FERC last week approved CAISO’s agreement for integrating Canadian power marketer Powerex into the Western Energy Imbalance Market (EIM) (ER17-1796).
According to the Sept. 7 order, the ISO is working with Powerex to develop a participation framework that addresses the company’s unique situation as a Canadian entity. Powerex is the marketing arm of provincially owned BC Hydro, a generation owner and transmission provider that operates under the jurisdiction of the British Columbia Utilities Commission.
Powerex markets BC Hydro Generation such as the 2,480-MW Revelstoke Dam
“CAISO explains that BC Hydro will not assume a participant role or undertake commercial activities in the EIM,” FERC said. “However, CAISO states that BC Hydro will supply certain data and information directly to CAISO that is needed for Powerex’s participation.” CAISO is developing a data sharing agreement for that purpose.
FERC staff last month provided qualified approval for Powerex’s EIM implementation agreement but cautioned the plan could be subject to further scrutiny after restoration of the commission’s quorum. (See Wary FERC Approval for Powerex EIM Agreement.) Powerex, which currently markets power across the U.S. and as far south as Mexico, brings the EIM increased access to about 17,000 MW of generating capacity, about 12,000 MW of which is hydro.
Powerex is slated to join the market in April 2018 and will pay a fixed implementation fee of $1.9 million, a figure based on the company’s portion of the estimated $19.6 million CAISO would incur if it were to reconfigure its real-time market to incorporate all balancing authorities in the Western Electricity Coordinating Council.
Southern California Edison, Pacific Gas and Electric and other EIM participants raised concerns about provisions in the implementation agreement that could require modification to include participation by additional parties, as well as potential changes to the EIM framework needed to integrate the company into the market.
FERC said those concerns are “premature, given that CAISO and Powerex have not yet developed or proposed the specific terms and conditions of the framework under which Powerex will participate.”
“We expect CAISO to follow through with its commitment to consider the issues raised by commenters and to engage in outreach and dialogue with interested stakeholders as the framework is developed,” the commission said.
The participation agreement framework will allow voluntary offers from residual BC Hydro generation, intra-hour deviations in load and generation in the BC Hydro balancing authority area and transmission arrangements to support EIM transfers.
SEATTLE — The Western Energy Imbalance Market (EIM) Governing Body on Wednesday approved a CAISO proposal allowing market participants to take part in a program that models generator outages and the impact of remedial action schemes (RAS) on market operations.
The current market structure only addresses cases in which a transmission line goes down, potentially causing overflow on other lines. The new method reflects how the system will react to the loss of generation, CAISO Manager of Market Policy Design Brad Cooper said at the Governing Body meeting.
“It should result in a much more efficient market solution than just using offline tools and manual actions,” Cooper said, and be “more efficient and transparent as to what is happening.” The CAISO Board of Governors will vote on the rule changes later this month, after reviewing a more comprehensive package that would bring the measures into the ISO’s day-ahead market. The changes must also be approved by FERC.
The ISO currently uses manual, out-of-market dispatches to manage generator contingencies and RAS, which are protective processes that automatically disconnect generators or load in order to prevent transmission line overload in the event that another line goes out. The new method will update the ISO’s security constrained economic dispatch by modeling the loss of generation within the dispatch, as well as modeling the loss of transmission and generation because of RAS operations. The program effectively incentivizes generator participation in RAS.
“The proposed changes result in an update to the congestion component of the locational marginal price so that it considers the cost of positioning the system to account for generator contingencies and remedial action scheme operations,” the ISO said in its final proposal. “A remedial action scheme-connected generator will potentially receive higher energy prices than generators not connected to a remedial action scheme at the same bus because a remedial action scheme-connected generator does not contribute to binding emergency limits.”
CAISO says the new method will better reflect congestion in localized prices and improve generator dispatch.
Allowing EIM entities to model generator contingencies and RAS falls within the Governing Body’s “primary” approval authority, while it approved the general design of the proposal under its “advisory” capacity. CAISO’s Market Surveillance Committee and Department of Market Monitoring support the new program.
Southern California Edison expressed concerns over what it considered to be the anomalous effects of the changes on CAISO’s interconnection process — but that would not apply to EIM entities not subject to that process, Cooper said.
“We disagree with Southern California Edison in any case,” regarding the effects of the new functionalities, he said.
Governing Body Chairman Doug Howe asked if the modeling would be totally voluntary and queried Cooper as to the trade-off between the benefit and cost of the proposal.
“That is something we consider in everything we develop,” Cooper said. “We are convinced that the benefits justify the costs.” He confirmed the program is voluntary and is part of larger improvements to market operations.
SEATTLE — Western Energy Imbalance Market (EIM) resource sufficiency tests are generally working, but fluctuating load forecasts are a major challenge in passing the tests, market participants said in a regional forum Thursday.
Participants in CAISO’s regional EIM market must pass a series of resource sufficiency tests, including a balancing test for energy, a capacity test and a flexibility ramping test. Market participants discussed possible enhancements at the Regional Issues Forum held in conjunction with the EIM Governing Body meeting the day before.
The forum meets three times a year and includes 10 representatives from various sectors who discuss topics outside of the normal ISO stakeholder process. The sectors include transmission-owning utilities; power producers and power marketers; public interest groups; publicly owned utilities; and neighboring balancing authorities.
The EIM is integrated with CAISO’s market but only includes the ISO’s real-time functionality and not that for the day-ahead market. The sufficiency test is one of a series of processes meant to ensure that EIM entities have sufficient generation to supply the real-time market in the absence of providing day-ahead schedules. (See CAISO: Don’t Lean on EIM for Capacity.) The ISO performs the test ahead of the market run for each operating hour.
While the general structure of the resource sufficiency framework is sound, it could be enhanced, said Powerex trading manager Mike Goodenough. Powerex does not yet participate in the EIM but is slated to join next April. FERC on Thursday approved the company’s implementation agreement for joining the market, which was first conditionally approved by FERC staff in August. (See Wary FERC Approval for Powerex EIM Agreement.)
Goodenough said the level of required resource sufficiency should not be changed because different balancing authority areas (BAAs) have different capacity and flexibility challenges. Raising the requirement might increase costs for entities that don’t have surplus capacity, and decreasing it might reduce flexibility costs but remove opportunities to sell capacity and energy.
The workability of the program could be improved, and “we think we should work toward getting more transparency and metrics around those tests,” Goodenough said.
Possible improvements include adjusting the timelines of the tests so entities know their specific requirements and can obtain needed capacity or flexibility. There are questions as to whether some BAAs are failing in hours when they should have passed, and others are passing when they should have failed, he said. He suggested more granular data from CAISO and historic analysis by the Department of Market Monitoring on whether the required quantities have been consistent with demand and imbalance requirements in BAAs.
Arizona Public Service’s EIM project manager Moe Sakkijha said his utility worked with CAISO to address the fact that the ISO’s load forecasts can fluctuate up to 300 MW. APS in June also began providing the ISO with hourly load forecasts to assist in modeling. CAISO has agreed to freeze the load forecast to help with the resulting uneconomic dispatch, Sakkijha said, but he is not sure when the ISO plans to implement the change.
“A very important issue for the EIM entities was freezing of the load forecast,” he said. APS is also bidding solar and wind resources into the EIM to improve the results for the sufficiency tests for capacity, balancing and flexibility. The company is working with some utility scale solar sources to be able to automatically respond.
Kathy Anderson, Idaho Power system operations leader, said that her company has not begun participating in the EIM but already has some concerns. (See Idaho Power Inks Agreement to Join Western EIM.)
“A lot of conversations with the entities that are live [in the EIM] give me some concerns, especially when we start talking the moving target of the load, and chasing that,” she said. Idaho Power has hydro, wind, natural gas and coal, but a lot of EIM resources will be non-run-of-river hydro.
Idaho Power also plans to have one coal plant and some natural gas participate in the EIM, but not its wind and solar. The hundreds of megawatts of wind and solar in its BAA under Public Utility Regulatory Policies Act contracts can only be dispatched for reliability. Hydro flexibility limitations because of fish protection requirements and other regulations at its 1,400-MW Hells Canyon facility will be one challenge in passing resource sufficiency tests, and the plant is also affected by seasonal challenges, and regulations.
The changing load forecast is a big issue, she said, and “it is hard enough to be a balancing authority without continually chasing a number just to pass the test,” she said.
SPP stakeholders last week endorsed a proposed interregional project to be developed in partnership with MISO, despite the project’s dim prospects.
The Seams Steering Committee unanimously agreed with staff’s recommendation to endorse the $5.2 million Split Rock-Lawrence project in South Dakota, identified through the interregional process. It would have been the RTOs’ first-ever interregional project, but staff told the Planning Advisory Committee last month that it no longer recommended moving forward with the initiative. (See SPP Glum as MISO Axes Last Interregional Project.)
| MISO & SPP
MISO said its latest analysis of the project indicates the congestion on the 115-kV line is still manageable and that an alternative project could provide the RTO with at least the same benefit at a lower cost.
“It seems odd to endorse a project when we don’t have a partner,” said Jeff Knottek, director of transmission planning and compliance for City Utilities of Springfield, Mo., during the committee’s Sept. 6 conference call.
“We were aware we could come down on different sides on this,” said Adam Bell, SPP’s interregional coordinator. “We didn’t come to a point knowing MISO’s decision until we were done with a majority of the analysis.”
GridLiance’s Bary Warren, who chaired the meeting, said the RTOs’ coordinated study process identified a good project “from the SPP and MISO perspective.”
“MISO stakeholders don’t agree this is the best solution,” Warren said. “From SPP’s perspective, it appears this is a better solution for both RTOs.”
David Kelley, SPP’s director of interregional relations, said the South Dakota project could surface again in a future study. However, SPP’s Tariff prevents the RTO from approving an alternative interregional project other than the one that advanced from the interregional study out of a regional review.
“We’re recommending to you what we feel we’re obligated to do under the process,” he said.
Staff Prepping Response to AECI Project’s Protests
SPP staff is preparing comments due to FERC on Sept. 12 in response to protests lodged by Xcel Energy Services and Westar Energy over a proposed interregional project with Missouri-based Associated Electric Cooperative Inc. (See “Board Reaffirms Seams Project with AECI,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
Last month, the RTO filed with FERC the terms and conditions of a cost-sharing and usage agreement among SPP, AECI and Springfield, as well as Tariff changes that would regionally allocate costs to the RTO’s transmission customers (ER17-2257).
The $13.75 million project involves installing a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield.
Westar asserts a lack of transparency regarding SPP and AECI’s cost-sharing methodology and their negotiations.
Xcel protested the proposed allocation of the Morgan transformer’s costs, noting the project is outside SPP’s footprint and being allocated to members on a regional load-ratio share basis. It also says SPP’s filings do not justify “a departure from the cost allocation methodologies” currently stipulated by the RTO’s Tariff.
SPP Sends MISO $1.2M for M2M Settlements
SPP sent MISO $1.2 million in market-to-market (M2M) payments for June congestion on flowgates along the seam between the two RTOs. The payments reduced the net amount of settlements SPP has collected from MISO to $20.5 million — as of June — since the two began the process in March 2015.
| SPP
Temporary flowgates accounted for most of the congestion, binding for 214 hours, 32% less than the month before, and resulting in almost $1.2 million in M2M settlement charges to SPP. Permanent flowgates were binding for 27 hours, giving MISO an additional $59,339.
More than half of the M2M settlements came over a MISO flowgate in northwest Iowa near the Nebraska and South Dakota borders. SPP was unable to commit enough generation during low-wind periods to compensate for outages in the area, resulting in 23 hours binding and $676,332 in charges.
FERC has rejected a MISO plan to shorten the number of days allowed to customers negotiating a generator interconnection agreement during the interconnection queue process.
The commission on Thursday ruled that MISO did not provide “sufficient support” for Tariff revisions that would have required that GIAs be negotiated and executed within 90 days, down from the current 150 days (ER17-1728). Negotiation and execution represent the last steps in the RTO’s interconnection queue process, occurring after impact and feasibility studies have been completed.
FERC said MISO failed to demonstrate that the shorter agreement process would give interconnection customers sufficient time to sort out final details on new generation projects.
In its filing with FERC, MISO said that, after the commission’s January acceptance of a leaner 460-day interconnection queue (ER17-156), the RTO realized that it also must “proportionally” reduce the amount of time allotted to crafting and signing GIAs — or risk exceeding the new queue timeline by about two months.
“Without reducing this piece of the timeline, the [generator interconnection process] will last for 520 days instead of 460,” MISO claimed.
The RTO had sought approval to pare down all three queue stages, with negotiation cut from 60 days to 45; execution of a customer agreement reduced from 60 days to 30; and transmission owners given 15 days to sign off on an agreement instead of 30 days.
MISO had argued that the 460-day timeline approved by FERC “specifically contemplated a reduction in the [agreement] negotiation and execution timeline from 150 days to 90 days.”
The commission responded that a diagram proposing a general, 90-day agreement process was only attached to testimony in the queue reform changes, and not reflected in MISO’s Tariff changes. FERC also said its approval of the new queue process hinged on shortening the definitive planning phase of the queue — where restudies most often occur — and did not focus on altering the interconnection agreement process.
MISO’s filing framed the changes as “limited revisions … to improve and clarify the language implementing the commission’s recently approved interconnection queue reforms.” But FERC responded that the RTO’s characterization of the filing as merely a “cleanup” filing to reflect Tariff revisions was incorrect.
Several MISO members — including multiple wind developers — protested the shorter deadlines, arguing that the RTO was attempting to put the entire onus of a shorter queue on interconnection customers while making no sacrifices itself. Those members pointed out that they have already agreed to increased financial milestones and shorter time frames to review the results of system impact studies, and that MISO should now focus on shortening the timeline it gives itself to conduct studies during the definitive planning phase. The wind developers also said MISO is already failing to implement the more streamlined queue, with a backlog similar to that which dogged the old queue process now threatening the 2020 commercial operation deadline imposed on developers seeking the production tax credit.
Other members said the back-to-back 60-day negotiation and execution periods are crucial because that’s when facility costs are finalized and the companies obtain board approval of the project.
MISO last month told stakeholders to prepare for imminent delays while it studies an unprecedented influx of prospective projects that last year entered the queue. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)
MISO also asked FERC for permission to give interconnection customers fewer days in which to modify their selected level of network resource interconnection service so that any change did not occur after the conclusion of the final system impact study. FERC did not address the proposed change in its decision to reject the RTO’s broader proposal.
FERC last week granted East Kentucky Power Cooperative an exemption from being required to purchase power from Public Utility Regulatory Policies Act qualifying facilities larger than 20 MW — but not in time for the cooperative to avoid such purchases from two solar projects within its territory.
The 1978 federal law requires that utilities — including municipals and cooperatives — purchase electricity from QFs at the utility’s “avoided cost.” QFs were defined as cogenerating plants and small power producers under 80 MW. FERC Order 688, issued in October 2006, granted utilities the ability to disregard the requirement for QFs over 20 MW if they can prove the facilities have nondiscriminatory access to the wholesale markets. As a PJM member, EKPC argued that QFs in its territory have that access.
EKPC CEO Tony Campbell speaks in May at the ground-breaking for a 60-acre solar farm on EKPC’s headquarters property in Winchester | EKPC
FERC agreed, but it declined to backdate the approval far enough for EKPC to avoid contracting with two solar projects.
“Until a utility applies for termination of the PURPA mandatory purchase obligation, and the commission grants such application, a QF has the statutory right to pursue a contract or other legally enforceable obligation with that utility,” FERC said.
The 80-MW Bluebird Solar and 60-MW Blue Jay Solar projects notified EKPC in December and March, respectively, of their intention to sell their entire output to the cooperative at the avoided cost rate.
EKPC argued that it first requested an exemption from the PURPA rules last November, which would have relieved the cooperative of any responsibility to buy from the solar projects. However, the commission’s lack of a quorum earlier this year caused the request to languish and eventually be denied by FERC staff once its 90-day time frame for action had passed.
The cooperative refiled the request on June 9, arguing that the effective date for the exemption should start from the November filing because it was reasonable to believe that FERC would have approved it with a quorum.
The commission rejected EKPC’s argument and set the effective date for June 9.
ALBANY, N.Y. — NYISO stakeholders on Wednesday offered broad support for incorporating a $40/ton carbon charge into the ISO’s markets, but some expressed concern over how the costs of New York’s decarbonization effort would be allocated.
The comments came at a Sept. 6 public hearing jointly run by NYISO and the New York Department of Public Service (DPS).
Both New York Public Service Commission Chair John Rhodes and NYISO CEO Brad Jones, who opened the hearing, signed off last month on a much-anticipated Brattle Group report on pricing carbon into generation offers and energy clearing prices. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)
Brattle’s Sam Newell presented a summary of the report, saying more than 90% of the increased energy costs could be offset through carbon rebates to customers, reduced prices for renewable energy credits and zero-emission credits (ZECs), and improved investment signals. The report predicts the net impact on customer electric bills will be between a 1% reduction and a 2% increase.
Scott Weiner, DPS deputy for markets and innovation, said the plan being developed by his agency, the ISO and the New York Energy Research and Development Authority envisions fossil fuel generators incurring a penalty based on carbon emissions levels. The carbon adder idea was prompted by the PSC’s decision to subsidize the state’s nuclear plants through ZECs.
Jones noted that New York hopes to implement the plan in the markets within three years, a time frame that Weiner called reasonable. Weiner said officials will have a clearer picture in January, after additional outreach.
As first steps, Weiner said, the DPS would seek stakeholders’ comments on, and alternatives to, Brattle’s proposal by Nov. 1. NYISO and the department will hold a series of technical conferences on the issue, with the first likely to be held around Thanksgiving, he said.
“The exact format has yet to be determined, but we have zeroed in on two topics. One is the issue of borders and seams … and the second topic is revenue allocation,” Weiner said.
During the hearing, Mark Younger of Hudson Energy Economics contended that the Brattle report understated the volume of expected offsets. Brattle did not account for the New York Power Authority, “which has a lot of green resources also [selling] a fair amount of generation at market prices,” he said.
The Brattle report concluded that a $40/ton carbon charge would raise energy prices by approximately $19/MWh on a load-weighted average basis, but that after accounting for static energy price offsets, net customer costs would rise only $6/MWh.
| The Brattle Group
“And so, this is a source of revenues, certainly to the state, that could be used either to reduce taxes or to be rebating people, but that’s not included anywhere in [the report’s] estimate of savings and offsets against this $19/MWh cost,” Younger said.
“As we get rid of net metering, we end up with a value stack, and part of the stack is a credit for CO2 savings,” he said. “And obviously the more the market represents the CO2 savings, the less you have to essentially subsidize this behind-the-meter stuff, and that would be another savings because that would bring an out-of-market payment more directly into the market, and that’s not captured anywhere.”
While Newell conceded Younger’s “good point,” he said Brattle’s goal was to make reasonable assumptions in the middle of the range of predicted outcomes.
| The Brattle Group
Kelli Joseph, director of New York market and regulatory affairs for NRG Energy, pointed to the major challenge of the state trying to achieve a variety of goals through different methods. Among them: RECs, ZECs, the Clean Energy Standard and Reforming the Energy Vision.
“And is the $40 price sufficient to not only handle ZEC, but get 50% renewable and achieve whatever the REV goals are?” she asked.
Matthew Schwall, director of market policy and regulatory affairs for the Independent Power Producers of New York, referred to FERC’s interest in price formation, a subject brought up at a May technical conference on harmonizing public policy with wholesale markets. (See NYISO Sees Carbon Adder as Way to Link ZECs to Markets.)
“FERC is looking for guidance,” Schwall said. “Would it be possible for NYISO to work through its stakeholder process to come up with a conceptual filing to submit to FERC — prior to any Tariff filing, prior to coming to a complete market design — in order to get some guidance from FERC?”
NYISO Chief Information Officer Rich Dewey responded that in May the commission said that any proposal would require “a great deal of stakeholder support” to be successful.
Dewey (left) and The Brattle Group’s Sam Newell
“And we want to have the most thoroughly vetted design before we go down to FERC,” he said.
Weiner added, “Importantly, nobody should assume that FERC is not aware of what we are doing here today and going forward. The DPS staff and NYISO staff have ongoing conversations with FERC staff, so they’re well aware of this process, and I think it’s fair to say they’re encouraged by it.”
David Clarke, director of wholesale market policy for the Long Island Power Authority (LIPA), questioned the allocation of carbon costs, saying they might be disproportionately borne by consumers in southeastern New York.
“Right now, everyone has a pro rata share of REC requirements,” Clarke said. “LIPA takes on a proportional share of those renewable energy requirements. … Those collections are going down because the costs of the RECS are going down, but the collections from locational-based marginal prices are going up because you’re [reducing] carbon. Those effects are not remaining in the same proportion and they have different effects for downstate New York than for upstate.”
Newell said New York may want to consider allocating carbon revenues evenly to make up for the non-proportional impacts.
“The total wholesale cost, if it goes up about $20/MWh times about 150 TWh, that’s about $3 billion in total wholesale costs, and then the carbon fund is about half of that, or about $1.5 billion,” Newell said. “The incidence of who’s seeing prices increase more or less is not even, and that is why you might want to consider [proportional rebates],” Newell said.
Weiner said the topic of revenue allocation is key. “How do you divide it up? Is there a way to reconcile these competing interests? The status quo is the status quo, but maybe that’s not the best way, either.”
Stuart Nachmias, Consolidated Edison’s vice president for energy policy and regulatory affairs, said “markets have worked well in meeting the reliability needs of customers in the state but haven’t yet incorporated clean energy goals.”
The capacity markets address reliability, and Con Ed spends a lot of time trying to figure out how the energy market price impacts the capacity market, Nachmias explained. “And more importantly, how does that affect the resources we need for reliability to manage a variable future?” he said.
Dewey said reliability is always the grid operator’s first concern.
“The reality is there’s a lot more renewables coming onto our system, so we need to look at what changes might be necessitated in our existing market products and our existing capacity markets, energy markets or ancillary services to be able to accommodate that grid in the future,” he said.
Nuclear Power not ‘Clean’
Manna Jo Greene, environmental action director for Hudson River Sloop Clearwater, said, “I implore you not to use the word ‘clean’ when talking about nuclear energy. I ask you to think about the communities who had the benefit of the goose that laid the golden egg for so many years and are now faced with massive amounts of high-level radioactive waste.”
Jessica Azulay, program director at Alliance for a Green Economy, echoed Greene’s view and suggested that the DPS and NYISO consider a charge on other greenhouse gases, such as methane.
Erin Hogan, of the New York Department of State’s Utility Intervention Unit, asked if Brattle could share the study’s spreadsheet model, which might help the formation of independent proposals. Weiner said he didn’t want to put Newell “on the spot … but I think that’s a very good point.”
Hogan said she knew people had different perspectives: “Those who don’t want combined cycle, those who don’t want nuke, and there’s those who don’t want transmission, but they want the emissions to go down. The reality is … the most challenging part is to maintain reliability, and the other part is to achieve the environmental goals, and the third part is trying to do this in the most cost-effective way possible. … I’m asking people to come at it with a pragmatic perspective. Often people look at it as if we’re going to optimize to achieve the perfect evolved frame. I think what we really do is choose the least imperfect solution.”
When Consolidated Edison last year canceled a decades-old arrangement with Public Service Electric and Gas to wheel 1,000 MW of power from upstate New York to New York City via northern New Jersey, the move appeared to free up transmission capacity in the northeast corner of PJM. (See NYISO Members OK End to Con Ed-PSEG Wheel.)
PJM stakeholders are finding out that’s not so.
The cancellation forced operational changes that caused PJM to remodel phase-angle regulator (PAR) flows along the New York-New Jersey border — and along the PJM-NYISO seam — that will reduce transmission limits and increase the region’s LMPs. (See “‘Wheel’ Replacement Reduces Transmission Limits,” PJM PC/TEAC Briefs: Aug. 10, 2017.)
The modeling changes eliminate non-firm transmission service from the capacity emergency transfer limit (CETL) calculation and specify that adjacent non-PJM areas are not available to supply non-firm energy. In practice, the changes only affect operations along the NYISO interface, PJM’s Mike Herman acknowledged. PJM’s recent analyses as part of its Regional Transmission Expansion Plan have not indicated that external support is needed in any other region within its footprint, he said.
Con Ed subsidiary Rockland Electric objected to the revisions during an Aug. 30 educational session hosted by PJM. Rockland serves about 61,000 customers in northern New Jersey as part of Con Ed’s Orange and Rockland Utilities subsidiary just across the New York border.
“It’s very understandable that you wouldn’t want to over-rely on [the PARs] to the extent that you had under the status quo,” Con Ed’s Diana Barsotti said. “We still oppose the deletion of language [in the manual] that has to do with modeling such support that may be reasonably expected in the future.”
Barsotti requested a manual revision that provides a link to information about firm service interchanges.
Stakeholders had been confused by PJM’s changes to CETL values posted in February and had asked the RTO to explain what alterations it made beyond eliminating non-firm imports.
PJM’s Jonathan Kern acknowledged stakeholder concerns but said he was confident the “more conservative” recent assumptions are the most reasonable and don’t depend on the same “extreme mathematical optimization” that the February numbers do. The new calculations also account for resource diversity, resource retirements and PAR-adjustment coordination.
“We’ve been planning the system for decades using a certain set of assumptions and it’s taken us six months to hone in on what we feel is the best approach, so there were some growing pains,” Kern said. “We decided it would be more realistic, practical and conservative from a PAR perspective to more closely align with how New York is planning their system and PJM is operating our system.”
“There must be some number that can come in [through the PARs] in an emergency,” said Dean Bickerstaff of Hartree Partners. “Even though I know you don’t want to count on New York from a planning perspective, the real world would suggest there is some. … The market isn’t just retiring resources up there [in New York]; it’s adding resources as well. So to the extent that we would be good neighbors to them, I’m sure they would be good neighbors to us.”
Herman clarified that PJM isn’t planning to remove non-firm service from its capacity import limit (CIL) calculations.
“The inclusion of non-firm service is intrinsic to the CIL calculations,” he said. “Utilizing a combination of firm transmission service as well as the non-firm energy purchase allows the CIL test to properly identify physical system limits. In PJM’s analysis and experience, firm transmission service alone may not be enough megawatts to hit a physical limit. The purpose of this test is to identify what that physical transmission limitation is.”
WASHINGTON — President Trump’s nominee for FERC chair brought little comfort to Republican senators seeking assurances that, under his leadership, the commission would look into shoring up uneconomic coal plants.
“FERC is not an entity whose role includes choosing fuels for the generation of electricity,” Kevin McIntyre, cohead of law firm Jones Day’s global energy practice, said at his Senate Energy and Natural Resources Committee confirmation hearing Thursday. “FERC’s role, rather, is to ensure that the markets for the electricity generated by those facilities proceed in accordance with law.”
McIntyre was responding to a question from Sen. John Barrasso (R-Wyo.), who asked if he agreed with acting Chair Neil Chatterjee’s belief that so-called baseload power — coal and nuclear plants — needed to be “properly compensated” to recognize their value to “reliability and resilience.” (See Coal Seeks ‘Resiliency’ Premium; FERC ‘Fuel Wars’ Coming?)
“I think, overall, the FERC’s role should be to take a hard look at these very important questions and determine where FERC’s jurisdiction actually gives it a role in making decisions that could ensure that there’s a proper attention to the reliability and resilience impacts of what is traditionally thought of as baseload generation,” he said.
Later, Sen. Angus King (I-Maine) urged McIntyre to “just go with the science” when it came to baseload generation, expressing concern that the term had become politicized.
“FERC does not pick fuels among different generating resources,” McIntyre responded. “And so it’s important that it be open to, as you say, the science, which I would expand somewhat also to include the characteristics of reliability and the characteristics of economics.”
The other nominee being considered for the commission, Richard Glick, echoed McIntyre’s position. He told Barrasso that a recent U.S. Energy Department study of the electric grid determined that the loss of baseload generation had not impacted reliability, “but they also suggested it was something to keep an eye on and look for in the future.”
“So I think both FERC and the Department of Energy need to keep an eye on it and continue to study the matter,” said Glick, currently general counsel for the Democrats on the Senate committee.
The committee devoted less than half of the two-hour hearing to McIntyre and Glick, as it also considered two nominations to the Interior Department: Ryan Nelson to be solicitor, and Joseph Balash to be assistant secretary for land and minerals management. The committee’s senators — some hailing from states with large swaths of federally owned land and sizable Native American populations, such as Alaska, Arizona, Nevada and New Mexico — had plenty of questions for the two Interior nominees about policies important to their constituents.
The two FERC nominees, on the other hand, found themselves declining to provide specific answers to many questions, citing ongoing proceedings and Notices of Proposed Rulemaking before the commission. Those questions covered issues such as price formation in energy markets, and eliminating barriers to distributed energy resources and energy storage.
Several Democratic senators asked the nominees about states’ rights in enacting renewable portfolio standards. After discussions with the Interior nominees about her home state, Sen. Catherine Cortez Masto (D-Nev.) asked McIntyre and Glick for quick, yes-or-no answers to her questions.
“Do you agree that states have the authority to establish the resource mix that best serves their customers?” she asked, to which the nominees responded in the affirmative.
She also asked if they agreed that renewable resources can be reliably integrated. Glick noted that several states get at least half of their electricity renewables and that none have had any problems.
“In part due to actions taken by the FERC, renewable energy resources are making their way reliably to our grid,” answered McIntyre.
Noting her state’s adoption of a zero-emission credit program, Sen. Tammy Duckworth (D-Ill.) asked if they agreed that states were “the appropriate place for these types of policies to be decided.”
“We do have a federal system of law,” McIntyre responded. “FERC has its role and the states have theirs, and there’s no question that the states have the absolute right to implement these renewable portfolio standards.”
Committee members refrained from addressing some of the more controversial issues brought up during the May confirmation hearing for Chatterjee and Commissioner Robert Powelson — such as climate change and the Public Utility Regulatory Policies Act. (See No Fireworks for FERC Nominees at Senate Hearing.)
Duckworth did ask about FERC’s role in securing a cleaner environment. Both nominees asserted that FERC is not an environmental regulator, while also noting that the commission ensures that clean resources have nondiscriminatory access to the markets and that it is seeking to better integrate DER, storage and demand response.
Committee Chair Lisa Murkowski (R-Alaska) told reporters after the hearing that she hopes to advance McIntyre and Glick to the full Senate “late next week.” Their confirmation would restore FERC to a full, five-member slate — which it has been without since the departure of Philip Moeller on Oct. 30, 2015.
WILMINGTON, Del. — Sempra Energy moved a step closer to acquiring Texas utility Oncor after a U.S. bankruptcy judge on Wednesday approved the $9.45 billion agreement (14-10979).
The deal would give Sempra an 80% stake in the rate-regulated operations of the largest transmission and distribution utility in Texas. The deal must still be approved by the Public Utility Commission of Texas.
The utility has been the subject of a series of failed takeover bids since parent Energy Future Holdings, saddled with almost $50 billion in debt after poor bets on energy prices, declared bankruptcy in April 2014.
EFH announced the deal with Sempra three weeks ago in the same Delaware courtroom, after hedge fund Elliott Capital Management — the largest holder of EFH bonds — opposed as too low a $9 billion all-cash offer by Berkshire Hathaway Energy. Including debt, Berkshire’s bid valued Oncor at $18 billion, while Sempra’s values the utility at $18.8 billion. (See Sempra Outmuscles Berkshire for Oncor.)
‘Largely Consensual’
“Unlike any proposal we’ve had in the past, this proposal has the support of one of the debtors’ largest and most active creditors,” Chad Husnick, an attorney representing EFH, told Judge Christopher Sontchi. “The Sempra transaction is the highest and best available transaction.”
Husnick said the Sempra deal was “largely consensual” and prompted just one objection regarding how creditors would be compensated, a consideration that Sontchi said should be reserved for a confirmation hearing. That hearing would take place after the PUCT approves the deal.
“We’ll try it again,” Sontchi said in approving the documents, drawing laughter from the courtroom.
Sempra said it is committed to ensuring that Oncor remains independent, financially strong and based in Dallas with local management.
“Oncor is a well-managed, top-tier utility, operating in one of the strongest U.S. growth markets. We believe it will be an excellent strategic fit with our portfolio of utility and energy infrastructure businesses, while opening up a new avenue for our long-term growth,” Sempra CEO Debra Reed said in a statement after the hearing.
The acquisition would allow Sempra to regain a foothold in Texas, where it once owned and operated 10 power plants and still maintains a 200-person Houston office to support marketing and development activities. (See Sempra Begins ‘Listening Tour’ of Key Stakeholders.)
| Sempra Energy
With the approval in hand, EFH set an Oct. 30 voting deadline for its plan. EFH approved the deal in part because Sempra was willing to accept ring-fencing of Oncor — giving it independence from its corporate parent — and no assurance that it will get control of the 20% of Oncor now owned by Texas Transmission Holdings Corp.
Sempra is the fourth would-be suitor for Oncor. Dallas’ Hunt Consolidated and Florida-based NextEra Energy saw separate bids fall apart in the face of the Texas PUC’s calls for strict ring-fencing measures and a requirement that Oncor be run by a “truly independent” board with control over decisions on capital expenditures and operating expenses.
NextEra Termination Fee Battle
Wednesday’s hearing also addressed EFH’s upcoming legal battle with NextEra, which had offered $18.7 billion for Oncor but failed to win approval for the deal from the PUCT. EFH accused NextEra of failing to do its best to receive approval and sued the former suitor earlier this year to prevent any attempt by NextEra to claim the deal’s $275 million termination fee. The trial is set to begin next April.
EFH filed for Chapter 11 protection in 2014 with roughly $42 billion in debt, which was then the eighth-largest bankruptcy in U.S. history. About $25 billion of the debt has been restructured by spinning off subsidiary Texas Competitive Electric Holdings, which split the company in half.
