The SPP Market Monitoring Unit has released its quarterly State of the Market report for the winter, which includes a discussion of several weather events.
Electricity and gas prices | SPP
The MMU said the market performed well during the winter months, “sending appropriate price signals during times when delivering power reliably was more challenging.” It said higher prices during an event indicates “a greater need for energy at a particular location.”
The report covers December 2018 through February 2019.
The MMU will host a webinar on Wednesday to add further color to the report.
Generation by technology type | SPP
Highlights for the period include:
Day-ahead energy prices climbed slightly, while real-time energy prices fell from winter 2018 levels.
Average hourly load in December and January was in line with the prior years, with only February exceeding previous levels.
Wind generation capacity continued to climb, increasing to 21.4 GW, a 5.3-GW increase from a year ago.
Generation by coal resources continued to decline, dropping to 44% of the fuel mix.
Overall profits from virtual transactions at the resource level nearly doubled from the previous winter, while profits at interfaces shot up from $200,000 to $3 million, which the MMU attributed to day-ahead and real-time price differences stemming from a modeling issue.
Net market-to-market payments from MISO were about $6.3 million, compared with nearly $16 million the year before.
CARMEL, Ind. — MISO last week proposed a set of changes to buttress its financial transmission rights market and said it will convene a new task team to work out the details of the fledging proposal.
Two alterations involve stiffer collateral requirements, while the third will prohibit known “bad actors” from participating in the RTO’s FTR auctions. During a Market Subcommittee meeting Thursday, MISO and stakeholders created a task team to refine the three-prong proposal.
“MISO has had no losses in the FTR market. Having said that, that doesn’t mean that there aren’t opportunities to improve,” said Brian Brown, a credit analyst with the RTO.
Brown said the improvements are targeted for April 2020, before the next annual FTR auction. By Friday, MISO will create the task team that will draw up the two required Tariff filings this fall, Manager of Credit and Risk Management Matthew Mullin added.
According to Brown, MISO is considering introducing a 5-cent/MWh minimum collateral requirement, which would boost collateral by $35 million across the entire FTR market.
Credit requirements could also be adjusted based on a proposed mark-to-auction valuation that would estimate the market value changes of an FTR portfolio by calculating the difference between FTR purchase prices and the most recent auction prices. PJM recently introduced such a measure to spot reductions in portfolio value in order to increase credit requirements, saying declining market value can be an indicator of increasing risk in FTR markets.
MISO said it plans to require FTR traders to post collateral based on the highest figure derived from either the current FTR credit calculation, the new minimum amount or the mark-to-auction valuation.
Customized Energy Solutions’ Ted Kuhn asked if the changes might negatively impact participation rates in the FTR market.
“We expect the impact to be minimal, but it’s difficult to forecast that,” Brown said, adding that MISO market participants have always been willing to post collateral.
RTO staff also said they will discuss the changes with its Independent Market Monitor.
MISO is justifying the changes based on a 2003 FERC policy statement that said the commission expects that ISO/RTOs “should act on behalf of their membership to minimize likelihood of default.”
Preventing ‘Bad Actors’
In a separate Tariff filing, MISO will seek to bar what it deems “bad actors” — either those that have defaulted or settled market manipulation charges in FERC jurisdictional markets — from becoming market participants.
Mullin said MISO currently lacks the authority to keep those with ill intent out of its markets.
“In light of recent events, we believe MISO should have authority to prevent bad actors from participating. … Right now, we don’t have the explicit authority to do anything,” Mullin said. “We believe this is a logical next step.”
He was referring to GreenHat Energy’s record default in PJM’s FTR market. MISO recently completed a scheduled analysis of its FTR market and has repeatedly reassured members that similar failures are unlikely to occur. (See MISO Offers Reassurances on FTRs, Examines Changes.)
Mullin said MISO must still define what constitutes a “bad actor” and what steps it will take after identifying one. He said the new task team would work out those details.
“These improvements won’t eliminate the risk of a loss; however, it closes the gaps and the opportunity to exploit those gaps. More importantly, it will reduce the magnitude of a loss,” Brown said.
Brown stressed that MISO’s historical FTR performance shows that it has been “minimally exposed.” He added that its FTR market has never experienced a default.
SPRINGFIELD, Mass. — More than 100 people turned out Wednesday evening at John J. Duggan Academy to protest a Department of Energy Resources proposal to alter the state’s renewable portfolio standard to include biomass plants.
“We want to give everybody an opportunity to be heard in an equal and fair way, and it’s really our opportunity to listen to your feedback on the proposed changes we have made to the regulations,” said Mike Judge, DOER renewable energy division director.
The state’s RPS requires all electricity retailers in the commonwealth to obtain minimum percentages of their supply from renewable resources, starting at 16% last year and increasing 2% annually to 80% in 2050.
The DOER in April filed draft changes to the RPS that would allow facilities burning non-forest derived woody biomass to receive grants for up to 80% of construction and installation costs and still receive ratepayer subsidies for energy generated, increasing the likelihood of biomass generators being built.
Nearly 300 people attended the fourth and final public hearing on the topic hosted by the department June 4. Among the nearly 60 people testifying were a dozen biomass industry proponents and five members of the Springfield City Council opposing plans by Palmer Renewable Energy for a 35-MW wood-burning plant in East Springfield.
City Councilor Melvin Edwards, who testified that he is in line for a double lung transplant, told RTO Insider that, “The first day that this plant runs will be the first day and the only day that it would run its cleanest, regardless of the standards as they change. It will never be a benefit for my community except for the few jobs it will create, and allow me to suggest that the majority of the jobs … will be at the respiratory department of Baystate Medical Center.”
Edwards said that “we don’t want to make this about any one project.”
Licensed forester John Clarke testified in favor of the RPS changes.
“I practice sustainable forestry in my daily business and know that there’s opportunity for sustainably derived wood chips to provide local, renewable fuels for thermal, electric and co-generation facilities,” Clarke said. “These fuels are renewable and will directly replace fossil fuels, leaving ancient carbon in the ground and utilizing biogenic carbon for our energy needs.”
City Councilor Jesse Lederman drew a standing ovation from about two-thirds of the crowd when he opposed the RPS changes as providing subsidies “to large-scale wood-burning incinerators in Massachusetts and the region.”
“I particularly draw your attention to the 2010 Manomet [Biomass Sustainability and Carbon Policy] study, which was commissioned by the state … and clearly found that these types of large-scale, low-efficiency incinerators were not carbon-neutral and could accurately be compared to the emissions of a coal power plant,” said Lederman, who is chair of the council’s committees on sustainability and the environment and health and human services.
Lederman said he and his colleagues would ask the legislature to remove biomass completely from the RPS statutes and also requested that the DOER extend the deadline for written comments to June 30. On Friday, the department pushed the deadline to July 26.
Charlie Bagnall of Peterson Pacific, a manufacturer of wood processing machinery, said he favored accommodating non-forest derived wood fuels such as the byproducts of vegetation management by utilities and from other sources. His company tries “to be as green as possible,” he said, telling how it implemented Tier 4 diesel emissions standards in 2012, six years before they went into effect in Massachusetts.
Jake Dubreuil, sales manager of Barry Equipment in the town of Webster, testified that “1 million tons of non-forest derived fuel sources are produced annually — 1 million — in Massachusetts alone. … With the proposed changes to the RPS, responsible solutions … can be monitored by our state regulatory commissions and committees, ultimately displacing the use of fossil fuels.”
Tanisha Arena, executive director of local activist group Arise for Social Justice, testified that, “Biomass isn’t clean energy. Burning anything isn’t clean energy.
“If you betray Springfield with a biomass plant, Palmer Renewable Energy gets $10 million to $12 million a year in renewable energy subsidies, but we, the residents of Springfield, receive what? Will you compensate us for the nasty air we will breathe?”
ORLANDO, Fla. — NERC is likely to merge its Planning, Operating and Critical Infrastructure Protection committees into a single “Reliability Council,” committee members learned last week.
NERC announced in May that a Stakeholder Engagement Team (SET) was reviewing the ERO’s structure after 10 years of operations. The organization said it was considering two options: retaining the three committees while adding an Oversight Committee to coordinate their work, or merging them into a new Reliability Council reporting to the Board of Trustees. (See “Potential Change to Committee Structure,” NERC MRC, Trustees Meeting Briefs: May 8-9, 2019.)
“Right now, Option 2 is the one that’s getting the most traction within the group,” outgoing OC Chair Lloyd Linke told attendees of a joint OC/PC/CIPC meeting June 4. “And so, we have a small group that is reviewing the participation models from the various existing functions.”
Linke said the proposed change is a response to complaints that the three technical committees were inefficient given the increasing “blurring of the siloes.”
“The Member Representatives Committee and the NERC board was receiving input from executives in the industry that the current structure was too expensive; too much manpower was being spent in supporting the technical committees,” Linke said. “And they wanted NERC to take a hard look at that and see if there was any way that the technical comms could become more efficient.”
Linke also said the change is a recognition that NERC has been increasingly using cross-disciplinary task forces to address emerging issues, such as those on essential reliability services and inverter-based resources.
“The executives in the industry and the board have seen that working really well and want to make sure we maintain an agile process where we can continue to meet emerging issues,” he said.
The stakeholder engagement team — which includes Chief Reliability Officer Mark Lauby, Trustees Ken DeFontes and Fred Gorbet, and MRC Chair Greg Ford — is considering a 22-member Reliability Council with a hybrid structure: a single representative from each of the 11 sectors excluding regional entities and an equal number of at-large members selected based on a diversity of skills and geography, Linke said.
“There was a strong feeling that the regional entities are part of the ERO, and this being a stakeholder representative [group], there didn’t need to be regional entity participation,” he explained. “Most of the regional entities participate in these meetings as guests anyway, so that would still continue.”
The Reliability Council’s meetings would offer listen-only web access, Linke said. “So, I would still expect for those who wanted to actively participate to physically attend the meeting.”
Linke acknowledged the smaller committee would have to look beyond its membership to find subject matter experts for future task forces. “It will be a little more difficult, but I think it’s still manageable,” he said.
The current schedule calls for seeking MRC endorsement in August and delivering a final proposal to the board in November. The new structure would be effective Jan. 1, 2020, and be implemented for the March meetings, Linke said.
There are no current plans to change the structures of the subcommittees, task forces and working groups, but there would be a review after one year to determine if other changes should be considered, Linke said. “Right now, I don’t see charter changes to the subcommittees. Whether there may be in the future, I’d hate to hazard a guess.”
The current two half-day meetings for each committee would probably expand to a day-and-a-half or two days and would mostly take place at NERC offices, Linke said.
“What you would lose was some of the some of the industry presentations on lessons learned. … It would evolve down to … strictly a business meeting — report on what the subcommittees are doing, the task forces; providing whatever oversight and guidance may be needed and not a lot of the extra things,” he said.
Linke said the training and security briefings the CIPC has included in its meetings “could be on the front-end or back-end of some of these meetings or maybe the E-ISAC [Electricity Information Sharing and Analysis Center] will have to pick up a role.”
CIPC Chair Marc Child urged members to provide feedback on the proposal. “I’m a member of the Stakeholder Engagement Team myself, and I still have a thousand questions about how this is all going to work,” said Child, of Great River Energy. “The CIPC … [has] relationships with the E-ISAC we have to make sure that we maintain: entity direct access to National Lab partners and other federal partners.
“Work through your [trade groups], work through your other stakeholder organizations [to communicate] things that you like about the current model; things that you don’t like about the current model; things that you wish were happening,” Child continued. “Make sure your voice is heard.”
Linke said the board will accept input through the MRC sector representatives. “It will be probably be a consensus of the sectors as to what that policy input [to the board] will be,” he said.
NYISO said Wednesday it expects to have adequate resources on hand to meet slightly above-normal demand this summer, with 42,056 MW of capacity available to meet a forecasted peak of 32,382 MW.
The figures show the ISO will far exceed its capacity requirement of 35,002 MW, which includes an operating reserve requirement of 2,620 MW.
New York statewide generating capacity by fuel type | NYISO
“The state’s grid is well-equipped to handle forecasted summer demand,” said Wes Yeomans, NYISO vice president of operations, said in a statement. “We have performed on-site visits of key generating stations to discuss maintenance, testing and adequacy of fuel supplies for hot-weather operations.”
The ISO’s projected summer peak is 1.5% above the 10-year average and outpaces last summer’s actual peak of 31,861 MW recorded on Aug. 29 (and the 2017 peak of 29,677 MW) but is down from the 2018 peak forecast 32,904 MW. Demand topped 31,000 MW on six days last summer.
The peak is calculated to reflect normal summer conditions, but under more extreme weather scenarios peak demand could increase to about 34,186 MW, NYISO estimates. The ISO’s record peak of 33,956 MW occurred in July 2013 at the end of a heat wave.
The total capacity of power resources available to New York this summer include 39,295 MW of generating capacity from in-state power plants, 1,309 MW of demand response resources and 1,452 MW of imports from neighboring regions. The forecast factors in the expected impact of distributed resources and energy efficiency programs.
NYISO staff and the New York Department of Public Service last month informed the state’s Public Service Commission on summer electricity preparedness. (See “Grid Prepared for Summer,” NYPSC Modifies Standby Rates for DERs.) The department forecasts summer energy prices will be down 1 to 3% compared with last year, depending on load zone and weather conditions.
ORLANDO, Fla. — Tim Fritch, vice chair of NERC’s Synchronized Measurements Subcommittee, said June 4 that his panel’s research into the Jan. 11 Eastern Interconnection oscillation event has identified the need to improve data sharing and provide guidance for responding to such events.
Fritch briefed NERC’s Planning Committee on a survey the subcommittee created to determine whether utilities were aware of the event and how they responded. NERC reported earlier that the event lasted about 18 minutes, with power swings of 200 MW around Florida and 50 MW around ISO-NE.
Eleven utilities responded to the survey, including both transmission operators and reliability coordinators, and nine said they were aware of the event. Only two utilities reported taking action in response, both taking some of their units out of automatic generation control when they were oscillating, Fritch said.
Seven of the utilities agreed there is a need to develop both a phasor measurement unit data-sharing requirement for RCs, and a real-time regional oscillation and source detection tool. The same number agreed the SMS should identify and address gaps in existing reliability standards on RC-to-RC coordination.
The event was illustrated in a video by the University of Tennessee’s FNET/GridEye tool.
“It was hard to tell, unless you saw the very beginning of that video, who was creating the oscillation and who was responding,” said Fritch, an electrical engineer for the Tennessee Valley Authority. “And then going back and listening to RC calls, it was hard for the RC operators to understand where this all originated. So, I think we all agree this is something that needs to be addressed because a lot of these operators were essentially flying blind. Fortunately here, there were only two utilities that took action. … We know that, depending on what units were taken offline, it could have made the oscillation worse. … We need to address that and provide guidance to our operators about what to do when we have these type of events — or what not to do.”
Rob Cummings, NERC’s senior director of engineering and reliability initiatives, said that using FNET/Grid Eye “within 15 minutes I knew that it was a forced oscillation … and I also pinpointed the beginning and end to be in Tampa, Fla. So, if I could do that … the operators could too. And I’m more than willing to put together tutorials on how to determine this for the RCs.”
Fritch said the SMS would “essentially hand [the issue] off” to the Operating Reliability Subcommittee for additional discussion.
ORLANDO, Fla. — NERC’s task force on electromagnetic pulses (EMPs) will hold its first face-to-face meeting at the ERO’s offices in D.C. on June 12, but if you’re not already signed up, it’s too late to attend in person.
Director of Engineering and Standards Howard Gugel told a joint meeting of the Operating, Planning and Critical Infrastructure committees here on June 4 that the meeting was already full but that the daylong session will be accessible via WebEx.
Gugel said NERC is planning a workshop on the subject for late July that will be held in a larger venue.
The task force was formed in response to the Electric Power Research Institute’s April report on EMPs, which concluded that a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers have warned of. The EPRI report focused on the grid and transformers and did not examine potential impacts on generation. (See “NERC Task Force to Build on EPRI EMP Study,” NERC Standards News Briefs: May 8-9, 2019.)
“As we knew this report was coming out, we decided we needed to get a better understanding of how EMPs could affect our grid and if there were any potential actions that needed to be taken,” Gugel said. “So we reached out to the trade organizations to ask for a small representative number of individuals who had some expertise in the area that could look through the report and determine if there were any immediate actions that needed to be taken and to provide some direction.”
Gugel said the task force has not been formalized with a reporting relationship to any standing committees but that its structure could change in the future.
The task force, which is broken into three committees, will make any recommendations to the technical committees by the third quarter. Guidelines or best practices is one potential result, he said.
“Of course, everyone hates to use the dreaded SAR [standard authorization request] word. We’re certainly not jumping to any kind of standards solution,” he said. “But if, when that team is looking at that, they feel there’s something that needs to be addressed — whether it’s through our existing body of standards or a new [one] they develop — then that SAR would be presented to the Standards Committee, if applicable, in the fourth quarter of this year.
“I don’t want to raise everyone’s standards radar at this point,” he added. “I want to assure you that this is not the priority that this team is looking at.”
Supply Chain Data Request Coming
Gugel also said NERC staff are collaborating with the Supply Chain Working Group to develop a data request on supply chain cybersecurity that should be issued about July 2.
The data request is in response to a recent staff report that recommended additional study on whether low-impact systems with external routable connectivity should be covered by reliability standards. (See “Supply Chain Report Recommends Expanding Standards,” NERC Standards News Briefs: May 8-9, 2019.)
Gugel said staff drafted “strawman” questions for debate by the working group. “Any time we, as staff, try to develop something like that, we always seem to ask the wrong questions. So I’m very grateful that we get industry weighing in on this and helping us get the right questions.”
The responses will be due July 22, in time to share results with the Board of Trustees at its August meeting, Gugel said.
ORLANDO, Fla. — NERC’s Planning Committee acted on three reliability guidelines during meetings June 4-5, prompting SPP’s Shannon Mickens to ask how standards enforcement officials will treat entities that do not choose to follow them.
He noted that the guidelines state that ERO Enterprise Compliance Monitoring and Enforcement Program (CMEP) staff will give examples endorsed in such documents “deference when conducting compliance monitoring activities.”
“You say this is one way to meet your compliance. So, doesn’t an entity technically have to adopt that document?” Mickens asked.
Tim Fritch, vice chair of the Synchronized Measurements Subcommittee, said he shared Mickens’ concern. “We have gone round and round on this,” Fritch said. “So, if I don’t follow this, am I in compliance or not? … I guess the other way to do it is to try and cover every aspect [of compliance in the guidance document] and that’s” unrealistic.
PC Chair Brian Evans-Mongeon said entities should take up such questions with their regional entity’s compliance department. “There’s no way an implementation guidance document will answer every question,” he said. “We already know there are regional differences from time to time on subject matters, so your region may be willing to consider it differently than others.”
Evans-Mongeon also said the PC can submit implementation guidance to the compliance monitoring group. “So, if people have particular items that they would like to have passed on through, we’d be happy to assign it to a group and take a look at it.”
The chair also said that at its next meeting, the PC Executive Committee will consider creating a schedule for reviewing and updating existing guidelines about every three years.
Voting Actions
The committee:
Approved the application guide for Modeling Turbine-Governor and Active Power-Frequency Controls in Stability Studies to ensure turbine-governor models produce accurate angular stability, frequency stability and primary frequency response simulations. Applicable to: generator owners (GOs), generator operators (GOPs), transmission planners (TPs), planning coordinators (PCs) and power plant modelers as well as balancing authorities, transmission operators (TOPs) and reliability coordinators when performing stability studies.
Authorized posting of reliability guideline DER_A Model Parameterization for a 45-day comment period. The guideline is intended to avoid incorrect parameters that can prevent the DER model from capturing the frequency, voltage or trip settings needed to represent system performance accurately. Applicable to: PCs, TPs, TOPs and RCs.
Approved the Modeling Notifications process document, which explains the work of the System Analysis Modeling Subcommittee. The process allows SAMS to receive modeling information from power system modeling subject matter experts and simulation tool users and develop modeling notifications as needed.
Approved the Electric-Gas Working Group scope. The group will initially focus on developing guidance or guidelines for considering fuel-related risks in planning studies and system analysis.
Philosophical Question on Inverter-based Resources
ERCOT’s Jeff Billo, vice chair of the Inverter-based Resource Performance Task Force (IRPTF), raised what he called a “philosophical” question posed by the challenges of asynchronous generation displacing synchronous machines.
“As we move forward to more and more inverter-based generation, do we need to require the inverter-based generators to behave more like synchronous machines or do we change our philosophy of how we operate the system and make the system more accommodating to inverter-based [machines]?” he asked. He said he had not settled on an answer.
Billo cited studies showing that the grid cannot run on 100% “grid-following” inverters, whose control systems rely on strong 60-Hz signals from synchronous machines. “I really don’t like the term ‘grid forming’ inverter technology but that seems to be becoming the buzz phrase that people are using,” he said.
“You really need some of those to be grid-forming inverters. … I don’t think we’re at a point where we can specify technically what grid-forming means but there’s a lot of good discussion going on about that.”
Battery and Energy Storage Workshop Planned
NERC, the North America Generation Forum and the Energy Systems Integration Group are planning a workshop on battery and energy storage in September or October, John Moura, NERC director of reliability assessment, told the committee.
Chair Evans-Mongeon said the goal of the workshop will be to identify the impact of storage on the bulk power system and determine “if there is something of growing significance that warrants our attention.”
“I’m told there are two 400-MW battery systems that are slated for the West to come online this year. There is another proposal that I just saw earlier this week for a 1,000-MW compressed gas storage facility in the salt caverns of Utah,” he added.
Billo said that a workshop the Texas grid operator held on the subject in April attracted the biggest crowd of any stakeholder event in the last 10 years. “So, there’s a lot of interest,” he said. (See “Workshops Discuss Storage, Inverter-based Resources,” ERCOT Briefs: Week of April 22, 2019.)
Moura said the NERC session will likely be in D.C., with web access.
PC Chair Re-elected; MOD-32 SAR Reviewers Appointed
Evans-Mongeon (Utility Services) was re-elected as PC chair for a two-year term. Joe Sowell (Georgia Transmission) was elected vice chair, replacing Noman Williams (GridLiance).
Evans-Mongeon and Sowell also were appointed as reviewers for the System Planning Impacts from Distributed Energy Resources Working Group’s (SPIDERWG) draft standard authorization request to revise MOD-032-1 (Data for Power System Modeling and Analysis) to improve modeling of DER in planning studies.
Joining them will be Billo; Jason Spitzkoff (Arizona Public Service); Carl Turner (Florida Municipal Power Agency); Wayne Guttormson (SaskPower); Christine Ericson (Illinois Commerce Commission); Phil Fedora (NPCC); and Enoch Davies (WECC).
The current standard addresses the collection of modeling data for interconnection-wide base cases but has no provisions regarding DER data. The SAR proposes to include data requirements and reporting procedures for DER and replace the term load-serving entity with distribution provider (DP) because of the removal of LSEs from the NERC registry criteria.
Electronic Vote Set for PRC SAR
The committee will conduct an electronic vote on a SAR to amend PRC-019-2 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection) to address distributed power resources.
The standard, which addresses the reliability issue of miscoordination between generator capability, control systems, and protection functions, was developed for synchronous generation and “does not sufficiently outline the requirements for all generation resource types,” the SAR says. The initiative would seek to correct or clarify issues regarding synchronous generation to remove ambiguity.
Member Roundtable
In the member’s roundtable that closed the meeting, Williams and Turner expressed concern about the ERO’s ability to keep up with the accelerating rate of change in the industry. “Some of it’s driven internally, but I think a lot of it is driven by policymakers that are making decisions that are forcing us to do things that drive change, but they also stretch reliability and resiliency,” Williams said.
Turner noted the increasing involvement of manufacturers in NERC’s process as a result of changing technology. NERC should not stifle innovation, he said, but it must take the time to ensure that new technologies are properly vetted. “We have a duty, first and foremost, of providing safe, reliable power,” he said. “And we can’t just have it be a gold rush here: Some people got rich; some people got hurt. … I worry about that. Let’s stay vigilant as we try to keep up with all this.”
FERC gave PJM stakeholders just 90 days to settle all disputes about how to best liquidate financial transmission rights left over from the GreenHat Energy default before kicking off a paper hearing on the RTO’s request to clarify a previous ruling related to the debacle.
In an order issued Tuesday, FERC encouraged conflicting parties to hammer out disagreements ahead of the hearing under the guidance of a settlement judge, who will report progress on the discussions to the commission at the 45- and 90-day marks (ER18-2068). A one-time extension may be granted for 30 days, FERC said.
The order also granted PJM’s motion for clarification on its denied petition to waive its liquidation rules, which has complicated the RTO’s efforts to minimize the damage of the default and potentially increases costs to members by $300 million. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
In the absence of a rehearing, PJM had requested clarification on six different issues arising from the rejected waiver order that would force the RTO to unwind five months of FTR settlements and rerun the cleared July 2018 auction.
“The issues raised in the PJM motion for clarification and the subsequent answers demonstrate that there are multiple complexities associated with implementing the waiver order directive that should be addressed in a paper hearing where all parties will have an opportunity to present written evidence and argument,” the commission wrote.
Apogee Energy Trading and Elliot Bay Energy Trading both filed answers to PJM’s motion, with the former urging the RTO to follow Tariff provisions as closely as possible when rerunning the July auction using uncleared bids that do not violate the simultaneous feasibility test. The company argued the RTO’s motion favors one group of stakeholders over another “in terms of the allocation of the GreenHat default and by misrepresenting and potentially overstating the impact of the GreenHat default on the PJM market.”
Elliot Bay likewise complained that PJM’s proposed implementation steps would violate the filed rate doctrine and the related rule against retroactive ratemaking. “The PJM motion for clarification raises numerous issues of material fact that should be addressed in a technical conference, hearing or stakeholder process,” the company wrote in its March 13 filing.
PJM said, “There’s nothing simple about rerunning an auction and settling market positions” and contended that the accusations of discrimination were unsupported.
“While we are setting these matters for a paper hearing, we encourage the parties to make every effort to settle their disputes before the paper hearing commences,” FERC wrote, noting the paper hearing will be delayed to give enough time for negotiations. “Although the paper hearing is limited to PJM’s motion for clarification, we are not establishing similar limitations on the scope of the settlement discussions, and the parties are encouraged to address all disputes arising out of this proceeding.”
“We’re pleased that the commission set the matter for settlement,” PJM spokesperson Jeff Shields said Wednesday. “And we are hopeful that we will reach a resolution of the issues.”
LS Power filed a complaint Wednesday asking FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV and change its approach to estimating the benefits of smaller projects.
The complaint under Federal Power Act Section 206 requests the commission to order reforms on a 60-day deadline that establish cost allocation for market efficiency projects (MEPs) below 345 kV (EL19-79).
Currently, MEPs must meet a voltage threshold of at least 345 kV and cost at least $5 million. However, MISO earlier this year filed a Tariff revision to lower the threshold to 230 kV, a change that RTO staff have said will reflect the reality of a footprint where 230-kV lines are prevalent. (See MISO MEP Cost Allocation Plan Goes to FERC.)
FERC has yet to rule on the requested change, and LS Power has also filed its complaint in the docket for the associated proceeding (ER19-1124).
Comparison of lower voltage facilities in MISO | MISO
In its complaint, LS Power argues that reducing the voltage threshold to 100 kV would “remedy flaws in MISO’s economic planning process” and also expand the number of projects eligible for competition, consistent with FERC Order 1000.
“The commission should require MISO to resolve this issue quickly as it has been aware of this deficiency in its economic planning process for several years and failed to solve it in a just and reasonable manner,” LS Power said.
The company contends that MISO’s planning process fails to provide a “clear path” for regionally beneficial economic projects at lower voltages, resulting in “unnecessary congestion costs and unjust and unreasonable rates.”
Not Far Enough
MISO’s filing does seek to address at least some of LS Power’s concerns by creating a new category for economic projects below 230 kV and above 100 kV for which 100% of costs would be allocated to a local transmission pricing zone, rather than across multiple zones. Such transmission projects were previously categorized as “other” projects without clear allocation rules.
But the company said the RTO’s cost allocation proposal doesn’t go far enough and argued that economic projects below 345 kV can relieve congestion in multiple transmission pricing zones.
“There are not clear criteria or procedures for identifying and evaluating economic projects outside of the Market Efficiency category to determine whether they provide regional benefits and thus should be selected in MISO’s regional transmission plan. As a result, economically beneficial projects may not be identified or may otherwise stall during the planning process to the detriment of ratepayers,” LS Power said.
| LS Power
The company’s complaint goes a step beyond the cost allocation issue, asking FERC to find MISO’s current MEP planning process unjust and unreasonable because it doesn’t outline a path for planning regionally beneficial economic projects that don’t meet MEP criteria. The company also pointed to a substantial amount of 100- to 200-kV facilities in the MISO footprint, saying it’s likely the RTO has overlooked similar smaller projects that would reduce congestion across the footprint.
LS Power also charged that the MEP voltage threshold undermines Order 1000 because such a strict voltage criteria “effectively grants incumbent transmission owners in MISO a federal right of first refusal to build regionally economic enhancements that do not meet the market efficiency project thresholds.”
“It is time for the commission to send a clear message that it will not allow such end runs around Order No. 1000,” LS Power said. While it is difficult to gauge the financial harms related to MISO’s 345-kV voltage requirement for MEPs, the company said it is making a “good faith effort” to estimate the number of projects it may have lost out on.
The company also said it has already raised its MEP-related concerns with both MISO staff and in the RTO’s Regional Expansion Criteria and Benefits Working Group, where cost allocation decisions are made.
LS Power’s Republic Transmission is currently in the process of building the Duff-Coleman 345-kV transmission project in Southern Indiana and Western Kentucky, the RTO’s first competitive transmission project. (See Texas ROFR Law Clouds Hartburg-Sabine Future.)
