Robb, who has led WECC since 2014, has more than 30 years of experience as a power sector engineer, consultant and senior executive. He formerly served in senior roles at both Northeast Utilities (now Eversource Energy) and Reliant Energy.
“The board took this duty very seriously by engaging in a comprehensive, nationwide search culminating in the unanimous selection of Jim Robb,” NERC Board of Trustees Chairman Roy Thilly said in a statement. “We are confident that Jim will provide the combination of strong leadership, vision and commitment to the reliability and security of the bulk power system across North America that is essential to NERC’s continuing success.”
NERC has been without a CEO since Gerry Cauley stepped down last November after being arrested for allegedly assaulting his estranged wife, who told police he had been involved in a sexual relationship with a female employee at the agency. (See Cauley Resigns; NERC Launches Search for Replacement.)
Cauley had served as NERC CEO since January 2010 and was often the face of the reliability agency in hearings before FERC and Congress. NERC General Counsel Charles Berardesco has been serving as acting CEO.
As head of WECC, Robb led NERC’s largest Regional Entity, “where he improved member relations, strengthened the management team and expanded collaboration with NERC and other Regional Entities,” NERC said. WECC’s territory covers all or part of 14 Western states, Alberta and British Columbia in Canada, and the northern portion of Baja California in Mexico.
“I have been fortunate to lead WECC and be a part of the NERC-enterprise family for the past four years, and I look forward to the next chapter of my career leading the” FERC-certified Electric Reliability Organization, Robb said. “This experience, combined with my past industry knowledge, has prepared me for this exciting opportunity at NERC.”
WECC said it will search for a replacement for Robb over the next several months. It has appointed Vice President and General Counsel Steven Goodwill as interim CEO. Goodwill is not a candidate for the top job.
In a written statement, WECC Board of Directors Chair Kristine Hafner said Robb’s “unrelenting focus on effectively and efficiently reducing risks to the reliability and security of the bulk power system in the Western Interconnection has been vital to the 80 million people within our footprint who rely on power for their day-to-day lives.”
Salt Lake City-based WECC is in the midst of revamping its operations following its 2014 restructuring into the current WECC and Vancouver, Wash.-based Peak Reliability. (See WECC Finding New Direction in Old Mission.) Among the changes in the works to refocus the RE on its reliability functions is a renaming to Reliability West. Other changes in the organization’s bylaws are proposed for a possible June vote by WECC members.
PJM’s Board of Managers last week assured Pennsylvania legislators that the state has ample power generation for its needs and cautioned that fuel diversity will not ensure reliability.
The RTO was responding to a Feb. 9 letter from the state legislature’s Nuclear Energy Caucus with its own letter that seemed intended to assuage lawmakers’ fears about of blackouts and grid interruptions caused by inadequate resources. While the caucus’s message referred only to “baseload” units, it did voice support for several FERC and PJM initiatives that would benefit coal and nuclear plants.
Peach Bottom Nuclear Generating Station in 1974
“We are losing confidence in the ability of wholesale electric markets to ensure Pennsylvania maintains a diverse supply of baseload generation resources that ensure stable prices for our citizens and a reliable and resilient electrical grid,” the caucus wrote. “Pennsylvania’s baseload power plants continue to face the risk of premature retirement, and we do not see expeditious and sufficient action being taken by PJM or the Federal Energy Regulatory Commission to correct the market flaws at the heart of this problem — flaws that PJM itself acknowledges.”
PJM’s Independent Market Monitor noted last week in its 2017 State of the Market report that just 52% of coal-fired plants in the RTO recovered their avoidable costs in 2017. All of Pennsylvania’s five nuclear facilities made enough money to cover their costs last year, although none did in 2016, the report showed. Three Mile Island has seen negative revenues since 2015 and will continue to through 2020 unless market changes occur, while the other four will remain profitable through that year. (See IMM Report Says PJM Prices Sufficient.)
Adequacy Assured
PJM CEO Andy Ott penned the response to the caucus, which defended the RTO’s operations. Ott noted that Pennsylvania has built more than 12,000 MW of new generation over the 20 years that the RTO has managed its grid, calling it “a direct result of the investment signals sent by the PJM wholesale market.”
In the past six years, Pennsylvania has produced between 18 and 27% more energy than it needed, equating to about 6,500 MW of generation, or nearly two-thirds of the Keystone State’s nuclear fleet, Ott said.
While the caucus’s letter never mentioned costs, Ott remained focused on them, noting that “PJM markets have yielded reliability at the lowest cost for Pennsylvania.”
“The dramatic increase in wholesale power prices during that period highlight the risk of overreliance on any single fuel source, a risk we believe PJM can and should avoid by swiftly enacting reforms,” the legislators wrote. “We believe that [PJM’s price-formation proposal] is an important first step in recognizing the benefits of fuel diversity within this market, and one that will help keep our grid — and power prices — stable for many years to come.”
Ott noted in his response that both the RTO and Pennsylvania are more fuel-diverse today than ever, but downplayed the significance of that fact.
“Fuel diversity, however, is not a metric with which PJM can measure reliability,” he said. “Instead, fuel security — the certainty of fuel availability for power production — affects reliability.”
Market Changes
The caucus supported PJM’s efforts to revise its energy price-formation methodology, calling the current process “a flaw in its market rules that unfairly disadvantages certain low-cost baseload generation resources” by not allowing them to set clearing prices. As a result, “market prices are artificially low and do not reflect the true cost of meeting customer demand.” It gave PJM “credit” for developing “a potential solution.”
The RTO’s solution is a controversial plan to allow large, inflexible units like coal and nuclear to set clearing prices. Currently, those plants’ bids are often among the highest of dispatched units, but only “flexible” units that can regulate their output in response to price signals are allowed to set prices. The inflexible units receive subsequent “uplift” payments to cover their operating costs. In PJM’s plan, those units would set price and the flexible units would be paid additional revenue to back down their output to avoid oversupply.
Critics of the plan argue that plants that don’t receive enough revenue in the competitive market should take that as a signal to shut down, not change the rules.
The caucus called the proposal “an important first step” but said it “will not fully correct the existing market flaws nor fully provide the compensation necessary to maintain baseload resources.” Still, a failure to implement the plan “will continue to inequitably exacerbate the financial challenges” those units face, the lawmakers said.
While Ott did not specifically address PJM’s price-formation proposal, he acknowledged “there is room for markets to more sharply define power grid requirements.”
“Efforts are underway to improve wholesale market price efficiency for all the resources that rely upon the wholesale market to compensate them for their services, and appropriately to provide transparent investment signals,” he assured the legislators.
In his market report, Monitor Joe Bowring said the changes were not based on market flaws. Nearly 79% of the $24.7 million in uplift costs from day-ahead operating reserve differences were paid to coal units in 2017, but not because of market design issues, he said.
“That actually has to do with some very specific circumstances about coal units that have nothing to do with convexity and non-convexity and would not be affected by PJM’s price-formation proposal,” Bowring said.
FERC Resilience
The caucus also applauded PJM’s proposal as “entirely consistent” with the state legislature’s resolution in October calling on FERC to address the U.S. Department of Energy’s Notice of Proposed Rulemaking to financially support baseload generation. FERC denied the NOPR request in January but opened a docket to investigate concerns about the resilience of the nation’s energy grid.
The caucus endorsed the new docket as “an early step” and said it plans to press for any recommended changes that emerge from it.
“We are encouraged that FERC valued our concerns,” the caucus wrote. “You should know that as elected lawmakers ultimately responsible for our commonwealth’s energy policy, we will engage in the discussion and strongly support urgent implementation of critical findings.”
CARMEL, Ind. — After six months of little progress, stakeholders are now asking MISO to consider changing its billing practices to reflect how behind-the-meter resources use the transmission system.
But the RTO says it’s still collecting stakeholder input before it develops an official stance on multiple BTM measures.
“In large part, we’re still in listening mode here,” MISO Director of Planning Jeff Webb said at a March 14 Planning Advisory Committee meeting.
The RTO is still working with stakeholders to determine whether it should account for net or gross BTM load when it assesses network integration transmission service.
“I think that’s the debate here: whether behind-the-meter uses the transmission system for load, uses it sufficiently enough or uses it on peak,” Webb said. “Under what circumstances are costs incurred [from load typically served by BTM generation] when building the transmission system?”
The RTO must also settle on planning study assumptions for both registered and unregistered BTM generation and determine whether BTM retirements should be subject to a formal Attachment Y notice and subsequent reliability studies.
Last year, WEC Energy Group proposed that all resources be required to register with MISO as a network resource before being authorized to fulfill capacity obligations. That proposal aligns with an existing RTO plan to implement a one-time deliverability test for BTM generators that could trigger a requirement to acquire network service in an upcoming capacity auction. (See WEC Takes Stab at MISO Behind-the-Meter Definition.)
Webb said MISO will continue to discuss how to plan for BTM generation at the PAC’s April meeting and that the conversation would likely extend until the end of the year.
“We’ll make some sort of strawman proposal and let people beat up on that for awhile until we get something,” Webb said. “Let’s keep the dialogue going here.”
Stakeholders: Tx Charge Rewrite?
The question of how to bill BTM generation for transmission use sparked a larger conversation on revising transmission use charges in the face changing load shapes in MISO.
Veriquest Group’s David Harlan said MISO is headed for a future of more complex and “spiky” load shapes attributable in part to BTM generation, possibly requiring the RTO to reassess how it bills for transmission use.
“In the past we’ve expected load shapes to be fairly predictable and planned around peak. I think what we’re increasingly seeing is that when you connect to the transmission or distribution system, there’s an option value. You can either inject or withdraw. What’s the proper way of accounting for that option right?”
Wisconsin Public Service’s Chris Plante said his company has also been discussing a more nuanced approach to transmission billing.
“I think more and more we’re not just building transmission for the peak, but for energy withdrawal,” Plante said.
Representing Illinois Industrial Energy Consumers, Jim Dauphinais said he’d like to see the transmission charge issue contained within the broader BTM subject, noting that MISO’s Regional Expansion Criteria and Benefits Working Group is responsible for proposing transmission cost-sharing policies.
Webb said he supported limiting the issue to how MISO plans for and bills for BTM generation ― for now.
“I think maybe we bite off what we can here,” Webb said. “I think we’re in a — every generation says this — but we’re in a transitional period. There’s growing uncertainty about the load that we plan for.”
LOS ANGELES — CAISO’s proposal to extend its day-ahead market across the Western Energy Imbalance Market (EIM) could be tailored to uniquely fit a region historically resistant to organized markets, a key participant in the roll-out of the EIM said.
The ISO’s Extended Day-Ahead Market (EDAM) proposal could also be done without the political and economic entanglements involved with an RTO, Portland General Electric Director of Transmission Services Sarah Edmonds said during a March 9 public meeting of the EIM Regional Issues Forum (RIF). It could strike a balance between an ISO transmission access charge and a full RTO construct, she said.
“It is possible that with EDAM, a different construct will be born,” Edmonds said, adding that her comments reflected her own opinions, but they are “illustrative of the kinds of questions and issues the EIM community would be looking at” to determine their interest in day-ahead market participation.
In her previous job as general counsel for PacifiCorp, Edmonds served on the EIM’s Transitional Committee, which advised CAISO’s Board of Governors on the development of the market’s governance structure.
A “winning feature” of the EIM has been that participating balancing authority areas retain their responsibilities and control, Edmonds said, pointing also to the benefits of voluntary participation and no exit fee. But as they explore EDAM, industry participants will need to address the many issues around how excess transmission capacity is shared. (See CAISO Plan Extends Day-Ahead Market to EIM.)
As for an RTO, the issue of governance — which was still being debated in the California legislature when last year’s regionalization effort stalled — is “center stage,” Edmonds said. Lawmakers are working on new legislation this session. (See Calif. Lawmakers Relaunch CAISO Regionalization.)
Governance is important because “the power of who gets to decide what issue is a big deal when you are talking about what comes with a full regional ISO,” Edmonds said.
Industry stakeholders still have many questions about transmission development and costs in a Western RTO because of the longer transmission lines, distance between loads and other planning considerations such as increased adoptions of distributed energy. Other complications include state roles in resource adequacy planning, transmission access charges and a regional transmission planning framework, she said.
“These issues really come up and are of particular concern in a regional ISO context,” she said, adding that there is also a “deeply ingrained culture of self-determination in the West.”
‘A Lot of Work’
Kathy Anderson, Idaho Power systems operations leader, told the RIF that her utility has been working on EIM implementation for two years and is due to go fully live on April 4, having shifted the date from April 1 because of the Easter holiday. One of the uses of the market will be to market renewable energy from qualifying facilities under the Public Utilities Regulatory Policies Act.
Anderson told the forum that the two-year process to integrate into the EIM has not been easy.
“I don’t think I really appreciated it until I was right in the middle of it. It was a lot of work,” Anderson said. “There were very few places in the company that we didn’t touch with this.”
The company employed three full-time external contractors and hired 6 employees to work directly on the EIM. It also required new software applications and outage management system.
Idaho Power and Canadian marketer Powerex have been in parallel operations with the EIM, in preparation for going live early next month. (See EIM Participants Seek Resource Test Tweaks.)
SPP’s Board of Directors and Members Committee on Tuesday approved a set of conditions that will guide Mountain West Transmission Group’s pending membership into the RTO.
SPP said the board’s endorsement during a special meeting in Dallas represents “a vote of confidence in the value of Mountain West’s membership and the benefits it will bring to SPP’s existing members, the Mountain West entities” and their customers.
COO Carl Monroe, who has been leading the RTO’s team during the negotiations, told RTO Insider he has been pleased with the work so far.
“We have been able to alleviate some of [Mountain West’s] concerns with joining SPP,” Monroe said Wednesday. “We’ve been able to work together and move forward. We’re pleased to come to this point, where we have general agreement of the things that are required to have Mountain West join SPP.”
The board approved 18 policy statements and directed staff and stakeholders to begin revising SPP’s Tariff, bylaws, membership agreement and other governing documents. The RTO’s Corporate Governance Committee and working groups will coordinate the work through the normal stakeholder process.
Changes to SPP’s Governing Documents Tariff will be presented for approval by stakeholder groups prior to going to the Members Committee and board.
The policies govern the terms of SPP membership, governance, the cost to operate the four DC ties in the SPP footprint, transmission planning and resource adequacy, and rates and revenue. SPP’s Regional State Committee would be expanded to include state commissioners from the Mountain West region.
SPP has scheduled a webinar on March 22 to provide further detail on the policies.
SPP and Mountain West members have been meeting behind closed doors since October to discuss the move. Monroe told stakeholders in January that a small negotiating team had been working to resolve a subset of “real contentious” issues. The Mountain West entities have suggested several governance changes important to their side of the footprint. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)
Mountain West has said studies have shown participating in SPP’s markets and efficiently using the DC ties between the two footprints would yield annual savings of $80 million to $154 million for its members. The entities also expect to realize additional benefits from regional transmission planning and SPP’s other services.
SPP has estimated its current members could receive more than $500 million in total net benefits over the first 10 years of Mountain West’s membership through reduced administrative costs because of a larger customer rate base, adjusted production cost savings from east-west energy exchanges and capacity cost savings from increased load diversity.
The RTO projects it will take about two years to fully integrate the Mountain West entities as members, but it plans to begin reliability coordination services in late 2019.
SPP currently serves a 546,000-square-mile, 14-state region. Mountain West’s membership would add 165,000 square miles, 16,000 miles of transmission lines, 21 GW of generating capacity and parts of three more states (Arizona, Colorado and Utah) to the RTO’s footprint.
Mountain West, which primarily services Colorado, Wyoming and Nebraska, began discussing RTO membership in 2013. It announced in January 2017 it was pursuing membership in SPP, and discussions entered a public phase in October. (See SPP, Mountain West Integration Work Goes Public.)
New York stakeholders on Monday wrestled with the complex issue of how to evaluate the impact of a carbon charge on the dispatch of energy resources — especially in neighboring regions.
It was part of an ongoing effort by the Integrating Public Policy Task Force (IPPTF) to determine how to price carbon emissions into NYISO’s wholesale electricity market.
The group, a joint effort between NYISO and the state’s Department of Public Service, also discussed a method for calculating marginal emission rates, the allocation of carbon revenues and the effect of carbon pricing on customer bills — all part of “Track 5” of the carbon pricing initiative.
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The group also touched on issues related to “Track 4,” which covers the interaction of carbon pricing with other state and regional programs, such as the renewable energy credit and zero-emissions credit programs, as well as the Regional Greenhouse Gas Initiative.
Assumptions and Metrics
“We are interested in looking at not just the financial impacts but also at what happens to emissions,” said task force co-chair Nicole Bouchez, NYISO market design specialist.
“How do we assume the cases?” Bouchez asked. “Do we assume there’s a change in RGGI or not? In realization that we’re not going to be able to run dozens of permutations, what are the key assumptions?”
If the group “ends up modeling emissions in neighboring regions, for example in Ontario, which trades with MISO, then you have to model all of MISO’s resources,” she said. “While Ontario may look like a low-carbon import … if all it’s doing is causing MISO coal use to go up, then not so much.”
Marc Montalvo, representing the DPS Utility Intervention Unit, said, “If we’re designing a policy and implementation, if success is highly dependent on having perfect or near-perfect information about our neighbors’ emissions rates and those kinds of things, then it’s probably not a good policy in the first instance.”
Bouchez said the group’s May 7 and 21 meetings would focus “on how to structure the analysis, what questions, what metrics we’ll be reporting, etc.”
Defining Impacts
During a discussion of the impact of carbon pricing on consumer costs, Bouchez said the ISO’s locational-based marginal pricing (LBMP) represents “only the beginning of impacts on consumers because we’re also going to be looking at the return of these residuals associated with a carbon charge to consumers, so you can’t just look at the LBMP increase on its own.” The “residuals” refer to leftover money refunded to load under a carbon pricing scheme.
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Representing a coalition of large industrial, commercial and institutional energy users, Couch White attorney Michael Mager said his clients were seeking “two big things” from the impact analyses. First, “a thorough, unbiased analysis” of the impacts on market prices and what consumers are paying.
“And the second piece is, what are the emission reductions, if any, that reasonably could be anticipated if this were to be done,” Mager said.
New York could see some really material carbon reductions if it starts retiring unused RGGI allowances, he said.
“On the other hand, if nothing is being done to RGGI whatsoever, and it’s just going to simply reduce the price of allowances that are going to be then used up by other states such that there’s little to no reduction in carbon throughout the RGGI region, then this whole effort strikes us as somewhat symbolic and not getting much for any price impacts,” he said.
Howard Fromer of PSEG Power New York asked, “Consumer impacts compared to what?
“And the what is not identified here,” Fromer said. “Obviously, the what, in my mind, has to include the fact that New York state right now is already spending and writing checks on a monthly basis and potentially, over the period that we’re talking about, could be spending billions of dollars.”
Fromer said that, aside from considering dispatch issues, the task force process also needs to consider the impact of a carbon charge on price signals, demand response and investment in the state’s 40,000-MW generation fleet.
No Pot of Money
Stakeholders asked how the trend of increasing electrification — in the transportation sector, for example — should affect pricing carbon into the wholesale market.
Bouchez said many experts have told her the price of electricity has very little to do with electrification.
Bob Wyman of Dandelion Energy countered that electricity prices definitely affect consumer choices in New York City, where Consolidated Edison learned that city residents who install heat pumps use them for air conditioning but simply turn them off in winter because of high electricity prices for heating.
“Whether this approach is complementary or designed to supplant the mandated programs [such as the state’s Clean Energy Standard] … to the extent that you are supplementing the existing programs, the issue is always about what are the incremental benefits, does it affect dispatch, new investment, how are the effects by zones, and you have to address those transition overlap and windfall revenue questions as part of the impact analysis,” said James Brew of Nucor Steel Auburn.
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He said New York is relatively unique in trying to pursue both mandated and market programs, which means any analysis has to examine how the two programs interact.
David Clarke, director of wholesale market policy at the Long Island Power Authority, said carbon revenue collections within RGGI states would be a useful metric for examining the cost of abatement.
“I know we’re going to be looking at how much folks are paying for carbon allowances within New York as kind of the pot of money that we’re going to be splitting, but it would also be useful, depending on what scenario you are running, to find out what folks are collecting in terms of RGGI revenues within the other RGGI states,” Clarke said.
“There will be no pot of money,” Bouchez said. “I’ve been talking about them as residuals, which is how NYISO sees them, residuals being the difference between what we collect and what we pay out. How you allocate that within the wholesale settlements is a question. Do you give it back on a per-megawatt-hour basis? Do you give it back based on the impact of the increase in the LBMP?”
Warren Myers, DPS chief of regulatory economics, said that the joint staff are “nowhere near having an answer” on how to integrate multiple analyses into something useful but that “the work would get done by rolling up our sleeves” over the next few months.
The task force will next meet on March 19 to discuss Track 5 at NYISO headquarters.
FERC on Monday approved MISO Tariff revisions allowing the RTO to gather more information about proposed energy resources before they enter the interconnection queue.
Key among the changes is a requirement that a developer provide clearer upfront information about who will own a generating unit once its clears the queue.
In its ruling, FERC agreed the changes will “provide greater clarity to interconnection customers and greater transparency to all parties in the interconnection process” (ER18–636). The new measures became effective March 1.
Under the new rules, interconnection customers must provide MISO upfront documentation of “legally binding relationships” with parties that may claim ownership rights to a facility during the interconnection process.
MISO said the change will reduce the time it spends confirming ownership changes and will be necessary only when an interconnection customer “reasonably anticipates” another entity may claim ownership rights. The documentation would be limited to “that necessary to confirm the legal status and relationship of the relevant entities,” the RTO said.
Interconnection customers associated with a project can sometimes change during the definitive planning phase (DPP) of the interconnection queue, MISO said in its filing. In those cases, the RTO must confirm the legal status and relationship between the original and newly designated interconnection customers, creating an “administrative burden … that hinders the ability of MISO staff to administer other aspects” of the DPP.
“Requiring documentation proving legally binding relationships with entities that the interconnection customer reasonably anticipates may claim rights under the interconnection request upfront in the interconnection request form will ease administrative burden if a facility changes ownership later in the interconnection process,” FERC said, adding the change will help expedite projects moving through the DPP.
The commission rejected EDF Renewable Energy’s protest that MISO didn’t justify its need for the additional detail and that the changes would give the RTO more information than it needed. The company alternatively proposed that interconnection customers provide MISO with documentation “confirming a legally binding status upon requesting a name change,” rather than at the outset of the process. FERC said EDF was conflating name changes with changes in ownership status.
The Tariff revisions also require interconnection customers to provide MISO with IRS W-9 forms; banking information (including for other companies that may claim ownership in a generating facility); GPS coordinates for the point of interconnection for a project; descriptions of the number of generators, inverters, and transformers involved in the interconnection request; and additional contact information when a customer uses an agent.
They also expand the service options listed on MISO’s interconnection request form, allowing customers to specify a net-zero interconnection service request for an existing facility with no increase in capacity; indicate whether a request should be considered for the RTO’s fast-tracked process offered to small generating facilities; and inform MISO when a request for network resource interconnection service is intended for an existing facility.
The new rules additionally stipulate that net-zero interconnection customers must attach a system impact study to their requests and provide MISO with all necessary data before generator interconnection agreement negotiations can begin.
CARMEL, Ind. — MISO and its stakeholders have agreed on a plan to treat merchant HVDC lines as transmission instead of generation when physically connecting to the RTO’s system.
A year in the works, the proposed Tariff revision would subject merchant HVDC lines to MISO’s traditional transmission schedule charges and make them ineligible for interconnection service. The RTO will file the proposal with FERC by the end of this month.
Speaking at a March 14 Planning Advisory Committee meeting, MISO Director of Resource Utilization Vikram Godbole said the proposal does not prescribe any revenue plans for developers of merchant HVDC service. Developers would instead be responsible for determining the “net economic viability of their merchant HVDC project by considering their revenue streams and cost to connect to MISO transmission,” he said.
Some stakeholders asked how the RTO will treat transmission upgrades needed to connect HVDC lines in the interconnection queue.
“They’re not going to have interconnection rights,” Godbole said, adding that the lines will instead connect to the MISO system at a 0-MW status.
Under the changes, MISO will hold discussions with HVDC developers and owners before grid connection to determine whether a line is designed to withdraw or inject energy into the system, Godbole said. The RTO will require upstream generators contracting with injecting lines to procure network resource service through the interconnection queue, subject to system impact studies. Those units will be modeled like MISO’s other network resources, showing up in planning studies. Merchant HVDC customers that have secured injection rights and interconnection customers will share the costs of any needed network upgrades.
Meanwhile, merchant HVDC developers will be required to acquire MISO injection rights or a precertification that the system will be able to reliably handle the capacity and energy from proposed lines at the point of connection. (See “HVDC Interconnection,” MISO Eyes Small Queue Changes, Merchant DC Interconnections.)
Godbole acknowledged that MISO may eventually need to develop a more nuanced connection plan for merchant HVDC lines, but that, for now, it is focused on allowing such lines to connect to the system.
CARMEL, Ind. — After almost three years of deliberation, MISO is putting the final touches on a plan to create external resource zones for its annual capacity auction by 2019.
Under the proposal, which is poised for a FERC filing at the end of this month, MISO would alter its Planning Resource Auction to include external resource zones based on neighboring balancing authority areas (BAAs). In cases of price separation, the RTO would also distribute historical supply arrangement credits from excess auction revenues as a refund to external resources with long-term and consistently used historical supply agreements.
The proposal would also establish new zonal capacity export limits in time for the 2019/20 planning year auction. Those limits would be based on the unforced capacity values for external resources participating in the auction in each external zone.
External zones would not have capacity import limits, planning reserve margin requirements or local clearing requirements. Resources in zones based on BAAs that border MISO Midwest zones will clear at one price based on a subregional unconstrained auction clearing price, while those in BAAs bordering MISO South will receive another price. BAAs that border both MISO Midwest and MISO South — Tennessee Valley Authority, SPP, Associated Electric Cooperative Inc. and Southwestern Power Administration — will receive a blended price. (See MISO Postpones External Zones Until 2019 Auction.)
Speaking at a March 7 Resource Adequacy Subcommittee, Laura Rauch, MISO’s director of resource adequacy coordination, said the RTO would provide capacity hedges only to external resources with historical capacity arrangements, despite stakeholder requests for hedges for other newer external resources.
MISO intends to tweak the proposal before filing, including adding potential penalties for external resources that don’t offer into the PRA after qualifying and registering for the auction. Under the current proposal, those resources would only face “questions” from the Independent Market Monitor but face no specific consequences for withholding, Manager of Resource Adequacy John Harmon said.
Rauch also said stakeholders are still asking how MISO will differentiate a “border external resource” from other external resources. In November, MISO said it identified 3,837 MW of capacity from potential border external resources, which have direct electrical connections to the RTO but are located in another balancing authority. Some stakeholders last month said that the concept of border resources amounts to preferential treatment of some external resources.
Rauch clarified that a border external resource’s point of interconnection must be a substation on the border.
“We really want these to be resources physically on the border,” she said.
MISO will rely on the volume of zonal capacity registered to participate in the auction to calculate an external zone’s capacity export limits, which will be posted each November ahead of the auction, Rauch said. Participating resources must maintain firm transmission to at least the MISO border, she noted.
“Trying to study a slice of PJM or SPP” to determine a capacity export limit is too complex a task, Rauch said.
She said MISO does not foresee any binding external capacity export limits, except in rare cases that exports fail a simultaneous feasibility test.
If FERC approves the filing, MISO will begin developing business practice manual language with stakeholders beginning in June, Rauch said.
Meanwhile, MISO will open its 2018/19 PRA offer window at 12:01 a.m. on March 27 and close it on March 30 at 11:59 p.m. Results will be posted by April 12.
SPP has scheduled an executive session of its Board of Directors and Members Committee for Tuesday to discuss admitting Mountain West Transmission Group’s members into the RTO.
The meeting is being held at an undisclosed location. SPP has often used Dallas/Fort Worth International Airport to meet for its ease of access and onsite hospitality facilities.
SPP CEO Nick Brown told the Board of Directors in January the RTO was hoping to hold a “decision meeting” for members at the end of February for those stakeholders “who need to engage outside counsel and consultants, who previously were not engaged in the debate.”
SPP and Mountain West members have been meeting behind closed doors since October. SPP COO Carl Monroe told stakeholders in January that a small negotiating team had been working to resolve a subset of “real contentious” issues. The Mountain West entities have suggested several governance changes important to their side of the footprint. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)
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Brown said SPP’s primary goal for 2018 is integrating Mountain West. “Our goal is to get it over the line in early 2018,” he said.
With members primarily serving Colorado, Wyoming and Nebraska, Mountain West began discussing joining or creating an RTO in 2013. It announced in January 2017 it was pursuing membership in SPP, and discussions entered a public phase in October. (See SPP, Mountain West Integration Work Goes Public.)
The two entities are working on an Oct. 1, 2019, target date for membership.
Record $6.9M in January for Market-to-Market Payment
SPP’s Riverton-Neosho-Blackberry flowgate — quickly becoming recognized by just its 5375 ID — was binding for 350 hours in January, resulting in a record $6.9 million market-to-market (M2M) payment from MISO. The Kansas-Missouri border flowgate was responsible for $6.2 million of the charges, more than all the flowgates combined in any other single month.
SPP has accumulated almost $44 million in M2M payments since the two RTOs began the process in March 2015. MISO has not had a month in its favor since last July and only nine overall.
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SPP staff told the Seams Steering Committee on March 7 that they have been implementing an “enhanced shadow price override” non-monitoring RTO process on swing-related flowgates since Jan. 4. The two RTOs are also considering implementing a “monitoring RTO reverse role,” where MISO would control the physical flow on a flowgate and SPP control the market flow.
Permanent and temporary flowgates were binding for 632 hours in January, SPP staff told the committee.
Staff also briefed the committee on FERC’s April 3-4 technical conference related to how SPP, MISO and PJM coordinate generator interconnection studies on projects near their seams. The commission called the conference to address issues raised in an October complaint by EDF Renewable Energy, which contends that inconsistencies and a lack of clarity in the RTOs’ rules for “affected systems” interferes with developers’ ability to judge the commercial viability of proposed projects. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
SPP, AECI Wait on Joint Study Scope
SPP and Associated Electric Cooperative Inc. last week failed to reach an agreement with their stakeholders on a scope for a 2018 joint study during an Interregional Planning Stakeholder Advisory Committee meeting. Another IPSAC will likely be scheduled in a few weeks, giving members a chance to review the draft scope with their companies and providing staff additional time to revise its models.
SPP staff said they had drafted a scope that identified needs from its 2018 near-term assessment that are “electrically significant to the SPP-AECI seam.”
The RTO plans to use its near-term assessment models, which have already been approved by its stakeholders. AECI regularly participates in the near-term model-building process, which allows the two entities “to explore a broader set of projects which could potentially provide benefit to both systems,” SPP staff said.
