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October 6, 2024

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ERCOT Technical Advisory Committee Briefs: Nov. 29, 2021

ERCOT’s Technical Advisory Committee last week held its last scheduled meeting of a year that was upended by February’s disastrous Winter Storm Uri.

The storm, which came close to collapsing the ERCOT grid, was linked to billions of dollars in damages and hundreds of deaths. It also resulted in political pressure and legislation that revamped the ISO’s board, the regulatory commission, and the market’s design, the latter of which has fallen partly on the stakeholder group to implement.

“What a year it’s been,” said South Texas Electric Cooperative’s Clif Lange, the committee chair, during its Nov. 29 virtual meeting. “We’ve had quite a bit to tackle this year, and we have done some really good work and provided some good information and feedback to the ERCOT board and the commission, as necessary.”

Despite the work, TAC faces uncertainty in its future. In July, interim ERCOT CEO Brad Jones discussed with the committee his plan to convert TAC into an officer-level group. During a candid conversation, Jones told members that if they didn’t “think TAC is in the crosshairs, you’re not paying close attention.” (See ERCOT Technical Advisory Committee Briefs: July 28, 2021.)

Since that meeting, Jones’ 60-point roadmap to improving grid reliability has updated his plans to note that TAC “has cancelled further discussion on this item until the new ERCOT Board and/or the [Public Utility Commission] initiate discussions on it.”

Lange told the committee that the board will review TAC’s processes and “make tweaks as necessary, while still retaining valuable input from the stakeholder process.”

“We don’t have any further guidance at this point on what further processes we need to review, but we’ll continue to engage with the board as they deem fit,” Lange told TAC’s members.

Storm-related NPRRs Pass

TAC members approved four nodal protocol revision requests (NPRRs) related to operational actions and other measures taken as a result of the winter storm.

Stakeholders offered some pushback against staff’s urgent measure NPRR1105 allowing ERCOT to instruct transmission and/or distribution service providers (TDSPs) to deploy any available distribution voltage-reduction measures before declaring an energy emergency alert (EEA). The revision is the result of Board Chair Paul Foster’s directive in October that TAC endorse the NPRR before the directors’ December meeting.

“We do think this can be an effective tool in the right circumstances,” Woody Rickerson, the ISO’s vice president of grid planning and operations, said in addressing concerns that the revision will put the system in a weakened condition. “We would like to see this passed so we can use this tool, but we welcome additional conversation on this.”

“It’s a small arrow in the quiver. I think it’s a wasted quiver,” Advanced Power Alliance’s Walter Reid said. “Hopefully, ERCOT will use this in a very judicious way.”

Morgan Stanley Capital Group’s Clayton Greer said he agreed with the NPRR’s use to avoid rolling blackouts but said, “In this instance, we’re not ever close to that level. We’re taking pretty severe action when we don’t even know whether there’ll be [severe] conditions present.”

Morgan Stanley and Demand Control 2 opposed the measure, which passed 23-2 with four abstentions.

A second change (NPRR1107) adds new fees for ERCOT’s weatherization inspections of the resource entity’s capacity divided by the entity’s aggregate capacity. Those inspections already have begun, with staff hoping to inspect about 300 facilities.

The NPRR also clarifies that existing generation interconnection or change request fees apply to all GI projects, regardless of whether they will interconnect at the transmission or distribution level. Those fees are $5,000 for projects less than or equal to 150 MW and $7,000 for projects greater than 150 MW.

Transmission service providers will pay $3,000 for each substation or switching station that is inspected.

“We would like to pay for the actual costs of our plants,” said NRG Energy’s Bill Barnes, who represents Reliant Energy Retail Services. He said lower costs for renewable resources “would be fair.”

The measure passed without opposition, although independent generators Engie North America and Avangrid Renewables abstained.

The committee also approved:

  • NPRR1103, which establishes the processes for assessing and collecting default charges and default charge escrow deposits for the debt-obligation order securitizing about $800 million owed to the market by cooperatives and municipalities. (See “Securitization Orders Finalized,” Texas PUC Nears Market Redesign’s Finish Line.) ERCOT expects to begin issuing invoices in January.
  • NPRR1106, codifying the grid operator’s current practice of deploying emergency response service when physical responsive capability falls below 3 GW before declaring an EEA. The PUC ordered the new approach in October.

Staff to Seek Price Correction

ERCOT will request board review and a price correction for eight operating days in September and October after staff discovered a modeling error for a generation transmission constraint in the day-ahead market. Staff patched the defect by the end of surrender, but not before determining the Sept. 30 and Oct. 6-12 operating days met the criteria for a price correction from the board.

Staff’s resettlements of the error resulted in more than $816,000 in increased charges and more than $122,000 in reduced charges to market participants.

The board will take up the issue during its meeting Friday.

Lange Honors John Dumas

TAC is short one member heading into 2022 following the recent death of the Lower Colorado River Authority’s John Dumas in November. Dumas, long a fixture in ERCOT circles and with more than 28 years of experience in managing electric grids and wholesale market operations, was one of four cooperative representatives.

“He was a great person to know. Very congenial and always willing to talk,” Lange said. “He contributed an extraordinary amount to the ERCOT market and the reliability of the system over his career. His influence on the ERCOT region will persist for quite a few years to come.”

Dumas joined LCRA in 2015 as vice president of market operations. Previously, he was with TXU, Vistra’s predecessor, before joining ERCOT in 2008 as manager of operations planning and then director of wholesale market operations.

Annual Membership Meeting Friday

Staff said ERCOT’s annual membership meeting will be held virtually on Friday. In lieu of the usual guest speaker, Jones and Foster will both deliver short comments. The 2022 TAC members, currently comprised of familiar faces, will also be announced during the 30-minute session.

The meeting will follow the board’s December meeting, which will be held in-person in Taylor. The directors will meet in executive session Thursday before holding an open session Friday morning. ERCOT’s Austin headquarters building is closed to meetings during the transition to a new nearby facility.

In-person stakeholder meetings are expected to resume in January, beginning with TAC on Jan. 26. ERCOT’s new headquarters workspace is expected to be ready by then.

TAC Endorses $1.28B Tx Project

TAC’s combination ballot, which passed unanimously, included the endorsement of a $1.28 billion dollar transmission project put forward by the Regional Planning Group. (See ERCOT Finds 345-kV Solution for Valley Constraints.)

The project would add 351 miles of transmission lines radiating from a new substation in the Lower Rio Grande Valley, where ERCOT and the PUC have identified an urgent need for more transmission capacity. The commission in September exerted its new-found regulatory muscle in bypassing the stakeholder process and directing three utilities to add a second 345-kV circuit to an existing transmission line in the valley. (See Texas PUC Directs Tx Construction in Valley.)

The combo ballot also included endorsement of ERCOT’s proposed 2022 ancillary service methodology. Staff recommended one change in computing minimum responsive reserve service (RRS) requirements by using a floor of 2.8 GW to meet the grid’s more conservative operations approach. They also proposed changing the minimum RRS-primary frequency response limit to 1.24 GW, based on NERC’s updated BAL-003 Interconnection Frequency Response Obligation assessment for next year.

The combo ballot also included five NPRRs, two Nodal Operating Guide revisions (NOGRRs), a pair of other binding document changes (OBDRRs), a revision to the Planning Guide (PGRR) and two modifications to the resource registration glossary (RRGRRs).

Members approved separately a revision request (NPRR1109) that allows a resource entity to bring a decommissioned generating unit back to service if it notifies ERCOT within three years of its removal from the network operations model. The measure passed by a 21-2 margin with six abstentions.

    • NPRR1077: expands NPRR1026’s self-limiting facility concept to include sites with one or more settlement-only generator (SOG) and introduces additional revisions to fully address requirements for generators and energy storage systems (ESSs) connected at distribution voltage. The NPRR requires the SOG’s qualified scheduling entity to provide telemetry of the injection or withdrawal at the point-of-interconnection (POI) for transmission-connected sites or point-of-common coupling for distribution-connected sites.
    • NPRR1091: addresses energy-price suppression and liquidity issues created by ERCOT’s early and greater procurement of ancillary service by extending the treatment of must-take energy from reliability unit commitments in pricing run to offline non-spinning reserve (non-spin), when it is manually deployed. The change also increases the amount of responsive reserve and non-spin services that an entity can self-arrange above its obligation.
    • NPRR1094: allows a transmission operator (TO) and a transmission and/or distribution service provider (TDSP) to manually shed load connected to under-frequency relays during an energy emergency alert (EEA) Level 3 if the affected TO can meet its overall under-frequency load shed (UFLS) requirement and its load shed obligation under the Nodal Operating Guide.
    • NPRR1101: modifies load resources’ deployment grouping requirements if they’re not controllable load resources (“NCLRs”) providing non-spin to include generation resources providing offline non-spin.
    • NPRR1104: corrects the definition of real-time liability extrapolated (RTLE) to include market activity for entities that have no load or generation but do have real-time exposure.
    • NOGRR231: updates ERCOT’s regional map in Section 1.1 to reflect the current boundaries.
    • NOGRR233: allows a TO and a TDSP to manually shed load connected to under-frequency relays during an EEA Level 3 if the affected TO can meet its overall UFLS requirement and load-shed obligation.
    • OBDRR034: provides ERCOT with the authority to move network operations model resource nodes for POI changes or resource retirements.
    • OBDRR035: aligns the non-spinning reserve deployment and recall procedure with NPRR1101’s revisions.
    • PGRR092: allows an interconnecting entity (IE) proposing a SOG to designate it as part of a self-limiting facility during the generator interconnection or modification (GIM) process, consistent with NPRR1077.
    • RRGRR029: allows an IE proposing a SOG to designate it as part of a self-limiting facility during the GIM process.
    • RRGRR030: removes voltage levels’ hard coding for certain resource registration information related to transformer data, allowing resources connected to other voltage levels to submit their data without receiving a validation error.
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‘Ecosystems’ Needed to Drive Green Hydrogen Growth

The widespread adoption of clean hydrogen in North America will depend on the construction of “ecosystems” that span economic sectors, state lines and national boundaries, industry supporters said last week at the Green Hydrogen Coalition’s virtual annual conference.

“A green hydrogen economy doesn’t exist in any one city or state; it is a regional and national solution,” Janice Lin, GHC founder and president, said Wednesday.

In wrapping up the two-day conference, Lin said one of her key takeaways was the need for creating hydrogen “hubs” internationally to lay the groundwork for expanded adoption of green hydrogen as a fuel source across multiple economic sectors.

In the U.S., the $1.2 trillion infrastructure bill passed by Congress last month provides $8 billion for development of four such hubs in the country, as well as $1 billion toward domestic production of the electrolyzers needed to produce hydrogen, part of the Department of Energy’s Hydrogen Energy Earthshot initiative. (See Granholm Announces R&D into Green Hydrogen as 1st ‘Energy Earthshot.’)

Sunita Satyapal, director of DOE’s Hydrogen and Fuel Cell Technologies Office, reminded conference participants of the initiative’s “1-1-1” objective: “One dollar for 1 kg of clean hydrogen in one decade.”

Through an effort that predates the infrastructure bill, GHC has been spearheading development of a green hydrogen hub centered in Southern California. The goal of the HyDeal Los Angeles initiative is to deliver green hydrogen for the Los Angeles Basin at $1.50/kg by 2030.

Lin said HyDeal LA was conceived in part to help combat the heavy air pollution that plagues the basin. The top five sources of smog in the region, she said, include ships, heavy-duty trucks, offroad equipment, aircraft and diesel locomotives, and much of that pollution emanates from activity related to the area’s massive ports in Los Angeles, Long Beach and San Pedro Bay.

Green hydrogen could be a “key enabler” for improving the region’s air quality, especially for residents living in the disadvantaged communities near the ports and along L.A.’s busy freeways, she said.

“It’s a scalable, commercially viable alternative, both as a direct fuel as hydrogen [and] as [an] energy ingredient in a synthetic fuel that can directly displace all fossil fuel use in and around the port,” Lin said. “Nearer term, we can use green hydrogen to go after cargo-handling equipment [and] heavy-duty vehicles, and in the medium- to long-term — and we call that 2025 to 2030 — we can use green hydrogen to go after locomotives, oceangoing vessels and harbor craft.”

Despite those objectives, Lin noted that HyDeal LA’s initial foothold into a green hydrogen economy will take shape in the electricity sector, as the Los Angeles Department of Water and Power (LADWP) converts the massive coal-fired Intermountain Power Plant in Delta, Utah, into a natural gas-fired plant capable of burning 30% hydrogen when it opens in 2025. With ample transmission capacity to draw on surplus solar generation, the facility will also be capable of producing hydrogen on site — and able to store large volumes in nearby salt domes.

Intermountain-Power-Plant-(Green-Hydrogen-Coalition)-Alt-FI.jpgIntermountain Power Plant in Delta, Utah, which LADWP plans to convert from coal to a gas-fired plant capable of burning a fuel mixture containing green hydrogen. | Green Hydrogen Coalition

LADWP will also replace its gas-fired Scattergood plant in El Segundo, slated for closure by 2024, with a new plant capable of burning a gas-hydrogen fuel mixture. The utility owns other gas-fired facilities that could also be candidates for conversion.

“Repurposing these power plants, and converting them from natural gas to green hydrogen has immediate local air quality and health benefits,” Lin said. “For starters, once power plants are converted to green hydrogen, their emissions are cut to zero for carbon dioxide, carbon monoxide, SOx, volatile organic compounds and particulate matter. In the future, these plants won’t be run as often because we’ll have a whole portfolio of abundant different types of renewable resources, and so the frequency will go down tremendously. That means the NOx emissions from the stack will also go down tremendously.”

European Ambitions

HyDeal LA was inspired by the HyDeal Ambition consortium, a similar and more advanced effort unfolding in Europe. Speaking at the GHC conference, HyDeal Ambition founder Thierry LePercq (also a GHC board member) said the concept was the result of collaboration among industry players and governments.

“But first and foremost, what is fundamental in the HyDeal approach is that you bring upstream companies — that is solar developers and electrolyzer makers; you bring the midstream companies — mostly gas transmission and storage; and then you bring offtakers in industry, in energy and potentially other fields,” he said.

LePercq said that as Germany ramps up its renewable capacity and works to phase out coal (by 2030) and natural gas from an electricity system that has already abandoned nuclear power, all dispatchable power serving the country will need to be “H2-ready.”

“What does that mean? It means that dispatchable power in Germany is going to be based on hydrogen. How many gigawatts of renewable energy [to produce the hydrogen] do you need to get there?” LePercq said.

The hydrogen hub intended to serve those needs will be based in an industrialized area of the northwestern Spanish province of Asturias. The renewables needed to produce the hydrogen will take the form of “captive” — or dedicated — solar resources that will generate low-cost electricity to power the electrolysis process.

LePercq said HyDeal Ambition is approaching its project with the idea of serving demand at scale, rather than serving a limited purpose.

“Because when you are a cement plant or fertilizer plant and steel plant, or a thermal power plant, you want very big volumes. You don’t want a tiny project supplying a tiny bit of hydrogen produced locally at super high prices,” he said. “And I must be frank with you: Until recently, in Europe, most of the projects that have been developed have been developed in what we call ‘policy’ hydrogen, small-scale hydrogen, which is not leaving too much, because small volumes, very high prices, [create a] need for very big subsidies.”

The large scale and ready market will enable green hydrogen to quickly become cost-competitive with natural gas, LePercq explained.

Collaboration Across Sectors, Boundaries

Lin has a similarly expansive vision for the HyDeal LA hub, which would connect the L.A. Basin with the Desert Southwest to include LADWP’s IPP project.

“Long term, we set out to make Los Angeles North America’s first green hydrogen industrial hub at scale, the first to achieve truly 100% renewable electricity affordably and reliably; move to fuel refining and alternative synthetic fuels; provide green hydrogen and its derivatives for shipping [and] aviation [and] maybe someday fertilizer; [and] demonstrate green hydrogen flight,” Lin said.

GHC is also talking with other governments — including Japan’s — about exporting green hydrogen, she said.

“As we look at hydrogen as a whole, we really like the idea of this hub approach, because we really need to maximize the capacity factors of the electrolyzers that we’re installing,” said Peter Sawicki, regional director of sales and marketing at Mitsubishi Power Americas, which will supply the turbines for the IPP project. “And in order to do so, we have to really bring in other sectors, which utilize maybe not as much hydrogen [on a] per-unit basis, but also utilize that hydrogen around the clock.”

Sawicki said LADWP and Mitsubishi are “blessed” with the massive storage capacity available at IPP, but for other regions he likes the idea of using pipelines to store hydrogen or move the fuel to and from storage fields.

“Mitsubishi is not going to be developing these pipelines throughout the United States. We’re looking for really partners on that approach as we look to build out this hydrogen infrastructure as we move forward,” he said.

Michael Healy, vice president of origination at 8minute Solar, said his company thinks the use of behind-the-meter solar is the most cost-effective way to produce clean hydrogen.

“It’s not just as simple as hooking up a solar plant to an electrolyzer. There are all these components that go into it, and it will really drive down costs if they’re integrated together in an efficient and optimal way,” Healy said.

Andrew Hegewald, Utah-based gas development manager for Dominion Energy, said four elements need to be addressed in building a hydrogen ecosystem: production, transportation, distribution and consumption. Furthermore, each sector, such as transportation or power generation, will require its own ecosystem.

“Once you understand the landscape, then it’s figuring out who would the partners be in building this ecosystem,” he said.

Barbra Korol, executive director of Alberta’s Department of Energy, noted that the Canadian province currently produces the equivalent of 24% of all hydrogen generated in the U.S., most of which is “gray” hydrogen produced from natural gas.

“Our ambition is to transition that gray production to blue hydrogen or ultra-low carbon — clean — hydrogen,” Korol said.

Alberta has an abundance of natural gas for producing hydrogen, but the province is open to “other pathways,” recognizing that its competitiveness will require reducing the carbon intensity of its hydrogen, she said. The province’s hydrogen strategy, released last month, calls for clean hydrogen “integrated at scale” for use in domestic and export markets.

“It’s very much a regional strategy that seeks to collaborate and find synergies with our partner to the west — our friends in British Columbia — as well as our friends to the south.”

“We feel there’s great alignment between the provinces, the [Canadian] federal government and our friends in the U.S., with each region holding different strengths and advantages, and that collaboration and partnership can address those challenges, resolve the gaps within the supply chain, and really advance this economy swiftly and with purpose,” Korol said.

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PJM TEAC Briefs: Nov. 30, 2021

Transource Re-evaluation

PJM stakeholders received an update on Transource Energy’s suspended Independence Energy Connection (IEC) transmission project at last week’s Transmission Expansion Advisory Committee meeting.

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Nick Dumitriu, PJM

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Nick Dumitriu, principal engineer in PJM’s market simulation department, provided an update on the 2020/21 long-term market efficiency window, highlighting the suspended project in Maryland and Pennsylvania.

The Pennsylvania Public Utility Commission voted 4-0 in May to reject a series of related applications and petitions filed by Transource for lines in Franklin and York counties. The PUC denied the project based on concerns about whether the need established in the PJM planning process met the requirement for needs specific to Pennsylvania. (See Transource Tx Project Rejected by Pa. PUC.)

The PJM Board of Managers endorsed the RTO’s recommendation to suspend the IEC project at its Sept. 22 meeting because of the “permitting risks” and to remove it from the pending Regional Transmission Expansion Plan models.

Dumitriu said PJM is required by schedule 6 of the Operating Agreement to “annually review the cost and benefits” of board-approved market efficiency projects that meet certain criteria to assure that a project continues to be cost beneficial. The annual re-evaluation is not required for projects that have started construction or have received state siting approval, and the Transource IEC was the only eligible project for 2021 re-evaluation.

Dumitriu said the base case analysis conducted by PJM yielded a benefit-to-cost ratio of 1.44, which excluded $131.88 million in sunk costs of incurred spending on the project. Dumitriu said that when the full in-service cost of $428.76 million for the project was analyzed, the benefit-to-cost ratio was 1.

The re-evaluation using a sensitivity scenario with higher load growth in PJM yielded a benefit-cost ratio of 2.08 with the exclusion of sunk costs and 1.44 for the full in-service cost.

A sensitivity scenario using additional coal retirements in the RTO yielded a benefit-cost ratio of 2 with the exclusion of sunk costs and 1.39 for the full in-service cost. Dumitriu said Talen Energy announced that its Montour generation facility in Pennsylvania and the Brandon Shores and H.A. Wagner coal generation facilities in Maryland, totaling more than 3,500 MW of generation, will cease coal-fired operations by the end of 2025 as the company moves toward renewable energy and battery storage projects.

Dumitriu was asked if PJM saw congestion growing on the AP South interface after removing the Transource IEC project. He said there are changes in congestion patterns after removing the IEC and that PJM sees “increasing congestion” on all the nearby constraints.

NJ OSW Projects

Work continues on proposals to interconnect New Jersey’s offshore wind projects through the 2021 state agreement approach window. Aaron Berner, PJM senior manager, provided an update on the 2021 RTEP analysis.

Berner said the proposals, which were presented at the October TEAC meeting, have been posted on PJM’s competitive planning page in redacted form. (See “NJ OSW Proposals,” PJM PC/TEAC Briefs: Oct. 5, 2021.)

East-Coast-Federal-Offshore-Lease-Areas-(AWEA)-Alt-FI.jpgNew Jersey is preparing to be a manufacturing and operational hub for wind projects up and down the East Coast. | AWEA

PJM is continuing to work through various analyses as part of the option 1a portion of the OSW window, Berner said, which included onshore upgrades on existing facilities. A total of 45 proposals were submitted for option 1a.

The RTO is working with entities who submitted proposals to identify issues in the planning process, Berner said, while also utilizing consultants as part of the competitive process to begin evaluations of construction processes and financial terms for the proposals.

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Aaron Berner, PJM

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Berner said PJM is concentrating on starting evaluations for 26 proposals that call for new offshore transmission connection facilities and eight proposals looking at offshore transmission networks. Berner said offshore transmission is more complicated because they’re not “traditional” facilities PJM has experience with building.

PJM is working toward adopting the schedule provided in the NJBPU guidance document indicating certain processes to be employed going forward during the project evaluations. New Jersey retains the right to elect to move ahead with any of the projects and is targeting the end of 2022 to make final decisions.

Berner said many of the proposals will be adjustable for changes in “scheduling accommodations” and the megawatt injection quantities based on NJBPU needs.

The BPU has already awarded three offshore wind projects in two solicitations: the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2 projects, both developed by Ørsted, and the 1,510-MW Atlantic Shores project, a joint venture between EDF Renewables North America and Shell New Energies US. The BPU is planning to hold three more solicitations over the next five years to help the state reach its goal of supplying 7,500 MW of offshore wind by 2035. (See NJ Awards Two Offshore Wind Projects.)

Generation Deactivation Notification

Phil Yum of PJM provided an update on recent generation deactivation notifications.

Yum said PJM received two battery deactivation requests in the ComEd transmission zone, including the Joliet Energy Storage battery and the West Chicago Energy Storage battery, which are both six years old.

Generation-deactivation-Map-(PJM)-Content.jpgGeneration deactivation announcements in PJM from 2018-present | PJM

Each battery unit has 20-MW capabilities for the energy portion, Yum said, but they were listed as 0 MW for capacity.

The requested deactivation date for both units is Feb. 8, and a reliability analysis is underway.

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PJM MIC Briefs: Dec. 1, 2021

Fuel-cost Policy Standards Proposal Endorsed

Stakeholders endorsed a joint PJM/Independent Market Monitor proposal regarding fuel-cost policy standards at last week’s Market Implementation Committee meeting.

The proposal, which was developed at the Cost Development Subcommittee, received 221 votes in favor (95%) and won 192 votes (95%) favoring it over the status quo.

PJMs-fuel-cost-policy-form-(PJM)-Content.jpgPJM’s fuel cost policy form. | PJM

Melissa Pilong, senior analyst in PJM’s performance compliance department, reviewed the proposal clarifying fuel-cost policy standards in Manual 15 and Operating Agreement Schedule 2 penalty language. The proposal was first presented at last month’s MIC meeting. (See “Fuel-cost Policy Standards and Penalties,” PJM MIC Briefs: Nov. 3, 2021.)

Pilong said the proposal includes a combination of clarifications and language for more elaboration on PJM’s 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.

It would have market sellers of generation units verifying that all intraday offer triggers are specified in the unit’s fuel-cost policy. Market sellers will also have to verify that weekend or holiday natural gas estimation practices match either the default assumptions in the PJM Fuel Cost Policy Guidelines contained in Manual 15 or specify estimation practices in the unit’s policy.

“This takes the burden off the market seller to have to update their fuel-cost policy to clarify what their estimation practice is,” Pilong said.

The Manual 15 updates include changes to the intraday update triggers. Pilong said market sellers need to have a one-time trigger to update the maximum allowable cost offer to opt into intraday offers.

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Paul Sotkiewicz, E-Cubed Policy Associates

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Paul Sotkiewicz of E-Cubed Policy Associates said he wished the issue would have been discussed in a different venue, calling attendance of the Cost Development Subcommittee “spotty at best.” Sotkiewicz said most stakeholders don’t have the ability to attend all PJM meetings, and many of the issues discussed at the CDS are “extremely down in the weeds and esoteric.”

Sotkiewicz requested that PJM find a way to bring some of the issues discussed at groups like the CDS to the MIC for broader discussions before they’re voted on.

“These are potentially pretty substantial changes that are happening that affect all generation owners,” Sotkiewicz said.

PJM will seek final endorsement of the proposal at the Members Committee in February and issue a FERC filing following approval by the Board of Managers.

Virtual Combined Cycles Regulation Endorsed

A proposal from Vistra addressing regulation for virtual combined cycles received unanimous stakeholder support in an acclamation vote.

Michael Olaleye, senior engineer with PJM’s real-time market operations, reviewed the proposal to revise Manual 12. The issue charge was originally endorsed at the May MIC meeting and worked on during committee meetings. (See “Virtual Combined Cycle Regulation Issue Charge Endorsed,” PJM MIC Briefs: May 13, 2021.)

Olaleye said units that are modeled virtually by PJM can sometimes receive varying regulation awards from the market clearing engine, which Vistra has been experiencing with some of its units. When a combined cycle unit is modeled as multiple virtual units, there is a possibility for unbalanced or unequal regulation awards to each unit by the engine.

Vistra’s proposed enhancement to performance group scoring calls for calculating the “hourly” score and extending it to each market resource with an assigned regulation for the given hour. It also called for PJM to calculate the “historic” performance score and extend it to each market resource in the performance group.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686783207.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Becky Robinson, Vistra

” data-credit=”Vistra” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Becky-Robinson-(Vistra)-FI.jpg” align=”right”>Becky Robinson, Vistra | Vistra

Olaleye said the enhancements would ensure that all resources of the performance group have the same historic performance score, which should fix the regulation clearing calculation problem in the software.

Becky Robinson of Vistra said the proposal should solve the identified problem that only impacts a “handful” of market participants while having “no negative effects” for other market participants not impacted by the regulation for virtual combined cycle units.

Capacity Offer Opportunities

Jason Barker of Exelon provided a first read of a problem statement and issue charge in conjunction with Brookfield Renewable to address the treatment of generation with co-located load and to examine capacity offer opportunities.

Barker said there’s a “burgeoning consumer interest” in co-locating new, large interruptible commercial loads behind the wholesale meter of existing generation resources. He said interested customers include those engaging in commercial activities like Bitcoin mining, server farms and hydrogen electrolysis that require “very fast” curtailment times of 10 minutes or less in their facilities.

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Jason Barker, Exelon 

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Barker-Jason-2019-03-06-(RTO-Insider)-FI.jpg” align=”left”>Jason Barker, Exelon  | © RTO Insider LLC

“This is a discreet and novel issue due to the characteristics of the load,” Barker said.

Customers are expressing preferences for a low-cost physical energy supply, Barker said, while others are seeking a carbon-free physical energy supply.

Barker said PJM’s current market rules make customer choices “challenging,” resulting in “unduly costly and inefficient outcomes for the grid.” He said PJM markets don’t offer options for fast-response interruptible customers to select physical supply from their choice of generator technology.

The issue charge includes investigating clarifications and market rule changes to support new interconnection configurations for highly interruptible load that is co-located with generation. Key work activities cited include education regarding current capacity offer requirements for existing generation resources and interconnection requirements for “new, large, fast-response interruptible commercial load.”

The expected deliverables in the issue charge are potential modifications to capacity market rules in the PJM tariff and relevant manuals and potential modifications to cost-based offer rules.

Work on the issue is expected to take six months at the MIC.

Consultant Roy Shanker said he believes state rules on the retail side will be relevant to the discussion, suggesting that the key work activities include education on how the modifications will interact on the retail side.

“There are lots of interesting rules and laws that may or may not apply to these kinds of arrangements based on state franchise laws,” Shanker said.

Erik Heinle of the D.C. Office of the People’s Counsel said he would like to see education included about how other RTOs and ISOs are handing the issue of generation with co-located load.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686783209.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

PJM Monitor Joe Bowring

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”capacity transfer rights ” align=”right”>PJM Monitor Joe Bowring | © RTO Insider LLC

Monitor Joe Bowring said the key work activities listed in the issue charge “make sense,” but he was a “bit skeptical” about how the issue is laid out for discussion. Bowring said the language can be interpreted as providing capacity value to the behind-the-meter customer but requiring other customers to pay for it.

Bowring suggested the issue charge should be revised to be more neutral but that it remains an important topic to discuss.

“It’s fundamentally about how the costs are getting assigned and who’s winning and who’s losing as a result,” Bowring said. “This is a potentially radical change to the capacity market design.”

The committee will be asked to approve the issue charge at the January MIC meeting.

Minimum Run Time Guidance

Tom Hauske, principal engineer in PJM’s performance compliance department, provided education and a first read of a problem statement and issue charge addressing pseudo-modeled combined cycle minimum run time guidance.

Hauske said PJM and the Monitor were bringing the issue forward as a result of the “disaggregation of many multiple block combined cycles” into individual pseudo-model market units, or virtual modeled combined cycle units. Market sellers can currently model a combined cycle unit as multiple pseudo units composed of a single combustion turbine and a portion of a steam turbine.

Hauske said if the market units of a pseudo-modeled unit are dispatched at different times on parameter-limited schedules, the potential exists for one or more of the pseudo-modeled units to operate “for some period beyond the minimum run time parameter limit for an identical non-pseudo-modeled combined cycle unit.”

The issue charge includes a key work activity of stakeholders developing guidance for market sellers regarding offering operating parameters for pseudo-modeled combined cycle units through education on the issue. Expected deliverables include revisions to Manual 11 or other relevant PJM governing documents.

Hauske said PJM was looking to use the “CBIR Lite” (Consensus Based Issue Resolution) process in Manual 34 to develop any manual changes and have final endorsements of any changes by the Markets and Reliability Committee’s meeting March 23.

Calpine’s David “Scarp” Scarpignato said the issue was a “little bit complex” to use the CBIR Lite process and that it would be better to conduct discussions under the normal CBIR process. Scarp said he prefers to use the normal CBIR process in stakeholder discussions “unless there’s a real reason to deviate from them.”

“I don’t see a burning reason to go to the lite process here,” Scarp said.

Hauske said the shorter process was suggested because PJM’s unit-specific parameter adjustment process starts on Feb. 28 with market sellers submitting requests. PJM must provide a determination on the requests by April 15.

Scarp said he “doesn’t see a huge reliability” threat if the issue isn’t resolved in time and didn’t want to rush discussions to get imperfect language implemented. He said the prior rules were used last year, and there were no major reliability concerns.

“I definitely want to get the work done, but I want to get it done in due diligence and a conscientious fashion,” Scarp said.

De-energized Bus Replacement

Vijay Shah, lead engineer in PJM’s real-time market operations department, provided a first read of conforming revisions to Manual 11: Energy and Ancillary Services Market Operations as part of five-minute dispatch and pricing. The changes are designed to address enhancements to the dead bus replacement logic for assigning prices to de-energized pricing nodes (pnodes).

Shah said the objective of the revisions are to provide increased transparency in the logic and how it performs replacements for de-energized buses. PJM is required to produce LMPs for all pnodes in the RTO’s network model for all intervals, including de-energized pnodes.

Shah said PJM wants to use new logic based on Dijkstra’s algorithm, an industry standard, to find a suitable replacement for de-energized pnodes. He said the algorithm uses the “least impedance path” to find a suitable source, and it’s to be implemented in both day-ahead and real-time market clearing engines.

The manual changes include updated language to reflect the new logic.

The committee will be asked to endorse the manual revisions at the MIC’s meeting Jan. 12, with final endorsement at the Jan. 26 MRC meeting. The new dead bus replacement logic would be effective March 1.

Manual 6 Revisions Endorsed

Members unanimously endorsed conforming changes to Manual 6 resulting from the endorsement of a proposal to address PJM’s auction revenue rights and financial transmission rights at the October MRC meeting. (See Stakeholders Endorse PJM ARR/FTR Market Changes.) Emmy Messina, senior engineer with the PJM market simulation department, first presented the manual changes at the November MIC meeting. (See “Manual 6 Revisions,” PJM MIC Briefs: Nov. 3, 2021.)

Messina said the changes would only impact Manual 6 and include language for bid limits and the network model user guide. The changes would update section 6.6 to reflect an increase of bid limits from 10,000 to 15,000 per corporate entity, auction round and period in FTR auctions. The February 2022 auction will be the first FTR auction with the updated limits.

Section 9.1 was also updated to direct stakeholders to a new network model user guide on the FTR section of the PJM website to get additional information on the auction.

PJM will now seek endorsement of the manual changes at the December MRC meeting.

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FERC Splits on Waivers from SPP IC Process

FERC last week settled a pair of disputes over waivers from SPP’s generator interconnection procedures (GIP), approving one and denying the other.

The commission reaffirmed Lookout Solar Park’s request for a limited waiver of the GIP’s financial security cure period and posting requirements in responding to SPP’s rehearing request (ER21-1841). However, the agency also denied Invenergy’s request for a prospective waiver from GIP security posting requirements (ER21-2807).

In the first Dec. 1 order, FERC found that the waiver request it granted Lookout Solar earlier this year satisfied the commission’s criteria for granting waivers in that the request did not harm third parties or have undesirable consequences. It clarified that the waiver order extended Lookout Solar’s timeline to either make the applicable financial security payments or withdraw from the generator interconnection queue.

Lookout Solar is developing a 110-MW solar facility in South Dakota and entered the SPP GI queue in 2017. It said in its waiver request that the grid operator posted the results of its definitive interconnection system impact study (DISIS) queue cluster on Oct. 30, 2020, but then reposted revised results on Nov. 20, 2020, triggering a requirement that Lookout Solar post about $16.9 million in financial security.

Proposed-Lookout-Solar-Park-(WAPA)-Content.jpgThe proposed Lookout Solar Park in South Dakota. | WAPA

The developer disputed the revised obligation and said it had reached an agreement via email with SPP that further modified the obligation to $8.1 million. The RTO posted additional study results in April allocating Lookout Solar $181.6 million in upgrades and requiring $28.1 million in financial security. SPP subsequently notified the cluster’s customers that it had identified errors in the DISIS and extended the cluster’s next decision point until May 13.

The solar developer contended that SPP acknowledged that the study “appeared” to over-allocate certain upgrade costs to the facility. It said the RTO did not revise the reposted study results and ultimately told Lookout Solar that no substantive corrections were required.

SPP withdrew Lookout Solar from the queue and asked that it post its financial security amounts to restore its position, leading the developer to file its waiver request. FERC granted the request over SPP’s objections.

Commissioner James Danly concurred separately with the order but expressed his “continuing concern” over the “innumerable” waiver requests FERC grants and reiterated that the commission “must be sparing in its liberality.”

Invenergy Issue not ‘Concrete’

The commission found that Invenergy did not demonstrate that its potential loss of posted financial security “is a concrete problem that warrants waiver” in the second order.

The renewable developer said it had eight interconnection requests pending in the same DISIS queue cluster as Lookout Solar. It alleged that SPP said the DISIS study would need to be redone because higher-queued requests were withdrawn from an earlier cluster. Invenergy said a discussion with SPP staff about the upgrades and assigned cost allocations left its questions unresolved.

Invenergy said that faced with the choice of withdrawing its requests or posting a third financial security to preserve its option to stay in the queue and avoid losing previously paid security amounts, it chose to post security under protest for three of its eight projects.

FERC said Invenergy did not show that its potential loss of its posted financial security was a concrete problem warranting a waiver from SPP’s tariff. It said there was not sufficient detail to demonstrate that an IC customer having to make decisions and provide financial security based on information it views as unsatisfactory warrants granting the waiver.

The commission also said Invenergy’s waiver request is distinguishable from Lookout Solar’s request in that the agency relied on undisputed allegations in the record of SPP’s inconsistent communications and actions.

Commissioner Mark Christie dissented from both orders, saying that after reading the Lookout Solar rehearing order, he could “reach no conclusion other than that today’s [second] order unduly discriminates against Invenergy in an unlawful manner.”

He said there is no “rational basis” for distinguishing between Invenergy and Lookout Solar and said the decision to deny Invenergy’s waiver on “thin factual differences is mystifying.”

“Today the commission relies on semantics to get itself out of the mess it inevitably made by granting the initial waiver in Lookout Solar — the result of which is to put Invenergy (and presumably any subsequent waiver applicants in the cluster) at a patently discriminatory commercial disadvantage to another member of the queue without any rational basis to distinguish the two waiver requests,” Christie wrote.

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SEIA Policy Forum Asks ‘To RTO or not to RTO?’

WASHINGTON — Organized power markets have proven their worth over the past 20 years, but former FERC Commissioner Tony Clark says that doesn’t mean RTOs are the best choice for states in the West and Southeast seeking regional cooperation and reliability.

A senior adviser at Wilkinson Barker Knauer, Clark said RTO membership should be a state decision. “As we move forward, are there third ways that are going to develop? It seems like there kind of are in ways that make sense for those regions,” he said at the Solar Energy Industries Association 30×30 Policy Forum on Thursday. He cited current discussions about regional resource adequacy in the Pacific Northwest and the Southeast Energy Exchange Market recently approved by FERC.

“To RTO or not to RTO?” was the question posed to Clark, current FERC Chair Richard Glick and former Commissioner Suedeen Kelly at the SEIA conference. The solar trade association has set a goal of solar providing 30% of U.S. power generation by 2030, and organized markets will be critical in that effort, said moderator Gizelle Wray, SEIA’s director of regulatory affairs.

Suedeen-Kelly-2021-12-02-(RTO-Insider-LLC)-FI.jpgSuedeen Kelly, Jenner & Block | © RTO Insider LLC

“Organized wholesale markets are the key to unlocking the cheapest, most reliable and affordable solar in the country,” Wray said. “We have seen time and time again that wholesale markets provide our members — independent power producers — with opportunities that are not afforded in vertically integrated states. At the moment, only organized wholesale markets are capable of providing the long-term certainty that clean energy businesses need to deploy solar and storage at scale.”

Glick said he favors RTOs and the benefits they provide in terms of economies of scale and regional power integration and reliability, but mandating their formation raises some thorny issues of jurisdiction. While he believes FERC does have the authority to mandate RTO membership for Western states, any such effort would not apply to municipal and public power utilities — such as the Bonneville Power Authority or the Los Angeles Department of Water and Power — which are outside of the commission’s authority.

“I think we need to encourage RTO development,” Glick said. “I think the time is now to act. We see the threats due to weather [and] the lack of resource sufficiency in certain areas. If [the states] don’t start working together, I think we’re going to see some calamitous issues.”

Kelly, partner at Jenner & Block, also underlined the advantages of RTOs — creating large, integrated transmission networks that foster reliability and eliminate unnecessary costs — but, like Clark, she saw the need for more flexible market structures. The West’s Energy Imbalance Market, while valuable, does not include a transmission component, she said, which makes it inefficient and difficult for “people in Santa Fe or Albuquerque to get an electron from California because they have to go through all the transmission [issues].”

“The states in the West come at this at a time when they’ve seen a history of how RTOs work,” Kelly said. “Most of those states want to see more renewables and a cleaner electricity mix. They have the opportunity to create an RTO that is not a cookie cutter, and my sense is that this FERC would be open to a construct that is not cookie cutter; rather [one] that is designed to achieve the goals” of those states.

Flexibility and False Dichotomies

The hundreds of gigawatts of solar and storage projects in interconnection queues across the country are, Wray said, “stuck in a perpetual waiting room because the transmission pathways to the markets are not being built.”

“This is not acceptable if we want to deploy a record amount of solar across the country,” she said. “We want FERC to reform the transmission planning process to include interconnection. Right now, renewable energy generators are left guessing which projects are needed and where, and these reforms will help to clarify the process and send the right market signals.”

Glick said changes to transmission planning are major priorities at FERC, with the Advance Notice of Proposed Rulemaking potentially providing solutions to bottlenecked interconnection queues. He expects a proposed rulemaking “by early next year,” he said.

As more renewables come onto the grid, flexibility, along with reliability, will be a key issue, Glick said. “There are certainly lots of ways to handle reliability, but how do you attract, how do you encourage flexibility?” he said. “Whether it’s gas or storage, how do you encourage, how do you incent [it] so it’s adequately compensated for the value it provides to the grid?”

Tony-Clark-2021-12-02-(RTO-Insider-LLC)-FI.jpgTony Clark, Wilkinson Barker Knauer | © RTO Insider LLC

While agreeing that thorough-going changes are needed, Clark argued that RTOs are not the only answer, particularly for reliability. “There’s sometimes a false dichotomy that’s presented to public policymakers, which is on one hand here, we have markets and free enterprise and competition and that’s RTOs, and on the other hand we have big, bad old [state] regulation,” he said.

Drawing on his experience at FERC and as a state regulator in North Dakota, Clark said, “There’s as much politics and rent seeking and regulatory capture in the RTO stakeholder processes as we ever dealt with in the cost-of-service regime. So, what you’re really dealing with is a couple of different administrative constructs, both of which can utilize myths of competition, or elements of competition, to try to drive outcomes that are good for consumers.”

States with vertically integrated utilities may be better at ensuring capacity than those with restructured retail power markets, Clark said. “The reason is because if you need to retain that sort of dispatchability in your capacity, you just go to your state commission [and] you build it into rates,” he said. “It’s going to be a trickier situation in most regions that have transitioned away from that.

“In my mind, Texas is kind of the canary in the coal mine on that issue,” he said, referring to last winter’s power outages in the state.

Getting Rid of Barriers

Kelly noted that the U.S. has experimented with a range of market-making strategies. The Public Utility Regulatory Policies Act helped kick-start the commercial and utility-scale solar market, she said.

Creating markets through incentives could be the “advantageous” result of the Build Back Better Act, with its $555 billion in funding for tax credits and other clean energy programs, she said.

But FERC’s creation of the RTOs and wholesale power markets was “revolutionary” for the U.S., she said. Beyond economies of scale and cost savings, the deployment of new technologies was also a core driver for the initial formation of RTOs, she said. But at that time, combined cycle natural gas plants were the “new guy on the block” facing market barriers from vertically integrated utilities, she said.

The caveat, Kelly said, is that state participation in RTOs is “optional, but an option that I think everyone should have available to them. The more buyers and the more sellers that can come together in one place, the better.”

Glick said FERC’s role is to remove barriers to markets, such as the commission’s orders opening wholesale markets to demand response (Order 745) and energy storage (Order 841).

“But we have a lot more to do in terms of hybrid resources,” such as solar and storage projects, he said. “Are there market rules out there discriminating against hybrid resources? Offshore wind is another area we need to take a look at; are there barriers there we need to get rid of? That’s the prime objective the commission needs going forward: getting rid of barriers.”

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NJ Hearing Debates 300 MW Competitive Solar Solicitation

A plan that would put solar developers in a competitive bidding process for state incentives for their projects received a mixed reception at a Tuesday hearing before the New Jersey Board of Public Utilities. The state’s top consumer advocate expressed support for the plan, but solar advocates said the proposed process would inject too much uncertainty into project finance, which would in turn draw few bidders.

The main point of contention was the BPU’s proposed Competitive Solar Incentive (CSI) Program, under which developers of solar projects above 5 MW would have to participate in a competitive bid to set the level of payment they would receive for solar renewable energy credits (SRECs) for their projects. Both behind-the-meter and grid-tied projects above 5 MW could participate, and the BPU would rank the bids and award the incentives to the lowest bidder.

The goal of the CSI program is to add 300 MW of new solar to the state’s energy mix every year, reaching a total of 17 GW of capacity by 2035 and 32 GW of solar — about 34 % of the state’s electricity — by 2050. Developers say grid-scale projects will be essential to meet the state’s targets. According to figures from the Solar Energy Industries Association (SEIA), the state has about 3,739 MW of solar installed.

But Scott Elias, senior manager of state affairs, mid-Atlantic, for SEIA, questioned how many developers would be interested in participating in the CSI solicitations for large, net metered projects, given the preparation work needed, without knowing the size of the incentive in advance.

“It’s pretty impractical for developers to meaningfully engage in complex and lengthy power purchase agreement negotiations with an offtaker [solar power purchaser] without knowing the revenue streams that will be available,” Elias said.

However, Sarah Steindel, assistant deputy rate counsel at the New Jersey Division of Rate Counsel, welcomed the BPU’s effort to set the level of incentives by a market process, rather than staffers deciding the incentive levels, as was done in the past.

“Over the years, rate counsel has advocated for competitive processes as a tool to control the high costs of solar for New Jersey’s utility ratepayers,” she said. “We strongly support the current effort to let the competitive market tell us what levels of subsidies are truly required to meet the state’s renewable energy goals.”

Tuesday’s hearing was the first of several the BPU expects to schedule to gather public input on the competitive component of the board’s plan for reshaping New Jersey’s solar incentive system, which the board released in July. The BPU expects to complete the information gathering process by the end of the year and develop a program guideline proposal by the end of March 2022. Additional hearings on the proposal will then be held, with the goal of having a completed plan in late spring.

“We’re working with getting the maximum benefits to ratepayers at the lowest cost,” said Louisa Lund, project manager for Daymark Energy Advisors, the consultant hired by the BPU to help develop the CSI program. “We want to support the growth of the solar industry. We want to help New Jersey meet its renewable energy credit goals. And we want to have a transparent process.”

Shrinking Incentive Rates

Earlier this year, Gov. Phil Murphy signed the Solar Act of 2021, which created a new incentive program and competitive bidding process for projects above 5 MW, with the goal of encouraging larger-scale projects in the state. (See NJ Grid-scale Solar Bill Signed by Murphy.) A few weeks later, the BPU incorporated that program into a larger new program to revitalize solar sector incentives offered by the state.

The new program, known as the Successor Solar Incentive Program (SuSI), includes two parts: the CSI competitive bidding program and the Administratively Determined Incentive (ADI) program, providing incentives for net metered residential projects, net metered nonresidential projects of 5 MW or less, and community solar projects. The ADI program was not the focus of the hearing Tuesday.

The legislation created a new program of solar renewable energy certificates, SREC-II, to be reimbursed by the BPU for each megawatt-hour of energy produced, with a goal of deploying 3,750 MW of new power generation capacity by 2026. (See NJ Sees Solar Growth in Reduced Incentives.)

New Jersey awarded similar energy credits for more than a decade through the Solar Renewable Energy Certificate (SREC) Program, which paid about $250 per MWh of power generated. Concerns about that program’s expense led to the Clean Energy Act of 2018, which shut down the SREC program when solar generation hit 5.1% of the state’s electricity production. That cap was achieved in April 2020, after which the state created an interim program with transition renewable energy credits (TRECs) of about half the value of those in the original SREC program.

Under the new program, SREC-IIs will be awarded in both the CSI and the ADI programs, with the value of certificates set in the ADI program varying between $70 and $100 per MWh, depending on the type of project, with an additional $20/MWh for public projects.

About 60% of the new capacity is expected to be generated with incentives at rates set by the BPU, and competitive bids under the CSI program will account for the remainder, with an emphasis on non-greenfield projects.

“We know that there’s a preference in New Jersey for developing on the previously disturbed lands,” Carrie Gilbert, internal project sponsor for Daymark, told the hearing. “But we wanted to understand some of the particulars of developing on contaminated land and landfills: like, how is the development timeline different than maybe a greenfield project? Are there additional costs? What kind of information could you provide on the environmental benefits that might help us figure out a ceiling for additional costs?”

Other issues raised by the BPU staff for public input include whether SREC-II subsidies should be provided through administrative rules or contracts, and whether developers believe that either of the two systems has “any implications on project cost, risk premium or other aspects of project financing.”

Seeking Serious Projects

The BPU and Daymark highlighted several specific issues for public input at the forum, including

      • whether projects on contaminated land and landfills should get special consideration — and longer time frames for completion — due to their complexity;
      • how big a fee the agency should charge bidders to take part in the competitive solicitation;
      • what kind of barriers might prevent the participation of public agencies in the bid process — such as public procurement requirements, financing and rigid timelines — and how can the BPU shape the program to alleviate them.

Joe Henri, vice president of business development at Dimension Renewable Energy, a California-based developer of community solar projects, encouraged the board to set application fees and performance deposits at levels high enough to “discourage speculation” and ensure a pipeline of viable projects.

“Performance deposits tend to suck the speculation right out of the market,” Henri said. “Knowing that you have a nonrefundable deposit helps focus the developer. If it’s a substantial and meaningful deposit, it ensures that their financiers have been over the proposed project to make sure that it’s actually viable and has a chance to go forward and produce what it’s promising to produce.”

Elias, of SEIA, said that if the competitive bid program goes ahead, it should avoid awarding fixed SRECs, which might “not offer any energy revenue certainty to project investors.” Although the SREC value will not change, fluctuations in energy prices will mean the developer’s income from selling energy will vary as market prices go up and down, Elias said. To avoid that, he suggested that the BPU consider an “Index-REC,” like the one offered in New York and being implemented in Illinois.

In the proceeding for the New York rule, the American Wind Energy Association [now the American Clean Power Association] and the Alliance for Clean Energy New York filed a petition arguing for an indexed REC based on a reference market index that will change monthly over the life of a project contract. Indexed RECs would serve as a hedge against market volatility, lower the financing costs for renewable generators, and provide lower costs and less volatile prices for ratepayers, the organizations said. (See NYPSC Expands Energy Efficiency, Indexes RECs.)

Echoing that argument, Elias said, “Instead of staying fixed, the Index-REC price will go up or down depending on the direction of prices in the energy and capacity markets.” That ensures “a consistent amount of revenue for developers, and the projects can always get what they need. This basically de-risks the revenue for the developer and [independent power producer] and allows the REC bids to be much more competitive” because they don’t have to add in a safety margin to the bid to account for possible market fluctuations, he said.

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Vermont Energy Plan Targets 100% Zero-emission Car Sales by 2035

Vermont has released a draft comprehensive energy plan (CEP) for the state that aims to facilitate a clean energy transition in an equitable manner while keeping electric sector costs down.

Among the draft’s recommendations is to make all light-duty vehicles sold in the state zero-emission by 2035.

The plan would expand the state’s “aggressive” renewable energy target and adopt the state’s greenhouse gas reduction requirements, said TJ Poor, director of the Vermont Department of Public Service’s (DPS) Efficiency and Energy Resources Division.

“We also recognize that currently the burdens and the benefits of energy policy in the state have not been equitably distributed across the state or its people,” he said during a public stakeholder meeting for the CEP on Thursday.

The DPS must update the state’s energy plan every six years, and it will provisionally adopt the CEP in January after taking public comment on the draft by Dec. 20.

EV Sales

In the 2016 CEP, DPS set a goal of having 10% of vehicles in the state powered by electricity by 2025. By the end of 2015, there were slightly more than 1,000 electric vehicles registered in the state. The total in-state passenger vehicle registrations at the time was 550,000.

By 2017, passenger vehicle registrations had risen to 578,000, and by the end of 2020, just fewer than 4,000 were EVs, according to the Energy Action Network’s 2020/2021 Annual Progress Report for Vermont. And new passenger vehicle sales, the report said, averaged 38,500 annually between 2012 and 2020.

Of the vehicles sold in that period, a steadily increasing number were light passenger trucks or sport utility or crossover utility vehicles, reaching 85% in 2020. The state will face specific challenges in transitioning sales in those vehicle categories to zero-emission technologies in the near term.

All-electric SUVs and CUVs currently on the market range in price from $40,000 to $100,000, and light-duty trucks are yet to arrive. The draft CEP acknowledges that Vermont’s zero-emission vehicle goal is dependent on the national vehicle market, and the state should re-evaluate the EV sales goal regularly. It also suggests that Vermont can influence the national market by adopting California’s ZEV standards, which will help put pressure on vehicle manufacturers to produce more EVs.

In addition, Vermont’s state-level incentives for EVs are not available for models that cost more than $40,000.

“This presents a particular problem in rural areas of the state where [all-wheel drive] vehicles are a necessity,” the draft CEP said. “Higher incentive amounts will help accelerate the [plug-in EV] market, encouraging consumers to purchase EVs sooner than they might otherwise do so.”

Vermont also needs to incentivize development of a fast-charging network in advance of the passenger fleet’s ability to sustain it. The state is “a long way” from having the charging units needed to support electrification of the transportation sector, according to the draft CEP.

“To the extent funding is available, Vermont needs to substantially up its investment in [EV infrastructure],” the draft says. “This may need to include funding to operate fast-charging stations at unprofitable sites for a period of years until the market share of [plug-in EVs] increases enough to make these stations profitable.”

Other options in the draft plan for reducing transportation sector emissions include:

  • establishing an incentive program for electric medium- and heavy-duty vehicles;
  • determining the viability and cost-effectiveness of converting the state’s diesel transit bus fleet to electric;
  • encouraging utilities to include utility load management for home and workplace EV charging; and
  • encouraging utilities to offer rates that relieve fast-charging load from traditional demand charges.

Climate Plan Alignment

DPS staff worked closely with the Vermont Climate Council this year to ensure that the updated CEP would be in line with the council’s first Climate Action Plan (CAP). (See related story, Vt. Climate Council Adopts ‘Initial Climate Action Plan’.)

The council adopted its initial CAP on Dec. 1, but Poor said the CEP and CAP “are distinct plans.”

Both plans target GHG reduction requirements set by Vermont’s 2020 Global Warming Solutions Act. And while they shared energy sector analyses and public engagement during development, the CAP addresses energy and non-energy sector emissions.

The CEP and CAP also share recommendations to:

  • adopt California’s Clean Cars II regulations;
  • expand existing state weatherization programs (The CAP target is 90,000 homes by 2030, while the CEP target is 120,000 homes by 2030.);
  • consider a clean heat standard;
  • expand the state’s 75% renewable portfolio standard to 100% carbon-free power (The CAP target is “no later than” 2030; the CEP target is by 2032.); and
  • continue to work with other jurisdictions on implementing the Transportation and Climate Initiative Program and consider participating in it.

Equity

For the first time, the CEP seeks to “root out and redress” inequities in the energy system that “continue to disproportionately impact many of Vermont’s communities,” Poor said.

A chapter on equity and injustice issues in the state leverages the work of the Vermont Climate Council’s Just Transitions Subcommittee in preparing the CAP.

The subcommittee’s work “really grounded the energy plan,” Poor said, noting that the draft CEP recommends that equity be centered in decision-making alongside cost and environmental issues.

Among the CEP’s recommendations for a just transition is a call for the DPS to develop a diversity, equity and inclusion strategy.

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OGE, CenterPoint Complete Enable’s Disposal

OGE Energy (NYSE:OGE) and CenterPoint Energy (NYSE:CNP) said last week that midstream energy company Energy Transfer Partners (NYSE:ET) has completed its acquisition of their Enable Midstream Partners gas-gathering partnership.

The $7.2 billion all-equity transaction was announced in February. (See Energy Transfer to Acquire Enable Midstream.)

OGE, which owned about 79% of Enable’s common units together with CenterPoint, will keep approximately 3% of Energy Transfer’s outstanding limited partner units with the transaction’s consummation. CenterPoint received about 201 million common units of Energy Transfer and $5 million in cash for its common units of Enable and general partner interest.

OGE CEO Sean Trauschke said in a statement that the acquisition “is an important step in OGE’s plan to become a pure-play electric utility.”

“We are now firmly on an accelerated path to reducing our exposure to the midstream industry,” CenterPoint CEO David Lesar said.

Enable was created in 2013 by merging OGE’s Enogex midstream subsidiary with CenterPoint’s pipeline and field services businesses. OGE held a 25.5% limited partner interest and a 50% general partner interest in Enable; CenterPoint owned 53.7% of the common units representing Enable’s limited partner interests.

In early 2020, OGE and CenterPoint took major earnings hits when Enable halved its quarterly distributions to investors and cut its capital expenditures for 2020 by $115 million. The cost reductions came during a global slump in petroleum demand and the COVID-19 pandemic. (See Enable Losses Slam CenterPoint, OGE Energy.)

Energy Transfer now owns and operates more than 114,000 miles of pipelines and related assets in all major producing regions in the U.S. and markets across 41 states.

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Michigan ROFR Bill Approved, Sent to Governor

LANSING, Mich. — Legislation granting incumbent transmission owners the right of first refusal to build and operate transmission lines in Michigan is on its way to Gov. Gretchen Whitmer (D) for signature after winning final legislative approval.

SB 103, which would benefit ITC Holdings and American Transmission Co., was sent to Whitmer by the Michigan Senate Thursday after the House approved the bill in a 71-29 vote late Wednesday.

Whitmer’s administration has said nothing about the legislation, which had bipartisan sponsors, including Democratic Sen. Curtis Hertel Jr., who succeeded Whitmer in the Senate. It was opposed by only a few Democrats.

Most of the 29 opponents in the House were the most conservative of the majority Republicans.  The most conservative Republicans opposed the bill in the Senate, which is also controlled by Republicans.

ITC-Michigan-Tx-Map-(ITC-Holdings)-Content.jpgITC Holdings’ ITC Transmission and Michigan Electric Transmission Co. serve most of Michigan’s Lower Peninsula through a network of about 8,700 circuit miles. The companies have made $5.5 billion in capital investments in the state since 2003. | ITC Holdings

The bill was unchanged by the House from the version passed in the Senate in October. (See Mich. Senate OKs Transmission ROFR for Incumbent TOs.)

The bill would apply to “regionally cost-shared” transmission projects, such as those resulting from MISO’s Transmission Expansion Plan. It takes advantage of the exception under FERC Order 1000 that allows states to create a ROFR. The order prohibited such rights in tariffs filed with the commission in a bid to create competition, although some incumbents have recently urged FERC to reverse the prohibition in the commission’s Advance Notice of Proposed Rulemaking proceeding. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

With the legislature pushing to finish the 2021 session this week, the House Energy Committee reported the bill on Tuesday, and it was rushed through its final readings on the House floor before passing.  There was no debate on the bill in the House.

John Dulmes, executive director of the Michigan Chemistry Council, blasted the legislation, calling Michigan’s electric costs a major barrier to attracting investments and jobs. “That’s why it is disappointing to see today’s vote to support the interests of a monopoly energy company instead of ratepayers. Our policymakers need to get serious about competitive energy policies and the high bills paid by our businesses and residents,” Dulmes said in a statement.

The state’s utility costs — some of the highest in the region — were cited as a reason Ford Motor Co. (NYSE:F) announced in September it was locating a major new electric vehicle factory in Tennessee.

The Chemistry Council was one of only a few vocal opponents to the bill.  The measure was backed by as many as a dozen groups, including labor groups and the Michigan Chamber of Commerce.

When the bill passed the Senate, the chief sponsor Sen. Wayne Schmidt (R ), said the state’s efforts to reduce carbon emissions through electrification will require more transmission in the state. The bill will help ensure a more orderly system to develop transmission, he said.

Whitmer will have 14 days to sign or veto the measure once she receives the proofed and printed version of the bill.