New Jersey Democrats last week introduced a reworked version of a nuclear bail-out bill that didn’t come to a vote in the state legislature’s recent lame-duck session.
NJ Senate President Steve Sweeney (D)
The bill, submitted Thursday by New Jersey Senate President Steve Sweeney and Sen. Bob Smith, is supported by Public Service Enterprise Group, the operator and majority owner of the Salem and Hope Creek nuclear generating stations.
NJ Senator Bob Smith (D)
The senators introduced the bill a day after the Associated Press reported that it had obtained records showing that PSEG lobbyists worked with the administration of former Gov. Chris Christie (R) to strengthen language in the earlier version of the bill meant to keep the company’s financial information confidential. That version, which would have provided upward of $300 million annually to nuclear operators, failed when Speaker of the General Assembly Vincent Prieto declined to post it for a vote earlier this month. (See NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)
PSEG said the language was standard and intended to protect proprietary information, but the revelation intensified criticism that the company’s nuclear plants don’t need subsidies to continue operating. PSEG has said the plants will become unprofitable within two years and that it will have to close them, putting thousands out of work and eliminating a zero-emission source of energy that produces 40% of New Jersey’s power.
Sweeney said the new legislation requires PSEG to show the need for the subsidy, which could cost each New Jersey electric ratepayer $41 per year. To address concerns by Gov. Phil Murphy that the previous version didn’t boost the use of renewable energy, the bill also includes provisions for energy-efficiency standards and solar energy credits, and would give neighborhoods a new way to invest in solar projects. The bill would also create a financial assistance program for offshore wind projects.
A controversial provision of the bill would prevent New Jersey’s Division of Rate Counsel from taking part in proceedings to determine whether the subsidy for the plants is necessary. Smith said the division is only allowed to participate in proceedings involving regulated companies, and the subsidiary of PSEG that operates the nuclear plants isn’t regulated by the state. Stefanie Brand, who directs the division, said it would have to be involved in proceedings involving the plants, or they would be “a sham.”
The earlier version of the bill was expected to be voted on in committee Thursday, but Sweeney moved back the vote to Feb. 5 to give interested parties more time to review the measure.
The Assembly has not taken any action on the bill.
Murphy Signs Order to Start Bringing State Back into RGGI
Murphy on Monday signed an executive order directing the heads of the Department of Environmental Protection and Board of Public Utilities to begin negotiations with states in the Regional Greenhouse Gas Initiative to determine the best way for New Jersey to rejoin it.
Christie had taken the state out of the regional cap-and-trade program, which caps the amount of carbon dioxide emissions for each state and requires power plants in each state to buy allowances, either through auctions or on the secondary market, for the carbon dioxide they emit.
Participating states use revenue from the auctions for energy efficiency and renewable projects. An analysis by Acadia Center found that New Jersey had foregone $232 million in RGGI auction revenue since Christie pulled it out of the initiative in 2011.
WILMINGTON, Del. — In a series of votes, stakeholders at last week’s Markets and Reliability Committee meeting declined to endorse any proposals to revise PJM’s capacity model, reiterating previously expressed support for the status quo.
The initial vote displayed in perhaps the most civil — and emphatic — way possible stakeholders’ disapproval of PJM’s decision to file its own changes for FERC approval instead of the plan endorsed by member committees.
At the behest of Bob O’Connell of Panda Power Funds, stakeholders postponed voting on the Tariff revisions previously endorsed by lower committees — an extension of the minimum offer price rule (MOPR-Ex) proposed by PJM’s Independent Market Monitor — to allow for members to register an advisory vote on the RTO’s proposed filing. That sector-weighted vote registered 3.93 out of 5 in opposition, definitively denouncing PJM’s plan, which would add a second stage to capacity auctions to isolate subsidized offers and subsequently revise the clearing price if approved. (See PJM Going it Alone on Capacity Repricing Plan.)
The unexpected vote came after PJM’s Stu Bresler defended the RTO’s decision and highlighted additional revisions from previous versions of the proposal, including an exemption from repricing for any generators of 20 MW or less and returning to the “net CONE [cost of new entry] times B” formula for developing subsidized units’ adjusted offers if their avoidable cost rate (ACR) couldn’t be used.
Several stakeholders critiqued the proposal.
“We’re concerned that what PJM has put on the table doesn’t quite get us there,” NRG Energy’s Neal Fitch said. He noted that his company has generally supported the two-stage repricing concept but prefers a version it proposed that would lower capacity commitments for bids that cleared in the first stage to address “in-between” units, with commitments for all resources then proportionally reduced below their offer amounts.
Carl Johnson, who represents the PJM Public Power Coalition, said the proposal goes “beyond accommodating state policies” and creates “a race to the bottom to secure state subsidies.”
“I just don’t feel like we’ve gotten” to the best option, said Greg Poulos, executive director of the Consumer Advocates of the PJM States.
“Subsidies are contagious. We think PJM’s proposal is not an adequate vaccine and MOPR-Ex is,” Monitor Joe Bowring said.
When focus returned to the MOPR-Ex proposal, proponents were left deflated by a series of failed votes. To acquire additional votes, the Monitor had previously revised the details of its proposal from the version that was endorsed by lower committees. However, PJM’s rules require a vote on the endorsed version, so stakeholders voted that down — with 3.83 opposed in a sector-weighted vote — so they could consider the revised version as an alternative proposal.
Exelon reiterated criticism of Bowring’s efforts to secure votes.
“They’re a product of wheeling and dealing to get a Section 205 filing,” Exelon’s Sharon Midgley said.
The Old Dominion Electric Cooperative and Panda received approval for some friendly amendments, but that vote failed the two-thirds threshold, with only 3.02. A vote without the friendly amendments followed, but that also failed with 3.19 in favor.
Transmission Flashpoint
Customers flexed their muscles at last week’s MRC meeting, rejecting proposed Manual 14F changes. The revisions, backed by transmission owners, would allow PJM to consider caps on construction costs when evaluating transmission proposals. A vote on the motion, which required two-thirds approval in a sector-weighted vote, instead received nearly two-thirds in opposition, gathering just 1.71 in favor out of 5.
The vote was prefaced by an alternative proposal brought by LS Power’s Sharon Segner that would require PJM to consider construction cost caps but also revenue requirement caps. Segner’s proposal garnered strong support from consumers, transmission customers and the Monitor, who urged support for any measures that increase competition.
The alternate proposal was the culmination of several months’ debate on the issue at special sessions of the Planning Committee, where proponents of additional cost-containment consideration consistently clashed with TOs, who argued that construction cost caps represented the limit of their willingness to compromise. (See “Cost Cap Discussion Continues,” PJM PC/TEAC Briefs: Jan. 11, 2018.)
Proponents of additional cost-containment provisions argue they’re used in other RTOs/ISOs, but PJM staff warned that the differences in the RTO’s proposed procedures make adding those considerations impossible. PJM’s sponsorship model allows bidders to propose innovative solutions to RTO-identified problems, whereas other grid operators’ processes define the parameters of the project and ask bidders to compete on price and innovative rate-recovery strategies.
“If we’re going to pursue this approach … we’re going to have to look at the entire competitive construct because we cannot fit that amount of evaluation into the planning cycle we have,” PJM’s Steve Herling said. “It would require, I think, a fairly fundamental structural reworking. We can certainly do that, but we cannot proceed by simply shoehorning this into our current cycle.”
TOs criticized the lateness of the alternative proposal, pointing out that the primary proposal was developed through the stakeholder process while the alternative set a precedent that members can just bring their own proposals to the MRC when they don’t get their way in the lower committees.
The primary proposal included “considerable compromise,” FirstEnergy’s Jim Benchek said, and “holding [the issue] hostage” with an alternative proposal “to restart the debate” is “both wrong and a disservice to the stakeholder process.”
State consumer advocates defended the proposal, saying the focus should be on the quality of the proposal rather than when it was filed, and criticized the primary proposal for having no mechanism to hold contractors to the construction cost caps they set.
Segner’s proposal was seconded by Erik Heinle of the D.C. Office of the People’s Counsel.
“We believe this is really in the best interest not just of our consumers but everybody in this room,” he said.
EDP Renewables’ John Brodbeck asked whether either proposal moved the ball forward on the overall goal of getting transmission projects completed faster.
“The purpose here is really to evaluate what is the right project to expand the system, so we want to encourage innovative projects without impeding innovative rate structures,” PJM’s Sue Glatz said.
Proponents of the main motion beat a tactical retreat after its defeat, calling for a deferral on the alternative motion for more discussion at the PC. Several transmission customers agreed, and members approved a motion to defer the vote until no later than May’s MRC meeting.
Resilience Definition
PJM’s Chris O’Hara asked stakeholders for comments on the definitions of “resilience” proposed by FERC and the RTO. PJM’s definition is more concise than FERC’s, but it misses some of the mitigation nuance that the commission’s includes.
The commission has ordered RTOs and states to weigh in on the meaning of resilience after it rejected the Department of Energy’s Notice of Proposed Rulemaking that would have provided price supports to ailing coal and nuclear generators.
O’Hara asked for comments to be submitted by Feb. 9 so they can be incorporated into a discussion of the issue at the Feb. 13 Liaison Committee meeting and a special session of the MRC on Feb. 23. PJM’s responses to FERC are due March 9.
Generators Performed Better During Cold Snap than 2014
PJM staff said data show generators responded better during the cold snap than the infamous cold streak in January 2014 known as “the polar vortex,” proving that PJM’s subsequent Capacity Performance changes have had their intended impact.
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The difference from 2015 to 2018 in the fuel mix of the dispatched fleet during peak winter conditions showed that nuclear rose slightly while gas and coal declined slightly. Hydro disappeared, and oil increased from 4% to 10% while wind was stable at 2%.
PJM didn’t track the fuel mix during 2014, but the 2015 numbers “were about the same,” PJM’s Chris Pilong said. “We’ve done some checks.”
| PJM
Outages also decreased from their peak periods in 2014 to 2018. Outages that peaked at 40,200 MW on Jan. 7, 2014, were cut nearly in half during the peak period during the cold snap earlier this month. Outages on Jan. 6, 2018, totaled 22,906 MW. Coal outages decreased by roughly 6,600 MW to 7,095 MW, while overall gas outages similarly dropped about 6,200 MW to nearly 12,800 MW.
PJM staff plan to push back on a recent FERC order that denied the RTO’s plan for allocating uplift costs to up-to-congestion (UTC) virtual transactions. The move, part of which could include asking FERC to temporarily prohibit UTC trading, elicited disapproval from financial stakeholders.
“We essentially believe that FERC inserted its own judgement as to what was more just and reasonable than something else,” PJM’s Bresler said. “We believe they erred in doing so.” (See FERC: PJM Uplift Proposal for UTCs Falls Short.)
PJM will be requesting rehearing on the order, arguing that FERC’s logic is flawed in determining that it’s unfair to allocate uplift to UTCs in the same way it is applied to incremental supply offers (INCs) and decrement demand bids (DECs). Once an UTC clears, Bresler said, “substantively, there is exactly zero difference.”
Because UTCs are a voluntary product, Bresler said PJM is “very seriously considering” asking FERC to suspend them until there’s an approved way to allocate uplift to them.
“We think the current situation is inequitable … and as such, we think we need to deal with that as soon as we possibly can,” he said.
Several stakeholders, including Monitor Bowring, Susan Bruce of the PJM Industrial Customers Coalition and Joe DeLosa of the Delaware Public Service Commission, supported PJM’s plan, but financial traders criticized its characterization of UTCs as voluntary.
“I think the biggest substance is PJM is thinking about terminating a product that provides benefit to the stakeholders,” DC Energy’s Bruce Bleiweis said.
“That, we believe, has not been proven at all,” Bresler responded.
Vitol’s Joe Wadsworth suggested using an uplift allocation philosophy that FERC has previously outlined.
“I think you would get a lot of support from stakeholders on something like that,” he said.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 38: Operations Planning. Revisions developed from periodic review to include protection system/relay communication outages and PJM assessment of impact.
Tariff and Reliability Assurance Agreement revisions associated with the demand response subcommittee proposal for the relevant electric retail regulatory authority (RERRA) review of energy efficiency resource participation in the capacity market. (See “Rules Endorsed for Enforcing Regulator Requirements on EE,” PJM MIC Briefs: Jan. 10, 2018.)
A problem statement and issue charge at their first reading to address how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as oil or a different pipeline. (See “Emergency Pipeline Switching Instructions Sparks Rights Debate,” PJM MIC Briefs: Jan. 10, 2018.)
Members Committee
Stakeholders Endorse Proposals
Stakeholders endorsed by acclamation the committee’s consent agenda along with several other Operating Agreement and Tariff changes:
Tariff revisions related to the procedures associated with the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
Tariff and Reliability Assurance Agreement revisions also endorsed by the MRC (see above).
FTR Revisions Approved over Financial Dismay
Members endorsed revisions resulting from special sessions on financial transmission rights issues, but not before financial stakeholders lodged one final critique. Two of the less controversial sets of revisions — to address changes to long-term FTR modeling for future transmission expansion and streamlining management of overlapping FTR auctions — were endorsed by acclamation, while the final set required a sector-weighted vote. The revisions allocating any surplus funds from day-ahead congestion and FTR auction revenue were endorsed with a vote of 3.94 in favor out of 5. (See “FTR Changes in the Works,” PJM MIC Briefs: Dec. 13, 2017.)
“Those who bear the risk of FTR revenue shortfalls should also receive the benefit of FTR excesses,” Bleiweis said. “We’re getting away from that. … We’re going to end up with another series of protests before the commission.”
Wadsworth argued that PJM would be better served by allocating more auction revenue rights to transmission customers prior to the year so they can preserve their tradeable rights, rather than “just moving money around at the end of the planning year.”
Though ‘Not Perfect,’ Incremental Auction Changes Endorsed
Members endorsed proposed revisions to the Incremental Auction process with a sector-weighted vote of 3.38 in favor out of 5. The revisions would reduce the number of IAs from three to two following each Base Residual Auction. PJM says the change will reduce the opportunities for BRA sellers to “shop” for the cheapest replacement capacity while allowing them to cure a physical inability to satisfy their commitments. (See “Incremental Auction Revisions Endorsed,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
“It’s not the perfect, from anyone’s perspective,” Bruce said, but she urged members to endorse it as a “really quite good and, in fact, just and reasonable” alternative.
FERC Commissioner Cheryl LaFleur took time from a whirlwind listening tour of the Rocky Mountain region last week to visit the Colorado Public Utilities Commission and discuss the Mountain West Transmission Group’s desire to join SPP.
Appearing Jan. 25 before the PUC’s fourth information session devoted to Mountain West’s pursuit of RTO membership, LaFleur recalled sitting in on what she said felt like the “100th meeting” of Mountain West stakeholders as they discussed the subject. SPP’s and Mountain West’s utilities are now deep into negotiations over membership, accelerating a process that began last January when the group announced its intention to join the RTO. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)
“You don’t go out on 200 dates if you’re going to break up,” LaFleur said. “There’ve been 100 since then, so it’s starting to seem pretty real.”
FERC’s most senior commissioner addressed questions from Colorado regulators, industry representatives and consumer advocates about jurisdictional issues, consumer representation in SPP and the new opportunities presented to Mountain West by recent structural developments in the Western Interconnection.
“These are exactly the kind of questions you should be asking,” she said. “There’s no time like now to ask questions of SPP, [of] the utilities that are coming to you for the authority to do this — of whomever is involved in this, because you have a critical role to play in making sure that what happens is right for the people in Colorado.”
The PUC has jurisdictional authority over Xcel Energy’s Public Service Company of Colorado and Black Hills Energy, both Mountain West members.
No Rubber Stamp
Colorado Commissioner Frances Koncilja, who has been organizing the information sessions, said she will invite CAISO, Peak Reliability and PJM to a fifth forum, in either February or March, to explain “what they think they can do for Colorado citizens.”
“This is not a decision this commissioner is going to rubber stamp,” Koncilja said. “I want to know what all the alternatives are.”
While SPP is intent on becoming Mountain West’s reliability coordinator (RC), Peak Reliability, the group’s current RC, has recently proposed to offer market services in the Western Interconnection through a joint effort with PJM. Further complicating matters, CAISO has also given 18-months’ notice that it intends to leave Peak and offer its own reliability services for half the RC’s price. (See Peak, PJM Detail Western Market Proposal and CAISO to Depart Peak Reliability, Become RC.)
LaFleur said the prospect of multiple RCs in the West will require a concerted effort by regulators and others involved to maintain the “situational awareness” developed by years of having only one.
“It will take work with multiple RCs, but I suspect if we do the work right, it can be done in the same way as we have multiple RCs in the East,” she said. “It will take some careful work to make sure the situational awareness between RCs is sustained and that everyone’s treated fairly.”
Consumer advocate Larry Miloshevich, with Energy Freedom Colorado, asked LaFleur how nonutility stakeholders could make their interests heard in the face of decisions that he said were being made behind closed doors “for reasons that are not all that clear.” Come to FERC, she replied.
“I hate to sound like a civics book, but the citizens are not unprotected. [FERC’s commissioners] are sworn to protect them. That’s our whole job. We’re not here for the utilities,” LaFleur said.
“There are probably political reasons why [Mountain West] kind of sought to be its own thing rather than being with other parts of the West, but that’s not for me to judge,” she said. “Yes, file those arguments. We’ll listen to them.”
LaFleur referred to FERC doctrine, saying the move to join an RTO “is a voluntary decision by the members who go in.” She said the commission learned this the hard way after considering a nationwide standard market design in the early 2000s.
“There was a revolution, almost coast to coast, with people saying, ‘We’ll decide who we want to sign up with, not FERC,’” LaFleur said. “FERC said, ‘If this market thing is going to take off, we’re going to let people come together and make their own decisions.’”
The commissioner extolled the benefits of RTO membership, pointing out that organized markets now cover two-thirds of the country and include regions with and without electric competition.
| SPP
“It’s worked across all different models. Why? Because you’re deploying resources over a bigger footprint, so you can run your systems more efficiently with less reserves to bring your energy to customers and hopefully keep your lights on at lower costs,” LaFleur said. “All this change, all this wind, all this solar … it’s made people stand up and say, ‘Wow, there might be something in this for our customers too.’”
It just had to grow organically in the West.
“If this came from Washington, it would be DOA. We’ve seen that through multiple attempts,” LaFleur said. “The best thing FERC could do is say nice things when invited to go somewhere but not do anything. It appears the time is approaching when we might have to do something.”
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week asked its Wholesale Market Subcommittee (WMS) to determine what went wrong during two recent market events.
On Jan. 22, ERCOT disabled the 69-kV contingencies being solved by the day-ahead market (DAM) software, with the exception of a contingency included in a real-time binding constraint during the previous 30 days. Staff issued a market notice at the time.
ERCOT’s Carrie Bivens said staff followed protocols by issuing the notice. “The alternative was aborting the DAM run,” she said.
On Jan. 23, real-time prices jumped to $5,800/MWh for 15 minutes, forcing ERCOT to deploy non-spinning reserves. Prices also exceeded the energy offer cap of $9,000/MWh during two five-minute intervals.
The ISO said it was the first time market prices reached the $9,000 price cap during two security constrained economic dispatch (SCED) intervals, pointing to ramping issues because of cold weather and higher-than-expected load around 7 a.m. Resource adequacy was not a problem, ERCOT said.
Staff’s David Maggio said ERCOT doesn’t intend to reprice the event, noting the systems were “working as expected.”
“We don’t see any issue with how things worked out,” he said.
Staff said the two events were unrelated, prompting Citigroup’s Eric Goff to respond, “They felt related to everyone.”
“The issue that caused the DAM software problem was unrelated to ramp constraining in real time,” Bivens said. “They just happened on the same operating day.”
The contingencies were restored Jan. 24 for the following operating day.
“We need a discussion at WMS, because you’re determining winners and losers when you turn off contingencies,” Morgan Stanley’s Clayton Greer said during the TAC’s Jan. 25 meeting.
The WMS next meets Jan. 31. The subcommittee will also provide real-time co-optimization training following its meeting.
ERCOT Sees 62% Drop in RUC Practices
ERCOT staff’s annual reliability unit commitment (RUC) report to the TAC last week revealed a more than 62% drop in the practice.
Maggio said that 562 instructed RUC resource-hours last year resulted in 534 effective RUC resource-hours, compared to 1,514 and 1,417, respectively, for all of 2016.
Of those resource-hours, 163 were successfully bought back, a clawback percentage similar to previous years. The total RUC make-whole amount was about $540,000, which was covered through capacity short charges.
The 534 effective RUC resource-hours were all a result of congestion (433), capacity (66) and Hurricane Harvey (35). No resource-hours were committed for ancillary service shortages, system inertia or extreme cold weather/start-up failures.
Maggio pointed to several recent improvements as causing the drop in RUCs, including reducing shadow price caps for transmission constraints from about $1 million/MWh to about $100,000/MWh and a nodal protocol revision request (NPRR744) that used a common trigger to fix the opt-out decision inconsistency between the SCED and settlements systems.
Staff and stakeholders are still working to improve both RUC functionality and transparency, Maggio said.
In other staff reports:
Assistant General Counsel Vickie Leady told stakeholders that staff have developed a definition of “affiliate” in line with the typical corporate use of the word. The proposed bylaw amendment clarifies when an affiliate relationship arises between two or more ERCOT members.
Members will be allocated almost $26,000 in resettlements from the Greens Bayou Unit 5 reliability-must-run contract, after certain costs were not fully settled before applicable true-up dates. The RMR, ERCOT’s first since 2011, was approved in June 2016 and terminated effective May 29, 2017.
Controller Sean Taylor said the ISO forecasts the system administration fee will be adequate and he “sees no need for a change” through 2019. Stakeholders had requested advance notice of any fee increases during the 2016-17 budget process.
Task Force Looks at Subcommittees’ Restructuring
Stakeholders agreed to form a task force to combine or restructure the TAC’s Retail Market (RMS) and Commercial Operations (COPS) subcommittees. The task force will begin its work Feb. 5, with the intention of reporting back to the committee for its Feb. 22 meeting.
Leadership from the two subcommittees met over the holidays and agreed on three options for restructuring them. The initiative is a result of the TAC’s annual structural review of its subcommittees and input from the Board of Directors’ Human Resources and Governance Committee.
Reliant Energy Retail Services’ Rebecca Reed Zerwas will lead the task force, after she was “‘volun-told’ to get this started.”
The RMS and COPS will continue in their current forms until a solution is endorsed by the TAC.
TAC Elects Helton Chair, Coleman Vice Chair
The committee unanimously elected Dynegy’s Bob Helton as its chairman, a position he has essentially held since September. Previously vice chair, Helton stepped into the role vacated by Adrianne Brandt, who left San Antonio’s CPS Energy to join Chair DeAnn Walker’s staff at the Public Utility Commission of Texas.
Diana Coleman, senior market specialist with the Office of Public Utility Counsel, was elected vice chair.
NPRR Clarifies ERCOT’s Jurisdictional Status Quo
The TAC unanimously endorsed NPRR861, which clarifies ERCOT can and will take all actions necessary to preserve its jurisdictional status quo and market participants with respect to FERC. Possible actions include, but are not limited to, ordering the disconnection of transmission facilities and denial or curtailment of an electronic tag.
The PUC in December instructed the ISO to draw up the NPRR over concerns that transmission projects along the U.S. border with Mexico may threaten ERCOT’s electrical separation from the rest of the country and the PUC’s exclusive jurisdiction over the Texas grid operator. (See “Fending off FERC,” Texas PUC Challenging SPP-Mountain West Intertie Costs.)
FERC’s jurisdiction is derived from the Federal Power Act, which gives the commission broad authority to regulate interstate commerce by public utilities. FERC does not have plenary jurisdiction over the ISO because the energy generated in the region is not transmitted in interstate commerce, except for certain interconnections ordered by the commission that do not give rise to broader jurisdiction.
The committee also unanimously endorsed six other NPRRs, a system change request (SCR) and a nodal operating guide revision request (NOGRR):
NPRR819: Removes language referencing “data errors” for resettlement of the DAM and real-time market (RTM); gives the ERCOT board authority to direct a DAM resettlement parallel to its authority to direct an RTM resettlement; removes references to undefined “declarations” of resettlements; changes the thresholds that determine a resettlement; and fixes a semantics error.
NPRR841: Determines in real time the day-ahead make-whole payment by incorporating the ancillary services infeasibility charge, approved with NPRR782, into the payment’s analysis.
NPRR842: Defines a “study area” as an ERCOT-designated “geographic region,” separate from a weather zone or load zone, used primarily for study purposes.
NPRR844: Corrects the current process of including capacity that is modeled but not yet commercially operational in the outage scheduler, which is then reflected in the outage report.
NPRR852: Creates a more efficient approval process when updating the congestion revenue right activity calendar; removes unnecessary “advisory approval” language; and moves the calendar’s approval from the TAC to the WMS.
NPRR855: Clarifies the criteria for including new and retiring resources in the seasonal peak average capacity estimation calculations used for ERCOT’s Capacity, Demand and Reserves report. The revisions apply to wind, solar, DC ties, hydro and all-inclusive generation resources within private-use networks.
NOGRR169: Aligns the guide’s language with NERC Reliability Standard PRC-002-2 (Define Regional Disturbance Monitoring and Reporting Requirements) to determine required locations for NERC-required disturbance monitoring equipment. This relieves the burden on facility owners to adhere to two vastly different requirements for the same purpose.
SCR794: Updates how the SCED limit is calculated by the Transmission Constraint Manager to consider how the megavolt-ampere flows compare to actual limits.
Montana regulators last week found themselves at the center of yet another court case regarding the rates offered to the small solar producers — this one stemming from a 2016 decision to suspend those rates at the request of the state’s largest utility.
Cypress Creek Renewables filed suit in the U.S. District Court for Montana alleging that the Public Service Commission’s action violated the Public Utility Regulatory Policies Act by denying solar developers the right to earn the PURPA rates in effect when they originally committed to sell their power to NorthWestern Energy.
Cypress Creek construction site | Cypress Creek Renewables
Under PURPA, utilities like NorthWestern are obligated to purchase electricity from qualifying facilities at avoided-cost rates that reflect a utility’s own cost to build new generation. The federal law leaves it to each state to determine both the rate and when a legally enforceable obligation (LEO) begins, barring any conflict with FERC regulations.
In November, the Montana PSC voted to reduce the standard PURPA contract length from 25 to 15 years and cut the energy rate available to renewable energy projects up to 3 MW from $66/MWh to $31/MWh.
But that move came after the PSC voted to allow NorthWestern to suspend its PURPA rates in June 2016 after the utility complained that the rates exceeded its avoided costs for new generation. The PSC grandfathered in facilities that had completed their agreements with NorthWestern prior to the June 16, 2016, date of the order but added the stipulation that QFs must have obtained interconnection agreements before that date to earn the previous rates.
In its lawsuit, Cypress Creek says that 13 of its solar projects that had not obtained interconnection agreements by that date are still entitled to receive the old purchase rate and contract length.
“PURPA further requires that state energy regulators like defendants recognize that, where a QF unequivocally commits to sell its output to a utility, it establishes a ‘legally enforceable obligation’ on the part of the QF to sell, and on the part of the utility to purchase, the QF’s output at the utility’s avoided-cost rate, calculated at the time the obligation is incurred,” the company wrote.
Cypress Creek also argues that at a June 9, 2016, Montana PSC hearing, NorthWestern acknowledged it was obligated under federal law to enter into long-term contracts for the 13 projects under Montana’s previous PURPA rate.
The company’s argument relies on a 2016 FERC declaratory order that found the Montana PSC violated PURPA by requiring QFs to have power purchase agreements and interconnection agreements with utilities to create a LEO, finding that the arrangement give utilities too much control over when the obligation occurs. (See FERC Declares Montana QF Requirements Illegal.)
The Montana PSC maintains that its LEO standard is still state law and has called FERC’s order nonbinding unless it is upheld by a district federal court.
“The petitioners are essentially trying to enforce FERC’s declaratory order in which the [commission] took issue with the piece of the Montana PSC’s legally enforceable obligation test, which required a qualifying facility to obtain a signed interconnection agreement,” said Montana PSC Communications Director Chris Puyear. “Importantly, FERC said nothing of the commission’s decision to suspend the rate and contract terms available to qualifying facilities up to 3 MW in size.”
Puyear pointed out that the rate available to QFs is voluntary and can be suspended at any time.
Still, the PSC disagrees that Cypress Creek had a LEO to the old contract terms on the 13 projects, as the complaint argues.
“The commission’s standard is less rigorous than many other states, some of which require a qualifying facility to be near the end of construction before a LEO can be established,” Puyear said. “While the commission remains open to revisiting its LEO test in the future, absolutely no evidence has been presented which shows that the current LEO test disadvantages qualifying facilities.”
Cypress Creek sees it differently.
“Before this rate change, the [plaintiffs] had fully committed to sell their output to NorthWestern, creating their legally enforceable obligation to sell — and NorthWestern’s statutory obligation to purchase. … NorthWestern repeatedly conceded that it had reached a final (if unsigned) contractual agreement with the QFs prior to June 16, 2016,” the company said.
Cypress Creek said it received “continued” assurances from NorthWestern in May and June 2016 that the old rates and contract lengths would apply to the 13 projects.
The company — along with Vote Solar and the Montana Environmental Information Center — is also a co-complainant in a state case alleging that the PSC last year “drastically and unreasonably” reduced the state’s PURPA standard contract length and energy rate, dealing a fatal blow to future small solar development in Montana. (See Montana PURPA Solar Saga Continues in State Court.)
In January, Cypress Creek reported its strongest-ever construction growth rate, having built 1 GW of solar installations over the previous 18 months.
CAISO this month launched a sweeping set of updates to its interconnection policies, an annual process made increasingly complex by a rapidly changing resource mix.
The effort “will likely address some substantial concepts but also a myriad of minor concepts that have not been addressed in some time,” the ISO said of its 2018 Interconnection Process Enhancements (IPE) initiative.
“Once we finalize the scope of the initiative, we will be able to determine the issues that will be included in this year’s process and the timing for development,” CAISO said.
The program is divided into six broad categories: deliverability; energy storage; generator interconnection agreements; interconnection cost responsibility and financial security; interconnection requests; and modifications.
A Jan. 17 issue paper defined the proposals that CAISO is considering. The document includes 42 potential topics and will be developed into a draft final proposal, but the ISO has not specified when it would be presented to the Board of Governors for approval.
The deliverability category alone contains nearly a dozen topic areas related to transmission planning, criteria for commercial viability and transparency into the availability of deliverability.
Other major tasks laid out in the IPE paper include:
Ensuring the development of the most viable projects;
Giving projects with power purchase agreements a greater opportunity for deliverability; and
Providing resource developers reasonable timelines for interconnection.
The ISO expects a March ruling from FERC on last year’s more narrowly tailored IPE package, which was expedited to obtain a ruling before the next transmission plan deliverability (TPD) allocation takes place in March.
The ISO published its issue paper on the proposal on January 17
A TPD allocation provides resources the transmission capacity required to deliver power during peak conditions and is a condition of receiving full capacity deliverability status, which is critical for eligibility to be counted as resource adequacy.
CAISO twice a year allocates TPD to generating projects that meet certain criteria. The 2017 IPE package proposes a third TPD allocation, which FERC is likely to approve.
The TPD allocation process works well during periods of high procurement, CAISO said. However, renewable procurements have recently slowed significantly, resulting in few projects meeting the criteria to qualify for a TPD allocation.
There are also uncertainties around renewable procurement that will affect the ability of a resource to obtain power purchase agreements. CAISO noted that the California Public Utilities Commission has proposed establishing a two-year resource procurement cycle to meet the targets of integrated resource plans, with the first procurement proposed for the end of 2018. But modeling used by the commission for the program shows a minimal need for renewable procurement until 2026 because California utilities are on track to meet — or exceed — renewable portfolio standard targets, the ISO said.
“The IRP will have significant impacts on interconnection customer’s ability to obtain PPAs for their projects,” CAISO said.
In a Jan. 24 presentation, CAISO discussed items that stakeholders requested be included in the IPE, including a proposal that would allow interconnection customers to replace their entire project with storage during the interconnection process. But CAISO has only approved up to 10% conversion to battery from an existing project during the process.
“A complete change of technology from existing technology requires a study to determine the new electrical characteristics and the impact to the grid,” CAISO said in explaining that it would not explore that topic in IPE 2018.
The energy storage category of IPE 2018 is focused on distributed energy resources, wholly replacing existing facilities and deliverability assessment for energy storage.
The ISO is taking comment on the IPE package through Feb. 7 and said stakeholders should suggest other items that might be included.
CARMEL, Ind. — MISO is asking stakeholders to put pen to paper by spring to describe how the RTO should measure grid resilience.
Stakeholders will participate in a broad discussion of what constitutes resilience during MISO Board of Directors Week in late March. And the RTO has asked each stakeholder sector to prepare its own whitepaper on the topic.
During a Jan. 23 Informational Forum, MISO CEO John Bear celebrated FERC’s recent decision to reject Energy Secretary Rick Perry’s proposed rulemaking to financially support nuclear and coal-fired generators, instead requiring RTOs to answer questions about how they assess resilience. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.) Bear said MISO is committed to promoting reliability and resilience throughout its footprint, emphasizing that no near-term reliability issues exist, attributable in part to the RTO’s partnership with state regulators.
DOE’s original rulemaking timeline didn’t allow for “reasoned decision-making and thoughtful review,” Bear added.
“A one-size fits-all wasn’t feasible in MISO given our diverse footprint,” he said, promising to work with stakeholders in drafting a response to the order. MISO Director of Planning Jeff Webb last week said the RTO is still holding internal meetings to formulate its response.
MISO Website Officially Migrates
MISO’s officially launched its redesigned website on Jan. 16, and market reports and real-time data feeds are up and running, said Kacey George, the RTO’s digital strategy adviser.
“We had 12 million hits on the first day,” George said.
MISO expects to upload planning and training materials as well as leadership and governance pages by the end of the month, she said. Staff must also address a few bugs, namely involving some member pages related to the interconnection queue.
Lower natural gas prices and relatively light congestion translated into lower year-over-year prices for MISO in December despite slightly higher load.
Shawn McFarlane, MISO executive director of strategy, said average temperatures in the RTO’s footprint last month ranged from 1 to 6 degrees Fahrenheit colder than the 30-year average, driving the increase in load. But prices averaged $27.26/MWh, 11% lower than the same period a year earlier.
“We were about $3/MWh lower than what we saw last year,” McFarlane said.
He credited the lower prices to a 25-cents/MMBtu drop in gas prices and lower congestion compared with the previous December. Average load was up 0.8 GW to 77.7 GW, and load peaked at 98.8 GW on Dec. 27, a 5.8% increase over the average monthly high.
“Multiple rounds of arctic air swept through the footprint” during the month, McFarlane said, making load forecasting challenging and leading to two days with a poor unit commitment score in MISO’s monthly self-assessment.
“Holiday loads … are always kind of tricky to figure out,” he said.
McFarlane also said MISO had to manage high market-to-market congestion with SPP in December because of high wind output and transmission outages in SPP.
MISO Shuffles Leadership
MISO has made several leadership changes in the new year, Bear said.
Todd Ramey will now exclusively head MISO’s market platform replacement effort, leaving his role of vice president of system operations to become vice president of system enhancements, a new position. MISO is poised to spend $130 million by 2024 to replace its aging market platform with a more adaptable modular system.
Former Executive Vice President of Operations and Corporate Services Richard Doying will step away from the operational side of MISO to focus exclusively on designing a market for the future.
“Everything is on the table here,” Bear said of Doying’s new role. “Put some simulations in place and stress it. What concerns me is not so much the next five years, but the five years after that … and the queue shows that. If we don’t get ahead of the curve, we’ll be chasing it.”
Bear said the markets were designed in 2005 and not equipped for today’s realities of more exact forecasting, high wind penetration and copious amounts of data.
“Quite frankly, it’s hard to keep the system safe. It wasn’t designed for the environment we live in today,” Bear said.
Finally, MISO South Vice President Todd Hillman will transition to become head of external affairs.
Additionally, in December, MISO revealed a plan of executive succession that promoted Clair Moeller from vice president to president of MISO, and will have Moeller stepping into the role of CEO should something unforeseen happen to Bear. (See MISO Board Promotes Moeller, OKs 2018 Budget.)
Entergy New Orleans CEO Talks Big Easy Challenges
MISO welcomed Entergy New Orleans CEO Charles Rice during the meeting for a brief conversation of the challenges and considerations of powering the Big Easy.
“It’s a pretty unique place in terms of the population density and the geography. We’re surrounded by water on three sides. For us to import power into the City of New Orleans is very challenging and very difficult,” Rice said.
The city has little right-of-way space for additional transmission lines, Rice added.
The CEO highlighted the need for the planned, $210 million, 128-MW natural gas-fired plant within city limits at the site of Entergy’s retired Michoud plant. He has previously warned that the city has only 1 MW of generation within its borders and needs a more reliable, onsite generation source. The proposed plant currently awaits New Orleans City Council approval; city advisers rejected an earlier proposal from the utility for a larger, more expensive plant.
Hillman asked how Entergy New Orleans plans to prepare for the increased likelihood of another hurricane.
“We never stop preparing. We prepare year-round for hurricanes,” Rice said. “And after … we take a look at what went right, what went wrong.”
Entergy is still in the process of replacing natural gas pipelines damaged by Hurricane Katrina in 2005. “Right now, we’re probably focused on the largest gas infrastructure project in the country,” Rice said.
Rice said New Orleans’ demographics make providing utility service a delicate balance: “37% of my customers live at or below the poverty level, so I’m always thinking of that,” Rice said. “When we make decisions, we have to make sure it’s something our customers can afford.”
He said New Orleans is making strides in its goal of having up to 100 MW of rooftop solar located within the city and will pursue other new technologies, such as building microgrids at hospitals in the coming years.
“There’s going to come a time when customers are going to want to have 100% control of their energy,” Rice said. “If customers want a microgrid, we have to give them a microgrid. If they want rooftop solar, we’re going to have to figure out how to make that work.”
MISO traditionally holds its springtime quarterly board meeting within the city’s French Quarter; this year’s meetings occur March 27-29.
CAISO last week kicked off an effort to implement major changes in the way it procures backstop generation needed to maintain grid reliability, in the face of growing stakeholder dissatisfaction over increased use of the practice.
The ISO is reviewing its reliability-must-run (RMR) and capacity procurement mechanism (CPM) programs and considering combining the two. It considers both backstop procurements to be “last resorts” to guarantee adequate capacity when it identifies generation deficiencies, as well as to prepare for unexpected events on the grid.
CAISO is undertaking the effort “to address concerns identified by the ISO and by other stakeholders” in light of recent RMR and CPM designations, it said in a Jan. 23 straw proposal and issue paper.
“This initiative will review the RMR tariff provisions, pro forma agreement and procurement process, and seek to clarify and align the use of RMR procurement and backstop procurement under the CPM tariff,” CAISO said.
CAISO has recently increased its reliance on RMRs and CPMs for gas-fired power plants, which are unpopular with owners of other resources competing in the market, as well as state regulators who favor non-fossil-based resources. The ISO in recent months has inked contracts with gas plants, citing misalignments with state resource adequacy programs as one reason for doing so.
CAISO has signed RMR contracts with four natural gas-fired power plants | CAISO
The initiative will also look at reworking the ISO’s Condition 1 and Condition 2 classifications for RMR units, which have different payment structures. The former recover only a portion of their revenue requirement, while the latter operate under a full cost-of-service payment methodology.
Following recommendations from the ISO’s Internal Market Monitor, the proposal seeks to remove certain limits on market participation currently imposed on Condition 2 resources and make both types of units subject to must-offer obligations for energy and ancillary services. In a protest of the Metcalf RMR filed at FERC, the Monitor said consumers are currently bearing full costs for Condition 2 facilities that are barred from CAISO markets in many hours.
The grid operator’s Board of Governors in November approved the latest RMRs, with Governor Ashutosh Bhagwat saying: “I am going to hold my nose very, very hard” while voting in favor. (See Board Decisions Highlight CAISO Market Problems.)
But the California Public Utilities Commission responded on Jan. 11 by fast-tracking a nullification of the RMRs. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.) Representatives from the CPUC and Pacific Gas and Electric told the ISO board in public meetings that they opposed the contracts.
Grid planners are being pushed into backstop procurements to maintain longer-term reliability as gas generators fail to obtain contracts under California’s resource adequacy program. CAISO has 852 MW of capacity under RMR, including Dynegy’s Oakland units and Calpine’s Feather River, Yuba City and Metcalf Energy Center plants, all of which were signed in September-November 2017.
The involuntary RMRs receive a negotiated rate, and CPMs receive a market-based price subject to a cap. The cost of the contracts eventually falls on retail ratepayers, which must shoulder tens of millions of dollars, often with relatively short notice.
Some power marketers say the rapid growth of community choice aggregators has further scrambled the procurement picture as customers depart from investor-owned utilities, leaving a small rate base to shoulder the costs.
CAISO said it wants to develop the first phase of the new program enhancements in time for May approval by the board. A second phase would be in place this fall to be used in 2019 and would clarify when RMR is used instead of CPM and explore whether the two designations can be merged.
The ISO has already posted a detailed presentation for a Jan. 30 stakeholder meeting to be led by Keith Johnson, manager of infrastructure and regulatory policy.
FERC on Friday accepted an unexecuted large generator interconnection agreement (LGIA) filed by ISO-NE and National Grid for Clear River Energy’s 1,100-MW natural gas-fired plant in Burrillville, R.I. (EL18-349).
The commission’s Jan. 26 order rejected Clear River’s protests over the dates for providing financial security for the cost of required transmission upgrades; its request to self-build certain interconnection facilities; its cost responsibility for transmission upgrades; and its request for additional data backing the cost allocation.
Clear River’s twin one-by-one combined cycle generating units will interconnect with the grid at National Grid’s existing Sherman Road 345-kV switching station through a new 345-kV generator lead line. During LGIA negotiations, Clear River requested to push back the initial commercial operation date two years, to May 31, 2021. National Grid confirmed that it could meet the new deadlines.
Clear River complained that the unexecuted agreement would require it to begin spending up to $88 million prior to the project’s permits being secured.
The commission ruled that the milestones developed by National Grid were based on the schedule proposed by Clear River. “Clear River’s request to adjust the dates by which it must issue its notices to proceed and post security appears to be due to permitting delays. We note that, if Clear River prefers to proceed once it receives the required permits, then it is free to propose later key milestone dates. National Grid has stated that it will re-evaluate the other milestones should Clear River avail itself of this option.”
The commission also rejected Clear River’s request to self-build its interconnection facilities, saying that option is only available if National Grid is unable to meet Clear River’s milestone dates.
FERC also found that ISO-NE had provided all the information it is required to in justifying Clear River’s $44 million in transmission upgrades.
| Clear River Energy
It also rejected Clear River’s request to restudy its cost obligation because of the two-year delay in its proposed commercial operational date. The company said some upgrades in its LGIA will not be necessary because of several transmission projects expected to be online by 2021 in the Southeast Massachusetts/Rhode Island area: the New Grand Army switching station; upgrades to the Somerset Substation; and upgrades to transmission lines X3 and W4.
FERC said Clear River’s decision to delay its commercial operating date was not grounds for triggering a restudy under ISO-NE’s Tariff.
In November, Clear River had filed a separate complaint asking FERC to eliminate provisions in the RTO’s pro forma LGIA that permit the direct assignment to interconnection customers of network upgrade-related operations and maintenance costs (EL18-31). On Jan. 23, however, the company filed to withdraw the complaint.
“Clear River believes it has shown that, given the nature of the relevant upgrades (which consist almost entirely of replacing or relocating existing network facilities), there very likely would be no monetary impact on Rhode Island ratepayers whatsoever. Nevertheless, the relief sought by Clear River has proven contentious in the Rhode Island Energy Facility Siting Board (EFSB) proceeding regarding Clear River’s application for the permits necessary for the project to be constructed,” the company said. “Accordingly, in order to remove this issue from being considered in any way in the EFSB proceeding — and to eliminate even the false perception of negative ratepayer impact — Clear River is submitting this notice of withdrawal.”
FERC’s Jan. 26 order noted that the notice of withdrawal remains pending. “The commission’s determination in this case should not be read as prejudging the resolution of any substantive issue in that proceeding,” it said.
FERC accepted ISO-NE’s informational filing for Forward Capacity Auction 12, rejecting protests from a demand response provider and renewable generators over qualification rules (ER18-264).
The commission’s Jan. 19 order agreed with the RTO’s list of resources that qualified for the Feb. 5 auction for the 2021/22 delivery year. It also approved the three capacity zones to be modeled, which are unchanged from FCA 11.
| ISO-NE
Efficiency Maine Trust — a quasi-state agency that administers energy efficiency programs in Maine and is overseen by the state Public Utilities Commission — protested the RTO’s methodology for calculating existing capacity qualification values. The agency said ISO-NE inappropriately subtracts the amount of expiring measures from a demand resource’s qualified capacity from a prior FCA, rather than from the demand resource’s actual and known performance capacity, as reported in ISO-NE’s energy efficiency measure database.
ISO-NE rules define qualified capacity — the quantity for which a capacity supplier is compensated — as the lower of the resource’s summer or winter qualified capacity. When a capacity supplier’s summer and winter qualified capacity is significantly different, as is the case with the Efficiency Maine programs, the supplier will not receive compensation for the higher seasonal capacity unless it can pair the higher capacity with other resources in a composite offer.
Storage Technology Connected Directly to Power Grid as a Generator | ISO-NE
Efficiency Maine said the RTO’s rules would deny it compensation for $3.7 million in capacity for FCA 12, although it said it has been able to reduce the loss to $1.5 million through composite offers covering its entire qualified summer capacity.
The commission said Efficiency Maine projects performed above their qualified capacity because measures installed after the initial clearing of the resources. “We agree with ISO-NE that Efficiency Maine should have sought to qualify any additional capacity prior to such additional measures being in service. Accordingly, to the extent that the Efficiency Maine projects’ overperformance is the result of Efficiency Maine’s failure to seek to clear new incremental capacity in the FCA, we find it inappropriate to now mitigate the consequences of that action (or inaction) through changes to the demand resource methodology.”
The commission also agreed with the RTO “that it would be inappropriate for the commission to require ISO-NE to use Efficiency Maine’s proposed methodology for the Efficiency Maine projects while still using the current demand response methodology for all other energy efficiency resources with expiring measures.”
Renewable Technology Resource Exemption
The commission also rejected a joint protest by CPower and Tesla, which combined to enter Tesla’s SolarCity rooftop generation into the auction.
The companies asked the commission to require ISO-NE to re-evaluate the renewable technology resource (RTR) designation for five solar projects and one combined solar and fuel cell project.
The projects passed the RTO’s qualification process and were assigned the default offer review trigger price (ORTP) — a price floor based on the cost of new entry — of $12.864/kW-month. CPower said it did not challenge the ORTP because it sought to use the RTR exemption to receive an offer floor price of $0/kW-month. RTO rules permit up to 200 MW of RTR exemptions annually to renewable resources receiving out-of-market revenue through state renewable portfolio programs.
In October, however, ISO-NE rejected CPower’s application as incomplete. CPower contended the additional information the RTO requested meant that new resources must already be accepted into a state RPS program and receiving revenue to qualify for RTR designation, contrary to the RTO’s Tariff.
ISO-NE responded that although CPower’s qualification package was sufficient to determine an appropriate capacity amount to qualify each resource, it lacked details necessary to determine whether each resource met the requirements for an RTR designation.
The commission sided with the RTO.
“Although CPower’s qualification package contains some location-specific information and that CPower’s RTR submittal contains general information on possibly applicable RPS statues and regulations, we agree with ISO-NE that neither sufficiently enable ISO-NE to determine the specific provisions and manner (e.g., on an individual or aggregate basis) in which the renewable projects seek RPS qualification,” the commission said. “We agree that such specificity is necessary for ISO-NE to have sufficient certainty that the renewable projects will still qualify as RTR resources by the time of the relevant capacity commitment period. Thus, we find that CPower failed to comply with the Tariff’s requirements to obtain RTR designation.”
Zones and Resources
As in FCA 11, ISO-NE will model three capacity zones in FCA 12: Southeastern New England (Southeastern Massachusetts, Rhode Island and Northeastern Massachusetts/Boston), which will be modeled as import constrained; Northern New England (Maine, New Hampshire and Vermont), which will be modeled as export constrained; and Rest of Pool (Connecticut and Western/Central Massachusetts).
The installed capacity requirement (ICR) is 34,683 MW. After accounting for 958 MW per month of Hydro-Québec interconnection capability credits, FCA 12 will procure a net ICR of 33,725 MW.
ISO-NE qualified 5,605 MW of new resources and 35,007 MW of existing resources: 30,702 MW from intermittent and non-intermittent generation; 82 MW from imports; and 3,224 MW from demand resources.
The RTO said 2,309 MW of static de-list bids — one-year exemptions from the auction — were submitted for FCA 12.
