Seven of the eight stakeholder-originated project proposals evaluated by MISO and PJM are not expected to pass the RTOs’ benefit threshold.
The sole project left standing is Northern Indiana Public Service Co.’s proposed new line section between its Thayer and Morrison 138-kV substations in northwestern Indiana, near the Illinois border. The greenfield project would be in service by 2022 at a $42.5 million cost, RTO stakeholders learned at an Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting Aug. 18.
MISO would reap the lion’s share of expected benefits at $75 million, while PJM would see $7.3 million in benefits; the costs would be split 91.1% and 8.9%, respectively. Staff said the project will now be evaluated in each regional process based on interregional cost allocation. PJM engineer Alex Worcester said the RTOs still plan to return to an October IPSAC meeting to discuss all eight projects and their final benefit-cost ratios, however dismal.
In May, the RTOs revealed three upgrade and five greenfield proposals from stakeholders, ranging from $1 million to $198 million, for three congested flowgates around the borders of Michigan, Indiana and Ohio.
Most proposals’ effectiveness was undercut by American Electric Power’s recently announced plans for a supplemental project for the Olive–Bosserman constraint near the western Indiana-Michigan border. AEP plans to remedy the problem by increasing voltage and rerouting nearby PJM circuits dating back to the 1930s with two new 138/120-kV distribution stations. (See MISO, PJM Weighing 8 Interregional Tx Proposals.)
All but two of the project proposals concentrated on the Olive–Bosserman constraint. Another NIPSCO proposal — an $8 million plan to reconductor a NIPSCO line between AEP’s Bosserman and Olive 138-kV substations and reconductor a NIPSCO line between Bosserman and AEP’s New Carlisle 138-kV substation — was found to benefit neither PJM nor MISO after the AEP proposal was factored in.
| MISO and PJM
NIPSCO’s Clark Gloyeske asked if PJM had plans to refund the project submission fees the RTO charged to consider the proposals. “The supplemental came along and wiped out all of these proposals,” he said.
PJM Manager of Interregional Planning Chuck Liebold said it may conduct additional analysis to explore the possibility, but he did not elaborate on an expected timeline.
Meanwhile, MISO engineer Adam Solomon said the RTOs still have five targeted market efficiency projects (TMEPs) at the ready should FERC approve the regional cost allocations for the new category. MISO filed for regional allocation Aug. 4 (ER17-2246), and PJM filed its allocation on April 11 (ER17-1406).
Commission staff tentatively approved the TMEP category in a delegated order in June but said the decision was subject to review by the commission once it regained the quorum it lost in February (ER17-721). (See FERC Tentatively OKs New MISO-PJM Project Type.)
“Pending FERC approval, we are still ready to recommend the five TMEPs that we’ve had on our hands for a while now,” Solomon said.
The RTOs will not conduct a new TMEP study this year. The TMEP process was originally intended to be performed annually, but Solomon said MISO and PJM are still undecided if they will undergo a study even in 2018.
“Closer to the end of the year is when we’d try to make that decision,” Solomon said.
MISO’s rejection last week of the last possible transmission project resulting from a coordinated study with SPP surprised the latter RTO and left officials wondering whether the neighbors will ever build an interregional project.
MISO staff told its Planning Advisory Committee on Aug. 16 that it was no longer recommending the $5.2 million Split Rock-Lawrence initiative in South Dakota, which would have been the RTOs’ first-ever interregional project.
MISO now says an analysis of the project shows that congestion on the line can be managed for now and that another alternative project could provide the RTO with at least the same benefit at a lower cost.
SPP COO Carl Monroe told RTO Insider Friday that the RTO only discovered MISO’s recommendation through posted meeting materials and the ensuing coverage. “We’re disappointed we can’t find any of these types of projects,” Monroe said. “We go through the Order 1000 process, which, from the joint study, seems to have some benefits. But it just doesn’t seem like when we go to the individual [RTOs’] studies, it shows that type of benefits.”
The project was halted before it could clear the Joint RTO Planning Committee — composed of staff with ultimate say over interregional issues — and before it would have been recommended for inclusion in MISO’s 2017 Transmission Expansion Plan. The coordinated study was meant to focus on needs along the border of SPP’s Integrated System in North Dakota, South Dakota and Iowa. Some MISO stakeholders expressed doubt at the beginning of the study that any projects would materialize.
MISO said the congested line in South Dakota is now operating as an open circuit under an operations guide proposed by Xcel Energy in May, which shifts some congestion to the nearby Sioux Falls–Split Rock 230-kV line. Had the project — which would have looped Xcel’s existing Split Rock-Lawrence 115-kV circuit into the Western Area Power Administration’s Sioux Falls station, crossing SPP territory — proceeded, Xcel would have been at risk of incurring SPP penalties for unreserved use of non-firm point-to-point transmission service, the RTO said.
| MISO and SPP
MISO recommends maintaining the status quo and operating the Lawrence–Sioux Falls line in an open state to relieve the congestion for now, Davey Lopez, the RTO’s adviser of planning coordination and strategy, told the PAC. He added that the open state operation “provides MISO nearly the same adjusted production cost savings” as the interregional project at little to no cost.
However, MISO said it would continue to pursue upgrades to terminal equipment on the Lawrence–Sioux Falls line through joint efforts between MISO, Xcel, SPP and WAPA. The terminal upgrades would still represent a savings over the originally proposed loop project, MISO said.
Questions on Open Circuit
Monroe questioned MISO’s use of an open circuit, which can reduce reliability when congestion is shifted from one line to another. “Normally, we don’t run the system with open lines,” he said. “In some regards, it increases the risk you’re taking.”
Monroe said SPP has offered to go beyond FERC’s Order 1000 process to find “mechanisms and ways to share costs” to ensure both RTOs benefit from interregional projects, “but we haven’t found one of those.”
“It’s hard to say whether it’s the process or stakeholders or something,” Monroe said, “but we just haven’t been able to get across the goal line from the perspective of their regional review.”
SPP stakeholders have questioned the desire of MISO to develop interregional projects with its western neighbor. The two RTOs have now conducted two coordinated joint studies and failed to agree upon a single interregional project.
Adam McKinnie, utility economist for the Missouri Public Service Commission, said he had “severe concerns” that MISO was allowing a temporary operations plan to become a long-term solution for congestion.
“We couldn’t justify subjecting our customers to a $5 million project when there’s a no-cost solution available,” Lopez explained.
Seeking a ‘Willing Partner’
McKinnie also questioned if the SPP-MISO seam is receiving the same level of interregional coordination as the MISO-PJM seam. “I’m kind of tired of refereeing fights between MISO and SPP because my ratepayers pay for those fights,” he said, adding that SPP officials seem more receptive to interregional planning than those at MISO.
MISO staff countered that the RTO is looking for the most economic and efficient solution to the congestion.
MISO’s interregional project cost and voltage thresholds with SPP remain unchanged at $5 million and 345 kV, respectively. FERC ruled at the beginning of the year that MISO and SPP were not bound by its directive to PJM and MISO to remove identical thresholds. SPP had asked FERC last year to apply the same directive to the MISO-SPP seam.
Had the 115-kV Split Rock-Lawrence project won approval, MISO would have had to designate its portion of the project as “miscellaneous,” unable to qualify for cost allocation, because it does not meet the 345-kV voltage threshold required of its market efficiency projects.
“We just haven’t seen that ability, whether it’s because they don’t want to do it, or they don’t feel like they can do it, or the stakeholders don’t want it,” Monroe said. “I just don’t know where the resistance is. If you feel like these [projects] are good to do and you want to get them done, you can work through these issues, hopefully, and even demonstrate the rigidness of the problems that Order 1000 creates. We just haven’t found a willing partner on the other side to negotiate those issues.”
SPP’s Seams Steering Committee was to present the South Dakota project to the Markets and Operations Policy Committee in October, but that is unlikely to happen now, Monroe said. “You could probably believe we don’t have much hope that our members want to go ahead with this either, if MISO doesn’t want to,” he said.
It’s unclear how soon the RTOs will embark on another joint study. Last spring, MISO staff originally decided against a coordinated study, explaining that it was hoping to improve the process behind coordinated studies before taking up another one. Staff later reversed course and agreed to the 2016 coordinated study. A 2014-15 MISO-SPP coordinated study ran over deadline by three months and left both RTO staffs frustrated and empty-handed. (See SPP, MISO Try to Bridge Joint Study Scope Differences.)
HARTFORD, Conn. — Connecticut regulators got an earful at a public comment session Thursday on the future of Dominion Energy’s Millstone nuclear plant, with multiple speakers opposing a state subsidy such as those adopted by New York and Illinois.
Instead, the speakers urged that any efforts to preserve the plant be part of a regional initiative that also includes other emission-free generation. Others questioned whether Millstone needed financial support in addition to its revenue from ISO-NE’s energy and capacity markets.
The Aug. 17 hearing was in response to Gov. Dannel Malloy’s executive order requiring state officials to assess the economic viability of Millstone and determine whether the state should provide it financial support. The governor also directed the Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority to assess the viability of all forms of renewable energy and to report their findings by Feb. 1. (See CT Gov Orders Financial Analysis of Millstone Plant.)
Free to Solicit
PURA Chair Katie Dykes, who led the public meeting, reminded participants that they were not only to look at nuclear, but also at “large-scale hydropower, demand reduction, energy efficiency measures, energy storage and emissions-free renewable energy — all those different resources together — and how they could help Connecticut meet interim and long-term carbon and other emission targets. So there is a larger scope here.”
The Connecticut General Assembly in June failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state procurement process (S.B. 106). Dominion had sought the legislation to boost the plant’s revenues, which have suffered from low-priced natural gas, which often sets LMPs in New England.
Dominion has until Aug. 29 to respond to PURA’s request for the company’s financial records on Millstone, which supplies approximately 45% of Connecticut’s electricity.
Tom Swan, executive director of the Connecticut Citizen Action Group, characterized Dominion’s pleas of economic hardship as “BS” and said the regulators should also look at additional legislative remedies if the company wants to leave the business. While the state may need Millstone to meet its emissions reduction goals, “that doesn’t say it has to be Dominion,” he said.
State regulators have been given leeway to act by a 2nd U.S. Circuit Court of Appeals ruling in June that rejected claims that Connecticut’s renewable energy procurement law intruded on FERC’s authority. The court on Aug. 17 declined to revisit its decision.
The ruling affirmed a lower court decision on the law, which requires the state to solicit proposals for renewable energy projects and for utilities to sign contracts with the winners. Renewable energy developer Allco Finance challenged the law’s implementation as discriminatory (16-2946, 16-2949). (See Second Circuit Upholds Conn. Renewable Procurement Law.)
Despite the court’s support for state’s rights, Peter Fuller, vice president of market and regulatory policy for NRG Energy, said, “We need to keep everything in the context of the regional context, the regional structure. ISO-NE and the New England markets are specifically tasked with maintaining reliability of the grid, are structured to achieve those reliability goals at lowest cost.”
Connecticut’s agencies need not “start from whole cloth” and worry about those issues, Fuller said. “We have those structures in place. Hopefully ISO-NE will be involved in assessing the various scenarios and so forth and assuring the various agencies on what is reliable.”
Michael Cuzzi, senior director of government relations for Brookfield Renewable, recommended that the study consider all hydropower resources in ISO-NE and adjacent control areas, not simply large-scale hydropower as stated in the governor’s order and as currently defined under Connecticut statutes.
“The existing statutory definition — which contains both size and geographic limitations — prevents Connecticut from accessing existing, interconnected hydropower resources from both Canada and New York that can help Connecticut meet its energy needs and that are not currently accounted for in the state’s greenhouse gas emissions inventory,” Cuzzi said.
If the “hydro resources in New York and Canada aren’t currently counted toward their renewable goals, are they currently counted towards other jurisdictions’ goals?” Dykes asked him.
“It depends,” Cuzzi replied. “As you know, in New York, the initial Clean Energy Standard did not incorporate existing clean energy resources, so I think there’s a bit of a first-mover opportunity here to frankly claim those attributes and lock them into one jurisdiction or another.”
Pricing Carbon
Fuller said that any targeted subsidy will distort markets, produce less-efficient outcomes and potentially increase risk to consumers.
He urged the regulators to “think about the multistate issues, think about the legislative proposal from a few months ago to place a broad, economy-wide carbon tax — those are the kinds of solutions either within the IMAPP [Integrating Markets and Public Policy] or within the broader economy we feel are going to be far more effective at getting the right answer.”
The New England States Committee on Electricity (NESCOE) told the New England Power Pool in April that the states opposed “a FERC-jurisdictional tariff reflecting carbon pricing.” (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
Cuzzi similarly recommended that the study “examine a uniform ISO-NE-wide carbon price.”
On Aug. 11, NYISO and the New York Department of Public Service released a report that said a $40/ton carbon charge in the state would have “a relatively small impact” on customer costs, with bills dropping by 1% or rising no more than 2%. The analysis from the Brattle Group was prompted by the Public Service Commission’s decision to subsidize upstate nuclear plants through zero-emission credits (ZECs) and penalize fossil fuel generators based on their level of carbon emissions. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)
“The question of carbon pricing has come up a lot in the IMAPP context,” Dykes said. “The executive order does highlight that we should consider best mechanisms, including potentially collaborating with other states, but we also have to consider how they would work [and] what the impact would be if Connecticut could not entice other New England states to participate with us: so as a one-state option versus how it would work if there was a multistate option.”
Dykes added that “in an IMAPP context, the New England states’ comments provided to NESCOE were not supportive of carbon adders, but I just wanted to highlight that this is one of the variables we’ll be looking at as we assess mechanisms, one state versus regional implementation.”
James Shuckerow, director of electric supply for Eversource Energy, said any recommended remedy should be least-cost and for the shortest duration possible.
“Because Millstone is a regional resource, if somehow there could be a regional remedy, I think that would be preferred by all,” Shuckerow said. “I recognize the problem in New England. We have six different states versus the situation we have in New York.”
In its written comments, Eversource said that Millstone is not a Class I, II or III renewable resource and “cannot simultaneously be a competitive merchant generator and receive state-sponsored financial support.”
The company said that “any financial remedy that is developed to address a legitimate economic need should be based on cost-of-service principles with correspondingly limited returns on equity to reflect the reduction in risk resulting from Millstone’s receipt of state financial support that is unavailable to other non-renewable merchant generators.”
“Look at the costs affecting all customers and the overall impact not only on standard service customers or large customers, but all customers throughout Connecticut,” Shuckerow said.
The cost-of-service approach would allow all types of customers through an appropriate charge to share the benefits, Shuckerow said. “Essentially, we’d sell the energy into the market, get credit for that energy and credit that against the cost of service.”
Kerry Schlichting of the Acadia Center said that because the study results could influence Connecticut’s long-term energy strategy, her organization asked DEEP and PURA to “issue a draft methodology and base case scenario sometime this fall for stakeholder review and comment” before the release of the draft report in early December. If the agencies wait too long it will be difficult to incorporate stakeholder feedback on modeling issues, she said.
Nancy Burton, director of the Connecticut Coalition Against Millstone, said “Millstone is hardly a zero-emissions facility. … Every year they pile [DEEP] up with documents about their emissions, their continuous radioactive emissions into the air and the water, as well as their toxic discharges to the Long Island Sound.”
John Erlingheuser, representing AARP, said: “How do we know what the problem is if Millstone doesn’t release actual data? … We’re not opposed to nuclear or opposed to Dominion or to keeping the plant open. What we object to is devising solutions without proper information and without determination that there’s an actual need.”
Local construction worker John Thomson spoke as a consumer on the potential economic impact of losing Millstone. “I’m concerned about the economic impact of that area of the state,” he said. “We’ve lost a lot of businesses already, so what’s that going to look like going forward for taxpayers, not just ratepayers?”
Lynne Bonnet, a member of the New Haven Energy Task Force but speaking on her own behalf, said the Cross-Sound Cable was built as a two-way conduit but that so far the energy has only flowed from Connecticut to Long Island. “Why don’t we ask Long Island now to generate power to help us to shut down Millstone?” Bonnet said. “And Long Island could also generate power to supply their own needs so they won’t have to buy power on a contracted Cross-Sound Cable.”
Bonnet also asked the regulators to be wary of the assumption that the state has already been penetrated with solar energy and energy efficiency. “If you pay attention to these situations where energy efficiency has decreased the load from residential use, New Haven is an untapped resource. It’s not saturated and not even been penetrated,” she said.
MISO has developed a revised approach for providing owners of financially struggling generators more flexibility, saying it will treat Attachment Y filings as suspension notices while allowing owners 18 months to make a final retirement decision.
MISO adviser Joe Reddoch said staff has drafted near-final Tariff language to align the RTO’s retirement and suspension process with the annual capacity auction.
In April, MISO said it would eliminate the temporary suspension provisions from its Attachment Y change of status rules in favor of a catch-all “economic shutdown” period. But some stakeholders said the move to a binary status for generators — on or off — might nudge some owners into prematurely retiring units. (See “Removal of Temporary Suspensions will Provide Generators Flexibility, RTO says,” MISO Planning Advisory Committee Briefs.)
With the revised language bringing the suspension concept back, retirement terminology would only come into play when generation owners waive their rescission rights or when the rescission period ends, giving asset owners time to decide, Reddoch said.
Under the proposal, all Attachment Y notices will be submitted as open-ended suspension requests without the estimated return date currently required by MISO. The temporary shutdowns would be limited to 18 months, with the RTO open to extending a suspension status to 30 months, aligned with the beginning of the planning year. MISO said that will allow an asset owner time to evaluate repairs in the case of a forced outage.
“By reorienting this process around suspensions, the process is a little more intuitive,” Reddoch said, adding that asset owners would no longer be forced to decide when submitting an Attachment Y notice if their units will suspend or retire.
Reddoch asked for stakeholder feedback by Sept. 1 and said he would return to review final Tariff language at the September PAC meeting. MISO plans a FERC filing in October or November, he said.
Clean Line Energy Partners said Thursday it is considering legal appeals and other options following the Missouri Public Service Commission’s third rejection of its proposed Grain Belt Express.
The PSC on Wednesday rejected Clean Line’s request for a certificate of convenience and necessity (EA-2016-0358). The commission previously denied the $2.3 billion project last year on a procedural error, and in 2015 for not proving the project’s necessity and worth.
Mike Skelly, Clean Line’s founder and president, said the company will review the PSC’s order to determine its next course of action.
“We are currently assessing all existing authorities available to move the Grain Belt Express project forward, including, but not limited, to legal appeals,” Skelly said in a statement. “The PSC’s decision … sends a clear message that investors contemplating new infrastructure projects should not come to Missouri.”
Clean Line’s other options, said spokesperson Sarah Bray, include asking the PSC for a rehearing, working with the state’s legislature to revise pertinent laws or seeking U.S. Energy Department approval under Section 1222 of the 2005 Energy Policy Act. The latter would authorize the department to take part in “designing, developing, constructing, operating, maintaining or owning” new transmission.
“The project is certainly not dead,” Bray said.
Following the PSC’s 2015 rejection of the Grain Belt Express — when the commission determined there weren’t enough benefits for Missouri consumers and cited landowner opposition — Clean Line signed up more than three dozen cities to purchase about 100 MW of power from the project. The Houston-based company projects ratepayers in those cities will see annual savings of $10 million.
| Clean Line Energy Partners
Four of the commission’s five members said in a concurring opinion Wednesday the project is needed, economically feasible and beneficial to the public.
However, they referenced a March state appeals court ruling on an unrelated case involving Ameren Transmission Company of Illinois, which found that infrastructure projects must first secure approvals from each county it crosses.
In 2012, Clean Line won permission from the commissions of eight counties to construct the line along and across their public roads. But the company was tripped up in Caldwell County, after a court ruled in 2015 that county officials had violated the state Sunshine Law when they approved the line.
“It was in the public interest to approve the line,” PSC Chairman Daniel Hall said. “Unfortunately, because of the structure of this commission and because of the legal system in this state, we were unable to act in the public interest.”
Commissioner Steve Stoll did not sign the order, saying “the court has spoken.”
Bray told RTO Insider that Clean Line was “encouraged by the PSC’s determination that the project is in the public interest and will benefit the State of Missouri.”
The “ruling is inconsistent with good government and sound public policy, and it is our hope that moving forward, Missouri will work to remove barriers to building new critical infrastructure projects,” Skelly said.
James Owen, executive director of Renew Missouri, which supports renewable energy and energy efficiency, said the PSC ruling is based on a misreading of state law and undermines Gov. Eric Greitens’ promise to eliminate “job-killing regulations.”
“The [appellate] opinion now says that a few county commissioners have absolute veto power over the regulatory decisions of the federal and state government,” Owen said in a statement. “This multibillion-dollar project spanning four states is now stalled due to a baseless objection from a single Missouri county. … In the face of this absurd result, Gov. Greitens’ silence is deafening.”
The Grain Belt Express would deliver approximately 4,000 MW of wind power from western Kansas through Missouri and Illinois to the Indiana border over 780 miles of DC lines. Kansas and Illinois regulators approved the project within their states in 2013 and 2015, respectively.
Clean Line said the decision would be “devastating” for Missouri ratepayers and workers “who will be deprived of good paying local jobs.”
The company had support from a number of the state’s companies and organizations, including the Missouri Joint Municipal Electric Utility Commission, the Missouri Department of Economic Development, the International Brotherhood of Electrical Workers, the Missouri AFL-CIO, The Wind Coalition and Wind on the Wires.
CAISO on Tuesday unveiled its latest revisions to a program meant to compensate uneconomic generation units needed to maintain reliability.
After consulting with stakeholders since June, CAISO unveiled 20 changes to the Capacity Procurement Model Risk-of-Retirement Initiative (CPM ROR). The ISO is taking comments through Aug. 28 on the revised straw proposal, which is due to be reviewed by the Board of Governors on Nov. 1.
Stakeholders were skeptical of the program when it was proposed earlier this year, saying it does not address the fact that CAISO’s energy market can no longer adequately compensate generation resources that are unprofitable but are still needed to manage the integration of large amounts of renewables (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)
On a call Tuesday, Pacific Gas and Electric representative Peter Griffiths asked how the CPM ROR process relates to a separate reliability-must-run process, as one of CAISO’s stated objectives is to see if ROR could be used rather than RMR. “I just want to make sure that is a touchstone to some degree that we continue to look back at,” Griffiths said.
CAISO Manager of Infrastructure Policy and Contracts Keith Johnson replied that “one of the objectives here is to see if CPM is a viable option.” He said the changes are intended to increase the possibility of using the program, which has never been deployed since its creation in March 2011.
“We want to see if there is a way that we can at least make the existing provisions work better so there is a higher probability that they will be used and useful,” Johnson said. There are still circumstances in which RMR will be needed, he said.
Earlier this year, CAISO awarded RMR designations to Calpine’s Yuba City and Feather River peaking plants after the company said it would be forced to retire the facilities if required to await a decision on CPM next year. (See CAISO RMRs Win Board OK, Stakeholders Critical.) Calpine said the RMR award was the only viable option, but CAISO wants the CPM ROR to be the primary backstop to generation shortages through retirement.
CAISO is tweaking its backstop procurement for resources like Calpine’s Yuba City Plant that are needed for reliability | Calpine
Most stakeholders support allowing any resource to apply for a ROR designation, including resources that are under a resource adequacy (RA) contract. Currently, generation resources that have an RA contract for the upcoming (January-December) RA year cannot apply for ROR designation. Capacity under a RA or RMR contract or another kind of CPM procurement may not receive ROR payments at same time.
Resource owners say that one current problem is that CAISO cannot initiate its study to determine the need for an individual unit until November of each year, just after all load-serving entities publish their RA requirements for the following calendar year. Generation owners have expressed concern that they don’t know if their resources will have RA contracts until Oct. 31. One of CAISO’s objectives is to provide for its ROR analysis to take place prior to the end of the RA contracting period.
| CAISO
Under the new proposal, windows would open in April and November each year for three types of ROR designations:
Type 1 refers to non-RA resources for designation within the current RA compliance year (April window).
Type 2 is for RA resources or non-RA resources for designation during the calendar year following the current RA compliance year (April window).
Type 3 is for non-RA resources for designation during the upcoming RA compliance year (November window).
The straw proposal also clarified the criteria for an ROR designation: that the “grid cannot be reliability operated without that specific resource in service.” CAISO plans to post reports within 30 days of such findings to allow stakeholders to comment.
CAISO’s draft final proposal is due to be posted on Sept. 11, and another stakeholder call is set for Sept. 18.
MISO is yanking support on the last possible project resulting from a coordinated study with SPP, nixing the RTOs’ chances this year to collaborate on a first-ever interregional project.
The RTO now says an analysis of the $5.2 million Split Rock-Lawrence project in South Dakota shows that congestion on the line can be managed for now and that another alternative project could provide the RTO with at least the same benefit at a lower cost.
MISO originally forecast that the 115-kV circuit project into Sioux Falls would have a 4.79 benefit-cost ratio. The project was the only contender to come out of MISO and SPP’s coordinated system plan study last year, and MISO stakeholders voted in a nonbinding ballot to recommend the project to officials in both RTOs in May. (See MISO-SPP Coordinated Study Yields 1 Possible Project – For Now.)
The project was halted before it could clear the Joint RTO Planning Committee — composed of staff with ultimate say over interregional issues — and before it would have been recommended for inclusion in MISO’s 2017 Transmission Expansion Plan. The coordinated study was meant to focus on needs along the border of SPP’s Integrated System in North Dakota, South Dakota and Iowa. Some MISO stakeholders expressed doubt at the beginning of the study that any projects would materialize.
The RTO said the congested line in South Dakota is now operating as an open circuit under an operations guide proposed by Xcel Energy in May, which shifts some congestion to the nearby Sioux Falls–Split Rock 230-kV line. Had the project — which would have looped Xcel’s existing Split Rock-Lawrence 115-kV circuit into the Western Area Power Administration’s Sioux Falls station, crossing SPP territory — proceeded, Xcel would have been at risk of incurring SPP penalties for unreserved use of non-firm point-to-point transmission service, MISO said.
The RTO recommends the maintaining status quo and operating the Lawrence–Sioux Falls line in an open state to relieve the congestion for now, Davey Lopez, the RTO’s adviser of planning coordination and strategy, said during an Aug. 16 Planning Advisory Committee meeting. He added that the open state operation “provides MISO nearly the same adjusted production cost savings” as the interregional project at little to no cost.
However, MISO said it would continue to pursue upgrades to terminal equipment on the Lawrence–Sioux Falls line through joint efforts between MISO, Xcel, SPP and WAPA. The terminal upgrades would still represent a savings over the originally proposed loop project, the RTO said.
Adam McKinnie, utility economist for the Missouri Public Service Commission, said he had “severe concerns” that MISO was allowing a temporary operations plan to become a long-term solution for congestion.
“We couldn’t justify subjecting our customers to a $5 million project when there’s a no-cost solution available,” Lopez explained.
McKinnie also questioned if the SPP-MISO seam is receiving the same level of interregional coordination as the MISO-PJM seam. “I’m kind of tired of refereeing fights between MISO and SPP because my ratepayers pay for those fights,” he said, adding that SPP officials seem more receptive to interregional planning than those at MISO.
MISO staff countered that the RTO is looking for the most economic and efficient solution to the congestion.
The RTO’s interregional project cost and voltage thresholds with SPP remain unchanged at $5 million and 345 kV, respectively. FERC ruled at the beginning of the year that both RTOs were not bound by its directive to PJM and MISO to remove identical thresholds. SPP had asked FERC last year to apply the same directive to the MISO-SPP seam.
Had the 115-kV Split Rock-Lawrence project won approval, MISO would have had to designate its portion of the project as miscellaneous, unable to qualify for cost allocation, because it does not meet the 345-kV voltage threshold required of its market efficiency projects.
| MISO & SPP
It’s unclear how soon the RTOs will embark on another joint study. Last spring, MISO staff originally decided against a coordinated study, explaining that it was hoping to improve the process behind coordinated studies before taking up another one. Staff later reversed course and agreed to the 2016 coordinated study. A 2014-15 MISO-SPP coordinated study ran over deadline by three months and left both RTO staffs frustrated and empty-handed. (See SPP, MISO Try to Bridge Joint Study Scope Differences.)
MISO will pursue changes to its Transmission Expansion Plan futures weighting process in the 2019 cycle of projects, delaying the initiative by one year.
Starting with MTEP 19, equal weighting will be assigned to all four future grid and generation scenarios, effectively eliminating weighting of the 15-year futures. Staff initially said it would drop weighting beginning with MTEP 18. (See MISO Rethinks Weighting of MTEP 18 Futures.)
The RTO began reviewing its weighting process early this year after MISO South transmission owners and regulators of southern states asked for less emphasis in one MTEP 17 study on futures containing policy regulations and increased penetration of alternative technologies. The RTO granted the request. (See MISO Changes MTEP Futures Weighting for South.)
MISO policy studies engineer Matt Ellis said the RTO is delaying the change because MTEP 18 futures were developed with the understanding that stakeholders would be involved in deciding their importance.
“It doesn’t make sense to change something when it was implicitly understood at the beginning,” Ellis said during an Aug. 16 Planning Advisory Committee meeting. He asked for stakeholder input on the unfinished MTEP 18 weighting process and said MISO still reserves the right to “put its thumb on the scale” if it thinks the stakeholder rationale for weighting is weak. Not surprisingly, MISO is recommending a 25% weighting for all four MTEP futures: a “limited,” “continued” and “accelerated” fleet change and an emerging technologies scenario.
MISO is also considering using benefit-cost criteria in all four futures in MTEP 18 to determine which transmission projects are sent for Board of Directors approval. Projects may have to have an average 1.25:1 benefit-cost ratio across the four MTEP futures and earn at least a 1:1 cost-benefit ratio in at least two. Projects may also be rejected if a project earns a negative benefit of 0.8 greater in any one future.
Ellis said MISO will take a backward look at previously approved MTEP projects to further refine benefit-cost criteria and asked for stakeholder input on establishing benefit-cost floors.
The new equal-footing weighting process in 2019 will make MTEP futures more predictable year to year and shift the focus from stakeholders’ perceived likelihood of a certain future to how effectively a project can perform under varying scenarios, Ellis said.
“What we can all agree on is the old process wasn’t very predictable. The MISO process should be very predictable, very cut and dried,” he said.
Bill Booth of the Mississippi Public Service Commission asked if MISO was firm in its decision that all futures will have equal importance. “Seems to me that by eliminating weighting, you’re eliminating stakeholder feedback,” Booth said.
“We are firm on that. We are firm on even and equal weighting,” Ellis said.
The PSC’s David Carr asked if MISO viewed the Trump administration’s rollback of environmental regulations — which sparked the requests for reweighting of MTEP 17 futures — as an “anomaly” that is not likely to occur again.
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“We can tell you in the previous three [MTEP] cycles, we’ve gotten requests to reweight. So this is an issue that’s been building for quite some time,” Ellis said.
Going forward, Ellis said, MISO would only consider revising weights when all stakeholder sectors ask it to rethink the likelihood of a certain future. He also said that development of futures themselves will remain unchanged.
“As we go through the futures development process, we gather extensive stakeholder feedback. … We can tell you that all of our futures are very reasonable,” Ellis said.
“Sectors aren’t providing weights based on their expectations of the future, but on their advocacy of a particular business model,” said Wisconsin Public Service’s Chris Plante.
“That’s a great point,” replied Ellis.
Customized Energy Solutions’ David Sapper said it was important to have MISO’s “independent, unbiased” voice in the futures weighting process.
MISO will conduct a study to identify the challenges of integrating growing volumes of renewable generation in its footprint.
The open-ended, multiyear study will be used to “facilitate a broader conversation about renewable energy-driven impacts on the reliability of the electric system,” MISO said.
“We trying to look at the impacts over a much broader period of renewable penetration and quantify the impacts,” said Jordan Bakke, of the RTO’s policy studies group, at an Aug. 16 Planning Advisory Committee meeting. “If we look over the last decade of MISO, we started at very minimal [renewable] penetration … and we’ve grown quite steadily over that time frame.”
Different types of renewables are growing at different rates throughout the MISO regions, Bakke said, and the RTO wants to identify “inflection points” at which the growth of renewables and the retirement of baseload units will require changes in the structure or operation of the system. With more projects moving through the interconnection queue, Bakke said MISO may soon have to begin forecasting for solar output.
The study aims to predict how and when reliability will be impacted under heavy renewable output; if there are limits to the amount of wind and solar generation MISO can support; how long before energy storage becomes a requirement; what parts of the grid will be stressed first; and how much renewable energy can be deployed before significant system changes are needed.
“We don’t have a great idea of when certain things will have to take place to integrate renewable generation. We don’t know at what mix that will have to take place,” Bakke said.
MISO’s current registered wind capacity is about 16.8 GW and current registered solar capacity is about 180 MW, but those figures could pale in comparison if all the prospective projects in its generation interconnection queue are realized. The RTO currently has about 31 GW of wind capacity and 15.7 GW of solar capacity advancing through various stages of the queue.
After some stakeholders cautioned MISO not to inhibit state jurisdiction over resource adequacy or renewable portfolio standards, staff stressed that the study will be limited to an impact assessment, and nothing will be built or changed as a direct result of the study.
“We’re looking purely at the technical impacts of the system, and how those can change,” Bakke said, adding that if something significant is discovered, study results will be passed to other departments.
Some stakeholders demanded to know if the study results would eventually inform modeling in MISO’s annual Transmission Expansion Plan.
“It really depends. It’s an exploratory study, and that’s the nature of research,” Bakke said.
Wind on the Wires’ Natalie McIntire asked how this study would differ from other renewable studies the U.S. Energy Department has already conducted.
Bakke said that while national studies seek ways to incorporate targeted amounts of renewables, MISO’s study will lack “a solution-oriented focus.”
Indianapolis Power and Light’s Lin Franks offered to share the company’s data on its solar assets and Harding Street storage facility. “We’ve been trying to get MISO’s attention now for a while to provide real PV data,” Franks said. “We need to bring real data to the table before engaging in a worthless academic exercise.”
Bakke agreed that renewable data for the footprint is hard to come by and said MISO may use IPL’s data.
The RTO will return to the PAC in September with a study scope for stakeholders to review, he said.
Massachusetts regulators have issued new, stricter limits on greenhouse gas emissions from the state’s fossil fuel power plants and ordered utilities to buy at least 16% of their electricity from clean energy sources in 2018.
The regulations, announced Aug. 11 in response to a 2016 court order, include a Clean Energy Standard (CES) that requires utilities and competitive suppliers in the state to procure increasing amounts of electricity from clean energy sources every year, with the minimum percentage increasing 2 points annually to reach 80% in 2050.
The new rules also set annually declining limits on aggregate CO2 emissions from 21 large fossil fuel-fired power plants in the state, from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. The regulations establish an allowance trading program for CO2 emissions from generators, with allowance auctions beginning in 2019 and direct allocations for 2018. The rules offer flexibility in the form of limited allowance banking and a “deferred compliance” option to address electricity grid reliability.
allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER
The regulations also reduce allowable methane emissions from natural gas pipelines and distribution systems. They also tap the transportation sector by requiring state, city and regional transportation planning agencies to evaluate and report the aggregate GHG emissions of their facilities, fleets and programs.
The new procurement rules are like those of the Massachusetts Renewable Portfolio Standard, while the emissions targets are stricter than CO2limits under the Regional Greenhouse Gas Initiative, the cap-and-trade system agreed on by nine Northeastern states.
Pushed to Act
The state acted in response to a 2014 lawsuit by the Conservation Law Foundation that accused Massachusetts officials of failing to enact regulations needed to meet the targets set by the 2008 Global Warming Solutions Act. The state’s top court ruled in favor of CLF in May 2016.
CLF helped win passage of the climate change law, which requires Massachusetts to issue regulations to incrementally reduce greenhouse gas emissions each year.
“These rules re-establish the commonwealth as a national leader in developing sensible, enforceable standards to transition our economy to a low-carbon future,” CLF President Bradley Campbell said in a statement. “Much more needs to be done, and Gov. [Charlie] Baker’s leadership will be essential to getting neighboring states to take meaningful action to prepare New England for the energy future being shaped by the Paris Climate Agreement.”
20-year levelized cost of renewable energy resources | Mass. DOER
Last September, Baker issued an executive order that set a deadline of Aug. 11 for the secretary of energy and environmental Affairs and the Department of Environmental Protection to have “designed such regulations to ensure that the commonwealth meets the 2020 statewide emissions limit mandated by the GWSA.”
That limit — a 25% reduction in emissions below 1990 levels — was established seven years ago by the state to meet the GWSA requirement of a minimum 80% reduction by 2050. Officials estimate that by 2014, Massachusetts had already cut carbon emissions by 21% from 1990 levels.
“These regulations will help ensure the commonwealth meets the rigorous emission reductions limits established in the Global Warming Solutions Act in order to protect our residents, communities and natural resources from the effects of climate change,” Baker said.
Limited Effect on Consumers
The DEP concluded that the emissions targets and clean procurement rules would likely increase customer electricity bills by 1 to 2% per year.
The Bay State has been busy this year ramping up its environmental regulations. Officials earlier this summer announced that the state’s electric distribution utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020. (See Massachusetts Underwhelms with 200-MWh Storage Target.)
In late July, the state received more than half a dozen proposals to meet its call for 9.45 TWh a year of renewable generation. Projects will be selected next January, with contracts to be submitted in late April. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
In response to public comment, the final CES included limited grandfathering to accommodate electricity sold in 2018 and 2019 under existing contracts. For the next three years, the alternative compliance payment rate is being increased to 75% of the RPS amount, but it will drop to 50% of the RPS amount in 2021. The use of banked clean energy credits is not allowed until 2021.
allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER
The RGGI emissions cap represents a regional budget for CO2 emissions from the power sector, with each CO2 allowance representing an authorization to emit 1 short ton from a regulated source. The nine RGGI states agreed on a 2014 cap of 91 million short tons. The CO2 cap declines by 2.5 percentage points each year from 2015 to 2020.
