The Rocky Mountain chapter of the Energy Bar Association this month hosted a panel to discuss the intricacies of creating an organized market in the West.
Erin Overturf, Western Resource Advocates | Energy Bar Association
Each panelist at the March 3 “Winter Energizer” gave a short presentation on their organization and its part in the energy transition. And each made it clear that an organized market would be crucial to reaching the region’s decarbonization targets.
“The aim of this conversation is to decarbonize … the power system as quickly as possible, as reliably and as cost effectively as we can,” Erin Overturf, director of clean energy programs for Western Resource Advocates, said. “We see regional markets as … a key tool to be able to achieve those aims.”
But the panelists acknowledged that the political diversity of the West means designing this market will not be a simple undertaking. Being flexible enough to accommodate states and their varied interests is key to creating a system that benefits states, utilities and ratepayers alike.
Carrie Simpson, Xcel Energy Colorado | Energy Bar Association
“Letting states speak for themselves about what it is that they need to be able to get out of a regional market in order for it to work, I think is absolutely critical,” Overturf said.
But designing a market that is mutually beneficial for all participants would only be the first step to widely decarbonizing the West. To curb greenhouse gas emissions more rapidly, interregional transmission will need to be constructed throughout the entire footprint. And as seen with MISO and SPP, an organized market does not inherently lead to the construction of interregional transmission, said Carrie Simpson, director of western markets for Xcel Energy Colorado.
“I don’t know that an RTO automatically just opens the door for transmission because I think it’s all about what the rules are and what the policies are and what the cost allocation rules are,” Simpson said.
Rachel Bryant, PA Consulting | Energy Bar Association
Though membership in an RTO may improve a utility’s situational awareness and allow it to better assess what kind of interregional transmission projects may be most beneficial, it does not necessarily ease the process of constructing these projects.
The main drawback states and utilities face when considering an organized market is the fear of a lack of autonomy. Rachel Bryant, a principal consultant with PA Consulting, said states have seen how some markets in the East have been rigid and were designed without diverse state policies and adaptability in mind.
“Breaking through that sort of stigma that you’re going to lose all your rights and be forced to do things you don’t want to do — I think is a huge part,” she said. “I feel like markets almost need a marketing manager to make this seem appealing to the people who are most resistant.”
PJM stakeholders at last week’s Planning Committee meeting endorsed an update to the generation deactivation process as some members asked the RTO to slightly modify the proposed timing language.
The issue charge, developed by PJM, received 148 votes in support (99%), with two members voting against it. In a vote asking stakeholders if they preferred the proposal over maintaining the status quo, 109 (83%) favored the proposed and 22 the status quo.
The tariff currently provides 90 days advance notice and 30 days to complete deactivation studies, Egan said, causing “insufficient” time for PJM staff to determine adverse impacts on reliability if more than one deactivation notice is made in a single study period. Industry trends and state energy policies are increasing the number of deactivation notices, Egan said, putting even more pressure on staff to finish deactivation studies in a timely manner.
PJM’s issue charge calls for tariff and manual changes that “provide more time to complete analyses, allow additional and improved studies, and provide the ability for more efficient work control and consistency regarding timing of deactivation studies,” Egan said.
The proposed deactivation process would establish quarterly study times for requests, with periods beginning Jan. 1, April 1, July 1 and Oct. 1. PJM staff would study deactivations as a batch. For example, the Jan. 1 study period would result in a reliability notification at the end of February.
PJM generation deactivation requests from June-August 2021 | PJM
Egan said the quarterly schedule would allow sufficient time for additional required seasonal, interim year and short-circuit analyses, scheduling upgrades and cost estimates. It would also allow PJM operations to identify additional needed operational measures, he said.
As a comparison to other RTOs and ISOs, Egan said MISO requires advance notice of 26 weeks for a deactivation, and the studies include 75 days to identify issues and 26 weeks to complete the deactivation study. NYISO requires advance notice of 365 days for deactivation, and studies are conducted in the subsequent quarter.
Becky Robinson of Vistra said she had concerns about possible upcoming actions on generation plants through EPA’s Coal Combustion Residuals Rule, which required most of the country’s 500 unlined ash pits to stop receiving waste and begin to close by April 2021. EPA began reinforcing the rule, established under President Barack Obama, this year after being targeted for rollback under President Donald Trump. (See EPA Coal Ash Enforcement Impacts Midwest Coal Plants.)
Robinson said a plant could be ordered to stop using ash pits within 135 days, effectively shutting it down and conflicting with the new deactivation timing. Resources affected by the rule have made compliance filings, she said, but EPA has yet to act on most of them, leaving the timing of their deactivation in limbo.
Paul Sotkiewicz of E-Cubed Policy Associates said he agreed with Robinson’s assessment of the EPA rulings. Other enforcement actions that can take place on a unit-specific basis through EPA or state rules don’t necessarily have well defined timelines for actions, he said.
Sotkiewicz recommended that PJM insert tariff language that “doesn’t pin” a generator down to a specific time frame and to create exemptions if a unit is forced to deactivate through actions of EPA or states. He said a goal of the new timeline should be to avoid running afoul of EPA or state environmental agency rulings.
“I’m trying to save everybody a lot of work and heartache here by putting in some language,” Sotkiewicz said.
Dave Souder of PJM said the RTO was willing to add appropriate tariff and manual language before the update is voted on at the Markets and Reliability Committee meeting in April.
Gov. J.B. Pritzker signed the legislation Sept. 15. It requires all investor-owned baseload coal-fired power plants and remaining oil peaker turbines in the state to shut down by 2030. (See Illinois Senate Passes Landmark Energy Transition Act.) Gas turbine plants, including ones currently under construction, must also close by 2045 under the terms of the bill, although the state has the option to retain plants that are critically needed.
PJM created a draft reliability guidance document to send to Illinois regarding the law and its impacts on the region. (See “Illinois CEJA Reliability Guidance Update,” PJM Operating Committee Briefs: Feb. 10, 2022.)
Egan said PJM has already identified retirement assumptions for two study periods in Illinois, with 9,905 MW impacted from the present until 2030 and 5,845 MW impacted from 2035 until 2045 for a total of 15,750 MW of generation in the state.
PJM will conduct additional sensitivity studies later this year, Egan said, with methods similar to a deactivation study using Regional Transmission Expansion Plan (RTEP) criteria for thermal and voltage studies. The RTO plans to have the study completed by July.
Egan said PJM is coordinating with MISO to conduct a study on the deactivations and have agreed to use a 2031 base case of the Multiregional Modeling Working Group (MMWG). The RTOs will model already announced generation deactivations and assumed deactivations based on the Illinois legislation. The models will also use projects in the interconnection queues for the generation replacement from deactivations.
PJM will work with the affected transmission owners for case assumptions and identifying any mitigation upgrades, schedules and costs resulting from the deactivations, Egan said.
Jason Connell, director of infrastructure planning for PJM, discussed the possibility of forming a new subcommittee to continue discussions of interconnection process changes after work in the Interconnection Process Reform Task Force (IPRTF) finishes.
PJM’s proposal regarding the development of new rules for the interconnection process that came out of the IPRTF won near unanimous support from stakeholders at the January PC meeting. (See “New Interconnection Rules Endorsed,” PJM PC/TEAC Briefs: Jan. 11, 2022.)
Connell said PJM staff have had discussions for several weeks internally and with stakeholders about creating a new subcommittee to continue discussions on additional interconnection issues identified in the task force. PJM is working on formulating a subcommittee charter to bring to the April PC meeting for a first read. Connell said the intention is to begin holding meetings of the new subcommittee by June and establish a near-term agenda if it’s endorsed by stakeholders.
Manual 14F Update
Joseph Hay of PJM’s infrastructure coordination department provided a first read of Manual 14F: Competitive Planning Process regarding the biennial review. Hay said the review involved two main changes to the manual.
First, the critical energy/electric infrastructure information (CEII) in Manual 14F was referenced over to Manual 14B because that manual is the source document for PJM’s CEII. Hay said the change will eliminate the requirement to edit Manual 14F whenever a change is made to 14B.
The second significant update was that the Secure File Transfer Tool used to submit all proposals was replaced with a requirement to use “Competitive Planner” to submit proposals. Hay said the Secure File Transfer Tool is still available for stakeholders and will be used to submit supplemental data on an “as needed” basis.
Stakeholders will vote on the manual changes at the April PC meeting.
Manual 21A Revisions
Joshua Bruno, senior analyst in PJM’s resource adequacy planning department, provided a first read of revisions in Manual 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis. The revisions are part of an effective load-carrying capability (ELCC) model run timing update and other changes to reflect the continuation of the current method of providing unit-specific backcasts only as requested.
The committee will be asked to approve an issue charge and problem statement and endorse the proposed manual revisions as part of the “quick fix” process at the April PC meeting.
PJM rules allow voluntary submission of unit-specific wind and solar parameters for development of backcasts for newer resources, Bruno said, but current manual language has an expiration date of March 1 for voluntary submissions. The submission of unit-specific parameters for all wind and solar is mandatory after the expiration date.
The alternative method is to use a zonal backcast, Bruno said, which PJM has found to be an “adequate” process.
The quick fix calls for removing the March 1 expiration date, Bruno said, which would allow PJM to continue the current practice where newer resources have the ability to elect to submit the unit-specific data or use the zonal backcast.
Bruno said another change included in the proposal is that the 2025/26 Base Residual Auction would use the December 2022 ELCC run instead of the older July 2022 run. He said the change would allow for the most recent data to be used for the when calculating the accredited unforced capacity (UCAP) for the 2025/26 BRA.
Aaron Berner, PJM manager of transmission planning, provided an update on the New Jersey offshore wind state agreement approach (SAA) proposal window at last week’s Transmission Expansion Advisory Committee meeting.
Berner said PJM has divided Option 1a, which involves onshore upgrades to existing transmission facilities, into several different geographical clusters to help in the review process. The clusters include: Northern New Jersey; Central New Jersey; Southern New Jersey; the Southern New Jersey border; and the Pennsylvania-Maryland border.
PJM is also continuing a market simulation analysis for the project combinations selected for a reliability analysis, Berner said, along with constructability and independent cost reviews of both the onshore and offshore proposals.
Berner said the New Jersey Board of Public Utilities recently posted a notice regarding a series of stakeholder meetings to collect stakeholder input on the evaluation of the transmission proposals. The first meeting takes place on March 22 with a focus on the SAA goals, the evaluation process and a review of the applications received.
Potential solution options for offshore wind projects in New Jersey | PJM
A second meeting on March 30 deals with how the potential transmission projects will integrate with future offshore wind projects.
Generation Deactivation
Phil Yum of PJM’s system planning modeling and support department provided an update on two recent generation deactivation notifications.
Generation deactivation requests in PJM from 2018-present | PJM
The 1.9-MW Ottawa County Landfill in Ohio’s American Transmission Systems Inc. (ATSI) transmission zone requested a deactivation date of May 31, while the 81-MW Essex 9 gas-fired generation unit in the Public Service Enterprise Group zone in New Jersey requested a deactivation date of June 1.
Yum said reliability analyses for both units are currently underway.
PJM wants the Resource Adequacy Senior Task Force (RASTF) advance discussions to evaluate the RTO’s need for procuring additional reliability-based generation as more intermittent resources are integrated into the grid.
Chris Pilong and Alex Scheirer of PJM provided a first read at last week’s Operating Committee meeting of a proposed “initial direction” regarding reliability products and services required in the RASTF charter.
Pilong said stakeholders began looking at the list of generator “reliability attributes” at the beginning of the year, examining PJM’s renewable integration studies and papers to determine the recommendations for addressing potentially new reliability services and next steps in the process at the RASTF and other committees and task forces.
Pilong said stakeholders will discuss reactive capability and supply issues in the Reactive Power Compensation Task Force to make sure PJM is able to “utilize, measure and compensate the full reactive capability of synchronous and non-synchronous generators independent of their power output.” The issue also calls for discussions on the ability of all resources to follow voltage schedules and demonstrate performance.
From a regulation perspective, Pilong said, stakeholders recommend reviewing existing regulation market signals and considering future system needs as part of the regulation market redesign issue charge approved by the Market Implementation Committee. (See “RTO to Propose Review of Regulation Market,” PJM MIC Briefs: Nov. 3, 2021.)
“If the signals are going to be reviewed and looked at, we should be looking at what are the right signals for the future,” Pilong said.
Members recommended that the Energy Price Formation Senior Task Force consider how to value flexibility of generation within the existing or modified ancillary services, Pilong said, while another recommendation would have RASTF explore how to value fuel assurance for all resources that can be relied upon for “unexpected system conditions.”
Pilong said PJM and stakeholders may evaluate methods for data submission and review the existing penalty structure if data reporting requirements in PJM manuals are not followed. He said a potential problem statement and issue charge could be brought to the OC to examine manual language changes.
“We do see, in some instances, the data is not as accurate as we need it to be, especially as the fleet of inverter-based resources begins to grow,” Pilong said. “We really need to make sure we have accurate forecasts.”
Stakeholders will vote on the recommendations at the April 14 OC meeting.
UFLS Requirements Applicable to EKPC
Denise Foster Cronin of the East Kentucky Power Cooperative (EKPC) provided a first read of a problem statement and issue charge to appropriately document EKPC’s under frequency load shedding (UFLS) requirements in PJM.
Foster Cronin said EKPC is seeking stakeholder approval of limited PJM Operating Agreement, tariff and Manual 36 changes to document the UFLS.
The purpose of the UFLS requirement is to avoid an uncontrolled loss of load situation, Foster Cronin said, and the requirements establish a total percentage of load shed that must be achieved when the system frequency drops to a certain level to maintain the system.
All electric distributors must comply with the UFLS requirement established by their respective NERC region. When EKPC integrated into PJM in 2013, the cooperative was in the SERC region of the ERO.
Before EKPC’s integration, PJM’s OA documented a UFLS requirement for entities in the “PJM Mid-Atlantic Region,” the “PJM West Region” and the “PJM South Region.” But the OA was not changed with EKPC’s 2013 integration to incorporate the cooperative’s applicable UFLS requirement, and it wasn’t included in any of the regions.
In 2018, EKPC was added to the PJM West Region when the RTO worked with stakeholders to clarify the region definitions in its governing documents. However, other entities included in the PJM West Region are in the ERO’s ReliabilityFirst region, while EKPC remained in SERC, which has slightly different UFLS requirements.
Forster Cronin said a recent review of the region revisions “highlighted a potential confusion” of EKPC’s appropriate UFLS requirement. She said the oversight did not create a reliability problem or a “compliance vacuum” for the cooperative.
“There hasn’t been any gap with respect to the actual compliance and reliability,” Foster Cronin said.
Foster Cronin said EKPC has been working with PJM on the language correction issue.
The OC will be asked to approve the issue charge and endorse the proposed solution at the April meeting. The Markets and Reliability Committee and Members Committee will ultimately endorse and approve the solution and corresponding OA revisions.
“We’re hoping the committee agrees this is a pretty straightforward item and only impacts East Kentucky Power Cooperative,” Foster Cronin said.
Derin said the manual changes partially resulted from revisions in NERC standards CIP-012, COM-001 and EOP-008.
Minor changes were made throughout the manual, Derin said, including removing revision numbers from where NERC standards are referenced and replacing the term “member” with “PJM member” where applicable to keep the term uniform throughout the manuals.
In Section 2.5.6: Recovery Procedures, PJM clarified the loss of control center functionality procedures and documentation relating to EOP-008 and TO/TOP Matrix.
In Section 3.2.1.1: PJMNet Communications System, the language was clarified to ensure PJM is responsible for protecting all real-time assessment and real-time monitoring data through the PJMNet private network as the data is “in transit” between the PJM control centers and its routers. The RTO must also make sure all data is encrypted.
The committee will be asked to endorse the changes at its April meeting.
Manual Changes Endorsed
Several manual changes resulting from the periodic review were unanimously endorsed by stakeholders, including:
Manual 13: Emergency Operations, with a review of the language that added columns with winter values for estimated peak load and estimated load reduction in the voltage reduction summary table.
Manual 37: Reliability Coordination, with a review of the language that corrected Silver Run Electric to properly show as a transmission owner in Attachment A of the manual.
Lawmakers in Connecticut are taking another look at legislation that would allow auto manufacturers with an exclusive electric vehicle strategy to circumvent franchise law and sell directly to consumers in the state.
The bill (SB.214) “allows Connecticut to join 22 other states that allow all-EV-only, non-franchised manufacturers, like Rivian (NASDAQ:RVIN), Lucid (NASDAQ:LCID) and Tesla (NASDAQ:TSLA), to invest in brick-and-mortar dealerships in Connecticut,” said Kaitlin Monaghan, manager of public policy and senior counsel at Rivian.
EV-only companies would be subject to the same regulations as franchise dealers in the state under the law, if passed, according to Monaghan, who spoke Monday in support of the bill during a Transportation Committee hearing.
While current law in Connecticut requires auto manufacturers to sell their vehicles through a third-party dealership, the bill would allow the state to issue a dealer’s license to EV-only manufacturers. Under the bill, EV manufacturers would not be allowed to have a prior franchise agreement with a new car dealer or a controlling interest in or be owned by another licensed manufacturer.
“The bill allows Connecticut customers to choose the EV model and the EV purchasing experience they want,” Monaghan said. “A poll last year showed 83% of respondents support direct sales of EVs to consumers.”
A similar bill introduced in January 2021 gained some traction in the Connecticut legislature but did not pass the Senate before the end of the session. New York lawmakers are also considering a bill (S1763) that would alter dealer franchise law in the state in favor of EV manufacturer direct sales.
Recent auto sales statistics show that the presence of EV manufacturers with a direct sales approach is not hurting franchise dealerships, according to testimony by Daniel Witt, director of state and local public policy at Lucid.
“Dealers have been more profitable in the last two years than ever before,” Witt said. “That’s as Rivian and Lucid have started producing and delivering cars and as Tesla has sold more cars than ever before, globally.”
States that have allowed direct sales to customers have not lost jobs at dealerships, Kenneth Gillingham, a professor of economics at Yale University, said in testimony. “If there’s any impact at all, it’s not statistically distinguishable from zero.”
Connecticut EV owners, however, will have more money “in their pockets” because of lower costs on fuel and maintenance than for internal combustion vehicles, he said. That money, he added, will go toward in-state purchases that drive tax revenue.
Opponents of the bill in Connecticut say allowing the direct-sales model would establish two sets of rules for automobile competitors within the same market.
There is no law prohibiting Tesla, Rivian and Lucid from selling their vehicles in the state, as long as they “follow the same rules on automobile distribution that every other automaker is required to follow by law,” said Wayne Weikel, senior director of state affairs at the Alliance for Automotive Innovation, in testimony.
The franchise dealer model, however, does not work with Tesla’s approach to sales, according to testimony by Tesla Senior Policy Adviser Zach Kahn.
“By utilizing the direct-to-consumer sales model, Tesla has created a sales experience completely unlike the typical car buying experience in a dealership,” Kahn said. “We spend the time to educate our customers on the technology, answering countless questions about charging, battery performance and the like, and prepare them for electric vehicle ownership.”
Tesla’s call to change dealership laws was founded originally on its claim that the company was too small and its technology too new to compete in the existing market. But Weikel says that’s no longer the case.
An estimated 130 new EV models are due to hit the market by 2026, he said, and more companies are following in Tesla’s footsteps.
“Rivian and Lucid are asking for the same special treatment, but understand that there is a line of other startup companies right behind them,” he said.
The Maryland Senate late Monday approved legislation increasing the state’s greenhouse gas emission reduction goal to 60% below 2006 levels by 2030 — up from the current 40% target — and setting a 2045 deadline for reaching net-zero emissions (SB 528).
The Climate Solutions Now Act of 2022, which must also be approved by the House of Delegates, would target landfill methane emissions, set new energy conservation standards for buildings and require the purchase of zero-emission vehicles (ZEVs) for public school buses and the state fleet.
The bill, sponsored by Sen. Paul G. Pinsky (D), chair of the Senate Education, Health and Environmental Affairs Committee, cleared the Senate on a 32-15 vote, with all Republicans opposed.
The vote came after Pinsky last week withdrew a requirement that all new buildings use electric power, rather than fossil fuels, for space and water heating by 2024 and a mandate that new buildings be equipped to install solar energy systems and electric vehicle charging. Instead, the legislation requires the Public Service Commission to report to the legislature by September 2023 whether the electric grid can support an all-electric building code in the future.
Maryland GHG emissions and targets by year | Maryland Department of the Environment
Pinsky tweeted that the bill was “a major step forward but weakened by the utility industry that placed their profits ahead of people & the environment.”
Last year, negotiations to increase the state’s emissions-reduction target collapsed after the Senate rejected House revisions that would have set the state’s 2030 goal at only 50% of 2006 levels. (See Md. Climate Bill Dies in House-Senate Standoff.)
Among other provisions, SB 528:
Requires the Maryland Department of the Environment to adopt standards for methane emissions for municipal solid waste landfills by 2024 that are at least as stringent as those adopted by California.
Creates a Climate Justice Corps Program for 18- to 25-year-olds to work on clean energy or climate mitigation projects.
Requires a transition to zero-emission school buses: Beginning in fiscal 2024, county school boards would be prohibited from signing contracts to purchase or use any school bus that is not a zero-emission vehicle (ZEV) unless the school board is unable to obtain federal, state, or private funding to cover the “incremental costs” of ZEVs or there are no available ZEVs to meet the district’s performance requirements.
Transitions the state vehicle fleet to ZEVs: The bill sets a goal that all passenger cars in the state vehicle fleet be ZEVs by 2030 and that other light-duty vehicles in the fleet be ZEVs by 2036. It would require the state to make ZEVs 25% of all passenger cars purchased in fiscal 2023, rising to 100% beginning in fiscal 2027. Beginning in fiscal 2024, any passenger car purchased for the state fleet that is not a ZEV must be a hybrid vehicle.
Creates the Climate Catalytic Capital Fund, administered by the Maryland Clean Energy Center to promote environmental justice and to leverage private capital investment in technology development and deployment, including project planning. Minimum annual funding for fiscal 2024 through 2026 would be $5 million.
Requires annual funding of $12 million from fiscal 2024 through 2032 to help school systems cover the cost difference between meeting basic high-performance building requirements and net-zero energy requirements. Subject to funding, at least one of the schools constructed in each school system from July 2023 through June 2033 would be required to meet net-zero energy requirements. During the same period, districts would have to consider including rooftop solar panels on new schools.
Requires funding of $5 million annually in fiscal 2024-26 for projects to reduce direct GHG emissions from multifamily residential buildings.
Requires development of performance standards for “covered” buildings (non-school or historic buildings of at least 25,000 square feet) owned by the state: a 50% reduction in net direct GHG emissions by January 2030 compared with 2025 levels and net-zero direct GHG emissions by 2035. For covered buildings not owned by the state it requires a reduction of at least 30% in GHG emissions by 2035 and net-zero emissions by 2040.
The House of Delegates has been considering SB 528’s provisions in three bills heard by separate committees.
“It’s my understanding that the House is actually going to work off the Senate bill versus those three independent bills,” Kim Coble, co-chair of the Greenhouse Gas Mitigation Working Group, told a working group meeting Tuesday.
She said the Senate Budget and Tax Committee on Monday endorsed the funding for implementing the Pinsky bill. “So that is embedded in the budget at this point in time,” said Coble, who represents the Maryland League of Conservation Voters.
Working group member Sandy Hertz, of the Department of Transportation, noted that the bill passed by the Senate struck a provision making the state fleet EV targets “subject to the availability of funding.”
The bill said that “it will be done, regardless of whether or not you have the funding set aside for it,” Hertz said. “That was one thing that stood out to me as fairly impactful to us at the state level.”
Partners in a recently formed New Mexico Reforestation Center are seeking roughly $80 million in federal funding to reach the goal of producing 5 million seedlings a year to plant in wildfire burn areas.
The Reforestation Center was created in January through an agreement among the New Mexico Energy, Minerals and Natural Resources Department (EMNRD) and three state universities: New Mexico Highlands University, New Mexico State University and University of New Mexico.
Two bills in the New Mexico legislature this year — HB101 and SB145 — would have allocated $4.6 million to the Reforestation Center. Neither bill passed.
The center’s collaborators now plan to apply for a federal grant to fund their activities.
The U.S. Department of Agriculture in February announced $1 billion in funding through its Partnerships for Climate-Smart Commodities opportunity. The funding is offered to farmers, ranchers and forest landowners to implement climate-smart production practices on working lands. Recipients are asked to quantify the greenhouse gas benefits of those practices and develop markets for the resulting climate-smart commodities.
Proposals ranging from $5 million to $100 million will be considered in the first funding pool. The application deadline is April 8.
Growing Capacity
The state needs more than 300 million seedlings for a backlog of burned areas, according to EMNRD, but the current tree nursery capacity is 300,000 seedlings per year.
The New Mexico Reforestation Center’s goal is to grow 5 million seedlings per year. And the seedling production will be “climate smart,” to increase the odds that trees planted now will survive in future climate conditions.
“The new Reforestation Center will increase the number of acres planted each year, which in turn contributes to healthy watersheds and climate change resiliency,” EMNRD Secretary Sarah Cottrell Propst said in a release.
Joshua Sloan, associate vice president of academic affairs, Forestry and Reforestation Center at New Mexico Highlands University, told NetZero Insider that two steps are being taken to produce climate-smart seedlings.
The first is to collect seeds from trees that, through natural selection, have shown that they can handle heat and drought.
The next step focuses on how the seedlings are grown. Rather than watering them regularly, Sloan said, water is limited so that the seedlings begin to adapt to drought conditions. The idea is to prevent the transplant shock that seedlings grown in conventional ways often experience.
In another part of the project, researchers at the University of New Mexico will be working on forest climate modeling and quantifying carbon capture by trees.
“Every seedling we put on the landscape is a carbon sink,” Sloan said.
The Reforestation Center also includes a workforce development component.
“A skilled forestry workforce is necessary to plant the seedlings grown by the Reforestation Center,” New Mexico Highlands University President Sam Minner said in a statement. “Our students and faculty will be training the next generation of tree planters and foresters.”
Funding Sources
The reforestation team is still working on its application for USDA funding, but Sloan said the request would likely be for about $80 million. The funding would cover the costs to build the new, high-capacity nursery and keep it running for five years.
Meanwhile, Sloan said, the reforestation efforts have received some smaller contributions, including a private donation and in-kind support. The funds are enough to jump-start the seed collection project, he said.
Although the bills requesting $4.6 million for the Reforestation Center failed, the state legislature approved an $80,000 annual appropriation to EMNRD for reforestation projects, department spokeswoman Susan Torres said.
The legislature also approved a new full-time reforestation coordinator in EMNRD’s Forestry Division. The employee will be responsible for statewide seed collection and planting coordination.
“Our forests, grasslands, and agricultural lands have a large part to play in absorbing CO2 as we work towards fewer emissions,” the climate strategy said in a section on natural and working lands.
The climate strategy calls on the Forestry Division to develop a plan for incorporating drought-tolerant plants in reforestation efforts. In addition, the division will use research on wildfire burn areas to identify microsites where seedlings are more likely to survive.
The approaches to tree-planting will be shared with other state divisions and agencies. For example, EMNRD’s Mining and Minerals Division could use the Forest Division strategy in its mine reclamation reforestation work.
In a now-familiar refrain, MISO is warning stakeholders of possible maximum generation emergencies should high load and high outages collide this spring.
Under probable load scenarios with expected outages, MISO expects to have:
99 GW of available capacity in March to cover an 88-GW peak demand estimate;
91 GW of available capacity in April to cover an 83-GW peak; and
101 GW of available capacity in May to cover a 91-GW peak.
However, the RTO said should elevated load and excessive outages enter the picture, it could find itself declaring an emergency to access its emergency-only resources in April and May. MISO said it doesn’t see itself exhausting its 12 GW of load-modifying resources and operational reserves, even in the direst situations.
In a worst-case scenario, the grid operator would have just 79 GW of non-emergency capacity in April should demand reach 88 GW. Under the same scenario in May, MISO would have 95 GW of capacity to handle a 104-GW demand peak. In both cases, staff would be forced to access emergency supplies.
MISO set its all-time spring peak of 111 GW in May 2018.
Over the past five years, the RTO has experienced an average 36.3 GW of forced and planned outages during spring monthly peaks. It saw its highest on-peak spring outages at 54.2 GW in April 2019.
MISO did not alter this year’s spring reliability outlook to include the loss of its firm contract path linking its Midwest and South regions through June 30. Staff said it wasn’t necessary to factor the line loss into its forecasts because it was unlikely to cause any operational impacts. (See MISO Midwest-South Transfer Service on Outage until July.)
The National Oceanic and Atmospheric Administration predicts higher-than-average temperatures for MISO South and a chance at higher temperatures across most of the Midwest, except for the northernmost portion of the footprint. NOAA also expects much of the Midwest to experience more precipitation than usual.
MISO ended winter without the serious reliability event it was steeling itself for. The grid operator had a 100.2-GW winter peak on Jan. 21, 2022, about 9 GW short of the all-time winter peak set in early 2014 during a polar vortex.
FERC on Monday granted MISO’s request to give generator interconnection customers an opportunity to reduce their time in the interconnection queue from more than 500 days to a single year.
In a letter order issued Monday, the commission said MISO could offer interconnection customers a faster finish time in return for proceeding without definitive network upgrade cost information (ER22-661).
The grid operator is hoping to whittle about 140 days from its generator interconnection process by cutting the days allotted for interconnection agreement negotiations and study and performing some study aspects simultaneously. (See Shorter Interconnection Queue Coming, MISO Says.)
Interconnection customers in the final phase of MISO’s three-part definitive planning process will now have a choice to spend 60 days in the stage without waiting on a network upgrade facilities study before proceeding to generator interconnection agreement (GIA) negotiations. Their other options is to spend about 150 days in a holding pattern while they wait on a final upgrade report.
GIA negotiations will be condensed from about 150 days to around 108 days under MISO’s plan.
FERC said the reductions stand to improve the interconnection queue’s efficiency.
The commission said it was appropriate for MISO to offer “each interconnection customer a choice between a timelier path to GIA negotiations with less cost certainty or a less timely path with more cost certainty entering into GIA negotiations, based on its preferences.”
FERC said generation developers that opt for the shorter path will do so with the “understanding that their assigned costs may be refined in the final interconnection facilities study report.”
MISO has said shortening the queue timeline will help it better align network upgrade planning with its transmission expansion plan, which is conducted on an annual basis.
For years now, the RTO has placed an emphasis on accelerating hold times for generation waiting for system access in its interconnection queue. Last month, the queue held 133 GW of projects, comprising mostly renewable generation.
Some stakeholders have expressed concerns that MISO can accomplish its goal. They say the real slowdown lies in the RTO’s notoriously time-consuming affected system analyses with its neighbors. Staff have said that if the new changes don’t meaningfully shorten queue wait times, MISO will pursue additional changes.
FERC on Friday accepted PJM’s revisions intended to increase transparency into and the efficiency of the RTO’s auction revenue rights (ARR) and financial transmission rights markets (ER22-797).
The commission’s decision marks a milestone for PJM after it and its stakeholders spent several years discussing changes to the markets after the GreenHat Energy default in 2018.
PJM filed the proposal in January after stakeholders endorsed the revisions at the Markets and Reliability Committee and the Members Committee in the fall with majority support. The FTR portion of the tariff revisions will take effect on Sept. 1, and the ARR portion on Feb. 1, 2023.
“We find that PJM’s proposal is just and reasonable because it enhances hedging opportunities for load and helps enhance market liquidity and future price discovery,” the commission said.
PJM’s proposal included revisions to its tariff and the Operating Agreement that were guided by the findings of a report developed by London Economics International (LEI).
Proposed enhancements to PJM’s current ARR/FTR market design. | London Economics
The RTO said its proposal aimed to recognize recommendations made in the LEI report and address concerns raised by the Independent Market Monitor and stakeholders. The proposal also sought to maintain the consultant’s conclusion that the existing FTR product is “reasonable and generally achieving the intended purposes” of serving as a financial equivalent to firm transmission service and to ensure “open access to firm transmission service by providing a congestion-hedging function.”
“The LEI report found that PJM’s FTR/ARR market design is achieving its dual purposes of facilitating the return of congestion charges to load and enabling hedging and supporting forward market activity, and overall is ‘creating overall positive value for load,’” the commission said. “However, the LEI report outlined potential enhancements to PJM’s FTR/ARR market design, focused on the themes of equity, efficiency and transparency, which PJM reflected in the instant proposal.”
The revisions make it so ARRs are allocated based on 60% of network service peak load, rather than zonal base load. They also provide additional self-scheduling options for ARR holders; add new FTR class types for on-peak weekday, on-peak weekend and holiday, general everyday off-peak and 24-hour products; increase the bid limits in all FTR auctions from $10,000 to $15,000; and add a $1/MW-period class clearing price floor for all FTR option products.
Protests
Several stakeholders protested portions of PJM’s proposal.
A group of consumer advocates — including the D.C. Office of the People’s Counsel, the Citizens Utility Board, the Delaware Division of the Public Advocate, the Maryland Office of People’s Counsel, the New Jersey Division of Rate Counsel, the Pennsylvania Office of Consumer Advocate and the PJM Industrial Customer Coalition — said they supported PJM’s proposal but maintained that it “does not go far enough in some respects.”
The advocates argued that even though a more direct alignment of congestion revenues and costs is “undoubtedly a step towards a more efficient and equitable FTR/ARR market,” the change doesn’t address situations where surplus congestion or auction revenues occur and “should be returned to the load that paid for the transmission upgrades that made those surplus revenues possible.”
Dominion also expressed support for portions of the proposal, but it argued that the revisions don’t fully address the “under-allocation of congestion revenues” for load and an inability of certain load-serving entities to “come close to covering their congestion costs.” Dominion said PJM’s filing “does little” to address “disparate outcomes” under the current ARR/FTR construct that “persistently creates results where the congestion cost recovery by LSEs varies greatly.”
The Monitor alleged that PJM’s filing “perpetuates or worsens fundamental flaws in the existing PJM FTR/ARR market,” saying the current market design “consistently failed to return the congestion revenues to the load that paid it.”
It also argued that the total congestion offset paid to load is “inequitable and varies by zone,” with some zones receiving more in offsets than the total congestion payments and other zones receiving less in offset. The offsets “are a function of the assignment of ARRs and the valuation of ARRs in the FTR auctions” and that the expansion or modification of the path-based rights available to load and the market will “simply change the arbitrary allocation of congestion among ARR holders and participants in the FTR market and will not correct the arbitrary allocation of congestion.”
FERC Determination
The commission said it determined the ARR market construct were just and reasonable and that the expansion of the source/sink combinations of the ARR allocation process “provides load the first rights to the transmission system before FTR holders can purchase such rights and, therefore, increases the network capacity allocated to load.”
“While not the sole purpose, one of the purposes of the FTR/ARR market is to return congestion charges to load, and this proposed change is consistent with that purpose,” FERC said.
FERC said the proposal’s call to replace zonal base load “protects zonal native load hedging ability by increasing up-front capability to load.” The commission said PJM’s selection of the 60% standard was a “reasonable limit at which additional value could be guaranteed” without significantly increasing violations or producing additional transmission constraints.
It also said that “PJM’s proposal to not award FTR options with a market-clearing price of less than $1 mitigates risk-free profit by ensuring all FTR options that clear have, at least at the time they were bid and awarded, actual value,” the commission said. “We also find that PJM’s proposal to create new FTR class types provides more flexible hedging opportunities.”
The commission said it disagreed with the challenges to how congestion surplus is allocated and the “fundamental nature” of a path-based FTR/ARR construct. It said the protests citing concerns regarding provisions of the existing FTR/ARR market construct were outside the scope of the proceeding.
FERC also disagreed with the Monitor’s argument that the revisions in the proposal do not return “sufficient” congestion revenue to load, saying it rejected the “foundational argument” that the “sole purpose of FTRs is to return congestion revenue to load and the market should therefore be redesigned to accomplish that purpose.”
“PJM’s proposal is not rendered unjust and unreasonable simply because the IMM thinks a further allocation to load would be desirable,” FERC said. “Consistent with commission precedent, we reiterate that ‘the purpose of FTRs to serve as a congestion hedge has been well established.’ FTRs were designed to serve as the financial equivalent of firm transmission service and play a key role in ensuring open access to firm transmission service by providing a congestion-hedging function.”
ERCOT interim CEO Brad Jones last week continued his push for a Texas gas desk in testimony before state legislators, who are toying with the idea creating a gas market monitor after disruptions in fuel supplies nearly collapsed the grid during last winter’s major storm.
Appearing Wednesday before the Senate Business and Commerce Committee, Jones compared ERCOT’s lack of transparency into the state’s natural gas system with looking through a peephole in the front door.
“We see images, we see shapes, but we don’t necessarily see the full picture of what we need to see. We don’t have a full view of the reliability situations in the gas market,” he said. “This is important today in our market as we try to assess the reliability of natural gas generators to get the fuel they need to produce the generation we need.”
Jones told the committee that ISO-NE, NYISO and PJM all have gas desks manned by staff 24/7. He has for several months pitched the grid operator’s board and stakeholders on the idea of having staff who “can gather that information and make sure we have the situational awareness we need at ERCOT.”
“We don’t know when a pipeline is out for maintenance or a compressor station on outage for something that is broken,” Jones said.
ERCOT’s Brad Jones (right) testifies before a Texas Senate committee as (left to right) Division of Emergency Management chief W. Nim Kidd, Railroad Commissioner Wayne Christian and PUC Chair Peter Lake listen. | Texas Senate
In October, he said staff “discovered by happenstance” that one generator it was counting on for power during a future low-wind day would not be able to operate because its gas supply transportation system would be undergoing maintenance. After a few calls and with the regulators’ help, staff was able to identify the transportation company and have the maintenance outage rescheduled “in a very cooperative way.”
“It was very helpful they did that, but the key is we didn’t know the information we needed to know,” Jones said.
For the moment, Jones believes the grid operator can get the information it needs through “voluntary cooperation,” but with the Texas Energy Reliability Council’s lead. The agency is made up of leaders from ERCOT, state regulators and industry. It has been meeting once or twice a month lately, helping improve coordination between the electric and gas sectors.
Asked whether Jones needed anything from legislators to make the gas desk a reality, he said not for the time being.
“The TERC has the capability to work through these issues,” he said. “Absent a cooperative environment, which I fully believe we have with the gas companies, TERC has the ability to make those recommendations to the legislature for the next legislative session.”
Increasing Oversight
The back-and-forth revealed that legislators may be conflating an operations desk like some gird operators have with the market monitors that keep an eye on wholesale electricity markets.
However, the gas industry is commonly seen as the weak link in ERCOT’s ability to meet demand with supply. While the grid operator’s generation and transmission facilities were required to be winterized and inspected before this winter, gas facilities don’t have to meet the same requirements until next winter.
The Railroad Commission (RRC), which regulates Texas’ intrastate oil and gas industry, is seen as being too chummy with the industry it regulates and has been accused of slow-walking regulatory changes. The commission’s first winterization rules allowed companies to opt out for a $150 fee, but that was changed after political pushback. (See Texas Senators Call for New RRC Weatherization Rules.)
A joint report by FERC and NERC pointed to the lack of consistent natural gas supplies to power plants as among the major causes for the widespread outages that followed last year’s winter storm. Natural gas supplies again dropped this year during several cold fronts, indicating shut-in production at Texas natural gas facilities, Bloomberg said.
“We need to continue our oversight responsibilities,” Committee Chair Charles Schwertner (R) said. “I think what happened last February has in some part the responsibility and blame of the legislature for lack of oversight.”
RRC Chair Wayne Christian was evasive in several of his responses to the committee. He told the committee there is “no state, nation, anything” that has daily monitoring and reporting of the gas supply.
Christian, who faces accusations of ethics violations, is in a Republican primary runoff with oil and gas attorney Sarah Stogner, who gained attention with a racy video involving her riding a pumpjack.
“I hesitate to add another layer of government regulation to the free market natural gas system.” Christian said.
He may not have a choice. Sen. Donna Campbell (R) said she might file legislation to gain greater transparency into the natural gas market when the 88th Texas legislature goes into session next January.
“I haven’t heard of any agency that wants more regulation by the legislature, but I will take that up,” Campbell said.
Erin Overturf, Western Resource Advocates | Energy Bar Association
Rachel Bryant, PA Consulting | Energy Bar Association
