SPP stakeholders’ effort to simplify the RTO’s complicated crediting system for transmission upgrades continues to spin its wheels.
Members once again discussed alternatives to SPP’s cumbersome Z2 process during an all-day meeting in Kansas City on Wednesday, but they adjourned without reaching any major decisions. (See SPP Z2 Panel Sees ILTCRs as Cure to ‘Mess of Complexity’.)
“It feels like we’re going over the same material every time,” said the group’s chair, Kansas City Power & Light’s Denise Buffington. “At some point, we have to get to where we can make a decision. We have to pull the trigger eventually, and it’s clear to me we’re not ready.”
The group did agree to schedule two additional meetings next month to improve its chances of presenting a recommendation in July to the Strategic Planning and Markets and Operations Policy committees.
The task force rehashed the pros and cons of two of the alternatives they have settled on: staff recommendations to replace Z2 credits with incremental long-term congestion rights (ILTCRs) or credit payment obligations (CPOs) under a Tariff schedule. Westar Energy’s Grant Wilkerson has proposed a third alternative, in which only upgrades that create transfer capability would receive credits under the Tariff.
Under Attachment Z2 of SPP’s Tariff, members are assigned financial credits and obligations for sponsored upgrades. The task force is trying to simplify the process while still meeting FERC requirements.
Several stakeholders raised concerns over using ILTCRs to replace Z2 credits, arguing that SPP’s transmission congestion rights (TCR) market is not yet fully functioning. Charles Cates, the RTO’s manager of transmission services, disputed that perception, saying the market is “working very well.”
“Seventy-eight percent of the load entities are fully hedged,” Cates said. “It’s a perception I do not agree with.”
“That’s not a perception OGE shares,” said Oklahoma Gas and Electric’s Greg McAuley, expressing a different viewpoint. “If you dilute a TCR market that’s not fully functional because you’ve never really used an ILTCR yet … I don’t know why you would do that intentionally.
“Z2 is functioning. Some people may not like it, but it’s doing the job it was designed to do. From OGE’s perspective, we’re getting credits for the upgrades that have been put in palace, and we’re also paying for upgrades that have been in place. We have a system that’s in place and working.”
“I’m hearing that we’re trading one set of problems for another set of problems,” NextEra Energy Resources’ Aundrea Williams said. “I want to make sure we don’t lose sight of the ultimate goal of simplification and transparency. I don’t want us to completely discount [that] Z2 can be improved, but the objective doesn’t have to be to get rid of it.”
Cates, who has been tasked with developing the ILTCR alternative, warned against changes to SPP’s market design, saying adding an auction revenue right mechanism connected to financial rights is a disconnect from the original purpose of the design.
“The unintended consequences of going this route could be profound — or not. It’s hard to say at this point,” he said to laughter. “If we’re not careful, the complaints I hear about the TCR market not working — which I personally don’t agree with — could get more loud.”
The moments of levity, while lightening the mood, did not diminish the difficulty of the task before the group.
“The problem I have now is every time I think I understand it, I don’t,” McAuley said. “I don’t have a problem going back to MOPC and saying this is a complicated animal. I don’t want to approve one of these [alternatives] and have a bigger mess on our hands because we didn’t understand it.”
CARMEL, Ind. — Capacity prices last month cleared at just $1.50/MW-day across MISO because of increased supply and low demand, John Harmon, MISO senior manager of capacity market administration, said during a post-mortem of the RTO’s April capacity auction. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.)
Coal accounted for most of the auction’s 135 GW of cleared capacity at 53,332 MW, followed by natural gas (48,784 MW) and nuclear (12,885 MW).
A key factor in depressing demand and prices: the overall rise in self-scheduled offers and fixed resource adequacy plans (FRAPs), which increased by more than 10% in zones 4 and 8.
Speaking at a May 10 meeting of the Resource Adequacy Subcommittee, Harmon said changes in offering behavior flattened the offer curve compared with last year’s auction, which saw prices clear at $2.99/MW-day in MISO South, $19.72/MW-day in Zone 1 and $72/MW-day in zones 2, 3, 4, 5, 6 and 7.
Indianapolis Power and Light’s Ted Leffler pointed out that many offers in this year’s auction came in at less than a dollar, with some entered at just a penny.
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“There were no instances of mitigation for physical or economic withholding,” Harmon confirmed.
American Electric Power’s Kent Feliks wondered if MISO had to contact any resources in order to enforce a new rule that imposes a 50-MW physical withholding ceiling on affiliated market participants collectively, rather than on each affiliated company individually. The new rule won tentative FERC approval mid-March with forewarning that the rule may not be just or reasonable. (See FERC Staff OKs MISO Mitigation Changes; Refunds Possible.)
“There were a few phone calls, largely from late offers,” Harmon said, noting that some resources bid into the auction near the end of the three-day offer window.
“MISO acting as a conduit to affiliates makes us a little uneasy,” Feliks replied.
Some stakeholders have argued that FERC Order 697 already prohibits affiliates from colluding to dodge withholding mitigation and MISO and its Independent Market Monitor’s new rule is unjustified. (See MISO Plans Additional Capacity Auction Revamps for 2017.)
RASC Chair Chris Plante expressed surprise that stakeholders didn’t have more to say about the auction results, given the low clearing prices.
Stakeholders Won’t Debate Single Year of MISO-SPP Settlement
Stakeholders voted overwhelmingly to end debate about whether costs for MISO’s transmission use settlement with SPP should be allocated by capacity benefit to holders of transmission service requests above the 1,000-MW contract path linking MISO Midwest to MISO South.
Laura Rauch, MISO manager of resource adequacy coordination, said the RTO agreed that the allocation amounts in question were too small to warrant more presentations and feedback cycles.
The RTO had previously asked stakeholders about holding discussions about how to allocate costs for the 300 MW in requests for 2018/19 that exceed the current limit on the North-South interface. Staff warned that the cost split may be negligible, and the matter was put to a stakeholder vote last month via a motion prepared by the Load-Serving Entity Coalition. (See “Single Year of SPP-MISO Settlement Allocation on Ballot,” MISO Resource Adequacy Subcommittee Briefs.)
MISO to Keep Current OMS Survey Format
MISO will stick with using the existing format for its annual resource adequacy survey with the Organization of MISO States, while examining next year’s project estimate approach in light of a new interconnection queue process, RTO staff said.
Rauch said that while stakeholders had not reached consensus on how to display survey results, most believe the RTO should do more to emphasize a fuller range of capacity possibilities. Staff were considering a “floating” results format, but it failed to garner stakeholder favor. (See “MISO Still Tweaking OMS-MISO Survey Format,” MISO Resource Adequacy Subcommittee Briefs.)
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MISO is still uncertain about how survey results will be affected by the roll-out of FERC-approved improvements to the interconnection queue, which could increase capacity counts through a quicker turnaround of project approvals. Rauch said it will continue to look into revising its project estimates in future surveys.
This year, MISO and OMS will count 35% of projects in the definitive planning phase of the queue toward future available capacity, in addition to the typical counting of all generation projects with signed interconnection agreements. The new approach was announced after multiple stakeholders voiced displeasure at what they saw as overly conservative results. (See OMS-MISO Survey Moves Ahead with New Calculation.)
Attorney Jim Dauphinais, speaking on behalf of Illinois Industrial Energy Consumers, said trade press and policymakers tend to take zonal capacity projections at their word and ignore the import capability of neighboring zones, which can solve capacity shortfalls.
“Those are negative amounts, and there is some concern with that, but import capability can solve that, and somehow that needs to come through so that policymakers aren’t left with the impression that this is a big problem,” Dauphinais said. “I think sometimes the press and policymakers miss” import capability. He also suggested that MISO post results by state rather than by local resource zones.
Ted Kuhn of Customized Energy Solutions said that even the scaling of the shortfalls versus surpluses on the findings graph is off, with shortfalls drawn visibly larger than their identical surplus counterparts in 2016 results. Rauch examined the graph and agreed that shortfalls were exaggerated in illustrations.
MISO and OMS will present results of the survey mid-June.
MISO to Study Effects of Extended Outages
MISO is still considering whether to bar resources on extended outages from participating in Planning Resource Auctions — or to make changes to capture the risk of such outages in its loss-of-load expectation (LOLE) analyses.
Harmon said the RTO will review its current LOLE study against actual recent outages and present results to stakeholders by mid-July.
MISO’s Tariff does not currently prohibit auction participation for resources on outages for 90 days up to the entire planning year. Staff last month asked stakeholders to suggest maximum outage lengths that would disqualify a resource from PRA participation. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
ALBANY, N.Y. — NYISO’s plan to integrate carbon into its markets will test the independence of FERC under President Trump, speakers told the Independent Power Producers of New York’s 31st Annual Spring Conference last week.
The IPPNY gathering came one week after a FERC technical conference at which NYISO CEO Brad Jones outlined plans to respond to the state’s zero-emission credits for its upstate nuclear plants. Jones told FERC that the ISO has hired the Brattle Group to develop a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. PJM also is considering a similar mechanism for some of its states. (See NYISO Sees Carbon Adder as Way to Link ZECs to Markets.)
Speakers at the IPPNY conference disagreed over whether FERC under President Trump would approve the ISO’s proposal.
In a keynote speech, acting FERC Chair Cheryl LaFleur, a Democrat, indicated she was open to the idea. But she would need to find allies among Trump’s four appointees to the commission to prevail.
One IPPNY speaker, Romany Webb, a fellow at Columbia Law School’s Sabin Center for Climate Change Law, outlined a recent paper she coauthored that concludes FERC has the authority to approve a carbon charge adopted by a wholesale market operator such as NYISO.
“Obviously, the Federal Power Act doesn’t authorize FERC to price carbon, and it sort of approaches an area of environmental regulation that has traditionally been considered outside of FERC’s authority,” she conceded. “So it would really push the boundary of what has to date been the limit of FERC’s authority. But it would do so in ways that are consistent with that authority.”
She noted that FERC has traditionally shown deference to grid operators’ market designs, requiring only that they be just and reasonable. “When an ISO makes changes, it doesn’t have to show that the old rules were somehow deficient or the new rules are somehow superior.”
Webb said NYISO could argue that a uniform carbon adder is needed to “rationalize” New York policy because the ZEC program doesn’t apply equally to all generators. It could also say that the current markets are skewed by their failure to capture carbon externalities, including the risks severe weather from climate change poses to the grid.
“The validity of that kind of charge comes down to how it’s structured,” she said. Using the federal government’s social cost of carbon — calculated using a discount rate of 5% to limit the cost impact — would produce an initial carbon price of $12.82/ton.
“I agree with Romany that the most elegant solution is you price carbon into the market,” responded former Colorado regulator Raymond Gifford, a partner with Wilkinson Barker Knauer. “It’s never going to happen. … A fully constituted FERC is not going to sign off on a carbon imposition.”
In addition to being in conflict with Trump’s pledge to bring back coal jobs, Gifford said, a carbon price would be difficult to sell politically.
“If you look through our regulatory history, the best subsidies are the hidden subsidies. … Once you make that price signal transparent … the politics of sustaining it become damn near impossible. That’s where the elegant, economists’ solution runs into the political economy of regulation. And in that fight, the political economy of regulation will win 99 times out of 100.”
Reregulation
A more likely outcome, Gifford said, is a return to some form of reregulation by the states, “maybe continuing to exist uncomfortably in a regional wholesale market.”
“What we have now is an engineering model of the market that has been stressed past the breaking point,” he said. “When this many states are doing versions of the same things and some of them are red states and some of them are blue states, you clearly don’t have a consensus that markets are the way to do this.”
Gifford said he is hopeful that courts will rule on challenges to the state actions in a way that provides clarity to the markets and states — even if prior state-federal jurisdiction rulings have not done so. (See Court’s Reticence Frustrates Energy Bar.)
“Our best hope for a categorical and clear answer going forward is for a court to tell us whether or not these state actions are permissible,” he said. “Now, I know courts don’t always give you a categorical answer, but I think anything is better than the regulatory muddle that we have right now.”
The Brattle Group’s Sam Newell, who is leading the ISO’s effort to develop a carbon adder, said he’s “hopeful” that the ISO’s effort will win FERC approval. But determining the size of the charge is anything but straightforward, he acknowledged.
“The costs of carbon [are] not easily boiled down to a number. It’s not like we’re talking about a very simple externality where you’re harming somebody else’s property and its very immediate and quantifiable,” he said. “You have questions like, how do you deal with the global impact? How do you deal with impacts over centuries and discount them? Most importantly … how do you deal with if there’s a 10% chance of catastrophic outcomes? It becomes almost entirely a political question of how willing are people to support and pay for decarbonization?”
Trump Nominees Will Decide
Last week, Trump nominated Pennsylvania Public Utility Commissioner Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), to fill two Republican vacancies on FERC.
The president can also nominate a third Republican and a replacement for Democrat Colette Honorable, who announced last month she won’t seek a new term when hers expires in June. Numerous reports have identified Kevin McIntyre, co-head of the energy practice at law firm Jones Day, as the third Republican nominee and likely chairman. (See Trump Nominates Republicans Powelson, Chatterjee to FERC.)
In a 2015 interview with Bloomberg Government, Chatterjee said that as the majority leader’s aide, he viewed all legislative proposals based on the impact on Kentucky, a coal state that is his home as well as McConnell’s.
“For anyone coming to our office to raise a policy issue, the first thing they have to explain is how this will affect Kentucky,” Chatterjee said. “Is this a proposal that will lead to job creation or economic growth in the commonwealth? Or is it going to adversely affect people in the Bluegrass [State]?”
McConnell bitterly opposed the Obama administration’s Clean Power Plan and urged state officials to refuse to comply with it.
Whether Chatterjee will carry his Kentucky-centric view to FERC is an issue Democrats will likely raise at his Senate confirmation hearing.
They also may challenge Powelson, who has been criticized by environmentalists as beholden to the natural gas industry in Pennsylvania, home of the Marcellus Shale.
“As to the political likelihood that FERC [under Trump] is going to approve carbon pricing, that is above my pay grade,” LaFleur told the IPPNY audience. “On a good day, I know what Cheryl LaFleur thinks. I don’t pretend to know what anyone else thinks. And I also don’t prejudge what individuals are going to come in and decide after they get there. But I do think a single-state ISO should have the best chance of reaching a negotiated solution … and I encourage the continuing efforts by the ISO and others to work on that effort.”
LaFleur said a carbon adder would be on firmer legal ground if it resulted from a Federal Power Act Section 205 filing by the ISO.
“I’m fairly certain that our ability to approve a proposal and prevail on appeal would be stronger if a proposal was brought to us under Section 205 and it was agreed upon and proposed by stakeholders in a region,” she said. “I can’t guarantee that would prevail, but I think that would put us in a much stronger position than if we imposed carbon pricing under Section 206, [which] I think would be far more vulnerable on appeal.”
Former FERC and New Mexico Public Service Commissioner Suedeen Kelly said she saw a big difference between the independence of the two agencies.
“The concept of an independent commission … didn’t exist in New Mexico. And so the politics of the governor’s office and the Legislature have a lot of effect,” she said. “But FERC, historically has … been very independent.”
Gifford agreed that FERC has been “relatively insulated” from politics. “It’s certainly not the basket case of the [Federal Communications Commission], which is the prototypical lawless agency.
“But it is, I think, going to be very difficult for this — I know two of the folks who are headed [to FERC] pretty well — I think it’s going to be really tough in this kind of polarized environment for FERC to say to New York: ‘You want a carbon tax? Go for it.’”
CARMEL, Ind. — MISO is testing the waters for creating a multiday energy market that would keep generators with long start-up times switched on for more than one day.
The effort has strong backing from stakeholders, who last year assigned the introduction of multiday financial commitments a “high priority” in the RTO’s Market Roadmap. (See MISO Projects Reordered Following Stakeholder Frustration.)
MISO says the change will result in more cost-efficient unit cycling and more diversity in the selection of resources called up for commitment. Market participants have said that relying on the routine cycling of baseload units can lead to inefficient unit commitment and higher maintenance and capital costs when a slow-moving unit is repeatedly switched on and off to conform to a next-day schedule.
RTO staff will begin analyzing historical market data in order to assess the costs and benefits of committing units over multiple days, MISO Markets System Analyst Chuck Hansen said at a May 11 Market Subcommittee meeting. The existing day-ahead market is not designed to accommodate units with long lead times or high start-up costs, he said.
“For units with a long lead time, the day-ahead market is going to think that it’s not profitable to start that unit,” he said, adding that the day-ahead market does not typically commit units to serve reliability needs.
But MISO could stretch its market model to notify units days ahead of time when they will be needed.
Still, a multiday market raises the question of who pays for the risk of overcommitting resources. Hansen said that risk could either be assigned to market participants, or MISO could take on the risk with the creation of multiday revenue sufficiency guarantees, which could result in increased uplift payments. Stakeholders could even agree to eliminate the day-ahead market in favor of a multiday market, although it would be a huge undertaking, he said.
Wind units — forecasted only a day out — and forced outages could complicate how slow-response units are scheduled. Hansen also told stakeholders that the “potential to improve unit commitments may be limited” compared to self-scheduling. Resources with high production costs will almost never be committed, even in a multiday commitment market, Hansen said. On the flip side, resources with low production costs can self-commit and remain running.
A multiday market could be useful for even faster-ramping gas-fired units, which must complete their weekend gas reservations on Fridays, Northern Indiana Public Service Co.’s Bill SeDoris said.
MISO market engineer Shu Xu said the RTO would not include the elimination of the day-ahead market in its cost-benefit analysis because the scenario is impossible to test with current software.
That comment prompted DTE Energy’s Nick Griffin to ask if MISO’s impending market system overhaul would allow a multiday market to completely replace a day-ahead market. Dhiman Chatterjee, MISO’s senior manager of market analysis, responded that, given the target deadline for completing a cost-benefit analysis, the RTO could not wait on the development of an entirely new market software platform just to test for such a far-fetched scenario.
MISO hopes to complete its analysis late this year and produce a conceptual design for a new multiday financial commitment market during the first half of 2018.
ERCOT last month set a new record for April peak demand, registering a high of 53,420 MW during the hour ending 5 p.m. on April 28, easily exceeding forecasted demand of 51,622 MW.
That marked a 4.88% increase from the high for the same month last year, when the Texas grid operator recorded a peak of 50,932 MW.
Panda Power’s 758-MW combined cycle power plant in Temple, Texas. | Panda Power Funds
ERCOT’s previous high for the month occurred April 18, 2006, when unseasonably high temperatures led to a peak of 51,800 MW.
The ISO generated more than 26 million MWh of electricity in April, bettering the forecast of 25,872,676 MWh. For the year, it has produced 102.4 million MWh, up from 100.5 million MWh through April 2016.
Coal last month surpassed natural gas as ERCOT’s primary fuel source for the first time since January, accounting for 33.57% of the ISO’s energy production. Gas accounted for 33.31% of energy produced and wind another 24.88%. Nuclear dropped to 7.08% of energy production, down from its previous 2017 low of 12.67% in March.
INDIANAPOLIS — Coming off a bumpy 2016, Indianapolis’ first-in-the-nation electric car-sharing service is looking to resume its expansion with the construction of new charging stations and a campaign to attract more members.
And the French company backing the BlueIndy program hopes to transplant the model to California, which is aggressively pursuing the adoption of electric vehicles as part of its policies to reduce greenhouse gas emissions.
Launched by the Bolloré Group in September 2015, BlueIndy boasts about 300 cars and 85 five-port charging stations around the Indiana capital. The company has planned for an additional 200 cars and 115 stations, but events last year halted expansion.
“We haven’t changed the goal, but the construction slowed down a lot in 2016,” BlueIndy President Hervé Muller said in an interview. “We had to deal with some political issues and had to sign a contract with the city.”
BlueIndy put a hold on construction during most the year while negotiating an agreement with the Indianapolis City-County Council, which contended that the process for placing stations lacked transparency. Business owners also complained the stations were taking up parking spaces near their storefronts.
The company and the council eventually settled on a franchise agreement last fall that allows the city to possibly relocate up to seven stations and requires the company to pay the city $45,000 per year to compensate for lost parking meters. Business owners must show that they have suffered financially to get a charging station moved.
“That was unfortunate and it took a lot of tension and most of 2016 to negotiate the agreement,” Muller said. “We think that phase is behind us, learning the political environment. That page has turned.”
Rideshares in Sync with Public Transit
BlueIndy has yet to uproot any charging stations, although a recently voter-approved rapid transit bus route might require some relocations. Still, Muller is not concerned that buses will infringe on his company’s growth.
“The two are not competing,” he said. “If you need to go somewhere, and you don’t have a car, what are your options? On some days instead of using the bus, you might use the cars. We think it’s all complementary. It’s to give options to people who don’t own a car or don’t want to own a car.”
Muller said Bolloré’s AutoLib’ sharing service happily coexists with the expansive public transit in Paris, which he considers the company’s showcase city.
“There’s no debate there whether we are taking a rider from public transit,” he said. Bolloré has similar rideshare services in Lyon and Bordeaux in France; London; and Turin, Italy. The company will soon expand to Singapore.
Unlikely Host
The company is currently building five new charging stations in Indianapolis and awaiting word on a backlog of notices submitted to the city for review of prospective locations. Each station costs anywhere from $50,000 to $100,000.
Bolloré has converted its Midwestern host into an unlikely early adopter of EV technology. The company’s 400-plus public chargers give Indianapolis the distinction of having the largest network of public charging stations of any U.S. city. While the number of private charging stations in Los Angeles might currently outstrip those in the Indiana city, Muller noted that BlueIndy charging stations can be used by anyone.
Navigating the American political landscape for construction approval is not unlike working with government officials in France, Muller said.
“Our goal is to work well with local political power. That’s why we’re selective about the cities we go to,” he said. “It is a transformation of the city, and we do believe that electric vehicle sharing must happen in the public right of way.”
Bolloré has a 15-year contract with Indianapolis and anticipates investing a total of $41 million in BlueIndy, with the city funding $6 million and Indianapolis Power and Light contributing about $3 million. The company has hired about 40 full-time and part-time staff in Indianapolis to run the program and has contracted with local construction unions to erect charging stations.
Residents can sign up for membership at a charging station kiosk or the BlueIndy website, and reserve cars or charging spots via the website or an app. Members are charged according to a metered payment structure based on the first 20 minutes of use and a per-minute charge thereafter. Membership packages, which come with a monthly fee, reduce the per-minute charge by up to half. A daily rental, requiring no commitment, costs $8 for the first 20 minutes, then 40 cents/minute. With a one-year membership (about $120), the charge is $4 for the first 20 minutes and 20 cents/minute afterward.
BlueIndy is now focused on expanding its membership, currently 1,500 active members that take about 1,000 rides per week.
“That is really the measure of the service — how often the cars are used,” Muller said.
While the company doesn’t maintain detailed demographics on its current users, it does collect information through member surveys, which Muller said shows “a large contingent of young users, millennials and students,” as well as retired people and families that want to become a one-car family. The company last year also rolled out targeted discounts to encourage college students to join.
Muller estimates that BlueIndy’s profitability is still a few years out: “The nature of our business is a big infrastructure investment. We know that we’re going to spend millions and millions of dollars. We generally anticipate that it takes five to seven years to break even and after that we can recoup our investment.”
Bolloré Goes West
Having gained a foothold in the U.S., Bolloré is now eyeing a West Coast expansion with a BlueLA pilot program underway that will consist of 100 vehicles and 200 charging ports by the end of spring.
“Los Angeles is a fantastic city for our service,” Muller said. “We had always envisioned to employ our service in California. It’s starting as a pilot, but there’s a long-term vision to deploy a service similar to what we have in Paris or Singapore.”
The California Air Resources Board granted Los Angeles $1.6 million for the pilot, but Muller said Bolloré expects a similar 80-20 funding split like that in Indianapolis, with the company paying the lion’s share for construction and cars, and the city and local utilities picking up the rest.
Los Angeles Mayor Eric Garcetti said the stations will target low-income areas where residents are less likely to own cars. “We are so proud that we can now launch the nation’s first pilot program for electric vehicle sharing in disadvantaged communities. That is real progress,” Garcetti said.
Bolloré is not currently considering any other U.S. cities for expansion.
“We make a big investment in the charging infrastructure, so we make a careful decision,” Muller explained.
Different Locations, Same Cars
The EVs used for the service — Bolloré’s Bluecars — are nearly identical worldwide. The two-door, four-seater hatchback was developed with Italian automotive design firm Pininfarina and is manufactured in Italy. The cars have a top speed of 81 mph and an on-board computer for navigation.
While the Bluecars’ 30-kWh lithium metal polymer batteries can last for a 150-mile trip on a single charge, Muller said the total useful life of the battery is still unknown because the technology is so new. The batteries, which are produced in Bolloré’s factories, passed the five-year mark in 2016 in France with heavy use, and the company has yet to replace any of the recyclable batteries.
“We think it should outlast most batteries on the market. There is no known end of life for the batteries right now. We can say that they are exceeding our expectations,” Muller said.
A new CAISO initiative could allow power producers a way to temporarily suspend the operation of an unprofitable generating plant — and possibly provide compensation to plants denied permission to do so.
That would crack the door for the ISO to issue a type of capacity payment to some financially struggling generators not needed to maintain system reliability, even if it falls far short of establishing a capacity market.
The Temporary Suspension of Resource Operations initiative will explore under what circumstances the ISO might permit a resource owner to temporarily pull a money-losing generator out of the market short of the “mothball” and retirement procedures already spelled out in the ISO’s Business Practice Manual.
“The initiative will assess how potentially allowing this type of resource status change would interact with other requirements of the CAISO Tariff, contracts, and with grid and market operations,” the ISO said in an issue paper describing the scope of the effort.
CAISO said it was seeking to address the issue in response to stakeholder comments filed in a 2016 FERC proceeding over the ISO’s refusal to approve outage requests for three of four units at the 965-MW La Paloma combined cycle plant 140 miles north of Los Angeles (EL16-88).
Completed in 2003, La Paloma — like other gas-fired plants in California — has in recent years struggled to compete in the wholesale market because of depressed prices, largely driven by lower-priced renewable resources. The owners estimated that the plant would lose $39 million annually under continuous operation and asked that CAISO allow them to shut down the three units from July to November 2016.
The ISO rejected the plant owners’ requests because they were made for economic — and not physical — reasons. It also rebuffed an additional request to compensate the units by designating them as reliability-must-run resources, contending that they were not needed for reliability purposes. At that time, 42 MW of the plant’s Unit 2 were under an RMR agreement.
Last December, two months after FERC refused to overturn the ISO’s decision, La Paloma filed for bankruptcy, citing $524 million in debt and an “inhospitable regulatory environment.”
CAISO’s initiative stems from stakeholder concerns raised during a 2016 FERC proceeding related to the La Paloma generating plant, which filed for bankruptcy late last year after being refused permission to suspend its operations in the ISO market. | Kern County, California Public Health Services Department
While market participants generally agreed with CAISO’s decision, some suggested that FERC direct the ISO to amend its Tariff to address revenue shortfalls for conventional generators. FERC rejected the request.
The new initiative seeks to address at least some of those stakeholder concerns. In its filings with FERC, CAISO acknowledged the importance of keeping conventional generation available to help integrate the growing volume of renewables on its system and noted that it was actively pursuing market changes to compensate generators for their needed characteristics.
The ISO seeks to keep the scope narrow, avoiding a discussion of using the current outage management system — which is intended for maintenance outages — for economic requests.
“The distinction here is that this initiative will look at the conditions under which the CAISO may allow a participating generator to temporarily suspend the operation of its generating unit,” the ISO said in its paper. “The solution will likely involve a process and a new method for requesting and then reporting a temporary suspension of operations.”
Perhaps most significantly, the ISO wants stakeholders to consider the need for a mechanism to compensate generators not needed for resource adequacy but denied permission to suspend operations, including a potential cost allocation scheme.
The initiative will also explore maximum and minimum time limits for temporary suspensions, timelines for requesting suspension and whether suspended resources should maintain a level of readiness to return to the ISO market if it’s needed.
The ISO additionally expects to consider whether a generator can switch operation from one balancing authority area to a neighboring one for an extended period of time and how that would affect resource adequacy accounting.
Under current rules, owners that plan to mothball a generator must provide CAISO 60 days’ notice before shutting down and submit a “long-range” outage request. To maintain its repowering rights and deliverability status, the plant must provide a repowering plan within one year of closing.
CAISO will kick off the initiative with a May 19 stakeholder call.
Maryland regulators on Thursday approved two offshore wind projects totaling 368 MW, setting in motion what the state called the nation’s “first large-scale” offshore wind deployment.
The Public Service Commission awarded offshore renewable energy credits (ORECs) to US Wind and Deepwater Wind’s Skipjack Offshore Energy.
PSC Chairman W. Kevin Hughes said the approval “brings to fruition the General Assembly’s efforts to establish Maryland as a regional hub for this burgeoning industry.”
Maryland Offshore Wind Lease Area | BOEM
The PSC awarded the credits at a levelized price of $131.93/MWh for 20 years, beginning when the plants start generating.
US Wind’s 62-turbine, 248-MW project, 12 to 15 nautical miles offshore, has an estimated cost of $1.375 billion and is expected to begin operations in January 2020. It will connect to the grid at the Indian River Substation in Delaware.
Skipjack’s 15-turbine, 120-MW project, 17 to 21 miles off the coast, is estimated at $720 million and has a target in-service date of November 2022. It will connect to the grid at a substation in Ocean City, Md.
Conditions
The PSC’s order included more than two dozen conditions, including requirements that the developers create almost 5,000 direct jobs during the development, construction and operating phases of the projects.
The companies will be required to use port facilities in the Baltimore region and Ocean City for construction, operations and maintenance, fund almost $40 million in upgrades at the Tradepoint Atlantic (formerly Sparrows Point) shipyard in Baltimore County and invest at least $76 million in a steel fabrication plant in the state (Case No. 9431).
To address concerns about the ability to see the turbines from the shore, the order also requires US Wind to locate its project as far to the east of the designated wind energy area as practical. “Each developer also must take advantage of the best commercially available technology to lessen views of the wind turbines by beach-goers and residents, both during the day and at night,” Commissioner Anthony O’Donnell said.
The two companies must notify the PSC by May 25 whether they accept the conditions. The projects also are subject to the federal government’s approval of site assessment, construction and operations plans.
“As we review the details of the commission’s order, we thank the Public Service Commission for the trust that they have placed in Deepwater Wind,” CEO Jeff Grybowski said in a statement. “We look forward to continuing our dialogue with the Ocean City community about the Skipjack Wind Farm. Our goal is to build a project that the entire community is proud of.”
Deepwater Wind operates the first offshore wind project in the U.S., the 30-MW Block Island project off Rhode Island that began operations in December. (See Offshore Wind Industry Looks for Next Gust of Support.)
US Wind, a subsidiary of Italy’s Toto Holdings, thanked the PSC for the decision in a statement, saying “Maryland is now the undisputed national leader for offshore wind.”
| US Wind
“This marks the real start toward an extensive offshore wind industry that will one day soon stretch from Cape Cod, Mass., to Cape Hatteras, N.C., and provide as much as a third of the East Coast’s electricity,” the Chesapeake Climate Action Network said in a statement.
Cost to Ratepayers
An analysis conducted for the PSC estimated the ORECs will cost residential customers less than $1.40/month and boost rates for commercial and industrial customers by less than 1.4% — below the limit set by the legislature in the Maryland Offshore Wind Energy Act of 2013. The law allows offshore wind to comprise up to 2.5% of total retail electricity sales.
The projects are part of the state’s plan to reduce carbon emissions 40% by 2030 and will allow electric suppliers to replace some renewable energy credits produced in other states. Maryland’s renewable portfolio standard requires production of 25% of electricity from renewables by 2020.
CARMEL, Ind. — Customers of the Southwestern Power Administration (SWPA) asked MISO on Wednesday to change how it accredits their hydropower allocations from the federal power marketing administration, saying current rules are shortchanging them and denying the RTO full use of the resources’ seasonal peaking capacity.
“We didn’t come today with a fix. … We’re going to hope that the people in the room come up with a solution and a fix in future meetings,” Rick Henley, of Jonesboro City Water and Light in northeast Arkansas, told stakeholders at a May 10 Resource Adequacy Subcommittee meeting. Appearing on behalf of SWPA customers with Aiden Smith, the agency’s vice president of transmission strategy, Henley offered a problem statement outlining their concerns.
Move from SPP to MISO
SWPA markets about 2,000 MW of power produced by 24 U.S. Army Corps of Engineers hydropower projects, most of them located in the SPP footprint.
When Entergy joined MISO in 2013, it added 27 SWPA customers to the RTO’s footprint in addition to one existing customer. “As a result, the vast majority of SWPA’s federal hydropower customers were not present in MISO’s stakeholder processes when the rules concerning resource adequacy were crafted,” the problem statement said.
The problem, Henley said, is that MISO’s resource adequacy rules treat the hydro assets as baseload power when they were designed to provide peaking power. He said MISO could reap reliability benefits in the summer and winter if it modified its requirements for hydro assets.
MISO’s Business Practice Manuals require the Use-Limited Resource type to be available for the four peak hours of the day (1,460 hours/year). But because SWPA’s contracts with Jonesboro and other “preference customers” typically only guarantee power for 1,200 hours/year, MISO revised its rules to give the SWPA customers a reduced capacity credit of 82% of their federal allocations to spread the guaranteed amount of firm energy across 1,460 hours.
Intended as Peaking Power
“While the federal preference customers are very grateful for this compromise, MISO, its footprint and the customers could be better served by federal hydropower if it was used as intended as peaking power,” the problem statement says.
It noted that SWPA hydropower has 236 MW of import capability into MISO. It said one unnamed preference customer with a 100-MW allotment is not importing into the RTO because of the current rules but would do so if the problem were resolved.
“We have a 1,200-hour product that does not conform with MISO’s 1,460-hour resource adequacy rules,” Henley said. “We’re scheduling now as a baseload resource, and we think it reduces the ability of the federal hydropower when it’s most needed and valuable in the MISO footprint. If we can bring more resources to the table, you [would] think that would bring down prices for everyone.”
Jonesboro City Water and Light, which has a 303-MW peak demand for 36,000 customers, has an 80-MW hydropower allocation from SWPA. “It’s a pretty big deal for us,” Henley said of the hydropower share. “We think there’s a better way to utilize this resource within MISO constraints.”
David Sapper of Customized Energy Solutions said stakeholders have long considered asking MISO to revise its resource adequacy rules, saying it’s difficult for any fuel type to meet the availability requirements.
RASC liaison Shawn McFarlane said MISO can examine the issue with stakeholders, but he said the RTO would not commit to a timeline. He said it could work to compile statistics on hydropower use for stakeholders.
“Obviously, anything we apply has to work generally; we cannot create one-offs,” McFarlane said.
RASC Chair Chris Plante said stakeholder process dictates that the issue is first sent to the Steering Committee, which would decide which committee works on it. Steering Committee Chair Tia Elliott said her committee would most likely move the issue to the RASC at the May 24 meeting.
Texas regulators on Wednesday agreed to reconsider its recent rejection of a proposed acquisition of Oncor by Florida-based NextEra Energy, which sought a review of the decision.
The state’s Public Utility Commission will rehear the case (Docket 46238) during its May 18 open meeting, the first without longtime Chairman Donna Nelson, who is retiring May 15. No replacement has yet been named to the three-person panel. (See Texas PUC Chair Nelson Stepping Down.)
The PUC last month unanimously rejected NextEra’s $18.7 billion bid for the Texas utility, saying the risks outweighed the promised benefits. (See Texas Commission Denies NextEra’s Bid for Oncor.)
In a filing made earlier this week, NextEra said the commission went beyond the scope of its powers when it found the acquisition not to be in the public interest, calling the PUC’s order “unprecedented.”
“The order represents an expansion of power that exceeds the limits set by the Legislature and the bounds of the commission’s own precedent,” NextEra said, listing 14 points of error ranging from “the exercise of authority not granted by the Legislature to reliance on facts not in evidence.”
The company said the order also ignores “Moody’s determination that NextEra Energy’s acquisition … will unequivocally benefit Oncor,” and that it fails “to give any consideration to the benefits and protections” of the 73 regulatory commitments the company made to the PUC.
NextEra requested the commission give it as much time as allowed by law to “encourage possible settlement discussions.”
At stake is a $275 million termination fee that NextEra would be liable for should the deal fail for certain reasons.
The PUC has until June 7 to act on NextEra’s request.
Oncor’s future is central to parent company Energy Future Holdings’ bid to exit Chapter 11 bankruptcy proceedings, which have now dragged on for three years. The PUC rejected Hunt Consolidated’s bid for Oncor last year.
