SPP told stakeholders last week that it has chosen a hybrid approach to improve its transmission- and congestion-hedging markets, focusing first on equitably allocating congestion rights instruments and then increasing the pool of awards available.

The proposal marks a change in direction from the initial focus on counterflow optimization. Stakeholders were unable to coalesce around the market mechanism despite three years of effort.

The SPP Board of Directors in April directed staff to survey members, the regulatory stakeholder groups and the RTO’s Market Monitoring Unit (MMU), gather feedback, and bring a final recommendation to the board’s October meeting. (See “Counterflow Optimization not Dead Yet,” SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)

Staff will bring a proposal to the board later this month, but they will also ask that a vote be delayed until the directors meet again in January. That will give the board and state regulators an opportunity to provide the policy direction that will go into developing tariff changes. It will also give staff more time to build stakeholder support for the proposal and gather additional feedback.

“I know the board values input from the members, but we feel that this is taking a look at the entire picture and not just focusing on one thing,” COO Lanny Nickell told the Markets and Operations Policy Committee Oct. 10. “We feel pretty confident and pretty good on the direction where we’re going.”

Micha Bailey, SPP | © RTO Insider LLC

Nickell complimented staff for their recent work “to get some movement on resolving the concerns and issues around the congestion-hedging process.” Congestion-hedging supervisor Micha Bailey said staff talked with stakeholders who provided input to gain a deeper understanding of their concerns.

“We kept hearing some of the same themes … Fair, transparent, equitable, needs to provide a hedge. And as we looked at those and as we were hearing the same common themes, we wondered, ‘What can staff propose?’” Bailey said. “What can we propose that’s going to help SPP today and also in the future, recognizing that generation is changing.”

Bailey said “hybrid” was the new buzzword, replacing counterflow optimization. That market mechanism, which keeps system transmission flows between two points in balance, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency. (See SPP Continues its Counterflow Optimization Work.)

The hybrid proposal will increase the number of hedges available as the Holistic Integrated Tariff Team intended when it approved a package of 21 improvements to the SPP grid in 2019, Bailey said.

“We’re going to increase equity and fairness within the congestion-hedging process,” Bailey said. “We’re focusing on bringing those who are getting nothing up right. When you introduce equity, some entities [receiving hedges] … have to give up some to allow other entities to come in. We need to focus on a short-term solution that that will help entities that are getting nothing get something.”

He compared the current process to a buffet line, where excess auction revenue is distributed to participants, who already have hedges, in what amounts to a load-ratio share.

“You’re double dipping … at the end of the year, you’re getting something on top of what you want,” Bailey said. “In the buffet line analogy, which we’ve heard time and time again, you’re going two to three times in the buffet line. Those sitting with empty plates at the end of the year, they’re the ones who should be getting the ARR excess revenue.”

Staff’s recommendations include:

• Resetting long-term congestion rights (LTCR) awards every 10 years to give market participants more opportunities to gain the hedges.
• Modifying the LTCR’s second round of nomination capacity from 100% to a more equitable incremental percentage up 100%.
• Changing the auction revenue rights (ARRs) process’ annual first round nomination capacity calculation to more fairly allocate ARRs.
• Revising the ARRs’ first round nomination capacity from 50% to an incremental percentage up to 50%.
• Distributing excess auction revenues.

SPP also plans to update its load and generator modeling to better align them with transmission service that is studied, review the planning process’ firm transmission assumptions, and provide further stakeholder education.

“We need to involve the upstream applications from congestion hedging because congestion hedging starts with firm transmission service,” Bailey said.

While stakeholders generally expressed support for the proposal, American Electric Power’s Richard Ross, who chairs the Market Working Group that put a lot of time and effort into resolving the issue, offered a counterpoint.

“I don’t hold out much hope for the stakeholders suddenly going, ‘Oh yeah. This is great.’ But, you know, we’ll see,” he said, offering his own praise for staff’s work.

MMU Executive Director Keith Collins said the hybrid proposal addresses the monitor’s concerns and is a good package.

“There’s no silver bullet in this process. The approach that Micha is outlining is like a scattershot approach … but it applies that basic set of points that Micha raised of how we improve the equity so that we can improve affordability,” Collins said. “We reduce the effects of the buffet line. You want people to go through the line and if you can do that at least a couple of times, you’ll allow folks to be able to get more if you’re at the back of the line.”

Members Address Resource Adequacy

MOPC approved five revision requests (RRs) related to resource adequacy and a planning reserve requirement (PRM) that the board and state regulators recently raised from 12% to 15% for the summer season, effective next year. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

The committee had to first reconcile competing versions of a revision request (RR515) that lays out the process by which load-responsible entities (LREs) may qualify for and receive exemptions of the deficiency payments assessed to those that have not met the tariff’s resource adequacy requirement, if they have met the applicable criteria.

Members eventually sided with the version brought forward by the Supply Adequacy Working Group (SAWG), which allows a three-year exemption from a deficiency payment and adds triggers if the PRM was increased the year before. To qualify, LRES must demonstrate they had adequate capacity to meet the resource adequacy requirement based on the prior effective PRM and show enough capacity to meet the upcoming season’s forecasted load and a prior effective PRM.

Under SAWG’s version, LREs meeting the PRM, must demonstrate that as of April 5 of the current year, sufficient capacity for purchase has not been identified on bulletin board or demonstrate a contracted obligation to purchase capacity from a generator/developer or demonstrate it has a pending request for interim, surplus or replacement generator interconnection service that is of sufficient size.

The Cost Allocation Working Group, comprised of regulatory staff and which reports to the Regional State Committee, offered the same language, with the exception of using “and” instead of “or” before “demonstrate it has a pending request …”

The motion to endorse RR515 cleared the two-thirds threshold at 72.5%.

Casey Cathey, SPP’s director of system planning, said staff has already begun developing the principles for deficiency payment exemptions.

“[The exemption] needs to be realistic and must support reliability improvements,” he said. “We need to ensure the policy meets the proper incentive for the reserve margin. When it’s increased, we need to make sure we’re still sending the right signal for reliability purposes. We want to create a positive policy that FERC would agree to and approve.”

A bulletin board for informational purposes only will be developed so LREs and generation owners can view and post requests to buy or offers to sell power. All information on the board will be confidential, with only the MMU having the rights to review the data.

SPP bases its reserve margin requirement on a probabilistic loss-of-load expectation (LOLE) study during summer months that is performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year).

Stakeholders also approved RR508, which allows LREs to use deliverable capacity to meet their winter season obligation as well. SPP said with more LREs seeing increased loads in the winter season and some becoming winter peaking, it became apparent that the LREs should be able to use the same method to meet their winter obligations.

MOPC also endorsed three other RRs:

• RR513: Removes barriers to requesting surplus interconnection service by permitting expansion of existing substations to a location near enough to be considered part of the existing substation. Equipment additions required at the interconnection substation classified as network upgrades would not invalidate the request and would further permit added or modified “system protection equipment” at a remote substation.
• RR516: Implements the planning reserve margin’s increase from 12% to 15%.
• RR517: Creates a business practice documenting SPP’s consideration of a long-term service reservation as evidence that interim interconnection service or interconnection service subject to limited operations associated with a long-term service reservation causes no adverse thermal or voltage impacts to the transmission system. It also documents that the generating facility can continue to operate, provided there are no adverse short-circuit or stability impacts.

RRs 508 and 513 passed together unanimously and RR517 passed with 93% approval. RR516 barely passed at 67.9% approval, although it simply adds the 15% PRM to the tariff. AEP opposed the proposal during the SAWG vote, saying imposing an immediate 25% increase to the LRE reserve margin, given SPP’s generator interconnection queue backlog and other challenges faced by LREs, “sets a dangerous precedent and represent a poor implementation of capacity rules changes.”

Members Endorse 2022 ITP

MOPC approved a pair of working groups’ recommendation to endorse the 2022 Integrated Transmission Plan and its assessment report. The 2022 assessment report documented the 2022 plan as being complete.

The Economic Studies (ESWG) and Transmission (TWG) working groups said the reliability-only portfolio is smaller than previous ITP plans, thanks to the $3.4 billion in new transmission projects being placed in service between 2015 and 2019. The 17-project, $35.4 million plan solves 25 system needs in rebuilding 11 miles of transmission but will not result in any new transmission.

The 2022 study was re-baselined in April to get back on schedule by only performing the reliability assessment. (See “Tx Planning Changes Pass,” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022.)

SPP has four ITP studies in process. | SPP

 

During the re-baselining process, staff worked with the ESWG and TWG on a comprehensive review of the ITP’s governing documents to find efficiencies and improvements to help meet future assessment deadlines. The work resulted in four to six weeks of time savings.

SPP staff is currently juggling three other planning studies: the 20-year long-term assessment and the 2022 and 2024 ITPs. The 20-year assessment is the only study that is still behind, and that is only by one month. Staff said they will have to reduce scope to meet its April 2023 deadline.

Cathey complimented the ESWG for developing 2024 ITP futures that reflect industry trends in arriving at realistic renewable energy projections.

The stakeholder group’s base case foresees solar capacity growing from 7.1 GW to 14 GW between years five and 10 and wind increasing from 43.8 GW to 49.9 GW. Its emerging technologies future has greater projects of 11 GW to 22 GW and 48.2 GW to 54.9 GW, respectively. The ESWG expects storage to grow to as much as 8.8 GW in 10 years, based on a percentage of solar capacity.

“For a number of ITPs, we feel like we’ve gotten better at hitting the future. That said, the last few cycles, we’ve been hitting 10-year numbers within two years,” Cathey said. “We believe, especially given the Inflation Reduction Act and everything that’s going on in the industry, that this is probably the first one that really is taking a leap. We’re kind of all on board that this is a better prediction of what we’re actually going to see in the next five to 10 years.”

The ESWG evaluated more than 35 projections, using input from SPP’s GI queue, the U.S. Energy Information Administration’s annual energy outlook, and extrapolated 2022 ITP input from its members and the Market Monitoring Unit to arrive at its numbers.

The group plans to bring the final 2024 ITP scope document to MOPC in January for its approval.

Cathey also said the long-term assessment, due in the spring, should inform more of the assumptions that will be made in the 2025 ITP and in the consolidated planning process.

Increasing BTM, DR Resources’ Visibility

MOPC approved a pair of Operating Reliability Working Group (ORWG) revision requests designed to give SPP’s balancing authority visibility into controllable, dispatchable, non-registered behind-the-meter (BTM) and demand response data, referred to as “cats and dogs” by some stakeholders.

The ORWG said RR520 improves the BA’s ability to forecast and measure non-registered, available demand response by analyzing data submitted daily from affected load-responsible entities (LREs). Under RR512, LREs will submit used and unused capacity on BTM resources that have qualified as accredited capacity that can be used to respond to emergency conditions.

The first change passed with 84.4% approval and 10 abstentions. RR512 passed unanimously, also with 10 abstentions.

The RTO said its tariff exempts certain generations of small size from full market registration. Because some entities don’t have the proper technology to meet market registration data requirements, SPP will allow data submission through its managed file transfer system but plans to also use its application programming interface before next February’s implementation deadline.

“[Being] registered is key, whether through the market or modeled in [the energy management system], but it is not a requirement for all units that are BTM,” SPP’s Yasser Bahbaz, director of markets development, told stakeholders. “If these resources are not registered, then we are not requiring or receiving telemetered information … Your BTM units may be modeled in the reliability model but not registered. In this case, we still need to know about the info requested in these RRs.

“Knowing that capacity that’s available is really important to SPP,” he said.

“We need SPP’s real-time visibility into what’s out there,” Nebraska Public Power District’s Ron Gunderson, the ORWG’s acting chair, said.

The changes are a result of the 2021 winter storm, which required SPP to rely on energy transfers from MISO to meet demand.

The MMU registered several concerns with the changes, saying BTM generation and demand response are not adequate for the grid operator to objectively apply its performance-based accreditation but would likely represent a small reliability risk. It disagreed with the grid operator’s legal determination that adding the data requirements to the operating criteria results in enforceability and recommended better definition of various terms.

GI Backlog Down to 405 Requests

Staff told MOPC that they have reduced the number of active requests in the GI queue down to 405 as of September, a 37.8% reduction since their backlog mitigation process began in January with 651 requests. SPP has eliminated 76 active requests since its last update to members in April. (See “Staff Reducing Interconnection Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022).

“We’re happy with the progress we’re making,” the RTO’s Juliano Freitas said.

Renewables dominate SPP’s current generation-interconnection queue. | SPP

 

More than 200 requests have been withdrawn, leaving 222 in progress and another 183 waiting to be processed. The grid operator has executed 33 GI agreements, with four more pending.

But SPP is still in a hole, though not as deep. Staff said they have received and validated another 82 GI requests totaling 17.7 GW of capacity since April. That leaves the current queue at 487 requests totaling almost 96 GW of capacity. Solar requests (210, 45.1 GW) account for the bulk of the new requests.

Freitas said the grid operator doesn’t plan to close the current cluster until its finishes the backlog mitigation plan, still on schedule by the end of 2024. He said SPP is forecasting that it could install more than 50 GW of capacity by 2028.

“We have to keep our eyes on [the current cluster], because we don’t think it’s feasible to study a cluster with 100 megawatts in it,” he said.

NASEB Gas-electric Forum Convened

Charles Yeung, SPP’s executive director of interregional affairs, encouraged members to engage themselves in a gas-electric harmonization forum recently begun by the North American Energy Standards Board.

The forum was convened in August at the request of FERC and NERC. The organizations want NAESB to address a recommendation from their 2021 joint report on the year’s winter storm that calls for improving the reliability of the natural gas infrastructure system in support of the bulk power system. The recommendation focuses on gas-electric information sharing regarding system performance, gas infrastructure reliability during cold weather, and generators’ ability to obtain fuel during extreme cold weather.

“Obviously, SPP alone cannot deal with those issues,” Yeung said, noting many of the items date back to a similar cold-weather event in 2011. “Some of these issues have been brought up before, but the perception of them has changed with the disaster in Texas.”

The forum is tasked with delivering a report that includes concrete actions to increase gas infrastructure reliability, detailed plans to implement the recommendations, and the entities responsible for deploying the changes. The group met for the first time in August and will continue to convene monthly into early 2023.

Among those involved in the forum are former FERC Chair Pat Wood and Department of Energy veterans Susan Tierney and Robert Gee, who, like Wood, also chaired the Texas utility commission.

MOPC Chair Buffington ‘Honored’

AEP’s Ross, who hands out to staff and stakeholders eponymous “Gold Star” awards, complete with certificates of authenticity, unveiled a new “Richard Ross Boot Award” during the meeting.

Ross, jokingly saying he was “booted off” a recent stakeholder conversation, promised to send the first Boot Award to Evergy’s Denise Buffington, who is cycling off the committee as its chair, for her leadership the past two years.

Buffington warned members her term does not expire until Dec. 31. ITC Holdings’ Alan Myers, MOPC’s vice chair, will succeed Buffington next year.

Gold Star awards are also due for SPP’s Bailey, Drew Gilvray and Nikki Roberts in recognition of their work to improve the congestion-hedging process, Ross said. He will bring the awards and certificates to an upcoming meeting.

12 Revision Requests Pass

MOPC unanimously approved a consent agenda with 12 RRs, although nine members abstained:

• RR492: Provides clarity on the risks, timing and treatment of generator-interconnection requests’ financial securities refunds, cost allocation comparisons and withdrawn opportunities. It also adds a definition to distinguish “equally-queued” versus “lower-queued” priority of GI requests.
• RR497: Adds further definition to the Project Cost Working Group’s oversight for applicable projects that are funded through direct assignment of cost.
• RR498: Allows the ESWG to determine whether SPP’s additional incremental generation capacity recommendations should be included in the ITP’s economic model.
• RR499: Adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units.
• RR500: Clarifies and documents a more efficient and detailed process for submitting late data submittals in the ITP, including a new submittal form to help staff assess impacts. 
• RR503: Modifies language in the market mitigation sections of the protocols and tariff by removing references to dispatch and “settlement purposes” and replacing them with clarifying language to specify the solution will be used for determining locational margin prices and marginal clearing prices (MCPs). 
• RR504: Addresses potential inefficiencies in the regulation mileage compensation design by revising the mileage factor calculation and setting the mileage MCP to the resource projected to provide the last mile based on the mileage factor.
• RR507: Updates the list of transmission services grandfathered agreements.
• RR510: Revises SPP’s competitive transmission process with changes to the request for proposal’s scoring methodology and deposits and cost calculations sections and adds an additional table to the confidential information treatment section.
• RR511: Changes the tariff by updating the IEP public report deadline from 14 to 21 calendar days.
• RR514: Updates the operating constraint and spin violation relaxation limits by increasing the values of all operating reserve constraints not subject to market-to-market coordination to be $1,500.
• RR518: Corrects a calculation error in the protocols related to when regulation is not cleared in the real-time balancing market.