Page 1153 – RTO Insider

June 8, 2018

OMS-MISO Survey Reveals Dimmer View of Future Supply

By Amanda Durish Cook

CARMEL, Ind. — MISO’s supply picture for the next five years is less rosy — and less clear — than it was a year ago, according to an annual capacity survey released Friday in conjunction with the Organization of MISO States.

This year’s OMS-MISO resource adequacy survey projects that the RTO’s 2019 spare capacity will exceed its regional requirement by anywhere from 0.6 to 6.6 GW, yielding a reserve margin ranging from 17.6 to 22.4%.

OMS-MISO Survey resource adequacy — OMS MISO 2018 survey results | *MISO*

But survey results show the volume of spare supply after next year is less certain, owing to expected decreases in resource commitments, although it’s still possible the RTO’s excess capacity could outpace the high end of its 2019 prediction through 2022. Using the current 17.1% planning reserve margin, over the next five years, MISO’s footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall:

In 2020, MISO could have anywhere from a 7.3-GW surplus (representing a 22.9% planning reserve margin) to a 0.1-GW shortfall (a 17% reserve margin).
In 2021, the RTO could experience anywhere from a 7.5-GW surplus (23%) to a 0.9 shortfall (16.4%).
In 2022, the chance of a shortfall increases, with a range between a 7.5-GW surplus (23%) and a 2.3-GW shortfall (15.3%).
In 2023, MISO’s possible high-end capacity surplus drops to 6 GW (21.8%), while the possible shortfall could reach 4.5 GW (13.5%).

Last year’s survey showed MISO would have anywhere from 2.7 to 4.8 GW of excess resources from 2018 to 2022, translating into a 16 to 22% reserve margin because of lower demand forecasts and a lukewarm growth rate of 0.5%, down from 0.8% in 2016. (See Capacity Survey Shows MISO in the Black.) In this year’s five-year outlook, the regional growth rate again decreased from 0.5% to 0.3%. MISO said 97% of load responded to the survey.

“While we continue to see decreasing demand in the MISO footprint, the story continues to be the evolving generation portfolio,” MISO CEO John Bear said in a statement. “As the MISO footprint continues to transform, we must learn to adapt in areas such as our transmission planning studies, market-based solutions that focus on speed and flexibility and enhancing coordination with our neighboring seams partners.”

During a June 8 conference call to discuss results, MISO Executive Director of Resource Planning Patrick Brown acknowledged that this year’s survey shows more risk to resource adequacy than projected last year.

“The main driver of this resource adequacy risk are generation retirements,” Brown said, adding that more retirement announcements have occurred since MISO and OMS collaborated on the 2017 survey, resulting in about 4.6 GW of decreased resource availability. The RTO said the majority of potential deficits are concentrated in Illinois’ Zone 4 and Michigan’s Zone 7. Brown noted the resource adequacy risk is higher because the RTO predicts it will require higher future reserve margins because of its increasing forced outage rate.

But Brown also pointed out that the survey represents a “snapshot,” and that more capacity than currently expected could come online to offset retiring generation.

“MISO fully expects this forecast to change going forward,” he said.

Zones with surplus capacity can help neighboring zones with capacity deficits, Brown added.

“Zones with deficits do not automatically face a reliability risk,” he said.

But by 2023, zones enjoying surpluses may not be sufficient to entirely cover possible capacity deficits in three zones. By that year, the survey showed Zone 4 could face either a 1.1-GW capacity surplus or a 2.8-GW capacity shortfall, while Zone 6 in Indiana and Kentucky could experience anywhere from a 0.3-GW surplus to a 1.6-GW shortfall. Zone 7 faces the most certain shortfall, ranging between 0.8 and 1.8 GW.

Brown said MISO’s current 93-GW interconnection queue contains 80 GW of renewable energy, with just 580 MW of storage in the works to make renewable capacity more dependable. However, he said, MISO fully expects more storage to enter the queue in the future.

“It’s particularly import that we’re doing this in light of the evolving resource mix,” OMS Executive Director Tanya Paslawski said of the survey.

This year’s survey relied on a new calculation for estimating the volume of future new resources. MISO tallied projects not yet in the three-part definitive planning phase (DPP) of its interconnection queue (and those having entered the DPP’s first phase) at a 10% completion rate. Conventional and intermittent resources in phase two of the DPP were counted at 50% and 25%, respectively, which increased to 75% and 50% in phase 3. Projects still negotiating a generator interconnection agreement were tallied at 90% completion, while those with signed agreements were counted as new generation in the survey’s weighted averages. (See MISO RASC Briefs: Little Change to Capacity Forecasts.)

MISO staff will present a more detailed rundown of OMS-MISO survey results at the RTO’s July 11 Resource Adequacy Subcommittee meeting.

June 7, 2018

LaFleur, Glick Promise a Light Touch on Changing West

By Jason Fordney

BOISE, Idaho — Two top federal energy regulators told state utility commissioners that they will take a light-handed approach as the West develops new market structures, allowing flexibility and acknowledging regional differences.

Cheryl LaFleur Richard Glick Western Conference NARUC — LaFleur | © *RTO Insider*

Long-time FERC Commissioner Cheryl LaFleur, and Richard Glick, who joined the commission in November, made their remarks to state regulators and industry representatives at National Association of Regulatory Utility Commissioners’ Western Conference of Public Service Commissioners (WCPSC).

LaFleur on Monday noted that dramatic shifts have taken place in the West just this year, with membership changes at Mountain West Transmission Group and competing market proposals from CAISO and Peak Reliability/Multiple Entities, Markets Now Beckon in West.)

“I think the West is the biggest story of 2018, just because of the level of interest and the number of changes,” LaFleur said. She told Idaho Public Utilities Commission President Paul Kjellander that she is “trying to send positive vibes out to the West” and “a warm current of support.”

She acknowledged that when it comes to federal oversight of the West, the California energy crisis and opposition to FERC’s Standard Market Design are still on people’s minds. There are also concerns among Western states about increased regulation by FERC during the administration of President Trump.

“Anything that happens cannot be driven from Washington, D.C., because we tried that, and it really failed,” she said, adding that “we are trying to not make it a FERC thing — it doesn’t really matter what we want.”

She said the West “seems to be in a very dynamic place right now.” The commission’s default answer on Western market integration proposals should be “yes, you can do things differently, unless there is something that is going to be wrong for customers and not just and reasonable.”

Appointed in 2010, LaFleur has worked alongside 11 commissioners and is a former chairman and acting chair. Kjellander asked what lessons LaFleur had learned during her time, which last year included a stint as the sole commissioner.

“I definitely have had a very unusual run,” LaFleur said. “It’s really been a magical mystery tour.

“One my little aphorisms is that life is a movie, not a snapshot,” she added. “Things change.”

She acknowledged changing political headwinds in the transition from President Barack Obama to Trump. “I really wanted to stay through and come out the other side and be happy, and I have,” she said. “I love the work.”

She said that the current FERC membership is still finding its center as a body.

FERC’s newest challenge is Trump’s June 1 directive to Energy Secretary Rick Perry to prevent further nuclear and coal plant retirements. The announcement was a major topic among attendees at the conference. LaFleur in comments to RTO Insider indicated a wait-and-see approach on the directive. (See More Questions than Answers for FERC, RTOs on Bailout.)

Glick Discusses Regionalization, Tx Incentives

Glick told the conference that when it comes to FERC’s regulation of the West, “more of a hands-off approach is best.”

He took to the stage on Tuesday under emergency lighting, with no microphone or sound system as a local substation problem had the Boise Centre operating with backup generators.

“Obviously, if we just had more coal and nuclear plants, this wouldn’t be happening,” Glick joked as he opened his speech, drawing laughter from the state officials in the audience. Power was restored during his comments.

Glick noted that when he was at the Department of Energy, he spent a year and a half working “almost exclusively” on the Western Energy Crisis, which he called “an interesting learning experience.” He also worked for PacifiCorp, Iberdrola (now Avangrid Renewables) and for Sen. Maria Cantwell (D-Wash.) as counsel to the Senate Energy and Natural Resources Committee.

“We are in an incredibly interesting time in the energy industry right now,” Glick said. There have been benefits to the rapid change, he said, including more choices for consumers, lower costs and cleaner energy resources.

“That doesn’t mean there aren’t some challenges,” he said, mentioning integrating renewables and the “duck curve” in California, communities being affected by coal and nuclear plant closures, and difficult issues around Western market regionalization.

He noted that benefits of the Western Energy Imbalance Market are multiplying, the market is growing and “it seems to be working very well.” But he added that “I am very aware of the politics vis-a-vis FERC and the Western states,” mentioning hostility toward Standard Market Design, and lingering mistrust between California and other Western states. Glick said his approach at FERC will be to support regionalization, but “we need to be as deferential as possible.”

“If we push the envelope, given the history of FERC and the West, that might not necessarily work out the best for anybody,” he said.

Glick also reiterated his call for FERC to review its policy on transmission incentives. “I’m not sure we are really incenting the right thing,” he said, noting that FERC routinely grants return on equity bonuses for participation in an RTO or ISO.

“I think the argument is they would be in an RTO or ISO anyhow.” He said FERC should be encouraging “right-size” transmission and using existing transmission more efficiently.

June 7, 2018

NYISO Favors Cost Levelizing on Carbon Charge

By Michael Kuser

RENSSELAER, N.Y. — NYISO continues to propose a cost-levelizing approach for allocating carbon charge residuals to load-serving entities, it told New York’s Integrating Public Policy Task Force (IPPTF) and stakeholders on Monday.

The ISO’s preferred approach would have suppliers embed the carbon charges into their all-in day-ahead and real-time energy offers, as they currently do with emissions costs under the Regional Greenhouse Gas Initiative, as it presented to the task force in April. (See NY Task Force Briefed on Carbon Charge Mechanics.)

The June 4 allocation discussions were part of issue Track 2 in the group’s five-track effort to price carbon emissions into New York’s wholesale electricity market.

Progress Review

IPPTF Chair Nicole Bouchez, the ISO’s principal economist, reviewed the task force’s progress in meeting almost weekly every Monday over the past eight months. She said the group is on track to deliver by December either a proposal to incorporate the cost of carbon into the wholesale market, provide a detailed schedule to complete the proposal next year or notify the task force if it concludes that the plan is not viable.

A draft proposal is slated to be delivered Aug. 1, Bouchez said.

“It is absolutely critical that we move quickly to get to a point of either this is going to happen or this is not,” said Mark Younger of Hudson Energy Economics. “We need clarity on that as soon as possible so that if it’s not going to happen, we can proceed with other things that will.”

Couch White attorney Kevin Lang, representing New York City, asked why stakeholders needed to move quickly.

“Because we have a serious problem with a substantial mismatch between public policy actions and our markets, and it is causing severe damage in our markets,” Younger said.

“No, that’s your view that there’s a mismatch,” Lang said. “The [Public Service Commission] is adhering to its public policy, which it has every legal right to do. You may not like the result, but that doesn’t mean we need to move very quickly on this issue, which is not yet fully developed.”

Fair Cost Burden

Locational-based marginal prices would increase according to the emissions rate of the marginal, price-setting resources — the marginal emissions rate (MER).

“As a result of load paying the full LBMP for their energy withdrawals, and suppliers not receiving the full LBMP for their energy generation — then being charged for their carbon emissions — there is an imbalance between bills and credits,” said ISO staffer Nathaniel Gilbraith. “This imbalance is what we’re calling a residual, and it’s going to be returned to loads using one of the methods we discuss today.”

carbon charge cost-levelizing LSE NYISO — | *NYISO*

The ISO’s presentation Monday detailed three approaches to allocation of residuals: load ratio share, cost levelizing and proportional allocation, with the latter two based on the carbon effect on each zone’s LBMPs.

The load ratio share results in all LSEs receiving the same refunds on a dollar-per-megawatt-hour basis, causing greater differences in the net cost of carbon pricing. On the plus side, it would provide LSEs with price signals more reflective of the carbon intensity of their consumption.

Cost levelizing produces the most similar cost burden in terms of dollars per megawatt-hour of carbon charge, but it also limits the differential price signal to reduce consumption, Gilbraith said. Zones with high MERs would not necessarily see an incentive to reduce consumption relative to those with lower rates.

Proportional allocation would return carbon charge residuals to all LSEs based on the proportional effect carbon prices have on their gross energy payments. It would return more revenues to LSEs facing higher dollar-per-megawatt-hour cost impacts but would not go as far as levelization.

The ISO said this provides some balance between economic efficiency and equity of cost burden by maintaining some of the differential price signals to encourage reduced consumption and emissions.

In its 2025 base case analysis, the ISO said downstate LSEs would face the highest net increase in energy payments (carbon payments minus residuals) under the load ratio share (8.93 cents/kWh) and the lowest under levelizing (8.96 cents/kWh).

The impact on upstate would be reversed: 6.57 cents/kWh under load ratio and 6.71 cents/kWh for levelizing.

Gilbraith added that the analysis did not cover allocation by LSEs to retail customers, which would be under PSC jurisdiction.

Lang said he understood not considering retail allocation but noted that the ISO assumed that a carbon charge would affect the price of renewable energy credits, which is entirely under PSC jurisdiction. “So why are you picking and choosing which area of PSC jurisdiction you’re going to intrude into and which parts you’re not?” he said.

Michael DeSocio, the ISO’s senior manager for market design, said the ISO is working “to make sure that if a market-based carbon pricing effort like this would move forward, that future determination of RECs and other products like that could be adjusted to consider that alternative. … We’re filing comments [with the PSC] regarding ORECs [offshore wind RECs] on how a contract structure could work with a carbon pricing mechanism [to] minimize any double compensation.”

Topics for discussion include whether residuals allocated to an LSE should be allowed to exceed that entity’s gross carbon payments and what criteria stakeholders are looking for in terms of equity vs. cost burden.

Status, Schedules

The ISO in May began running the task force, which it set up last year in partnership with the state’s Department of Public Service.

The straw proposal assigned to issue Track 1 was delivered on April 30 and reviewed by stakeholders May 14, and therefore will be closed, said Bouchez.

Track 2 focuses on the market mechanics of a carbon charge and has so far had the broadest range of topics covered of any track, Bouchez said. The IPPTF will discuss the track on June 18 and July 9, and the schedule has five open Mondays through October in case the group needs more time on it.

Track 3 covers how a carbon charge should be set and adjusted for the Track 5 customer impacts analysis. No additional work has been scheduled on Track 3 since DPS staff and a stakeholder both presented recommendations for setting the carbon charge, which is ultimately the responsibility of the PSC.

Track 4 focuses on a carbon charge’s interactions with other state policies and programs, and there is no additional work currently scheduled. The group plans one more meeting on Track 5 customer impacts analysis before starting the base modeling work. The group will also meet to review assumptions used in the “dynamic change case” analysis, with stakeholder review in September and October, Bouchez said.

The task force next meets June 18 at NYISO headquarters to address Track 5 assumptions and scenarios on customer impacts, and wholesale market processes under Track 2.

June 7, 2018

MISO Offers Straw Storage Proposal to Meet Order 841

By Rich Heidorn Jr.

Electric storage resources (ESRs) 100 kW or larger would be eligible to offer capacity, energy and ancillary services under a straw proposal MISO officials presented to stakeholders Wednesday.

FERC Rules to Boost Storage Role in Markets.)

miso ferc order 841 energy storage — Storage modes under MISO straw proposal | *MISO*

The Market Subcommittee will take the lead on six of the issues:

definition, elements and modeling, including minimum size requirements;
market participation (bid parameters, offers, commitment and dispatch);
state of charge measurement and management;
market participation (eligibility, as seller and buyer);
metering and accounting; and
settlements (make-whole payments, compensation, performance and penalties).

The Reliability Subcommittee will address reliability (qualification) and non-market products. The Resource Adequacy Subcommittee will focus on capacity and resource adequacy administration.

MISO officials outlined the proposal during a daylong joint meeting of the three subcommittees and the Planning Advisory Committee.

The RTO expects stakeholder discussions through October and completion of the plan for a compliance filing on Dec. 3. Implementation would begin in December 2019. The first resources registered under the new participation model will be able to participate starting March 1, 2020.

In meeting Order 841’s requirements, MISO’s compliance filing will also address shortcomings FERC identified in the RTO’s existing Tariff rules on Stored Energy Resources (SER) – Type II. MISO previously proposed the SER – Type II category in response to FERC’s partial granting of Indianapolis Power and Light’s earlier complaint on its storage rules. (See FERC OKs MISO Plan to Expand Storage.)

Four Commitment Modes

The new rules will apply to batteries, flywheels, compressed air, pumped hydro and any other technologies meeting FERC’s definition of an ESR: one “capable of receiving electric energy from the grid and storing it for later injection … to the grid.”

Resources could be connected to the interstate transmission grid, a distribution system or behind the meter. Demand response, which cannot inject energy, is excluded. The initial ESR participation model also will not accommodate distributed energy resource aggregations across multiple pricing nodes.

The RTO said it will expand the ESR category in the future based on improvements to its Market Systems, the Market Roadmap and advances in storage technologies.

ESRs would participate under four modes of commitment: charging, discharging, continuous operations and outage/offline, as specified by the market participant for individual dispatch periods. When in online mode, storage will be treated as must-run resources.

The state of charge will be managed by the market participant and communicated to MISO via telemetry and offer parameters.

A storage resource would pay the LMP of their commercial pricing node when withdrawing charging energy and receive payment at the LMP during injections. Storage will be eligible for make-whole payments under MISO dispatch decisions consistent with eligibility rules for other resource types.

In addition to providing energy, capacity and ramping, storage will be permitted to offer non-market-based services (reactive supply and voltage control and black start).

Rehearing Request

On March 19, MISO asked FERC to clarify or change some aspects of the order. For example, it requested a phased approach for small ESRs (less than 5 MW). It suggested up to 50 be permitted in the first year and 150 in the second.

It also requested a six-month extension for implementation relating to issues pending in the commission’s separate DER proceeding (RM18-9, AD18-10).

MISO asked for feedback on the straw proposal, including responses to a questionnaire by June 22. The proposal is expected to be discussed at the RASC on July 11 and MSC on July 12. The proposal is also expected to be mentioned at the Energy Storage Task Force meeting on June 27.

June 7, 2018

Westward Ho: SPP Plans to Become RC in West

By Tom Kleckner

SPP’s announcement Tuesday that it will provide reliability coordinator (RC) services in the Western Interconnection should not come as a surprise.

The Arkansas-based RTO has long been interested in expanding into the Western market, where CAISO stands as the only system operator. The integration of Nebraska utilities in 2009 and the Integrated System in 2015 brought the RTO’s footprint alongside the seam between the Western and Eastern Interconnections.

SPP’s bid to add the Mountain West Transmission Group entities to its membership roll, though threatened by Xcel Energy’s decision to withdraw from the effort, would expand the RTO into the Western Interconnection. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

SPP reliability coordinator Mountain West — SPP’s headquarters | *Nabholz Construction*

SPP said it intends to serve as an RC in the West by late 2019, leveraging “its expertise and systems to provide reliability and cost savings to Western utilities while lowering costs for its existing members.” The RTO said it has sent letters to the Western Electricity Coordinating Council and NERC expressing that intention and its commitment to working with WECC and Western RCs to ensure reliability.

“We’ve shown consistently throughout our history an ability to coordinate people, systems and complex processes to keep the lights on,” SPP CEO Nick Brown said in a statement, noting the organization has been performing reliability services since its founding in 1941 and was certified as an RC in 1997.

SPP said 28 Western utilities, representing about 200 TWh of net energy for load, have already signed letters of intent expressing interest in its reliability services. If it proceeds with its plans, the RTO will join CAISO and PJM Connext, a joint effort between PJM and Peak Reliability, in offering reliability services in the West. (See Multiple Entities, Markets Now Beckon in West.)

Peak not Surprised

Peak said it was not surprised by SPP’s announcement.

“We are in a competitive market for RC services and the [balancing authorities] and [transmission operators] are quite rightly preserving their options so that they can determine the best fit for their organization,” said Rachel Sherrard, Peak’s vice president of external affairs. SPP’s announcement “is not an indication of decisions made.”

Sherrard said Peak will join SPP and CAISO in soliciting letters of intent from entities interested in taking their RC service from it. “Our process aligns with a recent request by WECC to the BAs and TOPs in the Western Interconnection to provide WECC with confirmation of which RC they will be using by Sept. 4, 2018,” she said.

Plenty of Room

Asked whether there’s room for another RC in the West, SPP pointed out that it is one of 10 RCs in the Eastern Interconnection, where it has a “proven history of working with neighboring RCs.”

“We are confident our experience, tools and processes can contribute to enhancing reliability in the West,” SPP spokesman Dustin Smith said in an email. “As we’ve done with RCs in the East, we are committed to working with Peak and CAISO to establish tools and data exchanges that ensure wide area visibility between RCs.”

Smith said the announcement doesn’t mean SPP’s integration of the Mountain West entities is over.

“SPP continues to discuss potential RTO membership opportunities with [Mountain West], and we expect those discussions to continue as we work to develop our RC services offering parallel to that,” he said.

June 7, 2018

FERC Seeks Info on MISO South Capacity Plan, SPP Tx Limit

By Amanda Durish Cook

FERC is seeking more specifics on MISO’s plan to improve its procurement of reserves in MISO South, asking the RTO in a June 5 deficiency letter how it will impact the contractual transfer limit on flows crossing SPP transmission (ER18-1464).

MISO proposed in late April to apply its existing reserve procurement enhancements — first rolled out in 2011 in MISO Midwest — to the sub-regional constraint between Midwest and South.

The RTO’s reserve procurement enhancement models the effects of transmission constraints by accounting for the deliverability of reserves deployed from market-cleared resources and adding a marginal cost of delivering reserves to the zonal reserve market clearing price. The change would also subject sub-regional capacity commitments in South and binding flows in the Midwest-to-South direction on the sub-regional limit to the Independent Market Monitor’s mitigation authority.

reserve procurement enhancement MISO South — MISO Midwest and MISO South | *MISO*

MISO’s reserve procurement practices currently only apply to physical transmission constraints, not contractual constraints like the sub-regional limit with SPP.

MISO acknowledged in its filing that a new product providing capacity within 30 minutes would be most effective in solving South’s lack of fast-start resources and reserve scarcity but said its April proposal was a more near-term solution and asked that it become effective June 27. The RTO said it currently makes out-of-market commitments to meet South capacity requirements that result in high revenue sufficiency guarantee (RSG) costs.

In stakeholder meetings, MISO staff have said that a short-term capacity reserve would be especially helpful in South, which has less than 500 MW of capacity available within 30 minutes. The West of the Atchafalaya Basin load pocket has 100 MW of 30-minute reserves, while Amite South has none. (See “Short-term Capacity Product is a Go, MISO Concludes,” MISO Market Subcommittee Briefs: April 12, 2018.)

In an affidavit accompanying the filing and supporting expanded mitigation, Monitor David Patton said that South is more susceptible to market power than Midwest because South has more pivotal suppliers.

But FERC said MISO’s reserve plan only promised to abide by “appropriate limits” of its sub-regional transmission and did not explicitly reference the maximum contractual limits set forth in the MISO-SPP transmission use settlement agreement struck in 2015. The commission said it was “unclear” if MISO intended to abide by the established megawatt limits in the proposal. The commission also asked MISO to explain its generation shift factors — especially when the MISO-SPP contract path binds on flows into South — and to explain its process for updating shift factors.

FERC issued the deficiency letter after regulators from Texas, Arkansas, Louisiana, Mississippi and New Orleans filed a limited protest May 24. The regulators asked that MISO specify that its reserves procurement modeling will use a 3,000-MW limit on north-south flows and 2,500-MW cap on south-north flows, reflecting the regional directional transfer limits in the MISO-SPP joint operating agreement settlement.

The commission required MISO to list the number of hours by month that the sub-regional constraint bound in each direction during 2016 and 2017. It also instructed MISO to estimate the amount of RSG payments that would be affected had the changes been active in 2016. MISO had said that its proposal to extend mitigation would reduce RSG payments.

Finally, FERC asked MISO whether it or Patton could produce “any studies or analyses regarding the expected increase in the frequency with which the … constraint will bind into MISO South once MISO applies the reserve procurement enhancement provisions.”

The commission gave MISO three weeks to respond to its questions.

June 5, 2018

Gas Gens Ask FERC for ‘Clean MOPR’ in PJM

By Rory D. Sweeney

Three owners of gas-fired generation in PJM’s territory have filed a complaint asking FERC to direct the RTO to adopt what they’ve termed a “clean MOPR” to be implemented in time for the May 2019 Base Residual Auction (EL18-169).

The minimum offer price rule sought by CPV Power Holdings, Calpine and Eastern Generation would be applicable to all subsidized resources and wouldn’t include categorical exemptions like those in the Independent Market Monitor’s MOPR-Ex proposal that PJM filed along with its own capacity repricing proposal as part of its “jump ball” proceeding.

FERC PJM Calpine Eastern Generation Clean MOPR — FERC Headquarters | © *RTO Insider*

While the clean MOPR would also include federal subsidies, it would retain an exemption for unit-specific justifications of offers below the rule’s floor. MOPR-Ex includes exemptions for self supply, states’ renewable portfolio standards, public power and competitive entry. (See PJM Capacity Proposals Widely Panned.)

The generators say they are offering “a vehicle for the commission to initiate a separate proceeding” from the other two proposals and a 2016 complaint, which Calpine and Eastern Generation joined, on how the existing MOPR handles subsidized resources (EL16-49). They say neither of the two previous dockets “allow the commission to take the sort of comprehensive action that is urgently needed at this time,” but they also ask that the records from those two dockets be incorporated into their new complaint.

The complaint, which is more than 600 pages, includes an affidavit by Roy J. Shanker, a well-known industry consultant, who says that “the only realistic fix to subsidies is a clean MOPR” that is “straight-forward, easily understood and, with the elimination of the exceptions and exemptions, administratively simpler than MOPR-Ex.” He goes on to list six attributes that the “clean MOPR” would provide, including facilitating “robust competition,” not impeding or distorting price signals, ensuring least-cost resources are selected, price transparency, shifting risk from customers to private capital or the political entities creating the subsidies, and mitigating market power.

The companies also note that some subsidies “greatly exceed” BRA clearing prices, which Shanker says “should provide the commission great pause.” The subsidies “crowd out” economic resources, causing them to retire early, and discourage new economic resources. Shanker says that the participation of 1,000 MW of subsidized resources in the auction could “depress overall market prices by $1 billion,” and with states considering subsidies for perhaps 10,000 MW or more, “billions of dollars in price suppression is simply not sustainable.”

The complainants make several arguments for why subsidies need to be eliminated from markets completely, lest they irrevocably break them. They mention the Monitor’s warnings that “subsidies are contagious” and “an effort to reverse market outcomes with no commitment to a regulatory model and no attempt to mitigate negative impacts on competition.”

The actions of one state “can have a significant impact on wholesale prices affecting loads in other states,” they argue, urging FERC to “be cognizant of the fact that failure to protect the organized, multistate [Reliability Pricing Model] market from one state’s policy choices inevitably impacts other states.”

The generators say they’ve brought up the issues in PJM stakeholder meetings, but the results lead them to “believe that further discussions between the parties will [not] resolve the concerns.”

June 5, 2018

FERC Postpones Tech Conference on PJM Regulation Market

By Rory D. Sweeney

FERC agreed last week to postpone a technical conference over PJM’s frequency regulation market and appoint a settlement judge to help resolve a dispute over how the service is compensated (EL17-64, EL17-65, ER18-87).

The Energy Storage Association, Renewable Energy Systems Americas and Invenergy Storage Development, which had opposed PJM’s October 2017 proposal to revise the service, joined with the RTO in asking FERC to postpone the technical conference. They said the delay would allow them “to focus their efforts on settlement proceedings and avoid potentially duplicative information gathering.” They said appointing a settlement judge would “facilitate the expeditious resolution of the issues.”

pjm ferc frequency regulation technical conference — PJM’s updated regulation rules changed requirements from on- and off-peak to on- and off-ramp | *PJM*

FERC ordered the technical conference March 30 while also granting in part a complaint by the ESA and rejecting PJM’s proposed changes to improve its regulation market. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.)

In October 2017, the RTO proposed a four-part plan that included redesigning its two regulation signals to work together to manage area control error. It included a new “regulation rate of technical substitution curve” to replace the “mileage ratio” calculation that the RTO says is problematic, and adjusted calculations for performance scoring, settlements and lost opportunity costs.

The opponents argued that related operational changes had significant negative impacts on battery storage and are “a symptom of the broader problem that the RTO misuses regulation resources to reduce generation on its system for sustained periods of time.”

In rejecting PJM’s proposal, the commission said the RTO hadn’t addressed the issues for which the commission rejected previous proposals on the topic.

In their May 18 request to delay the technical conference, the parties said they’ve had “preliminary discussions” that “would be best addressed under the direction of a settlement judge and in a forum in which all interested intervenors could participate.” They promised to file a joint update within 90 days of the judge being appointed.

PJM’s Independent Market Monitor opposed the request, saying it’s “premature” because FERC’s most recent rejection remains subject to requests for rehearing.

FERC disagreed, saying its “policy favors settlement.” It ordered the judge to file an update within 30 days of being appointed and every 60 days thereafter if the discussions continue.

June 5, 2018

MISO Makes Second Attempt at Pseudo-tie Contract

By Amanda Durish Cook

CARMEL, Ind. — MISO plans to file a reworked version of its pro forma pseudo-tie agreement this month after FERC rejected a previous proposal earlier this year.

The commission’s February order rejecting the earlier agreement in part found fault with MISO’s proposed suspension and termination provisions. (See FERC Rejects MISO Pseudo-Tie Pro Forma.)

This time MISO will file two separate pro forma agreements with FERC: one for generators pseudo-tying into the RTO and one for generation pseudo-tying out, Principal Engineer Kyle Abell said during a May 31 Reliability Subcommittee meeting. He said the two separate agreements will clarify the responsibilities of both MISO and the external balancing authority.

miso pjm ferc pseudo tie — MISO Reliability Subcommittee in April | © *RTO Insider*

Additionally, MISO says it will coordinate the suspension and termination of pseudo-ties with external BAs and follow suspension processes outlined in joint operating agreements with those BAs, if they exist.

Identical provisions in both versions of the agreement would allow MISO to suspend a pseudo-tie if it poses a reliability risk, violates the Tariff or any applicable joint operating provisions, breaches the pro forma, or fails to provide required real-time data to the RTO. MISO may also terminate pseudo-ties when they are subject to two or more suspensions during a 30-day period.

Each of the agreements provides pseudo-tie owners up to 30 days to resume normal operation from suspended status when they provide “a remedy for the cause of the failure.”

MISO could also terminate an agreement after a 60-day notice if it determines that the “existing market design does not accommodate the pseudo-tie.” It also retained provisions to suspend or terminate pseudo-ties that do not maintain firm transmission service from source to sink for the life of the pseudo-tie or cannot maintain a generation-to-load distribution factor within 2% between MISO and an external balancing authority area.

During a May 30 MISO-PJM Joint and Common Market meeting, PJM’s Tim Horger said there wasn’t much left to report on the RTOs’ overall pseudo-tie coordination plan, which he called a “good thing.”

“A lot of the pseudo tie initiatives have come to a conclusion,” Horger said.

MISO and PJM hope to implement the first phase of a previously announced fix to the double-counting of pseudo-tie congestion charges by Aug. 1, although FERC has not yet ruled on the RTOs’ rebate solution filed in late October 2017. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)

June 5, 2018

ERCOT Briefs: Week of June 5, 2018

Potomac Economics, ERCOT’s Independent Market Monitor, released its annual State of the Market report last week, saying the wholesale market “performed competitively” in 2017.

The Monitor said higher natural gas prices led to higher energy prices last year, with ERCOT’s load-weighted average real-time energy price rising 14.7% to $28.25/MWh. The average price for natural gas jumped 22%, from $2.45/MMBtu to $2.98/MMBtu.

ercot market monitor state of the market report — | *Potomac Economics*

Market conditions were rarely tight last year, the Monitor said, noting real-time prices did not exceed $3,000/MWh and broke $1,000/MWh for only three and a half hours.

However, total congestion costs in the real-time market almost doubled to $967 million. The Monitor attributed the increase to continued limitations on export capacity from the Panhandle, planned outages associated with the Houston Import Project’s construction and “unusual operating conditions” after Hurricane Harvey.

Although the market performed competitively, the Monitor made seven recommendations — all but one of them repeats from prior years — to improve the system’s operation and resources and price formation in the energy and ancillary services markets.

The Monitor’s new recommendation is to pay locational prices to all generators with output that affect a transmission constraint. Generators less than 10 MW and connected to the transmission system don’t bear the same obligations as larger generators and are settled at the load zone price, not a location-specific nodal price.

“Small generators … should settle in a manner consistent with the effect they have on the system,” the Monitor said in its report. “The output of some small generators can significantly affect transmission congestion.”

The Monitor suggests that when the smaller generators relieve a constraint, they be paid a much higher price than they are currently. When they aggravate a constraint, they would generally settle at a lower price.

“Settling with this generator [at] a zonal price fails to provide efficient incentive for it to operate in a manner consistent” with the system’s reliability needs, the Monitor said.

The report’s repeat recommendations are:

Implementing real-time co-optimization of energy and ancillary services.
Evaluating policies and programs that create incentives for loads to reduce consumption for reasons unrelated to real-time energy prices.
Modifying the real-time market software to better commit load and generation resources that can be online within 30 minutes.
Consider including marginal losses in LMPs.
Pricing future ancillary services based on the shadow price of procuring the service.
Evaluating the need for a local reserve product.

The Monitor has called real-time co-optimization the “most vital” market improvement and “foundational” to efficient pricing. The Public Utility Commission of Texas in December approved ERCOT’s proposed plan to further assess the benefits of implementing real-time co-optimization and marginal losses (Project No. 47199). As part of the project, the Monitor developed software to simulate co-optimization for 2017, and it intends to make the software, data and results available to all market participants.

The Monitor usually reviews the State of the Market report during the June Board of Directors meeting. Beth Garza, the Monitor’s director and Potomac Economics vice president, is also scheduled to detail the market’s performance during the Gulf Coast Power Association’s June 21 luncheon in Houston.

System Sets New Demand Records for May, June

The ERCOT system began June the way it concluded May, registering a new monthly demand record in the face of sweltering Texas heat.

The grid operator, which manages the energy flow for about 90% of the state’s electric load, recorded a new demand record for June on Friday with a load of 67.9 GW between 4 and 5 p.m. That broke the previous June record of 67.6 GW, set last year.

Real-time average prices peaked at $54.02/MWh in the interval ending at 2 p.m.

ERCOT established a new record for May for three consecutive hours on May 29, reaching 64.8 66.3 and then 67.3 GW during the intervals ending at 3, 4 and 5 p.m. The new mark is a 13.5% increase over the May record set last year.

Prices were as high as $92.95/MWh.

Texas has been beset with triple-digit temperatures. The National Weather Service issued a heat advisory for areas northwest of Fort Worth over the weekend, with predicted highs of 105 degrees Fahrenheit.

ERCOT said it had no plans to appeal for conservation, saying it has sufficient generation to meet demand.

The grid operator has now set monthly demand records for four months this year. It has projected a summer peak of 72.8 GW in August, which would break the 2016 record of 71.1 GW. It says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

— Tom Kleckner