VALLEY FORGE, Pa. — PJM is hoping to simplify its communication of items that require stakeholder action through a new “stakeholder impact slide” in appropriate presentations, PJM’s Rebecca Carroll told members at last week’s Operating Committee meeting.
The slide will identify what action is needed, the deadline and which stakeholders it impacts.
“It will spell out very clearly what the action is that is required for the stakeholder,” Carroll said.
The concept will be piloted in the OC and the Tech Change Forum before it’s rolled out elsewhere, she said.
Low Frequency
Grid operators handled an unusual number and variety of issues in July, staff explained.
Chief among them was a low-frequency event on July 10 between 3 and 4 p.m. Operators had been targeting a frequency of 59.98 Hz to account for a “time error correction,” but it fell to 59.903 Hz by 3:45 p.m. The event occurred in two frequency drops, and staff are puzzled over what caused the first one.
A timeline of the July 10 low-frequency event with brief analysis of several events. | PJM
In the five minutes after 3:30 p.m., the frequency gradually dropped by 0.04 Hz, and PJM staff are working with NERC’s Resource Subcommittee to determine why. PJM’s Chris Pilong said the analysis is “not to point fingers” and that RTO tools intended to determine the cause of such issues “right now … aren’t pointing to anything.”
“It’s going to be outside the PJM system,” he said. “We’re thinking there may be some data errors in there somewhere.”
A second 0.03-Hz drop that began around 3:40 p.m. was caused by an 800-MW pseudo-tied unit tripping, Pilong said. Just before the drop, PJM initiated a synchronized reserve event, which deployed all the RTO’s synchronized reserves. PJM’s pseudo-tie error was roughly 900 MW under its target leading into the reserve event, and it dropped further down to 1,800 MW at the frequency’s lowest point.
PJM called a “simultaneous activation of reserve” (SAR) with the Northeast Power Coordinating Council at 3:50 p.m., about five minutes after the second frequency drop. The frequency rebounded to above its target level within five minutes.
Staff said the event isn’t normal but does happen every three years in the Eastern Interconnection. While this was the lowest they’d seen, it would have had to fall another 0.1 Hz for operators to call for a load action.
The puzzle for staff is what caused the initial drop, which drifted down rather than dropping immediately in a way indicative of a unit tripping.
“We drifted low. It wasn’t a step function low,” PJM’s Glen Boyle said.
Spinning Events
Grid operators also dealt with “obviously a higher volume of spinning events” than usual during July, Pilong said. The cause was multiple generators tripping, he said, but initial analysis indicates they were all unrelated. He said staff would analyze whether the system is experiencing more generators tripping or if there are any other takeaways.
“This could have just been a fluke month, or it could be a trend of something more,” Pilong said.
Load Shed
Staff confirmed that the load shed ordered July 18 was dissimilar to the load shed that occurred just months earlier in the same transmission zone.
The July 18 event occurred in the Lonesome Pine area on the border of Virginia and West Virginia after tripped equipment caused low voltage in the area. The events in American Electric Power’s zone were the first since PJM implemented Capacity Performance and its financial penalties and bonuses for generator performance during reliability events such as load sheds, though neither event triggered those calculations. (See 2nd Load Shed of PJM’s CP Era Follows Closely on 1st.)
A diagram of the area around the July 18 load shed. | PJM
Staff said the events differed in that the Lonesome Pine event was in response to actual system conditions while the previous Twin Branch event was based on concerns identified through simulations.
“That was a little more complex,” Pilong said. “This one was a little more straightforward.”
Citigroup’s Barry Trayers asked if PJM would develop additional CP event categories for situations like this with no financial repercussions. Staff confirmed the Lonesome Pine event did not create a balancing ratio since no generators were involved.
User Interface Fuel Security Changes
PJM’s Brian Fitzpatrick announced “voluntary” gas usage data requests, but stakeholders were skeptical whether the requests would be implemented that way.
Fitzpatrick said PJM is asking gas-fired generators to report through its Markets Gateway online interface all gas nominations made to the appropriate city gate. PJM is attempting to correlate the amount of gas requested at a location with its ongoing study of gas pipeline contingency plans.
“We’re not looking for what the [local distribution company] is nominating,” Fitzpatrick explained. “We’re looking for what the generators are nominating to the LDC.”
PJM’s Dave Souder confirmed that “it’s not a mandatory field” that must be completed for a generator’s energy market bid to be accepted, “but it is information we’re asking for” and staff will be contacting those who don’t comply to help them become “comfortable” with providing the information.
“It’s voluntary to the extent that if you don’t enter it, we won’t reject your bid … but this is information that we want so that we can move this gas contingency process forward,” Souder said.
SPP’s Schedule 1A Task Force last week kicked off an expected monthslong effort to develop an alternative rate structure to the RTO’s current method for recovering its administrative costs.
The Finance Committee and SPP staff have both discussed changing the fee’s billing units from transmission metrics to energy metrics by charging market transactions. The administrative fee, currently 42.9 cents/MWh, is collected under Schedule 1A of SPP’s Tariff on contracts between transmission providers and customers. (See SPP Stakeholders to Study Admin Fee Changes.)
“From an SPP standpoint, what we have now works fine,” CFO Tom Dunn told the group Aug. 8. “From a members’ standpoint, feedback indicates it’s not necessarily fine.” He said transmission customers have complained of difficulty recovering the charges “through their rate base process.”
While SPP’s costs have increased with the addition of the Integrated Marketplace, “the number of folks paying [the costs] is not necessarily growing,” Dunn said.
The task force discussed Dunn’s July presentation to the Markets and Operations Policy Committee, which led to the group’s creation. Members also took a first look at other grid operators’ recovery mechanism.
The task force is scheduled to present a recommendation to SPP’s Board of Directors and Members Committee in January.
SPP, MISO to Discuss Seams Transmission with Stakeholders
SPP and MISO are bringing stakeholders into the conversation as they continue efforts to improve transmission service along their seam.
The RTOs have agreed to remove their $5 million cost threshold and joint modeling requirement for transmission projects, two barriers that have prevented them from agreeing on interregional projects. (See MISO, SPP Loosen Interregional Project Requirements.)
The Interregional Planning Stakeholder Advisory Committee has scheduled a conference call on Aug. 27 to review with stakeholders the proposed changes to the interregional planning process.
Adam Bell, SPP’s interregional coordinator, told the Seams Steering Committee on Aug. 8 that feedback to the changes has been “somewhat split,” but staff are working to address stakeholder concerns.
“We need to move the conversation in a direction that everybody is happy with,” Bell said. He said the grid operators plan to file the revised process this year so they can begin a new study in 2019.
The RTOs are also working to schedule a meeting this fall with staff and stakeholders to further explain the January “Big Chill” and actions being taken to prevent a reoccurrence. Colder-than-normal weather and generation shortfalls in MISO South on Jan. 17 led to MISO exceeding its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system.
MISO Adds $213,189 in M2M Payments to SPP
June’s market-to-market (M2M) payments between SPP and MISO came in at $213,189 in SPP’s favor. While the amount was the lowest since last August, June was also the 11th straight month and 19th of the last 21 in which the payments have been in SPP’s favor.
| SPP
The RTO has recorded $53.8 million in M2M payments from MISO since the two began the process in March 2015.
ERCOT’s Board of Directors last week approved an ISO request to correct real-time prices following a July event that caused brief market palpitations. (See “Stakeholders, Staff Discuss Price Investigation Notices,” ERCOT Technical Advisory Committee Briefs: July 26, 2018.)
The correction changes 25 security-constrained economic dispatch intervals and nine settlement intervals between 4:30 and 6:30 p.m. on July 18. The average revision across all settlement points was a $10.67/MWh decrease, while the average change in 15-minute settlement price points was a $8.78/MWh decrease.
The ISO was required to seek board approval for the price correction when staff missed a two-business-day deadline to correct the July 18 error on their own.
A data-input mistake in ERCOT’s weekly operational model resulted in two double-circuit contingencies on a 138-kV line east of Dallas being identified as two triple-circuit contingencies. Kenan Ogelman, ERCOT vice president of commercial operations, said the contingency bound when it shouldn’t have, restricting nearby generation and affecting both system prices and prices near the generating units.
The issue, which wasn’t caught until July 19, affected the July 18 real-time operating day and the July 20 day-ahead operating day. Corrected day-ahead prices were published on July 23.
Woody Rickerson, ERCOT vice president of grid planning and operations, said staff have changed the operational model’s automated process to avoid similar mistakes in the future. Each model includes about 7,000 contingencies.
“We fixed the problem; we’ve validated the contingency files; we’re moving forward with the same process,” Rickerson said.
Staff Continues Southern Cross Work
Compliance Director Matt Mereness briefed the directors on ERCOT’s progress in accommodating the Southern Cross Project (SCT), a 2-GW DC tie in East Texas that would connect the ISO with SERC Reliability Corp.
Because ERCOT’s largest existing DC tie is 600 MW, Texas’ Public Utility Commission last year directed the grid operator to address several issues as a condition for energizing SCT, asking it to respond to 14 directives (Project No. 46304).
Mereness said ERCOT has begun work on six of the directives and is engaging members through the stakeholder process. Two other directives are updates to the PUC and are ongoing.
The board approved staff’s recommendation that no protocol or binding documents concerning primary frequency response are necessary in determining whether SCT or any other entity scheduling flows across the tie should be required to provide or procure the service.
The project is scheduled to be energized in 2023.
ERCOT Reports $16.7M Net Revenue Favorable Variance
ERCOT CEO Bill Magness told the board the ISO’s revenues continue to be favorable, thanks mostly to the record demand this summer.
“It’s load and weather that drives ERCOT,” he reminded the directors.
Magness reported system administration fees were $5 million overbudget through June because of the weather and Texas’ stronger economy. Including $4.2 million in interest income, the ISO is $16.7 million above its year-to-date projected net revenues.
Staff is projecting a year-end total of $19.8 million in favorable net revenues.
ERCOT has also made “significant progress” on a delayed congestion revenue rights software update, Magness said. He said a go-live date is expected to be finalized in September, now that communication has been improved with the vendor and a better process for managing bug fixes is in place.
Special Membership Meeting to be Set
The board voted to call a special meeting of ERCOT’s corporate members “as soon as reasonably practicable” to hold votes on amendments to the ISO’s Articles of Incorporation, which has been renamed the Certificate of Formation, and to the bylaws, which clarify the definition of affiliates and affiliate relationships. The board unanimously approved both sets of amendments.
The members’ annual meeting isn’t until Dec. 11, but ERCOT’s legal department wants to ensure the amendments are effective for the 2019 membership year.
The directors also approved the 2019 schedule for board meetings and accepted a favorable audit report on ERCOT’s employee 401(k) plan.
Board Clears 15 Change Requests
The board unanimously approved its consent agenda, which included a Nodal Protocol revision request (NPRR) it had remanded back to the Technical Advisory Committee in June.
NPRR847 incorporates an intraday weighted average fuel price into the mitigated offer cap. It unanimously cleared the TAC in May, but the board sent it back over concerns that the calculation of blended fuels was “vague and confusing.” (See “Board Approves 8 Change Requests,” ERCOT Board of Directors Briefs: June 12, 2018.)
The measure is intended to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.
Director Nick Fehrenbach, who represents the commercial sub-segment within the consumer market segment, said he was satisfied with the language changes. He thanked ERCOT for taking his comments into consideration.
The consent agenda also included seven other NPRRs, a revision to the Nodal Operating Guide (NOGRR), two changes to the Planning Guide (PGRRs), an update to the Resource Registration Glossary (RRGRR), a system change request (SCR) and two changes to the Verifiable Cost Manual (VCMRR).
NPRR856: Clarifies that for day-ahead make-whole settlement purposes, the “offline but available for SCED deployment” status is considered an online status and will be considered an offline status after system implementation.
NPRR862: Incorporates a number of revisions addressing recent changes made by the PUC’s rulemaking related to reliability-must-run service (Project No. 46369).
NPRR866: Addresses two objectives related to mapping registered distributed generation and load resources to transmission loads in the network operations model by codifying the existing process for mapping a load or aggregate load resource to its appropriate load point in the model; and by outlining how to map a registered DG facility to its appropriate load point in the model.
NPRR873: Outlines expectations for posting information pertaining to intra-hour wind power and load forecasts on the Market Information Systems public area. The NPRR also proposes two new definitions and acronyms for the intra-hour wind power and intra-hour load forecasts (IHWPF and IHLF, respectively).
NPRR874: Changes the “net allocation to load settlement” stability report by breaking out the load-allocated CRRs monthly revenue zonal amount from the other load-allocated charges, and by providing dollars per megawatt-hour by congestion management zone.
NPRR875: Adds clarifying language to sync the protocols with NPRR864, which modifies the reliability unit commitment engine to scale down commitment costs of fast-start resources with less than one-hour starts.
NPRR877: Allows for use of actual metered interval data for initial settlement of an operating day for electric service identifiers that currently require BUSIDRRQ load profiles.
NOGRR174: Harmonizes the automatic voltage regulator and power system stabilizer testing requirements with the recently approved NERC Standard MOD-026-1.
PGRR061: Includes locations for registered DG facilities in the annual load data request process.
PGRR062: Proposes new processes, communication and document sharing and storage requirements to be included in the new generation interconnection or change request application.
RRGRR017: Supports NPRR866 by providing a process for mapping registered DG facilities to their appropriate load points in the network operations model.
SCR796: Modifies the Market Management System’s validation rules for bids and offers to exclude resource nodes within a private-use network site as valid settlement points for day-ahead market energy-only offers and bids, and for point-to-point obligation bids.
VCMRR021: Aligns the VCM with the language proposed in NPRR847 by removing references to make-whole payments for exceptional fuel costs. The costs will be recovered in NPRR847.
VCMRR022: Directs ERCOT to contract a coal index price with a fuel vendor and includes a methodology for calculating the quarterly fuel adder for coal-fired and lignite-fired resources based on that index.
SACRAMENTO, Calif. — The state’s three investor-owned utilities want lawmakers to limit their liability for forest fires sparked by power lines, but the companies’ proposal met with stiff opposition Thursday at a capitol wreathed in smoke from fires burning in nearby mountains.
The plan, advanced by Gov. Jerry Brown at the behest of Pacific Gas and Electric and others, calls for the state to change a longstanding rule that holds private and public utilities strictly liable when electric lines cause wildfires. Under current law, the utilities must pay for all destruction of private property through the legal remedy of “inverse condemnation” if their equipment was a substantial cause of a fire.
Brown’s plan would still allow suits for inverse condemnation but would require judges to balance the public benefits of the electric infrastructure with the harm caused to private property and to determine if a utility acted reasonably in a particular circumstance. It would also require the utilities to pay proportional damages and not be entirely responsible if others were also at fault.
In addition, the proposal requires utilities to submit wildfire mitigation plans and to harden their grids with upgraded equipment more resistant to weather and fire damage.
Last year’s infernos in California’s famed wine country and the Sierra Nevada foothills resulted in billions of dollars in damage to homes, vineyards and businesses. The current fire season, which is less than half over, appears to be keeping pace.
At Thursday’s hearing, some lawmakers said the proponents’ timing couldn’t have been worse. The largest fire in state history, the Mendocino Complex Fire, raged in the coastal mountains north of San Francisco, and another major fire had closed Yosemite National Park during the peak of the summer tourist season.
The smoke from the fires turned the air in Sacramento into a yellowish haze.
“I don’t know if you noticed, but there’s smoke in the air,” State Assemblywoman Eloise Gomez Reyes told James Ralph, chief of policy and legal affairs for the California Public Utilities Commission. Ralph presented the governor’s plan on behalf of his boss, CPUC President Michael Picker.
Brown originally sent his proposal in writing to the legislature on July 24 with the understanding that it would be part of SB 901, a measure dealing with wildfire prevention. To take effect, the bill must clear the legislature by the end of August, when lawmakers adjourn at the end of a two-year session.
To that end, members of the State Senate and Assembly have held a series of conference committee hearings — on July 25, Aug. 7 and Aug. 9 — to take testimony and gather information. Powerful interests on both sides have argued for and against the proposal.
New Normal
Among those fighting the plan are ratepayer groups, the state’s trial attorneys, insurers, farmers, and cities and counties. They all stand to lose financially if the utilities are given what some call a bailout.
The utilities — PG&E, San Diego Gas & Electric and Southern California Edison — argue multibillion-dollar payouts threaten their financial stability, undercut fire-prevention efforts and result in rate hikes for consumers.
Last year’s fires, which among other damage wiped out a large area of the city of Santa Rosa, caused destruction on an unprecedented scale. Many in California attribute such long and destructive fire seasons to climate change and say they are the “new normal.” (See Wildfires Reshaping Regulator’s Role, CPUC Chief Says.)
That makes the utilities nervous because they tend to receive much of the blame and pay most of the costs.
So far, investigators with the California Department of Forestry and Fire Protection (Cal Fire) have concluded that 16 of last year’s Northern California fires were caused by trees or branches hitting PG&E power lines, along with a power pole failure and a conductor that crashed to the ground.
Eleven of the 16 cases have been referred to county prosecutors to review for possible criminal violations of a state law that requires adequate clearance between power lines and vegetation, according to Cal Fire news releases in May and June.
Altogether, the fires killed 18 residents, destroyed nearly 3,000 structures and burned more than 180,000 acres. The cause of dozens of other blazes, in what Cal Fire calls the “October 2017 Fire Siege,” remain under investigation.
‘Insurers of Last Resort’
The financial fallout for PG&E is huge. Last quarter the company posted a net loss of $1 billion and took a $2.5 billion pre-tax charge for third-party claims related to 14 of the fires. Fitch Ratings downgraded the company’s stock in February, estimating that it could face $15 billion in liability over the next 10 years.
The amount is so massive because California is the only state that relies on inverse condemnation to hold utilities primarily liable for wildfire damage, even when the companies complied with all safety requirements and were only partly to blame for fires.
The current law unjustly “makes utilities the insurers of last resort,” Henry Weissmann, a lawyer for Southern California Edison, told the legislative panel Thursday. He said utilities should be held to a negligence standard of liability, which would require proof of wrongdoing, rather than facing strict liability, which does not.
Weissmann said utilities still would have an incentive to prevent fires under the less-stringent standard because they would continue to be subject to lawsuits and government oversight.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, told lawmakers that the state’s progress in sourcing energy from geothermal, solar and other sustainable power producers was threatened by California’s insistence that utilities, and ultimately ratepayers, foot the bill for catastrophes.
“All of this is predicated on the financial stability of the companies,” he said. “If a utility goes broke … that’s a significant impact.”
Freeing up funds for fire prevention would lead to a safer state, proponents argued.
Skeptics, however, said they found it hard to believe that utilities would behave more responsibly if their potential costs were lessened.
Sen. Hannah-Beth Jackson noted that one rationale behind inverse condemnation is that utilities are given the power of eminent domain for easements on private property. They are therefore fully liable for damage to private property, she said.
“Shouldn’t we expect you’ll do everything possible to protect our property?” Jackson, also a lawyer, asked a panel of utility executives and advocates.
Another major goal of California’s policy has been to make wildfire victims whole as quickly as possible without subjecting them to years of litigation to determine negligence. Applying a strict liability standard skips that fight and moves the parties directly to the issue of damages, Jackson said.
The lawmaker said she had trouble grasping how holding the utilities to a lesser standard of liability would increase public safety, as they contend.
“Why should we reduce their liability and expect they’re going to do more with less liability?” Jackson asked. “I don’t understand the logic here.”
CARMEL, Ind. — MISO last week laid out a more detailed proposal for how it will determine the capacity accreditation of electric storage resources under FERC Order 841.
The RTO is proposing to determine electric storage resources’ capacity based on two different measurements: the resource’s power output capability and its energy storage capacity as measured by MISO’s generator verification test capacity (GVTC).
Speaking at an Aug. 8 Resource Adequacy Subcommittee meeting, Senior Adviser of Capacity Market Administration Rick Kim said the rule will ensure both a megawatt and megawatt-hour measurement of a storage resource’s capability.
Kim said for storage resources under 10 MW or that have fewer than 12 months of operational data, MISO will apply a 5% default equivalent forced outage rate in its unforced capacity calculation. Other storage resources will be assigned a forced outage rate based on their quarterly data inputs to MISO’s generating availability data system (GADS). GADS reporting is required for storage resources 10 MW and above and optional for those under 10 MW.
Because NERC hasn’t yet addressed unit reporting for storage resources, Kim said resource operators should use the “miscellaneous” unit type option when reporting unit data.
“It’s going to be another year before we see registration of energy storage resources,” he added.
Kim also said storage resources connected to the transmission system will require either network resource interconnection service or firm transmission service with MISO to ensure capacity deliverability. If resources are connected at the distribution level, MISO will ensure deliverability with the distribution provider and transmission owner on a “case-by-case” basis, he said.
MISO has said that when storage resources are connected at the distribution level, market participants “must have sufficient metering or accounting for non-wholesale transactions to prevent double counting of energy.”
The RTO in June said it would accommodate Order 841 by dividing storage bid parameters into four operating modes: discharging, charging, continuous operations and offline. Market participants will be left to choose a mode for individual dispatch intervals and will also be responsible for managing the state of charge of their storage units. (See MISO Weighing Feedback to Storage Proposal.) Storage resources will be able to set prices under MISO’s extended LMP.
MISO and stakeholders will continue to discuss storage capacity accreditation at the September RASC meeting, with draft Tariff language targeted for October. November will be used to finalize the full Order 841 compliance filing before FERC’s early December filing deadline.
Oklahoma City-based OGE Energy said last week that a strong regional economy and positive regulatory developments led to an improved second quarter for the company, which reported earnings of $110 million ($0.55/share), compared to $105 million ($0.52/share) the year prior.
Earnings just missed Zacks Investment Research’s consensus estimate of 57 cents/share.
OGE’s Sean Trauschke | YouTube
CEO Sean Trauschke said Oklahoma Gas & Electric continues to add customers near its historical average of 1%, the state’s unemployment numbers are at or under the national average and tax revenues are “now growing solidly again.”
“We are seeing growth on our system driven by our low rates and quality service. I’m very proud of our team’s work to deliver this competitive advantage to the communities we serve,” Trauschke told financial analysts during an Aug. 9 conference call.
“Our core is solid, our employees are doing a great job, and we’re effectively executing on our plans across every area of the company,” he said.
OGE Assets | OG&E
OGE in June reached a $64 million settlement with the Oklahoma Corporation Commission that provides full recovery of its investment in the newly converted Mustang Energy Center. The plant’s seven gas-fired combustion turbines have had more than 1,200 starts this year, Trauschke said.
Mustang Energy Center | OG&E
OGE Energy Holdings, which includes OGE&’s 25.6% limited partner interest and 50% general partner interest in Enable Midstream Partners, contributed 11 cents/share to earnings and $35 million in cash distributions.
“Enable continues to perform very well and their financial metrics are strong,” Trauschke said. He told analysts OGE has not changed its thinking around how the petroleum-gathering company is organized.
CARMEL, Ind. — MISO’s market was competitive in 2017, but the RTO should do more to address increasing congestion and low capacity prices, Independent Market Monitor David Patton told stakeholders last week.
Patton said potential economic withholding throughout the year was low, at about 0.11% of load, with market power mitigation rarely necessary.
“The offers we’re getting and the market outcomes are very competitive,” Patton said in a 2017 post-mortem during an Aug. 9 Market Subcommittee meeting, part of his annual State of the Market report. In late June, he recommended seven new market revisions from the report to the Board of Directors. (See 7 New Recommendations from MISO IMM.)
Patton said MISO’s 2017 peak load of about 121 GW was comparable to the nearly 120-GW peak in 2016 and below the forecasted 125-GW peak. However, congestion costs last year still rose 7% to $1.5 billion, in part because of higher natural gas costs for frequently dispatched gas units.
Patton said four key factors have increased the RTO’s costs of managing congestion.
Factor 1: Lack of Market-to-Market Testing
Patton faulted MISO for not requesting testing from other markets to define market-to-market (M2M) constraints for congestion management. He said his team identified almost 170 chronically binding constraints costing $240 million in 2017 that were never classified as M2M, “generally because MISO did not ask for testing.”
“Most of those dollars are because MISO didn’t ask for the test from either PJM or SPP,” Patton said. “When you don’t define market-to-market constraints with your neighbors that are impacting them, then you’re basically subsidizing their flows on the constraint. You don’t go through the settlement process that would bill them for the constraint.”
Patton acknowledged that the RTO put a tool in place in January to screen for potential constraints, but he said his team has not yet assessed the results of the new practice.
Factor 2: Keeping the Current Pseudo-tie Construct
Patton again leveled his aim at the pseudo-tie process and said PJM’s dispatching of the RTO’s resources has to date resulted in 95 new M2M constraints and $155 million in congestion on those constraints.
“It’s no surprise that we think PJM’s Tariff … shows a lack of understanding of how to run an electrical system,” Patton said, adding that PJM cannot effectively model all constraints in the day-ahead market and is overscheduling flows on the MISO system.
“We think it’s unfortunate that FERC hasn’t figured out how bad this is yet,” Patton said, adding that there are other ways for MISO to deliver PJM’s purchased capacity without giving it dispatch control over resources located in MISO. He said he hoped more of the RTO’s market participants would come out in public support of the complaint.
Factor 3: Need for Increased Outage Coordination
Patton said transmission and generation outages occurring simultaneously on the same constraint have contributed to $400 million in congestion to date — more than 30% of all of MISO’s real-time congestion.
“What this points to is the need to give MISO more authority in denying or approving outages,” Patton said. “In some cases, MISO is the only one that can coordinate these because of the lack of communication between generation and transmission.”
Greater outage coordination is an ongoing discussion in the RTO’s larger effort around resource availability and need currently being discussed in its Reliability Subcommittee. (See MISO Moving to Combat Shifting Resource Availability.)
Factor 4: Incomplete Facility Ratings
Patton said most of the RTO’s transmission owners don’t adjust their facility ratings to reflect ambient temperatures and wind speeds. He said adjusted facility ratings could have saved the RTO as much as $127 million in production costs in 2017.
“If transmission owners submitted dynamic ratings to MISO, we’d have much more transmission capability,” Patton said.
Capacity Auction
Patton also said the RTO’s capacity auction design is causing capacity prices to remain “inefficiently low.” The 2018/19 auction resulted in almost all local resource zones clearing at $10/MW-day, while the 2017/18 auction resulted in a single clearing price of $1.50/MW-day. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
Had MISO implemented a sloped demand curve design in its auction, Patton estimated that auction clearing prices would have been $115.74/MW-day in all zones in the 2017/18 planning year and $111.06/MW-day in nearly all zones for the 2018/19 planning year. He said the RTO’s competitive suppliers stand to benefit the most from a sloped demand curve.
Patton said the RTO lost 2.6 GW of capacity on net in 2017 owing to a flawed capacity auction design, “persistent” low natural gas prices that suppress energy prices and environmental regulations “requiring costly retrofits for certain resources.”
MISO Response Timed to Market Roadmap
MISO Executive Director of Market Operations Shawn McFarlane said the RTO is still preparing its required response to the Monitor’s observations and recommendations.
He said this year MISO will align its written response with the release of the RTO’s Market Roadmap list of market improvements to its board. The RTO will publicly post a written response in October, present the response at the November Market Subcommittee meeting and discuss it with the board at the December meeting of its Markets Committee.
“This year we will use most of the 120 days allotted by the Tariff,” McFarlane said, adding that the RTO has historically provided a written response within 90 days.
MISO Charts Market Improvements with Stakeholder Help
Meanwhile, MISO is continuing its Market Roadmap prioritization to determine what improvements it should undertake in 2019. Unofficial Market Roadmap rankings show that the RTO and stakeholders agree that creating short-term capacity reserves is a pressing matter.
MISO melded its market improvement priorities with the Monitor’s and stakeholders’ rankings after a June and July voting period in which 67 stakeholders participated. (See MISO Stakeholders to Rank Market Improvement Ideas.) The preliminary results show the RTO should next year focus on creating an improved combined cycle generation model and developing a short-term capacity reserve product that can supply capacity within 30 minutes.
NEW YORK — NYISO CEO Brad Jones likely summed up the sentiments of the dozens of industry experts attending Infocast’s New York Energy Market Summit last week to learn more about the state’s rapidly evolving grid and changing policy landscape.
“All of us seem so thankful to be in this industry at this time,” Jones said. “There’s so much change going on, so much opportunity to do new things and create new things.”
Kevin Sheen, vice president of business development at Terra-Gen, said New York began falling behind other states in renewable development despite having started a 10-year renewable energy credit (REC) program in 2004 that managed to incent about 1,400 MW of wind over the past decade or so.
Realizing it needed to do more, the state last year began offering 20-year REC contracts, Sheen noted. He said that the state’s commitment to improve transmission signals to developers that New York is worthy of their investment and time. The ISO’s Congestion Assessment and Resource Integration Study process identifies the top congestion elements on the system and indicates where developers ought to be thinking in terms of building additional transmission. (See NYISO Study Identifies Key Areas of Tx Congestion.)
“Delays are part of development — they happen in every market — but I think New York has done the best they can to try to address that,” Sheen said.
Transmission developers cited permitting and interconnection costs as the two biggest risks for new project development.
“We recently saw Deepwater Wind narrowly get through the East Hampton town board process by a 3-2 vote, so five individuals held the fate of that 90-MW cable” connecting the offshore project to land, Anbaric Development Partners project manager Bryan Sanderson said.
Bringing 2,400 MW into NYISO Zones J and K is going to be hard because the ISO’s study process takes three to five years, Sanderson said, leaving companies to bid today on costs they will not know until 2022.
“Imagine New York procuring its first offshore wind farm and the interconnection costs come in $500 million more than projected,” he said. “That would be a huge embarrassment. Just ask Massachusetts about their Northern Pass experience.
“One problem with transmission development is that it eats its own young, so you solve the problem like congestion and the price arbitrage disappears,” Sanderson continued. “How do you pay for your line when your mere existence eliminates your profit stream?”
John Douglas, CEO of transmission developer oneGRID, noted there’s been talk of developing a national backbone grid to optimize renewables, but no one has resolved the problem of who will pay for it and how all the RTOs would interact.
“It’s unfortunate, because we’re going to end up with all these regional, Band-Aid optimizations when there could be something national,” Douglas said.
Jones addressed the conflict between state policies and RTO market principles, pointing out that both ISO-NE and PJM went to FERC with solutions to what they saw as state interventions that could undermine their wholesale markets.
“When New England brought CASPR [Competitive Auctions with Sponsored Policy Resources] to the commission, they said, ‘We want to address it in this way,’ essentially to change the capacity market structure, which would arguably eliminate the impact of state subsidies on new resources,” Jones said.
“The FERC agreed with them, but in a decision which I never knew was possible. They approved 3-2,” Jones said. “Clearly the FERC was torn; they struggled with that decision.” (See Split FERC Approves ISO-NE CASPR Plan.)
Jones said the commission saw ISO-NE’s solution as being different from PJM’s rejected solution in that the former was dealing only with new assets that were being subsidized, while the latter was dealing with both new and existing assets, primarily nuclear and coal units.
“New York looks very similar to PJM, with assets that have been retained, plus new assets, but FERC has not decided to take any action on New York,” Jones said. “I think the commission is waiting to see where the NYISO gets on its work to price carbon directly into the wholesale market.” (See Stakeholders Annoyed by NYISO Carbon Price Draft.)
Off the Grid
Douglas said he realized how most large industrial customers are looking for change when he heard that a survey by one of the nation’s largest utilities found that its top 15 customers all want to get off the grid.
“Imagine you’re an integrated, investor-owned utility and your top customers are all saying they don’t want to have anything to do with you,” Douglas said.
oneGRID is planning the 1,000-MW HVDC Empire Connector project to move energy from upstate into New York City via the Gowanus Substation in Brooklyn. The project is now in the second phase of its solicitation, aggregating wind, solar and biomass supply offers to sell into the city.
Contracted merchant power “is a forgotten pathway to transmission development,” and customers in New York want it, Douglas said.
“We found out how important physical delivery is to customers in New York City for both reliability, and probably more importantly, for resilience,” Douglas said. “HVDC is so controllable that it actually counts as in-city generation, so it’s a tremendous advantage.”
While renewable energy resources are known for changing the direction of power flow on the grid as smaller generators along the line feed their excess electricity back onto the grid, New York City has so far been unaffected by that phenomenon, said Damian Sciano, Consolidated Edison director of distributed resource integration.
“We’re in a dense urban area … so even when someone puts a fairly large solar installation in, or CHP [combined heat and power] — those are the two big things we see in our service territory — it’s pretty much consumed very close to where it’s generated,” Sciano said. “We don’t typically have backfeed on the substations.”
Lawrence Berkeley National Laboratory research scientist Andrew Mills said a team at the lab compared the levelized cost of energy estimates with value estimates and found that the most attractive U.S. sites for offshore wind are located off New England, while the least attractive are far offshore of Florida and Georgia, where the water is deeper and the wind speeds are lower.
Wind energy off the southeast coast is worth about $160/MWh less than the best sites up north, he said.
“We were very interested in questions about the seasonal and diurnal profiles of offshore wind and how much that might be driving differences in the value across these sites,” Mills said. “If you were to just have a flat block of power, which is constant across all hours, we wouldn’t be far off in the estimates we came up with … within 5% or so.”
Differences in average energy and REC prices primarily drive locational variations, not differences in diurnal and seasonal wind generation profiles, he said. The market value of offshore wind was lowest in the most recent year evaluated, 2016, falling roughly 50% from 2007.
The marginal total market value of offshore wind — considering energy, capacity and RECs — varies significantly by project location and is highest for sites off of New York, Connecticut, Rhode Island and Massachusetts. The median, 2007-2016 market value is highest in ISO-NE (around $110/MWh), in part because of higher REC prices. The energy and capacity value is higher for NYISO, particularly Long Island.
If you look south, the median value is “significantly lower, down in the $55/MW range in the non-ISO region south of PJM,” Mills said.
The capacity value can be up to 50% different from that calculated based on a flat block of power, but capacity value is only a small component of overall value, Mills said. The capacity credit of offshore wind in the NYISO and ISO-NE markets is significantly higher in winter than in summer, with offshore wind in these regions benefiting from having capacity credit assessed in both seasons.
FERC on Tuesday approved Tariff revisions that will finally allow SPP to implement a resource adequacy requirement (RAR), reducing its planning reserve margin from 13.6% to 12% (ER18-1268).
The commission found the revisions will help ensure that sufficient capacity and planned reserves are maintained to meet SPP’s balancing authority load requirements. The proposal also clarifies the types of authorities that may impose rules considered force majeure events, defined as “any curtailment order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities.”
SPP revised its filing after FERC rejected a previous submission in September 2017, the second time its RAR proposal was found to be deficient last year. (See FERC Again Rejects SPP’s Resource Adequacy Revision.)
The grid operator said its new Tariff Attachment AA includes all the terms and conditions relevant to the establishment, compliance and enforcement of the requirement that each load-responsible entity (LRE) in the SPP BA area maintain sufficient capacity and planning reserves to serve its forecasted load.
PSO’s gas-fired Tulsa Power Station provides resource adequacy | Public Service Co. of Oklahoma
The RAR change will require LREs without sufficient generation to participate in bilateral capacity markets. FERC noted SPP’s current market is “relatively net long” compared to the planning reserve margin, and that “likely many sellers of capacity are available to meet LREs’ net peak demand and planning reserve margin.”
The commission said it “continue[s] to encourage SPP and its stakeholders to consider the potential for the exercise of market power in the market for bilateral capacity as the overall reserve margin potentially shrinks in the future.”
FERC suggested last year the proposal could be “more fully develop[ed].” It provided guidance that SPP require all power purchase agreements be backed by verifiable capacity; that the proposed treatment of firm power purchases and sales in the determination of net peak demand was unduly discriminatory; and that the RTO was unable to support its proposal to post publicly a list of all LREs unable to meet their RAR.
Westar Energy protested the most recent filing, separately and with Kansas Power Pool and Missouri Joint Municipal Electric Utility Commission. FERC sided with SPP in each of the arguments.
The RAR proposal is effective July 1, 2018. SPP said this would allow LREs to participate in a full cycle of the annual process before being exposed to a deficiency payment.
SPP’s Board of Directors and stakeholders approved a package of policies in January 2017 that included reducing the RTO’s planning reserve margin to 12%, which translates to a 10.7% capacity margin. LREs with resource mixes that are at least 75% hydro-based are allowed a planning reserve margin of 9.89%.
A stakeholder task force spent more than two years developing the package, which was projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
SPP said it intends to recalculate the planning reserve margin every two years, “based on a probabilistic analysis using a loss-of-load expectation study.” Any future changes to the planning reserve margin must go through the RTO’s Regional State Committee, composed of state regulators, for approval.
Commission Rejects PMU Proposal over Cost Concerns
The commission rejected without prejudice to SPP a second Tariff change that would have required phasor measurement units (PMU) at new generator interconnections, saying the proposal’s language is unclear (ER18-1078).
The American Wind Energy Association argued against the Tariff proposal, questioning the extent to which transmission owners should be required to fund PMU installations. AWEA raised concerns that SPP did not address funding obligations and said that, as drafted, the proposal would have allowed TOs to exercise market power and force interconnection customers to fund installations.
FERC found the revision’s proposal to allow TOs the option to fund PMU installations only when their interconnection customers are affiliates “could result in affiliated interconnection customers having lower costs than non-affiliated interconnection customers.” That would give affiliates an undue competitive edge, the commission said.
The agency said SPP did not address how TOs would account for the costs of the installations for their own generators or those of affiliated interconnection customers, and how the costs would be treated under the transmission formula rates in order to prevent unreasonable and/or unduly discriminatory rates.
The commission said any subsequent SPP proposal should clarify how TOs will treat PMU installation costs to avoid including them in transmission rates. Doing so, it said, could effectively result in non-affiliate customers subsidizing installations for generators belonging to TOs and/or their affiliated interconnection customers.
FERC also said SPP should develop Tariff language regarding responsibility for ongoing PMU communication and operation and maintenance expenses, and clarify the extent to which the interconnection customer can use existing equipment, such as relays or digital fault recorders with phasor measurement capabilities, or provide data from PMUs already deployed and/or sited on the generator side of the interconnection point.
PMUs are devices that measure the voltage, frequency and angle of the grid’s electrical waves, using a common time source for synchronization. The devices can take samples hundreds of times a second, while the standard supervisory control and data acquisition systems can have scan rates of 10 to 30 seconds.
The proposal cleared SPP’s board and stakeholder groups in January.
The results of PJM’s 2018 Base Residual Auction were “not competitive” and illustrate the need to change how the RTO sets its capacity offer cap, the Independent Market Monitor said Thursday in its second-quarter State of the Market report.
“The outcome of the [2021/22] Base Residual Auction was not competitive as a result of participant behavior which was not competitive, specifically offers which exceeded the competitive level,” the report said.
In a separate analysis released Thursday night, the IMM calculated that total revenues from the auction would have been only $6.57 billion had all identified noncompetitive offers been capped at their net avoidable cost rate (ACR). The analysis said offers exceeding net ACR, while permitted by current rules, amounted to “economic withholding” and boosted total auction revenue by 41.5% to $9.3 billion.
The Market Monitor’s analysis found that clearing prices in the 2018 Base Residual Auction would have been lower everywhere but the PSE&G zone had prices been capped at net avoidable cost rate. Not identified is the DEOK zone, which cleared with the rest of the RTO at $140/MW-day, but would have priced at $128/MW-day. | PJM, Monitoring Analytics
Capping at net ACR would have reduced the RTO clearing price from $140.53/MW-day to $90.47/MW-day. “All binding constraints would have remained the same except that the ComEd import constraint would not have been binding and the DEOK import constraint would have been binding,” the analysis said.
It singled out nuclear units, saying more nuclear capacity was offered at higher sell offer prices and fewer nuclear megawatts cleared than in 2017.
Although the IMM has regularly cited structural market power in the capacity market, 2018 was the first time that mitigation efforts failed and market prices were inflated, said Joe Bowring, president of Monitoring Analytics, which serves as PJM’s independent Market Monitoring Unit (MMU).
“I think it’s significant,” Bowring said in an interview. “It’s the result of the fact that the offer cap in the rules is mis-specified and needs to be fixed. We’ve been making that point for a while. But that issue resulted in an impact on this auction.”
PJM issued a statement Friday disagreeing with the Monitor’s conclusions.
“While PJM respects the Market Monitor’s opinion, the facts regarding the 2021/2022 Base Residual Auction are clear. The auction was conducted in accordance with all Tariff-specified requirements and rules, including those rules related to the application of offer caps, and the offers were in concurrence with those rules. The Market Monitor expresses an opinion of what the offer cap should be; the proper forum for such concerns about competitiveness of offers is the Federal Energy Regulatory Commission.”
Grades
For the 2018 BRA, the Monitor gave “not competitive” grades to the aggregate and local market structures, as well as market performance and participant behavior. Market design was judged “mixed.” The Monitor gave the 2017 BRA the same grades for market design and structures but rated both participant behavior and market performance as competitive.
The IMM said this year’s auction failed the competitive test because of the way PJM sets the offer cap under Capacity Performance rules.
| PJM, Monitoring Analytics
“Some participants’ offers were above the competitive level. The MMU recognizes that these market participants followed the capacity market rules by offering at less than the stated offer cap of net CONE [cost of new entry] times B [balancing ratio]. But net CONE times B is not a competitive offer when the expected number of performance assessment intervals is zero or a very small number and the nonperformance charge rate is defined as net CONE/30. Under these circumstances, a competitive offer, under the logic defined in PJM’s Capacity Performance filing, is net ACR. That is the way in which most market participants offered in this and prior Capacity Performance auctions.”
Because net CONE times B exceeds the competitive level in the absence of performance assessment hours (PAHs) — periods requiring urgent actions, such as the dispatch of emergency or pre-emergency demand response — it should be re-evaluated for each BRA, the report said.
Repeating a recommendation it first made in 2017, the Monitor said PJM should develop forward-looking estimates for both B and the expected number of PAHs used in calculating rates for nonperformance charges.
The Monitor said CP rules, which increased penalties for nonperformance, “have significantly improved the capacity market and addressed many of the issues” it previously identified.
But it also said the CP Tariff language is overly rigid. “If the Tariff had defined the offer cap consistent with PJM’s filing in the Capacity Performance matter, the offer cap would have been net ACR rather than net CONE times B,” the report said.
“The bottom line is net CONE times B is way too high, especially when the performance assessment hours are less than 30,” Bowring said.
Of the 1,132 generation resources that submitted CP offers for delivery year 2021/22, 953 (84%) used the net CONE times B offer cap, while 129 (11%) were price takers.
Only eight generation resources (0.7%) requested the Monitor calculate unit-specific ACR-based offer caps. “The fact that so few resources requested unit specific offer caps is further evidence that the net CONE times B offer cap exceeds competitive offers,” the Monitor said.
PJM Disputes
PJM noted that market sellers must declare whether they will use net ACR or the net CONE times B offer cap 120 days before the auction.
“During the weeks where actual offers are submitted and the auction is cleared, the IMM has full visibility into all data relevant to the auction, including resource offers. If the IMM believed that economic withholding was taking place based on submitted offers and preliminary auction clearing results, the IMM could have consulted with the asset owner during that time period,” PJM said.
“If the IMM believes that economic withholding took place, the proper course of action is for the IMM to refer the market seller responsible for such offers to FERC for further investigation. If the IMM believes that the current rules regarding the default offer cap allow for economic withholding, the IMM, like any other stakeholder, can bring forward a problem statement and issue charge to be discussed by the PJM stakeholder body.”
PJM also questioned the IMM’s simulation results for nuclear units offering at their ACR. “They are based upon hypothetical offers that could have been submitted on the basis of the IMM’s anticipation of potential performance assessment hours, as well as the IMM’s determination of the appropriate value of ACR to use for certain resources as opposed to their actual going-forward costs,” PJM said. “Given these errors in the assumptions, the simulations bear no direct relevance to any hypothetical auction outcome had different offer-capping rules been in place for this auction.”
PJM spokesman Jeff Shields said the RTO does not agree that there is a problem with the current offer cap. “PJM is supporting stakeholder consideration of proposals that could result in adjustments to the default offer cap, but it is unclear whether a proposal that results in such an adjustment will be approved,” he said.
Should the proper offer cap be net ACR? “No. This assertion is dependent upon an expectation of performance assessment hours,” Shields said. “Whether a given submitted offer was above the competitive level, even though it was within the rules, is a matter for FERC.”
Comparison with 2017
The Monitor’s quarterly report also repeated its concerns over generation subsidies, saying they “threaten the foundations of the PJM capacity market as well as the competitiveness of PJM markets overall.” The Monitor wants to extend the minimum offer price rule (MOPR) to include existing units as well as new resources.
Although the Monitor found the capacity market problematic, it said PJM’s energy markets produced competitive results in 2018. Compared with the first half of 2017, PJM saw the following in the first six months of 2018:
Energy prices and fuel prices were higher and more volatile, resulting in higher margins for generation types. Average energy market net revenues increased by 160% for a new combustion turbine; 63% for combined cycle plants; 525% for coal plants; 44% for nuclear units; 10% for wind; and 20% for solar.
Total energy uplift nearly tripled from $49.7 million to $146.4 million.
Payments for DR programs increased 13.7% to $271.7 million.
Congestion costs increased by 214% to $896.6 million. Auction revenue rights and financial transmission rights revenues offset only 50.7% of total congestion costs for the 2017/18 period, the first in which new rules required the allocation of balancing congestion to load instead of FTR holders. ARR and FTR revenues offset 98.1% of congestion costs for load during the 2016/17 planning period.
New Recommendation: FTR Liquidations
The report includes two new recommendations. The Monitor said PJM should set a high priority on reviewing how it liquidates FTR holdings, a recommendation prompted by GreenHat Energy’s default in June, when it failed to pay a weekly invoice of $1.2 million. PJM has asked FERC to approve a waiver of rules that require immediate liquidation of a defaulting member’s FTR portfolio (ER18-2068). (See “Default Details,” PJM MRC/MC Briefs: July 26, 2018.)
Bowring said he supports a change in the rules that allows PJM to liquidate the portfolio over a longer period. “These are long-term” positions, he noted.
New Recommendation: REC Transparency
The Monitor also said states with renewable portfolio standards should make the data on renewable energy credits (RECs) more transparent. D.C. and all but five of the 13 states in PJM have a mandatory RPS. Virginia and Indiana have voluntary standards, while Kentucky and Tennessee have no renewable targets. West Virginia repealed its voluntary standard in 2015.
Although FERC has determined that RECs are not regulated under the Federal Power Act unless they are sold in a bundled transaction that includes a wholesale sale of electric energy, RECs affect market prices and the mix of clearing resources, the report said. “Some resources are not economic except for the ability to purchase or sell RECs.”
But data on REC prices, clearing quantities and markets are not publicly available for all states. In addition, RECs do not need to be consumed during the year of production, resulting in multiple prices for a REC based on the year of origination, the Monitor said.
“RECs markets are, as an economic fact, integrated with PJM markets, including energy and capacity markets, but are not formally recognized as part of PJM markets. It would be preferable to have a single, transparent market for RECs operated by PJM that would meet the standards and requirements of all states in the PJM footprint including those with no RPS. This would provide better information for market participants about supply and demand and prices, and contribute to a more efficient and competitive market and to better price formation. This could also facilitate entry by qualifying renewable resources by reducing the risks associated with lack of transparent market data.”
The Monitor said the CO2 price implied by REC prices ranges from $4.74/metric ton in D.C. to $35.41/ton in Pennsylvania, while solar RECs’ implied prices range from $18.07/ton in Pennsylvania to $861.52/ton in D.C.
Those contrast with the 2018 average clearing price of $4.31/ton in the Regional Greenhouse Gas Initiative and the social cost of carbon, which is estimated at about $40/ton. “The impact on the cost of generation from a new combined cycle unit of an $800/ton carbon price would be $283.56/MWh. The impact of a $40/ton carbon price would be $14.18/MWh,” the Monitor said. “This wide range of implied carbon prices is not consistent with an efficient, competitive, least-cost approach to the reduction of emissions.”
