CAISO is dropping a handful of proposed enhancements to the Western Energy Imbalance Market (EIM) less than two months before the ISO’s Board of Governors is slated to review a broader package that still contains other changes.
The ISO decided to abandon three portions of its Consolidated EIM Proposal initiative based on stakeholder feedback.
| CAISO
One proposal would have allowed non-EIM third-party transmission owners to provide transfer capacity in the market, another adjusted management of bilateral schedule changes, and a third was to ensure payments to EIM entities that currently don’t get compensation for wheeling power.
The purpose of the effort was to combine EIM initiatives from the 2017 roadmap into one package in order to gain stakeholder input.
“Based on stakeholder feedback from the issue paper and straw proposal, the ISO decided to remove the 2017 roadmap items from [the] scope of the initiative,” CAISO said in its Sept. 5 draft final proposal.
CAISO kicked off the EIM proposal process in June. (See Consolidated EIM Proposal Effort Gets Underway.) The broader package is due to be reviewed by the EIM Governing Body on Oct. 10 prior to a Nov. 1 vote by the board.
Third-party TOs had expressed interest in providing transfer capacity in the EIM, but that proposal fizzled. Some of those outside owners have since received approval to enter the EIM, and there was a lack of interest among stakeholders in the measure. (See CAISO Drops EIM Third-Party Transmission Plan.)
CAISO Market Design and Policy Specialist Don Tretheway told RTO Insider on Thursday that the third-party TO proposal will still be included in the ISO’s annual policy initiatives catalog. It might be a solution to concerns regarding net wheeling, and EIM transfer costs could be used to enable compensation for a transmission contribution, he said during a Tuesday presentation.
The ISO said it felt it was unnecessary to pursue changes to management of bilateral schedules. Some market participants want the base schedule deadline moved up 10 minutes. Under current practice, changes made after submitting base schedules are exposed to real-time imbalance settlement payments. The ISO provided examples of how EIM entities can manage bilateral schedule changes through their tariffs and business practices.
Also dropped was the proposal to compensate EIM participants for wheeling power through their balancing authorities into neighboring areas. All EIM entities currently show more net transfers in and out their territories than wheel-through transactions, so they are benefiting more than they are facilitating wheels, CAISO said. But the ISO will monitor and post net wheeling data and include it in the quarterly benefits report. That initiative will also remain in the catalog to be possibly addressed later.
Although CAISO dropped the enhancements, it is moving forward with new EIM functionalities to be implemented in the winter of 2017. They include automated matching of import and export schedule changes with a single EIM nonparticipating resource; automated mirroring of system resources at ISO intertie scheduling points; base EIM transfer system resource imbalance settlement; non-generator resource modeling functionality; and allowing submission of base generation distribution factors for aggregated EIM non-participating resources.
RENSSELAER, N.Y. — NYISO’s Business Issues Committee on Tuesday endorsed a public policy transmission planning report’s recommendation to build NextEra Energy’s proposed Empire State Line in western New York.
NextEra Empire State Line transmission project recommended by NYISO for western New York | NYISO
The line was one of 10 transmission projects evaluated to relieve constraints in the region. Independent consultant Substation Engineering Co. (SECo) estimated the project would take 40 to 49 months to build and cost about $181 million. NYISO set an in-service date of June 2022, basing the schedule on SECo’s estimates.
Dawei Fan, NYISO supervisor of public policy and interregional planning presented the report, which detailed the grid operator’s methodology in ranking more than $3 billion in proposed projects for efficiency, operability and cost-effectiveness.
The report represents NYISO’s inaugural evaluation of transmission needs stemming from public policy requirements. The ISO kicked off the process in August 2014 by seeking stakeholder input on policy-driven requirements for the system. In July 2015, the New York Public Service Commission issued an order identifying a need in western New York. (See NYISO Identifies 10 Public Policy Tx Projects.)
Lessons Learned
Several market participants raised concerns that NYISO had not provided sufficient methodology background and detail on the evaluation. Some also questioned the emissions data used in the study.
Fan said “the NYISO considered emissions in the western New York evaluation based on RGGI [Regional Greenhouse Gas Initiative] carbon price forecasts instead of social cost of carbon,” which led one participant to suggest that the PSC needs to define upcoming public policy needs.
“The worst thing we could do is dispatch on one price of carbon and then turn around and redefine the emissions cost using a different price. That is the path of stupidity,” said Mark Younger of Hudson Energy Economics.
David Clarke of the Long Island Power Authority said he would like to see detailed analytics such as the breakdown of production cost by zone, so that LIPA can determine “who will benefit” from the recommended transmission project.
NYISO officials spoke of eventually holding a session on “lessons learned” in the grid operator’s first try.
“Speaking of lessons learned, any process that takes three and a half years is broken,” said Howard Fromer, director of market policy for PSEG Power New York. He added that leaving unresolved issues that have an important effect on the market has a “chilling effect on the market.”
Most Efficient
NYISO planners have found the Empire State Line project to be the most cost-effective solution of all proposals for the region. A substation proposed for Dysinger would become western New York’s new 345-kV hub — connecting seven 345-kV lines — and help reduce the transmission distance between Niagara and Rochester.
A proposed phase angle regulator (PAR) on the Dysinger–East Stolle Road 345-kV line would provide additional operational flexibility to the system. The project still demonstrates significant benefits even when the PAR is bypassed, according to the evaluation.
NYISO cited the project’s independent cost estimate and cost-per-megawatt ratio as among the lowest of all proposals, while its production cost saving over the cost ratio is the highest across all scenarios. The evaluation found no critical risks for the line regarding siting, equipment procurement, real estate acquisition, construction or scheduling.
Monitor Approval
Pallas LeeVanSchaick of Potomac Economics, NYISO’s Independent Market Monitor, joined by phone to give a presentation showing how the Monitor found the recommended project to be “economic under a variety of conditions.”
LeeVanSchaick said NYISO identified qualitative factors not fully reflected in the quantified benefits that further support selection of the Empire State Line. While the Monitor found the ISO’s methodologies to be sound, it did point out several enhancements to consider in future public policy transmission evaluations, including:
Incorporating additional priced and unpriced benefits of new transmission projects into a single benefit/cost metric;
Factoring non-capital costs and life-cycle capital costs into the benefit/cost metric;
Developing tariff provisions allowing developers to take on the risk of project cost overruns;
Modeling entry and exit decisions for generators in a manner consistent with the expected competitive market outcomes;
Refining assumptions for future operation of key plants in New York based on latest available information;
Modeling variability resulting from loop flows around Lake Erie in production cost simulations;
Considering transmission outages and other unforeseen factors in estimating production cost savings; and
Enhancing the quality of natural gas and emission allowance price forecasts.
The committee recommended that the Board of Directors approve the project. If the Management Committee also recommends approval this month, the report will be delivered to the board in October.
SACRAMENTO, Calif. — State legislation that would regionalize CAISO and mandate 100% zero-carbon retail electricity sales statewide by 2045 sputtered with just days left in the legislative session and will not pass this year, a key legislator told RTO Insider on Wednesday.
State Assemblymember Chris Holden (D), who sponsored two bills that would regionalize CAISO, said he plans to go forward with the regionalization effort next year. His main vehicle for regionalization, AB 726, was kicked back to the Senate Rules Committee yesterday and would need to be approved by a policy committee before returning to the State Senate floor.
That won’t happen, Holden said, because it was not assigned to a committee and will not be heard. Another bill with regionalization language, AB 813, was amended last week by the Senate and referred back again to the Rules Committee.
“What we wanted to do on the regionalization piece is make sure there was legislative review of whatever came out of a committee evaluation,” said Holden, who chairs the Assembly Utilities and Energy Committee. “We wanted that committee to be unanimous. The strategy was then to move to the legislature where people who represent all parts of California had a chance to sign up and speak. It is big legislation, and we wanted to make sure everybody had a say in it.”
Both bills also contain a provision that would require California electricity sellers with more than 100,000 customers to procure “tax-advantaged” renewable generation above that required by the state’s renewable portfolio standard and recover costs from retail ratepayers. The measure is intended to encourage the development of new renewable resources within the state before the expiration of federal production tax credits in 2020.
Holden said his focus initially was taking advantage of expiring tax credits on wind and solar, and there were also concerns in the geothermal community.
“Regionalization was introduced into the conversation around the bill, which I had no problem with doing, as long as it was broken into two pieces — multiple pieces — so it’s not like ‘here’s what we’re going to do and we are cutting everybody out,’” he said.
Independent Energy Producers Association CEO Jan Smutny-Jones said that regionalization would make it easier to export excess solar from California and allow access to lower-cost renewables around the West.
“Obviously, we have spent a lot of time on these issues this year. It’s unfortunate that we couldn’t quite get it out of the legislature this first year, but we look forward to working on it when we come back in January,” he said.
The ISO has allowed for more efficient use of transmission, and the same would be true with regionalization, Smutny-Jones said.
“From a market efficiency perspective, it will work a lot better,” he said. He noted that the Western Energy Imbalance Market (EIM) is working well on a regional basis, but it is only a five-minute market and does not allow day-ahead transactions like a full ISO.
CAISO itself also favors regionalization. It did not return a request for comment as of press time.
The zero-carbon bill, SB 100, introduced by Senate President pro Tempore Kevin de Leon and widely anticipated by the renewable energy community, faces strong headwinds, according to Holden. (See California Zero-Carbon Power Bill Advances.)
Of SB 100, Holden said, “That is not going to move — there is overwhelming opposition to it. And there is not time to work that out.” He is hoping to integrate the various proposals so there is “a global fix to everything. But we are out of time.”
MISO is recommending a new version of a transmission project intended to alleviate constraints in the West of the Atchafalaya Basin (WOTAB) area straddling Texas and Louisiana, but some stakeholders are balking at assumptions underpinning the proposal.
The $129.7 million project involves construction of a new substation in eastern Texas equipped with a 500/230-kV transformer. The facility would accommodate a new 500-kV line running from Hartburg, Texas, as well as a reconfiguration of the existing Sabine-McFadden and Sabine-Nederland 230-kV lines. The expanded voltage is expected to fully relieve area congestion and reduce the amount of voltage and local reliability make-whole payments needed in the WOTAB load pocket.
New WOTAB Project | MISO
“We’ve looked at this project every which way … and this is robust and cost-effective, even under conservative assumptions,” said Arash Ghodsian, MISO manager of economic studies.
Flowgate Oversight
An earlier $137.6 million proposal called for a new 500-kV line from Hartburg to Sabine and an expansion of two existing substations. That project was identified in MISO’s annual Market Congestion Planning Study, which this year focused exclusively on possible MISO South projects.
After local transmission owner Entergy increased a flowgate rating in March, the project no longer met the 1.25 benefit-cost ratio required to qualify as a market efficiency project for this year’s MISO Transmission Expansion Plan. While TOs can increase or decrease line ratings without permission from MISO, they must update facility ratings with the RTO.
MISO initially overlooked the spring flowgate rating change. The RTO waited until July to model that change and study three project alternatives, eventually settling on the revised 500-kV proposal. Some stakeholders objected to last month’s last-minute unveiling of possible projects, noting that the Board of Directors reviews MTEP projects in early December.
Two other smaller projects resulting from the Market Congestion Planning Study — also in the WOTAB load pocket — were unaffected by Entergy’s flowgate change. (See Congestion Projects, Siting Review on MISO Slate.)
Last-minute Concerns
Xcel Energy expressed concerns about MISO’s decision to change the modeling and weighting of MTEP futures for the study after having developed and approved the study’s supporting models and initially identifying congestion in the area. While stakeholders last year agreed on the relative weight of MTEP futures in planning studies, the RTO allowed a unique weighting for MISO South after the region’s TOs and state regulators asked for reduced emphasis on a future scenario involving accelerated alternative technologies. (See MISO Changes MTEP Futures Weighting for South.)
Xcel said that MISO — in the spirit of openness — should have reopened the planning study’s project submission window after changing the weighting.
“Without reopening the entire development process and reopening the window after the new models and weights were decided, MISO set a very concerning precedent which introduced gaming of the study results by allowing this unacceptable change to happen without a sufficient level of stakeholder involvement,” Xcel said in comments filed with the RTO.
NRG Energy also cautioned MISO against making last-minute modeling changes.
“New or changes in modeling assumptions can be requested at the beginning of each Market Congestion Planning Study cycle,” the company said in comments. “However, last-minute modeling changes should not be allowed unless they are necessary to correct gross errors. Otherwise, this would set a dangerous precedent and the process could well become a ‘free-for-all’…
“All modeling changes should be thoroughly vetted in the stakeholder process for approval and implementation.”
‘No Process is Perfect’
Ghodsian said the new project has been subject to open and transparent vetting despite the change in modeling criteria. Other stakeholders, including DTE Energy, LS Power, Apex Clean Energy and ITC Holdings, supported MISO’s analysis behind the project alteration.
Apex said it’s clear that the load pocket needed a high-voltage project to mitigate voltage and local reliability issues.
“The transmission system needs expansion. Lack of high-voltage solutions for WOTAB has inhibited growth in an area of the country which has seen unrivaled increases in petrochemical manufacturing in addition to the production and export of LNG,” Apex said.
Some stakeholders did take issue with MISO modeling a $1,000/MWh emergency energy price in the study when it currently caps prices at $3,500/MWh. Entergy’s Matt Brown called for aligning the emergency pricing in the models for MTEP 17 with the RTO’s actual cap.
“We can’t just continue to kick this can down the road. … This issue has been with us for a while now, and at some point, we have to address it,” Brown said.
Ghodsian said MISO will address new emergency energy pricing in the models starting with MTEP 18.
“No process is perfect, and we welcome suggestions on improving [it],” Ghodsian said.
The three projects arising from the Market Congestion Planning Study will go before the board’s System Planning Committee next week and the Planning Advisory Committee later this month.
The Illinois Commerce Commission on Monday conditionally approved Ameren Illinois’ request to lower the utility’s energy-efficiency goals established under the state’s recently enacted Future Energy Jobs Act.
The commission’s approval came despite extensive pushback from consumer and environmental nonprofits — who accused Ameren of attempting to bypass efficiency targets — and a preliminary ruling from an administrative law judge denying the requested change (17-0311).
| Ameren Illinois
The judge last month issued a preliminary order rejecting the utility’s plan, saying Ameren could shift money and priorities around to meet its annual energy savings goal while staying within the law’s budget cap. (See State Could Reject Ameren Illinois Efficiency Target Reset.)
Still, the commission approved Ameren’s plan despite its relatively high costs for each unit of energy saved. Under the plan, Ameren expects to spend 32 cents/kWh saved, compared with the 21 cents/kWh saved for residential customers and 13 cents/kWh for business customers during 2016.
Critics had wanted Ameren to squeeze more energy savings out of the $114 million per year the utility has allocated to the program, but the commission agreed with the company that the “unique circumstances” of its “largely rural” service territory — in which many customers are exempt from the efficiency provisions — made it difficult to achieve higher savings.
The proposed measures “promote the objectives of the statute,” the ICC found.
Conditions Apply
The commission’s approval also came with some strings attached.
“Ameren Illinois’ request for approval of modified goals is conditionally granted, provided that the company present to the commission, as a compliance filing, amendments to its plan design that provide additional annual savings that will assist more Ameren Illinois customers,” the ICC said in its ruling.
Among the conditions: Ameren will be required to attend at least three workshops hosted by commission staff where “stakeholders may offer proposals to aid Ameren Illinois in achieving statutory savings goals” in future plans. Commission staff will make a report following the workshops.
The commission also said it will reassess Ameren’s goals and performance after a year and required that the utility donate any performance incentives from meeting its modified savings goals to nonprofits that assist low-income communities with energy-efficiency measures.
“By proposing to donate any performance incentives it might realize, Ameren Illinois satisfactorily addresses any concern that it is attempting to profit by manipulating savings goals so that it will be certain to achieve them,” the commission said.
Under the Future Energy Jobs Act, Ameren is required to meet 9.8% in cumulative annual energy savings by 2021, but the utility is planning for 8.24% in savings. The utility had allocated $114 million per year for the program, the maximum budget under the law, but it claimed it still could not meet the savings goal. A maximum budget triggers the ICC’s authority to reduce annual incremental savings goals.
Ameren said it remains committed to achievement of the agreed upon savings target of 13% by 2025.
“Based on our initial understanding of the order, we are in agreement with the commission on many points. Our innovative energy efficiency plan will result in customer cost decreases,” Ameren Illinois spokesperson Marcelyn Love told RTO Insider.
Rehearing?
The Environmental Defense Fund said it would seek a rehearing on the issue after learning of the decision, citing the ALJ’s preliminary order. EDF, the Natural Resources Defense Council and the Citizens Utility Board “provided numerous suggestions for Ameren to meet its efficiency goals and provide maximum savings to a greater number of customers,” EDF said.
“Ameren is abandoning its energy-efficiency commitments, meaning fewer customers will get help lowering their energy bills, and those who do will be saving less. … The decision robs people in Central and Southern Illinois of the cleaner air, lower bills and clean-energy job opportunities they were promised by the Future Energy Jobs Act,” said EDF’s Christie Hicks.
The Illinois Clean Jobs Coalition also expressed disappointment with the order, saying the ICC disregarded the opinion of its own ALJ.
“Ameren’s plan to scale back savings from energy-efficiency services will prevent people in Central and Southern Illinois from reaping the same benefits that people in Chicago and Northern Illinois will receive under the Future Energy Jobs Act,” the coalition said. “Disadvantaged communities should be prioritized for investments, and we believe that Ameren can and should also provide the same quality of services.”
Last-minute legislation that would transform CAISO into a new regional system operator appeared to stall in the California State Senate yesterday after being kicked back to the Rules Committee.
Lawmakers drew criticism this week for moving ahead with legislation close to the end of the session that could spur the process of regionalizing CAISO starting in late 2018. The regionalization language was inserted late last week into two bills sponsored by State Assemblymember Chris Holden (D), chairman of the Assembly Committee on Utilities and Energy, which held a June hearing to look at CAISO expansion. (See California Lawmakers Take Up CAISO Expansion.)
One bill, AB 726, was amended on the Senate floor and essentially became a new bill that now requires waiver of procedural rules to be reviewed by a policy committee and then sent back to the Senate for a vote. But time is short, with the legislative session ending Friday and a heavy volume of other legislation under consideration before the legislative deadline. Similar language was inserted into a separate bill, AB 813, which was sent back to Rules Committee on Sept. 8.
The legislation could set in motion a dramatic restructuring of CAISO — an expansion that has been discussed since 2015 — by requiring the ISO’s Board of Governors to develop and approve governing documents for a new RTO by Oct. 31, 2018.
The nature of Tuesday’s amendments is not yet clear, but the proposal as written would create a Commission on Regional Grid Transformation, charged with determining whether the new governance structure adheres to principles set out in the legislation, including:
Acknowledging and preserving state authority over matters traditionally regulated by the participating states, such as resource procurement, resource adequacy, utility planning and “other policy issues,” including those related to greenhouse gas emissions;
Allowing participating transmission owners (PTOs) to withdraw from the RTO, including at the behest of a state of local regulatory authority; and
Creating a process to transform the current board into a new, independent board.
The bill also stipulates the creation of committees drawn from CAISO stakeholders to advise the new ISO governing board. They would include representatives from each state with a PTO under CAISO control, TOs, transmission-dependent utilities, publicly owned utilities, consumers, environmental groups, exempt wholesale generators, emerging technologies and labor organizations.
The governance structure would not become effective until getting approval from the transformation commission, which will consist of representatives from the governor’s office, the legislature and state agencies. The commission must issue its decision by Dec. 31, 2018.
If the commission approves the expansion, the bill would void existing provisions on the formation of ISO advisory committees, the adoption of transmission maintenance, repair and replacement standards, requirements that the ISO conduct performance reviews following certain major outages, and establishing the Electricity Oversight Board.
Opponents warned that the proposed law dilutes California’s role in controlling its energy future and subjects the state to more oversight from President Trump’s appointees at FERC. While regionalization would help the state export excess renewable generation stemming from its aggressive carbon reduction policies, it would also bring coal-fired generation operated by PacifiCorp into a market that would not be governed by California entities.
The Consumer Watchdog group on Monday issued an open letter to state senators, referencing the Western Energy Crisis of 2000/01 that led to gaming, blackouts and skyrocketing electricity costs.
“In this last week of session, Gov. [Jerry] Brown is asking you to take the first steps toward a similar bargain with an even more pernicious devil, Donald Trump and other billionaires with power to sell, much of it dirty,” the group said in the letter.
The Utility Reform Network, which represents retail ratepayers, tweeted: “Is CA going to give away its energy future again? We’ve barely recovered from deregulation, [why] give away control to FERC and Warren Buffet?”
PacifiCorp, one of the holdings of Buffet’s Berkshire Hathaway Energy, and other out-of-state sellers already participate in CAISO’s Western Energy Imbalance Market (EIM), which does not function as an ISO.
Brown moved to delay regionalization last summer in the face of opposition both within and outside California, but earlier this year he reaffirmed that ISO expansion could help the state address climate change. (See Gov. Brown Reaffirms Commitment to Expanded CAISO.)
AB 726 was originally written to require utilities with smart meters to provide automated alerts and notifications regarding energy usage and billing to retail customers unless they opt out, while AB 813 initially included now-deleted language regarding education.
Both bills also contain a provision that would require California electricity sellers with more than 100,000 customers to procure “tax-advantaged” renewable generation above that required by the state’s renewable portfolio standard and recover costs from retail ratepayers. The measure is intended to encourage the development of new renewable resources within the state before the expiration of federal production tax credits (PTCs) in 2020.
While sponsors of the measure acknowledge that new renewable builds are not needed in the state over the next few years because of existing surpluses and expected RPS compliance among load-serving entities, they pointed to a California Public Utilities Commission finding showing that the state will save $633 million over the long term by allowing renewable developers to take advantage of the PTC.
ISO-NE Vice President for External Affairs and Corporate Communications Anne George gave a presentation on the grid operator’s role in implementing Order 1000, along with updates on the RTO’s preparations for Forward Capacity Auction 12, the Integrating Markets and Public Policy (IMAPP) initiative and its 2018 budget.
Vermont Gov. Phil Scott also addressed the Sept. 7 meeting of ISO-NE’s Consumer Liaison Group.
Here are the highlights of what we heard.
Order 1000 and Public Policy Tx Projects
In April, the D.C. Circuit Court of Appeals rejected separate challenges by New England Transmission Owners and state officials to Order 1000, including FERC’s elimination of federal rights of first refusal (ROFR) for incumbent transmission owners and one aspect of the public policy transmission planning process. (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)
Jason Marshall, general counsel for the New England States Committee on Electricity (NESCOE), said during a panel discussion that the ruling on the public policy process, while denying the petition, had “at least provided what we wanted: a ruling that ISO New England does not have to choose a public policy project as part of the Order 1000 process.”
The court also ruled that “ISO-NE has no role in setting public policy for the states.”
Liaison Group Chair Rebecca Tepper, chief of the energy and telecommunications division in the Massachusetts attorney general’s office, brought up the transmission projects proposed in response to the Massachusetts solicitation for 9.45 TWh a year of Class I renewables (wind, solar, hydro or energy storage). (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
“What’s confusing to people is that none of these projects are ‘public policy’ projects that have gone through the Order 1000 process,” she said. “People are trying to understand what kinds of projects these transmission projects are [under the FERC Order 1000 construct] and who’s going to pay for them.”
Marshall responded that if a transmission project arises out of a state-run request for proposals, it would be one of two types. “It could be a public policy upgrade, which has to go through the Order 1000 process. Alternatively, it could be an elective transmission upgrade, and that’s a separate category that’s not regionalized, not socialized across New England to all consumers. That’s the difference.”
Colin Owyang, general counsel of Vermont Electric Power Co. (VELCO), said he believed that the Massachusetts projects were mostly outside the three categories. “I think of the public policy upgrades as regional public policy decisions, so if there were a New England governing body … and if they were to collectively agree on a mutually acceptable public policy, then it would go through the [Order 1000] process.”
Owyang said that states may have believed that if they went through FERC’s process, they would lose control of projects. As a result, he said, that’s why he thinks they run their own RFPs “over on the side.”
Developer Balancing Act
New England Clean Energy Power Link | Transmission Developers Inc.
VELCO negotiated the compensation to Vermont — a total of $136 million spread evenly over 40 years — for the New England Clean Power Link, which includes a submarine cable under Lake Champlain and a smaller overland section connecting with a substation in Ludlow. Transmission Developers Inc. has fully permitted the project to bring 1,000 MW of hydropower, solar and wind from Canada with its partner, Hydro-Québec. The Vermont section of the line is 154 miles long.
Another developer, Stephen Conant of Anbaric, asked how developers could justify making Massachusetts residents pay a “tax” to Vermont for letting energy cross the latter state. Owyang said he would not put it so “flippantly,” calling the payments fair compensation and a necessary cost of doing business.
“As a developer, what you have to balance is how do you get your project developed [and] how do you get it built on time,” added TDI CEO Donald Jessome. “There’s going to be costs, whether those are capital costs or operating costs, property taxes — you could go down a whole laundry list of different issues that you have to take into account. Ultimately, if the benefits don’t outweigh the costs of the project, you’re just not going to go forward.
“There are going to be costs, there are going to be community issues and we have to take all of that into account,” Jessome continued. “If we priced it wrong, we will lose the [Massachusetts] RFP.”
Mary Ellen Paravalos, vice president for ISO, siting and compliance at Eversource Energy, also appeared on the panel moderated by Guy Page, communications director of Vermont Energy Partnership.
Gov. Scott said that one in 16 workers in Vermont are employed in clean energy, the highest ratio of any state in the U.S., he said.
“We’re going to need all those workers and all that knowledge because we have a goal of getting 90% of our energy needs from renewable resources by 2050,” he said. “As daunting as that might sound, I believe it’s achievable.”
Scott highlighted how investments in clean energy are also changing the state’s electric grid, which frequently sees its lowest net load in the middle of the afternoon because of the amount of solar on the system. The peak hour is now after sunset, once the solar resources stop producing.
As the state encourages people to switch to electric vehicles, the resulting increase in electrification calls for smarter load management and rate design, partly “to ensure that we don’t increase peak demand or make the Northeast less competitive than it already is in terms of rates,” Scott said. “Also, when we talk about changes in how people consume power, we need to be certain we aren’t hurting the most vulnerable. We can’t have regressive policies that add costs onto people who can’t afford to pay, or hurt folks who are working third shift, for instance, and can’t change the timing of their electrical usage.”
Scott said that while modernizing the grid and how people use electricity, planners shouldn’t ignore more traditional resources such as baseload hydroelectric. Vermont has a long history of working with Hydro-Québec, he noted.
“We first started importing power from Quebec in the late 1980s through Highgate, Vt.,” Scott said. “A few years later we hosted the first DC line into New England from Quebec through the Northeast Kingdom of Vermont [Essex, Orleans and Caledonia counties], and through to northwestern New Hampshire. We now have a number of companies looking to use Vermont as a conduit to transfer more power from Quebec to help our friends and neighbors in Massachusetts. And as unbelievable as this may sound to anyone who has done work in this state, Vermont has already fully permitted one of those projects, TDI’s Power Link.”
Scott said that TDI worked with host communities and “now enjoys significant support in our state and a clear path to construction. In my view, the Clean Power Link is a smart, common sense and very affordable solution for Massachusetts and New England. It provides economic and environmental benefits for both states, and it shows how a region can work together to accomplish energy goals.”
Stakeholders will have 15 days to comment on ISO-NE’s reorganized transmission planning guide, which will reduce the existing guide’s more than two dozen sections to four. It will be organized like a transmission needs assessment or solutions study report: Introduction; Modeling Assumptions; Reliability Criteria and Guidelines; and Analysis Methodology.
Lead engineer for system planning Steve Judd, who presented the new guide to the ISO-NE Planning Advisory Committee on Wednesday, said the need for the reorganization became apparent when staff found it difficult to identify the proper section for adding a new probabilistic methodology for creating base case dispatches.
Since the guide’s creation in 2013, Judd said, new information was added as additional sections at the end of the document. As a result, the current guide’s 26 sections are “in no cohesive order,” he said.
The new methodology (section 2.2.2 of the revised guide) aims to develop a “same-probability” curve to describe the combined likelihood of certain levels of load and generation unavailability.
Planners will use the curve to determine the representative amount of generation in megawatts to be modeled as out of service in the transmission needs assessment for the study area. Instead of modeling a particular number of generators out of service, the new concept models a representative quantity of generation as being unavailable.
Planners based the load level probability on the most recent capacity, energy, loads and transmission (CELT) forecast and 17 summer weeks of distribution curves.
The 15-day comment period will be triggered when the guide is posted, Judd said.
Stakeholders Seek Briefing on SOARES
Analysts conducting ISO-NE’s 2017 System Operational Analysis and Renewable Energy Integration Study (SOARES) will brief PAC stakeholders at a future meeting, Director of Regional Planning and Coordination Michael Henderson said.
ISO-NE’s System Operational Analysis and Renewable Energy Integration Study (SOARES) will address the reduction in traditional thermal generation that provide inertia and other reliability services, such as regulation, ramping and reserves. | Thayer School of Engineering at Dartmouth
Stakeholders requested the briefing by professor Amro M. Farid and his team at the Thayer School of Engineering at Dartmouth after Henderson reviewed the SOARES scope of work Wednesday.
ISO-NE spokeswoman Marcia Blomberg called SOARES “a key element” of Phase II of the 2016 New England Power Pool Scenario Analysis/Economic Study, which is focused on regulation, ramping and reserves. The study will address the reduction in traditional thermal generation that provide inertia and other reliability services.
No date has been set for the briefing. The SOARES project is expected to be completed by the end of the year.
Eversource Spending $22.7M to Replace 3 Transformers
Eversource Energy presented its plans to replace three aging transformers at a cost of a cost of about $22.7 million.
Eversource Director of Transmission System Solutions Bob Andrew said the three are among eight General Electric transformers aged 30 to 45 years in its system, half of which have shown significant deterioration. One, at Scobie Pond, N.H., was replaced after it failed in March following a short-lived refurbishment. Two new units will replace transformers at Littleton and Deerfield, N.H. In addition, a new spare transformer will be purchased to replace one that took the place of a fourth aging unit.
Cost allocation for the new transformers will be subject to review by the RTO’s Reliability Committee, Andrew said.
The four transformers’ internal insulation had deteriorated, resulting in the formation of methane and ethane in the transformers’ oil. Eversource will monitor the remaining four GE units for future trouble.
Andrew said the RTO has discussed the issue with GE. “The response was typical of the [original equipment manufacturer] with 30-year-old equipment: ‘Of course, you should buy one of our new transformers and replace it.’”
CAISO’s Department of Market Monitoring on Friday amplified its opposition to a fundamental aspect of the ISO’s plan for mitigating market power in generators’ commitment costs.
The department told the Market Surveillance Committee on Friday that it “fundamentally disagrees” with the Commitment Cost and Default Energy Bid Enhancements (CCDEBE) initiative. The program, which CAISO Senior Market Policy Developer Cathleen Colbert outlined in a presentation, is designed to better reflect unit commitment costs and overhaul how the ISO calculates the default energy bid (DEB) used for units with market power.
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The Monitor had previously raised concerns with the CCDEBE proposal, which would apply to both the ISO and the Western Energy Imbalance Market (EIM). (See CAISO Monitor Says Bid Rule Changes Flawed.)
The debate has large financial implications for EIM power sellers subject to default bidding, such as Berkshire Hathaway Energy entities PacifiCorp and NV Energy, which last month asked FERC to lift their DEB restrictions. (See Berkshire Companies Request EIM Rate Authority.) The restrictions also apply to Arizona Public Service.
“We think there are a lot of questions left on the dynamic mitigation,” the department’s Michael Castelhano said. The Monitor has urged splitting the proposal into two parts and getting a new process for reference levels in place by fall 2018. Then commitment cost bidding and mitigation could be addressed “in a more robust way than we have been able to do so far,” Castelhano said.
The ISO has suggested it will use a static competitive path assessment (CPA) on a seasonal basis to determine which constraints should be tested for commitment cost market power. In other CAISO proceedings, stakeholders have proposed eliminating the CPA because it is designed for the seasonal level and not a daily or hourly market.
The static CPA often fails to capture market power for commitment costs, which potentially has more financial impact than missing market power for energy costs, Castelhano said. “You will never get the models right,” he told ISO officials.
“Conceptually, we would support the opposite approach,” he said, which would assume the paths are competitive unless proven otherwise. “We really think that is the right thing to do in this situation.”
“We think it is really important that this is vetted and [discussed] in the stakeholder process,” Castelhano added. He said it appears the ISO is adapting energy market mitigation methods for commitment costs.
Energy market mitigation has to do with the effect of market power on LMPs, while commitment cost mitigation asks how different constraints affect the likelihood of a resource to be committed, he said in the presentation. “You are not starting with the right question,” he told ISO officials.
CAISO says its goal is to submit the proposal to the EIM Governing Body for an advisory vote on Oct. 10 and to the Board of Governors for approval on Nov. 1.
ERCOT’s latest resource adequacy forecasts project the Texas grid will have sufficient installed generating capacity this fall and winter, despite the destruction wrought by Hurricane Harvey.
Pete Warnken, ERCOT’s manager of resource adequacy, said staff studied several scenarios that could affect the availability of generating resources. The results were favorable.
“[We] do not currently anticipate any systemwide issues,” Warnken said in a statement Thursday. “Even in the most extreme scenarios considered, there were ample operating reserves.”
The fall seasonal assessment of resource adequacy (SARA) report shows nearly 86 GW of capacity available for a predicted peak demand of just over 56 GW. The final fall SARA, covering October and November, includes 3 GW of new generation added since the preliminary report in May.
Exelon accounted for 2.2 GW of the new generation, adding gas-fired combined cycle units at plants near Houston and Dallas. More than 837 MW of new wind and solar resources are expected to contribute 374 MW to covering the fall peak, based on capacity factors.
The preliminary winter SARA report projects a record peak of more than 61 GW, beating ERCOT’s all-time record of 59.7 GW, set in January. The report, covering December through February, anticipates almost 85 GW of capacity being available.
ERCOT will release the final winter SARA in early November.
Harvey Restoration Efforts Continue, but Numbers Down
ERCOT said last week that while Hurricane Harvey’s restoration efforts will continue for an “extended period” in some areas, the number of affected transmission facilities and generation resources has decreased considerably since the storm hit the Texas Gulf Coast on Aug. 25.
The ISO said Friday that one 345-kV line still remains out of service. However, the grid has remained stable and the competitive markets have continued to operate normally, it said.
Most of the remaining outages are in Rockport and Aransas Pass, where the storm’s eye made landfall. AEP Texas said 15,000 of its remaining 16,600 outages were in the Rockport-Aransas Pass area as of Friday afternoon. The utility said it may take an “extended amount of time” to reconnect power to some homes and businesses damaged by Harvey.
CenterPoint Energy said about 3,200 customers remained without power in the Houston area Friday afternoon. The utility has been forced to route power from a flooded distribution substation to a nearby temporary substation in west Houston.
Most of CenterPoint’s customers without service live near the overloaded Barker Reservoir. The U.S. Army Corp of Engineers has been releasing water to save the reservoir’s structural integrity.
Entergy reported about 2,300 customers out of service in Southeast Texas as of Friday afternoon.
Southern Cross Offers Suggestions for its Market Participation
Stakeholders on Thursday discussed potential definitions and market participant categories during a workshop for the Southern Cross Transmission Project, which could become ERCOT’s first merchant DC tie operator.
The ISO does not currently include DC tie operators as market participants, but the project’s developer is working to define language that would allow the proposed DC tie with the Eastern Interconnection to take part in the market. The HVDC transmission project would be capable of shipping more than 2 GW of electricity between the Texas grid and Southeastern markets.
“There’s a way to do this that would probably make sense,” Cratylus Advisors’ Mark Bruce said, speaking for Southern Cross Transmission (SCT). “We have a bunch of boxes that Southern Cross can’t check [on the market participant agreement form]. [The tie] doesn’t serve load, [and] it doesn’t buy or sell energy. ‘DC tie operator’ would describe the function we’re registering for. We think that’s a good place to start.”
The project would link ERCOT to the Eastern Interconnection through a 345-kV line, owned by Garland Power & Light, that connects with a convertor station just across the Louisiana border. SCT would build a 400-mile, 500-kV DC line to connect with Southern Co.’s existing 500-kV system in Alabama.
SCT envisions ERCOT qualified scheduling entities (QSEs) buying capacity on the line similar to how they do on the ISO’s existing five DC ties. The company would not participate in the settlement process, but the QSEs would. Southern Cross would not have a Texas tariff or collect transmission rates, leaving the QSEs responsible for paying transmission service charges for use of the ERCOT system.
“Users of the Southern Cross line are going to pay for this equipment in the capacity charge. ERCOT ratepayers aren’t going to be paying for any of this,” Bruce said.
He suggested protocol language for a DC tie operator as a market participant that “has completed applicable registration and approval for the purpose of operating a DC tie interconnected to the ERCOT transmission grid.” Bruce also drafted bylaw language for a definition of an independent DC tie operator, suggesting it be any transmission and distribution entity or affiliate that “owns or operates” a DC tie interconnected to ERCOT’s grid or is “preparing to own or operate” such a tie.
Bruce said SCT would fit best in ERCOT’s investor-owned utility segment. He pointed out the company is investor-owned and a “public utility” under the Federal Power Act, although not under Texas law. Its only function in ERCOT is operating a high-voltage transmission facility, he said.
ERCOT staff will now work with SCT to develop and submit the appropriate revision requests to the Protocol Revisions Subcommittee for its November meeting. Market participants were invited to provide feedback and input from the workshop, along with other comments for consideration prior to sponsoring the appropriate revision requests.
The Public Utility Commission of Texas opened a pair of dockets for the SCT proposal. Docket 45624 approved Garland P&L’s application for the 345-kV line, which has an established route. Project 46304 establishes the PUC’s 14 directives for integrating and operating the project as a part of the ERCOT system and within its market construct.
Southern Cross obtained final FERC 210/211 orders and agreements in 2014 for interconnection to and transmission service in ERCOT that maintain its FERC jurisdictional status quo.
Developers hope to begin construction in 2019 and commercial operation in the third quarter of 2022. They are working to obtain a siting certificate for the line’s Mississippi portion from the state’s Public Service Commission. Louisiana does not require a siting certificate.
