Washington’s House Democrats have resurrected last year’s stalled attempt to add climate change mitigation to land use planning.
In the first action on the legislationthis year, the House voted 57-41 along party lines Friday to resend House Hill 1099 to the state Senate. Last year, the House approved the same bill 56-41 only to have the legislation stall in the Senate Transportation Committee, then chaired by moderate Sen. Steve Hobbs (D). (See Sponsor Plans to Revive Stalled Wash. Land Use Bill.)
Hobbs has since been appointed Washington’s secretary of state, and a more left-leaning Sen. Marko Liias (D) is now chair of the transportation Committee, improving prospects for the bill.
Last year, the bill by Rep. Davina Duerr (D) successfully made it through the Senate’s Housing and Local Government and Ways and Means committees before being held up. It must go through the same three committees again this year.
Duerr’s bill would add climate change as a factor in Washington’s Growth Management Act, which governs land-use planning by city and county governments. The bill would require comprehensive plans, development regulations and regional plans to support state greenhouse gas emission targets and improve resilience to climate impacts and natural hazards.
Her bill would have required climate change to be considered in land use and shoreline planning for the largest 10 of Washington’s 39 counties and in cities of at least 6,000 people. Washington’s 10 largest counties cover Puget Sound, Spokane, the Yakima River Valley and the Washington-side suburbs of Portland, Ore. A legislative memo said 246 county and city governments would be affected, including 110 jurisdictions outside the 10 most populous counties.
The bill calls for the state’s Department of Commerce to set guidelines by 2025 on how those areas can reduce GHG emissions and vehicle miles traveled. Because 40 to 45% of Washington’s GHGs come from motor vehicles, traffic issues would become a major priority in those guidelines.
“Planning should be about the future. It needs to be about improving the quality of life for our kids,” Duerr said in a press release. “That means reducing our contributions to climate change and planning our communities so they are better protected against disasters like flooding, fires and heat events. It also means creating livable, walkable communities as opposed to expensive urban sprawl.”
ERCOT said Wednesday that a retired gas-fired power plant is being brought back to life by its new owners.
The Texas grid operator said it received a notification that the Wharton County Generation plant, a 69-MW combustion turbine along the Texas Gulf Coast, would become operational as of Feb. 4. The plant was decommissioned and retired by Luminant in late 2020 after a forced outage.
However, after discussions with CenterPoint Energy, the interconnecting transmission service provider, ERCOT said the required studies and facility upgrades to return the unit to service will delay that targeted in-service date. Once the studies and upgrades have been completed, it will be allowed to return to service.
Luminant sold the plant in 2021. It is now owned by Phoenix Power Holdings, according to Texas regulatory filings.
In-person Meetings in March?
After initially planning to resume in-person stakeholder meetings in February, ERCOT also announced Wednesday that next month’s meetings will continue to be virtual.
In-person meetings will begin in March at its new headquarters building in the MetCenter office park in Austin. The new facility is being readied for occupancy, but ERCOT said it needs time to properly move in staff and ensure “all communication technologies are ready for effective stakeholder meetings.”
Travis County, in which Austin is located, has raised its COVID-19 guidelines to its highest threat level.
Environmental justice ran into reliability at FERC last week as commissioners debated whether the “sky is falling.”
The question of whether the Weymouth Compressor Station in Massachusetts, part of Enbridge’s Atlantic Bridge pipeline project, is dangerous for the communities surrounding it was front and center as the commission resolved a paper briefing on the project at its monthly open meeting Thursday (CP16-9-012). (See FERC Rejects Calls to Shut Down Weymouth Compressor.)
But lurking in the background was a familiar debate over whether pipeline constraints and limited gas supply are a threat to the reliability of New England’s grid.
In his concurrence and partial dissent on the order, Republican Commissioner Mark Christie wrote that the facility “under attack” in the proceeding is necessary to help alleviate gas supply concerns in the region.
He made the point as part of a larger argument that the commission’s paper briefing revisiting its original certification of the project was part of a worrying trend.
“Even today in two other cases, the majority is issuing a new procedural rule that will drive up litigation costs and create new avenues to attack certificates after they have been issued,” Christie wrote. “These actions do not appear to recognize the reality that a reliable supply of natural gas will be critically necessary to keep the lights on and homes warm in New England and the rest of the country for years to come.”
Christie was referring to FERC’s approval of requests for additional time from two separate developers to complete construction of their gas projects: Adelphia Gateway, a pipeline upgrade and extension project in Pennsylvania (CP18-46-004); and Delfin LNG, which is constructing onshore facilities in Louisiana to transport gas to a new offshore LNG port, possibly the first in the U.S. (CP15-490-002). Both developers cited the COVID-19 pandemic as causes for the delays.
While both Christie and fellow Republican Commissioner James Danly concurred with the decisions to grant the requests, they dissented over a new procedural rule introduced by the Democratic majority that allows new intervenors each time a request for extension is filed. Christie argued in his dissent that the new policy “will undeniably drive up the legal costs associated with building gas facilities, creating yet another disincentive to the construction of vitally needed infrastructure.”
Christie sparred Thursday with Commissioner Allison Clements, who said that FERC’s two Republicans have been claiming that the “sky is falling on regulatory certainty.”
“Given my experience as an infrastructure project finance attorney who has dealt with the risk of policy change, I’m confident that the path to regulatory certainty does not lie in continuing to ignore the legitimate concerns of stakeholders. It does not lie in hiding behind blanket claims of reliability risk,” Clements said.
Christie retorted that an “honest reliability dialogue” will acknowledge that gas is an essential part of reliability.
“And what this commission has been doing over the last year has been absolutely drawing a lot of uncertainty into whether we’re going to stand behind gas projects or whether we’re going to let gas projects be built at all, or subjected to such additional costs as they become unfeasible. So it’s not a ‘sky is falling’; it’s reality,” Christie said.
Opponents have challenged the Atlantic Bridge project on several grounds, including that it may be used to export LNG to other continents, but FERC shot down that claim when issuing its approval to the project in 2017. (See Atlantic Bridge Project Approved by FERC.)
Region on Edge
ISO-NE offered a familiar but increasingly loud warning ahead of this winter season that gas pipeline constraints was one of the issues threatening the region’s cold weather reliability. (See ISO-NE: New England Could Face Load Shed in Cold Snaps.)
That has led to increasingly loud complaints from New England states that the grid operator hasn’t done enough to ensure that the lights stay on this winter.
Last week, the rest of the New England states joined in with a NESCOE follow-up to that exchange along a similar line, suggesting that the RTO has not adequately replaced winter reliability programs that were halted in 2018.
ISO-NE “identifies immediate risks of sustained cold weather — an otherwise unremarkable occurrence for New Englanders — without any analysis of the magnitude of risk or any proposed way ISO-NE, the entity responsible for regional planning and system reliability, will act to address them,” NESCOE wrote.
ERCOT sailed through its second stress test of its system’s winter readiness over the weekend, easily meeting demand that came within 10 GW of its peak during last February’s winter storm.
The season’s second cold front swept through the state Thursday and Friday, bringing with it freezing temperatures and wind chills that dropped to levels where they could have affected power plant operations. System demand peaked at 63.5 GW, less than last year’s record peak of 69.2 GW, set Feb. 14 before demand and the frigid temperatures overwhelmed the system.
ERCOT declined to comment, but it’s more conservative operations approach and winter readiness activities resulted in a 10- to 15-GW cushion between demand and capacity.
The grid operator issued an operating condition notice (OCN) ahead of last week’s expected “extreme cold weather.”
During the second day of a two-day training session Jan. 18, interim CEO Brad Jones assured the Board of Directors that the OCN is just an initial step in ERCOT’s emergency alert system and that he was confident the grid operator would manage the situation.
“It’s not a significant reliability challenge,” Jones said.
The OCN signified a need for additional resources. An OCN is still three levels away from an energy emergency alert.
ERCOT’s operations alert levels | ERCOT
Staff told the board ERCOT had about 79 GW of operating capacity to meet projected demand of about 61 GW at its peak Thursday night and Friday morning. Dan Woodfin, vice president of system operations, said the capacity was “significant” and a “little more” than the grid operator had at its disposal during a Jan. 2-3 cold snap. (See ERCOT, PUC Say Grid is Ready for Winter Weather.)
Woodfin said that about 11.8 GW of thermal resources are currently on outages, a normal amount for ERCOT.
That did little to comfort some of the directors, who heard much about the lack of transparency between Texas’ electric and natural gas systems. The loss of thermal fuel supplies, primarily natural gas, have been fingered as the primary reason for the widespread power outages during last February’s winter storm. (See FERC, NERC Release Final Texas Storm Report.)
The electric industry has added weatherization requirements with regulatory teeth for its power plants since then, but the gas industry, regulated by the Texas Railroad Commission (RRC), has lagged behind. The commission is not expected to mandate strict weatherization practices until next winter.
Asked if ERCOT would have enough gas supplies for the system’s plants, Jones said staff had already received one notice of a gas restriction that could affect up to 1.5 GW of capacity.
“One of the concerns we have is the great deal of information we don’t have,” Jones said of the gas side. He said he has plans to add a gas desk in the operations center that would monitor gas availability or restrictions, an idea that he said was first brought up in 2015 when he was ERCOT’s COO.
“We had concerns [in 2015 that] we wouldn’t get the information we needed,” he said. “We’re still in the same situation. There’s not a great deal of transparency around the operations of our natural gas system. That information doesn’t usually flow to us.”
Jones and Peter Lake, chair of the Public Utility Commission, both pointed to the Texas Energy Reliability Council (TERC) as where dialogue and coordination between the two industries takes place. Lake said the group was an informal group before the winter storm, but that legislation last year formalized TERC and “designed it specifically for that kind of information sharing.”
TERC meets as often as twice a month, Lake said. However, the meetings are not public.
Director John Swainson pressed Lake on the RRC’s regulatory responsibility. Lake declined to speak for that commission, saying, “They do oil and gas. They’re sitting across the table from us at TERC.”
“Doesn’t that look like sort of a weakness in the system here?” Swainson asked. “We’re trying to ensure our generators can provide power, but if no one’s providing gas to our power plants, that’s a weak link.”
“That’s why the legislature gave us TERC, and that’s why TERC is meeting more frequently,” Lake responded.
Pipeline company Kinder Morgan warned its customers that the severe cold could result in wellhead freeze-offs and lead to gas shortfalls. Energy Transfer, which made $2.4 billion during the storm last year, threatened to cut off supplies to Luminant over what it said was an unpaid $21.6 million penalty for buying too much gas and oversupplying their pipelines. The parties eventually reached an agreement after Luminant filed a complaint at the RRC.
ERCOT’s meteorologist expects another cold front to move through Texas on Tuesday, bringing with it frozen precipitation and light snow over West Texas and the Panhandle on Wednesday.
Staff also updated the board on their weatherization inspections at power plants and transmission facilities, saying they have inspected 324 generation resources and 22 transmission sites. This followed receipt of winter weather readiness reports from 850 generators and 54 transmission service providers. (See ERCOT Generators Near 100% Winter Readiness Compliance.)
David Kezell, ERCOT’s newly hired director of weatherization and inspection, said the inspections found 10 potential deficiencies at dispatchable generation sites, not at intermittent renewable resources, and six at transmission facilities. He said all of the deficiencies are being tracked and that most have been resolved and closed.
“I believe the system is in much better condition this year than it was last year,” Kezell said.
With Kezell’s organization still staffing up, ERCOT was forced to rely on contractors to handle most of the inspections. Staff that were pulled from other departments helped with the more than 3,600 hours of work during the fourth quarter.
ERCOT filed a report on its winter weather readiness inspections with the PUC on Jan. 18 (52786, 52787).
The board also agreed with staff’s recommendation to reschedule its Feb. 8 meeting to March 7-8. Its meeting schedule was set under its previous format, which was overhauled by the Texas legislature following last year’s storm. Several of the new directors had conflicts with the February date.
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.
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.)
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.”
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.”
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.
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.
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.
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.”
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.
