HARRISBURG, Pa. — Critics of a bill to subsidize Pennsylvania’s failing nuclear fleet on Monday advised state lawmakers to put the brakes on the proposal, saying it would distort the deregulated energy markets it worked long to build.
Glen Thomas
Glen Thomas, president of GT Power Group, testified before the House Consumer Affairs Committee that House Bill 11 upends two decades of regulatory and legislative work and wastes $12 billion in stranded costs spent transitioning to a competitive wholesale power marketplace.
“It’s an absolute competition killer,” he said. “It’s a big deal. It’s a very complicated piece of legislation … that undoes a lot of the hard work it took to get us here.”
HB 11 would create a third tier of resources in the state’s Alternative Energy Portfolio Standard (AEPS) program from which retail providers must purchase at least 50% of their electricity by 2021: nuclear, solar, geothermal and low-impact hydropower. The first two tiers of the legislation include 16 resource types with targets of 8% and 10%.
Prime sponsor Rep. Thomas Mehaffie (R) said the plan would provide consumer protections through capped pricing and the prevention of “double dipping” across programs. He estimated the bill would cost $500 million — one-eighth of the $4.6 billion in annual costs he claims would result should all five nuclear plants in the state shut down: $788 million in higher electric prices; $2 billion in lost GDP; and $1.86 billion in costs associated with carbon emissions and harmful criteria air pollutants, including SO2, NOX and particulate matter. (See Pa. Lawmakers Unveil $500M Nuke Subsidy Bill.)
Exelon will begin the four-month process of shutting down Three Mile Island near Harrisburg in June if lawmakers fail to act. FirstEnergy will retire Beaver Valley in 2021 in what the company described as a growing trend during its testimony before the committee on Monday.
Dave Griffing
“On one hand, emitting plants get to pollute for free, not bearing any of the cost of the pollution they put into the air or water,” said Dave Griffing, vice president of government affairs for FirstEnergy Solutions. “And on the other hand, 16 other forms of technology get a payment, some as high as $55[/MWh], from the federal and state government through tax credits and AEPS credits. The result is not shocking. Pennsylvania nuclear facilities and others across the country have their hands tied behind their backs and are facing early retirement.”
Critics of the plan argue there’s better, cheaper ways to reduce carbon emissions and insist that subsidizing nearly 70% of the market props up aging nuclear reactors at the expense of competition.
“This is a major shift in Pennsylvania’s energy policy from a policy that puts consumers in the driver’s seat to one that puts policymakers in the driver’s seats by dictating where their energy comes from,” Thomas said, noting he’s spent the majority of the last 15 years convincing other states to deregulate their energy markets like Pennsylvania has. “HB 11 puts the thumb on the scale for 68% of the delivered megawatts in this state if approved.”
Tom Ridge
Tom Ridge, former secretary of Homeland Security, and Pennsylvania governor from 1995 to 2001, said preserving the state’s five nuclear facilities maintains reliability. He signed the 1996 bill deregulating the state’s energy markets and allowing it to join PJM.
“I’ve always believed in a diversified portfolio,” he told lawmakers Monday. “We want competitive markets and competitive markets need multiple sources of generation. Other states are doing it because they can’t wait on the feds to do it. In five or six years, we may not have these facilities left.”
Todd Snitchler
Todd Snitchler, vice president of market development for the American Petroleum Institute, said PJM’s generation portfolio will remain balanced, even as trends shift away from nuclear energy. Last month, the Independent Market Monitor said gas-fired energy output exceeded coal in PJM last year for the first time, though sources remain relatively balanced among gas (30.9%), coal (28.6%) and nuclear (34.2%), with renewables accounting for a small but growing share of less than 3%.
“A concern about a dash to gas needs to be tempered by realities on the ground,” he said.
The committee will host a second public hearing on HB 11 in Harrisburg on April 15.
The Senate version of the bill, SB 510, was introduced last week by Sen. Ryan Aument (R). That bill differs from the House version in that it directs the state’s Public Utility Commission to set credit prices and guarantee that between 17 and 23% of Tier III sources purchased include non-nuclear suppliers, like wind and solar. (See related story, Pa. Lawmakers Introduce 2nd Nuke Subsidy Bill.)
ERCOT staff and stakeholders began the long process of implementing real-time co-optimization (RTC) last week with the first meeting of the Real-Time Co-Optimization Task Force.
The group spent its Thursday meeting reviewing ERCOT’s current market design and the changes that RTC will necessitate. ERCOT Compliance Director Matt Mereness, the task force’s chair, said it’s important to understand the elements in RTC’s high-level design principles in order to better understand what is being implemented.
“We have a mandate to implement real-time co-optimization, and we will be working to see what market functions have to be changed to enable that,” Mereness said.
RTC is supposed to efficiently coordinate the provision of energy and ancillary services (AS) in the real-time market and price AS shortages according to their defined demand curves. Its elements include: real-time market and AS deployment; reliability unit commitment; day-ahead market operations; internal and external reporting; and performance monitoring.
Implementation of the process will mean the loss of ERCOT’s supplemental AS market.
The Texas Public Utility Commission directed ERCOT to implement RTC earlier this year (Project 48540). The grid operator has said it will take four or five years and about $40 million to add RTC to the energy-only market.
Bryan Sams, director of regulatory affairs for Lone Star Transmission, is serving as the RTCTF’s vice chair. The group is composed of stakeholders and staff from ERCOT, the PUC, the Independent Market Monitor and the Office of Public Utility Counsel. The task force will report directly to the Technical Advisory Committee.
ERCOT to Ask Board for NPRR916 Changes
ERCOT will ask its Board of Directors during its bimonthly meeting Tuesday to accelerate the implementation date for a previously approved Nodal Protocol revision request (NPRR) and to change its mitigated floor offer as a result of negative gas prices.
The TAC endorsed NPRR916 on March 27. The change sets the mitigated offer floor to $0/MWh for “combined cycle” (CCGTs) and “gas/oil steam and combustion turbine” (CTs) resource categories, replacing the fuel index price-based (FIP) calculation. The change also eliminates the grey-boxed language from NPRR664.
During a Thursday webinar, staff explained that negative fuel prices at the Waha Hub coupled with mitigated floor offers are creating “irrational restrictions” for CTs and CCGTs. When gas prices are negative, a floor of zero is excessive relative to the resource’s optimal offer, staff said.
ERCOT wants to change the offer floor to -$20/MWh, aligning CTs and CCGTs with coal and lignite units’ offer floor.
Texas Natural Gas Prices | ERCOT
The grid operator also wants to move up implementation of NPRR916 from May 1 to April 10. Staff said West Texas fuel prices support the need to “make this system adjustment as soon as practicable.” The proposed change to -$20 requires modifications to ERCOT systems that would become effective upon system implementation.
The current floor for CCGTs is set at 1 MMBtu/MWh x FIP, and 6 MMBtu/MWh x FIP/FOP (fuel oil price) for CTs and gas and oil steam turbines. NPRR916 changes those numbers to a straight value of $0/MWh.
The NPRR916 changes are expected to cost less than $10,000 and will be absorbed by ERCOT’s operations and maintenance budgets, staff said.
CHARLOTTE, N.C. — There was no stated theme to this year’s Transmission Resiliency Summit, held at Electric Power Research Institute laboratories last week, but some common motifs ran through the event.
The North American Transmission Forum (NATF), headquartered less than 6 miles west of the EPRI labs, gathered representatives from utilities, RTOs, NERC regional entities and government agencies to discuss improving the resilience of the bulk electric system.
That group held its first meeting in April 2013 in the aftermath of Superstorm Sandy, focusing on severe weather events, according to NATF CEO Tom Galloway. Less than two weeks later, gunmen carried out a highly sophisticated attack on Pacific Gas and Electric’s Metcalf substation, costing the utility more than $15 million in direct costs and $100 million in security upgrades.
Galloway’s recollection of those events set the stage for two days of discussing not just the myriad threats the grid faces — and the best ways to secure the grid, both physically and digitally, against them — but also how to respond to and recover from a catastrophic event.
Last week’s summit, hosted jointly with NERC this year, was the largest NATF and EPRI have held and the first one open to non-NATF members, including the press. Andrew Phillips, EPRI vice president of transmission and distribution infrastructure, said 230 people had registered, representing more than 100 different entities from the U.S. and Canada.
The maximum capacity for the conference room: 230. And there were only a few open seats throughout the event.
“Who’s who in the zoo [are] all here,” said Brian Harrell, assistant director for infrastructure security at the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA). “No. 1, I think that’s a testament to this particular conference, and two, it’s showcasing the fact that you all are taking resilience very, very seriously.”
Speakers Stress Collaboration, Info Sharing
A constant refrain among the multiple speeches, presentations and panels was an emphasis on working together and sharing information, both between the public and private sectors, and among utilities.
“I think we really need to advocate for a collective defense: Whether you are a critical infrastructure company, whether you are a citizen of the United States or you are the U.S. government, we are all in this together,” said Harrell, a former director of the Electricity Information Sharing and Analysis Center (E-ISAC). “Your problem quickly becomes my problem. My problem quickly becomes your problem. Duke’s problem quickly becomes SCANA’s problem, which becomes Dominion’s problem, etc.”
The current director of E-ISAC, Bill Lawrence, urged attendees to join the NERC-operated program, noting the effort to improve its web-based tools in the past few years. “Basically, back in 2015, many of your organizations took a hard look at us and said, ‘Hey, ISAC, if [you want us] to use you, you gotta suck less.’”
E-ISAC benefits from the required reporting under NERC’s Critical Infrastructure Protection standards, “but we also need to get that voluntary information sharing,” Lawrence said in a presentation on measuring the program’s effectiveness. “We’re definitely not sitting on … a pile of gold in voluntary shares, but it’s growing, because our vision is to be a world-class, trusted source of quality analysis and rapid sharing of electric infrastructure security information.”
Galloway asked Lawrence if there was anything besides “‘better information sharing’ … that this audience can do to better support you in moving the E-ISAC forward.”
“Other than my catch-all — ‘share more’ — challenge us,” Lawrence answered. He encouraged members to inform the center if they found its resources were not useful to them.
Most of the first day of the event was spent discussing the incident command system (ICS). The concept was originally developed by fire chiefs in several states in the 1970s to provide a common hierarchy and standardized terms among their departments to coordinate their response to wildfires. Now it is used across multiple sectors, companies and institutions to coordinate their responses to emergencies.
“Firefighting is a team sport,” said Wike Graham, battalion chief for the Charlotte Fire Department. He recalled that Carolina Panthers Head Coach Ron Rivera, after observing firefighters put out a fire in his house, compared the incident commander to a coach. “‘They send the plays in, and you watch these guys, they all know what they’re doing and they’re working as a team.’ That’s what ICS is all about.”
An ICS determines who is in charge (the incident commander) among teams from different entities that respond to an emergency — for example, local police, FBI and the military.
“Training military guys to not be in charge is difficult,” said Taylor Cox, senior consultant for business continuity at Xcel Energy. “‘Yes, sir, I understand you were in charge in Iraq. You are not in charge here,’” recalled Cox, a former member of the Army National Guard.
Staff members from several utilities shared their experiences implementing ICS. Manny Cancel, Consolidated Edison’s chief information officer, described how his company used the system to restore power to Wall Street after the terrorist attacks of Sept. 11, 2001. Kathy Bosse, crisis manager for Exelon, said her company used the system during the civil unrest in Baltimore following the death of Freddie Gray in 2015. Others shared their experiences using the system to respond to simulated cybersecurity attacks.
Emergency Communications
The Metcalf attackers, whose motives and identities remain a mystery, cut fiber optic cables less than a mile from the substation, briefly knocking out internet, phone and 911 service in the area. “One of the things that was most troubling is that it was a very deliberate effort to impact communications,” Galloway said.
One panel at the conference focused exclusively on communications during an event in which all other methods are unavailable.
Ross Merlin of DHS gave a presentation on the department’s SHAred RESources (SHARES) high-frequency radio (HFR) program. He began by explaining how HFR works.
“It works by something called ‘PFM.’ It stands for ‘pure freaking magic.’”
Actually, it’s quite simple but, based on the audience’s reaction to the technology, no less impressive. HFR works by bouncing signals off Earth’s ionosphere, the part of the atmosphere that has been ionized by solar radiation, about 80 km above the surface.
Normally, HFR is used for communicating over very long distances. But it can also be used in cases where all short-distance comms are down.
“By using the right antenna, you can make your signal go almost straight up, which sounds useless unless you’re trying to talk to the International Space Station,” Merlin said. But once it bounces off the ionosphere, the signal comes “not just straight down, but kind of like an upside-down ice cream cone,” allowing for communication within a certain radius. Users can send not only voice, but email and images as well.
SHARES has more than 2,600 participants using about 2,300 radio stations, according to Merlin. The program used to be restricted to the federal government only, but “a few years ago we found giant loophole, I mean, we found a way to reinterpret the rules so as to allow state and local government and critical infrastructure and key resources folks to take advantage of this. … The folks you depend on, whatever you have a dependency on to keep going, we can probably get them in here.”
Several attendees representing Canadian utilities said after Merlin’s presentation that they intended to inquire about applying for the program.
Drones
The second day of the conference featured presentations on the threats posed by unmanned aerial vehicles, more commonly known as drones, both those used by utilities for maintenance and those used by the public — or hostile foreign actors.
CISA’s Harrell repeated his warnings against using foreign-manufactured drones from last month’s NERC Reliability Leadership Summit. (See Feds Late to Act on Drone Threat, DHS Official Says.) E-ISAC’s Lawrence advised the audience to “look beyond” the manufacturers from which the federal government is banned from purchasing under the National Defense Authorization Act for Fiscal Year 2019.
There have also been incidences overseas of environmentalists using drones to try to disable electric infrastructure, including one last year in which Greenpeace flew a device shaped like Superman into a nuclear plant in France.
But according to Xcel’s Cox, “nuisance drones,” piloted by careless or curious hobbyists, are the most common threat to utilities.
“A lot of them are like the kid who throws the Frisbee on your roof and just wants his Frisbee back.”
The Federal Aviation Administration has exclusive jurisdiction over what can fly where, meaning utilities that spot drones over their substations or other facilities can’t do much about them except report them. But that doesn’t mean utilities shouldn’t monitor them.
“There are a lot of physical security managers not paying attention because they say, ‘Well we can’t shoot them down anyway, so why should we care?’” Cox said in response to an audience question about what is allowed. “Well a lot of your security folks don’t have arrest authority, and yet we’re still taking pictures of people stealing copper.”
He advised utilities to leave downed drones alone: Blades can easily cut off fingers, and any sim cards could be compromised with malware.
Travis Moran of Welund North America urged audience members to submit comments on FAA’s Advance Notice of Proposed Rulemaking regarding drones, due April 15. Proposed earlier this month under Section 2209 of the FAA Extension, Safety and Security Act of 2016, the rules would allow utilities to apply for airspace restrictions over their facilities.
“2209 is your best interest right now, and you’ve got to get your lobby people off their butts on this,” said Moran, also a strategic partner with SRC/Gryphon Sensors and a member of the Energy Drone Coalition’s advisory board. “I’ve always said you guys get it because you’re already used to the CIP standards and CIP process, so electricity should be the one to lead this. … Get your people on there … or else you know how the government is going to do it. They’re doing it without your comment, and you’re not going to like what you get.”
CHARLOTTE, N.C. — There was no stated theme to this year’s Transmission Resiliency Summit, held at Electric Power Research Institute laboratories last week, but some common motifs ran through the event.
The North American Transmission Forum (NATF), headquartered less than 6 miles west of the EPRI labs, gathered representatives from utilities, RTOs, NERC regional entities and government agencies to discuss improving the resilience of the bulk electric system.
That group held its first meeting in April 2013 in the aftermath of Superstorm Sandy, focusing on severe weather events, according to NATF CEO Tom Galloway. Less than two weeks later, gunmen carried out a highly sophisticated attack on Pacific Gas and Electric’s Metcalf substation, costing the utility more than $15 million in direct costs and $100 million in security upgrades.
Galloway’s recollection of those events set the stage for two days of discussing not just the myriad threats the grid faces — and the best ways to secure the grid, both physically and digitally, against them — but also how to respond to and recover from a catastrophic event.
Last week’s summit, hosted jointly with NERC this year, was the largest NATF and EPRI have held and the first one open to non-NATF members, including the press. Andrew Phillips, EPRI vice president of transmission and distribution infrastructure, said 230 people had registered, representing more than 100 different entities from the U.S. and Canada.
The maximum capacity for the conference room: 230. And there were only a few open seats throughout the event.
“Who’s who in the zoo [are] all here,” said Brian Harrell, assistant director for infrastructure security at the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA). “No. 1, I think that’s a testament to this particular conference, and two, it’s showcasing the fact that you all are taking resilience very, very seriously.”
Speakers Stress Collaboration, Info Sharing
A constant refrain among the multiple speeches, presentations and panels was an emphasis on working together and sharing information, both between the public and private sectors, and among utilities.
“I think we really need to advocate for a collective defense: Whether you are a critical infrastructure company, whether you are a citizen of the United States or you are the U.S. government, we are all in this together,” said Harrell, a former director of the Electricity Information Sharing and Analysis Center (E-ISAC). “Your problem quickly becomes my problem. My problem quickly becomes your problem. Duke’s problem quickly becomes SCANA’s problem, which becomes Dominion’s problem, etc.”
The current director of E-ISAC, Bill Lawrence, urged attendees to join the NERC-operated program, noting the effort to improve its web-based tools in the past few years. “Basically, back in 2015, many of your organizations took a hard look at us and said, ‘Hey, ISAC, if [you want us] to use you, you gotta suck less.’”
E-ISAC benefits from the required reporting under NERC’s Critical Infrastructure Protection standards, “but we also need to get that voluntary information sharing,” Lawrence said in a presentation on measuring the program’s effectiveness. “We’re definitely not sitting on … a pile of gold in voluntary shares, but it’s growing, because our vision is to be a world-class, trusted source of quality analysis and rapid sharing of electric infrastructure security information.”
Galloway asked Lawrence if there was anything besides “‘better information sharing’ … that this audience can do to better support you in moving the E-ISAC forward.”
“Other than my catch-all — ‘share more’ — challenge us,” Lawrence answered. He encouraged members to inform the center if they found its resources were not useful to them.
Most of the first day of the event was spent discussing the incident command system (ICS). The concept was originally developed by fire chiefs in several states in the 1970s to provide a common hierarchy and standardized terms among their departments to coordinate their response to wildfires. Now it is used across multiple sectors, companies and institutions to coordinate their responses to emergencies.
“Firefighting is a team sport,” said Wike Graham, battalion chief for the Charlotte Fire Department. He recalled that Carolina Panthers Head Coach Ron Rivera, after observing firefighters put out a fire in his house, compared the incident commander to a coach. “‘They send the plays in, and you watch these guys, they all know what they’re doing and they’re working as a team.’ That’s what ICS is all about.”
An ICS determines who is in charge (the incident commander) among teams from different entities that respond to an emergency — for example, local police, FBI and the military.
“Training military guys to not be in charge is difficult,” said Taylor Cox, senior consultant for business continuity at Xcel Energy. “‘Yes, sir, I understand you were in charge in Iraq. You are not in charge here,’” recalled Cox, a former member of the Army National Guard.
Staff members from several utilities shared their experiences implementing ICS. Manny Cancel, Consolidated Edison’s chief information officer, described how his company used the system to restore power to Wall Street after the terrorist attacks of Sept. 11, 2001. Kathy Bosse, crisis manager for Exelon, said her company used the system during the civil unrest in Baltimore following the death of Freddie Gray in 2015. Others shared their experiences using the system to respond to simulated cybersecurity attacks.
Emergency Communications
The Metcalf attackers, whose motives and identities remain a mystery, cut fiber optic cables less than a mile from the substation, briefly knocking out internet, phone and 911 service in the area. “One of the things that was most troubling is that it was a very deliberate effort to impact communications,” Galloway said.
One panel at the conference focused exclusively on communications during an event in which all other methods are unavailable.
Ross Merlin of DHS gave a presentation on the department’s SHAred RESources (SHARES) high-frequency radio (HFR) program. He began by explaining how HFR works.
“It works by something called ‘PFM.’ It stands for ‘pure freaking magic.’”
Actually, it’s quite simple but, based on the audience’s reaction to the technology, no less impressive. HFR works by bouncing signals off Earth’s ionosphere, the part of the atmosphere that has been ionized by solar radiation, about 80 km above the surface.
Normally, HFR is used for communicating over very long distances. But it can also be used in cases where all short-distance comms are down.
“By using the right antenna, you can make your signal go almost straight up, which sounds useless unless you’re trying to talk to the International Space Station,” Merlin said. But once it bounces off the ionosphere, the signal comes “not just straight down, but kind of like an upside-down ice cream cone,” allowing for communication within a certain radius. Users can send not only voice, but email and images as well.
SHARES has more than 2,600 participants using about 2,300 radio stations, according to Merlin. The program used to be restricted to the federal government only, but “a few years ago we found giant loophole, I mean, we found a way to reinterpret the rules so as to allow state and local government and critical infrastructure and key resources folks to take advantage of this. … The folks you depend on, whatever you have a dependency on to keep going, we can probably get them in here.”
Several attendees representing Canadian utilities said after Merlin’s presentation that they intended to inquire about applying for the program.
Drones
The second day of the conference featured presentations on the threats posed by unmanned aerial vehicles, more commonly known as drones, both those used by utilities for maintenance and those used by the public — or hostile foreign actors.
CISA’s Harrell repeated his warnings against using foreign-manufactured drones from last month’s NERC Reliability Leadership Summit. (See Feds Late to Act on Drone Threat, DHS Official Says.) E-ISAC’s Lawrence advised the audience to “look beyond” the manufacturers from which the federal government is banned from purchasing under the National Defense Authorization Act for Fiscal Year 2019.
There have also been incidences overseas of environmentalists using drones to try to disable electric infrastructure, including one last year in which Greenpeace flew a device shaped like Superman into a nuclear plant in France.
But according to Xcel’s Cox, “nuisance drones,” piloted by careless or curious hobbyists, are the most common threat to utilities.
“A lot of them are like the kid who throws the Frisbee on your roof and just wants his Frisbee back.”
The Federal Aviation Administration has exclusive jurisdiction over what can fly where, meaning utilities that spot drones over their substations or other facilities can’t do much about them except report them. But that doesn’t mean utilities shouldn’t monitor them.
“There are a lot of physical security managers not paying attention because they say, ‘Well we can’t shoot them down anyway, so why should we care?’” Cox said in response to an audience question about what is allowed. “Well a lot of your security folks don’t have arrest authority, and yet we’re still taking pictures of people stealing copper.”
He advised utilities to leave downed drones alone: Blades can easily cut off fingers, and any sim cards could be compromised with malware.
Travis Moran of Welund North America urged audience members to submit comments on FAA’s Advance Notice of Proposed Rulemaking regarding drones, due April 15. Proposed earlier this month under Section 2209 of the FAA Extension, Safety and Security Act of 2016, the rules would allow utilities to apply for airspace restrictions over their facilities.
“2209 is your best interest right now, and you’ve got to get your lobby people off their butts on this,” said Moran, also a strategic partner with SRC/Gryphon Sensors and a member of the Energy Drone Coalition’s advisory board. “I’ve always said you guys get it because you’re already used to the CIP standards and CIP process, so electricity should be the one to lead this. … Get your people on there … or else you know how the government is going to do it. They’re doing it without your comment, and you’re not going to like what you get.”
FERC staff last week issued deficiency letters to all six jurisdictional RTOs and ISOs over their proposed energy storage rules, pressing for definitions, tariff citations and details on issues including metering, make-whole payments, and self-scheduling.
The grid operators are facing a December deadline for compliance with Order 841, which requires them to revise their market participation models to allow storage resources 100 kW and larger to provide capacity, energy and ancillary services within their technical ability.
The deficiency letters by the Division of Electric Power Regulation ranged from eight to 11 pages.
U.S. energy storage deployments by segment | Wood Mackenzie U.S. Energy Storage Monitor 2018 Year in Review
Jeff Dennis, general counsel of Advanced Energy Economy, said in a tweet that the detailed questions “demonstrate that FERC is looking for real compliance with the [requirements] to open the markets to storage, and not just paper compliance. Overall, I think this is a positive development.”
“They have some hard questions that go to the particular issues raised by commenters,” agreed Earthjustice attorney Kim Smaczniak.
Below is a summary of the issues raised by staff. The grid operators have 30 days to respond.
FERC Challenges CAISO on Storage Minimum
FERC cited seven major areas of concern regarding CAISO’s proposal (ER19–468).
Staff wanted the ISO to explain, for instance, how it could reconcile the difference between its own minimum size requirement for storage resources of 500 kW, as noted in a Tariff appendix, with Order 841’s minimum size of 100 kW.
The commission also asked the ISO to explain if “it is CAISO’s position that each of the three participation models — the non-generator resources (NGRs) model, pumped storage hydro units model and demand response model — considered on its own, complies with all of the requirements of Order No. 841.”
FERC then asked the ISO to explain its eligibility requirements for storage resources to provide “all other services the CAISO procures on behalf of its market, including CAISO’s backstop capacity procurement mechanism.” And it requested CAISO elaborate on how it allows storage resources to derate their capacity to meet minimum run-time requirements.
Next, FERC asked CAISO to for an explanation of how “NGRs can be dispatched as supply or demand, set marginal price, self-schedule and otherwise participate fully in CAISO’s markets … [and] that pumped storage hydro resources can be dispatched as supply and demand, set wholesale market clearing prices, and submit bids and self-schedules.”
| SDG&E
It asked the ISO to further describe its mechanisms for dealing with conflicting dispatch signals and for incorporating bidding parameters.
Then it ordered CAISO to cite Tariff provisions that ensure storage resources are charged the LMP for electricity stored for “later resale back to the market” and that the resources’ “charging is accounted for as negative generation” as required by Order 841.
Metering and accounting practices for charging energy rounded out the commission’s concerns.
“Please explain and provide citations to the relevant proposed Tariff language that demonstrates whether the NGR and pumped-hydro storage participation models prevent electric storage resources from paying both the wholesale and retail rates for the same charging energy,” it wrote.
The commission’s deficiency letter (ER19-470) asked the RTO to explain whether a continuous storage facility, if dispatched for reserves rather than energy and as a result experiences lost opportunity costs, would be compensated for its lost opportunity costs.
In addition, FERC asked the RTO to explain its “modified mechanism to permit electric storage resources with one hour or less of energy to provide only energy and not reserves,” and also how the RTO “will implement such mechanism prior to Dec. 3, 2019, the effective date of ISO-NE’s compliance filing.”
FirstLight Power Resources owns the largest pumped-storage hydroelectric plant in New England, the 1,143-MW Northfield Mountain Project on the Connecticut River in Massachusetts. | FirstLight Power Resources
Regarding the physical and operational characteristics, the commission questioned the RTO’s use of the term “maximum discharge time,” saying it “is not a characteristic defined by the commission or defined by ISO-NE.” FERC asked the RTO to either define the term or “confirm that ISO-NE intended this to be written as maximum run time, as defined by Order No. 841.”
The commission also asked whether some continuous storage facilities may have start-up or no-load costs, such as costs for cooling a storage facility that is online but not dispatched. “Could such costs be accounted for through non-zero values in the start-up or no-load cost parameters, similar to other resources that participate in ISO-NE markets?”
The RTO was also asked “to provide specific citations to the relevant existing and/or proposed Tariff sections that demonstrate that binary storage facilities and continuous storage facilities will not receive conflicting dispatch signals to charge and discharge simultaneously.”
— Michael Kuser
Staff Seeks Details on MISO Phased Participation
In an April 1 letter requesting more information on the plan, FERC said it could not process MISO’s Order 841 compliance filing until it clarifies several points regarding its phased participation approach, proposed commitment statuses, complexities for storage resources on the distribution system, conflicting offers and bids, and make-whole payments (ER19-465). MISO has 30 days to respond.
MISO and its stakeholders spent the better part of last year negotiating rules that culminated in a 1,300-page filing. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.) The RTO said it “anticipates significant uncertainty and risks related to the ability of MISO’s system and software to handle the participation of large numbers of very small” energy storage resources. It asked for a “phased approach in the accommodation of very small” storage resources that would limit participation of small storage resources to 50 in the first year of compliance and 150 in the second year.
MISO said that approach would give it time to “further develop and fine-tune its system and software to be able to handle potentially increasing numbers of very small” storage resources.
Harding Street Energy Storage in MISO | AES
But FERC directed MISO to specify what year it expects to provide market access to all storage resources that meet the 100-kW minimum threshold.
MISO must also explain how its must-offer requirement is affected when storage resources elect to use the RTO’s proposed dispatch status of “not participating” or other commitment statuses, the commission said. MISO’s filing proposed that owners of storage resources could choose between several commitment modes, including charge, discharge, continuous, available, not participating, emergency charge, emergency discharge and outage. MISO has said its discharging, charging and continuous modes will carry must-run designations.
FERC said MISO must clarify whether it proposes to levy transmission charges on storage resources when they are charging to resell energy later. MISO must also explain how it will help storage on the distribution system from making double payments — at both retail and wholesale — for charging energy.
The commission also asked if MISO would propose metering practices to manage the “complexities” of selling energy to a storage resource that will then resell the energy at the wholesale LMP.
MISO’s proposal requires storage owners to secure agreements with distribution companies that can deliver stored energy to the transmission system. FERC asked if MISO would require the same agreements when energy is moved from the transmission system to distribution-level storage, and it asked the RTO to explain a provision that prohibits distribution-level storage resources from pseudo-tying into a different balancing authority.
The commission also told MISO to cite Tariff provisions that will allow owners of storage resources to self-manage their state of charge.
FERC additionally said if MISO were to rely on existing Tariff provisions for a storage participation model, it should provide the commission with citations to the applicable market rules and pseudo-tie requirements for transmission-level resources. MISO must also describe how its filing will give storage resources access to all capacity, energy and ancillary service markets, as well as non-market services such as black start, primary frequency response and reactive power.
The commission told MISO to explain how its filing will prevent the same resource from submitting conflicting supply offers and demand bids for the same market interval. It also seeks to know if the participation model allows for make-whole payments when a resource is dispatched as load and the wholesale price is higher than the bid price and when a resource is dispatched as supply and the wholesale price is lower than the offer price. It also asked if resources available for manual dispatch will be eligible for make-whole payments.
Finally, FERC asked MISO to cite how it will allow storage dispatched as supply and demand to set the wholesale market clearing price as both a wholesale seller and buyer, as Order 841 dictates. The commission also asked for citations to support that storage resources can set the price in the capacity market, that MISO will accept wholesale bids from storage owners and that self-scheduled storage resources can participate in the market as price-takers.
The commission’s letter asked NYISO to explain how its dispatch-only model will allow energy storage resources to reflect commitment costs in their bids consistent with other generators, and whether there are any circumstances that could preclude such a resource from effectively managing its capability to meet obligations through bidding (ER19-467).
NYISO said that energy storage resources will not be eligible for dual participation until the ISO develops and implements additional Tariff changes at an unspecified date.
Commission staff also asked whether resources with “limited commercial obligations” such as seasonal retail commitments or other contracts for a portion of the resource’s capacity would be prohibited from participating in the ISO’s markets. Staff also questioned whether a resource could register only a portion of its capacity as storage with the ISO and reserve the remaining capacity for other customers.
FERC’s questions ranged from basic — whether energy storage resources that have start-up costs will have an opportunity to recover these costs — to extremely technical.
For example: “Recognizing that the dispatch-only model alleviates some of the time it takes security-constrained unit commitment (SCUC) to develop a solution, what proportion of the additional time required to solve the SCUC is a result of using a dispatch-only model versus managing these parameters? In other words, could the amount of time saved by foregoing management of these parameters allow for the SCUC to make commitment decisions with an acceptable solve time?”
— Michael Kuser
PJM Queried on Pump Storage, 10-Hour Minimum
The commission cited 10 deficiencies within PJM’s proposal, mostly surrounding how existing Tariff language supports its proposed model for energy storage resources (ER19-469).
The RTO must first clarify how pumped storage hydro resources comply with Order 841, as well as whether a “capacity storage resource” is included in the definition of a “generation capacity resource” and whether one unit can serve as both.
Earthjustice’s Smaczniak said the question indicates FERC is “pushing back” on PJM requirement that storage offering capacity would have to continuously supply energy for 10 hours, which critics have called onerous. ISO-NE sought a two-hour supply, while NYISO proposed a four-hour minimum.
“So I read this as a very positive development for Order 841 implementation!” Smaczniak said.
The commission also wants existing Tariff citations that detail how the RTO will manage electric storage resources, including eligibility for nonsynchronous reserves; exemption from the day-ahead scheduling reserve process; participation in Tier I synchronized reserves; and eligibility for reactive service.
Invenergy’s 31.5-MW Grand Ridge Energy Storage project is 80 miles southwest of Chicago. | Invenergy
The RTO must also clarify whether a capacity storage resource is included in the definition of generation capacity resource as detailed in Schedule 9 of the Reliability Assurance Agreement. The commission wants more information on the “rules and procedures [that] specifically recognize the unique characteristics and capabilities of capacity storage resources and their relative ability to ‘maintain output at stated capability over a specified period of time.’”
PJM must also explain why storage resources deemed “out of charge” wouldn’t be considered an outage.
FERC wants to see the specific Tariff language detailing the process for dispatching and self-scheduling energy storage, as well as how the resources can participate as price-takers. Definitions for charge, discharge and continuous mode must also be submitted.
PJM must also detail the annual process energy storage resources must undergo when selecting a participation model and the corresponding Tariff revisions. FERC staff requested more detail regarding how the RTO will avoid conflicting dispatch and how resources in “continuous mode” will serve as demand and supply simultaneously.
FERC also seeks insight into how PJM determines which energy storage resources are eligible to receive make-whole payments, as well as how the RTO’s proposed model accounts for minimum state of charge, maximum state of charge, minimum charge time, maximum charge time, minimum run time and maximum run time in existing bidding procedures.
PJM must also explain how operators will use telemetered state of charge in day-ahead and real-time markets and why the RTO believes market sellers don’t have to submit minimum charge time, maximum charge time, minimum run time and maximum run time for situational awareness. FERC wants to know if resources can self-manage their state of charge and the penalties for deviating from their dispatch schedules.
The commission also appears skeptical over PJM’s position that metering requirements found in Manual 14D apply to energy storage resources because the cited language focuses specifically on telemetry for generators.
— Christen Smith
SPP Queried on LSE Rules
SPP’s initial response to Order 841 noted that it does not have a capacity market, but that load-serving entities are subject to a resource adequacy requirement. It said LSEs may designate capacity resources, including storage resources, to satisfy that requirement if the resource meets “the continuous run time requirement applicable to all resource types.”
The commission asked SPP to define the “continuous run time requirement” and to identify and describe any additional technical, operational or performance requirements resources must meet in order to qualify as a capacity resource “satisfying an LSE’s resource adequacy requirement” (ER19-460).
SPP also told FERC that it does not “directly meter” facilities as the order requires to ensure a storage resource resells energy back to the market at the wholesale LMP. Instead, the RTO said, meter agents submit settlement meter values directly to SPP, and it proposed that, “consistent with the handling of pseudo-tied resources, the actual meter values of distribution-sited market storage resources may be split among the retail and wholesale use by the meter agent in both real time and for settlement.”
The commission requested SPP explain how its “metering and accounting practices” would comply with Order 841 by ensuring the energy would be resold back to the market at the wholesale LMP and that storage resources would be prevented from paying twice for the same charging energy. FERC also asked how the handling of metering and accounting for distribution-sited storage resources would be “consistent with the handling of pseudo-tie resources.”
The commission asked SPP to address deficiencies in three other areas, including storage resources’ participation in the markets as simultaneous supply and demand. SPP’s proposed tariff revisions would have storage resources “not continuously dispatchable across 0 MW” choose between offering supply or bidding in demand for a given market interval.
FERC requested SPP define a market storage resource that is “not continuously dispatchable across 0 MW,” and to explain why including the resources’ start-up time constraints in their offer parameters does not allow the RTO to accommodate resources’ simultaneous supply offers and demand bids in a given market interval.
The commission asked SPP to clarify how a storage resource will “self-charge” in the Integrated Marketplace, given that the RTO said it does not have a mechanism to explicitly manage their state of charge and “that it does not propose to add any such mechanism.” FERC also asked for clarification on whether proposed provisions to “decommit self-committed charging resources” to address insufficient capacity in the day-ahead and intraday reliability unit commitment processes apply to all storage resources or only to “market storage” resources.
FERC last week denied requests by New York state officials and the Sierra Club for rehearing and stay of its determination that the state had waived its authority to issue or deny a water quality certification for the Northern Access natural gas pipeline (CP15-115-004).
National Fuel Gas Supply’s proposed 97 miles of pipeline would be capable of carrying about 500 MMcfd of gas from western Pennsylvania to the Buffalo area and also interconnect with the TransCanada pipeline.
The commission last summer ruled that the state Department of Environmental Conservation had waived its authority to issue or deny a water quality certification under Section 401 of the Clean Water Act by failing to act within one year of receiving National Fuel’s application.
Map shows facilities in a portion of the proposed Northern Access pipeline. | National Fuel
The case hinges on the date of receipt of the application, which FERC asserts was March 2, 2016, but which the DEC contends was changed by agreement with National Fuel to April 8, 2016. The department denied the application on April 7, 2017.
In its April 2 ruling, the commission faulted the DEC for citing cases that address waiver of rights in criminal proceedings, saying, “by contrast to the statutory schemes at issue in the cases cited by New York DEC, the Section 401 deadline cannot be waived by agreement.”
The commission cited Hoopa Valley Tribe v. FERC, in which the D.C. Circuit Court of Appeals considered whether waiver occurs when there is a written agreement to delay water quality certification. The court concluded that such an agreement constituted a failure and a refusal to act under Section 401.
“Hoopa Valley Tribe determined that a ‘deliberate and contractual idleness’ not only usurps the commission’s ‘control over whether and when a federal [authorization] will issue’ but would contravene Section 401’s intended purpose, i.e. to prevent a state’s ‘dalliance or unreasonable delay,’” FERC said.
National Fuel remains “committed to the project” and intends “to request a notice to proceed from FERC once all necessary authorizations are secured,” including permits from the U.S. Army Corps of Engineers, company spokeswoman Karen Merkel said.
The project faces a number of legal challenges that are currently pending in different venues. The targeted in-service date is 2022, Merkel said.
Cattaraugus Creek in western New York is one of 192 streams crossed in the state by the Northern Access pipeline route. | National Weather Service
In denying the DEC and Sierra Club their motion for a stay of the waiver order, the commission said, “The movant must substantiate that irreparable injury is ‘likely’ to occur. The injury must be both certain and great, and it must be actual and not theoretical. Bare allegations of what is likely to occur do not suffice.”
The commission also dismissed the DEC’s assertion that a state environmental assessment’s finding that the pipeline would have no significant impact — and a subsequent conditional certificate authority — were no longer valid given the department’s denial of the water quality certification. The DEC had argued that the environmental assessment assumed the existence of certain mitigation measures, including those set out in a future water quality certification.
“On balance, the Northern Access 2016 project, if constructed and operated in accordance with the application and environmental conditions imposed by the certificate order, would not significantly affect the quality of the human environment and would be an environmentally acceptable action,” the commission said.
The SPP–MISO Joint Planning Committee has voted to begin a new coordinated system plan (CSP) this year, SPP staff told the RTO’s Seams Steering Committee last week.
The JPC, composed of planning staff from both RTOs, conducted the vote in March. The CSP is the first step in determining whether to build transmission projects that address interregional needs.
SPP Interregional Coordinator Adam Bell told the SSC during its Wednesday meeting that the RTOs’ planning staffs are exchanging solutions submitted through their regional processes for the CSP “joint” needs. Staff are also finalizing a draft CSP study scope, he said.
The RTOs have not yet scheduled a meeting to share initial results with stakeholders, but they have identified six potential economic projects along the seam. (See MISO, SPP Seek Coordinated Plan in 2019.)
“We’ve identified modeling inconsistencies, but our models are always going to be different,” Bell said. “Once we posted the needs, that’s when both sides began looking into the models.”
The study could result in a first-ever interregional transmission project for the RTOs, which conducted CSP and regional reviews in 2014 and 2016. They were unable to reach an agreement on interregional projects both times.
Switchable Generation Plan with ERCOT Almost Complete
The grid operators have been working since 2016 on a new agreement to cover the four resources capable of switching between SPP and ERCOT. The plan applies only to the operations of the reliability coordinators and does not address financial obligations of the SWGRs directed to switch in emergency conditions, RTO staff said.
SPP’s Market Working Group will be responsible for developing new commitment statuses and a mechanism to uplift financial obligations of SWGRs instructed to switch to SPP from ERCOT.
Two of the resources belong to Golden Spread Electric Cooperative and have historically operated in SPP. The other two resources belong to Tenaska and operate in ERCOT.
M2M Payments Soar to $3.33M in February
SPP recorded $3.33 million in market-to-market (M2M) payments from MISO in February, the highest amount since last March and the ninth-highest since the two RTOs began the process in March 2015.
February also marked the 23rd month in the last 29 in which M2M distributions have flowed in SPP’s direction. SPP has now amassed $58.6 million in net payments from MISO.
| SPP
Permanent flowgates along the SPP-MISO seam were binding for 244 hours, and temporary flowgates were binding for 245 hours. That resulted in $1.98 million and $1.35 million in payments, respectively.
Casey Cathey, the RTO’s manager of reliability planning and seams, told the SSC that staff hope to discuss with MISO potential changes to the M2M process. “My personal view is to optimize the system for congestion, rather than this clunky process,” he said.
Having met its current carbon reduction goal ahead of schedule, Entergy now says it plans to further slash emissions over the next decade to well below levels seen 20 years ago.
In a report issued Wednesday, Entergy said it is “intensifying” its efforts, pledging to reduce its CO2 emission rate to 50% below 2000 levels by 2030. If achieved, the company would produce about 24.6 million short tons of annual emissions, compared with 36 million short tons in 2017.
The announcement was rolled into Entergy’s 2018 Integrated Report, which combines the company’s annual shareholder report with its sustainability report. The company has already surpassed its previous commitment to reduce emissions to 20% below 2000 levels by 2020.
“The broad consensus of current scientific data on climate change indicates that, as an industry, we must do more to reduce our footprint and that of our customers and communities. Entergy sees this not as a choice but as a responsibility and an opportunity,” Entergy CEO Leo Denault wrote in a letter to stakeholders. “Speaking plainly, this means that for every unit of electricity we generate in 2030, we will emit half the carbon dioxide we did in 2000.”
| Entergy
In 2018, Entergy’s utility-only CO2 emission rate was 763 pounds/MWh, lower than the national average of 1,009 pounds/MWh. The 2018 emissions rate represented a 28% reduction from 2000.
Since announcing its portfolio transformation strategy in 2002, Entergy says it’s replaced almost 30% of its older generating assets. Natural gas-fired generation now represents 60% of the company’s more than 25 GW in generating assets.
While Entergy is not releasing a supply plan, it did say the new goal could mean a supply mix that’s 60% natural gas, 32% nuclear, 7% renewable and slightly more than 1% coal.
Entergy estimates it currently has about 1 GW of renewable projects in “various stages of development.”
Denault added that Entergy’s 8.8-GW nuclear portfolio is a “critical source of safe, large-scale and virtually emission-free baseload power” that could make or break the company’s sustainability goals. Preserving the plants is crucial, he said.
Those statements come at a time when Entergy is seeking to offload two nuclear units outside its service territory to a subsidiary of Holtec International. Entergy expects to complete the sales of the Pilgrim plant in Massachusetts by the end of 2019 and Palisades plant in Michigan by the end of 2022. The sales are part of the company’s strategy to exit the merchant power business and re-establish itself as a pure-play regulated utility.
Entergy also released a separate analysis and risk assessment on climate change. The company concluded it should focus on coastal wetland restoration, renewable generation, grid modernization, emergency response, energy efficiency and electric vehicles. It also said it’s designing facilities that can withstand flooding and extreme weather events.
| Entergy
The company is simultaneously planning for load reduction, as customers invest in distributed resources, and load growth, from increased demand for cooling and refrigeration. It expects climate change impacts to be “especially pronounced” in coastal Louisiana and Texas, where risks from sea level rise, damaging storms and coastal erosion are highest. The company also predicted “potentially disproportionate” impacts for its low-income customers.
None of the four states in Entergy’s utility service territory has passed carbon emissions regulations, though Texas has a renewable portfolio standard and New Orleans has published a climate action plan aimed at halving emissions by 2030. However, Entergy predicts that a federal carbon tax will soon become a reality.
Entergy said it would hold off on making plans around any technologies it might adopt until they prove cost-effective.
“Some of the technologies viewed as necessary to reduce greenhouse gas emissions consistent with a 2-degree [Celsius] scenario do not exist today. Others currently are not commercially viable and would require significant resource investments to adopt at a scale that is cost-competitive with conventional generation resources,” Entergy said.
The company also said simply halving its total emissions by 2030 isn’t feasible. To meet a 50% net reduction in emissions by that time, the company said it would have to increase its zero-carbon generation from the current 37% of the fleet mix to nearly 55% by 2030. One analysis showed Entergy would have to add 9.8 GW of solar capacity and 5.3 GW of battery storage in order to achieve the reduction, a scenario the company deemed unrealistic.
New York officials, utilities and solar energy advocates are trading comments through the state’s Public Service Commission on what constitutes appropriate compensation for the capacity value of distributed energy resources (VDER) (Case 15-E-0751; 15-E-0082).
The comments come after the PSC in December issued a staff whitepaper regarding capacity value compensation and in January ruled that John F. Kennedy International Airport could have a solar project up to 5 MW compensated under the VDER program while having other solar projects dedicated to serving on-site load (Case 18-E-0766). (See NYPSC Clarifies Value Stack Capacity Limits.)
In the value stack white paper, Department of Public Service staff recommend replacing the market transition credit (MTC) model, a value based on installed capacity estimates, with a new “community credit” model to compensate participants of community distributed generation (CDG) projects.
The commission’s original VDER order in March 2017 directed that the state’s compensation scheme for eligible DER transition from net energy metering (NEM) to the value stack, which bases compensation on provided benefits. The PSC’s Jan. 17 declaratory ruling said, “The rated capacity of projects used solely for serving on-site load and not seeking compensation under the value stack or net metering should not be counted towards the rated capacity limit.”
Rate Design
The DPS’ Utility Intervention Unit (UIU) filed comments that addressed rate designs for post-NEM mass market customers — those with eligible on-site generation.
“The proposed rate relies in part on advanced metering infrastructure (AMI) capability, which New York utilities have not yet fully implemented,” the UIU said. “Thus, to the extent that AMI is required to participate in this rate, the proposal appears premature.”
The Clean Energy Parties (CEP) — an ad hoc group including the Solar Energy Industries Association, Coalition for Community Solar Access, Pace Energy and Climate Center, Natural Resources Defense Council, New York Solar Energy Industries Association and Vote Solar — filed comments supporting DPS staff’s recognition “that some aspects of the tariff, such as DRV [demand reduction value], were achieving a false sense of accuracy and recommends changes that will better align the financial signals sent to customers with the benefits they can provide to the distribution system.”
A 2-MW solar project at Mohawk Valley Community College was supported by a grant from the New York State Energy Research and Development Authority. | NYSERDA
The group said that for more than a year they have “made the case that the current tariff does not accurately reflect the value of distributed energy resources or provide stable enough compensation.” The state’s utilities show “a surprising misunderstanding of the development process for medium-sized to larger-sized solar energy facilities,” it said.
Utilities — including Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas and Electric — dismissed New York City’s advocacy of a higher MTC for Con Ed as unnecessary.
In addition to the 18 MW of projects identified in Tranche 0/1 as of March 1, 2019, Con Ed’s interconnection queue contains an additional 84.7 MW of eligible projects, including 42.5 MW of fuel cell projects, the utilities said. Because fuel cells are expected to operate at capacity factors in excess of 90% and achieve a high coincidence with the DRV, they will have the same cost impact as roughly 255 MW of solar installations, they said.
Resource Eligibility
The PSC last September expanded the eligibility of DER to be compensated under the state’s value stack tariffs, particularly standalone storage systems with 5 MW or less of capacity, including crediting to any clean generation technology that qualifies as a Tier 1 resource under the Clean Energy Standard (CES).
The new rules also make resources eligible for compensation that would qualify for Tier 1 but for their start date before Jan. 1, 2015, and also authorize interzonal crediting, allowing DERs receiving value stack compensation to apply credits to the bills of customers in the same utility territory but different NYISO load zones. (See NYPSC Takes Subway into Value Stack.)
In responding to the white paper, the utilities suggested that, rather than exposing customers to long-term commitments that provide limited customer benefits, DRV compensation should be tied to DER production during each utility’s service territory-specific peak hours.
“To the extent that the current 10-peak-hour window creates more volatility than is deemed necessary to support development of eligible resources, a modest expansion to 50 hours may be appropriate,” the utilities said. “Similarly, the [state’s] Office of General Services argues that behind-the-meter generation should also be eligible for value stack compensation. This proposal should be rejected as customers using generation to offset their usage are already avoiding distribution and energy charges.”
The utilities opposed creating a community credit, but if one is established, they also oppose the recommendation by large commercial and industrial end-users that its costs be allocated only to residential customers, favoring instead the same methodology as the MTC, which allocates costs to those customer classes that receive the benefit.
They also recommended that the PSC reject the CEP’s suggestion to establish a Distribution Planning Advisory Committee, saying that “such a committee is unnecessary and would duplicate the existing Distributed System Implementation Plan Advisory Committee” and also create an additional burden on stakeholder resources.
Texas regulators last week praised ERCOT for its response to stakeholder criticism over how it handled an early March cold-weather event that prompted it to ask generators to reschedule planned outages.
Market participants publicly aired their concerns with ERCOT during a Technical Advisory Committee meeting March 27, arguing that the grid operator did not give the market a chance to work and that it had not adequately shared its insight into the market. (See ERCOT Generators Upset over Early March Weather Event.)
Since then, ERCOT has begun assembling a task force that will consider improvements to communications and procedures during anticipated emergency conditions; increasing the market visibility of ERCOT forecasts; reviewing how planned outages are delayed or withdrawn; and whether to develop cost-recovery mechanisms for outages postponed or canceled because of reliability reasons.
That was enough for the Texas Public Utility Commission to wave off a presentation by ERCOT Senior Director of System Operations Dan Woodfin during its open meeting Thursday. Woodfin had planned to deliver the same presentation he gave during two hours of discussion before the TAC.
“I’m happy to see you have a process now and you’re working on it,” Commissioner Arthur D’Andrea told Woodfin. “That’s promising to restore some confidence in the market and make some changes.”
“I would like the market participants to work this out at ERCOT, like we typically do,” PUC Chair DeAnn Walker said. “ERCOT acknowledges they can do things better. I’ve told everyone I’m not interested in going back and punishing anyone for anything that happened. I don’t want anyone dwelling on putting more arrows in Dan, because he got more than he deserved at TAC.”
The PUC opened a proceeding on ERCOT’s outage scheduling processes (Project 49378) and was moved to action after South Texas Electric Cooperative filed a complaint. STEC said it received an instruction to reschedule an outage at its 400-MW, lignite-fueled San Miguel plant less than 12 hours before maintenance work was to begin.
“ERCOT exercised what amounts to a free capacity call option … at great risk to both those generators and the market that have to perform maintenance or risk being subject to forced outages during the period of the lowest reserve margins the ERCOT market has ever seen,” STEC said.
Oncor ARR Reduced by $218M
The commission consented to Oncor’s request to reduce its annual revenue requirement by $218.8 million as a result of the Tax Cuts and Jobs Act of 2017 (Docket 48325).
The PUC directed Oncor to apply a 3.25% carrying charge to the amount of federal income tax expense it collects above the amount it would have collected since Jan. 1, 2018.
The commission also consented to staff’s wholesale transmission service charges for transmission and distribution service providers operating in the ERCOT system (Docket 48928).
Sempra-Oncor-Sharyland Hearing
The PUC held a prehearing conference Monday to accept exhibits for its April 10-12 hearing on proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities, and Sharyland Distribution & Transmission Services (Docket 48929).
The companies in October announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)
AEP Texas, Oncor Propose Asset Swap
AEP Texas and Oncor have filed an application with the PUC requesting transfer to AEP Texas of Oncor’s distribution assets and associated certificate of convenience and necessity rights in the Rio Grande Valley cities of McAllen and Mission (Docket 49402).
Under the proposal, AEP Texas would acquire Oncor’s distribution assets, valued at about $18 million, and about 54,000 retail distribution customers. Oncor acquired the customers during an asset swap with Sharyland Utilities in 2017. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)
