Page 1366 – RTO Insider

August 15, 2016

PJM Market Implementation Committee Briefs

Excess capacity expected to be released in the third incremental auction for the 2017/18 delivery year in February would likely clear at $0 under current rules, PJM’s Jeff Bastian told the Market Implementation Committee Wednesday.

To avoid that, PJM presented a proposal that would release excess capacity on an upward trajectory, ranging from 0 MW at $10.74/MW-day to all 10,017 MW being available at $144/MW-day or 1.2 times the Base Residual Auction clearing price.

That is, the RTO would retain more capacity at lower prices but be willing to release more at a higher price.

PJM must file its plans for releasing the capacity with FERC by November. Because of that time constraint, some members suggested advancing the PJM proposal to the Markets and Reliability Committee for a first read.

Among them were Jeff Whitehead of Direct Energy and Mike Borgatti, representing NextEra Energy. Both said they would be willing to forego their companies’ alternate proposals to support PJM’s solution.

At the July MIC meeting, Direct Energy had proposed using a sloped offer curve to create a price floor that would prevent supply resources from being able to cheaply buy out of their obligation at load’s expense. NextEra proposed PJM’s sell offer equal the transitional incremental auction adder that the RTO charges to load. (See “Members Debate Ways to Release Excess Capacity into Incremental Auction,” PJM Market Implementation Committee Briefs.)

Bastian said all three approaches are intended to preserve value for load.

“If the clearing price is zero, then you are releasing capacity commitments with no benefit going back to load,” he said.

The PJM proposal contains three parts. The first retains the status quo for how PJM determines the quantity and price at which it procures or releases MW in an incremental auction due to changes in load forecast or reliability requirements.

The second part, however, would release the 10,017 MW separately, according to the upward-sloping price curve.

Lastly, any of those separately released MW that did not clear would not be included in the determination of excess commitment credits.

“We would exclude this uncleared quantity from the quantity included in the first bullet,” Bastian explained.

Katie Guerry of EnerNOC said she was surprised by PJM’s new proposal, given that in July it had presented a plan to release capacity into the 2017/18 year using the same method FERC had approved for the 2016/17 delivery year, which yielded $4.79/MW-day.

“To hear PJM changing [its] position after the conclusion of that second incremental auction, after what we’ve been hearing from PJM for months now, is a little confusing,” Guerry said, adding that she was not comfortable with the issue being advanced yet to the MRC.

“PJM’s thinking has evolved,” Bastian said. “I wouldn’t say we had a position here. When we brought this forward again, we brought it forward as a discussion item. Our intent at this point would be to release it. We could go forward using the same method as last time. But if we use the same method, we’re likely to clear at zero, and that didn’t seem to make sense.”

Whitehead said PJM’s new proposal should not be a surprise, as the committee has been debating different approaches for several months.

“I feel this has been vetted here. I understand that you may not be happy with the outcome, but the opportunity for dialogue certainly occurred,” Whitehead said to Guerry.

“There’s a reliability tradeoff for these sales,” he said. “It is critical to recognize that we have the potential to sell back 10,000 MW of capacity. To do that and to know there’s a distinct possibility that most of those MW could clear close to zero … it’s counter-intuitive that in one auction we’re valuing capacity at $150, and, in the next instance, we’re valuing it at zero. The reduction in load’s cost is 1%, while giving up 5% of reliability — that should be concerning.

“It’s a lot of capacity, and my company’s position is we need to make sure we are putting the right value on those sales,” said Whitehead.

Independent Market Monitor Joe Bowring repeated his position that PJM should not buy more capacity than it needs and should not sell it back for less than it paid. But, he said, the PJM proposal goes in the right direction.

Still, Bowring said, “There’s no cap. There is no limit. There’s no reason not to hold onto that capacity, which was purchased for a higher price.”

In the end, committee Chair Chantal Hendrzak declared the item an official first read for the group.

Order 825 Progress

PJM staff announced their preliminary plans for implementing five-minute interval data for load, generation and shortage pricing.

For generation, PJM would use existing estimated or telemetry data and create five-minute profiles that correspond to hourly revenue-quality meter data already submitted. The five-minute telemetry data would be average and combined with a scaling factor for each five-minute interval profile associated with five-minute LMPs. The total of the 12 intervals would equal the hourly revenue-quality data. This is a protocol other ISOs are using, PJM’s Adam Keech said.

Order 825 doesn’t require load to provide five-minute data, so PJM plans to use flat profiling over the 12 intervals in an hour and associate that with five-minute pricing to determine load pricing. Demand response is also submitted hourly, so PJM would prorate such resources by interval for curtailments of less than an hour. PJM doesn’t have the granularity to use state estimator data for discrete DR, Keech said.

PJM wants to continue using megawatt-hour values and augment them with five-minute LMPs for pricing. The plan hasn’t yet been discussed with other RTOs, though, and stakeholders expressed concern that differences in each RTO’s plan might impact their interaction.

For shortage pricing, PJM introduced a problem statement to develop new curves that are complementary with the rules of Order 825.

While the order allows more time for initiating shortage pricing, PJM wants to implement it jointly with the load and generator changes because of concern that five-minute pricing could distort hourly prices, Keech said. PJM has been discussing this with other RTOs, particularly ISO-NE, and have come up with similar solutions.

Currently, PJM’s four curves are very similar and all have the same $850 penalty factor. The RTO currently addresses transient shortages — those expected to last a very short time —by easing reserve requirements slightly until expected supply arrives. Order 825 prohibits PJM from doing this, so the RTO wants to develop new demand curves that complement the requirements of the order.

Members Hear First Read on Plan to ‘Un-Nest’ Operating Parameters

The MIC will be asked at its September meeting to endorse one of two proposals on whether and how to “un-nest” operating parameter definitions to separate soak time from start time (see table).

The definitions are contained in Manuals 11, 15 and 28. (See “Members OK Operating Parameters but Urge Refinements,” PJM Markets and Reliability and Members Committees Briefs.)

NYISO to be Consulted on Changing Spot-in Service Allocation Methods

Joe Wadsworth of Vitol presented further discussion on how to improve the process of allocating spot-in transmission for energy imports from NYISO.

In April, the committee approved a problem statement and issue charge on the subject. (See “Allocating Spot-in Service for NYISO Imports to be Studied,” PJM Market Implementation Committee Briefs.)

Currently, the free but limited service is allocated on a first-come, first-served basis with no priority for participants who have cleared the NYISO market.

Wadsworth proposed removing PJM’s limit on requests for spot-in service and relying on NYISO’s real-time economic evaluation to determine which importers get spot-in service. He also proposed modifying some rules and timelines for the NYISO/PJM interface.

Wadsworth said talks are planned with NYISO and he would present their feedback at the next meeting.

Although no similar concerns have been expressed regarding the MISO seam, Bowring suggested the committee consider expanding the proposal to apply to all of the neighboring RTOs.

— Suzanne Herel and Rory D. Sweeney

August 15, 2016

Energy Wildcatter Hopes to Make His Mark in Emerging Mexican Market

By Tom Kleckner

With its electricity demand projected to grow 3 to 4% annually, the expected retirement of 10 to 15 GW of fossil plants, a commitment to add 1 GW of wind power annually and off-peak prices as high as $65/MWh, Mexico presents an appealing target to generation developers.

And Mannti Cummins wants a piece.

A certified public accountant by training, Cummins now calls himself a wildcat wind-energy developer, having developed more than 1,000 MW and $2.2 billion worth of wind projects in the U.S. and Mexico.

“Get in early, get in cheap,” he said in describing his strategy. “Hopefully, it’ll be a good market position with relatively few dollars spent.”

For now, however, Cummins and other developers are finding that a lack of transparency and uncertain rules are making their efforts anything but a sure bet.

Cummins, who grew up near the Gulf of Mexico, has made his home in Mexico for the past decade and speaks Spanish fluently enough to have completed a course in energy law from Mexico’s Escuela Libre de Derecho law school. He helped develop that country’s first two managed health care insurance firms and served as their CEO.

In his spare time, Cummins has been an avid surfer. He’s also been known to play Billy Idol’s “White Wedding” on his accordion.

Having made his mark in industries on both sides of the border, Cummins has jumped headlong into the Mexican energy market, which opened to national and international wholesale competition earlier this year.

Focus on Renewables

For the time being, much of the market’s focus is on renewable energy. Mexican President Enrique Peña Nieto in June joined President Obama and Canadian Prime Minister Justin Trudeau in pledging to generate half his country’s power from clean-energy sources by 2025, accelerating its 2013 pledge to produce 35% of its energy from renewable sources by 2024.

Cummins notes that Mexico’s definition of “clean-energy sources” does not include natural gas or nuclear energy. The Ministry of Energy’s National Electricity System Development Program projects Mexico will need more than 20,000 MW of clean energy over the next 15 years, part of an estimated $62.5 billion in private investment in the energy industry by 2018.

“Every year, Mexico has … to add 1,000 MW of wind power,” said Cummins, currently director of Energia Veleta, S. de R.L. de C.V. (which translates as wind vane energy) in Monterrey, Mexico.

Market Phase-In

Mexico’s wholesale market will be implemented in phases through 2018. It consists of short-term markets (day-ahead, hour-ahead, real-time and ancillary services), medium-term auctions (three-year energy and capacity contracts), long-term auctions, financial transmission rights auctions, a capacity-balance market and the 20-year clean-energy certiﬁcates — instruments equivalent to 1 MWh of energy from clean sources — market that Cummins and other developers have their eyes on.

In the first clean-energy auction in March, about 80 firms offered more than 200 bid packages, with contracts awarded to Enel Green Power, Acciona, Jinko Solar and other players.

Cummins said state-owned Comisión Federal de Electricidad (CFE), Mexico’s only utility, saw some solar projects bid as low as $40/MWh, lower than the utility had expected. All told, CFE awarded 5.38 million MWh of contracts, with almost 75% of those going to solar developers. A second auction will be held in September.

Because bidders were required to have a financial guarantee of about $40,000/MW to participate, Cummins lamented, the wildcatters were priced out.

“I wanted to bid in March, but I couldn’t find anybody to put up the guarantee,” Cummins said. “That would have required about $2 million, which I ain’t got.”

Cummins was riding in a Mexico City taxi as he spoke, on his way to a meeting with a fourth-level executive in the country’s energy department to discuss timetable issues. The man he was going to meet “is the guy that turns the crank,” the person who implements policy directives, Cummins said.

In order to place financial guarantees for the September auction, Cummins needs an interconnection, which requires a bond guaranteeing that upgrade costs will be paid, and a generation permit from Mexico’s Energy Regulatory Commission. And he must be ready to turn in reams of paper.

“Coordinating calendars for other permits … makes it tricky,” Cummins said. He planned to complete the paperwork by Aug. 29. “The [first official] deadline is Sept. 1. That’s a slim margin for error.”

It may not matter. Cummins said in a subsequent email exchange that an “unexpected change” in the auction’s evaluation criteria “most likely knock[s] us out as contenders in this auction as well.”

Growing Pains

Growing pains are to be expected in any immature market, but those pains have been amplified by Mexico’s emergence from a state-run monopoly. Vertically integrated CFE has long been the country’s only electric utility, much as Pemex controls the country’s oil industry. It is only now being restructured into generation, transmission and distribution firms.

“The market is open, and it has a single participant … CFE, which was the single participant before it opened,” Barbara Clemenhagen, Customized Energy Solutions’ vice president of market intelligence, explained at an Infocast conference in March. “If the statements for the initial 48 days are indicative, there’ s not much transparency and liquidity in the market.”

Clemenhagen said CFE is participating as both a buyer and a seller in the clean-energy auctions, covering the demand of its regulated clients and load centers. The utility was the only buyer for capacity, energy and clean-energy certificates in the last two auctions but was not allowed to sell because its generation companies do not exist yet.

El Centro Nacional de Control de Energía (CENACE), the grid operator, was an operating division of CFE, the vertically integrated national electric utility. CENACE became an independent system operator in August 2015.

CFE is also being restructured into different generation, transmission and distribution firms.

“The same guys who are on the CFE payroll in the morning are with CENACE in the afternoon,” Cummins said. “The independent part needs some time to set, since most CENACE folks were transitioned from similar posts in CFE.”

Grupo Fenix, which works with rural communities in Nicaragua to promote renewable energy, reforestation and sustainable development, also qualified as a market participant but has chosen not to participate.

“They pulled this thing together so fast, all the loose ends aren’t tied up,” Cummins said. “How long did it take ERCOT to get [its competitive market] going? The Senate bill passed in 1999 and it took 10 years to decide what was up.

“Wildcatter guys like us, we don’t mind navigating in an uncertain environment. But when you start putting hundreds of millions of dollars down, you better have everything locked up pretty good.”

Cummins said he would like to see more clarity in the market’s interconnection rules, the source of many of his current headaches.

“There needs to be coordination between the auction process and the interconnection process,” he said. “In ERCOT, you file your study and ERCOT comes in with theirs. There’s a date certain your study has to be done. Not in Mexico. That process and the auction timetables sometimes just don’t line up.”

The wildcatter would also like to see clean-energy generators create bilateral contracts outside the auction process with consumers, who will be required by Mexican law to buy 5% of their load from clean-energy sources in 2018.

“The rules in that market are uncertain and not definable for the amount of risk [involved],” Cummins said. “Those rules have not been ironed out.”

Compounding the problem, Cummins said, is the lack of a mechanism to balance load with generation and the requirement that private-generation companies purchase clean-energy certificates — even though clean-energy projects have yet to be built.

Clemenhagen said even when the rules are finalized, a lack of transparency makes it difficult to know who changed the rules and why. As of this spring, only 13 of 30 expected operating procedures and manuals had been released, and only one (the long-term auctions market) had been ﬁnalized.

“She’s not the only one [who feels that way],” Cummins said. “There are inconsistencies in the rules, gaps in the rules, downright confusion in the rules. The sheer volume of the rules … you have to have a person, or two or three, just to read the darn documents on a daily basis.

“It’s a haul, especially in a market like Mexico’s, where you have plenty of unknown unknowns,” he said.

Still, Cummins is making a go of it. His 148.5-MW Tres Mesas wind farm in the state of Tamaulipas, owned and operated by Oak Creek de México, is scheduled to be operational by the end of the year.

mexico energy — Tres Mesas *Source: Manti Cummins*

He also has four other projects in development in four states, Baja California Sur, Jalisco, Sonora and Zacatecas. That includes a 50-MW wind farm in Baja Sur, an island grid where all generation is supplied by fuel oil.

“We’re in so deep now,” Cummins said, “we don’t have a choice but to accomplish the goal.”

August 15, 2016

ERCOT Board of Directors Briefs

ERCOT will rely on its stakeholders to improve its reliability-must-run (RMR) practices after a second rejection last week of a protocol change that would allow the economic dispatch of RMR units.

The ISO’s Board of Directors on Aug. 9 rejected NRG Texas and Reliant Energy Retail Services’ appeal of a nodal protocol revision request (NPRR) addressing how RMR units are priced and dispatched. The appeal was shot down by an 11-3 vote, with one abstention.

The two companies also lost an appeal in July to the Technical Advisory Committee (TAC) after the revision request failed to clear the Protocol Revision Subcommittee (PRS). (See “Pricing Change on RMR Units Rejected, Appealed to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)

NRG drafted NPRR 784 earlier this summer as ERCOT was in the process of issuing and extending into 2018 an RMR contract for the company’s Greens Bayou Unit 5, a 371-MW gas plant near Houston. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)

Greens Bayou - ERCOT board of directors - reliability must run (RMR) — Greens Bayou

The protocol change would have allowed security constrained economic dispatch (SCED) of RMR units to relieve transmission congestion, after all other capacity available for transmission congestion relief had been exhausted. It would have applied only when generator offers are mitigated due to inadequate competition.

RMR units are currently subject to the same offer mitigation as other units in such a situation, with Greens Bayou Unit 5 likely being offered at around $50 to $60/MWh. When there is adequate competition, RMR units are offered at $9,000/MWh under either the status quo or the proposed change.

The revision request would have required all RMR units to be offered at the highest possible price that would still allow SCED to dispatch the unit for congestion. In Greens Bayou’s case, the estimates are as high as $700/MWh.

NRG’s Bill Barnes said the proposed change raised a pricing policy question that is fundamental to the energy-only market design. “The energy-only market requires effective pricing, and it does so all the time,” he said.

“It sends a signal for existing resources to remain in the market or exit if they’re uneconomic. Second, it provides incentives for new investment. Locational price signals are equally important as systemwide price signals.”

Air Liquide’s Phillip Oldham advocated TAC’s position by urging the board to reject NRG’s appeal, given the “important stakeholder input” provided by its failure at TAC and PRS. He reminded the directors that RMR protocols are currently being reviewed and asked they let the process play out.

Barnes © RTO Insider, ercot, board of directors, reliability-must-run — Barnes © *RTO Insider*

“We believe [784] is inconsistent with market principles that have been in place,” Oldham said. “We fundamentally disagree, even at the most basic levels, about what an RMR is. It is not a generation issue. It’s a transmission issue.”

Oldham said the revision request doesn’t support resource-adequacy objectives, noting Greens Bayou Unit 5 is an RMR for local reliability, not systemwide capacity. He also pointed to the $590 million Houston Import transmission project as the RMR “exit strategy” for the Houston area, a position later supported by ERCOT’s COO, Cheryl Mele.

“Using the RMR to set high prices in Houston between now and 2018 will not incentivize new resources because a transmission solution is already in process,” Oldham said.

ERCOT Director Nick Fehrenbach, the City of Dallas’ manager of regulatory affairs and utility franchising, said he had received calls from his consumer market segment members worried about the revision request’s consequences.

“They’re concerned about the impact this could have on load in the Houston area,” he said. “It’s simply a short-term solution before we get the Houston Import project built. I don’t think this is a smart move.”

ERCOT’s RMR contract with Greens Bayou requires the ISO to pay $3,185/hour for the duration of the agreement and an incentive factor of as much as 10% to reserve the unit’s capacity.

“As you saw in the debate … there’s some sense of urgency around looking at this,” said ERCOT CEO Bill Magness when the smoke had cleared. “[RMR] is an important reliability tool, but it’s a relatively blunt instrument. It is a large bundle of issues, but one that we believe, with a lot of effort and focus from stakeholders and staff, we can get some items to the board for consideration fairly soon.”

TAC Chair Randa Stephenson of the Lower Colorado River Authority was reminded her committee had predicted NPRR 784 would be a “hot topic” six months ago. She said stakeholders have been “digging into the protocols” and existing parameters as they try to improve the RMR process.

At a workshop in May, stakeholders identified 18 RMR-related issues, giving priority to the following three:

A timeline on notifications suspending operations;
Studies, processes and criteria used to identify whether a resource is needed for RMR service; and
Capital contributions to an RMR unit.

Several NPRRs are currently being developed that address the RMR process, timeline and notice. Stephenson said the timing of a staff-drafted revision request modifying the current RMR process has yet to be determined, but other NPRRs will bubble up through the stakeholder request during the next six months.

Last month, ERCOT also issued a request for must-run alternative resource proposals that offer more cost-effective solutions (defined as more than $1 million in savings) than Greens Bayou. Responses are due Aug. 24, with any agreements to be announced Oct. 7.

IMM Notes 26% Drop in Real-Time Prices

The Independent Market Monitor reported that the growing abundance of Texas’ wind resources helped cut load-weighted real-time prices 26% in the first half of 2016 compared with 2015.

IMM Director Beth Garza said ERCOT’s real-time prices have averaged $20/MWh through June, compared with $27/MWh for the same period last year. She called the number “momentous” but said prices will increase “as you factor in the effects of last month and going into August.”

Garza said ERCOT’s wind fleet has grown so much that in June there was never less than 3,500 MW available. She said average capacity factors and energy totals have been higher per MW of nameplate capacity this year, thanks to ERCOT’s recent transmission buildout.

“And the preliminary data in July shows the wind will be higher than it was in June,” she said. “ … People are building more of it, so we get more energy.”

ERCOT’s generation-interconnection status report shows more than 10,000 MW of wind generation due to come online through 2018.

Garza’s report also noted that ERCOT’s ancillary service (AS) costs at mid-year have increased $0.05/MWh over 2015, even though the ISO is procuring fewer such services. She said the IMM will continue to monitor the AS market to determine the cause of the increase.

Magness Reports Favorable Financials to Board

Magness said August’s searing temperatures are expected to make up for milder conditions earlier in the year. The ISO’s net revenues were $4.9 million over budget through June, despite being $2.5 million behind on administration fees. Those numbers are currently projected to finish $7.5 million and $0.5 million over budget, respectively.

The president’s report also addressed the July 7 Energy Management System (EMS) outage and TAC’s concerns that ERCOT did not communicate quickly enough with the market. (See “Committee Discusses July 7 System Outage,” ERCOT Technical Advisory Committee Briefs.)

“It’s always a balance of not wanting to speak until we know what’s going on, but that’s something we’re working on,” Magness said. “It was a human error event, and we took responsibility for that. We’ve changed the process to make sure that is not an error we’re going to see again.”

Magness also took time to recognize the 170-person team behind ERCOT’s recent EMS upgrade. The four-year project went live June 16 following 84,000 person-hours of work, coming in under budget and ahead of schedule.

“The EMS upgrade was one of those processes that’s described as performing brain surgery on the pilot while he’s flying the plane,” he said.

Board Approves 8 Protocol Revisions, 2 Other Changes

The board approved seven NPRRs, a system-change request (SCR) and revisions to the Planning Guide (PGRR) and the Resource Registration Glossary (RRGRR). NPRRs 696 and 738 were the only two revision requests that received any opposing votes.

NPRR696: Establishes price corrections following a SCED failure by correcting prices for settlement intervals corresponding to the active watch period, giving market participants transparency to known prices that reflect the last good SCED execution.
NPRR738: Excludes intervals from performance calculations when an emergency response service generator is unable to meet its obligations due to transmission or distribution service provider (TDSP) outages.
NPRR747: Proposes new definitions related to voltage profiles, defines various entities’ responsibilities for voltage support and clarifies that the interconnecting transmission service provider or its designated agent may modify a generation resource’s voltage set point.
NPRR767: Changes the eligibility check for the startup portion of the reliability unit commitment make-whole payment. Resources with lead times longer than six hours may submit a settlement dispute to have their resource-specific startup times considered when determining eligibility for including startup costs in the make-whole payment calculation.
NPRR770: Adds visibility and situational awareness to the market by posting the aggregate number of telemetered resources and their statuses to the ancillary services capacity monitor.
NPRR771: Clarifies that TDSPs must ensure an electric service identifier has been created in ERCOT systems before initiating electric service at a premises to avoid transactional, billing and out-of-sync issues.
NPRR774: Removes duplicate language regarding the calculation of seasonal transmission-loss factors.
PGRR046: Aligns the planning guides with NERC’s TPL-007-1 reliability standard related to geomagnetic disturbance events by specifying a process for developing geomagnetically-induced system models.
RRGRR009: Adds three categories of data to the Resource Registration Glossary: Voltage limits for transmission level equipment at generator substations; geomagnetically-induced currents and the presence of blocking devices to allow identification of vulnerabilities due to geomagnetic disturbances; and a most limiting single element (MLSE) allowing a resource entity to identify an MLSE on lines it doesn’t own.
SCR789: Updates the network model management system topology processor to add a software tool commonly used by transmission-planning entities in ERCOT.

— Tom Kleckner

August 15, 2016

SPP Briefs

SPP says it is on track to go live as scheduled with the new gas-day timeline in October and enhanced combined cycle (ECC) software in March.

Testing on SPP’s gas-day system began Aug. 1 and concludes Aug. 29.

The first operating day will be Oct. 1, when participants must submit bids and offers by 9:30 a.m. instead of 11 a.m. SPP requested a one-day extension of the first operating day from Sept. 30, which FERC granted last week.

“There’s no real system changes for members,” Jodi Woods, SPP’s day-ahead market manager, told the Gas Electric Coordination Task Force last week. “We’re using this opportunity to go through the processes and make sure they can meet their deadlines.”

The gas-day timeline changes are a result of FERC Order 809, which moved the RTO’s timely nomination cycle deadline for gas supplies to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle.

Last July, SPP’s Board of Directors approved timeline changes that post day-ahead market results at 2 p.m. CT, up from 4 p.m., and shorten the reoffer period to 45 minutes, with reliability unit commitment offers due at 2:45 p.m. and results posted by 5:15 p.m. (See “Board Approves Gas-Electric Timeline Change,” SPP BoD/Members Committee Briefs.)

Enhanced Combined Cycle Project

Testing the enhanced combined cycle (ECC) project’s software, which involves more than a dozen systems and interfaces, is scheduled to begin in December, with a projected March 1, 2017 go-live date. The project is expected to provide more sophisticated modeling to capture combined-cycle plants’ flexibility.

The two projects have an estimated implementation cost of $7.7 million, the bulk of which is related to the more complicated ECC software.

Task Force Suggests Minimum Threshold for Competitive Projects

The Competitive Transmission Process Task Force last week made official its support for a minimum threshold for competitive projects under FERC’s Order 1000. However, the group rejected the idea of instituting a $2.5 million threshold, asking staff to return with additional analysis before its next meeting Wednesday.

The threshold was one of five issues the task force was assigned to study by the Strategic Planning Committee.

The SPC directed the group to base any process improvements on lowering costs for the end customer — rather than simplifying the process for staff — and to report back with recommendations in October.

MISO currently has a $5 million threshold for market-efficiency projects and a $20 million hurdle for its multi-value projects. An SPP staff review of more than 300 highway/byway high-priority projects dating from 2010 found that only 34 projects receiving notices-to-construct (NTC) had costs under $10 million, with 18 under $5 million.

The task force is also considering whether to: seat the industry panel evaluating competitive bids earlier in the solicitation process; develop a region-wide formula rate; report proposal costs as an incremental cost or as an average for each respondent; and move from the current competitive model to a sponsorship model.

The task force also approved developing Tariff language that allows for the re-study of approved competitive projects before an NTC is issued. The action was a result of last month’s cancellation of SPP’s first competitive project under Order 1000. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

MOPC Fills Out Z2 Task Force

On Friday, the Markets and Operations Policy Committee (MOPC) closed its solicitation for members interested in participating on a task force to address unresolved issues concerning the Z2 crediting process.

The Board of Directors created the task force last month to address complaints of members being charged for costs that were not identified in service agreements after declining to address the members’ waiver requests. (See Board Approves Z2 Timeline Extension, Creates Task Force for Further Study.)

Bruce Rew, SPP’s vice president of operations, told members the task force would review the waiver requests, with the intention of “expeditiously” conducting a study and finding an “acceptable solution” before the October MOPC and board meetings. Rew said the full scope of work is still being developed, but the group may also be asked to work on improving the Z2 payment process.

The task force is expected to be “highly engaged” for at least six months, Rew said.

– Tom Kleckner

August 15, 2016

PJM Planning Committee and TEAC Briefs

VALLEY FORGE, Pa. — A reliability analysis identified no adverse impacts on the PJM system from closing the 1,819-MW Quad Cities nuclear plant, which Exelon plans to deactivate on June 1, 2018.

Exelon announced the closure in June after failing to convince Illinois legislators to act on a bill that would help subsidize its money-losing stations. (See Exelon to Close Quad Cities, Clinton Nuclear Plants.)

It also plans to shutter the 1,065-MW Clinton station next June 1.

Meanwhile, PJM is wrapping up analyses on FirstEnergy’s plans to close its W.H. Sammis and Bay Shore plants — a combined 856 MW — in Ohio.

Those studies did indicate some issues, said Paul McGlynn, senior director of planning, but they are in areas where PJM already has identified needs for baseline Regional Transmission Expansion Plan (RTEP) upgrades.

“We’re just making sure those previously approved upgrades will meet the needs,” he said.

In July, FirstEnergy announced the retirement of Sammis, its largest coal-fired plant in Ohio. At the time, it said it would deactivate or sell its Bay Shore plant by 2020. (See FirstEnergy Closing Largest Coal Plant in Ohio, Bay Shore also in Peril.)

Third RTEP Window of 2016 Set to Open in September

PJM expects to open the third RTEP window of the year in mid- to late September, McGlynn told the Transmission Expansion Advisory Committee (TEAC) on Thursday. Its scope will be short circuits and 2021 winter and light load reliability.

McGlynn also provided an update on the second proposal window, which closed July 29. (See “PJM to Open FERC Order 1000 Proposal Window in Late June,” PJM Planning Committee and TEAC Briefs.)

PJM received 87 proposals from 13 entities in a dozen transmission zones to address N-1 and N-1-1 thermal and voltage issues and load and generation deliverability problems.

Of those, 46 involve greenfield projects, ranging in cost from $5 million to $224 million; 41 were transmission owner upgrades estimated at $30,000 to $125 million.

PJM said it cannot provide details on the projects until after cost analyses are submitted. They were due Aug. 15.

PSE&G End-of-Life Price Tag: $1.15B

McGlynn presented $1.15 billion in proposed solutions to end-of-life issues involving Public Service Electric and Gas equipment. (See “PJM Concerned PSE&G Equipment at the End of its Life,” PJM Planning Committee and TEAC Briefs.)

Planners are considering replacing the double 138-kV circuits on the Metuchen-Edison-Trenton-Burlington corridor with 230-kV lines in three sections: Metuchen-Brunswick ($125 million), Brunswick-Trenton ($327 million) and Trenton-Burlington ($349 million).

The 30-mile Metuchen-Trenton span is about 86 years old; structures in the 22-mile Trenton-Burlington section average 75 years old. About 81% of the towers are at 95 to 100% of their load-carrying capacity and as much as 30% of the structures require extensive foundation rehabilitation or replacement.

“We don’t have time to put [the projects] through a [competitive] window,” McGlynn said.

An alternative would be to rebuild the corridor with the existing double-circuit 138-kV configuration, an option that would be about 20% cheaper, McGlynn said.

PJM staff also recommend the existing Newark switch station be demolished and a new one constructed adjacent to that site at a cost of $353 million.

PJM Creates System Planning Modeling and Support Group

PJM has created a new planning department called the System Planning Modeling and Support Group.

The reorganization, which will take effect next month, is intended to streamline case-building, PJM’s Jason Connell explained. The effort is time-consuming, and PJM is seeing an increase in required cases, he said.

The unit will report to McGlynn, along with Interconnection Analysis, headed by Aaron Berner, and Transmission Planning, led by Mark Sims.

Planners are reaching out to transmission owners about the change, Connell said.

PJM Poised to Exempt TO Upgrades from Order 1000 Process

PJM is waiting until FERC accepts its deficiency filing related to exempting low-voltage facilities from the Order 1000 process before it files a similar request involving transmission-owner upgrades.

PJM’s Mark Sims said the commission is expected to act by Aug. 26, and the Planning Committee likely will be asked to endorse the proposal at its September meeting. If approved, the exemption would go into effect for the 2017 RTEP cycle.

The proposal would exclude typical transmission substation equipment upgrades from competitive windows unless there’s an indication that the problem could yield a greenfield project. (See “PJM Beefing up Details of TO Upgrade Exemption Proposal,” PJM Planning Committee and TEAC Briefs.)

Such upgrades would include short-circuit violations and fixes to substation terminal equipment such as wave traps, current transformers and capacitors.

In February, members approved revisions to the Operating Agreement exempting transmission reliability projects of less than 200 kV from the competitive proposal windows. (See “Low-Voltage Projects to be Exempted from Competitive Window Process,” Markets and Reliability and Members Committees Briefs.)

FERC responded by ordering PJM to make a compliance filing addressing concerns such as how stakeholders would comment on exempted projects (ER16-1335).

PJM Staff Continues to Scrutinize Planning Process

PJM staff is continuing to review the RTEP planning cycles and the TEAC’s communications and processes, Fran Barrett told the Planning Committee.

Preliminary discussions are being held internally, but Barrett assured members that no action would be taken without being vetted by the stakeholder process.

Cross-departmental teams are mapping out current processes and identifying areas for improvement.

“We want to take a picture of today, project it to the future and you tell us what’s right about that picture and what needs to change,” said Barrett.

For example, he said, while some stakeholders do business within PJM only, others are involved in transmission planning projects in other RTOs as well. One idea: provide members an ESPN SportsCenter-like “highlights reel” from various RTOs’ planning committees.

“We’re trying to improve workflow and do it more efficiently,” said Barrett. (See “PJM Starts Process of Redesigning TEAC,” PJM Planning Committee and TEAC Briefs.)

— Suzanne Herel

August 15, 2016

Federal Briefs

The amount of electricity generated by natural gas in July eclipsed its own record, set in July of last year, according to the Energy Information Administration. The trend, caused in part by coal plant retirements and a boost in temperatures, spurred the agency to predict natural gas and coal will be used to generate 34% and 30%, respectively, of the nation’s electricity in 2016. This compares with slightly less than 33% for natural gas, and a bit more than 33% for coal, last year.

The increase in the use of natural gas to generate electricity led to a rare drawdown of natural gas stocks in a month when pipeline operators typically are injecting natural gas into storage for winter use, rather than sending it out. Gas inventories declined by 6 billion cubic feet for the week ending July 29. The last time a net withdrawal was recorded in July was in 2006.

More: EIA; PennEnergy

Jury Convicts PG&E in San Bruno Blast Trial

A federal jury last week convicted Pacific Gas & Electric on six charges of violating gas pipeline safety laws and obstructing the federal investigation into the 2010 pipeline explosion that killed eight people and destroyed 38 homes in San Bruno, Calif.

PG&E faces a maximum penalty of $3 million after it was found guilty on five felony counts of wittingly failing to inspect its gas network, as well as the felony obstruction count.

Prosecutors initially sought $562 million in penalties before the presiding judge ruled the company could not be held to newer safety standards that would have led to higher fines for illegal cost-cutting. The penalty will be paid by company shareholders, but ratepayers will have to cover the costs for pipeline upgrades. No company executives were convicted in the case.

More: San Francisco Chronicle

NRC Names David Nelson As New Chief Info Officer

The former chief information officer at the Centers for Medicare and Medicaid Services (CMS) will be the next CIO for the Nuclear Regulatory Commission.

David Nelson, an Air Force veteran and developer of two broadband companies, has worked for the federal government since 2004, including several positions at CMS, where he was director of the Office of Information Services, director of the Office of Enterprise Management and director of the Data Analytics and Control Group at the Center for Program Integrity.

One of his high-profile jobs was to help rescue the problem-plagued HealthCare.gov site.

More: FCW

NM Spent-Fuel Facility Seeking NRC Approval

Intrepid Potash has relinquished a mineral rights lease in eastern New Mexico, clearing the way for construction of an interim storage facility for spent nuclear fuel by a partnership between Holtec International and the Eddy Lea Energy Alliance.

The HI-STORE Consolidated Interim Storage project is expected to cost more than $1 billion and provide around 200 construction and operations jobs. Initially, the facility will be built to house 200 to 500 spent fuel casks, but it can be expanded to store 4,000. Holtec will present its application to the Nuclear Regulatory Commission in March, with the approval process taking two to three years.

Intrepid Potash idled its West Mine near Carlsbad in May, eliminating around 300 jobs. The New Mexico Land Office will now retain the rights to the minerals.

More: Carlsbad Current-Argus

Regulator Calls for Companies to Put up Collateral for Cleanups

The head of the federal Office of Surface Mining and Reclamation Enforcement said states should demand that coal companies put up collateral to cover the cost of mine cleanups.

Joe Pizarchik said that coal companies are edging toward bankruptcy in a climate of low demand and cheap natural gas prices, leaving behind a potential legacy of environmental waste.

He pointed at the bankruptcies of Peabody Energy, Arch Coal and Alpha Natural Resources in the past year. Those bankruptcy plans call for the companies to use federal subsidies to fund cleanup efforts, at the expense of taxpayers.

More: Reuters

Two Former EPA Chiefs Backing Hillary Clinton

Two former EPA administrators who served under Republican presidents said they are endorsing Hillary Clinton over Donald Trump for the U.S. presidency. William D. Ruckelshaus, the first EPA administrator under President Richard Nixon, who also served under President Ronald Reagan, and William K. Reilley, who served under President George H.W. Bush, issued a joint statement of endorsement.

The Republicans said Trump “threatens to destroy that legacy of respect for the environment and protection of public health” and went on to decry Trump’s unwillingness to accept the prevailing consensus on climate change.

“That Trump would call climate change a hoax — the singular health and environmental threat to the world today — flies in the face of overwhelming international science,” they said.

More: CNN

GE Exec Calls for Fed Support of New Tech

The head of GE Hitachi Nuclear Energy issued a call for federal support of research and adoption of advanced nuclear reactor technology during an Aspen Institute appearance.

GE Hitachi Nuclear Energy President and CEO Jay Wileman called nuclear generation the nation’s largest source of clean energy and said it was an important part of attaining clean air goals set by the government.

“We are seeing significant global opportunities for our PRISM advanced reactor technology, but in order for us to move forward, we must gain the support of the federal government on specific developmental milestone projects,” Wileman said.

More: GE Hitachi Nuclear Energy

In 5 Years, Army’s Energy-Saving Investments Exceed $1B

In response to a 2011 challenge by President Obama, the Army has entered into 127 energy-saving projects with the private sector worth more than $1 billion.

Under the Energy Savings and Performance-Based Contracting Investments Initiative, Obama asked federal agencies to engage in $4 billion of power-saving projects by the end of this year.

The Army’s projects are spread among 52 installations.

More: U.S. Army

DOE 80% Certain Waste Facility Will Reopen by December

A Government Accountability Office audit released last week revealed that the Department of Energy knew it had only a 1% chance of meeting a March 2016 deadline to clean up and safely reopen the Waste Isolation Pilot Plant nuclear-waste facility near Carlsbad, N.M. A truck fire and a leaking drum of radioactive waste shut down the nation’s only underground nuclear waste facility in February 2014.

In 2015, the agency admitted that it couldn’t safely reopen the Waste Isolation Pilot Plant until at least December 2016 and that the project would be over budget. Now auditors say even the revised cost estimate was flawed. The result of missteps in the process of reopening the facility, according to auditors, was a nine-month delay and a price tag $64 million higher than the original $242 million estimate for cleanup and an additional $77 million to $309 million to install a critical new ventilation system.

The department now says it is 80% confident that it will meet the December 2016 deadline to reopen on a limited basis.

More: Santa Fe New Mexican

Scientists Conclude Fracking Report ‘Lacking’ in Areas

Most of the advisory group behind EPA’s draft report on fracking announced last week that, as a group, it has concluded that the report was “comprehensive but lacking in several critical areas.”

The panel said 26 of the 30 members reached the decision that the report be updated to include “quantitative analysis that supports its conclusion.” The draft report concluded that the analysis “did not find evidence that these mechanisms [fracking] have led to widespread, systemic impacts on drinking water” in the U.S.

The oil and natural gas industry praised the preliminary report, while environmentalists criticized it. The report has been five years in the making so far.

More: The Washington Post

Interior Department to Open NC Shore to Wind

The Department of the Interior announced Friday that it would be opening 144,000 acres off the coast of North Carolina to leases for offshore wind projects. The site, to be called the Kitty Hawk Wind Energy Area, starts about 24 miles offshore and extends another 26 miles to the southeast.

The department’s Bureau of Ocean Energy Management will hold September seminars on the auction rules in Raleigh and in Kitty Hawk.

More: The Charlotte Observer

August 15, 2016

Michigan Asks: Will the Lights Stay on If Nukes Go Dark?

By Amanda Durish Cook

Concerned about the impact of plant retirements in the state, Michigan officials have asked MISO to conduct a reliability analysis that assumes simultaneous outages at the Palisades and Fermi 2 nuclear plants.

Fermi 2 (DTE Energy) - michigan nuclear plant retirements miso — Fermi 2 Nuclear Plant *Source: DTE Energy*

Entergy’s Palisades plant on Lake Michigan and DTE Energy’s Fermi 2 on Lake Erie — both in MISO’s Zone 7 — are capable of generating a combined 1,855 MW.

In a letter to MISO, Michigan Public Service Commission Chairwoman Sally Talberg and Valerie Brader, executive director of the Michigan Agency for Energy, said they wanted to understand what would happen in the summer of 2018 if Michigan experienced another event like it did in the summer of 2012 when the two nuclear plants were out of service while MISO was under a hot weather alert.

MISO spokesperson Andy Schonert said the RTO was reviewing the request.

The state officials said it was “crucial” for Michigan to know its vulnerabilities and whether it still could ensure reliability. They asked MISO to assess the zone’s internal generating capacity and available contracted capacity as well as how much generation could be imported from outside the state.

“We did not pick this scenario randomly,” Brader said. “In the summer of 2012, we had outages at two nuclear facilities while MISO was under a hot weather alert. Despite those outages, we were able to keep the lights on. Now we have a lot fewer plants operating. We want to know if the lights would stay on if we had the same thing happen in the summer of 2018.”

Talberg said the assessment would be “a valuable tool” for future PSC planning. She noted Michigan already relies on out-of-state imports to meet its reliability requirements.

The Michigan PSC’s five-year outlook through 2020 predicts “reliability challenges during periods of peak demand in the 2017-2018 timeframe” in Michigan’s Lower Peninsula.

August 15, 2016

MISO Reliability Subcommittee Briefs

MISO wants to know how it can improve frequency response under an evolving generation fleet and is asking for stakeholder involvement to draft an issues statement.

“This isn’t a new topic. The industry has been grappling with the issue for years,” said Durgesh Manjure, MISO’s manager of resource adequacy coordination.

Manjure said MISO hasn’t encountered the frequency response challenges that other systems such as ERCOT have encountered.

“But that doesn’t mean everything is fine and we won’t have to introduce something to keep this reliable trajectory going forward,” Manjure said during an Aug. 10 meeting of the Reliability Subcommittee (RSC). “By no means is this an issue now or next year, but I can’t say that with the same level of confidence for five years out.”

The RTO said that “opportunities exist to improve dynamic models” and performance measurement.

MISO said its changing fleet is driving the frequency response discussion, with coal taking an ever-shrinking share, while gas and wind sources climb. Manjure said MISO relies on coal for “most if not all” of its frequency response, but technological advancements are allowing other generation types to provide a governor-like response to a drop in frequency.

Between 2009 and 2015, MISO’s coal generation capacity dropped from 71.8 GW to 65.2 GW, while wind capacity almost doubled from 7.6 GW to 15 GW. Natural gas, responsible for only 6% of MISO energy production in 2010, now claims 28%; coal’s share fell from 73% to 45% over the same period.

According to NERC’s State of Reliability 2016 report, frequency response reliability in the Eastern Interconnection is expected to decline from the approximate 2,500 MW/0.1 Hz in 2012 to a little more than 2,000 MW/0.1 Hz in 2019.

Manjure said MISO wants to know if its models accurately reflect actual systemwide performance and what fuel mix point would render MISO’s frequency response inadequate. MISO is also asking if it needs to improve its tools that measure frequency response and revise Tariff or market mechanisms relating to frequency response.

“This is very high-level, very open to feedback,” Manjure said.

Manjure asked for stakeholder input that will be used to shape an issues statement in the coming weeks.

Improvement to Pseudo-Ties Process on MISO Horizon

Kyle Abell of MISO’s market planning division said MISO is trying to improve the congestion management process for its increased volume of pseudo-ties.

MISO said it has experienced escalating pseudo-tied generation with load farther from the seams in 2016. In the 2015/16 planning year, MISO-based generation pseudo-tied into PJM equaled only 155 MW; in the 2016/17 planning year, the amount is expected to reach about 2,000 MW. In the 2017/18 planning year, pseudo-ties are expected to creep toward 2,800 MW, with many of the deeper pseudo-ties sent to attaining balancing authorities with “very limited or no modeling-based visibility” of how their usage affects the larger MISO system.

Abell said MISO is contemplating new requirements for approving a pseudo-tie, including notification, pre-assessment and conditional approval steps. In addition, the RTO may set out requirements for an attaining balancing authority’s network model for proposed pseudo-ties. Currently, MISO reviews and approves pseudo-tie requests, while balancing authorities are responsible for market-to-market redispatch.

MISO asked stakeholders for suggestions to improve its pseudo-tie congestion management before Aug. 26. The RTO also said it would meet with neighboring balancing authorities and RTOs and its Independent Market Monitor to discuss the issue. Abell said he would make another pseudo-tie presentation at the Aug. 16 Planning Subcommittee meeting.

MISO plans to revise its processes around congestion caused by pseudo-ties through November, in time to draft a work plan to implement the changes in December.

Smooth Operations in MISO Despite ‘All-Time Hottest’ July

MISO operations performed well in July despite several hot weather and severe weather alerts, said Steve Swan, MISO senior manager of dispatch and balance.

Swan said July 2016 was the “all-time hottest July” for multiple cities in the southern portion of the MISO footprint. It was also the driest month since MISO’s creation for some southern MISO locations. Load peaked at 120.6 GW on July 21.

MISO reported that July 10, 12 and 20 fell outside of its unit commitment performance targets since forecasted load didn’t materialize due to thunderstorm activity; units that were preemptively called up had to stay online to fulfill their minimum run times. MISO also had one maximum generation event in July.

July also marked the first month MISO was required to abide by NERC’s balancing authority area control error limit (BAL-001-2) standards, which limit interconnection frequency errors to less than 30 minutes. Swan said MISO did not experience an error lasting longer than 15 minutes event in July.

RSC Chair Tony Jankowski commended MISO for its operations in the face of the hot weather. “We’ve had a pretty good summer so far, and MISO’s gotten us through some hot weather we haven’t seen in a while,” Jankowski said.

Winter is Coming and Coordinated Seasonal Assessment is Scoped

With Labor Day looming, MISO is already thinking about winter. Its 2016/17 winter Coordinated Seasonal Assessment, which assesses risks and system capabilities will include four main analyses, said MISO’s Katie Hulet:

A steady-state AC analysis to study the effect of simple and complex contingencies;
An analysis identifying large phase angle differences associated with reclosing a transmission line;
A voltage stability analysis that will assess four critical interfaces for high transfers in combination with transmission and generator outages, which can cause stability issues; and
A first contingent incremental transfer capability analysis to study the impact of high megawatt transfers and flowgate limitations. This analysis will examine six transfers in addition to wind transfer sensitivity.

MISO also will use only approved retirements and planned and forced transmission and generation outages lasting two months or more between December and February in its assessment.

Hulet said MISO would return to the RSC in November to provide the study’s results.

— Amanda Durish Cook

August 15, 2016

MISO to Begin Charging Tx Fees on PJM Exports

By Amanda Durish Cook

MISO last week filed revised Tariff language allowing it to recover costs for multi-value transmission projects that benefit PJM customers by charging a fee on exports to PJM (ER10-1791-003). The Aug. 12 compliance filing requested the new language be retroactive to July 13, 2016.

Last month, FERC partially lifted the three-year-old restriction on MVP allocations for exports in response to a 2013 remand from the 7th U.S. Circuit Court of Appeals. (See FERC Looks Again at Export Pricing for MISO MVPs.)

MISO Transmission Fees PJM — Foundations are laid for Ameren’s Illinois Rivers transmission project, a 345 kV line stretching from West Adair, Mo., to Sugar Creek, Ind. The line consists of five multi-value projects, and portions are expected to come online as early as this year.

The commission said it was persuaded by the large-scale wind buildout “capable of serving both MISO’s and its neighbors’ energy policy requirements.”

It also cited “the reported need of PJM entities to access those resources; and the reported need for MISO to build new transmission facilities to deliver the output of those resources within MISO for export.”

“Given these changes, it is appropriate to allow MISO to assess the MVP usage charge for transmission service used to export to PJM just as MISO assesses the MVP usage charge for transmission service used to export energy to other regions,” FERC concluded.

MISO created the MVP category six years ago for projects that address more than one reliability or economic need across multiple transmission zones. The RTO originally intended to allocate project costs to all of its load and exports, but FERC excluded the export charge because of concerns over rate pancaking.

Chris Miller, FERC’s liaison to MISO, said the RTO removed Tariff language that had prohibited it from charging exports. Affected portions include Attachment MM, Schedule 26-A, Schedule 39 and Attachment L.

MISO also made an informational filing in early August detailing multi-value, market efficiency and baseline reliability projects approved during the Transmission Expansion Plans in 2014 and 2015 (ER13-186, ER13-187). While 140 baseline reliability projects were approved in the two years, only one market efficiency project was greenlit.

The RTO did not approve any MVPs in 2014 or 2015. It said its $6 billion 2011 MVP portfolio — 17 projects in various transmissions zones over nine states — left only local reliability projects to be addressed for the time being.

Three of the projects are in service, with the remainder scheduled to be operational in three to five years.

August 15, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM is considering providing generation operators an indicator to signal that the RTO has entered emergency conditions, which triggers a performance assessment hour under Capacity Performance rules.

The RTO will determine if there should be any delay in the notification process and, if so, for how long, PJM’s Rebecca Stadelmeyer said. Stakeholders requested that PJM also ensure the signals don’t create any type of market advantage.

Stadelmeyer also clarified that non-ramp-limited basepoints have no impact on calculating either performance bonuses or nonperformance charges during a PAH.

The question arose because generators had been asking for the basepoints to be sent via PJM’s network, thinking they could help estimate units’ expected performance, Stadelmeyer said.

Non-ramp-limited basepoints are theoretical expectations based entirely on the economics of the current LMP and regardless of the unit’s actual capabilities. Ramp-limited basepoints, however, are developed from information about each unit submitted by operators into PJM’s systems.

Nonperformance charges are imposed when a unit’s output fails to meet its expected performance, and bonuses occur when actual output exceeds expected performance without exceeding PJM’s dispatch instructions. Expected performance is calculated by multiplying a balancing factor by the amount of a unit’s unforced capacity (UCAP) that clears as CP in a Base Residual Auction.

Balancing factors are hard to estimate, Stadelmeyer said, so she urged using the maximum 1.0 to identify the highest possible expectations.

PJM also clarified that the difference between UCAP and installed capacity (ICAP) is also available for bonuses as long as the RTO has dispatched the unit to that level.

In May, FERC rejected Tariff changes that would have exempted a capacity resource from nonperformance charges if it was following the RTO’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. The changes were designed as an interim solution to guard against generators self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)

Post-Polar Vortex Tools Enable PJM to Better Face Severe Weather

Thanks in part to new forecasting, scheduling and reserve-checking tools implemented after the polar vortex of 2014, PJM was better able to weather a seven-day July heatwave, PJM’s Chris Pilong told the Operating Committee last week.

The RTO recorded its 13th-highest peak load at 151,822 MW on July 25, a day that saw an average LMP of $35.51. During the hot spell, which ran July 21-27, the daily average LMP ranged from $25.88 on July 26, which recorded a peak load of 143,654 MW, to $42.72 on July 27, which saw a peak load of 146,166 MW.

Pilong said the experience was good news for PJM, which wanted to gauge the self-scheduling behavior of generators now that Capacity Performance is in effect. The RTO doesn’t want generators to disregard its dispatch orders and self-schedule more capacity to avoid penalties when they believe they are approaching a performance assessment hour. (See “Ramp Rate Approach Would Excuse Nonperformance Penalties,” PJM Markets & Reliability and Members Committees Briefs.)

“The day-ahead self-scheduled megawatts didn’t change much from the past few summers,” he said. “We’re not seeing a big shift.”

Day-ahead self-schedules for July 25 stood at 69,476 MW, compared with 68,649 MW a year ago, when load hit 143,633 MW. In real time, generators self-scheduled 73,177 MW, compared with 76,430 MW a year ago.

Self-scheduled units are price takers and cannot set marginal prices; they also are ineligible for operating reserve credits.

July 25 was the first time under the new market construct that PJM issued a maintenance outage recall. It canceled 11 planned outages, totaling 124 MW over 72 hours. Eight of them, a sum of 48 MW, were online by noon July 25; the remaining three, totaling 76 MW, did not return and were converted to forced outages.

An RTO-wide hot-weather alert was issued July 22-25. A heat advisory was issued July 21 in the ComEd zone and July 26-28 in Mid Atlantic and Dominion.

The grid experienced no transfer or interconnection reliability operating limits (IROL) issues during the hot weather, Pilong said.

However, two 765/345-kV transformers tripped in different parts of the system, causing local congestion. (See “Grid Remains Strong During Recent Heat Wave,” PJM Markets and Reliability and Members Committees Briefs.)

PJM’s new tools address two scheduling concerns leading into the polar vortex. Operators’ ability to view the capacity position for the next several days was limited, as was their capacity to capture generator reserves in real time in order to validate their calculations.

In June 2014, PJM rolled out its “long lead” tool, which consolidates load forecasts, safety margins and generator data, and adopted a new procedure for scheduling generation that includes a seven-day look-ahead.

Last September the RTO developed an instantaneous reserve check, allowing it to validate unit reserves in real time.

Pilong said the new tools helped reduce balancing operating reserve (BOR) payments. BOR payments totaled $18.1 million from June through August 2015. That amount stood at $10.1 million through July 26, 2016.

Uplift payments for July 25 came to nearly $1.1 million, compared with $447,118 for the hottest day in 2015, which occurred on July 28.

Metering Task Force Presents Proposal to Improve Clarity

PJM presented the first read of an 11-point proposal for manual and Tariff changes to close the gap between PJM’s metering requirements and members’ understanding of the rules.

The proposal was outlined by Nancy Huang of the Metering Task Force, which was formed by a problem statement approved Sept. 8. (See “Metering Requirements to Receive Overhaul,” PJM Operating Committee Briefs.)

The group also recommended two topics for further study: minimum metering requirements for location and density to ensure system observability, and metering requirements for distributed generation.

The revisions aim to reduce the risk of non-compliance, provide clarity around the specifications and design of new equipment, improve the energy management system’s state estimation solution and maintain operation reliability and market fairness.

The proposal is set to go before the Members Committee on Sept. 29, with a FERC filing expected in October.

Systems Information Committee Heads into the Sunset

Members approved sunsetting the Systems Information Committee.

Topics related to the energy management system will be assigned to the Data Management Subcommittee (DMS), which will meet next on Aug. 25. Remaining topics will be transitioned to the new Tech Change Forum, which will hold its first meetings Sept. 27-28.

To accommodate the changes, the Operating Committee also approved modifying the DMS charter.

The DMS will now function as a joint subcommittee, with generator and transmission owners addressing pertinent issues and TOs considering topics applying only to them.

— Suzanne Herel