Page 1189 – RTO Insider

September 30, 2019

Key Details Change in MISO MEP Cost Allocation Plan

By Amanda Durish Cook

CARMEL, Ind. — Months after FERC rejected an earlier cost allocation plan, MISO is circulating a new draft proposal that would further lower voltage thresholds but raise cost minimums on economically beneficial transmission projects.

Under the new plan, MISO would lower the voltage requirements on market efficiency projects (MEPs) from 345 kV to 100 kV, compared with the 230-kV minimum in the first filing.

However, the cost threshold is set to rise from $5 million to $25 million for regional MEPs.

For interregional MEPs with either SPP or PJM, MISO will also seek a 100-kV voltage threshold but no cost threshold.

MISO MEP — Jesse Moser, MISO | © *RTO Insider*

“Perfection is not achievable, but we want to be as good as we can be,” Jesse Moser, MISO director of economic and policy planning, said during a meeting of the Regional Expansion Criteria and Benefits Working Group (RECBWG) on Thursday.

Moser said the cost requirement increase maintains a “demarcation of larger, regionally beneficial projects.” MISO’s $5 million threshold was approved by FERC in 2007.

The $25 million figure is not final and still open to suggestion, Moser said. He said a regional MEP cost threshold could also be designed to move with inflation. Going forward, MISO intends to review its MEP cost allocation method with stakeholders once every three years, he said.

“It was more about having a way to have some separation between local and regionally economic projects,” Moser said. “There’s not going to be an answer that doesn’t have some controversy and challenges.”

As in the first filing, the new plan would exempt from MISO’s competitive bidding process any MEPs needed within three years to mitigate reliability issues. The filing also preserves the elimination of a 20% postage stamp cost allocation. It additionally still seeks to add new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path.

But the new filing has abandoned a provision that would create a local economic project type.

FERC rejected the first cost allocation filing in June, finding it would have violated the principle of cost causation because projects proposed under the local economic transmission category would be required to demonstrate regional benefits while only being cost-shared on a local level.

The project type was meant for smaller, economically driven transmission projects between 100 and 230 kV, with 100% of costs to be allocated to the local transmission pricing zone containing the line. The projects would not only have to meet a local benefit-to-cost ratio of 1.25-to-1 or greater within their pricing zones but also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs. (See MISO Mulling Next Steps on Cost Allocation Overhaul.)

“While FERC expressed appreciation for many aspects of the proposal, the commission had some concerns about the newly created local economic project category,” MISO CEO John Bear said at the RTO’s July Informational Forum.

Discord

MISO considered several possibilities before settling on the draft proposal, including lowering the voltage threshold to 100 kV for interregional MEPs only or placing projects lower than 230 kV back into the RTO’s existing “other” project category. Stakeholders have offered various opinions on the refiling, with some urging MISO to lower the interregional voltage threshold to 100 kV on both sides of the seam, and others advising that any 100-kV project be eligible for regional cost-sharing.

“This seems simpler than some of the earlier discussions,” Clean Grid Alliance’s Natalie McIntire said of the new version at the RECBWG meeting.

However, other stakeholders contended the MISO community was suffering from “cost allocation fatigue.” Some said it wasn’t clear why the RTO so dramatically altered its original proposal to include 100-kV projects instead of simply removing the lower-voltage project issues FERC raised.

Xcel Energy’s Susan Rossi characterized the proposal as a “drastic change at the last minute.”

But others said that if MISO failed to address the lower-voltage cost-sharing, it would be ignoring LS Power’s pending complaint that asks FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)

McIntire also said some stakeholders were forgetting that the original proposed 230-kV threshold was just the product of a compromise that several stakeholders still disagreed with because they felt it still represented too high a bar.

“I think MISO’s decision to move to 100 kV throws that compromise out the window, and that will be evident to FERC,” Entergy’s Matt Brown contended.

2020 Extension

The new MEP filing will still contain a cost allocation proposal for interregional projects with PJM, even though FERC’s rejection of MISO’s first allocation plan stood to complicate separate deadlines associated with compliance around the longstanding complaint by Northern Indiana Public Service Co. (See “Interregional Filings Also Rejected,” MISO Allocation Plan Fails on Local Project Treatment.)

FERC in mid-September granted an extension that will allow MISO to file its interregional allocation compliance by Jan. 2, 2020, instead of the original late September deadline (EL13-88). MISO was originally due to file its PJM interregional cost-sharing plan by Sept. 23, the date established in FERC orders stemming from NIPSCO’s 2013 complaint over the PJM-MISO seam that ultimately eliminated a cost minimum and lowered the voltage threshold for MISO-PJM interregional projects to 100 kV.

MISO said it needed the extra time for the MEP filing “to ensure proper coordination” with the compliance filing ordered in the NIPSCO complaint. The RTO also said that this is its first extension request since FERC rejected its proposed cost allocation changes to interregional and regional MEPs.

At a Sept. 17 meeting of the MISO board’s System Planning Committee, Director Nancy Lange urged stakeholders to keep working on a cost allocation refiling and remain undeterred by FERC’s rejection of the first proposal.

“I was happy that there was a consensus that could be filed with FERC,” Lange said of MISO’s first filing in late February.

Moser said MISO doesn’t envision using all the extension period granted in the NIPSCO complaint and hopes to make a revised cost allocation filing before Thanksgiving. MISO’s latest proposal is open to stakeholder comment through Oct. 10.

September 30, 2019

PUCO Delays Ruling on AEP Solar Projects

By Christen Smith

The Public Utilities Commission of Ohio last week delayed ruling on the need for two solar projects proposed by American Electric Power after the company asked for a “brief hold” to update its filings to reflect the impact of the recently approved Clean Air Act.

In its request filed Sept. 20, AEP said certain provisions of the new law — also known as House Bill 6 — convey potential benefits to the 300-MW Highland Solar and 100-MW Willowbrook facilities proposed in its long-term forecast report filed last year. The company offered very few details of how the legislation changes its proposal, citing confidentiality agreements, but did ask for a 60-day delay in proceedings.

“The new filing, if successful, would present the commission with additional options and flexibility as compared to the company’s existing proposal filed in these proceedings,” Steven Nourse, AEP’s attorney, wrote in the request. “Moreover, it is the company’s view that the new filing will ameliorate many of the concerns and objections raised by opponents in these proceedings. Such developments should be viewed as helpful regardless of whether the potential opinion and order scheduled for consideration on Wednesday would have initially rendered a positive finding or a negative finding on the need issues.”

The $170 million Clean Air Act, signed into law in July, curtails the state’s current renewable portfolio standards and tacks on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills, mostly for FirstEnergy Solutions’ Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects, including Highland Solar and Willowbrook, in rural areas of the state. (See Ohio Approves Nuke Subsidy.)

AEP submitted documents last year seeking cost recovery under the state’s renewable generation rider (RGR) for 500 MW of wind and the Highland and Willowbrook solar projects.

PUCO said last year that it would first determine the need for the projects before approving cost recovery mechanisms. On Sept. 19, the commission indicated it would announce a decision in the first half of the proceedings at its Thursday meeting; however, the agenda item was subsequently withdrawn. PUCO spokesperson Matt Schilling said the commission gave no reason for the change, telling RTO Insider that “it’s not uncommon to pull cases from the agenda to allow for more time to consider.”

Protesters — including the Ohio Consumers’ Counsel, Direct Energy, IGS and IGS Solar — urged the commission to rule in the case anyway, calling the bill irrelevant to “the statutory issue of whether Ohio utility consumers need electricity from the proposed solar plants.” Kroger and the Ohio Coal Association also opposed AEP’s request.

“HB 6 did not alter Ohio law that strictly limits a utility’s ability to seek PUCO approval of customer-funded subsidies for new generation plants that it proposes to own or operate,” the protesters wrote in a joint filing. “This separate funding for a monopoly utility generation project (including solar) can only be approved by the PUCO if the utility can show, among other things, that utility consumers need the electricity from the proposed power plants. As has been shown in this case, Ohio consumers don’t need electricity from AEP’s proposed plants, as the competitive market provides more than an adequate supply of power.”

The companies further allege that AEP doesn’t need a second revenue stream on top of the money afforded to the projects via HB 6.

“An outcome that could actually ‘ameliorate many of the concerns and objections raised by opponents in these proceedings,’ as AEP asserts, would be for AEP to withdraw its proposal and to develop the contested renewable projects through a separate affiliate,” the companies wrote. “Of course, AEP is free to undertake that endeavor outside this proceeding, without a delay in the PUCO’s decision.”

Scott Blake, an AEP spokesperson, told RTO Insider on Monday that concerns about the company collecting twice on the same projects presuppose the commission would accept the proposals as filed — an unlikely scenario given the impacts of HB 6 and the points raised by protesters within the proceeding.

“The HB 6 credit would also be factored in to any customer charge,” he said. “Under the proposal, we would purchase power at a fixed cost per megawatt-hour from the developer of the project. The credit from HB 6 would be included in the cost and used to calculate the customer portion.”

September 30, 2019

Stakeholder Soapbox: The Risky Case for Gas-fired Plants

By Mark Dyson, Chaz Teplin and Grant Glazer

Last week, RTO Insider published an op-ed from Steve Huntoon that challenged the approach and findings of the latest report from Rocky Mountain Institute (RMI) on “clean energy portfolios” (CEPs), defined as combinations of renewables, storage and demand-side management programs that, together, can provide the same energy and reliability services as a gas-fired power plant.

Our study, using detailed modeling approaches and robust, region-specific data, found that 90% of gas plants currently proposed for construction face significant risk of competition from CEPs, and associated stranded-cost risk within 10 to 15 years.

Gas-fired Plants — Historical and project evolution of CEP costs | *Rocky Mountain Institute*

The RMI team welcomes feedback and respectful discourse from all perspectives as it relates to our work and its implications, but Huntoon’s article misses the mark by misrepresenting our motivation, oversimplifying our approach, and downplaying the significance of key findings relevant to investors and other RTO market stakeholders. In dismissing our study as relying on “pixie dust,” Huntoon ignores evidence of the fundamental transition underway in the electricity industry and reflects a view of industry dynamics from a decade or more ago that is unsuited to today’s landscape.

An Evidence-based Study Focused on Financial Viability and Risks

RMI is an independent research and consulting firm focused on market-based, profit-motivated solutions for clean energy. Having observed the plight of the coal industry and its investors in recent years, we set out in our study to answer a simple question: Is gas-fired generation heading down the same pathway that has led coal plants into financial distress and early retirement?

There is evidence that this is already occurring. The Panda Temple project bankruptcy in 2017 was an early warning signal, and the planned closure of a 10 –year –old gas plant in California announced in June 2019 suggests a growing trend. Nationally, investors are taking notice, with final investment decisions in new gas capacity declining each year since 2014, and capacity factors for a growing share of new combined cycle gas projects already falling significantly below expectations.

With more than $100 billion in planned gas infrastructure investment through 2025, we set out to examine the risks to shareholders and ratepayers if those investments don’t pan out in today’s rapidly changing competitive environment.

A Transparent Approach with Conservative Assumptions

Huntoon’s first claim about our study is that “numbers are lacking: It’s not possible to validate the data and algorithms.” In fact, we clearly cite every source of data that we rely on, all of which are drawn from industry-standard sources (see pages 27-29 and the technical appendix). We also reference the full mathematical formulation of our model published in our initial, 2018 report (pages 29-37 of the appendix).

Huntoon then challenges our inclusion of energy efficiency and demand response in aggressive quantities. In fact, our estimates are consistent with definitive resource potential assessments from the Electric Power Research Institute, FERC and others, as well as recent evidence from leading utilities. To name just a few examples from the past year: Xcel Energy is including more than 800 MW of EE in its integrated resource plan in Minnesota; Portland General Electric is leaning heavily on demand flexibility in its 2019 IRP while building no new gas; and Glendale Water & Power ran a competitive, all-source procurement that resulted in new EE, DR and other customer-sited resources accounting for approximately 20% of new capacity needs.

Huntoon also argues that it is illogical for us to consider EE and DR only as part of CEPs, and not as complements to gas-fired generation. However, our optimization-based modeling approach shows directly how EE and DR are natural complements to zero-marginal-cost generation from wind and solar, with regionally distinct portfolios that leverage resource diversity and load profile characteristics across seasons and hours. More importantly, in making this argument that a combination of EE, DR and a small gas plant might be less costly than either a big gas plant or a CEP, Huntoon actually bolsters the case that EE and DR are a competitive threat to gas investments if planners do not account for them when sizing projects.

Finally, Huntoon takes issue with the possibility that batteries included in CEPs may be charged with “pixie dust” — or more accurately, energy from fossil-fired generation. To be clear: That is a feature of our analysis, not a bug. This assumption that batteries can be charged from the grid during off-peak hours is consistent with the reality of electricity markets, where off-peak capacity is readily available. Our model also carefully subtracts the energy required for battery storage when calculating the CEP’s net monthly energy generation.

A CEP shouldn’t be restricted from leveraging the current system any more than any other grid asset. Similarly, we would not argue that a new gas plant must keep the lights on without help from other, existing generators. Huntoon’s argument is irrelevant as it pertains to our central finding: that CEPs can compete and win on gas plants’ own turf.

Risks and Uncertainty in an Investment Case for New Gas Capacity

In short, the challenges made by Huntoon against our work are inaccurate, irrelevant or both. Our study finds clear evidence that the majority of proposed gas generation projects are uneconomic to begin with and, if built anyway, will likely lose money well ahead of their expected economic lifetimes. Far from relying on “pixie dust,” our analysis reflects the current state of the market and the inevitable outcomes of further innovation and cost declines in renewables and storage. Perhaps the “pixie dust” that Huntoon refers to is, instead, required to believe forecasts of new gas plant profitability even in light of current market trends and their clear implications.

September 29, 2019November 13, 2023

ERCOT Technical Advisory Comm. Briefs: Sept. 25, 2019

AUSTIN, Texas — ERCOT stakeholders approved the creation of a battery energy storage task force as the grid operator steps up its efforts to accommodate the resource type.

Staff told the Technical Advisory Committee on Wednesday that ERCOT is “shifting gears” and dedicating full-time resources to integrate energy storage in its systems. Staff conducted an energy-storage workshop in April but have done little publicly since.

“We need a more focused and centralized discussion,” said ERCOT’s Sandip Sharma, who will chair the Battery Energy Storage Task Force (BESTF). “Creating a formal task force structure would allow us to better share information with stakeholders.”

The task force will hold its first meeting on Oct. 18, when it will finalize a scope document and elect a stakeholder as vice chair. The group will report to the TAC, which will be asked to endorse any recommendations it makes.

Congestion in Permian Basin an Issue

Transmission congestion will remain an issue in the Permian Basin through 2020, staff told members, requiring ERCOT to request relief from the state’s environmental regulator for increased generation emissions.

The Texas Commission on Environmental Quality obliged, granting “enforcement discretion” through 2019 for resources needed to resolve congestion in West Texas. A market notice detailing the action was distributed following the TAC meeting.

The commission said it would exercise its discretion in evaluating Luminant’s Permian resources’ compliance with air-permit limits “when they are needed to address certain ERCOT-declared transmission emergencies.”

Luminant will only be subject to enforcement discretion when ERCOT declares a transmission emergency and commits one or more of its Permian units through a reliability unit commitment. The units are approaching their 2019 emissions limitations but are the only resources with shift factors sufficient enough to help security-constrained economic dispatch resolve the constraints.

ERCOT told the commission that the basin’s substantial growth in petroleum-related load has resulted in “occasional limit exceedances” on the region’s import paths. Transmission additions to relieve the congestion will not be completed until late 2020 and early 2021, staff said.

Staff Issue Guidance on D-side Resources

Staff also previewed a market notice describing “intended practices” to interconnect and operate distribution generation resources (DGRs) that participate in ancillary services or economic dispatch.

DGRs present “certain operational concerns” not yet addressed in ERCOT’s rules, the grid operator said. It said it is concerned that the increasing numbers of DGR interconnection proposals “could create reliability risks if sufficient numbers of DGRs begin to interconnect.”

ERCOT said it is developing rule revisions to resolve the issues and expects to submit the revision requests “in the near future.” Until the rules are implemented, it said, DGRs should either operate under restrictions or be prohibited from interconnection.

“The most prudent policy at this point is to allow existing DGRs to continue operating and to allow those entities that can demonstrate substantial investment in one or more DGRs to pursue development of those DGRs, but only on the condition that each such existing or proposed DGR complies with certain specified conditions regarding interconnection and operation,” ERCOT said.

Members Approve 23 Revision Requests

The committee cleared a two-month backlog of revision requests after rejecting a motion to table a system change request (SCR) to give transmission operators access to ERCOT’s GridGeo application. The browser-based tool will provide better situational awareness of the transmission grid and is meant to replace the grid operator’s Macomber Map. (See ERCOT, SPP Collaborate to Improve Visualization Tool.)

Lower Colorado River Authority’s Emily Jolly asked that SCR804 be tabled to give stakeholders time to see whether the app could be scaled up for the greater market’s use. “Real-time weather information, seeing what ERCOT does … that could really be helpful,” she said.

ERCOT Senior Director of System Operations Dan Woodfin said GridGeo contains integrated generation data. To open it up to market participants beyond transmission operators would require different software, he said, and increase its estimated $400,000 to $600,000 cost.

“I’m not sure it warrants holding up what the transmission operators need,” Woodfin said.

The motion to table failed by a 9-13 vote, with eight members abstaining. The SCR passed by a voice vote, with LCRA abstaining.

The TAC unanimously endorsed 15 Nodal Protocol revision requests (NPRRs), two changes to the Nodal Operating Guide (NOGRR), single revisions to the Planning Guide (PGRR) and Retail Market Guide (RMGRR), a system-change request, a change to the Settlement Metering Operating Guide (SMOGRR) and two Verifiable Cost Manual updates (VCMRR):

- NPRR918: Clarifies and updates hourly validation rules for the non-opt-in entity load forecast related to the submission of point-to-point obligations.
- NPRR930: Requires staff to use an outage-adjustment evaluation process to delay accepted or approved outages after issuing an advance action notice, providing time for qualified scheduling entities to adjust their outage plans. The NPRR sets an offer floor of $4,500/MWh for resources in making them whole for following ERCOT’s instructions.
- NPRR936: Changes the congestion revenue rights (CRR) auction’s transaction limit to the counter-party level from that of the CRR account holder.
- NPRR939: Replaces ERCOT’s practice of creating two groups of load resources, other than controllable resources providing responsive reserve service (RRS), into groups of 500 MW each to provide up to 60% of the system’s RRS requirement and up to 150% of their RRS ancillary service responsibility toward physical responsive capability (PRC). The change allows ERCOT to maintain at least 500 MW of PRC from generation resources when releasing RRS capacity to SCED.
- NPRR940: Removes from the protocols NPRR664’s gray-boxed language that introduces a fuel index price for resources.
- NPRR948: Incorporates changes in the American National Standards Institute standards; increases the test schedule for coupling capacity voltage transformers (CCVTs) tested in the last quarter of a year and removes references to fiber-optic current transformers.
- NPRR950: Prohibits any switchable generation resource contracted to provide black start service from generating in any control area other than ERCOT’s.
- NPRR951: Expands the network security analysis active constraints report and the network security analysis inactive constraints report to include megavolt-ampere flows and limits.
- NPRR952: Fully replaces the Houston Ship Channel with Katy Hub as the reference for the natural gas fuel index price in ERCOT’s systems.
- NPRR954: Allows transmission and distribution service providers or load-serving entities to opt out of Texas standard electronic transaction 867 data for electric service identifiers with ERCOT-polled settlement meters.
- NPRR958: Modifies the wind and solar capacity calculations used in ERCOT’s Capacity, Demand and Reserves (CDR) report and better aligns the two calculations.
- NPRR959: Splits the CDR’s existing non-coastal wind region into a Panhandle region and an “other” region.
- NPRR960: Revises NPRR863’s gray-boxed language to implement the Board of Directors-approved phasing approach for the NPRR. Also corrects resource status references within the gray-boxed language.
- NPRR961: Aligns the protocols with changes proposed in NOGRR194.
- NPRR962: Requires ERCOT to publish hourly the approved DC tie schedule for the following seven days.
- NOGRR191: Paired with NPRR939, allows ERCOT to manually deploy load resources providing RRS to maintain at least 500 MW of physical responsive capability reserves while maintaining stable grid frequency for smaller disturbances.
- NOGRR194: Clarifies and relocates to the Nodal Operating Guide black start training attendance requirements, originally located in the Nodal Protocols.
- PGRR072: Allows staff to collaborate with stakeholders in setting a resource not yet subject to a notification of suspension of operations to “out of service” in the regional transmission plan and geomagnetic disturbance vulnerability assessment base cases, provided the resource’s entity notifies ERCOT of its intent to retire or mothball the resource or makes its intent public.
- RMGRR161: Aligns the guide’s language with state regulations for providers of last resort by specifying market notices’ required contents in notifying market participants of a mass transition.
- SCR803: Adds to the wind-integration report a new graphical dashboard showing actual and forecasted solar production and creates new solar-integration reports.
- SMOGRR022: Removes from the guide references to fiber-optic instrument transformers.
- VCMRR023: Aligns the manual’s language with NPRR940’s removal of gray-boxed language.
- VCMRR024: Clarifies that auxiliary equipment using power from third-party service providers is recoverable as a variable cost, rendering moot the requirement to include start-up and minimum energy fuel consumption.

— Tom Kleckner

September 29, 2019

FCA 13 Results Stand Without FERC Quorum

By Rich Heidorn Jr.

The results of ISO-NE’s Forward Capacity Auction 13 became effective “by operation of law” Sept. 24 because FERC was unable to muster a quorum following the departure of Commissioner Cheryl LaFleur and the recusal of Commissioner Richard Glick.

The commission issued a notice on the action Sept. 25 (ER19-1166), and Chairman Neil Chatterjee and Commissioner Bernard McNamee issued a joint statement Friday saying that they would have voted to accept the results despite multiple protests.

The auction for June 2022 through May 2023 produced a clearing price of $3.80/kW-month, well below FCA 12’s $4.63/kW-month and the RTO’s lowest price in six years. It was the first auction run under the Competitive Auctions with Sponsored Policy Resources (CASPR) rules, which established a secondary substitution auction in which new generation resources could assume the obligations of resources that retire in the same commitment period. The substitution auction had a $0 clearing price, and no demand bids below that price cleared. (See ISO-NE Completes FCA 13 Despite Controversy.)

ISO-NE filed the results on Feb. 28. The results became effective when the commission failed to act within the 60-day deadline for filings under Federal Power Act Section 205. FERC said the clock began on July 26, when ISO-NE responded to the second of two FERC deficiency notices.

Closing at a preliminary clearing price of $3.80/kW-month, FCA 13 continues the trend of declining prices shown in the previous three auctions. | *ISO-NE*

Glick, a former lobbyist for Avangrid, said he recused himself because the Vineyard Wind offshore project, a joint venture between Copenhagen Infrastructure Partners and Avangrid Renewables, filed a protest in the docket. (See Glick Recusal May Mean No MOPR Ruling Before December.)

LaFleur, who began abstaining from ISO-NE orders before leaving the commission at the end of August, joined the RTO’s Board of Directors on Sept. 13. (See LaFleur Elected to ISO-NE Board.)

Chatterjee and McNamee said they would have upheld the auction results as just and reasonable, dismissing multiple protests as outside the scope of the proceeding or collateral attacks on past commission orders. They rejected arguments by Calpine, which said market design defects suppressed prices, and Public Citizen, which said consumers were overcharged in the substitution auction because only 10% of the supply offers cleared.

Waiver Request

Chatterjee and McNamee said they also would have voted to grant ISO-NE’s request for a waiver from a rule requiring it to grant access to confidential information to parties that sign nondisclosure agreements. The RTO made the request so it wouldn’t have to disclose resource-specific cost data submitted by the Killingly Energy Center, a 650-MW natural gas-fired generator slated to begin operations in Connecticut in 2022.

The commissioners acknowledged that FERC has “recognized both that parties have an interest in protecting the confidentiality of their data and that they must be permitted to participate meaningfully in proceedings.” They said they had sought to allow both by requiring NDAs to access the confidential material. “But the commission has also recognized that it is inappropriate to disclose confidential material that can create adverse impacts to competition, even under a nondisclosure agreement,” they wrote. “Specifically, in the FCA 8 order and 2017 waiver order, the commission ruled that release of resource-specific privileged information was inappropriate because that information would remain sensitive beyond the FCAs in question and could harm the competitiveness of FCAs going forward.”

Chatterjee and McNamee also said they would have rejected the argument of a group of capacity suppliers (Cogentrix Energy Power Management, Great River Hydro, NRG Power Marketing and Vistra Energy) who challenged the ISO-NE Internal Market Monitor’s unit-specific offer floor price for Killingly. They said it must have been at or below $3.79/kW-month — less than half the $8.19/kW-month default offer floor applicable to Killingly.

“We would have found that Killingly was appropriately mitigated,” the commissioners wrote. “Based on an evaluation of the data submitted in the deficiency response in this docket, we believe that the IMM complied with its responsibilities as outlined in the Tariff. For example, we would have found that through its deficiency response, ISO-NE demonstrated that its review was not focused solely on whether Killingly received out-of-market revenues but rather that the IMM scrutinized all aspects of Killingly’s offer to ensure they were consistent with prevailing market conditions, including all relevant cost components and revenue assumptions that support Killingly’s offer.”

Vineyard Wind MOPR

Also rejected were arguments by Vineyard Wind, Massachusetts Attorney General Maura Healey, Public Citizen and “Clean Energy Advocates” — Acadia Center, Conservation Law Foundation and the Sierra Club — that the auction resulted in unjust and unreasonable rates because Vineyard Wind was not exempted from the minimum offer price rule (MOPR) as a renewable technology resource (RTR).

The deadline to qualify as an RTR was Oct. 2, 2018. It wasn’t until Jan. 29, 2019 — six days before the auction was conducted — that the commission accepted revisions to the Tariff allowing offshore wind resources to qualify as RTRs.

The commission never acted on Vineyard Wind’s request for a Tariff waiver to participate in FCA 13. The request remains pending.

Clean Energy Advocates and Public Citizen complained that Vineyard Wind’s exclusion as an RTR showed the substitution auction failed to accommodate state policies and will be an inadequate substitute once the RTR exemption is phased out.

“With respect to the substitution auction, the commission previously found that the substitution auction construct and gradual phase-out of the renewable technology resource exemption struck a just and reasonable balance between the competing objectives of maintaining competitive capacity market prices and accommodating state policy interests,” Chatterjee and McNamee wrote. “The commission added that the substitution auction is not rendered unjust and unreasonable simply because it does not guarantee that state-sponsored resources will obtain capacity supply obligations.”

September 29, 2019

FERC’s Glick Navigates Political Dynamic

By Tom Kleckner

HOUSTON — The FERC that Richard Glick joined as a commissioner in November 2017 was nothing like the “sleepy agency” he came to know during his many years as a D.C. insider.

“For the most part, it’s been a nonpartisan agency. The vast majority of orders have gone out on non-party-line votes,” Glick said in keynoting the 18th Annual Gas and Power Institute last week near the heart of the nation’s energy industry.

“That’s starting to change, for a variety of reasons,” he said. “With technology changes, these issues are becoming much more contentious. The more traditional technologies are clearly fighting to protect their turf, and the newer technologies are fighting to get a part of that. That’s posed some issues for us.”

But the greater issue is the political divide, said Glick, the lone Democrat among the three men sitting on the commission.

“Some of atmosphere at FERC is a little more tense than it has been, in large part because of what’s going on in Washington, D.C., in general,” he said. “It’s a different atmosphere than before, and FERC is reflective of that.”

FERC Commissioner Richard Glick | © *RTO Insider*

Glick said he has dissented a “lot more” than he thought he would have when he joined FERC. Most recently, he argued that the commission’s recent move to adopt proposed revisions to how it administers the Public Utility Regulatory Policies Act of 1978 would essentially “gut” a law that has spurred renewable energy growth. (See FERC to Reshape PURPA Rules.)

Glick has often been the only commissioner taking a stand against approving gas pipelines and LNG projects. He has repeatedly expressed concerns about the lack of greenhouse gas considerations in commission rulings and now has begun charges that FERC is “scrubbing” references to climate change from its orders. He noted that boilerplate language encouraging developers to take GHG emissions into consideration has been removed from recent orders.

“All of a sudden, that’s been taken out of the orders,” he said. “The commission is choosing to stick its head in the sand and not consider greenhouse gas emissions, and that’s problematic.”

“Glick is the lone voice in the wilderness,” Tom Hirsch, a D.C.-based lawyer with Norton Rose Fulbright, told attendees.

“My beef with the majority, and what FERC has been doing for a number of years, is relying on precedent agreement, and not even arguing it,” Glick said. “We’ve been called a ‘rubber stamp’ for the pipelines. That’s not always true … but I don’t think we’ve done our job [in determining a project’s need] as we should.”

Compounding Glick’s frustration is the turmoil surrounding FERC itself. The commission, which struggled to reach a quorum in 2017 following the change in administrations, is now back to three members following Cheryl LaFleur’s departure in August. (See FERC Heaps Praise on Departing LaFleur.)

Normally, the administration would nominate a candidate from each party to fill the two vacant seats, maintaining a 3-2 split favoring the party holding the White House. “That’s been the tradition,” Glick said.

However, the talk in D.C. is that FERC General Counsel James Danly will be nominated for the Republican position and the Democratic seat would be left open. Asked if he was familiar with the rumor, Glick said, “I hear the same things you do. I will guarantee you the White House did not call me up and ask my opinion.

“Even if you change one commissioner for another, it takes a while to get used to each other’s rhythms,” Glick said. “There’s a lack of stability. I’m very hopeful that we will get another commissioner [soon].”

FERC Chairman Neil Chatterjee declined to comment on Danly during an earlier September visit to Houston.

Compounding matters is a recent determination by FERC’s designated agency ethics official (DAEO) that Glick should continue to recuse himself from proceedings related to his former employer Iberdrola USA (now Avangrid), again making quorum an issue, particularly in a key proceeding related to PJM’s capacity market. (See Glick Recusal May Mean No MOPR Ruling Before December.) Glick said he initially understood the two-year recusal would have expired two years after he left Avangrid in February 2016. In reality, he was later told, the clock started ticking when his term began in November 2017.

“I think he made an honest mistake,” Glick said of the DAEO’s first ruling.

The same ethics office has advised Commissioner Bernard McNamee that he doesn’t have to recuse himself from the commission’s grid resilience proceeding, unless it “closely resembles” the debate over the coal and nuclear subsidies he helped write at the Department of Energy.

Still, Glick soldiers on. While appearing reserved at first glance, he seems comfortable speaking out while manifesting a wry sense of humor.

When he mentioned he disagreed with a fellow commissioner, a reporter tried to pry Glick into naming names. “I think I disagree with both of my colleagues. I like them, but we disagree on policy.”

ERCOT Monitor: August ‘High Excitement’ for RT ‘Geeks’

Also speaking at the conference, Potomac Economics’ Beth Garza, executive director of ERCOT’s Independent Market Monitor, described the Texas grid operator’s ability to meet customer demand during scarcity conditions this August as “high excitement for those of us who are real-time energy market geeks.”

ERCOT called its first energy emergency alerts (EEAs) in five years this summer and relied on emergency response service and DC tie imports to meet record-breaking demand. However, the two EEAs weren’t called on days when load reached record levels, but during days when West Texas winds died down before the late afternoon peak. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)

“In ERCOT, high loads used to be driven by high temperatures, but it’s no longer that,” Garza said. “Now, it’s, ‘Is it going to be hot? Is it going to be still? Now, the third piece is, ‘Is it going to be cloudy?’ Those are the drivers for pricing and price outcomes.”

Prices briefly hit $9,000/MWh during both EEAs. “Prices should be reflective of the conditions you are in,” Garza said. “If you are in scarce conditions where you may have to curtail load, the price should be high.”

Geek that she may be, Garza noted that ERCOT’s real-time energy prices averaged $50.70/MWh through August, a 40% increase year-to-date over 2018 ($36.20/MWh). This despite a 15% decrease in natural gas prices so far in 2019.

But, Garza asked, is that enough for people to “plunk their money down and build a power plant” to take advantage of scarcity prices? She would only point to the 2020 summer’s forward on-peak prices, which spiked to more than $400/MWh in August but have since dropped to $250/MWh, and let her audience decide.

Glick offered his own positive outlook on the ERCOT market.

“Texas has a very unique market,” he said. “It’s an energy-only market, yeah, and prices spike during certain hours in the summer, but contrary to predictions, the lights didn’t go out.”

Questions over Capacity, Traditional Markets

Glick also shared his insight on capacity markets, which he said are one of the biggest policy issues before FERC. He suggested participants are losing faith in the markets as they attempt to integrate renewable generation.

“Capacity markets procure a lot of reserves that aren’t needed, and that costs a lot of money,” he said. “Generators are asking us to intervene. … To me, we’re spending a lot of time arguing about whether we need to subsidize nuclear or coal. To me, that’s an argument from a long time ago. What we need, with intermittent resources, is a lot of flexibility on the gird. We should incentivize and reward flexibility.”

Tim Wang, a director with Filsinger Energy Partners, questioned whether energy markets will even remain viable in the future.

“Energy markets are based on 1990s technology and fuel costs. That is all changing,” he said.

Wang said energy storage costs are dropping as dramatically as wind and solar costs, further reducing marginal costs.

“In the future, with 100% renewable energy markets, the marginal costs could be zero. There are no coal or gas heat rates. All that is gone … so what does the future look like? Will the markets still be there?”

September 29, 2019

NYISO Management Committee Briefs: Sept. 25, 2019

The New York Control Area summer peak load of 30,397 MW on July 20 fell below the 50/50 projection for the sixth consecutive summer, Operations Vice President Wes Yeomans told the Management Committee on Wednesday.

The summer 2019 50/50 forecast was 32,382 MW, while actual peak load last summer was 31,861 MW.

“Things were relatively easy for the NYISO this summer, operationally speaking, with two heat waves, on July 18-21 and July 29-30,” Yeomans said. He noted there were four days with peak loads over 30,000 MW.

“We did go into this summer knowing this was the last summer we’d have six nuclear plants,” he said, referring to next spring’s phased shutdown of the first of the two reactors at Indian Point, with the second unit to be decommissioned in 2021.

Yeomans noted that NYISO termed the July 29-30 period as “hot weather operations” on his slides, as the heat has to last three days to be classified a heat wave.

NYISO recorded the all-time peak for a Sunday on July 21 at 30,339 MW and met reliability criteria with surplus operating margins, with no emergency activations and no need for statewide supplemental capacity commitments, he said.

“Prior to July 18, transmission owners rescheduled a lot of their transmission work in anticipation of the heat wave,” Yeomans said. “And it was hot, with heat indexes as high as 110 degrees [Fahrenheit] over the weekend [July 18-21].”

Daily mean temperatures were above the 20-year average in July, near average in June and August, and below average in May, with Albany posting 12 days with highs above 90 F.

Staff Transitions

CEO Rich Dewey mentioned a couple of “public service announcements,” saying the NYISO Board of Directors’ search is underway to fill the upcoming vacancy of Robert Hiney, who is set to leave in April 2020.

The board also approved the appointment of Robb Pike as vice president of market operations, Dewey said. Pike worked for NYISO’s legacy organization, the New York Power Pool, and moved to the ISO at its inception in 1999.

Parallel Testing of EMS/BMS

NYISO hopes to go live with a new energy management system (EMS) and business management system (BMS) at the end of October and is operating a parallel testing phase through Oct. 7.

“That application is receiving all the telemetry that our legacy system is receiving and is doing everything but sending dispatch signals,” Chief Information Officer Doug Chapman said.

The testing is an important phase, with EMS/BMS “running pretty well” except for a few issues that need to be resolved with vendor ABB before going live in October, he said.

If NYISO decides to proceed with the new EMS/BMS, it will move into parallel operations for two weeks in mid-October, double-staffing the control room, Chapman said.

The cutover date is currently targeted for Oct. 22. NYISO’s last opportunity to switch to EMS/BMS in 2019 will be Oct. 31, which is the latest NYISO can cut over to the new system and still issue a necessary System and Organization Controls report to stakeholders by the deadline of Jan. 15, 2020.

“If we miss, the next opportunity to go live is March 1, and that delay has cascading impacts to our 2020 plans,” Chapman said.

The ISO also is replacing the tool used to model the electric system, he said.

Draft 2020 Budget

Alan Ackerman, of Customized Energy Solutions and chair of the Budget and Priorities Working Group, delivered budget highlights.

NYISO’s draft 2020 budget totals $168 million allocated across a forecast of 154.3 million MWh, for a Rate Schedule 1 charge of $1.089/MWh. Comparatively, the 2019 budget was $168.2 million allocated across 157.1 million MWh for a Rate Schedule 1 charge of $1.071/MWh.

The draft budget would represent a 0.12% decrease in revenue requirement from 2019 and a 1.78% decrease in projected megawatt-hours, for an overall Rate Schedule 1 increase of 1.66%.

Cost avoidance is the main strategy behind keeping the ISO’s budget flat for the fourth year in a row, according to the presentation, with salaries and benefits increasing $500,000 from this year, but employee health insurance plan changes effective for the 2020 plan year projected to avoid additional ISO cost increases of $400,000.

The board will review the draft budget in October ahead of an MC vote on it at the end of the month. The budget will then go to the board for approval at its Nov. 19 meeting.

— Michael Kuser

September 29, 2019April 16, 2025

Bonneville Power Signs Agreement with CAISO EIM

By Hudson Sangree

The Bonneville Power Administration signed an implementation agreement with CAISO’s Western Energy Imbalance Market on Thursday, positioning a vast region of the Pacific Northwest, with its powerful hydroelectric dams and thousands of miles of transmission lines, to begin participating in the ISO’s real-time market in 2022.

“We see BPA’s participation in the Western EIM as the natural next step in a collaborative partnership that began many years ago to optimize transmission connections and boost reliability throughout the West,” CAISO CEO Steve Berberich said in a statement. “BPA will provide exceptional benefits to the real-time energy market, as it leverages its robust and regionally strategic transmission system and energy resources.”

BPA would be the largest transmission owner and hydroelectric provider in the EIM. The federal power marketing administration owns and operates three-quarters of the high-voltage transmission lines in the Pacific Northwest, totaling about 15,000 circuit-miles. Its footprint occupies an area larger than the size of France, encompassing the sprawling drainage areas of the Columbia and Snake rivers.

The agency’s assets include 31 hydroelectric projects, such as the 7,079-MW Grand Coulee Dam and the 2,614-MW Chief Joseph Dam. It supplies electricity to 143 electric utilities that serve millions of customers in Washington, Oregon, Idaho, Montana, California, Nevada, Utah and Wyoming.

The Bonneville Power Administration’s service area stretches across a vast area of the Pacific Northwest. | BPA

The move also boosts CAISO’s EIM in competition with WAPA, Basin, Tri-State Sign up with SPP EIS.)

While the implementation agreement is nonbinding, it commits BPA to paying a $1.8 million nonrefundable implementation fee, the first payment of up to $35 million in estimated start-up costs. BPA will not issue its final record of decision on becoming a member until late 2021, just months before it plans to join in March 2022. (See BPA Marches Toward EIM Membership.)

“This milestone was made possible by the collaboration and broad participation of our customers and constituents in the Northwest,” BPA Administrator Elliot Mainzer said in a statement. “We’ve also benefited from a strong partnership with the CAISO that allowed us to carefully explore the value of the EIM for BPA and its customers, while addressing issues important to the region.”

BPA said the EIM will allow it to more efficiently market its hydropower and manage transmission usage and congestion. The agency has touted the ability to use the EIM as a “non-wires” solution to address congestion and avoid new transmission builds while helping to identify areas of needed investment.

“Selling surplus energy and capacity in the Western markets is essential to keeping Bonneville’s rates low,” the agency said on its website. “BPA must adapt its business model as these markets change. Our analysis shows that joining the Western Energy Imbalance Market is one potential method to achieve this outcome.”

In June, BPA kicked off a monthlong public comment process in hopes of signing an implementation agreement with the EIM in September. During a July meeting at BPA headquarters, BPA “preference” customers concerned about their inability to trade in the EIM’s intra-hour market probed agency officials about short-term opportunities to purchase surplus hydropower before it’s offered into the EIM. (See Customers Probe BPA on EIM Impact.) While those concerns remain unresolved, no BPA customers apparently opposed joining the EIM.

“We got 100% support for signing that agreement,” Mainzer said at the Northwest & Intermountain Power Producers Coalition annual meeting in Union, Wash., on Sept. 9.

CAISO is evaluating adding an extended day-ahead market (EDAM) to the real-time EIM to increase its usefulness as a regional marketplace, and the BPA administrator said he believed the EDAM is needed to help move BPA’s hydropower and other renewable resources across the West.

“It’s not going be enough to sell all this stuff on a five-minute market,” Mainzer said.

CAISO says its five-minute market has saved participants more than $736 million in the five years since it started.

The Balancing Area of Northern California (BANC) and the Western Area Power Administration recently said they will sign an implementation agreement with CAISO that would allow WAPA’s Sierra Nevada region and BANC members Modesto Irrigation District, Redding Electric Utility and Roseville Electric Utility to begin trading in the EIM in April 2021. The decision does not affect any other WAPA regions.

WAPA SN would be the first PMA to participate, potentially followed by BPA. The agreement represents the second phase of BANC’s approach to incorporating its members into the EIM. Sacramento Municipal Utility District entered the market in April. (See SMUD Goes Live in Western EIM.)

Other current Western EIM participants include CAISO, PacifiCorp, NV Energy, Arizona Public Service, Puget Sound Energy, Portland General Electric, Idaho Power, Powerex and BANC (Phase 1). The Western EIM is slated to expand with the participation of Salt River Project and Seattle City Light in 2020; Los Angeles Department of Water and Power, NorthWestern Energy, Turlock Irrigation District, Public Service Company of New Mexico and BANC (Phase 2) in 2021; and Tucson Electric Power, Avista and Tacoma Power in 2022.

September 29, 2019

RTOs Gather to Discuss Real-time Co-optimization

By Tom Kleckner

AUSTIN, Texas — Normally, Texas’ electricity industry points to ERCOT’s energy-only — and deregulated — market as a model for the rest of the country to follow.

Last week, however, ERCOT staffers and stakeholders gathered to hear advice from the RTOs that have already implemented real-time co-optimization (RTC) in their markets. MISO, PJM and SPP staff gave high-level overviews of their forward markets and lessons learned from their experience with the practice.

The Texas grid operator is just months into a multiyear effort to improve its market by adding RTC, a market tool that procures both energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements.

Gary Cate, SPP’s manager of market design, told members of the Real-Time Co-optimization Task Force gathered at ERCOT’s headquarters that his RTO’s implementation of RTC was “clean once we went there” with its integrated marketplace in 2014.

“[Our] real-time market doesn’t have performance issues,” Cate said, rapping the podium in front of him. “The day-ahead market did have commitment issues initially, with reg[ulation] up and reg down as separate products … but we didn’t have a lot of issues from a co-optimization perspective. We did co-optimization after multiple RTOs did it, so we kind of learned from their missteps.”

MISO added RTC to its market in 2009 at a cost of $75 million. Jeff Bladen, MISO’s executive director of digital strategy, said the tool provides an annual return of at least $60 million through a more efficient commitment and dispatch of energy and reserves.

“Our fundamental belief is co-optimization for all our products is necessary to be as efficient as our customers expect us to be. The market is now compensating for availability and flexibility, not just energy,” Bladen said. He noted the RTO plans to file a request with FERC to offer a short-term, 30-minute spinning reserve product.

MISO suggested ERCOT pay attention to ramp sharing, where energy and reserves share the same ramp capability. Bladen said the RTO observed frequent price spikes during parallel operations, which increased reliability risks because insufficient reserves were cleared. With ramp sharing, he said, reserve requirements are scaled up to account for the sharing.

ERCOT’s Matt Mereness, who chairs the RTCTF, said he found the information beneficial for the team’s current principle design phase, including the need to focus on “market education and technical details.”

MISO, PJM and SPP operate capacity markets, designed to ensure reliability by requiring suppliers to have enough resources to meet customer demand and a reserve amount. ERCOT’s energy-only market pays generators only when they provide power day-to-day, relying on scarcity pricing to incent additional generation.

‘Grappling’ with RTC

Reliant Energy’s Bill Barnes said RTC will work well in ERCOT’s market, pointing to the construction of demand curves as being the important difference.

“The energy-only market relies on the ASDC [ancillary services demand curve] to set scarcity prices to drive operational and investment decisions,” he told RTO Insider. “The must-offer requirement in the other markets is due to resource adequacy requirements that don’t exist in ERCOT.”

Resmi Surendran, senior director of regulatory policy for Shell Energy, agreed with Barnes. She said the AS demand curve’s design and the restrictions placed on AS offers could significantly affect the reserve margins the market can sustain.

Capacity markets expect must-offers from resources with capacity obligations, “which seems reasonable as they are paid to be available,” she said. She pointed out SPP and MISO were “very explicit” during their discussion that AS must-offers and near-zero offers for the services shouldn’t be expected if the RTO values the AS product.

“They don’t require resources that don’t have capacity obligations to offer into the AS market, and their offer caps for these AS products are high,” Surendran said. “AS markets are not a key revenue stream for the generators in those markets. In ERCOT, that is not the case. … How we design it could have an impact on the new type and amount of investments the market will attract.”

Shams Siddiqi, Crescent Power | © *RTO Insider*

Shams Siddiqi, who has been involved in much of ERCOT’s market design and is now president of consulting firm Crescent Power, has freely offered his expertise to the RTC task force. He said the tool will be more efficient in ERCOT’s nodal market, where all AS-capable resources are required to offer or let the system create proxy offers.

ERCOT’s must-offer requirement and reduced risk to selling AS under co-optimization will likely reduce AS prices, he said.

“Even if [ERCOT’s] proxy AS offers are set to [$0], when the resource does not submit an offer [under RTC], it’s unlikely that AS clearing prices will be $0, as AS clearing prices always take into account opportunity cost,” Siddiqi said. “Unlike what’s being proposed by ERCOT, other ISOs substitute higher-value AS capacity for lower-value AS capacity and maintain the substituted AS capacity as the higher-value service. This … results in higher level of reliability, making the ASDC continuous so that additional higher-value products always have value greater than or equal to lower-value AS service, and ensures higher or equal clearing price for higher-value AS compared to lower-value AS.”

Barnes said stakeholders are “grappling” with how to set AS proxy offers for RTC. “The pricing of AS in other markets with RTC helps inform our decision,” he said.

TAC Endorses 2 More Key Principles

The RTCTF also received endorsement last week of two additional key principles (KPs) from ERCOT’s Technical Advisory Committee. (See related story, ERCOT Technical Advisory Committee Briefs: Sept. 25, 2019.)

The latest KPs are:

KP 1.1: Replaces the operating reserve demand curve’s adders with ASDCs to determine market-clearing capacity prices for AS products, while continuing to adjust for ERCOT’s defined out-of-market actions to maintain reliability.
KP 1.2: Evaluates the values of and interaction between the systemwide offer cap, value of lost load and power balance penalty price as part of RTC’s implementation. The principle also sets parameters for the values.

The KPs will be sent to the ERCOT Board of Directors, which will now “consider,” rather than “approve,” the principles as a result of a tweak to the group’s scope. Following the KPs’ consideration, staff will draft and sponsor the necessary revision requests, according to the protocols.

The task force plans to consider 19 more KPs during its Oct. 9 meeting.

The TAC also reaffirmed Bryan Sams as the task force’s vice chair. Sams recently left Lone Star Transmission for a position with Calpine as director of government and regulatory affairs.

September 29, 2019

More MISO Members Join Call for Tx Planning Change

By Amanda Durish Cook

CARMEL, Ind. — A growing number of stakeholders are prodding MISO to create a task team to improve transmission planning assumptions and devise ways to prevent new generation projects from becoming responsible for most transmission development.

Multiple stakeholders at a Planning Advisory Committee meeting Wednesday said MISO’s lagging renewable forecasts and increasingly pricey network upgrades for queue projects merit examination by a new task team.

Clean Grid Alliance’s Natalie McIntire said MISO’s 15-year futures — even the accelerated fleet change scenario — project smaller renewable growth than indicated by projects that have already signed interconnection agreements in the queue. Projects set to come online in the next few years eclipse all futures expectations, she said.

Representatives from the Organization of MISO States and CGA appeared before the RTO’s Board of Directors in mid-September to warn about the increasing trend of otherwise economically viable renewable projects exiting the queue because of prohibitively expensive network upgrades. (See MISO Readies MTEP 19, Debates Futures Change.)

MISO has promised to evaluate special, targeted economic planning studies in its 2020 Transmission Expansion Plan (MTEP 20), while postponing a futures overhaul until the 2021 cycle. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.) During the PAC meeting, MISO project manager Sandy Boegeman asked stakeholders for suggestions on the targeted studies.

Several members have said the RTO cannot afford to wait another year before recasting its future scenarios. MISO will essentially snub transmission projects designed to help facilitate the renewables growth indicated by the interconnection queue, creating a self-fulfilling prophecy, they say.

The accelerated fleet change future should now be considered MISO’s base case future scenario, while the three other futures are “not at all representative of what we might expect,” McIntire said Wednesday. She called for a “better alignment” between planning assumptions and queued generation projects.

McIntire said the Helena-to-Hampton Corners second circuit project should be included in MTEP 19 as a market efficiency project, a contention her organization already put before the board. (See MISO Readies MTEP 19, Debates Futures Change.) The $36.1 million, 345-kV project, originally identified in this year’s Market Congestion Planning Study, was set to solve congestion in southern Minnesota at a 4.22:1 benefit-to-cost ratio, but MISO said the project quickly lost value once forecasted wind generation was removed from the equation.

McIntire said there was “not a very robust stakeholder process” around testing of the project, which should have been subject to more vetting and a PAC review.

She also said network upgrades borne by new generators in the queue “provide benefits well beyond simply interconnecting generators.” She pointed out that the February 2017 definitive planning phase studies showed that the batch of projects needed more than $1.3 billion in upgrades, an average of $1.5 million per megawatt of new generation.

“It is not efficient or cost-effective for MISO to plan the system one interconnection queue at a time,” said McIntire, who issued the first call for a task team to examine network upgrades and transmission planning. She said MISO should also consider creating a new transmission project category that allows for cost sharing between generators and load.

At a special workshop on MTEP futures Thursday, MISO Planning Manager Tony Hunziker said the RTO is developing a strawman proposal on new futures development for stakeholder review at an Oct. 17 workshop.

Hunziker agreed that industry projections are already “outpacing” even MISO’s accelerated fleet change future, which predicts wind and solar will account for 29% of capacity by 2033. He said there are signs that wind and solar generation will make up more than 30% of the generation mix by that time.

CGA’s Sean Brady noted that some MISO states are targeting a 40 to 50% renewables mix by the mid-2030s.

Veriquest Group’s David Harlan said MISO’s reliance on planning for new generation based on a reliability-focused planning reserve margin might now be “too narrow” to use in transmission planning. He said MISO should consider that the future generation portfolio will have ramping, reactive power and voltage support needs among others.

Hunziker said MISO could move to a “dynamic” — instead of static — planning reserve margin for transmission planning. Though still undefined by the RTO, a dynamic planning reserve margin could change in out-years based on forecasts. Currently, MISO’s futures ensure its planning reserve margin is met.

Some stakeholders have also suggested MISO create a member survey to better capture its members’ carbon-reduction goals and resource additions and retirements.

MISO is also asking whether it should split its footprint into subsections for planning studies or allow for different input assumptions at the local resource zone level, state level, or the MISO Midwest and South regions. Hunziker said subregional futures would require significantly more work.