ISO-NE forecasts sufficient resources to meet demand for electricity this winter and will implement special operating procedures to maintain reliability in the event of higher-than-projected demand, unforeseen generator outages or natural gas supply constraints that squeeze gas-fired power plants.
The RTO on Thursday issued its 2017/2018 winter outlook, which forecast peak demand under various scenarios:
21,197 MW at normal winter low temperatures of about 7 F; and
21,895 MW in extreme winter weather dropping to 2 F.
Resources with Forward Capacity Market (FCM) supply obligations total 30,999 MW; including resources without FCM obligations, capacity totals 32,521 MW.
| ISO-NE
Last winter’s peak demand of 19,647 MW occurred on Dec. 15, 2016, between 5 and 6 p.m., while New England’s all-time winter peak of 22,818 MW occurred on Jan. 15, 2004.
Gas Concerns
The report highlighted “a continuing concern” that “the region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow.”
ISO-NE said 4,000 MW of natural gas-fired generating capacity is at risk of not being able to get fuel when needed.
The RTO said the retirement of the 1,500-MW coal- and oil-fired Brayton Point power plant in Somerset, Mass., in May removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable.
The Brayton Point Power Station in Somerset, MA went offline in June 2017.
The grid operator is again running its Winter Reliability Program, which provides incentives for demand-side resources and generators that stock up on oil or contract for LNG. The program, which runs from Dec. 1, 2017, through Feb. 28, 2018, will be replaced by new capacity market performance incentive rules that go into effect June 1, 2018.
Total energy consumption and peak demand have been flat in New England in recent years because of increased energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems. Both the normal and extreme peak demand forecasts include the 1,832 MW in energy savings from EE acquired through the capacity market. While PV helps reduce energy consumption during sunny winter days, demand peaks in winter after the sun has set. By reducing demand on sunny days, PV can help preserve other fuels for use when demand is peaking.
The prospects became bleaker for one Big Rivers Electric coal-fired generator last week after FERC declined to rehear an earlier ruling that denied a bid to extend interconnection rights for the Kentucky plant.
In its rehearing request, Big Rivers did not challenge the commission’s earlier refusal to extend the rights, but instead argued that a “termination of interconnection service for the Coleman Station could potentially harm reliability and impose increased costs on Big Rivers’ members.”
FERC disagreed with that contention (EL17-15-001).
“Big Rivers cites no specific evidence in support of its claim that there are potential adverse impacts on system reliability due to termination of interconnection service to the Coleman Station,” the commission said in its Nov. 27 order. “Moreover, we note that MISO evaluated reliability concerns associated with the suspension of the Coleman Station when Big Rivers submitted its Attachment Y notice to suspend its operations.”
The commission’s ruling once again pointed out that Coleman cannot return to service until it complies with EPA’s Mercury and Air Toxics Standards. It also noted the plant does not currently have load to serve since the nearby Century Aluminum smelter — once the plant’s primary customer — completed load curtailment arrangements.
Employees in front of the Coleman Station in June 2017 | Big Rivers
“Big Rivers itself acknowledges that the decision of whether and when to return the Coleman Station to service will be a complicated one. It thus appears that the Coleman Station may not be returned to service regardless of whether its interconnection service is reinstated,” FERC said.
‘Not Unique’
In early October, Rep. Brett Guthrie (R-Ky.) wrote to Chairman Neil Chatterjee urging a “full and fair consideration” of Big Rivers’ request for rehearing.
But FERC said the challenges facing the nearly 50-year-old Coleman are commonplace: “While we appreciate the difficulties facing Big Rivers with regard to the future disposition of the Coleman Station, its circumstances are not unique. There are likely other generators that are currently uneconomic that would, if possible, reserve their interconnection service indefinitely in the hopes of future market changes.”
Big Rivers also argued that FERC was still allowing for disparate treatment of generators. While Coleman never had a generator interconnection agreement (GIA) with MISO, the RTO would be prohibited from cutting service to a generator operating under a GIA, the company contended.
FERC said the result would be the same, GIA or not, “because Big Rivers had not satisfied the requirement of taking ‘significant steps to maintain or restore operational readiness … as soon as possible.’”
Big Rivers additionally filed a motion in September asking FERC to consider the “evolving status of MISO’s policies on replacing retiring generation facilities and the interplay of MISO suspension, retirement and SSR rules.” MISO officials and stakeholders are currently considering whether SSR units facing terminations should be able to maintain service even after contract expiration in order to allow them to participate in the RTO’s annual capacity auction.
“Although styled as a motion to clarify the record, Big Rivers seeks to reopen the record and lodge the two MISO presentations for commission consideration,” FERC responded. “Evidence that MISO and its stakeholders are in the process of considering changes to the Tariff that may allow generators to retain interconnection rights following retirement do not constitute a ‘change in core circumstance’ at ‘the very heart of the case.’”
The loss of three natural gas pipelines is creating major concerns about Southern California’s gas and electricity supplies, with three state and local regulators saying that Los Angeles-area electricity generators could experience gas curtailments this winter.
The California Public Utilities Commission, California Energy Commission and Los Angeles Department of Water and Power (LADWP) last week issued a new assessment of the situation suggesting that curtailments are more likely this winter than last because of pipeline ruptures — but much will depend on the weather. Southern California Gas’ Line 235-2 ruptured on Oct. 1 and also damaged Line 4000, adding to an existing outage of Line 3000, according to the report.
Southern California has three natural gas pipelines out of service
“Natural gas service is threatened to noncore customers, including electric generators, this winter,” the report said. “This threat occurs even though there is more gas in storage than at this time last year.”
The concerns arose even after SoCalGas’ Aliso Canyon gas storage facility resumed injections in July, despite objections from state agencies. (See Aliso Canyon Resumes Injections.) Operations at the facility had been halted following a massive methane release detected in October 2015 and finally plugged in February 2016. The California Division of Oil, Gas and Geothermal Resources determined it is safe for the company to resume injections at the site.
Location of the Aliso Canyon natural gas storage facility
The agencies issuing last week’s report said that other actions under consideration include an emergency moratorium on new natural gas service connections in the Los Angeles County area served by Aliso Canyon.
“Another proposed measure would direct electricity generators to more frequently shift generation to facilities located outside the SoCalGas system to reduce gas use in December,” the agencies said. “This could allow SoCalGas to preserve storage inventories deeper into the winter.”
The report also said LADWP could delay electrical transmission upgrades until February in order to maintain access to power sources outside the region. The agencies are additionally considering slightly increasing the volume of gas that can be stored at Aliso Canyon.
Last week’s public hearings on the repeal of the Clean Power Plan provided EPA Administrator Scott Pruitt the stage he sought for coal industry supporters to blast the Obama administration’s environmental policies. But not everyone stuck to the script.
Pruitt said he chose to have the hearings in “the heart of coal country to hear from those most impacted” by the CPP. During two days of hearings at the West Virginia State Capitol in Charlestown, coal magnate Robert Murray, West Virginia Attorney General Patrick Morrisey and other CPP critics derided the regulation as two dozen miners in hard hats and overalls looked on in support.
Audience view of the Clean Power Plan hearing | EPA
But the hearings also attracted many supporters of the CPP, as well as business groups who argued for replacing the CPP with less stringent rules to provide regulatory certainty and protection against litigation.
Pruitt announced the repeal of the CPP in October, saying the Obama administration overstepped its authority by regulating beyond the “fence line” of individual generators. The question facing the Trump administration now is what the replacement — required by EPA’s 2009 finding that CO2 emissions endanger public health — should be. (See EPA to Announce Clean Power Plan Repeal.)
Morrisey said the CPP “would impose a top-down reordering of state energy economies … and would be disastrous for West Virginia and the country as a whole.”
Murray, CEO of Murray Energy, said EPA should repeal the power plan “in its entirety,” including overturning the endangerment finding.
But utilities and business groups urged EPA to leave the endangerment finding in place and focus on a replacement for the CPP.
The U.S. Chamber of Commerce asked for “durable and achievable standards.”
Scott Segal, director of the Electric Reliability Coordinating Council, which represents utilities including Duke Energy and Ameren, said he supports a regulation that would require efficiency improvements in fossil fuel plants.
Coal miners outside capitol bldg for EPA hearing | West Virginia Coal Association
“While ERCC believes that absent specific guidance in legislation from the U.S. Congress, market principles are the most sound basis upon which to proceed, we nevertheless support the process advanced by EPA,” Segal said. “Federal guidance of sufficient flexibility, and limited to actions within the fence line, can provide regulatory certainty, diminish frivolous litigation, and can aid in planning.”
Richard Revesz, director of the Institute for Policy Integrity at the New York University School of Law, told the Los Angeles Times that repeal without replacement “could open the floodgates for litigation,” leaving power companies vulnerable to “significant and highly uncertain liabilities.”
“The EPA is required to publicly regulate these pollutants. Therefore, repealing the [CPP] without a replacement is illegal,” Connecticut Department of Energy and Environmental Protection Commissioner Robert Klee testified. “Ignoring these facts won’t make the problem go away; it will only serve to make it worse and delay the solutions we desperately need to meet this local, regional, national and international challenge.”
Klee told RTO Insider later that while the first day of the hearing was dominated by many coal miners in the audience, EPA’s strategy to hold the meetings in coal country “backfired” on the second day when dozens of ordinary West Virginians spoke out against repeal. Klee and others called for additional hearings in other regions of the U.S.
The Obama EPA held public hearings in four states before issuing the CPP. An EPA official said last week that the agency was considering whether to hold additional hearings and had not set a schedule for announcing what kind of replacement rule it will propose.
“As a West Virginian, I’m insulted at the choice of this location,” resident David Lillard said. “It doesn’t make for great TV to have coal executives and some coal barons speaking about saving a few pennies per ton of coal, but it’s great theater to have desperate coal miners carrying the message for the coal barons and the coal companies that have lied to them repeatedly. They were told their pensions were safe, and that was a lie. They were told they would always have health care; that promise was broken.”
Nick Mullins, a fifth-generation coal miner from Kentucky, said the CPP will lead to safer and better job options for his son. “I don’t want him to be a sixth-generation coal miner,” Mullins said, citing the physical toll of the work.
“As long as I can draw a breath, I’m going to keep working to fight climate change and protect the land and country I love,” said Stanley Sturgill, a Kentucky resident who said he suffers from black lung disease after more than 40 years as a coal miner.
“The coal miners I talk to seem to know coal jobs will continue to dry up, with or without a Clean Power Plan,” said Angie Rosser, executive director of the West Virginia Rivers Coalition. “We’ve been pitted against each other by being told we’ll either have coal, or we’ll have nothing. This administration seems to thrive on public anger and conflict. It’s a distraction. When people are fighting, they are not talking. … The clock is ticking to do something different than leaning on a dying industry.”
Indeed, just last week PPL said its Kentucky utilities will retire their aging coal units and replace them with natural gas and renewables — even without carbon regulations. The company said it projects CO2 reductions of 45 to 90% by 2050.
Utilities are at the epicenter of public battles between the California Public Utilities Commission and its critics over wildfires, public safety and ethics that have major financial implications for companies and ratepayers.
Those controversies surfaced at a Nov. 30 CPUC meeting at which the commission denied San Diego Gas & Electric’s request to recover from ratepayers $379 million in costs related to the 2007 Southern California wildfires. SDG&E quickly vowed to vigorously fight the commission’s unanimous decision.
Following recommendations by an administrative law judge, the CPUC said the utility “did not reasonably manage and operate its facilities prior to the 2007 Witch, Guejito and Rice Wildfires,” which killed two people and destroyed homes and property. SDG&E’s $379 million request was separate from other court proceedings, settlements, insurance payments and federal cost recovery regarding the fires.
Commissioner Liane Randolph said the SDG&E case turned on the specific question of equipment maintenance, including faults on a transmission line, a communications wire and vegetation management.
“There is no dispute that each of the fires were caused by SDG&E facilities,” she said. Randolph noted the decision is not a final statement of the doctrine of inverse condemnation, the legal tool that SDG&E leaned on in its claim. The logic is that “the costs of a public improvement benefiting the community should be spread among those benefited rather than allocated to a single member of the community.”
But Randolph said it is appropriate to put the costs on Sempra shareholders, not ratepayers, and the case has nothing to do with the utility’s current management of the system. “The decision is specific to the 2007 incident and the facts of this case,” she said.
Commissioner Clifford Rechtschaffen added that inverse condemnation “is somewhat of a theoretical issue in this matter.”
“The decision does not hold the utilities to a standard of perfection,” he said. “We can’t apply a standard that provides an incentive for a utility to act imprudently or unreasonably,” adding that would send the wrong signal to the utility.
In a written statement, SDG&E Chief Regulatory Officer Lee Schavrien said: “SDG&E strongly disagrees with today’s decision. The CPUC got it wrong. The 2007 wildfires were a natural disaster fueled by extreme conditions including the worst Santa Ana wind event this region has ever seen, combined with high heat, low humidity and hurricane-force winds as high as 92 mph.”
During its third-quarter earnings call, SDG&E parent Sempra Energy vowed to take legal action if denied the cost recovery. (See SDG&E’s Wildfire Costs Undercut Sempra Profits.) The commission did receive praise from The Utility Reform Network and the California Office of Ratepayer Advocates for denying the cost recovery.
During the meeting, commissioners also discussed the increased risk of fires attributed to climate change in California. PUC President Michael Picker noted that areas of elevated or extreme fire hazard are growing in California, to almost 42% of the state, and more people are moving into those areas with higher wind and lightning.
“This is become an increasingly complex area for us,” Picker said, adding that the decision “may or may not” set a precedent for future cases.
As the battle over the 2007 fires continues, the CPUC is preparing to evaluate a similar situation for Pacific Gas and Electric regarding the particularly destructive fires that ravaged California’s wine country this summer, from which the death toll rose to 44 this week. The cause of the fires is still under investigation. (See Wildfires Color California PUC Utility Decisions.)
Embroiled in Controversy
The CPUC issued the ruling amid a swirl of legal battles, regulatory proceedings and public accusations that focuses heavily on the tenure of former President Michael Peevey, who resigned from the commission in January 2015 and has been under investigation by the state’s attorney general for engaging in back-channel discussions with Southern California Edison over the financial terms of the San Onofre nuclear plant’s closure.
The environment around the current CPUC has been increasingly darkened by years of public allegations of other ethics violations. State lawmakers last week renewed their call for Attorney General Xavier Becerra to file charges regarding improper communication between the PUC and PG&E concerning the 2010 explosion of the company’s gas pipeline in San Bruno. The request came soon after the discovery of old email communications between the PUC and former PG&E consultant and Commissioner Susan P. Kennedy regarding the San Bruno settlement. (See Probe Reveals More CPUC-PG&E Contacts on Pipeline Blast.)
The situation led to a confrontation at last week’s meeting between Picker and San Diego attorney Michael Aguirre, a frequent CPUC critic who is involved in the San Onofre case.
As Aguirre approached the microphone during the public comment period at the San Francisco hearing, Picker asked him if he was there to apologize for his “rude, abusive and disruptive behavior” at a recent hearing regarding the San Onofre plant. Aguirre ignored Picker and instead spoke of recent wildfire deaths, the San Bruno explosion and the natural gas leak at the Aliso Canyon storage facility near Los Angeles.
Aquirre said the victims of the Tubbs Fire in Napa and Sonoma Counties “are not here to ask why the California Public Utilities Commission did not enforce the safety rules against PG&E that could have saved our lives.” Picker told Aguirre he himself was a party to one of the proceedings and his appearance might violate commission rules.
Commission Response
The commission on Dec. 1 issued a lengthy public statement saying, “The CPUC has cooperated with the attorney general’s office through every step of the investigation as well as with federal investigators whose demands for documents preceded those of the attorney general. Throughout the process, the CPUC has produced more than 1 million documents to the attorney general.”
The CPUC said the agency had fully complied with a search warrant as of December 2016. “The case is in the hands of the attorney general’s office, and the next steps are up to the office,” the commission said.
At its Nov. 30 meeting, the commission also voted to defer consideration of a related $86 million settlement between it, PG&E and other parties over improper ex parte communications in the wake of the San Bruno blast.
BOSTON — Massachusetts’ $2,500 rebates are increasing electric vehicle sales, and state officials are preparing for the shift in demand now, the state’s Department of Energy Resources said Thursday.
“We do have a goal for 300,000 electric vehicles to be registered in the state by 2025,” DOER Director of Emerging Technology Will Lauwers said in a briefing to the Environmental Business Council of New England on Nov. 30. “Providing the charging infrastructure for that is crucial.”
EV registrations have grown from 782 in July 2013 to 3,770 as of March 31, 2017, according to the state Department of Environmental Protection. In the same period, the number of gas-electric hybrids has increased more than five-fold, from 1,034 to 5,701. The state launched its rebate program, which covers both EVs and hybrids, in June 2014.
Although the alternative transportation sector includes biofuels and gas-electric hybrids efforts, electric vehicles and transportation electrification dominate the state’s efforts, Lauwers said. The DEP’s program to incentivize workplace charging stations exhausted its funding this year.
“Utilities have shown interest in helping to reduce the cost of entry to deploying EV charging, so they would help to cover more of the associated costs with new meters, new pads and new connections,” Lauwers said. “Then there’s the VW funding.”
As penance for having rigged diesel emissions test results, Volkswagen is spending $2 billion to install more than 300 vehicle chargers in 15 metro areas, including Boston.
Resiliency, not Totality
Lauwers said Massachusetts is “a nation-leader” in its commitment to reducing greenhouse gases and fostering new renewable energy resources and has “made a lot of progress in the past 12 months” on energy efficiency, energy storage and demand reduction.
He cited the DOER’s June announcement of $10 million in incentives for energy storage demonstration projects, a 200-MW storage deployment target and a $40 million initiative that awards grants to cities and towns to use clean energy technologies to mitigate the risks of power outages arising from severe weather. Award announcements on the storage incentives are expected by early 2018. (See Massachusetts Underwhelms with 200-MWh Storage Target.)
Michael Judge, the DOER’s director of renewable and alternative energy, said storage is key for both grid stability and reducing emissions. Without storage “you end up keeping all these fossil fuel units going because they can’t ramp that fast,” Judge said.
In discussing resiliency studies that the department conducted on 12 state medical centers, Lauwer said resiliency doesn’t mean 100% of normal power availability, just enough to run core functions. For example, a nursing home might lose its heat in a power outage just because it needs 9 V to run the pilot light.
Infrequently used back-up generators at hospitals often fail in the first few hours of running, so energy storage can make a big difference in such situations, he said in discussing the agency’s analytical tools that help facility administrators understand what energy resiliency steps are economically viable for them. In addition, DOER will soon be clarifying how much energy storage utilities can own and how they will be compensated, Lauwers said.
Massachusetts is funding incentives to include energy storage in solar installations, as well as grants for peak demand reduction. Pairing energy storage with solar panels is meant to enhance grid resiliency by reducing the demand curves. Peak reduction grants cover a wide range of projects, from utilities improving the efficiency of substations, to municipalities working to reduce the energy consumption of big-box retail stores, to a thermal energy storage project on Nantucket that will delay the need for a new undersea transmission cable.
| Mass. DOER
The state this year launched its Solar Massachusetts Renewable Target (SMART) program to provide incentives for “long-term sustainable … cost-effective solar development.” The program provides adders based on location, and to projects that provide unique benefits, including community solar and energy storage.
Judge said the state’s new Alternative Energy Portfolio Standard is the only one of its kind in the country. The final draft regulations, expected to be promulgated on Dec. 29, include combined heat and power, flywheel storage, renewable thermal, fuel cells and waste-to-energy thermal technologies. The regulations oblige all retail electric suppliers to acquire a certain percentage of their power from eligible technologies, starting at 4.25% in 2017 and increasing by 0.25% each year.
“Heating is behind the electric sector in decarbonizing and amounts to about 30% of GHG emissions,” Judge said. “DOER incentives for renewable thermal energy and heat pumps are paying off, with nearly 500 MW of combined heat and power systems installed as of the end of October 2017.”
Energy Efficiency Peaking?
Arah Schuur, DOER director of energy efficiency, said the state will deliver $8 billion in efficiency benefits from 2016-2018 and that those savings will continue to grow.
“You put in a light bulb, you put in an efficient piece of technology and it lasts for five, seven, 11 or 20 years, and those benefits accrue as we add more to the portfolio,” Schuur said.
Lighting savings comprise 83% of residential energy efficiency gains and 23% of overall savings. Although the state has nation-leading goals for both electric and natural gas, efficiency savings seem to be peaking, she said.
“That’s because of the change in the lighting market and the change in federal lighting standards. So, screw-in light bulbs are nearing market saturation. There’s natural uptake of LED lights. This [is a] great good news story overall for energy efficiency,” Schuur said.
The limits to lighting’s contribution to efficiency savings will “require a whole new way of thinking about energy efficiency,” she said. The DOER is exploring new ways to achieve efficiency results, such as addressing demand through utility programs, looking at the residential contractor market and driving innovation.
ERCOT stakeholders unanimously endorsed almost $250 million in transmission projects during last week’s Technical Advisory Committee meeting, sending the package to the Board of Directors for its Dec. 12 meeting.
The two projects will address “significant” industrial growth in the Freeport area, a seaport south of Houston on the Gulf of Mexico. Newly committed industrial loads are expected to push the area past 2.2 GW by 2022, surpassing the heavily populated Rio Grande Valley.
The market “thinks about big meaty load pockets like the [Dallas-Fort Worth] area, Houston, San Antonio and Austin, but we haven’t really thought about Freeport,” said Jeff Billo, ERCOT’s senior manager of transmission planning.
ERCOT staff project a 92% increase in the area’s load by 2019, from 1,028 MW to 1,979 MW. An additional 300 MW is expected by the end of 2022.
| ERCOT
CenterPoint Energy, which services the area, submitted the “Freeport Master Plan Project” to ERCOT’s Regional Planning Group, proposing a two-phase approach to solve reliability criteria violations caused by the increased load. Staff’s independent review agreed with the projects’ needs, finding multiple reliability criteria violations in 2020 and 2022 cases.
The $32.3 million first phase, or “bridge-the-gap upgrades,” focuses on near-term reliability needs. It consists of a 345-kV loop and a series of reactors, autotransformers and capacitor banks at a key substation.
The $214.4 million second phase comprises a new 48-mile, 345-kV double-circuit line and circuit upgrades to another 345-kV line. It was one of five options considered by staff, four of which involved a new 345-kV right of way, and would meet the “long-term reliability criteria needs in the most cost-effective manner.”
| ERCOT
The other four options had cost estimates of between $223.2 million and $281.8 million.
“We realize there is a long-term need to put in bigger infrastructure projects, but to get to that point, interim upgrades need to be done,” Billo said. “More upgrades will need to be done in order to meet the long-term needs of the system.”
Staff’s recommendation met little resistance from members, who only needed to be assured the load increase will be included in ERCOT’s next Capacity, Demand and Reserves (CDR) report. That report, to be released Dec. 18, includes a snapshot of planned resource additions during the next five years, current information about existing resources and the annually updated peak demand forecast for the next 10 years.
Billo also updated members on the South Plains Project, a proposed $247.5 million, 345-kV line in the Texas Panhandle.
Billo | ERCOT
Billo said Sharyland Utilities has proposed the transmission line as an economic project but that ERCOT’s analysis has yet been able to economically justify the project. He said about $210 million of the South Plains Project overlaps with work that would be done to integrate Lubbock Power & Light, which wants to shift 470 MW of load from SPP into ERCOT.
The Public Utility Commission of Texas has scheduled a hearing on LP&L’s integration Jan. 17-18 (Docket 47576). Until then, staff has paused further analysis.
“We will wait to see what happens in that hearing and the subsequent decision that comes out of the PUC,” Billo said. “That may supersede the need to analyze part of [the South Plains] project. If the commission says we’re going to go ahead with Lubbock and those lines get approved, we don’t have to do an economic justification for [the South Plains] lines anymore.”
Billo said staff would update its assumptions and Sharyland’s capital cost updates, and add plant retirements and other fresh data in a potential reassessment of the project that could be ready by mid-2018.
MISO will roll out a new public website this winter and begin a $130 million project to replace its aging “monolithic” market platform with a new “modular” system.
The RTO is “off to a good start” to replacing the platform, Vice President of System Operations Todd Ramey said during a Nov. 28 conference call of the Board of Directors’ Technology Committee. MISO expects to spend $21.7 million on the project in 2018, one-sixth of the amount budgeted over the next seven years. (See MISO Makes Case for $130M Market Platform Upgrade.)
Executive Director of Market Design Jeff Bladen said MISO will provide quarterly project briefings to both the board and stakeholders, with the first one slated for a Dec. 5 meeting of the board’s Markets Committee. The RTO has already convened the chief information officers of some of its member companies for a nonpublic meeting to discuss project risks and timelines.
MISO Director Baljit Dail asked that the RTO’s next update identify key milestones in the platform replacement that could affect the overall project timeline if not met. MISO expects to begin migrating to the new system in 2020, keeping the current one in operation at least until 2021.
Bladen said MISO has met with the leaders of other RTOs that also use vendor General Electric to discuss how to ensure the company honors its delivery deadlines.
New Site Ready for Launch
MISO plans to launch its new external website next month, moving the current site to old.misoenergy.com, where it will remain available until early 2018 to ensure the RTO maintains its web presence if the new site fails.
beta.misoenergy.org | MISO
“We’ll keep both sites running concurrently, at least for the first few months, then make a decision on the old site in the first quarter of 2018,” said Kacey George, MISO public relations specialist.
A beta version of MISO’s new website has been up since October at beta.misoenergy.org.
CARMEL, Ind. — MISO’s Independent Market Monitor said Wednesday that PJM has for years been committing two market-to-market operations errors that have possibly cost MISO millions of dollars.
Monitor David Patton contended that PJM has been “overstating” its response to transmission loading relief (TLR) requests and — more seriously — failing to order mandated tests required to define M2M constraints between the two RTOs.
As a result, PJM’s neighboring balancing authorities have been forced to make up for the RTO’s TLR shortfall and spend more on congestion, incurring costs they are not likely to recover.
Neglected M2M Constraint Test
The test cited by Patton uses real-time system topology to measure the congestion generating resources in a non-monitoring RTO (in this case MISO) contribute to a PJM flowgate, and is mandated by the joint operating agreement between the two RTOs.
“This has not been instituted since it was introduced, which I don’t know, is a decade or more,” Patton said during a Nov. 29 Joint and Common Market meeting between MISO and PJM. “It was an error that was known and is a serious violation of the JOA.”
PJM Director of Energy Market Operations Tim Horger said his RTO is still examining the potential impacts of failing to request the tests but cautioned against labeling the failure to act a Tariff violation.
“PJM is not in a position to say that by not requesting the study it is in a Tariff violation,” Horger said.
It would be “very difficult to quantify the impacts” of PJM’s neglected tests, Patton said, but he thinks they explain some of the past gaps his monitoring firm has observed in M2M coordination. The Monitor’s 2016 State of the Market report showed that substantial volumes of congestion were not coordinated because constraints were not properly identified as being M2M. From January 2016 to October 2017, Patton detected $341 million worth of congestion on constraints that should have been coordinated by PJM.
“Not all of this amount is due to this violation of the JOA; some are likely due to simply not testing constraints or not testing them in a timely manner,” Patton said.
But in consistently failing to evaluate constraints affected by its neighbor’s generators, PJM couldn’t capture transmission outages, “frequently the cause of severe binding constraints,” he said.
“Not only did this undermine efficient dispatch and congestion management, but [it] also effectively granted PJM an unlimited entitlement to MISO transmission” because it did not test for constraints causing congestion, Patton said.
He added that it would be impossible to eradicate all congestion from MISO and PJM’s M2M coordination.
“We know that some of this uncoordinated congestion in MISO is because some constraints weren’t requested to be identified. To be honest, we think that all issues that prevent a constraint from being quickly identified are problematic,” Patton said.
PJM Miscalculation
Patton also contended that PJM’s TLR calculation — which enables MISO, PJM and SPP to acknowledge and receive credit for relief provided during TLR procedures — has been incorrect since 2009. MISO first noticed PJM’s error in September, when binding constraints during TLR procedures in the Tennessee Valley Authority area alone boosted MISO Midwest real-time monthly average prices by almost 8%, according to Patton.
“This has been very costly for MISO because MISO has incurred extreme costs attempting to provide the relief requested in response to a TLR,” Patton said. “If it raised the relief obligation that MISO had, we’re talking a lot of money.”
MISO officials believe PJM has since corrected the problem, although they continue to investigate.
Patton and MISO seams management expert Ron Arness said no precedent exists for resettling energy prices because of TLR errors, but the Monitor thinks the impact could easily reach into the millions of dollars.
“In any particular month, the cost may not be big, but this has been happening for years,” Patton said.
Horger pointed to the challenge of resettling prices influenced by TLRs.
“If after investigation, PJM decides that prices were affected, that doesn’t change the fact that the dispatch reflected the generation movement [in response to TLRs]. That’s a dangerous slope,” he said.
BOISE, Idaho — Integration into the Western Energy Imbalance Market (EIM) can present challenges for resources that don’t fit neatly into CAISO’s existing market model, market participants said during a regional conference Tuesday.
Speakers at the Nov. 28 Regional Issues Forum discussed their approach to effectively integrating hydropower, coal and jointly owned plants into the market. The group, which includes representatives from 10 sectors that gather to discuss various EIM topics, can produce opinions and other documents for CAISO, the EIM Governing Body or the ISO Board of Governors.
Khai Le, senior vice president at generation supply management software developer PCI, told the forum that hydropower units are ideally suited to balance the variable output of renewables in the EIM, but could be much more effective with some operational changes to the market. Most EIM participants have a fairly rich mix of hydro and renewables, and “properly coordinated, that could be a very good marriage between the two,” Le said.
But hydro operators believe “there is lots of room for improvement in terms of hydro dispatch in the EIM market,” he said.
EIM hydro operators include PacifiCorp, Pacific Gas and Electric, Portland General Electric, Puget Sound Energy and Southern California Edison. Their hydro resources vary, and include pumped storage and “cascading hydro” systems in which the discharge from one hydro plant is used as intake for another. Seattle City Light will be the first EIM participant to offer 100% hydro resources when it joins the market in April 2019.
Modeling hydro resources can also be more difficult than other types of generation, Le said. Hydro owners cannot model their plants using CAISO’s “multi-stage generator” (MSG) model because some MSG parameters might only be updated one or two times a month, while hydro units have much more dynamic characteristics that require modeling on an hourly basis.
And while MSG allows for modeling of so-called “forbidden regions” — the different configurations, characteristics and overlapping regions that constrain the operations of many hydro resources — the CAISO system does not recognize cascading hydro and does not understand hydro topology and constraints, Le said.
Integrated properly, hydro operators will get more value in the EIM for the same output they had prior to joining the market, he said. Flexible capacity payments from the EIM are not sufficient for hydro operators to modify their operating rules for the market, he said, constituting just about 5% of the market’s revenue, which is mostly energy payments.
“The greatest challenge in operating your hydro resources is somehow trying to use your bid parameters to reflect the real-life hydro constraint that you have,” Le said.
Operating jointly owned units in the EIM can also be a challenge, according to Kelcey Brown, PacifiCorp manager of market and analytics. When it first joined the market, PacifiCorp modeled the full output of its jointly owned Jim Bridger plant but ran into problems with modeling schedules, ramping, heat rates and other issues.
“There were a lot of problems, actually,” she said. “We just could not get it right.” So in February 2016, the company began modeling only its share of the plant, which has made the situation much smoother, she said.
CAISO does not have the ability to model one unit as separate, individual units, she said, creating the need for PacifiCorp to modify the model to show its individual share of each unit. The company is exploring participation with its Hunter 1 and 2 coal units, which would require a similar approach.
Clay MacArthur, vice president of power marketing at Utah-based Deseret Power Electric Cooperative, met resistance from plant operators and others when he proposed joining the EIM, which the company finally did in August. Deseret’s primary coal resource is the 500-MW Bonanza coal-fired plant, located in EIM member PacifiCorp’s balancing authority area.
“There was a pitchfork-and-torches moment when I announced to the coal plant, ‘Hey, I would like to take the plant into the EIM,’” MacArthur said. The company wanted to optimize its resource portfolio and improve reliability while gaining experience in organized markets.
“Everybody said ‘You’re insane, this is a huge mistake, you can’t do this,’” MacArthur said, because of worries about engineering and responding to the market. The co-op had to be careful to model the Bonanza units for the EIM in a way that would not destroy the unit, he said.
Co-op members visited a PacifiCorp coal plant that was already participating in the EIM and explored what he called “tribal knowledge” about transitioning into the market, which helped convince the doubters.
The EIM does not require owners to completely turn over control of their plants, MacArthur said, but for Deseret, joining the market did involve plant upgrades, simplifying market modeling and using bidding strategies and operational expertise.
“We had to just kind of cross the Rubicon, and hope for the best.”
