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.
VALLEY FORGE, Pa. — PJM’s plan to switch which side of a transformer is considered for cumulative ramping impact is “a win-win” because it models the system better without implicating expensive upgrades, the RTO’s Jonathan Kern explained to stakeholders at last week’s Planning Committee meeting.
The RTO was proposing to include in its calculations only transformers whose lowest terminal voltage level is at least 500 kV rather than any whose high side is at least 500 kV. PJM justified the change because distribution factors for transformers are generally closer to the lower-side system they connect to than the higher side. The plan was part of a larger package of revisions to Manual 14B developed through an annual review. Stakeholders endorsed moving the proposal to the Markets and Reliability Committee but not before examining PJM’s determinations.
Kern said an analysis found that two transformers — the 500/138-kV Wescosville and 500/230-kV Ladysmith — could potentially be overloaded by the change at a cost of $18 million and $25 million, respectively. He said the change would only take effect starting with the 2023 Regional Transmission Expansion Plan, an initial analysis of which doesn’t show any impacts.
“There’s very strong evidence for the technical change we’re proposing to make here,” Kern said. “To us, it appears like a win-win change. In other words, it’s meeting the obvious technical intuition we have for generation delivery but also not creating any new overloads.”
However, American Municipal Power’s Ryan Dolan reminded everyone that no cost increases come without impact.
“I would argue that over $30 million of required upgrades wouldn’t be minimal,” he said.
External Capacity
PJM’s Aaron Berner successfully urged stakeholders to endorse rule revisions that would allow pseudo-tied external resources wanting to offer into the RTO’s capacity auctions to deliver into the energy market any additional generation beyond what’s authorized for capacity.
The RTO’s rules for external resources impose requirements that can limit how generation those units can offer into the Reliability Pricing Model.
“That doesn’t mean though that the transmission service is not deliverable for energy use,” Berner explained. “So with the addition of this language, the studies that PJM performed previously or would perform for new generation would still allow that generation to be delivered as transmission service for participation in the energy market.”
The revised language was added to changes developed for Manual 12 to address pseudo-tied capacity resources. Berner fielded several clarifying questions before stakeholders requested that PJM add detail to their proposed revisions.
“The current language does not explain in detail what you explained,” said James Manning with the North Carolina Electric Membership Corp.
Berner agreed to work with stakeholders on that issue, but he asked that they endorse the intent of the revisions so it can move on to the MRC.
Limiting Meetings Causing Stakeholder Strain
In explaining why proposed revisions to Manual 21 were only presented at the Planning Committee, staff said they were only trying to comply with stakeholder requests to limit meetings.
PJM’s Jerry Bell explained the revisions, which would change how generators are tested to receive and retain capacity interconnection rights (CIRs). Stakeholders argued that the changes are wide-ranging, requiring input from experts who don’t typically attend committee meetings, and asked why the considerations hadn’t been put to a task force or other high-level committees.
“This is really a generation operations issue, but we’re looking at it in the Planning Committee. We’ve got mostly transmission planners in the room here. We really need to expose this to all of the people this is really going to affect,” FirstEnergy’s Jim Benchek said. “These changes are pretty major.”
“I don’t necessarily think there’s any ill intent here, but it’s just that sometimes what looks to be just something for the Planning Committee has broader impacts,” said Adrien Ford with the Old Dominion Electric Cooperative. She suggested that PJM’s problem statement/issue charge process could have arrived at a result faster because the necessary stakeholder groups could have been identified up front.
“We’re trying to balance the needs of the stakeholders where we’ve gotten feedback about having too many other meetings and having the agendas jammed and the days of the week jammed with other meetings,” said Ken Seiler, who chairs the Planning Committee. He said he would confer with the chairs of the Operating and Market Implementation committees about how to handle the requests.
Stakeholders noted several concerns with the proposal, which would eliminate June from the summer testing period (leaving July through August) and require simultaneous testing of all resources at a plant except wind and solar units. They would have to be able to start within five minutes.
“If you were to call on all the units at a plant and apply the test simultaneously, the start-up costs could get quite expensive,” Benchek said, adding that his company didn’t favor the reduced testing period either.
Solar and wind would be exempt because they use their average capacity factor during the peak hours included in the testing, but all capacity factors will be determined by calculating the median rather than average performance going forward. Bell confirmed those calculations won’t become fully effective until 2021/2022.
Mike Borgatti with Gabel Associates was concerned that the proposed language changes didn’t adequately enunciate that units’ capacity factors wouldn’t be affected for three years.
Bell also walked stakeholders through analysis that shows that the 650 MW of non-dispatchable hydro generation might be overstated by 520 MW because the expected capacity factor of 20% shows that 130 MW is predicted to be available.
AEP Project Removed from RTEP Modeling
American Electric Power’s portion of Duff-Rockport-Coleman project has been placed on hold and will not be modeled in the 2018 RTEP, PJM told the Transmission Expansion Advisory Committee on Thursday.
Robert Bradish, AEP’s vice president of transmission grid development, informed PJM of the change in a letter Feb. 20. Bradish said the supplemental project was proposed to address voltage stability limitations and eliminate the special protection scheme at the Rockport plant by interconnecting the Rockport 765-kV station with the MISO Duff-Coleman 345-kV market efficiency project.
“The current generation situation at Rockport plant is quite different from the situation when this supplemental project was included in the 2015 RTEP,” Bradish wrote. “There is currently significant uncertainty regarding generation-related conditions which may affect future operation of the Rockport units. Certain of these generation conditions can only be addressed through coordination with third parties, regulatory proceedings and other circumstances outside of AEP’s control.”
Retirement Studies Update
PJM has completed reliability analyses on retirements at six generating stations and is conducting reviews for three others.
The retirements of Buggs Island 1 and 2 (138 MW), Bremo 3 and 4 (227 MW), and Bellemeade CC 1 (265.7 MW) are all effective April 16; Possum Point 3 and 4 (317.7 MW) and Chesterfield 3 and 4 (262.1 MW) are both scheduled for Dec. 1. PJM said it has asked Dominion Energy, the transmission owner for all the plants, to perform additional analysis to identify any required upgrades.
PJM said it identified no impacts from the scheduled May 3 closing of Evergreen Power United Corstack (25 MW) in Met Ed.
It is conducting analyses on the Morris Landfill Generator (1.9 MW) in ComEd and the Reichs Ford Road Landfill Generator (1.7 MW) in APS, both set for May 31, as well as FirstEnergy’s Pleasants Power Station 1 and 2 (1,278 MW), scheduled for Jan. 1, 2019. (See FirstEnergy Shutting down Unsold Coal Plant.)
Market Efficiency Update
PJM planners have selected a $25.4 million proposal by Baltimore Gas and Electric to address constraints on the Conastone-Graceton-Bagley 230-kV corridor after finding it cleared their reliability and cost/constructability analyses. The project (proposal 5E), which involves reconductoring and upgrades to equipment at the Conastone and Windy Edge substation, is expected in service in 2021. It will be recommended for approval at the Board of Managers meeting in April.
Planners said they won’t be recommending any market efficiency projects in the PPL zone after seeing the projected congestion benefits from the proposed Susquehanna–Harwood drop by about half under the base case because of a lower load forecast and changes in generation expansion since the start of the 2016/17 project window.
PJM is now developing assumptions for its 2018/19 RTEP long-term window, which it expects to open between November and February 2019.
Officials also said they expect to open a 60-day reliability project window in May or June.
VALLEY FORGE, Pa. — PJM will hold its spring restoration drill May 15-16, staff told attendees at last week’s Operating Committee meeting. Invitations will be emailed March 19 to the contacts listed in transmission owners’ restoration plans for the transmission operator, generation operator and training liaisons, PJM’s Alpa Jani said.
PJM’s Glen Boyle said stakeholders’ work in the Primary Frequency Response Senior Task Force became more complicated and urgent after FERC issued Order 842, which requires all new generation that receives an interconnection agreement to provide primary frequency response. (See FERC Finalizes Frequency Response Requirement.)
The order silenced any debate about new facilities, so staff will instead focus on what should be required of existing units. The order could delay the PFRSTF’s work, but the group plans to vote on proposals after its March 21 meeting. Stakeholder endorsement votes will likely be completed in June.
Unit-specific Parameter Adjustments
Jani also reviewed the statistics about the number of unit-specific parameter adjustment requests that PJM received this year. The request period closed on Feb. 28.
All final determinations will be made by April 15 so they can be implemented by the start of the delivery year on June 1. Jani noted that soak time information is only for reference this year but will be added as a parameter and integrated next year.
PJM’s Dean Manno reviewed the RTO’s resilience roadmap and highlighted the next steps for 2018. PJM is evaluating the needs for “extreme events,” he said, including reserves and regulation requirements, transmission loading and triggers. Staff are also planning to review the weather/environmental and sabotage/terrorism emergencies sections of Manual 13 to see if anything should be added.
30-Minute Reserves
PJM’s Vince Stefanowicz explained staff’s thought process on developing a real-time 30-minute reserves product and announced that a problem statement and issue charge will be forthcoming in April.
Currently, 30-minute reserves are only procured in the day-ahead market, so when more primary reserves are needed, they’re moved in from secondary reserves, which only serves to reduce secondary reserves rather than bringing in more units. The new product would achieve that, he said, “not just move things from secondary into primary.”
Dave Mabry with the PJM Industrial Customer Coalition said that “perhaps a bigger audience” would be necessary to make such changes and asked if the Market Implementation Committee would become involved.
“Conceptually, I’m in agreement with you,” said PJM’s Dave Souder, the interim chair of the Operating Committee. He said the plan is to figure out the operational needs, then determine what other committees need to be involved.
Implementing DER Ride Through
The RTO is hoping TOs will take the lead on implementing “ride through” for distributed energy resources, PJM’s Andrew Levitt said. Ride through is the process of remaining connected to the grid during abnormal conditions. Despite being a “challenge” for large generators, Levitt said they’re required to do it while DERs are not.
Today, DERs can trip off very quickly and potentially over a wide variety of variables. However, there are already 4,000 MW of distributed solar generation in PJM today with expectations of that tripling in the next three years, making it a significant issue if they all trip when the grid is having issues.
“We think ride through is critical for DER,” Levitt said.
PJM recently published a draft revision of standards for DERs that would require ride through. However, it has no control over the net-metered solar that accounts for all the DER growth.
“We’re looking to follow the utilities’ lead on this topic … but we also anticipate a public stakeholder process” to support stability bulk energy supply and move toward a single standard for implementation, Levitt said.
Changing Tier 1 Reserve Estimates
PJM’s Joe Ciabattoni unveiled planned revisions to how Tier 1 reserves are estimated to address stakeholders concerns about major overestimates. (See “Investigating Improvements Based on Additional Cold Response Details,” PJM Operating Committee Briefs: Feb. 6, 2018.)
The RTO is proposing to cap spin max at a unit’s economic minimum and require that the spin ramp rate equal the economic ramp rate, he said.
“We find that during spin events this is an issue,” he said.
A TO representative who asked not to be named voiced concerns about reducing too much spin and asked that additional data be presented to explain the problem. Ciabattoni agreed.
“I just want to make sure we’re actually seeing a problem there as opposed to fixing a problem that doesn’t exist because there’s no way a resource could tell if there’s going to be a Tier 2 payment,” the TO representative said.
Tom Blair of the Independent Market Monitor said the issue is exacerbated because of how the reserve market is set up.
“There is no penalty for Tier 1 synchronized reserve not responding. There is, however, a significant incentive to overestimate your Tier 1 reserve,” he said.
Blair explained that the reserve market is set up so that units can earn enough money that they still make a profit even with the penalties that occur if they don’t respond when called upon.
“I think directionally this is worthwhile, probably helpful,” said Carl Johnson, representing the PJM Public Power Coalition.
Calpine’s David “Scarp” Scarpignato said another issue is that scarcity pricing is not being triggered when it needs to be and that “the issue is much broader than this.”
RAS Removed
Commonwealth Edison is removing the Davis Creek remedial action scheme (RAS). The plan was needed to prevent thermal overloads in the event of losing a 345-kV line to the substation by auto-closing a 345-kV bus tie at the station.
A supplemental project to expand the 345-kV bus at the substation is expected to be completed by the end of the year.
WASHINGTON — Transmission developers, planners and regulators gathered last week at the Washington Marriott Georgetown hotel for the three-day Infocast Transmission Summit East. While grid security was on the minds of all who attended, speakers also had plenty of opportunities to vent about FERC Order 1000 and RTO planning processes — as well as poke fun at Ted Koppel.
Bruce Walker, assistant secretary of the Office of Electricity Delivery and Energy Reliability at the U.S. Department of Energy, briefed attendees Wednesday on five initiatives by the department to enhance grid security.
The most ambitious, by the department’s Grid Modernization Lab Consortium, is developing a “North American all-energy systems model” that includes all the grid operators across North America and identifying their interdependencies.
“Once we’ve got this model, we’ll be able to do real-time analysis [and] next-worst-case analysis, so when an excursion occurs on any one of the major systems in the United States or Canada or Mexico, we’ll be able to run it and understand what that means and what the next-worst piece of equipment or system is to lose, so that we can proactively act to prevent that, whether it’s providing physical security, whether it’s changing the load flows on the grid to lessen the load or demand in one particular place,” Walker said. Many of these actions would be taken by RTOs, he said.
The model will be so comprehensive, he said, that it will be able to do “N-K” load-flow analysis, with the “K” standing for assets that aren’t traditionally considered part of the electric grid. (See related story, “Beyond N-1,” Tx Summit Attendees Struggle to Define ‘Resiliency’ Problem.)
Another initiative is “megawatt-scale storage strategically being utilized throughout the grid.” Walker said this initiative ties in with the North American Model, which will allow the department to “identify where the best investments of these” storage assets would be.
This raised the eyebrow of Rob Gramlich, president of Grid Strategies. “‘Identifying best investments’: that sounds like a market function. How does this initiative interact with the market?” he asked.
“Because we’re focused on the resiliency component — and then we’re specifically focused on critical infrastructure — … the market actually has no place in making the determination for those investments,” Walker responded. “So part of why we got FERC, NERC and DOE looking at the system and building this model is we come at it from slightly different angles. FERC’s angle is a bit more market-driven; NERC’s is more reliability-driven; DOE has got very specific requirements, being the sector-specific agency for cybersecurity in the energy industry, focusing in on critical infrastructure throughout the United States.”
Impact of Ukraine-style Attack Would be Less
A cyberattack on the U.S. grid by a foreign power such as the one experienced by Ukraine in 2015 and 2016 is certainly possible, several experts said in a Wednesday panel on cybersecurity.
But Ukraine lacks the basic protections and infrastructure of the U.S., meaning such an attack would be far less disruptive and destructive here, they said.
Or as moderator Brian Harrell, senior fellow at George Washington University’s Center for Cyber and Homeland Security, quipped, “I don’t know too many utilities here in the United States running pirated versions of Windows XP on their systems. So, there are some differences here.”
The general consensus among the panel, which included a National Guard colonel, was that utilities need to be incentivized to do more than the minimum required by NERC, as well as be on guard for insider threats.
But the panelists unanimously labeled as off-base the assertion made by broadcast journalist Ted Koppel in his book “Lights Out” — the mention of which drew laughter from the audience — that the U.S. is susceptible to a catastrophic attack and that industry and government are not taking the threats seriously.
Flaws in Planning Processes
Many speakers complained about the transmission planning processes in RTOs, including the competitive and interregional processes.
On a Thursday panel discussing the effects of renewable energy resources on transmission planning, Invenergy Senior Vice President Kris Zadlo said he doesn’t “think transmission planning is happening.”
“Operating lines that [are] 2% overloaded or replacing transformers: that’s not transmission planning,” Zadlo said. “That’s asset management.”
He pointed to American Electric Power’s Wind Catcher Energy Connection Project, which Kelly Pearce, director of contracts and analysis for the company, had briefed attendees on earlier in the day. The project would be the largest wind energy facility in the U.S at 2 GW, with a dedicated 765-kV tie line from the Oklahoma Panhandle to Tulsa.
“Folks are trying to find end-arounds,” Zadlo said. Wind Catcher is a “360-mile end-around because SPP’s transmission planning process has failed. … Quite frankly it’s disgraceful that we have to wait three to five years for an interconnection study to be processed by utilities and by ISOs.”
Kip Fox, president of Electric Transmission Texas, said, “One thing we do notice across all of the RTOs that everybody should kind of think about is we’re not seeing a lot of interregional” projects. “We are not seeing projects that are going across RTOs. And unfortunately, that’s where the big bang for the buck economically is going to be. And usually I find it’s a fight over who’s going to pay for that project, rather than whether that project makes sense.”
On a separate panel Thursday, Kamran Ali, AEP vice president of grid development, noted that between 2012 and 2016, PJM identified 72 projects that were open for competition. Of those, only three ended up being assigned to nonincumbent utilities, he said.
Trump Admin’s Effects?
Speakers at the conference uniformly dismissed the actions of the Trump administration as having any effect on the growth of renewables and the retirement of coal-fired generation. Even as one attendee announced to the conference that President Trump had imposed tariffs on steel and aluminum imports Thursday afternoon, panelists were not concerned.
“There’s something interesting that’s going to happen in 2020,” Zadlo said. “It’s not that the [production tax credits] are going to run out.” Nor is it the next presidential election year. “In 2020, millennials will be over 50% of the workforce. Have you guys polled the millennials as to what their feelings and thoughts are regarding renewable energy? If you haven’t, you better. Because they want it.”
WASHINGTON — The Institute for Electric Innovation’s spring 2018 forum Wednesday featured a discussion on corporate renewable energy procurement and an appearance by Rep. Yvette Clarke (D-N.Y.), co-chair of the newly formed Smart Cities Caucus. Here’s some of what we heard.
Electric Industry an ‘Afterthought’ to FCC?
Edison Electric Institute Executive Vice President and former FERC Commissioner Phil Moeller told Clarke that the electric industry feels like an afterthought in the Federal Communications Commission’s discussions on the rollout of 5G cellular technology.
“We have another issue [at the FCC] with pole attachments and spectrum allocation, but particularly with [the] 5G network, our infrastructure is going to play a big role,” Moeller said. “Safety has to come first. We could probably use your help at the Smart Cities Caucus to remind the FCC that our industry should not be an afterthought but should be at the table during some of these discussions.”
“I agree wholeheartedly,” responded Clarke. “We’ve had hearings already with that in mind. That’s going to be a challenge in every corner of the nation because we’re going to be expected to utilize the infrastructure that already exists. So there has to be a collaboration. In many towns, cities, municipalities, there’s going to be a struggle about how you site these things.”
Corporate Renewable Procurements, Green Tariffs Growing
Letha Tawney, director of utility innovation for the World Resources Institute, led a panel discussion on corporate renewable energy procurements, noting that green tariff programs in 15 states have helped to bring 1 GW of new solar and wind projects to the grid since 2013.
“There’s been some successes,” said Tawney, whose organization works with utilities and customers to craft green tariffs. “How do we scale this? This is still pretty marginal. We just passed a gigawatt of transactions being signed. That’s not that much, really, in the whole U.S. market. … We need to do a lot more.”
Robert M. Blue, CEO of Dominion Energy’s Power Delivery Group, worked with customers like Steve Chriss, director of energy and strategy analysis for Walmart, in developing a new renewable generation (RG) tariff that functions as a contract for differences.
“The renewable generation tariff that we filed, a lot of it wasn’t working for a lot of customers,” Blue said. “That’s why we revised it. We heard from them what would make it work better and we expect that that will have a substantial impact.”
Last October, Dominion announced Facebook will build its eighth U.S. data center in the utility’s territory outside Richmond, Va., under a proposed new Schedule RF (renewable facility) rate structure, with which the company will offset its 130-MW load with renewables. Facebook’s goal is to power all its operations with renewable energy.
Walmart, which takes service from 1,000 utilities, has a goal of being 50% renewable power by 2025.
“We operate in a lot of states that aren’t deregulated and a lot of states where there’s not necessarily a market in place,” said Chriss. “In SPP or MISO, you can do a virtual [power purchase agreement] … but in Southern Co. or in some of the other big IOUs, there is no market, per se. So really, the market is their system and so you have to figure out structures that work within that.”
Even within Southern’s utilities, rules differ across state lines, Chriss said. “Our deal with Alabama Power [a 72-MW solar farm in southeastern Alabama that went into operation several weeks ago] … is very different from the Georgia [Power] structure.”
Nick Wagner, a member of the Iowa Utilities Board, discussed concerns over corporate procurements resulting in cost shifts to other customers.
“It’s no secret to probably anybody in this room that utility costs have been so highly socialized for a long time. It will take us some time to unwind those as we have the data” from cost-of-service studies, he said. “It’s probably a little more masked in the vertically integrated [states] than in the non-vertically integrated [states]. As we get more data, I think it’s going to become a little bit easier to separate those things out.”
Wagner said regulators’ efforts are aided by interventions by customers and other interest groups. “If nobody’s happy at the end of the day, but no one is really angry, you probably came to about the right place,” he said. “If someone’s walking out high-fiving, we know we messed up somewhere.”
VALLEY FORGE, Pa. — PJM stakeholders at last week’s Market Implementation Committee meeting approved two problem statements and issue charges presented by Exelon, over objections from the Independent Market Monitor.
Exelon’s Sharon Midgley presented both proposed investigations. The first problem statement and issue charge focused on PJM’s rule for forfeiting revenue from financial transmission rights if a market participant’s portfolio of day-ahead virtual bids creates a larger LMP spread in the day-ahead market than in real-time auctions.
Midgley argued that changes PJM implemented last year in response to FERC’s order to revise the forfeiture rule have made the rule overly restrictive, which Exelon says resulted in forfeiture of substantially more revenue from legitimate positions. A year-over-year comparison of monthly forfeitures before and after the rule changes took effect in 2017 shows as much as a $1.8 million difference in a single month.
The Monitor’s Howard Haas said that, while the rule changes have yet to be approved by FERC, they follow the commission’s guidance on the required changes. Given all the changes in the rule, he said, it was expected that the forfeiture numbers would be different than under the old rule, and the results under the old and new rule are not directly comparable. He said the observed level of forfeitures to date are in large part a result of the retroactive application of the new rule. Since information has become available under the new rule, participants have changed their behavior and forfeitures numbers are down dramatically. (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
PJM attorney Jen Tribulski agreed with Haas that the revisions the RTO filed for approval are in line with FERC’s order, but she said that Exelon’s concerns are “probably worth a discussion here” and that the commission’s order doesn’t prevent stakeholders from discussing and seeking approval for additional revisions. PJM’s Asanga Perera later noted in response to a stakeholder question that others have complained about the rule, though he didn’t have an exact number.
“It’s not only Exelon. We have seen other parties express concerns with the forfeiture rule,” he said.
Some stakeholders were unconvinced by Exelon’s argument but also reluctant to buck the tradition of supporting each other’s requests to analyze market procedures.
“I don’t know what we see that there is a problem, but I don’t know that we have much objection,” said Dave Mabry, who represents the PJM Industrial Customer Coalition.
Direct Energy’s Marji Philips said she would support the request but that it “seems premature” given the amount of work already teed up in stakeholder committees and the lack of clarity on how many market participants have been negatively impacted.
On Midgley’s second problem statement and issue charge on the exemption process for the must-offer rule, Monitor Joe Bowring said the focus of the analysis should expand to include how capacity interconnection rights (CIRs) would be handled for units that transition from capacity to energy. Midgley welcomed the revision.
Exelon’s request comes in response to difficulties the company has experienced with the timing of the current exemption approval process, specifically that it may be physically impossible to install dual-fuel capability within the three months between the third Incremental Auction and the start of the corresponding delivery year. Sites without winter fuel supplies may need to construct onsite oil storage, which can’t be completed in the three-month period. Midgley said it’s unclear what documentation needs to be submitted to receive approval for an exemption on such grounds.
The proposal would have stakeholders consider revising the guidelines for documentation required by the Monitor and PJM to grant an exemption, implementing process reforms to improve efficiency and establishing a process for resources with an existing must-offer requirement to become energy-only resources.
Both investigations were endorsed by stakeholders.
Hardware to Improve Day-ahead Performance
PJM announced it had purchased several new computer servers to address issues with delays in posting day-ahead auction results. The hardware was acquired as part of an ongoing two-year cycle to upgrade equipment, so there was no additional budget impact, PJM’s Todd Keech explained.
“We’re right into one of those refresh cycles now, so it was good timing,” he said.
Chantal Hendrzak, who chairs the MIC, acknowledged requests to expand the bidding window but said the RTO is focusing on posting the results sooner rather than increasing flexibility.
Five-Minute Settlements to Begin
PJM’s Ray Fernandez reminded stakeholders that units have until March 16 to sign up for five-minute settlements, which go into effect April 1. After that, resources will have to alert the RTO at least three days ahead of the desired change-over date before submitting five-minute revenue meter data.
Maintenance in Cost-Based Offers
PJM’s Tom Hauske said the RTO is considering whether to include maintenance costs in cost-based offers. Special sessions on variable operations and maintenance (VOM) costs produced three proposals, among which stakeholders will be asked to choose at next month’s meeting.
The current rules for what can be included in cost-based offers. | PJM
Cost-based offers created through current Manual 15 rules do not allow for inclusion of any maintenance costs. PJM’s proposal would allow for maintenance attributed to running the unit and directly tied to electricity production by including FERC accounts minus labor costs. Generators could also add operating costs, such as lubricants, chemicals and other consumables, into incremental energy offers, but not VOM.
PJM’s proposed changes would allow some maintenance costs | PJM
Energy-only resources or units that didn’t clear the delivery year’s Base Residual Auction could add their avoidable cost rate (ACR) fixed costs (such as staffing, taxes, fees, insurance and fuel availability) into their VOM, but capacity resources could not because they should recover those expenses through their capacity payments.
PJM also presented another proposal that would give resources the option of using its package or default resource-class VOM values calculated using U.S. Energy Information Administration data.
The Monitor’s package would replace “incremental” with “short-run marginal” in the Operating Agreement and would operate under the premise that all maintenance and labor costs are included in a unit’s capacity offer. The net cost of new entry (CONE) for each resource class would be modified to include maintenance and labor costs. Manual 15 would be stripped of all costs except short-run marginal ones: fuel, emissions, water, chemicals and consumables. A unit’s ACR would encompass everything else, including project maintenance expenses.
The Monitor’s proposal would redefine how offers are made by allowing only short-run marginal costs to be included. | PJM
“The IMM package is based on what a competitive offer in the market should be,” the Monitor’s Catherine Tyler said. “We also think this is the most straightforward and simple to implement.”
Once a proposal is approved, stakeholders would discuss implementation and time frame, Hauske said.
PJM ICC’s Mabry said “one of the big heartburns we have” is that overhaul and major inspection costs are included in VOM rather than ACR.
“That frankly weighs into the decision … should I go buy a new resource?” he said.
PJM’s proposal operates under the theory that VOM is recovered after it’s been spent, while ACR is what’s projected to be spent, Hauske said. He pointed out that if gas prices go up and a unit decides to run — and therefore performs maintenance — less often, it would have already received recovery for the higher amount of maintenance if it was recovered through ACR.
A representative of a transmission owner who asked not to be named said the default values are “pretty conservative” and should be based on actual costs, not averages. Tyler said the Monitor publishes its own defaults, but the TO representative said they’re not explained.
The default option would allow use of these or PJM’s proposal. | PJM
Long-term FTRs Undercut Annual FTRs
The Monitor appears to have won over PJM regarding its concerns about long-term FTRs. Haas presented analysis requested by stakeholders that showed the cost to auction revenue rights holders from the long-term FTRs market construct. Among other findings, Haas showed that over the past four planning periods, FTRs sold in the long-term market have been undervalued by more than $337.2 million compared to the annual FTRs for the corresponding delivery year. (See PJM Stakeholders Decline to Change Market Path Rules.)
Buyers of long-term FTRs only paid, at most, 3.5% of the total revenue from the total FTR revenue for the past four delivery years, even though they made up between a third and half of all FTR activity each year. This shows that they sold as a substantial discount to annual FTRs, which means that buyers could make profit by selling them back during the delivery year’s annual FTR auction. | Monitoring Analytics
The current long-term market construct doesn’t allow ARR holders to directly benefit from the sale of congestion rights, despite owning the rights to congestion, Haas said.
“I think we’re on the same page with [the Monitor] about most of the issues,” PJM’s Brian Chmielewski said.
The 2nd U.S. Circuit Court of Appeals on Monday heard oral arguments in an appeal of a judge’s decision to dismiss a suit against New York’s zero-emission credits program.
In filing the appeal, the Electric Power Supply Association and members Dynegy, Eastern Generation and NRG Energy joined Roseton Generating and Selkirk Cogen Partners in arguing that some generators would lose millions in revenue because the subsidized nuclear plants would suppress NYISO capacity and energy prices.
Indian Point Nuclear Plant
Judge Valerie Caproni, of the U.S. District Court for the Southern District of New York, last year granted motions to dismiss the case by the Public Service Commission, the defendant, and intervenor Exelon, owner of the three nuclear plants that would receive ZEC payments (16-CV-8164). (See New York ZEC Suit Dismissed.)
ClearView Energy Partners issued a statement on Monday’s arguments saying that at least two of the three appellate judges appeared skeptical of petitioners’ pre-emption claims that the ZEC program infringes on FERC’s exclusive jurisdiction over wholesale markets.
Miles Farmer of the Natural Resources Defense Council said in a blog post that the 2nd Circuit will likely provide the final say on the validity of New York’s ZEC program under federal law.
New York’s Clean Energy Standard and its provisions for subsidies for nuclear plants are also being challenged in state court. The Albany County Supreme Court in January rejected the state’s motions to dismiss outright a lawsuit challenging the ZEC program. (See New York Court to Consider ZEC Challenge.)
