Wheeler, who has been serving as acting administrator since the July resignation of Scott Pruitt, was supported by all but one Republican, Susan Collins (Maine).
Collins criticized Wheeler’s efforts to replace the Obama administration’s Clean Power Plan and weaken air emission standards for vehicles.
“These efforts are of great importance to the state of Maine, which is located at the end of our nation’s ‘air pollution tailpipe’ and is on the receiving end of pollution generated by coal-fired power plants in other states,” Collins said in a statement. “Moreover, there is no doubt that the greenhouse gas emissions driving climate change pose a significant threat to our state’s economy and our natural resources, from our working forests, fishing and agricultural industries, to tourism and recreation.”
Collins also cited EPA’s determination that it is no longer “appropriate and necessary” to regulate mercury emissions from power plants. “Controls for mercury, one of the most persistent and dangerous pollutants, are especially important for children and pregnant women,” she said. “The agency’s recent efforts to halt progress in these critical areas takes us in the wrong direction.”
Other Republicans and business groups, however, praised Wheeler for continuing Pruitt’s work undoing regulations they contend were strangling industry.
“I believe he will do an excellent job leading the agency,” said Sen. John Barrasso (R-Wyo.), chair of the Environment and Public Works Committee. “As acting administrator of EPA, he has prioritized commonsense policies that protect our air and water, while allowing our economy to grow.”
Sen. Lisa Murkowski (R-Alaska), chair of the Energy and Natural Resources Committee, said she supported Wheeler because “he has proven himself during his tenure as acting EPA administrator as a leader who hears and takes seriously the concerns of Alaskans.”
“Regulatory certainty has been key to the historic manufacturing job growth we’ve seen under the current administration, and that would not have been possible without Andrew’s leadership at EPA,” said Jay Timmons, CEO of the National Association of Manufacturers.
Democrats and environmental groups blasted Wheeler’s appointment.
“At this moment of growing harm from climate change, appointing someone to lead the EPA who has vigorously opposed our efforts to reduce carbon pollution … would be like putting the Monopoly Man in charge of regulating big banks,” Sen. Chris Van Hollen (D-Md.) said.
“As a former fossil fuel lobbyist, he consistently worked against the public interest to advance an anti-environment agenda and dismantle many hard-won climate change programs,” Sen. Dianne Feinstein (D-Calif.) said.
“As administrator, we expect he will continue doing the bidding of the polluters he used to represent,” said John Bowman, senior director of federal affairs for the Natural Resources Defense Council. “And what he can expect from us, and many others, is a wall of opposition and legal challenges to stop this dangerous agenda.”
At his confirmation hearing before Murkowski’s committee on Jan. 16, Republicans praised Wheeler’s nearly two decades of experience at EPA and on the committee staff. Wheeler began his career at the agency during the George H.W. Bush administration and later served as staff director and chief counsel to Republicans on the committee.
SAN FRANCISCO — The explosive growth of solar power in California will require a huge amount of new electricity storage to allow the state to meet its ambitious green energy goals, panelists said Tuesday at this year’s Infocast Storage Week conference.
“What’s my vision for storage? Very quickly. We’re going to have to have a lot of it,” said Monterey Bay Community Power CEO Tom Habashi, who was part of a panel on storage and community choice aggregators (CCAs). “We are not even at a fraction of 1% of what we need to be at. I don’t see any other way of reaching decarbonization unless we have a lot of solar and a lot of storage to go with it so we can cover all the hours when the sun doesn’t shine.”
Last year’s SB 100 established a timeline for the state’s utilities and CCAs to get all their electricity from zero-carbon sources by 2045. But the state’s ample solar production peaks at a time when it’s least needed — during the lowest point of the so-called “duck curve” in the middle of the day. (See Can Calif. Go All Green Without a Western RTO?)
Larger batteries are just beginning to store a tiny portion of the electricity needed during the evening ramp, when the sun goes down and electricity demand soars as people arrive home on the West Coast. Doing away with natural gas peaker plants, as the state envisions, will require solar projects to be coupled with storage, speakers said.
The Monterey Bay CCA, for example, has 265 MW of solar energy plus 85 MW of storage. “We’re way, way ahead of what we are required to do,” Habashi said.
John Zahurancik, CEO of Fluence Energy and a 20-year veteran of large-scale storage projects, said larger and longer-duration battery projects are coming online all the time, but that it’s likely just the beginning.
“We’re in the early days of when this starts to scale,” Zahurancik said during a panel on standalone storage. “It’s just starting to pick up speed.”
Fluence is building a 100-MW standalone storage project, among the largest in the U.S., he said. More utilities are looking to lithium-ion batteries, in “increasingly large types of systems,” as a solution to the challenges of intermittent solar and wind power.
Asked whether any technologies would emerge to compete with lithium-ion batteries, Zhurancik said the batteries are a proven technology being built at volume with backing from deep-pocket investors. He said he expects to see improvements and changes but probably not a “wholly new” storage solution in the next five years.
Rooftop Solar ‘Underestimated’
In a panel on ISOs and storage moderated by RTO Insider Deputy Editor Robert Mullin, Clyde Loutan, CAISO’s principal planner for renewable energy integration, said the ISO hadn’t anticipated how fast rooftop solar would proliferate and create challenges for it.
“We completely underestimated the speed at which rooftop PV was going to come onto the grid,” Loutan said. There are 7,000 MW of rooftop solar in California, and planners expect to see as much as 13,000 MW by next year, he said.
Utility-scale solar projects supply another 12,000 MW of electricity in CAISO, he said.
With a variable resource like solar, output can suddenly drop by 1,000 MW, requiring battery storage that can come online quickly and make up for the shortfall, he said, and solar falls away each night.
“During the evening you got to meet that huge ramp when the solar drops off,” Loutan said.
On the other hand, there’s far too much solar power available on weekends. Oversupply and undersupply create challenges controlling the grid and maintaining the frequency at 60 Hz, Loutan said.
“You need a lot of stability,” he said. “You need a lot of fast-injecting capability. Storage can provide that.”
‘Best, Highest Use’
Mullin cited an RTO Insider story in which MISO CEO John Bear said RTO staff are working to determine the “best, highest use” for storage projects.
“We’ve almost internally forced ourselves as a company to calling them batteries, as opposed to storage, just because we don’t want to presuppose what the best use of them might be,” Bear said at the Gulf Coast Power Association’s MISO South Regional Conference in February. (See Overheard at GCPA MISO South Regional Conference.)
Batteries might be most valuable as quick-response resources to help balance the grid, he said.
Asked to elaborate, Kevin Vannoy, MISO’s director of market design, said, “What I think John was getting at there was it’s not about just storing energy for later injection.”
“I think we don’t want to limit ourselves to just a single product when it comes to storage or a single use or a single application because of the flexibility and the different products it can provide and the problems that it can solve.
“We don’t want to get stuck into just thinking of these as we have our traditional pumped hydro units,” Vannoy said. “We want to make sure we’re getting the full value … [and] capabilities that batteries and storage can bring.”
Loutan said the highest and best use for storage right now is to provide reliability and frequency response.
“We still need to explore the capabilities of storage,” he said. “How can we utilize the capabilities of storage to develop new products and help operate the grid differently?”
Challenges and Opportunities
Connecting storage to the grid isn’t as simple as plugging in a battery, panelists said. Challenges exist, with more to come, but batteries also present potential solutions to pressing needs, they said.
“One thing I would recommend is … making sure that the battery’s sized accordingly,” said Eric Hsia, liaison to the CEO at PJM. Oversizing or undersizing can cause trouble.
“If they do that and they do it wrong, it could potentially pose operational issues, which we did experience in the regulation market,” he said.
Kenneth Ragsdale, market design principal with ERCOT, said “I don’t want to sound like a Texan, but I think our challenges are a little harder than theirs.”
The Texas Interconnection is smaller than the Western or Eastern interconnections, “so the loss of our two largest units in the ERCOT system is a big hit in terms of trying to maintain the frequency. We’re very careful about making sure we have enough rotating mass, enough inertia, on the system.”
ERCOT adopted a “fast frequency response” protocol, he said. “Basically, you need a resource that can respond to a frequency deviation within 15 cycles,” he said. “We see a lot of hope for some batteries coming in and doing that.”
Batteries could also help alleviate five- to 15-minute price spikes and deal with the daily four-hour peak in the hot Texas summers, Ragsdale said.
In New York, “there’s tremendous opportunity for storage,” said Mike DeSocio, senior manager of market design with NYISO. The state mandated storage and has about 2,000 MW queued up, from 1.5- to 300-MW storage projects. “Storage is coming,” he said.
The state is looking to develop large quantities of offshore and onshore wind power along with rooftop solar. Batteries could help balance those variable resources with low-carbon electricity, he said.
Batteries could also buffer the state’s ample nuclear output (which is set to get financial support from zero-emission credits) — the same way pumped hydro did when the nuclear plants were first built, he said.
“I kinda feel like we’re going back to the future here a little bit,” DeSocio said.
RENSSELAER, N.Y. — NYISO stakeholders on Wednesday concluded an unusually lengthy public policy transmission planning process and reviewed a revised report and new analysis for selection of two AC transmission projects to improve transfer capability into the New York City area.
The new analysis by ISO staff followed a December decision by the Board of Directors to decline the Management Committee’s recommendation to build Project T029 — a standard 345-kV line from Knickerbocker to Pleasant Valley — on Segment B, a section of the grid feeding the Upstate New York/Southeast New York (UPNY/SENY) electrical interface. (See NYISO Board Partially Reverses AC Tx Project Selection.)
| NYPA
ISO staff are now recommending Project T019, as is the board, saying it has the highest incremental UPNY/SENY transfer capability, which results in the lowest cost-per-megawatt ratio, highest production cost savings, greatest CO2 emissions savings and highest Installed Capacity (ICAP) savings of the Segment B projects, Zach Smith, vice president for system and resource planning, told the committee.
The board did not object to the committee’s selection of Project T027, a double-circuit 345-kV line from Edic to New Scotland for Segment A, which feeds the Central East interface.
Advised by consultant Substation Engineering Co., NYISO reviewed seven proposals for Segment A and six for Segment B before making their choices last June. (See NYISO MC Supports AC Transmission Projects.)
Project T019 was proposed by National Grid’s Niagara Mohawk Power and NY Transco, while North America Transmission (NAT) and the New York Power Authority together proposed both projects T027 and T029.
Cost estimates for both NAT/NYPA projects ranged from $900 million to $1.1 billion. The estimated capital costs for T027 and T019 are higher, at $1.2 billion, but the project is made more cost-effective by the up to 550 MW of additional N-1 emergency transfer capability provided on UPNY/SENY by T019, Smith said.
The ISO estimates the two AC transmission projects, if approved by the board in March, will be in service by December 2023.
Lawrence Willick of LS Power said the incremental benefits of T019 do not justify the incremental costs, but New York Transco General Counsel Kathleen Carrigan said the ISO on two occasions (including with the selection of T027 for Segment A in the AC Transmission PPTN and for the Western New York PPTN) has recommended projects with higher capital costs to be selected as the most efficient or cost-effective solution to satisfy a PPTN. In both cases, she said, the higher capital costs correlated to significantly greater benefits to the statewide electric system than the lower-cost alternative proposals. She contended that the ISO should take a similar approach in its recommendation for Segment B as well.
Several stakeholders requested an opportunity to address the board, and LS Power and NY Transco will make oral presentations on March 18, one day before the board meets, interim NYISO CEO Rob Fernandez said.
“We only wish to present if LS Power presents — if they don’t, we don’t,” Carrigan said. Fernandez responded that the ISO would work out the details soon. Comments on the PPTN review were due Friday.
The ISO estimates the two AC transmission projects, if approved by the board in March, to be in service by December 2023. | NYISO
Stakeholders in January informed the ISO of a modeling error in the analyses, specifically that the impedance data had been transposed for the New Scotland-Knickerbocker and Knickerbocker-Alps 345-kV projects.
“We corrected the impedance and confirmed it with the developers,” Smith said. “The ISO also revised its dispatch methodology after the board said it created a perception of a constraint. The board requested we dive a little deeper into operability analysis.”
Specifically, the impedance data correction impacted the UPNY/SENY limit, he said. For T019, the incremental UPNY‐SENY emergency transfer capability decreased from the previously calculated level of 2,100 MW to 1,850 MW. For T029, the data correction caused the incremental emergency transfer capability to increase from 1,150 MW to 1,300 MW.
Additional analysis also included a “sensitivity” in which the G‐J Locality is eliminated and a new H‐J Locality is created.
“The capacity scenario should be eliminated as being more misleading than useful,” said Mark Younger of Hudson Energy Economics, which helped the Independent Power Producers of New York submit comments on the analysis. IPPNY took no position on the board’s PPTN project selection.
Younger said it was unreasonable to assume capacity could be replaced in the more densely populated areas of Zones H and I for the same price as in the more rural Zone G, and that it was also impossible that the market would not respond to stopping payments to resources based on their locational value. He also noted that NYISO’s own analysis in the study showed that there continues to be a need for capacity in Zone G.
Entry and Exit Modeling
“One of the things that limits the benefits from the recommended projects is limited transfer capability south of the projects, so future increases in transfer capability south of these projects could lead to substantial additional benefits,” said Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit.
“At the same time, if the PSC relies more on offshore wind than upstate renewables to achieve the goals of the Clean Energy Standard, then it would tend to reduce the benefits,” so the location and amount of intermittent renewables is in flux, he said in summarizing his report’s conclusions.
NYISO’s public policy transmission planning process calls for the Monitor to review and consider the impacts on the ISO’s markets.
The Monitor made several recommendations for improvement, but LeeVanSchaick particularly highlighted one: to model entry and exit decisions for generators in a manner consistent with the expected competitive market outcomes.
“If the ISO could incorporate entry and exit scenarios into its modeling, that would be very useful for ensuring the scenarios provide a realistic picture of the future benefits of the projects,” he said.
Marc Montalvo of Daymark Energy Advisors, representing the New York Department of State’s Utility Intervention Unit, said the UIU was concerned, as were several other stakeholders, about the qualitative measures being applied and decisions being reached in a different way from the MC’s understanding during its serious deliberations.
“We ought to make sure we are not creating a process that gives developers pause,” Montalvo said. “Given how much time and energy on behalf of the developers goes into the process, the last thing we want to see is a lack of confidence … whereby developers might choose not to participate, reducing the efficiency of market outcomes and possibly harming consumers.”
The New England Power Pool indicated Thursday it won’t let reporters into its meetings without a fight, asking FERC to reconsider its order rejecting the group’s press ban.
The commission ruled unanimously Jan. 29 that it had jurisdiction over NEPOOL’s membership rules and that barring journalists from joining was unduly discriminatory (ER18-2208-001). (See FERC Rejects NEPOOL Press Membership Ban.)
NEPOOL Participants Committee | NEPOOL
FERC said it would rule separately on RTO Insider’s complaint under Section 206 of the Federal Power Act asking the commission to terminate the group’s stakeholder role or direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
The stakeholder group sought to amend the NEPOOL Agreement to bar members of the press from membership after RTO Insider reporter Michael Kuser, an electric ratepayer in Vermont, applied to join as an End User in March 2018.
In its request for rehearing or clarification, NEPOOL contended that “the commission’s jurisdictional determination not only lacks sufficient explanation, but its conclusion that the membership provisions are jurisdictional is potentially limitless in scope.
“Under these circumstances and given the issues pending before the commission in the complaint proceeding in Docket No. EL18-196, NEPOOL files this request to preserve its rights until the commission provides clarity and explanation for its decision to exercise jurisdiction over the membership arrangements of an entity that does not provide wholesale power or transmission service to any customer,” the organization continued.
The commission’s order rejected NEPOOL’s contention that its membership provisions were not FERC-jurisdictional, concluding that “they directly affect commission-jurisdictional rates.”
NEPOOL said FERC’s ruling cited as precedent only “one factually dissimilar case … and provides no explanation as to how the cited precedent supports the commission’s jurisdictional claims.”
The case cited was a 2016 ruling involving PJM in which the commission found that the RTO stakeholder process is “a practice that affects the setting of rates, terms and conditions of jurisdictional services.” The commission made the filing in rejecting rehearing of an order approving PJM’s funding of the Consumer Advocates of the PJM States. (See FERC Upholds PJM Advocates’ Funding.)
“Without an explanation of how and why PJM is relevant to the treatment of NEPOOL’s membership amendments, the January order fails to meet the commission’s obligation to carry out reasoned decision-making,” NEPOOL said. “NEPOOL requests that the commission further articulate the basis for its conclusion that the membership amendments are jurisdictional. As it stands, the January order could be read to sweep virtually any NEPOOL practice, procedure or protocol under commission jurisdiction, no matter how tangential to rates, terms or conditions of jurisdictional service.”
NEPOOL said the commission’s reasoning was “similar to the expansive view of its jurisdiction that was rejected” by the D.C. Circuit Court of Appeals in its 2004 CAISO ruling.
In that case, the court rejected FERC’s attempt to replace CAISO’s Board of Governors, ruling that the commission “does not have the authority to reform and regulate the governing body of a public utility under the theory that corporate governance constitutes a ‘practice’ for ratemaking authority purposes.”
Membership Pending
NEPOOL’s rehearing request comes two weeks after its Membership Committee recommended to the Participants Committee that Kuser be granted membership. The Participants Committee has listed the issue on the agenda for its next meeting, March 13.
In addition to seeking to change its Agreement to bar press from membership, NEPOOL last year also amended the Participants Committee bylaws to limit the ability of meeting participants to share what they’ve heard.
The new language — which was not submitted for FERC approval — states that: “Attendees may use the information received in discussion, and may share the information received within their respective organizations or with those they represent, provided those who receive such communications are not press and also are aware of and agree to respect the nonpublic nature of the information. In no event may attendees reveal publicly the identity or the affiliation (other than sector affiliation) of those participating in meeting discussions.”
The commission’s January order left that prohibition intact.
MISO and a majority of its transmission owners on Monday filed a new cost allocation plan with FERC that would change the way the RTO allocates costs for its market efficiency projects (MEPs).
The proposal applies to MISO’s 2019 Transmission Expansion Plan and includes MISO South, which saw its five-year transmission cost-sharing moratorium expire at the end of 2018.
The 622-page filing includes proposals to lower the voltage threshold for MEPs from 345 kV to 230 kV and eliminate a 20% footprint-wide postage-stamp cost allocation method for projects. It will also create two new project benefit metrics: the value of deferred or avoided reliability transmission projects, and the value of reducing power flows on the contract path on shared transmission from MISO Midwest to South (ER19-1124, ER19-1125).
| MISO
The proposal additionally creates a new category for economic projects below 230 kV and above 100 kV where 100% of costs would be allocated to the local transmission pricing zone. Such projects were previously categorized as “other” transmission projects without clear allocation rules.
MISO said the proposal was “extensively vetted” through its stakeholder process for more than three years. It noted that the package creates “additional opportunities for the identification and approval of market efficiency projects and greater precision in cost allocation for such projects, and formalizes the process for development of locally based economically beneficial projects.”
The RTO told FERC that the lower voltage threshold will likely result in more MEPs and, by extension, more opportunities to bid projects under the competitive transmission process. Because of the expected uptick in activity, MISO also proposed a limited exception to the competitive selection process for MEPs that can also demonstrate an immediate reliability need. The exception would only apply when a lengthy bid selection process would push a project’s in-service date past the expected reliability need date, MISO said, urging the commission to accept the provision, because it had approved similar selection exceptions in three other RTOs.
More Benefit Metrics?
MISO last year opened the door to the two new benefit metrics on MEPs besides the usual adjusted production costs; earlier this month staff signaled willingness to add even more benefit metrics to the list this year.
At the February Planning Subcommittee meeting, MISO planning coordinator Adam Solomon said the RTO and stakeholders will likely begin with ideas that didn’t make the cut last year, including increased capacity import and export limits, reduced congestion from fewer transmission outages, reduced transmission losses and the ability of a project to boost grid resilience.
MISO will work with stakeholders to identify new benefit metrics to pursue during the first half of the year and then determine how to quantify them during the second half. The work could culminate in a FERC filing by the end of the 2019.
PJM’s Market Implementation Committee, which approved changes to its must-offer exception rules in November, will consider two alternative proposals at its meeting March 6.
Members will vote on a joint proposal by PJM and the Independent Market Monitor and one by Exelon in a review prompted by the Markets and Reliability Committee’s decision to defer a vote on the earlier proposal and send the issue back to the MIC for further discussion.
The initial proposal, which won 79% stakeholder support at the November MIC, would:
Codify the current must-offer exception process in Manual 18.
Add timing to the list of acceptable reasons for an exception. Exceptions would be permitted for capacity market sellers that can demonstrate they will “be physically incapable of satisfying the requirements for a Capacity Performance generation resource by the start of the relevant delivery year.”
Allow a capacity market seller to voluntarily initiate a status change to energy-only by making a request to PJM and the Monitor. Status changes would not be permitted while the resource holds a capacity commitment for the relevant time period.
Require existing capacity resources approved for CP must-offer exceptions and not offered in three consecutive auctions to change to energy-only.
Treat capacity interconnection rights (CIRs) of resources converted to energy-only the same as if the unit had been deactivated. CIRs will terminate one year from the date on which the resource status change takes effect, unless the rights holder submits a new generation interconnection request within that year which uses the same CIRs.
Permit participants to request exemptions from multiple auctions in a single exception request.
Stakeholders Delay Action
On Dec. 20, the MRC deferred a vote on the MIC-approved proposal at the request of Susan Bruce, representing the PJM Industrial Customer Coalition. Bruce, who made the motion on behalf of industrial gas producer Praxair, said industrial consumers wanted stakeholders to conduct additional discussion on resources wanting to move between capacity- and energy-only status. (See “Must-offer Exception Process Deferred,” PJM MRC Briefs: Dec. 20, 2018.)
The alternate PJM/Monitor plan to be considered next week adds to the MIC-endorsed package documentation requirements to support exception requests. Effective with the 2023/24 delivery year, exception requests would have to include a plan showing how the resource will become able to satisfy the CP requirements, including a timeline with design, permitting, procurement and construction milestones. Regular status updates also would be required. Exceptions would be limited to two auctions, and status changes would be mandated for existing resources that fail to provide a plan or show good-faith effort to make the resource physically capable of CP.
“The general idea of a plan is just for the seller to inform PJM if they are CP-capable,” PJM’s Pat Bruno explained at the MIC’s Feb. 6 meeting. “The plan would be reviewed by the IMM and PJM.”
Exelon Demurs
Exelon, which initiated stakeholder discussions on the issue a year ago, will offer a second alternative that does not include a requirement for resources to become energy-only.
Sharon Midgley, senior manager of wholesale market development for Exelon, questioned PJM’s insistence on revoking CIRs. “Storage and renewables have no must-offer requirements,” she said at the February MIC. “So why target conventional generation owners?”
Bruno said there are separate rules for intermittent resources and storage.
Midgley said Exelon’s proposal does not include a mandatory switch to energy-only because stakeholders are not in consensus on the issue and that aspect of the updated PJM/Monitor proposal raises important CIR equity issues that haven’t been addressed. “We think there is clear consensus on the process enhancements and the voluntary process if generators want to become energy-only,” she said. “It seems like a double standard. … For that reason, we are agnostic and don’t have anything in our proposal that addresses a mandatory process.”
Monitor Joe Bowring said the IMM has recently seen “a lot of people seeking deactivation and then changing their mind.”
“A voluntary process, in our view, is not sufficient,” he added.
If any of the packages receive more than 50% support at the March 6 MIC meeting, a second nonbinding vote will be taken asking whether participants prefer that package over the status quo and the original MIC-endorsed proposal.
Any proposals receiving 50% MIC approval will be given a first read at the March 21 MRC meeting. The committee will vote on the alternatives at its April 25 meeting.
SPP and MISO staff and stakeholders recommended performing a coordinated system plan in 2019-20 that will study six possible sites for interregional transmission projects.
The RTOs announced the recommendation during their Feb. 26 Interregional Planning Stakeholder Advisory Committee meeting, which served as their annual review of congestion issues.
MISO Expansion Planning Engineer Ben Stearney said both “staffs are fully in support” of the study, which was approved by stakeholders on the conference call.
| SPP
The recommendation still needs approval from the MISO-SPP Joint Planning Committee, which is composed of planning staff from both RTOs. The committee will meet sometime in March to hold the vote. If the JPC approves, the RTOs will begin working on building the scope of the CSP.
The study could result in a first-ever interregional transmission project for the RTOs, which conducted CSP and regional reviews in 2014 and 2016 but were unable to reach an agreement on any projects.
So far, the RTOs’ studies show that they may need transmission projects along multiple spots near their southern seam in addition to a location on the South Dakota-Iowa border.
The six possibilities for joint economic projects are:
The Neosho-Riverton 161-kV line on the Kansas-Missouri border, which also appeared in the RTOs’ 2016-17 CSP study;
A circuit on the Kerr-Maid 161-kV double-circuit line in northeast Oklahoma, needed for west-to-east bulk transfers;
The 138-kV South Shreveport-Wallace Lake line in northwest Louisiana, where the area is experiencing load growth;
The 345-kV Hugo-Valliant line in southern Oklahoma, the loss of which causes overloads on the nearby 138-kV system;
A 230-kV line in Sioux City, where MISO predicts that growing wind generation in South Dakota will drive up north-to-south flows; and
The 115-kV Marshall-Smittyville line in northern Kansas, needed as a generation corridor.
If approved, the CSP would be the first in which MISO and SPP rely on their individual regional processes instead of a joint model to evaluate potential transmission projects.
Some stakeholders asked MISO and SPP for a special study of the seam’s most expensive flowgates to see if the RTOs could identify needs that the separate regional processes might be missing. A few said some of the most costly flowgates don’t seem to be captured in the models.
But MISO and SPP staff said a special joint study would introduce more hurdles and negate last year’s decision that the joint model was too cumbersome and ineffective at identifying projects. “To me that was part of the decision-making in 2018 that led to where we are … that we won’t do anything separate and one-off,” SPP’s Adam Bell said.
“I support the study, but I disagree with what we’re looking at,” said Omaha Public Power District’s Josh Verzal, one of the stakeholders who criticized the RTOs for not taking stakeholder-submitted project needs seriously enough.
The RTOs plan to make a FERC filing soon seeking approval for interregional process changes they agreed to last year. In addition to doing away with the joint model, they also agreed to eliminate a $5 million cost threshold for projects, add avoided costs and adjusted production cost benefits to project evaluation, and make CSP studies a more regular occurrence.
Last month, the RTOs said stakeholders and staff support an annual joint study of interregional transmission projects. Currently, their CSP is not mandated annually. (See MISO, SPP Pushing for Annual Joint Studies.)
FERC on Monday accepted rule changes broadening energy storage resources’ ability to provide capacity, energy and ancillary services in ISO-NE’s markets, effective April 1 (ER19-84).
The commission said the Tariff revisions, which were largely backed by the Energy Storage Association and include a new section devoted to electric storage, “enhance competition.”
The commission declined to respond to ESA’s complaints regarding how ISO-NE’s plans to assign reserves to storage, saying it would deal with the issue in responding to the RTO’s compliance filing with Order 841 (ER19-470).
Storage resources could face tougher requirements in some regions than in others under proposed tariff revisions filed by RTOs and ISOs in their Order 841 compliance filings in December. (See RTOs/ISOs File FERC Order 841 Compliance Plans.)
Issued last February, Order 841 set a Dec. 3, 2019, compliance deadline.
FirstLight Power Resources owns the largest pumped-storage hydroelectric plant in New England, the 1,143-MW Northfield Mountain Project on the Connecticut River in Massachusetts. | FirstLight Power Resources
Storage Old and New
ISO-NE says it has 19 MW of battery storage already participating in its markets, with more than 800 MW in its interconnection queue and another 170 MW of proposed battery storage in the queue that would be co-located with wind and solar power projects.
On-site storage | ESA
The RTO noted that while it has limited experience with electric battery storage, the region has been home since the 1970s to nearly 2,000 MW of pumped-storage hydroelectric units. Pumped storage has participated in the region’s wholesale electricity markets as two distinct asset types: a dispatchable generator asset that submits offers to supply energy and regulation, and a dispatchable asset-related demand (DARD) asset that submits bids to consume energy.
“The defining physical and operational characteristic of an electric storage resource is its ability to transition between consuming and injecting electric energy,” the RTO said in its filing.
The new Tariff section (III.1.10.6) defines electric storage facilities as one of two types:
Binary storage facility: a pumped-storage hydro unit that offers both its generator asset and DARD in the energy market as rapid response pricing assets.
Continuous storage facility, which the RTO explained in its Order 841 compliance filing “can transition seamlessly between charging and discharging.” It must be registered as both a dispatchable generator asset and a DARD, with each registration representing the same equipment. It also may provide regulation and must be registered as an alternative technology regulation resource (ATRR). The ATRR construct, ISO-NE explained, allows continuous storage facilities to “provide regulation in a manner that permits them to take full advantage of their ability to follow a regulation signal that traverses all or part of their negative-to-positive range nearly instantaneously.”
Sustainable for 1 Hour
The Northeast Power Coordinating Council mandates reserves be sustainable for at least one hour from the time of activation, which the RTO said can be met by traditional generators but can constrain limited energy resources such as continuous storage.
To comply with this standard, the RTO said it will automatically reduce the economic maximum limit of a continuous storage facility’s generator asset when the facility has less than one hour of available energy remaining. If such a unit were at risk of running out of energy in less than one hour, ISO-NE’s software will automatically adjust the unit’s economic maximum limit to an output level that can be sustained for the hour.
ESA asserted that “the operational impact of the proposed Tariff implementation” is unjust and unreasonable because it prevents some electric storage from providing all the energy service of which it is technically capable.
ISO-NE includes as reserve providers those generators that have dispatchable “headroom” above their current dispatch point and maximum output level and offline generators able to start up within 30 minutes.
| ESA
The RTO said its Tariff revisions do not become unjust and unreasonable “simply because they may not facilitate a participant’s efforts to maximize its revenues, as ESA suggests.”
It also said ESA exaggerated the extent to which revenues would be impacted by redeclaration. The grid operator said it would not issue a dispatch instruction unless it could be followed for at least 15 minutes, and therefore “the figures that ESA provides are not entirely accurate.”
The commission said ESA’s concerns regarding the assignment of reserves were beyond the scope of the proceeding, noting that “what ESA describes as the ‘automatic redeclaration process'” was referenced only in ISO-NE’s transmittal letter and not the Tariff changes. It added the Tariff “already requires resources to update their operating limits in real time.”
“To the extent that the practices described in ISO-NE’s transmittal letter relate more generally to compliance with Order No. 841, we decline to address their merits in this proceeding,” the commission said. “ESA has filed a motion to intervene and submitted comments addressing automatic redeclaration in [the Order 841] proceeding, which will be addressed there.”
Pennsylvania lawmakers may create a new tier within the state’s alternative energy program for nuclear power, according to a draft proposal leaked Monday.
The plan would carve out subsidies intended to save two of the state’s five nuclear plants from decommissioning as the deadline for government intervention looms. (See Exelon: Need Pa. Action by May to Save TMI.)
The bill would revise the 2004 Alternative Energy Portfolio Standards Act (AEPS), which mandates electricity distributors boost usage of renewable or alternative energy sources to 18% by 2021. It could hit the legislature March 7, according to prime sponsor Rep. Thomas Mehaffie (R).
Supporting lawmakers say the legislation will thwart a projected $4.6 billion annual cost to taxpayers should the state’s five nuclear facilities deactivate — including $788 million in increased electricity rates, a $2 billion GDP loss, $1.6 billion in carbon emissions-related increases and $260 million lost to managing harmful criteria air pollutants.
“I wouldn’t introduce the bill if I didn’t think it would pass,” Mehaffie said Tuesday, describing it as one the most important proposals to be vetted in the last 25 years. “I’m really confident we can get something completed” before May.
State Sen. Ryan Aument (R) will introduce a similar bill in the Senate next week, according to his chief of staff, Ryan Boop.
“The leaked draft that is being circulated is not a draft that Sen. Aument’s office drafted,” he said. “I can verify that we are working on language with a number of other legislators that will create a new Tier 3 within the AEPS, and we hope to have that language introduced in the next week or so.”
Nuclear Carve-out
Nuclear generation supplied about 42% of Pennsylvania’s net generation in 2017, compared with 4.5% for renewables, according to the Energy Information Administration. In the draft bill, lawmakers would create a third tier of resources in the portfolio from which companies must purchase at least 50% of their electricity by 2021: nuclear, solar, geothermal and low-impact hydropower, with a few exceptions. The first two tiers include many of the same resources — plus fuel cells, municipal solid waste, biomass energy and biologically derived methane gas — with targets of 8% and 10%, respectively.
Analysts with ClearView Energy Partners suggest the qualifying language found in the third tier — such as rules excluding renewable resources that receive other tax credits and exemptions — is designed to solely benefit nuclear energy.
That’s a big problem for Citizens Against Nuclear Bailouts, a coalition of natural gas industry advocates opposed to saving Three Mile Island Unit 1 near Harrisburg before Exelon shuts it down in September.
“It’s still unclear to us what exactly the problem is that legislators are trying to solve,” said Steve Kratz, spokesperson for the group, in an email Tuesday. “Three Mile Island is the only facility in Pennsylvania that isn’t profitable, and regulators at all levels, including FERC and PJM Interconnection, have been very clear that Three Mile Island can close as planned with no impact to grid reliability or ratepayers.”
In a 2017 filing with the U.S. Securities and Exchange Commission, Exelon said TMI had lost money for the last five years as a result of “prolonged periods of low wholesale power prices,” its failure to clear the last three PJM capacity auctions and “the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution while contributing to grid reliability.” The company, manager of the largest nuclear fleet in the country, announced similar closures in New York and Illinois before lawmakers approved zero-emission credits in both states. (See Seeking Subsidy, Exelon Threatens to Close Three Mile Island.)
“While we can’t comment until we see legislation introduced, the principles outlined in the recent co-sponsorship memo represent an important next step toward valuing the carbon-free energy that nuclear energy provides Pennsylvania,” said Dave Marcheskie, senior site communications manager at TMI. “The loss of these plants would cost the commonwealth $4.6 billion annually in the form of increased pollution, higher electricity prices to consumers, lost jobs and reduced economic activity.”
Other proponents say nuclear energy deserves inclusion in the AEPS because it provides 93% of the state’s zero-carbon electricity. Rescuing the state’s aging generators from decommissioning could likewise preserve up to 16,000 full-time jobs and $69 million in state tax revenues, they contend.
Martin Williams, business manager for Boilermakers Local 13 in Philadelphia and co-chair of Nuclear Powers PA, described the draft as “pleasing” and said the group “eagerly” awaits the final bill language.
“We have known for some time that changes to the AEPS law could be one of the common-sense mechanisms for treating carbon-free nuclear energy like the other 16 forms of environmentally friendly forms of energy currently included in the AEPS,” he said. “Pennsylvanians want clean, safe and reliable energy and [want] to keep energy prices in check. This type of approach would allow that to happen.”
Fixed Resource Requirement
Last June, a FERC order concluded that increasing state subsidies for renewable and nuclear power were suppressing capacity prices. The commission’s 3-2 ruling required PJM to expand the minimum offer price rule (MOPR) to cover all new and existing capacity receiving out-of-market payments, including renewable energy credits and ZECs for nuclear plants. The MOPR currently covers only new gas-fired units. (See Little Common Ground in PJM Capacity Revamp Filings.)
FERC suggested modifications to PJM’s fixed resource requirement (FRR) option to allow the removal of state-subsidized resources and corresponding amounts of load from the capacity market. The first round of filings in the commission’s “paper hearing” on the issue were filed in October (EL18-178).
ClearView suggested the leaked draft would allow AEPS payments to be rolled into an FRR, though it’s unclear how far the bill will get before May. Pushback from free-market conservatives and the natural gas industry could derail Mehaffie’s and Aument’s tight timelines.
“It’s a work in progress,” Mehaffie said. “We’re working extremely hard with our colleagues and others in explaining what this bill does and how important it is to Pennsylvania.”
FERC has ended its enforcement action against the operators of the Salem Harbor Power Station, dropping allegations that plant operators made ISO-NE supply offers they could not meet because of insufficient fuel.
The commission’s Feb. 25 order approved the Office of Enforcement’s recommendation last summer that FERC withdraw its Order to Show Cause against plant owner Footprint Power (IN18-7). (See FERC Walks Back Salem Harbor Manipulation Case.)
Salem Harbor Power Plant | Tetra Tech
OE had sought to force Footprint Power to disgorge more than $2 million in capacity payments Salem Harbor Unit 4 received for a period in June and July 2013 during which the commission said the plant’s fuel supply prevented it from operating at its offered capacity. OE also had sought $4.2 million in civil penalties.
Enforcement staff recommended dropping the matter based on Footprint’s arguments that FERC had failed to consider the 17.5 hours it took Salem Unit 4 to reach full output from a cold start.
The company made its argument in its response to the Order to Show Cause, saying: “The commission should terminate this misguided investigation, just as it terminated the 200-plus other referrals the ISO-NE Internal Market Monitor made during this same time frame.”
OE staff told the commission they still believed that Footprint violated ISO-NE Tariff provisions and regulations in its day-ahead limited energy generator (LEG) offers from July 18 to July 25, 2013. But they recommended the commission vacate the Order to Show Cause and not assess a penalty because the reduced scope of the violations lessened the impact on the market.
In Footprint’s Sept. 26 reply to OE’s concession, the company denied OE’s allegations regarding the July offers.
“In light of the submissions made by Footprint and OE litigation staff, as well as OE litigation staff’s recommendation not to pursue the remaining alleged violations, we terminate the proceeding in this docket,” the commission said in ending the case. “In doing so, the commission makes no findings of fact or conclusions of law concerning the merits of any issues in the proceeding, either procedural or substantive.”
Footprint’s lead attorney, John N. Estes III of Skadden, Arps, Slate, Meagher & Flom, declined to comment Tuesday.
“Our policy is not to comment on FERC investigations,” ISO-NE spokeswoman Marcia Blomberg said.
