FERC on Monday approved Basin Electric Power Cooperative’s requests to eliminate its obligation to purchase power and capacity from generating facilities over 20 MW under the Public Utility Regulatory Policies Act.
The consumer-owned co-op, which provides supplemental wholesale power to 141 rural electric member systems in MISO and SPP, last year assumed the mandatory obligations of its members to purchase output from PURPA qualifying facilities — QFs of 150 kW or more in the case of SPP.
Crow Lake facility | Basin Electric Power Cooperative
In its rulings — one for QFs in MISO (QM18–7) and one for SPP (QM18–6) — the commission agreed to terminate Basin’s mandatory purchase obligation under FERC regulations, which stipulate that QFs in excess of 20 MW of net capacity in the two RTOs have nondiscriminatory access to a market, satisfying PURPA’s requirements.
The commission dismissed the combined protests of two wind farm developers, Thomas Mattson and David VanderLeest, who argued that Basin was attempting to “rewrite” and “violate” PURPA and other laws intended to protect small generators.
Mattson and VanderLeest contended that larger developers have received “substantially” better power purchase agreement terms from Basin than smaller developers, causing the complainants to lose out on a number of proposed projects because of expiring option agreements.
“Basin destroys their competition, keeping all small cooperatives under their rule,” their protest said. “QF wind farms would provide less costly power than Basin, reducing customer rates while providing economic stability for the small cooperative.”
The developers asked FERC to take six actions, including an order to reduce interconnection costs.
The commission said the issues raised in the protest went beyond the scope of the proceedings. “Mattson and VanderLeest allege, among other things, delays in providing developers with accurate long-term avoided costs rates and failures in the overall implementation and enforcement of PURPA at the federal and state levels,” the commission said. The Basin proceedings were limited to whether QFs in MISO and SPP have nondiscriminatory access to a market that satisfies PURPA’s requirements, it said.
FERC cited Order 688, in which it “explained that there can be factors unique to individual QFs, including operational characteristics and transmission limitations, that prevent such QFs from having nondiscriminatory access to the markets described in Section 210(m)(1) of PURPA.
“However, Mattson and VanderLeest’s protest does not discuss those factors or otherwise attempt to rebut the arguments in the [Basin] application,” FERC said.
Basin’s territory includes portions of Colorado, Iowa, Minnesota, Montana, Nebraska, New Mexico, North Dakota, South Dakota and Wyoming.
American Municipal Power contended Thursday that PJM’s limited review of transmission owner projects is not rigorous enough to ensure the RTO is avoiding unnecessary costs or that TOs’ evaluation of other stakeholders’ proposed solutions are accurate and unbiased.
AMP’s Ryan Dolan noted that Manual 14B prohibits PJM from evaluating supplemental projects as part of the Regional Transmission Expansion Plan, meaning the plan can’t capture whether a supplemental project creates or alleviates economic issues. “We can’t assure an optimized build-out of the system,” said Dolan, who presented a list of proposed rule changes at Thursday’s Planning Committee meeting.
Dolan said PJM’s limited review was not a problem in the past but that the RTO should provide more scrutiny now, because supplemental and other TO projects represented 88% of RTEP spending last year.
“There’s information that PJM has that the TOs don’t have, that we [stakeholders] don’t have,” said Dolan, who said the RTO should tap all available expertise in its analyses.
‘Do No Harm’ Reviews
Dolan spoke after Aaron Berner, PJM manager of transmission planning, explained the RTO’s “do no harm” reviews of baseline upgrades, supplemental upgrades and new service requests. The review is intended to identify any reliability issues caused by new upgrades, determine if the upgrades should be more or less “robust” and assess the cost efficiency of packages of upgrades needed to correct reliability violations.
The testing required depends on the scope of the upgrade, not the type of upgrade, Berner said. No analysis is required for direct in-kind replacements, while minor changes to impedances or ratings undergo “minimal analysis.” Significant changes to impedances, ratings or new topology may require “significant” review — load-flow, short-circuit and stability analyses.
AMP wants PJM to vet supplemental projects to identify interdependencies with baseline projects and quantify the impacts of TO proposals on previously approved economic projects or whether they eliminate previously approved reliability projects or change cost allocations.
Dolan said many TOs create their own base cases with generation dispatch and load profiles that differ from PJM’s practice, but the RTO’s analysis is only applied on its own models. “There are no checks and balances to ensure that the [TO’s] process is being followed and that [that] process is consistent,” he said.
Dolan also expressed concern about the large number of TO projects submitted at the end of the RTEP cycle, saying PJM should establish start and stop dates for TOs to submit needs and proposed solutions, aligned with competitive windows.
He also called for standardizing the data reporting requirements for all project submissions and requiring reporting of all scenarios, models, standards and documentation used to justify and size project facilities; and a process that allows for formal submission and PJM review of alternative proposals.
Alex Stern, manager of transmission strategy and policy at Public Service Electric and Gas, said AMP’s proposals were “misplaced.”
“My initial reaction is the PJM stakeholder process might be the wrong forum” for AMP’s proposal, said Stern, noting FERC’s Feb. 15 ruling, which he said accepted PJM’s current role and declined to mandate it do more (EL16-71, ER17-179). (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
“FERC just advised that it doesn’t believe there is any modification needed to PJM’s analysis. It confirmed the acceptability and appropriateness of PJM’s role with respect to planning for supplemental projects and specifically declined to require greater PJM involvement in planning for and selecting supplemental projects.
“The stakeholder process probably shouldn’t be discounting FERC on this,” Stern added.
“They weren’t saying [PJM] couldn’t do more,” Dolan responded. “They were just saying, ‘It’s OK.’”
Internal Discussions on Sharing More Info on Tx Projects
Earlier in the meeting, Berner described the RTO’s internal discussions about how it can respond to requests for more information on proposed transmission projects.
Berner said PJM is developing a tracking mechanism for identifying information shared without disclosing critical electric infrastructure information. The RTO is considering making more information available through the Planning Community portal launched in September.
The RTO expects to share its proposals within “a couple months,” Berner said. Some information requests to the RTO indicate it should offer additional education on its study process, he added.
TOs Answer Questions at TEAC
At the Transmission Expansion Advisory Committee meeting later Thursday, officials of Baltimore Gas and Electric and Commonwealth Edison answered questions Dolan had posted on supplemental projects brought up for a second read. BGE, for example, said that circuit breakers slated for replacement at its Jericho and Howard substations are 47 and 27 years old, respectively, and have been the subject of expensive repairs.
Dolan appeared pleased to be receiving responses, smiling in the room when the BGE representative spoke up on the phone. He had posed the questions to Berner, who said PJM was still in collecting the necessary information and determining how to respond, but BGE then volunteered the responses. When Dolan later brought up his questions about replacing a transformer and installing two breakers at ComEd’s Wayne substation, Berner deferred to a ComEd representative on the phone, who provided responses.
| PJM
Earlier in the TEAC, stakeholders received first-read presentations on eight supplemental projects: six by American Electric Power totaling $163.4 million and two by Dominion, totaling $860,000. (See table.) When discussing an AEP project to replace two breakers at its Jefferson station, Berner told Dolan he didn’t have answers to questions AMP had submitted and wasn’t planning to bring the project back to a subsequent meeting to review the responses “unless something changes.” Dolan argued that AMP had submitted questions within the timeline laid out in the TOs’ recently proposed Tariff Attachment M-3, which they developed to codify the “additional detail and transparency regarding the process for planning supplemental projects” they’ve agreed to. It is currently circulating for review and comments.
In a discussion on a $53 million project to replace aging transformers at AEP’s Wyoming substation, Dolan asked whether stakeholders would be permitted to review maintenance records on the transformers. “There’s a discussion about whether maintenance records need to be made available,” said Berner.
Vice President of Planning Steve Herling said PJM’s reading of FERC’s February order is that stakeholders should be able to replicate the TO’s planning studies, “not replicate asset conditions.”
“As we’ve been discussing, we’re trying to change the progress of the supplemental upgrades as they come to PJM,” Berner said at one point. “It’s going to take us a little bit of time to get those specifications of the required upgrades to a point where we can present them all in a fashion that would allow identification of the issues earlier in the process, but there are a number of issues out there right now that need to be addressed. We can’t delay that.”
FERC Chairman Kevin McIntyre disclosed Sunday that he underwent successful surgery for a brain tumor that was discovered last summer.
The disclosure, made in a statement posted on FERC’s website, appears to explain the dramatic difference in McIntyre’s appearance between his Senate confirmation hearing in September and his swearing in in December, after his hair — apparently having been partly shaved — was beginning to grow back.
The health issues also may have played a part in McIntyre’s delayed arrival at FERC. He took office on Dec. 7, more than a week after Commissioner Richard Glick; both were confirmed by the Senate on Nov. 2.
McIntyre said he issued the statement because of inquiries about his health. He said the tumor was discovered unexpectedly last summer. “Through an incidental finding, i.e., a medical issue discovered by accident, I was diagnosed with a brain tumor. I was very fortunate that the tumor was relatively small, that I had no symptoms and that I was otherwise in excellent health.
“Thereafter, I underwent successful surgery, followed by the post-operative treatment that is the standard of care for my situation. I was advised at the time that, with the surgery and subsequent treatment behind me, I should expect to be able to maintain my usual active lifestyle, including working full time, and that expectation has proven to be accurate.”
The chairman expressed gratitude for the support he received from those who had been aware of his situation “especially those in the White House, Congress and the FERC.”
He said he did not intend to provide further details or updates “for reasons of personal and family privacy.”
“I am grateful that my health is now stable and that I am able to devote my full energy to serving the American public every day as chairman of the FERC and continuing to work to earn the trust that has been placed in me,” he said.
McIntyre joined FERC after two decades at Jones Day, where he represented energy clients in administrative and appellate litigation, compliance and enforcement matters, and corporate transactions.
Open markets drive competition. Competition drives innovation and affordability. Case in point: Today, more and more consumers are utilizing innovative battery solutions — with many powered by rooftop solar — to provide clean energy to homes and businesses. In the coming weeks, regulators will consider proposals by utilities in Massachusetts and New Hampshire that seek to fully control customer-owned batteries, or seek to reach into peoples’ homes and actually own batteries. There is no reason for regulators to allow utility control or ownership of generation and storage resources that can be supplied competitively. With no natural monopoly to regulate or market failure to fix, enabling utility ownership and control will serve only to stifle innovation and impede competitive solutions. We urge regulators to consider a better future.
Sunrun’s Brightbox home battery service | Sunrun
The way Americans make and use electricity is in the midst of a remarkable evolution. For more than a century, we were unable to store electricity at our homes or businesses the way we store gasoline or recharge devices like our cell phones. Energy needed to be generated and consumed simultaneously. As a result of steep cost reductions in technology and competitive innovation, we are entering an exciting new era of empowerment. Consumers and businesses across the country are pairing batteries with rooftop solar. Large power plants are also now pairing with batteries to smooth spikes in demand. These new resources can enter markets, lowering costs for all consumers.
Twenty years ago, many states unleashed innovation by restructuring and creating competitive markets, no longer allowing monopoly utilities to own generation. That policy choice helped pave the way for consumers to benefit from electricity supply options and unleashed fierce competition in how electricity is produced. The result? More efficiency. Thanks to increased competition in the marketplace, today it takes three plants to generate the same amount of electricity as it used to take four to generate. This in turn helped lower the price to produce power dramatically, though consumers’ bills are still increasing, as utilities continue distribution and transmission spending and charge us more to transmit power. These efficiency gains and competitive investments have also helped power plants in New England drive down carbon dioxide emissions by more than 40% since 1990, now representing only half of the emissions of the transportation sector. The framework of a competitive and dynamic marketplace set the stage for more competitive storage options.
Dolan | NEPGA
But the glide path for consumers and competitive markets is riddled with bumps along the way. Some utilities are seeking to own batteries in peoples’ homes and businesses. Others are requesting the right to the energy in a consumer’s battery, at the very least. Their goal? To receive returns for their investors by controlling storage that was funded by consumer and business investments. In other words, utilities want to take control of a family’s home battery, which was charged by the family’s home solar system, and bid that electricity into the competitive wholesale markets themselves. That is anticompetitive and counter to public policy goals that encourage investments in a cleaner and more resilient electricity grid.
The New England Power Generators Association and residential solar and storage companies agree that utilities should not impede consumer energy and storage investments when there are competitive options available. Such utility ownership or control is a dramatic step away from open energy markets. Rate-based utility ownership of batteries stifles competition — both at the rooftop and large generator scale — and threatens to raise rates for everyone.
Hoskins | Sunrun
Let’s get this right. Dozens of innovative companies are already stepping up to replace portions of our aging energy infrastructure with innovative storage solutions — competitively and with increased flexibility for consumers and generators. At the same time, however, utilities are spending tens of billions of dollars annually on building poles and wires. Some of these investments are necessary to replace power lines and substations at the end of their useful life, but some can be avoided with distributed energy solutions and large-scale storage. Consumers will foot the bill for utility infrastructure now and for decades into the future — if we don’t allow competitive solutions to emerge. With the right policies in place, investments in competitive electricity supply and storage can improve resilience and affordability. By providing clear price signals, utilities or system operators can incentivize private storage assets, at all scales, to meet system demands. There is no need for utilities to own or control the assets.
As the National Energy Marketers Association, which represents global suppliers and major consumers of natural gas and electricity, wrote, “After nearly two decades of experience with competitive retail markets, it is abundantly clear that the anticompetitive impacts of monopoly utility participation in competitive energy markets … is poor public policy, is not in the public interest and deters and discourages the private capital investment and technology innovation.”[1]
Dan Dolan, President, New England Power Generators Association. NEPGA’s mission is to support competitive wholesale electricity markets in New England. We believe that open markets guided by stable public policies are the best means to provide reliable and competitively-priced electricity for consumers.
Anne Hoskins, Chief Policy Officer at Sunrun. Sunrun is the nation’s largest dedicated residential solar, storage and energy services company with a mission to create a planet run by the sun.
FERC on Friday approved ISO-NE’s reduction in the dynamic delist threshold for Forward Capacity Auction 13, turning aside protests by generators.
The commission reduced the threshold to $4.30/kW-month from the $5.50/kW-month the RTO had used in FCAs 10-12 (ER18-620). The threshold, which must be revised every three years, is a key parameter for generators considering retirement, which must submit delist bids to opt out of the capacity auction.
ISO-NE accepted the retirement bid from PSEG’s 383-MW Bridgeport Harbor 3 coal-fired unit for Forward Capacity Auction 12. | PSEG
ISO-NE’s auction use static and dynamic delist bids. A static bid must be filed before the auction for review by the Internal Market Monitor; bids below the dynamic delist bid threshold will be removed from the capacity market for one year.
Dynamic delist bids are submitted during the auction and are not subject to IMM review. If the auction price falls below a resource’s delist bid, that resource is removed from the auction and does not acquire a capacity supply obligation.
ISO-NE’s proposed threshold is calculated by the IMM, whose objective is to set the level slightly below the competitive price from the marginal resource in the FCA to increase the likelihood that the marginal bid is subject to a market power review. If the threshold is too high, the RTO says, existing suppliers — who know the remaining supply in each FCA round — can exert market power by increasing the FCA clearing price through their dynamic delist bids.
FCA 13 will be the second consecutive reduction in the threshold. In FCA 9, the threshold was raised from $1/kW-month to $3.94/kW-month.
Methodology
The IMM calculated the $4.30 threshold based on the most recent supply-and-demand curve information and data on shortage conditions and resource performance. The Monitor said it was unable to use recent static delist bid data to represent net going-forward costs because suppliers have submitted fewer static bids in recent auctions. Instead, the IMM estimated going-forward costs using a proxy price calculated from a weighted average of capacity that remained in the auction during the last round of FCA 11. It also used several “implied bids” — bids from resources that did not submit a dynamic bid in the final round of the auction, instead remaining to the end-of-round price of $4/kW-month.
ISO-NE said the decrease in the threshold is consistent with changes in supply and demand, noting that the amount of capacity in the RTO has increased each year since FCA 9, while the installed capacity requirement has consistently decreased. The RTO estimated a surplus of 1,250 MW for FCA 12.
Protests
The New England Power Generators Association (NEPGA) protested the RTO’s threshold, saying the IMM’s methodology was inconsistent with that used in updates since FCA 9 and that it will distort market signals and harm reliability. It noted that the Monitor disregarded cost-based offers from fossil steam resources that had been used in the past, instead using a forecast of future market conditions.
The generators group also challenged ISO-NE’s assumption that the capacity market faces a surplus in future auctions, and that the number of hours of capacity scarcity conditions will decrease.
By sending a market signal that offers above $4.30/kW-month are unlikely to clear, NEPGA said, generators will be inclined to make below-cost offers to obtain capacity revenues.
Public Service Enterprise Group also protested, saying the $5.50/kW-month threshold is already less than 70% of the net cost of new entry (CONE) for FCA 12 and that offers in that range should be considered competitive. The first seven auctions used a threshold that was 80% of net CONE, PSEG said.
Ruling
FERC sided with the IMM’s methodology, saying it was reasonable given the changing supply-and-demand dynamics since the last update. “We agree with ISO-NE and [the New England Power Pool] that the question before the commission in this proceeding is whether ISO-NE has demonstrated that its proposed dynamic delist bid threshold and the methodology that the IMM used to calculate it are just and reasonable, not whether ISO-NE’s proposal is more or less just and reasonable than protesters’ proposed alternatives,” FERC said.
It added, “The fact that the IMM used different data than it has used in the past to calculate the dynamic delist bid threshold does not, on its own, render ISO-NE’s filing unjust and unreasonable.
“While NEPGA argues that the dynamic delist bid threshold should be based on the costs of oil-fired resources because they are typically the marginal resource, we find compelling ISO-NE’s statement that, under current market rules and conditions, it is difficult to forecast with certainty the type of resource that will submit the marginal bid,” the commission continued. “As ISO-NE notes, several different resource types have submitted dynamic delist bids near the auction clearing price in the last two auctions.”
It rejected NEPGA’s prediction that bids above the reduced threshold will not clear as “speculative.”
“We agree with ISO-NE that suppliers should not rely on the dynamic delist bid threshold as an indicator of the likely clearing price in the next auction; the purpose of the dynamic delist bid threshold is not to signal the likely market clearing price but instead to help ensure that the marginal bid is subject to IMM review for the potential exercise of market power. Further, the proposed dynamic delist bid threshold does not prevent capacity suppliers from submitting properly supported delist bids that exceed the threshold.”
The commission said PSEG’s protest that the reduced threshold will exacerbate problems with the delist process was beyond the scope of the proceeding.
By Amanda Durish Cook, Jason Fordney, Tom Kleckner, Rory D. Sweeney and Rich Heidorn Jr.
RTO officials asked FERC on Friday to allow their stakeholder processes time to develop additional resilience measures while urging the commission to require more coordination with natural gas operators and provide more information on cyber threats.
Friday was the deadline for the six jurisdictional RTOs and ISOs to respond to two dozen questions FERC presented in its January order rejecting the Department of Energy’s call for price supports for coal and nuclear generators and creating the resilience docket (AD18-7). ERCOT also responded, although FERC’s jurisdiction over the Texas grid is limited to NERC reliability rules. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
The order asked RTOs to identify their resilience risks; whether they should assess their resource portfolios against contingencies from the loss of key infrastructure; and the bulk power system attributes that contribute to resilience.
ISO-NE expressed the most acute concerns among the RTOs, saying inadequate natural gas supplies could lead to load shedding on peak days by winter 2024. It said it will need until mid-2019 to develop solutions with its stakeholders.
An ISO-NE study found that extended outages of key energy facilities would result in as much as 138 hours of load shedding by 2024. | ISO-NE
PJM, however, said RTOs and jurisdictional transmission operators in non-RTO regions should be required to file rule changes needed to address resilience within nine to 12 months. “A deadline … would help ensure focus on these issues in the stakeholder process,” PJM said.
CAISO, meanwhile, criticized FERC’s definition of resilience as “somewhat vague.”
CAISO’s comments reflected its changing resource mix and unique circumstances compared with other RTOs, but the grid operator questioned the meaning of the term “resilience.”
“The CAISO notes that the concept of ‘resilience’ presented in the resilience order is general and somewhat vague. It includes no clear objective criteria, metrics or standards to evaluate whether the existing grid is resilient,” CAISO said in comments signed by General Counsel Roger Collanton and other attorneys.
The order also lacks cost-benefit analysis, financing concerns or “prudence assessment,” CAISO said, adding that current reliability standards address many similar issues.
While the ISO criticized aspects of the order, it did detail some challenges it faces, noting that the growth of renewables has put economic pressure on the gas-fired fleet through factors such as the inability to attain resource adequacy contracts and competition for flexibility services such as ramping.
Earthquakes, drought and wildfires are the unique risks facing California, CAISO said in its 176-page filing. It also cited as risks cyberattacks and the closure of the Aliso Canyon gas storage field and the San Onofre nuclear power plant.
There are no baseload coal units in the CAISO balancing area, and the last remaining nuclear plant, Diablo Canyon, is set to retire in 2024. With natural gas generation declining and the system rapidly transitioning to renewables, in part because of the massive expansion of rooftop solar, CAISO has surplus power in daylight hours, resulting in curtailments and ramping needs illustrated by the “duck curve.”
The grid operator said that entities other than RTOs also have a role in providing resilience, such as transmission and generation owners, fuel suppliers, federal and state agencies, environmental groups and others.
CAISO said it did not see a need for an additional requirement for RTOs/ISOs to identify resilience needs as proposed in the order, for multiple generation outage scenarios, fuel disruptions and other events. Analyzing “common-mode” impacts is appropriate and addressed in normal utility reliability planning, it said.
“Creating a new risk-based analysis requirement would likely be overly prescriptive, difficult to clearly define and likely duplicate existing reliability standards given the wide range of varying specific risks different ISOs and RTOs face,” it said.
CAISO said its sensitivity analyses indicate 1,000 to 2,000 MW of retirements could result in shortfalls in load following and reserves after sunset when rooftop solar goes offline. It is supporting multiyear resource adequacy requirements for local capacity resources instead of one year and changing its backstop procurement programs.
The ISO has a filing with FERC regarding its capacity procurement mechanism and reliability-must-run changes, the topic of heavy debate in stakeholder discussions. The ISO’s internal market monitor has filed a protest to the proposal. (See CAISO, Stakeholders Debate RMR Revisions.)
Studies that CAISO has conducted include gas-electric coordination planning studies for both Southern and Northern California, as well as frequency response studies related to the replacement of conventional thermal resources with renewables, storage and distributed energy sources. Special reliability studies are done during the transmission planning process.
The grid operator added that the question as to whether the grid could “reasonably withstand” high-impact, low-frequency events was not defined and is difficult to respond to.
CAISO asked for a “a holistic approach that also considers the unique circumstances and conditions facing each region” as the resilience criteria is considered.
ERCOT, Texas PUC: Consider All Foreseeable Threats
ERCOT and the Public Utility Commission of Texas filed joint comments in the docket, although they noted that the Texas grid operator does not fall within the Federal Power Act’s definition of an RTO or ISO and “therefore does not fall within the coverage of the commission’s order.”
Still, both entities saw “great value in providing input” because it could inform FERC’s “possible application of its authority over public utility tariffs” and affect the potential development of NERC reliability standards, to which ERCOT is subject.
ERCOT is exempt from FERC’s rules for RTOs and ISOs but is subject to NERC reliability standards. | ERCOT
The two entities agreed with FERC’s concept of resilience. “Any disturbance to the bulk power system that impairs the continuous provision of electric service has, to that same extent, impaired reliability,” they said. “ERCOT and the PUC view resilience as an important subset of their existing reliability responsibilities.”
They urged FERC to look beyond “high-impact, low-frequency events” such as cyberattacks, fuel-supply disruptions and extreme weather events. “The ultimate goal of policymakers should be to ensure that all foreseeable threats to the reliability of the bulk power system are identified and addressed in the most cost-effective way,” they wrote.
ERCOT and the PUC also underscored the importance of Texas’ energy-only market design in ensuring system resilience, saying it “is inextricably linked to long-term system reliability.” As an example, they referred to February 2011, when cold temperatures knocked several generators offline and market prices hit the cap ($3,000/MWh, which has since been raised to $9,000/MWh).
“This resulted in severe financial consequences to generators with day-ahead commitments that failed to generate in real time, just as it greatly rewarded those generators that stayed online during the event,” ERCOT and the PUC said. Subsequent improvements in plant weatherization resulted in “substantially fewer generators suffering equipment failures” during similar events in 2017 and 2018.
“In short, ERCOT’s scarcity pricing mechanisms are designed to alleviate the need for many resilience-based regulatory controls,” they wrote in the 22-page filing.
ERCOT and the PUC said they address resilience concerns in operating and planning the grid, noting the “greater penetration of renewable resources … compared with most other ISOs” and the “greater vulnerability” they pose to certain extreme weather events.
“ERCOT has robust processes in place to ensure the ERCOT system will be operated in a way that can resist and recover from a variety of foreseeable disturbances,” they wrote. “These processes will continue to identify other areas for improvement as the system evolves.”
ISO-NE Sees Growing Fuel Security Risks
ISO-NE filed a 61-page response citing winter fuel security as its most significant resilience challenge and asking FERC to allow it until the second quarter of 2019 to develop a long-term solution through its stakeholder process.
The RTO said the stakeholder discussions will build on the sobering findings of its Operational Fuel Security Analysis (OFSA) report issued in January, which found the region would face energy shortfalls because of inadequate natural gas supplies in almost every fuel-mix scenario by winter 2024/2025, “requiring frequent use of emergency actions to fully meet demand or protect the grid.” (See Report: Fuel Security Key Risk for New England Grid.)
ISO-NE says natural gas generators will increasingly face fuel shortages during the winter, when heating demand is high. | ISO-NE
ISO-NE said potential solutions range from “changes to Pay-for-Performance parameters to market designs that increase incentives for forward fuel supply and resupply to inclusion of opportunity costs associated with scarce fuels and emission allowances.”
“New England’s fuel-security challenges do not lend themselves to easy solutions. Thus, the proposed time frame is necessary to allow for a systematic and deliberative regional process for examining the risks and possible solutions — a complex undertaking,” the RTO said. “A key question to be addressed in these discussions will be what level of fuel-security risk ISO-NE, the region, policymakers and regulators are willing to tolerate.”
The RTO noted that New England lacks indigenous fossil fuels production, leaving it reliant on imported fuels, including from five interstate natural gas lines whose winter capacity is mostly consumed by local distribution companies for heating. Generators are dependent on capacity released by utilities in the secondary market.
ISO-NE said it has made changes to its market design, operating procedures and systems since identifying fuel security as a problem during a cold spell in 2004. The RTO noted corrective actions it has taken, citing a change in the timing of the day-ahead market to give generators more time to procure gas; allowing market participants to modify their offers on an hourly basis to reflect changing fuel costs; Pay-for-Performance rules, which will take effect June 1; and the winter reliability program that Pay-for-Performance will replace.
But the problem has worsened as generators with onsite fuel have retired, largely replaced by natural gas-fired generators relying on just-in-time deliveries.
Changing Fuel Mix
In 2000, oil- and coal-fired power plants produced 40% of the electricity generated in New England, while natural gas fueled just 15%. Since then, the region added 16,000 MW of gas-fired generation while losing 4,600 MW of non-gas generating capacity.
By 2016, gas-fired generation was responsible for 49% of the RTO’s power, with coal and oil reduced to 3% of production, although they remain almost 30% of the region’s capacity. Natural gas’ generation share is expected to grow to 56% in 2026 while another 5,000 MW of coal- and oil-fired generation is at risk for retirement.
During the December 2017-January 2018 cold spell, oil and coal plants, which had been producing only 2% of the region’s electricity, were called on to supply one-third of New England’s power. Natural gas-fired generation dropped from almost half to less than one-quarter.
“With oil-fired generation operating at or near capacity, oil supplies, as well as emission allowances, at power plants around the region began to deplete rapidly over the two-week period, making system operations extremely challenging and significantly increasing the reliability risk to the system,” ISO-NE said.
The region, which has relied on dual-fuel capability in previous winters, said that option is becoming less viable “as emissions restrictions are tightening dual-fuel generators’ ability to use the oil-firing capability.”
The OFSA report was the first time ISO-NE had performed a deterministic analysis that looked at the entire three-month winter season between December and February as opposed to a single forecast winter peak day.
The study found that load shedding would be needed to maintain system balance in 19 of the 23 scenarios considered and that extended outages of any key energy facilities — the Distrigas and Canaport LNG terminals; the Millstone nuclear plant; or an interstate pipeline compressor station — would result in as much as 138 hours of load shedding.
The analysis said load shedding could be minimized with higher levels of LNG, imports and renewables, changes that would require new transmission and “advanced arrangements for LNG with assurances for winter delivery.”
While most of its response focused on fuel security, ISO-NE also cited as risks cybersecurity, physical security and geomagnetic disturbances, issues it said were being addressed “in other forums.”
MISO: Work Already in Progress
MISO’s filing focused on the practices it already has in place to promote resilience and pointed out that its stakeholder processes and projects have been geared toward resilience “for nearly two decades.” The RTO said it doesn’t have any “imminent or immediate” resilience concerns.
“MISO’s core foundation of ensuring regional reliability needs are met at the lowest possible cost has facilitated the creation of robust planning, operations, markets and security mechanisms that are utilized to not only identify, assess and avoid resilience threats, but also to mitigate any impacts that may occur from high-risk events,” the RTO said.
Vice President of System Planning Jennifer Curran said MISO already works with stakeholders to ensure daily grid reliability and resilience.
“Grid resilience is core to our foundation and day-to-day activities at MISO,” Curran said in a statement that the RTO issued in addition to the 52-page response to FERC. “We constantly evaluate our operations and look for opportunities to strengthen our systems, reduce risk and contribute to the dialogue and knowledge-sharing that benefits the industry and the power grid.”
MISO said it addresses resilience through its biennial Market Roadmap, a process in which it and its stakeholders identify the most pressing market improvements to undertake. (See MISO Accepting Market Roadmap Ideas.) The RTO also said it enhances resilience through gas-electric coordination, drills on severe weather and other emergencies, and its annual Transmission Expansion Plan process. It currently studies “approximately 6,500 extreme events impacting loss of multiple facilities on the transmission grid” and maintains a cyber operations team to monitor critical systems.
In researching disruptive events, it said it found only one scenario that would violate the one-day-in-10-years planning criteria: “the extreme and long-term event of the loss of the largest natural gas pipeline for the entire summer peak season.”
MISO’s generation mix has changed dramatically since 2005. | MISO
It also said the replacement for its market platform computer system was selected following a “comprehensive assessment to determine the system performance and security requirements that will be necessary to meet MISO’s long-term needs.” (See MISO Makes Case for $130M Market Platform Upgrade.)
While MISO said it generally agreed with FERC’s definition of resilience, it urged the commission to add a nod to the “changing nature of the electric grid.”
For FERC to facilitate a resilient grid, MISO said the commission should make sure “inflexible” critical infrastructure protection compliance standards do not limit cybersecurity measures. It also urged the commission to research how to value resilience in the transmission planning process and “actively support” more efficient interregional operations that can respond to disruptions.
MISO called for “broader introduction of advanced operational tools” that can improve situational awareness and congestion management. “Current limitations in both processes and tools restrict the efficient use of transmission and redispatch opportunities to fully leverage available infrastructure. These limitations result in fewer operational options to address unplanned events that may test grid resilience,” the RTO said.
As an example, it said, using the interregional transmission load relief (TLR) process to manage congestion may become inadequate as more intermittent resources join the grid. “RTO/ISO energy market advancements have facilitated the development of superior market-based congestion management tools, including redispatch, seams coordination and market-to-market processes that improve reliability and reduce costs (particularly when compared to TLR),” it said. It cited its coordination with PJM as “the model for seams operation” that could be applied “to advance interregional operations more broadly.”
But MISO also said resilience planning shouldn’t rest with RTOs and ISOs alone.
“The commission’s evaluation of resilience issues should not be limited to just RTOs and ISOs; rather, grid resilience is a national issue that broadly impacts the bulk power system. Additionally, to the extent the commission is interested in addressing concerns at the distribution level, the commission should work in partnership with state regulators to help ensure a coordinated effort,” MISO said.
NYISO Cites ‘Track Record,’ Current Initiatives
NYISO’s 26-page response noted that its most recent Reliability Needs Assessment concluded that the ISO will meet its transmission security and resource adequacy requirements through 2026.
It also identified six initiatives it is pursuing to respond to challenges resulting from “technological developments, economics, environmental considerations and public policies” transforming the grid: re-evaluating its ancillary services products and shortage pricing; ensuring that market price signals incentivize compliance with dispatch instructions; considering changes to the measurement of capacity to reflect resource performance during critical operating periods; evaluating deliverability and performance requirements for external capacity resources; potential enhancements to interregional transaction coordination; and better integration of energy storage and distributed energy resources.
It also said it will perform a “comprehensive re-evaluation” of its planning process to ensure it “stands ready to facilitate the transmission infrastructure additions and upgrades and other resources necessary to meet the evolving needs of the grid.”
In addition, the ISO said its markets “inherently value and support elements of resilience,” including the use of shortage pricing in the day-ahead and real-time markets. Since the 2013-2014 winter, the ISO said it has boosted the statewide 30-minute reserve requirement by 655 MW to 2,620 MW and implemented a new reserve region for Southeastern New York with a 1,300-MW operating reserve requirement.
It also cited its fuel inventories, gas-electric coordination and improved situational awareness from phasor measurement units added to the grid in recent years.
NYISO also pointed to the importance of its interconnections with neighboring regions, saying its exports helped ISO-NE survive fuel supply challenges during the cold weeks surrounding New Year’s Day and “provided significant levels of emergency energy” to PJM for five hours on Jan. 7.
The ISO said its public policy planning process could result in changes to require additional resilience beyond that necessary to achieve minimum reliability requirements or additional infrastructure to improve energy delivery capability. Thus far, the process has identified two transmission needs: the 345-kV transmission project in western New York, expected in service in 2022; and AC transmission additions to relieve congestion on the UPNY-SENY and Central East interfaces.
NYISO cited its transmission expansions among its efforts to enhance resilience. | NYISO
The ISO said that because there are differences of opinions regarding the definition of resilience, “the commission could potentially facilitate this dialogue through a technical conference to explore near-term concepts being considered across the diverse regions of the country.”
It also asked FERC to trust its stakeholder process, saying it “has a proven track record of success in addressing the challenges and opportunities facing the bulk power system and wholesale energy markets in New York.”
“In recognition of this success, the NYISO respectfully requests that the commission allow the NYISO to continue to work with its stakeholders in assessing and developing the enhancements necessary.”
PJM Seeks More Coordination with Pipelines, LDCs
PJM says its grid is stable and secure but urged FERC to demand changes to improve identification and mitigation of current vulnerabilities and future grid resilience challenges. The RTO also touted itself as a good example in several areas and asked FERC to make other grid operators follow its lead.
The RTO’s 84-page response also offered revisions to FERC’s proposed definition of resilience: “The ability to withstand or reduce the magnitude and/or duration of disruptive events, which includes the capability to identify vulnerabilities and threats, and plan for, prepare for, mitigate, absorb, adapt to and/or timely recover from such an event.” The RTO said the definition needs to “accurately reflect” grid operators’ capabilities without imposing “additional liabilities and … a new duty and standard of care.” FERC should also stipulate that enhancing resilience is one of grid operator’s responsibilities within regional planning, the RTO said, and that the commission has authority over resilience under its responsibility under the FPA to ensure “just and reasonable rates, terms and conditions of service.”
While acknowledging the risks of high-impact, low-frequency events, PJM also warned about “addressing vulnerabilities that evolved over time and threaten the safe and reliable operation.” It asked that FERC develop a process for grid operators to receive a review and feedback on their threat and vulnerability assessments based on national security information the commission has access to that grid operators don’t.
PJM said it has already begun addressing flaws within its operating reserve, shortage pricing, black start, energy price formation, and integration of DERs and storage. (See “Stakeholders Challenge PJM Decisions on Reserve-Shortage Identification,” PJM OC Briefs.)
Restoration Needs
Interestingly, PJM also asked that it be required to develop procedures to “permit non-market operations during emergencies, extended periods of degraded operations or unanticipated restoration scenarios … including provisions for cost-based compensation when the markets are not operational or when a wholesale supplier is directed to take certain emergency actions by PJM for which there is not an existing compensation mechanism.”
PJM said work like it’s doing to require dual-fuel capability at all black-start units should be extended throughout the country to identify “critical restoration units” and fuel-assurance criteria for them. (See “Black Start RFP,” PJM Operating Committee Briefs: Feb. 6, 2018.)
Pipeline Coordination
PJM also sought help in improving information sharing and coordination with gas pipelines, asking FERC to:
Require information sharing by pipelines by revising the “voluntary nature” of Order 787;
“Encourage” pipelines to share their threat and vulnerability analyses with grid operators, along with real-time contingency modeling and restoration-planning coordination;
Encourage development of additional pipeline services tailored to the flexibility needs of gas-fired generation “beyond today’s traditional firm/interruptible paradigm”;
Work with the Transportation Security Administration and the Pipeline and Hazardous Materials Safety Administration to improve “harmonization of cyber and physical security standards between the electric sector and the natural gas pipeline system”; and
Support more communication and coordination with local distribution companies supplying generators, perhaps by imposing obligations on local distribution companies through interstate pipeline tariffs.
Grid operators should also be required to show how they’re coordinating with other “critical interdependent infrastructure systems” like telecommunications and water utilities, PJM said.
SPP: One-Size-Fits-All Approach ‘Not Appropriate’
SPP agreed with the commission’s approach to evaluating resilience, saying FERC should continue its holistic approach and “consider the roles and relationships all participants in the electric industry, not just RTOs and ISOs, have with respect” to the grid’s resilience.
In its 21-page response, SPP wrote that it “agrees with the commission’s premise that a one-size-fits-all approach to resilience is not appropriate given the differences that can exist between the various regions.”
It stressed the importance of weighing the potential benefits against the costs in considering changes to current requirements. “Changes to requirements to address resilience could increase the costs of transmission owners’ systems, and those increased costs would ultimately impact transmission customers and their end-use customers,” SPP said.
“Accordingly, SPP respectfully submits that the perspectives and practices of non-RTO entities, including, without limitation, transmission owners, generation owners and state regulators, should be sought out and considered, as different participants in the electric industry can provide valuable insight regarding their experiences.”
ERCOT and SPP have to account for large amounts of wind energy within their resilience efforts. | NextEra Energy Resources
The RTO said FERC’s definition of resilience is “a reasonable way to capture the concept” and said it is consistent with a framework NERC is using. The reliability organization’s Issues Steering Committee told the Board of Trustees in February that most resilience definitions have two common elements: that resilience is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. (See “FERC’s McIntyre Says Resiliency Still of Interest in DC,” NERC MRC/Board of Trustees Briefs: Feb. 7, 2018.)
The committee’s framework includes four outcome-focused capabilities:
Robustness: the ability to absorb shocks and continue operating.
Resourcefulness: the ability to skillfully manage a crisis as it unfolds.
Rapid Recovery: the ability to restore services as quickly as possible.
Adaptability: the ability to incorporate and improve with lessons learned from past events.
SPP said its approach is based on “(1) resolving potential problems before they have a chance to disrupt daily operation … and (2) restoring daily operation as quickly and seamlessly as possible in the event a disruption does occur.”
It cited the resilience benefits of new transmission. “The construction of new transmission facilities pursuant to modern design standards enhance the robustness of the system,” SPP said.
“Continually evaluating risk and upgrading equipment, tools and procedures … facilitates rapid recovery by minimizing the extent and impact of disruptions.”
SPP said its approach remains adaptive, “as it is based on historical experience … combined with forward-looking evaluation of new risks and evolving technologies used in the industry.”
FERC approved ISO-NE’s two-stage capacity auction to accommodate state renewable energy procurements, with Commissioner Robert Powelson dissenting and Commissioners Cheryl LaFleur and Richard Glick leveling new criticism on the minimum offer price rule (MOPR) (ER18-619).
ISO-NE proposed the Competitive Auctions with Sponsored Policy Resources (CASPR) construct in January to address state regulators’ concerns about ratepayer costs for policy-driven resources and generators’ fears that out-of-market procurements would suppress capacity prices.
Under CASPR, ISO-NE will clear the Forward Capacity Auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction (SA), generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR. The RTO will phase out the renewable technology resource (RTR) exemption, which has allowed it to clear 200 MW of renewable generation in its capacity auction annually (to a maximum of 600 MW) without regard for the MOPR.
CASPR failed to win a 60% supermajority among stakeholders, and the RTO’s filing was opposed by its External Market Monitor, Massachusetts Attorney General Maura Healey, municipal utilities, Connecticut, the Natural Gas Supply Association, a coalition of environmental groups, the New England Power Generators Association and several merchant generators. (See ISO-NE Defends CASPR Against Protests.)
The opponents challenged the definition of sponsored-policy resources (SPRs) eligible for the SA; the cut-off date of Jan. 1, 2018; restrictions on interzonal transfers; and the phase-out of the RTR exemption without a “backstop” to ensure SPRs receive capacity obligations. They also expressed fears that “fictitious” resources would enter the auction to collect revenues from SPRs and that the construct would worsen the region’s fuel security concerns.
The commission rejected all the protestors’ concerns, approving CASPR as proposed. The commission did acknowledge concern over potential anticompetitive bidding, urging ISO-NE “to work with its stakeholders to pursue market enhancements” to strengthen market mitigation rules.
Powelson Dissent
Powelson, however, wrote a dissent calling the construct “a complicated, patchwork solution that will neither accommodate the desires of the states, nor send proper price signals to market participants.”
“The two goals that CASPR tries to achieve are fundamentally in conflict and cannot coexist in one market,” he wrote. “By trying to both accommodate state policies and protect the [Forward Capacity Market], CASPR will likely only accomplish one goal at the expense of the other. Today’s decision threatens the viability of the FCM to serve as a mechanism to ensure resource adequacy in ISO-NE, and therefore, it is unjust and unreasonable and should be rejected.”
Powelson said he shared the states’ concern that their ratepayers do not “pay twice” for capacity, as would happen if state-sponsored resources failed to win capacity commitments. “However, the states had the opportunity to foresee this ‘double-payment’ problem when they made the decision to support resources outside the market. … So unless the states are willing to reassume complete responsibility for resource adequacy, they must accept that the commission is required to take action to ensure the viability of the capacity markets.”
Powelson said CASPR will not prevent state-sponsored resources from suppressing prices, because they are exempted from the MOPR after their first year and thus permitted to offer into the market at a lower price that reflects their out-of-market revenues. “Instead of incentivizing developers to compete for market revenues, the message the commission is sending to market participants is that the best way to ensure the future viability of a particular resource is to seek state support,” he said.
In addition to suppressing prices, Powelson said CASPR also may fail to accommodate state-supported resources. “The FCM has been clearing at lower prices over the past few years, making it unlikely — if this trend continues — that a resource near retirement (i.e., one with high going-forward costs) would clear in the primary auction. As a result, there may be few or no resources eligible to swap capacity supply obligations with eligible state-supported resources.”
Glick: MOPR Rationale ‘Ill-Conceived’
Glick took the opposing view in supporting CASPR, but he dissented over the order’s “suggestion” that state-sponsored resources must either be subject to MOPR or some alternative mechanism for ensuring state policies don’t interfere with the capacity market. “That rationale — which is not adopted by a majority of the commissioners that support the order — is ill-conceived, misguided and a serious threat to consumers, the environment and, in fact, the long-term viability of the commission’s capacity market construct,” Glick said.
Instead, Glick wrote, the commission should “stop using the MOPR to interfere with state public policies and, instead, apply the MOPR in only the limited circumstance for which it was originally intended: to prevent the exercise of buyer-side market power.”
Glick contends FERC has misinterpreted the Federal Power Act, failing to respect “that states, not the commission, are the entities primarily responsible for shaping the generation mix.”
“The fact that state policies are affecting matters within the commission’s jurisdiction is not necessarily a problem for the commission to ‘solve’ but rather the natural consequence of congressional intent.
“I do not believe that it is — or should be — the commission’s mission to create an electricity market free from governmental programs aimed at legitimate policy considerations, such as clean air and combatting climate change,” he continued. “Nevertheless, today’s order appears to suggest that it is appropriate for the commission to insert itself into the states’ domain.”
Glick said the commission’s goal of ensuring “investor confidence” in the capacity market will result in over-procurement; with significant excess capacity, ISO-NE’s auction should send price signals inducing high-cost resources to retire. “There is nothing in the record that supports the conclusion that, to ensure resource adequacy in New England, the commission must act to ensure that investors in all forms of generation — both existing and new — remain confident that they will recover their costs,” he said.
Glick also said his support for CASPR is predicated on whether it facilitates the entry of state-supported resources into the FCM.
“To the extent that, as implemented, the CASPR proposal does not facilitate the entry of state-sponsored resources, it may render ISO-NE’s tariff unjust and unreasonable,” he concluded.
(Editor’s Note: Although Glick supported CASPR, his office said he was recorded as a no vote, making the tally 3-2. An earlier version of this article reported the vote as 4-1.)
LaFleur: MOPR ‘A Blunt Instrument’
LaFleur also supported CASPR but issued a concurring statement joining Glick in disagreeing with paragraph 22 of the order, which she said suggested MOPR should be the “standard solution” against the impacts of all state policies.
LaFleur said MOPR is “a blunt instrument” and that other constructs, such as carbon pricing, can also achieve state objectives within the market.
“I acknowledge that these issues are not easy, as evidenced by the split commission decision today. I also believe that these issues do not lend themselves to a cookie-cutter solution to be broadly applied across all regions,” she wrote. “I therefore hope we receive market design proposals developed by other RTO/ISOs and their stakeholders. Without prejudging any specific proposal, I believe we should be open to region-specific solutions of different types.”
CARMEL, Ind. — In what marked a first for the grid operator, MISO last week detailed its spring readiness and said there’s a small possibility of emergency conditions.
While the RTO expects to have adequate resources on hand to meet sometimes volatile demand, it might also have to rely on emergency operating procedures during what was once considered a calm shoulder period, stakeholders learned during a March 8 Market Subcommittee meeting.
“Projected spring transmission and generation outages show challenging but manageable outages, similar to recent years,” said Jeanna Furnish, MISO manager of resource planning and transmission studies.
MISO’s analysis shows a 25% probability it will need to invoke systemwide emergency operating procedures during the spring, but only if either loads or forced outages are higher than normal, Furnish said.
“My presence here isn’t to cause any alarm but to talk about … the realities of challenges that may exist on the system,” Furnish said.
Based on forecasts from the National Oceanic and Atmospheric Administration, the RTO is expecting a warmer-than-usual spring for MISO South and normal to above-normal precipitation in most of its footprint.
MISO said volatile spring loads that deviate from forecasts will require careful coordination of outages.
| MISO
Furnish pointed out that MISO maintains a nonpublic member webpage called “Maintenance Margin” that keeps a monthly forward account of how many megawatts can be taken out of service without affecting reliability. The RTO uses the data to inform generators when it predicts outages will have an impact on reliability and will recommend alternative outage schedules.
Last year, high generation and transmission outages paired with unseasonably elevated loads in MISO South produced an early April maximum generation event, unusual for a shoulder season, prompting the RTO to call on load-modifying resources for the first time in a decade. The event prompted the Independent Market Monitor to call for MISO to have increased authority over approving maintenance outages. (See 4 LMRs Face Penalties after MISO Max Gen Emergency.)
Customized Energy Solutions’ Ted Kuhn asked if Maintenance Margin provided any indication that emergency conditions were imminent last spring.
“Was the Maintenance Margin showing a deficit, or did we just fall into a black hole?” Kuhn asked.
Furnish didn’t know but said MISO continues to work with stakeholders to enhance outage coordination, including developing reserves that can be available within 30 minutes and improving congestion management with PJM at the seams by swapping control of flowgates.
MISO did not venture a guess about the projected spring peak. The RTO is planning for a 126-GW summer peak load, which it predicts will require a 17.1% planning reserve margin. (See MISO Planning Reserve Margin Climbs to 17% for 2018/19.)
WASHINGTON — Growing the electric vehicle market beyond early adopters will require creative regulations, an expanded charging network and a vastly improved customer experience, speakers told the Institute for Electric Innovation’s (IEI) spring 2018 forum Wednesday.
“The early adopters were able to deal with some of the challenges of interacting with five different charging networks and the fact that sometimes stations didn’t work; maybe they’re in the back of a parking lot that wasn’t well lit and it was kind of dangerous,” said Scott Fisher, vice president of market development for Greenlots, which sells EV charging software and services.
Fisher said he senses increased momentum for EVs, with moves in Europe to ban diesel vehicles and Volvo announcing all its models will be electric-powered by 2019.
“There seems to be a commitment among large credible companies to create this positive customer experience. So, it’s not going to cater to the 1% anymore. … To get to that 5% or 10% — that next stage of early adopters — thinking about the customer experience that’s needed” is crucial, he said. “Some of it’s in place, but making it more consistent is a really important objective.”
Alan M. Oshima, CEO of Hawaiian Electric and the owner of a plug-in Ford Fusion, agreed. “The [conflicting] charging protocols we have right now is even worse than Betamax vs. VHS,” said Oshima, who moderated the panel discussion.
“It can’t be depending on niches. It can’t just work in California or Massachusetts or New York,” said Mark S. Lantrip, CEO of Southern Company Services. “Somehow we’ve got to think about how we bring everyone along. Until that, it’s going to be a series of fits and starts.”
Exhibit A is Georgia, which — thanks to a $5,000 state tax credit — was the fastest-growing EV market in the U.S. between 2010 and 2014, according to the Edison Electric Institute, which funds the Edison Foundation and IEI. When the tax credit expired, EV sales in the state plummeted. (The federal government continues to offer a $7,500 tax credit.) Still, with 25,500 EVs as of 2016, the state ranked second to California in EV sales between 2011 and 2016.
Wooing Newcomers
Although U.S. EV sales increased by 26% last year to almost 200,000, they still represented only 1% of new vehicle sales. Globally, EV sales jumped by more than 60% last year, with China responsible for more than half the sales in the third quarter.
Fisher said the best marketing EVs could get is more charging stations. “Whenever I talk to my liberal friends in Princeton, N.J., where I live, [they say] ‘Oh, that’s a great car, but where would I charge it?’ If I have to explain to them, I’ve already kind of lost them.”
Lisa Wood, IEI’s executive director, said EVs also will benefit from the increasing visibility of electric fleets such as city buses, United Parcel Service delivery vans and school buses that can provide energy storage in summer. Electric companies have increased their EV fleets by more than 40% since 2015, according to EEI, with more than 70 companies investing more than $120 million last year alone.
Lantrip said proponents are discouraging potential adoptees from making the switch with talk of EVs’ potential as distributed energy storage.
“We’re trying to get people to just even entertain the idea of buying [an electric] car, and what I see in so many presentations on electric vehicles is they immediately go to vehicle-to-grid, vehicle-to-home, and that freaks out the average new potential buyer … because they just don’t get it or want it. It’s like, ‘You’re going to drain my battery?’ We have to separate those two conversations.”
Lantrip predicts EV penetration will not surge until there is price parity between EVs and conventional vehicles and charging times are reduced to five minutes. “We have to manage our expectations,” he said, warning that current investments in the technology and charging infrastructure should be limited to “no regrets” steps while the market remains small and different technologies are competing for dominance.
About 80% of EV charging is done at home, where residents can use either a Level 1 charger (a standard AC outlet providing up to 1.5 kW of electricity that takes 30 hours to fully charge a 115-mile battery) or a Level 2 (a 240-V AC outlet delivering up to 9 kW, which can charge in 5.5 hours). Commercial charging locations with DC-powered fast chargers deliver 50 kW and reduce a 90-mile charge to 30 minutes. In Europe, a new generation of chargers is being installed offering 350 kW, which would complete a charge in 10 to 15 minutes, but no vehicles currently offered can use them.
Norm Saari, a member of the Michigan Public Service Commission, shared Lantrip’s concern about investing in technology that could be rendered obsolete.
Saari said policymakers could be hesitant to act because of uncertainty over what is the “proven, right technology.”
“[Do] you want to have a Level 1 or Level 2 or DC fast charging? Or do you want inductive charging on the road? Or let’s forget about that. Let’s go to hydrogen fuel cells instead. There’s a lot of issues that still have to be resolved,” Saari said.
The Michigan commission held its second technical conference on EVs in February. Saari said he and his colleagues are concentrating on four primary areas: customer education, rate design, the impact of EVs on the grid and charging infrastructure — “who is going to build what, where and how is it going to be priced out?”
Under the “make ready” model, the utility supplies the service connection and supply infrastructure, with the customer supplying the charging equipment. Another model would have the utilities assume full ownership of the charging equipment — the opposite of the business-as-usual model in which the customer is responsible for all equipment.
Saari said he expects both DTE Energy and Consumers Energy to request money for EVs in rate cases the companies will file later this year.
Lantrip said Southern Co.’s Georgia Power will propose several pilot projects to regulators later this year on getting EVs to low-income customers. “It could run the gamut from something like Zipcars or it could be electrified Ubers targeted in certain areas or something in between that,” he said.
Lantrip called on utilities and regulators to be “creative in developing new rate designs.”
Fisher said that although higher EV penetration will mean more electric demand, the grid investments required to expand the market are “going to turn out to be a wise ratepayer investment.”
In California, which has more than 277,000 EVs — about half of the nation’s total — a joint study by the state’s three investor-owned utilities reported the costs of distribution upgrades to serve EVs have been “immaterial.” But Southern California Edison has said 25% of its network must be upgraded to support new chargers.
Dan Adler, vice president of policy for the Energy Foundation, which promotes energy efficient buildings and appliances, said the industry needs “durable” coalitions to ensure regulatory policy does not become an obstacle to growth. “You get better policy outcomes … if the coalition is formed ahead of time,” he said.
Role for Gas Stations
From the audience, D.C. Public Service Commission Chair Betty Ann Kane asked whether the industry was working with gas stations that might otherwise become “stranded investments” in an electrified transportation system.
“If you get the charging times down, there’s an opportunity to work with that community,” Adler said. Because gas stations make most of their profits from snack and beverage sales and not fuel, Adler said, station owners may welcome a new way to generate foot traffic.
Lantrip said new gas stations are increasingly being designed to be fit with electric charging. He said they may be the best locations for charging in urban areas where few residents own garages. Last October, Royal Dutch Shell announced it was buying one of Europe’s largest EV charging providers; it is also beginning to add EV chargers at its stations in the U.K. and the Netherlands.
AUSTIN, Texas — Texas Public Utility Commissioner Brandy Marty Marquez quietly resigned Thursday, saying she will pursue life in the private sector after two decades of public service.
Her resignation is effective April 2.
The announcement came several hours after the PUC’s open meeting. There was little hint of what was to come during the meeting, other than when Chairman DeAnn Walker, a close friend of Marquez, choked up in announcing the commission was going into a closed session to “deliberate personnel matters.” Walker avoided looking at Marquez as she gathered her composure.
“Is that it? Can we go?” Marquez said, smiling broadly. She had already met separately with Walker and fellow Commissioner Arthur D’Andrea before the open session to tell them of her decision.
Marquez’s resignation will mean the three-person PUC has completely turned over since last May, when longtime Chair Donna Nelson left. Her departure was followed by that of Ken Anderson, who resigned after his term expired in August. They were the two longest serving commissioners in PUC history, each having served eight years or more.
Marquez was appointed to the commission in August 2013 by then-Gov. Rick Perry and reappointed by Gov. Greg Abbott in 2015. Her term was to expire in September 2019.
She said in a statement she leaves the commission knowing it will continue to serve Texas “with fairness under the principled leadership” of Walker and D’Andrea.
“Supported by the best staff of any Texas agency, the PUC will continue working tirelessly on behalf of stakeholders and consumers,” Marquez said. “I am honored to have served my fellow Texans. I leave with a happy heart.”
Despite speculation that she would return to the political arena, Marquez said she plans to enter the private sector. She served as Perry’s policy director during his successful 2010 gubernatorial campaign and was his chief of staff during Texas’ 83rd legislative session. The Legislature next meets in January 2019.
“The state of Texas has benefited greatly from the more than 17 years of dedicated service from Brandy Marquez,” Abbott said. “Her commitment and passion for public service have been on full display throughout her impressive career. I commend Brandy for her extraordinary accomplishments during her tenure as commissioner.”
While at the commission, Marquez also served on the Texas Reliability Entity, which serves as the PUC’s reliability monitor for the ERCOT region and enforces NERC standards.
Commission Directs ERCOT to Revise ORDC
The PUC directed ERCOT to begin the process of removing reliability unit commitment (RUC) capacity from the ISO’s operating reserve demand curve (ORDC), which creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves (Project No. 47199).
Marquez said her preference was to wait until after the summer, when operating reserves are expected to be tight, but she joined with Walker and D’Andrea in the decision.
“I think taking out the RUC is the right thing to do,” Walker said. “I don’t think it’s going to make a significant difference for the summer, but it sends the signal we’re fully supportive of the energy-only market, and we will stand behind it.
“I want to be clear that this decision is based on what I believe is the correct decision, and not because anyone has made me believe this,” she continued. “I’ve been there a long time, and I didn’t need help getting there.”
“I can’t envision anybody … who believes in this market that wouldn’t support this change,” Marquez said. “We’ve never gone into a summer like this. It will be an incredible learning opportunity for our market. Anything we’re preparing for now will potentially look very different after August.”
PUC staff have also recommended removing the RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics. Some market participants have pushed back, sharing Marquez’s view that it would be best to wait until after the summer to make the change. (See “Participants Caution Against Market Changes Before Summer,” Overheard at the Infocast ERCOT Market Summit.)
ERCOT staff filed a report with the PUC on March 2 that indicates removing RUC capacity from the ORDC would have provided generators an additional $6.6 million and $18.6 million in revenue in 2016 and 2017, respectively. Given that total generator revenues in ERCOT were about $8.4 billion in 2016 and $9.5 billion in 2017, the adders respectively represented about 0.07% and 0.2% of total revenue, staff said.
The ISO study estimated it would cost $15,000 to $25,000 to modify ERCOT’s systems to remove online RUC and RMR resources from the ORDC capacity value, and could be done internally within 60 days.
ERCOT will include the revised protocol language for its April 10 Board of Directors meeting.
PUC to Intervene at FERC in MISO’s Docket
Following the PUC’s executive session, Walker announced the commission would be intervening in MISO’s application before FERC to create targeted market efficiency projects, a new category of small interregional transmission projects (ER18-867).
Walker also said Thomas Gleeson, the commission’s director of finance and administration, will serve as its interim executive director until a full-time replacement can be found. Brian Lloyd resigned from the position March 1, after seven years. (See Texas PUC Executive Director to Resign.)
