The Western Energy Imbalance Market continued expanding Wednesday as the Sacramento Municipal Utility District (SMUD) became the first publicly owned utility to begin participating in CAISO’s real-time electricity market for the West.
“The Western EIM demonstrates the economic and environmental savings achieved when participants work collaboratively across the region,” CAISO CEO Steve Berberich said in a news release. “As one of the premiere community-owned utilities in the country, SMUD’s participation will only strengthen the market and add to its efficiency and diversity.”
SMUD first announced its intent to join the EIM in October 2016. The nation’s sixth-largest community-owned utility, SMUD also is the largest member of the Balancing Authority of Northern California (BANC). Other BANC members — all publicly owned — may eventually join the EIM. (See SMUD Balancing Area Inks Agreement for EIM Membership.)
“BANC is excited to be the first publicly owned agency to become an EIM entity in the Western EIM,” BANC General Manager Jim Shetler said in the joint statement by CAISO, SMUD and BANC. “We found the CAISO staff to be extremely helpful in assisting us in what was a very smooth transition effort. BANC is currently evaluating future participation by its other members.”
BANC, which began operations in 2011, is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. Created as an alternative to CAISO, BANC is responsible for balancing load among its members, as well as coordinating system operations with neighboring balancing areas. BANC contracts with SMUD to perform day-to-day balancing functions.
BANC also serves the Modesto Irrigation District, Redding Electric Utility, Roseville Electric Utility, the city of Shasta Lake and the Trinity Public Utilities District. The BA includes a portion of the Western Area Power Administration’s transmission grid and the U.S. Bureau of Reclamation’s hydroelectric resources in California. The agency’s members control capacity on the California-Oregon Intertie, one of two high-voltage transmission lines linking California with the Pacific Northwest.
CAISO says the EIM has cut carbon emissions by more than 324,000 metric tons since its 2014 launch by replacing electricity generated from fossil fuels with energy from wind, solar and hydropower resources.
In addition to CAISO, the EIM’s other members are PacifiCorp, NV Energy, Arizona Public Service, Puget Sound Energy, Portland General Electric, Idaho Power and Powerex. Entities scheduled to begin participation next year include Seattle City Light, the Los Angeles Department of Water and Power and Arizona’s Salt River Project.
Montana’s NorthWestern Energy is planning to join the EIM in 2021. Public Service Company of New Mexico was hoping to join by 2021, but recent regulatory delays have cast doubt on that timing. (See PNM’s Bid to Join Western EIM Gets Approved in Part.)
The EIM serves areas in Washington, Oregon, California, Nevada, Idaho, Wyoming, Utah and Arizona.
“SMUD sees significant financial, operational and resource value in participating in the Western EIM due to its broader regional scope and dispatch,” SMUD CEO Arlen Orchard said in Wednesday’s statement. “The EIM’s geographic diversity allows easier and more economical balancing and integration of intermittent renewable energy resources, helping SMUD meet its and California’s aggressive renewable and carbon-reduction goals.
“SMUD is pleased to have forged this important partnership with the CAISO and the other EIM participants to further these goals.”
FERC on Monday rejected a plan by CAISO to modify an exemption to its Resource Adequacy Availability Incentive Mechanism (RAAIM) that it grants to variable energy resources such as wind and solar (ER19-951).
“CAISO proposed RAAIM as a way to provide incentives to resources to meet their resource adequacy must-offer obligations through a series of incentive payments and charges,” FERC explained. “CAISO also proposed to exempt certain resources from RAAIM, including variable energy resources,” so that they wouldn’t be unfairly penalized for weather and other natural circumstances beyond their control.
FERC accepted CAISO’s exemption for variable energy resources in October 2015 (ER15-1825).
On Jan. 31, CAISO asked to alter the exemption by referencing “participating intermittent resources” and “eligible intermittent resources” instead of “variable resources.” The ISO said the change would clarify the exemption because only solar and wind currently can qualify as participating intermittent resources. The proposed change was a product of CAISO’s Commitment Cost Enhancements Phase 3 (CCE3) initiative.
CAISO is headquartered in Folsom, Calif. | CAISO
“CAISO explains that it has no approved forecasting methodology for other resource types besides wind and solar, and thus it has not offered RAAIM exemptions for them,” the commission said.
Pacific Gas and Electric protested, saying CAISO’s proposed changes would unfairly exclude certain variable energy resources from the RAAIM exemption, including run-of-river hydroelectric plants that don’t have dams and reservoirs.
“PG&E asserts that this proposal would discriminate unjustly and unreasonably against certain types of variable energy resources without adequate justification,” FERC wrote. “PG&E explains that certain hydro resources, such as run-of-river hydro, operate similarly to wind and solar in that there is no storage capability, and, thus, no ability to optimally choose when to generate.”
In response, “CAISO asserts that these terminology revisions maintain existing application of the bidding and RAAIM exemptions for wind and solar resources … [and] that forecasting run-of-river hydro resources is outside the scope of this proceeding.
“Further, CAISO argues that because its revision maintains the status quo … [it] will have no practical impact because the terms ‘variable energy resource’ and ‘eligible intermittent resource’ are interchangeable.” The changes would substitute more concrete terms for a generic one, CAISO said.
FERC decided it wouldn’t accept the wording change because the ISO had failed to show it wasn’t preferential or discriminatory.
When it previously accepted the ISO’s proposed RAAIM exemptions, it was so variable resources wouldn’t be unfairly penalized, FERC wrote.
“In this filing, though, CAISO proposed to limit eligibility for the RAAIM exemption based on whether CAISO has developed a forecast methodology for that resource,” the commission said. “This approach to determining eligibility for the RAAIM exemption is not consistent with the reasoning CAISO originally offered in support of its proposal, and with which the commission agreed.”
The commission did accept a handful of other Tariff revisions related to the ISO’s CCE3 and Reliability Services initiatives, including the following:
a provision stating resource-specific information that resource owners provide for inclusion in CAISO’s master file of resources must accurately reflect the design capabilities of a resource when operating at maximum sustainable performance over minimum run time, recognizing that performance may degrade over time;
revisions clarifying the integration dates for opportunity cost adders stemming from the CCE3 proposal; and
provisions clarifying the bidding obligations of resources with limited availability.
FERC on Monday conditionally accepted MISO’s second attempt to address an inherent conflict within its Tariff related to the termination of generator interconnection agreements (GIAs) (ER18-2054).
The conflict stemmed from a discrepancy between what was laid out in MISO’s generator interconnection procedures (GIP) and its pro forma GIA.
In an October 2017 order, FERC found that a provision in the GIA allowing interconnection customers to extend the commercial operation date (COD) of a project by up to three years without facing termination conflicted with a GIP provision stating a COD extension required a material modification of the interconnection request — or the project risked removal from the queue. The discrepancy was discovered when the Merricourt wind project in North Dakota sought to extend its COD under a GIA with Montana-Dakota Utilities and MISO.
In mid-2018, FERC directed MISO to make a second Tariff filing clarifying an interconnection customer can extend its COD by up to three consecutive years before risking withdrawal from the queue. (See FERC OKs MISO Revision of Queue Termination Rules.) At the time, FERC directed MISO to “provide clarity as to the three-year period that must lapse before MISO must seek to terminate a GIA for failure of a generating facility to achieve commercial operation by the [COD].”
MISO’s updated Tariff language clarifies that an interconnection customer’s project has up to three years beyond its original COD to begin generating or risk removal from the interconnection queue.
The GIP now explains that once a GIA is executed or filed unexecuted, “if the generating facility fails to reach commercial operation by the [COD], such [COD] may be extended by [the] interconnection customer for a period up to three consecutive years, after which [the] transmission provider shall terminate the GIA if the generating facility has still failed to reach commercial operation.”
In its filing, MISO relayed concerns that the new GIP language could inadvertently allow a maximum six-year extension to a generating facility’s COD by creating a three-year maximum extension that is “distinct” from the same three years allotted in the GIA. That could occur when a project’s timeline is jeopardized by a change in milestone fees by another party to the GIA, a change in a higher-queued interconnection request and delays in MISO studies; and when an interconnection customer can show that engineering, permitting and construction will take longer than the definitive planning phase allows. None of the four exceptions amounts to a material modification under MISO Tariff.
FERC agreed with MISO that the language could be construed as creating an “additive” three-year extension that is “distinct from, and in addition to, the three-year extension that an interconnection customer may receive if it qualifies for any of the four exceptions.”
To avoid that reading, the commission Monday directed MISO to make a further compliance filing to reference that the new GIP language is consistent with the provision in its pro forma GIA that limits the COD extension to three years.
MISO must flesh out more details around its already lengthy proposal for allowing energy storage resources to participate in its markets, FERC said Monday.
In an April 1 letter requesting more information on the plan, FERC said it could not process MISO’s Order 841 compliance filing until it clarifies several points regarding its phased participation approach, proposed commitment statuses, complexities for storage resources on the distribution system, conflicting offers and bids and make-whole payments (ER19-465). MISO has 30 days to respond.
FERC Order 841 requires RTOs and ISOs to revise their market participation models to allow storage resources 100 kW and larger to provide the capacity, energy and ancillary services they are technically capable of providing. MISO and its stakeholders spent the better part of last year negotiating rules that culminated in a 1,300-page filing. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.)
In its compliance filing, MISO said it “anticipates significant uncertainty and risks related to the ability of MISO’s system and software to handle the participation of large numbers of very small” energy storage resources. The RTO asked for a “phased approach in the accommodation of very small” storage resources that would limit participation of small storage resources to 50 in the first year of compliance and 150 in the second year.
MISO said that approach would give it time to “further develop and fine-tune its system and software to be able to handle potentially increasing numbers of very small” storage resources.
But FERC directed MISO to specify what year it expects to provide market access to all storage resources that meet the 100-kW minimum threshold.
MISO must also explain how its must-offer requirement is affected when storage resources elect to use the RTO’s proposed dispatch status of “not participating” or other commitment statuses, the agency said. MISO’s filing proposed owners of storage resources could choose between several commitment modes, including charge, discharge, continuous, available, not participating, emergency charge, emergency discharge and outage. MISO has said its discharging, charging and continuous modes will carry must-run designations.
Tesla Powerpack lithium-ion battery storage | Tesla
FERC said MISO must clarify whether it proposes to levy transmission charges on storage resources when they are charging to resell energy later. MISO must also explain how it will help storage on the distribution system from making double payments — at both retail and wholesale — for charging energy.
FERC also asked if MISO would propose metering practices to manage the “complexities” of selling energy to a storage resource that will then resell the energy at the wholesale LMP.
MISO’s proposal requires storage owners to secure agreements with distribution companies that can deliver stored energy to the transmission system. However, FERC asked if MISO would require the same agreements when energy is moved from the transmission system to distribution-level storage, and it asked the RTO to explain a provision that prohibits distribution-level storage resources from pseudo-tying into a different balancing authority.
The agency also told MISO to cite Tariff provisions that will allow owners of storage resources to self-manage their state of charge.
FERC additionally said if MISO were to rely on existing Tariff provisions for a storage participation model, it should provide the commission with citations to the applicable market rules and pseudo-tie requirements for transmission-level resources. MISO must also describe how its filing will give storage resources access to all capacity, energy and ancillary service markets, as well as non-market services such as black start, primary frequency response and reactive power.
FERC told MISO to explain how its filing will prevent the same resource from submitting conflicting supply offers and demand bids for the same market interval. It also seeks to know if the participation model allows for make-whole payments when a resource is dispatched as load and the wholesale price is higher than the bid price and when a resource is dispatched as supply and the wholesale price is lower than the offer price. The commission also asked if resources available for manual dispatch will be eligible for make-whole payments.
Finally, FERC asked MISO to cite how its compliance filing will allow storage dispatched as supply and demand to set the wholesale market clearing price as both a wholesale seller and buyer, as Order 841 dictates. The agency also asked for citations to support that storage resources can set the price in the MISO capacity market, that MISO will accept wholesale bids from storage owners and that self-scheduled storage resources can participate in the market as price-takers.
ERCOT market participants last week grilled staff over the grid operator’s requests to delay generation outages in advance of an early March cold-weather event that led to a new monthly peak but ultimately did not require emergency actions.
Members rained their concerns on Dan Woodfin, ERCOT’s senior director of system operations, for more than two hours at the Technical Advisory Committee’s March 27 meeting. They contended the grid operator didn’t give the market a chance to work and that it had an insight into the market not shared with its participants.
When it was over, TAC Chair Bob Helton teased Woodfin to be careful drinking water “because of all the holes punched in you.”
Citigroup Energy’s Eric Goff (left) and Morgan Stanley’s Clayton Greer question ERCOT’s Dan Woodfin (not pictured).
Cold Weather, High Loads
In late February, weather forecasters projected an arctic cold front to cover much of Texas during the first week of March. ERCOT’s earliest assessments indicated peak loads of more than 58 GW, “substantially higher” than is typical for early March.
Complicating matters was the more than 7.7 GW of capacity scheduled to begin maintenance outages on March 1 and 2, in addition to more than 12 GW of outages already underway. Meanwhile wind forecasts from ERCOT vendors indicated the grid operator could face low wind output during peak times through March 5.
ERCOT issued an operating condition notice (OCN) just after noon on Feb. 27, warning of a “potential cold weather system” affecting its footprint March 3-7. Staff said they followed up by asking the generators’ qualified scheduling entities to review their fuel supplies and urging them to delay maintenance or return from outages early. ERCOT said it asked about 6 GW of outages to be delayed, but by the following afternoon, only one unit had delayed its outage.
“Normally, when we issue an OCN of this type, we see a lot of response from the pertinent units,” Woodfin said. “It’s not a matter of OCNs causing us to do things; it’s a matter of OCNs causing the market to respond. The idea is to look at your outages … it should cause people to sit up and look closer, and delay the outage because things look tight.”
On Feb. 28, ERCOT projected it had 58 GW of capacity available, which included 2 GW of wind and load resources. However, expected gas curtailments and forced outages led to what ERCOT called a “more reasonable scenario” of a 5.5-GW shortage and a “potential for more extreme conditions” — considering a projected 60-GW peak and a need for 3.5 GW of reserves.
But when ERCOT posted market information at 8 a.m. on Feb. 28, it indicated a surplus of 3.4 GW, boosted by 7 GW of wind energy. Later that day, ERCOT switched to a second vendor’s more conservative forecast of wind production.
ERCOT assessments on Feb. 28 for a March 5 peak | ERCOT
‘Voluntary’ or not?
Generator representatives objected to ERCOT’s descriptions of the event. Calpine’s Brandon Whittle noted ERCOT used the terms “ask” and “voluntary” in reviewing the event, but said it was “not the case for my shop.”
The OCN “was just a notice. We get many of those during the year,” he said. “[ERCOT said,] ‘We issued an OCN, no one did this, now you have to respond.’ Ultimately, this is an issue for operators and generators to determine when it is to their economic advantage to start a plant or do whatever they need to do.”
“When we issued the OCN, our expectation was people on their own would respond to it,” Woodfin replied.
“The language I heard over and over that afternoon and the next morning, in discussions with ERCOT staff and management, was that because no one responded to the OCN, you have to do this,” said Whittle, using “strong arm” to describe the underlying message he received from staff. “Part of the instruction to generators was if you don’t move your outage, we’ll cancel it, or you will have it forced.”
When Woodfin explained ERCOT was requesting outage delays so generators could maintain their place in the schedule, Whittle responded, “Is that not a threat in some way?”
“We were trying to help them,” said Woodfin, who observed communications between ERCOT operators and market participants. “All those communications were very cordial. There was no animosity.”
Calpine’s Brandon Whittle (left) and Luminant’s Ian Haley
Eventually, more than 6.5 GW of generation originally scheduled to begin planned outages was available through the cold spell.
Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitor, said that while she was supportive of the grid operator’s description of events, it also reminded her of the “offerhecouldn’trefuse” line from “The Godfather.”
“‘Either your brains or your signature will be on the contract.’ Either your outage will be moved, or it will be withdrawn,” she said. “That’s what it sounds like right now. That’s not a good situation.”
“No doubt ERCOT was doing what they think they needed to do to maintain the reliability of the system,” Reliant Energy Retail Services’ Bill Barnes said. “We would certainly have a different view when ERCOT declares an OCN and there would be some expectation to take action. The OCN, to us, is information that is interesting, but the No. 1 thing that will drive our behavior is what the prices are doing.
“If the prices are high enough, that would encourage us to change our outage schedule around. I don’t think ERCOT should have that expectation that people are going to start taking all this action unless the market sends the price signal to do so,” he said.
ERCOT “complained of a lack of voluntary outage deferrals after it issued the OCN, but based on the forecasts … there was no reason for the market to expect an extreme situation,” Whittle told RTO Insider on Monday. “Without an expectation of scarcity, the forward prices for the cold snap were not high enough to incent generators to defer outages on their own.”
The generators also complained about a lack of transparency in ERCOT’s development of planning scenarios for March 3-7 and what they saw as a delay in issuing the OCN.
“We want to wait as long as possible to let the market respond on its own,” Woodfin said. “On the 27th, we realized no one was adjusting and we see this [cold weather] coming. Hello? That was what the OCN was for.”
“Issuing the OCN earlier would have prompted more response,” South Texas Electric Cooperative’s Clif Lange said.
Lack of Transparency?
“Why didn’t market prices reflect what was going on?” Barnes asked. “[There was] a lack of transparency in some of the information [provided]. There were also likely expectations that ERCOT would intervene with reliability actions. That should be the focus of what we try to address. There should be confidence in the market.”
Reliant Energy Retail Services’ Bill Barnes
“We try to let the market respond, and hopefully, it will, so we don’t have to take command-and-control actions,” Woodfin said.
ERCOT set a new monthly record for demand on March 5 at 60.7 GW, breaking a mark set in 2014. The grid operator wound up with 66.5 GW of capacity to work with, and it canceled the OCN at noon on March 6.
Prices briefly eclipsed $1,300/MWh in the real-time market and approached $800/MWh in the day-ahead market during the morning hours. There were also periods of lower operating reserve demand curve (ORDC) reserves and higher ORDC price adders during the same period.
Asked whether ERCOT believed it had completed all reasonable options before issuing the initial OCN, COO Cheryl Mele responded, “We’ve heard that message.”
“We’re already talking about the ways we can ensure we’re portraying to the market all the things we are looking at,” she said. “The root of the problem is we didn’t do a good job of selecting the forecast early enough that would be what we thought was going to be the most likely outcome.”
Pricing outcomes for March 5 | ERCOT
ERCOT staff will review its existing Protocols governing the use of OCNs and other market notifications, and it has already begun discussing improvements to its communications processes. Separately, Helton said he would work with TAC Vice Chair Diana Coleman to assemble a group to review how ERCOT distributes planning information data, its definitions or levels of emergencies in the planning horizon, and the timing of market notifications.
Texas Public Utility Commission Chair DeAnn Walker was among the interested observers during the two-hour discussion. Walker did not join in the discussions, but the PUC has opened a docket (Project 49378) to review ERCOT’s “outage scheduling processes” and has placed it on the agenda for its April 4 open meeting.
Despite record-high capacity factors and reduced operating costs, the U.S. nuclear power industry is threatened by federal and state policies and an “increasingly distorted” energy market, Nuclear Energy Institute CEO Maria Korsnick said last week in her annual state of the industry address.
Maria Korsnick | NEI
“Our capacity factor and generation has never been higher, and our operation costs have not been this low since 2004,” said Korsnick, citing the 2018 capacity factor of 92% and a 25% drop in “average total generating costs” since 2012. Nuclear power produced 20% of the nation’s electricity in 2018 and more than 55% of emissions-free power, she added.
But Korsnick said nuclear’s role in limiting carbon emissions is at risk from both RTO energy markets that fail to compensate them fairly and renewable portfolio standards in more than half of the states that limit their carbon-free technologies to wind and solar. “They ignore nuclear, and that’s shortsighted,” she said.
‘Not a Bailout’
She noted that the Nature Conservancy and the Union of Concerned Scientists have become more supportive of nuclear power, calling it a recognition of nuclear’s role as the “workhorse” of emission-free generation.
“I think it’s a realization that this idea of 100% renewables is not gonna happen,” she said in a Q&A session with NEI’s senior director of external communications, Monica Trauzzi. (Although Trauzzi asked some questions from viewers, Korsnick did not take questions from the media.)
Korsnick praised state officials in Illinois, New York, New Jersey and Connecticut, who have authorized new revenue streams to keep their nuclear plants operating, while noting that 12 plants nationwide are planning early retirements. (See related story, Clock Ticking on Pa. Nuke Subsidy Bill Hearings.)
“Saving nuclear plants is not a bailout. It is not a subsidy. It’s helping to right wrongs in an increasingly distorted energy market,” she said.
Korsnick said the industry also is at risk of losing its competitiveness internationally, saying two-thirds of the reactors being built around the world are from China or Russia. She called on Congress to reauthorize the Export-Import Bank and restore its quorum to ensure the financing needed to compete internationally.
Bright Times Ahead?
Korsnick was nevertheless optimistic about the future, saying 2020 could see the Nuclear Regulatory Commission approve its first application to renew a plant license for a second time; it would add a second 20-year extension, for a total of 80 years. Next year also could see NRC certification of NuScale’s design for a small modular reactor.
NEI has high hopes for bipartisan legislation introduced last week to create public-private partnerships to develop, test and deploy new nuclear technologies. It follows President Trump’s signing in January of the Nuclear Energy Innovation and Modernization Act, which seeks to accelerate the development of new reactor designs.
Korsnick said she was hopeful NRC’s Transformation Initiative would result in “off ramps” that allow the commission to terminate proceedings involving issues of “low-safety significance.”
The Electric Power Research Institute “came out with a report recently and mentioned that the current designs … are over 100 times safer than the original safety goals that the NRC set many years ago. … The industry is mature,” she said. “Let’s come up with ways — we’re calling it off ramps — so that we’re not spending an inordinate amount of time … churning on an issue that quite frankly just has low safety significance.”
Korsnick’s speech came the day before the 40th anniversary of the partial meltdown at Three Mile Island, which ended the expansion of nuclear power in the U.S. for decades.
Vogtle Milestone
Korsnick celebrated progress on Georgia Power’s Vogtle plant, which reached a milestone March 22 with the installation of the containment cap on Unit 3. Vogtle will be the first new U.S. nuclear plant built in three decades.
She did not mention the delays and massive cost overruns that have plagued Vogtle, and which led to the cancellation of a nuclear project in South Carolina. She said only that “massive infrastructure projects are always messy. They don’t always go as planned.”
Vogtle nuclear plant construction | Georgia Power
In 2008, Georgia Power estimated that Vogtle Units 3 and 4 would cost $14.3 billion and begin commercial operations in 2016 and 2017, respectively. The most recent estimates put the total cost at about $28 billion and the completion dates in November 2021 and November 2022, according to Taxpayers for Common Sense.
The Department of Energy last month approved an additional $3.7 billion in loan guarantees for the project, bringing total taxpayer liabilities to more than $12 billion, the taxpayers group said.
The ERCOT Technical Advisory Committee last week tabled a request to lower the grid operator’s peaker net margin (PNM) threshold pending further direction from the Public Utility Commission of Texas, which is debating the threshold’s continued existence.
The PNM threshold is used to determine the point at which ERCOT’s systemwide offer cap is reset from the high limit of $9,000/MWh to the low cap (the greater of $2,000/MWh or 50 times the daily effective fuel index price).
The ERCOT Protocols require the PNM threshold be set at three times the cost of new entry (CONE) for a power plant, historically a combustion turbine. The threshold has been $315,000/MW-year in recent years, but a Brattle Group report in December identified the latest CONE for a CT to be at $88,500/MW-year.
ERCOT has proposed the PNM threshold be reduced to $265,500/MW-year, which is three times the recently determined CONE.
“We’re taking something that came out of an academic exercise. This needs more vetting,” Reliant Energy Retail Services’ Bill Barnes said.
“Several of us have commented at the commission,” said Direct Energy’s Sandy Morris, representing the Independent Retail Electric Providers segment. “You might have a resolution from the commission. If we don’t hear from the commission, then we can proceed with what we hear here. That’s fine with me. … I want to see a lower CONE.”
ERCOT’s Dan Woodfin addresses the TAC at its March 27 meeting.
RTC Task Force to Begin Work April 4
The TAC endorsed the creation of a task force to establish market rules for implementing real-time co-optimization (RTC), which PUCT Chair DeAnn Walker hopes will bring “economic benefits that exceed its costs” and “operational benefits for ERCOT as well.” The PUC has directed ERCOT to proceed with RTC’s implementation (Project 48540).
The Real-Time Co-optimization Task Force (RTCTF) will be led by ERCOT Compliance Director Matt Mereness and Bryan Sams, director of regulatory affairs for Lone Star Transmission. Mereness will serve as either chair or co-chair alongside Sams, depending on the task force’s determination.
“It’s an honor to do this. It’s a big deal,” said Mereness, who promised up to three meetings a month. ERCOT has said it will take four or five years and about $40 million to implement RTC.
The RTCTF will report directly to the TAC and comprise stakeholders and staff from ERCOT, the PUC, the Independent Market Monitor and Office of Public Utility Counsel. It will hold its first meeting April 4.
ERCOT staff have said RTC will efficiently coordinate the provision of energy and ancillary services (AS) in the real-time market and price AS shortages according to their defined demand curves.
ERCOT Gathering Input for Storage Workshop
ERCOT staff briefly reviewed a list of issues to be discussed during an April 23 workshop on energy storage. Staff are still gathering input on the workshop, which will also include a brief overview of an April 25 workshop on inverter-based resources.
The PUC opened a rulemaking on energy storage ownership (Project 48023) following last year’s rejection of AEP Texas’ request to connect two West Texas battery storage facilities to the ERCOT grid. Transmission and distribution providers have squared off against generators over the devices’ ownership. (See “Commission Welcomes Legislative Input on Energy Storage,” Texas PUC Briefs: Jan. 17, 2019.)
TAC Approves RMS Leadership, 15 Revision Requests
The TAC approved American Electric Power’s Jim Lee as chair and Just Energy’s Eric Blakey as vice chair of the Retail Market Subcommittee, which serves as a forum for resolving retail market issues directly affecting ERCOT and its Protocols. Lee and Blakey are exchanging the positions they held through much of 2018, maintaining the RMS’ unofficial practice of having a utility representative and a retail electric provider representative share the leadership positions.
The committee also endorsed 11 Nodal Protocol revision requests (NPRRs), two changes to the Retail Market Guide (RMGRRs), one to the Resource Registration Glossary (RRGRR) and one system change request (SCR):
NPRR891: Removes the 50-kW threshold for non-opt-in entities to report unregistered distributed generation to ERCOT for its unregistered DG report.
NPRR900: Addresses inconsistencies in the current Nodal Protocol language that don’t align with current processes, PUC rules and system design.
NPRR906: Streamlines the Protocol language and removes ambiguity over how ERCOT systems handle the decision-making entity during security-constrained economic dispatch’s (SCED) mitigation processes.
NPRR908: Aligns RMG references and updates mass transition notification requirements for emergency qualified scheduling entities to match with RMGRR159’s revisions.
NPRR909: Resolves a gap in the Protocols by addressing the unplanned unavailability of emergency response service (ERS) loads and generators.
NPRR912: Addresses the settlement of switchable generation resources (SWGRs) that receive a reliability unit commitment instruction to switch from a non-ERCOT control area to the ERCOT control area. The change provides a make-whole payment for an SWGR when its real-time ERCOT revenues are not sufficient to cover certain specified costs the resource may have incurred in complying with the RUC instruction.
NPRR914: Adds data points unique to a controllable load resource available for dispatch service or dispatch with a real-time market bid to the existing 60-day SCED disclosure report.
NPRR916: Sets the mitigated offer floor to $0/MWh for “combined cycle” and “gas/oil steam and combustion turbine” resource categories, replacing the fuel index price-based calculation. The change also eliminates the grey-boxed language from NPRR664.
NPRR920: Modifies the resource ramp rate logic in the Protocols (Section 6.5.7.2, Resource Limit Calculator) to dynamically adjust the amount of ramp rate reserved for regulation service in real time based on the percentage of regulation service being deployed in the opposite direction.
NPRR922: Aligns the DC tie import forecast with forecasts of other resources in ERCOT’s Capacity, Demand and Reserves (CDR) report that are deployed during ERS and other energy emergency alert events. The revision also addresses a reporting gap in the CDR by specifying an approach for forecasting expected capacity imports for planned DC tie projects.
NPRR925: Increases the minimum quantity that can be submitted for point-to-point (PTP) obligation bids from 0.1 MW to 1 MW, matching the minimum quantity for energy-only offers and energy bids.
RMGRR158: Codifies competitive retailer responsibilities during an extended unplanned system outage.
RMGRR159: Clarifies the mass transition processes and communications by: shortening required minimum timelines for initial notification to affected parties from two hours to one hour; allowing preliminary notification of mass transition to affected transmission and distribution service providers, providers of last resort and PUC staff, as long as protected information is not disclosed; and clarifies that ERCOT may coordinate periodic testing of mass transition systems and processes with market participants.
RRGRR020: Corrects certain submittal requirement fields inadvertently left blank during RRGRR007’s implementation by replicating requirements from the full interconnect study column to the planning model column for the affected rows. The request does not add any new data requirements to the glossary.
SCR798: Introduces a limit on the total number of PTP obligation bids that can be submitted into the day-ahead market per qualified scheduling entity and per counter-party. The limit will apply to the number of bid IDs per operating day.
CARMEL, Ind. — FERC on Friday granted MISO permission to implement the remaining two proposals in its three-part short-term resource availability and need project.
Facing baseload generation retirements, more frequent emergencies and diminishing capacity margins, MISO had proposed stricter outage scheduling rules and annual real power testing for demand response. FERC said MISO could implement both provisions, though it wants the RTO’s Maintenance Margin tool chronicled in its Tariff.
In February, FERC approved a MISO proposal requiring owners of load-modifying resources to provide firmer and more clearly documented commitments regarding their availability. (See MISO LMR Capacity Rules Get FERC Approval.)
Taken together, the three filings are geared toward freeing up an additional 10 GW of supply as MISO navigates its spring maintenance outage season and the arrival of warm weather.
Stricter Outage Planning
MISO can now impose new generator accreditation penalties for planned outages taken during what it deems “low margin, high risk periods” (ER19-915). RTO staff have said the rules will incent the forward scheduling of planned generation outages.
FERC approved the proposal effective Monday and said it expected the rules will promote advanced scheduling, improve outage coordination and help MISO address its recent spate of shoulder period emergencies.
“MISO’s proposed Tariff revisions add specificity and incentives to the Tariff’s existing provisions governing the scheduling of generator planned outages,” FERC said.
MISO generation resources now must provide 120 days’ notice for planned outages. However, outages scheduled between 14 and 119 days in advance will be exempt from the RTO’s accreditation penalties, provided the outages are scheduled during predefined periods with adequate margins. Generator planned outages and derates scheduled fewer than 14 days in advance and occurring during a declared maximum generation emergency would be subject to accreditation penalties. The proposal also provides safe harbor provisions for resources that adjust a planned outage at MISO’s request.
The RTO also has instituted a transition period to the new set of outage rules. Outages scheduled prior to April 1 will not be subject to the accreditation penalty, while requests and revisions submitted April 1 and beyond for outages starting April 15 through July 29 would be exempt from the penalty if the request is submitted no later than 14 days in advance and MISO foresees “adequate projected margin at the time of the request.” The full set of outage requirements will go into effect for outages scheduled to start July 30 or later.
MISO said that although it has so far managed generation outages through voluntary rescheduling, “there has been a significant increase in the number of maximum generation emergencies that are at least in part driven by highly correlated generator planned outages.” The RTO said only 30% of planned outages are scheduled 120 days or more in advance, with most being scheduled just weeks in advance.
A group of state regulators and Prairie Power argued that MISO wasn’t providing enough detail into what load forecasts it uses in its Maintenance Margin tool, the nonpublic webpage the RTO maintains to help members schedule outages during adequate supply conditions.
The two also contended that MISO mischaracterized the accreditation penalty as an “incentive”; violated its stakeholder process by allowing just 11 days for stakeholders to review the final proposal; and that the proposal “ignores the real world of utility operations” in which previously unknown problems can be uncovered as equipment is disassembled. Indiana Municipal Power Agency and Southern Minnesota Municipal Power Agency also derided the 14-day deadline as “arbitrary.”
But FERC said the tiered approach “provides MISO with the forward transparency it seeks, reduces the risks associated with correlated [outages] and maintains sufficient flexibility for generator owners to schedule their [outages] without risk of an accreditation penalty.” FERC also pointed out that outages scheduled fewer than two weeks in advance aren’t automatically subject to an accreditation penalty unless the outage occurs during an emergency.
However, FERC agreed with WEC Utilities and American Municipal Power that MISO needs to define the Maintenance Margin in its Tariff. The tool “is the sole factor in determining whether there is an ‘adequate projected margin’ under the proposed Tariff revisions,” FERC said, and as such, should be recorded in the MISO Tariff.
“We find that the Maintenance Margin can have a significant impact on rates, terms and conditions of service,” the commission said, directing MISO to make a compliance filing by the end of April.
Real Power Testing for DR
FERC on Friday also approved MISO’s proposal to require annual actual power tests from its DR resources (ER19-651).
The RTO had asked for permission to conduct the tests to get more certainty about resources’ ability to perform when needed during tight operating conditions.
At MISO’s recent Board of Directors week in New Orleans, RTO executives said the move will put DR on a more level playing field with other resources, which are already beholden to the annual power tests.
DR resources that complete the annual testing will receive credit for one of the five deployments required of them in a planning year. MISO has said that resources that are deployed and follow all scheduling instructions in a planning year will not be subject to the testing in the following year.
MISO has also said it will waive the testing requirements for DR resources “that are subject to regulatory restrictions that preclude testing.” Additionally, a DR resource that simply wants to opt out of testing can do so, provided it agrees to pay MISO three times the cost of demand reduction for non- or underperformance.
Some MISO member companies protested the filing, arguing that the RTO failed to justify the need for annual testing; the testing would cause DR to exit the market; the proposed penalty cost was arbitrarily punitive; and an annual testing requirement would result in increased production costs and risk to equipment.
But FERC disagreed on all fronts.
“To the extent that MISO’s proposal increases costs on demand resource owners, they can reflect those costs in their submitted offers into the auction,” FERC said.
WASHINGTON — Transportation Security Administration officials last week defended their efforts to protect the country’s natural gas pipelines, telling FERC they are adding more staff to the effort.
The importance of securing gas infrastructure was a recurring theme at a technical conference organized by FERC and the Department of Energy on security investments for energy infrastructure — an acknowledgement of the fuel’s growing importance to the country’s electric generation mix (AD19-12).
TSA — established under the newly created Department of Homeland Security after the Sept. 11, 2001, terrorist attacks — has come under increasing scrutiny in the last year over its role in securing pipelines.
Last June, the Houston Chronicle published an op-ed by FERC Chairman Neil Chatterjee and Commissioner Richard Glick that called on Congress to move responsibility for pipeline security from TSA to “an agency that fully comprehends the nation’s energy sector and has sufficient resources to address the growing cybersecurity threat to gas pipelines.”
The Government Accountability Office issued a critical report in December that noted TSA’s Pipeline Security Branch had only six full-time equivalent employees watching over more than 2.7 million miles of natural gas, oil and hazardous liquid pipelines.
In January, the U.S. Intelligence Community’s Worldwide Threat Assessment warned that Russia and China can launch cyberattacks that cause “localized, temporary disruptive effects on critical infrastructure,” such as pipelines. (See GAO Critical of TSA Pipeline Security Efforts.)
At a Senate Energy and Natural Resources Committee hearing on energy cybersecurity in February, some senators questioned whether Congress should give the pipeline job to a different, energy-focused agency. (See Senators Call for Urgency on Energy Cybersecurity.)
The GAO report suggested TSA’s pipeline role has been neglected by the agency in favor of airport security, a conclusion TSA Administrator David Pekoske did not dispute at Thursday’s hearing.
One of the criticisms of the GAO report was that “the agency has a detailed allocation plan for strategically aligning resources to screen passengers at TSA-regulated airports, but not for the entire agency.” Pekoske said that currently, all the agency’s inspectors, including those designated for surface transportation, are on the staffs of the 440 airports under TSA jurisdiction. “But we’re going to make a change to that,” he said.
Pipeline is one of the six modes of transportation under TSA’s jurisdiction, along with Aviation, Freight Rail, Highway & Motor Carrier, Postal & Shipping, and Mass Transit, according to the agency’s Cybersecurity Roadmap.
Pekoske also said he was consolidating the agency’s multiple “policy shops” into one. “I think there is a lot to be learned from security in other sectors that apply across the board, so all of our policy is going into one place.” He said he is also establishing regional offices co-located with the Federal Emergency Management Agency in New York City, Atlanta, Chicago, Dallas and Seattle.
“We already have a [regional presence] in place right now; it’s primarily purposed to support our aviation security mission,” he said. “I’m repurposing that … to advance the surface transportation security mission and also advance our contingency and planning response capability.”
Another criticism of the GAO report was that TSA lacked a strategic workforce plan to identify the skills required of its employees, such as cybersecurity expertise. Pekoske said the agency was “working very hard on” investing in staff with cybersecurity expertise. It currently relies on DHS’ Cybersecurity and Infrastructure Security Agency, “but it’s my desire to have specific, industry-related cybersecurity expertise within TSA,” he said.
“We believe TSA has both the tools and the authority to address any threats within the pipeline industry,” said Sonya Proctor, the agency’s assistant administrator of surface operations. “As a result of the realignment of resources that the administrator has undertaken, we’re going to be able to increase the number of personnel focused on pipeline security, which means we will have a presence in the pipeline community on a very regular basis.”
Though TSA has the authority to issue mandatory standards, its voluntary Pipeline Security Guidelines “provide us the flexibility to address threats outside of the time-consuming regulatory process, which could conceivably take months or even years to go through,” Proctor said. She also noted that as administrator, Pekoske has the authority to issue mandatory directives to pipeline companies in the event of an emergency or serious threat.
Pekoske urged those listening to visit the agency’s website and view its 2018-2026 Strategy and Administrator’s Intent. Neither of these documents, however, specifically mentions pipelines.
Neither Pekoske nor Proctor mentioned current staffing levels, or how many people would be added.
Questions of Standards
TSA published the documents Pekoske mentioned shortly before the Chatterjee-Glick op-ed. Chatterjee has backed off somewhat on the recommendation that pipeline security be reassigned, telling senators and the National Association of Regulatory Utility Commissioners that he had been impressed by Pekoske’s and the industry’s efforts since the article’s publication.
“TSA and industry should have an opportunity to better address cybersecurity concerns on a voluntary basis before anyone imposes mandatory cybersecurity standards for gas pipelines,” he said Thursday.
Glick pressed Proctor about how the agency prioritizes its pipeline oversight. According to the GAO report, TSA takes the top 100 critical pipeline systems, ranked by the volume of fuel transported a year, and re-ranks them through a risk assessment that calculates threat, vulnerability and consequences to determine their priority in getting reviewed.
“Putting aside the 100, what do you do with regard to the rest of the pipeline system around the country, including the distribution pipelines?” Glick asked.
Proctor said that the agency isn’t limited to the top 100 when it conducts its reviews, “but clearly we’re looking at risk, and we’re looking at the resources we have to apply to that risk so that is where our focus is first.” She said the agency will have the capability to review more than the top 100 with Pekoske’s resource realignment.
The GAO report said that operators of at least 34 of the top 100 had identified no critical facilities, speculating that this was because TSA’s guidelines lack a clear definition of the criteria to determine facilities’ criticality. Glick asked Proctor if the agency only did reviews of pipelines that had identified critical facilities.
“That is the language in the Pipeline Security Guidelines, and that’s something we continue to discuss with the pipeline systems, so that’s an area we continue to work with,” Proctor responded.
Glick also asked Don Santa, CEO of the Interstate Natural Gas Association of America (INGAA), why the industry doesn’t support mandatory standards.
“INGAA thinks the current collaborative model with the Transportation Security Administration works well, and in fact it is improving,” Santa replied. “We think that, as Assistant Administrator Proctor described, it enables us to be more agile and reacting quickly to things than if we were in a mandatory situation. …
“Let’s focus on improving [TSA’s work], making it better [and] getting it to be what it can be, rather than on changing the model,” he concluded.
NERC CEO Jim Robb was noncommittal over whether there should be mandatory pipeline standards.
“The gas system and the electric system are so intertwined right now from a reliability perspective that the gas system has to have at least equivalent secure reliability to serve its needs as the electric system that’s built on top of it,” he said in response to a question from Glick. “So, whether it’s through a mandatory standards regime or some other regime than what TSA is doing today or just through the work that TSA is doing, I don’t really care so much about that. What I do care about is making sure that the gas is there when we need it.”
CARMEL, Ind. — MISO may have to contend with security concerns, communication constraints and even the eventual phaseout of the vertically integrated utility model as it strives to manage a grid with growing amounts of distributed energy resources.
Those possible scenarios were laid out March 26 at the latest in a series of educational workshops hosted by the RTO and the Organization of MISO States. The events are a precursor to MISO bringing discussion of DER market rules to its stakeholder process.
The first workshop on DERs in late January was cut short by a dangerous cold snap that knocked out power to MISO’s Carmel headquarters. (See Cold Snap Halts DER Talk as MISO Calls Max Gen Event.) The RTO has planned two additional workshops more technical in nature for April 9-10 and April 17-18.
Located far from the coasts, the Midwest and South are typically slow to take up new energy trends. MISO has a relatively low level of DERs on its system, with a 2018 OMS survey finding about 2.6 GW (compared with about 6 GW in the geographically smaller CAISO footprint). But Bob Shively, president of training firm Enerdynamics, said MISO’s volume is “significant” and predicted that DER will grow — albeit lopsidedly — based on state politics and regulation.
MISO DER Program Manager Kristin Swenson said it’s appropriate for discussions to happen now, even if adoption is currently relatively low.
“The rate of change seems very slow until it happens all at once. … Political, regulatory changes happen quickly, and it takes a long time to prepare,” Swenson said. “Now is the time to be looking at what’s going to be five years, 10 years away.”
Shively said DERs are fast becoming economic: “There’s this distinct possibility that DER penetration is happening very quickly out there, and it will have impacts on the bulk electric system.”
T&D Communication
Shively said MISO and its members must now figure out how to improve communication at the transmission and distribution interface to increase visibility and determine what wholesale market changes are needed to include aggregated DER.
“There’s going to be a coordination and discussion that never took place in the past,” Shively said, adding that metering DERs will one day become a “necessity.” He said the distribution grid will likely become a data monitor and automated system in addition to a power delivery system. Distribution operators may soon be scheduling generation, Shively said, or form distribution-level system operators to optimize the use of DERs. He also said MISO may need to devise a special interconnection agreement for DER aggregations.
“This is not going to happen overnight, but there are some models being talked about out there,” Shively told stakeholders.
Currently, MISO has neither visibility nor situational awareness about the location or output of DERs in its footprint, and management thinks it possible that FERC will issue rules on the treatment of DERs this year. The grid operator also predicts that DERs will require “new gird management protocols” as the transmission grid, distribution grid and end users begin flowing energy between one another, deviating from the traditional pattern of one-way flows.
But Shively said changes to incorporate DERs must be made thoughtfully, with special attention on system frequency, voltage and resource adequacy.
“When we’re planning the system, the No. 1 thing is we don’t want to break the system,” he said. “So if we’re bringing DERs on … we want to make sure that we’re not doing things to damage our equipment.”
He said to maintain frequency, utilities can control generation and might someday control even load courtesy of smart devices.
Shively also pointed out that there’s no dollar value placed on reactive power to control voltage and no incentive to provide it. “Unless you want to be a good corporate citizen,” he chuckled. He added that voltage instability will likely be localized and managed on the distribution circuit and said frequency issues are the bigger threat to the grid.
‘Points of Entry’
Stakeholders pointed out that DERs open the question of what generation falls under NERC Critical Infrastructure Protection standards. Shively said DERs open new “points of entry” to the grid. He said it’s possible that hackers could access controllable home systems.
But he also pointed out benefits, saying DERs could potentially provide black start services to restore the grid from blackout.
Stakeholders asked about the difference between a DER and a more energy efficient refrigerator, when both serve to reduce load.
“It starts to get really fuzzy: What is a DER and what isn’t a DER. … So the answer is, it’s a fuzzy line, not a fine line,” Shively said. “Is a Nest thermostat that changes your temperature a DER, or is it just customer behavior?”
Shively said MISO will have to keep in mind that its DER supply mix will directly result from state processes, but it’s up to the RTO to plan the system and model load. That will prove difficult for grid operators that lack visibility of DER behavior, he said. Shively said MISO should also consider that line maintenance can take multiple DERs out of service.
Minnesota Public Utilities Commission staff member Hwikwon Ham recommended MISO differentiate its future operational concerns from its planning reserve concerns regarding DER integration. The RTO has said it may have to rethink its planning reserve margin as resource availability shifts. (See MISO, Stakeholders Debate Merits of Seasonal Auction.)
Others’ Load
WPPI Energy economist Valy Goepfrich observed that the MISO system only seems to encounter complexities when a DER owner goes from serving its own load to serving others. She asked if MISO might only have to make changes when groups of DERs enter the wholesale market en masse.
But Shively said even when customers choose to serve their own load with DERs, load modeling becomes a problem. He said under that scenario, data exchanges will still be needed between distribution and transmission.
“I think you’re right; it’s probably a spectrum” of grid preparation based on DER use, Shively said.
Shively also said that once new guidelines for visibility and control are in place, MISO members can’t assume that existing communications systems will be adequate. He pointed to rural areas that lack high-speed internet.
But he said the DER discussion is reminiscent of the fears he heard when utility-scale wind and solar were being integrated into the system. However, he allowed that the question of generation on the distribution level muddies the regulatory waters.
Vertical Integration
Stakeholders asked how increasing use of DERs would interact with the largely vertically integrated utility model in the MISO footprint.
Shively paused. “That’s a great question.” But, after a beat, he said, “I think that there’s going to be more pressure for customers to have retail choice. … I would contend you can go down the road for a while without retail choice, but the more you crack open the door…”
He trailed off, later adding that companies like Google and Amazon might lead the way on pushing for supplier choice.
At the end of day, Shively said, the difficulties of absorbing DERs into the market should prove worth the effort.
“We can come up with lots of problems with implementing DERs, but we also have to remember there’s a lot of potential,” he said. “I think, long-term, DERs can provide low-cost reliable service to customers. That’s the goal of what all this should be.”
