Virginia regulators have graded Dominion Energy’s proposed integrated resource plan as incomplete, saying the company must provide more information on how it will comply with the Virginia Clean Economy Act (VCEA) approved by lawmakers last year.
retire all carbon-emitting electric generation plants by the end of 2045;
participate in a renewable energy portfolio standard (RPS) program; and
seek commission approval by the end of 2035 to construct or acquire 16.1 GW of solar and onshore wind, 5.2 GW of offshore wind and 2.7 GW of energy storage.
Dominion Energy Virginia, which owns 27,100 MW of generation, has proposed building 2.6 GW of wind generation off the coast of Virginia and is about halfway through a plan to add 3,000 MW of solar generation. Its proposed IRP for 2021-2045 would quadruple the amount of solar and wind generation in its previous 15-year plan. (See Dominion Undecided on FRR Option.)
Dominion Energy solar farm in Louisa County, Va. | Dominion Energy
But that didn’t go far enough, the State Corporation Commission said in an order Monday (PUR-2020-00035).
“The commission recognizes that Dominion did not have an extended opportunity to conform its 2020 IRP to address all the interrelated aspects of recent legislation. The commission, however, cannot conclude, based on the record in this proceeding … that Dominion’s 2020 IRP, as filed, is reasonable and in the public interest for purposes of a planning document,” it said.
More Detail in Updates
The commission said the utility’s 2021 and 2022 updates to the plan must improve the modeling of alternative plans for complying with the VCEA and explain how its plan will address environmental justice issues.
The 2020 plan included four alternatives for complying with the act, but commission staff and other commenters challenged the company’s modeling and the reasonableness of the results. “With few exceptions, Dominion’s VCEA plans are substantially similar and do not model multiple paths to compliance with the VCEA,” the commission said.
It said Dominion would “substantially overbuild” the capacity it needs to meet peak load and energy requirements. One of the plans included capacity in excess of projected load of 1,800 MW in 2027, rising to 7,400 MW by 2045.
The VCEA plans also produced more renewable energy credits (RECs) than required by the RPS program. “Dominion’s modeling of the VCEA’s RPS Program requirements did not consider monetizing or banking excess RECs or model the RPS Program deficiency payments.”
Dominion did not update its forecasts of future energy, capacity and fuel prices to reflect the passage of the act, regulators said.
Several commenters, including Appalachian Voices and the Sierra Club, criticized the plan for modeling 970 MW of new natural gas-fired combustion turbines to be added between 2023 and 2024 in all VCEA plans. The company said the resources were “placeholders” to address potential reliability problems from the addition of large amounts of intermittent generation. “In the future, the company should also include one or more plans without such ‘placeholder’ additions to address reliability concerns for comparison purposes and to improve transparency in the company’s planning processes,” the commission said.
Appalachian Voices and the Natural Resources Defense Fund also criticized Dominion for not modeling any energy efficiency targets after 2025. The VCEA set EE targets through 2025 and directed the commission to set targets after that date. “The commission has not yet set the post-2025 energy efficiency targets,” regulators said. “We agree, however, that assuming those targets would be zero after 2025 was unreasonable and direct the company to continue to model energy efficiency targets after 2025.”
Staff, the Attorney General’s Division of Consumer Counsel and other commenters also faulted Dominion for not including a least-cost VCEA compliant plan.
Glen Besa, retired director of the Virginia chapter of the Sierra Club, took issue with Dominion’s inclusion of a 300-MW pumped storage facility, which he contends is uneconomic, while staff said the company included a second tranche of offshore wind not mandated by the act.
Environmental Justice, Bill Impacts
The commission noted that the 2020 plan was the first in which Dominion was expected to address environmental justice in its long-term planning. “In addition to addressing environmental justice in more specific contexts, such as requests for certificates of public convenience and necessity for particular facilities at known locations, the commission finds that the company should address environmental justice in future IRPs and updates, as appropriate,” it said. “As one example, the company may consider the impact of unit retirement decisions on environmental justice communities or fenceline communities.”
Regulators were also skeptical of Dominion’s analysis of its plan on customer bills. The company projected residential bills would increase by $52.40 and $55.02 per month by 2030. Commission staff said the utility understates likely increases because it projects that it will recover a declining percentage of its costs from the residential class over the next decade. Based on current allocation factors, staff estimated bills would rise by $64.27 to $67.32 monthly based on the company’s compliance with the act.
Commissioner Angela L. Navarro, who was appointed in December and confirmed last week, did not participate in the order.
Dominion spokesman Rayhan Daudani said the company “will carefully review the commission’s order and incorporate its direction in our next IRP filing. We appreciate the commission’s acknowledgement of the vital role electric reliability plays and look forward to working with our regulator to make our strong record of reliability even better.”
Commenters will have a chance to discuss the IRP on Feb. 12, when the commission will hold a public hearing at 10 a.m. on Dominion’s RPS plan (PUR-2020-00134). The deadline for registering to speak is Feb. 10.
Pacific Gas and Electric said Tuesday it had agreed to sell rights to install wireless communications equipment on 700 transmission towers and other infrastructure for $973 million, plus future licensing revenues on 28,000 other towers and equipment that could bring in millions more per year.
The deal with a wholly owned subsidiary of SBA Communications will help PG&E recover from years of wildfires sparked by its equipment and its ensuing bankruptcy, which ended in June, the utility said in a statement.
“When we emerged from Chapter 11, we made a commitment to achieve financial stability and bolster our overall financial health and we’re delivering on that objective,” PG&E interim CFO Chris Foster said. “Strategically selling non-core assets like these is one way we’re continuing to follow through on that commitment, reduce our financing needs and strengthen our balance sheet.”
California’s largest utility paid fire victims and insurance companies tens of billions of dollars as part of its plan to exit bankruptcy, including giving fire victims a 22% stake in the company. (See PG&E Trying to Move Forward from Bankruptcy.)
The utility said the deal will help ratepayers and fire victims.
“PG&E estimates that approximately half of the net sale proceeds will be returned to electric transmission and distribution customers in the form of lower monthly bills,” it said. “Furthermore, the net transaction proceeds are expected to help partially offset future equity issuances and dilution of PG&E shares, a substantial portion of which are held by the fire victim trust established to compensate victims of 2015, 2017 and 2018 fires.”
The license agreement with SBA will be for 100 years, though PG&E will retain the right to terminate it for individual cell sites for regulatory or operational reasons, the company said. It also allows SBA to enter sublicensing agreements with wireless providers that attach equipment to transmission towers and other utility structures, giving PG&E a portion of those future revenues, the utility said.
“SBA will have the exclusive rights to sublicense and market potential additional attachment locations on approximately 28,000 of the utility’s other electric transmission towers to carriers for attachment of wireless communications equipment,” with licensing fees split between PG&E and SBA, the utility told the U.S. Securities and Exchange Commission in a filing Tuesday.
“PG&E is not selling any transmission towers as part of this transaction,” it said in its statement.
FERC and the California Public Utilities Commission have both approved the installation of wireless antennas on transmission towers as a secondary use, PG&E said.
SBA CEO Jeff Stoops said that with 5G networks expanding, the “transaction adds a significant portfolio of high-quality, exclusive locations to our outstanding existing U.S. macro tower portfolio, and SBA expects these assets to generate approximately $39.5 million in tower cash flow in their first full year in our portfolio.”
“We are also particularly pleased about the opportunity to work closely with PG&E over the coming years to maximize wireless deployments across their extensive network of transmission towers.”
Biomass is more valuable for its carbon-capture ability than for its energy production, according to a new global roadmap of strategies to achieve net-zero emissions by 2050.
The study released last month by the Innovation for Cool Earth Forum (ICEF), an annual gathering hosted by the government of Japan since 2004, proposes a new term, biomass carbon removal and storage (BiCRS), to supplant bioenergy with carbon capture and storage (BECCS).
“This topic has been part of the global dialogue on climate change in a number of ways for many years, and it sparks some controversy,” said David Sandalow, inaugural fellow at Columbia University’s Center on Global Energy Policy (CGEP) and chair of the ICEF roadmap project.
Nearly 500 people attended a virtual webinar Tuesday hosted by CGEP, moderated by Sandalow and featuring several authors of the report.
Comparison of the carbon-removal value of biomass with the energy content equivalent value of biomass for a range of carbon prices. | ICEF
New Tech
“BECCS is something that exists in models, but it doesn’t exist much in reality,” said Roger Aines, energy program chief scientist at Lawrence Livermore National Laboratory. “The number of total operating facilities is small around the world, and most of the ones that are moving a lot of CO2 are basically ethanol plants that are catching CO2 from fermentation.”
The existing knowledge base of converting biomass to energy is based upon a very small number of facilities, and most of them are actually computer simulations, he said.
“One of the big focuses of this report is that the value [of biomass] is in removing the carbon, and we should look at all the ways you can remove carbon,” Aines said.
Biochar — charcoal produced by burning biomass — is an already established method. A brand new concept, bioliquid production, uses pyrolysis to make oil, which is then directly injected underground, Aines said.
Biochar | Oregon Department of Forestry
“If we’re trying to manage carbon on the planet, we need to make … benefits available to these kinds of technologies so that they can make money doing the jobs they want to do; we just need to add these technologies into the carbon systems that exist in the world today,” Aines said.
Julio Friedmann, CGEP senior research scholar, said policy could drive procurement of low-carbon steel.
“In thinking about the value of biomass, one of the things we spent a lot of time talking about was the idea of biocoke, meaning biomass-based substitutes for coking substances in primary steelmaking and ironworks,” Friedmann said. “That’s something that’s very hard to decarbonize, and biomass could be one of the few things that provides that optionality.”
Possible Harms
The controversy that Sandalow spoke of comes from concerns that using biomass for carbon sequestration harms food security, biodiversity and forests.
Clockwise from top left: David Sandalow, CGEP; Holly Buck, University of Buffalo; Roger Aines, Lawrence Livermore National Laboratory; Colin McCormick, Georgetown University; Daniel Sanchez, UC Berkeley; Julio Friedmann, CGEP; and Cynthia Rosenzweig, NASA. Nobuo Tanaka, Innovation for Cool Earth Forum, is center. | Center on Global Energy Policy
“That is absolutely the top thing we worried about when we wrote this report,” said Colin McCormick, adjunct professor at Georgetown University. “We wanted to say, ‘If this is going to happen, what controls are needed, what monitoring is needed, what knowledge is needed to avoid these bad outcomes?’ And you’ll note that a big part of the report is the policy recommendations.”
“The focus is on waste and residue biomass as ones that likely have zero to no impact on food prices or on biodiversity because they are typically byproducts of things that are already happening on the land,” said Daniel Sanchez, an environmental scientist at the University of California, Berkeley.
Counting One, Two, Three
A participant asked how composting compares as a way to store carbon.
“Composting doesn’t tend to be as long-term a source of carbon storage as something like biochar tends to be, but it also highlights something that we tried to emphasize here: that it has another great benefit in that it encourages other long-term carbon storage in soil,” Aines said. “As we think about BiCRS, we want to think about the net carbon for the entire process, and encouraging carbon in soil is a terrific benefit.”
“Composting is probably the No. 1 thing that farmers may really be doing in this country to begin to mitigate climate change,” said Cynthia Rosenzweig, senior research scientist at the NASA Goddard Institute. “It’s really important because it improves the fertility of the fields that it’s stored in.”
Issues with composting include determining the baseline for a farmer’s carbon in the soil, how to assign values to the amount of carbon stored, and to how much credit or monetary value is given to the farm, Rosenzweig said.
In doing carbon accounting, it’s important to differentiate among avoided carbon, reduced carbon and removed carbon, Friedmann said.
“Adding compost may allow you to avoid using fertilizers — that would be an avoidance — and it may be that using a bio-hydrogen can substitute for fossil hydrogen and get you a carbon reduction; but we really wanted to focus on the removal part, of the transfer of CO2 from the air to the lock-up,” he said.
FERC last week approved a settlement between ReliabilityFirst and ITC Holdings subsidiary Michigan Electric Transmission Company (METC) for violations of NERC reliability standards, along with a separate settlement between RF and Michigan Power (NP21-5).
The METC violation carries a $125,000 penalty, but no monetary damages were assessed for the Michigan Power infringement.
NERC submitted both settlements to FERC in a spreadsheet notice of penalty in December, which FERC indicated on Friday it would not review. In the same docket, NERC filed a separate spreadsheet NOP. The documents in that filing were not accessible, likely because it contains information on violations of NERC’s Critical Infrastructure Protection (CIP) standards, which are to be kept confidential in accordance with a policy agreed between FERC and NERC last year. (See FERC, NERC to End CIP Violation Disclosures.)
ITC Admits Facility Misratings
RF’s settlement with METC stems from a violation of FAC-008-1 (Facility Ratings Methodology). The issue was discovered by ITC Midwest (ITCM) via an internal control review in Jan. 2017, with METC filing a self-report to the regional entity on behalf of ITCM in July of that year.
ITC Holdings’ headquarters in Novi, Mich. | ITC Holdings
During its internal review, ITCM discovered that a relay thermal limit in the Tiffin to Arnold 345-kV circuit “did not match the published equipment rating.” As a result, the facility rating had to be reduced at two locations. After finding the misrating, ITCM worked with METC and ITC’s other Michigan operating companies to conduct a root-cause analysis and an extent-of-condition review aimed at identifying “how ITCM and the Michigan groups calculated, considered and applied relay thermal limits” in ITC’s facility ratings database.
The review determined that the Michigan companies’ rating methodology did not account for relay thermal limits on transformers; only transmission lines were addressed. In addition, the methodology also did not include delta-connected current transformers, which were found to have contributed to the misrating of the relay thermal limit.
As a result, ITC committed to review all 254 substations in its footprint. The work was still underway at the time of the settlement, with completion expected by the end of 2021. As of August, the company had completed reviews of 184 substations; ratings changes have been required in about 7% of examined facilities.
Along with the ongoing review, ITC has already completed a number of additional measures, including updates to its facility ratings database and ratings methodology to account for relay thermal limits. RF considered these actions a mitigating factor in determining the penalty amount, in addition to the moderate risk posed by the violation and the fact that it was identified and reported before any harm occurred. On the other hand, the RE also noted that the company has a history of compliance issues under FAC-009-1 (Establish and Communicate Facility Ratings), which supports an increased penalty.
Because some of the affected facilities are in MRO’s footprint, the settlement amount will be divided between the two REs based on net energy for load in each region. NERC calculated MRO’s portion at $41,250.
Michigan Power Overlooks Voltage Changes
Michigan Power’s settlement arises from an infringement of VAR-002-4.1 (Generator Operation for Maintaining Network Voltage Schedules).
During a spot-check in December 2018, the utility discovered it had not maintained the reactive power schedule as required and had also failed to satisfy notification requirements since November 2017, the month the entity entered a reduced dispatch agreement (RDA) with Consumers Energy. Under the RDA the utility was required to reduce its output at the request of Consumers, which would notify it of required reductions at the beginning of each day.
Michigan Power performed the megawatt reduction according to schedule but neglected to “reduce the output of MVARs as needed to maintain the reactive power schedule.” As a result, the entity was found to have failed to maintain its voltage on 254 of the 284 occasions in question.
RF attributed the violation to “the entity’s lack of awareness of the constant output of MVARs to the grid” and a misunderstanding of the notification requirements in its contract with Consumers. However, the RE noted that Michigan Power is “inherently lower risk” because it has no record of misoperation and is not a black start resource, and that Consumers had not identified any system voltage issues caused by the violation. The utility has also committed to updating its operation requirements to ensure that MVAR is maintained during future adjustments. For these reasons, the entity elected not to apply a monetary penalty.
PJM is back to the drawing board as two different solution packages aimed at addressing the disputed black start unit issue were rejected by stakeholders at last week’s Markets and Reliability Committee meeting.
The RTO’s option 1 package, which emerged as the main motion with 83% support at the Dec. 3 Operating Committee meeting, failed with a sector-weighted vote of 2.48 (49.6%) at the MRC. Dominion Energy’s package, which served as the alternate at the OC meeting with 82% support, failed with a sector-weighted vote of 2.47 (49.4%) at the MRC.
Tasley, a single-unit 33 MW industrial gas turbine that began commercial operation in 1972 in Tasley, Va., is a black start-capable unit. | Calpine
The black start issue has been lingering for months since the problem statement was endorsed at the May OC meeting, leading to heated discussions among PJM members and generation owners fighting back against calls for retroactively applying CRF to existing black start units. (See Gen Owners Balk at Change to PJM Black Start Rates.)
The CRF issue emerged as the most contentious portion of the black start unit discussions, with stakeholders voting to amend the issue charge at the OC in December to align with language in the problem statement. (See Vote on PJM Black Start Compensation Deferred.)
Proposed issue charge language said, “Current black start units receiving the capital cost recovery rate (Schedule 6A) and units already awarded in recent black start [requests for proposals] will continue with the commitment period and capital recovery factor rates as documented in the current Open Access Transmission Tariff.”
The issue over the language emerged when stakeholders discovered the issue charge, which is officially voted on for endorsement as codified in Manual 34, did not include a footnote contained in the problem statement, leaving the application of CRF rates up to interpretation in the proposed black start packages.
The Independent Market Monitor’s package, which ultimately received only 7% support at the December OC meeting, called for updated CRF rates to apply to new and existing black start units. Updated commitment periods would have also applied to new and existing black start units.
Monitor Joe Bowring said the CRF table was originally created in 2007 as part of the Reliability Pricing Model capacity market design and includes assumptions that are no longer correct. Bowring said the CRF values are significantly higher than they should be under the lower corporate tax rate from changes in the 2017 tax law, leading to overcompensation for units.
The addition of the updated black start issue charge language at the December OC led to last-minute modifications to the Monitor’s package and PJM’s primary package, both of which failed to be endorsed.
The next steps for the black start issue are yet to be determined and will be discussed at the Feb. 11 OC meeting.
Adrien Ford of Old Dominion Electric Cooperative said the packages failed to correct the error of the CRF table not being updated in the tariff with the 2017 tax law.
Susan Bruce of the PJM Industrial Customer Coalition said she appreciated that black start is a “pretty muddy issue” and that there are aspects of the issue that “cut both ways.” Bruce said her biggest concerns with the black start packages are the changes to the capital recovery and commitment periods.
“It’s a complex issue for many of the reasons highlighted, but what’s before us doesn’t solve the issue,” she said.
Alternative Black Start Package
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), reviewed a proposal as a first read on behalf of the Delaware Division of the Public Advocate as a compromise alternative to the PJM and Dominion packages that failed.
Poulos said the changes to the black start issue charge at the December OC meeting stifled the voices of minority interests related to the CRF issue.
“It completely materially changed the black start discussion and eliminated certain aspects of that discussion,” Poulos said.
The advocate package uses much of the same language from the failed proposals, keeping intact aspects of testing, unit substitution and termination and the MTSL. The changes include the addition of the Monitor’s language regarding CRF, applying rates to both new and existing black start units.
It also uses the language from the primary PJM package, with a five-, 10-, 15- and 20-year capital recovery period based on unit age at the time of it entering black start service.
“The advocates at this point could not support the two current proposals that are up, and that’s why I’ve tried to find an alternative proposal,” Poulos said.
Bowring said he continues to believe that exempting existing resources with the change in the black start issue charge was “inappropriate” and that the CRF issue should ultimately be decided at FERC.
“We don’t think there are any rights to windfalls built in to the CRF process,” Bowring said. “That’s exactly what’s been occurring for existing units back to the time of the tax law change.”
Marji Philips, LS Power vice president of wholesale market policy, said she objected to the term “windfall” being used regarding CRF. Philips said PJM conducted a competitive procurement process with the black start service for units currently in operation, and prevailing interest rates were considered and accepted by all interested parties.
Philips said she does not have a problem with updated CRF rates applying to new black start units, but she said applying rates to existing units is “retroactive ratemaking.” She said the advocate proposal is not fair and doesn’t recognize long-term contract law.
“These projects were built based on an assumption, and it was competitively chosen,” Philips said.
Alex Stern, director of RTO strategy for PSEG Services, made a motion for the advocate package to be sent back to the OC for further discussion, saying it was “ripe for a motion to remand.” Stern said he appreciated Poulos bringing forward a new proposal that doesn’t fall within the issue charge, but he believed that the OC “needs to go back to the drawing board” to discuss the issue.
“I think everybody now has to go back and roll up their sleeves and try to work together to figure out what’s in the best interest of all,” Stern said.
Ford said she didn’t see why the MRC would direct the advocate proposal back to the OC for discussion, as stakeholders on the committee “very clearly rejected” the idea of applying CRF to existing black start units.
“I think it’s appropriately before the MRC, and that’s where it should stay,” Ford said.
Stern’s motion to remand failed with a sector-weighted vote of 2.2 (44%).
Mike Bryson of PJM said that if there was a procedure to get the advocate package back to the OC to discuss, it would be the best outcome to flesh out ideas or possible compromises. Bryson said PJM is still concerned about addressing CRF on existing black start units and that the RTO has a “significant commitment to these units,” and changing existing structures would be “problematic.”
“We’re going to have to fix this CRF issue one way or another,” Bryson said.
MOPR Revisions Endorsed
Stakeholders unanimously endorsed revisions to Manual 18: PJM Capacity Market that conform to the FERC-ordered rule changes in the minimum offer price rule (MOPR) and forward-looking net energy and ancillary services (E&AS) offset calculation. The revisions were also unanimously endorsed earlier this month at the Market Implementation Committee meeting Jan. 12. (See “MOPR Changes Endorsed,” PJM MIC Briefs: Jan. 12, 2021.)
Jeff Bastian, PJM senior consultant in market operations, reviewed the updates to Manual 18, including recent changes to the redline language resulting from stakeholder discussions.
The first change is a previously unmapped region of the Ohio Valley Electric Corp. (OVEC) zone, which is now mapped to the Columbia-Appalachia TCO fuel pricing point for the purpose of establishing the net E&AS offset for the zone. The OVEC zone was also mapped to the AEP-Dayton Hub for determining the forward hourly LMP.
The second change includes new language in section 5.4.5.5(A) that clarifies that a seller’s financial accounting statements should serve as the primary form of evidence for use of an asset life more than 20 years.
Bastian highlighted two additional conforming changes made after the MIC endorsement. Language changes include the use of an average equivalent availability factor for PJM nuclear resources to account for refueling outages in the calculation of the forward net E&AS offset for existing nuclear units.
An additional change eliminated a requirement that a resource submit a sell offer at the resource-specific value under certain circumstances. Bastian said the update was related to the recent FERC filing regarding tariff revisions that account for when the default offer price floor exceeds the market seller offer cap (MSOC) under PJM’s MOPR (EL16-49-004, et al.). (See FERC Partially Accepts PJM MOPR Offer Floor Filing.)
Chen Lu, PJM senior counsel, provided a summary of the FERC order that largely accepted the RTO’s compliance filing, submitted Nov. 13, with the exception of one provision regarding the MSOC.
PJM included the Attachment DD language directed by the commission but also proposed an additional sentence to the tariff, which stated, “In the event the resource-specific MOPR floor offer price is greater than the applicable market seller offer cap, the capacity market seller of such capacity resource may only submit an offer for such resource equal to the resource-specific MOPR floor offer price into the relevant RPM auction.”
The commission rejected the additional sentence on the grounds that it exceeded its October compliance order, directing PJM to submit a new compliance filing within 15 days removing the sentence from the tariff. Lu said PJM will file an additional compliance filing by Feb. 3 to remove the rejected sentence from Attachment DD in accordance with FERC order.
PJM maintains that the additional compliance filing allows them to run the long-delayed capacity auctions for the 2022/2023 delivery year, Lu said, with the auctions set to commence on May 19.
“We believe we have the greenlight to run the next auction,” Lu said. “And we are prepared, ready and intend to commence the next auction.”
Stability Limits Endorsed
Members endorsed a proposed capacity constraint solution package and corresponding Operating Agreement and tariff revisions regarding stability limits capacity constraints. The package was endorsed with a sector-weighted vote of 4.05 (81%).
The proposal addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. (See “Stability Limits Review,” PJM MIC Briefs: Dec. 2, 2020.)
The problem statement and issue charge were initially brought forward for endorsement at the August 2019 MIC meeting. (See “Modeling Units with Stability Limitations,” PJM MIC Briefs: Aug. 7, 2019.)
Lisa Morelli, director of market design for PJM, said the packages were developed to create consistent treatment of generator stability limitations.
Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.
The capacity constraint proposal was put forward by PJM and the Monitor and endorsed by the MIC with 64% support. It addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts.
Joe Ciabattoni, PJM manager of interregional market operations, said the units would be dispatched in economic merit order up to the stated stability limitation. If a unit chooses not to remedy a stability limitation identified during the planning process, Ciabattoni said, its operating restrictions — as documented in its interconnection service agreement — would be invoked prior to those for other units.
The package also included a measure for transparency, with PJM posting data on the frequency, location and number of affected units while maintaining confidentiality rules.
Lost opportunity cost (LOC) credits would not be paid for any reduction required to honor the stability limit. Similarly, LOC is not paid for economic megawatts of a resource that cannot produce because of a ramp limitation.
Paul Sotkiewicz of E-Cubed Policy Associates reviewed the alternate opportunity cost solution package that was ultimately not voted on. The proposal, presented by J-POWER, was fundamentally the same as the PJM-IMM package except for providing compensation for LOCs.
Sotkiewicz said if a generator is requested to take an outage when it can still run, the unit is in essence being asked to “not reveal our true capabilities” to the market of what could actually be generated. He said it creates a “slippery slope” going forward to misrepresent a unit’s true capabilities.
“I think the mechanical changes to the market are excellent, and I applaud PJM and the Market Monitor for that,” Sotkiewicz said. “But we do believe we should be paid lost opportunity costs.”
Catherine Tyler of Monitoring Analytics said LOC was not included in the PJM-IMM proposal because generators could endanger a unit’s stability and risk damage by pursuing opportunities for LOCs. Tyler said the costs to repair potential damages to a unit would outweigh the LOC.
“There’s not a benefit of receiving the higher LMP if you’re going to break your unit to do it,” Tyler said.
A final vote on the package will be held at the Feb. 24 Members Committee meeting. Ciabationi said conforming manual revisions will be brought through the OC and MIC for endorsement following FERC approval of the proposal.
Mark Sims, PJM’s manager of infrastructure coordination, said the committee proposed minor changes to Manual 14C, including an update of the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5. New sections on cost-tracking for baseline projects and another for supplemental cost-tracking were also proposed.
Poulos made the request to delay the endorsement by one month to work with PJM on some language suggestions after expressing concerns about some of the language. Poulos specifically referenced sections 6.1.2 and 6.2.1 dealing with tracking of supplemental projects.
Sims said PJM coordinated with Poulos to address the language concerns, and Poulos presented the friendly amendments to make the language consistent with Manual 14B.
In Manual 14B, the transmission owners must update PJM on the status of state regulatory approval in the quarterly updates. But in Manual 14C, Poulos said the burden is on PJM to “request” the status of state regulatory approvals.
Poulos said PJM currently does not wait for state approval of supplemental projects, and with the manual change, it was less likely that the RTO will even be aware of the state procedural process.
The friendly amendment said the Manual 14C sections will be consistent with language in Manual 14B and will include “any relevant regulatory siting authority approval necessary for the project and the status of such approval.”
“My goal is to make the language consistent between the two manuals and ensure that PJM is updated on what the approval process is for each of these projects,” Poulos said.
Robert Taylor of Exelon asked if PJM was comfortable with the friendly amendment.
Sims said the language was consistent and added value in clarification. Sims said PJM was also intent on not making the procedures for requesting documentation overly burdensome for stakeholders or PJM staff and that the “relevant” documents would be enough for PJM engineers to adequately do their work.
Laura Walter, senior lead economist for PJM, said the original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.
The PJM package requires that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.
For the timeline of an RTV submittal, Walter said, the package would require that the requested period not exceed one market day. She said that when an RTV is requested, it would be available for that one day, then the entire schedule would revert to the previous day’s values.
The package also calls for adding RTVs to the tariff. Currently, RTVs are mentioned only in the manual, Walter said.
Siva Josyula of Monitoring Analytics reiterated the Monitor’s concern that the changes proposed in the PJM package undermine the parameter-limited scheduling (PLS) rules used in RTVs. The PLS rules are part of the capacity performance rules requiring units to operate to defined parameters, he said.
The package will be voted on at the February MC meeting.
PRD Credits Disposition
Stakeholders unanimously endorsed through an acclamation vote the proposed solution package addressing the disposition of price-responsive demand (PRD) credits.
PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity (LSE) for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service providers (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs.
Langbein said the LSE was removed from emergency/pre-emergency demand response process several years ago.
The solution package calls for the PRD provider to receive the PRD bill credit and that any member that is a PRD provider is treated the same with no need to differentiate between a PRD provider and an LSE.
The package now heads to the MC for a vote in February.
Members Committee
Manual 34 Changes
Proposed revisions to Manual 34: PJM Stakeholder Process were unanimously endorsed at last week’s Members Committee meeting.
The change provides clarifying language to affirm that the preference over the status quo 50% requirement is binding. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Nov. 19, 2020.) Gary Greiner, director of market policy for PSEG, sponsored the revisions that came out of discussions at the Stakeholder Process Forum.
Members proposed incorporating an additional threshold for moving a proposal to a senior standing committee. The language change says a proposal must pass a simple majority voting threshold and be preferred over the status quo by more than a simple majority. Current rules that do not require a majority prefer the alternative over the status quo.
“In the way of enhancements, we determined that we were going to ask the preference question for all proposals before we knew the level of support that they garner,” Greiner said.
The Connecticut League of Conservation Voters held its annual environmental summit last week with hundreds tuning into discussions on the Transportation and Climate Initiative and the controversial plan to build a natural gas power plant in southeastern Connecticut.
Here is some of what we heard from elected officials, state regulators and environmental activists.
Lamont, Dykes Target Planned Power Plant
Gov. Ned Lamont (D) did not pull his punches in expressing his opposition to NTE Energy’s proposed 650-MW gas-fired Killingly Energy Center.
“I don’t want to build Killingly; I’m not interested in building Killingly, and I’m not sure the market will say that we need Killingly,” Lamont said. “The question is, what can I do about this?”
The plant received siting approval and is going through the permitting process. The project is “a lot of the way down the road” according to Lamont. He said playing “some games” with permits could slow things down, but the market itself could dictate the plant’s future.
“Look, electric usage is flat to down. … I’m not quite sure where the market is going to come out on this,” he said.
Lamont did concede that there is a “slight benefit” that Killingly could provide “relatively cleaner” energy as opposed to a coal-fired power plant, but “I’m not positive you’re going to see Killingly built at all.”
When asked if the lawmakers can do anything to stop the Killingly, House Speaker Matthew Ritter (D) said, “probably not.”
“The reason I say that is because I haven’t even been approached about that yet, which leads me to believe that there are people who would be concerned about the legality of [legislation],” Ritter said. “People can certainly research it, but my instinct is that this one is now at the administrative level. We need to make sure we’re very clear about what we’re committed to doing, how we’re going to meet our [clean energy and decarbonization] goals.”
Katie Dykes, commissioner for state’s Department of Energy and Environmental Protection, said she hears from people “every day about their concerns about this gas plant.” Dykes added that outside of the established permitting process, “we have to change the system … if we want to achieve our broader transformation and decarbonization goals, and we’re doing that by working” to change ISO-NE.
Dykes referenced Lamont and the four other New England governors, who released a joint statement in October calling for reforms to the RTO, saying it is frustrating their efforts to reduce economy-wide greenhouse gas emissions. A subsequent vision statement listed changes the states seek to ISO-NE market designs, transmission planning process and governance. (See States Demand ‘Central Role’ in ISO-NE Market Design.)
“It’s really important. This is a generational opportunity,” Dykes said. “We have to transform our grid and make sure that we can get the clean energy resources that we need to achieve our goals.”
Dykes added, “with every concern that I’ve heard from folks about this power plant, it’s redoubling our efforts to make this system-wide change if we want to prevent future projects like this from coming forward or much older, much dirtier plants from operating longer than is necessary.”
Focus on TCI-P
Charles Rothenberger, climate and energy attorney for Save the Sound, sought to counter misinformation he said is being spread about the memorandum of understanding Connecticut, Massachusetts, Rhode Island and D.C. signed in December to launch the Transportation and Climate Initiative Program (TCI-P), which aims to cut GHG emissions from vehicles by 26% from 2022 to 2032. (See NE States, DC Sign MOU to Cut Transportation Pollution.)
From top left: Katie Dykes, Connecticut DEEP; Connecticut Gov. Ned Lamont; and Lori Brown, Connecticut League of Conservation Voters | Connecticut League of Conservation Voters
TCI-P is a cap-and-invest program that will require large gasoline and diesel fuel suppliers to purchase allowances for the pollution and later to auction them, which officials said will generate $300 million for yearly investments in less polluting transportation. Each year, the total number of emission allowances would decline.
Rothenberger said the challenge of needing to rapidly decrease emissions “at a much quicker and steeper pace to meet medium- and long-term mitigation targets” will not be successful without a focus on transportation.
In Connecticut and throughout the region, transportation is the largest source of GHG emissions, accounting for approximately 38% of the total.
Rothenberger said there is “a lot of work to be done” to develop the rules that will govern the regulatory structure.
He said the hope is that Connecticut lawmakers will pass legislation this year and that the regulatory rulemaking and early reporting period can both be in place by January 2022 as a trial run for the tracking and accounting of emissions from the regulated fuel sources. The first formal compliance period begins in January 2023.
Rothenberger added that there is already “inaccurate and false information” about TCI-P making the rounds.
“It’s important that legislators know the actual facts and have the relevant information about how the program works, and its benefits,” he said.
One of the “absolutely not true” elements circulating is that TCI-P a Trojan horse for raising the gas tax.
“There is no tax, gas or otherwise, in sight,” Rothenberger said. “It’s a cap on emissions, and individuals, wholesalers, primary fuel suppliers that are bringing fuel into the state and participating jurisdictions will need to purchase auctioned emissions allowances. It’s shifting the cost of pollution on to the suppliers of the pollution producing fuels.”
Rothenberger said it is possible that fuel suppliers “may pass some portion of those costs on to consumers, which is “clearly their decision.”
“But there’s no state tax component to this whatsoever, and the program has modeled the most conservative scenario in which 100% of the compliance costs would be passed on to consumers by the fuel suppliers that indicates there may be at most a 5-cent increase in gas prices at the pump,” Rothenberger said.
Ritter said that although he has discussed TCI-P with Gov. Lamont, “rank-and-file legislators” might only have “an inkling” about the program. “So, there’s a real education gap, including for me,” he said. He added that lawmakers need to understand better “what Connecticut’s commitments are” and not construe it as a gas tax.
“It’s a silly notion, but you have to explain this to people and get the education out because I don’t think the average legislator is familiar,” Ritter said. “The good news is … we have a lot of time to get there and explain it, and I’m confident that when we explain what it does, how we’re working with our neighboring states … we will be able to make a compelling case.”
Ritter Speaks
Ritter, a six-term legislator serving his first term as speaker, said that although the COVID-19 pandemic will prevent a regular legislative session in 2021, advocates need to continue to reach out to legislators to signal their support or opposition to potential bills. He said virtual lawmaking is a slower process, and as committees prioritize bills, some items could be pushed off to the 2022 session.
“Every week since January we’ve had a member in our caucus positive with COVID,” Ritter said. “If we are in session and somebody tests positive, or staff tests positive, at any given time, we could be on a 14-day hiatus from the state capitol building. So, keep that in mind, no voting at all. If that happens in late April or early May, it takes up a lot of session days. You’ve got to think about the worst-case scenarios.”
El Paso Electric, a utility that serves more than 400,000 customers in the Rio Grande Valley of Texas and New Mexico, said Monday it plans to join CAISO’s Western Energy Imbalance Market in 2023.
The move would expand the EIM’s footprint to Texas for the first time. It also ups the competition between CAISO and SPP’s Western Energy Imbalance Service (WEIS), which launched operations Monday. (See related story, SPP Successfully Launches Western Market.)
“The EIM will allow EPE to leverage our interconnection to the electrical grid with neighboring markets to reduce cost and balance our energy generation with the real-time power needs of our customers, as well as integrate greater amounts of renewable energy,” EPE CEO Kelly Tomblin said in a joint statement with CAISO.
Public Service Company of New Mexico, whose territory borders EPE’s to the north, plans to go live in the EIM early this year.
An iconic sign sits atop El Paso Electric’s Rio Grande Power Plant in Sunland Park, NM. | El Paso Electric
SPP has been trying to attract utilities in more politically conservative states that do not want to get too cozy with liberal California and its 100% clean-energy agenda.
But the EIM’s oversight — its Governing Body members come from other states — and its economic benefits have been attractive to entities across the West, including in more conservative interior states.
In the fourth quarter of 2020, the EIM provided participants with $69 million in benefits, bringing its total savings for members to $1.18 billion since it began in 2014.
El Paso Electric serves 441,200 customers in a 10,000-square-mile area of the Rio Grande valley in west Texas and southern New Mexico. | El Paso Electric
The initial eight members of SPP’s WEIS are Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, the Wyoming Municipal Power Agency, and the Western Area Power Administration’s Upper Great Plains West, Rocky Mountain region and Colorado River Storage Projects.
The EIM’s current members include Arizona Public Service and Arizona’s Salt River Project; Idaho Power Company; NV Energy; and PacifiCorp’s vast service territory in Oregon, Washington, Utah, Wyoming, Idaho and Northern California.
Five entities plan to go live in the EIM in the first half of 2021: PSC, the Los Angeles Department of Water and Power, NorthWestern Energy, Turlock Irrigation District and the Balancing Authority of Northern California Phase 2. Six more utilities are scheduled to join the EIM in 2022, including Avista and the Bonneville Power Administration, covering most of the Pacific Northwest, and Xcel Energy, which serves much of Colorado.
EPE was the first entity to announce plans to join the EIM in 2023.
A privately held group, Infrastructure Investments Fund (IIF), bought EPE last year for $4.3 billion, after winning approval for the deal from the Nuclear Regulatory Commission. EPE owns a nearly 16% stake in the Palo Verde power plant in Arizona, the nation’s largest nuclear generating station. (SeeFERC OKs El Paso Electric Mitigation.)
Its decision to join the EIM was based on the projected economic benefits and a desire to pursue “a clean, green energy future,” Tomblin said in the statement.
CAISO CEO Elliot Mainzer said he was pleased EPE chose to join the EIM.
“El Paso’s entry … will improve efficiencies for their customers while strengthening and expanding the geographical scope of our market,” Mainzer said. “We look forward to providing them with outstanding customer service as they join the family of Western EIM entities.”
CAISO introduced a straw proposal Wednesday that aims to attract supply this summer and head off shortfalls like those that led to rolling blackouts in August and energy emergencies in September.
Propelled by those concerns, the ISO is moving ahead on its “market enhancements for summer 2021 readiness” stakeholder initiative at an unusually fast pace. It began advancing the measure in earnest in early January and scheduled it to be adopted by the Board of Governors in late March, with implementation scheduled for June 1.
The proposal took the form of a slide presentation only, not a written proposal as would normally be the case, because of time constraints. It is part of a series of fast-tracked measures being pursued by the ISO and the California Public Utilities Commission in anticipation of summer heat waves and capacity deficiencies as the state transitions from fossil fuels to renewables.
It and other measures are intended to address issues identified in a root-cause analysis of the summer shortages submitted to Gov. Gavin Newsom by CAISO, the CPUC and the state Energy Commission at Newsom’s request. It identified a variety of problems including transmission constraints, questionable exports from the ISO during tight supply conditions and market practices that undermined supply. (See Summer Readiness Sought by CAISO, CPUC.)
“This initiative’s goal is to prepare the CAISO’s operations and market ahead of this summer,” James Friedrich, market design policy specialist, said in his presentation. The “initiative is part of several measures to better access available supply, protect grid reliability and avoid rotating power outages during extreme heat waves. In addition to reliability, the CAISO has the responsibility to ensure its markets are operated efficiently, including mitigating market power and ensuring rational price formation.”
| Shutterstock
The proposal deals with import incentives during tight load conditions, scarcity pricing enhancements and coordination with the interstate Western Energy Imbalance Market (EIM), among other changes. (See Western EIM Questions Performance in Shortfalls.)
For example, it proposes reviewing the performance of the ISO’s resource sufficiency evaluation (RSE) as part of its EIM participation. The re-evaluation would address defects identified in prior workshops such as accounting for resources that are derated as part of the capacity test and eliminating the double counting of mirror resources.
Two proposed enhancements seek to improve market incentives during times of tight supply. One would improve day-ahead market scheduling incentives, and a second would improve real-time incentives.
Another part of the straw proposal involves increasing the real-time market’s prices under certain conditions, including when the ISO issues a day-ahead market alert, or a warning or emergency in real time. The proposal would scale prices to the $2,000/MWh threshold established by FERC in Order 831. The order required ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000; offers over $1,000 require suppliers to justify their costs.
CAISO’s Market Surveillance Committee said in September that the ISO needs to consider implementing scarcity pricing to obtain energy during heat waves and supply shortages. (See CAISO Adds Scarcity Pricing to Policy ‘Roadmap’.)
Making sure storage resources are charged in strained conditions is another component of the straw proposal. Hundreds of megawatts of additional storage are scheduled to come online by this summer. A lack of storage for renewable resources last summer led to shortages when solar ramped down in the evening but demand from air conditioning remained high.
Comments on the straw proposal are due this Wednesday, with a final proposal expected by the end of the month.
The Texas Public Utility Commission last week approved a change to the decommissioning funds for Vistra Energy’s Comanche Peak Nuclear Power Plant.
During its Jan. 29 open meeting, the PUC signed off on an order that allows Vistra’s Luminant subsidiary to continue its annual decommissioning funding amount of $20.1 million for the plant’s two units. However, the order adjusts the funds’ allocation to 72.3% from 57.1% for Unit 1 and to 27.7% from 42.9% for Unit 2 (50945).
The net after-tax value of the units’ trusts total more than $1.3 billion, with nearly $624 million allocated for Unit 1 and $692.5 million for Unit 2. The plant said external and internal analyses indicates it will cost $1.729 billion to decommission and completely dismantle the facility in 2019 dollars, assuming a 10% contingency.
The commission said Comanche Peak “demonstrated that the funds in its nuclear decommissioning trusts are being invested prudently” and are following its investment guidelines.
Comanche Peak Nuclear Power Plant | The Nuclear Decommissioning Collaborative
Unit 1, which began operating in 1990, is licensed until February 2030. The license for Unit 2, which opened three years later, expires in 2023.
While numerous nuclear plants have received extensions of their original 40-year licenses, others have been shut down as uneconomic, and five reactors totaling 5.1 GW of capacity — Indian Point 3 in New York, and Byron (two units) and Dresden (two units) in Illinois — are scheduled to close this year.
“Given Comanche Peak is one of the youngest plants in the country, significant decisions on license renewal are a few years away, but the plant is currently well positioned, and we have no plans to close it prematurely,” a Vistra spokesman told the Houston Chronicle in 2019.
Other Action
In other actions, the PUC approved a financing order that allows Entergy Texas to issue $539.9 million in transition bonds to recover hurricane-related costs (37247).
It also denied the city of Seymour’s request to overturn an administrative law judge’s December ruling allowing four people to intervene in its request for a declaratory order confirming that Tri-County Electric Cooperative has no grandfathered corridor rights for retail service within its city limits (49726).
Also last week, the commission announced it had promoted agency veteran Connie Corona to the new position of deputy executive director. She was previously the PUC’s chief program officer, guiding the market analysis, customer protection, infrastructure, rate regulation and legal divisions.
“Connie is a walking encyclopedia of industry knowledge who makes everyone around her more focused, productive and effective,” Executive Director Thomas Gleeson said. “We are truly fortunate to have her in such a critical role on our team.”
SPP successfully launched its Western real-time balancing market at midnight Sunday, making it the first RTO with power markets in both the Western and Eastern Interconnections.
The RTO has said its Western Energy Imbalance Services (WEIS) market will lower wholesale electricity costs, increase price transparency and mitigate congestion for its participants. The market joins the reliability coordinator services SPP has been offering 12 entities in seven states since 2019; the grid operator will expand its RC function in April. (See SPP Expands its Western RC Footprint.)
“This will be a historic moment for SPP to launch this market … on time, and under budget,” CEO Barbara Sugg told stakeholders last week.
SPP celebrated its WEIS market launch Monday. | SPP
The WEIS market centrally dispatches energy from the region’s participating resources every five minutes. It is contract-based and does not require its participants to be SPP members. However, most of its participants have since indicated they are committed to evaluating becoming RTO members. (See Western Utilities Eye RTO Membership in SPP.)
WEIS market participants include:
Basin Electric Power Cooperative
Deseret Power Electric Cooperative
Municipal Energy Agency of Nebraska
Tri-State Generation and Transmission Association
Western Area Power Administration (WAPA)
Wyoming Municipal Power Agency
WAPA’s agreement includes the firm loads and resources of Pick-Sloan Missouri Basin Program–Eastern Division in the Upper Great Plains Western Area balancing authority footprint, the Loveland Area Projects and Salt Lake City Area Integrated Projects in the Western Area Colorado Missouri balancing authority footprint.
“Our electricity markets have played a big role in lowering costs, integrating renewables and enhancing reliability in the East, and we’re excited to see a new part of the country begin to see similar benefits,” Sugg said in a statement. “I’m hopeful this is just the beginning of valuable partnerships between SPP and western utilities that will help them and the customers they serve meet their financial, reliability and renewable-energy goals.”
SPP has long eyed expansion into the Western Interconnection. It explored a relationship with the Mountain West Transmission Group several years ago, but the effort was scuttled by Xcel Energy’s decision to join CAISO’s Energy Imbalance Market.
The RTO became the Western Interconnection Unscheduled Flow Mitigation Plan’s administrator in 2018 and it has been hired by the Northwest Power Pool to develop its regional resource adequacy program. (See NWPP Program Taking Shape for Q3 Launch.)
