Page 998 – RTO Insider

January 12, 2021

‘Participant Funding’ Violates FPA, Grid Groups Say

RTO policies assigning most costs of large network upgrades to interconnection customers violate FERC’s “beneficiary pays” principle and are no longer just and reasonable, renewable advocates said in a new report.

The report by the American Council on Renewable Energy and Americans for a Clean Energy Grid (ACEG) contends that the “participant funding” policy under FERC Order 2003 is “obsolete” and is hampering the transmission expansion needed to accommodate growing renewable generation.

Before the 2003 order, FERC required generators to pay 100% of “interconnection facilities” needed to establish the connection between the generator and the transmission network. The costs of “network facilities” — those at or beyond the point of interconnection needed to address stability and short-circuit issues — were initially funded by the generator but repaid through transmission credits. Order 2003 ended the crediting, which critics said diminished the incentive for interconnection customers to make efficient siting decisions.

The report’s authors said the order worked for gas-fired generation, which can interconnect in locations that avoid transmission constraints. “Transmission planning is less important with gas generation, as locational wholesale market prices and network upgrade costs assigned to interconnecting generators are able to direct gas generation investment to economically efficient locations,” they said.

But the authors said the policy doesn’t work for location-constrained wind and solar generation that now dominate interconnection queues. “Wind turbines located near the best wind resources are several times more productive than wind turbines at a typical site selected at random, while the best solar resource sites are about twice as productive as less optimal sites,” the authors said. “Wind and solar are also scalable and benefit from economies of scale, so most projects are large and built in remote areas where large amounts of land are available at low cost. As a result, these renewable projects often require larger transmission upgrades to serve load.”

Free Riders

The report contends the policy violates the Federal Power Act and results in “inefficiently small upgrades, raising costs to consumers.”

However, Rob Gramlich, executive director of ACEG and one of the authors of the report, said the two organizations have no plans to make a formal complaint to FERC. “We plan to issue another report in a week or so with what we think the real solution is — a comprehensive transmission planning rule,” he said. “It has been 10 years since the last such rule, Order 1000, which followed [Orders] 890 and 2000. ACEG will be sharing ideas broadly and hoping to stimulate discussion.”

The current policy means that after one project is assigned high-cost network upgrades, subsequent projects could use the additional capacity created without paying a fair share for the improvements. “Project developers, knowing there was a chance of getting lucky with a lower network upgrade cost assignment, had an incentive to enter multiple project proposals and multiple locations,” the report said. “Thus, many projects would enter queues, and many projects would cancel, leading to a cycle of continuous churn.”

Increasing Costs

In the past, interconnection charges for new renewables represented less than 10% of renewables projects’ total cost. Now, however, interconnection costs have risen so much they can represent 50% or more of project costs, according to the report.

“The system has reached a breaking point recently as spare transmission has been used up. Presently in most regions, new network capacity is needed for almost all of the projects in the queues,” it said. “When an increasing amount of location-constrained generation applies for interconnection in the same area, the grid begins to require not only ‘driveway’ type transmission facilities, but also bigger roads and highways. … What we are observing is that interconnection studies for individual generators (or groups of generators) are increasingly identifying costly regional upgrades.”

Participant Funding — Heat map shows MISO’s net first contingency incremental transfer capability (FCITC) as of 2016. Most of western MISO had an estimated deficit of 5 GW or more of transfer capacity to the rest of the region. “This means that at least that amount of transmission capacity must be constructed across MISO and into the PJM region before any new generation can be added,” says a report by ACORE and ACEG. | *MISO*

The authors cited research from Lawrence Berkeley National Laboratory that they said show that costs to integrate new generation “have reached levels that are unreasonably high for a developer to proceed in MISO and PJM.”

After Order 2003, MISO required generation owners to pay 100% of costs of network upgrades for lines below 345 kV and 90% for those above 345 kV. Wind projects in MISO, which historically paid about $66/kW to interconnect, are now being billed at $317/kW, five times as high.

MISO reported last year that it needs network upgrades exceeding $3 billion to accommodate the initial queue volume in its West region, a trend it expects to also hit its Central and South regions. (See MISO West Risks Becoming ‘Dead Zone,’ Stakeholders Warn.)

In PJM, interconnection costs for wind projects has risen to $54/kW from $19/kW while that for solar has more than doubled to $132/kW, from $62/kW. In 2019, a 120-MW solar-plus-storage project in southern Virginia was told it would face as much as $1.5 billion ($12,086/kW) in system upgrades, including the demolition and rebuilding of several 500-kV lines.

“The construction of large transmission lines required by some interconnection studies, which leads to such high network upgrade costs, are not isolated incidents,” the report said. “A number of offshore wind projects in PJM, for example, are expected to build long, 500-kV lines that are clearly network elements that benefit the entire region and should be planned and paid for through the regional planning process.”

Order 2003 allowed participant funding only in RTO and ISOs territories. In non-RTO areas, “where transmission upgrade costs are rolled into rates for all users, we do not find evidence of similar problems,” the report said.

Planning Reforms Needed

The authors said RTOs’ “siloed” transmission study processes, which consider reliability, economic and public policy transmission projects separately because of their different cost allocation methods, result “in a race that no one wants to win, as it will result in them bearing the cost for the transmission upgrades.”

“Each group of stakeholders attempts to free ride on other groups of stakeholders by failing to plan transmission that they would have to pay for, in the hope another group of stakeholders will plan and pay for it. Unfortunately, the typical result is that nobody builds the transmission, and all customers suffer from increased congested and reduced reliability.”

“Cluster” studies that analyze groups of generators simultaneously are an improvement, the authors said, but are limited because they consider only what is in the current queue. The report called for “proactive” transmission planning like the Competitive Renewable Energy Zones (CREZ) in ERCOT, Multi-Value Projects in MISO and priority projects in SPP that incorporate assumptions about wind and solar development and can maximize economic and reliability benefits.

January 12, 2021

Report Outlines NEPOOL ‘Pathways’ to a Future Grid

A new report explores ways for New England to overcome the growing conflicts between states’ clean energy goals and the functioning of ISO-NE wholesale markets.

The “Pathways to the Future Grid Process” report, part of New England’s Future Grid Initiative, focuses on four approaches that could potentially smooth tensions between the states and RTO. It was presented to the NEPOOL Participants Committee last week.

The New England States Committee on Electricity, ISO-NE and NEPOOL commissioned Rutgers University Professor Frank Felder to review “a multitude of potential pathways” for resolving differences and assess tradeoffs “between achieving the clean energy policy objectives of the New England states and maximizing the benefit of efficient, regional wholesale markets.”

Felder identified four approaches that have been thoroughly discussed in more than a dozen presentations to the PC: a Forward Clean Energy Market (FCEM) or Integrated Clean Capacity Market (ICCM), an Energy Only Market (EOM), carbon pricing and alternative resource adequacy constructs (ARACs).

NEPOOL Future Grid — This figure provides a conceptual orientation of the four core pathways across two dimensions, including variations within each identified pathway category. | *NEPOOL*

Felder’s report points to “the importance of defining the criteria for determining the types and quantities of balancing resources needed to reliably plan and operate the regional power grid as the penetration of renewable energy resources increase.”

Most New England states are pursuing aggressive decarbonization. They have goals or policies that envision replacing existing power generation with variable renewable energy resources “whose output is intermittent, and many of these new resources, such as offshore wind, are likely to be at different locations than existing power plants.”

A further challenge for ISO-NE is the minimum offer price rule (MOPR) for new resources bidding into its capacity markets. Although the MOPR addresses potential adverse impacts from out-of-market, state-sponsored contracts on price formation in the competitive wholesale markets, it also prevents state-sponsored resources from clearing the Forward Capacity Market (FCM) and being counted toward the RTO’s resource adequacy requirements.

Felder wrote that New England states “would like to achieve their specific policy objectives cost-effectively, whereas wholesale electricity markets are designed to maximize economic efficiency.

“Although there is some substantial overlap between the states’ objectives of decarbonization and environmental enhancements, economic development, and political acceptability, and the objective of efficient, regional wholesale electricity markets, these objectives are not necessarily reconcilable.”

Comparing Pathways

Felder said the four pathways cut across two comparative frameworks: regional vs. state-specific measures and planning vs. markets. For example, carbon pricing and EOM represent pathways consisting of regional measures paired with a market-based solution. Planning refers to the process of states setting types, quantities and timing of clean energy investments, whether through specific mandates or market mechanisms. By that description, FCEM, ICCM and ARACs are more planning-based than carbon pricing and EOM.

Of the pathways identified, FCEM, ICCM and carbon pricing are primarily directed at reducing greenhouse gas emissions. EOM and ARACs are different ways to provide resource adequacy, although some ARACs are directed at advancing or supporting states’ clean energy objectives.

Both carbon pricing and EOM pathways rely on short-term, wholesale energy prices — augmented by longer-term forward bilateral markets — to drive capital investment decisions. The FCEM and certain ARACs provide longer-term commitments as part of their constructs. However, the report warned that stakeholders should carefully consider whether these constructs would withstand FERC Orders End to ISO-NE Capacity Price Locks.)

More on Carbon Pricing

The report explores alternatives to using FCEM or ICCM to acquire clean energy resources via regional market mechanisms. One alternative would supplement the Regional Greenhouse Gas Initiative (RGGI) carbon price with an additional regional carbon cost, a move favored by ISO-NE and adamantly opposed by the states. This could be achieved through net carbon pricing, which would require agreeing on a social cost of carbon, subtracting the RGGI price, having ISO-NE charge emitting generators the resulting additional cost of carbon, and rebating the carbon revenue back to load-serving entities. Net carbon pricing mitigates — but doesn’t necessarily solve — the double payment issue that arises when clean resources earn payments from both subsidies and market revenue. It also reduces the states’ ability to control the specific timing and type of clean energy resources to meet their individual policy objectives. And it also fails to explicitly address the balancing resource issue.

Though it is not mentioned in Felder’s report, Connecticut, Massachusetts, Rhode Island and D.C. last month signed a memorandum of understanding to launch the Transportation and Climate Initiative Program (TCI-P), which aims to cut GHG emissions from vehicles by 26% from 2022 to 2032. A cap-and-invest program like RGGI, TCI-P is another step away from carbon pricing in three New England states. (See NE States, DC Sign MOU to Cut Transportation Pollution.)

The report is available for comment until Jan. 22, and all comments will be publicly posted on the NEPOOL website. Felder concluded that detailed evaluations of the pathways will be necessary in 2021, including potential quantitative analysis, which will require greater specificity regarding design and the interaction with other regional policies such as transmission planning.

January 12, 2021

Members Endorse Charter for PJM PIEOUG

Members of PJM’s Public Interest and Environmental Organizations User Group (PIEOUG) last week unanimously endorsed a new charter for the stakeholder body, formalizing its structure and expanding its scope.

The PIEOUG, which includes consumer advocates and representatives of public interest and environmental organizations, has been a longstanding group within the RTO that typically holds discussions with the PJM Board of Managers at the RTO’s annual meeting in May. (See Advocates Challenge PJM Board on Exelon, FE.)

PJM PIEOUG — Greg Poulos, CAPS | © *RTO Insider*

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said members have long discussed having the group take on a larger role within PJM and to serve as a more active entity.

Poulos said it’s been “quite a process” to assemble the charter, working with the interested stakeholders and PJM.

“We’ve tried to move this along over the last year or maybe longer,” he said. “The charter will help us in communications.”

Poulos described several core parts of the charter, including five principles for the purpose of convening the PIEOUG:

providing an open forum for discussion of policy issues that are pertinent to the PJM region and to the members of this group;
addressing PJM policy issues, actions and recommendations that PIEOUG members find important;
providing access to the PJM stakeholder process for organizations not eligible for membership;
providing a venue for PJM staff to educate and solicit input from the environmental and public interest community; and
organizing environmental and public interest group communications with the PJM Board and RTO members.

Poulos highlighted the charter’s inclusion of two chair positions — one representing environmental and public interest organizations and another for consumer advocates. Each chair must be a representative of a PIEOUG member and will serve a one-year term. A secretary will also serve a one-year term.

William Fields of the Maryland Office of People’s Counsel and Tom Rutigliano of the Natural Resources Defense Council currently serve as co-chairs of the PIEOUG. Poulos said PIEOUG members will elect new chairs at the group’s next meeting.

The charter also requires the two chairs to alternate presiding over meetings. Meeting protocol will be generally informal, he said, but Robert’s Rules of Order will be followed when necessary. A quorum will consist of no fewer than 10 members.

PIEOUG membership is open to “bona fide” environmental organizations and other public interest groups, including the consumer advocates of the PJM states.

The charter lays out organizations that are ineligible for PIEOUG membership, including:

PJM Members, other than consumer advocates;
any organization eligible for PJM membership, except consumer advocates, CAPS members and those who are eligible for membership in the end-use customer sector or as an affiliate member only as an incidental result of their status as a retail electric consumer;
organizations substantially funded by a PJM member, and;
organizations whose primary mission is furthering the interests of other PJM members, except CAPS.

PIEOUG meetings will still be open to ineligible groups and the general public, although they will not be able to participate.

Fields said he was hopeful the PIEOUG would have a greater impact in PJM’s stakeholder process and bring forward environmental and state issues for discussion and action.

“I think it’s great that we have a charter, and hopefully this group will be able to move forward and make some good progress on issues,” Fields said.

January 12, 2021

Cuomo Outlines Green Path for New York in 2021

New York Gov. Andrew Cuomo presented a seven-point overview of government priorities in his State of the State address Monday, ranking the transition to a green economy number five after defeating the pandemic and meeting its associated challenges.

“We will launch the most aggressive green economy program in the country,” Cuomo said.

State officials last July announced New York’s largest-ever package of renewable energy solicitations, seeking a combined 4 GW of offshore wind, onshore wind and solar power. (See NY Announces 4 GW in Clean Energy RFPs.)

New York Green energy — An offshore wind turbine maintenance platform is shown as part of Gov. Andrew Cuomo’s State of the State address. | *NYDPS*

The governor promised in the coming days to give three separate and more detailed descriptions of his program for the state. The priorities include:

defeating the coronavirus pandemic;
increasing the pace of vaccinations;
dealing with the short-term economic crisis;
planning the economic resurgence;
seizing the opportunity to make New York the leader in a green economy;
capitalizing on the changes, i.e., with clean energy jobs; and
addressing systemic injustices of inequity, racism and social abuse.

Green Energy Capital

“What will we make of this moment? Will we move forward, or will we move backward?” Cuomo said of the many challenges facing New York.

Climate change is the existential threat, he said.

“New York will be the green energy capital of the world,” Cuomo said. “We will not only construct renewable projects, we will develop manufacturing capacity, research and development expertise and state-of-the-art worker retraining, all here in New York, and we will do it this year.”

The day before, Cuomo announced a proposal to prohibit utility disconnections under any state of emergency and will propose legislation to ensure the availability of electric and other utility services to all New Yorkers. Utilities that fail to comply will be subject to penalties.

“In a year in which we dealt with an unprecedented pandemic, ferocious storms added insult to injury by knocking out power for hundreds of thousands of New Yorkers,” the governor said. “Utility companies provide essential services, and we need to make sure they continue to provide them, rain or shine. That’s why we’re proposing legislation to make sure that New Yorkers, especially those living in regions under states of emergency, have access to these critical services to provide for themselves and their families.” (See “Utilities Must ‘Show Cause’ on Isaias Response,” NYPSC OKs First Rate Increases Since COVID Outbreak.)

Economic Justice

Unlike other states, New York had no notice and no time to prepare for the spread of COVID-19, Cuomo said.

“As soon as we found out, the COVID enemy was already amongst us and had been coming for months,” he said. “We just saw the same federal negligence reenacted when it failed to test travelers from the U.K., where a new strain of the virus had been detected. The United States did nothing, even though 120 other countries had already acted.

“New Yorkers were called on to flatten the curve created by federal failure,” he continued. “New Yorkers cannot now be asked to pay the financial bill for federal incompetence. New Yorkers already paid too high a cost.”

The pandemic is a national crisis rather than a state or regional one, but the federal government delegated authority to the governors without providing the resources, he said.

“Washington passed the buck without passing the bucks,” Cuomo said. “And again in December, Congress failed this nation when it failed to pass state and local financing during the last legislative session. This is a national challenge; it is a war, and like every war before, it must be financed by Washington. If the federal government needs revenue, it should raise income taxes on the wealthy to finance the states’ resurgence from this national devastation. That is basic economic justice — and economic prudence.”

January 12, 2021

Calif. Governor Proposes $1.5 Billion for ZEVs

California Gov. Gavin Newsom proposed investing more than $1.5 billion in zero-emission vehicles to accelerate their adoption as part of his $227 billion budget plan released Friday.

Newsom’s proposed budget for fiscal year 2021-22 would allocate $1 billion to ZEV infrastructure, including charging and fueling stations for battery powered electric vehicles and hydrogen fuel cell electric vehicles (FCEVs).

The spending plan calls for securitizing revenues from vehicle registration fees to support the expansion of the California Energy Commission’s Clean Transportation Program. A portion of the proceeds would fund loans “to leverage additional private sector capital to build the necessary infrastructure,” the governor’s office said in its summary of the plan.

Another Newsom budget provision would allocate $465 million in one-time cap-and-trade funds for incentives, rebates and financial assistance “to improve access to new and used zero-emission vehicles,” including heavy-duty equipment and buses, it said. The plan would put $50 million toward the installation of ZEV charging stations at state-owned facilities.

The huge cash infusion is meant to help the state meet Newsom’s order in September that all new passenger cars sold in the state must be emissions-free by 2035 and that all new medium- and heavy-duty vehicles sold in the state must be ZEVs by 2045.

California ZEVs — Part of the $1.5 billion proposed by the governor would fund hydrogen fueling stations, as seen in a rendering. | *Iwatani Corp. of America*

It comes on top of hundreds of millions of dollars already invested by the state to bolster ZEV adoption.

The Energy Commission (CEC), for example, allocated $116 million for hydrogen fueling stations in December. And in August, the California Public Utilities Commission authorized $437 million to fund the installation of 38,000 charging ports for EVs through Southern California Edison. (See CPUC OKs 1.2 GW of Storage by 2021, 38,000 EV Chargers.)

To meet Newsom’s mandate — and to comply with a 2018 executive order by former Gov. Jerry Brown of having 5 million EVs on the road by 2030 — the state needs to install millions of chargers and double its pace of electric vehicle sales, researchers told the CEC in August. (See California Needs Huge Number of EV Chargers.)

The proposed funding would boost the scale of ZEV adoption and allow lower-income residents to drive EVs, the budget summary says.

“A focus on equity prioritizes public investments in communities suffering most from a combination of economic, health and environmental burdens,” it states. “A focus on scale brings down the transition cost, accelerates private capital investment and reduces the need for direct public investment.”

The plan also recommends doing away with property taxes for ten years on new ZEV charging stations completed by Jan. 1, 2024.

The California Hydrogen Coalition, among others, praised the governor’s plan, saying its “recommendations for hydrogen infrastructure are an important investment in this practical, zero emission technology.”

Newsom’s plan will be subject to revisions in May and needs approval from the heavily Democratic state legislature by June 15.

January 12, 2021January 21, 2024

Summer Readiness Sought by CAISO, CPUC

CAISO and the California Public Utilities Commission entered the new year trying to get ready for summer and avoid the shortfalls and rolling blackouts that plagued the state in August and September.

The CPUC on Friday proposed ordering the state’s three big investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to contract for additional “incremental” capacity that can be ready this summer to meet heavy demand.

On Wednesday, CAISO held a meeting on the schedule and scope of a series of upcoming sessions to address “market enhancements for summer 2021 readiness.” Substantive meetings are scheduled to begin this week, with topics that include export and load scheduling priorities and resource sufficiency in the ISO’s interstate Western Energy Imbalance Market.

In the first week of 2021, CAISO conducted three days of meetings on its Resource Adequacy Enhancements stakeholder initiative, which started in 2018 but took on new urgency after last summer’s energy emergencies.

The ISO and stakeholders weighed a final draft proposal on the first phase of RA enhancements and a six-time-revised straw proposal on the initiative’s second phase. Items under discussion include RA import requirements, activating storage resources and rules on planned generator outages.

CAISO’s Board of Governors is scheduled to vote on the phase-one changes in March and on phase two in May and September

The ISO proceedings address issues raised in the preliminary root-cause analysis of the blackouts on Aug. 14-15 that affected more than 1 million residents during a severe heat wave that encompassed the Western U.S. Shortages occurred as solar power waned in the evening and there was insufficient capacity to meet continued high demand from air conditioning.

The October preliminary analysis, and a subsequent report by CAISO’s Department of Market Monitoring, identified problems that included inadequate RA planning, forced outages at power plants, a lack of storage for solar and wind resources, transmission constraints, imports that did not materialize and exports that should not have occurred in strained conditions. (See CAISO Wasn’t Gamed in Blackouts, Watchdog Finds.)

“The most significant and actionable of these factors involve California’s resource adequacy program,” the DMM’s November report said. “To limit the potential for similar conditions in future years, system level resource adequacy requirements should be modified to ensure more capacity is available during net load peak hours,” as solar ramps down but demand stays high.

Supply is tightening across the West as coal and “older baseload” fossil-fuel and nuclear plants retire, CAISO staff members noted during an RA enhancements meeting Wednesday.

“Severe weather events have become more common and have impacted … several BAs at the same time, further tightening system conditions,” said Milos Bosanac, CAISO lead infrastructure and regulatory policy developer. Heat waves could continue to pummel the West in the future and limit imports, Bosanac said in his presentation.

To head off shortfalls, RA imports must be linked to specific generating resources in other states, he said. That is not the situation now. If supply is not connected to a physical source, “it poses a risk to supply not being committed to the CAISO when it matters most, when conditions are tight,” he said.

In addition, the ISO wants firm commitments from transmission owners to prioritize RA imports during times of tight supply. Transmission lines from the Pacific Northwest to California can become nearly maxed-out during heat waves, Bosanac noted.

Much of California’s import RA capacity comes from the Bonneville Power Administration over the California-Oregon AC intertie (COB) and the Nevada-Oregon Border DC Intertie (NOB), he said. Those interties will require the highest guarantee of transmission capacity, he said.

“Looking at particularly the COB and NOB interties, usually on those last legs of those interties … especially in the summer months, flows tend to reach or be very close to the limits of those path, Bosanac said. “[With] a higher likelihood of curtailment … it’s important that these deliveries be on the highest priority transmission service to minimize that risk of curtailment so that those imports can be delivered to the CAISO.”

Some stakeholders question the plan because they worry it could lead to the exercise of market power. (See CAISO Seeks ‘Firm’ Tx for Resource Adequacy.)

During an RA meeting Thursday, Doug Boccignone, a principal at Flynn Resource Consultants representing the California Community Choice Association, said only five parties control half the transmission import capability on COB and NOB.

“The rights are really concentrated,” Boccignone said. “It makes me concerned that if California is dependent on imports from the Northwest to meet the resource adequacy requirements … there’s the potential for those parties that control those rights to be in a much different position than they are today.”

CAISO said there are 21 parties that hold transmission rights on the two interties. Bridget Sparks, infrastructure and regulatory policy developer, said the ISO’s analysis did not show a high risk for the entities to exert market power.

“If we think of the market as COB and NOB combined … there is a slight market concentration, [but] it’s nowhere near a monopolistic control,” Sparks said.

January 12, 2021

SPP Stakeholders Fill Open Committee Positions

SPP’s Corporate Governance Committee last week approved nominations for several open positions on stakeholder groups. The nominations will go before the Board of Directors on Jan. 26 for final approval.

Members selected Sunflower Electric Power’s Al Tamimi and NextEra Energy’s Matt Pawlowski to fill contested open positions on the Finance Committee. Tamimi, a familiar face for years in SPP stakeholder meetings, will represent the transmission-owning (TO) sector and Pawlowski the transmission-using (TU) sector.

SPP Committee — SPP’s Corporate Governance Committee hears from applicants for open committee positions. | *SPP*

The CGC also approved Oklahoma Gas & Electric’s Usha Turner as an investor-owned utility sector representative on the Members Committee. She replaces Greg McAuley, who left OG&E in December to return to his native Florida.

Turner, director of federal and regional policy for the utility, said she has absorbed McAuley’s RTO policy responsibilities into her existing role.

OGE Energy’s Scott Briggs and Arkansas Electric Cooperative’s Maria Bunting Smedley were recommended to fill positions on the Human Resources Committee representing the TO and TU sectors, respectively.

The CGC endorsed Northeast Texas Electric Cooperative CFO Caleb Head as chair of the Credit Practices Working Group.

January 12, 2021

SPP, MISO See $22.8M in M2M Settlements

SPP staff assured stakeholders they are looking into the causes of congestion around the MISO seam following a third straight month of record market-to-market (M2M) settlements.

SPP incurred $22.87 million from MISO in M2M settlements during November, a 56.3% increase from the $14.63 million in October. That mark more than doubled the previous high. (See Record $14.63M M2M Settlement for SPP, MISO.)

“Some of it [the spike in M2M settlements] is a ‘perfect storm’ scenario,” SPP’s Scott Brown told the Seams Steering Committee on Friday. “It was a combination of significant outages in certain areas, increased wind and a low mix of [firm-flow] entitlements [FFEs] in the areas where there is an increased use of the system along the seam.”

FFEs are allocated property rights to the RTOs, with each RTO calculating its real-time usage. The grid operators exchange M2M settlements for redispatch based on the non-monitoring RTO’s market flow in relation to its FFE.

“In general, one of the major causes for these M2M events and settlements is when the wind is high in both SPP and MISO,” said Clint Savoy, the SSC’s staff secretary.

SPP MISO — Market-to-market settlements between SPP and MISO have set records for three straight months. | *SPP*

Ten permanent flowgates were binding for 525 hours, resulting in $11.77 million in M2M settlements, while 36 temporary flowgates bound for 1,612 hours, accounting for $11.1 million in payments.

Pointing to a trouble spot on the western side of the Nebraska-Iowa border, SPP Director of System Planning Casey Cathey reminded the committee that the grid operator identified a potential interregional transmission project in the area last year. It failed to meet MISO’s benefit-to-cost ratio threshold.

The 161-kV Raun-Tekamah permanent flowgate in eastern Nebraska accounted for almost $5 million in settlements to SPP alone, binding for 198 hours. Cathey said the Raun area is one of the highest priorities for SPP’s 2021 Integrated Transmission Planning assessment and the joint transmission study with MISO. (See MISO, SPP Stakeholders Applaud New Joint Study.)

“You look at the locations of the [generator interconnection] queue for SPP and the locations of the queue for MISO, and intuitively, without running any studies, you understand that unless we build bigger pipes — more transmission — [the Raun area’s congestion] is going to continue,” Cathey said.

“It’s not going to drop down, but I don’t know that the magnitude will be as high for a sustainable period,” he said. “There’s nothing in the works that alleviates this congested area. The trend will continue, just not to that magnitude.”

Cathey hopes the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT), which has been tasked with reviewing and possibly combining SPP’s seven different transmission planning processes, will be able to relieve some of the pressures on the grid. (See “SPC Takes Look at Tx Planning,” SPP Briefs: Week of Aug. 31, 2020.)

“All these different business functions operate on different timelines and for different reasons. I’m not saying it’s broken, but this is what happens,” he said. “That’s the big part of what we’re trying to do with SCRIPT and consolidation.”

SPP has piled up $140.23 million in settlements from MISO since the two grid operators began the M2M process. Under the process, the monitoring and non-monitoring RTOs manage M2M constraints by exchanging shadow prices and other information to ensure that the RTO with the more economic dispatch addresses flows. The shadow price indicates the marginal value of an additional increment of relief on a congested constraint in reducing the total production costs.

M2M settlements have been in SPP’s favor 13 of the last 14 months and 52 times in 69 months since the process began in 2015. The top 10 constrained flowgates since the process began all have MISO paying SPP, staff said.

SSC Supports Affected-system Studies

The SSC told staff it would approve a proposal to revise the queue priority for transmission projects in affected-systems studies with seams neighbors, but only if they are applied to all neighboring grid operators.

A majority of stakeholders in a snap poll during Friday’s webinar said they would support Associated Electric Cooperative Inc.’s (AECI) proposal to establish a relative queue priority for study requests between the cooperative and AECI.

Only three of the 15 respondents to the poll said they would not support AECI’s proposal.

Staff are also gathering feedback from the Generation Interconnection Users Forum.

SPP uses the studies to determine non-jurisdictional and neighboring interconnection requests’ effects on its transmission system. The studies take into account interconnection requests on neighboring grids, including those of AECI, MISO, Minnkota Power Cooperative and NorthWestern Energy.

January 12, 2021

PJM, States Exploring 6 Scenarios in OSW Tx Study

PJM and state officials seeking the most efficient way to integrate more than 12 GW of offshore wind generation have identified six scenarios for analysis in a study expected to produce results after mid-2021, the RTO told the Transmission Expansion Advisory Committee Wednesday.

The Offshore Transmission Study Group, which was created in response to a request by the Organization of PJM States Inc., developed the scenarios during five meetings since October 2020, Matthew Bernstein, PJM analyst for state policy solutions, told the TEAC. PJM staff also held one-on-one meetings with individual states, he said.

The scenarios will consider the magnitude, points of interconnection and timing of OSW injections for both announced and planned projects. The analyses will also consider the impact of generator deactivations and states’ clean energy goals, Bernstein said.

PJM may study additional scenarios based on the initial study findings and feedback from the states, he continued.

Within PJM, New Jersey (6.4 GW), Virginia (5.2 GW) and Maryland (1.2 GW) have announced OSW goals.

Bernstein said the analyses are directed at upgrades that will be necessary for the onshore system and will not consider offshore infrastructure such as a mesh network grid or collector stations.

“We’re looking at what these different offshore wind injections are going to do to the onshore system,” Bernstein said. “We’re still in the process of developing these scenarios and have not begun the actual analysis itself.”

Stakeholder Questions

PJM OSW — Theodore Paradise, Anbaric | © *RTO Insider*

Theodore Paradise, senior vice president of transmission strategy for Anbaric Development Partners, asked how the modeling efforts relate to the New Jersey Board of Public Utilities’ request in November that PJM integrate the state’s OSW goals into the RTO’s Regional Transmission Expansion Plan. New Jersey’s request made it the first state to embrace the state agreement approach under FERC Order 1000, which allows states to fund transmission projects needed to meet public policy needs.

PJM expects to open a competitive solicitation window including New Jersey’s request in the first quarter of 2021. (See NJ Asks PJM to Seek Bids for OSW Tx.)

Bernstein said the assumptions and analysis of the onshore component developed in response to New Jersey’s request will be incorporated into the study.

“You can look at this as incorporating the other states’ offshore wind objectives around what we’ve already done with New Jersey as part of a larger collaborative effort,” he said.

Sharon Segner, vice president of LS Power, said the goal of having a more active public policy planning process is “really encouraging.” Segner asked if PJM anticipates the scenarios will be made public before the results are produced.

Bernstein said it is “too early” to tell what will be made available to stakeholders and when. He said the scenarios will be described in the final report.

Segner said PJM’s presentation made it seem as if the RTO was attempting to identify regional transmission solutions to accommodate states’ OSW goals. She said typically in these types of scenarios, each would be put into the planning windows and the parties would be developing and proposing regional transmission solutions.

“I’m not completely understanding how this fits into the process,” Segner said. “It sounds like an interesting development, but I’m just trying to put the pieces together.”

Mark Sims, PJM’s manager of infrastructure coordination, said Segner was jumping a bit too far ahead in the process. Sims said there’s still education that needs to be completed on the issue before PJM decides how to implement the potential solutions a state decides to move forward with.

Sims said the goal is to identify what the states want to accomplish, develop assumptions, run the studies and give information on possible results.

“If any state or group of states decides to move forward, we envision that’s when the competitive process would play a role,” he said.

January 12, 2021November 6, 2023

MISO Questions VOLL Pricing During Abnormal Events

More than four months after Hurricane Laura’s landfall in its South region, MISO is questioning whether its value-of-lost load (VOLL) should be used to price energy during extraordinary weather events.

During a Market Subcommittee teleconference last week, Director of Market Design Kevin Vannoy solicited stakeholder opinions as to whether the RTO’s $3,500/MWh VOLL pricing is appropriate during force majeure events.

“What should the market reflect when we take actions to manage transmission, balance the system, balance the region?” Vannoy asked stakeholders during the call Jan. 7.

Vannoy also asked whether MISO’s pricing logic for dead buses should be reviewed. Stakeholders have until Jan. 28 to submit their feedback.

MISO’s Independent Market Monitor continued its call for a retroactive pricing change for the dead buses priced at VOLL in Hurricane Laura’s wake. (See “Laura Pricing in Question,” MISO Monitor Reviews Blustery Fall.)

The Monitor’s David Patton said MISO’s after-the-fact settlements produced $90 million in balancing congestion costs, which showed up on customer bills as uplift charges. He said approximately $10 million of the cost was because of dead-bus pricing at $3,500/MWh in Louisiana’s Lake Charles area, where Hurricane Laura destroyed enough distribution and transmission lines to effectively create a dead zone.

“We’re concerned about some of these settlements applying the VOLL pricing to dead buses,” Patton said. “Load is not being served because the system effectively doesn’t exist to serve it. The load is not being served because we lack sufficient resources to serve it. The load is not being served because the system is demolished.”

He went on to say MISO’s VOLL settlements near Lake Charles for Aug. 27 are “not consistent with how MISO settles dead buses in the day-ahead market, which would price such a load zone at basically $20/MWh.”

MISO’s day-ahead dead-bus pricing relies on prices from nearby live buses.

“That’s what the Tariff calls for,” Patton said.

Vannoy said an evaluation of MISO’s pricing practices at dead buses will likely be rolled into MISO’s existing scarcity pricing reconsideration, which was already poised to bring changes to the VOLL and operating reserve demand curve. (See MISO Revisits Scarcity Pricing Rethink.)

The grid operator is hosting a workshop on the scarcity price effort on Jan. 22.

Market participants impacted by Hurricane Laura had until December to initiate a settlement dispute with MISO. The RTO is now in confidential discussions over the disputes.

Customized Energy Solutions’ Ted Kuhn asked whether MISO should pause collections on some Hurricane Laura-induced settlements until it determines whether VOLL pricing should apply to the event.

“What if we did that rather than everyone having to scramble and file legal briefs, so their rights are protected?” he asked.

Vannoy said he wouldn’t comment on the Aug. 27 retroactive settlements. “I think the goal here is to look at future modifications and future event applications,” he explained.

Laura Rauch, MISO’s director of settlements, said if settlement changes are granted after dispute resolution, other affected market participants will be notified and invited to final discussions to hear the outcome.

“The Tariff is very clear that changes to historic settlements require disputes submitted in a timely manner,” Rauch said. “To the extent that we make a determination that the historic settlements need modification, we’ll review that for all impacted market participants.”

MISO Corporate Counsel Jacob Krouse added that affected market participants can challenge the RTO’s determinations even if they haven’t filed dispute resolutions.

Patton said the hurricane’s devastation might have been minimized if MISO had specifically assigned capacity to load.

“The South is one of the worst problems in this regard. In the Midwest region, we don’t have as big a problem with this disconnect,” he said, adding that load pockets in Louisiana and Texas are limited by transmission constraints.

“The capacity values do not correspond to the load pockets. It’s all merged together,” he said. “This might not have happened … if we defined our loads better.”