SPP’s Holistic Integrated Tariff Team (HITT) wrapped up the educational portion of its work last week and will now begin refining the high-level recommendations it will make to the Board of Directors.
SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary, offered several suggestions on how the group might take the information and data it has gathered “and assimilate it into a report.”
Suskie broke down the recommendations into sub-sections dealing with transmission planning, congestion rights and hedging, and resource adequacy, among others. However, no action was taken to endorse any recommendations during the team’s Dec. 4-5 meeting, with stakeholders suggesting some of the concepts discussed be addressed by other working groups.
The HITT has an April 2019 deadline for delivering a report on the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services.
SPP announced Dec. 6 that senior executives Lanny Nickell and Barbara Sugg will take over the staff secretary positions on two of its most important committees, the Markets and Operations Policy Committee and Strategic Planning Committee, respectively.
The MOPC, relying on stakeholder groups, develops and recommends policies and procedures to the board. The SPC is responsible for the RTO’s strategic direction.
Nickell, vice president of engineering, will assume the MOPC’s reins from COO Carl Monroe, who has filled that position for 18 years. Monroe will continue to directly engage with the committee as a resource, CEO Nick Brown said.
Sugg, SPP’s IT vice president and chief security officer, will replace Michael Desselle, who served as the SPC’s staff secretary for 10 years.
Brown said the appointments will allow Nickell and Sugg “to continue [their] professional development and service to SPP.” He made the announcement in a pair of emails to stakeholders.
SPP’s Sorenson has Role at Bush Funeral
The SPP Market Monitoring Unit’s Greg Sorenson, a supervisor of market surveillance, was part of a special naval escort for dignitaries and family members attending President George H.W. Bush’s funeral ceremonies in D.C. last week.
Sorenson, a lieutenant commander in the U.S. Navy Reserve, arrived in the capital Dec. 2 to join 10 other Navy officers in escorting visitors at Andrews Air Force Base and the National Cathedral. Sorenson was present at Andrews when Air Force One landed with Bush’s body and met Sully, the president’s service dog.
“I had to rearrange some things, but [SPP was] very accommodating in allowing me to do this for our country,” Sorenson told the Northwest Arkansas Democrat-Gazette.
Staff Eyeing FERC Filing on Seams Projects
SPP staff were unable to gain stakeholder consensus last week on their proposal to change the criteria for regional funding of seams projects. The revision would apply to all seams projects unable to pass the interregional Order 1000 process and approved in an SPP regional study.
At the Seams Steering Committee meeting Wednesday, several stakeholders suggested the effort to create Tariff language would be worthwhile. However, committee Chair Jim Jacoby, with American Electric Power, said he wasn’t sure the time and effort was worth it.
“It won’t fix anything on the MISO side,” Jacoby said, referring to the inability of the RTOs to agree on interregional projects. “Having something in the Tariff is a good thing, but I’m torn over the amount of effort it will take versus the benefits it will provide.”
Staff said they will continue discussions with the committee in 2019.
They also told the SSC they were close to finalizing revisions to the joint operating agreement governing the coordinated system plan for interregional projects with MISO. Staff said the RTOs hope to reach an agreement during the Interregional Planning Stakeholder Advisory Committee’s Dec. 20 conference call, and then prepare the JOA for FERC filings in January or February.
The RTOs have agreed to revise the JOA to improve the chances of funding interregional projects. The changes will eliminate the $5 million cost threshold for the projects, add avoided costs and adjusted production cost benefits to project evaluation, and remove the joint modeling requirement in favor of individual RTO regional analyses. (See MISO, SPP to Ease Interregional Project Criteria.)
M2M Payments Flow in SPP’s Direction Again
| SPP
Staff told the SSC that the market-to-market (M2M) process wound up in SPP’s favor in October, reversing three consecutive months of net payments to MISO.
Flowgates along the seam were binding for a total of 663 hours on SPP’s side, resulting in more than $380,000 in M2M payments. SPP has now amassed $51.6 million in distributions since the two RTOs began the M2M process in March 2015.
Payments have flowed SPP’s direction 20 of the last 25 months.
Walker: More Visibility Needed into DERs, Self-Gen
Calling ERCOT’s recently projected reserve margin of 8.1% for 2019 a “very concerning number,” DeAnn Walker, chair of the Public Utility Commission of Texas (PUCT), last week urged the grid operator to gain a “better sense” of the distributed resources and self-generation that could be affecting the system.
The Texas PUC’s Dec. 7 open meeting
“I think we’re getting to a point where we need more transparency into those issues,” Walker said during the PUC’s Dec. 7 open meeting. “I think the electric system is changing, and we’re moving to a more customer-initiated ownership” of energy resources.
A Buc-ee’s station near Houston | Buc-ee’s
Using her favorite example of the mammoth Buc-ee’s convenience stores found along Texas highways, Walker noted how the chain “is dropping gas units behind [the stores] to get away from high prices or to sell into the market.”
“More and more people are going to be doing this,” Walker warned. “I really want ERCOT and the market to move forward to give them more visibility into what we have out there.”
PUC Chair DeAnn Walker questions legal counsel during the open meeting.
Warren Lasher, ERCOT’s senior director of system planning, agreed with Walker that the initiative does not require a rulemaking from the PUC.
“We have been working with stakeholders on a different number of fronts,” Lasher said. “It’s likely our current efforts are not urgent enough to meet the need associated with the changing grid and the resource reports we have been issuing lately. I would take that need back, and maybe set a slightly different tone working with stakeholders.”
ERCOT has seen a 62% growth rate in distributed energy resources over the last three years, CEO Bill Magness said during a November Gulf Coast Power Association luncheon. Although DERs currently account for about 1.3 GW of capacity, Magness said staff have worked with transmission and distribution providers to map some of the 93 existing registered DERs and to map all registered DERs to the system load. (See ERCOT CEO: Solar Growth ‘an Interesting Challenge.’)
ERCOT’s Warren Lasher explains ERCOT’s position to the commissioners.
Commissioner Arthur D’Andrea pointed out that the lack of visibility into DERs and self-generation hampers the preciseness of meeting projected load.
“It’s striking how much well-spent time ERCOT [uses] estimating load out in West Texas, and how much time we spend getting it right,” he said. “Then you have that precision undermined by someone and having this giant question mark out there.”
SPS, DOE Dispute Dismissed
The PUC agreed with an administrative law judge’s dismissal of a dispute between Southwestern Public Service and the U.S. Department of Energy’s Pantex nuclear weapons facility near Amarillo, Texas (Docket 48440).
The department sought an order from the commission compensating it for excess generation from the facility’s 11.5-MW wind farm. The request was part of a broader SPS rate case but was severed from the application in 2017.
The ALJ found SPS met its burden of proof in showing its billing arrangement with DOE was appropriate and ordered that no changes be made.
PUC Issues $1.49M in Fines
The commissioners approved $1.49 million in administrative penalties following settlement agreements in nine dockets. The largest fine, $1.1 million, was assessed to generator Luminant for providing ERCOT with false telemetry data, which prevented the grid operator from economically dispatching units (Docket 48607).
Two retailers, Source Power and Gas and Reliant Energy Retail Services, were fined $50,000 and $100,000, respectively. Source improperly placed switch-holds on 91 customers who had entered into payment arrangements and failed to remove 71 switch-holds in a timely fashion (Docket 48608), while Reliant was docked for failing to timely send bills to customers and for improperly billing more than 47,930 customers (Docket 48773).
The commission also approved $240,200 in electric utility service quality settlements involving six different utilities in the following dockets: 48573, 48628, 48642, 48674, 48772 and 48774.
Following its executive session, the PUC agreed to intervene in Xcel Energy’s request before FERC to change SPS’ transmission formula rate template (ER19-404).
SPS is seeking a $9.4 million increase in its 2019 wholesale transmission service revenues, with almost $5 million being recovered from wholesale customers in the company’s SPP transmission rate zone and $4.5 million being recovered from other SPP tariff customers through regional transmission rates.
CARMEL, Ind. — Several MISO stakeholders are criticizing Tariff filings the RTO plans to make by the end of the year to free up an additional 5 to 10 GW of capacity in time for the spring outage season.
The discord played out in meetings as part of MISO Board Week and during a special conference call of the Reliability Subcommittee on Dec. 7.
At the Dec. 5 Advisory Committee meeting, Reliability Subcommittee Vice Chair Ray McCausland, of Ameren, said MISO worked unusually fast on the short-term resource availability and need filing.
“For those used to MISO running at the lightning pace of a glacier, MISO has flown through this,” he joked. McCausland also acknowledged stakeholder concerns about the pace of the filing. He said a few have voiced skepticism that the new load-modifying resource (LMR) treatment and outage coordination can in fact free up the capacity the RTO has cited as the reason for the Tariff filing.
Earlier this month, several stakeholders criticized MISO’s plan to require more testing of and data from certain LMRs and impose stricter notification times for planned outages. (See Stakeholders Critical of MISO Resource Availability Filing.)
Because of stakeholder pushback, the RTO said later in the Dec. 7 conference call that its originally planned Tariff filing will now become three separate Tariff filings: one each for demand response capability testing, LMR seasonal availability documentation and a new 120-day notice time for planned outages.
Kevin Murray, representing the Coalition of MISO Transmission Customers and the Eligible End-User Customers sector, called the original filing “controversial.” He said a full filing runs the risk of garnering so many protests that FERC will refuse to act on it, especially considering a D.C. Circuit Court of Appeals ruling last year that the commission overstepped its authority in its approval of PJM revisions to its minimum offer price rule. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
“I’m here to express my profound disappointment that we’re here today,” Murray said during the Advisory Committee meeting. He added that the RTO should do something about its lack of fast-start resources as winter approaches, particularly in MISO South.
Coalition of Midwest Power Producers CEO Mark Volpe said MISO’s proposed limits on outages may be punitive to generation owners. “We’re going way too fast here on something this serious,” Volpe said.
Jim Dauphinais, a consultant with Brubaker and Associates representing end-use customers, said the filing seeks to unnaturally force improved availability.
Imagining Blackouts
Board members who heard the discord urged stakeholders to work through their differences with MISO.
Director Baljit Dail asked stakeholders to imagine how they would respond today if the RTO experienced rolling blackouts. “How would you approach this problem differently? How would you change your answer?” he asked.
“I appreciate that no one wants rolling blackouts in the press … but I think there’s an unintended consequence here,” Madison Gas and Electric’s Megan Wisersky said. She said more rules for LMRs would drive some out of the market, resulting in reduced resources.
“I urge caution here,” she said.
However, representatives of the State Regulatory Authorities sector said they were supportive of a filing. Minnesota Public Utilities Commissioner Matt Schuerger said stakeholders cannot deny the urgency of needing changes.
Speaking at a Dec. 4 meeting of the board’s Markets Committee, MISO Executive Director of System Operations Renuka Chatterjee said “availability of resources is the key to avoiding real-time shortages.”
“We’re seeing an increase in unavailable megawatts for each of the last three winters,” Chatterjee told the committee.
Almost 12 GW (about 9%) of MISO resources are classified as LMRs, accessible only as part of emergency load management. The RTO had not called on LMRs for a decade after a localized Wisconsin emergency in February 2007 but has relied on them three times since 2017, most recently in MISO South in mid-September. Independent Market Monitor staffer Michael Wander said most MISO South LMRs were unable to respond in time during the September event because the units have long start-up times.
MISO has seen a 4.6-GW decrease in installed capacity from existing resources since 2017.
“We’ve experienced retirements of what we considered excess capacity,” RTO President Clair Moeller explained to board members.
Dail said the situation underscores the need for MISO to be able to better supervise planned outages. “This just looks like it’s going to get more complicated as we go forward,” he said.
Responding to a question from Director Barbara Krumsiek about whether MISO’s neighbors face similar availability challenges, Moeller said SPP has a similar experience of growing renewable resources paired with conventional generation retirements.
Seeking Clarity
MISO discussed a few recent additions to the possible multiple filings during the Dec. 7 conference call.
Staff said they propose to issue scheduling instructions up to 12 hours in advance based on resource lead times but would not actually call on the resource until two hours before it’s needed. Demand response resources that acknowledge scheduling instructions but are not ultimately called would nevertheless receive credit toward the five deployments per year that would be required of LMRs.
DR would also prove demand reduction capability by “performing to its requirements when called upon during the prior planning year” in addition to MISO’s original proposal of participating in a real power test. Testing of DR resources would begin for resource qualification in the 2020/21 planning year.
But stakeholders said the new demonstration option was vague, with some asking about the minimum number of performance hours and how MISO would account for performance when it calls up partial demand-reducing output.
MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO’s testing requirements would require full output of a DR resource for at least an hour.
Xcel Energy’s Kari Hassler asked what would happen if a properly scheduled planned outage takes more time to complete under the original scope of work and an emergency event occurs during the outage extension.
Rauch said the outage extension would likely fall under MISO’s “high-risk” determination, and the outage could be rebranded as a forced outage for the time it overlaps a maximum generation emergency, which would count against a resource’s accreditation.
However, she also said MISO is still working through revisions of its proposed filings and may choose to delay the outage coordination piece until January, still targeting changes by the spring outage season. She said the RTO will accept another round of feedback through the end of the week. MISO is planning to post an updated version of its filing or filings by Wednesday and will use stakeholder feedback in final revisions.
[Editor’s Note: An earlier version of this story incorrectly identified Jim Dauphinais’ affiliation and misnamed the Coalition of MISO Transmission Customers.]
WASHINGTON — When it comes to the smart grid, count consumer advocate David Springe as a nonbeliever.
He began his talk at gridCONNEXT 2018 last week with a vendor’s definition: “Smart grid is the convergence of information and operational technologies applied to the electric grid, allowing sustainable options to customers and improved security, reliability and efficiency to utilities.”
Then Springe gave the consumer advocate’s definition: “Smart grid employs new technologies that are more expensive and less secure than the current technologies to give pricing flexibility that customers don’t want, to communicate with small and smart appliances customers don’t own.”
Although he wrote that definition eight years ago, Springe, executive director of the National Association of State Utility Consumer Advocates (NASUCA), said it still applies. “The vast majority of customers don’t interact with their meters; [they] aren’t on time-of-use rates,” he said.
Customers, he said, have seen little benefit from replacing $100 analog meters that were depreciated over 30 years with digital meters that cost twice as much and are depreciated over only five years. “Frankly, all that meter infrastructure was pretty much used to read meters once a month. We spent a lot of money. If we did it under the premises of providing something that consumers wanted, we failed.
“There’s a million great ideas out there that only need somebody’s money to make it happen,” he continued. Consumer advocates “see this at the ground level where all these grand ideas that are being shared in this room show up on the utility balance sheet, show up on the utility bill.”
Instead of lusting after new technology, Springe said, utilities and regulators should focus on increasing efficiency and reducing costs through outsourcing and cloud computing. “Why does every utility have its own communication system? Meter system? Back office systems?” he asked.
Springe said consumers are seeing reduced generation costs swamped by increases in distribution and transmission charges.
That’s due in part to antiquated cost-of-service ratemaking that is preventing innovations that could save consumers money, said former FERC Chair Jon Wellinghoff, who shared a panel with Springe.
Wellinghoff is much more bullish on new technology, such as transmission devices that can add capacity without reconductoring or adding new substations.
He cited a project that Pacific Gas and Electric is building in West Oakland, which will combine distribution-level storage, behind-the-meter controls for demand response and distributed generation, and the aggregation of rooftop solar to address reliability concerns over the retirement of a Dynegy generator. The $100 million project won out over a $300 million proposal to add a new 230-kV transmission line.
That was good news for consumers, but not for PG&E, which won’t get to earn a return on the more expensive transmission investment, said Wellinghoff, who served for seven years as Nevada’s consumer advocate before joining FERC.
“We have to reconcile this somehow … so that utilities will have … incentives aligned with what we all would like to have for consumers, which is [an] efficient, cost-effective system that is clean,” he said.
Narrow Window for Energy Legislation in 2019
The conference also featured discussions on prospects for energy legislation in the new Congress.
The new Democratic House majority will have only a few months to work with Senate Republicans and President Trump on energy policy before the 2020 presidential election intrudes, said Jason Hartke, president of the Alliance to Save Energy.
Hartke said likely Speaker Nancy Pelosi (D-Calif.) will face a challenge managing the tension between “a whole lot of excited new members who want to do things like build the Green New Deal versus [veteran Rep. Paul] Tonko [D-N.Y.] talking about singles and doubles.” (See Optimism Rising on EVs as Sales Hit 1 Million Mark.)
Hartke said a bipartisan infrastructure bill that includes spending for grid modernization and electric vehicle charging is “the one opportunity for a home run.” But he said the fate of such legislation hinges on whether Trump engages and can win the support of the Republican-controlled Senate.
“We’re working hard now for a tax extenders package that makes sense. Right now, the House package is looking backwards, so it’s retroactive [extending already expired tax breaks]. We want it to look forward, so you could actually change behavior.”
Attorney Andrew Shaw, senior managing associate with Dentons, said new members who campaigned on bold action on climate change will be motivated to support smaller changes so they can take credit for legislative accomplishments.
“Something like an infrastructure bill — which faces a lot of hurdles undoubtedly — is a vehicle that you could maybe get some of those wins, because everybody wants to be able to go back home and be able to talk about what they’re doing,” Shaw said.
“It’s not a given that energy’s going to be in the mix” in an infrastructure bill,” said Amit Ronen, deputy chief of staff to Sen. Maria Cantwell (D-Wash.) in a separate discussion. “It’s something we’ve got to educate members … on.”
Ronen noted that Cantwell, the ranking member of the Energy and Natural Resources Committee, cosponsored the $7,500 passenger EV tax credit with Orrin Hatch (R-Utah).
“So now we’re looking at, is there a role for the government in incentivizing electrification of other transportation? We’re talking about boats, trucks, buses, even planes, which two years ago I wouldn’t have even thought … was possible.”
Shaw said there has been some progress in the last six years in building consensus on climate change, noting the introduction last month of a bipartisan bill that would set a carbon tax beginning at $15 per metric ton in 2019. The bill is based on the carbon dividend proposal offered last year by Republican party elders James A. Baker III and George P. Schultz. (See Lott, Breaux Join Push for Baker-Schultz CO2 Dividend Plan.)
“Unfortunately, in the House we did lose some more moderate [Republicans] who do believe in climate change science and were willing to engage,” Shaw acknowledged.
Companies are “being forced to act [on decarbonization] because government has failed us,” said Amy Davidsen, North America executive director for the Climate Group, which manages RE100, a collaborative of more than 150 businesses that have committed to using 100% renewable electricity.
Bill Weihl, former Google “green energy czar,” predicted RE 100 companies will grow to more than 300 in the next several years.
Weihl said the big innovation the last few years has been less about technology and more about development of new products, such as the two dozen “green” tariffs in 15 states.
But Hans Royal, director of strategic renewables for Schneider Electric, said many of the tariffs are too expensive or put too much risk on corporate buyers to be effective.
Electrifying Bus Transit
The two-day conference also provided an update on accelerating efforts to electrify city bus fleets.
“The orders for battery electric [buses] are ramping up really rapidly,” said Lisa Jerram, director of bus, paratransit and surface transit for the American Public Transportation Association.
Jerram said only about half of city transit buses are now pure diesel, down from 90% 10 years ago.
Compressed natural gas powers about 25% of fleets now, with hybrid diesel-electrics comprising about 20%, according to Jerram and Ryan Popple, CEO of electric bus maker Proterra.
But Jerram said many transit agencies need utilities’ assistance to make the transition. “They don’t understand utility systems that well; they don’t understand rate structures,” she said. Utilities also can help bus operators manage the logistics of charging in their depots and on routes, she said.
Popple said his company has received orders from 39 states. “If you add up the cities that have already mandated that they’re going electric — that includes … cities like Seattle and New York City — 10,000 of the 70,000 buses on the road are already politically mandated to go electric. So it’s coming. And the things that we figure out on the bus side you’ll need to them again at larger scale in school bus and truck [conversions].”
Europe’s Challenges
The conference heard a keynote address from Laurent Schmitt, secretary-general of the European Network of Transmission System Operators (ENTSO-E), which he described as “kind of the FERC of Europe.” The organization has 43 transmission system operators in 36 countries.
Schmitt said although the Nordic countries are blessed with offshore wind, it is a challenge to move the power to load centers. “Our system does not get planned as efficiently as what we would like, and it’s getting very hard to get transmission lines [sited] in Europe, especially getting people from certain states understanding that they have to build the line for the sake of other Europeans,” he said.
Schmitt said Europe does not use LMPs, “but I think we will have to go into a similar model in the future” to address scarce grid capacity.
Europe also faces challenges as renewables replace traditional generation, he said. Fossil fuels (coal, gas, oil, mixed fuels and peat) were responsible for 43% of Europe’s energy production in 2017, with renewables adding 33% and nuclear 22%.
“Are we going to be able to maintain frequency … when we have no rotating mass?” he asked.
WASHINGTON — Storage resources seeking to provide capacity would face much tougher requirements in some regions than others under proposed tariff revisions filed by RTOs and ISOs last week in compliance with FERC Order 841.
Storage offering capacity would have to continuously supply energy for two hours in ISO-NE, but four hours in NYISO and 10 hours in PJM.
Together, the filings by CAISO (ER19-468), ISO-NE (ER19-470), MISO (ER19-465), NYISO (ER19-467), PJM (ER19-469) and SPP (ER19-460) total more than 2,500 pages. FERC, grid operators and stakeholders now have a year to review, revise and implement the plans under a Dec. 3, 2019, deadline set by the commission when it issued Order 841 in February. (See FERC Rules to Boost Storage Role in Markets.)
The complexity of the revisions led some grid operators to ask FERC to rule on their proposals quickly to give them enough time to implement all the changes by the deadline.
“The implementation of the revisions proposed herein is estimated to cost SPP alone in excess of $800,000, and the magnitude of the effort requires major software and process changes to core SPP systems,” said the RTO, which requested FERC rule by March 1.
NYISO requested that FERC rule by Feb. 1, and it further asked that its implementation deadline be extended to May 1, 2020, because it is in the middle of “a significant upgrade” to its market software.
While MISO did not request an extension, it too is undergoing an overhaul of its market platform, noted Tanya Paslawski, executive director of the Organization of MISO States.
Speaking at Infocast’s Federal Energy Policy Summit on Thursday, Paslawski said “there are limits to what [the RTO] can do” to implement the order given its outdated system. For example, MISO established a 100-kW minimum size requirement for resources — the maximum allowed by the order — “because MISO’s existing market systems do not support offer or bid quantities less than this amount.”
Comments on the filings are due by Dec. 24. Several industry groups — including Advanced Energy Economy, the American Wind Energy Association and the Solar Energy Industries Association — filed a joint request to extend the comment period for another 45 days.
“The standard 21-day comment period will not be adequate for interested parties to review and comment on all of the RTO/ISO compliance filings,” the groups said. “The filings are voluminous and contain proposed revisions to several tariff provisions and market rules.” They also noted that the comment deadline is “in the middle of the holiday season, when many organizations are short-staffed.”
“I think it’s probably likely that the comment deadline gets extended,” Scott Baker, senior business solutions analyst for PJM, said at the summit.
U.S. energy storage annual deployments will reach 3.9 GW by 2023, according to a report released last week by Wood Mackenzie. The report attributes the estimated increase in part to tariff changes spurred by FERC Order 841. | Wood Mackenzie
Requirements Vary
Each grid operator submitted a participation model for storage resources to provide any services of which they are capable, but requirements vary.
“RTOs have largely allowed storage to provide the same services, under the same conditions, as a provided by other types of resources. Sometimes this creates barriers to storage participation,” the New York School of Law’s Institute for Policy Integrity said in an analysis of the filings.
PJM’s “onerous” 10-hour requirement is only possible for most resources “through significant derating of capacity, and even then may not facilitate cost-effective participation in the capacity market,” the institute said.
“PJM also has proposed an accounting framework that effectively requires all charging by energy storage resources participating in PJM’s participation model that are not owned by load-serving entities to discharge (sell their energy) back to PJM,” it continued. “These resources cannot sell to others or use the stored power themselves.”
As for energy markets, resources would have flexibility under the proposals, with some grid operators allowing suppliers to participate in different “modes.” How many modes — and what they’re called — depends on the region.
PJM, for example, proposed to allow three modes: continuous, charge or discharge. In continuous mode, resources can both charge and discharge, with no limitations on start-ups or ramp rate.
NYISO would offer four modes: ISO-committed fixed, ISO-committed flexible, self-committed fixed and self-committed flexible. In the ISO-committed modes, suppliers would leave it up to NYISO to determine the most optimal dispatch times for their resources. In the fixed mode, the ISO would schedule them in the day-ahead market and dispatch them no more frequently than every 15 minutes in the real-time market. In the flexible mode, NYISO would dispatch resources in the real-time market based on LMPs. In the self-committed modes, suppliers would make these decisions themselves.
MISO would allow for eight “commitment statuses”: discharge, emergency discharge, charge, emergency charge, continuous, available, not participating and outage (offline). (See MISO Offers Storage Proposal, Promises to Exceed Order 841.)
Under the proposals, resources will able to participate in any market they choose, without having to participate in others. For example, Baker noted that PJM currently requires resources wishing to provide synchronized reserves also participate in the RTO’s energy market. “In other words, if you were just a battery that didn’t want to participate in the energy market, but you were sitting there and have the capability to respond within 10 minutes to a synchronized reserve signal, we didn’t have the ability for a resource like that to do that,” he said.
In part because of California legislation requiring investor-owned utilities to procure storage, CAISO filed the fewest revisions among the grid operators. One of the more significant changes was that it reduced its minimum size requirement from 500 kW to 100 kW, Andrew Ulmer, ISO director of federal regulatory affairs, noted Thursday.
SPP noted that it gave storage resources in its footprint — all of which are currently pumped hydro and not able to vary their dispatch mode — the ability to stick with its current model for participation or register as a market storage resource (MSR).
The Western Reliability Executive Committee, which is overseeing SPP’s effort to provide reliability coordination (RC) services to more than a dozen Western Interconnection entities, pushed back last week against the Western Electricity Coordinating Council’s suggestion that the RTO coordinate its go-live date with that of CAISO.
SPP, CAISO and Canada’s BC Hydro have agreed to provide RC services in the West in response to Peak Reliability’s surprise move this summer to wind down its operations by the end of 2019. (See CAISO RC Wins Most of the West.)
CAISO will become the RC for its existing territory on July 1, 2019, and take over RC services for many areas outside of California on Nov. 1. SPP will take responsibility for about 12% of the region on Dec. 3.
BC Hydro will become the RC for most of British Columbia on Sept. 2.
SPP Vice President of Operations Bruce Rew told the committee during its Dec. 7 meeting that Peak is concerned that staff attrition may hinder its ability to continue providing RC services as it approaches its wind-down date.
At a WECC meeting last week, Jim Shetler, chair of Peak’s Member Advisory Committee, also said the staggered go-live dates do not afford the organization any room for error. (See related story, RC Transition Fraught with Pitfalls, WECC Hears.)
Rew said that during a recent Western RC-to-RC meeting, WECC said it may offer a streamlined recertification process to Peak and the new Western RC providers during footprint modifications. He said WECC’s actions should mitigate some of the concerns.
“Peak will have already gone through July 1 and Sept. 2 transitions,” Rew said. “As for [Peak] staff, they should have financial incentives to stay until January 2020. I don’t see a significant difference in risk between Nov. 1 and Dec. 3 … but I’m not in Peak’s shoes, either.”
Committee members pointed out that by Dec. 3, Peak will only be handling RC services for a small portion of its footprint. Committee Chair Keith Carman, with Tri-State Generation & Transmission Association, urged SPP to “hold fast and steady” on the Dec. 3 date.
“I’m struggling with what the issue is,” Carman said. “As the footprint gets smaller, they have less to worry about.”
WASHINGTON — California and Illinois won the top spots on the GridWise Alliance’s fifth annual Grid Modernization Index, standing out for their initiatives on energy storage, distributed generation, non-wires alternatives and ratemaking innovations.
Minnesota jumped to 10th place from 21st, and Colorado also jumped several spots to No. 11 in the index, which ranks states and D.C. on policies, customer engagement (rate structures, customer outreach and data collection practices) and grid operations (deployment of technologies such as sensors and smart meters).
GridWise announced the results at the gridConnext 2018 conference, where attendees heard about some of the projects exciting grid technology advocates.
The GridWise Alliance’s Grid Modernization Index ranks states on state policies, customer engagement and grid operations. | GridWise Alliance
GridWise CEO Steve Hauser said California “continues to be the grid modernization trailblazer,” citing its distribution system planning requirements and “multi-pronged approach to support distributed energy resources, including competitive solicitations, multiple DER demo projects, a self-generation incentive program, a net metering tariff, and an energy storage target and default time-of-use rates.”
Speaking at the conference, Courtney Prideaux Smith, chief deputy director of the California Energy Commission, noted that the CEC had just received approval to implement a requirement that new homes include solar panels beginning in 2020.
The new standards require that the solar systems be sized to meet each home’s energy usage and encourage battery storage and heat pump water heaters. The CEC says the new rules and other energy-efficiency initiatives will reduce energy use in new homes by more than 50%.
“It is going to save Californians money starting on day one,” Smith said.
Smith also touted the microgrid developments in the state, citing Borrego Springs, a desert community 90 miles east of San Diego that sits at the end of a transmission line, where frequent outages can leave elderly residents without air conditioning.
After a wildfire knocked out the line in 2007, San Diego Gas & Electric applied for a grant to create what Smith said is one of the world’s largest utility-owned microgrids, which integrates generation and storage and has reduced the community’s greenhouse gas emissions by 20%.
When lightning and flooding knocked out the transmission line again in 2013, Smith said, “the microgrid did exactly what we wanted it to. It islanded, and it directed power to critical infrastructure” — a gas station, a library that served as a cooling center for those who couldn’t relocate, and an elderly community.
Smith also cited a tenant-owned mobile home park in Bakersfield where the state helped add solar power with storage, reducing the low-income community’s net energy consumption by 30%.
Solar panels at Borrego Springs microgrid | San Diego Gas & Electric
Anne Pramaggiore, who oversees Exelon’s six utilities, told the conference about a pilot to build “the world’s first microgrid cluster,” which will connect a solar-powered microgrid in the Bronzeville neighborhood of Chicago to an existing microgrid at the Illinois Institute of Technology. The project was approved by the Illinois Commerce Committee in February.
Solar panels located on a Chicago Housing Authority building will provide power to both the building residents and the microgrid. The plan also includes a “first-mile, last-mile” electric vehicle rideshare program for senior citizens and solar- and battery-powered lighting in areas without streetlights, a STEM education program at local schools, and an energy-efficiency program.
Pramaggiore said Exelon’s utilities also are “beginning to make investments to accelerate the conversion of distribution circuits from 4 kV to 12 kV to accommodate more distributed generation; build[ing] out smart inverters to better integrate diverse resources into the grid; … [and] standing up hosting capacity maps to help customers and developers see where the grid has capacity for solar.”
GridWise also cited the ICC’s approval of an order allowing utilities to recover the costs of cloud-based computing services “seen by many observers as a key pathway to move toward a service orientation (versus the traditional infrastructure focus core to most regulatory regimes).”
GridWise gave Outstanding Progress Awards to Ohio and Rhode Island for recent initiatives.
The Public Utilities Commission of Ohio is pursuing regulatory changes “to support innovation while envisioning the distribution grid as an open-access platform enabling various levels of customer engagement,” GridWise said.
The group said Rhode Island regulators addressed their changing distribution system with new rate design principles and a benefit-cost framework.
CARMEL, Ind. — MISO’s Board of Directors voted unanimously last week to approve the $3.3 billion, 442-project 2018 Transmission Expansion Plan in its entirety despite stakeholder objections to three projects.
Last month, the Planning Advisory Committee withheld endorsement of two MTEP 18 projects: the rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota, and American Transmission Co.’s proposal to replace a 138-kV circuit connecting Michigan’s Upper and Lower peninsulas in the Straits of Mackinac. (See MTEP 18 Advancing with 2 Contentious Projects.)
At the board’s System Planning Committee meeting on Dec. 4, and again at the Dec. 6 board meeting, Xcel Energy’s Carolyn Wetterlin insisted that the Wabaco-Rochester area is “not ripe for a project yet,” asking directors to delay the project for a year so planners can find a better solution to ease congestion in the area. Dairyland Power Cooperative representatives also reiterated their concern that the co-op’s customers would have to pay for an unnecessary line, complaining that MISO staff and board were ignoring stakeholder voices.
MISO’s 10 most expensive projects range from the Mount Pleasant Tech Interconnection ($140 million) to the Natchez SES-Red Gum 115-kV Rebuild ($46 million). | MISO
Meanwhile, Consumers Energy challenged a third project, a $21 million, 138-kV interconnection near the Michigan-Ohio border.
Consumers’ Donald Lynd said Michigan Electric Transmission Co.’s (METC’s) Morenci line is a distribution line under the seven-factor test of FERCOrder 888 because the line would be radial in nature.
“If MISO approves the project, Consumers Energy does intend to seek a determination from FERC,” Lynd announced during a public comment period.
The RTO responded that it had no authority to address Consumers’ request.
“MISO legal staff has reviewed this objection and has determined that under the terms of the Transmission Owners Agreement, asset classification is a matter to be determined between the transmission owner (METC) and FERC,” it said.
“Clearly, we’re at an impasse for at least a few of the projects,” Director Mark Johnson acknowledged before the SPC approved the full MTEP 18.
But he noted that the committee ensured that RTO leadership responded to the stakeholders and followed the MTEP procedure as outlined in the Tariff and Business Practices Manuals.
“I don’t think we should ever have grand illusions that we will have 100% consensus with the size and scope of the projects in Appendix A,” Johnson said.
Director Phyllis Currie said stakeholders should not view the board’s approval of the projects as brushing aside member concerns. “We acknowledge there’s going to be times when there’s disagreement,” she said.
BOSTON — Fuel security topped the agenda at the quarterly meeting of ISO-NE’s Consumer Liaison Group on Thursday.
“While the calendar might not say winter yet, the cold season starts Dec. 1” for the RTO, said Anne George, ISO-NE vice president for external affairs. She highlighted three new ways the RTO is dealing with winter this year, including new measures on fuel security that were approved by FERC earlier in the week. (See ISO-NE Fuel Security Measures Approved.)
First, the Winter Reliability Program was discontinued as Pay-for-Performance incentives took effect June 1. Second, a new energy availability forecasting and reporting framework has been added to the operating procedures to improve situational awareness and encourage proactive measures to avoid energy shortages.
“The third one is a way for resources to price in their opportunity costs for having fuel,” George said. “It was not fully available to do that in the energy market last winter, and we hope that by doing this it gives resources the opportunity to value their fuel and … that the energy market will reflect that value.”
“The wholesale energy markets were not designed to deal with fuel security at all,” said Mark Karl, the RTO’s vice president for market development. “We need to look at where we’ve come from. … The world has changed and so the design objectives need to change.”
In a concurrence on the commission’s Dec. 3 fuel security order, Commissioner Richard Glick wrote that “ISO-NE’s apparent need to retain units for fuel security is the result of a market failure” and that the RTO’s “ultimate approach to fuel security will need to be more sophisticated than the interim approach we approve today.”
Karl said the long-term solution the RTO is considering has three components: multiple day-ahead markets, a new ancillary service that’s integrated into that, and a new, voluntary, forward seasonal auction.
The RTO plans to launch a quantitative and qualitative analysis on its proposal, including potential cost impacts, next year and file a proposal with FERC by July 1, 2019, he said.
The new ancillary service would seek “to maintain an inventory — what we call a buffer stock in economics — of fuel that can be converted into electricity.”
While current markets optimize over a single day, the new design will optimize fuel supplies and stored energy over five or six days, Karl said. The voluntary auction is intended to provide an incentive for resource owners to procure fuel inventory for the next winter.
FERC’s ruling, which approved an out-of-market agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022, endorsed the ISO-NE proposal and rejected all of the New England Power Pool’s suggestions, said Paul Peterson of Synapse Energy Economics, which serves numerous NEPOOL participants, mostly in the End User and Alternative Resources sectors.
The NEPOOL alternative proposals approved by stakeholders and filed with FERC would limit the retention of resources for fuel security to Forward Capacity Auction 14, covering 2024-2025, and add FCA 15 only if necessary. NEPOOL also recommended requiring generators to report fuel status for winter; raising the threshold for triggering a fuel security reliability contract; and allocating reliability costs to the transmission portion of bill to reduce risk premiums from suppliers.
“Time will tell,” Peterson said. “We’ll have an opportunity four or five years from now to see whether or not the levels of fuel security that the [RTO] used to justify retention of Mystic really were true.
“And that’s one of the concerns on the ongoing back-and-forth between NEPOOL stakeholders and ISO-NE: What level of risk? What level of reliability? What level of cost? How are those things balanced out in a way that makes the region reasonably secure in the delivery of electricity?” Peterson said.
“How do we get an adequate supply of natural gas? How long is it going to take to build the offshore wind projects?” asked Massachusetts Rep. Thomas Golden, House chair of the state legislature’s Joint Committee on Telecommunications, Utilities and Energy.
“There’s a misperception that New England is seeing a continually increasing demand for natural gas to generate electricity,” Peterson said.
“Since 2010, the share of power generated by natural gas has grown, but overall consumption of gas has declined and will continue to do so,” Peterson said. “By our projections, demand for natural gas in 2030 will have declined 41% from 2015 figures.” Peterson’s projection assumes the operation of a Massachusetts “clean hydro” transmission line by 2023 and the addition of 1,600 MW of offshore wind in 2027.
Millstone
Eric Annes, a technology analyst with Connecticut’s Department of Energy and Environmental Protection (DEEP), said that both DEEP and the state’s Public Utilities Regulatory Authority have found Dominion Energy’s Millstone nuclear plant to be at risk and that the 2,111-MW plant “is critical to our carbon goals and to winter fuel security.” (See Connecticut Likely to OK Millstone for Zero-carbon RFP.)
“No one has had experience with the winter we’re about to experience this year or will experience the next couple of years,” Peterson said. “Suppliers don’t know what kind of costs they’re going to be facing. When they go to customers to offer them a bid for energy supply for 18 months or two years in the future, they’re going to put a risk premium on that because of the costs they don’t know whether they can take care of or not — they don’t even know how big they’re going to be.”
The CLG on Thursday elected a new coordinating committee for the 2019-2020 term. The new members and their respective states are: Deena Frankel (Vt.); August Fromuth (N.H.); Douglas Gablinske (R.I.); D. Maurice Kreis (N.H.); Erika Niedowski (R.I.); Guy Page (Vt.); Robert Rio (Mass.); Joseph Rosenthal (Conn.); Mary Smith (Mass.); Rebecca Tepper (Mass.); Mary Usovicz (Mass.); and Liz Wyman (Maine).
CARMEL, Ind. — The MISO Board of Directors last week approved the RTO’s 2019 capital and operating budgets, allocating $20.5 million for another year of the RTO’s ongoing effort to replace its market platform.
MISO sought a $312.6 million operating budget, a 3% decrease from 2018, and a $27.2 million capital budget, an 8.3% decrease. The RTO’s administrative fee will continue to be 40 cents/MWh in 2019, the same as 2018’s rate.
Kevin Caringer, executive director of MISO’s technology team, praised early-phase vendor General Electric for attracting the usual levels of talent to the company despite its publicized troubles.
During a meeting of the board’s Technology Committee on Dec. 4, Caringer said MISO is currently “withholding judgment but having healthy skepticism” about GE’s ability to deliver software needed to clear the day-ahead market until future platform deliveries are evaluated by the RTO. GE is supposed to have an updated delivery schedule to MISO by the year-end.
Further talk on GE’s schedule was held for closed session of the board at the advice of MISO General Counsel Andre Porter.
The RTO will not announce a recommended platform vendor until the fourth quarter of 2019, when it finishes evaluating alternatives.
Director Michael Curran asked MISO to create milestones to gauge GE’s progress throughout 2019. “I’m struck by the fact that it’s going to be 2019 fourth quarter before we have a sense of the performance,” he said.
Caringer said that executives will provide quarterly updates.
MISO executives also confirmed that they have deliverable expectations for GE’s work but did not reveal dates.
Director Baljit Dail said he felt more positive about GE’s plan and new employees. He said the platform replacement schedule was on a “dark” trajectory earlier in 2018. (See MISO Platform Replacement Risks Delay, Budget Overrun.)
By the first quarter of 2019, MISO will upgrade its web service to support modern browsers.
“It’s a marathon, and we’re into the first 5 miles of it. We’ve hit a really, really good pace,” Dail told MISO executives, while commending the RTO’s work on the project so far.
DART Outages
During an IT scorecard presentation, MISO staff disclosed it suffered an outage of its day-ahead and real-time (DART) application on the afternoon of Sept. 11. The RTO said a process within the program was unresponsive, causing its unit dispatch system and look-ahead commitment tool to miss the targeted solve time of five minutes. MISO said the unit dispatch system, look-ahead commitment tool and its coordinated transaction scheduler were not solving, leading the RTO to perform manual workarounds during the 40-minute outage and restart.
MISO said it experiences DART outages occasionally and the problem requires a solution from GE. RTO staff said it provided operator logs to GE detailing the outage.
Curran, Kozey Get MISO Send-off
Porter will take over as board secretary in 2019, replacing outgoing Senior Vice President Stephen Kozey, board members have decided.
The board voted in closed session on the succession decision. As a rule, all MISO personnel matters are taken up privately.
“I won’t say you have you have big shoes to fill … I would say you have a big head to fill,” Curran told Porter, and after a beat and audience laughter, he said, “That probably didn’t come out right.”
Kozey is retiring at the end of the year after more than 18 years of service in MISO. Curran said Kozey helped build the RTO’s legal team and commemorated him with some of the first written words about Kozey in the MISO record: “The candidate has been recruited without the expense of an outside recruiting firm.”
The audience laughed then gave Kozey a standing ovation.
Curran, also departing MISO at the end of the year, likewise got a standing ovation. Curran has served on the board for 12 years.
Outside board counsel Karl Zobrist lauded Curran’s insistence on “plain language and transparency” during his board tenure.
“I’ve only known you for two years, but it feels like 20. You are the most generous mentor I’ve had,” Director Barbara Krumsiek told Curran.
Director Thomas Rainwater praised Curran’s “directness” and took a benevolent jab at him for now having to deal with ISO-NE’s sloped capacity demand curve. Curran, who will join ISO-NE’s Board of Directors in 2019, has long sparred with Independent Market Monitor David Patton over his appeals to adopt a downward-sloping demand curve in the MISO capacity market.
“I actually like you,” Director Mark Johnson joked. MISO CEO John Bear borrowed a Curran phrase and called him “wicked smart.”
Curran signed off saying, “I refuse to say ‘goodbye’; it’s ‘see you later.’”
The board approved into MISO membership non-transmission-owning businesses Cleco Cajun, Nuclear Development, TransCanada Energy Sales, Xcel Energy Acorn Transmission and Xcel Energy Birch Transmission. The board also approved the transmission-owning membership application of the city of Henderson. The western Kentucky municipality owns Henderson Municipal Power and Light.
