CAISO’s straw proposal for procuring black start resources would entail significant collaboration with affected transmission owners.
The draft plan also calls for costs to be allocated to the transmission owner area in which the black start resource is located, rather than across the entire CAISO footprint, as the ISO initially considered.
The ISO developed the proposal after identifying a need for additional black start resources in the transmission-constrained San Francisco Bay Area, which is served by Pacific Gas and Electric. (See CAISO Kicks off Initiative to Procure Black Start Resources.)
CAISO’s developed the black start procurement proposal to address a need to better prepare the transmission-constrained San Francisco area for system restoration. | Visit California
Black start resources serving the Bay Area are relatively far from population centers, unlike in Southern California, where capability is more evenly distributed near major load centers and can provide a more rapid restoration.
The ISO’s initiative represents the second phase of a 2013 undertaking to address NERC reliability standard EOP-005-2, which requires transmission operators to develop plans for system restoration following blackouts.
Under the proposal, CAISO and the TO would jointly develop specifications describing the requirements and selection criteria for the black start resource. Criteria could include generator minimum load, the unit’s proximity to critical loads, interconnection voltage, megawatt output and reactive power capabilities and type of unit.
Responses to the subsequent procurement would be turned over to the TO, which would evaluate them against the selection criteria and then submit a written recommendation to CAISO.
The ISO would then evaluate the TO’s recommendation and approve or reject the choice. Once a resource is approved, CAISO would begin the contracting process with both the black start resource owner and TO.
“The length of any contractual commitment by the ISO and the black start service provider carry different risks and benefits to each party,” CAISO said in its proposal. “A longer commitment term to the ISO will provide greater certainty of sufficient black start capability, but the ISO may also want reasonable exit provisions to address changes in circumstances.”
CAISO is considering basing compensation on a cost-of-service approach rather than providing a capacity-type payment sufficient to support an otherwise unprofitable generator in operation.
“These arrangements should be expected to provide some reasonable expectation of cost recovery and margin to the black start service provider, but predicated on the basis that the resource is providing an incremental service — as opposed to an RMR [reliability-must-run] arrangement,” the ISO said.
CAISO is also considering a standard five- or 10-year contract with a clause requiring one year’s notice for termination in order to provide sufficient time to obtain a replacement resource or reach an RMR agreement to keep the contracted resource in place until a replacement is in service.
Under the proposal, the ISO would allocate the black start contract costs to the host TO, which could then recover the expense from its customers through its reliability services rate schedule. The ISO will likely need to revise its own Tariff to include black start services in the schedule.
“CAISO recognizes this approach would allocate incremental black start costs to all transmission customers within a PTO [participating transmission owner] transmission access charge area. However, to the extent this capability assists in restoring the PTO’s system, all transmission customers will benefit from this restoration,” the ISO said.
CAISO has scheduled a Feb. 21 call to discuss the proposal and is asking stakeholders to submit comments by Feb. 28. ISO staff are specifically seeking input on the proposed contract terms.
PJM’s Board of Managers on Wednesday approved more than $1.5 billion in transmission upgrades, led by a project to rebuild aging lines in Burlington, Mercer and Middlesex counties in New Jersey.
The project, in the territory of Public Service Electric and Gas, will replace transmission equipment as old as 80 years. It will rebuild and upgrade the 138-kV lines in the Metuchen-Edison-Trenton-Burlington corridor to 230 kV.
“The growing need to replace aging infrastructure, energy efficiency and the resulting reduction in the growth of demand for electricity are affecting transmission development,” PJM CEO Andy Ott said in a statement. “The current round of projects approved by the board reflects the trend.”
Other projects approved include transformer replacements and line rebuilds in the PSE&G, Metropolitan Edison, PPL, American Electric Power, Dominion, and Duke Energy Ohio and Kentucky areas.
PJM has now authorized more than $30.8 billion in transmission additions and upgrades in its Regional Transmission Expansion Plan since 2000.
PJM’s Board of Managers on Wednesday approved more than $1.5 billion in transmission upgrades, led by a project to rebuild aging lines in Burlington, Mercer and Middlesex counties in New Jersey.
The project, in the territory of Public Service Electric and Gas, will replace transmission equipment as old as 80 years. It will rebuild and upgrade the 138-kV lines in the Metuchen-Edison-Trenton-Burlington corridor to 230 kV.
Helicopter repairing transmission line | PSEG
“The growing need to replace aging infrastructure, energy efficiency and the resulting reduction in the growth of demand for electricity are affecting transmission development,” PJM CEO Andy Ott said in a statement. “The current round of projects approved by the board reflects the trend.”
Other projects approved include transformer replacements and line rebuilds in the PSE&G, Metropolitan Edison, PPL, American Electric Power, Dominion, and Duke Energy Ohio and Kentucky areas.
PJM has now authorized more than $30.8 billion in transmission additions and upgrades in its Regional Transmission Expansion Plan since 2000.
Stakeholders have lingering questions about CAISO’s proposal to protect small transmission owners from bearing the costs of network upgrades needed to interconnect generation serving load outside their service territories.
While the proposal was introduced to accommodate the specific circumstances faced by Valley Electric Association, the most recent draft allows CAISO to apply the plan to other small TOs that may join the ISO in the future. (See CAISO Issues Final Plan for Small TO Interconnection Costs.)
It was the ISO’s effort to retain that flexibility that prompted most stakeholder concerns.
“If we’re really trying to make this specifically helpful for this particular instance, it makes a lot of sense for us to make this as narrowly applicable as possible,” John Newton, a regulatory analyst at Pacific Gas and Electric, said during a Feb. 13 call to discuss the proposal.
Under the proposal, CAISO would examine case-by-case whether a TO should be allowed to fold low-voltage generator interconnection costs into high-voltage transmission revenue requirements — which would spread those costs across the ISO’s full rate base to avoid burdening ratepayers of small TOs with outsized fees.
Without the change, a $5 million network upgrade would increase Valley Electric’s low-voltage transmission access charge (TAC) by 18.75% to $7.44/MWh, said Steve Rutty, CAISO’s director of grid assets. A $25 million upgrade would nearly double the utility’s low-voltage TAC to $12.15/MWh.
The table shows the approximate increase in each TOs low-voltage TAC for network upgrade costs on their respective systems under CAISO’s current cost allocation methodology. | CAISO
By contrast, spreading the $25 million upgrade across the entire ISO would result in a 0.09% increase in the combined high-voltage and low-voltage TACs for Valley Electric and PG&E, while Southern California Edison would see a 0.06% bump.
Proposed Criteria
The ISO will determine eligibility for the relief based on whether the TO is:
Very small relative to other TOs, with a gross load of 2 million MWh or less (currently about 2.2% of the load of the ISO’s largest TO);
Located in a renewable resource-rich area gaining “elevated” interest for generator procurements; or
Not subject to a renewable portfolio standard or does not need the new interconnecting generation to meet that requirement.
Joseph Abhulimen, program and project supervisor at the California Public Utilities Commission’s Office of Ratepayer Advocates (ORA), wondered how the ISO landed on the 2 million MWh threshold, nearly triple Valley Electric’s load.
“Why is that number significant?” Abhulimen asked.
“Originally, in the draft proposal, we had proposed 5% [of the largest TO’s load], which would’ve equated to around 4 million MW,” Rutty said. “It would allow a utility such as [Valley Electric] to really significantly increase their size.”
Some stakeholders thought the 5% figure was too generous, Rutty explained, so the ISO narrowed it down to closer to 2%.
“We also wanted an even number, so we picked 2 million [MWh],” Rutty said. “The reason why we’re sticking at a fixed number is so that it’s not a moving target on them. As you know, loads change over time.”
The ISO was also concerned that a lower gross load threshold could subject relatively small TOs — and their ratepayers — to sharply increased low-voltage TAC rates once they exceeded the cap, Rutty noted.
‘Resource Rich’
Abhulimen also wondered about how the ISO would determine what qualifies as a “resource-rich” area. “What is the primary determinant for that designation?” he asked.
Bill Weaver, CAISO senior counsel, said the term was intended to allow case-by-case, rather than formulaic, determinations.
Stakeholders “can go to our board, they could comment at FERC, and we could really make a case-by-case determination whether we think someone meets this criteria, rather than trying to establish a bright-line test that may prove infeasible for future areas,” Weaver said.
“I’m still very concerned that I would have expected that there would be certain criteria established that would say that this particular [TO] is in a resource-rich area for X and Y reasons,” Abhulimen said. “It’s very hard for someone to comment on this particular principle when you don’t know what criteria were used to make this determination.”
Kallie Wells of Resero Consulting stumped ISO staff with a question about whether the proposal would apply to TOs that don’t serve any load.
“Most likely that would be something we would have to take up on a case-by-case basis with a different set of criteria,” Rutty said. “I don’t know that we would have any low-voltage, transmission-only type [TOs] that would be under 200 kV under those scenarios. But if it did come into play we would have to take a look at it at that time.”
PG&E’s Newton wondered how the new proposal would apply with the potential for the ISO to expand into other parts of the West. “Do you anticipate that is policy will apply broadly?” he asked.
Rutty replied that it — and anything in the Tariff — would be applied to similarly situated customers.
“That said, we’re not hiding anything here,” Rutty said. “We’re not trying to sneak this in. We have no new [TO] with less than 2 million MWh in the pipeline for [TO] participation.”
Gaming Concerns
Charles Mee of the California ORA posed what he called an “extreme” hypothetical situation in which a small TO contracts with external resources to serve all of its local load while all generation within its area is contracted to serve load in other TOs — thereby evading any upgrade costs being rolled into its low-voltage TAC.
“So do you consider all the generators that, contractually, are not serving the local load be qualified for this treatment?” Mee asked.
“I think so,” Rutty responded. “We see what you’re getting to — that we don’t want to create a system that can be gamed. But at the same time, we want to ensure that each [TO] can find the lowest-cost capacity for its load-serving needs, which is why we started this” proposal.
Rutty added he couldn’t imagine Mee’s hypothetical being cost-efficient for a transmission-owning utility and that any hint of manipulating the system could result in a “very easy” Section 206 complaint at FERC.
“I think we need to think about that, so include it in your comments,” he added.
Comments on the proposal must be submitted to CAISO by Feb. 22. The ISO expects to seek approval for the plan at next month’s Board of Governors meeting March 15-16.
WASHINGTON — A group of environmentalists, regulators and public power advocates told the D.C. Circuit Court of Appeals on Tuesday that it should overturn PJM’s Capacity Performance construct, saying it was fast-tracked into implementation without proper review and discriminates against renewable generators and demand response (16-1234, 16-1235, 16-1236, 16-1239).
E Barrett Prettyman Federal Courthouse
PJM developed CP in response to increasing generation forced outage rates, which peaked at 22% during the 2014 polar vortex cold snap, when the RTO had to implement emergency procedures to avoid blackouts. CP phased out seasonal resources and increased both bonuses for overperformance and penalties for nonperformance.
FERC approved PJM’s plan — which was submitted without stakeholder approval — in June 2015, saying the changes were justified by “the combination of deteriorating resource performance and the ongoing change in the resource mix in the PJM region.” (See FERC OKs PJM Capacity Performance: What You Need to Know.)
FERC’s approval is being challenged by a group including the American Public Power Association, National Rural Electric Cooperative Association, New Jersey Board of Public Utilities, Public Power Association of New Jersey, Natural Resources Defense Council, Sierra Club, Union of Concerned Scientists, American Municipal Power and the Advanced Energy Management Alliance.
High Costs, Ignored Alternatives
“The common thread in all of these appeals is that PJM rushed to assemble its Capacity Performance proposal, and FERC rushed to approve it, ignoring any alternative proposals despite the proposal’s high cost to consumers, its discriminatory effect on certain capacity resources and other flaws,” APPA attorney Randolph Elliott said. “This is like getting to the 5-yard line and having the referee push you over the goal line, or hitting a triple and having the umpire wave you home.”
The opponents argue FERC failed to demand sufficient evidence that PJM’s proposal would result in just and reasonable rates, saying that while the increased costs of the new requirements have been estimated, there was no attempt to quantify the reliability benefits it would produce.
They also contend that limiting capacity bidders to year-round resources discriminates against renewables and DR and that FERC unreasonably imposed limits on aggregating resources across locational deliverability areas. Also under dispute are PJM’s default offer cap, its unit-specific operating parameters and the design of its nonperformance penalties.
“It’s undisputed that PJM did not have the authority to make all of these changes unilaterally,” Elliott said. “The proposal was so controversial among the stakeholders that PJM did not even try to get the support they needed to file it unilaterally under [Section 205 of the Federal Power Act], so they elected to file this Section 206 complaint along with the other Tariff changes they filed under Section 205. … FERC said that the unilateral Tariff changes that PJM had made were just and reasonable, but then it turned around and said, ‘Because you did those, you’ve rendered your operating agreement and some other provisions in your Tariff unjust and unreasonable.’ Now how could those both be true at the same time? So they then turned around and granted the complaint, and said, ‘In light of the changes that you’ve made unilaterally, we have no choice but to grant your complaint.’”
Price | Jenner & Block
Judge Janice Rogers Brown asked if it would have been acceptable for FERC to initiate the Section 206 filing. Elliott argued no. But Matthew E. Price, representing CP supporter Exelon, later argued that it’s well within FERC’s purview to also order parallel revisions when an order is issued.
‘Strange Result’
“It would be a very strange result if the law were somehow different because PJM had initiated the 206 proceeding and pointed out to FERC, ‘Hey, here are some areas where you might want to consider making some changes,’ rather than leaving FERC to hunt around in other tariffs and identify changes that might need to be made,” he said.
Carol Banta, an attorney from FERC’s Office of General Counsel, defended the commission’s order approving CP, saying FERC fairly and carefully weighed PJM’s proposal and is entitled to deference in its conclusion. She noted that the commission found the proposal not unreasonably discriminatory toward any stakeholder.
FERC approved the proposal, she said, because it transferred the risk for performance from consumers to suppliers. The 2014 outages were a “conflation of events that really showed a number of weaknesses in the system,” she said. “It showed that we were already paying for reliability that we weren’t getting.
“When we talk about what are the reliability benefits that customers are getting for what they’re paying, it’s also in the context of what they were getting and not getting before,” she said. “A conventional resource, if it’s unable to guarantee its performance, it can fix something: It can upgrade its equipment; it can firm up its fuel arrangements. It has options, and actually this entire market proposal is to put those risks on suppliers. … If you have a wind farm, you can’t order more wind, so the commission agreed that it’s a reasonable accommodation for resources that couldn’t improve their performance just by making investments to allow them to still participate in these markets.”
Dictating Terms
This exemption for intermittent resources, like wind and solar, to aggregate their production so they can also guarantee year-round performance remained a focus throughout the hearing for Senior Judge David Sentelle. He asked why the commission hadn’t allowed conventional resources, like natural gas- and coal-fired plants, to also aggregate.
“PJM is not supposed to be dictating the terms here,” he said. “I can understand why aggregation would be a good thing, but would it not then be a better thing if they were allowed to cross-aggregate with traditional resources?”
Allowing such aggregation would create opportunities for companies to exercise market power, Price pointed out.
The technical aspects of the case appeared to be a challenge for the judges to hash out beyond the legal questions.
“There are many things in this case I don’t fully understand,” Senior Judge A. Raymond Randolph said. “What exactly is a delivery area, and second of all, why wouldn’t they be allowed to [aggregate] across delivery areas?”
“PJM didn’t provide the level of detail that the commission needs to approve that,” Banta said. “That could still happen.”
Price explained that the delivery areas are defined by transmission constraints, so resources “wouldn’t necessarily be able to deliver energy” to other areas.
Randolph also asked if any stakeholders had challenged that decision, and Banta said that American Municipal Power had made it part of its appeal.
Desormeau | NRDC
Cost vs. Benefits
Also participating in the nearly hour-long hearing was attorney Katherine Desormeau for the NRDC, who focused on CP’s cost versus the value of its benefits.
“PJM has acknowledged from the outset that this proposal will increase costs on consumers, but it did not support its final proposal with any evaluation of the costs,” she said. “And it didn’t attempt to evaluate the reliability benefit that was the purpose of the Capacity Performance proposal. … [FERC concludes] that the costs will be outweighed by benefits, but we have no way of knowing what FERC thought that was.”
Price replied that the proposal was designed to meet PJM’s reliability objective of no more than one outage every 10 years. “That reliability standard is a bedrock principle of capacity market design that goes back many years and is true in all of the regions under FERC’s authority,” he said. “When you hear petitioners complain about the costs of this program, what they’re complaining about are the costs of achieving that standard. What they’re really arguing to you is that standard is problematic because it costs too much and they’re willing to tolerate more risk, but that standard was not litigated in this proceeding. … Petitioners should not be able to make essentially a collateral attack on this well-settled reliability standard by complaining about the costs of the program.”
FERC’s final brief cited precedents in which the agency’s decisions have been given “great deference,” saying its factual findings should be considered conclusive if supported by “substantial evidence” — “more than a scintilla, but … less than a preponderance of the evidence,” the standard in civil trials.
The D.C. Circuit also has pending before it a challenge to ISO-NE’s similar Pay for Performance rules (New England Power Generators Association v. FERC, D.C. Cir. Nos. 16-1023, 16-1024). Banta noted that in both cases, FERC has said it’s reasonable for all capacity resources to be expected to perform year-round “regardless of technology type.”
ERCOT may have more wind, but SPP can lay claim to becoming the first North American RTO to obtain more than half of its power from it.
At 4:30 a.m. Sunday, SPP’s footprint generated 11,419 MW of wind energy at the same time its load was 21,919 MW. The wind-penetration mark of 52.1% broke the RTO’s previous record of 48.2%, set last April, and ended a friendly battle with ERCOT to see who could reach the 50% level first.
The two neighboring grid operators sit in the nation’s most wind-rich regions. Texas may top all other states with more than 20 GW of installed capacity — with ERCOT managing more than 17 GW of that — but SPP and its 14-state footprint is not far behind, with more than 16 GW of installed capacity and another 21 GW in the interconnection queue.
In the early 2000s, SPP counted less than 400 MW of wind energy, reporting it as “Other” in its fuel-mix data. Wind now makes up about 15% of the RTO’s nameplate generating capacity, trailing only natural gas and coal generation.
SPP added 4,000 MW of wind capacity in 2016, boosting its maximum simultaneous wind generation peak from 9,948 MW to 12,336 MW. It has set seven peaks for wind generation since last year, the latest coming Feb. 9 at 13,342 MW. Staff has even thrown out a 60% penetration number, saying it expects to crack that level this April.
“Ten years ago, we thought hitting even a 25% wind-penetration level would be extremely challenging, and any more than that would pose serious threats to reliability,” SPP Vice President of Operations Bruce Rew said in a statement. Fifty percent “is not even our ceiling. We continue to study even higher levels of renewable, variable generation.”
Several stakeholder groups are already at work trying to determine how best to add even more wind to SPP’s 550,000-square-mile footprint. The RTO has approved more than $10 billion in transmission infrastructure over the last decade, much of it to connect rural, isolated Midwest wind farms to distant population centers. (See “Stakeholders Try to Grasp Wind Energy’s Implications,” SPP Board of Directors/Members Committee Briefs.)
The RTO is holding a two-day Variable Generation Integration Workshop this week at its corporate headquarters in Little Rock, Ark. Staff will provide a deep dive on the second analysis it has performed on variable generation resources during the last several years. The study focused on system requirements needed to operate reliably at higher penetration levels while calling on fossil fuel resources to compensate for drops in wind production.
“If we start pushing 12 to 15 GW of output, we’re at the point where we should be concerned,” SPP’s Casey Cathey, manager of operations analysis and support, told the Markets and Operations Policy Committee last month. “We’re not trying to say the sky is falling, but it’s important we have a grip on the traditional resources and that we leverage them, as opposed to manually pushing more resources online in case the wind drops.”
Independent power producers on Tuesday filed suit in federal court challenging Illinois’ zero-emission credits for Exelon’s Quad Cities and Clinton nuclear plants, calling the program “illegal and unfair.”
The lawsuit seeks to overturn the Future Energy Jobs Act, which authorized the ZEC program, contending the law violates FERC jurisdiction over the wholesale electricity market.
Exelon’s Clinton Nuclear Plant | Nuclear Regulatory Commission
It was filed in the Northern District of Illinois, Eastern Division, by the Electric Power Supply Association (EPSA), Dynegy, Eastern Generation, NRG Energy and Calpine, naming the Illinois Power Agency and the Illinois Commerce Commission as defendants (1:17-cv-01164).
Jonathan Schiller, a managing partner of the plaintiffs’ attorneys Boies, Schiller & Flexner, said Illinois’ legislation will fail for the same reason that the Supreme Court last year unanimously rejected Maryland’s attempt to subsidize a combined cycle plant. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
“The Hughes [v. Talen Energy] decision clearly stated subsidies tied to wholesale power market prices — such as ZECs — are plainly illegal. The ZEC program is designed to allow Illinois to take actions that directly affect the wholesale electric market in an attempt to replace the federally regulated market prices with costs determined by the state instead,” Schiller said. “The credits are directly tied to the Illinois nuclear plants’ participation in interstate energy markets and are unconstitutional as a result.”
The plaintiffs cite an estimate that the out-of-market payments will total $235 million annually over 10 years.
Separately, EPSA also made two filings with FERC calling for expedited action to reject the ZEC programs in Illinois and New York. New York’s program also has been challenged, despite regulators’ contention that the program was designed to avoid the jurisdictional problems cited by the court in Hughes.
EPSA said its filings — answers to other parties’ comments — argue “that there is no merit to the procedural or substantive objections raised, urging the commission to act decisively and without delay” (EL16-49, EL13-62).
The commission, however, will be unable to act until a third commissioner is confirmed to restore its quorum.
EPSA noted with alarm that officials in Connecticut, New Jersey and other states are considering ZEC-type supports for their nuclear fleets.
“The commission should not allow opposing parties to obfuscate matters and should remain focused on the issue at hand to address the recognized threat to the markets through imposition of a minimum offer price rule (MOPR) on existing units for the capacity auctions used in New York and PJM to protect consumers and markets,” EPSA President John E. Shelk said in a statement. “FERC should take this corrective action and then work with all stakeholders on fuel-neutral market reforms and state concerns consistent with competitive market principles.”
WASHINGTON — Texas Public Utility Commissioner Ken Anderson and other state regulators sharply questioned MISO officials Monday over its refusal to share with them raw cost data on transmission projects.
The exchange came during an in-person gathering of the Organization of MISO States Board of Directors at the winter session of the National Association of Regulatory Utility Commissioners.
OMS President and Indiana Utility Regulatory Commissioner Angela Weber, who has been calling for the organization to be more transparent itself, joined Anderson in pressing the RTO.
Anderson was already riled up when he arrived about 10 minutes late for the OMS meeting, having gotten lost looking for the conference room in an interior hallway of the Renaissance Hotel. He burst into the meeting, arms waving and complaining that the session had been scheduled in an unnumbered room. “There is a number outside,” Weber calmly informed him before going on with a discussion of an appeals court brief.
Minutes later, Anderson was steamed up again. Priti Patel, manager of customer and state and regulatory affairs for MISO North, was explaining that the RTO aggregates cost data from transmission developers before sharing the figures with state commissions because it considers them proprietary information.
“This is the problem in MISO … really? Proprietary?” Anderson asked testily.
Weber and other regulators at the Feb. 13 meeting also expressed dismay and called on MISO to provide more visibility on project costs.
The discussion ended when — at the urging of Iowa Utilities Board Member Libby Jacobs — Patel agreed to ask her superiors whether state regulators could sign confidentiality agreements to be privy to the more granular information as the RTO receives it from the developers.
Before FERC Order 1000, Patel had explained, MISO only required “minimal” project information such as facility statuses and in-service dates. New Tariff requirements dictate that developers provide the RTO with regulatory status, right-of-way status, permitting status, and design and engineering status. She said MISO can investigate causes of schedule delays and cost overruns greater than a 25% deviation from the budget.
While MISO’s monitoring could intersect with state regulators, the RTO is not infringing on states’ rights, Patel said, reminding OMS members that MISO does not determine rates. “We’re not there to judge the prudency of a cost,” she said.
MISO gives more weight to operations and maintenance planning than construction costs when evaluating project bids, Patel said. “What we’re evaluating is the actual infrastructure,” she said. Patel added that developers are keenly aware of costs, however, noting that 10 of the 11 bidders on MISO’s competitive Duff-Coleman project wrote a cost cap into their proposals.
OMS Executive Director Tanya Paslawski said ratemaking power ultimately lies with FERC, and both MISO and states “are limited in what they can do.”
Weber said state access to developer information varies from state to state, pointing out that commissioners in Indiana do not have access to cost information.
OMS Reviewing Own Transparency
OMS is also reassessing the appropriateness of using closed sessions during its meetings.
The topic came up in early February after some OMS members requested a closed session to discuss MISO and PJM’s FERC filing to implement targeted market efficiency projects (TMEPs). Weber said some members wanted a closed session to discuss different state viewpoints of the TMEP. She questioned whether OMS should use closed sessions for simple disagreements.
“I felt that … it’s a very broad interpretation of closed meetings. Once you get into that broad interpretation, there are going to be more and more closed meetings,” Weber said at a Feb. 2 OMS Executive Committee meeting.
OMS bylaws dictate that meetings be generally open because they are composed of public commissions.
Weber said the organization could clarify the language that permits closed sessions only when strategy on a FERC filing is discussed.
OMS should not enter closed session every time a legal issue comes up in discussion, she said. “Almost everything we do touches on legal” proceedings.
CARMEL, Ind. — MISO has taken another shot at explaining how behind-the-meter generation will function in its markets, this time focusing on how those resources can participate in the upcoming capacity auction.
BTM generators identifying as load-modifying resources will be able to demonstrate deliverability for excess capacity in the 2017/18 Planning Resource Auction by meeting with staff for a case-by-case review, John Harmon, MISO manager of resource adequacy, said during a Feb. 8 Resource Adequacy Subcommittee meeting.
“We’re going to need to talk with folks and work with them to determine [if] they have excess capacity and how do they go about demonstrating deliverability of power,” Harmon said.
American Electric Power’s Kent Feliks asked if staff had any idea how many reviews it might conduct and what they might entail. “It seems a little black box-esque,” he said, adding that in some zones, a small amount of additional megawatts could impact clearing prices.
Harmon declined to comment on the scope or scale of the reviews, but he did say staff would review a generator’s proof of deliverability of any excess capacity to determine an “interconnection service equivalency.” If cleared, generators could then acquire transmission service for delivery.
For future planning years, MISO will require BTM generators to enter the interconnection queue and attain network resource interconnection service before entering the auction, Harmon said. The RTO will also schedule a discussion on possible “alternative deliverability” methods for BTM generation during May’s RASC meeting.
Last month’s educational workshop on BTM generation definitions raised questions about excess capacity deliverability and how generators could register in MISO’s Open Access Same-Time Information System (OASIS), the first step in procuring transmission service. (See MISO Behind-the-Meter Generation Definitions Create Confusion.) The RTO allows BTM generation to register as a capacity or load-modifying resource to participate in the auction.
Harmon said BTM generators could be included in OASIS by adding their commercial pricing nodes to the system. Generators would have to take the extra step of contacting MISO to submit their existing nodes, he said.
Customized Energy Solutions’ David Sapper asked if BTM generators would be guaranteed a reservation after contacting MISO. Harmon replied that they would enter MISO’s system impact studies like any other generator entering OASIS.
Sapper also asked if MISO would let BTM generators create new commercial pricing nodes for OASIS recognition, claiming some generators might encounter a snag if they could not. MISO staff rejected that idea.
VALLEY FORGE, Pa. — A simulated performance assessment hour last summer would have produced nearly $13.5 million in nonperformance charges, resulting in approximately $1,283/MWh bonus payments for overperforming units, PJM’s Joe Ciabattoni said at Tuesday’s Operating Committee meeting. (See PJM Generator Notification Plan Gets Mixed Review.)
The simulation, which was requested by stakeholders, was simplified to exclude bonus capping and excusals for shortfalls. “Just remember it’s a simulation,” PJM’s Mike Bryson cautioned.
PJM used the 3-4 p.m. hour on Aug. 11, a $1,896.30/MWh penalty rate and Tariff formulas to determine the expected and actual performance. Of the 528 capacity resources, 176 combined for a total shortfall of 7,093 MW, while 306 exceeded their promised output by a combined 10,485 MW. There were 46 resources with neither a shortfall nor a bonus.
Fifteen resources would have been charged more than $250,000 each, with the highest individual charge calculated at almost $1.2 million. Twenty-five resources would have received more than 100 MW worth of bonus payments, with the largest individual credit equaling 601 MW. PJM also calculated separate numbers for just the Mid-Atlantic territory.
Stakeholders felt the broad focus left too much ambiguity. “To me, there are so many details left out that it raises more questions than it does provide answers,” American Electric Power’s Brock Ondayko said.
On some levels, PJM agreed. “I don’t know if we consider this a good predictor of what to expect or not,” PJM’s Adam Keech said.
Later, PJM staff reviewed member responsibilities for several other components of Capacity Performance, including inputting real-time values such as minimum and maximum run times to reflect operational capabilities when the resource cannot operate according to its unit-specific parameters. The deadline for changing unit parameters for delivery year 2017/18 is Feb. 28.
“This is your opportunity to give us the rest of the story,” Ciabattoni said.
Stakeholders expressed concern over the costs of replacing a phase angle regulator that failed at Consolidated Edison’s Ramapo substation last June.
That leaves just one PAR at the facility, but Con Ed is waiting for certainty on cost allocation before replacing the second one, PJM said. Without it, PJM’s transfer capability into NYISO is limited by about 300 MW. The situation is complicated by the fact that Con Ed is ending its PJM membership in May with the termination of the Con Ed-PSEG “wheel.” (See NYISO Members OK End to Con Ed-PSEG Wheel.)
The grid operators are considering modifications to their joint operating agreement to develop a cost recovery mechanism for replacing the PAR. The methodology would be used for future cost sharing as well.
The PARs were added in 1988 to control loop flows that had undermined the reliability benefits of the Branchburg-Ramapo 500-kV line, which was built in response to the 1965 Northeast blackout. The current agreement splits costs of the two PARs 50-50 between NYISO and PJM.
Stakeholders were quick to question the financial implications of the proposal, including how much it would cost and what PJM’s thoughts were on a likely cost allocation agreement.
“We do not have any preconceived notions of how that would work,” PJM’s Stan Williams said, adding that the replacement would cost $10 million to $20 million. He confirmed PJM’s plan to consider the changes through a problem statement and issue charge.
Williams also acknowledged that some of the PARs’ main benefits have been “muted” since they were initially implemented. The second PAR reduces the risk of sustained customer outages during severe weather, but that happens “rarely,” he said. Additionally, the loop flows that originally necessitated the PARs have been reduced.
PJM has conducted modeling both for the operational baseflow that will replace the wheel with one PAR, or two PARs, PJM’s Paul McGlynn said. However, PJM’s current planning parameters for the upcoming Base Residual Auction assumes two PARs, he said.
The grid operators are planning joint stakeholder meetings on the issue, likely beginning in March, Williams said.
New Regulation Rules Improving ACE Control
Recent changes to regulation signals and operational requirements are improving area control error (ACE) statistics, PJM’s Eric Hsia said. (See “Regulation Requirement Changing from ‘Peak’ to ‘Ramp,’” PJM Operating Committee Briefs.)
The average of the median daily ACE has been cut in half since the new signal was implemented and the monthly average mileage ratio has more than doubled. That indicates a larger utilization of Regulation D resources and better alignment of Regulation A signals with unit ramps, PJM said.
“We’re moving the Reg-D resources more aggressively,” Hsia said.
PJM’s efforts last year to improve the alignment between its day-ahead and real-time modeling has reduced balancing congestion, PJM’s Nicole Scott said.
The RTO calculated impedance differences to compare the planning model versus the model used by operators, Scott said, and used summer 2015 peak base cases as a benchmark. Staff has worked to improve the parity between the models by correcting errors, increasing mapping of transmission facilities, refining processes and providing additional training, she said.
The goal is “normalizing the two models to get them to look the same,” PJM’s Mark Sims said. “If we tried to do this five years ago, we would [have struggled], but everything lined up [now].”
Among additional initiatives for 2017, PJM plans to create an alarm warning when a model is out of compliance.
Sunsetting the Metering Task Force, whose work was completed with revisions to metering standards and requirements in Manual 1. (See “No Objections to Metering Revisions,” PJM Markets and Reliability and Members Committees Briefs.)
One would have to live under a rock to not know about the Second Coming of electric cars.[1] (The First Coming 100 years ago is pictured.)
Virtually every auto maker has announced plans, and the media have anointed their inevitability. As TheWall Street Journalproclaimed recently, “The car of the future will be electric …”
But to paraphrase Thomas Huxley, the great tragedy of reality is the slaying of a beautiful hypothesis by an ugly fact.
In the case of electric cars there are not one but three ugly facts. First is that they cost a lot more than gasoline cars and that’s not going to change for a long time. Maybe never.
Second is that they tend to contribute to global warming more than gasoline cars.
Third is that they cause more death and disability than gasoline cars.
Let me walk you through this great tragedy of reality.
First ugly fact: Electric cars are and will be much more expensive — indefinitely. Ignore the media hype and consider peer-reviewed academic articles, like one by researchers from the University of Chicago and the Massachusetts Institute of Technology in the Journal of Economic Perspectives last year, showing that electric cars are far out of the money for customers on a total cost of ownership basis.[2] Basically, the high cost of batteries trumps (sorry, couldn’t resist) the lower cost of electricity relative to gasoline.
And here’s the killer — it ain’t going to get much better for the next 10 years — if ever. Even if battery costs drop precipitously from the current $325/kWh to $125/kWh (an Energy Department “target”), oil prices would still need to rise to $115/barrel for electric cars to make sense. There is a fascinating chart in the Chicago/MIT paper (pictured) showing the break-even relationship between battery costs and oil prices.
Neither battery costs nor oil prices are likely to align for electric cars. Battery costs seem to be plateauing above $300/kWh. Tesla’s Powerwall 2 has debuted at $321/kWh even if one generously gives its inverter a $1,000 value.[3]
As for oil, the futures price is below $60/barrel through 2025, about half of what oil would need to cost in order for a battery cost of $125/kWh to break even.
To summarize, the electric car propulsion system is 400% out of the money, with little prospect of making that up any time soon, if ever. And the recharging time and location problems still need to be solved.
So, yes, Tesla and others will sell their electric cars as Veblen goods — commodities for which demand is high because of their high prices and perceived status — in the hundreds of thousands. But tens ofmillions of cars sold every year will continue to run on gasoline.
Second ugly fact: Electric cars exacerbate global warming. Surprised? It’s important to remember a couple things. One, converting raw fuels to electricity is inefficient. Two, the fuels generating electricity when an electric car is charging tend to be the worst from an environmental perspective.
There is only one study I can find that was sufficiently “granular” to do carbon emission analysis on this hard reality basis. It is a paper published in another obscure periodical, the Journal of Economic Behavior & Organization, with the engrossing title: “Spatial and Temporal Heterogeneity of Marginal Emissions.”[4]
Buried in excruciating detail is the hard reality. The average rates of carbon dioxide emissions on an apples-to-apples kilowatt-hour basis are:
Electric car: 2.10 lbs/kWh.
Comparable gasoline car: 1.79 lbs/kWh.
Comparable hybrid: 1.13 lbs/kWh.
So if you buy an electric car instead of a comparably sized gasoline car, you will most likely make global warming worse. And an electric car instead of a hybrid would be twice as bad.
Third ugly fact: Electric cars cause much more death and disability (euphemistically, “human toxicity potential”) from the mining of heavy minerals and graphite. This has received anecdotal attention in TheWashington Post and other media, but there is an empirical study by Arthur D. Little showing that the aggregate “days of life impact” in terms of death and disability are 30 for an electric car (with a 50-kWh battery in 2025) versus six for an equivalent gasoline car.[5]
So to sum up, electric cars cost more, contribute to global warming more and hurt more people than gasoline cars.
May I make a modest proposal if you care about the environment and don’t want to hurt people? Take the money you would have overspent on an electric car and spend it on (1) a renewable energy supply option from your utility or other electric supplier, (2) a hybrid car and/or (3) high efficiency appliances and lighting such as LED bulbs.
You may not have the coolest toy in the neighborhood, but the planet and your fellow humans should thank you.
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel LLP.
[1] Here we mean battery-powered electric cars, not driverless cars or hybrid cars.
[3] $5,500 minus $1,000 divided by 14 kWh is about $321/kWh. The inverter value may be high; Tesla isn’t charging anything less if you get the DC version without the inverter.
Stakeholders expressed concern over the costs of replacing a phase angle regulator that failed at Consolidated Edison’s Ramapo substation last June.