CARMEL, Ind. — MISO will make two changes to improve its year-old emergency pricing structure by this summer in addition to the two emergency pricing floors rolled out last year, RTO staff said during a March 9 Market Subcommittee meeting.
The first change: Commitment costs of offline fast-start units will be allocated into the minimum runtime when calculating the offer floor for emergency prices.
The second: Emergency-committed units dispatched at their economic minimum prices will be allowed to set those emergency prices.
The two changes were the only selected among the five proposed by MISO staff after a July 2016 emergency event resulted in depressed prices. (See “MISO May Tweak Emergency Pricing Floors,” MISO Market Subcommittee Briefs.)
MISO engineer Oluwaseyi Akinbode said the modifications are meant to produce more efficient prices.
“If you believe what the planners are saying, there’s a chance we will get into these emergency conditions this summer, and we want to be prepared for that,” Akinbode said.
New User Group Aims to Improve Ease-of-Use in MISO Apps
MISO will later this month debut a new Application User Group for people who use the RTO’s technology.
April Peterson, a representative from MISO’s asset registration team, said the group will focus on improvements and common challenges market participants face when using the RTO’s computer market applications. She said attendance is also open to MISO software vendors and IT specialists that are contracted to make software changes.
Peterson said MISO aims to hold conference calls monthly, with the first call scheduled for March 23.
Potential Cost Recovery Gap in Manual Redispatch
Day-ahead resources can see gaps in cost recovery when they are manually redispatched offline — and a Tariff change could remedy the problem, MISO staff said.
When the RTO decommits a day-ahead resource, the day-ahead margin assurance payment does not take into account the resource’s minimum down times or start-up costs for reimbursement, said Jason Howard, MISO market quality manager.
Howard said yet-to-be-written Tariff language could “close the gap.”
“The manual redispatch might only last four hours, but a minimum down time for a resource might be seven hours,” Howard explained. “Our current day-ahead margin assurance payment does not account for these situations.”
Proposed Tariff language will be presented at a future Market Subcommittee meeting.
AUBURNDALE, Mass. — Stakeholders are considering four proposals for making New England’s markets more accommodating to state clean-energy initiatives, including a carbon adder in the energy market, potential changes to the capacity market and a possible new “clean energy” market.
David T. Doot, counsel and secretary to the New England Power Pool, outlined the changes to about 200 attendees at the Northeast Energy and Commerce Association’s 2017 Renewable Energy Conference on March 6.
Doot said the four long-term proposals were narrowed from the 17 proposed over seven meetings of the Integrating Markets and Public Policy (IMAPP) initiative last year. Officials announced last month that IMAPP will suspend its monthly meetings until May to allow ISO-NE time to develop “a conceptual market approach” that could be implemented in the near term for “accommodate[ing] state-supported capacity resources while appropriately pricing other resources in the Forward Capacity Market.” The delay also will allow states time to analyze long-term proposals discussed to date and for them to hold “off-line” discussions with stakeholders. (See NEPOOL Extends IMAPP Timeline.)
“We at the moment are in a pause … because ISO-NE has said, ‘We have to give you something to deal with the here-and-now that we’re worried about,” Doot explained. “They’re going to come back with something for us to debate and digest in the May timeframe.”
Panel moderator David O’Connor, senior vice president for energy and clean technology at ML Strategies, set up the panel by describing IMAPP as a “work in progress,” adding that “by various metrics it could be described as yet being in its infancy.”
But Doot characterized the initiative as being in “the unruly teen years.”
“We’re well beyond our infancy at this point. … We get into this room [and] there’s a lot of people talking to each other, by each other, at each other — in varying levels of decibels depending on what exactly is going on.”
Proactive
Doot said it was essential that New England stakeholders be proactive in developing a solution, noting that FERC has two cases pending before it challenging zero-emission credits for nuclear generators in NYISO and PJM.
“If we — NEPOOL or New England — don’t do something, FERC is going to do it. They will do something to us or for us. And I can predict with some degree of certainty that we won’t like it,” Doot said.
“So I think what we need to do is decide whether we’re going to take the opportunity in New England to establish how we want to change the marketplace in order to help the states achieve what they’re trying to achieve in a way that allows the rest of the market to function, or whether we’re going to have FERC tell us how they’re going to do it. Because what we currently have is not necessarily sustainable in the long term.”
Ron Gerwatowski, an energy and regulatory policy consultant, formerly with National Grid, agreed on the need to eliminate what he called the current “market schizophrenia.”
“Somebody’s going to take a meat ax to this if we don’t fix it on our own,” he said.
Four Proposals Explained
Doot said the proposed carbon adder would be included in energy offers and energy clearing prices and collected from carbon emitters under an allocation to be determined.
A second alternative, proposed by the Conservation Law Foundation, calls for a “Carbon-Integrated” Forward Capacity Market (FCM-C), under which a new ZEC market would be integrated with the FCM.
A third option, offered by RENEW Northeast and NextEra Energy, is a Forward Clean Energy Market (FCEM), a new forward market for new clean energy resources. As initially proposed, the FCEM would expand to include supports for existing renewable resources.
“We’ve been moving a little bit away from that in part because the price tag is so high,” Doot said. “What they’re now talking about is a capacity clean energy market just for new [resources] but that they would allow for support of existing resources through some form of carbon pricing.”
The fourth proposal is a two-tiered pricing construct, with the FCM clearing at one price for existing resources and a lower price for state-supported resources offered at below competitive prices, an effort to protect prices from being suppressed.
‘Civil War’
Gerwatowski said one challenge is that the states are not unified in their goals, referring to “somewhat of a civil war” between the northern and southern states.
“We have some uniformity among Connecticut, Rhode Island and Massachusetts … with respect to the very aggressive goals to reduce greenhouse gas emissions. We’re in a very different place, I think, in New Hampshire and Maine — and in Vermont it’s hard to read with the new administration coming in,” Gerwatowski said, referring to Republican Gov. Phil Scott, who replaced Democrat Peter Shumlin in January.
“If you’re in the southern states, anything that’s going to drive greenhouse gas reduction, even if it comes at some costs, is going to be something that should be under consideration,” he said, referring to carbon pricing and long-term contracts for renewables.
“They have a different perspective in the north. … They’re not quite as convinced that these are the right ways to go in designing the future. We’ve heard some of the states, like New Hampshire in particular, saying, ‘Look, you guys want to do something to raise prices in order to meet your goals, that’s OK. But I’m not paying for it.’”
Abigail Krich, president of Boreas Renewables, said that while New England’s capacity market has provided price signals to encourage development of natural gas generators, it is insufficient for resources such as wind. Boreas worked on the FCEM proposal as a consultant to RENEW Northeast.
A combined cycle plant that wins a seven-year capacity contract at $7/kW-month can lock in almost 60% of its overnight capital costs, and a simple cycle turbine with the same contract would lock in 70% of its capital costs — both percentages high enough to secure financing, she said.
“A wind project, even if it’s actually more cost effective overall when you look at energy, capacity, [renewable energy credits], things like that … they can only lock in about 6% of their capital costs,” she said. “You can’t take 6% of your capital costs as locked-in revenues and go get financing for a project based on that.”
That, she said, is why long-term power purchase agreements are being sought for renewables. “We need these to be financeable projects,” she said.
Jon Norman, vice president of government and regulatory affairs for Brookfield Renewable, said the current capacity market was designed primarily to support conventional fossil generation and doesn’t address a growing gap in value recognition for existing sources of non-emitting generation, including hydropower and wind projects with expiring PPAs.
“At some point there needs to be a stable price signal” for existing clean resources, he said. “In the absence of that, you … end up over the long run cycling capital through and just putting it into new resources. And then old resources are either exporting somewhere else or they’re retiring. I don’t think that’s a good outcome.”
Matt Kearns, chief development officer for Longroad Energy Partners, said that states have generally found long-term contracts the cheapest way to meet their renewable portfolio standards.
“We’ve seen the most consumer savings generated by these larger procurements. … The result has been to attract cheap capital and drive down the cost of the product to the consumer,” he said. “Sending a signal to the market for a 15-year contract, you tend to get very competitive, good results.”
What Would FERC Do?
Doot said that he has been asked whether FERC has the authority to approve market rules that incorporate carbon policy. The commission has scheduled a technical conference for May 1-2 on the energy and capacity markets in PJM, NYISO and ISO-NE.
Before President Trump’s election, Doot said, FERC was “begging us to come forward with something under our voluntary market structure that they can consider and potentially say yes to. Now, that was FERC before President Trump.”
After Trump? “There’s just no way of predicting,” Doot said.
Doot ended the session by returning to a question about how consumer advocates can ensure that ratepayers don’t “double pay” for carbon reductions through both an ISO-NE-wide carbon price and state initiatives such as renewable portfolio standards.
“The answer is ‘Show up.’ Because at the end of the day we have to come up with a solution. … If we don’t come up with a solution, I’m not sure you have an assurance that you aren’t double paying.
“It’s up to us — the marketplace — to help define how it is we’re going to address these challenges. If we don’t, the federal government and the state governments are going to do it, and I’m not sure that the marketplace is going to be happy with the outcome.”
CARMEL, Ind. — MISO is considering how to alter its market rules to comply with a FERC order that “softens” the current energy offer cap and establishes a higher “hard” cap for cost-based offers.
One potential change: The RTO could possibly increase its maximum value of lost load (VoLL), which represents the estimated amount that firm electricity customers would be willing to pay to avoid losing service. The VoLL, established in 2005, caps LMPs at $3,500/MWh. MISO is the only RTO to enforce such a cap.
“We really should update the value of lost load,” Chuck Hansen, MISO senior market engineer, said during a March 9 Market Subcommittee meeting. “It’s been around for a decade. It’s probably time to refresh that number.”
Hansen said MISO is hoping to implement FERC’s directive by winter 2017/18, although the scope of the market changes could vary from adjusting the VoLL to ending LMP caps altogether.
Order 831 replaces the current energy offer cap of $1,000/MWh with a soft cap of $1,000 and a hard cap of $2,000 for verified cost-based incremental offers. MISO’s offer portal will be reprogrammed to automatically block all offers above $2,000/MWh, while offers between $1,000 and $2,000/MWh will be verified only after the daily market close.
A resource may qualify for uplift payments if legitimate offers above $1,000/MWh cannot be verified quickly enough. For the past three winters, FERC has granted MISO a waiver on the RTO’s energy offer cap policy. (See MISO Granted Winter Waiver on Offer Cap.)
“We have not seen offers above $1,000 yet in MISO,” said Jeff Bladen, MISO executive director of market design. “The degree to which we could see them is just too hard to predict, [but] the likelihood that we see offers above $1,000 or $2,000 — [in] my view is it’s pretty unlikely because we haven’t seen it before.”
Hansen said MISO’s Independent Market Monitor will adapt to the new offer cap by stepping up its monitoring efforts next winter, updating resource reference levels as it keeps tabs on natural gas prices throughout the day. Going forward, market participants will be able to request a consultation with the Monitor for higher reference levels. The Monitor’s Jason Fogarty said it would host a workshop later this year for market participants on the consultation process.
| MISO
The Monitor’s 2017 State of the Market report will likely recommend that MISO update the VoLL cap to also reflect the “likelihood of real-time capacity loss exceeding a given reserve level,” Fogarty said.
According to Hansen, the higher energy offer cap paired with the operating reserve demand curve during scarcity conditions could easily breach the $3,500/MWh threshold.
Hansen said MISO could try to weather the higher energy cap with an updated VoLL cap and minimal Tariff changes — or undertake a major market redesign, in which the LMP cap would be abandoned in favor of a PJM-style system marginal price cap. MISO could also divorce its operating reserve demand curve from its VoLL cap, although it must be careful to keep LMPs in check, he said.
More involved market changes would “preclude a quick solution” — and MISO is hesitant to pursue a major market redesign, Hansen said. The RTO is asking market participants to submit suggestions on the issue by March 20.
Unrest grows along the PJM-NYISO border after the dismantling of the CON ED-PSEG WHEEL that for decades held sway over daily operations in the region. Expensive infrastructure replacements loom on the horizon, and stakeholders on both sides suspect the other of attempting to take advantage of the situation.
At the RAMAPO SUBSTATION, a phase angle regulator has failed, sparking a dispute between territorial transmission owners that threatens to reignite longstanding, deep-seated grudges.
As a last resort, a small group of delegates from both sides of the border have journeyed to an unassuming office complex on the outskirts of PHILADELPHIA to meet in person in the hope of averting chaos…
VALLEY FORGE, Pa. — If Friday’s joint PJM–NYISO meeting to discuss replacing a phase angle regulator (PAR) at Consolidated Edison’s Ramapo substation, near the New York-New Jersey border, had a “Star Wars”-like preamble crawling off into space, it would probably look something like that. Ok, maybe a bit less dramatic.
One of the substation’s two PARs failed in June, and Con Ed has hesitated to replace it until it receives certainty on how it will be paid for. That has been in question because the 1993 agreement signed by NYISO (then known as the New York Power Pool) and PJM transmission owners is in dispute.
The agreement covered just the original PARs at the facility, PJM transmission owners argue, neither of which remains in service. They say Con Ed’s decision in 2013 to replace the first failed PAR constituted a breach of the agreement, which requires the PJM transmission owners to be involved in the decision. Con Ed disagrees with that interpretation and believes the cost allocations under the contract — which would put PJM transmission owners who were a party to the agreement on the hook for 50% of the costs — remain in effect. However, stakeholders said that Con Ed’s reluctance to replace the failed equipment without knowing how it will be repaid doesn’t square with the company’s argument for why it replaced the first PAR after its failure in 2013, without consulting transmission owners.
“It seems like your own decision not to replace the PAR is in violation of your own interpretation of the agreement,” said Mark Younger of Hudson Energy Economics.
But before deciding on who should pay for it, some stakeholders are asking whether it needs to be replaced in the first place. In its current form, Calpine can’t support the project’s scope, company representative David “Scarp” Scarpignato said. “You really need to know what projects should be shared before you discuss sharing those costs,” he said. “The cost of paying for the PAR is not the big deal here. It’s that you’re potentially using the PAR to change the winners and losers here.”
He argued that the PAR helps alleviate congestion, which mutes the price signals on which generation companies like Calpine depend. “When you’re talking about using transmission to manage congestion rather than dispatching to address congestion, that is direct competition to generation,” he said.
Since the 1970s, operator and planners have operated under an agreement in which Con Ed wheels 1,000 MW of power through Public Service Electric and Gas’ transmission system in northern New Jersey into New York City. Con Ed announced last year that it no longer needs the service and would be canceling it as of May 1. Con Ed also canceled its membership in PJM and ended all commitments for cost allocation in the RTO, despite having been the reason for a substantial amount of now-unnecessary transmission upgrades. PJM stakeholders have taken issue with being forced to take on additional financial responsibility for maintaining infrastructure that’s no longer in use or being paid for by its intended beneficiary. (See NYISO Members OK End to Con Ed-PSEG Wheel.)
PSE&G’s Vilna Gaston asked if there had been an analysis regarding the benefits of replacing the PAR to determine if that’s even the best investment. “It seems like we’re proposing a solution before we do the investigation. This is putting the cart before the horse,” she said.
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Despite their disagreements, stakeholders produced a list of objectives for a potential analysis, including ensuring the endorsed solution adheres to competitive market principles and that the cost allocation is aligned with who receives the benefits.
PARs are an expensive solution. Beyond the millions of dollars in installation costs, PARs require about $200,000/month in upkeep, PJM’s Stan Williams said. Additionally, NYISO allocates such costs through all of its load-serving entities, while in PJM, only the signatories to the original agreement would share the costs, so there is a larger group to distribute through in NYISO than in PJM.
The group’s next meeting will be on April 18 at NYISO’s offices.
[Editor’s Note: An earlier version of this article incorrectly reported that the phase angle regulators on the 5018 line at the Ramapo substation were part of the CON ED-PSEG wheeling service. The Ramapo PARs were not part of the wheel.]
CARMEL, Ind. — Recent preliminary load forecast data for the 2017/18 Planning Resource Auction show that each of MISO’s local resource zones has enough capacity on hand to meet its own clearing requirement.
The RTO’s 172 GW worth of total installed capacity can handily meet its 135 GW of planning reserve margin requirements, John Harmon, MISO manager of resource adequacy, said during a March 8 meeting of the Resource Adequacy Subcommittee.
A general slowdown in manufacturing and continued energy efficiency efforts across the footprint is slowing load growth and lowering peak forecasts, Harmon said.
Robinson | RTO Insider
MISO derives its load estimates from a random sampling of load-serving entities and data reviews from LSEs whose load represents 45% of the RTO’s annual peak demand, according to Michael Robinson, MISO’s principal adviser of market design.
Robinson said MISO this year encountered issues with LSEs not providing historical data, excluding methodologies for non-coincident peak and accounting for transmission losses, which the RTO already does once it receives the data. He said all LSEs eventually met the forecast reporting requirements.
“We did see a rash of LSEs that didn’t provide all the information originally,” Robinson said, suggesting the “tightening” of some documentation requirements.
Multiple stakeholders expressed concern that MISO still has 7,300 MW of unconfirmed unforced capacity a month before the auction and asked about the potential for moving up registration deadlines to get more complete data earlier — something Harmon said the RTO would consider.
Harmon said that the unforced capacity data includes about 15 generators that have applied to defer completion of their generator verification tests — which qualify resources as capacity resources or load-modifying resources — until after the 2017/18 PRA.
The RTO said that it will separately report reserve margin data from Michigan’s Local Resource Zone 7, after receiving permission from market participants there that were concerned about protecting competitive information.
Zone 7 shows a 20-GW coincident peak load and a 22-GW planning reserve margin.
Zones 3, 5 and 7 were previously grouped together, as were zones in MISO South (Arkansas’s Zone 8, Zone 9 covering Louisiana and Texas, and Mississippi’s Zone 10). Iowa’s Zone 3 and Missouri’s Zone 5 will continue to be grouped together. (See “Preliminary Load Forecast Released,” MISO Resource Adequacy Subcommittee Briefs.)
MISO will host a stakeholder call to review the results of the PRA on April 14, followed by a longer meeting on the subject April 17.
In a related matter, the deadline to seek rehearing on FERC’s order prohibiting MISO’s three-year forward auction design has passed without any parties requesting a rehearing. (See MISO Won’t Seek Rehearing on Auction Redesign.)
“MISO still believes that mechanisms are needed to support competitive retail areas,” RASC liaison Shawn McFarlane said. He added that the RTO will work with Illinois officials to develop separate capacity auction provisions for retail areas that will not affect regulated areas.
MISO attorney Jacob Krause said the RTO could implement the changes — subject to refund — prior to the auction, or that FERC could issue a deficiency letter delaying the changes until the 2018/19 PRA. The commission has until March 17 to act on the filing.
IMM Offers Own PRA External Zone Design
The Independent Market Monitor is recommending its own option for the proposed locational element to the PRA — a year after the RTO began discussing the matter.
Monitor David Patton wants the RTO to create external resource zones based on neighboring balancing authority boundaries and set a clearing price for each external zone set using a shadow price and shift factor. By comparison, MISO staff have proposed six smaller, external resource zones based on geographic groupings of generation and transmission that would be priced using sub-regional prices and clear in the PRA.
Patton’s suggestion would require MISO to quantify how much capacity would be delivered from SPP and PJM and model how the power would flow through MISO’s internal zones. He said his approach would create consistency for MISO operations even as PJM and SPP resources supply capacity.
Some stakeholders asked why an LSE would purchase from external suppliers when the price would be different from auction clearing prices.
Patton said he didn’t see a difference between an LSE contracting bilaterally to purchase power from a different MISO zone and buying megawatts from an external resource. He said he would return to the RASC next month with a more detailed proposal.
Indianapolis Power and Light’s Ted Leffler said buying externally for commercial purposes — and not for reliability — represents an “imperfect hedge.”
However, MISO staff have proposed that external zones clear the PRA at a systemwide or sub-regional clearing price — and not at their offer prices. Akshay Korad of MISO’s market design and evaluation team said the RTO’s three simultaneous feasibility tests run after the auction could limit the capacity export limit of external resource zones if constraints bind and price the external zones as a marginal resource.
MISO used its four proposed MISO Midwest (formerly MISO North) external zones and two proposed MISO South external zones to run a simulation of the 2016/17 PRA. Using the projected external zones, MISO concluded that zones 2-7 could have cleared at $24.80/MW-day, instead of the actual $72/MW-day. (See MISO’s 4th Capacity Auction Results in Disparity.)
A small number of megawatts in the 2016/17 PRA caused the capacity export limit to bind, dictating the high clearing price in zones 2-7, Korad said.
“Even if you see that supply stack change a little bit, you’re going to see a change in price,” Korad said.
The six resource zones proposed by MISO are based on external zones that cleared in the most recent auction, and the number and location of external resource zones could change, said Laura Rauch, MISO manager of resource adequacy coordination.
Stakeholders asked MISO staff to come back with more pricing simulations using external zones.
Like other stakeholders, Leffler remained critical of the entire external zone concept. He asked why MISO couldn’t require LSEs to create fixed resource adequacy plans to hit their full local clearing requirements using only local resources and forbid them from relying on external resources toward their local clearing requirement.
“There ought to be a way that’s easier to do this than create external resource zones,” he said.
MISO Examines Single Year of MISO-SPP Settlement Allocation
MISO stakeholders are questioning the benefits of debating whether some costs of MISO and SPP’s transmission use settlement be allocated to holders of transmission service requests above the 1,000-MW contract path. MISO wants to determine who gets allocated the costs for using the North-South interface for about 300 MW that went above the 1,000-MW North-South limit in 2018/19.
Stakeholders will decide if the RTO can allocate a portion of the costs of just one year of the settlement — the 2018/19 planning year — based on capacity benefits, where firm TSRs from MISO South to MISO Midwest reach 1,304 MW. In all other years of the settlement from 2014-2021, TSRs were or are 1,000 MW or below.
MISO’s Jesse Moser said the question is “narrowly focused” on capacity benefits and is not a forum for negotiating other terms of the settlement agreement.
“MISO is approaching this without a desired outcome in mind. We’re facilitating discussion,” Moser said.
Multiple stakeholders said that an effort to decide the one-year allocation within MISO’s stakeholder process might not be worth pursuing considering the low monetary amount at stake.
Per the settlement agreement, MISO has until Nov. 17 to decide on an allocation to TSR holders, either by filing to alter the terms of cost allocation or making an informational filing to explain that it won’t change allocation.
“That 1,000-MW cap should have been in place in OASIS prior to December 2013,” NRG Energy’s Tia Elliott observed dryly.
Mathis wanted to know the dollar amount at stake — something Moser said he could supply at the April RASC meeting.
The settlement dictates that costs be allocated on a graduating scale based on a ratio that phases out over time — with 100% to load in the first two years of the settlement, decreasing to 45% in the third year and 10% in the seventh year, with the remaining percentage taken on by a flow-based allocation.
MISO pays about $27 million per year for use of SPP’s transmission that links the RTO’s Midwest and South region. The maximum amount MISO could pay under the settlement for heavy transmission use is $38 million per year.
MISO Wants Deferral Year to Create Queue Withdrawal Penalty
MISO is seeking a yearlong extension to develop specific penalties for generation project withdrawal, as directed by FERC in the RTO’s interconnection queue overhaul (ER17-156).
MISO attorney Jacob Krause said the RTO wants to hold off on a filing until March 31, 2017, in order to work with stakeholders to determine an appropriate penalty. He said MISO is currently seeking FERC permission for the deferral.
The Public Utility Commission of Texas last week asked its staff to revise a rulemaking on emergency response service (ERS), saying it did not favor expanding the program to prevent local load-shed events (Project No. 45927).
As drafted, the proposed order would permit ERCOT to use ERS to prevent firm load shedding (rolling blackouts) in the event of local transmission emergencies. It also would give ERS resources the flexibility to replace reliability-must-run services.
ERS pays loads for reducing their consumption and distributed generation such as backup generators for injecting power during emergencies. ERS currently is used for non-local emergencies and is not permitted to also serve as a must-run alternative (MRA).
Commission staff published the rulemaking for comments in June 2016. The proposed amendments drew comments from 13 different groups, including ERCOT, its Independent Market Monitor and various energy companies and industry and environmental associations.
Price Suppression Concerns
PUC Chairman Donna Nelson said Thursday she “struggled” with the rulemaking and was concerned about ERS suppressing local prices when it is deployed to address local congestion. The draft order said the issue of price suppression should be addressed through the ERCOT stakeholder process.
Commissioner Ken Anderson said he shared Nelson’s concerns, and asked staff to return to the amendment’s original concept of allowing ERS participants to opt out of ERS “if they’re in a situation in which ERCOT is seeking load alternative to RMR.”
“If they’re in an [MRA] contract, they can opt out at their choosing, but they forego the [ERS] payment,” he said.
SCED Integration?
Anderson also asked staff to delete language in the preamble referencing a Shell Energy North America proposal to expand the current ERS program by allowing some resources to submit energy offer curves to ERCOT’s security constrained economic dispatch (SCED) algorithm. As drafted, the proposed order says the commission agrees with ERCOT that requiring ERS resources to telemeter bids and respond to SCED dispatch would “undermine a core purpose of the ERS program — to capture the benefit of demand response or generation that otherwise would be unable to participate in the ERCOT market.”
Anderson said the rulemaking had identified a bigger issue: the integration of distributed generation and allowing the resources to bid into SCED.
“Whether it’s paired with load or just on its own, [DG] needs to be integrated into ERCOT,” Anderson said. DG “should get the LMP. I know ERCOT is working on that, but I would strongly encourage them to make it a priority.”
Anderson told Monitor Beth Garza he thought one reason staff expanded the amendment’s original scope was to address suggestions made by the Monitor that there might be other alternatives than the Greens Bayou Unit 5 RMR agreement. (See ERCOT Ending Greens Bayou RMR May 29.)
“It would be helpful if you could come up with a real concrete proposal that we could shoot at,” he said.
Garza said her initial suggestion for using ERS resources in local emergencies was “not necessarily directed at RMRing Greens Bayou.”
“Frankly, it was a response to … other times we have had to shed load,” she said, pointing to localized events. “I consider ERS as a program that allows loads to be paid, to be the first in line to be curtailed when we’re at the cliff. At that point, the need for effective market mechanisms diminishes. Prices should be reflective of that. ERS is a way for specific loads to step up and say, ‘Yes, I’ll be the first ones to go.’”
Anderson said that with a recent ERCOT cost-benefit analysis indicating a multi-interval SCED would not be cost effective, it opens up the discussion about co-optimizing the real-time market (shifting the responsibility for providing reserve services to online generation resources with the lowest incremental energy cost).
“Which we’ve been talking about for how long?” Nelson asked.
“I still had hair, I think,” Anderson joked. “[Co-optimization] would help with the whole proper price signal and dispatching, hopefully minimizing reliability unit commitments. Then if we co-optimize, we could adopt local [operating reserve demand curves] that reflect that sort of scarcity.”
Anderson was careful to say he was not expressing an opinion, but just hopeful of addressing congestion and local transmission problems.
“To the extent that you just eliminate unnecessary barriers, that’s fine,” he said. “I don’t think ERCOT should spend a lot of time trying to use ERS to relieve localized problems.”
“I would just leave the must-run alternative agreement aspect in the rule, and limit it to that,” Nelson said, saying she was concerned about interfering with ERCOT’s competitive market. “The whole purpose of opening this rulemaking was to look at ways of using ERS as it currently exists and the money that’s being spent. I do not in any way want to enlarge ERS … it shouldn’t be larger than it is.”
The draft order rejected calls to eliminate or increase the $50 million annual cap on ERS spending but promised the commission would review the limit if the new ERS local deployment product results in costs threatening to exceed the limit.
The commissioners asked staff to return with a rulemaking reflecting the day’s discussion for the PUC’s next open meeting March 30. Staff is targeting a March 23 publication of the revised language.
The PUC also:
Approved the City of Garland’s request to amend its certificate of convenience and necessity with a final route for a double-circuit 345-kV transmission line east of Dallas that will interconnect ERCOT with the SERC Reliability Corp. through the proposed Southern Cross DC tie in Louisiana (Docket No. 45624). The line will connect an Oncor substation with a Garland substation, that will then connect with the Southern Cross.
Approved a settlement between Entergy Texas and its customers allowing the utility to recover an annual revenue requirement of $29.5 million, almost $19 million above the amount approved in its previous transmission cost recovery (TCRF) factor proceeding (Docket No. 46357). Entergy will recover almost $3.4 million in additional transmission-related revenues through its base rates than it did when the TCRF baseline was set, because of an increase in billing determinants since its last base rate case.
Reduced revenue requirements for Electric Transmission Texas by $46.2 million (Project No. 44550) and Cross Texas Transmission by $86.5 million (Project No. 45636). The reductions were a result of the PUC’s annual true-up for regulated entities.
U.S. wind industry jobs and generating capacity will grow by more than 40% by 2020, despite uncertainty over the Clean Power Plan, according to a study released last week by the American Wind Energy Association.
In fact, said AWEA CEO Tom Kiernan, President Trump’s vow to undo the Obama administration’s bid to cut power plant carbon emissions could be good news for the wind industry in the short run.
Suzion S88 Wind Turbines at Dry Lake Wind Project in Arizona | AWEA
“If anything, [the death of the CPP] may accelerate” the pace of wind energy construction over the next few years, as projects attempt to beat the expiration of the production tax credit (PTC), Kiernan said.
Kiernan’s comments came during a news conference Thursday at which AWEA presented a Navigant Consulting study that predicts that wind generators, who ended 2016 with 82 GW of nameplate capacity, will add another 35 GW by 2020.
The study also predicts the number of Americans working for wind companies or in their supply chain will grow from the current 102,500 to 147,000. The number of direct wind energy jobs grew 17% in 2016, according to the study.
A two-thirds reduction in costs since 2009 has helped drive the industry’s growth, AWEA said.
But some of the incentives the industry currently enjoys could be imperiled. The PTC, extended by Congress in 2015, will be phased out over three years, terminating at the end of 2019.
Tax credits drove a lot of the industry’s success, Kiernan acknowledged. “The policy certainty provided by the 2015 production tax credit phase down has allowed the industry to make long-term investments in the American workforce and manufacturing to further bring costs down,” he said.
Navigant said its projections were based on the assumption that the CPP, which also encouraged wind energy growth, would be stricken.
Energy Secretary Rick Perry oversaw a doubling of wind capacity in Texas when he was governor, but it’s unclear how much he could do for the industry in his current role.
Kiernan said land leases associated with wind projects will add up to about $1.2 billion in the next five years, benefiting farmers and ranch owners, making wind “a cash crop.” The average land lease, for two turbines, comes out to about $6,000 a year.
CARMEL, Ind. — MISO will roll a 35% share of the capacity from resources sitting in the definitive planning phase of its interconnection queue into the annual resource adequacy survey conducted with the Organization of MISO States — over the objections of some stakeholders who seek inclusion of a greater portion of capacity.
The survey currently counts only future resources that have already executed a generator interconnection agreement.
Indianapolis Power and Light’s Lin Franks said MISO’s 35% completion estimate is too conservative, especially when considering projects submitted by state-jurisdictional utilities that are obligated to serve load and whose projects might be more reliably completed than other queue entrants. (See Stakeholders, MISO at Odds over Resource Adequacy Survey.)
“You know the damn thing is going to be built — it needs to be included” in the survey, Franks remarked during a March 8 Resource Adequacy Subcommittee meeting.
She also warned of the “self-feeding” problem of developers entering the queue long before they are certain that a resource will be constructed — the product of long queues.
Franks suggested that MISO examine rates of withdrawal based on resource type.
“If you don’t take a look at which resources are withdrawing, you don’t have a transparent picture,” she said. “You’ve got to be more transparent and not convince people that the sky is falling.”
Madison Gas and Electric’s Gary Mathis said he did not see evidence of stakeholder advice in MISO’s proposed improvements.
“This issue has been around for a number of years, and MISO has been aware for a while of the improvements that are needed. … Certain projects in the queue will be realized,” he said. “I’m disappointed that we didn’t come further, and I question whether we were listened to in this process.”
The RTO says it will consider adding more resources in other phases of the queue as it carries out queue reforms.
Darrin Landstrom, MISO’s resource forecasting adviser, said the terms “committed” and “potential” will replace the “high certainty” and “low certainty” descriptors currently used for resources in the queue’s definitive planning phase.
Bonnie Janssen, a Michigan Public Service Commission staffer, said OMS could additionally include a “probable” category. MISO will send out questionnaires by March 31, with detailed results expected to be released in June.
Laura Rauch, manager of resource adequacy coordination, said MISO can provide stakeholders with mockups of survey results at the April RASC meeting.
RASC Chair Chris Plante plans to present MISO and stakeholder differences over the survey’s improvements to the Board of Directors during its March 23 meeting.
CAISO last year paid out $47 million more to congestion revenue rights holders than it took in from its auctions, the ISO’s internal Market Monitor has found.
That deficit — a persistent problem since the ISO instituted CRR auctions five years ago — could buttress the Monitor’s call for ending the auctions, which it says allows financial speculators to reap hundreds of millions of dollars at the expense of California electricity ratepayers. (See CAISO Monitor Proposes to End Revenue Rights Auction.)
“The [Department of Market Monitoring] believes that the trend of revenues being transferred from electric ratepayers to other entities warrants reassessing the standard electricity market design assumption that ISOs should auction off these financial instruments on behalf of ratepayers after the congestion revenue right allocations,” the Monitor said in its quarterly market issues and performance report covering the fourth quarter of last year.
The Monitor’s suggestion: Replace the auction with a bilateral or exchange market for contracts-for-differences for pairs of ISO nodes — also known as locational basis price swaps.
Under that arrangement, swaps would be traded among willing counterparties, rather than leaving ratepayers as unwitting parties in a market in which they are outmatched by more sophisticated traders, the Monitor says.
CAISO management has responded to the Monitor’s concerns by agreeing to consider a stakeholder initiative on potential changes to the auction, a move that has been met with mixed reactions from market participants. (See CRR Initiative Elicits Mixed Reviews from CAISO Participants.)
Proposal Unwarranted?
“While I don’t believe DMM’s latest findings warrant their specific proposal to replace the CRR auction with a bilateral market or locational price swaps … I think the CAISO’s study is absolutely an opportunity to make improvements to the current CRR auction and identify practices and transparency issues that may be causing some inefficiency in the CRR auction pricing,” Carrie Bentley, a principal with Resero Consulting, told RTO Insider.
Bentley’s firm frequently works on behalf of the Western Power Trading Forum (WPTF), an energy trader interest group that opposes the suggestion to scrap the auction. It has called the proposed stakeholder initiative a “pet project” of the Monitor.
The Monitor’s most recent findings show that last year’s CRR deficit increased by $1 million over 2015, with auction revenues representing just 68% of CRR payments made to auction participants, compared with 73% during the previous year.
While total payments to auction rights holders declined 15% to $147 million, auction revenues also fell 21% to $99 million year over year.
Financial traders last year took in $33 million from the auctions, paying 63 cents for every dollar made from their CRRs. Their overall take was down 30% from the previous year, but it still represented the largest share of all participants. The Monitor has contended that “purely financial entities” are the main beneficiaries of the auction program.
Power marketers saw their auction profits increase by 43% to $10 million, while generator profits fell by 29% to $5 million.
Load-serving entities, which CAISO provides an annual allocation of CRRs, made about $3 million from rights they sold into the auction, down sharply from $14 million earned the previous year.
CAISO’s congestion revenue rights auction revenues have consistently come up short of payments to rights holders, leaving ratepayers to foot the difference. | Q4 2016 Report on Market Issues and Performance, March 6, 2017; CAISO Department of Market Monitoring
Transmission congestion dropped last year as drought conditions resulted in decreased electricity use for moving water supplies across California. Transmission usage also was undercut by growth in behind-the-meter rooftop solar.
The fourth quarter saw the resumption of the prevailing pattern of CRR payments outpacing auction revenues, following a short-lived surplus during the third quarter (see chart).
WPTF Comments
In comments filed with CAISO earlier this year, WPTF contended that auction revenues increased as a percentage of payments in the third quarter after the ISO implemented practices that improved transparency into how it represents transmission outages in its market models.
“I think the fourth-quarter results were due to unexpected transmission outages and nomograms [prediction tools] that were not included in the CRR model or known by participants in advance of the auction,” Bentley said.
She cited as evidence the ISO’s own monthly market performance reports for October, November and December, which attributed at least a portion of auction revenue shortfalls each month to unexpected binding constraints on the transmission system.
Unlike other RTOs that have imposed penalties for “late, unnecessary or nonemergency outages that impact the day-ahead market, but were not modeled in the monthly auction,” CAISO has no such policies, Bentley said.
“Therefore, events like this last quarter are frequent, where outages impact CRR shortfalls with no repercussions on those causing the shortfall,” she said.
Bentley added that the ISO may compound the issue by not providing sufficient notice in advance of auctions about nomograms created to account for outages.
“While the majority of nomograms understandably may not be done in advance sufficient to notify market participants, a tightening up of transparency policies would enable better CRR auction outcomes in those cases that the CAISO could have given advance warning,” Bentley said.
Analysis Challenged
Ryan Kurlinski, manager of the Monitor’s analysis and mitigation group, rejected Bentley’s analysis. “There is no evidence to support WPTF’s suggestion that improvements in the ISO’s transmission outage reporting accounted for the reasons that CRR auction revenues exceeded payouts during the third quarter of 2016,” he said.
Kurlinski said the third quarter was “very anomalous” and that lower payments to auction participants stemmed from “unusually low” congestion appearing in the ISO’s day-ahead market during the period.
“During periods of this quarter, virtually no congestion appeared in the day-ahead market,” Kurlinski said. “DMM is working with the ISO to understand factors which might have caused this.” That lack of congestion likely accounts for last year’s overall drop in payouts to CRR holders.
Kurlinski doubted that adjustments to the auction model could ultimately improve outcomes for ratepayers.
“Even if the CRR auction model includes all outages known by CAISO [transmission owners] at the time the model is completed, there will be outages that cannot be adequately modeled,” Kurlinski said. “For instance, if an outage is scheduled for only a few days, this outage cannot be accurately represented in the monthly CRR model.”
WASHINGTON — PJM Independent Market Monitor Joe Bowring on Thursday warned that state plans to subsidize unprofitable generating resources present “a very real threat” to wholesale electricity markets.
The subsidies in question come in the form of zero-emission credits for uneconomic nuclear plants, which were included as part of New York’s Clean Energy Standard and are intended to aid the state’s transition away from fossil fuels and into renewables.
Exelon has been pushing for similar treatment for its nukes in Illinois, while FirstEnergy has said it will seek financial assistance for its Ohio plants.
“I don’t believe that any of the subsidies are being driven initially by state policy,” Bowring said during his PJM 2016 State of the Market Report presentation. “They’re being driven by the specific requests of generation owners about particular units because those units are not profitable. We would not be talking about the units in Illinois or Ohio if the capacity market prices had been higher and those units were profitable.”
| Monitoring Analytics 2016 State of the Market Report
Social goals — such as the reduction of carbon emissions to reduce the effects of climate change — can be accomplished through market-based solutions, such as a price on carbon, Bowring contended.
“Economists everywhere agree that … the most cost-effective way to do that is have a carbon price,” Bowring said. “It’s certainly not by picking individual power plants that are low carbon.”
To protect the markets from the effects of the subsidies, Bowring advocated for applying PJM’s minimum offer price rule (MOPR) to all existing resources. The rule currently covers only new subsidized gas-fired plants.
“Action is needed to correct the MOPR immediately,” the Monitor said in its report. “An existing unit MOPR is the best means to defend the PJM markets from the threat posed by subsidies intended to forestall retirement of financially distressed assets. The role of subsidies to renewables should also be clearly defined and incorporated in this rule.”
Bowring expressed concern that Illinois and Ohio could set a precedent for other states, calling the subsidies “contagious.” The Monitor views the threat as so severe that in January it filed as an intervenor in support of independent power producers opposing New York’s ZEC program.
“The ZEC program is not consistent with the operation of a competitive wholesale electricity market,” the Monitor told the New York Public Service Commission, adding that the program would artificially suppress NYISO, dissuade the construction of new generation and, if extended, “result in a situation where only subsidized units would ever be built.”
Record-low LMPs in PJM
The Monitor found that PJM’s energy, capacity and regulation markets were competitive during 2016. The average real-time, load-weighted LMP was $29.23/MWh, 19.2% below the previous year and the lowest since the competitive wholesale market commenced operation in 1999 — “which is fairly astonishing,” the Monitor noted.
| Monitoring Analytics 2016 State of the Market Report
Fuel prices were the main drivers: Gas prices were very low, while those for coal remained flat. High output from efficient combined cycle units — despite flat load growth — also played a significant role.
All those factors translated into a competitive market, Bowring said.
“New combined cycles have been added because of competitive markets,” he said. “They’ve been added because of the fact that we have a capacity market. … But for PJM overall markets, we probably would not have seen that level of entry of highly efficient combined cycles.”
As a result, net income for new combustion turbine and combined cycle units were up 21% and 14%, respectively. Meanwhile, profits decreased for new coal (54%), diesel (86%), nuclear (26%), wind (19%) and solar (28%).
Total transmission congestion costs fell by $361.6 million (26.1%), the result of low prices and smaller price differences across constraints.
Capacity Market
Capacity prices were lower last year than in 2015, except in the PSEG zone. Capacity revenue accounted for 43% of total net revenues for new combustion turbine plants, 32% for new combined cycles and 23% for new nuclear.
Total installed capacity last year rose 2.7% to 182,449 MW. As of Dec. 31, 101,474 MW were in the generation interconnection queue, with combined cycle units accounting for 68.3% and wind projects 14.4% of capacity. The Monitor expects gas to surpass coal in installed capacity this year.
Demand Response
Total payments to demand response resources decreased by $163.2 million (20.1%) to $655.7 million. Bowring attributed the decline to low prices, which undercut incentives to reduce power usage.
The capacity market remains the primary source of income for DR, making up 99% of its revenue — something Bowring is still not happy with, as he continues to advocate its removal from the capacity market. He said stakeholders are seriously considering the “best way” to manage those DR resources within the market.
“It’s important to understand our perspective here, which is not anti-DR at all,” Bowring said. “We’re very much pro-DR. We think it’s essential to making markets work. We want more people to have the option … to reduce demand and save capacity revenues.”
