FERC on Monday agreed with a financial trader that PJM failed to provide “all available supporting documentation” for two real-time repricing events that cost the company more than $500,000, but the commission rejected the company’s effort to obtain refunds from the RTO.
The commission said it denied Monterey MA’s request for PJM to the return to the original incorrect pricing to avoid an “absurd” result (EL18-150).
Monterey complained that it lost money on day-ahead financial positions it took after PJM revised nodal prices following events from April 1 to April 30 and June 22 to July 10 in 2016. While Monterey’s complaint was specific to those events, the company argued that PJM “frequently” revises real-time prices after the fact and “while the occurrence of these adjustments decreased in 2017, following an all-time high in 2016, the frequency of adjustments is again trending upwards, with 2018 numbers already matching or surpassing 2017 numbers.”
A financial trader in PJM’s virtual markets claims a recalculation of a real-time price at a dead bus cost it nearly half a million dollars. | Pexels
Bagley Event
In the April event, three of the four transmission lines to the BC Bagley 230-kV substation near Baltimore were out of service, according to the complaint. PJM said the fourth line was also out, creating a “dead bus replacement” situation in which the RTO calculates the nodal LMP using active nodes nearby. That recalculation switched the marginal congestion cost at the bus from negative to positive, costing Monterey $480,000.
However, Monterey argues that MISO’s state estimator shows the fourth line was still in service and that PJM’s outage reports didn’t include the line during that time. PJM failed to provide sufficient information when announcing the price reposting to explain why its data didn’t match up with data elsewhere, Monterey said.
LaSalle-Plano Event
In the second event, the LaSalle-Plano 345-kV line in Illinois was out because of forced outages on two 765-kV lines. Monterey took financial positions based on five-minute pricing signals over the previous few days, but the real-time LMPs were subsequently recalculated, costing the company $31,000.
PJM told Monterey the prices were changed because the model didn’t match how RTO staff actually operated the system.
Monterey said it sought arbitration with PJM over the event, but the RTO denied the request.
XO Energy, another financial trader, told FERC that it also lost money during the LaSalle-Plano event and supported Monterey’s request for Tariff and Manual 11 changes. XO agreed that PJM needs to be timelier in its customer response.
“Reasonable guidelines and Tariff obligations must be incorporated into these provisions to increase transparency and reduce abuse,” XO said.
FERC agreed that PJM failed to provide the amount of information required by its Tariff in connection with the Bagley event, but it also agreed with the RTO’s response that it complied with its Tariff in recalculating the LMPs. The commission therefore denied Monterey’s requests for changes, as well as its complaint about the LaSalle-Plano event.
FERC on Tuesday approved PJM’s proposal to extend the deadline for day-ahead energy market bids and offers by 30 minutes, from 10:30 a.m. to 11 a.m. (ER19-305).
The approval is the final step in the RTO’s expedited implementation of changes to take advantage of enhanced computing power and puts it on track to complete the effort in mid-December. (See “Day-ahead Market Timeline Manual Changes,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)
The window for bids into PJM’s day-ahead auction is expanding. | PJM
The changes were also made possible, PJM said, by a recent reduction in the number of biddable points for virtual transactions, which was part the third and final phase of its plan for mitigating uplift. (See FERC OKs Slash in Virtual Bidding Nodes for PJM.)
PJM told FERC that the extension would provide natural gas-fired generators additional time to engage in fuel price discovery each day, thereby increasing certainty around costs.
“The additional time for price discovery will place gas-reliant generation units on more equal footing with market participants who are not dependent on fluctuating daily natural gas prices when formulating and submitting their bids and offers in the day-ahead energy market,” the RTO explained.
The expedited implementation timeline means the changes will be in place before the winter season, when gas prices have been historically volatile. Several additional related changes are expected to be approved at a Thursday meeting of PJM’s Markets and Reliability Committee.
ETI Requests
The Energy Trading Institute (ETI) supported the change, but it asked that PJM additionally work to further reduce the day-ahead solve time without damaging the efficiency of the market and provide additional information regarding the software and hardware upgrades for market efficiency and transparency purposes. It also asked the RTO to “evaluate the divergence in the market and the increase in uplift [since the reduction of available locations for virtual transactions] and provide additional analysis on the cost associated with the de minimis solve time gain of reducing virtual transactions.”
In its reply, PJM welcomed the discussion with ETI through the RTO’s stakeholder process but said the requests were out of scope for the filing. FERC agreed and dismissed ETI’s requests.
The U.S. Senate voted 50-49 on Thursday to confirm Bernard McNamee as a FERC commissioner, restoring the commission to full strength and Republicans’ 3-2 majority.
Every Democratic senator voted against McNamee, including Sen. Joe Manchin (D-W.Va.), who had joined Republicans on the Energy and Natural Resources Committee in its 13-10 vote Nov. 27 to advance the nominee to the floor. (See McNamee Advances to Senate Floor.)
Manchin, a coal-state Democrat who often votes with Republicans on energy and environmental issues, is in line to become ranking member of the ENR Committee if Sen. Maria Cantwell (D-Wash.) moves to the Commerce Committee. That has rankled environmental groups and members of the more progressive wing of the party, who protested to Minority Leader Chuck Schumer at his office in New York on Monday.
Manchin said Wednesday he changed his mind on McNamee after learning of statements suggesting the nominee denies humans’ role in climate change.
Senate Majority Leader Mitch McConnell (R-Ky.) filed cloture on McNamee’s nomination last Thursday, but the vote to limit debate was postponed until after the state funeral of former President George H.W. Bush on Wednesday.
The cloture vote Wednesday was identical to the confirmation vote. After Senate rule changes in 2013, the vote to prevent filibustering presidential nominations requires a simple majority rather than a supermajority. Sen. Thom Tillis (R-N.C.) did not participate in either vote.
President Trump nominated McNamee in early October, after Robert Powelson left FERC in August to become CEO of the National Association of Water Companies, having served on the commission for only a year. McNamee, executive director of the Energy Department’s Office of Policy, would serve the remainder of Powelson’s term, which ends June 30, 2020.
McNamee could extend his tenure through 2025: The 2020 end date for his term means Trump would be able to re-nominate him before the end of the president’s own term the following year.
Leaked Video
Democrats’ opposition to McNamee stems in part from his role in drafting DOE’s Notice of Proposed Rulemaking seeking subsidies for endangered coal and nuclear generators. Democrats on the ENR Committee urged McNamee to recuse himself from FERC’s resilience docket, which it opened in January after rejecting DOE’s proposal. (See Democrats Urge McNamee’s Recusal from Resilience Docket.)
In response, McNamee said he would consult ethics lawyers on the matter.
McNamee has served in the DOE Office of Policy since June. Prior to that, and after FERC’s rejection of the NOPR in January, he worked briefly as the director of the Texas Public Policy Foundation’s Center for Tenth Amendment Action, a group that files legal challenges over what it views as government overreach. It was in this role that McNamee promoted the center’s Life: Powered initiative — described as a project to “reframe the national discussion” about fossil fuels — in a February speech captured on video. In the speech, McNamee described the effort to change public opinion about fossil fuels, which he called “the key not only to our prosperity [and] quality of life, but also to a clean environment.” He also attacked environmental groups, describing their activism against fossil fuels as a “constant battle between liberty and tyranny” and criticized renewable resources.
“Renewables, when they come on and off, it screws up the whole the physics of the grid,” he said. “So, when people want to talk about science, they ought to talk about the physics of the grid and know what real science is, and that is how do you keep the lights on? And it is with fossil fuels and nuclear.”
The video — which was apparently taken down from the TPPF’s YouTube channel when McNamee was nominated — was uploaded to YouTube by the Energy and Policy Institute, a liberal advocacy group, on Nov. 20. The speech was a stark contrast to McNamee’s promise days earlier at his confirmation hearing to “be a fair, objective and impartial arbiter in the cases and issues that would confront me as a commissioner.”
“After viewing video footage, which I had not previously seen, where Bernard McNamee outright denies the impact that humans are having on our climate, I can no longer support his nomination to be a FERC commissioner,” Manchin said in a statement explaining his vote Wednesday. “I would hope that Mr. McNamee will be open to considering the impacts of climate change and incorporates these considerations into his decision-making at FERC.”
McNamee Responds
After the video became public, Cantwell issued several supplemental questions to McNamee about his statements, saying “these biases will make it difficult both for you to be the impartial arbiter that you have committed to be, and for the American public to have confidence that you will be an impartial arbiter who relies on the ‘law and facts’ as you have stated in your testimony.”
In his response last Monday, before the committee vote, McNamee repeated his support for “a level playing field for all types of technologies and resources” and pledged to be “an independent arbiter, making my decisions based on the law and facts.”
Asked by Cantwell to “point to a peer-reviewed scientific study” that supports his criticism of renewables, McNamee cited NERC’s May 2017 comments on DOE’s grid study: “With no mass, moving parts or inertia, increasing amounts of inverter-based resources (such as solar photovoltaic) present new risks to reliability, such as managing faster fault-clearing times, reduced oscillation dampening and unexpected inverter action.”
He also cited a February 2018 National Renewable Energy Laboratory study on the challenges posed by California’s “duck curve.”
“I recognize the value of all resources to operating the electric grid while also recognizing that resources may have different operating characteristics that may be necessary to support the electric grid during different situations,” McNamee said.
Cantwell also asked, “How can environmental groups possibly expect a fair shake from you as a FERC commissioner given that you equated these groups and their values with those of tyrants?”
McNamee responded: “I understand the difference between being an advocate and an independent arbiter.”
Echoes of Binz
McNamee’s nomination somewhat resembles that of a previous nominee: Ron Binz.
Chosen by President Barack Obama in 2013 to be FERC chair, Binz withdrew his nomination after Manchin joined Republicans, then in the minority, in opposing him over his statements favoring renewables.
Binz served as chairman of the Colorado Public Utilities Commission from 2007 to 2011. Part of the opposition to his nomination, led by the coal industry, stemmed from his participation in the drafting of Colorado’s Clean Air-Clean Jobs Act, which offered utilities incentives for replacing coal-fired power plants with natural gas. The law led to the closure of several coal plants in the state. (See Who is Ron Binz, And What Will He Do at FERC?)
But what ultimately ended up sinking his bid was the disclosure of documents showing he was communicating with public relations firm VennSquared Communications — which had been hired by Green Tech Action Fund, a nonprofit that provides grants for the development of clean energy technologies — in response to the coal lobby. The emails sparked a furor among right-wing media and led the previously noncommittal Lisa Murkowski (R-Alaska), then ranking member of the ENR Committee, to withhold her support.
On the Senate floor before the cloture vote Wednesday, Murkowski referenced the “bipartisan concerns on [Binz’s] efforts to recruit support for his nomination” as the key difference between Binz and McNamee.
Prior to McNamee’s committee vote last week, Cantwell recalled the Binz controversy.
“It was not that long ago that this committee refused — refused — to confirm the nomination of Ronald Binz to the commission because of his support for renewable energy,” she said.
After the committee vote, Murkowski was asked by reporters about Cantwell’s comments on Binz and Earthjustice’s Kim Smaczniak’s tweet asking “What happened to the Binz test?”
“I don’t know that there was ever a ‘Binz test,’” Murkowski said. “If there was, I wasn’t [giving] that. I have to look at every individual that comes before me, I have to ask the questions and make that determination.”
RENSSELAER, N.Y. — NYISO on Monday recommended its carbon pricing proposal no longer include a mechanism that would make emissions-free resources with existing renewable energy credit contracts pay the LBMP carbon component.
The ISO’s clawback proposal “creates a distortion in the market … that places the ISO in the position of picking winners and losers, which is not where we want to be,” Michael DeSocio, the ISO’s senior manager for market design, told the Integrating Public Policy Task Force (IPPTF) on Monday. (See NY Carbon Task Force Looks at REC, EAS Impacts.) The ISO initially proposed the idea to reduce the potential for REC resources to receive double payments for their lack of emissions.
DeSocio noted REC payments are not solely linked to carbon abatement or avoidance but are primarily intended to support renewable resources. Withholding the LBMPc from resources with existing RECs would increase the uncertainty in the value and potential cost of such contracts going forward and also create a disconnect between the wholesale market price and payment to the resource, he said.
Double Payment Issue
Multiple stakeholders expressed concern about the potential for double payments, with ratepayers paying for both REC contracts and an unforeseen bonus or windfall for holders of such contracts that pre-date the existence of a carbon charge.
“As much as there could be a concern with costs … we don’t view this as a problem with the design,” DeSocio said. He estimated the possibility for between $30 million and $60 million in such payments in an overall program representing a few billion dollars, whether through the state’s Clean Energy Standard alone or with carbon pricing.
The $60 million estimate is an upper bound of any double payment, said Sam Newell of the Brattle Group.
One of the motivations for RECs “was to develop a new way of getting energy… So did you pay a little extra to help pave the way for the much larger amounts of clean energy the state plans to procure? Maybe. That was part of the purpose,” Newell said.
Newell also pointed out carbon pricing was being contemplated at the time some of the existing REC contracts were signed. “To what extent did the REC prices get discounted accordingly? Were they willing to take a little bit lower price in a competitive process because they saw some upside from some future carbon prices?”
“It’s not very accurate to just blithely call it a double-payment issue,” said Warren Myers, director of market and regulatory economics at New York’s Department of Public Service. “We’ve heard from a lot of parties about what they have to go through to get financing and the hedges they sign, so to say that generators are going to get double paid is a misstatement … What the ISO proposed, while well-intentioned, was a remedy that was worse than the malady.” (See NY Task Force Talks LBMPc, Residuals, Hedge Effects.)
Brattle Updates
Newell presented the task force with updated analyses on carbon price effects, including the outcome if NYISO’s AC transmission project in western New York — the two components for which are now before the ISO’s board — does not get built by 2024 as the study projected.
Effects of a carbon charge on wholesale energy prices | Brattle Group
The study assumes the projects would be built by 2023 to provide 350 MW of increased transfer capability across the Central East interface, while they could actually provide as much 875 MW of increased transfer capability, he said.
“So what would happen if these projects weren’t there at all?” Newell asked. “Then you would just see a little more bottling in upstate and less LBMP upstate from a carbon charge, and the opposite downstate … If you get the full 875-MW increase in transfer capability, the state would be a little more uniform than we modeled with only a 350-MW increase on Central East.”
2022 Scenario
While the study motivation and scope remain unchanged, “we also did the updated [modeling and pricing software] runs to look at a 2022 scenario, as requested by stakeholders, and to look at what the market would look like if a carbon charge was implemented,” Newell said.
Brattle’s analysis continues to show minimal retail price impacts from a carbon charge, with the strongest impact in 2022 — the year of implementation, when consumer bills are projected to increase by 1.6%, mainly due to the retirement of Indian Point nuclear plant coupled with no AC transmission upgrades in service and a doubling of renewables upstate.
The biggest observation is relative to both the retail rate and the generation component of the rate, Newell said.
“If you look at the graph, it’s visually not far off the zero point, so that’s the main conclusion, with a little bit of a trend over time towards more benefit,” he said.
However, wholesale prices are expected to register their largest carbon cost impact — $17.60/MWh — in 2025, with an estimated carbon charge of $49/ton.
Summary of Modeled 2022 Scenario | Brattle Group
Nuclear Retention
Brattle also revised its projections of the retention of nuclear generation in 2030, increasing its assumption from 450 MW to about 850 MW of the 3,300 MW of upstate capacity.
The Public Service Commission approved the zero-emission credit program in 2015 to prevent the premature retirements of three New York nuclear power plants, Exelon’s FitzPatrick, Ginna and Nine Mile Point. (See Appeals Court Upholds NY Nuclear Subsidies.)
Newell said a carbon charge could boost the net revenues for upstate nukes and prompt owners of units in good physical condition to apply for license extensions.
The study assumes Nine Mile Unit 2 will remain under any case, while it considers the other three units to be at risk of retirement.
“You can see that there’s a fairly good case for some likelihood of retaining some of these plants,” he said.
Why Price Carbon?
Why even do carbon pricing, Newell asked.
“I really see two closely related reasons. One that we’ve talked about a lot is that you provide a price signal that directly signals to the market how to operate in such a way that cost-effectively reduces carbon and how to invest in such a way… where you avoid the most emissions, that’s where the biggest rewards go,” he explained.
Another major factor — harmonizing state policies and wholesale markets — has not been emphasized enough, Newell said.
“I’m talking about this from the perspective of somebody who works nationally and is seeing a lot of conflict on these issues,” Newell said. “And [I’m] seeing an opportunity for New York ISO and New York state to address this issue more successfully than the rest of the country and to be a leader in this regard.”
The IPPTF will next meet on Dec. 17 at NYISO headquarters to consider the final draft carbon proposal, which will be posted by Dec. 7.
ERCOT said Tuesday it confronts a historically low 8.1% planning reserve margin next summer in the face of continued high electricity demand from oil and gas producers in West Texas and the cancellation of several generation projects.
ERCOT’s December Capacity, Demand and Reserves (CDR) report shows more than 78 GW of operational generation capacity available next summer to meet expected demand of 74.9 GW. That marks a 600-MW increase in capacity over the May CDR forecast and a 1-GW jump above this summer’s record peak demand of 73.5 GW.
The ISO had an 11% reserve margin this past summer, when it met multiple demand peaks without resorting to emergency actions.
ERCOT faces historically low reserve margins next year in the face of expected increases in demand. | ERCOT
The grid operator has approved 1.7 GW of various resources for commercial operations since the May CDR. However, three proposed gas-fired projects totaling 1.8 GW of capacity and five wind projects totaling 1.1 GW have been canceled since May. Another 2.5 GW of gas, wind and solar projects have been delayed.
“The ERCOT market has experience in these cycles of [generation] retirements and resource investment,” Pete Warnken, the ISO’s manager of resource adequacy, said during a media conference call. “What we’re encountering now is nothing new.”
Warnken said ERCOT’s energy-only market is working as it was intended, with pricing signals incenting new generation. However, prices increased only slightly during the scarce times of the past summer.
“We are in a transition period where we’re facing lower reserve margins. Operationally speaking, we think the market is functioning the way it was designed,” Warnken said.
The report does indicate operating reserves will increase to 10.7% in 2020 and 12.2% in 2021, before falling again to 9.8% and 7.5% the following two years. More than 7.4 GW of installed capacity — all wind or solar, save for 100 MW of gas generation — is eligible for future inclusion in the CDR.
Warnken and Senior Director of System Operations Dan Woodfin worked hard to allay concerns during the call, reminding listeners that the CDR is a snapshot of resource availability “based on the latest information from resource owners and developers.”
Woodfin said ERCOT doesn’t view the shrinking reserve margin as a concern. He said the ISO can take several actions as operating reserves approach or drop below the minimum level of 2.3 GW, including using switchable resources in neighboring grids, procuring emergency responsive service, releasing ancillary services held in reserve and reducing load.
“Our role is to manage the grid and ensure it’s reliable on a systemwide basis. We certainly have the tools in place,” Woodfin said.
Asked whether ERCOT faces a greater risk of entering into an emergency situation, Warnken said, “We don’t know at the present time.” He said future CDR reports could show increases in capacity.
Warnken pointed to West Texas oil and gas development as driving the increased demand. ERCOT projects an 8% annual growth rate in West Texas peak demand through 2023, quadruple the ISO’s 2% systemwide load growth during the same time period.
Warnken admitted the oil and gas sector is volatile, but he said ERCOT has been in close contact with transmission and distribution providers about their service requests.
“Like the CDR in general, [ERCOT’s West Texas forecasts] are based on the current information we’ve been given,” he said.
“Industrial load growth has been central to ERCOT from the beginning,” CEO Bill Magness said last month in Houston. “That type of load comes in big chunks.”
ERCOT has a target planning reserve margin of 13.75%, which Warnken said is “purely informational” and not used to set requirements for generation standards.
Woodfin said ERCOT will be able to provide a clearer picture of summer expectations when it issues its next seasonal assessment of resource adequacy (SARA) in March. The SARA will include various scenario assessments, while the CDR relies on a 50/50 forecast with a 50% probability the peak will be higher or lower than predicted.
CARMEL, Ind. — MISO stakeholders are skeptical of a year-end Tariff filing intended to guarantee the RTO will have access to additional megawatts by spring through stricter outage rules and load-modifying resource (LMR) requirements.
The RTO last month announced it will focus on three short-term fixes it can roll out early next year to increase availability of 5 to 10 GW of additional supply. (See MISO Pivots to Near-term Resource Availability Fixes.) The proposed changes include stricter LMR obligations, more advanced notice of planned outages by members and firmer planned outage requirements.
Speaking at a Nov. 29 Reliability Subcommittee meeting, MISO Executive Director of Market Development Jeff Bladen said the RTO thinks it needs the incremental changes to give it time to work on long-term fixes throughout 2019. MISO will publish a straw proposal on longer-term solutions in the first quarter of next year.
Without the smaller changes, MISO could confront a serious emergency and face changes dictated by an outside entity, Bladen said.
Several stakeholders have criticized MISO for what they call a rush to a Tariff filing before the end of the year. Some pointed to the absence of an emergency driving the FERC filing and asked what the RTO could accomplish without a Tariff filing.
“Anytime you do these very forced Tariff changes … these rushes are extraordinarily expensive [for load-serving entities] to accommodate,” Madison Gas and Electric’s Megan Wisersky said during a Nov. 16 workshop on the project.
But staff said upcoming maintenance seasons pose a real risk.
Bladen said MISO has spent more than a year detailing the growing disparity between resource availability and need.
“I think there’s general consensus that we are facing real issues that we have to take real action on,” Bladen said, adding that he hasn’t heard stakeholders refute the position that MISO could face a reliability threat in spring.
“This community has agreed that there’s a problem,” he said.
Bladen noted that each of MISO’s most recent maximum generation events have become more difficult to manage. “We really run the risk of reliability challenges becoming more than just challenges. … We really are not in a position to sit on our hands.”
LMR Testing and Data
Dustin Grethen of MISO’s market design team said the RTO is planning to require annual tests of demand response resources that physically curtail load. LMRs that opt out of the real power test would be subject to triple monetary penalties for nonperformance. MISO currently requires LMRs to replace their undelivered energy at corresponding LMPs. The new rule would not apply to behind-the-meter generation, which is already required to perform a generation verification test.
“What we want to make sure is that all resources can be relied on for the amount they say is available through the MISO Communication System,” Grethen said.
The RTO will propose a two-year transition to the rule for LMRs operating under non-retail tariff contracts, which is intended to allow time to renegotiate contracts.
“We have contracts in place. It’s going to take time,” Grethen acknowledged.
For its part, MISO has pledged to convert anticipated emergencies to a declared event at least two hours prior to emergency conditions. Grethen said MISO will issue LMRs scheduling instructions hours in advance based on the resources’ notice requirements but will declare the emergency or cancel the call for emergency-only resources two hours in advance. Even canceled calls will count as one of five required responses per year, and emergency DR will still be eligible to recover shutdown costs.
Stakeholders said MISO was heaping more penalties on a class of resources that already have more requirements than the average resource. Some said the move risks driving away LMRs.
“We’re definitely asking for more than we have in the past,” Grethen said.
The RTO is also looking to require more information from LMRs that will sell their capabilities after clearing in the upcoming capacity auction in spring. Those resources will have to provide their seasonal availability based on expected load output and retail tariffs and the shortest reasonable notification time for eliciting a response. MISO will require supporting documentation of availability if an LMR is not available within two hours for at least nine months out of the year. DR personnel would also have to participate in at least one LMR drill per planning year if they have not successfully met a call to curtail load or submitted results from a real power test.
“MISO is not looking to assign a notice time. We’re trying to get an idea of your best reasonable notice time. Tell us with documentation,” Grethen said.
Coalition of Midwest Power Producers CEO Mark Volpe criticized MISO’s use of the term “survey” to describe the new information requirement.
“‘Survey’ implies optional,” Volpe said, asking what deadlines MISO is planning to impose.
MISO Director of Resource Adequacy Coordination Laura Rauch said data submittal will become part of annual LMR asset registration. For the upcoming planning year, MISO plans to defer LMR registration from the beginning of February to March 1.
Century Aluminum’s Brian Helms asked if MISO would improve its outdated Communication System to allow for easier input of LMR data.
Rauch said the RTO will not have the system in time for the new LMR requirements but promised improvements in the nonpublic platform soon.
Helms said MISO may not realize that when his aluminum smelter is called up for load reduction for four hours during the summer, he deals with the fallout and monetary implications for months afterward.
“At what point is it not worth registering my LMR anymore?” Helms said. “How do you explain these requirements to outsiders? We want to provide reliability to the grid, [but] there needs to be some kind of balance.”
He said there are more reliability benefits and megawatts to be extracted from outage coordination, not LMR requirements. More stringent outage rules are the second piece of MISO’s near-term resource availability filing.
Outage Planning
MISO is weighing additional penalties for planned outages that are not scheduled in a timely manner. It plans to label short lead-time planned outages that occur during maximum generation events as “forced” outages, which will count against a resource’s capacity accreditation.
The RTO wants resources to provide 120 days’ notice for planned outages, with only one “limited adjustment” to the outage schedule allowed up to 60 days before the outage. The new notice requirement will supplement existing outage coordination requirements and not affect MISO’s required three-year lead time for nuclear units or two-year lead time for other units. MISO will also provide a safe harbor clause from the 120 days when an outage is rescheduled at the RTO’s request.
“We’ve received a lot of feedback, anywhere from ‘do not proceed’ to ‘require more,’” MISO engineer Matt Sutton said.
He said the “limited” outage scheduling adjustment MISO will allow must not exceed seven days and can apply to either the length, start date or end date of an outage. However, Sutton said generation owners are not allowed to make such adjustments when it moves the outage from a low-risk to a high-risk period based on the volume of supply available in MISO’s public maintenance margin forecasting tool. The 120-day requirement would begin in earnest on June 1, 2019, in time for the 2020/21 planning year. In the meantime, MISO is requiring that owners request any spring outages no later than Feb. 1 to qualify for safe harbor.
But some stakeholders said the 120-day requirement does not consider the forecasting updates and weather volatility that create high-risk situations with little notice. Some said generators could inadvertently move outages to higher-risk periods.
“Please think about the behavior you’re driving with this activity,” Xcel Energy’s Kari Hassler urged.
Other stakeholders asked the RTO to separate the maintenance margin for MISO Midwest and MISO South, which is more affected by generator outages.
Staff said they were considering creating stakeholder focus groups to hear more suggestions on improvement to outage coordination processes and tools.
MISO is accepting more feedback on its short-term filing through Dec. 13 and is targeting a Tariff filing by Dec. 21. In response to stakeholder requests, the RTO has scheduled a Dec. 7 conference call to discuss more finalized Tariff language before the filing.
PHOENIX — California legislators will struggle with wildfire liability and prevention in 2019, while lawmakers in Washington and Nevada could debate clean energy and utility-choice plans after voters in those states rejected related ballot measures, panelists told the Western Energy Imbalance Market’s Regional Issues Forum (RIF) on Wednesday.
In California, “it’s fair to say the legislative session will be dominated by the wildfire issue,” Sacramento utility attorney Tony Braun said as part of a panel on state policy developments and impacts on markets. “The wildfire issues, which are energy issues, are going to take all the air out of the room.”
California lawmakers were sworn in Monday, when bills can also be introduced for the start of the 2019/20 legislative session. Already there’s been talk of bills that could either help Pacific Gas and Electric remain solvent or break it up after the devastation of the Camp Fire in Butte County, the state’s deadliest wildfire. (See Camp Fire Prompts Talk of PG&E Bailout or Breakup.)
State Assemblyman Chris Holden (D), chairman of the Assembly Utilities and Energy Committee, has indicated he may introduce a bill as early as this week that would fix last year’s wildfire measure, SB 901, to allow PG&E to issues bonds to pay for wildfire damage. (See California Wildfire Bill Goes to Governor.) State Sen. Jerry Hill (D) has said he’s looking into a measure that would break up the state’s investor-owned utilities or make them public.
PG&E has become a prime suspect in the Camp Fire following its report to the California Public Utilities Commission of equipment failures near the fire’s ignition points. It potentially faces billions of dollars in liability for the fire that has killed at least 88 and destroyed the town of Paradise, Calif., population 27,000.
One question, Braun noted, is where Governor-elect Gavin Newsom stands on wildfire issues. “Little has been revealed,” Braun told the audience, but he said he expects Newsom to remain on a “similar trajectory” as outgoing Gov. Jerry Brown, who supported efforts to provide liability relief for PG&E.
Washington and Oregon
In Washington state, a ballot measure failed in November that would have placed a fee on the state’s carbon emissions, with the revenues used to fund environmental programs. I-1631 went down with 56% voting against it after a costly fight between petroleum interests and environmentalists. (See High Failure Rate for Western Ballot Measures.)
Lawmakers have shown little interest in trying to legislate a similar plan, said Therese Hampton, RIF chair and executive director of the Public Generating Pool, which represents 10 consumer-owned utilities in Washington and Oregon. Hampton briefed the RIF meeting Wednesday on Washington’s policy plans.
After November’s election, she said, Democrats will hold larger majorities in both houses of the State Legislature and are likely to pursue ambitious carbon-free energy goals. “We fully expect they will pursue a 100% clean-energy standard” like that adopted in California last year, Hampton said.
Elysia Treanor, with Portland General Electric, said Democrats in Oregon now hold a supermajority in both houses and Democratic Gov. Kate Brown will return to office. The coming legislative session will be six months long, giving lawmakers time to negotiate and possibly pass a cap-and-trade bill, she said.
A similar bill failed in 2018, when lawmakers met for only 35 days and didn’t have time to work out such a complex issue, she said.
“In [20]19, it’s now a priority,” Treanor told the RIF.
Arizona and Nevada
Clean-energy measures in the desert Southwest played out differently in 2018 and will likely do so again in 2019, panelists said.
In Arizona, voters overwhelmingly rejected Proposition 127 in November. The measure would have required the state’s power providers to generate at least half their annual electricity sales from renewable resources by 2030.
The race became a high-priced battle between competing interests. California billionaire Tom Steyer, whose environmental advocacy group NextGen America backed the proposal, and Arizona utilities, including Arizona Public Service, spent more than $50 million in the fight.
Nevada voters went the opposite direction from their Arizona neighbors by approving new renewable energy mandates in the form of Question 6 by a vote of 59% to 41%.
The measure, also backed by Steyer and NextGen, would amend the state constitution to require utilities that sell electricity to retail customers source at least 50% of their energy from renewables by 2030.
Constitutional amendments in Nevada must be voted on in two consecutive elections, so the ballot measure will be taken up again in 2020.
With regard to another ballot measure, Question 3, Nevadans allowed NV Energy to keep its electricity monopoly in the state by 67% to 33%.
The measure would have required the legislature to provide for the “establishment of an open, competitive retail electric energy market that prohibits the granting of monopolies and exclusive franchises for the generation of electricity.” It would have allowed customers to exit NV Energy and obtain electricity from others without paying an exit fee.
Las Vegas casinos, which have had to pay hefty exit fees, helped finance the measure.
Question 3 was approved by 72% of voters in 2016, when NV Energy didn’t contribute. But this time the utility, owned by billionaire Warren Buffett, reportedly spent $63 million to defeat the measure, while supporters doled out $21 million. That made it the most expensive ballot measure in state history, with a combined $100 million in contributions over two election cycles.
Question 3 supporters vowed to continue their efforts to let Nevadans choose their energy provider.
David Rubin, a senior attorney with NV Energy, told the RIF meeting audience that he wouldn’t be surprised to see that happen.
“It’s certainly possible those proponents of Question 3 will seek to revisit legislatively what failed on the initiative side” when the legislature reconvenes in February, Rubin said.
He said a major difference between Arizona and Nevada regarding renewable standards is that Nevada doesn’t have any nuclear generation, while Arizona is home to the nation’s largest nuclear power plant, the Palo Verde Generating Station.
Opponents of Prop. 127 in Arizona argued that passing the renewable standards ballot measure would have threatened the economic viability of Palo Verde. The opposition was led by Palo Verde co-owner APS, which spent millions to defeat the measure while arguing Arizonans could pursue clean energy plans that weren’t forced on them by a California billionaire.
“We’ve said throughout this campaign there is a better way to create a clean energy future for Arizona that is also affordable and reliable,” Donald Brandt, CEO of APS’ parent company Pinnacle West Capital, said after Prop. 127’s defeat.
“As the nation’s largest producer of reliable emission-free energy, Palo Verde is the anchor of Arizona’s clean energy future,” Brandt said. “Any serious plan to reduce carbon emissions has to include nuclear energy and Palo Verde.”
Where Arizona will go with those plans remains to be seen.
FERC last week approved the extension of most of CAISO’s proposals to address reliability concerns posed by the Aliso Canyon natural gas storage facility, whose capacity has been limited since a massive methane leak in 2015.
The Aliso Canyon gas storage facility was closed in October 2015 after inspectors discovered a massive methane leak. | California Department of Emergency Services
The commission’s Nov. 26 order approved extension of six of the seven Tariff provisions, rejecting the continuation of gas price scalars used to calculate commitment cost caps and default energy bids for generators served by Southern California Gas and San Diego Gas & Electric (ER18-2520).
CAISO asked FERC in September for expedited approval to renew Tariff provisions first put in place in June 2016 and subsequently refined and extended. CAISO’s most recent update, called Phase 4, proposed extending the temporary provisions for another year beyond their expiration dates of Nov. 30 and Dec. 16, 2018. (See CAISO Seeks to Extend Aliso Canyon Rules.)
The provisions include a measure allowing the ISO to enforce constraints on the maximum amount of natural gas that can be burned by generators served by the two gas providers. The constraints were based on limited supply anticipated by CAISO during specific hours.
The provisions also allow CAISO to suspend or limit the ability of scheduling coordinators to submit virtual bids if it’s determined virtual bidding could undermine reliability or grid operations.
The ISO’s Department of Market Monitoring did not support the extension of the price scalars, arguing that they have not been useful tools for managing high prices.
FERC agreed, writing that “CAISO’s use of the gas price scalars over the past year were not effective and adversely affected the market through weakened market power mitigation and increased bid cost recovery for the period that they were active.
“We find DMM’s analysis regarding the market impacts of the gas price scalars to be persuasive,” the commission said, declining to extend the provision.
The damage to Aliso Canyon, once the state’s largest natural gas reservoir, poses challenges to generators and regulators alike.
Despite objections from local residents and Los Angeles County officials, SoCalGas resumed injections into the facility in July 2017 to comply with a state directive to maintain sufficient gas inventories to support gas and electric reliability. (See Aliso Canyon Resumes Injections.)
The California Public Utilities Commission in May authorized a temporary increase in the volume of injections to support summer grid operations but maintained a policy of allowing withdrawals only as a last resort. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
FERC last week rejected Baja California Power’s request to guarantee debt its parent company took on to purchase independent power producer InterGen’s Mexican assets (ES18-58).
Mexicali combined cycle plant | Saavi Energia
Baja Power owns and operates a 6-mile segment of a 12-mile, 230-kV line that connects generating facilities near Mexicali, Mexico, with CAISO at San Diego Gas & Electric’s Imperial Substation.
The company asked FERC for permission under Section 204 of the Federal Power Act to guarantee the debt Cometa Energia took on to acquire the InterGen assets, which includes six combined cycle generating plants totaling 2,420 MW. Cometa’s total debt for the purchases could exceed $1 billion, FERC said. Cometa is a subsidiary of Actis, a private equity firm based in the U.K.
Baja Power argued that it was the only one of Cometa’s 36 subsidiaries that hadn’t signed on as a guarantor, and that its guarantee of Cometa’s debt was in keeping with its performance as a public utility.
FPA Section 204 generally requires applicants to show that acting as a guarantor “will not impair [a public utility’s] ability to perform” as a public utility, the commission said.
“The commission typically bases its finding that proposed issuances of securities will not impair an applicant’s ability to perform service as a public utility in part upon the applicant’s demonstration that it will have an interest coverage ratio that is 2.0 or higher,” it said.
Baja Power did not submit an interest coverage ratio, however, “because Baja Power has no income,” FERC said. “Further, it did not submit any additional evidence that it would have the means to perform utility service if it is granted authorization to act as a subsidiary guarantor of its parent Cometa.
“The arguments presented by Baja Power indicate why a lender would find it desirable to have a subsidiary guarantor, such as Baja Power, step in to the shoes of the actual borrower, Cometa, but there is no demonstration that a guarantee by Baja Power is necessary or appropriate for, or consistent with, the proper performance by Baja Power of utility service and that a guarantee will not impair its ability to perform that service,” the commission concluded in denying the application.
Roughly a year into the discussion and months past the deadline requested by PJM’s Board of Managers, details of potential changes to the RTO’s energy market remain anyone’s guess.
At Wednesday’s meeting of the Energy Price Formation Senior Task Force (EPFSTF), PJM reintroduced a substantially altered proposal for revising its operating reserve demand curve (ORDC), and both the RTO and its Independent Market Monitor revised their proposals for the allowable synchronized reserve offer margin adder. A new proposal submitted by the D.C. Office of the People’s Counsel would largely maintain the current two-step curve but include some revision details from proposals by both PJM and the Monitor. (See Skepticism Lingers Around PJM Price Formation Goals.)
PJM revised its ORDC proposal to account for the impact of units’ regulation requirements, shifting its proposed curve to the left and more in line with the current two-step ORDC for synchronized reserves. The current curve escalates from $0/MWh to $300/MWh at 1,590 MW, and the new one escalates gradually from $0/MWh at roughly 2,750 MW to $265/MWh at 1,575 MW. PJM’s original proposed revisions began escalating from $0/MWh at roughly 3,500 MW and reached $265/MWh at 2,100 MW. The revised proposal means that the value of synchronized reserve megawatts will be less until the reserve drops to the minimum reserve requirement (MRR), which remains $850/MWh.
PJM also revised its proposed margin adder down substantially. The current adder is $7.50/MWh, but PJM said the calculation should instead be based on the expected value of the penalty resources pay if they receive a synchronized reserve obligation and fail to perform during an event. For 2017, that value was 1 cent/MWh, and so far in 2018 it’s been 2 cents/MWh. Rather than setting it at $0, PJM argued that it should be allowed to change as clearing prices change.
The Monitor’s revised ORDC proposal includes a temporal concept meant to factor in the expected cost of a unit commitment to maintain the reserve requirement in the future. Instead of happening over 30 minutes to provide reserves necessary for 10 minutes in the future, as PJM has proposed, the Monitor’s proposal would look forward until the next expected demand peak based on historical load patterns.
The resulting curves have seasonal variations but rarely extend past $60/MWh before hitting the MRR.
The Monitor revised its adder proposal from a “compromise” of $3.80/MWh — which it now finds “unjustified” — to $0/MWh and recommended that penalties should extend back to the last reserve event when the resource performed to its full obligation but no longer than 12 months.
The Monitor also added a new option to the matrix that would include the changes to the synchronized reserve market but reserve the discussion on the ORDC to the second stage of EPFSTF, including discussion of the relationship between the day-ahead reserve products and real-time reserve products.
Stakeholder Reaction
Stakeholders appeared unconvinced by either proposal. Carl Johnson, representing the PJM Public Power Coalition, said the measuring stick for whether the RTO’s proposal is successful should be its impact on uplift payments.
“If uplift doesn’t go away, we’ve got a problem,” he said.
PJM’s Adam Keech agreed, saying, “I think zero uplift is a good target.”
The Monitor disagreed, however. Monitor Joe Bowring noted several market mechanisms that create uplift that aren’t addressed in the proposal.
“We think some uplift is necessary,” Monitor staffer Catherine Tyler said.
PJM and the Monitor also disagreed with some stakeholders over what the overall goal of the changes should be.
“The goal isn’t to have the lowest prices possible,” Keech said. “The goal is to reflect what the system operators are doing. We’re trying to drive to prices that reflect the system operators’ needs.”
Bowring said the “objective of markets is to have the lowest prices possible for the defined product, but no lower.”
Stakeholders and PJM staff questioned whether the Monitor’s ORDC proposal was more about addressing scheduling issues than generation scarcity.
“This is compensating to some extent for the lack of scheduling tools,” Tyler acknowledged. “However, what we do see in the market now is an operator looking ahead and seeing a need for reserves in the future, and we don’t have a market tool to address that.”
Vote Delayed
PJM’s Dave Anders, who is facilitating the task force, summed up the day by quashing any question about whether stakeholders may be ready to decide.
“It’s been a fluid situation with respect to proposals. I don’t know that we’re ready to vote,” he said, noting that PJM staff will update the board at its meeting this week.
Bowring pointed out that if the initial vote had happened when PJM had initially requested the vote, its proposed demand curve would have been substantially higher than with its revised ORDC presented for the first time at this meeting.
While no one questioned the decision, stakeholders differed on whether a vote should come sooner or later. Some expressed concern that further delay risks the board deciding to approve revisions without waiting for stakeholders’ advice.
Stakeholders have already missed the board’s request to receive stakeholder endorsement for some changes by the third quarter, which could have already allowed for FERC approval and implementation for this winter. (See PJM Board Seeks Reserve Pricing Changes for Winter.)
