margin. He also recommended the ISO address what principles and objectives it seeks to achieve with the method to help evaluate its success in doing so.
Allocating Residuals
As part of the state’s evolving plan to price greenhouse gas emissions, a carbon charge would also be applied to most wholesale market suppliers holding renewable energy credit contracts with the New York State Energy Research and Development Authority. (See NY Carbon Task Force Looks at REC, EAS Impacts.)
For the carbon charge residual that results from charging suppliers for their carbon emissions, NYISO now recommends a proportional allocation approach, saying it would provide an equitable impact to consumers consistent with the current REC contract cost allocation to load, Avallone said.
NYISO originally proposed a levelizing approach but revised its recommendation based on recent analysis, Avallone said. It considered that there was a higher percentage impact to upstate load relative to downstate load under levelizing methodology compared with the proportional percentage allocation.
At the Sept. 24 IPPTF meeting, the Brattle Group provided a comparison of the carbon residual allocation options as part of the carbon pricing consumer impact analysis. That analysis showed that the proportional allocation methodology minimizes cost shifts among consumers, Avallone said. Allocation would not affect revenues to generators, who would receive the LBMP, inclusive of the carbon impact.
Considering dynamic effects, the proportional allocation methodology provides the most levelized allocation of carbon residuals. | NYISO
Hedge Effects
Brett Kruse, Calpine’s vice president for governmental and regulatory affairs, told the task force how NYISO’s proposed “clawback” of the carbon price from the LBMP provided to resources with REC contracts might affect lender-required financial hedges required for renewable generation financing.
“As proposed by NYISO, removing carbon prices from LBMP of some contracted generation is very disadvantageous to those of us with hedges in place,” Kruse said.
Under NYISO’s current proposal, the power produced by a unit with REC contracts would be settled at the LBMP net of the carbon charge (that is, after the clawback), but energy hedges would be settled at the actual LBMP, reducing the unit’s revenues.
Calpine proposes applying a discount that modifies the carbon price to account for the estimated carbon emission savings from existing RECs. The company argued that a discount to the SCC that decreases as REC contracts roll off could integrate the beneficial impacts of RECs and carbon pricing without disrupting commercial hedging practices needed by most renewable energy projects.
“The way these hedges work, and this is quite typical even if you’re not talking wind generation, is they sell at the hub,” Kruse said. “Because of the liquidity value at the hub, they don’t settle at the individual generator node. The banks … don’t want to write a hedge that settles at your node.”
The most popular type of hedge is a fixed-for-floating price swap, where a project company receives a pre-agreed fixed dollar-per-megawatt-hour price from a bank, and the project pays the bank the underlying LBMP, which ensures a certain amount of energy revenue for the project, he said.
While the New York Power Authority buys both RECs and power, NYSERDA just purchases the RECs, “so in today’s world, it’s not the late 90s where you had a lot of financing. … The markets started to unbundle … and the banks are very skittish about who they give their money to,” Kruse said.
There are only one or two companies with a large regulated business at their core who do renewables on the side that have big enough balance sheets to finance their own projects. “The rest of us cannot, so we have to get financing for the whole thing, and as a result, the financing requires us to get the hedge on the power side,” Kruse said.
Daymark Analysis Update
Marc Montalvo of Daymark Energy Advisors said his “massive slide deck” of an analysis on the carbon pricing scheme, updated from last month, has as its major theme “humility in the face of complexity.”
“This proposal adds more than a small wrinkle to the marketplace,” Montalvo said. “How we get it implemented matters an awful lot.”
Brattle took a no-arbitrage model with fairly low friction and fairly low transaction costs and estimated net benefits to consumers, he said.
“What I wanted to understand is what happens if you perturb those things?” Montalvo said. “What happens if there is friction, what happens if there are actually higher transaction costs? What happens if the implementation and the consequent behaviors that underlie the no-arbitrage premise don’t hold up?”
Daymark’s perturbed model, particularly regarding border charges, increases market volatility, with asymmetric results, “which means things tend to be worse, not better,” Montalvo said. Similarly, charges on internal resources “and the way the carbon charges are estimated and calculated really does matter.”
The analysis also found that the carbon charges proposed are not sufficient to motivate the volume of buildout being sought under the state’s Clean Energy Standard without further public policy action.
“You don’t get 15,000 MW of renewables over the 12-year study period with the carbon charge by itself … [and] a lot of the non-market barriers are not addressed at all by a carbon charge,” Montalvo said.
The task force next meets via teleconference on Nov. 9 to talk about three recent analyses and updates by Brattle, Daymark and Resources for the Future (RFF), and how they interrelate.
