SACRAMENTO, Calif. — The California Energy Commission rocked the energy world Wednesday when it unanimously approved a mandate requiring new homes in the Golden State to include rooftop solar, making it the first state to move to adopt such a rule.
The 2019 Building Energy Efficiency Standards would apply to most newly constructed buildings and additions to existing structures built after Jan. 1, 2020, requiring builders to add solar panels and encourage battery storage systems and heat pump water heaters to improve energy efficiency. They also update standards for indoor and outdoor lighting by incentivizing maximum usage of LED lighting in non-residential buildings.
The proposed rules also include three other major components in addition to solar: updated thermal envelope standards that prevent interior/exterior heat transfer; residential and nonresidential ventilation requirements; and nonresidential lighting requirements. California for the first time extended the standards to health care facilities.
The package still requires approval from the state’s Building Standards Commission. CEC spokeswoman Amber Pasricha Beck told RTO Insider the building commission usually approves what the CEC sends over.
In discussion ahead of the vote, CEC members said the measure will cut energy bills and reduce greenhouse gas emissions, noting that the cost of solar panels has dropped dramatically in recent years. The vast majority of comments filed in the proceeding favored the changes.
CEC Chairman Robert Weisenmiller said that California has expanded its economy in recent years even while reducing greenhouse gas emissions. Implementing the standards will require close work between the commission and the building industry, which he said he wants to keep “vibrant.”
“This is just a milestone, but there is a hell of a lot of work to go between now and 2020, and we really have to keep our eye on the ball to make this work smoothly,” Weisenmiller said. “There will be some surprises, and we will need to stay on top of this, but the bottom line is we are going to focus on making this happen.”
“Once we get there, yeah, we can talk about the future,” he added.
The CEC’s Wednesday meeting drew an unusually heavy media interest for a commission decision, and by the evening even the BBC had picked up the story.
The measures will make it more expensive to build new homes in a state already known for some of the highest housing and construction costs in the country, but the commission said it will be worth the expense.
While the new standards will add about $9,500 to the cost of a new home, they will save homeowners $19,000 in energy and maintenance costs over 30 years, the CEC said. The changes would add about $40 to the average monthly mortgage payment but save $80 per month on heating, cooling and lighting bills. Nonresidential buildings will use about 30% less energy under the standards, mainly because of lighting upgrades, according to the agency.
The explosion of rooftop solar in California has led to massive amounts of solar output coming online and offline each day as the sun rises and sets, requiring increased use of fast-ramping generation resources to compensate for the variability. Asked about the impact on California’s “duck curve” that illustrates the steep ramps, CAISO spokesman Steven Greenlee said Thursday that zero-net energy home projections are included in the CEC’s Integrated Energy Policy Report (IEPR) forecasts, which the ISO uses in its transmission planning process.
“Our planning already takes into consideration state policies,” Greenlee told RTO Insider. “We have been managing increasing amounts of renewables coming onto the grid for many years and use the IEPR forecasts for transmission planning. However, as the amount of renewables on the system grows, grid operators need increased visibility into behind-the-meter resources, including developing practices for aggregated information sharing and operational coordination.”
Solar Energy Industries Association CEO Abigail Ross Hopper said: “This is an undeniably historic decision for the state and the U.S. California has long been our nation’s biggest solar champion, and its mass adoption of solar has generated huge economic and environmental benefits, including bringing tens of billions of dollars of investment into the state.”
California Building Industry Association CEO Dan Dunmoyer said the standards “struck a fair balance between reducing greenhouse gas emissions while simultaneously limiting increased construction costs.”
Parties issuing statements in favor of the proposal include the Natural Resources Defense Council, Habitat for Humanity San Joaquin County, California Solar & Storage Association, California Air Resources Board, Southern California Edison, Pacific Gas and Electric, and Tesla.
Opposition to the standards was mostly limited to individual commenters, some addressing aspects of the standards other than the rooftop solar mandate.
At the meeting, longtime Colorado-based energy attorney and consultant Peter Esposito said he only learned of the rooftop solar proposal on Tuesday.
“I initially thought it was ‘fake news,’ and I would like to add that I think you are making a big mistake,” Esposito said. He advocated against a technology-specific approach and said consumers should be able to choose how to meet greenhouse gas emission goals.
“Please don’t lock out other technologies,” he said, without being specific as to what particular technologies he was referring to.
The Public Utility Commission of Texas on Thursday delayed its final approval of Southwestern Public Service’s request to build a 478-MW wind farm in West Texas, allowing the company and other parties in the docket time to provide written answers to the regulators’ latest questions and recommend further revisions to the draft order (46936).
SPS said it could make a reply filing on May 16, clearing the way for the PUC’s final approval during its May 25 open meeting.
PUC Chair DeAnn Walker apologized for the two-week delay, saying she developed the questions as she reviewed the proposed order.
PUCT Chair DeAnn Walker (left) and Commissioner Arthur D’Andrea share a laugh. | PUCT
“I fully intended to get it done today,” she said. “If anything should be clear to anyone in this industry, it’s that I need to be comfortable with what I sign.”
The wind farm is part of a 1.23-GW project by SPS parent Xcel Energy that will provide renewable energy to SPS customers in Texas and New Mexico. The utility says the project will save its retail customers about $1.6 billion in energy costs over its 30-year life.
PUC staff filed a draft order on May 9 that revised its previous version, eliminating provisions rendered moot by a settlement reached in March between SPS and staff, the Department of Energy, the Office of Public Utility Counsel (OPUC) and seven other consumer groups, area cooperatives and landowners.
Walker filed a memo that same day outlining her concerns about SPS’ exceptions to the latest order. She said some rate-related findings suggested in the order would be more appropriately made in a future rate proceeding, and that some sections of the order “lack the clarity” necessary for inclusion in a PUC filing.
She focused much of her discussion on the order’s proposal to recover costs by flowing production tax credits through fuel, asking the parties to explain why the commission should deviate from its “well-established principles” of matching costs and benefits.
“The benefit of production tax credits flowing through fuel accrues to some customer classes more than the costs those same customers bear through their base rates,” Walker wrote. “Conversely, customers who bear more of the costs in their base rates receive less of the benefits, because they flow through fuel. This does not meet the commission’s typical matching principle.”
Attorney Rex VanMiddlesworth, representing Texas Industrial Energy Consumers, said the PTCs should flow through fuel as they are earned, pointing out that they are used when bidding into the markets.
“You’ve got to have those PTCs going through fuel, otherwise the fuel costs won’t reflect the actual [bid] … into the LMPs. You would be bidding in at -$28, and the customers wouldn’t be getting that -$28,” VanMiddlesworth said. “PTCs are kind of a classic energy allocation. When we have a rate case, if it’s litigated, I wouldn’t be surprised to say at least part of the PTC ought to be allocated on an energy basis.”
SPS President David Hudson reminded the commission that the utility has said the wind farm will be an energy resource, rather than a capacity resource.
SPS’ legal counsel Ron Moss, with President David Hudson to his left, answers questions. | PUCT
“Our intention all along is to allocate the base rate case cost on energy,” Hudson said. “It’s going to be consistent with how the fuel goes back and the PTCs go back. Everything is going to be synchronized. It’s just some parties thought there might be a capacity addition in the future.”
“We’ve never had a plant like this. Every other plant we had was to meet demand,” he said.
VanMiddlesworth said the SPS facility is being built “largely because of PTCs,” which make it profitable over the first 10 years.
“You have your decision then, we have our rights to address it at that time,” he said. “We don’t foresee it as a problem. We do want the ratepayers to get the PTCs as they’re earned.”
Rayburn Country Picks 44.6 Miles of Trinity Valley Assets
The commission also approved the transfer of certificate of convenience and necessity rights for 44.6 miles of existing 138-kV transmission lines in East Texas from Trinity Valley Electric Cooperative to Rayburn Country Electric Cooperative (Docket No. 47951).
Rayburn already owns or leases more than 360 miles of 138-kV lines that serve wholesale loads in both ERCOT and SPP. The transferred facilities are operated in ERCOT.
Connecticut’s General Assembly on Wednesday passed a bill that doubles the amount of renewable energy utilities must use to serve load — 40% by 2030 — while also revoking net metering guarantees that ensure rooftop solar owners earn retail prices for their excess electricity.
The bill now goes to Gov. Dannel Malloy, who said the legislation (SB 9) will help cut emissions and create “good jobs in the green economy, all while decreasing costs for ratepayers.”
Connecticut state capitol building in Hartford
The bill also extends $8 million in renewable incentives for commercial users and allows them to sell their output to utilities in 15-year contracts. The new law creates a 25-MW community solar program for residential customers who cannot afford to install their own solar panels.
Peter Rothstein, president of the Northeast Clean Energy Council, said in a statement that while the bill “contains a robust expansion of the state’s renewable portfolio standard,” it also includes “counterproductive provisions that will significantly harm the state’s rooftop solar market.”
Net metering “will essentially be dismantled,” Rothstein said.
A coalition of solar developers, solar proponents and environmental groups, including SunRun, Vote Solar and the Connecticut Citizen Action Group, had also urged state lawmakers not to pass the law without amending its net metering language.
“Instead of restricting customers’ ability to choose solar and imposing a cap on solar investment, the bill’s community solar program should be strengthened to expand solar access,” the coalition said. “Rather than building Connecticut’s local clean energy economy, the current bill language puts the future of solar in Connecticut and thousands of jobs at risk.”
WASHINGTON — A panel of electricity industry leaders — including Public Service Enterprise Group CEO Ralph Izzo — came to the House Energy Subcommittee on Thursday prepared to talk about the importance of transmission infrastructure, but the visit was mostly in vain.
Votes on the House floor kept the hearing to about 90 minutes, most of it taken up by the prewritten opening statements by subcommittee leaders and the panelists. Subcommittee members barely asked any questions, and none were directed to either Izzo or Jennifer Curran, MISO vice president of system planning.
In the little time allotted to them, the panelists made clear that FERC Order 1000, which opened transmission development to competition in 2011, was not working as intended, with very few projects being approved.
But they differed in their overall assessment of the order. Izzo called for Congress to outright abolish the rule, while former FERC Commissioner Tony Clark repeated his past assertion that the order was “well-intentioned” but clearly needs revisiting by the commission.
The order replaced RTOs’ “collaborative, bottoms-up approach to transmission planning with a complex bureaucracy, where the name of the game is completing a compliance checklist that may not actually result in transmission development,” Clark said. He pointed to MISO’s multi-value projects as an example of pre-Order 1000 developments that were impactful.
Rob Gramlich, president of energy consultancy Grid Strategies, submitted detailed written testimony highlighting the benefits of the grid in lowering consumers’ costs and allowing access to resources in other regions. Among his recommendations was that the Energy Department use the never-applied Section 1221 of the 2005 Energy Policy Act, which allows the secretary of energy to designate transmission corridors in the national interest and for FERC to site and permit projects in those corridors.
“I recommend that for specific extra-high-voltage (e.g., 500 kV and up), long-distance lines that provide broad multistate reliability benefits and long-term consumer benefits, where state approval has been withheld after thorough consultation, DOE and FERC should be encouraged to be willing to use the current authority,” Gramlich wrote.
In the little time she spoke, Curran only gave general information about her RTO, lauding its transmission planning processes and reliability record. Also in attendance were Edward Krapels, CEO of Anbaric Development Partners, and John Twitty, executive director of the Transmission Access Policy Study Group.
FERC should let RTO stakeholder processes work and not issue broad and costly new mandates, most commenters told the commission in its proceeding on grid resilience (AD18-7).
RTO Insider’s review of more than 60 of the dozens of comments filed ahead of the May 9 deadline indicated widespread support for RTOs’ requests in their initial filings in March for time to discuss the issues with stakeholders, more coordination with natural gas operators and more information on cyber threats. (See RTO Resilience Filings Seek Time, More Gas Coordination.)
But many commenters criticized PJM’s call for setting firm deadlines for rule changes, saying the RTO’s proposals would increase costs without necessarily improving resilience. Several commenters, including Edison Electric Institute and the National Rural Electric Cooperative Association (NRECA), suggested FERC schedule one or more technical conferences on the issue. Numerous commenters called for cost-benefit analyses of any new requirements.
“The record in this proceeding does not support any universal resilience standard or tariff changes requirements to be applied to all RTOs/ISOs. To the contrary, the record demonstrates that RTOs/ISOs have different resilience issues and priorities, and requiring all RTOs/ISOs to follow PJM’s proposed schedule on the issues pertinent to PJM will undermine each RTO/ISO’s efforts to address the specific challenges within its region,” they said. “Thus, the commission should reject PJM’s requests and allow individual RTOs/ISOs to pursue the resilience-related issues and initiatives they have identified in their region through collaborative efforts with their stakeholders and pursuant to the time frames they have established.”
Others, including the Advanced Energy Management Alliance, agreed that RTOs should continue their existing efforts to address their unique challenges. “PJM’s explanation of the need for changes to certain energy and ancillary market rules is helpful to inform the commission as to areas PJM is working on, but PJM cannot ask FERC to require rule changes to be filed in pre-emption of the stakeholder process or development of an evidentiary record that change is necessary.”
After rejecting the Department of Energy’s call for price supports for coal and nuclear generators in January, the commission asked its six jurisdictional RTOs and ISOs to respond to two dozen questions on resilience. This week’s deadline was for responses to the RTOs’ comments.
The comments touched on topics including FERC’s jurisdiction, fuel security, cyber threats and climate change, as well as individual regional issues.
Jurisdictional Concerns
Several commenters raised jurisdictional issues, noting that states, not FERC, have authority over distribution systems where most outages occur. Arizona Public Service said NERC’s reliability standards already address resilience.
“Before taking any additional steps to address resilience, the commission [should] consider the … comprehensive federal, state and industry efforts [that] address all levels of the electric grid and significantly contribute to ensuring” resilience, APS said. The utility criticized proposals it said “are clearly focused upon expanding the role of ISOs and RTOs and are, without understanding efforts at the state level and among utilities commercially, premature.”
The Pennsylvania Public Utility Commission asked FERC to “clearly articulate” its jurisdiction regarding resilience, saying it disagrees with PJM’s assertion that resilience is “‘within the commission’s existing authority with respect to the establishment of just and reasonable rates under the Federal Power Act.’ Therefore, clear and precise justification of FERC’s authority on this matter will be beneficial prior to any initial steps in regulating resilience,” the PUC said.
Entergy also disagreed with PJM’s “overly broad” interpretation of the commission’s jurisdiction.
The Large Public Power Council (LPPC) agreed with commission’s proposed definition of resilience but urged that “to the extent further rules or standards are considered, FERC must be mindful of the statutory limits on its authority,” saying the Federal Power Act does not provide the agency a general grant of authority “to take action on reliability or resilience outside its specific statutory role in the approval and enforcement of standards.”
The LPPC also contended there is “no basis” for applying any rule governing resilience to non-RTO areas, as had been recommended by MISO and PJM. “This is not an issue within FERC’s domain in non-RTO regions, where states and localities maintain authority over generation investment decisions and cost recovery,” the group said.
The Electric Power Supply Association sees it differently. “Resilience must be a priority in all regions of the country, not only those served by independent system operators or regional transmission organizations,” EPSA said. “Therefore, it is important for the commission to extend its inquiry on the holistic examination of resilience to all jurisdictional entities, particularly transmission owners and systems outside of ISOs/RTOs.”
The American Petroleum Institute said PJM’s proposals regarding gas-electric coordination — such as requiring interstate pipelines to offer new transportation services and build new infrastructure — are unnecessary and may be beyond FERC’s jurisdiction under the Natural Gas Act.
LG&E and KU Energy warned FERC against undermining existing state processes, saying its resource planning and transmission and distribution operations are working well, and noting that it is not part of an RTO. In 2017, the utilities said, they attained their lowest forced outage rate since 2004 at 3.46% of its baseload generation.
The Transmission Access Policy Study Group, which represents transmission-dependent utilities, said FERC should give RTO stakeholders time to build consensus on issues within their purview and leave distribution systems to state and local regulators.
Cyber Threats
PJM’s Transmission Owners Agreement-Administrative Committee said their members need more information from the government on potential cyber threats. “The threat data that resides at, for example, the Department of Energy, Department of Homeland Security, National Security Council and Department of Defense is vital for the RTO/ISOs to have access to for developing and implementing effective protection mechanisms,” they said.
“Therefore, it is essential that the commission develop a process by which PJM may receive verification concerning the reasonableness of vulnerability and threat assessments based on internal government data that has not been made available to RTOs on national security grounds.”
Exelon said FERC, DOE and DHS should participate in the development of modeling scenarios and create a “design-basis threat” to provide a baseline against which RTOs can measure their resilience efforts.
Climate Change’s Role
The Center for Climate and Energy Solutions said that FERC’s scope of grid resilience lacks an acknowledgment of climate change and how it could hinder resilience.
The environmental nonprofit said that although it would prefer FERC order “an economy-wide pricing mechanism” to absorb the economic impacts and even prevent some physical impacts of climate change, it said the commission should at least ensure that wholesale power markets are “internalizing the costs of carbon emissions” through carbon pricing.
Mobile substation | AEP Texas
The center added that increasing regularity of droughts threatens cooling systems for generating stations and rising temperatures will impede the capacity of bulk transmission lines to transport power. The nonprofit called on FERC to convene a technical conference to explore best practices for an industry coping with global warming.
“Climate science and lived experience show that historical conditions are no longer a reliable predictor of future conditions,” Pacific Gas and Electric said. “As issues arise in the future, PG&E encourages the commission to consider the risks of climate change when making decisions that could affect stakeholders’ ability to make climate-smart investments, or to make other decisions to address climate resilience for the future.”
Fuel Supplies
Numerous commenters cited the certainty of fuel supplies as an essential element of resilience.
NERC said FERC should consider encouraging firm transportation, multiple pipeline connections and dual-fuel capability for gas generators. “Further, the commission could consider requiring that resource adequacy assessments account for potential reliability ramifications associated with the ‘just-in-time’ natural gas fuel delivery model.”
“Fuel security risk is the most important factor to include in the commission’s definition of resilience and in its evaluation of grid resilience generally,” the American Coalition for Clean Coal Electricity said. The American Coal Council said coal generation retirements are a threat because intermittent resources can’t always be counted on.
Basin Electric Power Cooperative said its fossil generating units continue to be affected by markets “that fail to adequately compensate resources” for providing “essential electric service” in the wholesale markets.
The North Dakota co-op called for “equity across all fuel types,” saying the RTOs’ comments did not address the “preferential treatment” wind generation receives. It said a new ramp product, “if structured appropriately,” could reflect the value of stand-by products and provide “sufficient mitigation for assets that must stay online and incur losses” to backfill wind.
The Electricity Consumers Resource Council and industrial energy users warned against using resilience as a pretext for a “bailout” of coal and nuclear plants, adding, “No action to advance resilience can be considered ‘just and reasonable’ if it has not considered the impact to consumers and how to minimize that impact.”
Americans for a Clean Energy Grid, a coalition supporting a “fully electrified” society, noted that this winter’s “bomb cyclone” forced Northeast grid operators to rely on more expensive generation such as coal, oil and dual-fuel units, even while wind output — stranded by transmission constraints — was higher than normal during the weather event. “Thus, while wind power can be more reliable than other resources during extreme winter weather, it is limited by interregional transmission constraints,” the group said.
Role of Capacity Markets
While many commenters, including EPSA and the Natural Gas Supply Association, called for market-based responses to resilience needs, the American Public Power Association and NRECA said mandatory capacity markets are not producing the resource mix needed to provide required resilience attributes. “Rather than relying on the markets, appropriately accommodating state resource policy choices in the mandatory capacity markets likely would help alleviate some of these [resilience] concerns.”
API, in contrast, warned that some of PJM’s proposals “seem to be regressing back toward an integrated resource planning world where picking winners and losers takes precedence over markets and competition.”
Role of Transmission
Many commenters noted that most outages occur on the transmission and distribution system.
ITC Holdings said the bulk power system’s resilience faces “a substantial threat from the ongoing lack of any effective, regular interregional transmission planning processes between many RTOs/ISOs,” citing MISO’s seams with PJM and SPP. “Despite the highly interconnected nature of [the MISO-PJM] seam, and despite a long history of commission exhortation to ensure sufficient coordination between the two regions, no interregional transmission project has ever been planned for or built between these two RTOs. As such, each region is unnecessarily limited in its ability to call on generating resources from the neighboring region to respond to grid emergencies.”
Although the vast majority of customer disruptions occur because of failures of the distribution system and are beyond FERC’s jurisdiction, the commission could aid resilience by integrating distributed energy resources into wholesale markets and revising Order 1000 to increase the use of non-wires solutions to transmission constraints, said a group of environmental and public interest organizations, including the Natural Resources Defense Council and Environmental Defense Fund.
Trade group WIRES said FERC should update Order 890’s transmission planning principles to include resilience as a distinct planning driver for RTOs. “Generation and fuel supply policies offer only a limited hedge against potential disruption. Moreover, while distributed resources are important for rapid recovery, they are of limited long-term capability without the grid’s transfer capabilities,” the association said.
The Energy Storage Association said FERC could enhance resilience through greater storage use, embedding the resource type into transmission planning and encouraging wholesale market participation of distribution-level storage. “Storage decouples the element of time from supply and demand,” the ESA said. “It makes non-dispatchable generators dispatchable; it makes inflexible generators flexible; and it makes inefficient cycling generators more efficient.”
The WATT Coalition, a group of companies that offer technologies to increase the delivery capability of the existing grid, urged FERC to focus on how advanced transmission technologies can improve resilience. “During times of system stress, network topology optimization, dynamic line ratings, and power flow control can help ensure reliable operation,” the group said.
It noted that ISO-NE’s relaxation of transfer limits during this winter’s bomb cyclone allowed it to import an additional 200 MW of generation from NYISO. “When it is cold, cloudy, or windy, lines are cooled, so they can physically deliver more energy without sagging or over-heating,” the coalition said.
Tesla warned against a definition of resilience that focuses on generator availability or transmission. “Distributed energy resources that are co-located with load can continue to provide electric service to customers even in the face of a complete failure of the bulk power system and are best-placed to provide resilience in a wide variety of contingencies impacting the grid,” it said.
PJM Comments Under Scrutiny
PJM’s March filing was the subject of numerous commenters.
“In its zeal to address resilience in its own market, PJM has inappropriately laid out directives and requirements for every other market to follow, according to PJM’s proposed time frames,” EPSA said.
EEI agreed, saying “it may be premature to require all RTOs/ISOs to make specific filings as requested in PJM’s comments.”
David Patton, whose company Potomac Economics provides market monitoring services to MISO, ISO-NE, NYISO and ERCOT, said adopting PJM’s proposal to allow inflexible generators to set clearing prices would have boosted MISO’s system marginal prices by 30%, based on analysis of the 12 months ending in October 2017. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)
“This plan is a fundamental departure from the efficient locational marginal pricing framework that has been the foundation of all successful wholesale markets in the U.S.,” Patton said. “It would, for the first time, introduce fixed costs into real-time pricing that are clearly not marginal in the real-time dispatch horizon. In effect, PJM would be requiring that the average costs of all resources needed to service load be reflected in every five-minute interval.”
The Pennsylvania PUC said it supported some of PJM’s proposals but feared that some “offered in the name of resilience may shortchange or even bypass normal PJM stakeholder deliberative processes” and warned against giving RTOs “a license to ‘gold-plate’ the generation, transmission and cyber assets of its members to achieve standards of resiliency that are disproportionate to a particular vulnerability or threat assessment.”
The regulators said they were concerned over the potential scope and costs of PJM’s proposals. “Some of PJM’s recommendations, especially in the market design arena, appear to utilize the grid resilience docket as another forum to advocate for specific market modifications, such as energy price formation, that are not immediately germane to the resilience discussion,” the PUC said.
It agreed with PJM that FERC may need to “revisit” NERC reliability standards. “However, revision of NERC standards is a complex, time-consuming process that should be allowed to proceed on its own timeline without an accelerated impetus from this docket.”
The PJM Power Providers Group (P3), on the other hand, praised the RTO’s “thoughtful recommendations” for addressing “antiquated energy price formation structures.”
“However, the stakeholder deliberations regarding this issue have been unproductive to date. Commission direction may be required for energy price formation goals to come to fruition as a means to support the commission’s resilience aims,” it said. P3 expressed concern over PJM’s proposal to permit non-market operations during emergencies, saying the commission should require the RTO to submit Tariff revisions to allow the change.
PJM also received support from American Electric Power, Dayton Power and Light and East Kentucky Power Cooperative, which made a joint filing as the PJM Utilities Coalition.
The coalition said it agrees with PJM’s recommendation that all RTOs be required to submit proposed Tariff changes to implement resilience planning criteria and develop processes for the identification of vulnerabilities.
“No meaningful steps towards a resilient system can begin without appropriate direction given by the commission that explicitly grants power to the RTO to establish resilience planning criteria and other aspects of the process,” it said. It also questioned whether the stakeholder process could address the issues. “If PJM reverts to a stakeholder process to determine resilience criteria, the process may get mired in political debates and cost allocation, and not focus on the necessary task of determining objective resilience criteria. For this reason, clear direction from FERC to guide that process is requested.”
PJM also filed reply comments, saying it wanted to provide additional information on its fuel security initiative announced April 30, clarify its proposals regarding gas-electric coordination and “provide context for its approach to this docket relative to the approach taken by certain other RTOs and ISOs.” (See PJM Seeks to Have Market Value Fuel Security.)
The Organization of PJM States Inc. (OPSI) said PJM’s filing did “not address the prudency and affordability of measures that may be implemented as a result of” the RTO’s recommendations, which it said indicate “extensions of its current mandate.”
“While not the stated intent, a future PJM could be positioned to drive transmission planning and craft new market structures in its mandate to address perceived low-probability, high-impact threats,” OPSI said. “The prospect of this expanded authority, with planning and decision-making impacting billions of dollars in investments with cost recovery from end users, may require a re-examination of PJM’s scope, governance and oversight.”
Graph on the left shows how baseload resources recover their fixed commitment costs under current LMP rules. During the peak hours, prices are typically above the resource’s marginal costs; the excess revenues in area B will exceed the amount by which the revenues fail to cover average costs in area A. Under the PJM proposal (right), LMPs would cover the average cost of all baseload resources needed to serve load. | Potomac Economics
Industrial energy users, consumer advocates for Delaware, New Jersey and D.C., and American Municipal Power, filing jointly as PJM Consumer Representatives, said the inconsistencies between the positions of PJM and those of other RTOs indicate the need for regional flexibility.
“Unlike the comments of the other RTOs/ISOs, PJM’s comments embark on an aggressively activist course, advocating positions that could result in substantial changes to PJM energy and capacity market rules, in addition to whatever changes may be necessary in transmission planning and system operations rules,” they said.
They called for a cost-benefit analysis or “prudence assessment” of any new resilience rules and said neither the 2014 polar vortex nor the 2017-2018 cold snap “justify subsidizing uneconomic coal and nuclear units … in the name of resilience.”
FirstEnergy’s regulated utilities called for urgent action, noting they sought voluntary load curtailments during the polar vortex to prevent load shedding for 142,000 customers. FERC should “immediately implement stopgap measures to preserve the operation of generators that contribute to grid resilience until a full evaluation of resilience needs is complete,” the utilities said.
FirstEnergy Solutions, the company’s merchant generation unit, said it “disagrees with the overall thrust of PJM’s comments.” It called for FERC to adopt mandatory resilience standards for RTOs and ISOs and ensure the continued operation of “critical” nuclear and coal-fired generators in the interim.
The Natural Gas Supply Association said PJM’s fuel security initiative “appears to reflect an unsupported bias against natural gas.”
“PJM states that the process of examining fuel risk will be done in a fuel-neutral manner. However, its document describing its process only refers to risks associated with greater reliance on natural gas and the language suggests that PJM has already made an unsupported predetermination that natural gas is a weak link in their ability to be reliable and resilient.”
ISO-NE
ISO-NE’s response to FERC’s identified fuel security as its resilience risk. It said potential responses include additional gas pipeline or LNG capacity, relaxing rules on dual-fuel resources and additional investments in renewables and transmission.
The New England Power Pool Participants Committee stressed that resilience solutions be worked out in the stakeholder process, calling it “a prerequisite to yield the solutions that work best for New England.”
The New England States Committee on Electricity shared ISO-NE’s perspective that fuel security presents the primary challenge to the resilience of the region’s power system. NESCOE recommended additional analysis of potential risks and cautioned “against prescriptive actions or further processes” that could impede regional or state efforts to mitigate fuel security challenges.
The New England Power Generators Association said ISO-NE’s Operational Fuel Security Analysis (OFSA) “neither captures market participant behavior in response to price signals nor the probability of any particular outcome … and therefore should not be the basis for the market solutions to be developed and later filed for acceptance with the commission.” (See Report: Fuel Security Key Risk for New England Grid.)
Eversource Energy said ISO-NE’s fuel security study “may understate the magnitude and scope of the challenges.”
“This could lead one to falsely conclude that only minor changes are required, and that commission action may be unneeded at this time. To the contrary, time is not on New England’s side,” the company said.
The company urged the commission to convene a New England-specific technical conference to determine state and federal actions to improve the region’s infrastructure, citing additional gas pipeline capacity from the Marcellus shale deposit and electric transmission to carry Canadian hydropower and on- and offshore wind.
The attorneys general of Massachusetts, Rhode Island and Vermont also cautioned against overreliance on the OFSA, which they said “relies on underlying assumptions that do not present a realistic or complete view of either the present or the future bulk power system.”
“The OFSA presents a deterministic (as opposed to probabilistic) analysis that provides no context about whether modelled events are likely to occur,” they said.
They also said the study’s approach to resilience is overly narrow, failing to consider “cyber and physical adversarial threats, technological accidents, and extreme heat and other weather events.”
The region’s local gas distribution companies recommended FERC “consider expedited review of and decisions on new natural gas pipeline certificate applications in critical fuel security regions.”
NYISO
NYISO told FERC in March that it does not face “imminent resilience concerns that require immediate action.”
The New York Public Service Commission said it agreed that ISO and stakeholder efforts to address bulk system resilience “are comprehensive and continuous,” asking for no other FERC measures beyond its “continued attention.” The PSC also agreed with the ISO’s suggestion for the commission to host a technical conference on bulk system resilience.
The Independent Power Producers of New York also supported the ISO’s approach and said FERC should not force it to abide by PJM’s suggested deadlines. “Efforts to ensure resilience should not be rushed to meet some arbitrarily short time frame unless they are justified by the evaluation of the ISO/RTO,” the group said.
The New York Transmission Owners also called on the commission to respect regional differences. “Any requirement to change course could impede resilience efforts already underway in the stakeholder process,” they said.
MISO
The Organization of MISO States said NERC standards, combined with initiatives from RTOs, state regulators, utilities, municipalities and others were enough to ensure long-term resilience. No additional rules or standards are necessary, the group said, especially those that might impede on state jurisdiction. “It is clear to the OMS that the appropriate processes are already in place to identify and adapt to the evolution of the industry and perceived threats to resilience,” the group said.
The MISO Transmission Owners emphasized that RTOs have only part of the answer to resilience, noting the role of distribution systems.
“MISO and its utility members have developed an integrated electric system that is currently sufficiently resilient, and MISO has identified no imminent resilience crises requiring commission action,” they said. “Notwithstanding MISO’s and its members’ regional efforts, enhancements to interregional coordination will promote greater resilience. Thus, while seams issues are broader than the concept of resilience, MISO is correct that the commission should not ignore the benefits of greater, more effective and efficient interregional cooperation in this proceeding.”
Entergy said it saw no need for a federal role in determining the proper long-term resource mix — “at least in MISO.”
The company called for resource adequacy to “continue to be a shared responsibility in MISO,” with state and local regulators determining the fuel mix.
“In this way, state and local regulators ensure diversity of fuel resources consistent with each area’s needs and those regulated utilities’ customers bear the cost burden and the reliability and resiliency benefits of those local regulators’ decisions,” Entergy said. “Direct federal action to regulate the long-term resource mix also could jeopardize utilities’ continued participation in MISO.”
In a joint filing, the Coalition of MISO Transmission Customers and Illinois Industrial Energy Consumers said that resilience is already central to the RTO’s reliability assessments. “The commission should not carve out resilience and treat it as a discrete characteristic of wholesale electricity markets,” they said, adding that any resilience requirements should be subject to cost-benefit analyses.
Northern Indiana Public Service Co. said that most grid innovation is happening with customer-owned technologies that connect at distribution level, urging FERC to work with state regulators to address resilience “across the entire electric value chain.” The company said that a “top-down, nationally-focused approach could overemphasize one or two parts of the overall electric system” and fail to account for the adoption of storage devices, electric vehicles, microgrids and DERs.
Alliant Energy used its comments to call for modernizing the Public Utility Regulatory Policies Act and criticize qualifying facilities “that haphazardly site themselves on the grid, causing distribution system and system planning issues.” Alliant said PURPA must be reworked to incent QF developers to concentrate on “system reliability and long-term grid stability.”
SPP
SPP’s Market Monitoring Unit emphasized the importance of creating standards and metrics to quantify and measure resilience.
“We recommend that in addition to defining resiliency, the commission and the parties should also engage in discussions to measure resiliency in order to assess whether an area has or has not attained resiliency. This measurement may also contribute in creating new market mechanisms to promote resiliency,” the Monitor said.
It pointed to SPP’s 30 to 36% capacity margins over peak needs but said that those high levels do not necessarily equate to resilience.
The MMU also said the resilience discussion should not be used “as a venue to promote certain price formation proposals.”
CAISO
The California Public Utilities Commission said the state “has made substantial efforts to ensure grid reliability and resiliency by ensuring redundancy and coordination in its energy planning efforts,” citing the deployment of distributed energy resources and smart inverters.
It also noted the state “continues to aggressively plan for a changing climate to ensure Californians have safe, affordable and reliable access to electricity.”
Nevada Hydro, which develops pump storage projects, said CAISO’s transmission planning process has fallen short in properly valuing hydropower. CAISO’s “transmission economic assessment method (TEAM) has not fully applied the method to storage projects and has not quantified the grid reliability and resiliency benefits of the projects it has examined,” the company said. It said FERC should direct RTOs to include pumped storage hydro in transmission studies and resource adequacy planning.
Southern California Edison said FERC should consider regional differences and costs. It said it shares CAISO’s view that FERC’s proposed definition of resilience is lacking.
It said the use of the term “‘disruptive events” is indistinguishable from “‘contingencies,’ which, per NERC reliability standards, refers to unexpected failures or outages of a [Bulk Electric System] component.”
Contributing to this article were Robert Mullin, Jason Fordney, Amanda Durish Cook, Tom Kleckner, Michael Kuser, Rory D. Sweeney and Rich Heidorn Jr.
ALBANY, N.Y. — New York is reshaping its grid to accommodate public policy goals and an influx of new renewable resources while seeking to maintain a balance between state responsibilities and wholesale electricity market standards, industry stakeholders heard Tuesday at the Independent Power Producers of New York Spring Conference.
“It should not be up to the federal government to tell a state what its energy future is going to be,” FERC Commissioner Neil Chatterjee told conference attendees.
“New renewable resources, storage and other innovative technologies need to be integrated into the market,” Chatterjee said. “As our generation changes, as it modernizes, our policies may have to as well. … This could include revising market rules that might be a barrier to participation, or updating interconnection requirements, or modifying operating procedures for procuring operating reserves and other ancillary services.”
But Chatterjee cautioned that “the revolution in generation would fizzle” without the transmission capacity needed to manage supply and demand.
“In New York, like many other places, significant issues arise when vast quantities of cheaper generation resources are located great distances from the load centers,” he said. “In fact, the region might need hundreds of miles of new transmission in order to effect the renewables goal set forth in” the state’s Reforming the Energy Vision program that, along with the associated Clean Energy Standard, requires that 50% of the state’s electricity come from renewables by 2030 and that statewide greenhouse gas emissions be reduced by 40% from 1990 levels by 2030.
IPPNY Board Chairman John Reese, of Eastern Generation, said New York needs a forward capacity market like those in ISO-NE and PJM in order to reduce price volatility and provide investors with more certainty that generation investments will earn returns.
“New York has taken a different path from its neighboring RTOs and is looking at carbon pricing as a way of taking the externalities that you value … and see if we can put it into the marketplace,” Reese said.
“In a different world, we might have been there nationally today, but in the current environment, the burden is on the individual states to find ways to do that,” said Reese. “IPPNY’s been supportive of including carbon pricing in the marketplace; not choosing winners and losers, but setting a price, allowing the industry and private investment to choose how they invest, where they invest, to allow technology innovation.” (See NY Looks at Social Cost of Carbon, Modeling.)
IPPNY CEO Gavin J. Donohue said, “Like New England, we’re experiencing very low prices, stagnant if not decreasing demand and limited market-based investment. All of these are compounded by regulatory uncertainty and cross-signals within investment, making it very complicated in a one-state ISO to do business.”
“It’s important to make sure there’s a shift in investment risks to private developers,” said State Assemblyman Michael Cusick (D), chair of the Assembly Energy Committee. Cusick said he worked to block Gov. Andrew Cuomo’s proposal to allow the New York Power Authority to own and operate other renewable energy resources besides its statutory mandate for hydropower. The plan did not survive in the final budget.
Cusick said he is now focusing on new energy legislation, including a real property tax exemption that would be made available to certain renewable energy technologies such as fuel cells and linear generators (9651A).
State Sen. Joseph Griffo (R), chair of the Senate Energy and Telecommunications Committee, said “all ratepayers pay for our clean energy transformation,” and that legislators need to “apply the Hippocratic Oath here and know when to step back and do no harm.”
The legislative process has so many “intangibles” this year that making an accurate forecast is “almost like meteorology,” Griffo said. “We’re going to be wrapping up energy storage legislation … hoping to ensure competitive procurement processes.”
Griffo added that he “is working with the administration” to ensure the governor advances a candidate to fill the fifth and only open seat left on the Public Service Commission.
Richard Kauffman, chairman of Energy & Finance for New York and chair of the New York State Energy Research and Development Authority’s board, said Cuomo recognized five years ago that the energy system was unsustainable and that “we needed to change the whole system to build the new grid, a mix of large-scale generation and distributed energy resources.”
“It’s a big job to change the system of systems … we want the policies to drive the target, not the target to drive the policies,” Kauffman said.
Technological improvements seen in other industries have not occurred in energy because of how utilities are protected from market forces by the regulatory structure, he said.
“Our grid and its current IT system will not carry us forward; we need a much more robust IT system,” Kauffman said.
He said the model should be how Apple provides the platform for its iPhone and lets the apps come from other developers, who in turn provide feedback to Apple on how to invest to make the platform more valuable.
“Competitive actors will find the projects better than regulated utilities,” Kauffman said. “Competitive markets will figure out what customers want … and building this kind of platform is not a core competence for” the utilities.
“The effort to try to change utility compensation and business practices has begun,” Kauffman said, pointing to the “non-wires” approach of the Brooklyn-Queens Demand Management project, where Consolidated Edison “went to the market for alternative approaches that resulted in $200 million of costs, rather than spending $1.2 billion on substations.” (See “PSC OKs Con Ed Energy Storage Tariff,” NYPSC Expands VDER Project Size to 5 MW.)
Glen Thomas, president of PJM Power Providers, said, “There’s a lot going right in PJM, but when you look around the edges we start to get concerned about this market going forward.
“PJM just came out with estimates on the cost of new entry and they are dramatically reduced from where they currently sit,” Thomas said. “Of course the cost of new entry calculations are very important because that’s the base by which the curves are set for the capacity auctions, which are coming up here in a couple weeks.”
Power producers in PJM face a flat supply stack “pretty much year-round,” but New Jersey is the biggest challenge facing producers in the RTO’s footprint, he said. Legislation is now on the New Jersey governor’s desk that could see zero-emission credits applied to 40% of the megawatts delivered in the state by 2030, and renewable energy credits applied to 50%. The state also plans to subsidize construction of 3.5 GW of offshore wind and 2 GW of storage by 2030, he noted.
“You have to wonder what’s left of the market,” Thomas said.
Dan Dolan, president of the New England Power Generators Association, said his region saw the second-lowest prices in history last year at just over $33/MWh, “and at the same time we have the highest wholesale transmission rates of any market in the country — they’ve increased more than 400% over the last 10 years. Our wholesale transmission rates are double those in PJM [and] four times those in MISO.”
And while producers “are seeing remarkable competition, and extraordinary results from investment, reliability and emissions,” consumer bills are going up, Dolan said.
While energy supply costs have declined 35% over the past few years, consumer electric bills have gone up 6%, and consumers are not usually prone to breaking down their bills to see where the increases come from, he said.
Dolan faulted ISO-NE for saying it wants to keep Mystic 8 and 9 running for fuel security reasons after Exelon in March filed to retire the plant. It would take three and a half years to come up with a market construct for that attribute, he said. (See ISO-NE Moves to Keep Exelon’s Mystic Running.)
“I’d like to think we can walk and chew gum at the same time and get it done a little faster than that,” Dolan said.
John Shelk, CEO of the Electric Power Supply Association, took the long view on market prices, noting how opinions have flip-flopped since RTOs and ISOs were formed about 20 years ago.
“Ten years ago, we thought markets were going to fail … because prices were so high … and now suddenly markets are bad because prices are too low,” he said.
FERC has signaled that it’s done dealing with PJM’s concerns about market participants selling “paper capacity” to arbitrage price differences between the Base Residual and Incremental Auctions.
The commission issued an order Tuesday rejecting changes to the Incremental Auction (IA) structure and terminating a longstanding proceeding on the issue (ER18-988, EL14-48).
PJM voiced concerns with FERC about capacity auction arbitrage as far back as March 2014, when it filed for approval of auction revisions that would have made the activity harder. It would have created a sell-back offer floor at the relevant Base Residual Auction’s clearing price and eliminated two IAs, along with increasing charges and penalties and making it more difficult for generators to represent capacity that is unlikely to materialize.
FERC rejected the revisions as “beyond what was reasonable to ensure that offers are supported by physical resources” but initiated a proceeding under Section 206 of the Federal Power Act to hold a technical conference on the issue. PJM asked to defer it four times, including in its current filing on IA changes.
PJM’s Independent Market Monitor says demand response providers disproportionately replace commitments from Base Residual Auctions compared with sellers of other resource types. External generation and internal generation not in service also had high rates of replacement in some years. | PJM
In that filing, PJM asked for the authority to change the IAs in which it can offer excess capacity commitments — and to determine the allowable volumes. During the PJM stakeholder process, some stakeholders, represented by Direct Energy’s Marji Philips, argued the issue had been “subverted into a lot of other interests” and “is actually worse than the status quo at this point.” (See “Incremental Auction Revisions Endorsed” in PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
FERC agreed, saying PJM’s proposal resembled several other proposals the commission rejected.
“On three separate occasions, the commission has rejected as unjust and unreasonable PJM’s proposals to value sell-back offers at a level that differs from the valuation of excess of capacity reflected by PJM’s capacity demand curve,” the commission said. “We again find PJM’s proposal to submit sell-back offers at the relevant Base Residual Auction clearing price to be unjust and unreasonable, as it fails to establish a reasonable price for excess capacity as the commission has found in the prior orders, and, as a result, the Incremental Auctions would not adequately correct for PJM’s over-procurement of capacity in a Base Residual Auction and would not produce prices commensurate with load’s value of the over procured capacity.”
PJM’s Market Monitor had attempted to provide some support, developing a report to argue that “the lack of a specific requirement that all capacity resources be demonstrably physical assets when offered into PJM capacity auctions continues to provide strong incentives to offer speculative paper capacity.” (See PJM Monitor Asks FERC to Act on ‘PaperCapacity’.)
However, the commission argued that “in recent years, PJM has implemented reforms that reduce the likelihood of speculative offers,” including documentation to verify offers.
“For these reasons, we find that there is no need for the commission’s further consideration of solutions to address potential speculative behavior” in the auctions, the commission said, and with that, terminated the proceeding.
American Transmission Co. (ATC) has restored one of two underwater circuits connecting Michigan’s Upper Peninsula with the lower part of the state following a month-long outage for the damaged lines.
ATC reconfigured and combined three undamaged submarine cables to form one circuit across the Straits of Mackinac. The company owns two 138-kV circuits across the peninsulas, consisting of three submarine cables apiece. One cable in each circuit was damaged on April 1, and both circuits were taken offline after they leaked a toxic, petroleum-based fluid used for insulation into the water.
ATC said it tested the new configuration and has been operating the reworked circuit since May 1.
The company said the cables were possibly damaged by “vessel activity” in the lake, spilling fewer than 600 gallons of fluid insulation. The U.S. Coast Guard has initiated an investigation into the incident and is still reporting low risk to the public and wildlife.
The damaged cables have been “soldered, capped, sealed and returned to the bottom of the Straits,” ATC said. Company spokesperson Jackie Olson confirmed the cables were rendered “permanently inoperable.”
ATC said it is making plans to construct two new circuits in the Straits, this time using a solid dielectric insulator instead of a liquid-based insulation. If the new circuits are approved, ATC will permanently decommission all six fluid-filled insulating cables, the company said, though it did not release a timeline or cost estimate for the possible new project.
“Our planning team is hoping to secure internal approval for such a project in the next several weeks,” Olson said.
MISO spokesman Mark Adrian Brown said while the RTO was pleased to see restoration of ATC’s submarine connection, no reliability issues arose during the outage.
“While other routes also serve the U.P., the restoration is an important step for added reliability and greater redundancy of the power grid,” Brown told RTO Insider.
Brown also said ATC worked closely with MISO throughout the outage to ensure reliability as it performed subsea inspections and determined a course of action.
“This connection is essential for reliability for the eastern U.P. and the northern portion of lower Michigan,” said ATC Chief Operating Officer Mark Davis in a statement. “We were able to maintain reliability by implementing conservative operating procedures during the month the connection was lost, but re-establishing this powerline will give us greater flexibility and an added measure of reliability to help us keep the lights on.”
Davis thanked the Coast Guard and other groups that helped monitor and minimize the incident, including the EPA, the Michigan Department of Environmental Quality, county emergency managers, local native tribes, the National Oceanographic and Atmospheric Administration and U.S Fish and Wildlife.
“The coordinated response helped minimize impacts to the environment and local community,” Davis said.
Financing costs related to the acquisition of Texas utility Oncor helped pushed Sempra Energy’s earnings down by $94 million in the first quarter compared with the same period last year.
The parent company of San Diego Gas & Electric (SDG&E) reported net income of $347 million ($1.33/share), compared with $441 million ($1.75/share) in the first quarter of last year. Sempra closed on the Oncor transaction on March 9, the day after the Texas Public Utilities Commission (PUC) approved the $9.45 billion all-cash deal. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.) Sempra said it expects $320-$360 million in earnings from Oncor this year. Sempra funded the transaction with $3 billion in equity and $6.6 billion in debt.
Sempra, which also owns Southern California Gas, earned $2.96 billion in revenues for the quarter, compared with $3.03 billion a year earlier.
SDG&E reported earnings of $170 million in the quarter, compared with $155 million in the same quarter last year, primarily because of changes in consumption patterns that affected electric distribution revenues this year and a lower tax rate, partially offset by a higher interest expense.
Like other utility interests in California, Sempra is focused on revising California’s liability laws to reduce the risk and financial impact from wildfires, which have led to lawsuits and other financial woes as state investigators explore evidence that power lines caused the devastating and costly disasters.
Sempra CEO Jeff Martin, who replaced retiring chief Debra Reed on May 1, noted there are several pieces of legislation moving through committees in the California legislature. (See Calif. Legislation Shields Utilities from Wildfire Costs.)
“While the current text of the bills doesn’t directly address inverse condemnation, we and other stakeholders are also looking to separately address this issue in Sacramento,” Martin said.
Last November, the California Public Utilities Commission (CPUC) rejected SDG&E’s request to recover from ratepayers $379 million in costs related to 2007 wildfires. The ruling ignited a “three-pronged” — legislative, regulatory and legal — effort from the state’s investor-owned utilities to change wildfire liability laws. The CPUC found that SDG&E had not properly maintained its system. (See Besieged CPUC Denies SDG&E Wildfire Recovery.)
California’s investor-owned utilities say climate change plays a large role in the increasing number and severity of wildfires, and they cannot be held solely responsible for the billions of dollars in related costs for the disasters.
With the deadline for filings in FERC’s resilience docket looming, two aides to former FERC Chairman Pat Wood III last week sought to reset the definition — saying resilience is about transmission and distribution, not generation.
In a report funded by the Natural Resources Defense Council and the Environmental Defense Fund, Alison Silverstein and Rob Gramlich say resilience should be measured from the customers’ perspective: the number of outages (frequency), customers affected per outage (scale) and length of time before restoration (duration).
“Customers pay the ultimate price for power outages, whether through their electric bills or their own personal losses and expenditures,” says the study, whose third author is Michael Goggin, who worked with Gramlich at the American Wind Energy Association and has since joined Gramlich’s consulting firm.
Silverstein, the former senior energy policy advisor to Wood, made headlines last year when, after helping coauthor the Department of Energy’s grid study, she denounced DOE Secretary Rick Perry for using it as a pretext for price supports for struggling coal and nuclear plants. (See Author of DOE Grid Study Disputes Recommendations.)
The DOE NOPR sought “resilience” payments to power plant with 90 days of fuel on site.
In rejecting the NOPR in January and initiating the resilience docket, FERC offered its own definition of the term: “The ability [of the grid] to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
The Silverstein-Gramlich-Goggin report was filed in the docket Tuesday. [Editor’s Note: RTO Insider will have coverage of the filings later this week.]
“I’m a customer, you’re a customer. We operate the grid for the customer, not just for our jollies,” said Silverstein, in an interview. “It seemed to me that if the point of preventing outages is protecting the customer, as NERC and others assert, we should look at the most effective ways of measuring resilience.”
The report notes the vast majority of outage events occur at the distribution and transmission levels because of weather events — which has only led customers to expect more outages.
| Grid Strategies
The authors cite a Rhodium Group study that found less than 0.1% of customer-outage minutes in 2012-16 were caused by generation shortfalls or fuel supply issues. The study found most outages can be attributed to routine causes such as local storms, vegetation, squirrels and equipment problems, with high-impact, low-frequency events such as hurricanes and winter storms causing about half of customer outage-minutes.
“We cannot prevent and mitigate all the hazards and threats that cause outages, and we can mitigate some but not all of their consequences,” the authors write. “So which risks should we take, what level of resilience and mitigation cost are we willing to bear and how should we choose among resilience measures?”
The paper doesn’t answer the risk question, but it does offer a path for “assessing and selecting resilience regulatory policy options.” The report suggests regulators and stakeholders ask how each remedy “might reduce the frequency, magnitude and duration of customer outages relative to the entire scope of customer outages, not just those resulting from generation- or transmission-level causes.”
| Grid Strategies
In attacking the problem, Silverstein said she borrowed from the Rocky Mountain Institute’s co-founder and chief scientist, Amory Lovins, who has said you can solve the energy problem by enlarging it. By carving problems into bite-sized chunks, Lovins has said, “you don’t have a big enough design space to have enough options, degrees of freedom and synergies.”
“There’s a big difference between generation resilience and the resilience of the power system and resilience from customers’ perspective,” Silverstein said. “When you look at resilience from the customer’s perspective, there’s a whole lot of ways to solve the problem quickly. If I spend a fortune on reducing generation failures, that’s a whole lot of money that could have been spent on tree trimming or strategic spare equipment. Tree trimming and situational awareness are not addressed by a generation resilience proposal.”
Because most outages occur at the distribution level, Silverstein, Gramlich and Goggin write, “it logically follows that measures that strengthen distribution and hasten recovery would be highly cost-effective.”
One example of this would be mobile substations, which proved invaluable during Hurricane Harvey’s restoration effort. Other examples include hardening distribution poles, physical security, outage-management systems, mutual assistance, and emergency planning and drills.
| Grid Strategies
Silverstein said this will become even more important as severe weather events continue to increase in the years ahead. According to the report, the United States weathered 16 “disaster events” last year, each incurring at least $1 billion in damages. Most of the events damaged some electric system infrastructure and caused service disruptions, totaling more than $350 billion in damages.
“We really need to take that threat seriously and think about how to design power system architecture and assets for the long-term threat,” she said. “A lot of the designs today were developed in the early 1900s. The weather is going to be a lot more severe and meaner 10, 20 and 30 years in the future. We designed the grid for Ozzie and Harriet weather. What’s coming at us is Mad Max.”
