PJM MRC/MC Preview: Jan. 26, 2022

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:15-9:20)

B. Stakeholders will be asked to endorse proposed revisions to Manual 38: Operations Planning resulting from a periodic review. The revisions were endorsed at the Jan. 13 Operating Committee meeting. (See “Manual 38 Revisions Endorsed,” PJM Operating Committee Briefs: Jan. 13, 2022.)

Endorsements (9:20-11:25)

1. Enhancements to Dead Bus Replacement Logic (9:20-9:35)

The committee will be asked to endorse proposed revisions to Manual 11: Energy and Ancillary Services Market Operations addressing enhancements to the dead bus replacement logic for assigning prices to de-energized pricing nodes. PJM said the revisions are intended to provide increased transparency in the logic and how it performs replacements for de-energized buses. (See “De-energized Bus Replacement Revisions Endorsed,” PJM MIC Briefs: Jan. 12, 2022.)

2. Fuel-cost Policy Standards and Schedule 2 Penalties (9:35-9:50)

Members will be asked to endorse the proposed solution and corresponding revisions to Manual 15: Cost Development Guidelines and the Operating Agreement addressing clarifications to fuel-cost policy standards and Schedule 2 penalty revisions. PJM said the proposal includes a combination of clarifications and language for more elaboration on fuel-cost policies resulting from the RTO’s examination of the fallout from the February winter storm in Texas and other parts of the South and Midwest. (See “Fuel-cost Policy Standards Proposal Endorsed,” PJM MIC Briefs: Dec. 1, 2021.)

3. Regulation for Virtual Combined Cycles (9:50-10:10)

Stakeholders will be asked to endorse the proposed solution and corresponding revisions to Manual 12: Balancing Operations addressing regulation for virtual combined cycles. The proposal from Vistra was originally endorsed at the Market Implementation Committee meeting in December. (See “Virtual Combined Cycles Regulation Endorsed,” PJM MIC Briefs: Dec. 1, 2021.)

4. Resource Adequacy Senior Task Force Issue Charge (10:10-11)

The committee will be asked to approve a proposed updated issue charge for the Resource Adequacy Senior Task Force. The task force was first approved at the October MRC meeting. (See “Resource Adequacy Charter Approved,” PJM MRC MC Briefs: Oct. 20, 2021.)

5. Max Emergency Correction for Gas CTs (11-11:25)

Members will be asked to endorse an issue charge and proposed revisions to Manual 13: Emergency Operations addressing a temporary change to the maximum emergency requirements for gas combustion turbines. According to PJM, the Illinois Clean Energy Jobs Act restricts the number of run hours for gas CTs in the state. To manage near-term reliability concerns, PJM is recommending a temporary change to the maximum emergency provisions in Manual 13 for CTs to expire April 1. (See “Illinois Energy Transition Act Update,” PJM Operating Committee Briefs: Jan. 13, 2022.)

Members Committee

Consent Agenda (1:25-1:30)

B. Stakeholders will be asked to endorse proposed tariff and Operating Agreement revisions addressing various aspects of market participation by solar-battery hybrid resources. The revisions were unanimously endorsed at the Dec. 15 MRC meeting. (See “Solar-battery Hybrid Resources Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.)

C. Members will be asked to endorse proposed tariff and OA revisions addressing synchronous reserve deployment. The proposal, which was developed from discussions in the Synchronized Reserve Deployment Task Force (SRDTF), is meant to improve the deployment of synchronized reserves during a spin event. (See “Synchronous Reserve Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.)

Endorsements (1:30-1:50)

1. Sector Selection Challenge Process (1:30-1:50)

The committee will be asked to approve the proposed OA revisions to the sector challenge process. Several stakeholders questioned the proposal at the December MC meeting regarding the way members can be challenged on their chosen sectors in PJM. (See “Sector Selection Challenge Process,” PJM MRC/MC Briefs: Dec. 15, 2021.)

January 23, 2022December 14, 2023

Oregon PUC Advances Wildfire Rulemaking Despite Utility Concerns

Oregon regulators last week voted to move ahead with a formal rulemaking to amend utility wildfire mitigation plans despite the utilities’ concerns about a key provision in the proposed ruleset related to pole inspections on distribution lines.

The decision by the state’s Public Utility Commission (OPUC) on Jan. 18 comes after a six-month informal process in which OPUC staff worked with industry stakeholders and other concerned parties to draft rules for the commission to consider and eventually put to a vote (AR 638).

The commission’s formal proceeding typically allows for public input and deliberation intended to make modest adjustments to proposed rules already largely hashed out during the preceding informal process. But the AR 638 proceeding will likely entail heavier revisions and possible industry counterproposals regarding the pole inspection measures.

The updated wildfire rules come with a sense of urgency, as drier summers fueled by climate change put the heavily forested Pacific Northwest at increasing risk of catastrophic fires like those ignited over Labor Day weekend in September 2020.

It was just ahead of those fires that Portland General Electric (NYSE:PGE) invoked the state’s first ever public safety power shutoffs (PSPS) in the Mount Hood area southeast of Portland. (See High Fire Danger Prompts First Oregon PSPS Event.) Pacific Power and its parent company PacifiCorp (NYSE:BRK.A) face multiple lawsuits from residents who contend the utility should have done the same in Southern Oregon before the company’s power lines sparked four massive fires that together destroyed nearly 2,500 homes. (See PacifiCorp Faces Class Action over Wildfire Response.)

“These rules on wildfire mitigation are one of the commission’s most important missions,” OPUC Chair Megan Decker said during last week’s commission meeting.

More and Less Prescriptive

The amendments proposed by OPUC staff expand on existing rules (AR 648) that became effective Nov. 30, 2021, after the expiration of the temporary rules covering the 2021 wildfire season. The proposed rules call for the wildfire mitigation plans of the state’s three investor-owned utilities (PGE, Pacific Power and Idaho Power (NYSE:IDA)) to include analyses of the wildfire risk within their service territories, as well as areas outside them but within their rights of way for generation and transmission assets.

The analyses would include a “baseline” wildfire risk that includes fixed elements such as topography, vegetation, climate and “utility equipment in place.” They would also include seasonal risks such as cumulative precipitation and fuel moisture content. Each utility would also be required to outline risks to residential areas served by the utility and risks to its substations and power lines. The IOUs must also provide “narrative descriptions” of how those risks inform their decisions around PSPS, vegetation management, system hardening, investments and operations.

Under the proposed rules, amendments to existing rules that require the IOUs to work with communities on mitigation strategies would be “less prescriptive” than the provisions currently in place, Lori Koho, administrator of the OPUC’s Utility Safety, Reliability & Security Division, told commissioners and industry stakeholders.

The changes would provide IOUs more responsibility and flexibility “to establish community-appropriate communication and notification priorities, education campaigns and to identify relevant critical facilities,” a staff presentation explained.

The updated rules would also clarify that telecommunication providers be specifically identified as “critical facilities” in the event of PSPS.

“We had bundled up telecom as part of things that might be identified as critical facilities; they weren’t specifically called out in looking at the wildfires we’ve experienced,” Koho said. “And certainly in the ice storm last February, we recognize that sometimes telecom is almost more important than electricity. … If you have a charged phone, and you have a cell tower that still is active, you can at least tell somebody you’re out of power.”

Koho noted that OPUC staff are recommending “more prescriptive” equipment safety measures in the mitigation plans, including more stringent rules that would require more frequent trimming of fast-growing trees near power lines across the system.

PGE asked the PUC to keep those rules focused on the highest fire-risk areas.

“The proposed rules create a competing interest between the Oregon Public Utility Commission and the local jurisdictions,” said Larry Bekkedahl, PGE senior vice president of advanced energy delivery. “For example, should a utility deem it necessary to increase clearances on fast-growing tree species in high fire-risk zones, it will require additional tree trimming or removal. That same degree of trimming or removal in urban areas may place the utility in violation and noncompliance with many of the local permits and tree code restrictions.”

“What I hear is sort of this presumption that [local] rules should take precedence for clearance and tree trimming and so on, and I guess from a fire safety perspective, how will those 51 cities [served by PGE] know that their codes are safe for wildfire risk?” Commissioner Letha Tawney said. “And I don’t think wildfire risk is an exurban issue versus an urban issue; I think in Oregon, we have a lot of overlap. And as we continue to see this, we can get ignitions in relatively densely populated areas that then go on to create just real havoc.”

Joint Inspection Doubts

But the utilities most strongly objected to proposed rules requiring them to engage in “joint inspections” of utility poles that include any co-owners or shared users of the poles, such as telecommunications providers. Koho noted that utilities are often the only users to regularly inspect the poles, leaving the cost of inspections borne by ratepayers. In crafting the rule, OPUC staff sought to defray those costs.

Bekkedahl pointed to the complexity of orchestrating such inspections, especially given that in some high fire-risk areas, PGE shares ownership of poles with seven different users.

“We have significant concerns that the proposed joint inspection mandate will cause delays to find and remediate issues found in high fire-risk zones and inevitably increase wildfire risk,” Bekkedahl said, pointing to potential delays stemming from unresponsive third parties in scheduling inspections and disagreements over cost-sharing. “We’re doing [the inspections] today, and we want to continue to be able to do that.”

Allen Berreth, vice president of transmission and distribution operations at Pacific Power, said that while his company did not envision any “formal barriers” to engaging in joint inspections, it sought more clarity in the rules regarding what it will take to achieve such inspections.

Mitch Colburn, Idaho Power’s vice president of planning, engineering and construction, said his utility shared concerns about the joint inspection requirement.

“While we do not wish to further delay this important rulemaking, we do feel more discussion is necessary in the formal rulemaking to ensure that all the rules are clear and are ultimately going to effectively mitigate wildfire risk,” Colburn said.

Ahead of the vote to proceed with the formal rulemaking, Commissioner Mark Thompson expressed doubt about voting in favor of it because of doubts about the commission’s ability to work out the joint inspection issue during the formal process.

“I think that often works, but I think it doesn’t work very well if we feel like we’re maybe barking up the wrong tree, because then you’re asking a lot of that formal process to kind of extract yourself from that, and then replace it with a more meaningful path,” Thompson said. “And I will say on the topic of inspections … it doesn’t feel to me like a great solution to the problem. I’m concerned that it’s going to take a lot of resources for people to gear up to do joint inspections” and will slow down the process.

Chair Decker’s concerns centered on delaying a needed rulemaking ahead of the upcoming fire season, including implementation of the other measures proposed in the ruleset. She proposed that OPUC staff continue to work with the state’s IOUs on the joint inspection issue to develop an alternative before the commission’s regular public meeting on Feb. 8.

Decker moved to adopt PUC staff’s recommendation to proceed with the formal process while indicating “clearly in our order that we are still considering alternatives as we would for all the rules, but in particular, in the areas that have been discussed today.”

All three commissioners voted in favor.

January 23, 2022November 15, 2023

SPP Board, Regulators to Take up Rejected RRs

SPP’s Board of Directors and its state regulators this week will consider a pair of transmission revision requests that did not pass stakeholder muster earlier this month over cost-allocation and equity concerns.

The Regional State Committee, comprising regulators from the RTO’s footprint, will vote Monday on a measure (RR483) to address FERC-identified deficiencies in the grid operator’s byway facility cost-allocation process. The RSC has primary authority over cost allocation for SPP-directed transmission projects; any methodology allocating costs that the committee approves must be filed at FERC according to the RTO’s
bylaws.

On Tuesday, the board will consider that and RR477, which establishes uniform local planning criteria within each transmission pricing zone and has also been rejected in its previous form by the commission.

Both measures came within 3 percentage points of SPP’s 66% majority approval threshold during the Jan. 10-11 Markets and Operations Policy Committee. Transmission owners split 6-6, with five abstentions, on RR483 and favored RR477 9-7; transmission users favored the change requests 30-8 and 27-12, respectively.

Approval authority for SPP’s key committees | SPP

The Strategic Planning Committee endorsed both RR483 and RR477 during its Jan. 12 meeting by 10-4 and 11-2 (with an abstention) margins, respectively.

Under SPP’s bylaws, the board has independent authority over all RTO matters and it can approve a revision request, even if it is rejected by MOPC or another committee.

Both measures were among 21 recommendations from the Holistic Integrated Tariff Team in 2019, intended to integrate increased renewable energy, boost reliability, and improve transmission planning and the wholesale market. SPP General Counsel Paul Suskie told MOPC that all HITT recommendations must go the board for final approval. (See SPP Board Approves HITT’s Recommendations.)

“There are a lot of very entrenched opinions on this,” said John Krajewski, who consults for the Nebraska Power Review Board and led the Cost Allocation Working Group’s (CAWG) work on the subject. “If you’re not expecting opposition at FERC, you’re kidding yourself.”

The CAWG drafted a white paper in response to HITT’s recommendation to “evaluate creating a narrow process through which costs for specific projects between 100 and 300 kV can be fully allocated prospectively on a regionwide basis.” The document was approved by the board and RSC in July 2020, leading to tariff language that was filed at FERC.

Under SPP’s highway/byway methodology, transmission costs are allocated on a voltage threshold basis. Highway facilities, or those above 300 kV, are allocated 100% on regional, postage-stamp basis. Byway facilities, those between 100 and 300 kV, are allocated on a regional basis (33%) and to the pricing zone (67%) in which the facilities are located. Facilities at or below 100 kV are fully allocated to the zone in which they are located.

However, the commission rejected SPP’s filing last June without prejudice, finding that the proposal gave too much discretion to the board in allocating costs and did not include clear standards for making decisions. (See FERC Rejects SPP’s Cost-allocation Waiver Proposal.)

RR 483 responds to the filing with a “surgical approach” to evaluate byway projects in wind-rich zones. It allows a byway-funded transmission upgrade to be funded through a regionwide allocation after meeting certain criteria under the “narrow review process.” Projects eligible for this “narrow and limited process” must have base plan upgrade costs eligible for cost allocation under the SPP tariff.

Members in wind-rich pricing zones have long complained their small system loads have been unfairly saddled with costs for exporting largely unaffiliated generation. They argue the process should take regional benefits into consideration.

“Seventy, 80% of the time we’re exporting to SPP. We encourage SPP to continue working on a solution,” said Sunflower Electric Power Cooperative’s Al Tamimi, who has frequently asked for support for his zone, during the MOPC discussion.

Oklahoma Gas & Electric’s Usha Turner said SPP’s regional cost allocation review (RCAR) process provides a remedy “to resolve grievances around cost” and pointed to FERC Commissioner Mark Christie’s dissent. Christie said SPP’s previous application provided “insufficient detail” with respect to the various roles of stakeholder groups, states and load-serving entities in reviewing the waiver requests.

“I think this is going to make its way back to SPP, because I don’t think we’ve resolved FERC’s concerns,” Turner said before voting against the change.

“The RCAR uses lot of hypothetical assumptions,” Tamimi said. “It’s not used for cost allocation.”

“This is a waiver process that [an entity] is going to have to go through lots of hoops and hurdles when a wind-rich zone wants something considered,” said Golden Spread Electric Cooperative’s Mike Wise, a proponent of the measure. “We don’t want something crammed down. This surgical approach is ideally suited for what we’ve been trying to resolve over the last five years. This is an effective, appropriate approach to alleviate or allow a process to help a zone that has surely been harmed by our tariff in this way.”

FERC also rejected RR477’s previous iteration in 2020, siding with stakeholders who argued the proposal would give a pricing zone’s facilitating TO ”unilateral power” and “unduly” benefit them and the zone’s largest network load customer. GridLiance High Plains, Tri-County Electric Cooperative, Kansas Power Pool and a group of eight cooperatives argued the proposal would allow a single customer, based on the size of its load, to dictate planning criteria for everyone else in the zone. (See FERC Rejects SPP’s Zonal Planning Criteria.)

SPP’s proposed zonal planning criteria to create uniform local planning criteria within each transmission pricing zone | SPP

RR477 retains the facilitating TO concept but introduces a formal process to influence its decision-making in establishing the zonal planning criteria. SPP staff said the measure also establishes an avenue to ensure input from the zone’s other TOs, customers and stakeholders is considered and add a two-step voting process.

Some stakeholders have pushed back, saying the new language is overly burdensome on the FTO and includes hard dates that are inflexible. They said a requirement to perform the exercise annually is not in reliability planning’s best interest.

Evergy said in its comments that the “one-size-fits-all” approach includes rigid vote procedures in two early steps and weights that are not equitable in zones where the largest TO also has a clear majority of the load. The utility said local planning would cease to exist in transmission zones that don’t reach consensus because the planning criteria does not identify a zonal reliability upgrade.

“Status quo is not an answer,” Southwestern Public Service’s Bill Grant said at MOPC. “I think SPP will tell you there’s a lot of different TOs and each one has different criteria in each zone. That gets to be where it’s not workable.”

MOPC’s members suggested entities send their specific concerns to Evergy’s Denise Buffington, the committee chair. She said her company’s reliability concerns have not yet been addressed, but that work underway “could push the Evergy team over to support the proposal.”

“We’ll have that debate and dialogue at the board meeting,” she said.

“We’re close. We’re going to see if we can’t close that gap in the next two weeks,” American Electric Power’s Richard Ross said at MOPC. “We’d like to get this taken care of at the board.”

Heather Starnes, who represents Missouri Joint Municipal Electric Utility Commission, an alliance of municipalities, said RR477 is not perfect, “but it’s a good start.”

“If we can bolster SPP’s criteria to make people comfortable, we’d like to do that,” she said. “I don’t think we’ll make everybody happy.”

Starnes was part of a sub-team with Ross, Wise and Grant working to resolve differences between TOs and the protesting groups on RR477.

“Everybody understands it’s a great thing to work together on consensus,” Grant said. “There are some situations where people don’t agree, but that doesn’t tie your hands. I do agree a lot of good work has gone into [RR477] that addresses FERC’s concerns.”

January 23, 2022December 5, 2023

Oregon Study to Examine Prospects for Floating Offshore Wind

An upcoming study on the “benefits and challenges” of developing floating offshore wind (FOSW) off the coast of Oregon will explore a range of topics to help inform state lawmakers looking to produce bills to cultivate the sector.

Among the topics under examination: What impact, if any, would the state’s participation in an RTO have on facilitating development of FOSW?

During a virtual meeting to kick off the study, Jason Sierman, senior policy analyst with the Oregon Department of Energy (ODOE), said that areas of the East Coast currently seeing heavy development of OSW all have RTOs or ISOs.

“The department is interested in exploring how the nuances [of RTOs] could pose benefits and challenges to floating offshore wind coming to Oregon,” Sierman said. “Have RTOs helped spur the development of offshore wind on the East Coast? Was it primarily driven by costs or the state mandates? Or were RTOs helpful for that? Could that type of transmission structure potentially be a key for helping to spur floating offshore wind development off Oregon’s coast?”

The Oregon FOSW study is the product of House Bill 3375, passed last year to require ODOE to examine the impacts of integrating 3 GW of offshore wind into the region’s electricity system by 2030. ODOE staff are initiating the project close on the heels of completing another study weighing the benefits and risks of Oregon joining an RTO, which was submitted to the legislature late last month. (See Study Provides Ore. Lawmakers with Wide Shot on RTO Membership.)

In a similar vein to the RTO study, the FOSW report is not intended to offer policy recommendations. Instead, HB 3375 calls for ODOE to conduct a literature review and gather input from industry and regional stakeholders, various Oregon state agencies and federal entities such as the Bonneville Power Administration, the Bureau of Ocean Energy Management, the Department of Defense and energy research laboratories.

Ruchi Sadhir, ODOE associate director of strategic engagement, said the study will examine the FOSW issue from a range of perspectives, including renewable energy goals, job creation, infrastructure, transmission and ports, resilience and reliability, as well as “potential effects like impacts to ocean users and land users, impacts to the environment, public beaches, scenic byways — that sort of thing.”

“We would like the end product to be a final report to the legislature that provides neutral reporting on the literature and the range of perspectives that we’ve heard throughout this study process,” Sadhir said.

West vs. East

Oregon and the West Coast differ from the East Coast in that a sharp drop-off in the continental shelf relatively close to the coastline makes the installation of fixed-bottom OSW turbines impossible, leaving as the only option the less common floating turbine designs, which are just a “blip on the map” compared with fixed designs, Sierman said.

“There’s just a handful of [FOSW] projects out there right now, and the largest project is 50 MW, so relatively small in the grand scheme of energy projects. And the bottom line here is it’s a nascent industry,” translating into higher costs to build, Sierman said.

The West and East coasts also differ in that population centers in the former are largely situated far from the coast, leaving little existing transmission infrastructure available to interconnect large-scale OSW projects.

Sierman pointed out that most of the Pacific Northwest’s high-voltage transmission network was designed to carry energy from large hydroelectric dams in the Columbia Valley to the region’s load centers, while no large lines run out to the coast, where the largest are 230 kV.

“The big takeaway here is that as economies of scale might drive up floating offshore wind projects, there’s kind of an upper bound or a limitation currently without upgrades to existing transmission infrastructure here,” Sierman said.

For that reason, questions regarding transmission infrastructure will be one of the key topics addressed by the study. Other topics include FOSW technology, port infrastructure, siting and permitting, and “foundational” questions related to clean energy targets, equity and economic development. Another topic covers energy markets and RTOs.

Responding to a question from RTO Insider, Sadhir said the study would not attempt to capture the varying economics of placing wind turbines in different wind speed zones.

“We don’t expect to have our own technical analysis occurring,” she said. “It’s more about reviewing the literature, sharing it and giving an opportunity to get those qualitative perspectives from stakeholders on those questions as well.”

But Sadhir said the study will consider how OSW can contribute to the region’s resource adequacy, a subject she called “very topical in the energy sector.”

ODOE must submit the completed study to the legislature by Sept. 15, Sadhir noted. The department is seeking stakeholder comments by Feb. 18 and will hold another public meeting on the subject March 10.

January 23, 2022June 14, 2023

COVID Leads GCPA to Reschedule MISO-SPP Conference

HOUSTON — The Gulf Coast Power Association said Thursday during its annual meeting that it has rescheduled its annual MISO South-SPP regional conference to March 30-31 in New Orleans.

GCPA had canceled the conference, originally scheduled to take place Feb. 9-10, because of an increase of COVID-19 cases in Louisiana and its “concern for the safety of our attendees.” The organization’s executive director, Kim Casey, said several speakers had also expressed concerns about attending.

Mark Dreyfus Katie Coleman 2022-01-20 (RTO Insider LLC) FI.jpg

Katie Coleman (right) congratulates her successor as GCPA president, Mark Dreyfus. | ©RTO Insider LLC

The city of New Orleans requires a mask in all indoor spaces and proof of vaccination or a negative COVID test within 72 hours for indoor dining, bars and event spaces. Effective Feb. 1, the city’s protocols will require proof of two vaccine doses or one dose of the Johnson & Johnson vaccine, or proof of a negative COVID test within 72 hours.

The organization will reopen registration for the conference on Tuesday. Barring further developments, the two-day conference will be held at the Pan American Life Center. MISO CEO John Bear and SPP CEO Barbara Sugg had both agreed to deliver keynote addresses.

The annual conference was last held in 2020. It was canceled last year because of the pandemic.

This year’s meeting will mark the beginning of energy consultant Mark Dreyfus’ two-year term as GCPA’s president. Dreyfus succeeds Katie Coleman, a partner in O’Melveny & Myers’ Austin office.

Dreyfus, who has 25 years of industry experience, praised Coleman, whose term began just before the world shut down for the pandemic and also included the state’s response to the February 2021 winter storm.

“Katie led GCPA through these last two challenging years,” Dreyfus said. “My focus in this next year is to continue the recovery of the organization from the impacts of COVID, focusing on GCPA’s core functions of information exchange through our quality, low-cost conferences, and creating networking opportunities for our members.”

GCPA members also voted MISO’s Daryl Brown, executive director of external affairs for the RTO’s South region, to its board of directors.

GCPA is a regional electric power trade organization that serves Texas and the Gulf Coast and promotes an improved understanding of power market issues and opportunities.

January 23, 2022December 10, 2023

DC Circuit Upholds FERC on Duke-Muni Battery Dispute

The D.C. Circuit Court of Appeals said Friday it would not “second guess” FERC’s interpretation of a power purchase agreement between Duke Energy Progress (NYSE:DUK) and the North Carolina Eastern Municipal Power Agency (NCEMPA), upholding a ruling that allowed the latter to use storage to reduce its capacity charges (20-1495).

NCEMPA, which serves 32 cities and towns with municipal electric distribution systems, asked FERC in 2019 to issue an order declaring that its 2015 “full requirements” PPA with Duke permitted it to use battery storage to reduce the munis’ load during the peak hour each month that is used to determine capacity charges.

The capacity charge — based on NCEMPA’s pro rata share of the demand on Duke’s system during the one-hour peak — is intended to cover Duke’s fixed costs and provide a return on its infrastructure investments. NCEMPA also pays an energy charge to reimburse Duke for its fuel costs and variable operations and maintenance costs.

The munis cited sections 9.4 of the PPA, which permits demand-side management (DSM) (e.g., end users allowing the agency to turn off appliances during high-demand periods), and section 9.5, which permits demand response (end users acting themselves to curtail consumption in response to real-time price signals).

Duke spokesperson Randy Wheeless said the company was disappointed by the D.C. Circuit’s ruling. The company asked FERC in December to approve revisions to the PPA on the assumption that the commission’s ruling would be upheld on appeal (ER22-682).

“Although Duke Energy is supportive of battery storage technology, we must be mindful how the current rate design could potentially shift costs and unfairly burden other customer groups,” Wheeless said Saturday. “As more energy storage devices are deployed, this issue will continue to arise between utilities and wholesale customers.”

FERC Order

FERC granted NCEMPA’s request in an order in September 2020 (EL20-15). (See NC Muni Wins Right to Add Storage over Duke Objections.)

In its appeal, Duke contended that batteries don’t qualify as DSM or DR. And it said allowing NCEMPA to use batteries would make the PPA “confiscatory” by permitting the agency to reduce its demand to zero during the system peak, eliminating its payments toward Duke’s fixed costs.

The D.C. Circuit said the case hinged on two competing interpretations of section 9.5, which it called “a model of ambiguity.

“It does not define demand response; it never mentions batteries; and interpreting the provision required the commission to infer the meaning of two of its terms, ‘demands’ and ‘load,’ by reference to another provision of the agreement,” Circuit Judges Karen LeCraft Henderson, David S. Tatel and Cornelia Pillard ruled in an opinion written by Tatel.

Duke contended that section 9.5 only permitted reducing demand through communication of pricing information to the agency members and their customers. FERC concluded that the language allowed NCEMPA to reduce members’ demand through the use of pricing information — specifically the “combined system load signal” — data that allow the agency to predict when the maximum demand on Duke’s system will occur.

FERC noted that “Duke will continue to supply (and [NCEMPA] will continue to pay for) the energy needed to charge any batteries.”

“Given that we must ‘defer to the commission’s construction of the provision at issue so long as that construction is reasonable,’ it is not enough for Duke to offer its own reasonable interpretation of the provision,” the court said. “Instead, Duke must demonstrate that the commission’s interpretation is unreasonable. It has failed to do so.”

The court said section 16 of the PPA outlines a process for Duke to propose changes to the agreement if the utility has “concerns regarding whether the contract remains appropriately compensatory.”

“Accordingly, should [NCEMPA] deploy its batteries in a way that renders the agreement ‘confiscatory,’ Duke can return to the commission for relief,” the court said.

Contract Revision Sought

Duke did just that in seeking to reopen the PPA on Dec. 17.

“The enclosed rate design change is required because, even since the commission’s interpretation of the contract, certain power agency members have publicly and clearly announced their intention to procure enough battery storage technology to drastically reduce, and even eliminate entirely, their responsibility for capacity charges by superficially reducing or eliminating their demand only during the single coincident peak hour of the month, even though their reliance on the [Duke] system during the majority of other hours in the month continues unabated,” it said.

NCEMPA protested, saying Duke’s
“proposal would penalize the development of distributed energy resources, not only by NCEMPA and its members, but also by the members’ retail customers, thus increasing the cost of the resource transition, undermining reliability, and potentially increasing the use of carbon-emitting resources.” On Monday, NCEMPA filed a motion to lodge the D.C. Circuit’s ruling in the FERC docket.

Drew Elliot, manager of government affairs for NCEMPA parent ElectriCities of NC, said two of the agency’s larger member utilities — each 1,000 kW AC — have installed pilot battery projects since May 2019. “They are operated by the individual utilities, not the power agency, and are used for peak shaving,” Elliot said.

January 23, 2022

MISO Promises Long-range Tx Project Reveal Soon

MISO is close to proposing its first cycle of projects under its long-range transmission effort and has signaled that a massive transmission line touching four states shows promise.

During a special stakeholder workshop Friday, the RTO promised more specifics on project proposals next month.

“This work is complicated, but we’re starting to see some clarity around our first tranche of projects,” MISO’s Jarred Miland said.

Miland said staff has completed much of the reliability analysis on prospective projects, with economic analysis to continue into February. Transmission planners will have the projects’ business justifications solidified sometime in March, he said.

By April, discussions on the long-range projects will be handed over to the Planning Advisory Committee, Miland said. The RTO plans to have its board of directors vote on approval of the first cycle of projects in mid-June. (See MISO Postpones 1st Cycle of Long-range Projects.)

The first group of projects are limited to the Midwest and based upon MISO’s most conservative 20-year transmission planning future, which contemplates the three futures’ least amount of renewable penetration, fossil fuel retirements and electrification.

MISO is optimistic that a vast, curved 345-kV project would cross through Iowa, Illinois, Indiana and Michigan. The RTO said the line resolves “multiple, severe” steady state issues from the first planning future.

Staff said while the project appears to be a standalone corridor on a map, it ties into MISO’s existing 345-kV system at several points.

“It’s not one long line. It’s more of a reinforcement of the existing system; it’s not just a point A to point B,” MISO expansion planning adviser Matt Tackett said.

Tackett also said a 345-kV rating is the best call for the massive project. “While we intend to look into higher voltage, 765-kV lines in the future … we need a strong underlying 345-kV system to build on,” he said.

Study continues on a handful of smaller, 345-kV projects that are spread across central Iowa, northern Missouri, the Dakotas and western Minnesota, and Minnesota into Wisconsin. MISO is interested in constructing a path between South Dakota’s existing 345-kV infrastructure and a 345-kV line in southwest Minnesota built under its CapX2020 initiative.

While MISO is not prepared to issue cost estimates, some stakeholders said the first cycle of projects could reach $10 billion.

MISO Senior Engineer James Slegers said though the new lines may be near existing transmission and might be able to share right of way, staff is not going to propose the removal or replacement of existing lines under the long-range plan.

Staff also said they’re monitoring and sharing results with the MISO-SPP team working on the RTOs’ Joint Targeted Interconnection Queue (JTIQ) searching for interregional transmission projects to boost generation interconnections.

Julie Fedorchak, chair of North Dakota Public Service Commission, has pointed out that some projects under consideration in the plan are included among the joint study’s possible transmission solutions.

“That bothers me because they obviously have benefits to SPP if they’re on the JTIQ map,” Fedorchak said during a Jan. 13 Organization of MISO States meeting.

Aubrey Johnson, the RTO’s executive director of system planning, said that if similar solutions are showing up in both the long-range and JTIQ studies, it shows how desperately needed the projects are.

“We are internally discussing how to handle that overlap,” Johnson said. “Ultimately, these are all projects that are wholly located within MISO, so we think it’s appropriate to include them in the long-range plan.”

Customized Energy Solutions’ Ginger Hodge said she was concerned about a “lost opportunity” to share costs if the projects are shown to benefit SPP.

“I just really encourage MISO to think about that,” she said.

Stakeholders also asked that MISO’s models contemplate that the Cardinal-Hickory Creek line never gets energized. A federal judge recently ruled that the line couldn’t cut through protected wildlife habitat in Wisconsin. (See Federal Judge: Tx Line Can’t Cross Wildlife Refuge.)

The Cardinal-Hickory Creek line is the last of MISO’s $6.7 billion, 17-project Multi-Value Project portfolio approved in 2011; MISO has long assumed the project will become part of its system.

Some stakeholders asked whether the grid operator would increase its renewables projections before it proposes long-range projects based on the second and third future scenarios. MISO developed its current set of planning futures in 2020, and some stakeholders said that the speed of renewable installations can mean transmission projections quickly become outdated.

Johnson said he didn’t see a need for that as MISO’s three planning futures account for anywhere from 130 to 330 GW of resource additions, mostly from renewable sources.

“I think we’ve got it covered,” he said.

January 23, 2022November 28, 2023

FERC Grants MISO Temporary Storage Waiver

FERC last week gave MISO a hall pass on ensuring offline energy storage resources (ESRs) can furnish certain types of energy reserves.

Thursday, the commission granted the RTO both a temporary waiver and removal of tariff language that states offline storage resources can provide supplemental reserves or short-term reserves. The waiver is effective Nov. 23, 2021, and the tariff edits took effect Dec. 7 (ER22-461 and ER22-462).

MISO said that in implementing its new short-term reserve product late last year, it discovered that its markets cannot clear those reserve offers from energy storage resources, which currently only participate as either Stored Energy Resource Type II (SER Type II) or Demand Response Resource Type II (DRR Type II).

The grid operator said since its systems currently cannot track energy storage’s state of charge, it can’t detect whether those storage assets are offline.

SER Type II is a temporary resource designation created in 2017 for use until no later than 2023, when MISO should have a full participation model in place for storage under FERC’s Order 841. SER Type II was modeled after MISO’s existing DRR Type II. (See FERC OKs MISO Plan to Expand Storage.)

The RTO has committed to phasing out SER Type II “soon after” storage resources have access to full market participation under MISO’s Order 841 compliance design. The grid operator will begin registrations for storage assets in early June and open full market participation to them sometime in September.

MISO said it would be “extremely complicated, costly and time-consuming to explore, develop, test and install a software solution” that would allow offline storage to provide short-term and supplemental reserves until its full storage participation model is up and running.

FERC called the waiver an “appropriate interim solution.”

The Solar Energy Industries Association (SEIA) protested MISO’s plan, arguing that it “must compensate offline storage resources for the services those resources provide.”

But the commissioners agreed that MISO shouldn’t have to incur steep costs and man-hours creating a temporary fix. It also said the RTO seemed to have acted in good faith.

“We disagree with SEIA’s arguments that MISO’s proposed tariff revisions are an attempt to limit storage resources’ ability to participate in the markets. We note that, in fact, MISO’s proposed tariff revisions are a temporary measure until such time when [energy storage resources are] fully integrated in MISO’s markets,” FERC said.

MISO’s short-term reserve product went live Dec. 7. It’s meant to source energy within 30 minutes where needed from both online and offline resources, while accounting for real-time transmission constraints. (See MISO Begins Software Build on Short-term Reserves.)

The grid operator has said the reserves will reduce make-whole payments, cut down on out-of-market commitments, make market pricing more transparent, and provide pricing signals that encourage a greater number of fast-start resources that can meet voltage and local reliability requirements more cheaply.

January 23, 2022January 29, 2024

Tri-State Reaches Settlement over Resource Plan

Tri-State Generation and Transmission Association has reached a settlement with more than two dozen of its members and other parties over the first phase of its 20-year, $21.3 billion plan to reduce its carbon dioxide emissions.

The Colorado-based cooperative said Wednesday that the “landmark” agreement, filed for approval with the Colorado Public Utilities Commission, sets near-term targets for greenhouse gas emission reductions before 2030 as part of its Responsible Energy Plan (20A-0528E).

Tri-State CEO Duane Highley | SPP

Tri-State CEO Duane Highley thanked the cooperative’s members, state officials, environmental advocates and labor representatives who worked on the settlement, which he called “a meaningful advancement in our efforts to transform our cooperative as we responsibly serve reliable and affordable power to rural communities, for our members and Colorado.”

The agreement includes “numerous and complex provisions” resolving Phase I of Tri-State’s electric resource plan (ERP) that it filed with the PUC in December 2020 as part of an ongoing proceeding.

Under the settlement’s terms, Tri-State agreed to reduce GHG emissions related to its wholesale sales in Colorado by 26% in 2025, 36% in 2026, 46% in 2027 and 80% in 2030. The amounts will be calculated based on the cooperative’s 2005 emissions baseline.

Tri-State also said it will report its progress on GHG emission reductions to the commission in its ERP annual progress reports going forward and conduct a competitive solicitation for new resources with in-service dates through 2026.

The parties, which included PUC staff, agreed to recommend the PUC approve Tri-State’s resource plan, subject to certain modifications in the settlement. They also agreed to an extensive set of modeling assumptions and inputs for the ERP’s second phase.

Tri-State expects the commission to review and consider the settlement’s approval during the first quarter this year.

Jon Goldin-Dubois, president of Western Resource Advocates, said Tri-State “has come a long way” in “committing to near-term, enforceable reductions in climate-changing greenhouse gas pollution.”

“This agreement will make significant progress in accelerating emission reductions in the West, all while reducing costs for customers and supporting communities most impacted by the transition,” he said. “We have much work to do, but Tri-State is to be commended for taking these steps to maximize near-term emission reductions, the most important action society can take to avoid the worst impacts of climate change.”

Goldin-Dubois was one of several environmental advocates and members quoted in Tri-State’s press release announcing the settlement. Those groups are among those that have previously criticized the cooperative for its reliance on coal-fired energy.

Colorado lawmakers passed legislation in 2019 requiring utilities to cut CO₂ emissions by 80% from 2005 levels by 2030 and 100% by 2050.

In January 2020, Tri-State responded with its Responsible Energy Plan to shut down more than 1.1 GW of coal-fired resources, transition to a cleaner energy portfolio and ensure compliance with Colorado’s environmental regulations. (See Tri-State to Retire 2 Coal Plants, Mine.)

Tri-State said it added 304 MW of wind energy last year, and it plans to add six additional solar projects by 2024. It said renewable energy will account for 50% of its 42 members’ consumption that year and 70% by 2030.

The settlement agreement’s additional modeling will include continued analysis of the retirement date for Craig Station Unit 3, which previous modeling validated would retire by 2030.

United Power to Exit Tri-State?

While Tri-State works to clean up its fuel mix, it may also lose one of its largest members.

United Power, which accounts for about 20% of Tri-State’s business, filed with FERC in December its intention to withdraw from Tri-State, effective January 2024 (ER21-2818).

United made its termination contingent on FERC’s determination that the exit fee to leave the association is just and reasonable. Last November, the commission accepted Tri-State’s methodology for calculating membership exit fees, subject to a refund hearing set for May, and also opened an inquiry under Section 206 of the Federal Power Act. (See FERC Accepts Tri-State’s Exit Fee Calculation.)

“Tri-State will work with United Power, as it would with any other member, through the contract termination process to support an orderly withdrawal,” Highley said in a statement. “The contract termination tariff approved by the FERC ensures that any utility member’s withdrawal does not harm the remaining members of our cooperative or Tri-State.”

Tri-State’s Kit Carson Windpower facility | Tri-State

United has said its exit fee should be between $200 million and $300 million. Tri-State has set the amount at $1.5 billion.

Two of Tri-State’s members have already paid the exit fee and left the association. As many as eight other members have asked the co-op what it would cost them to exit their contracts.

Kit Carson Electric Cooperative departed in 2016, paying $37 million, and Delta-Montrose Electric Association left in 2020, paying $136.5 million. (See Tri-State, Delta Officially Part Ways.)

January 23, 2022December 14, 2023

DOE-DOT Joint Office to Begin Rollout of EV Infrastructure Funds

The Joint Office of Energy and Transportation will take the first steps in rolling out the Infrastructure Investment and Jobs Act’s (IIJA) $7.5 billion in funding for a national electric vehicle charging network next month when it releases a guidance document to help states submit plans for the federal dollars.

Announced Thursday at the National EV Charging Summit, the guidance document “will really be the beginning of a very deep collaboration where states are developing EV development plans, but we at the federal government level, the joint office, will be working very closely to support the states, provide them with the data — the information, the know-how — in that process,” said Michael Berube, the Department of Energy’s deputy assistant secretary for sustainable transportation.

The goal will be to get the state plans submitted and approved, and then to get the first federally funded chargers installed this year, Berube said. “But our point really is, let’s get it right. Let’s make sure we have a good national plan.”

While not providing specifics, Polly Trottenberg, deputy secretary at the Department of Transportation, said the guidelines would reflect the joint office’s goals of equity, accessibility, reliability and affordability and include standards and requirements for industry partners to follow.

“The initial focus is really building out those national [charging] corridors coast to coast,” Berube said. “We’re going to make sure we’re hitting all the communities — rural spaces, urban spaces, everywhere there are interstates and major travel corridors — so that will provide a certain backbone of access and equity.”

Transportation Secretary Pete Buttigieg and Energy Secretary Jennifer Granholm launched the joint office in December to oversee the rollout of the EV charging funds from the IIJA. Trottenberg said $5 billion will go to “formula” grants to help the states implement their EV charging plans and $2.5 billion to a discretionary grant program.

The discretionary funds are intended, in part, for communities “where otherwise private investment wouldn’t go,” Berube told reporters after the announcement. The priorities include environmental justice issues and “those people that don’t have EV charging at home because those are problems and that’s really where government can come in to help solve some of those issues,” he said.

“We’re going be looking for ideas from the public sector, the states on innovative services to provide charging for people in that situation,” Berube said. “Is it DC fast-charging in their community? Is it Level 2 overnight charging? Is it street charging or at least at the multiunit dwelling facility? So, there is not a one-size-fits-all.”

Collaboration across federal, state and local agencies and the private and nonprofit sectors was itself a central theme of the half-day summit, which was organized by the National EV Charging Initiative, a coalition of regional and national groups, private companies and labor.

Working with utilities to ensure grid reliability, especially as the number of EVs and chargers increase, is also part of the joint office’s vision, Berube said.

“We have some test cases looking at smart charging management to have both EVs and the grid working together … to basically make sure that as we add EVs, which will be the largest new load on the grid, we do it in a way that can be managed as a managed load,” he said. “That is a lot of the Level 2-type charging, workplace charging, home and community-based charging. Deploying that smart charger technology at the grid side and the charger side will be one key aspect of the sector.”

The other big focus for the joint office will be highway charging facilities with fast chargers that can be upgraded continually, Berube said. With fast-charging technology hitting 150 kW and even 350 kW, the highway network “will really start to get the future EVs that are in the 300-mile range chargeable in that 15-minute window,” he said. “That’s the vision.”