NERC is offering SPP’s 128 registered entities a chance to comment after assigning them all to a new Regional Entity.
The reassignments became necessary when the SPP RE announced its dissolution in July, addressing NERC and FERC concerns over its reliability oversight role. (See SPP to Dissolve Regional Entity.) Responses are due back to the organization by Jan. 5.
NERC said it received 122 transfer requests spanning five REs, with six entities expressing no preference for a “transferee” RE. The organization placed most of the registered entities into the Midwest Reliability Organization (MRO), with 13 Arkansas, Louisiana, Mississippi and Missouri entities assigned to SERC Reliability.
Arkansas Electric Cooperative Corp., which provides power to Arkansas’ 17 distribution cooperatives, was placed in both MRO and SERC.
In a message to the registered entities, RE President Ron Ciesiel said it was the RE’s “understanding” that NERC is on target to present final transferee recommendations to the organization’s Board of Trustees at its February meeting.
“We believe there is a high probability the transfer can be completed in the July time frame,” Ciesiel said.
After an initial review and analysis of entity requests, NERC said it determined that granting all the requests “would neither result in effective and efficient administration of compliance and enforcement activities, nor a cohesive functional alignment to support and promote BPS [bulk power system] reliability and security.”
In reviewing the requests, NERC considered the location of an entity’s BPS facilities in relation to the geographic and electrical boundaries of the transferee RE. The agency also assessed the impact of a proposed transfer on other BPS owners, operators and users, including affected reliability coordinators, balancing authorities and transmission operators, as appropriate.
NERC said it recognized that its procedural rules do not contain criteria for “the allocation of multiple registered entity transfers” when an RE dissolves, so it used criteria from another rule for considering requests. The organization reviewed each transfer request using that criteria and other “entity-specific circumstances.”
When NERC’s recommendations differed from the entities’ requests, it contacted the entities and explained its rationale, the agency said.
Created in 2007, the SPP RE is responsible for auditing and enforcing NERC reliability rules in three balancing authorities: SPP, the Southwestern Power Administration and parts of MISO.
SPP said it is dissolving the RE in part because the RTO’s expanded footprint no longer aligns with the RE’s territory. However, FERC criticized SPP in a 2008 audit for failing to ensure the RE’s independence from the RTO.
Calling 2017 a “tumultuous year for SPP RE,” Ciesiel told its registered entities that RE staff, while working at reduced levels, achieved its highest ever metrics performance.
“A good way to close out the year for us,” he said.
The dissolution is expected to be completed by the end of next year.
ERCOT’s reserve margins may be tightening, but executives on Monday assured reporters that all is well with the Texas grid.
The ISO’s year-end Capacity, Demand and Reserves (CDR) report projects a 9.3% planning reserve margin for 2018, half of what it was in the May report and 4 points below the 13.75% target ERCOT established for itself in 2010. But during a conference call with media, staff described the CDR report’s reserve margin projections as a “snapshot in time” and detailed a list of tools available to handle any emergencies.
“The reserve margin that comes out of the CDR is a snapshot,” said Warren Lasher, senior director of system planning. “Reserve margins are expected to fluctuate in the current market design.”
The May CDR reported an 18.9% reserve margin for next summer. Since then, Vistra Energy has said it would retire about 4 GW of coal resources and ERCOT has reported a year’s delay in completing construction of almost 4 GW of planned capacity. (See Vistra Energy to Close 2 More Coal Plants.)
| ERCOT
Lasher pointed out that since 2010, the Public Utility Commission of Texas has directed ERCOT to develop a new standard for determining the planning reserve margin, similar to a 2014 Brattle Group study on estimating “economically optimal” margins that minimize total system and operating costs. The ISO is currently conducting its own study, which it intends to complete in the third quarter of 2018 before reporting back to the PUC, Lasher said.
| ERCOT
“I wouldn’t call [the CDR] cause for concern,” he said.
ERCOT expects 14 GW of resources to be in service by 2020 and will still have 77.2 GW of capacity on hand to meet a 2018 summer peak demand forecast of almost 73 GW. That would break the August 2016 record peak of 71.1 GW.
Demand is expected to grow at a 1.7% average annually over the next 10 years. The reserve margin is expected to increase to 11.7% by summer 2019, peaking at 11.8% in 2020 before dropping to 9% in 2022. Total capacity is expected to reach almost 83 GW in 2022.
“We see these types of shifts as the ERCOT market experiences cycles of new investments, retirement of aging resources and growing demand for power,” CEO Bill Magness said in a statement.
If the worst comes to worst, Lasher said ERCOT can always request emergency assistance across DC ties with Mexico or the Eastern Interconnection, or fall back on interruptible customers and switchable units obligated to other regions.
The December CDR report includes information about existing and planned generation resources and expected energy needs over the next 10 years. The report does not include the potential additional migration of nearly 600 MW of load should Lubbock Power & Light and Rayburn Country Electric Cooperative eventually migrate customers from SPP into the Texas grid. (See “ERCOT, SPP to Coordinate Second Load-Migration Study,” PUCT Briefs: Aug. 17, 2017.)
MISO is reviewing an expedited project request from American Transmission Co. to connect a massive Foxconn manufacturing plant that would be Wisconsin’s largest power user.
ATC’s proposed $140 million Mount Pleasant Tech Interconnection Project is one of the first two expedited review requests for MISO’s 2018 Transmission Expansion Plan. Along with a small substation upgrade in Minnesota that the RTO has approved, the project was presented to stakeholders at Tuesday’s Planning Advisory Committee conference call, days after MISO’s Board of Directors approved MTEP 17.
ATC has proposed a new 345/138-kV substation, 14 miles of new 345-kV line and four short 138-kV underground lines to connect a southwestern Wisconsin manufacturing plant proposed by Foxconn to We Energies supply.
Foxconn, headquartered in Taiwan, is the world’s largest electronics manufacturer, responsible for building Apple mobile devices, Amazon Kindles and video game consoles.
Its factory will be similarly outsized. Wisconsin Gov. Scott Walker has framed the $10 billion plant, which is expected to create as many as 13,000 jobs, as a “once-in-a-century opportunity” and called for it to be operating by 2020. ATC has said the plant will require up to six times as much power as the next-largest manufacturing facility in Wisconsin.
ATC hopes to get the $10 billion plant connected to the grid by the end of 2019 and plans on ordering some long-lead time equipment beginning in February. It said MTEP 18 approval would arrive too late for its planned construction timeline.
The company said it received the load interconnection request from WE on Oct. 12. MISO posted ATC’s expedited request on its website Dec. 6, although it is not clear when the RTO received it.
MISO is still studying the implications of the request and will convene a Technical Study Task Force meeting in January to go over study results with stakeholders, according to Lynn Hecker, manager of expansion planning.
ATC plans to seek project approval with the Wisconsin Public Service Commission in February, with hope for approval in August.
In addition to the new substation, ATC plans to string a new 12-mile, 345-kV circuit from Pleasant Prairie to Mount Pleasant, Wis., and create two 1.2-mile, 345-kV loops into the new substation on existing transmission structures. The project also includes the construction of four new 138-kV underground lines at less than a mile apiece connecting the Mount Pleasant substation to the manufacturing plant.
Minn. Capacitor Bank
Meanwhile, MISO has already studied and approved a much smaller substation upgrade in Minnesota, making it the first expedited project approval in the 2018 package.
The project — a $500,000, 14.4-MVAR capacitor bank addition to a substation in southern Minnesota — is expected to be in service by the end of January, according to developer Great River Energy. Capacitor banks counteract a power factor lag or phase shift in a power supply.
MISO recommended the project be granted expedited status in MTEP 18 as a baseline reliability project because the substation is currently susceptible to low voltages when a generator outage is followed by a line outage, a NERC-defined contingency. The project will also improve local area voltage performance in general, Hecker said.
Developers of renewable energy and emerging technologies are predictably supportive of CAISO’s vision for the grid of the future, but operators of more traditional resources say the proposal drifts outside the ISO’s purpose of assuring reliability and managing markets.
The nearly 200 pages of comments on CAISO’s Vision 2030 paper illustrate concerns about the ISO’s changing grid mix, laying out arguments that the transition is coming at the expense of reliability, fair markets and reasonable costs to ratepayers.
CAISO’s Board of Governors and management published the discussion paper in October, saying it was “intended to help focus discussion on both technical and policy issues involved in decarbonizing and decentralizing electric service.” The document identified California energy trends over the next 12 years, including more efficient energy use, a significant decline in gas-fired generation, more variable energy resources, decentralized service, regional collaboration and integration of electric vehicles. (See CAISO Symposium Panelists Talk Grid of the Future, Western RTO.)
The Independent Energy Producers Association, which includes both fossil fuel and renewable interests, suggested that CAISO had wandered from its core mission and is picking winners and losers by focusing on decarbonization and distributed resources.
“Overall, we find the Vision Paper not particularly helpful in illuminating what, if anything, the CAISO management will be ‘tasked’ to accomplish over the near term, e.g. one to five years, related to the CAISO’s primary function to maintain 60 Hz on the electric transmission grid and administer just and reasonable wholesale markets,” said IEPA CEO Jan Smutny-Jones, a former CAISO board chair.
The group urged the ISO to focus on accessing low-cost, transmission-connected renewables. It also complained that while the California Public Utilities Commission’s integrated resource plan assumes that about 30,000 MW of gas-fired generation will not be subject to retirement because of environmental rules by 2030, CAISO’s paper makes no accommodation for sustaining those resources.
“The evidence clearly recognizes a need for this type of generation (flexible capacity), yet the market provides little if any means to ensure that competitive resources that can provide these necessary services are available to the CAISO when and where needed. Importantly, the Vision Paper is silent on what, if anything, CAISO intends to do to address this matter,” the group said.
The California Municipal Utilities Association (CMUA) filed brief comments saying that issues identified in the paper, such as energy efficiency, vehicle electrification and economic impacts, “may all have an indirect impact on how the CAISO operates the grid. But the policies and choices inherent in each of these issues are not the CAISO’s core function, which is critical and complex [in its] own right without these additional challenges.”
CMUA Executive Director Barry Moline mentioned reliability-must-run agreements, the congestion revenue rights auction and the fact that most load-serving entities in the Western U.S. are vertically owned utilities that regulators want to remain in business.
“The CAISO should be cautious when opining on these issues of industry structure, rather than focusing on its core functions, as it seeks to expand collaboration beyond California,” Moline said.
NRG Energy, which operates some fossil fuel plants, said that relying on natural gas plants in constrained areas “is environmentally preferable to spending large amounts of money to eliminate those resources.” CAISO recently determined that NRG’s proposed Puente power plant would be the cheapest alternative out of a mix of alternative resources, but the company suspended its application after the California Energy Commission indicated it would not approve the plant. (See CEC Members Recommend No-Go for Puente Plant.)
NRG also noted that many topics in the paper are outside of CAISO’s traditional role, such as developing a new zero-energy building plan and shaping the state’s resource adequacy plan, which is under CPUC jurisdiction.
In Powerex’s comments to the ISO, CEO Teresa Conway promoted “forward arrangements” for flexible capacity and renewable integration. The Canada-based power marketer is due to join the CAISO-run Energy Imbalance Market (EIM) in April 2018. (See FERC Approves Powerex EIM Agreement.)
“We believe the pursuit of forward arrangements, along with expanding short-term energy markets like the EIM, can be an effective strategy for unlocking the capabilities of existing clean resources outside of California, and in particular the unique capabilities of northwest hydro systems,” Conway said. She said the state is at a “critical point” in the transformation of its energy grid and “the initial approaches responsible for the state’s success cannot be scaled indefinitely, and signs of renewable integration challenges are already present.”
Increased regional electricity trade and coordination will provide economic and environmental benefits by meeting customer needs with the cheapest resources, Powerex said, but increased coordination must accommodate differing and sometimes conflicting policy goals.
Powerex proposed establishing a “clean” resource adequacy requirement, aggressively pursuing storage, expanding forward commitment and procurement, and accurately measuring California’s greenhouse gas emissions associated with out-of-state resources.
Southern California Edison said it is not sure it agrees with CAISO’s assessment that, by 2030, demand-side resources will be as important as supply in balancing the system. About 4,500 MW of San Diego peak load will need to be met with supply sources, and “similar conclusions apply to loads in the SCE and [Pacific Gas and Electric] distribution service areas.”
| CAISO
SCE said it supports a “well-designed” carbon cap-and-trade program and properly implemented regionalization, including a Western states committee advisory body.
The Public Generating Pool, which represents 10 publicly owned utilities in Oregon and Washington, gave a regional perspective as other states look to possibly join markets operated by CAISO. California’s neighboring states have more hydro and coal resources and traditional cost-based utility regulation.
“The broad nature of this document and the numerous recommendations for policy, however, do not seem to fit the expected role of the CAISO as an independent system operator,” the group said. “If there are future versions of this document, it would be helpful for the CAISO to be more specific about its role relative to California legislature and state agencies.”
But the ISO’s vision did get solid support from some corners. The California Electric Transportation Coalition said, “We agree with and support Cal ISO’s emphasis on transitioning from fossil fuels to electricity in the transportation sector.” The group said that EVs will be increasingly important to manage load and store excess renewable generation. The ISO’s plan stated that California cannot reach its greenhouse gas reduction goals without electrifying the fossil energy now used in buildings and vehicles.
Arizona-based First Solar, which develops utility-scale photovoltaic modules, offered praise for the CAISO board’s effort to provide a “guiding vision” for strategic planning. And while the company agreed with the “trends and solutions” offered in the paper, it also urged the ISO to consider transmission needs for renewable integration goals.
“Again this year, the CAISO is not addressing additional policy-driven transmission projects in its Transmission Planning Process, creating potential problems for the increased interconnection of renewables required to meet California’s policy goals,” First Solar said.
The CAISO board issued a statement of appreciation for the comments Tuesday, saying they “will be valuable input into the ISO’s ongoing strategic planning process.”
California regulators have approved new measures aimed at wildfire prevention, as utilities face growing scrutiny over fires that have occurred in the state over the last decade.
At its meeting in San Francisco on Thursday, the California Public Utilities Commission also approved a solar incentives program targeting low-income residents, among other decisions. But the CPUC deferred a vote on the retirement of the Diablo Canyon nuclear plant, which has sparked disagreements around the recovery of shutdown costs. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)
Focus on Wildfires, Utilities
The CPUC approved more stringent wildfire protections for utilities, creating a “high fire-threat” district where correction of fire safety hazards will be prioritized.
“This is one of the areas where we are working hard to be at the forefront of utility safety programs” and represents “a major rewrite of the fire prevention rules for utility poles,” CPUC President Michael Picker said.
“Most of the elements here are not specifically driven by climate change, but they accept and acknowledge that the scope of the problem is changing,” Picker said, noting that high-hazard fire zones have grown to 44% of the state landscape. The decision requires new vegetation management and more stringent wire-to-wire clearances, among other measures.
Speaking during the public comment period, Southern California Edison President Ronald Nichols told the commission that the Thomas Fire in the Los Angeles area is threatening transmission lines and has caused some outages, but only about 500 customers have been affected. The company issued a press release Dec. 11 saying that state investigations “now include locations beyond those identified last week as the apparent origin of these fires. SCE believes the investigations now include the possible role of its facilities.”
Recent fires in California, including the massive Thomas Fire, have been particularly destructive and increased the focus on utilities over their possible role. (See California Fires Spark CAISO Transmission Emergency.) The CPUC recently denied San Diego Gas & Electric’s request to recover the costs of 2007 fires from ratepayers. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) Pacific Gas and Electric is also facing investigation and lawsuits over the October fires in Northern California.
Low-income Solar Program
The CPUC passed a measure that implements the framework for a solar incentive program for multifamily housing, including goals, funding, administration and creating a new statewide program administrator. The program is to be financed by $100 million annually from PG&E, SDG&E, SCE, Liberty Utilities and PacifiCorp’s greenhouse gas auction proceeds.
The measure implements Assembly Bill 693, passed in 2015, which creates the Multifamily Affordable Housing Solar Roofs Program. The incentive program will be run by the new administrator and subsidize the costs of solar generation on certain types of multifamily affordable housing. It will allocate net energy metering tariff credits associated with the system’s generation to tenants and common areas of the property. The bill established the program for low-income households that would otherwise be unable to install on-site solar generation.
Picker expressed concerns over the long-term viability of the program because of tax proposals currently under consideration in Congress. Commissioner Martha Guzman Aceves was assigned the initiative.
Guzman Aceves cast the lone “no” vote against a proposed statewide marketing and outreach program for residential rate reform, which was assigned to Picker. The CPUC opened a rulemaking to examine investor-owned utilities’ rate structures, the transition to time varying and dynamic rates, and other statutory obligations.
CPUC Resolutions on CCAs, RMRs
The decisions at the CPUC’s regular meeting came in a week when the agency separately issued several new resolutions that received attention in the industry.
Another resolution sets up a vote next month in response to controversial reliability-must-run agreements signed between CAISO and Calpine to keep the company’s Yuba City and Feather River natural gas units online. The CAISO Board of Governors expressed reservations about the agreements, funded by ratepayers, when it approved them last month. (See Board Decisions Highlight CAISO Market Problems.) The increasing use of RMRs is drawing negative attention for keeping natural gas units operating when they would otherwise retire.
Finally, the CPUC on Friday issued a proposed resolution that would place a moratorium beginning Jan. 11, 2018, on new commercial and industrial customer gas connections in the Los Angeles County area that would rely on Southern California Gas’ Aliso Canyon storage facility.
VALLEY FORGE, Pa. — American Municipal Power last week continued its criticism of PJM’s grid spending, grilling utility officials during a marathon Transmission Expansion Advisory Committee meeting.
Scheduled for four hours, Thursday’s meeting lasted closer to five as Ryan Dolan, AMP’s director of transmission planning, asked technical questions about nearly every project presented and at one point accused American Electric Power of attempting to increase its revenue by overbuilding.
“The reason I was hired at AMP was to control their transmission costs,” said Ed Tatum, AMP’s vice president of transmission, who joined the company two years ago from Old Dominion Electric Cooperative. In September, he hired Dolan — from AEP — to aid his effort.
“AMP has put in place the human and transmission modeling resources to enable us to review and assess PJM and the Transmission Owners’ plans and ask the necessary technical questions to support the need for a project,” Tatum said.
‘Minimum’ Information Required
The TEAC session followed a Planning Committee meeting at which AMP presented templates illustrating the “minimum” information it needs to evaluate projects.
Tatum said he did not “try to orchestrate” the long meeting or “filibuster” to make his point. Without the information requested, he said, “we’re not going to have any choice but to ask those questions” and “we’re probably going to be here until 6 o’clock” next month as well, he said. “The meetings could be done in a couple hours if the information on the examples we provided was available sufficiently in advance.”
The TEAC meeting was surprising for its length, but not its content. Dolan and Tatum have led a customer pushback on the more than $1 billion in transmission projects that get discussed at monthly TEAC meetings before being authorized for construction by PJM’s board through the Regional Transmission Expansion Plan. Their frustration is also on display at meetings of the Transmission Replacement Processes Senior Task Force, where they argue for increased engagement with TOs on when to determine that transmission infrastructure needs to be replaced and how to do it. (See New Wave of PJM Transmission Upgrades Rankles AMP.)
TOs argue that their networks are theirs to maintain as they see fit, but AMP, ODEC and other customers contend that as the ones paying the bills, they should have a say.
Tatum had proposed presenting the project information templates at the TEAC, but PJM moved it to the PC because that is where all discussions on the planning procedure take place. Tatum hopes the move indicates that PJM will organize a discussion on the topic.
“At this point, I’d like to see how that discussion goes,” Tatum said after the meeting. “We would hope that we be able to get more transparency.”
PJM appeared amenable to discussing AMP’s information demands. Staff agreed to add the issue to next month’s PC agenda.
“Clearly what we’re doing now is not sustainable,” said Paul McGlynn, PJM’s administrator of the TEAC.
Confidentiality
TOs have previously raised legal concerns with discussing confidential details of transmission projects in open meetings and did so again on Thursday. Alex Stern of Public Service Electric and Gas said that because issues involving PJM and TO compliance with FERC Order 890 are awaiting a FERC decision, there is a limit on how much TOs can discuss. (See Load Blocks TO Effort to Extend Hiatus of PJM Transmission-Replacement Talks.)
“All of this raises some legal issues as well, so before we go back to the PC, you might want to confer with” PJM’s legal team, he said.
Dolan and Tatum said they understand confidentiality and security concerns and suggested that when there are multiple projects with Critical Energy Energy/Electric Infrastructure Information (CEII) information, PJM could hold meetings restricted to stakeholders with CEII clearance so that the information can be discussed.
Layering Impacts
The pair said several AEP and PSE&G projects discussed at the TEAC highlight their concerns.
AEP is planning to replace its Tidd 345/138-kV transformer on the Ohio-West Virginia border, about 45 miles west of Pittsburgh. The 150-MVA unit, which was manufactured in 1957, was taken out of service in March. The new unit will be increased to 450 MVA and include a series reactor on the low side to mirror a parallel transformer, at a cost of $7.8 million.
Dolan said the project description failed to explain whether the proposal sizes the reactor appropriately for future short-circuit changes. “Are we going to see an issue in five years? Four years? Two years?” he asked. Tatum later questioned whether AEP planned ahead when it replaced the facility’s breakers to account for a second breaker.
AMP argues that TOs’ supplemental projects — which are based on their internal criteria and don’t require PJM authorization — can create reliability issues that necessitate baseline projects, which are directed by the RTO’s criteria and do require board authorization. The lack of information makes it impossible to evaluate how a supplemental project impacts individual equipment on the system because stakeholders are only made aware after a piece of equipment is overloaded, AMP said. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“The lack of this information concerns us because by putting in a bunch of supplemental projects, the transmission owners can be bringing the system up to a point where the [NERC criteria] would soon require baseline reliability upgrades,” Tatum said.
| PJM
PJM has said its abiding principle in planning for increased grid resiliency is “do no harm.”
“What do you consider ‘do no harm’?” Dolan asked. “The only organizations that are aware of the impacts, power-flow-wise, of these supplemental projects are the TOs that are submitting them and PJM.
“Stakeholders are not getting an opportunity to review the impact of these projects. The only time that there is any sort of review done is if those projects actually create overloads,” he said. “What we are interested in is to understand the incremental [system power flow changes associated with these projects]. … We have concerns about the layering of projects … which change system impedances and responses that drive [future baseline] overloads.”
Selective Criteria
At the Broadford station in southwestern Virginia, AEP is planning to spend $102 million installing six new breakers and replacing seven breakers, a reactor and two transformers that are showing signs of imminent failure. Dolan argued the additional breakers were unnecessary and will protect nothing that isn’t already protected by the existing breakers.
AEP has similar situations at its Kenzie Creek, Cloverdale and Desoto stations, he said, but chose not to increase protection there. Kenzie Creek is in Michigan about 20 miles north of South Bend, Ind., Cloverdale is in Virginia and Desoto is northeast of Muncie, Ind.
“You’re willing to spend money when you’re able to get away with it,” Dolan said to AEP representatives who called into the meeting. They denied the accusation and said they use discretion when applying their criteria.
“Even though the projects involve circuit breakers’ replacement, the optimal solution for each is unique,” AEP’s Kamran Ali said in an email to RTO Insider.
The difference, he said, is that nearly all the 138-kV breakers need to be replaced at Broadford, so it makes sense — from a cost, reliability and outage perspective — to build a new 138-kV yard. Adding the “separation of protection zones” at that time is both cost effective and efficient, whereas the other projects only require individual equipment replacements that make separation of protection zones “neither prudent nor cost effective,” Ali said.
Dolan wasn’t satisfied.
“They are not being consistent, and they are not being consistent about information they do not provide to the public,” Dolan said. “I’m starting to notice that this is unique to certain states.”
Dolan said AEP is planning similarly excessive breaker installs at the Axton station, also in Virginia.
“It is most cost-effective to tailor the asset replacement solution to the scope of the project and the specific site conditions. This is not the result of inconsistent approaches, but a commitment to deliver solutions that address the need in the most cost-effective manner for our customers,” Ali said in his email. “Applying a rigid approach that does not recognize the differing situations could lead to higher costs, lower reliability, and less efficient projects for our customers.”
Maintenance Questioned
Other stakeholders joined Dolan in questioning PSE&G’s $546-million rebuild of its 53-mile Roseland–Branchburg–Pleasant Valley corridor. David Mabry, who represents the PJM Industrial Customer Coalition, noted that two of the photos of degraded equipment included in PSE&G’s documentation were date-stamped September 2013. Stakeholders questioned why PSE&G waited four years to present the violation of its FERC Form 715 criteria, which allow TOs to determine what factors indicate when its facilities should be replaced.
Roseland — Branchburg — Pleasant Valley Transmission Tower Damage | PJM
Dolan argued it might be because the shortened repair timeline designates the project as “immediate need,” which ensures PSE&G will be able to replace the infrastructure itself and the project won’t be eligible for competitive bidding.
“One of two things is happening: We’ve either chosen not to address it back then and customers could have been put at risk [of service interruptions], or we waited until we could make the determination that it is immediate need,” Dolan said. “By driving everything to immediate need … you’re preventing opportunities for competition. … When we have a lack of competition, we have an excessive amount of costs.”
Stern and PSE&G colleague Esam Khadr disagreed with the “immediate need” characterization, saying it went through a condition assessment as outlined in Form 715 procedures, including independent analysis by an outside consultant.
“These particular pictures may have been from 2013, but the line continued to be maintained and provide service while condition assessments per the FERC Form 715 procedures were only recently completed,” Stern explained.
Dolan said this is a pattern with PSE&G projects.
“I have yet to see a [Form 715] project come forward that is not immediate need when they bring it forward,” he said.
In an email to RTO Insider, Stern responded that “AMP can’t have it both ways.”
“They can’t profess to want TOs to maintain facilities for as long as viable, performing assessments and maintenance for as long as possible and then when condition assessments indicate that that is no longer viable, assert that the project should have been brought sooner. The Roseland-Branchburg-Pleasant Valley line is one of the original lines dating back to the formation of PJM 90 years ago. It has been maintained for decades and provided steady, reliable service on behalf of customers through that entire time. It has certainly done its job. However, condition assessment clearly reveals that it is in need of replacement, and replacement under these circumstances is the correct and cost-effective approach for customers.”
Sharon Segner of LS Power also questioned the timing of the proposal, saying the project should be opened for competitive bidding under FERC Order 1000.
“It very well may be the solution,” she said. “What I’m questioning is the process.”
Stern later noted that “FERC Form 715-driven projects are exempt from competitive bidding processes pursuant to FERC orders.”
AMP’s proposed project information templates received endorsement from Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS).
“The consumer advocate offices are well aligned with AMP,” Poulos said.
PJM Response
PJM staff attempted to divert project questions to its newly formed online Planning Community, providing a refresher on the group’s purpose.
“It’s not a dead letter office,” PJM’s Fran Barrett said.
But Dolan disagreed, complaining that he hasn’t received responses in that forum.
“I’ve submitted a whole slew of questions [to both the planning community and directly to PJM], and just writing them down doesn’t get them answered. My question is: Even if we write them down are they going to get answered?” he said. “I have not received a response to everything [asked], and in fact, we’ve been told we’re not getting an answer” to some questions.
PJM presented several charts documenting transmission projects including one that showed AEP, Dominion Energy and PSE&G proposing many supplemental projects, which are not competitively bid.
| PJM
“I understand the visuals here, but I don’t think this is enough information to draw conclusions about individual transmission owners and their [Form] 715 criteria,” PJM’s Sue Glatz said.
I’d like to thank Energy Secretary Rick Perry for granting, albeit ungraciously, new FERC Chair Kevin McIntyre’s request for 30 days to clean up one of the biggest piles ever dumped on FERC’s doorstep. As The Economist said last week: “In the fierce competition for the federal government’s worst policy, this is a contender.”[1]
Perry’s letter came the same day coal magnate Bob Murray said two totally opposite things: One, he can sell all his coal to China no problem.[2] Two, “we must have” the Perry plan immediately.[3] Setting a new bar for cognitive dissonance.
Perry’s letter included a lot of saber rattling. Like maybe he’s going to do something before or even after FERC acts.
Perry’s Legal Authority is Slim to None, and Slim Left Town
The saber rattling is interesting because those pesky lawyers already told Perry that Federal Power Act Section 202(c) can’t support what he’d like to do on his lonesome to prove his fealty to Donald Trump and Trump acolytes like Murray.
Apparently, Perry is contemplating ignoring the lawyers after all, going ahead with destroying competitive markets and imposing a carbon tax on consumers.
Now you may be thinking: “Steve, the last thing the Trump administration would impose would be a carbon tax.”
But, Kemosabe, this is not a tax on carbon; this is a tax for carbon. A new kind of carbon tax — accelerating climate change.
Of note, FPA Section 202(c) has three prerequisites: (1) emergencies, (2) shortages and (3) temporary situations.[4]
So Perry would need to prevaricate about all three.
It would be the energy equivalent of the Holy Roman Empire, which, as Voltaire quipped, wasn’t holy, Roman or an empire.
FirstEnergy, the 2003 Blackout and the Davis-Besse Catastrophe
I have some space left and don’t want to neglect the co-cheerleader for the Trump-Perry tax: FirstEnergy, the utility primarily responsible for the 2003 Northeast Blackout.
Yes, the same FirstEnergy that used the words “resilience,” “resilient” and “resiliency” 2,031 times in its comments to FERC.
A prior column talked about how FirstEnergy’s Sammis coal plant isn’t baseload, nor retiring prematurely, no matter how many hundreds of times FirstEnergy abused the words “baseload” and “premature” in its FERC comments.
Today, let’s talk about FirstEnergy’s Davis-Besse nuclear plant. Another of the power plants that FirstEnergy wants bailed out yet again, after its plants first got billions in “stranded cost” payments and then got even more money to support FirstEnergy’s credit rating.
Did you know Davis-Besse was down during the 2003 blackout that FirstEnergy caused? Yes it was.
And it was down for two years. So much for nuclear plant resiliency — 90 days fuel supply and all that poppycock.
Why was it down? Boric acid corrosion had eaten a cavity completely through a 6.63-inch-thick carbon steel reactor pressure vessel (RPV) head down to a 3/16-inch inner liner of stainless steel cladding, which miraculously held until the cavity was finally discovered. Had that last 3/16 of an inch been eaten away or collapsed before detection and shutdown, it could have been really bad news.
Close up view of boric acid corrosion | NRC
The corrosion had occurred over a number of years. As the Nuclear Regulatory Commission stated: “The licensee allowed accumulations of boric acid to remain on the RPV head even though Procedure NG-EN-00324 directed their removal.”[5]
This became a poster child for nuclear negligence, and the basis for NRC fines of $5.5 million[6] and Securities and Exchange Commission fines of $28 million.[7]
Here’s where things get relevant for today. Repairs and replacement power cost hundreds of millions of dollars. How much of that was “capitalized,” i.e., added to Davis-Besse’s rate base upon which FirstEnergy now wants a return? I ballpark that at $100 million based on the increase in total plant costs between the end of 2001 and end of 2004, relative to the increase for the Perry nuclear plant that didn’t share the Davis-Besse experience.
This $100 million is the tip of the iceberg. More recently, FirstEnergy spent another $600 million on Davis-Besse.[8]
If that $600 million had turned out to be a good investment, FirstEnergy would have kept mum and kept the money. But it hasn’t turned out so good, so FirstEnergy wants customers to bail it out. Yet again.
Heads I win, tails you lose. Hugely.
Wrapping Up
Remember the Wisconsin utility executive who famously said the utility business is the only one where you can make more money from redecorating your office?[9] If the Trump-Perry tax happens, we’ll know a utility can make even more money from causing a near nuclear catastrophe, and making more bad investments after that.
PJM must amend interconnection service agreements (ISAs) to allow two merchant transmission facilities to convert from firm to non-firm service, FERC ruled Friday, the latest reverberation resulting from the cancellation of the Con Ed-PSEG “wheel.”
The commission’s orders could relieve Hudson Transmission Partners (HTP) (EL17-84) and Linden VFT (EL17-90) from hundreds of millions in cost allocations under PJM’s Regional Transmission Expansion Plan.
Linden VFT’s exterior | Joseph Jingoli & Son
The commission said the companies’ ISAs, signed with PJM and transmission owner Public Service Electric and Gas, were unjust and unreasonable because they did not allow the merchants to convert firm transmission withdrawal rights (TWRs) to non-firm TWRs that are subject to curtailment.
HTP owns a 660-MW, 345-kV underwater HVDC line that connects PJM in northern New Jersey and NYISO in New York City. FERC issued a show cause order after PSE&G rejected its request to convert 320 MW of firm TWRs to non-firm. (See Rejecting PJM ‘Wheel’-related Requests, FERC Sets Inquiry.)
Linden VFT’s interior | Energy Initiatives Group
Linden VFT, which operates three 105-MW variable frequency transformers between the PSE&G system and Consolidated Edison, filed a complaint after PSE&G rejected its request to convert 330 MW of firm TWRs to non-firm.
The two merchant projects were part of a decades-old service agreement between PSE&G and Con Ed that the latter terminated in April. The service “wheeled” 1,000 MW from Upstate New York through PSE&G’s facilities in northern New Jersey and into New York City.
Following termination of the wheel, PJM asked FERC to reassign $533 million in costs related to the Bergen-Linden Corridor project to HTP, which the commission approved on April 25.
Under PJM’s Tariff, merchant transmission facilities are assigned the costs of the network upgrades that would not have been incurred “but for” their interconnection request. Merchant facilities also are responsible to pay annually for the costs of any post-interconnection network upgrades needed to support the merchant’s firm TWRs.
“We see no reasonable basis for barring HTP from converting from higher quality firm TWRs to lower quality non-firm TWRs by amending the existing ISA,” FERC said. “HTP already has satisfied the interconnection requirements, and we find that requiring it to maintain such firm TWRs for the life of the merchant transmission facility is unjust and unreasonable in the absence of any operational or reliability basis for doing so.”
The commission dismissed PSE&G’s allegation that reducing the service level would harm reliability.
“Under the existing ISA and PJM’s Tariff, PJM must guarantee that its transmission system is robust enough to permit HTP to use its firm TWRs to export 320 MW of power from its source in PJM across the river to New York at all times. Converting those firm TWRs to non-firm TWRs imposes no additional obligation on PJM and, in fact, is less burdensome in that PJM will no longer have to guarantee that its transmission system can support such use,” the commission said. “In any case, HTP’s line is fully controllable by PJM so that PJM can shut off flows if those flows jeopardize reliability or cause operational problems in New Jersey or elsewhere on the PJM system.”
FERC also rejected PSE&G’s contention that allowing the change would undermine the interconnection process. The commission said PSE&G’s argument that it relied upon the long-term duration of the existing ISAs was “unpersuasive,” noting that the merchants had unilateral rights to terminate the ISAs at any time.
The commission rejected as beyond the scope of the cases a request by PJM’s Independent Market Monitor to change Schedule 12 of the Tariff. The Monitor said the changes were needed to address what it called a discrepancy in the cost responsibility assignments for RTEP projects for merchant transmission providers that hold firm point-to-point transmission service and those that hold firm TWRs.
“Those general concerns with Schedule 12 do not address whether [the merchants] should be permitted to convert” their firm TWRs, FERC said.
The commission ordered PJM to file the revised ISAs in seven days from the Dec. 15 orders. Chairman Kevin McIntyre, who was sworn in Dec. 7, did not participate in the order.
Batteries have the unique potential to provide a broad range of valuable services to the grid. If operators are able to control the battery in a way that simultaneously captures multiple value streams, the resulting “stacked benefits” can amount to significantly more revenue than pursuing any individual stream in isolation. In some cases, those benefits can justify battery investment at today’s costs.
The potential for batteries to provide stacked benefits was challenged in a Dec. 5, 2017, RTO Insidereditorial titled “Grid Batteries & Kool-Aid, Once More with Feeling,” by Steve Huntoon. That article includes a critique of a report that I developed with colleagues at The Brattle Group, in which we quantify the multiple value streams that could be captured from batteries in California.[1]
| The Brattle Group
Huntoon’s article makes four basic points when arguing against the feasibility of stacked benefits. However, there are nuanced conceptual problems with each of those four points.
Combined Energy and Capacity Value
First, the Huntoon article argues that energy price arbitrage value cannot be added to capacity value, because “a battery cycled daily for energy arbitrage is going to be partially or totally discharged most of the time” and therefore unavailable to provide capacity. This assumes that all reliability events occur instantaneously, with no warning. In fact, system operators commonly provide notice prior to a reliability event and can often anticipate events in advance by tracking and forecasting supply and demand. Such notification would allow the battery operator to charge the battery and fulfill its commitment. Further, in the event that the timing of battery dispatch for energy value is not coincident with reliability needs, the modeling behind our study has accounted for that impact.
Capacity Value
The Huntoon article suggests that batteries cannot provide capacity value because reliability events often last longer than four hours (which was the assumed battery capacity in our study). However, system operators typically establish a performance duration that resources must satisfy in order to qualify as a capacity resource. The required performance duration is only three hours for “peak ramping” and “super peak ramping” resources in CAISO’s “flexibility capacity” products, for instance.
In fact, a battery with even less availability would still have capacity value. For example, the dispatch of two batteries each with two-hour capacity could be staggered in order to provide four hours of discharge. In the U.K., the government recently proposed a novel approach in which batteries are given capacity credit that is a function of their duration. Batteries with four-hour duration would receive the full allowed capacity credit. Batteries with less duration would receive a prorated credit.
To the extent that any individual day would have resource needs that are greater than four consecutive hours, that is accounted for in our study, and the capacity value of the battery was derated accordingly.
Energy Value
Huntoon’s article questions the extent to which battery operators could predict the highest priced hours of each day and discharge the battery during those hours. It is certainly true that battery operators will not have perfect foresight into market prices. However, system operators will schedule batteries in energy markets to minimize system costs. Our modeling is based on a realistic assumption that this dispatch will align reasonably well with high priced hours. Additionally, self-scheduling resources could use day-ahead prices as a guide for bidding into the real-time energy market, and potentially benefit from the higher price volatility in that market.
Frequency Regulation
The Huntoon article points out that frequency regulation is a shallow market with limited need. This is true, and is explicitly acknowledged in our report.[2] At the same time, early movers in many markets have provided significant value by using fast-responding batteries to provide this service. Frequency regulation (and other ancillary services) could become increasingly important in the future as more intermittent renewable resources must be integrated into the power system.
Additionally, in recognition of the current limited need for frequency regulation, we included a sensitivity case that assumed no incremental value from the frequency regulation market. In that case, the stacked value of the battery still exceeded $200/kW-year.
| The Brattle Group
A point that is not raised in the Huntoon article, but which is important to consider when assessing the value of energy storage, is the impact that large quantities of energy storage deployment could have on energy and capacity market prices, thus impacting the incremental value of additional storage resources. Our California study was focused only on the incremental value of 1 MW of storage. However, a study by my Brattle colleagues in the ERCOT market included detailed modeling that accounts for the effect of these market impacts on the stacked value.[3] The study identified a significant amount of economic energy storage potential, as well as a number of barriers to achieving that potential.
Capturing the Potential
Our study in California was intended to illustrate the potential system value of stacked benefit streams from battery storage in the absence of existing barriers. There certainly will be challenges to capturing this potential. To fully tap into this value, market rules may need to change, regulatory constructs may need to be revised, retail rates may need to be redesigned and technical challenges will need to be addressed.
But to paraphrase Theodore Roosevelt, “Nothing worth having comes easy.” In the power industry, initial skepticism about emerging technologies is regularly overcome through technological improvements and market and regulatory adjustments; just ask demand response providers, which have developed significant and valuable wholesale market resources over the past decade. In this case, the potential stacked value of battery storage is real and too significant to simply ignore.
Ryan Hledik is a Principal in The Brattle Group’s London office. He specializes in the economics of policies and technologies that are focused on the energy consumer. Mr. Hledik holds a Master’s Degree in Management Science and Engineering from Stanford University, and a Bachelor’s Degree in Applied Science from the University of Pennsylvania, with minors in Economics and Mathematics.
VALLEY FORGE, Pa. — PJM’s Independent Market Monitor faced a barrage of questions last week at the final stakeholder evaluation of its capacity market proposal ahead of a vote at Thursday’s Markets and Reliability Committee meeting.
Monitor Joe Bowring was absent for the first half of the meeting, leaving his chief counsel, Jeffrey Mayes, to answer whatever he could. Many were technical, however, and had to await Bowring’s arrival.
PJM offered stakeholders no assistance, making it clear from the start that its facilitation of the meeting did not indicate its support of the proposal. The Monitor’s MOPR-Ex proposal was the only one among 10 debated at the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) to receive the task force’s endorsement and automatic consideration at the MRC.
After a year of meetings at the CCPPSTF, many stakeholders decided they preferred the current capacity design to any of the proposals, but they feared PJM would file its own two-stage repricing proposal in the absence of a clear endorsement by stakeholders. They believed that the RTO’s repricing proposal, which isolated subsidized generation offers from competitive ones by administratively reorganizing auction results, was such a drastic change that it could not be undone once implemented, while the Monitor’s proposal, which would extend the minimum offer price rule (MOPR), was as close to the status quo as possible.
The MOPR-Ex proposal would allow exemptions for many unique circumstances, including public power facilities and generators subsidized through states’ renewable portfolio standards, but it would not include Illinois’ zero-emission credit (ZEC) program. That doesn’t sit well with Exelon, which stands to benefit the most from the ZECs and whose own repricing proposal was rejected by the task force.
Exelon’s Jason Barker peppered the Monitor with questions about revisions to the RPS exemption that were inserted after the CCPPSTF endorsed it. Those revisions will be proposed at the MRC as an alternative to the endorsed version.
He asked Mayes if ZEC programs, designed to curb air emissions like other states’ renewable energy programs, qualify as “renewable” under the proposal. Mayes said no.
“We don’t understand the rationale of that program,” Mayes said. “The definition of ‘renewable’ is not all that complicated.”
The reason for the revisions, he said, was that programs that incented one type of renewable energy, such as wind or solar, are acceptable, but being preferential to a certain type of technology to harness that energy, such as offshore wind or rooftop solar, was not.
“It’s ironic that we’re trying to protect against states picking winners and losers and drafting tariff language that picks winners and losers,” Barker said. “They’d have the same effect on the marketplace, but one would be mitigated and one would not.”
The exemption calls for the inclusion of some programs based on the date of their implementation.
“It’s called ‘grandfathering.’ You’ve never heard of it?” asked Ruth Ann Price, who represents Delaware’s Division of the Public Advocate. “What Jason is trying to do is he’s trying to show some discrimination. I get it.”
Barker and his colleague Sharon Midgley also questioned revisions that prohibited supply from affiliates but allowed public power to overbuild facilities and then have the excess capacity exempted from the MOPR floor price.
Bowring acknowledged some of the concerns and said he would consider ways to address them in a revised final proposal.
The situation is complicated by a ruling from FERC that struck down the MOPR that PJM has been using since 2013 and on which the Monitor based its proposal. (See On Remand, FERC Rejects PJM MOPR Compromise.) The previous iteration of the rule was limited to gas-fired units and included fewer exemptions, and PJM has indicated it’s planning to allow that version to largely go back into effect with enhancements to calculation methods that have been developed since it was implemented.
Bowring, however, was unconcerned.
“I think the MOPR-Ex aligns explicitly with the order,” he said.
“They seemed to pretty emphatic that extending the mitigation period would be more costly,” Barker said, referring to FERC’s denial of an extension of the MOPR mitigation from one year to three years.
Bowring said the mistake was in using a floor price that was designed for a new unit for the subsequent years after the initial mitigation. Had the floor been switched to being based on the units’ net avoidable cost rate, it would have been consistent, he said.
