NextEra Energy, which received FERC approval of its $21 billion bid to acquire Oncor earlier this month, is still facing questions on the deal from Texas regulators and calls for more protections from stakeholders.
The Public Utility Commission of Texas, which is scheduled to hold a hearing on the merits of the proposed acquisition Feb. 21, issued a seventh set of questions to the companies Jan. 11. The commission must render a decision by April 29 (Docket No. 46238). (See Texas PUC Sets Questions in NextEra-Oncor Merger.)
The PUCT staff’s latest questions focus on credit ratings and NextEra’s funding plan for the acquisition.
Several stakeholders also filed comments on the acquisition last week. The Texas Energy Association for Marketers urged the commission “to ensure that there are no impediments to competition and no cross-subsidization from the transmission and distribution utility to competitive affiliates of the utility.” It asked the commission to change a commitment prohibiting co-branding of the utility with a competitive affiliate to improve its “clarity [and] enforceability.”
NRG Energy called on the commission to “expand the protections that have been in place since 2008 in recognition of the greater challenges posed by the conflicts and incentives created by” NextEra’s proposed corporate structure.
It said the commission should prohibit NextEra from connecting generation to the Oncor transmission system and require NextEra to divest its retail electric providers to ensure it does not favor them over competitors.
NRG also asked regulators to require transmission and other capital projects above a certain cost threshold — NRG proposed $50 million — be approved by the commission, with cost caps and post-completion prudency reviews.
“This requirement is especially important given the potential that Oncor would have competitive generation affiliates and the fact that Oncor would be inherently incented to build transmission to optimize the delivery of power from its affiliated wind resources from neighboring transmission systems,” NRG said.
The PUC last year scuttled Hunt Consolidated’s attempt to acquire Oncor — the transmission and distribution subsidiary of bankrupt Energy Future Holdings (now Vistra Energy) — when it imposed conditions that caused Hunt to back away from its proposal. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
NextEra had no comment on the impending hearings or FERC’s approval. The commission’s Jan. 5 order found the Florida-based company’s proposed deal in the public interest (EC17-23).
While Oncor operates within ERCOT, it owns a 100-MW interest in a HVDC tie between the Texas ISO and SPP. Oncor also provides transmission service over ERCOT’s North and East interconnections and the Rio Grande Valley interconnection under a FERC tariff.
FERC accepted the companies’ assertions that the acquisition would not incent NextEra to exercise market power and that Oncor’s facilities are subject to FERC open access rules.
VALLEY FORGE, Pa. — On the day PJM submitted its five-minute settlement compliance filing to FERC, the Market Implementation Committee endorsed two proposed Manual 11 revisions related to shortage pricing, both of which were developed in response to FERC Order 825.
The order requires RTOs to align their settlement and dispatch intervals and implement shortage pricing as soon as a reserve shortage is detected in real time, rather than the current practice of allowing an RTO to wait until it has determined that the shortage will last for a sustained period of time.
Stakeholders asked PJM to perform a comprehensive review of the proposed manual changes — which would adjust the operating reserve demand curve — to ensure that all potential impacts are considered. Members were particularly concerned about whether the new three-step shortage pricing created any opportunities to take advantage of the system, or if it affected any existing market rules.
PJM believes the demand curve changes are necessary in order for it to appropriately implement Order 825’s five-minute interval requirement. The RTO hopes to submit revisions as a Section 205 filing sometime around March 1.
The revisions would insert an additional step in the curve at the $300 penalty factor allowing the reserves to be “extended” or increased. Under current practice, PJM can only extend reserve requirements in specific situations related to the issuance of hot or cold weather alerts. (See “Protocol Changes Proposed for Implementing Order 825,” PJM Market Implementation Committee Briefs.)
Citigroup Energy’s Barry Trayers asked whether the new steps would affect the “Four-Tick Rule,” which affects how some costs, such as balancing uplift charges, are allocated based on the number of intervals within an hour that certain conditions exist. PJM’s Dave Anders said that issue is being discussed through the Energy Market Uplift Senior Task Force.
“It seems like we’re finding [issues created by the new rules] instance by instance, and it might be better if somebody went through and … found [all of] the impacts,” Trayers said.
Other stakeholders asked about the potential for “opportunistic behavior” among some market participants if shortage pricing is implemented without simultaneously switching to five-minute settlements. PJM Independent Market Monitor Joe Bowring acknowledged that there is no rule against such activity, but he said “if people are taking advantage of that rule, we will refer them to FERC.”
While Order 825 specified a May 11, 2017, implementation date, PJM is requesting that its proposals on five-minute settlements and shortage pricing be implemented simultaneously on Feb. 1, 2018. The compliance filing seeks a response from FERC by Feb. 15.
If FERC approves the delayed implementation date, PJM would relax its timeline for the Section 205 filing related to the demand curve until April. Otherwise, it will keep its March 1 target for the filing and request that shortage pricing be implemented simultaneously with five-minute settlements.
PJM Gives First Take on NOPRs
PJM staff offered their initial impressions of two Notices of Proposed Rulemaking recently distributed by FERC.
One NOPR addresses price-setting related to fast-start resources, while the other considers rules for storage and distributed energy resource aggregation.
The fast-start NOPR issued on Dec. 15 has five proposed requirements to better integrate fast-start units in market pricing. PJM’s Lisa Morelli said the commission will likely need to expand its fast-start definition to cover resources with start-up times of an hour or less in order to realize intended benefits. The proposed rule limits the definition to units capable of ramping up within 10 minutes.
“We really have minimal resources that fall into the 10-minutes-or-less bucket,” Morelli said.
PJM’s response to FERC will clarify that it believes the fast-start category also applies to demand response. The RTO also believes that FERC intends for the rule to provide more flexibility for block-loaded resources such as combustion turbines, but Morelli said staff think disincentives for over-generation will be need to developed. RTO staff also have “some hesitation” about FERC’s proposal to allow offline resources to set the fast-start price, she said.
To fulfill FERC’s final proposal on including fast-start pricing in both day-ahead and real-time markets, PJM would focus on keeping the modeling and rules appropriate for each market, although not necessarily the same.
“In general, we like to keep the modeling consistent,” Morelli said, but she acknowledged the RTO is “not guaranteeing” it.
The deadline for filing comments is Feb. 28.
The DER and storage NOPR issued on Nov. 17 includes multiple proposals.
“It’s pretty broad,” PJM’s Andrew Levitt said. “Even within those sections, there’s quite a lot in play.”
Regarding the storage provisions, “PJM has already checked a lot of those boxes,” he said. The NOPR could be read to indicate that RTOs should be managing the state of charge for new offers, and “that’s something we’re chewing on internally.”
The DER section has prompted an “extensive” discussion about coordination with electric distribution companies, Levitt said.
Several stakeholders representing state interests expressed reservations about the proposal.
“In general, we states like to keep our hands on the mechanisms that control retail, and FERC [and RTOs] handle wholesale,” said Debbie Gebolys, a research analyst with the Public Utilities Commission of Ohio. “If we’re going to have them at the same party, how do we handle that?”
John Farber of the Delaware Public Service Commission said that debate is a “touchstone issue” because it’s not possible to “unmingle electrons.”
“Unless that issue is fully satisfied, it could create problems for states,” Farber said.
Levitt acknowledged the concerns. “We’re recognizing there’s much closer contact between retail and wholesale with DER.”
Problem Statement Endorsed to Address Pseudo-Tie Meter Correction
Stakeholders endorsed by acclamation a problem statement and issue charge proposed by the North Carolina Electric Membership Corp. to develop a protocol for monthly pseudo-tie meter correction.
Currently, no mechanism exists for monthly corrections of reported energy flow. Dave Pratzon of GT Power Group questioned whether the issue will be solvable within PJM or require collaboration with neighboring RTOs. PJM’s Ray Fernandez acknowledged that the question will be addressed in the research performed by the Market Settlement Subcommittee.
Spot-in Transmission Analysis Expanded to all Interfaces
Stakeholders approved revisions to a problem statement and issue charge intended to address spot-in transmission issues, expanding the analysis to consider all of PJM’s interfaces, not just that with NYISO.
The committee has already identified two potential solutions.
The first, more complex solution would entail NYISO modeling PJM’s available transfer capability (ATC) alongside its own in the ISO’s economic clearing engine. Spot-in transactions would then be allowed to clear economically up to the lower of the transfer values.
The second solution would move PJM’s earliest request time for spot-in service to 10 a.m. from the current 9 a.m. The delay would allow potential market participants to learn if their NYISO bid has been approved before requesting service into PJM. While this option would be easier to implement and easier to apply universally, it doesn’t directly address the issue.
Joe Wadsworth of Vitol, who has long sought resolution of the issue, prefers the first solution. “We wouldn’t oppose solution ‘B’, but it doesn’t get to the heart of the situation,” he said.
PJM Has No Objection to IMM’s ‘Paper Capacity’ Report
Bowring presented updated results of his team’s ongoing study on replacement capacity. The report found that some market participants are offering “paper capacity” into Base Residual Auctions and buying out of the obligations during subsequent Incremental Auctions to take advantage of price differences. (See PJM Monitor Asks FERC to Act on ‘Paper Capacity’.)
EnerNOC’s Katie Guerry contended that Bowring hadn’t sought comments from stakeholders before publishing the report and filing it at FERC. She asked what PJM’s stance was on the topic.
“Generally speaking, we don’t disagree with the report,” PJM Senior Counsel Jen Tribulski said. “We wouldn’t file anything with FERC to say we disagree with the report.”
PJM is proposing rules that would exempt certain substation equipment from competitive bidding because issues stemming from existing components are typically resolved by equipment upgrades, Mark Sims, transmission planning manager for the RTO, explained during last week’s Planning Committee meeting.
Exempting those types of upgrades, which won’t result in greenfield proposals, from competitive bidding will prevent the process from becoming overly complicated, PJM believes.
While transmission-level transformer upgrades were initially listed in the scope, they have been removed from the proposed rules. Instrument-level transformers will be exempted.
If the analysis shows that a greenfield project is possible, PJM would open a competitive window, Sims said.
“We wanted to avoid situations where we had to make a lot of judgements,” said Steve Herling, vice president of planning.
Gas, Solar Lead Interconnection Queue as PJM Seeks to Streamline Process
Natural gas generation represents the majority of projects seeking interconnection since 2011, although solar is quickly increasing, according to a queue analysis presented by PJM’s David Egan.
Solar projects are typically seeking 60 to 70% capacity interconnection rights — or even more for those utilizing panel-tracking technology, Egan said. Tens of thousands of additional megawatts remain in the queue, partly because PJM receives more than a third of interconnection requests the day before the queue closes, with more than half of them arriving within the final week. PJM is working on ways to increase earlier submissions.
“We’re actively trying to relieve that backlog,” he said.
“These numbers are way down from where they were several years ago,” Herling said. “We’ve made substantial progress, but there’s more work to do.”
PJM Largely in Compliance with Interconnection NOPR
PJM has already implemented many of the rules proposed in FERC’s Dec. 15 Notice of Proposed Rulemaking on generator interconnection, Aaron Berner, manager of interconnection analysis, said during an explanation of the new proposal.
Among the many provisions, the NOPR would require transmission providers that conduct cluster studies to develop a periodic restudy process; modify large generator interconnection agreements to require that transmission owners and interconnection customers mutually agree to have the owner opt to initially self-fund the costs of network upgrades; and require RTOs to establish an interconnection dispute resolution process.
The new rules would improve certainty, transparency and other aspects of the process, Berner said. The proposal comes after the American Wind Energy Association filed a petition with FERC that prompted a technical conference on the issue.
The RTO has no protocols for NOPRs, PJM’s Dave Anders explained, but it does have precedent. With the need to review and respond within 60 days after the notice is published in the Federal Register, going through the stakeholder process will likely take too long, he said.
Load Estimates Drop in Mid-Cycle RTEP Assumptions
The long-term proposal window for the 24-month market-efficiency cycle of the Regional Transmission Expansion Plan closes Feb. 28, PJM staff told stakeholders during last week’s Transmission Expansion Advisory Committee meeting. The mid-cycle window, open from January to April, will update major assumptions, including load and demand forecasts, fuel prices, generation expansion and topology. Proposals will be reviewed until October, with final determinations published in December.
The mid-cycle updates include a drop in expected annual peak load compared with last year’s forecast, with 2031’s projection down 5%.
Sue Glatz, PJM manager of infrastructure coordination, confirmed that projects already under construction based on old assumptions won’t be scrapped if they aren’t economic under the new ones. Paul McGlynn, senior director of system planning, said most approved RTEP projects have such a healthy benefit-to-cost ratio that a slight load change won’t make much of a difference.
Additionally, Baltimore Gas and Electric’s Crane generating units and Exelon’s Quad Cities have withdrawn their deactivation notifications.
Artificial Island Finalists to Be Announced at Special TEAC
PJM plans to recommend at least two finalists when it presents its re-evaluation of the Artificial Island project to the Board of Managers in April, Herling said. Staff are nearly done with reanalysis of the project, PJM’s first competitive solicitation under Order 1000, and are developing a “fairly substantial document” to present to the board. Herling said his staff will schedule a special meeting of the TEAC to go over the plans.
The document will address issues previously raised by stakeholders, and changes to the project’s scope will reduce project costs by about $130 million, Herling estimated. However, the reanalysis will not address cost allocation, which has been a contentious issue with stakeholders.
Requests for Information Dominate TEAC
Staff’s review of RTEP proposals elicited a barrage of questions — and requests for the RTO to provide more information.
American Municipal Power’s Ed Tatum led the inquiry, repeatedly asking what criteria made certain proposals preferable and why alternatives hadn’t been considered.
He said that American Electric Power had provided a “nice document” explaining its infrastructure-replacement process and guidelines in response to his questions from previous TEAC meetings. “This is a good start, and we look forward to getting more detail,” Tatum said.
LS Power’s Sharon Segner questioned why certain projects hadn’t been opened to a competitive bidding window.
“I don’t think it should be an automatic assumption that just because something is ‘immediate need,’ there is no window for it because that’s not what the tariff says,” she said.
PJM’s Mike Herman said staff will attempt to indicate whether a project should be subject to competitive bidding.
Stakeholders were also concerned about additions to the Bergen-Linden Corridor project in Public Service Electric and Gas’ northern New Jersey district.
PJM is recommending that four shunt reactors be installed to add 600 MVAr of reactive power to address potential voltage violations after the current project is constructed.
Jim Jablonski, executive director of the Public Power Association of New Jersey, asked how the project, which already has a $1.2 billion price tag, produced another $90 million in costs.
PSE&G’s Esam Khadr explained that retirement of generating units with reactive capabilities has been a major driver of the additional issues. Building underground is the only option in the region because of congestion. However, underground circuits so close together act as capacitor plates that create high-charging and high-voltage problems, McGlynn said.
The Western Area Power Administration has selected a route for the TransWest Express transmission project, a proposed 730-mile, extra-high-voltage DC line designed to deliver large volumes of renewable energy into the desert Southwest.
The announcement comes a month after the U.S. Interior Department’s approval of the project — which would cross about 440 miles of Bureau of Land Management land — after eight years of environmental studies.
TransWest Express transmission line map | TransWest Express LLC
The proposed 600-kV line would run from south-central Wyoming, passing through Colorado and Utah and ending at the Marketplace Hub substation about 25 miles south of Las Vegas. That hub functions as a major wheeling point for transmitting power from the interior West into Southern California.
WAPA’s decision will enable project developer TransWest Express to proceed with design and engineering activities, as well as position the agency “to better evaluate its options for participation in or financing of the project,” the agency said in a statement.
The federal power marketing administration is supporting the project through its Transmission Infrastructure Program, which allows transmission developers to “leverage” the agency’s development experience and provides eligible infrastructure projects with access to federal financing.
“Collaboration between WAPA and energy developers is critical to developing infrastructure capable of meeting our nation’s growing energy needs while minimizing environmental impacts,” WAPA Administrator Mark A. Gabriel said. “This decision and comprehensive study provides the foundation to further the project’s development.”
TransWest Express is a subsidiary of the Denver-based Anschutz Corp., a privately held company with extensive investments in energy and real estate.
The project will boast 3,000 MW of bidirectional capacity when completed. The line’s primary function will be to allow loads in Arizona, California and Nevada to tap the output of planned wind resources in Wyoming.
Project specifications include two 200-acre AC/DC converter stations at each terminating point, a fiber optic network communications system and two 600-acre ground electrode facilities.
The project is expected to cost about $3 billion and take three years to complete after the start of construction. WAPA and BLM were the lead agencies in preparing the environmental impact statement for the project, which is still subject to approval from additional state and federal regulatory bodies.
VALLEY FORGE, Pa. — PJM staff last week outlined a proposal to lengthen the RTO’s Regional Transmission Expansion Plan cycle for reliability projects from 12 months to 18 months.
Staff explained the plan at a special session of the Planning Committee on redesigning the Transmission Expansion Advisory Committee.
The proposal comes in response to more detailed analysis of the optimal timing for the planning cycle, a component of the TEAC redesign that began about a year ago, staff said.
The expansion of the cycle — along with the development of a flowchart for how projects will move through proposal windows — would represent a “memorialization” of existing processes that have never been specifically defined, PJM’s Mike Herman said.
The proposed change would take effect for the 2018 planning year, moving the beginning of the cycle to September 2017. The RTEP cycle for market efficiency projects would remain unchanged.
Stakeholders expressed concern about the decisional-process flowchart and asked for additional transparency around why certain projects are rejected. They also sought more opportunities to provide input.
Staff acknowledged some of the concerns but pushed back on others.
Paul McGlynn, PJM senior director of planning, said it would be challenging to rank projects against each other because of the difficulty in comparing the relative benefits of dissimilar project factors.
Vice President of Planning Steve Herling provided a hypothetical example of the challenge: “There’s no way to show how much a perceived benefit is going to wipe away the ability to get a right of way through the Gettysburg Battlefield.”
Alex Stern of Public Service Electric and Gas questioned the wisdom of trying to incorporate all project drivers into a single comprehensive manual and warned that critical pieces might get “lost in the sauce.”
PJM staff acknowledged his concerns. “Ultimately, I’m less concerned about the format of the manuals than about the content,” Herling said.
Stern also suggested that PJM include a provision to limit the potential for selling a project before or after it’s built, which attorney Steve Huntoon warned might create “unintended consequences that raise risk.”
The next meeting on the issue is scheduled for Feb. 10.
CARMEL, Ind. — MISO is poised to implement a laundry list of changes intended to improve its capacity market, some of which should take effect in time for the 2017/18 Planning Resource Auction.
The most significant — and controversial — is a proposal that would apply a 50-MW physical withholding threshold to affiliated market participants on a collective basis, rather than to each affiliated company individually.
The RTO’s Independent Market Monitor recommended the change in its 2015 State of the Market report, contending it would prevent a supplier from avoiding mitigation by creating multiple affiliates to increase its withholding threshold. (See “MISO Takes 1st Steps in Monitor Recommendations,” MISO Resource Adequacy Subcommittee Briefs.)
MISO plans to file the change with FERC on Jan. 17, MISO Manager of Resource Adequacy John Harmon said during Wednesday’s Resource Adequacy Subcommittee meeting.
In light of the change, the Monitor will this year begin to review bids made by affiliated market participants during the offer window. Monitor staff will contact affiliates once to notify them of a violation, providing an opportunity for violators to resubmit offers. Affiliates that continue to exceed the 50-MW threshold after the offer window closes will be subject to sanctions.
“It’s important to remember the offer window is a three-day window,” Harmon said. “Most offers are received on the first day, but there are three days” to submit offers.
Monitor staff member Michael Chiasson said the Monitor will not tell affiliated companies the specific volume of their collective shortfall of offers.
“It’s on or off, like any other light on the dashboard,” Chiasson said. Penalties will be identical to sanctions already detailed in Module D of the Tariff, which include fines, ineligibility for revenue sufficiency guarantee payments, bans on submitting virtual transactions or a condition that all of a company’s power requirements be scheduled in the day-ahead market.
Chiasson noted that the Monitor will notify violators of shortfalls by phone or emails and rely on contact information from the operating cost survey contact list and MISO’s official market participant registry.
“I just worry about the nightmare scenario that you’re calling and no one is picking up the phone,” said Jamie Watts, an attorney with the Long Law Firm.
Harmon said that MISO would not simply “leave a voicemail with a random individual and then shrug our shoulders.”
Some stakeholders are still wary of the change, maintaining that FERC Order 697 already prohibits affiliates from colluding to dodge withholding mitigation.
“I’d love to see what antitrust officials think of this,” said David Sapper of Customized Energy Solutions. “But that’s not relevant — or it might be.”
Tariff Clarifications
MISO will revise Module D of its Tariff to allow planning resources to request facility-specific reference levels for the auction. Offers for resources that make no such request will be set to $0/MW-day, as required by FERC. (See FERC OKs MISO Use of PJM Cost Estimates for Mitigation.)
Because a cost of new entry conduct threshold continues to apply to the auction’s initial reference level, the Monitor recommends that all resources whose competitive cost of selling capacity exceeds $26/MW-day request a facility-specific reference level. The RTO and Monitor are also proposing to exempt demand resources, energy efficiency resources and external resources from mitigation measures. The changes will be filed Jan. 17.
One stakeholder contended that resources external to the RTO should also be subject to mitigation, but MISO pointed out that external resources have no obligation to offer into the market and should not be discouraged from volunteering offers at their own prices.
The RTO has yet to establish an effective date for the changes because the filing will be made so close to auction registration, according to Jacob Krouse, MISO’s corporate counsel, but implementation could occur in time for the 2017/18 auction.
Indianapolis Power and Light’s Ted Leffler said the new reference levels were confusing. “I’m hearing zero, 10% of cost of new entry, and it all seems to be a bit of mush to me,” he said.
North-South Limit Calculation Specified
MISO will update its Tariff to specify a method for calculating transfer limits of flows between its North and South regions that cross SPP’s system, as directed by FERC late last year. (See FERC Backs MISO on Transfer Limit, Seeks Details.) The new provision will direct RTO staff to determine a megawatt limit by reviewing seams, transmission service and coordination agreements. Transmission providers will then be required to conduct a feasibility analysis to determine whether tighter limits are needed.
Harmon said MISO will submit a compliance filing by the end of the month (EL16-112), but the RTO is open to receiving stakeholder feedback up until Jan. 20.
Chiasson objected to the subtraction of all firm transmission service in determining the calculation for the limit and encouraged MISO to study the probability of actual firm transmission use to come up with a more accurate limit.
“When capacity import limits and capacity export limits are determined between [other MISO] zones, those determinations don’t use any firm transmission reservations,” Chiasson said. “We think that should also be true for limits between the North and South regions.”
The Monitor is likely to protest the filing, he added.
For the FERC directive to develop going-forward costs for facility-specific reference levels, also contained in the transfer limit order, MISO will use two years of data and a formula in which the hypothetical cost of suspension or retirement at the beginning of a planning year is subtracted from costs incurred during a 24-month period if the resource retires or suspends at the end of the planning year. MISO defines going forward costs as the sum of operations, administrative, taxes and insurance, maintenance and capital expenses.
Harmon said the calculation will become effective in time for the 2017/18 auction. While FERC did not require a specific deadline for implementation, the order did stipulate that the changes become effective in “future planning years.”
Dynegy’s Mark Volpe objected to the short gap between the filing and effective date, as many auction data collection deadlines occur on Feb. 15.
“Now you’re telling us that you’ve only got two weeks to change gears,” Volpe said. “You’ve led us to believe it was on a prospective basis for the 2018/19 Planning Resource Auction. … Now you’re saying it’s the seventh inning and we’re going to switch the rules.”
Chiasson said market participant data requirements are largely unchanged from prior years, adding that the Monitor has already asked for two years of planning data.
“I don’t think it will be work wasted,” Chiasson said. “But it would have been nice to know before the work started.”
Tim Bachus, MISO capacity market administration analyst, said the 2017/18 PRA is on schedule. He said 94% of market participants have submitted data for the Generator Verification Test Capacity reporting.
MISO is considering other improvements for the PRA — in addition to a proposal for seasonal categories and six new external resource zones — while awaiting FERC’s verdict on a request to implement a bifurcated capacity market.
Harmon said the RTO is seeking stakeholder evaluation of five potential changes, including:
Penalizing participating units that expect to be on planned or forced outages for most the planning;
Relaxing auction accreditation rules for hydroelectric assets that serve as load-serving entities, rules that MISO says might be too “onerous” and might not recognize capacity benefits;
Improving the partial unit clearing algorithm, which Harmon says clears marginal offers on a pro rata basis “that can result in resources clearing a small percentage of their unforced capacity, resulting in capacity revenue less than their costs”;
Creating a capacity accreditation formula for battery storage before widespread adoption of batteries occurs; and
Clearing up MISO rules and the Tariff with respect to treatment of behind-the-meter generation in the capacity auction.
Chris Plante of WEC Energy Group asked if any of the improvements could be implemented by the 2017/18 planning year.
With stakeholder support, improvements will be discussed throughout 2017 and implemented in the 2018/19 planning year, alongside the first separate forward capacity market for retail choice areas, Harmon replied.
MISO has sidelined the discussion of seasonal and locational auction issues until February, RASC liaison Shawn McFarlane said.
“Certainly the [Competitive Retail Solution] is the primary objective and we need to get that through before we tackle too much, but we’re looking at other resource adequacy improvements, including seasonal and locational improvements,” McFarlane said.
Leffler questioned whether seasonal constructs should continue to be a priority, given that stakeholder support has cooled since MISO revealed design specifics last year.
“I’d encourage people to provide that feedback,” Leffler said to stakeholders.
FERC last week approved a designated entity agreement (DEA) for Transource Energy to construct the AP South Congestion Improvement Project, subject to the outcome of a formula rate case the company has submitted to the commission (ER17-349).
PJM last year approved a $340.6 million proposal by Transource and Dominion High Voltage to address the congestion issue along the border of southwestern Pennsylvania and northwestern Maryland, despite criticism from other stakeholders. FERC noted in its approval that Transource has submitted security of $5.55 million for its $197.1 million portion of the project. (See “Planners to Recommend $340.6M Solution to Congestion in AP South,” PJM Planning Committee & TEAC Briefs.)
The commission’s approval lists Transource’s project requirements, including the installation of a 230-kV double-circuit line between the Ringgold substation and the new Rice substation and one between the Conastone substation and the new Furnace Run substation.
Old Dominion Electric Cooperative objected to the DEA, saying that it included cost recovery items that the commission should consider individually. American Electric Power responded that the agreement instead provides better transparency into Transource’s cost-containment commitments. (Transource is a joint venture of AEP and Great Plains Energy.)
FERC acknowledged both points, ruling that its acceptance of the DEA is subject to the outcome of the rate case (ER17-419).
Solar photovoltaic resources can provide ancillary services in a way comparable to — or better than — conventional generating resources, according to a study released by CAISO last week.
That finding was based on testing conducted last August in collaboration with the National Renewable Energy Laboratory (NREL), First Solar and Southern Co. using a 300-MW solar facility within the CAISO footprint.
“These test results demonstrated how smart inverter technology can leverage PV technology from simply generating as a variable energy resource to providing ancillary services, such as spinning reserves, load following, voltage support, ramping, frequency response and regulation, and power quality,” the ISO said.
| First Solar
The tests were performed to address industry concerns about transmission reliability as a growing amount of renewable resources interconnect with the grid — the result of both state renewable energy mandates and the increasing cost-competitiveness of wind and solar generation.
Unlike conventional generators that have the ability to automatically vary their turbines’ rotational speed and output based on the pull of load, nonconventional technologies typically have little or no inertial response to momentary changes on the grid.
That built-in capability of conventional resources functions as a kind of damper for frequency excursions. It also leaves those resources better equipped than renewable generation to offer key grid services such as frequency response and voltage support.
The CAISO findings could undermine that conventional wisdom and expand market options for renewable resources, as the ISO develops and refines market mechanisms intended to compensate resources equipped to rapidly react to automatic signals to respond to grid disturbances — both of which are increasingly likely to occur because of increased penetration by variable renewable resources. (See CAISO Seeks Primary Frequency Response Market.)
The results also demonstrate that renewables can, within certain limits, provide the fast-ramping capability needed to respond to variable output from renewable generation located in other areas of the grid — in effect using renewables to integrate renewables.
“These findings mean renewable energy in the ISO footprint — and beyond — could be integrated into power grids at a much higher level and faster pace than once believed, giving a glimpse at the future green and sustainable electric networks,” Clyde Loutan, the ISO’s senior advisor for renewable energy integration, said in a statement. “With these results, the electric industry can expect one day to realize ambitious goals of using primarily renewable sources to power our economy.”
The report notes that a key aspect of the “grid-friendly” nature of First Solar’s solar power plant is a plant-level controller, or PPC, developed by the company to regulate the plant’s real and reactive power output and ensure that the PV arrays collectively function as a single generator.
“Although the plant is comprised of individual inverters, with each inverter performing its own energy production based on local solar array conditions, the function of the plant controller is to coordinate the power output to provide typical large power plant features, such as [advanced process control] and voltage regulation through reactive power regulation,” the report said.
As a result, the PPC, and the facility as a whole, are capable of providing such functions as output curtailment in order to avoid an operator-specified limit, ramp-rate control to ensure that the plant ramps up or down as directed, and frequency response service.
Improvements in inverter technology can allow a solar plant to provide “essential reliability services” and enable renewable resources to help further integrate additional renewable resources, the ISO said.
“These tests demonstrated how controls can leverage the value of solar photovoltaic plants from being simply a variable energy resource to providing services that range from spinning reserves, load following, voltage support, ramping, frequency response and regulation, to power quality,” said Vahan Gevorgian, chief engineer at NREL’s Power Systems Engineering Center.
The ISO plans to perform similar testing on a large wind farm, which it expects will also be positioned to provide reliability services based on the use of similar technology.
The use of solar and wind resources to provide such services will enable the ISO to move more emissions-free power into its system during periods of high renewable production, an “essential” development for California to meet its statutory mandate of generating half of its electricity from renewables by 2030, according to the ISO.
“The next steps are to identify regulatory and operational barriers to the feasibility of renewables providing essential reliability services and explore economic and contractual incentives to maximize the potential for renewables to provide these services,” the ISO said.
VALLEY FORGE, Pa. — PJM has developed a load forecasting process that has improved the grid operator’s prediction accuracy, staff meteorologist Elizabeth Anastasio told stakeholders at a Jan. 11 Operating Committee meeting.
PJM purchases three weather forecasts from different vendors, Anastasio explained. Load forecasts based solely on the most accurate of the three created an average error of 1.91% in 2016.
Using its own, more comprehensive forecast process, PJM achieved an average 1.79% error rate during the same period.
Each day, PJM produces a forecast for the current day and the week ahead for 22 zones within its footprint, as well as for several aggregates and the entire RTO. Dispatchers can update forecasts at any time, and updates are published twice hourly at 15 minutes and 45 minutes past the start of the hour.
Initial forecasts are posted by 10 a.m. ET, before the close of the day-ahead market at 10:30 a.m. At 6 p.m., the current forecast update becomes the “original” forecast for the next day in members’ Data Viewer portal.
Dispatchers combine the weather forecasts with information about the day — such as the season or whether the day is a holiday — and historical load information to develop eight models. Several of them perform best on days with normal conditions, while others are most useful under specific circumstances.
“On average, the ensemble models are our best performers,” Anastasio said. “On holidays, a lot of these models are going to give you trouble.”
Unusual weather conditions, daylight saving time and a lack of information on load sources and likely human behavior can also contribute to forecast errors, Anastasio said. Dispatchers minimize those discrepancies in several ways, including by “backcasting” — a process used to determine what factors would have produced a perfect forecast and compare them with the factors that were actually used.
PJM is improving the process, she said, by combining the forecasts into a “smart mix,” creating better models, implementing a solar forecast, developing a load forecast analysis team and participating in industry forums on the topic.
“There’s a lot of things going on behind the scenes to make this better,” she said.
Manual 40 Revisions Approved with Exelon’s Addendum
Members endorsed PJM’s proposed Manual 40 changes that will reduce the grace period for completing operator training. The proposal had been updated from previous versions to include a phrase proposed by Exelon.
Exelon asked for language clarifying that the clock for the grace period begin only after the operator is “deemed qualified” by the employing company. PJM has proposed cutting the grace period in half to six months. (See “PJM Moves to Cut Operator-Training Grace Period in Half,” PJM Operating Committee Briefs.)
PJM plans for the new requirement to apply to anyone who begins training on Feb. 1 or later. Trainees who begin earlier than that date will remain subject to the 12-month grace period.
PJM Moves to Relax Refresh-Rate Standards
PJM plans to relax its telemetry scan rate requirements for internal special cases and transformer tie lines from four seconds to 10 seconds in proposed changes to Manual 1, PJM’s Ryan Nice explained.
However, he noted that if more than one regulation is involved, the more stringent standard still applies.
Emergency Procedure Messages Added
Two potential message types have been added as emergency procedure events: Conservative Operations and Synchronized Reserve Events, PJM’s Dave Hislop explained.
Conservative Operations might be declared when the RTO (or a portion of it) is undergoing, or has the potential to face, adverse impacts from a weather or environmental event and requires enhanced RTO reliability efforts, or if it enters an unknown operating state, such as an outage to its Energy Management System. PJM added this message type to any facilities that receive hot or cold weather alerts.
PJM has consistently exceeded its frequency response obligation based on criteria set by NERC.
Synchronized Reserve Event notifications were removed from the system in 2012 because the events are usually of such a short nature that operators often posted the notification after the event had already been canceled. Members have asked them to be reinstated now that notifications are system-automated and posted immediately. The notifications will be sent for the reserve capability of generation units that can be converted into energy or demand response resources able to respond within 10 minutes. PJM added this message type to any facilities that receive primary reserve alerts.
PJM Satisfying Frequency Response Obligation
PJM’s field trial performance has exceeded its expected frequency response obligation (FRO) every year since NERC’s BAL-003 standard went into effect in 2011, PJM’s Danielle Croop said.
“We are well above our obligation in our performance measure,” she said.
The performance is measured as the median of all NERC-selected events. Of 28 events selected in 2016, PJM met or exceeded its obligation on all but five. PJM’s FRO for the 2017 operating year is -258.31 MW/0.1 Hz.
“Coordination is an important part of MISO’s ongoing strategy, but it has a lot of different time horizons as our reliance on gas grows,” said MISO adviser Scott Wright at a Jan. 11 subcommittee meeting.
The RTO’s foremost priority is ensuring grid reliability while “analyzing and vetting” resource adequacy risks under increased gas reliance, according to Wright.
“We’re very well positioned in MISO with a good gas pipeline system,” Wright said. “Our 15-state footprint has about 20 to 30 pipeline systems.”
MISO will this year pilot a program that sends hourly gas usage profiles to a handful of selected pipeline operators. RTO staff will update stakeholders on the project later in the quarter. (See MISO to Continue Gas-Electric Coordination Efforts in 2017.)
Wright repeated assurances that the RTO will not try to influence generator behavior with the use of hourly profiles and expanded contingency planning: “For us, it’s knowing what is going on. It’s a way to be proactive in real time so operators know what kind of headroom they have.”
Preliminary Load Forecast Released
Preliminary data from MISO’s independent load forecast for the 2017/18 planning year indicates the RTO expects coincident peak demand of 122 GW during the period and a 135-GW planning reserve margin requirement.
Other details from the preliminary forecast:
Zone 1, covering Minnesota, North Dakota and western Wisconsin, shows a 16,307-MW coincident peak forecast and a 18,246-MW planning reserve margin requirement;
Zone 2, covering eastern Wisconsin and upper Michigan, should register 12,184 MW in coincident peak demand and will require a 13,410-MW planning reserve margin;
The collective coincident peak forecast for Iowa’s Zone 3, Missouri’s Zone 5 and Michigan’s Zone 7 comes in at 36,673 MW, with the planning reserve margin requirement expected to be 40,667 MW;
Zone 4 in Illinois should peak at 8,975 MW and have a 9,920-MW planning reserve margin requirement; and
Zone 6, covering Indiana and Kentucky, should register a 16,577-MW coincident peak and hold a 18,512-MW planning reserve margin.
MISO South — which includes Arkansas’s Zone 8, Zone 9 covering Louisiana and Texas and Mississippi’s Zone 10 — together have a 36,673-MW coincident peak forecast and a 34,081-MW planning reserve margin requirement.
Consumers Energy’s Jeff Beattie contended that data should not be combined for Michigan’s Zone 7, Iowa’s Zone 3 and Missouri’s Zone 5 because Consumers and DTE Energy are required to report their own load data to Michigan. He said the combined data is concealing trends that the company could otherwise identify and use.
“It’s putting us at a disadvantage,” Beattie said.
DTE’s Nick Griffin said he also supported more data transparency among zones.
RASC Chair Gary Mathis said the item would be taken up at the March meeting, when MISO plans to post more up-to-date values and host a discussion on the issue.
