New Mexico’s largest utility has requested state regulators’ permission to join the Western Energy Imbalance Market, officials announced Wednesday.
Public Service Company of New Mexico (PNM) has applied to join the EIM by 2021, Mark Rothleder, the EIM’s vice president of market quality and renewable integration, told the market’s Governing Body during its meeting in Denver.
PNM, which serves about 510,000 electricity customers in the state, still needs approval from the New Mexico Public Regulation Commission, Rothleder said.
The Governing Body greeted the announcement as good news. If PNM’s request to join the EIM is approved, it could give California and other states access to New Mexico’s wind and solar resources, and New Mexico could draw on California’s solar output during peak usage hours.
Wind far in New Mexico | Public Service of New Mexico
Part of the EIM’s mission is to trade renewable energy between states that generate and use it at different times.
California’s solar energy output reaches its peak midday, during a time of low in-state consumption, while solar farms in New Mexico and Arizona come online earlier, some in time to meet California’s high morning demand for electricity. Wind farms in New Mexico and Wyoming ramp up later in the day, when Californians get home and turn on their lights and TVs.
PNM owns or jointly owns 3,200 miles of electric transmission. It owns, leases or has power purchase agreements for about 2,580 MW of generation, dominated by gas (33%), coal (30%) and nuclear (16%). Its wind capacity totals 300 MW (12%) with solar at 117 MW (5%).
“Having cost-effective electricity available to immediately back up [intermittent] renewable energy in real time supports reliability and also ensures our renewables are used to their fullest potential,” Thomas Fallgren, PNM’s vice president of generation, told the Associated Press on Wednesday.
CAISO started the EIM in 2014, and its members have realized more than $400 million in benefits, including more than $71 million during the second quarter of 2018. (See EIM Benefits Surge to $71.2M in Q2.)
PNM would be the first New Mexico utility to join the EIM.
Major utilities in Arizona, California, Nevada, Oregon, Utah, Washington and Wyoming are already members. Idaho Power and Powerex joined this year.
With Gov. Jerry Brown’s support, CAISO also is pushing to become an RTO for the Western states. A bill to advance the change, AB 813, is pending in the legislature, but its fate is uncertain. It must be delivered to Brown before lawmakers end their current session Aug. 31. (See CAISO Regionalization Bill Cast on Uncertain Course.)
SACRAMENTO, Calif. — A measure to replace generating capacity and limit economic disruption caused by the retirement of the state’s last nuclear power plant is headed to the desk of Gov. Jerry Brown.
Pacific Gas and Electric’s Diablo Canyon Power Plant, which sits on a scenic stretch of coastline south of Big Sur, generates nearly a tenth of California’s in-state power and 20% of the utility’s needs.
Diablo Canyon | PGE
Senate Bill 1090, which passed the State Assembly by 67-1 on Aug. 20, would require Diablo Canyon’s output to be replaced with “a portfolio of greenhouse-gas-free resources,” the first measure of its kind in California.
The bill seeks to avoid a spike in emissions, which occurred after the San Onofre Nuclear Generating Station in Southern California closed in 2013 and fossil-fuel burning plants were brought online to compensate.
The measure directs the Public Utilities Commission to approve full funding for measures to lessen the impact on the local economy and to retain skilled workers until the plant is retired in 2025, when its last Nuclear Regulatory Commission operating license expires. The PUC approved PG&E’s application to retire the plant in January but balked at providing $85 million in community-impact funds and millions more for job retention and retraining, asking the legislature for guidance.
The bill, which cleared the State Senate 31-4 in May, was co-authored by Senate Majority Leader Bill Monning, a Democrat, and Assemblyman Jordan Cunningham, a Republican, both of whom represent districts surrounding Diablo Canyon.
“I am hopeful that Gov. Brown will also be supportive of the safe, reliable and carefully planned retirement of the Diablo Canyon Nuclear Power Plant and sign SB 1090,” Monning said in a statement. “The bill is imperative to the local economy, the state’s energy grid and the region.”
An agreement reached in 2016 among PG&E and environmental and labor groups initially laid out plans for the plant’s closure.
The Natural Resources Defense Council, which helped negotiate the agreement, lauded the bill’s passage.
“The package of policies included in SB 1090 offers a model for the phaseout of aging power plants with clean, increasingly less expensive energy while providing a just transition for workers and communities affected by the shutdown,” NRDC’s western energy director, Peter Miller, wrote in blog post Monday.
A spokeswoman for Monning said she had “no idea … one way or another” whether Brown will sign the bill.
Brown, who has until Sept. 30 to sign or veto the measure, declined to comment on his position. “We typically do not weigh in on pending legislation,” Deputy Press Secretary Brian Ferguson told RTO Insider.
MISO’s replacement of its market settlements platform is complete, with the RTO now settling at five-minute intervals.
The RTO reported “smooth and uneventful launches” for both the new platform and settlement time. Officials said the $10.3 million platform replacement is yielding more value than originally expected, though MISO is collecting more financial data through the end of the year before it announces the savings.
MISO rolled out five-minute settlements for weekly billing last month, later than most RTOs/ISOs, owing to extra time needed to replace its settlements platform and test the new program with stakeholders. (See MISO Wins Delay on 5-Minute Settlement Roll-Out.) Last year, the RTO billed $27 billion worth of market-based charges on an hourly basis to more than 450 market participants for the day-ahead market, real-time market, financial transmission rights and its resource adequacy construct.
Executive Director of Market Operations Shawn McFarlane told the Technology Committee of the Board of Directors on Aug. 21 that many settlements corrections are now automated, freeing up settlement analysts’ time. The time to make a settlement recalculation after correcting data has dropped to about 10 minutes from four hours.
“We’ve got some great results,” Kevin Caringer, executive director of MISO’s IT team, told board members.
The new settlements platform also allowed MISO to implement five-minute intervals in about three months, versus the originally estimated nine months, McFarlane said. He added that the RTO is also expected to spend less time coding to make changes on the new settlements system. He said coding changes will likely be necessary as MISO continues its multiyear project to entirely replace its market platform. (See MISO Platform Replacement Risks Delay, Budget Overrun.)
McFarlane said MISO sent market participants sample statements several times during testing of the new interval time, receiving input to correct issues before the program went live.
“This is an important step forward for MISO … that improves the efficiency of our market operations and ensures pricing transparency for the energy being delivered in real time,” McFarlane said.
The committee praised management for better-than-expected results.
“It’s very impressive to see a project of this magnitude come to light,” Director Theresa Wise said.
“Delaying the implementation so that we were in lockstep with stakeholders was a very good decision,” Director Baljit Dail said.
MISO also plans to replace its transmission settlements system in 2019. The system financially settles transmission customers’ use of the transmission system in monthly bills.
RENSSELAER, N.Y. — A NYISO proposal to disqualify some holders of renewable energy credit (REC) contracts from getting paid carbon charges risks undermining the state’s energy market, stakeholders heard on Monday.
In July, the ISO proposed that renewable generators holding REC contracts signed on or before Jan. 1, 2020, be ineligible to collect the carbon pricing portion of wholesale market energy prices. (See NY Sets Carbon Pricing Timeline, Reviews Progress.)
| Institute for Local Self-Reliance
“This would be the first time the NYISO has taken an action that goes against existing contracts,” said Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), which promotes renewables and energy efficiency. “It will increase uncertainty and decrease the willingness of future investors to invest in New York. It’s not very helpful in that regard.”
Reeder delivered a presentation on the topic Aug. 20 to the Integrating Public Policy Task Force (IPPTF), the group exploring how to incorporate the cost of CO2 emissions into the ISO’s markets to support the state’s nuclear plants.
NYISO’s proposal aims to limit customer impacts of the carbon charge by helping reduce or eliminate what it terms “double payments” to renewable resources. According to Reeder, that tells investors that it’s financially risky to develop energy resources that lower carbon emissions in New York. All carbon-free generators should receive the full market energy price, including carbon price effects, he said.
Reeder said the ISO should defer to the state’s Public Service Commission because double payments are a matter of public policy, not market design. REC contracts for 2019 solicitations and beyond should align with the indexed price approach that the PSC approved for offshore wind REC contracts (ORECs), he said. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)
The task force should separately estimate the consumer impacts of receiving the carbon price for existing REC contract holders, nuclear plants under the zero-emission credits regime, combined cycle gas turbines and state-owned hydro generation, Reeder said.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said that, “given the amount of potential double payment at stake here, no one should take it as a given that carbon pricing moves forward absent this issue being resolved.”
Making consumers pay renewable developers higher energy prices to reflect carbon pricing, while also requiring them to pay the same developers for RECs for carbon-free generation attributes, is a clear double payment that must be addressed by NYISO or the PSC, he said.
Renewable developers have benefited from other rule changes, including the Clean Energy Standard and the PSC’s decision to offer three-year contracts to maintain the operation of existing renewable generation facilities (Case 17-E-0603), Mager said. “So these things happen all the time, and I would venture to say that the vast majority of rule changes in the last five to 10 years have been extremely favorable to renewable developers.”
Evaluating a Carbon Charge
Daymark Energy Advisors’ Marc Montalvo, representing the New York Department of State’s Utility Intervention Unit, delivered the preliminary results of a study evaluating NYISO’s proposed carbon charge in outcomes between two cases, a “status quo” case assuming state policies are met but the carbon charge is not implemented, and a case with the carbon charge. The study period included each year between 2020 and 2025, in addition to 2030 and 2035.
Adding a carbon charge would result in higher emissions in New York through 2035, according to a study for the N.Y. Utility Intervention Unit. | Daymark Energy Advisors
The proposed carbon charge could result in slightly lower CO2 emissions in the Eastern Interconnection but higher emissions in New York, the study found. Low capacity prices and the large number of renewables being added to the system now may push prices too low to support new renewable entry within the study period, he said.
“Because so much new generation is being added, we thought it prudent to look at the proposal,” Montalvo said. “We used slightly different assumptions from the ISO’s; for example in the dynamic modeling of proposed border adjustments, which don’t capture likely changes in behavior.”
Several stakeholders questioned the usefulness of such a shuffling exercise, as the ISO’s straw proposal intends to be carbon-agnostic to resources outside New York: Imports would earn the locational-based marginal price but not the carbon adder; similarly, external loads would buy New York energy at the LBMP without paying the carbon charge.
A study for the N.Y. Utility Intervention Unit projects a proposed carbon adder would push incremental average LBMPs in Eastern Zones (F‐K) about $16/MWh higher than Western Zones (A‐E) through 2035. | Daymark Energy Advisors
Montalvo said all the modeled regions add and take away resources based on policy and economic reasons, and “we’ve seen resources stick around for years for reasons impossible to know from the outside.”
He claimed that his group’s “very detailed model of the Eastern Interconnection” provides valuable insight into the effects of pricing carbon into New York’s wholesale electricity markets.
Stakeholders also had access to two comments submitted on the ISO’s carbon pricing straw proposal — one from “private retired citizen” Roger Caiazza, and another from Consolidated Edison. (See Stakeholders Annoyed by NYISO Carbon Price Draft.)
The task force next meets Aug. 27 at NYISO headquarters.
FERC ruled Monday that PJM’s Independent Market Monitor can take part in negotiations over individual generators and doesn’t have to stick only to RTO-wide market issues, parting from a federal appeals court ruling on the Monitor’s role (ER18-1226).
The commission’s order came in response to an administrative law judge denying the Monitor’s request to participate in settlement discussions regarding PA Solar Park’s reactive service rate schedule.
The judge denied the IMM’s motion to intervene, citing a D.C. Circuit Court of Appeals ruling in June blocking the Monitor from participating in an unsuccessful attempt by Duke Energy and Old Dominion Electric Cooperative to recoup millions of dollars in “stranded” gas costs incurred during the 2014 polar vortex. (See Duke, ODEC Rebuffed on Polar Vortex Gas Refunds.)
In denying the motion and a subsequent appeal, the ALJ cited the D.C. Circuit’s characterization of the Monitor’s role as an “auditor” and said PJM’s Tariff provisions “support the notion that the [Monitor] should be limited to commission proceedings and technical conferences that address PJM and its markets at a macro level, but not discrete and individualized proceedings that are limited to specific parties and singular rate filings.”
The commission disagreed, remanding denial of the Monitor’s appeal back to the judge. FERC pointed out it initiated a process in 2014 to ensure resources in PJM’s footprint don’t receive payments for reactive power capability after the units have been deactivated. (See Impatient FERC Orders Immediate PJM Action on Reactive Power Payments to Retired Plants.)
Individual rate proceedings “are part of a broader, continuing effort by the commission to ensure that the rates for reactive power service within the PJM footprint are just and reasonable,” FERC said, adding the Monitor’s involvement would contribute to the “public interest.”
The ruling does not automatically admit the Monitor into the PA Solar Park case, however. Because the Monitor’s June 19 request to intervene was made after the filing deadline, FERC said the judge must rule on whether to admit the IMM anyway.
The Monitor said its filing was late because “no individual notice” of the matter was provided. It agreed to accept the record as it has developed to date and said its involvement would not prejudice existing parties in the proceeding.
After an unusual surge in the first quarter, CAISO prices fell in the second quarter based on lower prices for natural gas and increased output from wind, hydroelectric and solar sources, the ISO’s Department of Market Monitoring told stakeholders Tuesday.
“Q1 prices were relatively high, while Q2 prices were relatively low,” said Amelia Blanke, CAISO’s manager of monitoring and reporting, during a call to discuss the department’s quarterly market report.
She noted prices are generally lower in the first two quarters and rise later in the year. This year was different, however. Q1 prices spiked because of the increased costs of natural gas, due to tight supply and high demand, and limited hydroelectric output, due to scarce precipitation.
Snowpack in the Sierra Nevada was only 54% of normal in early April, Blanke said.
Hydroelectric and renewable sources picked up in the second quarter, adding supply and helping to lower prices. Still, she said, hydroelectric is expected to remain below average this year.
| CAISO Department of Market Monitoring
“We are predicting relatively low hydro for this year, but not as low as we had at the peak of the drought in 2015,” Blanke said.
Also during Q2, north-to-south congestion in the day-ahead market continued to play a significant role, as it had in the first quarter, CAISO reported. It increased day-ahead prices in the San Diego Gas & Electric area by $3.54/MWh, Blanke noted.
Planned outages in Southern California were largely to blame for the congestion, she said.
“Outages in Southern California also caused congestion in the 15-minute market,” the CAISO report said. Congestion increased prices in the San Diego Gas & Electric area by about $4.95/MWh and in the Southern California Edison area by about $1.32/MWh, it said.
Another major development in Q2 was Idaho Power and Powerex joining the Western Energy Imbalance Market on April 4, Blanke said. The report noted prices in the Northwest region including the two companies are generally lower than those in the ISO and other EIM balancing areas because of their “abundant supply and limited transfer capability out of the region.”
In a move that should please environmental and ratepayer advocates, FERC has denied requests to shut down debate on whether PJM’s Capacity Performance construct should make room for seasonal resources that can’t adhere to CP’s requirement to always be available (EL17-36).
The commission on Friday dismissed two requests for rehearing of its February order calling for a technical conference on whether the PJM should move from a year-round to a seasonal capacity construct. The commission ordered the conference in response to two complaints, one from the Advanced Energy Management Alliance, and a combined filing from Old Dominion Electric Cooperative, Direct Energy and American Municipal Power. (See FERC Rethinking PJM Capacity Performance Rules.)
PJM and the PJM Power Providers Group (P3) argued that FERC should have dismissed the complaints for not providing new evidence or changed circumstances that would require a decision other than approving CP. P3 challenged FERC’s position that the complaints “raised important issues as to whether certain aspects of the [CP] construct are performing as well as expected.”
FERC rejected those arguments, saying it hadn’t made a final decision on the issue and that the February order was just to open the investigation. It rejected PJM’s argument that the complaints were collateral attacks on CP and said the complainants had proven that CP might be unjust and unreasonable.
“The fact that the commission accepted a rate design in a proceeding under Section 205 of the [Federal Power Act] does not preclude the commission from later re-examining that rate design in a subsequent FPA Section 206 proceeding,” the commission said.
FERC said AEMA identified seven “distinct developments since the conditional acceptances” of CP:
multiple planning studies indicating that CP alone may not suit the region’s resource adequacy needs, and no study showing a winter resource adequacy shortfall;
a new reliability analysis from PJM showing that nearly all the resource adequacy value of marginal capacity lies in the summer months;
auction results that suggest CP will actually degrade resource adequacy by reducing needed peak-season capacity;
new PJM load forecasting information showing that peak-shaving programs have little impact on future capacity purchases, contradicting prior assumptions;
PJM stakeholder resolution of a previously deferred CP cost allocation component;
auction offers showing that significant amounts of capacity have been unwilling or unable to take on CP obligations at any price and that the aggregation mechanism proposed for demand response, energy efficiency and intermittent renewables does not appear to be working; and
indications that the combination of seasonal and annual capacity worked well during the phase-in of CP, as evidenced by PJM’s statements that its available capacity mix has been sufficient to meet demand.
FERC also found value in PJM sensitivity analyses presented in the complaints, settling arguments by PJM that they don’t provide new evidence or changing conditions because they’re solely backward-looking and completely hypothetical.
PJM’s load has its peak demand in the summer. | PJM
“We continue to find that these analyses constitute new evidence sufficient to warrant further investigation,” the commission wrote. “Given that PJM is a summer peaking system, these studies support the contention that the move to a single, annual capacity product may have pushed valuable summer-only resources out of the capacity market and thereby increased capacity costs with little or no reliability benefit. They indicate that allowing PJM to procure some capacity as summer-only capacity would allow PJM to procure significantly less capacity during non-summer periods and provide equivalent reliability at lower total capacity costs.”
FERC also rejected arguments that it’s too soon to determine whether anything’s wrong with CP.
“The concerns raised — including whether customers are paying more than necessary to ensure reliability — are the type of concerns that may be exacerbated, rather than ameliorated, by the passage of additional time,” the commission wrote.
VALLEY FORGE, Pa. — PJM would have to implement programs adhering to specific rules and strict oversight in order to include summer demand reductions in its load forecasts, stakeholders learned last week.
Staff unveiled a proposal for implementing the demand reductions initiative, which has been driven by ratepayer representatives, at an Aug. 15 meeting of the Summer Only Demand Response Senior Task Force. Participation would be restricted to demand response programs approved by a state or regional regulator, and, to avoid double-counting, customers included in the programs would be barred from also participating as DR or price-responsive demand in PJM’s markets during the same delivery year. Instead of receiving a direct payment, their value would be included as avoided capacity costs for the entire zone through a shift in the variable resource requirement curve used in the Base Residual Auction and Incremental Auctions for the delivery year.
Programs would need to indicate several factors by Aug. 31 prior to the delivery year’s BRA, including:
A threshold on PJM’s temperature-humidity index to trigger interruption;
A duration in hours;
The number of megawatts that can be curtailed per hour;
The months an interruption can occur; and
All historical add-backs for the programs.
PJM’s Tom Falin said the add-backs are necessary to “start with a clean load history.”
“Our concern is that some of this peak shaving may already be reflected in the load history,” he said.
Measurement and verification of the curtailment will also be important to confirm that what gets included in the load forecast is what actually occurs to ensure “as accurate a load forecast as possible.”
Staff’s initial forecast reduction will be based on a modified load history that assumes perfect curtailment performance since 1998. After three years of actual monitoring, the forecast will transition to using a three-year rolling average. But performance during the first two summers will be “key,” Falin said, because “we’re going to take the performance result for that summer and assume that would have happened for the previous 18 years.”
EnerNOC’s Brian Kauffman presented an alternative proposal that would allow summer DR to participate in both load forecast adjustment (LFA) and as Capacity Performance resources. To avoid double-counting, Kauffman offered several proposals on measurement and verification, add-backs and payment rules to differentiate between megawatts committed under the LFA versus CP versus energy markets.
PJM staff were immediately against the idea, but Kauffman implored them to “first explore this and determine if it’s impractical.”
The Independent Market Monitor’s Skyler Marzewski offered a revised proposal that would prohibit participation in multiple markets and exclude add-backs. PJM’s Andrew Gledhill said “we’re going to have to get the accounting right” because there might be potential for gaming.
Eric Matheson with the Pennsylvania Public Utility Commission withdrew his proposal but provided a presentation on timing conflicts between state peak-shaving programs, such as Pennsylvania’s Act 129, and PJM’s requirements.
PJM’s Rebecca Carroll said the group’s next meeting on Aug. 29 will cover dual registrations in capacity and energy programs, and whether load-reduction offers can be increased and decreased in IAs or just increased. Staff are hoping for a vote in time to review it at the group’s Sept. 19 meeting and report to members at the September meeting of the Markets and Reliability Committee.
Staff also confirmed that any changes the group develops wouldn’t be able to be implemented until the 2020 BRA.
CALGARY, Alberta — Canadian Electricity Association CEO Sergio Marchi took advantage of several opportunities during last week’s NERC Board of Trustees meeting to complain that he and other Canadian stakeholders have been excluded from Department of Homeland Security cybersecurity briefings.
“We’re forbidden to participate because we are considered, quote unquote, foreigners,” said Marchi, whose association represents integrated utilities, independent power producers, transmission and distribution companies, power marketers and industry suppliers. “The irony is the two CEOs [representing Canada’s electricity sector] happen to be American citizens.”
Marchi said that over the last year, he and the two U.S.-born CEOs on the Electricity Subsector Coordinating Council (ESCC), ENMAX’s Gianna Manes and Hydro One’s Mayo Schmidt, have been shut out of the classified briefings.
NERC responded that the Canadians have been excluded because they don’t have the proper security clearance. It added that it is working with industry and government partners to increase the functionality of the Electricity Information Sharing and Analysis Center (E-ISAC) portal, which gathers, analyzes and shares security data across the North American grid.
“NERC as a private company does not have authority to grant or sponsor clearances or to provide access to classified briefings in the United States or in Canada,” CEO Jim Robb said in a statement provided to RTO Insider. “However, NERC will ensure that all NERC events are inclusive of all our North American stakeholders. Simply getting information is only piece of the security pie, and the E-ISAC is in a unique place to analyze and triangulate information to identify threats and mitigation actions to share information that North American stakeholders need to protect their systems.”
Marchi told RTO Insider that the exclusion from the ESCC briefings has become more of an issue under the Trump administration.
“It’s frustrating, and whether it’s NERC or Bruce Walker [the Department of Energy’s NERC representative], they haven’t been able to pinpoint who is blocking us and why,” he said. “This is an example, where everyone says we should be in the meeting, but we don’t know who [is preventing us] and why we are kept out of the meeting. We’re hopeful we can make progress, and the next time the council meets, we can be on the same team.”
Robb acknowledged the issue while briefing trustees on the ESCC’s recent discussions. He said improving information sharing with Canadian industry members is “complicated territory.”
Marchi said the CEA was willing to give Robb a “proper runway” to improve the process.
A former member of the Canadian Parliament and cabinet minister, Marchi also objected to what he said was a 25% budget increase for the E-ISAC as part of NERC’s overall 9.5% budget increase.
“Our Canadian utilities receive the same information from Canadian sources, but it’s quicker and of higher quality,” Marchi said. “Why should we pay twice for information that is of less quality, and that is late on arrival?”
In his statement, Robb pointed out that Canadian stakeholders were able to file comments on the 2019 budget and business plan as part of NERC’s “open and transparent” budget process. He said the organization takes their concerns seriously.
“[We] had multiple meetings, phones calls and written exchanges with [Canadian stakeholders] to discuss the 9.5% increase,” Robb said. “While we acknowledge [their] concerns, we believe the budget approved by the NERC Board of Trustees is the right answer for industry based on all feedback we received.”
Robb acknowledged that the Canadian government has, at times, “authorized release of information to Canadian industry sooner than the U.S. government.” He said NERC recently executed a memorandum of understanding with the Canadian Cyber Incident Response Centre to help improve E-ISAC access to the Canadian government’s security information.
Marchi said the CEA will monitor the next budget cycle and “consider our options” at that time. He said the E-ISAC’s relationship with U.S. security organizations is “an important piece of that puzzle.”
“It’s very important those relationships are picture perfect, if a new investment to the E-ISAC will create the outcomes they’re intended to,” he said. “We need to continue to work closely as our industry evolves at a rapid pace and cyberattacks continue at a great pace. This work must be done in a cost-effective and efficient manner, because both regulators and customers demand and expect it.”
NERC Board Chair Roy Thilly said improving the involvement of Canadian utilities in the E-ISAC “is a very high priority” for the trustees. “We ask the Canadian utilities to work with us to help you provide that value.”
Earlier in the week, the NERC board and Canadian regulators held their annual meeting. NERC said Canadian regulators were briefed on cybersecurity, including the E-ISAC long-term strategic plan and the organization’s reliability assessment and performance analysis capabilities.
Robb Reflects on Cross-border Interconnections
Robb noted several significant milestones during his president’s report, pointing to NERC’s 50th anniversary and the 15th anniversary of the 2003 blackout in the Northeast. As Robb put it, a vegetation contact in Ohio led to power failures in Ontario and “returned the favor” for 1965, when a transmission line tripped in the Canadian province and blacked out Manhattan.
“These anniversaries and our meeting in Canada have given me a chance to reflect on the interconnected nature of our grid and the importance of our international collaboration,” he said. “The Electric Reliability Organization [ERO] is an agency for driving a common approach to reliability and security. We have a tremendous amount of work to do together, and it is a high priority for all of us.”
Robb said the early returns on NERC’s six-month-old, five-year strategic plan have been “very positive,” but that there is a “tremendous amount of work to do.”
“It’s a very complex system to defend,” he said of the grid.
The continuing retirements of coal- and nuclear-fired generation, combined with the rapid deployment of variable resources and natural gas plants, is a problem “no one agency or individual forum can solve,” Robb said.
He said NERC has started work on a guideline to bring “greater clarity” regarding what kind of contingencies need to be studied.
“There are serious issues in the Northeast and desert areas of the Southwest,” Robb said. “We need to move along very quickly on this.”
CEO: AESO’s Challenges Same as Everyone Else’s
The Alberta Electric System Operator (AESO) faces steep challenges in meeting legislative mandates to phase out its coal-fired generation — which accounts for 40% of its installed capacity — and produce 30% of its energy from renewables by 2030. Adding to the challenge, it has very little hydro and no nuclear power in its generation mix.
But that’s no different than the challenges facing other jurisdictions, CEO David Erickson said.
“With the integrated nature of the grid in North America, working together to solve those problems is important,” he said. “That’s the only way to get through this transformation, with the increasing penetration rate of renewables, cyber threats and changing generation mix. Those are real challenges we need to work together to solve. The ISO/RTO community has a big role.
“That said, NERC has an enormous role to get through this. I encourage the industry, I encourage NERC to work together. Whether we like it or not, we’re in this together. There’s a better path that’s more efficient and a lot more effective, if we do this together.”
MISO is probing what eligibility requirements it should establish before allowing electric storage resources to function as transmission assets.
The RTO is considering study processes, modeling, cost recovery and retirement rules, all raised with stakeholders during a special Aug. 17 Planning Advisory Committee conference call to discuss the issue.
MISO is leaning toward requiring a storage resource to complete the interconnection queue if it wishes to provide market services, regardless of whether a resource has already been approved as transmission through the annual Transmission Expansion Plan (MTEP).
The RTO has so far only connected storage to its system through its generator interconnection procedures, and the procedures do not contemplate electric storage resources as transmission assets, MISO Director of Planning Jeff Webb said.
“We have connected batteries recently through Attachment X. However, that process doesn’t contemplate these devices being solely used for transmission services or mixed services,” Webb said.
“One of the complaints for having them go through the queue is a timeline and compatibility process,” he said, explaining that a transmission-use storage resource would likely have to wait through a few MTEP cycles before it could become eligible through the interconnection process. The annual MTEP reliability modeling considers only generators already approved for interconnection, not future resources.
Webb said some storage owners might ask why their resource will have to undergo reliability studies as part of the interconnection queue when they’re already operational under the MTEP assessment.
“Would the subsequent interconnection process be superfluous? What function would it serve?” Webb asked rhetorically. “Maybe there’s a type of expedited interconnection. I don’t know.” He asked stakeholders for their ideas.
American Transmission Co.’s Bob McKee predicted that MISO will see many storage resources connecting under mixed-use market and transmission functions.
“To get the value out of that device, you’re going to use it for as many services as you can. I think we’re really going to have to make sure the process doesn’t impede the value for the customer.” He warned against completing separate assessments simply for the sake of following MISO’s current process.
Some stakeholders asked if it was a matter of treating all generation fairly as a matter of principle, or necessary to allowing storage’s possibly superior capabilities to compete in more than one area. Others said MISO may need to complete queue analyses with and without the presence of storage resources to find out whether storage as transmission is truly as reliable as traditional transmission.
Webb said MISO will likely make special modeling considerations for storage resources beyond traditional wires modeling.
“When we’re talking about wires or transformers or cap banks, those are available all day, every day to provide for any and all reliability issues or conditions on the grid that they can assist with. Storage as transmission would similarly be called upon by MISO to address any reliability issues they would be effective for,” Webb said.
He said storage as transmission in particular would have to be under some form of MISO control to make sure it is charged to perform its reliability functions over peak hours, for example. MISO plans to notify the resources when and at what charge state they will be needed to provide transmission reliability services and will provide enough time to ensure the resource can reach the necessary state of charge.
Webb said that if MISO chooses to defer a 40-year transmission project in favor of a storage solution, it must also gauge the anticipated life of a device for modeling, considering which major components will likely have to be replaced and when. He said MISO may find itself approving the original deferred transmission project if a storage asset doesn’t stand up over decades.
MISO must also decide how storage assets will recover costs so that customers don’t pay twice for the same services, Webb said, paying particular attention to the treatment of market revenues if either partial or full revenue requirements are recovered under cost-based transmission rates. Storage asset owners might decide to recover only a portion of transmission rates so the asset can compete with a cheaper wires solution, Webb said.
MISO is currently considering at least three approaches to cost recovery:
Full cost-based recovery for transmission reliability services, with full crediting of market revenues;
Partial cost-based recovery for transmission reliability services, calculated as asset cost minus asset owner-estimated market revenues with crediting proportional to cost-based revenue; or
Partial cost-based recovery for transmission reliability services, calculated as asset cost minus asset owner-estimated market revenues with no crediting of market services revenues because the amount was estimated to be necessary to recover asset costs.
Storage resources would also likely have to be registered in the MISO market for charging and discharging, even if they are strictly treated as transmission, Webb said. The question also remains about what storage assets would pay and be paid for energy used for charging and discharging when they must operate for transmission system reliability under MISO instruction. Webb said in those cases, storage owners could either be price-takers in the market, charged and paid at LMPs for injections and withdrawals, or they could be neither paid nor charged for such injections and withdrawals. He also said MISO and stakeholders could come up with a third option for consideration.
The RTO is also looking to draft a storage-as-transmission retirement process, Webb said. Traditional wires assets are rarely decommissioned in the footprint, according to MISO, and Webb said storage resources may become subject to system support resource studies or an equivalent to discern whether the devices are necessary for reliability purposes.
Webb also said stakeholders raised an issue of MISO investigating whether there are possible conflicts of interest if a transmission owner is also allowed to become a market participant operating a storage resource for market services. However, Webb said MISO did not think the issue was markedly different than utility-owned generation participating in the market today.
MISO will continue to discuss policy for storage-as-transmission at the September PAC meeting. Webb asked for stakeholder suggestions through Sept. 7.
