Page 1134 – RTO Insider

February 23, 2020

FERC Denies Rehearing in Z2 Remand Order

By Tom Kleckner

FERC last week denied SPP’s request for a rehearing of the commission’s 2019 order that the RTO provide refunds of credit payment obligations (ER16-1341).

SPP asked the commission to stay the refund directive and establish settlement judge procedures. The February 2019 order on remand reversed a waiver FERC had previously issued on Attachment Z2 of the SPP Tariff. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

The commission found the RTO failed to meet the first criterion to receive a stay: that it would suffer “irreparable harm” without it.

FERC questioned whether settlement discussions “would be productive at this point,” noting that SPP in 2016 sought a retroactive waiver of its Tariff, citing the complexity of invoicing transmission service customers for Attachment Z2 credit payment obligations for the 2008-2016 time period.

“Given the length of time that has elapsed since SPP’s initial waiver request, parties have had considerable time to engage in settlement discussions or consider negotiation through the stakeholder process,” the commission wrote. “However, at no point in the lengthy history of this proceeding have parties on opposite sides of the issue supported settlement at the same time.”

Under Attachment Z2 of SPP’s Tariff, sponsors that fund network upgrades can be reimbursed with revenue credits through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade.

Oklahoma Gas & Electric, Western Farmers Electric Cooperative, the city of Prescott, Ark., and a coalition of generation developers (EDF Renewables, Enel Green Power NA, NextEra Energy Resources and Southern Power) supported SPP’s position.

Kansas Electric Power Cooperative and Xcel Energy Services intervened against SPP, arguing that the RTO had not met FERC’s “high” standard for granting a stay.

The commission also rejected a separate rehearing request filed in April 2019 by SPP, OG&E and Flat Ridge 2 Wind Energy, a 470-MW wind facility in Kansas jointly owned by BP Wind Energy and AEP Renewables (ER16-1341-004). FERC did grant SPP’s request for clarification of the refund directive.

The commission affirmed its finding in the remand order, saying the filed rate doctrine and a rule against retroactive ratemaking prohibit the waiver. It also affirmed its determination that refunds are the appropriate remedy and granted SPP’s clarification request that any interest owed on the refunds should be collected from entities that received settlement payments from SPP — not the RTO.

FERC in January rejected SPP’s request to eliminate Z2 revenue credits for sponsored transmission upgrades. The grid operator hopes to replace the troublesome Z2 credits with incremental long-term congestion rights. (See FERC Order Keeps Z2, Aids EDF’s Sponsored Project.)

Co-ops Rebuffed in Settlement Rehearing Requests

The commission also denied rehearing requests of a pair of 2019 orders rejecting contested settlements filed by SPP regarding the annual transmission revenue requirements (ATRRs) for two cooperatives.

FERC rejected Corn Belt Electric Cooperative’s rehearing request but did grant, in part, Interstate Power and Light’s (IPL) petition for clarification of the order (ER15-2028).

Similarly, the commission turned down Northwest Iowa Power Cooperative’s (NIPCO) rehearing request (ER15-2115).

FERC last year rejected the contested settlements, saying that because they were contested, they couldn’t be approved under the commission’s guidelines and precedent set by a 1999 case involving Trailblazer Pipeline. Both proceedings were remanded to the chief administrative law judge to resume hearings. (See FERC Rejects SPP Settlements over ATRR.)

The Corn Belt settlement centered on SPP’s Tariff revisions to accommodate the co-op’s ATRR as an incoming transmission-owning member. At issue were three grandfathered agreements (GFAs) providing in-kind transmission service to the settlement’s parties.

The cooperative said it was not challenging FERC’s decision to set the case for hearing but argued against the framing of issues and the hearing’s scope. Corn Belt said that when TOs join regional grids, even indirect modifications to GFAs can trigger a threshold analysis under the Mobile –Sierra D octrine, which holds that negotiated, fixed-rate contracts are to be presumed just and reasonable under the Federal Power Act and cannot be revised by FERC without a finding that the public interest requires modification.

The commission disagreed with Corn Belt’s argument that a Mobile-Sierra analysis is required, saying it is not relevant “when [FERC] action merely affects a contract.”

“The commission is addressing SPP’s rate treatment of the service underlying the GFA, not whether the GFA itself should be modified,” the commission wrote.

FERC granted IPL’s request to clarify that the settlement order does not determine whether the rights granted in its GFA constitute transmission service. The commission said it made only preliminary findings that GFA loads were served with firm transmission service and that no rights or obligations were determined.

NIPCO used many of the same arguments in challenging the framing of issues and the hearing’s scope, rather than FERC’s decision to set its case for hearing. As in the Corn Belt case, SPP filed Tariff revisions to allow for the co-op’s ATRR when it joined the RTO as a transmission-owning member, drawing objections from members who said the rate treatment of two NIPCO GFAs would essentially subsidize transmission loads and shift the cost to transmission owners.

The commission responded that a Mobile-Sierra analysis is not relevant when its action merely affects a contract, saying it addressed SPP’s rate treatment of the GFA’s underlying service, not whether the GFA itself should be modified.

February 23, 2020

PJM MRC/MC Briefs: Feb. 20, 2020

PJM Seeks to Retire Opportunity Cost Calculator, Use IMM Tool

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee heard the first read of a compromise proposal to eliminate the RTO’s opportunity cost calculator and make the Independent Market Monitor’s calculator the required tool for market sellers.

PJM’s Glen Boyle said the RTO’s calculator would be retired July 1 under the proposal. “There’s a perceived … compliance risk in using the PJM calculator,” said Boyle, the manager of operations analysis and compliance. “So, most market sellers are using the IMM calculator.”

PJM’s Glen Boyle briefs the MRC on proposed changes to the opportunity cost calculator. | © *RTO Insider*

PJM will expand Manual 15’s description of the Monitor’s calculator and conduct an annual review of the tool in conjunction with the Monitor.

In September, 84% of the Market Implementation Committee approved a joint proposal by Panda Power Funds and Dominion Energy that would have made changes to the PJM calculator and improved documentation of the Monitor’s tool. An alternate PJM proposal that would make minor documentation changes to its calculator won only 51% support.

Following the MIC meeting, the joint sponsors negotiated with PJM and the Monitor to develop the compromise on which the MRC will vote in March.

The calculator is intended to ensure generators are made whole for being scheduled by PJM outside their most profitable time periods.

An opportunity cost adder can be included in a cost-based offer when a unit faces environmental restrictions on how much they can operate, an equipment manufacturer imposes an operational restriction because of equipment limitations or the unit faces a fuel limitation resulting from a force majeure event. The value of the adder is based on historical LMPs and forecasted future fuel prices.

‘Page Turn’ Review of Risk Evaluation Rules Set for Wednesday

Proposed Tariff revisions on market participant risk evaluations will be the subject of a “page turn” review at a special MRC meeting this Wednesday, Chief Risk Officer Nigeria Poole Bloczynski told the MRC.

The changes, endorsed by the Financial Risk Mitigation S enio r Task Force, would:

amend the definition of affiliate and add ones for principal, position limits, unreasonable credit risks and hedge exemptions;
add a provision for re-entry of defaulting market participants;
strengthen “know your customer” five-year look-back and internal credit score procedures;
improve PJM’s authority to ban market participants and demand additional collateral; and
eliminate an exception allowing financial transmission rights participants to avoid the minimum capitalization standard of “a tangible net worth of more than $1 million or tangible assets in excess of $10 million.” The current exception allows an FTR participant to post $500,000 and pay a 10% adder on collateral.

The changes are intended to prevent a repeat of GreenHat Energy’s default on its FTR obligations.

Advocates, TOs Continue Battle over ‘Critical’ Tx Projects

Although the PJM Transmission Owners sector’s critical infrastructure mitigation plan is pending before FERC, that hasn’t ended the bitter debate over it among stakeholders.

NERC critical infrastructure protection reliability standard CIP-014 requires transmission owners to protect assets whose loss or sabotage could result in widespread instability, uncontrolled separation or cascading outages.

The TOs proposed a confidential process (Attachment M-4) for removing critical transmission infrastructure from NERC’s CIP-014 list. They offered other sectors an opportunity to comment on the plan but have invoked their rights under contractual agreements with PJM and FERC orders to file it without majority support from the membership.

In early February, consumer advocates, industrial customers and state regulators asked FERC to reject the TOs’ plan as filed, saying it lacks transparency and improperly restricts input by stakeholders and the RTO (ER20-841). State consumer advocates were particularly upset that PJM endorsed the plan in a FERC filing despite a stakeholder resolution at the January Members Committee meeting arguing that the proposal conflicts with the RTO’s Operating Agreement. (See PJM Supports TO Critical Tx Plan.)

Greg Poulos, Consumer Advocates of the PJM States (CAPS) | © *RTO Insider*

At Thursday’s MC meeting, Greg Poulos, executive director of the Consumer Advocates of PJM States, said the advocates were “a little bit disappointed that PJM didn’t provide a response to the resolution.”

“The stakeholder process seems to carry a little less weight on planning matters,” Poulos said.

PJM — Sharon Midgley, Exelon | © *RTO Insider*

Exelon’s Sharon Midgley responded that the resolution “was advisory and did not and could not bind PJM.”

“These events provide evidence of various shortcomings in our stakeholder process and misplaced expectations about PJM’s duties as an independent system operator. PJM is properly respecting its contractual agreement with transmission owners,” she continued. “If stakeholders are concerned about the exercise of transmission owner rights, their recourse is at FERC. But it is improper for stakeholders to co-opt our consensus-based stakeholder governance rules in a self-serving attempt to bolster their litigation position.”

Poulos noted that former CEO Andy Ott raised the issue of critical grid assets at the RTO’s Grid 20/20 conference in September 2017. Ott called for “making critical facilities less critical” by building redundancies such as alternative transmission paths. (See PJM Grid 20/20 Debates Meaning of Resilience.)

“To see that these projects labeled as urgent were not addressed [since 2017] is a big concern,” Poulos said. “If they’re that urgent for three years, what were we doing?”

Alex Stern of Public Service Electric and Gas responded that Poulos’ comments should be placed “in a broader context.” Stern listed recent attacks on grid infrastructure, including the 2013 Metcalf incident, the 2015 Russian hacking attack on three Ukraine utilities and cyberattacks on U.S. utilities by China last year. He also noted concerns in January that rising tensions between the U.S. and Iran could provoke an Iranian attack on critical utility sector infrastructure. (See Iran Cyber Threat Increasing, Experts Say.)

Stern thanked PJM and its Board of Managers “for their courage” in supporting the M-4 filing. “I feel comfortable that the PJM TOs have done what they can,” Stern said. “The decision-making now rests with FERC.”

Midgley said the TOs’ Jan. 19 filing under Federal Power Act Section 205 is subject to a 60-day deadline, meaning FERC should rule by mid-March.

‘Resource Adequacy’ to be Topic of General Session

MC Vice Chair Katie Guerry said “resource adequacy” will be the subject of the General Session at PJM’s Annual Meeting in Chicago May 4-6.

Guerry said the subject was chosen based on discussions between stakeholders and the board at the Liaison Committee meeting in D.C. on Feb. 10.

MC Vice Chair Katie Guerry, right, and PJM CEO Manu Asthana | © *RTO Insider*

“We don’t see a resource adequacy problem,” said Greg Carmean, executive director of the Organization of PJM States Inc., citing the RTO’s “substantial” reserve margins. “Are you talking about integrating renewables?”

“That was a core component of the discussion,” Guerry responded, adding that states and their carbon emission goals are an “important component of thinking about that.”

“What we’re really trying to do is take a broad and open-minded look at what resource adequacy would look like” in the future, added Dave Anders, director of stakeholder affairs. “Not specific reserve margins.”

Manual Changes OK’d

The MRC approved two manual changes:

Manual 14F: Competitive Planning Process: modification in response to a September FERC order that said transmission projects solely needed to address Form 715 planning criteria violations should not be exempt from competition. (See FERC Opens Local Tx Projects to Competition, Cost Sharing.)
Manual 40: Training and Certification Requirements: revisions resulting from cover-to-cover periodic review; includes updated temporary waiver language to allow more flexibility in addressing compliance with training and certification requirements.

– Rich Heidorn Jr.

February 23, 2020

ISO-NE Planning Advisory Committee Briefs: Feb. 20, 2020

The ISO-NE Planning Advisory Committee last week heard the RTO’s latest study results on integrating up to 8,000 MW of offshore wind into the regional grid. The New England States Committee on Electricity (NESCOE) had requested the analysis.

At the April 2019 PAC meeting, Anbaric Development Partners and RENEW Northeast requested separate analyses, which are still under development.

Patrick Boughan, ISO-NE senior engineer for system planning, presented the NESCOE 2019 Economic Study for four scenarios with 8 GW of offshore wind additions connected in varying amounts to five different interconnection points.

“For these scenarios, as opposed to our preliminary results that were presented in December, we’re using 2015 as the base weather year,” Boughan said. “That means the shape of the load, wind and solar curves is based on the 2015 weather year, but it’s at 2030 values based on our forecast.” (See ISO-NE Planning Advisory Committee Briefs: Dec. 19, 2019.)

“We don’t see any significant transmission interface congestion being caused by offshore wind in any of the 8,000-MW scenarios,” he said. “We will be doing a more detailed analysis of transmission congestion [and] also estimated costs for required upgrades.”

That analysis may find congestion within the Regional System Plan that is not caught in a more general study, Boughan said.

Differences among the scenarios are driven by different volumes of energy from wind resources, which led the planners to increase the Surowiec-South interface limit to 2,500 MW from the 1,500 MW used in the preliminary results, he said.

“We see 15 TWh of spillage [yearly], which is imports, hydro, wind and solar together, in these 8,000-MW scenarios, with some slight variation among them. However, we do see significant variation in how much spillage there is by month [0.15 to 2.69 TWh],” Boughan said.

Increased offshore wind production shows the same positive trends as seen with lower levels, such as lowered use of natural gas production and imports, and significant decreases in production costs, LMPs, load-serving entity energy expenses and carbon emissions.

Heat pumps and plug-in electric vehicles make up only 4% of projected 2030 annual net load, which spikes to about 10% during winter evening peaks. This load addition is often served by storage or energy that would otherwise be spilled, he said.

Wind/Power Time Series Modeling

ISO-NE’s lead engineer for system planning, Steven Judd, reviewed the need for a new wind data power time series and the assumptions used to create the data.

The RTO hired consultancy DNV GL to create a new historical data set for both onshore and offshore wind. It said three of its ongoing studies require wind data, including 2019 Economic, Energy Security and Transmission Planning studies.

“With those three studies, the [RTO] decided we needed to go out and try to find a different area of trying to build this historical wind data output, [as if] those offshore wind farms have been built,” Judd said. “So how do you get historical data?

“DNV GL is already performing our operational wind forecasting, so they have the data on our onshore wind farm layouts, turbine types and power curves for the existing fleet,” Judd said. “This project will allow the [RTO] to update the time series in the future to continue to calibrate and expand our data set as new years of history go on.”

Chris Hayes of DNV GL presented wind and power time series m odeling of ISO-NE wind plants, which combined mesoscale and power time series modeling capabilities to produce simulated wind plant time series for 38 existing and 11 future — or hypothetical — wind plant locations.

“The data set for this particular study is confidential to ISO New England and is not publicly available,” Hayes said.

Because the mesoscale model is not perfect, the researchers generally use land-based wind farm performance measurements to calibrate the data sets, including for the wind energy areas off Nantucket, he said.

For the future or hypothetical wind plants in the Bureau of Ocean Energy Management lease area, increased variability in the offshore wind power time series versus onshore wind appears to be caused by a combination of the “portfolio effect,” stronger winds and a broader shape to the wind-speed frequency distribution, Hayes said.

The “portfolio effect” refers to increased geographic dispersion of onshore wind plants resulting in decreased variability of aggregate generation, which reduces the risk that a single weather system will impact the generation of all plants in the region at the same time.

“It doesn’t appear that the increase in potential variability applies necessarily to the hour-to-hour wind ramps or generation changes,” Hayes said. “We generally don’t have hour-to-hour changes that could drop aggregate generation at full capacity down to nothing. Those changes generally take a little bit more time.”

For operational purposes, although the offshore time series may have a larger range of possible generation values or likely values for each hour of the day, the change from one hour to the next is not necessarily going to be significantly greater than onshore, he said.

– Michael Kuser

February 23, 2020

SPP Seams Steering Committee Briefs: Feb. 20, 2020

SPP staff are working with both MISO and Associated Electric Cooperative Inc. (AECI) to develop coordinated system plans (CSPs) in the search for joint projects, staff told the RTO’s Seams Steering Committee last week.

Neil Robertson told the committee during its meeting Thursday that the RTOs are “not necessarily” on the same page as to what the 2020 CSP looks like, but that SPP would like to conduct a study similar to last year’s. The RTOs studied potential interregional projects using their regional models in 2019. However, as when they collaborated on CSPs in 2016 and 2018, SPP and MISO were unable to reach any agreements.

The wild card, Robertson said, is the limit MISO faces on regional directional transfers (RDT) between its northern and southern regions over SPP’s system.

Under the terms of a 2015 settlement agreement with SPP and other parties, MISO is limited to 1,000 MW of contracted, firm transmission capacity, with access to additional non-firm service capped at 3,000 MW in southbound flows and 2,500 MW northbound. MISO is keen on modifying the RDT arrangement when the settlement agreement expires in February 2021, and both RTOs have or will be conducting studies on the constraints. (See Interregional Projects May Become Reality for SPP, MISO.)

SPP — MISO South’s connection to MISO | *MISO*

“We’re trying to figure out how the RDT study melds with doing a typical CSP,” Robertson said.

The SSC endorsed staff’s recommendation to endorse the MISO RDT as a target area for additional analysis in SPP’s Integrated Transmission Planning (ITP) assessment. The Economic Studies Working Group has already endorsed the recommendation.

Planning staffs from both RTOs will hold a March 10 conference call to review “annual issues,” a precursor to a joint study.

Meanwhile, SPP and AECI are drafting the scope document for a potential CSP, which would use reliability models from the RTO’s 2020 ITP and possibly include economic planning analysis. Their Interregional Planning Stakeholder Advisory Committee plans to meet in March, with the hope of producing a final CSP report in July.

SPP to File AECI Project Costs with FERC

SPP is also working with AECI to finalize an agreement, to be filed with SPP Board of Directors/MC Briefs: Jan. 28, 2020.)

Because AECI is not a transmission owner under SPP’s Tariff, the agreement is necessary to outline project specifics and define cost allocation for AECI’s work. FERC’s approval would allow SPP to allocate funds compensating AECI for its work.

Once these steps are finalized, SPP is expected to put the project out for bids. The 2019 ITP assessment identified the project’s need date as Jan. 1, 2026.

M2M Settlements Reach $70M

Another month of multimillion market-to-market (M2M) settlements has pushed MISO’s tab with SPP past the $70 million mark.

SPP-MISO market-to-market settlements | *SPP*

Temporary and permanent flowgates on the RTOs’ seam were binding for 1,008 hours during December. That resulted in a $2.85 million settlement in SPP’s favor, pushing the overall total to $70.96 million since March 2015.

Under the M2M process, the RTO with the greater economic dispatch addresses market flows.

— Tom Kleckner

February 23, 2020

Michigan PSC Orders DTE to Redo IRP

By Amanda Durish Cook

The Michigan Public Service Commission last week told DTE Electric to extensively revise its 15-year integrated resource plan, finding the utility didn’t adequately factor in the benefits of renewable energy.

The decision, which was neither a rejection nor approval, means DTE must go “back to the drawing board,” the state commission said Thursday. It gave the utility until March 21 to submit a revised IRP (U-20471).

Administrative Law Judge Sally Wallace in late December ruled against DTE’s IRP, saying the utility used outdated information in its modeling that produced results that minimized the advantages of renewable energy and energy efficiency. She also said the plan failed to include competitive bidding for renewable generation to fill capacity needs and leaned too much on natural gas-fired generation. In addition to the $1 billion, 1,150-MW gas-fired Blue Water Energy Center under construction, DTE proposed multiple gas-fired plants rated about 400 MW, 693 MW of wind generation, 11 MW of solar with on-site storage and 859 MW in demand response programs by 2024. (See DTE IRP Draws Fire from Renewable Proponents.)

The commission did not have to follow the judge’s recommendation in its final decision. However, Wallace had said DTE should adjust the plan even if the Michigan PSC decided to approve it.

DTE’s Belle River power plant | *DTE Energy*

But the trio of regulators largely agreed with the judge’s decision, saying the IRP should contain plans for a request for proposals for new renewable resources. The PSC also initiated two new proceedings in the order, including an April 1 deadline for DTE to update its renewable energy plan and a Nov. 13 deadline to file an application for review of its compliance with the federal Public Utility Regulatory Policies Act.

The PSC also required that DTE reach 1.75% energy savings in 2020 and 2% in 2021, the same targets the commission set for Consumers Energy. Michigan’s statutory minimum is 1% per year; DTE had proposed it satisfy a 1.65% savings in 2020 and 1.75% in 2021.

“The commission acknowledges DTE’s focus in the near term on ways to increase programs to cut energy waste, but we’re recommending that the utility do more to tap into this cost-effective resource,” PSC Chairman Sally Talberg said.

The commission said the plan’s failure to use current data and study renewable alternatives painted an incomplete picture.

“These issues inhibited the commission from assessing the full range of alternatives such as utility- and third-party-owned wind and solar projects,” the PSC said in a statement. In the order, it said there were “significant deficiencies” in DTE’s record, “including a starting point that included a range of nonapproved and nonoptimized resources and the failure to issue a request for proposals for supply-side resource additions.” The commission said it would be best for DTE to remove all the supply-side resource additions it proposed to start fresh.

It also said DTE’s proposal to hold off on full retirement of the coal-fired Belle River power plant near the Canadian border until 2030 was “inadequately justified because an analysis of avoiding new environmental upgrade costs was not considered.”

The PSC agreed with the criticism that DTE’s modeling software Strategist is outdated and no longer supported by its developer ABB Group. It ordered the utility to schedule a technical conference within three months to discuss alternative modeling software with “interested stakeholders.”

The commission didn’t mince words about the stakes for the utility. “Should DTE Electric fail to file a revised IRP that substantially adopts the recommended changes, the commission will be left with little alternative but to deny the IRP,” it said.

It said it accepted thousands of public comments since the plan was filed last March, the “vast majority” urging it to reject the IRP and direct DTE to increase its renewable fleet. Michigan’s reliance on coal has fallen dramatically, from more than 65% of the state’s generation fleet in 2007 to more than 40% in 2017.

“We appreciate the unprecedented amount of public participation generated by the interest in this case, a clear indication that Michiganders are becoming more engaged in helping to shape Michigan’s energy future,” Talberg said.

In a statement, DTE said it was evaluating the recommendations to prepare for a response filing. The company said the IRP “reflects our long-term goals and plans to be a leader in providing cleaner energy to our customers.”

“Since 2009, DTE has been the largest investor in renewables in Michigan, driving $3 billion in solar and wind energy infrastructure and investments. Over the next decade, we will triple our renewable energy assets,” the company added.

DTE had defended its plan in January, calling it the “most reasonable and prudent means” of meeting its energy and capacity needs. The utility repeated claims that it will not have a capacity need to be filled by small qualifying facilities under PURPA for at least the next five years and no planning-level need for additional capacity for at least the next decade. After the Belle River units retire in 2029 and 2030, DTE said it would begin to experience a 585-MW capacity shortfall. Until then, there’s no “persistent capacity need,” the company said.

The Union of Concerned Scientists had been particularly vocal, dogging DTE throughout the process for its reliance on traditional resources and on self-scheduled coal generation.

“So much of the resource plan was ‘hardcoded’ that DTE actually prevented the model from selecting resources that would otherwise provide real economic value to DTE’s customers,” UCS Senior Energy Analyst Joseph Daniel said last year.

A day after the PSC’s decision, Daniel said state regulators cut a “Gordian knot” by “neither approving nor rejecting the IRP but recommending major modification in such a way that is sending DTE back to the drawing board.” He characterized the order as a “Midwestern rejection.”

February 23, 2020

Calif. Energy Commission Relaxes Rooftop Mandate

By Hudson Sangree

SACRAMENTO, Calif. — In a controversial decision, the California Energy Commission on Thursday allowed the Sacramento Municipal Utility District to sell solar power to homebuilders and homeowners as an alternative to the rooftop solar panels required on all new homes built in the state after Jan. 1.

The commission adopted the cutting-edge regulations requiring rooftop solar last year but provided that “a community-shared solar electric generation system” could substitute for rooftop solar in new subdivisions. SMUD was the first utility to apply for permission to build community solar under its Neighborhood SolarShares Program last fall.

The commissioners unanimously approved SMUD’s request after a three-hour hearing, during which about 75 speakers addressed them in a hot, crowded hearing room.

Stakeholders packed the chambers of the California Energy Commission and overflowed into a second room for the Feb. 20 debate on rooftop solar. | © *RTO Insider*

Opponents argued that a decision in favor of SMUD would open the door for public utilities, community choice aggregators and eventually investor-owned utilities such as Pacific Gas and Electric to sell solar power to new subdivisions instead of each house or neighborhood having its own solar panels.

“This proposal will significantly undermine rooftop solar and storage in the SMUD territory, and it will set a precedent and a blueprint for other utilities, particularly the IOUs, to do the same,” State Sen. Scott Wiener (D), a PG&E critic, told commissioners. “Because we know that when it comes to PG&E and the other investor-owned utilities … there is no attack on rooftop solar and storage that they will not engage in because they want it to go away, and they see it as competition.”

Wiener said he regretted having to oppose SMUD, which broke away from PG&E more than 70 years ago — as San Francisco, which he represents, wants to do now — and has been a statewide leader in renewable energy.

Steven Lins, director of government affairs at SMUD, countered, “We’re focused on the big picture here, and for us that’s net-zero by 2040. That’s an audacious, aggressive goal, and we’re going to need every tool in the toolbox to get there.

“Neighborhood SolarShares is just one of many strategies that we have for reaching that goal,” he said. “It meets all the requirements. It’s just another path or option for compliance. It creates a choice for builders and buyers. Without Neighborhood SolarShares, there’s quite simply no other choice but rooftop, and that’s not what was intended in the regulations.”

Homebuilders, utility lobbyists and numerous SMUD employees spoke in favor of the community solar proposal. Not all new home buyers want rooftop solar panels, which can increase the purchase price of a house by thousands of dollars and require regular maintenance, they contended. Under SMUD’s proposal, homebuyers would have the choice of purchasing rooftop solar from builders as an add-on option or buying into the community solar program.

“Fundamental to the Energy Commission’s 2020 standards is choice,” said Frank Harris, manager of energy regulatory policy with the California Municipal Utilities Association. “In establishing the eligibility of a community solar option, the Energy Commission recognized that homeowners should have these options. The community solar program can provide a more efficient way to increase solar and maintain choice for homeowners for whom rooftop may not be the best way for introducing solar.”

Smart vs. Dumb Buildings

Environmentalists and solar industry representatives backed Wiener’s views, saying the SMUD plan would harm the movement toward rooftop solar and distributed energy resources.

“The proponents are trying to frame this as a solar-versus-solar decision, which I would imagine would be a hard choice for any and most environmentalists to make,” said Bernadette Del Chiaro, executive director of the California Solar & Storage Association.

“This is not solar versus solar,” she said. “This is the smart buildings of the future versus the dumb buildings of the past. The Energy Commission hoped for innovative community solar projects to come out of the alternative compliance option. All you’re getting today is a very commonplace utility-scale project, the likes of which the [renewable portfolio standard] will already support and bring to the fore.”

Commission staff recommended approval after SMUD agreed to make changes to its Neighborhood SolarShares proposal.

CEC Executive Director Drew Bohan said SMUD had agreed to build new solar farms within its service territory of less than 20 MW each to serve its community solar program. The utility’s initial plan could have imported power from large arrays hundreds of miles away, he said.

Controversy arose because California was the first state in the nation, starting seven weeks ago, to require rooftop solar panels on new residential construction, and opponents believed SMUD’s plan compromised that landmark achievement, Bohan said. (See Calif. Code Change Would Mandate Rooftop Solar.)

Commissioner Andrew McAllister, who oversaw the vetting of SMUD’s plan, said California must continue eliminating greenhouse gases and fossil fuels under Senate Bill 100, Assembly Bill 32 and other historic measures. The electrification of transportation and buildings is key to those efforts, and rooftop solar panels and community solar arrays should both play a role, he said.

“Building decarbonization is a huge topic. It’s a huge project for the state, certainly for the CEC, and it’s bigger than today’s discussion, I would argue,” McAllister said. “This is but one piece of that.”

He called for others to bring innovative proposals to the commission for consideration.

“We need to tend the fields of California’s diverse clean energy landscape so that all its many flowers can continue to bloom,” McAllister said.

February 23, 2020

In Rare Surprise, FERC Declines to Act on Jordan Cove

By Michael Brooks

WASHINGTON — FERC Commissioners Bernard McNamee and Richard Glick on Thursday voted not to act on a proposed LNG export facility, resulting in the rare surprise at what are usually tightly scripted monthly open meetings (CP17-494, CP17-495).

The commission was prepared to approve Calgary-based Pembina Pipeline’s application for its Jordan Cove LNG export terminal and accompanying Pacific Connector pipeline in Oregon as part of its consent agenda. The project was listed as being approved in a packet summarizing the actions the commission took as part of the meeting’s agenda.

But during his opening remarks, McNamee announced that he would be voting “nay” on the project after he said the state’s Department of Land Conservation and Development (DLCD) “provided a letter, apparently, to the applicant regarding its permits. I want to see what the state of Oregon said, and I need that information to inform my decision about whether I’m going to ultimately vote for or against” the project.

The Oregon DLCD had notified Pembina on Wednesday that it had “determined that the coastal adverse effects from the project will be significant and undermine the vision set forth by the [Oregon Coastal Management Program] and its enforceable policies.” The department cited the federal Coastal Zone Management Act (CZMA), and the regulations implementing the law, in asserting that because it has objected, neither FERC nor the U.S. Army Corps of Engineers could approve the project unless its objection is overridden by U.S. Secretary of Commerce Wilbur Ross.

A rendering of Jordan Cove LNG export terminal, focusing on the processing facility and marine slip from the northwest | *Jordan Cove LNG*

As required by the CZMA, the DLCD notified both FERC and the corps of its objection, but McNamee told reporters after the meeting he was unaware of what exactly the department had done. According to FERC’s eLibrary, the letter was filed with the commission on Wednesday but not actually published until the day of the meeting.

“All I know is that I saw in the news that Oregon did something on this and supposedly denied certain permits,” he told reporters. “I don’t know the details, and that’s why I want to know what the details are so I can make a reasonable decision.”

Chairman Neil Chatterjee told reporters after the meeting that McNamee informed him of his decision “just prior to the meeting.” Chatterjee had placed the project on the consent agenda in an effort to comply with the directives of the Fixing America’s Surface Transportation Act’s Title 41 (FAST-41), which is intended to improve the coordination between federal agencies in issuing infrastructure permits to speed their construction.

Glick, however, was apparently uninformed of the decision, as he issued a scathing dissent in his opening comments as if the project were going to go through. As the newest commissioner, McNamee is last in the order of who speaks during opening remarks and staff presentations.

Glick said that in addition to his usual objection to FERC not considering the impact of natural gas projects’ greenhouse gas emissions on climate change, the commission was also disregarding an Oregon law charging the state with reducing its carbon dioxide emissions to 14 million metric tons/year by 2050. According to Glick, the project would emit 2 million metric tons of CO₂-equivalent per year.

“This is significant. This is going to make it really tough for Oregon to meet its standards here,” Glick said.

The commission ultimately voted 2-1 not to act on the application at the meeting, meaning the project is still pending before it, said Deputy General Counsel David Morenoff, invited by Chatterjee at his press conference to explain to reporters the procedure.

Prior to the vote, as commission Secretary Kimberly Bose read off the list of agenda items, Glick could be seen conferring with his staff and General Counsel James Danly before he joined McNamee in voting “nay” on the Jordan Cove agenda item. Normally, commissioners vote “aye” on the consent agenda after noting their individual dissents and concurrences on specific items.

McNamee said in a statement after the meeting that he voted against the project without prejudice, meaning he did not vote on the merits of the application. But Glick told reporters after the meeting that he was concerned that he could be deemed to have prejudged the matter because of his comments before the vote — though he noted that would mean he would have to recuse himself from the proceeding, leaving the commission without a quorum to act on it. He said he would not have said anything had he known what McNamee was going to do.

The commission could vote on the project again as soon as McNamee is ready, Chatterjee said. McNamee said he expected to be able to vote on it this week.

The Jordan Cove export terminal would be in Coos County, on the southwestern coast of Oregon. It would produce 7.8 million metric tons of LNG per year, according to FERC. The Pacific Connector pipeline would run 229 miles, transporting 1.2 million dekatherms/day of gas to the terminal from a trading hub near the city of Malin, Ore., on the border of California. The project’s website lists “proximity to active Asian markets” as one of its “essential characteristics for an optimal export facility.”

Glick ‘Disappointed’ and ‘Saddened’ by Dissents

Glick issued 14 dissents at the meeting, saying he was “very disappointed that we have gotten to this place, and I’m saddened about what that says about this agency.”

“This is an agency that used to be known for nonpartisanship and compromise, but … I still can’t vote in good conscience for orders that violate the law and come nowhere close to reasoned decision-making.”

Speaking about Jordan Cove, he listed several different impacts unrelated to emissions that he said the commission failed to adequately consider and mitigate.

“I think in this order, we’re actually being honest” about whether the commission weighs the benefits of a project against the adverse impacts in determining if it’s in the public interest, Glick said. “We say, ‘We don’t really do that. We just look at the adverse impacts on landowners, and we weigh that against the economic benefits of the project, and then later on, in the order, we’ll talk about the environmental impacts, but we really don’t include the environmental impacts in our decision-making process.’ Something’s really rotten with that. … I think that’s why the commission has really earned its reputation as being a rubber stamp for these types of pipeline and LNG projects.”

Glick noted that one of the orders he dissented on denied reconsideration of staff giving Enbridge a two-year extension to complete construction of its Atlantic Bridge, a project to expand its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems (CP16-9). Staff approved the extension Dec. 26, 2018 — the same day it was requested, only 34 minutes after it was published on eLibrary.

“I just don’t understand why … we’ve delegated this [function] to staff,” Glick said.

Glick gave his colleagues credit for establishing a new procedure for requests for extension of time to complete construction going forward. In the order, the commission directed the Office of the Secretary and Office of Energy Projects to notice all such requests within seven calendar days of receipt and establish a 15-calendar-day intervention and comment period deadline.

“But that doesn’t eliminate the injustice that occurred in this case,” Glick said. “I think at the very least we could have granted rehearing and reconsidered” Enbridge’s request.

McNamee acknowledged that the extension approval “doesn’t look good.” He noted that staff were aware of the incoming request and of the project’s ongoing delays because of litigation. But McNamee agreed with Glick that “the public should have more of an opportunity” to comment.

The meeting was interrupted seven times by protesters from environmental group Beyond Extreme Energy, the first such disruption since April 2019. (See Enviro Protesters Scale FERC HQ as Agency OKs More LNG.) The protesters were escorted out of the meeting room by security.

February 23, 2020

CAISO, NYISO, Companies Win Partial OK on Order 845

By Amanda Durish Cook

FERC on Thursday largely approved the Order 845 compliance filings for CAISO, NYISO and a handful of utilities, though none of the entities received perfect marks.

The commission said the companies and grid operators mostly adopted its pro forma large generator interconnection procedures but fell short of adopting all language required under Order 845.

FERC issued Orders 845 and 845-A in 2018 and 2019, respectively, to increase the transparency and speed of generator interconnection processes. (See ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)

The commission directed the two grid operators and five utilities to make additional changes to their filings, focusing on contingent facilities, provisional interconnection service, generators’ technological advancements and surplus interconnection service. The entities have 60 days to address the shortcomings.

In addition to CAISO’s (ER19-1950) and NYISO’s (ER19-1949) partial compliance, FERC found partial compliance from Arizona Public Service (ER19-1939), Cube Yadkin Transmission (ER19-1956), Deseret Power (ER19-1902-001), El Paso Electric (ER19-1953) and LG&E and KU (ER19-1916).

Contingent Facilities

In a familiar line, the commission said the entities’ proposals “lack the requisite transparency … because the proposed tariff revisions do not detail the specific technical screens or analyses and the specific thresholds or criteria that [they] will use as part of its method to identify contingent facilities” — unbuilt interconnection facilities and network upgrades on which the interconnection request’s costs, timing and study findings are dependent.

“Without this information, an interconnection customer will not understand how [they] will evaluate potential contingent facilities to determine their relationship to an individual interconnection request,” FERC said in nearly all the orders, adding that such criteria will ensure that interconnection customers are treated equally.

Contingent facility descriptions presented a challenge in an earlier round of 845 approvals. (See FERC Finds Partial Compliance on Order 845.)

Surplus Service

Revisions related to surplus interconnection service were also a stumbling block for many of the entities.

FERC said CAISO and Deseret failed to include tariff revisions that explicitly require that the transmission provider, original interconnection customer and surplus interconnection service customer file a surplus interconnection service agreement with the commission that outlines the terms and conditions of the service.

FERC Order 845 — Wind farm near Palm Springs | © *RTO Insider*

The commission directed LG&E/KU to remove a provision that it will not allow surplus interconnection service if the system impact study identifies a need for new interconnection facilities or network upgrades. FERC said while Order 845 does restrict surplus service when network upgrades are needed, it does not “restrict the construction of new interconnection facilities necessary to accommodate surplus interconnection service.”

El Paso Electric must also revise its tariff to explicitly state that surplus interconnection service requests will be processed outside the non-surplus interconnection queue.

Cube Yadkin’s surplus interconnection service provisions also missed the mark, FERC said. The subsidiary of North Carolina hydroelectric company Cube Carolina proposed that “any change made to the existing interconnection service will be treated as a new interconnection request.” FERC said that while Order 845 allows a transmission provider to deny surplus interconnection service if it requires network upgrades, it’s “not for the reasons that Cube Yadkin proposes.”

CAISO

CAISO has the most alterations ahead of it to fully comply with Order 845.

FERC said the ISO’s existing limited operation study — used when an interconnection customer requests service below its full generating facility capacity — missed the aims of Order 845 because the study places restrictions on when a customer may request provisional interconnection service. The limited operation study can only be performed when a transmission owner’s interconnection facilities or network upgrades “are not reasonably expected to be completed” before the generator’s commercial operation date, according to CAISO.

The ISO also must research its Tariff to find evidence that area delivery network upgrades can be cost-capped in the same manner as reliability network upgrades and local delivery network upgrades. FERC said it couldn’t accept some of CAISO’s Tariff language without proof that the practice was already in place. The ISO had said costs for area delivery network upgrades above caps identified in interconnection studies must be financed by the TO.

CAISO also went off-script in its pro forma large generator interconnection procedures when it proposed potential penalties for generators that exceed their level of interconnection service capacity. The commission explicitly decided against penalties for over-generation in Order 845, FERC said, adding that the ISO must make a separate filing to propose over-generation penalties.

Technological Advancements and Provisional Service

FERC also said that CAISO, Cube Yadkin and Deseret failed to mention their requisite 30-day deadline to determine whether a proposed technological advancement to a generation project amounts to a material modification. Additionally, the commission said APS and LG&E/KU didn’t describe studies used to determine whether generators’ technological advancement requests constitute material modifications.

Spotty language around provisional interconnection service was also an impediment to full Order 845 compliance for NYISO and El Paso Electric.

FERC said the ISO’s pro forma large generator interconnection agreement should specify the “frequency with which NYISO will study and update the maximum output of a generating facility” with provisional interconnection service.

The commission also said El Paso Electric’s pledge to update its provisional interconnection studies “whenever changes experienced or projected to occur on the system warrant re-evaluation of the maximum permissible output” was too vague.

February 23, 2020

MISO Steering Committee Briefs: Feb. 19, 2020

Stakeholders will keep a close eye on MISO’s attempt to improve a customer market portal, the RTO’s Steering Committee decided during a Wednesday conference call.

The committee instructed the Market Subcommittee to monitor the RTO’s progress on using more up-to-date information in the Customer Connectivity Environment (CCE).

The nonpublic CCE provides MISO members access to the day-ahead and real-time market user interface, meter data upload applications, and the financial transmission rights and auction revenue rights system.

DTE Energy submitted a complaint on connectivity issues and the state of the data upkeep in the CCE, saying database updates are not being performed regularly.

DTE Manager of Wholesale Market Development Nick Griffin said market participants and MISO software vendors “unnecessarily waste time and resources” during new software testing, “facing extended testing times and elevated costs for software implementations.”

Griffin said during MISO’s rollout of five-minute market settlements in 2018, a “lack of relevant meter data, awards, offers, dispatch instructions, etc.” resulted in a less-than-ideal member testing of the new settlement system.

“We have experienced ongoing production-submission incidents, including unit offers, demand bids and meter data submissions,” DTE said, adding that the problems “reduce confidence in CCE.”

DTE said the problem requires “immediate attention,” especially considering that MISO is refreshing its IT systems as part of its ongoing market platform replacement.

MISO’s Jim Kaminski said staff are aware of the problem and “actively working on the issue.”

“This is quite an issue that we need to take a look at,” SC Chair Tia Elliott said.

SC Mulls Consultant Transparency

The SC may also delve into how forthcoming consultants should be about who they represent during MISO committee meetings.

At the beginning of the year, committee leaders began enforcing a rule that all stakeholders making comments during meetings first identify themselves and who they’re representing before speaking.

The Planning Advisory Committee has reported that some consultants participating in meetings are reluctant to reveal their clients before offering comments or criticisms on MISO presentations.

“There are some individuals in some meetings that are making some rather large requests of MISO. … It would be nice to know who they’re making those requests on behalf of. I think that’s something important to know,” WEC Energy Group’s Chris Plante said.

“I think MISO’s meetings need to be open and fair. And this kind of behavior might not result in fair meetings because of hidden clients … trying to influence the process,” Minnesota Public Utilities Commission staff member Hwikwon Ham said. “I am biased towards the state regulatory sectors and the Minnesota commission. I do not deny this. I want the same of others so I can interpret their opinion in certain matters.”

Elliott said consultants could be bound to nondisclosure agreements. Such consultants also could be representing just one MISO stakeholder or several, she said.

The committee would schedule time at its March 25 meeting during MISO Board Week in New Orleans for a deeper discussion on the issue, Elliott said.

— Amanda Durish Cook

February 23, 2020

Study Gauges Reliability Benefits of EIM Day-ahead

By Robert Mullin

SEATTLE — Preliminary findings from a Western Electricity Coordinating Council study indicate that inclusion of day-ahead trading in the Energy Imbalance Market will yield reliability benefits that outweigh any expected risks for the Western Interconnection.

Among the benefits: increased coordination across a broader geographic area; uniform application of advanced scheduling processes over multiple balancing authority areas; and improved positioning of resources for real-time operations.

The working group developing the study shared its initial impressions Wednesday at a meeting of WECC’s Market Interface Committee (MIC).

Working group member Alaine Ginocchio, a policy analyst with the Western Interstate Energy Board, explained the report will be tightly focused on providing a “qualitative” assessment of the reliability impact of incorporating CAISO’s proposed extended day-ahead market (EDAM) into the EIM. It will not examine potential economic benefits or cost savings from the change, she said.

“We’re going to describe changes in the day-ahead processes and the potential impact those processes could have on reliability,” Ginocchio said. The group is examining reliability impacts through the lens of operations; ancillary services; resource sufficiency; transmission and seams operations; and congestion management.

EIM day-ahead — More than 30 people attended the WECC Market Interface Committee’s Feb. 19 meeting in Seattle. | © *RTO Insider*

The report’s analysis assumes that existing BAA boundaries and NERC-related responsibilities will remain intact and that CAISO will not take control of transmission facilities. It also assumes that integrated resource planning, resource adequacy procurement, and transmission planning and investment decisions will continue to fall to individual BAAs and their state and local regulators.

Ginocchio said the intended audience for the report is state policymakers, utility regulators and WECC’s Board of Directors. “You are not our target audience,” she told MIC members.

And she offered one important caveat: The report will be released before the conclusion of CAISO’s EDAM stakeholder initiative, which will not even produce a straw proposal until late March.

“We’re out ahead of the market design here,” Ginocchio said, clarifying that the working group has no special insights into what the ISO will produce from the EDAM initiative.

“We didn’t want there to be confusion as we go through this that somehow we have some inside information about what the potential design is and that’s what we’re analyzing. We do feel like there’s enough public information right now to make some high-level assumptions about this market framework,” she said.

Those assumptions include:

Participation in the day-ahead market will be voluntary for EIM participants.
The market will rely on security-constrained unit commitment, a full network model and LMPs.
Ancillary services will be offered in the market along with energy.
A resource sufficiency evaluation will be required before trading in the market, although the report will make no assumptions about the design of the test.
The EDAM will operate alongside the existing bilateral day-ahead market.
CAISO will not be offering a centralized capacity market.

Paradigm Shift

Jason Smith, senior manager of operations at Xcel Energy and a participant in the study, told the MIC the WECC report will go into “good detail” about the three trading “paradigms” currently in play in the West: a highly centralized CAISO, EIM BAAs and non-EIM BAAs.

“The things that the three types of BAAs are doing [before real-time commitment] are really the same process at a high level,” Smith said.

Before committing units, he said, “you’ve got to assess the situation depending on what your constraints are going to be,” including transmission limits, ancillary service obligations, load, and physical requirements for firming up variable energy resources.

A number of factors go into the decisions, including the cost of buying power in the market versus self-supply, opportunities to sell and market positioning.

“And we don’t just make those decisions in the day-ahead and send those guys home. It’s fully reoptimized in any of those scenarios all the way up until real time,” Smith said.

CAISO’s centralized market provides the benefit of coordinated submission of unit data and a single decision-maker dispatching across a wide area. And the ISO requires a lot more unit-specific data compared with the bilateral market, including resource commitment details and transmission availability. “All that information has to come into the market operator in sufficiently advanced time so those decisions can be made,” Smith said.

“There’s a lot of scrutiny on the data when we make it financially binding. I’ve always said, once you make the data financially impactful, the data seems to get better really quickly,” he said.

Smith said the working group had some difficulty in pinpointing the EDAM’s potential reliability benefits around transmission coordination.

“In going through this report, we found it was very, very difficult to carve reliability versus economic benefits.

“We would discuss that what are we doing in the day-ahead [is] … reducing [commitment] down to an efficient level,” he said. “Efficient means less resources online, so is that an economic benefit or a reliability benefit?”

But some reliability benefits are readily apparent, including better positioning for real time and improved visibility across the system, helping BAAs avoid “committing their own resources in a vacuum.”

An EIM day-ahead market could also reduce the region’s deployment of flexible resources needed to firm up the output from variable renewable resources.

“We use a phrase: ‘complementary diversity.’ That’s just reflecting solar decreasing in the afternoon as wind is starting to increase,” Smith said.

Risk/Benefit Trade-off?

But the study also points to possible risks, including the development of new seams between different market footprints. That could lead to a breakdown in communication and coordination as utilities inside and outside the EIM unknowingly vie for the same resources.

“We can’t have two entities looking at the same transmission capability and deciding that it’s available for use in the day-ahead. That has to be coordinated,” Smith said. “And congestion management is going to fall out of that. That has to be managed between and across seams.”

Smith also pointed to the working group’s concern about how EIM day-ahead scheduling will allow participating transmission operators to push transmission lines to the edge of their capacity.

“There are probably going to be parts of the transmission system that are run all the way up to their limits. Depending on your point of view, do you consider that a benefit or a risk?” Smith asked. “I mean, we’re more fully utilizing it, but yet we’re staying below any reliability considerations. Economically, that’s pretty apparent, but on the reliability side, it can get a little more gray.”

The same goes for changes that will tighten up the resource commitment process.

“You [currently] have a bunch of entities committing inefficiently, which may lead to excess capacity on the system at a given time,” Smith said. “How much reliability benefit has that given us? How much cushion has that been giving us that we’re going to decide — on an economic basis — to kind of give away?”

MIC member Raj Hundal, market policy and practices manager with Powerex, asked Smith to elaborate on the benefit of improved positioning in unit commitment. “Is that not occurring with the [reliability coordinators] right now? Are they not positioning themselves, or are they not seeing something there that’s going to be different?” he asked.

Smith said the role of the RCs is to keep BAAs “between the digits so you can get out of a problem,” not to minimize the system cost impacts of congestion. “They’re just there to ensure that the congestion can be resolved,” whereas an EIM day-ahead process will position the system so that the operator will have to mover fewer units “out of the way” in real time, he said.

“When we say better positioning in the real-time, there is definitely an economic aspect to that,” he said.

Illiquidity Trap

The study points to another likely risk: reduced liquidity in the region’s bilateral day-ahead market. A similar development has already occurred in the real-time bilateral market as more Western BAAs have joined the EIM, compelling others to sign up. (See EIM Entrants Cite Changing West as Motivation for Joining.)

Andrew Meyers, a public utility specialist on the Bonneville Power Administration’s trading floor, said the study assumes that EIM day-ahead market participants will turn over the day-ahead unit commitments to CAISO.

“As a result of that, we believe you’ll see a natural reduction in day-ahead, physical, bilateral activity as entities join the EIM plus [day-ahead],” creating “different pools of liquidity in the day-ahead arena” and leaving non-EIM entities to trade only among themselves.

And while Meyers said it would be “premature” to say what type of resource sufficiency test CAISO will perform to prevent EIM entities from leaning on each other in the day-ahead market, the working group anticipates there will be some sort of sufficiency check.

“We think entities failing resource sufficiency would be seeking supply to become resource sufficient … by going out to that bilateral pool. If that’s only a few folks or a small number, it may be more challenging for folks to be successful for grabbing the energy that they were hoping to locate,” Meyers said.

“As a part of a BA, and somebody without a huge amount of resources ourselves … I think it would be a problem for us, especially in a day-ahead market when we may have limits to the contracts we have now,” said MIC member Mike Shapley, a short-term power trader with Snohomish Public Utility District, which sits within the BPA BAA.

“I believe you have valid concerns,” said working group member Robert Follini, manager of preschedule and real-time trading at Avista. “It’s going to be something you’re going to have to go to your company with and see how you will position yourself.”

Ginocchio said the working group plans to post a draft of the EDAM report to the WECC website in mid-March. The final report should be released in late May.