Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Aug. 24. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report. There is no Members Committee meeting scheduled this month.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:25)
Members will be asked to endorse the following proposed manual changes:
A. Manual 11: Energy & Ancillary Services. Revisions developed as part of the implementation of Coordinated Transaction Scheduling, a new real-time energy scheduling product across the PJM-MISO interface. The presentation will include associated revisions with the Regional Transmission and Energy Scheduling Practices document.
3. Governing Document Revisions to the Limitation on Claims (9:25-9:40)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions that clarify the two-year limit on requests for billing adjustments.
4. Seasonal Capacity Resources Sr. Task Force (SCRSTF) (9:40-10:10)
5. Dynamic Schedule Pro Forma Agreement (10:10-10:25)
Members will be asked to endorse proposed joint operating agreement and Tariff revisions to develop a pro forma agreement for dynamic scheduling. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
Fort Lauderdale-based trader K. Stephen Tsingas agreed to pay $2.7 million in penalties and restitution in a deal with FERC’s Office of Enforcement that will also bar him from trading in commission-jurisdictional markets for three years. The commission approved a consent agreement setting the terms on Aug. 22 (IN5-5).
Tsingas and his company, City Power Marketing, agreed to the settlement without admitting to the commission’s allegation that they violated the Federal Power Act and commission regulations by engaging in market manipulation and later lying to FERC investigators.
City Power also agreed to pay a $9 million civil penalty, but the company is defunct and FERC agreed not to pursue Tsingas for the additional amount. In a filing in 2015, Tsingas said that FERC’s investigation forced him to lay off all his employees and “destroyed” the company. (See UTC Trader: Firm was Ruined by ‘Unfair’ FERC Prosecution.)
Although the $11.7 million in penalties were reduced from the $16.3 million the commission had sought, the case represents a victory for FERC in its crackdown on traders who profited from what the commission called risk-free up-to-congestion (UTC) trades. FERC said the trades were intended to cash in on line-loss rebates in PJM — the same type of trading that gave rise to the commission’s high-profile battle with brothers Kevin and Rich Gates and their Powhatan Energy Fund.
Three Types of Trades
The commission said City Power collected the rebates — or marginal loss surplus allocations (MLSA) — through three types of UTC transactions: “round-trip” trades that canceled each other out; trades between import and export pricing points of the same PJM interface with equivalent prices (SOUTHIMP-SOUTHEXP); and trades between two PJM nodes that historically had a very small price spreads (NCMPAIMP-NCMPAEXP).
The commission concluded that City Power created the false impression that it was trading to arbitrage price differences “when, in fact, it was engaging in trades solely to collect MLSA payments to the detriment of other market participants.”
Tsingas
The commission also accused Tsingas of attempting to mislead investigators by denying the existence of incriminating instant messages between him and a trading colleague.
The commission sued Tsingas after he failed to respond to a July 2015 order demanding the $16.3 million. The two sides reached a settlement in March, after a U.S. district court last August rejected Tsingas’ motion to dismiss and in January denied FERC’s motion for summary judgment. Approval of the settlement was delayed by FERC’s loss of a quorum in February.
Under the consent agreement, Tsingas will pay $1.3 million in disgorged profits to PJM and a $1.42 million penalty to the U.S. Treasury Department. Tsingas must pay $825,000 to PJM within 60 days, paying the balance over 10 years.
Barred from Trading
Tsingas also agreed that neither he, nor any person acting on his behalf, “will engage or participate (whether through consulting, advising, directing or strategizing), directly or indirectly, in any trading transaction (whether physical or financial or virtual) within the commission’s jurisdiction for three years.”
However, the bar “does not apply to any business entity in which Tsingas has an ownership interest, or its employees, so long as Tsingas does not personally engage or participate in, directly or indirectly, or otherwise operate or consult about, any trading transaction within the commission’s jurisdiction.”
“FERC would not have been able to pursue this remedy had the court decided the case on the merits,” observed Matthew Connolly, a senior associate in the litigation department of Nutter McClennen & Fish.
Like Tsingas, the Gates brothers and Coaltrain Energy — a third set of defendants accused of profiting from riskless UTC trades — have sought de novo reviews of FERC’s allegations, in which a federal district court would decide all issues of fact and law. (See Traders Deny FERC Charges; Seek Independent Review.)
The Powhatan case has been stalled in the Eastern District of Virginia, awaiting a judge’s ruling on how the review should proceed. FERC has asked for a short, appellate-style review (3:15-cv-452).
Coaltrain is awaiting a ruling from a judge in the District Court for Southern Ohio on its motion to dismiss (2:16-cv-00732).
PJM Seeks Advice
In April 2015, PJM asked FERC for advice on who should receive the disgorged profits and how they should be calculated. It also sought direction on how refunds should be made to parties who are no longer PJM members and noted that there were six entities alleged to have engaged in sham trades who would also be considered victims of the City Power trades. (See PJM Asks FERC for Direction on Refunds from Illegal Trades.)
In an order in July 2015, the commission told PJM to establish a method to distribute the resettled MLSA payments to market participants that would have received higher rebates if not for the money collected by City Power. The RTO must seek approval of its methodology from the director of the Office of Enforcement within 45 days after receiving the disgorged funds.
Power sellers and utilities in CAISO are urging the grid operator to develop a long-term plan to procure the flexible capacity resources increasingly needed to manage the integration of variable renewable generation.
Market participants commented on a recent stakeholder meeting regarding the ISO’s Flexible Resource Adequacy Criteria and Must Offer Obligation Phase 2 (FRACMOO 2) proposal. The ISO is proposing to introduce new variations in its flexible resource adequacy (RA) capacity product, which is intended to increase the ramp rate of the flexible capacity fleet. (See CAISO Flex Capacity Effort Targets Increased Variability.) CAISO is needing quicker ramping speeds within shorter time cycles as more renewables are brought into the system.
Monthly Three-hour Generator Ramp-ups are on the Increase in CAISO | CAISO
The current proposal is a set of short-term solutions, and CAISO said it will later develop a “long-term RA roadmap” to integrate system, local and flexible capacity needs, and state renewable portfolio standards.
The bulk of the current proposal represents short-term modifications to the flexible capacity criteria to emphasize start-up and minimum run times. CAISO is exploring the use of intertie resources but does not yet have a specific proposal. It hopes to have a program in place in time for the 2020 RA year.
Southern California Edison (SCE) said it is not a function of the resource adequacy program to optimize resources, as stated in a Brattle Group proposal discussed in the stakeholder call. Brattle included “products to optimally utilize resources” as a goal of flexible capacity, but SCE said that optimal use is the role of the wholesale market. The RA program is meant to ensure that capacity is available via a must-offer obligation. “SCE does not believe that the CAISO has clearly demonstrated where the current three-hour product is failing,” the company said.
Powerex, which markets BC Hydro output, commented that CAISO should examine why flexible capacity needs are causing challenges and how to make “cost-effective resource investments” to achieve environmental goals. Powerex said the ISO should develop additional tools to reduce the magnitude and steepness of net load ramps when they would otherwise exceed available flexible capacity in real time, allowing it to procure additional flexible capacity from existing resources.
The Western Power Trading Forum (WPTF) said that “this initiative does not have to be the end all, be all in incenting flexibility from the CAISO fleet. The CAISO can also enact energy market reforms and, if necessary, procure backstop capacity.” The group urged the ISO to keep the proposal simple and target products that will incentivize load-serving entities to contract with the most flexible resources, and incent interties to economically offer in their capacity.
“This will provide proper market incentives resulting in economically efficient outcomes, including the potential of the retirement of less flexible, unneeded capacity,” WPTF said.
The Alliance for Retail Energy Markets, a group representing competitive suppliers — including Constellation NewEnergy, Direct Energy and Noble Americas Energy Solutions — contended that CAISO should identify the root causes of the reliability needs and develop a market-based solution that properly assigns costs and provides price signals.
FRACMOO 2 is Intended to Reduce Curtailment of Renewables | NextEra Energy’s Altamont Pass Wind Farm Source Wikimedia
“In spite of many years of effort, the CAISO is still seeking to understand the flexible needs on the system,” the group said in its comments. “In addition, the continued focus of the CAISO on specifying prescriptive capacity procurement requirements for load-serving entities (LSEs) is fundamentally misplaced and excessively burdensome.” Meeting flexible capacity needs through ancillary services would provide transparency and investment signals for new resources, the suppliers said.
CAISO plans to have a draft final FRACMOO 2 proposal early next month and approval from the Board of Governors by the second quarter of 2018.
By Jason Fordney, Tom Kleckner, Amanda Durish Cook, Rory D. Sweeney and Michael Kuser
FOLSOM, Calif. — CAISO and other electric grid operators across the country managed large and rapid swings in solar generation output Monday during the first continent-wide total solar eclipse in nearly a century.
ISOs and RTOs were well prepared for the event, especially in solar-heavy California where the obscuration of the sun took thousands of megawatts of utility and rooftop solar off the grid. CAISO had to ramp up hydro and natural gas generation as solar dropped off, then do the reverse more quickly than usual as the sun came back.
Electronic board in CAISO control room displays solar generation (left) and load (right) during and after eclipse | CAISO
“We wanted to make sure we could make it if it was an extremely hot day, or if it was a mild day,” CAISO Executive Director of Operations Nancy Traweek said. She added that the ISO had reached out to solar and hydro operators and asked them to be prepared for the event.
The last total solar eclipse to occur in the continental U.S. was before the growth in solar power in 1979 and was viewable only from the Pacific Northwest, according to NASA. Monday’s was the first total eclipse since 1918 to span the width of the U.S.
As eyes equipped with protective glasses turned upward around the country, CAISO employees excitedly gathered outside the building, some with family members, to view the event.
CAISO said it would not be able to provide precise figures for how much solar generation dropped off its system until later this week.
“We forecasted 4,200 MW of utility-scale solar coming off. We believe that the actual will be more in the 3,000 to 3,500 MW range,” CAISO spokesman Steven Greenlee said.
CAISO data showed that the eclipse took a little more than 3,000 MW offline; in a briefing Monday morning, ISO officials said more than 3,000 MW of utility solar and 1,400 MW of rooftop solar could be lost.
Grid operators had to deal with two solar ramp-ups rather than just one.
About 10:50 a.m. PT, after totality, load was about 30,500 MW and solar generation was about 4,100 MW, with the grid stable. When the sun was nearly clear of the moon about 11:30, CAISO said load was about 29,300 MW and solar generation was about 6,800 MW. By about 1:30 p.m., solar generation in the ISO was back up to about 9,000 MW. There is about 10,000 MW of solar capacity on the ISO system.
CAISO had to manage not only the rapid loss of solar but also a steeper-than-usual climb of that resource compared with a normal day as the sun returned. CAISO predicted it would lose about 51 MW/minute, and as the blockage waned, solar generation came back at a rate of 93 to 100 MW/minute. On a normal morning, solar ramps about 29 MW/minute.
Wholesale prices briefly went negative as solar returned, as they normally do when there is excess generation on the grid. CAISO said that the 1,000-mile East-West span of the Western Energy Imbalance Market (EIM) allowed it to call on available resources as other areas ramped down.
About 860 MW of solar went off the grid in the EIM.
SPP, ERCOT See Little Impact
SPP had anticipated a peak load of approximately 45,000 MW across its system Monday but saw demand about 2,500 MW below that as air conditioning usage dropped and manufacturing facilities closed while employees observed the eclipse.
“In preparation for the relatively sudden and not entirely predictable drop in load, SPP utilized its day-ahead market processes beginning Aug. 20 to commit adequate reserves to accommodate load swings and the resulting impacts to frequency and interchange,” SPP said. The RTO increased its regulation service in preparation. An eclipse also slows wind speed by cooling air, causing a 1,200-MW swing in the RTO’s wind generation that also had to be managed.
“By increasing our regulation requirements, we essentially ‘widened the lanes’ of our system and operated more conservatively than we might have on a normal day to accommodate any unpredictable occurrences during this rare event,” Director of System Operations CJ Brown said.
This was a great learning opportunity for SPP,” said Vice President of Operations Bruce Rew. “And I’m proud that our staff and systems were able to ensure that, despite so many variables and the rarity of the solar eclipse, it was essentially a non-event electrically speaking.”
| GreatAmericanEclipse.com via SPP
Utility-scale solar in the ERCOT system dropped from a peak of 760 MW to a low of 299 MW during the eclipse, while total system load dropped from 60,824 MW to 60,163 MW. The ISO said a number of factors could have contributed to the load decrease, including reduced air-conditioning demand.
Duke Loses 1,700 MW in NC
In North Carolina, Duke Energy reported that it lost about 1,700 MW of capacity during the height of the eclipse. “Given the weather conditions, we should have expected 1,808 MW of solar output during the afternoon. But at the height of the eclipse, we were getting only about 109 MW,” said spokesman Randy Wheeless.
North Carolina is the nation’s No. 2 state for solar capacity, with 2,500 MW connected to the Duke system.
Peak demand for Duke Energy Carolinas and Duke Energy Progress in North Carolina is around 22,500 MW on a typical summer day.
MISO has no Issues
MISO employees watching the eclipse | MISO
MISO said it navigated the eclipse without reliability problems as it crossed its 15-state footprint, but operators did see a significant drop in load.
“Around 1:15 p.m. ET, demand for electricity in the region flattened out and then dropped during a two-hour period as the moon passed in front of the sun. Load began steadily increasing after 3 p.m.,” said spokesman Mark Adrian Brown. “Cooler-than-expected temperatures likely contributed to the drop in load as storms rolled through the Upper Midwest Monday afternoon. Decreased solar generation during the eclipse did not have a major impact on the numbers.”
Currently, MISO has about 180 MW of grid-scale solar and an estimated 350 MW of distributed solar in its footprint.
The RTO said before the event that it would be monitoring its distributed generation and learning lessons for the eclipse on April 8, 2024, when solar will make up more generation in the region.
Clouds in PJM
In the eastern half of the country, cloud cover and rain dampened the eclipse’s effects. At PJM headquarters in Valley Forge, Pa., more than 50 people filtered through an onsite auditorium to try and view the eclipse as it passed across the continent and approached its footprint, the RTO said.
Peak load was expected to be 137,800 MW on Monday, with temperatures near 90 degrees Fahrenheit across much of the Mid-Atlantic.
PJM actual load and forecasts during and after eclipse | PJM
PJM saw grid solar generation drop by about 520 MW from before the eclipse until its peak. Behind-the-meter solar dropped by 1,700 MW. Solar represents less than 1% of PJM’s 185,000 MW of generation capacity.
The RTO had expected the drop in solar production to result in an increase in net load. But “because of a variety of potential factors, including reduced air conditioning, increased cloud cover and changes in human behavior related to the event,” it saw a net decrease in demand of about 5,000 MW during the eclipse.
Temperatures dropped by an average of 2 degrees Fahrenheit, with the Chicago area hit by storms after the eclipse began.
“Substantial cloud cover largely obscured the event at PJM’s offices, but stakeholders and staff gathered outside with special glasses and homemade viewing apparatuses to catch whatever views were available,” PJM said. The grid operator carried about 1,000 MW of regulation service instead of the usual 800 MW.
PJM will use lessons from Monday’s event for April 8, 2024, when the RTO’s footprint will be in the path of a total eclipse between Texas and Maine.
Minimal Effects in New England
ISO-NE had sufficient resources available to meet the rise in electricity demand resulting from a drop in output from the region’s 2,000 MW of solar PV systems during the partial eclipse. New England saw peak obscuration at around 2:45 p.m., when the moon blocked about 65% of the sun. Skies were generally clear across the region during the eclipse.
Eclipse over TVA’s Watts Bar Nuclear Plant | TVA
ISO-NE reported in June that PV generation would face a less extreme reduction in output because the angle of the sun is lower in late August than earlier in the summer, and the eclipse would occur almost two hours after the solar noon peak.
“To precisely balance electricity supply and demand minute-to-minute during the partial eclipse, ISO system operators must consider three major factors that will affect PV output,” said the report: obscuration percentage, angle of the sun and cloud cover.
The grid operator cited human behavior as another factor that could dampen the dip in solar output: “When there’s an eclipse, people typically stop what they’re doing and watch,” which lowers demand for electricity, it said.
New York not Fazed
New York experienced the partial eclipse under clear skies. NYISO said it had minimal impacts on electric load and that it did not need to take any special transmission operating actions.
NYISO Vice President of Operations Wes Yeomans on Friday posted a YouTube video in which he explained that peak totality of roughly 80% would be strongest from 2:30 to 2:45 pm.
New York has approximately 850 MW of rooftop solar, but solar generation peaks at 625 MW because the panels are not aligned in the same direction, Yeomans said. Solar output peaks between noon and 1 p.m. on very sunny days.
The last significant solar eclipse in New York occurred on May 10, 1994, when there were very few solar devices in the state.
Sacramento, Calif. — California is offering $45 million in grants for the development of microgrids on a variety of siting categories to stimulate development of new distributed energy resources.
California Energy Commission staff on Thursday gave curious developers both broad guidance and more practical advice regarding the program, which has wider parameters than a similar solicitation two years ago. Energy officials see DER such as microgrids, energy efficiency, energy storage, electric vehicles and demand response as increasingly critical to help manage renewables.
“The goal of it is to allow creativity” and demonstrate both the technology and a business case, not “science projects,” CEC Deputy Division Chief Mike Gravely said. “Obviously we are looking for a project that has commercial viability and a potential for future success.” The commission is hoping to develop a standard configuration that can be adopted on a wider scale, and to define methodologies to evaluate their benefits. It is also important to identify a market where they can function, he said.
The application deadline for the funding opportunity is Oct. 20, with awards anticipated to be announced next January and associated agreements beginning in June 2018. The commission is due to approve the awards in March.
Successful projects must be designed to be permanent and must advance technology while helping the state meet its clean energy goals. Projects fall within three program areas: applied research and development, technology demonstration and deployment, and market facilitation.
Projects to be funded are divided into three siting categories: $22 million is allocated for microgrids on military bases, ports and tribal lands; $12 million for projects in low-income areas; and $11 million for local communities, rural areas, industrial complexes and local schools.
The minimum award amount for a single project is $2 million and the maximum is up to $7 million. Developers must obtain matching funds equal to at least 20% of the award amount if it is $5 million or less, and 25% if the award is $5 million to $7 million. Match funding can include cash, equipment, materials, information technology services, travel, subcontractor costs, labor and other expenses.
CEC manages the money collected through the Electric Program Investment Charge (EPIC), a retail ratepayer surcharge. The purpose of the EPIC program is to benefit customers of the state’s three investor-owned utilities — Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison — by investing in clean energy projects that promote reliability and lower costs. Projects that leverage other funds such as federal support will be given priority, and they must be in IOU territory.
Most of the projects funded following a 2015 solicitation are at the point where equipment is being installed and the systems are fully operational, “thus facilitating the collection of valuable data on performance, value streams and reliability,” CEC said in the grant funding opportunity. In the first round of funding, the state received 40 proposals from which it picked seven winners. The commission said the facilities “are providing a wealth of information on microgrid configurations, interconnection of different DER through a single controller, and system interconnection challenges.”
The earlier funding includes $5 million for a low-carbon community microgrid at Humboldt State University and a microgrid automation project at a community college. San Diego Gas & Electric received $5 million for a photovoltaic microgrid and another $5 million funded a microgrid at the Laguna Wastewater Treatment Plant. Overall, the state has awarded $470 million to 279 projects with $223 million in matching funds, which CEC highlights in its online Energy Innovation Showcase.
The discussion showed what CEC has learned. Sometimes projects don’t work or cease operation the day state funding ends — undesirable outcomes that have even led to equipment appearing on the eBay website.
After hosting a distributed energy resources conference early this month, the Organization of MISO States has formed a temporary work group to formulate ideas on incorporating DER into the grid.
The group will report to the OMS board, OMS Executive Director Tanya Paslawski said at a board meeting Thursday. She said the group will have a regional focus, studying how distributed energy resources in one state affects other states. Members will also discuss with MISO analysts the potential needs on the system from increased DER use, she said.
Missouri Public Service Commission Chairman Daniel Hall said the workshop sent a “very clear message to MISO and stakeholders” that distributed energy resources is a very important topic that regulators are going to take an active role in shaping.
“I thought it was a really fantastic, thought-provoking day,” Paslawski agreed. “It’s opening up conversations about DER.”
OMS, representing MISO’s state regulating sector, will also weigh in on distributed energy resource issues next month as part of the “hot topic” discussion during the RTO’s quarterly Board of Directors week in St. Paul, Minn.
The Public Utility Commission of Texas asked ERCOT and SPP on Thursday to coordinate a joint study on Rayburn Country Electric Cooperative’s proposed transfer of most of its existing SPP transmission facilities and load into ERCOT (Docket 47342).
The East Texas co-op is an SPP member, but only about 150 MW (less than 20% of its load) and 160 miles of its transmission sit in the Eastern Interconnection. ERCOT estimates it will cost $38 million to connect the SPP load with the Texas grid.
Transmission lines | Berkshire Hathaway Energy
Commissioner Ken Anderson said it would be “helpful” if the two RTOs would “give all of us — SPP, ERCOT and the commission — reasonable comfort as to what the costs, benefits and challenges are, if any — and to do it as quickly as humanly possible.”
“We can do that,” said Warren Lasher, ERCOT director of system planning. SPP was not represented at the meeting, but both RTOs are expected to report back with a study scope at the Aug. 31 open meeting.
The grid operators have already produced a similar, much larger study on Lubbock Power & Light’s proposed transition of its 430-MW load from SPP to ERCOT. The study indicated the transition would cost them nearly $370 million. (See Load Migrations Put SPP’s Focus on Retention.)
2nd Price Formation Workshop Scheduled
The PUC has scheduled a second staff-led workshop for Oct. 13 on price formation issues in the ERCOT market to pick up where the discussion left off earlier this month (Docket No. 47199). (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
Stakeholders have been invited to submit alternate proposals and additional analysis in response to a report commissioned by independent power producers NRG Energy and Calpine, which asserts “a need for adjustments” to the market’s pricing rules. The report, “Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT,” was the primary topic during the Aug. 10 workshop.
Staff on Friday filed a timeline for submitting comments, proposals and analyses. ERCOT’s Independent Market Monitor will file a paper fleshing out its proposal to address reliability-must-run issues with a local reserve product by Sept. 15; the ISO’s staff will submit a second filing on real-time co-optimization and scarcity pricing by Sept. 29.
Commission staff will then present a revised request for stakeholder comment during the PUC’s Oct. 26 open meeting.
The commission agreed a second workshop would allow them to be more specific in addressing the recommendations and studies. They also plan to conduct their own workshop at a date to be determined.
“We could … give participants a stronger reference point of what we’re working on, so their comments can be more targeted,” Commissioner Brandy Marty Marquez said.
“While I enjoy workshops as much as anybody, I don’t want this to devolve in an endless series,” Anderson said. “It would be my hope the October workshop will include any and all ideas and the reports that come in by the end of September.”
MISO officials last week presented three proposals related to the implementation of the RTO’s new generator interconnection queue for stakeholder feedback.
The proposals — dealing with retaining interconnection rights, changing dispatch modeling and updating a study coordination agreement — are part of MISO’s effort to implement new interconnection rules approved by FERC in January (ER17-156). The new queue is intended to streamline a process that was plagued by restudies and backlogs. Last month, several stakeholders asked that some implementation details be fleshed out in discussions involving either the Planning Subcommittee or Planning Advisory Committee. (See MISO, Stakeholders Differ on New Queue Plan.)
But planning manager Neil Shah told the PAC on Wednesday that MISO will immediately change the queue’s dispatch modeling to match its annual Transmission Expansion Plan. Before, generators in the queue were modeled based on their expected level of output; now they will be modeled based on their maximum requested interconnection service level. Stakeholders attending last month’s Interconnection Process Task Force had said the decision should not be made without soliciting stakeholder input during MISO planning committee meetings. (See MISO Adopts New Dispatch Model for Queue Studies.)
Shah said MISO sees a need for consistency between the MTEP dispatch modeling, which is used for baseline reliability studies, and the interconnection process.
Retaining Interconnection Rights
MISO is offering more flexibility on retention of interconnection rights. It is recommending that owners of retiring generation be allotted three years of continuing interconnection rights for replacement generation to begin commercial operations. However, some stakeholders said six years is a more realistic time period to allow generation to be built.
On Wednesday, stakeholders indicated that they would like MISO to allow for generator replacement instead of making owners of retiring generation re-enter the interconnection queue with their replacement plans. The RTO is considering executing a commercial agreement and conducting an out-of-cycle study with “reasonable study deposits” for such replacement scenarios.
Indianapolis Power and Light’s Lin Franks said MISO should check in with replacing generators to see what progress is being made before terminating rights at the end of an inflexible three-year deadline.
“Interconnection rights are not scarce in this footprint,” said Franks during an Aug. 15 Interconnection Process Task Force (IPTF) meeting. “If the rights are not scarce in the footprint ― and they’re not here ― it doesn’t make sense to put a definitive deadline on the project when they’re working through it.” She said although three years should usually be sufficient, she warned against the three-year deadline becoming an “unrealistic barrier to progress.”
“We still propose three years, but if at the end of the of that three-year period, the construction is still in progress, [MISO could allow] a three-year extension for commercial operations,” Shah said. He said MISO will consider the comments and bring back new queue implementation proposals in a few months.
Hwikwon Ham of the Minnesota Public Utilities Commission also pointed out that obtaining state approvals for generation construction can take time.
MISO will also allow generators to retain interconnection rights under an amended interconnection agreement when an owner upgrades equipment when it does not have a material impact on the grid.
New Study Coordination Agreement
MISO is also updating a coordination agreement with Manitoba Hydro and Minnkota Power Cooperative to improve the efficiency of generator interconnection studies under the revised queue. The agreement will be brought before the PAC in September.
Shah also repeated warnings about delays while MISO studies an unprecedented influx of queue projects under the definitive planning phase of the queue.
“It’s not set in stone. The timeline may change based on what we encounter,” Shah said.
Meanwhile, IPTF Chair Randy Oye said MISO PAC leadership is considering extending the life of the task force beyond its December sunset date, an extension approved by Steering Committee members late last month. If the IPTF is not extended beyond December, the IPTF and Steering Committee may have to assign unfinished queue issues to other MISO committees.
VALLEY FORGE, Pa. — After nearly a year of discussion on potential changes to PJM’s capacity model, stakeholders have begun determining what components a new construct should have.
At another two-day meeting of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) last week, stakeholders began developing the criteria on which the nine construct proposals will be compared. It was a year ago that American Municipal Power and likeminded stakeholders pushed for a “holistic” review of the RTO’s Reliability Pricing Model. (See Co-ops, Munis Call for Reset of PJM Capacity Model.)
PJM’s Murty Bhavaraju presented a model that RTO staff created to compare results for each of the proposals. The model currently only includes the five repricing proposals but will eventually address the other four, PJM’s Dave Anders said.
The model uses fictitious data in its comparisons, and Adrien Ford of Old Dominion Electric Cooperative asked if PJM could substitute data from recent Base Residual Auctions to give stakeholders a better indication of the real-world implications.
Staff balked.
“I think we probably need to explore what that would look like,” Anders said. “I think to make the step between this modeling and taking a prior BRA, there’s going to have to be a lot more assumptions.”
“I am worried that the results of that will be taken as price forecasts,” PJM’s Adam Keech said.
“If there’s concern about using the past, then what can we use?” Ford asked. “We also recognize that the supply stack in the examples isn’t anything like the actual supply stack. I seek to understand if we do have an issue here and, if so, how big it is.”
Ruth Ann Price of the Delaware Division of the Public Advocate asked PJM to identify if any proposals would discourage states from allowing resources within their borders to participate in the markets.
Susan Bruce, representing the PJM Industrial Customer Coalition, asked the RTO and its Independent Market Monitor to also report on how they believe the proposals would affect bidding behavior. “It would be helpful for us to understand what those concerns would be,” she said.
PJM staff agreed to research potential solutions that address stakeholder concerns.
MOPR Issues
Attorney Mike Borgatti of Gabel Associates explained the standards FERC set out in its 1991 Edgar Electric Energy (ER91-243) and 2004 Allegheny Energy Supply rulings (ER04-730) to prevent utilities from self-dealing. The Edgar ruling required demonstration that long-term power purchase agreements that utilities sign with their marketing affiliates are reasonably priced compared to alternatives. The commission said such a demonstration could include evidence of competition between affiliated and unaffiliated suppliers or a showing of prices paid by non-affiliated buyers. FERC refined its guidance in Allegheny.
Borgatti said he brought up the rulings to propose a “conceptual framework” for considering changes to the minimum offer price rule (MOPR).
“If we were to go this route, that would need to be something we spend a lot of time on,” he said.
John Hyatt of Monitoring Analytics, PJM’s Independent Market Monitor unit, said he believed that state sponsored competitive and non-discriminatory procurements are consistent with the IMM’s MOPR-Ex capacity proposal.
Roy Shanker, an industry consultant, expressed concern about using the rulings as guidance in this situation.
“Edgar certainly stands for the proposition of assuring there was not affiliate favoritism,” Shanker said. “It’s completely unacceptable to apply it without a thorough discussion of what nondiscriminatory means.”
PJM staff agreed to review the current MOPR policies to determine if they should be revised.
Fixed Resource Requirement
PJM provided a refresher on its current fixed resource requirement (FRR) rules. FRR contrasts with RPM in that it can be used by a load-serving entity to meet a fixed capacity requirement, while RPM is variable. FRR resources don’t receive RPM clearing prices and the LSE doesn’t pay the RPM locational reliability charge.
The education came in response to a proposal from Dayton Power and Light’s John Horstmann that would allow LSEs to choose acquisition from FRR, RPM or any combination of the two to address their capacity requirements. Horstmann acknowledged that his proposal has many factors that would have to be addressed, but argued that it also resolves many issues stakeholders have identified.
“I’d say look at the things you don’t have to worry about, including two-tiered auction design compromises, creation of a reference price, and auction participant bidding concerns,” he said.
Social Science Experiment
The nine proposals fall into three categories: Some completely redesign the capacity construct; some add to the RPM a repricing mechanism to avoid subsidized offers influencing clearing prices; and the last group would expand the MOPR to effectively prohibit subsidized units from offering into auctions.
In what he called a “social science experiment for stakeholders,” Anders split meeting attendees into three groups and directed each of them to identify the positive and negative aspects of one of the categories and develop potential questions for a poll of stakeholder interests.
Stakeholders found that the MOPR was straightforward and easy to understand, but that it could be subjective and fails to accommodate state policy actions. The task force’s charter called for developing RPM rule changes “that could accommodate/address both capacity construct objectives and state actions.”
The redesign proposals would give load and resources more flexibility in decision-making but could increase market volatility if enough buyers and sellers opt out. The repricing options all attempt to address price influence from subsidies but could incentivize undesirable behavior, such as bid suppression or additional pursuit of subsidies, stakeholders said.
Next Steps
The task force’s next meeting is scheduled for Wednesday, when Anders said stakeholders should be prepared to provide input on identifying the traits of an offer that would trigger repricing.
AMP’s Steve Liebermann said he plans to have revisions to discuss for his organization’s proposal — which focuses on encouraging long-term bilateral contracts — based on feedback he’s received.
“States with retail choice might have some difficulties with the bilateral-contract concept,” he said. “We think we have a workable solution.”
Other sponsors have already offered revisions or addendums to their proposals, including LS Power and Exelon. Both focus on repricing.
Jennifer Chen of the Natural Resources Defense Council promised some revisions as well. The NRDC’s proposal focuses on including seasonal resources that can’t meet Capacity Performance’s requirement to be always available.
FERC last week denied NRG Curtailment Solutions’ request for an exemption from NYISO penalties for nonperformance and invalid generator registrations on approximately 13% of its New York capacity obligations in May 2016 (ER17-834).
NRG argued that uncertainty about EPA emissions regulations compromised its ability as a Special Case Resource (SCR) to help the New York grid operator balance shortfalls in delivered capacity contracts.
SCRs are demand-side resources that agree to reduce load at the ISO’s instruction, using either curtailments or “local” generators — ones intended to self-supply a load and that do not supply the distribution system. As a “responsible interface party,” NRG Curtailment aggregates individual SCRs for the ISO.
An EPA rule change in 2013 allowed reciprocating internal combustion engines (RICE) providing emergency DR to run without extra emissions controls for up to 100 hours per year in emergency demand response programs, up from the previous limit of 15 hours annually. In 2015, the D.C. Circuit. Court of Appeals vacated and remanded the 100-hour exemption. (See Appellate Court Rejects EPA Rule on Back-Up Generators.) EPA was granted a stay of the D.C. Circuit’s decision until May 1, 2016.
On April 15, 2016, EPA issued guidance that RICE generators may not operate for any period of time unless they meet emission standards for nonemergency engines. On May 2, 2016, the D.C. Circuit issued a mandate implementing its earlier decision.
NRG said it only enrolled generators in the May 2016 installed capacity auction that would participate for 15 hours or less because it believed that the 15-hour rule would be reinstated with the elimination of the 100-hour rule. The company said it had no ability to withdraw resources that no longer complied with the revised emissions rule but that it stopped selling capacity from DR resources with noncompliant generators for the June 2016 auction.
Increasing Emissions Stringency
NYISO opposed NRG’s waiver request in a filing in February, arguing that EPA’s intent to apply more stringent emissions requirements was apparent beginning in July 2015, contrary to the company’s contentions. The ISO said EPA’s motion to stay indicated that the agency clearly intended not to revert to its 15-hour limit.
While NRG may not have intended to enroll ineligible resources, NYISO said, if the company was unsure, it could have waited until EPA had clarified its position. The ISO believes that NRG assumed the risk of noncompliance and therefore should be subject to the penalty provisions of its Tariff.
NYISO said that while it had not yet determined whether penalties were “appropriate” for NRG’s capacity sales for May 2016, “sales by invalidly enrolled SCRs would be subject to a penalty.” In addition, an aggregator can be penalized when its unforced capacity sales exceed the greatest quantity megawatt reduction achieved during a single hour in a performance test or event called by the ISO.
FERC ruled that granting the waiver “would have undesirable consequences, as it would effectively serve only to relieve NRG of the financial consequences of its market commitments … and could encourage similarly risky bidding behavior that market participants seek to remedy after the fact through a waiver.”
