A working group of the Maine Offshore Wind Roadmap is considering making a recommendation to extend the current OSW development prohibition for state territorial waters into federal waters.
“There is strong interest in the [Fisheries Working Group] in advocating for the state to take a position on moving OSW construction further offshore … to minimize OSW development and fisheries conflict,” said Meredith Mendelson, deputy commissioner of the Department of Marine Resources and co-chair of the working group.
The group is still discussing the potential recommendation, and it has not settled on a proposed distance for the prohibition, Mendelson said during a roadmap advisory committee meeting Friday.
“We’ve had multiple discussions around this, and I expect we will continue to for some time, but we wanted to bring it forward to the advisory committee because we think this is an important issue,” she said.
A document released by the working group Jan. 18, however, included a suggested distance of 75 nautical miles for the prohibition. At that distance, the prohibition would easily exceed the distance from shore of all active U.S. Bureau of Ocean Energy Management lease areas on the East Coast.
Vineyard Wind I, for example, is sited 30 nautical miles from the Massachusetts coast, and the lease areas recently announced by BOEM for the New York Bight range between 20 and 69 nautical miles from the New York coast.
Gov. Janet Mills signed a law last summer that prohibits new OSW development in state waters, which extend 3 nautical miles from the coast. Mills had originally proposed a 10-year moratorium on OSW in state waters, but she eventually agreed to a permanent ban to protect commercial lobster harvesting.
The Maine Governor’s Energy Office filed an application in October to lease a site in federal waters in the Gulf of Maine for a floating offshore wind research array. The preferred site, according to the application, is 25 nautical miles from the nearest point on the mainland.
Considerable engagement with members of the fishing industry went into selecting the proposed array site, according to the application. Selection of a site “no less than 17 nautical miles offshore” reduces “potential impacts on inshore fisheries,” the application said.
A possible recommendation by the working group to extend the state-waters ban to federal waters would be part of a wider package of recommendations that the advisory committee will consider related to OSW development and the state’s fishing industry.
The group shared 11 initial recommendations with the committee Friday, including encouraging the state and BOEM to engage the fishing industry directly in the development of wind areas in the Gulf of Maine. In addition, the group wants to see the state initiate a port assessment as wind areas are identified to determine the implications for local port economies.
Three other working groups delivered their initial recommendations to the committee in December, and all the groups will refine their recommendations with a goal of releasing an official set of draft recommendations in July. The final roadmap is due at the end of the year.
A working group of the Maine Offshore Wind Roadmap is considering a request that the U.S. Bureau of Ocean Energy Management bar OSW development within 75 miles of the state’s coast.
“There is strong interest in the [Fisheries Working Group] in advocating for the state to take a position on moving OSW construction further offshore … to minimize OSW development and fisheries conflict,” Meredith Mendelson, deputy commissioner of the Department of Marine Resources and co-chair of the working group said during a roadmap advisory committee meeting Friday. “We’ve had multiple discussions around this, and I expect we will continue to for some time, but we wanted to bring it forward to the advisory committee because we think this is an important issue.”
Mendelson said the group has not settled on a proposed distance for the prohibition. A document released by the working group Jan. 18, however, said the Fisheries Working Group “strongly encourages the state to advocate for BOEM and the [Gulf of Maine] Interagency Task Force to prohibit the development construction of OSW turbines within 75 nautical miles or less from the Maine coast.”
At that distance, the prohibition would easily exceed the distance of all active BOEM lease areas on the East Coast.
Vineyard Wind I, for example, is sited 30 nautical miles from the Massachusetts coast, and the lease areas recently announced by BOEM for the New York Bight range between 20 and 69 nautical miles from the New York coast.
Gov. Janet Mills signed a law last summer that prohibits new OSW development in state waters, which extend 3 nautical miles from the coast. Mills had originally proposed a 10-year moratorium on OSW in state waters, but she eventually agreed to a permanent ban to protect commercial lobster harvesting.
The Maine Governor’s Energy Office filed an application in October to lease a site in federal waters in the Gulf of Maine for a floating offshore wind research array. The preferred site, according to the application, is 25 nautical miles from the nearest point on the mainland.
Considerable engagement with members of the fishing industry went into selecting the proposed array site, according to the application. Selection of a site “no less than 17 nautical miles offshore” reduces “potential impacts on inshore fisheries,” the application said.
The call to extend the state-waters ban to federal waters would be part of a wider package of recommendations that the advisory committee will consider related to OSW development and the state’s fishing industry.
The group shared 11 initial recommendations with the committee Friday, including encouraging the state and BOEM to engage the fishing industry directly in the development of wind areas in the Gulf of Maine. In addition, the group wants to see the state initiate a port assessment as wind areas are identified to determine the implications for local port economies.
Three other working groups delivered their initial recommendations to the committee in December, and all the groups will refine their recommendations with a goal of releasing an official set of draft recommendations in July. The final roadmap is due at the end of the year.
[EDITOR’S NOTE: A previous version of this story erroneously included the New York Power Authority as part of the group of utilities.]
New York’s local transmission and distribution system owners on Thursday recommended that state regulators approve a coordinated grid planning process (CGPP) and revised benefit-cost analysis (BCA) method as proposed by them in December (20-E-0197).
The New York Public Service Commission in September established a category of public policy transmission investments and directed investor-owned utilities to revise their proposed benefit-cost analyses. (See New York Adopts Groundbreaking Tx Investment Rules.)
“The CGPP will facilitate technical collaboration between planning authorities and vetting of the existing system studies to ensure consistency between all studies, eliminating confusion and potential conflicting information,” Bart Franey, National Grid supervisor of regulatory strategy, said to more than 220 participants at a technical conference held by the PSC.
“Once established, the CGPP will align system representation planning tool assumptions and other key constraints to drive consistency between all CLCPA-based studies [and] will be used to inform the market policymakers on the cost and viability of future interconnections,” Franey said, referring to the Climate Leadership and Community Protection Act, which requires that 70% of New York’s electricity generation come from renewable resources by 2030 and that generation be 100% carbon-free by 2040.
The utilities group include the state’s IOUs, as well as the Long Island Power Authority. Staff from the Department of Public Service (DPS), the New York State Research and Development Authority (NYSERDA) and NYISO helped shape the proposals, on which interested parties can submit comments until March 21.
The revised BCA approach would use capacity expansion analyses. Costs would be evaluated on a dollars-per-megawatt basis for transmission and non-wire alternatives (NWAs). Benefits would be evaluated as the incremental amount of energy delivered to load as a result of reduced curtailments and the capacity of additional renewable generation that can be interconnected.
Projects would be ranked on the basis of metrics and criteria to be developed in collaboration with DPS staff, the utilities said.
New Technologies and More
The utilities considered several new and emerging technologies in their potential projects, including power flow control devices, dynamic line ratings and energy storage, the commission said, noting several “areas of concern” characterized by the presence of existing renewable generation that is already experiencing curtailments and a strong level of developer interest that exceeds the capability of the local transmission system.
FERC in December ordered transmission owners to stop the use of static line ratings in evaluating near-term transmission service, which it said will improve accuracy and transparency, and increase utilization of the grid. (See FERC Orders End to Static Tx Line Ratings.)
“Modifying the rating of a given transmission line throughout some given period rather than solely having seasonal based ratings, as is the conventional practice, can be taken into consideration in operations and planning, so that’s a very recent order,” said Zach Smith, NYISO vice president of system and resource planning. “From NYISO’s perspective we’re looking at it and considering what we do on compliance for that.”
PSC orders in this proceeding have specifically pointed to DLR as a technology that may help the state get more CLCPA benefit at low cost, said Elizabeth Grisaru, deputy director of the DPS’ Office of Electric, Gas and Water. “The commission has specifically pointed to [DLR] as one of the technologies our utilities should be considering when developing and proposing” their projects.
The crux of the grid analysis is to identify the placement of generation that can optimally use existing transmission on both the bulk and non-bulk systems, and those siting assumptions and land-use assumptions are going to be critical, Franey said.
NYISO analysis found tightening margins across the New York grid through time, with a margin of only 200 MW in New York City (Zone J) and only 700 MW in western New York (Zone A) by 2030. | NYISO
Transmission providers are hoping for long-sought-after changes on FERC’s Advance Notice of Proposed Rulemaking, a wide-ranging inquiry into the commission’s rules on transmission planning, cost allocation and generator interconnection. (See Transmission Industry Hoping for Landmark Order(s) out of FERC ANOPR.)
The ANOPR proceeding will likely have impacts not only on the comprehensive system planning process, but on the way that that interacts with various policies, such as the interconnection process and how the system is planned as a whole relative to generation coming forward, Smith said.
“Depending on what comes out of that FERC proceeding, presumably an order at some point, it could be a great opportunity for the NYISO, our stakeholders, for all of us to be working together on what’s the most efficient planning process,” Smith said.
Advisory Council Makeup
The utilities also proposed creating a new advisory council to manage the planning cycles.
The scope of work would be developed in the first stages of the CGPP by the council, said Martin Paszek, section manager for transmission planning at Consolidated Edison.
“I would try to keep the council as one group and maybe with subgroups … but not have two separate groups that are losing the coordination we’re trying to achieve,” said Bill Acker, executive director of New York Battery and Energy Storage Technology Consortium (NY-BEST).
A planning group with a distribution subgroup would work well, agreed Zack Dufresne, executive director of the New York Solar Energy Industries Association (NYSEIA).
The proposed process is two-pronged, with the first being NYISO’s local transmission owner planning process, wherein utilities’ specific content and technical information regarding transmission investments would be reviewed and discussed openly, Franey said.
“The second prong to our stakeholder engagement plan really adopts a couple of models that exist in New York today such as the New York State Reliability Council or the Climate Action Council, [which] are very useful at leveraging stakeholder input on a more tactical basis,” Franey said.
The council would invite information that utilities aren’t experts in, such as generation development and land use, so it would consist of representatives not only from utilities and the state, but also from community organizations and renewable energy trade associations, he said.
“We envision that these industry organizations or groups would nominate a rep and an alternate to set up a lot of the critical input that would then translate into assumptions for modeling purposes,” Franey said.
In thinking about stakeholder engagement, the DPS considered its own Interconnection Policy Working Group and Interconnection Technical Working Group structures, which “are pretty good models,” Grisaru said.
One important group that wasn’t in the proposal is consumers, who “absolutely” need to have a voice in the process, said Couch White attorney Kevin Lang, representing New York City.
“I believe there are a lot of people that are participating this morning who are not active in the NYISO process, and if what we’re talking about is distribution and local transmission, which is under PSC purview, I question whether or not a NYISO process that looks at the bulk system is the right venue to be talking about distribution and local transmission issues and whether or not the audience is even the correct audience for those discussions,” Lang said.
Lang had an ally in Erin Hogan of the state’s Utility Intervention Unit.
“Allowing developers to select sites very remotely and then have the expectation that consumers will be recouping costs and the investments that might need to expand the headroom does not seem to be wise, leaving consumers too far out of the loop,” Hogan said.
She suggested informing county executives of the planning discussions so they can share the information and make communities knowledgeable about the decisions being made and how people might be able to participate.
“I want to be clear today that this is the starting point for this effort,” said Tammy Mitchell, director of the DPS Office of Electric, Gas and Water. “Much more work and stakeholder input will be needed to fill out the details of the process and align [utilities] and New York ISO activities to support holistic views of CLCPA needs, so there will be many other opportunities to ask questions and provide input in the planning process.”
State regulators last week approved Hawaiian Electric Company’s (HECO) $4.98 million pilot to install electric vehicle charging infrastructure across the state in a bid to incentivize commercial customers to invest in charging ports.
The pilot program, Charge Ready Hawaii, tasks HECO with building the underlying infrastructure so that commercial customers only have to pay for the installation and maintenance of the EV charging ports themselves.
HECO will build “make-read” infrastructure in 30 locations across the state — 14 on Oahu, 8 on Maui and 8 on Hawaii Island, enough to support an estimated 180 EV charging ports over a three-year period. The pilot program will target commercial sites, multi-unit dwellings and locations for EV fleet parking.
HECO defines make-ready infrastructure as including “all infrastructure that the customer would otherwise be responsible for,” such as transformer upgrades and line extensions, “but excludes the charging stations, which are provided by the customer.”
Because of the high cost of installing EV charging infrastructure, HECO noted, the pilot program will provide an easier way for customers to “realize fuel savings relative to gasoline when they are charging at pilot participating commercial locations.”
HECO said emissions reductions “are anticipated” from the program, but that it could not provide specific figures. The data collected from the pilot will help with modeling future energy loads on the grid as the transportation sector adopts more EVs, the utility said.
HECO also noted its “openness” to prioritize building in underserved communities.
Based on expectations for future EV adoption in Hawaii, HECO estimates it will recover the $4.98 million cost of the pilot program in 10 to 12 years.
In approving the pilot, the Hawaii Public Utilities Commission said Charge Ready Hawaii will “yield meaningful data acquisition and experience that will enhance the development of a more permanent EV rate scheme and will inform the continued development of EV charging infrastructure.”
In a reversal of a decision last year, Arizona regulators voted last week to reject a set of energy rules that would have required the state’s electric utilities to cut carbon emissions 50% by 2032 and 100% by 2070.
The Arizona Corporation Commission (ACC) voted 3-2 on Wednesday to reject the energy rules. Commissioners Anna Tovar (D) and Sandra Kennedy (D) voted in favor of the rules, while commissioners Jim O’Connor (R) and Justin Olson (R), along with Chairwoman Lea Marquez Peterson (R), voted against them.
The vote is a reversal of the commission’s 3-2 vote in May to advance the rules, with O’Connor changing his vote. Because the rules approved in May incorporated substantial amendments, they needed to go through further rulemaking and return to the commission for a final vote.
O’Connor said on Wednesday that he supports clean energy but questioned whether the energy rules are needed.
“I have concluded that the utilities are serious and sincere with their commitment to clean energy,” O’Connor said. “I concluded they do not need these state-level energy rules at this time, which impose risks for ratepayers.”
‘Flip-Flop’ Criticized
Tovar chastised fellow commissioners who “flip-flopped” on the energy rules, “wasting hundreds of hours of staff time” as a result. The energy rules have been in the works for years, received thousands of public comments and are supported by a wide range of stakeholders, including utilities and energy industry companies, she said.
“We as commissioners should be ashamed that all of this painstaking effort was in vain, because we let politics get in the way of what is right,” Tovar said.
In November 2020, Marquez Peterson was one of four commissioners who voted in favor of starting the formal process to adopt a proposed rule that would require electric utilities to eliminate their carbon emissions by 2050.
But Marquez Peterson later said that she opposed mandates for reducing carbon emissions, saying such requirements would give utilities a “blank check” for recovering costs associated with the mandates.
When the energy rules came to the commission for a vote on May 5, 2021, Olson proposed an amendment to make the carbon-reduction targets voluntary. The amendment passed with votes from three commissioners — Olson, O’Connor and Marquez Peterson.
Later that month, Kennedy asked for a reconsideration of the rules. During a meeting on May 26, 2021, the commission accepted an amendment proposed by Tovar and O’Connor, which gave utilities until 2070 to reach 100% carbon-free emissions. Interim standards included a 50% reduction by 2032, a 65% reduction by 2040, an 80% reduction by 2050, and a 95% reduction by 2060.
The rules also included requirements for energy efficiency and energy storage.
The amended energy rules, with the 2070 deadline for eliminating carbon emissions, were approved on May 26 with a 3-2 vote. Marquez Peterson and Olson were opposed. (See Arizona Regulators Revive Clean Energy Rules.)
Utility Commitments
Marquez Peterson said Wednesday that when commissioners voted on early drafts of the rules, they knew it wasn’t the final vote.
She said that she supports 100% clean energy by 2050 as a goal. And now, she said, for-profit utilities have “adopted voluntary clean energy commitments on their own.”
“With their voluntary commitments, I believe we’ve entered into a new chapter and a transition to clean energy,” Marquez Peterson said.
In addition, she said, a report on the costs of a clean-energy mandate came out after the commission’s May vote.
An analysis by Ascend Analytics found that monthly electric bills would be $8 to $35 higher in 2050 if utilities provided 100% clean energy by then. The difference in cost, which varies by utility, is in comparison to a “least-cost” scenario. (See Report Projects Ariz. Ratepayer Costs for Going Clean.)
In a statement on Thursday, Marquez Peterson listed some examples of utilities’ commitment to clean energy. In January 2020, APS announced a goal of providing 100% clean, carbon-free electricity to customers by 2050.
In its 2020 integrated resource plan, Tucson Electric Power (TEP) said it would provide more than 70% of its power from renewable sources by 2035 and reduce carbon emissions by 80%.
TEP said in January that it brought three large clean-energy systems online in 2021. They are the 250 MW Oso Grande Wind Project near Roswell, N.M.; Wilmot Energy Center, which consists of a 100 MW solar array and 30 MW of battery storage near the Tucson International Airport; and the Borderlands Wind Project near the Arizona-New Mexico border, which includes 34 turbines producing a combined 99 MW.
Business Impact
Groups supporting clean energy reacted with disappointment to ACC’s decision to reject the energy rules.
“Strong, predictable clean energy standards are crucial for helping Arizona attract new businesses and build a booming job market for years to come,” said Shelby Stults, Arizona policy lead at Advanced Energy Economy, a national business group. “Abandoning this rules package takes Arizona’s economic and advanced energy growth drastically off course.”
Adam Stafford, Western Resource Advocates’ senior staff attorney in Phoenix, said that ACC must now find a new path forward for addressing the climate crisis.
“The power sector provides some of the most cost-effective opportunities to reduce climate pollution,” Stafford said in a release. “Arizona’s largest utilities have all said they want the regulatory certainty of a firm emissions reduction standard, and the business community has voiced support for that, as well.”
As more homeowners switch from natural gas to electric appliances, environmental researchers are thinking more about the fate of discarded gas appliances, speakers said at a Stanford University webinar.
“What happens to the old appliances?” said Chris Field, director of the Woods Institute for the Environment at Stanford, who moderated the session. “Are we just going to get a secondary market in junky gas appliances as a consequence of the push for electrification?” Field was relaying a question from a webinar listener.
Rob Jackson, a professor of Earth system science and a senior fellow at the Woods Institute, said that’s a question he’s been hearing a lot recently.
“If we just dump a bunch of gas appliances on the market and lower their cost, then we’ll make it more likely they’re used,” Jackson said. “I don’t know what the best approach for that is.”
Stephanie Greene, managing director of carbon-free buildings at the Rocky Mountain Institute, said incentives may be needed to address the issue of used gas appliances.
“Maybe not cash for clunkers per se, but some level of incentivizing, getting these older appliances out of the market entirely, is likely the right solution,” Greene said.
The webinar, which the Woods Institute hosted on Jan. 26, focused on electrification of the building sector. The idea behind building electrification is to phase out carbon dioxide emitting gas appliances, such as gas stoves, furnaces and water heaters, and instead use electric appliances, which may be fueled by clean energy.
Greene said that electrifying new buildings makes economic sense and will also help contractors, builders and the market in general get used to the electric technology. At the same time, homeowners should be offered incentives to replace gas appliances with electric when the gas appliances reach the end of their useful lives, she said.
When it comes to replacing gas appliances before the end of their useful lives, the decision depends on whether a homeowner has the financial means and wants to be at the forefront of new technology, Greene and other panelists said.
Methane Leakage Studied
Gas appliances contribute to GHG emissions in a couple of ways. The combustion of methane, the main component of natural gas, produces carbon dioxide. In addition, the appliances may leak methane, which is a potent greenhouse gas.
And methane leakage from gas stoves may be substantial, says new research from Jackson and colleagues at Stanford. The findings were published this week in the journal Environmental Science & Technology.
The study, which measured emissions from natural gas stoves in 53 California homes, found that up to 1.3% of the gas used by the stoves was emitted as unburned methane. More than three-quarters of those methane emissions occurred while stoves were turned off, suggesting the presence of leaks.
Another finding was that the age or cost of a stove didn’t seem to be related to the amount of emissions.
More than a third of U.S. households, or more than 40 million homes, use gas cooking appliances, the researchers said. They estimated that the amount of methane leaking from residential gas stoves in the U.S. each year has a climate impact comparable to annual CO2 emissions from 500,000 gasoline-powered cars.
The use of gas stoves can also cause nitrogen dioxide (NO2) to quickly build up in kitchens, especially if ventilation is poor or range hoods aren’t used, the study found. NO2 is a pollutant that may have harmful impacts on the human respiratory system, according to the Environmental Protection Agency.
Federal Efforts
Another speaker at the Stanford webinar was U.S. Sen. Martin Heinrich (D-NM), who discussed efforts at the federal level to promote building electrification. In November, Heinrich joined with other lawmakers to form the first bicameral Electrification Caucus. The group’s goal is to advance policies to accelerate widespread electrification.
Heinrich also led efforts to introduce in July the Zero-Emission Homes Act, which would provide rebates for buying and installing electric appliances in single-family homes and multifamily buildings. The bill includes additional support for low- and moderate-income households. A companion bill was introduced in the House that same month.
Heinrich said a version of his Zero-Emission Homes Act is included in the climate package that is part of the Build Back Better Act that was passed by the House. Although Build Back Better is facing roadblocks in the Senate, Heinrich said, the climate package seems to be the area that has the most agreement.
“I remain confident that we’re going to find a way to get many of those climate investments to the president’s desk,” he said.
CARMEL, Ind. — MISO’s resource adequacy stakeholder group is starting the new year by tackling new capacity accreditations for renewable and energy storage resources.
Lynn Hecker, senior manager of resource adequacy coordination, said the RTO hopes to have some new accreditation designs drafted by the end of the year.
She said during a Resource Adequacy Subcommittee (RASC) meeting Wednesday that a “fundamental shift” continues in the resource mix, with the generator interconnection queue dominated by renewable energy. Hecker said the footprint’s record-breaking, weather-dependent generation warrants a fresh look at accreditation.
Hecker asked stakeholders for suggestions on what new accreditation designs might look like for renewables, storage and hybrid formats that are combinations of both.
Currently, a new availability-based accreditation for thermal resources is pending before FERC. MISO did not propose a new accreditation design for renewable or storage resources as part of its recent capacity auction redesign. Instead, it kept its effective load carrying capability (ELCC) method in place for wind resources, explaining that the calculation already accounts for output that varies by season. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)
Some stakeholders have said that using two different methodologies for fossil fuel-fired and intermittent resources constitutes unfair treatment. RASC meetings during 2021 saw contentious debate on the appropriateness of applying an accreditation based on historical availability to fossil resources, with many members critical of the idea.
MISO plans to evaluate the usefulness of its wind resources’ ELCC method . Staff said it might not accurately capture capacity contributions during the footprint’s highest reliability risks.
The grid operator only has about 2 GW of solar currently participating in its markets, not enough yet to provide the historical data the ELCC relies on.
Hecker said solar is poised for explosive growth. “We feel like this is the appropriate time for us to start looking into solar accreditation changes,” she said.
Hecker also said MISO will first focus on renewable energy accreditation before proposing capacity credit treatment for storage resources.
When pressed by stakeholders, she said she couldn’t yet pin down a gigawatt threshold for participating energy storage before MISO would need an accreditation method.
“The magnitude of it cannot be overstated. We’re seeing more rapid change of the industry than at any point in our careers,” said the Brattle Group’s Sam Newell, who was contracted by the RTO to give advice on accreditation.
Newell called out record wind and solar additions, increasing demand response, changing daily load shapes and climate change as affecting capacity contributions.
“And now we’re in the news about reliability, about the transformation to clean energy,” he said. “Accurate accreditation is key to verifying adequate supply, signaling adequate planning … and identifying the economic tradeoff between resources.”
Newell said an ELCC calculation still “makes a lot of sense.” He said grid operators will need “quite a few years of data” to model energy-limited and intermittent resource performance. He also said they must consider that load is also weather driven.
“We’re going to have to argue about this a lot. That’s the business we’re in,” Newell told the RASC.
Staff Preps for Annual Auction
MISO is gearing up for possibly its final annual capacity auction. In advance of the auction, stakeholders have asked whether the RTO can share information on capacity resources that plan to take seasonal outages. Staff said it might provide that data at the local resource zone level to avoid revealing proprietary information.
For the 2022-23 planning year, the grid operator anticipates a 121-GW coincident systemwide peak with 157 GW in total installed capacity and almost 128 GW in total unforced capacity.
Fleet-wide, MISO’s wind capacity resources will have a 15.5% capacity credit in 2022-23, down one percentage point from the prior planning year.
MISO will conduct the Planning Resource Auction in early April.
MISO and SPP staff on Friday gave stakeholders their first chance to discuss and comment on the Joint Targeted Interconnection Queue (JTIQ) study, the culmination of a rare collaboration by the RTOs that began in 2020.
Staff said during a joint stakeholder meeting that the study resulted in seven projects that would cost an estimated $1.755 billion and “fully resolve” its targeted transmission constraints. The projects, six 345-kV transmission lines and a 345-kV bus reconfiguration, would deliver $724 million and $247 million of adjusted production cost (APC) benefit to customers in the MISO and SPP footprints, respectively, with a cumulative benefit-to-cost ratio of 0.56.
Four of the transmission projects are in MISO’s footprint in the Dakotas and Minnesota; one is in SPP’s; and the last crosses the seam. The bus reconfiguration is in SPP’s region.
David Kelley, SPP’s director of seams and tariff services, said he was unsure whether other grid operators had undertaken a similar collaborative effort to produce what he called “pretty exciting” information. (See MISO, SPP to Conduct Targeted Transmission Study.)
“I wanted to just mention briefly how cool, honestly, it has been to be part of such a novel study that has never been conducted before, at least between SPP and MISO,” he said. “You guys get to see the work as it’s taking place … but you all really miss, I think, the interaction that takes place on a week-to-week basis between what has been a really good team of engineers, analysts and a number of other supporting cast members that have … worked so closely together to bring to you the product that we’re very happy to share with you today.”
SPP’s power-flow models found the projects could enable as much as 53 GW of generating capacity for new interconnection projects on the seam. MISO’s models came up with 28 GW of new capacity.
Asked why the RTOs’ models were off, Kelley said their planning processes are “fundamentally different.”
“We even started with somewhat of a different future in the production cost modeling,” he said. “Even when you call the futures the same thing, different assumptions go into them. It’s more indicative and should be viewed as qualitative.”
David Johnson, an Indiana Utility Regulatory Commission staffer, asked to see the numbers in dollars per megawatt to interconnect to the system “because it says it’s an interconnection study.”
“Tell me what the [bogey] would be if all of these projects that are connected individually along the way and those interconnection costs,” he said. “All these studies make tons of assumptions.”
Staff agreed with Johnson that it would be a “monumental task.” MISO’s Andy Witmeier, director of resource utilization, said the capacity enabled calculations included generation enabled by JTIQ-mitigated constraints and additional generation by using unused capacity on mitigated constraints and the study’s projects.
Witmeier said a supplemental study conducted by an SPP consultant found that, consistent with the JTIQ analysis, 60% of the constraints assigned to MISO interconnection customers for mitigation could be addressed by the joint portfolio. The consultant’s work also indicated the portfolio alleviated the need to mitigate 44% of the constraints — representing more than $301 million of the assigned network upgrade costs — in an SPP study cluster.
The draft JITQ portfolio of projects | MISO, SPP
Cost allocation conversations are ongoing and additional stakeholder meetings will be scheduled in the first quarter, staff said.
“I believe it’s important to continue cost allocation discussions, but under the banner of the JTIQ,” Witmeier said. “We want to come up with cost allocations to hopefully get these projects built.”
Staff have already run modifications revising the joint operating agreement’s queue priority through the stakeholder process in both RTOs. A joint filing at FERC is expected in the next couple of weeks.
Stakeholders have until Thursday to provide feedback on the JTIQ study; a final report is expected Feb. 10.
The JTIQ study began as a mechanism to identify transmission projects required to address the significant transmission limitations restricting the interconnection of new generation near the SPP-MISO seam. Recognizing that large-scale transmission often provides multiple benefits, the study’s “novel” approach meant simultaneously considering whether transmission necessary to unlock the RTOs’ bulging generation interconnection queues could also provide economic and reliability benefits to their transmission customers.
The team closely coordinated the grid operators’ technical analyses, using each RTO’s respective transmission and generation planning methodologies to determine the project requirements that would cost-effectively resolve the transmission constraints inhibiting new generation near their seam. Staff performed reliability, economic and transfer capability studies and coordinated with stakeholders to develop solutions that met the study’s objectives.
CARMEL, Ind. — MISO has come up with one possible fix on how it could more easily access its resource stack outside of emergencies: prohibiting some resources from using an emergency commitment status.
The tightened ruleset is poised to affect units that have been designated to meet the grid operator’s resource adequacy requirements (RAR). Currently, such resources can use an emergency commitment status in the energy markets, making their entire output unavailable unless there’s a generation emergency. The emergency commitments don’t affect the resources’ capacity credits.
MISO says wider access to its capacity is crucial to “ensure reliable and efficient market outcomes.”
The RTO’s Dustin Grethen said during a Resource Adequacy Subcommittee Wednesday that restricting those units from making emergency-only offers could make a noticeable difference in the footprint’s resource adequacy.
Some stakeholders asked that MISO not altogether prohibit RAR resources from making emergency offers, especially for the top-end, emergency range of their output.
“We thought this should affect their accreditation instead of them just not being able to do it,” MISO Independent Market Monitor Michael Chiasson said of RAR units’ emergency-only statuses.
Customized Energy Solutions’ David Sapper said MISO’s proposal was “draconian.”
“It does seem to me there’s a difference between a resource that’s in an emergency commit status for two days versus one that’s in for two months,” WEC Energy Group’s Chris Plante said, noting that he was not communicating his company’s position.
Some stakeholders also pointed out that state emission regulations dictate that some generators only run in emergency situations.
MISO has spent several years searching for solutions that will improve its resource availability, which it says has been steadily worsening. It says it needs a clearer picture of what capacity is accessible to it and when.
The RTO’s Reliability Subcommittee plans to discuss and finalize the proposal in the second quarter.
Climate advocates are seeking to update Connecticut’s 14-year-old climate law to bring the state closer to meeting its statutory greenhouse gas emission reduction targets.
“We’re not on track to meet our GHG reduction mandates and that means … we’re going to need to be playing some pretty serious catch-up in the coming years with some very bold climate action,” Leah Lopez Schmalz, vice president of programs at Save the Sound, said Tuesday.
Connecticut’s GHG emissions inventory, released in September, showed that the state’s emissions are increasing, which means “limited action” on climate issues “is going to get compounded,” Schmalz said during a Connecticut League of Conservation Voters Education Fund Environmental Summit.
The 2008 Global Warming Solutions Act set a mandatory 10% reduction in GHG emissions below 1990 levels by 2020, but the inventory showed the state emitted 2.9% more GHGs in 2018 than required for 2020.
“That 2020 goal of 10% reduction was seen at the time as a really modest goal; one that wasn’t going to be too hard to achieve,” Schmalz said. “But here we sit in 2022, having passed 2020, looking at data from 2018, and seeing that what we’ve done is insufficient.”
The law also sets targets of 45% and 80% reductions below 2001 levels by 2030 and 2050, respectively.
Certain “upgrades” to provisions in GWSA will help Connecticut follow the lead of neighboring Northeast states and make the “significant cuts” necessary to reach its targets, Schmalz said
Those upgrades include:
setting mandates for net-zero emissions by 2050 and 100% zero-carbon electricity by 2040;
enabling citizens to bring a suit against the state if mandates are not met; and
establishing regulatory authority for agencies to adopt regulations to address climate change.
In addition, Schmalz said, the law should set shorter intervals for the emissions reduction targets.
“We have 10-year and 20-year targets, which means by the time you get to that 10 years, if you’ve missed some progress along the way, you have a lot of catching up at the very end of your requirements,” she said.
Setting a five-year interval, she added, would allow the state to “adapt in real time to real data.”
Transportation Policy
The state GHG inventory highlighted continuous increases in the transportation sector since 1990, largely because residents are “driving more,” Department of Energy and Environmental Protection (DEEP) Commissioner Katie Dykes said on Thursday during the second day of the summit.
Adopting California standards was among the recommendations in the report for the sector.
“I hope this year we’ll be able to get adoption of legislation that will finally allow DEEP to join our neighboring states in adopting California’s emission standards for medium- and heavy-duty vehicles,” Dykes said. “This is going to be a major solution to help reduce [transportation] emissions, especially in communities living close to industrial zones and along our transportation corridors.”
In a legislative policy framework released this week, environmental advocates also supported adopting California’s Advanced Clean Cars II regulations when the California Air Resources Board finalizes them. Doing so, the framework said, would ensure Connecticut has a target for 100% of new light-duty vehicle sales to be zero-emission vehicles by 2035.
Solar Caps
Caps on community and commercial solar in Connecticut should be amended to promote progress in the sector, according to Mark Scully, president of People’s Action for Clean Energy.
Scully, who spoke on behalf of the Coalition for Sensible Solar Regulation, said the annual 50-MW cap on commercial solar and 25-MW cap on shared clean energy facilities could be doubled. The coalition, he added, also supports removing limitations on the size of solar arrays in the commercial and community sector.
“As a result of these constraints, the majority of proposed commercial and community solar projects get stranded,” Scully said. “Each of these constraints was created by legislative act, and we believe they could be remedied in this legislative session.”
The legislative changes, he said, would increase solar incentives, but the effect on electric rates would be “negligible.” Changing the caps for the commercial and community solar programs would increase monthly bills for an average ratepayer by 15 cents and 2 cents, respectively, according to Scully.
