FERC on Thursday granted PacifiCorp a stay on the commission’s March 15 order regarding an application to partially transfer the company’s license for its Klamath Hydroelectric Project to the Klamath River Renewal Corp. (Project Nos. 2082-065, 14803-002).
The 169-MW Klamath project (No. 2082) is located in Oregon and California and includes federal lands administered by the U.S. Bureau of Reclamation and U.S. Bureau of Land Management. The project consists of eight developments, seven with hydroelectric generation.
Klamath River Project John C Boyle Dam
In September 2016, PacifiCorp and the Renewal Corp. proposed that the existing license for the project be amended to remove four developments and place them into a new license for the Lower Klamath Project (No. 14803), to be held by the Renewal Corp.
The application was made in accordance with the Klamath Hydroelectric Settlement Agreement, signed in 2010 and resigned in 2016 by all concerned parties, including the Yurok and Karuk Tribes, to resolve disputes over PacifiCorp’s efforts to relicense Klamath.
The Renewal Corp. also filed an application to surrender the Lower Klamath Project license and physically remove those four developments from the river, contingent on the commission’s approval of the amendment and transfer application.
‘Duplicative and Wasteful Work’
In its March 15 order, the commission found that “transferring a project to a newly formed entity for the sole purpose of decommissioning and dam removal raises unique public interest concerns, specifically whether the transferee — the Renewal Corp. — will have the legal, technical and financial capacity to safely remove project facilities and adequately protect project lands.”
The commission thus “authorized only the administrative amendment of the license for the Klamath project, effective as of the day the order was issued, such that PacifiCorp would remain the licensee for both the Klamath project and the Lower Klamath Project until we receive certain additional information.”
In its motion for a stay, PacifiCorp stated that compliance measures associated with dividing the Klamath project into two separate licenses could exceed $3.1 million.
PacifiCorp argued that requiring it to complete the license amendment compliance “would result in duplicative and wasteful work” in the event the license transfer is subsequently approved and the Renewal Corp. is required to undertake the same tasks. Alternatively, PacifiCorp stated that the measures would serve no purpose and may later need to be reversed in the event the transfer is not approved.
FERC stayed the order pending its ultimate ruling on the license transfer. “PacifiCorp’s arguments demonstrate that justice requires a stay,” the commission’s June 21 order said.
The commission also dismissed PacifiCorp’s alternative request for rehearing as moot.
The board voted unanimously to appoint Currie at its June 21 meeting after discussing her credentials and nomination in closed session a day earlier. As a rule, MISO considers all personnel-related matters to be confidential.
Currie is the second woman and first African-American woman to chair MISO’s board since it was established in 1998. Former Director Judy Walsh was the first woman to chair the board during her tenure from January 2016 to December 2017.
“I hope that I will perform in a manner that will bring continued pride in the MISO community,” Currie said upon accepting the position during a June 21 board meeting.
“I will be immediately instructing you on the Philadelphia sense of humor, and you can have my watch,” Curran joked.
Currie is one of three directors whose three-year term concludes at the end of this year. Along with Mark Johnson, she will be up for re-election for a second term. Curran will reach MISO’s three, three-year term limit at the end of 2018 and is not able to seek re-election.
Director Baljit Dail reported that the RTO’s Nominating Committee will begin vetting and interviewing candidates for the board starting in August.
MISO Expects Year-end Budget Overrun
MISO expects to end the year about 1% over its operating budget, the board heard. Chief Financial Officer Melissa Brown said the RTO is forecasting $267 million in spending this year, about $2 million more than its total budget.
Brown said the overrun would stem from spending on computer maintenance and reclassifying some outlays from its capital budget to its operating budget. MISO also expects to spend just $25.6 million of its $29.6 million capital budget by the end of 2018.
Year to date, MISO has spent $108 million of its $109 million operating budget and $11.4 million of its $15 million capital expense budget. Brown attributed the underspending mainly to delayed investment timing in the operating budget and delayed and decreased technology spending in the capital budget.
New York officials on Thursday outlined how the state plans to add 1,500 MW of energy storage by 2025, a target set by Gov. Andrew Cuomo in January.
Lt. Gov. Kathy Hochul, who announced the release of the Energy Storage Roadmap in Queens, said it “represents the next crucial step forward to tackle climate change and further develop our clean energy economy.”
“Clean energy is the future of our planet, and New York will continue to lead the nation in this technology to fight climate change and conserve resources for generations to come,” Cuomo added in a statement.
In his annual State of the State address in January, Cuomo directed the NY Green Bank to invest $200 million to meet the 1,500-MW target — equal to the demand of one-fifth of New York homes. Cuomo also directed the New York State Energy Research and Development Authority to invest at least $60 million in storage demonstration projects and efforts to reduce barriers to deploying energy storage, including permitting, customer acquisition, interconnection and financing costs. (See Cuomo Pushes Clean Energy in Annual Address.)
A scenario, informed by project economics and market sizing estimates, shows customer‐sited, distribution system and bulk system storage each reaching 500 MW by 2025. | NYSERDA
Developed by NYSERDA and the Public Service Commission, the Roadmap groups storage deployment into three market segments — customer‐sited, distribution system and bulk system — based on where the storage is located and the needs it serves. In bulk system deployments, energy storage can be a firming resource when paired with large‐scale intermittent renewables, can replace or complement peaker plants, and potentially defer transmission investment.
The Roadmap recommends providing $350 million in statewide market acceleration incentives to fast-track the adoption of advanced storage systems for customer sites or on the distribution or bulk electric systems.
The state has approximately 60 MW of advanced energy storage capacity deployed now, with another 500 MW being planned to add to the existing 1,400 MW of traditional pumped hydro storage.
The New York Power Authority is working on several energy storage projects to demonstrate the value of the technology, including work on multiple projects with the State University of New York. The SUNY New Paltz campus, for example, this spring completed a solar energy and battery storage system, and state officials plan a similar system at the SUNY Delhi campus.
Chart shows peak and off‐peak E Values. E Value is defined as the higher of the the social cost of carbon or Tier 1 renewable energy certificates under the Clean Energy Standard, net of expected Regional Greenhouse Gas Initiative allowance values. | NYSERDA
New York will also add incentives for energy storage to NYSERDA’s successful NY-Sun initiative and plans regulatory changes to utility rates, utility solicitations and carbon values to reflect the system benefits and values of storage projects.
The state also will consider recommending modifications to wholesale market rules to enable storage participation, including allowing storage to meet both electric distribution system and wholesale system needs to provide greater value for ratepayers, NYSERDA said.
NY Green Bank has released a Request for Information to solicit interest from project developers for its $200 million investment.
The Roadmap begins the public input phase of the PSC’s storage proceeding, which will include multiple technical conferences to allow for feedback on recommendations and approaches identified (18-E-0130). Public comments on the Roadmap can be submitted via the Department of Public Service’s website.
INDIANAPOLIS — MISO could ensure sufficient energy supply by improving demand response rules, devising a storage participation model and better coordinating outages, among other efforts, Advisory Committee members said last week during a “hot topic” discussion on resource adequacy at the RTO’s Board Week.
The RTO has declared 12 maximum generation events since June 2016 — nine of which occurred in winter and shoulder-season months. That represents a sharp increase from the past pattern of one event “about every two years or once a year,” said MISO Chief Customer Officer Todd Hillman, who moderated the discussion during a June 20 Advisory Committee meeting.
Hillman said the RTO is looking to abandon the standard that it has adequate resources on hand if it can reliably serve load during the one summertime peak hour of the year “when air conditioners run hard.”
Vistra Energy’s Mark Volpe, of the Independent Power Producers sector, said he wasn’t certain how much of MISO’s 12 GW of DR will respond to dispatch signals during maximum generation events. A MISO report last month showed that load-modifying resources underperformed during a mid-January emergency, and the RTO has signaled it will reconsider its rules for LMR participation. (See “LMR Performance in January,” MISO Mulls Additional Emergency Communication.) In 2017, 9% of the capacity load-serving entities committed to the forecasted summer peak consisted of emergency-only resources, MISO has said.
“I think we agree that LMRs have value, and a lot of these processes were designed before MISO was in existence,” said WEC Energy Group’s Chris Plante, representative of the Transmission-Dependent Utilities sector. “Right now, we have an annual resource adequacy construct. … Do we need to look at a more granular resource adequacy construct to respect the temporal nature of LMRs?” he asked.
Representing MISO’s End-User Customers sector, Kevin Murray of the Coalition of Midwest Transmission Customers said the RTO should switch from negative to positive reinforcement for DR performance.
“If MISO is getting to the point where it thinks its current Tariff structure is not blending well with operational needs, well, it needs to look at positive rewards,” Murray said.
MISO could employ a practice where resources agree to voluntarily remove load from the system when prices reach a certain level. He also said the RTO could improve its communication with state commissioners on resource adequacy efforts.
“You’re not going to change behavior until MISO communicates what it needs,” Murray said of LMR performance.
Madison Gas and Electric’s Megan Wisersky said LMRs were originally designed to address capacity emergencies but are now being called on to solve transmission emergencies.
“You have LMRs that have to be available at 2 a.m. on a Sunday now,” Wisersky said. “You’re asking them to do something they weren’t designed to do.”
She also criticized the MISO Communications System — where LMRs report their emergency availability — for being “hard to use” and inflexible.
Hillman asked where distributed energy resources fit into efforts to manage load in tight capacity conditions.
Murray said he saw a place for DERs in controlling load. “How many Nest thermostats does it take to offset a 1,000-MW gas unit?” Murray asked rhetorically. “It’s a crop that’s ready to harvest. It just needs the pickers.”
Great Plains Institute Policy Associate Matt Prorok, the Environmental sector representative, said he agreed DERs could unlock value by “shaving loads, shifting loads and shimmying loads.”
More Outage Control?
Hillman pivoted the discussion.
“OK, increasing outages,” he said. “What do we do?”
Multiple committee members said MISO should discount outages from capacity performance.
“Don’t we do that already?” Hillman asked, referencing the three years of generation data MISO uses to produce unit-specific forced outage rates.
Plante suggested MISO include in the rate planned and maintenance outages, in addition to unplanned outages.
Stakeholders also repeated a longstanding suggestion that MISO give itself a stronger role in outage coordination, perhaps with the authority to approve outages.
But Michigan Public Service Commission Chairman Sally Talberg said the Organization of MISO States does not support the RTO having authority over outage scheduling.
MISO Director Phyllis Currie asked if generation and transmission owners were communicating enough about the conditions of their resources to the RTO so it can better predict when and where outages will occur.
“Generation doesn’t take outages because they want to be out. They take outages because they want to be on,” Murray said. PJM provides more forward-looking information about resource need than MISO, he said, noting that last week the Mid-Atlantic grid operator issued a hot-weather alert for its footprint with a request that asset owners wrap up outages early, if feasible.
“We didn’t see a similar hot-weather notice” in MISO until two days later, Murray said. He added the notice was another example of the positive reinforcement he advocates: Generation owners could reap higher prices if they come online in a hot-weather, high-demand situation.
Wisersky agreed that MISO should communicate when it most needs equipment to return online.
Energy Storage
OMS President and Arkansas Public Service Commission Chair Ted Thomas said storage can help address resource availability issues.
“Storage is crazy flexible. It’s the most flexible thing I’ve seen,” Thomas said.
However, he thinks MISO and regulators should create rules to ensure storage has a monetary value in the market.
“FERC can’t do it all in wholesale, and we can’t do it all in retail,” Thomas said of creating compensation rules. “Who is going to do the aggregation? These questions are really complex.”
LS Power’s Pat Hayes, of the Competitive Transmission Developers sector, said a storage asset in MISO cannot currently generate enough revenue as a standalone resource. He said it should find ways to value storage resources as both a transmission facility and generation asset.
MISO is currently examining how storage resources can function as reliability transmission projects in its annual Transmission Expansion Plan. It is also considering permitting storage resources to bypass the interconnection queue when the resources will be used exclusively as a transmission asset.
‘One Thing’
“If there’s one thing MISO could be working on, what would it be?” Hillman asked, pointing at Advisory Committee members around the panel.
“Creating flexibility for the future — getting all resources on a level playing field. I can’t minimize how difficult that is, but clearly the evolving future requires it,” said Alcoa’s DeWayne Todd.
“Challenge MISO’s current planning assumptions to see if they reflect reality,” Exelon’s David Bloom responded.
“We need to take a hard look at policy associated with resource adequacy,” Plante said.
“Enabling competition among all resources,” Prorok added.
INDIANAPOLIS — MISO’s multiyear effort to replace its market platform will likely come in slightly over budget and is at risk of delay because of project snags with vendor General Electric, the RTO’s Board of Directors learned this week.
MISO now expects it will fully migrate to the new modular market platform by 2024, about a year later than it initially projected in 2017. The project’s cost is predicted to increase from $130 million to just under $134 million. (See MISO Makes Case for $130M Market Platform Upgrade.)
The platform replacement was discussed in multiple committee meetings during MISO Board Week.
Todd Ramey, MISO vice president of market system enhancements, said current platform vendor General Electric reported a “significant increase in the work requirement” in early May. Kevin Caringer, executive director of MISO’s IT team, said the RTO recently determined that GE was “too optimistic” in its original timeline, especially concerning estimates on the complex software needed to clear the day-ahead market. He acknowledged that GE got off to a “slow start” in recruiting and hiring staff for the project in 2017 and estimated the company is about five or six months behind schedule.
“We did express our disappointment” in response to GE’s proposed timeline, Caringer said, adding that MISO is working with PJM and ISO-NE to consider a counterproposal to GE’s timeline. The modular platform’s design is being jointly developed with those RTOs, which also use GE-designed platforms. (See MISO Sets Target for Market Platform Upgrade Decision.)
Although MISO executives said the RTO will likely have to adjust timelines for the remainder of the project, they maintain the overall replacement effort remains “generally on target.”
Sunk Costs
A separate third-party vendor was this year expected to deliver a development and testing platform to evaluate new components from GE. MISO now says that plan “is at risk of minor delays beyond July 31 due to vendor negotiations and lead time needed.”
Caringer said he thought MISO could meet its self-imposed 2018 deadline on the testing platform, but he added the RTO “used up a lot of [its timeline] flexibility in negotiations” with the third-party vendor.
Director Baljit Dail pointed out that MISO’s original $130 million budget provides for an additional 20% in contingency funds for unforeseen expenses.
“In the event that things happen — like they’re happening now — we have that buffer,” Dail said.
Director Theresa Wise asked how much in sunk costs MISO would risk if it decided to switch vendors at this point. Executives estimated the RTO has so far spent $2 million to $3 million with GE on developing the platform.
Soon after the question, MISO lawyers said that any discussion on alternative plans should be saved for closed session. Multiple directors responded that they would reserve more specific questions about vendor performance for a closed meeting.
Dail later reported that the board had a robust, nonpublic discussion on GE’s performance.
“General Electric’s woes are being well publicized; they’ve recently dropped out of the Dow Jones. We need to send a strong message to GE and its management because they are critical in this path. … I think we’re all very concerned, and I think we need to send a strong message that they need to step up their game,” Dail said during a June 21 board meeting.
“Could you convey at least one director’s disappointment … in the primary vendor?” Director Thomas Rainwater asked MISO executives during the same meeting.
Board Chairman Michael Curran said the situation was not unlike the adjustments made while developing transmission projects.
“You think you can understand what that vendor can do, you think you have a plan, but once you break ground, shifts may occur. They’re a natural part of the process, and we look forward to you managing it well,” Curran told executives at the end of the week.
MISO reported it is ahead of schedule on at least one aspect of the platform replacement: the hiring of extra staff for the project is occurring earlier than expected.
Caringer explained that the board previously expressed concern that skill shortages might cause delays in hiring technical talent. “While this risk is real, MISO has been able to attract the right skills so far, although this will continue to be a challenge.”
Limited Improvements for Old Platform
MISO reported again that its existing platform and new FERC directives are restricting which market improvements it can undertake.
Executive Director of Market Development Jeff Bladen said about a third of projects under the RTO’s Market Roadmap cannot be implemented because the existing market platform cannot manage the complexity required for the improvements.
However, MISO said it would complete at least two projects on its legacy computer system: 1) the creation of a short capacity reserve market by early 2020 that can deliver reserves within 30 minutes (a Market Roadmap item); and 2) compulsory compliance with FERC Order 841 to create a participation model for energy storage by late 2019.
MISO said other market system-dependent changes on the Market Roadmap will be deferred until the new platform can accommodate them. The deferral includes the plan to create a more sophisticated model that can mimic different combinations of combined cycle units and their dependencies. The project had previously been planned for implementation on the legacy system.
Bladen also explained MISO is not currently planning to implement an integration model for distributed energy resources on the legacy system. He said staff have been in contact with FERC since an April technical conference to explain that the RTO’s footprint doesn’t contain enough growth in DERs to warrant a significant rule change just yet. MISO will be able to transition technology platforms before the need for DER rules emerges, he said.
Dail thanked MISO for the analysis. “This is a very, very complex needle that we’re trying to thread,” he said of undertaking improvements as the platform replacement unfolds.
“It’s almost like there’s a new criteria [for market projects]: impacts to the legacy platform,” Curran said.
MISO President Clair Moeller agreed that it is a balancing act to select market design improvements while not “distracting from the market system enhancement.”
Meeting with Members’ CIOs
MISO has also begun holding biannual nonpublic meetings with member companies’ chief information officers to discuss cybersecurity, NERC critical infrastructure protection and adaptation to the new platform, among other technology issues.
MISO Chief Information Officer Keri Glitch said CIOs and chief information security officers from nine member companies attended a second meeting in St. Paul, Minn., in mid-May.
Glitch said MISO will hold another meeting of the group, now called the CIO/CISO Technology and Security Advisory Council, in St. Louis sometime in November.
CAISO’s Board of Governors on Thursday approved controversial revisions to the ISO’s congestion revenue rights auction to address what some stakeholders contend are inequitable results and shortfalls for electricity consumers stemming from the CRR process.
The five-member board unanimously approved a second round of changes to the CRR auction, long a subject of controversy over what the ISO’s Department of Marking Monitoring has called out as consistently unfair outcomes to electricity ratepayers who have been require to foot about $100 million per year to make up for auction revenue shortfalls since the auctions began in 2012.
The new changes, known as “Track 1B,” focus on the revenue adequacy issue. The board in March had approved the “1A” package of changes focused on auction efficiency, which are now under review at FERC. (See CAISO Moves Ahead With Market Changes.) CAISO wants to implement both proposals in time for the 2019 CRR auction in fall of that year.
CAISO CEO Steve Berberich noted that the board had called a special meeting to approve the changes, saying it “clearly shows the importance to all of us.”
The 1B changes alter the current process in which all revenue inadequacy is allocated to measured demand, which includes electricity load and exports. That process does not consider the location of constraints on the system and creates an incentive to profit from differences between the CRR auction model and the day-ahead market model, according to Greg Cook, CAISO executive director of market and infrastructure policy, who presented the ISO’s findings to the board.
Under the new partial funding model, revenue inadequacy will be allocated to CRR holders in proportion to their flow over each constraint. Holders will receive day-ahead market payments aligned with available transmission capacity, which should result in a more equitable allocation on a locational basis.
A second component of the changes reduces the amount of system capacity released in the annual process from 75% to 65%. This will provide greater assurance that CRRs obtained in the annual process will be feasible in the monthly process and will reduce the amount of payment reductions resulting from revenue inadequacy charges, CAISO Vice President of Market and Infrastructure Development Keith Casey said in a memo to the board.
The DMM, the publicly owned Six Cities utilities of Southern California and the California Public Utilities Commission support the changes. Other parties said they go too far and that the impact of previous changes should be considered first.
The ISO will provide information on the outcome of the changes in its market reports to help ensure transparency, Cook said. The changes had received resistance from financial traders who argue the current structure allows for legitimate hedging activity. (See CAISO Developing New CRR Proposal.)
At a separate meeting on Thursday, the leadership of CAISO’s Western Energy Imbalance Market confirmed a new member and made other changes as Chairman Douglas Howe prepares to leave the body at the end of this month.
The EIM’s Governing Body approved a nominating committee’s selection of Montana Public Service Commission Vice Chairman Travis Kavulla to replace Howe as a member effective July 1, for a three-year term. The body named current member Valerie Fong as chair, and re-nominated current member Carl Linvill as vice chair, both effective for one year. Linvill was also approved for a second three-year term.
Kavulla is the first new member named to the body since the original members were selected in June 2016 to oversee the regional energy trading market. The other two members of the body are John Prescott and Kristine Schmidt, whose terms end in 2019 and 2020, respectively.
Planned additions of renewable generation and storage will not compensate for gas retirements in the Western Interconnection, and any major disruption to gas supply would push the system “to the limit,” a new reliability assessment says.
Analysis by the Western Electricity Coordinating Council showed that reserve margins are projected to be tight through 2026, driven by coal and nuclear retirements and increases in power demand. The report forecasts 30% growth in natural gas demand across the interconnection. WECC retained Wood Mackenzie, Environmental Economics and Argonne National Laboratory to undertake the gas-electric interface study.
“We are now effectively in an N-1 scenario with any major disruptions in the gas transmission system or the Bulk Power System pushing the system to the limit,” WECC said. The Salt Lake City-based organization is the NERC-certified Regional Entity for the West.
Restrictions at the Aliso Canyon gas field near Los Angeles — a facility that many want to shut down after a massive gas leak three years ago — have created a situation in which the failure of another large component on the grid could lead to reliability problems. The heavier penetration of renewables will increase reliance on natural gas for system peaks, and the amount of renewable generation needed to meet current state policy goals is not sufficient to entirely offset the loss of roughly 12,000 MW of baseload generation.
The study assumes retirements of about 9 GW of coal and 2 GW of nuclear by 2026 across the West, including major baseload plants in California, the Pacific Northwest and the Desert Southwest, and 9 GW of wind additions to reach 29 GW of total wind. Solar capacity is projected to double to 36 GW, with 18 GW added in California. Total load in the interconnection is project to grow by 7% by 2026.
WECC says system reserve margins are expected to be tight through 2026 | WECC
The report recommends improved regional coordination, including planning exercises, and more transparency around firm gas supply contracts and the power plants they serve. It also suggests designation of specific plants as critical to core reliability, and that there be more clarity around interstate gas curtailment protocols.
While historical natural gas resources have been sufficient, events over the past few years have tightened supply, including outages of Southern California Gas pipelines, a colder winter in 2018 and restrictions at Aliso Canyon. Other factors likely to drive up gas usage are the 2024 retirement of the Diablo Canyon nuclear plant and coal retirements in the Southwest and Northwest.
The CAISO Department of Market Monitoring recently said that tight gas supplies in Southern California drove up wholesale prices by 25% last year. SoCalGas recently told RTO Insider there is no timetable to bring back Line 235-2 in Southern California, which suffered a rupture last October, despite its status as a backbone facility and extreme price spikes of up to $12/MMBtu. (See CAISO Board Approves Forecast Error Measures.)
“Among other things, the report highlights a critical need to focus on better gas-electric coordination between the two sectors but also deploy a combination of solutions to ensure Western Interconnection system reliability,” WECC Vice President of Reliability Planning Melanie Frye said in a written statement.
The report said the region must have “broader conversations” about ensuring that critical power plants have fuel, improving regional coordination around gas supply contingencies and better forecasting, as well as improved response by local distribution companies to curtailments.
HOUSTON — Ordinarily, the power sector would eagerly welcome a coming wave of efficient combined cycle generation, especially when the government has set goals to increase the number of clean energy resources.
But that is not the case in Mexico, where the aging transmission infrastructure is having trouble handling the current generation, let alone what is coming.
“In Mexico, the closer you are to the U.S. border, the greater reliability you have,” Al Garcia, an adviser to public and private sector energy companies in Mexico, said earlier this week during a meeting of the International Society for Mexico Energy (ISME).
Garcia said 10 GW of combined cycle generation is expected to come online through 2020, but he noted that is only part of the problem. He said Mexico’s ISO, CENACE, which was created as part of the country’s electric market restructuring, is still a work in progress.
“It takes more than the engineering side to become an ISO,” he said. “You’re going to see that in the next few years as the combined cycle units come online.”
“The infrastructure is not robust enough in many places, so there are a lot of outages,” said Acclaim Energy Advisors’ Alberto Rios. “It’s a physical obstacle.”
Rios joined Garcia for a discussion before ISME, a nonprofit professional organization focused on Mexico’s energy sectors. The two shared their insights on the nascent Mexican market with a bilingual audience eager to learn more.
“A new market gives you the ability to pick and choose what you’re going to buy, and when,” Rios pointed out. “Some generators in the market can sell to suppliers or on the spot market. Right now, the pricing in the spot market is more favorable. Generators are seeing very competitive pricing.”
Competitive enough that qualified suppliers can find some contracts under the Federal Electricity Commission’s (CFE) transmission retail rates, Rios said. The state-run utility’s regulated rates dropped steadily to 6.4 cents/kWh in February, when a new transitory methodology was established. Rates have climbed 41% since to 9 cents/kWh.
“The effective rate methodology does not provide the guidance that the marginal cost of electricity will show up in that tariff,” Rios said. “CFE is going to have to recover that cost.”
CFE is known to keep its retail rates artificially low and to subsidize its residential consumers by charging the industrials more. To see rising prices in an election year is unusual, Rios said.
“Personally, I thought we would not have had that [increase] before an election,” he said.
The market is somewhat leery of frontrunner Andres Manuel Lopez Obrador, a leftist populist who has advocated keeping the country’s aging thermal plants online. Noting that 15 GW of new generation is expected to become available during the next president’s single six-year term, Garcia said he doesn’t expect to see any changes to the country’s deregulation.
“I don’t think that’s going to happen under a left-wing government,” he said. “What’s going to save them is the influx of new generation. It’s going to keep the prices down. They’ll be able to say, ‘Hey, look at our great policies!’”
Garcia believes Mexico will be long on generation in some regions because of the lack of infrastructure. The government has pushed for new generation, but it has also cited a need for $10 billion in transmission investment. It has two competitive projects out for bids, with more potentially to come. (See Land Rights a Challenge to Mexico Tx Developers.)
“Generation shouldn’t have a problem in a few years. We’ll start having healthier reserve margins once we get through the tough times we’re seeing right now,” he said. “But this is where [the Ministry of Energy] has to come out and be more proactive. Instead of talking about investment in new power generation, it should talk about challenges of going through private land ownership.
“That’s what it should be doing to create sturdier infrastructure on the electric side,” Garcia said. “Let the physical constraints work their way through system, and things should start looking better.”
INDIANAPOLIS — MISO is likely to face an increasing frequency of emergency conditions in the near future, and key officials participating in the RTO’s Board Week sought to understand exactly what’s behind the development.
MISO executives, the Board of Directors and the Independent Market Monitor dissected contributing factors like erratic weather, demand response rules and the RTO’s reserve margin. They also debated whether solutions could be found in the interconnection queue or capacity auction.
Directors were presented the results of the annual resource adequacy survey produced jointly by the RTO and Organization of MISO States, which predicts adequate reserves through 2019, but less certainty thereafter. Over the next five years, the footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall. (See OMS-MISO Survey Reveals Dimmer View of Future Supply.)
MISO Executive Director of Resource Planning Patrick Brown said that despite flat load growth, resource retirements and increased forced outages continue to drive up the planning reserve margin, which increased year over year from 15.8% to 17.1%.
Forced outages in MISO South are nearing 14%, compared with about 8% at the time Entergy was integrated in 2013. Brown said the outages will eventually abate as new capacity resources replace retiring generation.
“However, this new capacity will require time and transmission,” Brown said during a June 12 conference call of the board’s System Planning Committee ahead of the quarterly Board Week.
At a June 19 meeting of the board’s Markets Committee, Director Baljit Dail asked if MISO could simply discount the planning reserve margin to shave the probability of emergencies.
RTO President Clair Moeller responded that MISO is currently reconsidering its planning reserve margin altogether as emergencies become more likely in shoulder months.
“The question we’re trying to ask is, ‘How do we evaluate risk every hour of the year instead of those four to five days across summer peak?’” Moeller said. MISO has said its analysis shows that peaks will soon occur during any hour of the year, rather than simply during an annual predicted system peak period.
Queue to the Rescue?
New generation could boost MISO’s resource adequacy, with the RTO possibly seeing as much as 11.4 GW of new generation come online by 2023. Wind generation interconnection requests should taper off as production tax credits expire in 2020, but solar requests should rise as the cost of panels come down, according to Brown.
But a record interconnection queue could impede development of new generation. And while stakeholders typically blame MISO’s lengthy study process for queue delays, Brown said the “true bottleneck” can be found in the physical limitations of the RTO’s transmission system.
Brown said MISO requires billions of dollars in transmission upgrades to support the 93 GW of generation currently in its queue, something particularly true of the nearly 200 proposed projects in MISO’s West region (including the Dakotas, Minnesota, Iowa and part of Wisconsin), where proposed projects can become uneconomic when the costs of new transmission to support them are factored in.
MISO Vice President of System Planning Jennifer Curran said the RTO is also evaluating expanded use of bidirectional HVDC technology to manage the changing fleet and make the grid more interconnected with other RTOs.
Monitor: PRA Should Take Share of Blame
However, Monitor David Patton said he partly blames the increasingly tighter operating conditions on the annual Planning Resource Auction, which he thinks is discouraging construction of new generation. He called the recent $10/MW-day clearing price “near zero.” (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
“Our markets are telling us not to build anything,” Patton said. “This is why our competitive suppliers are doing whatever they can to export to PJM.” He again urged MISO to adopt a sloped demand curve in its capacity auction.
“This is the first I’m hearing that the market is not sending the right price signal,” Director Michael Curran joked, feigning shock to a roomful of laughter. “The price signal is the price signal, but there’s more than 90 GW sitting in the queue,” he added.
Patton said he remains unconvinced that all the proposed generation in the queue will come online.
“It’s very expensive to let lower-cost generation retire and be replaced with more expensive new generation,” he added.
Patton also said new natural gas generation set to come online in MISO South won’t really benefit MISO Midwest because it will be trapped behind the transfer constraint along SPP’s transmission link between the regions.
He also predicted that the larger amounts of DR cleared in this year’s auction will lead the RTO to call emergency alerts earlier and then possibly cancel them, as occurred during a mid-May near emergency. He also remains concerned that states won’t take sufficient measures to guarantee resource adequacy.
Dail, asked if the situation was really that dire.
“If it’s harder for you to sleep at night, then my mission is accomplished,” Patton responded.
Volatile Spring
MISO’s average load was 72.2 GW this spring, compared with 69 GW a year earlier, and staff attributed the uptick to volatile conditions that saw April temperatures well below normal and May well above. The RTO hit a 111.6-GW systemwide peak on May 29, compared to last spring’s 92-GW spring peak on May 16.
“April was much colder than normal, and we flipped a switch in May to much hotter than normal. … We skipped over spring,” said MISO Executive Director of Market Operations Shawn McFarlane. Compared to the last spring, average load increased about 5% for the quarter, and peak load increased a “pretty incredible 20%, with a few other days approaching similar levels,” McFarlane said.
“This quarter was bizarre,” agreed Patton. “On May 29, temperatures in Minneapolis hit 100 degrees.”
Patton said high temperatures that day forced the RTO to derate transmission and contributed to a local transmission emergency in the central portion of MISO Midwest. He praised RTO operators for successfully managing the transmission emergency.
“We had 15 straight days of heat in May. That will impact day-to-day operations,” said MISO Executive Director of System Operations Renuka Chatterjee.
However, energy prices were down about 3% from last spring, averaging $29/MWh. MISO credited the lower prices to fewer instances of congestion and lower natural gas costs compared to last spring. The RTO also set a 15.6-GW wind peak on March 31, breaking the previous Jan. 17 wind output record of 15 GW. Spring maintenance season brought 29 GW in outages, in line with usual seasonal trends, it said.
The unusually warm May (the hottest in MISO’s history) yielded an emergency alert declaration on May 11 (a Friday) for conditions projected for May 14 (a Monday). The RTO ultimately retracted the warning on May 13 as forecasts changed and later asked stakeholders if they preferred the earlier warning. (See MISO Mulls Additional Emergency Communication.)
McFarlane said MISO issued the alert “out of an abundance of caution.”
Curran asked if load-modifying resources (LMRs) were equipped to respond in that instance.
The LMRs reported they could have furnished about 750 MW had an actual emergency been declared, said Rob Benbow, MISO senior director of systemwide operations. McFarlane reminded the board that LMRs are only required to respond to summer emergencies. May’s near emergency would have fallen outside the required months.
In response to the high spring temperatures, McFarlane said MISO is now exploring the possibility of revising its seasonal forecast model from one that switches over based solely on the calendar to one that also considers weather forecasts one to two weeks out.
MISO predicts above-normal temperatures will continue into summer, especially for MISO South, leading to a higher peak load. The RTO now predicts a 121.7-GW peak load, about 1 GW above last summer’s peak. It also forecasts an 80% chance of deploying emergency resources this summer. (See MISO: Summer Reserves Adequate, but Emergency Likely.)
But calling up DR resources takes careful planning, RTO officials said.
“Many of them have an eight-hour lead time, so you have to see the emergency yesterday,” Moeller said.
Staff have signaled that the RTO will possibly seek rule changes for DR participation, part of a larger effort to address changing resource availability and need times.
“For about eight years, we’ve been recommending that load-modifying resources be moved up in the stack,” said Patton, who noted he has recommended repeatedly that MISO allow itself to call up LMRs at the earliest stage of its emergency process, giving those resources adequate time to generate by the time emergency conditions materialize.
MISO 2019 demand response and emergency procedures | MISO
Director Thomas Rainwater suggested that MISO consider separating its emergency resources into those that can be ready in four hours or less and those that require a longer lead time. He added he was “encouraged” by the idea that some non-traditional generation in the queue could function as more nimble reserves.
Ted Thomas, OMS president and chair of the Arkansas Public Service Commission, said Patton’s concerns about DR were overblown. He said all MISO states except Illinois have a legal obligation to ensure resource adequacy, and he expected the footprint to persevere despite the possible shortfall reported in the OMS-MISO survey.
“While we had some red in some areas of the chart, we’re not going to cruise along for the next five years until we hit a wall,” Thomas said at a June 21 board meeting. “I will be resting just fine, waking up early to work through these issues.”
VALLEY FORGE, Pa. — Calpine and American Electric Power are offering stakeholder alternatives to plans from PJM and its Independent Market Monitor for complying with FERC Order 842, which requires certain generators to provide primary frequency response.
Generation stakeholders have resisted proposals that would require existing units to provide PFR and any mandates that don’t include compensation for the service. (See Stakeholders Oppose PJM PFR Mandate for Existing Units.)
Calpine’s David “Scarp” Scarpignato explained the proposal at a June 19 meeting of the Primary Frequency Response Senior Task Force (PFRSTF). The plan hinges on requiring existing resources that provide PFR to continue doing so, along with the order’s requirement of new resources and any generators that must revise their interconnection agreements after making modifications to their facilities. The plan also calls for allowing any resources that aren’t able to fulfill their obligation to enter bilateral contracting with resources that can.
Units entering into such contracts would have to alert PJM annually. Calpine’s proposal would also require that units be able to both ramp up and down to respond to frequency changes. Just like today, PJM would have the ability to dispatch units to ensure the necessary flexibility of output. Units would also be compensated for their lost opportunity costs, especially during system restoration.
PJM has filed request for clarification on whether Order 842 was meant to include both new and existing resources. The RTO argues it does.
“A lot of the PJM way of doing this thinks that there will be natural headroom on the system,” both up and down, Scarp said. “Those are not my presumptions. Those are the presumptions that must be made under the PJM proposal for it to work. They are not directing anywhere in their proposal to create real-time headroom for primary frequency response. They’re assuming it naturally occurs,” he said. “This proposal is not a small change. It requires a significant amount of work and also encompasses more recordkeeping.”
His plan didn’t contemplate any market transactions beyond the bilateral contracting, he said, because he “didn’t see a ton of dollars” in it, but he would be open to supporting any proposals that do want to address development of a market mechanism.
Locational Issues
In response to criticism that his proposal didn’t address the importance for PFR of units’ geographic location on the grid, Scarp said his proposal, like the others, relied on “expecting diversity of location with new megawatts.”
“I think the locational issue is a significant issue, and it’s not being addressed in the matrix in a very good way under any of the proposals. … I would not be surprised if five years down the road, we reconvene to start talking about locational issues, but right now there are no locational requirements,” he said.
PJM’s Vince Stefanowicz said the RTO’s plan is intended to address locational issues and expressed concern about Calpine’s bilateral contracting idea because during a restoration event, “we really don’t know where the system is going to break up and island,” and “we have to make sure that units in [those] areas have the [PFR] capability.”
Resource connections
Scarp suggested that a second stage of the proposal address units that are interconnected via wholesale market participation agreements (WMPAs), a concern that GT Power Group’s Dave Pratzon also expressed. That phase would examine “not whether to do it [require WMPA resources to provide PFR], but how to do it,” Scarp said.
He said he’d received comments that the package should treat all resources equally, including energy efficiency and demand response, but he acknowledged concerns that adding the necessary inverters to such projects might be infeasible because they don’t inject power into the grid and don’t have WMPAs.
“It seems like a stretch,” CPower’s Bruce Campbell said. “I suspect the commission would consider that a substantive barrier to entry” to require all resources to have to install an inverter, he added. FERC included distributed energy resources in Order 842 because it believed they already needed such inverters, but doing so for DR and EE would be trying to “add capability that just isn’t there,” he said.
“If you require an EE resource to have an inverter, you won’t have any EE resources,” he said.
PJM’s Glen Boyle, who facilitates the PFRSTF, seemed to agree.
“By definition, I don’t know how EE could provide PFR. I don’t know technically if that would be capable,” he said.
AEP Proposal
Under AEP’s proposal, units that already provide PFR would be “encouraged to continue to do so” and can seek compensation at FERC. Units would annually confirm whether they will continue to provide the service, and PJM and transmission owners would revise system restoration plans accordingly.
A company representative attempted to dispel “public assertions by PJM” that AEP’s proposal might “dismiss the important requirement of having primary frequency response during system restoration” by explaining that it “focuses the system restoration conversation where it should be, with transmission owner/operators/PJM and individual generators.”
If a TO discovers it has “inadequate” PFR in its zone, the proposal calls for issuing a request for proposals “so that the most efficient resources, that actually want to provide the service, can participate” in “the most cost-effective mechanism for obtaining services: as needed.” The RFPs would be temporary until enough new units come online or existing units upgrade — both of which would already be required to provide PFR — to mitigate the need.
AEP says PJM’s proposal would force companies to pay to upgrade “resources that are in decline,” namely coal and nuclear, and that prioritizing PFR would limit units’ ability to optimize emissions.
A presentation from AEP argues that “declining” resources, such as coal and nuclear, shouldn’t be required to make investments necessary to supply PFR. | PJM
The company touts its proposal as the only one “that recognizes the potential future need of adequate synchronous inertial response,” meaning from resources that have rotating masses such as nuclear, coal- and gas-fired units.
“Did you know that simple cycle [combustion turbines] have less inertial response than a combined cycle CT? Both have much less than a coal unit,” a company presentation said.
AEP says that units can’t change PFR controls based on immediate needs.
“There is no switch! If you want PFR during system restoration, the unit must be tuned to provide it at all times. Re-tuning valves and governor action when there is a restoration event could increase chance of resource tripping significantly,” it said.
The company also criticized what it sees as PJM’s request to “bypass control limits” to optimize its PFR output.
PJM’s Stefanowicz contested that assertion.
“We’re not intending for anybody to bypass any safety functions,” he said. “We’re talking about removing outer loop controls like megawatt set point in a restoration mode and being responsive to frequency. We realize there’s tuning and controls in place to run unit efficiency day in and day out.”
AEP and Scarp agreed that the wording in PJM’s proposal suggests that company should disable any controls that would impact PFR performance, such as emissions controls.
The task force has canceled its planned June 26 meeting but is maintaining one scheduled for July 25. Boyle predicted the agenda will be “fairly light unless we hear something back from FERC in the interim” on PJM’s request for clarification.
Boyle said a stakeholder vote on the proposals would be planned tentatively for a Sept. 26 or Oct. 24 meeting if FERC hasn’t responded.
Scarp endorsed a vote to at least clarify stakeholder positions in the absence of any word from FERC.
“My tolerance is not indefinite. FERC can and might sit on things,” he said.
