The push to develop green hydrogen in North America got a boost Tuesday with the announcement of a new program to hasten development of the clean-burning, renewable fuel for use in the Western Interconnection.
A joint effort of the National Association of State Energy Officials (NASEO), Western Interstate Energy Board (WIEB) and the Green Hydrogen Coalition (GHC), the Western Green Hydrogen Initiative seeks “to assist interested states and partners in advancing and accelerating deployment of green hydrogen infrastructure in the Western region for the benefit of the region’s economy and environment,” according to the GHC.
The initiative will look to engage the Western U.S. states and Canadian provinces.
“We are here to unveil the first-ever-of-its-kind collaboration around green hydrogen … [a] public-private partnership to really create an action-focused initiative to bring together energy officials, public utility commissions, developers and other key stakeholders to accelerate progress for green hydrogen throughout the West,” GHC Executive Director Laura Nelson said Tuesday during the first day of the Green Hydrogen Visions for the West Virtual Conference.
Laura Nelson, Green Hydrogen Coalition | Green Hydrogen Coalition
“I like to say this will be a template for the United States and — really — beyond,” said Nelson, a former energy adviser in the Utah governor’s office.
The initiative also has the backing of Mitsubishi Power, which won a contract to convert Utah’s 1,900-MW coal-fired Intermountain Power Plant into an 845-MW natural gas plant capable of burning a mixture of gas and hydrogen by 2025, with the goal of eventually using only hydrogen as a fuel source. The plant is operated by the Los Angeles Department of Water and Power and generates power for 29 municipalities in Southern California and Utah.
“We are really excited about this. From our point of view, we’ve been participating in decarbonizing the U.S. power sector for the past 20 years,” Mitsubishi Power Americas CEO Paul Browning said, noting that the sector’s carbon emissions are down about 40% from 2000 levels, the result of replacing coal-fired generation with a combination of natural gas and renewables.
Browning said that when his company asked the question of what would then replace natural gas to achieve future emission reductions, it landed on the combination of renewables and energy storage. And although Mitsubishi has made heavy investments in battery storage, Browning said use of lithium-ion batteries for longer-duration energy storage will be “prohibitively expensive,” even with expected cost reductions.
“In that application of longer-duration energy storage, we believe that green hydrogen is far and away the most affordable solution today and is going to become increasing affordable over time,” Browning said. “Three years ago, we decided we were all in on winning the order to supply gas turbines to the Intermountain Power Plant, because we saw it as a first step in many, many more green hydrogen projects to come.”
“The Mitsubishi offices have led in clean energy opportunities for decades, and I think the potential opportunities in this area for the West, and frankly around the entire nation, are enormous,” NASEO Executive Director David Terry said. He recalled that nearly 20 years ago, NASEO was involved in early research and development efforts around green hydrogen and that “it’s exciting to see that come full circle to a real market opportunity now to provide solutions to states’ energy challenges.”
‘Intelligent Tinkering’
In a press release Tuesday, GHC said, “Green hydrogen can help avoid uneconomic grid buildout, prevent renewable curtailment, repurpose existing infrastructure, reduce greenhouse gases and air pollution, reduce agricultural and municipal waste, and diversify fuels for multiple sectors from steel production to aviation.”
| Green Hydrogen Coalition
Green hydrogen development in the West has so far been minimal, it said. “To enable investments at scale, green hydrogen must be compensated for the many benefits it provides.”
To advance that goal, GHC laid out five key objectives for the initiative:
Coordinating and leveraging state, federal and industry R&D and green hydrogen demonstration projects “to guide priorities and scale commercial technology options.”
Addressing regulatory, policy and commercial barriers hindering the scaled production and use of green hydrogen.
Supporting “regional grid and gas sector modeling efforts to inform coordinated state policy actions and investment for green hydrogen utilizing existing energy infrastructure.”
Identifying “education and workforce opportunities that support the transition to a local and resilient green hydrogen energy system.”
Assisting states in “developing hydrogen storage and utilization roadmaps to advance innovation and expand opportunities for low-cost renewable energy to produce, use and store green hydrogen.”
“It’s an amazing initiative, and great results are coming to an energy future that I think is here,” Terry said.
WIEB Executive Director Maury Galbraith waxed philosophical about the potential key role for green hydrogen in transitioning to a carbon-free grid while maintaining reliability. He likened the Western Interconnection to “a living machine” in that it is “constantly evolving.”
“We cannot simply stop the machine and start all over again. The machine must operate as we improve it,” Galbraith said.
Quoting conservationist Aldo Leopold’s statement, “To keep every cog and wheel is the first precaution of intelligent tinkering,” Galbraith cautioned that the industry is currently discarding parts of the Western bulk electric system “at a rapid pace.”
“Whether you believe this is a good thing or a bad thing, I think we can all agree it is a risky thing,” he said, adding that his role as the head of WIEB “is to ensure that we tinker intelligently.”
“One point seems clear to me: A large-scale, dispatchable, clean source of electric generating capacity would be a tremendous help. Green hydrogen is a clean fuel source that can be potentially used in combustion turbines to provide this electric generating capacity,” Galbraith said.
“Is green hydrogen electric generation the technology that will be selected in the evolution of the bulk electric system? I do not know — that depends on a lot of factors. Is it an intelligent step to take as we tinker with the bulk electric system? Yes, without a doubt.”
Four electricity industry CEOs on Monday discussed the “challenges and opportunities,” as former FERC Chair Cheryl LaFleur put it, of decarbonization in the New England power sector over the next three decades.
Cheryl LaFleur, ISO-NE | FERC
The panel followed a keynote speech by former U.S. Energy Secretary Ernest Moniz at the virtual New England Energy Summit, hosted by the New England Power Generators Association. Moniz presented a study co-authored by his Energy Futures Initiative (EFI) and Energy and Environmental Economics (E3), which detailed how the electricity system could meet the challenges of growing demand and reducing economy-wide greenhouse gas emissions to nearly zero by 2050. (See Study Outlines Challenges of Decarbonizing New England.)
Alicia Barton, FirstLight Power | FirstLight Power
FirstLight Power CEO Alicia Barton said the study “put some provocative and important ideas on the table for us to consider as market participants, policymakers and thought leaders … about how we transition toward this net-zero target by midcentury.” There are “very difficult conversations ahead” about the evolution of market structures, she said.
“I think we have to acknowledge that neither our market construct nor the set of policies we have on the books at the state or federal level today gets us anywhere near hitting those targets or seeing any of those scenarios that were just presented [in the study] play out,” Barton said. “Our track record has been that it takes us a very long amount of time to implement market rule changes and policy changes actually to facilitate those transitions.”
Moderator LaFleur, now serving on ISO-NE’s Board of Directors, said that while 2050 seems “a long time away,” when it comes to designing new market rules, “it’s not a long way at all in the electric world.”
Scott Hall, Great River Hydro | Great River Hydro
Great River Hydro CEO Scott Hall said to reach its 2050 decarbonization goals, New England needs to implement regulatory and statutory policies that maintain and enhance existing resources and provide opportunities to put new resources into place. Hall said he supports “a simple, transparent carbon market” that the RTO has suggested because it offers stability from an investment standpoint.
Thad Hill, Calpine | Calpine
Calpine CEO Thad Hill said that “reliability will matter even more” as the economy decarbonizes.
“The gas fleet in New England today is not an inhibitor of decarbonization; it’s an enabler,” Hill said, echoing comments his company made in FERC’s carbon pricing docket. (See related story, Wide Support for FERC Carbon Pricing Statement.) “We’re going to have a lot more renewables, as the study showed, which is a good thing, and dispatchable assets [will be] run far less, which was also a good thing.”
Paul Segal, LS Power | LS Power
LS Power CEO Paul Segal said that he “would take the view that on the one hand, we’re talking about the need for all of this incremental dispatchable generation over time. On the other hand, we have the lowest capacity pricing that we’ve probably had since this market was created.” He added that “overly aggressive developers who make certain promises, without adequate penalties on the other side,” can overbuild and suppress prices.
“This is where I think it’s incumbent, whether you look at it as the grid operator or the regulator, to take steps to clean things up in markets, so that folks like us can make good decisions,” he said. “It’s not too long ago that we cleared a multiyear capacity award at around $9.55 … and now we’re looking at situations where between $2 and $4 is clearing, and it is unclear to me how capital will flow into this market in that type of environment.”
FERC’s proposed policy statement on carbon pricing won wide support in comments filed Monday, although some stakeholders expressed doubts that it will spur states to adopt a CO2 adder, suggesting regional, market-based clean energy standards (CES) may be more politically appealing.
Other commenters raised jurisdictional questions, with commenters disagreeing on FERC’s role in mitigating “leakage” or evaluating the efficiency of the programs that may be submitted.
FERC’s Oct. 15 proposal invited states to introduce carbon pricing in organized wholesale electricity markets but said the commission has no authority to initiate such programs itself (AD20-14). (See FERC: Send Us Your Carbon Pricing Plans.)
More than 40 companies, grid operators, interest groups and coalitions of state officials filed substantive comments; only a handful opposed the proposal outright.
“Establishing an ISO/RTO carbon pricing mechanism is the most durable and effective way to address climate concerns and facilitate an evolving resource mix while maintaining the integrity and reliability of the organized wholesale electricity markets,” the Electric Power Supply Association said.
A clean energy standard can be almost as effective as direct carbon regulation if it distinguishes between fossil generators with different carbon intensities, according to Energy and Environmental Economics. Policies such as renewable portfolio standards have significantly higher costs because they do little to accelerate coal retirements, retain economic nuclear generation or incentivize energy efficiency. | Energy and Environmental Economics
The Natural Gas Supply Association said FERC should broaden the statement to apply to both organized and non-organized markets.
Even the American Petroleum Institute expressed thanks for “the clarity, direction and deference from FERC to the RTOs/ISOs.”
“Properly designed carbon pricing can be one fuel- and technology-neutral tool to reduce emissions and deploy newer, cleaner sources of electricity,” API said.
Opponents
But coal lobbying group America’s Power (formerly the American Coalition for Clean Coal Electricity) said FERC should withdraw the policy statement and terminate the docket, saying a carbon price would undermine reliability by accelerating coal retirements. “By encouraging RTOs/ISOs to establish wholesale market rules that incorporate state-determined carbon prices, the commission might be deemed to impermissibly seek to do indirectly what it cannot do directly, which is to influence states to adopt carbon pricing,” it said. It noted that 39 states do not price carbon.
A coalition of conservative groups, including Americans for Prosperity, Americans for Tax Reform and the Competitive Enterprise Institute also opposed the proposal, saying “FERC should not rush forward with a blanket endorsement of ill-conceived, top-down climate policies that have been demonstrated to be costly, ineffective, regressive and consistently rejected by the American people.”
The groups said they agree with FERC Chair James Danly, who dissented in the 2-1 vote in favor of the policy statement, calling it “unnecessary and unwise.”
Instead, they said, the commission should investigate “existing, hidden carbon taxes” in current state subsidies and mandates for carbon-free power.
“Adding a carbon price on top of the mélange of subsidies would further erode the concept of competition in a level playing field for all generation resources,” they said. “There is no evidence to suggest that the carbon pricing schemes identified by FERC in the policy statement have been — or will be — accompanied by the elimination of inefficient, market-distorting government interventions that constitute a significant, nontransparent price in the status quo.”
The New England States Committee on Electricity (NESCOE) also reiterated its opposition to “a new, incremental carbon price” on top of the Regional Greenhouse Gas Initiative (RGGI).
NESCOE said it was open to the idea of a forward clean energy market and supported evaluation of a related proposal for an “integrated clean capacity market” in a Nov. 2 memo to ISO-NE’s Board of Directors. It urged the commission “not to create any barriers that could inhibit these collaborative processes.”
The Electricity Consumers Resource Council (ELCON), which represents large industrial consumers, said the proposed policy statement was premature because only one of the 32 panelists at the commission’s Sept. 30 technical conference on carbon pricing represented consumers. (See FERC Urged to Embrace Carbon Pricing.)
ELCON said the policy statement focused on the potential benefits of carbon pricing but ignored potential costs. “Carbon pricing would only improve economic efficiency if it were to effectively replace the carbon-related subsidies, mandates and regulations that apply to the electricity sector,” it said. It also said FERC should only accept a carbon pricing or cap-and-trade proposal that returns the revenues in full to consumers.
RTOs, Regional Differences
PJM, CAISO, NYISO and MISO all said they would work with the commission on the policy.
MISO said that although it “takes no issue with the commission’s analysis of its jurisdiction” to review an RTO proposal incorporating state carbon prices, FERC “should refrain from nudging RTOs towards specific carbon pricing proposals and instead should allow such proposals to emerge organically, through the stakeholder process, to accommodate member goals and specific state policies.”
MISO and the PJM Power Providers Group (P3) also called for FERC to allow for regional differences in proposals. “Failure to accommodate regional flexibilities and priorities would create an increased burden on member companies and may discourage future RTO membership,” the RTO said.
P3 said the commission should “retain flexibility to respond to different flavors of carbon pricing in different regions of the country. New England and PJM could easily develop different proposals related to carbon pricing, yet both could be considered just and reasonable.”
P3 also noted that Pennsylvania is considering joining New Jersey, Delaware, Maryland and Virginia as members of RGGI and that Illinois Gov. J.B. Pritzker has endorsed a carbon price in his state. “If Pennsylvania and Illinois begin to price carbon, 70% of the installed capacity in PJM will be subject to a price on carbon emissions. This would be a significant change from just two years ago,” P3 said.
The Independent Power Producers of New York said the commission should adopt the policy statement “as soon as possible to encourage the state of New York and adjacent RTOs to establish a carbon price that can be incorporated into the NYISO’s and adjacent RTOs’ wholesale energy market.”
“IPPNY believes that carbon pricing is a critical step to resolve the growing tension between the state’s efforts to meet its clean energy goals and the efficient functioning of the competitive wholesale markets,” it added.
Ravenswood Generating Station, a 2,480-MW fossil fuel plant in New York City
Consumer advocates for D.C., Delaware, Illinois, Maryland, New Jersey and Pennsylvania said the commission should evaluate proposed pricing schemes individually and include consumer representation at any future technical conference or workshop. “It is axiomatic that a carbon pricing proposal that is just and reasonable for ISO New England or MISO is not necessarily just and reasonable for PJM consumers or markets,” they said.
But the Real Estate Roundtable said the commission “should foster national uniformity that avoids a patchwork of different state and local carbon protocols.”
“If 50 states and scores of local jurisdictions are left to their own devices to craft their own approaches to measure and price carbon, havoc would ensue,” it said. FERC should “advance greater national uniformity in carbon measurement” by promoting use of data in EPA’s Emissions and Generation Resource Integrated Database.”
“Fair and equitable determinations of who produces ‘more’ or ‘less’ carbon — and who should pay ‘more’ or ‘less’ — necessarily depend upon common practices to quantify [greenhouse gas] emissions, convert fuel sources to carbon and affix a price per ton of emissions,” it said.
Disparate Treatment of State Programs?
Several commenters challenged what it saw as an inconsistency between FERC’s openness to carbon pricing while it is imposing mitigation measures on existing state efforts to decarbonize, including its controversial expansion of PJM’s minimum offer price rule (MOPR).
Public interest organizations including the Union of Concerned Scientists (UCS) and the Natural Resources Defense Council’s Sustainable FERC Project said the commission was wrong to treat carbon pricing differently from renewable energy credits (RECs), which the commission says produce “unreasonable price distortions” in wholesale markets.
“FERC cannot justify different treatment for state policies that seek to address environmental and public health harms through either imposing costs or conferring benefits,” they said. “Taxes and supports are equal but opposite measures. … Both are economic policy tools intended to move a market away from the equilibrium it would have achieved absent policy intervention.”
NRG Energy said carbon pricing is not the only way to incorporate state climate policies in wholesale markets and that FERC should also encourage the development of regional clean energy markets. It noted that trade in compliance-based credits totaled $4.4 billion from 2014 to 2018 in PJM alone, more than three times the $1.4 billion generated by the RGGI carbon-allowance market over the same period.
The company cited a study published last month by Energy and Environmental Economics (E3), saying it found “a well designed regional CES can rival the economic efficiency of a regional carbon price. The report concluded either a regional CES or a carbon price could eliminate one-third of PJM system emissions by 2030 at a cost of $3.60/ton and two-thirds by 2050 at a cost of $22.60/ton. That would save $3.2 billion annually in 2030 and $12.6 billion in 2050, compared with the current practice of individual states’ renewable portfolio standards and CES policies lacking a regional market, E3 said. (See Study Recommends Carbon Price for PJM.)
A recent study on PJM’s decarbonization options concluded that the most cost-effective policies for reducing carbon emissions are those that directly target CO2 by placing a price on carbon or limiting electricity-sector emissions. | Energy and Environmental Economics
Advanced Energy Economy also urged FERC to avoid disrupting the markets for RECs and similar instruments for compensating clean energy generation. “Numerous states have expressed frustration with the misalignment of the wholesale markets with their state policy requirements and have stated that while they would prefer to leverage the benefits of broader regional wholesale markets to achieve those requirements, they will abandon wholesale market structures if necessary, AEE said.
Cost-benefit Analysis, Section 206 Authority
UCS and Sustainable FERC also said the commission would be overstepping its authority by opining on the efficiency of a particular program. “In designing their policies, state legislators and regulators may consider matters far beyond and outside of FERC’s authority and jurisdiction,” they said. “In regulating power plants and protecting the public health and welfare, states are fully within their authority to consider environmental justice, land use, labor, economic development, environmental quality, aesthetics and nearly limitless other criteria. In contrast, FERC must limit its decision making to factors related to wholesale rates.”
But the right-leaning R Street Institute said FERC should amend its policy to consider the “net benefits” of carbon pricing regimes “to ensure costs are accounted for.”
“The decisional criteria should at least explicitly require a thorough process for evaluating economic efficiency and whether the proposal harmonizes state energy policy with wholesale market operation, which have been identified in the literature as key conditions to deem rates ‘just and reasonable’ under” the Federal Power Act, R Street said. “Some of the measures of accomplishing this — such as the benefits methodology of avoiding the social cost of emissions — are outside of the commission’s scope, but it can require that economic techniques must generally comport with the peer-reviewed literature.”
R Street also said the commission should “add an explicit statement that a uniform, FERC-imposed carbon price under [FPA] Section 206 is off the table.”
But the American Council on Renewable Energy said that FERC’s authority to proactively implement carbon prices under Section 206 warrants further examination. That issue should be decided based on “analysis of the particular facts and circumstances of any future Section 206 complaints lodged by the public or the commission,” it said.
Leakage
There also were disagreements over what FERC’s role should be in addressing carbon “leakage” between states with different energy policies.
Exelon said FERC should require development of leakage mitigation rules and convene workshops to help work through policy issues.
“Among other things, RTO/ISOs must consider and resolve issues related to how the carbon price will be determined and updated, how the carbon price will interact with the market, and how to mitigate leakage and ensure price transparency,” Exelon said. “These issues take time to work through RTO/ISO stakeholder processes, particularly if there is no explicit commission obligation. For example, NYISO has been working with its stakeholders to develop a carbon adder mechanism for several years, and despite the significant efforts and progress of NYISO, its staff and numerous stakeholders, that proposal has yet to be approved and filed.”
Winning consensus is even more difficult in multistate RTOs, Exelon said. “While PJM recognizes that the expanded mitigation required under the commission’s recent MOPR orders is not a sensible long-term path forward for accommodating state policy mechanisms in PJM, support for the status quo remains, and little meaningful work has been done in PJM towards implementing carbon pricing.”
PJM states use a range of policies to promote renewable energy, reduce GHG emissions and support specific technologies and plants, such as several nuclear and coal-fired generators. | Energy and Environmental Economics
Exelon said it is unclear whether the policy statement “will have much, if any, impact on RTO/ISO prioritization of this issue. Therefore, if the commission agrees that carbon pricing is a sensible part of any path forward, it needs to go beyond merely providing ‘encouragement’ in a policy statement.”
But attorneys general for Massachusetts, California, Delaware, Maryland, Michigan, Minnesota, New Mexico, Pennsylvania, Rhode Island, Wisconsin and D.C. said “the commission need not, and should not, declare general positions on the design elements of state programs that are plainly within states’ jurisdiction, such as the manner by which state policymakers determine carbon prices, the transparency of those prices to program participants and the design of any measures to address leakage.”
Researchers from D.C.-based think tank Resources for the Future said the issue of emissions leakage should not be a factor in determining if a carbon price proposal is just and reasonable. “It is up to the state that establishes a carbon pricing policy to decide whether it is willing to accept the environmental leakage associated with its efforts to limit carbon emissions,” they said.
Jurisdiction
Independent power producer Calpine said market clearing settlement rules under carbon pricing may raise new jurisdictional questions.
“The treatment of electricity imports from resources in a state that has chosen to impose no carbon price or compliance costs into an RTO/ISO in which member states do impose a carbon price or compliance costs may present jurisdictional questions that were not squarely before the Supreme Court” in 2016’s FERC v. EPSA, which upheld FERC’s jurisdiction over demand response, Calpine said. (See Supreme Court Upholds FERC Jurisdiction over DR.)
The company also sought to ensure a continued role for natural gas, the fuel used in most of its generating plants. “To support decarbonization and electrification, credible analytical and academic studies have shown that retention of modern, highly efficient, natural gas-fired generation at capacity levels similar to or even greater than present levels is also required to ensure grid reliability. Thus, natural gas generation is an enabler, not an impediment, of economy-wide decarbonization.”
[EDITOR’S NOTE: This story originally contained numerous factual inaccuracies that have since been corrected as of Dec. 2, 2020. These included referring to sulfur hexafluoride (SF6) as “sodium hexafluoride”; stating that mixed-gas breakers must be operated at a higher pressure than those using pure SF6; and stating that NERC recommended utilities switch to mixed-gas breakers (NERC cannot recommend that entities replace certain bulk power equipment with another type of equipment). ERO Insider apologizes for the errors.]
A safety mechanism present in many commonly used circuit breakers may pose an unexpected risk to the North American electric grid during periods of severe cold weather, according to a “LessonsLearned” notice posted by NERC on Thursday.
The “Cold Weather Operation of SF6 Circuit Breakers” paper stems from an investigation of the severe cold weather event of Jan. 29-30, 2019, in the Upper Midwest, when temperatures plunged below -30 degrees Fahrenheit in some areas covered by the report. During the event an unusual behavior pattern emerged on the system of two “Upper Midwest utilities”: Their sulfur hexafluoride (SF6) circuit breakers hit their critical pressure levels, causing them to auto-open or have their tripping operations blocked.
A subsequent investigation by Midwest Reliability Organization’s Protective Relay Subgroup found that 80 SF6 breakers operated by six registered entities in the region had exhibited such behavior. No outages were directly attributed to the circuit breakers’ pressure response, but the team warned that such actions could cause concern if they became widespread.
This was not the only unexpected impact to the bulk power system during the cold weather event; a number of wind generation cut-outs occurred in the region around the same time, after reaching their own temperature limits, though this was not identified as a contributor to the breaker lockouts. (See MISO Continues Honing Wind Forecasts.)
No Accounting for Widespread Breaker Failures
The auto-open and trip-blocking behavior was not a concern for the team itself: Auto-opening is understood to not only be normal, but desirable. But because SF6 gas must be above a certain pressure for the breakers’ tripping functions to work, equipment that nears this point may be unreliable.
Entities therefore prefer to either auto-open them or “block the trip and rely on a breaker failure relay to open all adjacent (or remote) breakers in the event of a fault.” But when a large number of breakers in an area enter a low-pressure state and become inoperable, their collective response can “[weaken] the overall topology of the system and … result in more facilities being removed from service to clear a fault.” In addition, entities’ real-time contingency analysis (RTCA) studies may no longer be accurate, increasing the level of uncertainty in the system.
The report notes that utilities in areas where extremely low temperatures are a regular occurrence take this into account in their system planning and prevent widespread low-pressure faults by installing breakers that use a mixture of SF6 and tetrafluoromethane (CF4) or nitrogen. SF6-CF4 mixtures remain gaseous at much lower temperatures than pure SF6.
The downside of mixed-gas breakers is that they are more expensive are require more equipment to handle the mixture than breakers using pure SF6. As a result, entities in areas where extremely low temperatures are less common will add heating elements to SF6 breakers to keep their temperature and pressure in safe operating range.
mixtures | NERC
This approach carries its own risk, however, because inoperative heaters — which were found in 70% of the breakers affected by cold weather event — are obviously of no use. Even heaters that are working properly can still be overwhelmed if temperatures fall low enough and strong winds in the region further hamper the performance of the working heaters.
Need for Heaters a ‘Key Disadvantage’
In the report’s conclusion, NERC stressed that the need for heaters is a “key disadvantage of using … SF6 [breakers] in cold weather climes.”
If utilities in areas that can get very cold choose to keep using pure SF6 breakers, it is imperative that they implement proper safeguards against cold weather pressure drops, the report says. These measures may include maintenance and inspection of tank heaters before the onset of cold weather and installation of any temporary thermal insulation that may be necessary during the winter months.
Even if such precautions are taken, entities should expect that some insulation and heating elements will fail and lead to low-pressure cut-outs among the breaker fleet. Sensors should be installed to warn operations staff when heaters have failed so they can schedule proactive maintenance or at least prepare for pressure failures. Contingency models should also be updated to include multiple critical pressure faults so staff can be prepared for the worst-case scenario.
PJM moved a step closer to restarting its capacity auctions with FERC’s approval on Thursday of the RTO’s new energy and ancillary services (E&AS) offset calculation (EL19-58-002).
FERC approved most of PJM’s revisions, filed in August to comply with the commission’s approval of major changes to its reserve market in May. The commission had acknowledged that the changes would increase the amount of reserves the RTO procures and, thus, the revenue resources receive, affecting the capacity market’s E&AS offset. (See FERC Approves PJM Reserve Market Overhaul.)
The offset is a key variable in calculating the net cost of new entry (CONE) for resources in the capacity market. It is calculated using energy market results from the three calendar years prior to the Base Residual Auction.
PJM’s revisions change the offset to be forward-looking and included in its filing indicative E&AS and net CONE values for various resource types. These values are “based on the latest published and publicly available forward prices at that time,” FERC said, and would be revised using updated forward prices prior to the upcoming Base Residual Auction for the 2022/23 delivery year.
PJM would seek to eliminate the first and second Incremental Auctions for delivery year 2022/23 if the Base Residual Auction is not held until December 2020. | PJM
PJM has yet to set an exact date to run the BRA. It has been paused since June 2018, when FERC determined that the RTO needed to revamp its minimum offer price rule to address price suppression by state-subsidized resources.
FERC agreed with PJM using “publicly available” forward energy prices at liquid trading hubs and mapping the hubs to specific zones, “due to the high correlations in historic prices between each hub.”
“Prices from liquid futures markets (i.e., those with many buyers and sellers, as determined by open interest) produce forward prices that reflect expectations about future conditions,” the commission said.
But it ordered PJM to make a compliance filing within 15 days to use the average equivalent ability factor of all the nuclear resources in the RTO to represent a projected refueling outage. Several stakeholders had argued that using individual anticipated refueling schedules when determining nuclear resources’ availability was inadequate.
“Using an average equivalent availability factor instead of a resource-specific anticipated refueling schedule not only may avoid yearly variations in expected E&AS revenues but also may result in more accurate refueling outage projections,” the commission said.
Commissioner Richard Glick dissented in part, saying he agreed with the commission’s decision to require PJM to move to a forward-looking E&AS offset because it helps to ensure the RTO’s various markets “work in concert” and that expected increases in E&AS revenues are reflected in the capacity market.
“While PJM’s E&AS offset is by no means perfect, I believe that it is good enough to remove this issue from the list of roadblocks standing between PJM and, finally, running its auction,” Glick said.
But he scolded his colleagues for forcing PJM to complete an “unprecedented, highly technical exercise in an impossibly short period of time.”
“The reason for that rush is readily apparent: Implementing the forward-looking E&AS offset is a necessary prerequisite to running PJM’s much delayed capacity auction for the 2022/23 delivery year,” Glick said. “The responsibility for that delay lies squarely at the feet of this commission, and we owe it to all stakeholders to proceed with running that auction as soon as reasonably possible.”
The decarbonization of New England’s electricity system will require deployment of significant quantities of renewables and energy storage complemented by firm capacity from nuclear, gas-fired power plants, carbon-capture facilities, hydrogen generation or other options, according to a new study.
“Net-Zero New England: Ensuring Electric Reliability in a Low-Carbon Future,” co-authored by Energy and Environmental Economics (E3) and Energy Futures Initiative (EFI), studied how the electricity system can meet the challenges of growing demand and reducing economy-wide greenhouse gas emissions to nearly zero by 2050.
All six New England states have adopted economy-wide GHG reduction targets of at least 80% by 2050, with Massachusetts recently adopting a net-zero commitment. Through decarbonization of electricity supply and the electrification of transportation and buildings, the grid will play a critical role in achieving regional and state targets.
Removing all gas generation increases the cost of achieving a zero-emission grid by about $19 billion annually, relative to a zero-emission portfolio with zero-carbon fuels, according to a new report. | E3, EFI
EFI CEO and founder Ernest Moniz, former secretary of energy during the Obama administration, presented the study’s key findings in a keynote address to the New England Energy Summit on Monday.
Net-zero Goals vs. Increased Demand
Profound change is required across all energy sectors to achieve the decarbonization goals in New England, the study stated. Presently, transportation and buildings make up two-thirds of the region’s emissions. The study listed prime strategies for mitigating economy-wide GHGs, including aggressive deployment of energy efficiency, widespread building and transportation electrification, development of low-carbon fuels and deep decarbonization of electricity supply.
Regionally, electricity demand will increase significantly over the next three decades under the study’s net-zero scenarios. In the two bookend scenarios, annual electricity demand grows 60 to 90% — 70 to 110 TWh — from the present. Peak demand is predicted to reach 42 to 51 GW as peaking shifts from summer to winter in the 2030s. The growth is driven by the electrification of transportation and buildings that currently rely on fossil fuels. This demand increase will occur even with significant energy efficiency resources.
Study scenarios selected a diverse mix of 47 to 64 GW of new renewable generation capacity needed by 2050. The study found renewables — which include land-based solar and wind, offshore wind and distributed solar, along with 3.5 GW of new incremental Canadian hydro — will play a significant role in providing zero-carbon energy to the region.
New England’s limited land availability means greenfield development will be required for renewables to reach adequate scale, even if opportunities to develop brownfield sites, rooftops and marginal lands are maximized, the study found. It also found that New England’s geography, the slow pace of electric transmission planning and historical difficulty siting new infrastructure are significant challenges.
A decarbonized grid requires firm generating capacity, and natural gas and nuclear generation are the primary sources of firm capacity in New England. Solar, wind and battery storage technologies will play large roles in the future regional system, but reliance on these resources alone would require substantial quantities of renewable energy and storage and would be too costly.
In practice, as much as 46 GW of firm capacity could be needed in 2050 to ensure resource adequacy. The study included 34 GW of gas generation, 3.5 GW of existing nuclear, 8 GW of imports and 1 GW of biomass and waste.
Significant gas capacity is retained even though the gas plants operate far fewer hours and contribute less energy and emissions to the region. New resources potentially developed and deployed to provide low-carbon firm capacity, such as advanced nuclear, natural gas plants with carbon capture and sequestration, long-duration energy
storage or generation from carbon-neutral fuels such as hydrogen. These resources would require significant investments in supporting infrastructure; for example, natural gas with CCS or hydrogen would require pipelines connecting New England to regions with suitable geology for carbon sequestration or hydrogen storage.
“Fundamentally, one way or another, we are going to need significant firm generation in order to have a reliable and resilient system,” Moniz said. “There are still some uncertainties that need to be addressed in that context, such as the need for long-term storage. There will be substantial infrastructure needs, and that frankly has been a significant challenge in New England. The path forward is not only through technical innovation but also through innovation in the policy and regulatory environment to allow the needed infrastructure to be built in a timely way.”
Technology Choices
The study also concluded that a broad range of technology choices could lower costs and risks. The availability of low-carbon firm generation technologies — such as advanced nuclear or natural gas with CCS — could provide significant savings and reduce the pressure of renewable development on New England’s lands and coastal waters. In addition to reducing costs, a portfolio approach to making low-carbon firm generating resources available mitigates the risks that one or more technologies do not materialize as expected.
Meeting net-zero GHG emissions requires carbon dioxide removal (CDR), though that alone will not be enough to achieve economy-wide decarbonization or meet the region’s policy targets. The lack of suitable geology for carbon sequestration makes direct air capture and bioenergy with CCS an imperfect solution, but a large stock of forests provides an excellent opportunity for in-region CDR.
“We need CDR to get to net-zero, probably beyond the borders of New England,” Moniz said. “We need to use the innovation capacity that this region is blessed with, hand in hand with what I believe will be a major federal push and a bipartisan push for really upping the game on the innovation of these clean energy pathways.” He added that the New England congressional delegation “should get fully behind a thrust to increase the innovation focus in the federal government.”
“By increase, I’m not talking here about 10% increases,” Moniz said. “I mean a doubling or tripling of the federal research and development budgets.”
Commercialization of emerging technologies can be additionally aided by leveraging regional innovation capacity, according to the study. Policymakers can increase the likelihood of commercializing emerging technologies by orienting the homegrown efforts of private, public and academic researchers already developing science and business innovations relevant to decarbonization. Specifically, advanced nuclear, long-duration storage and renewable fuels are innovation areas with tremendous regional potential, the study stated, and could play a role in supporting a low-carbon power sector, especially when localized efforts coordinate with federally funded programs.
The NEPOOL Markets Committee passed a five-time-amended motion to update Forward Capacity Market (FCM) parameters for the 2025/26 capacity commitment period during a marathon two-day meeting.
The motion won with 64% in a sector-weighted vote. Of the five amendments passed, four of them came from the Union of Concerned Scientists on behalf of RENEW Northeast; the other was from Borrego Solar and Enel X.
The committee rejected the initial motion from ISO-NE and Concentric Energy Advisors (CEA) and Mott MacDonald (MM), two consulting firms hired by the RTO to help update the cost of new entry (CONE), net CONE, offer review prices (ORTPs) and performance payment rate values for the FCM. It gained only 16.7% support, with only the Publicly Owned Entity sector voting in favor.
The RTO said the calculations it put forth did not include changes from its Energy Security Improvements (ESI) proposal and assumed the continuation of the Forward Reserve Market. FERC Rejects ESI Proposal from ISO-NE.)
The proposed CONE and net CONE values were based on a new combustion turbine unit in New England, identified as the lowest-cost, economically viable technology likely to be built in the region. ORTPs were proposed for gas turbines, combined cycle, onshore wind, battery, energy efficiency and demand response technologies. The PPR value was based upon the CT technology recommended for the proposed CONE values. The CONE, net CONE and ORTPs were from CEA and MM.
The 1,143-MW pumped-storage hydroelectric Northfield Mountain Project on the Connecticut River in Massachusetts | FirstLight Power Resources
ISO-NE also put forth Tariff revisions to align the calculations for updating the energy and ancillary services revenues input in the years where there is no full recalculation to revise the indices used to update these revenues.
The RTO previously stated that interdependencies among the FCM parameters present unique challenges when calculating the combined effect of more than one amendment on the values. The RTO said it would tabulate and publish the five amendments’ impacts before a vote on Dec. 3 by the Participants Committee.
Monitor and RENEW Duel in Memos
Abigail Krich and Alex Worsley of Boreas Renewables presented RENEW’s four amendments, including capital costs and the investment tax credit for the ORTP calculation for offshore wind.
RENEW used an overnight capital cost of $3,326/kW (2019$) and an 18% tax credit for OSW in Forward Capacity Auction 16 and added that the RTO’s capital cost is 161% of expected prevailing market conditions for 2024/25 projects.
The RTO’s Internal Market Monitor posted a memo critical of RENEW’s calculations and methodology, saying “the use of a top-down method to infer a capital cost from contract rates is not an accurate means of establishing capital cost and the resulting ORTP value as compared to the bottom-up approach taken by the ISO and prescribed by the Tariff.”
According to the Monitor, the approach taken by CEA and MM is a direct estimation of capital cost.
“It uses actual capital cost data; [it] can be scrutinized in its components; and the value does not vary with assumed model parameters,” the Monitor wrote. “While the details were not made available to NEPOOL for confidential/commercial sensitivity reasons, they were scrutinized by MM, CEA and the ISO — none of which has a financial or other interest in having a higher or lower capital cost value other than one that accurately represents the capital cost of a new OSW project in New England.”
In reply to the Monitor, RENEW said ORTPs in FCA 16 would affect capacity commitment periods between 2025 and 2028, when many OSW projects will come online.
“Offshore wind plays a significant role in states’ plans to reach their renewable energy and decarbonization objectives,” the memo said. “Without an appropriate ORTP, these projects will be prevented from clearing in the market due to unreasonable mitigation, which will deprive them of revenue critical to their implementation and consequently increase costs to consumers.”
The Monitor also noted that setting the ORTP “too low … carries with it the potential for significant market harm.”
RENEW countered that setting the ORTP at the low end is “exactly what we should be doing according to the Tariff and FERC directives.” It added that the RTO itself in its December 2013 filing updating ORTPs for FCA 9 described the intent of the calculation is to set ORTPs “at the low end of the competitive range of expected offers so as to strike a reasonable balance by only subjecting resources to IMM review which plainly appear commercially implausible absent out-of-market revenues.”
“If it is the position of the ISO and IMM to subject offshore wind resources to a higher bar than that specified in the Tariff or FERC directives, that could explain why the ISO’s proposed ORTP values are head-and-shoulders higher than all public estimates,” RENEW said.
Order 841 Compliance Filing Nets Support
The committee unanimously supported ISO-NE’s plan for its third Order 841 compliance filing.
The RTO proposed Tariff changes to comply with three FERC directives. The first change was removing Tariff language that could have created a barrier to the participation of a storage resource in its markets, effective in the first quarter of 2021. The second is the inclusion of four bidding parameters and a newly defined term into the Tariff that the RTO will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.
Separately at the NEPOOL Transmission Committee, the RTO and Participating Transmission Owners Administrative Committee have proposed Tariff changes to clarify the application of transmission-charge exemptions associated with storage. In addition to the compliance revisions, ISO-NE also proposed several clean-up revisions to Appendix C of the Tariff to correct outdated terminology.
The RTO will next seek support from the Participants Committee, which will vote on the plan at its Dec. 3 meeting, and has asked FERC to allow a Dec. 7 filing date.
Modifications for EERs, RAs Approved
The committee also voted to support the RTO’s modifications to the qualification process for energy efficiency resources (EERs) to better account for expiring measures. ISO-NE’s Ryan McCarthy wrote in a pre-vote memo to the committee that the modifications “will more appropriately balance the performance and expiration of energy efficiency measures and will produce qualification results that are more reflective” of EER capabilities.
There will also be changes to the monthly reconfiguration auction (RA) and bilateral qualification rules to better account for new financial assurance and performance accounting rules. Additionally, the RTO will assign monthly qualification to resources that become commercial during the capacity commitment period. The monthly qualification will track delayed commercial resources and allow noncommercial capacity to participate in monthly RAs and bilateral qualifications.
The EER qualification changes would become effective in February 2021 for FCA 16. The monthly qualification changes would become effective in January 2022 and implemented for the March 2022 RA and bilateral qualification period.
The Participants Committee will vote on the modifications at its Dec. 3 meeting.
San Francisco and Ojai, Calif., last week banned natural gas in new buildings, bringing the number of cities in the state that have adopted building codes to reduce their reliance on gas to 39, according to the Sierra Club.
Ken Costello | NARUC
While such bans have become increasingly popular in the push for electrification, they are an “exceptionally bad” way to attack climate change, regulatory economist Ken Costello told the National Association of Regulatory Utility Commissioners’ Annual Meeting and Education Conference during a panel discussion Nov. 10.
“Less than 9% of carbon emissions in the U.S. are from direct use of natural gas in homes and buildings. The U.S. emits about 15% of world carbon emissions. Thus, under the condition where all buildings are converted to be electric and we have electricity produced only from clean sources, the reduction in worldwide carbon would be less than 1.5%, which would have no impact at all … on global climate,” said Costello, an independent consultant who formerly worked for NARUC’s National Regulatory Research Institute. “We know there’s more efficient ways to deal with climate change.”
‘Incongruent’
Richard Meyer, managing director of energy analysis for the American Gas Association, was also critical, saying natural gas is desired by consumers and that its infrastructure will be essential for decarbonizing. Bans represent “an all-or-nothing approach that seems incongruent with the size and the scale of the challenge” of climate change, he said.
Richard Meyer, American Gas Association | NARUC
Residential natural gas represents 4% of U.S. GHG emissions, with the commercial sector adding another 3%. “Residential natural gas emissions on average are about 250 million metric tons per year of CO2. That’s equivalent to two weeks of Chinese coal emissions,” Meyer said.
The third member of the panel, Amber Mahone, a partner in San Francisco-based consulting firm Energy and Environmental Economics (E3), acknowledged that U.S. natural gas use is a small contributor to worldwide GHG emissions.
“I would say there’s two reasons for action despite that fact,” she said. “One is the incredible power of the U.S. market to drive innovation. We’ve seen that with investments in solar and wind, bringing down the capital cost of that equipment dramatically and leading to widespread economic adoption of renewables. I think we could see similar innovation occurring in decarbonizing buildings, both with innovations in heat pumps as well as innovations with renewable natural gas. Bringing down the cost of biomethane and hydrogen would certainly be beneficial globally for reducing emissions.
“The other [reason] I would say is that deciding not to take action is a bit of a cop-out for one of the most advanced industrialized economies that historically has contributed to the predicament that we find ourselves in today.”
A Trend?
Although more than three dozen California cities have adopted gas bans, the idea has not taken root elsewhere.
Brookline, Mass., banned natural gas hookups in new buildings last year, but the state’s attorney general struck it down because state law pre-empted the city’s ordinance.
Meanwhile, Arizona, Tennessee, Oklahoma and Louisiana passed laws this year barring local governments from adopting electrification measures or natural gas bans similar to those in California, according to InsideClimate News. At least four other states introduced similar measures, it reported.
Percent of Californians living in jurisdictions with clean energy building codes | Sierra Club
Meyer said bans have been enacted without sufficient analysis on costs and benefits, including the strain on electric infrastructure and the impact on jobs, taxes, wages and low-income residents. “I’m not saying [carbon emissions from natural gas] can’t and shouldn’t be reduced,” he said. “I’m not saying they’re unimportant. Quite the opposite: AGA is committed to reducing GHG emissions through smart innovation, new modernized infrastructure and advanced gas technologies.”
But he said gas is the most affordable way to heat homes, with electric heat costing about 3.7 times as much. “The natural gas system today delivers a tremendous scale of energy to homes and businesses when they need it most. The gas system delivers about three times more energy on the coldest day of the year than the electric system does on the hottest.”
As evidence of consumer demand for gas, Meyer noted that although California has led the way on gas bans, it has also added almost 600,000 residential gas customers since 2010, more than any other state. He said natural gas and its infrastructure will be crucial to meeting climate goals, which some say will require a future “hydrogen economy.”
“One of the key ways to make hydrogen is via natural gas. And you can use carbon capture with a steam reformation process and have low-carbon sources of hydrogen,” he said. “Europe has … come to a recognition that you really do need to leverage the gas system to achieve your goals quickly, effectively and cost-efficiently. I think the U.S. will come to the same realization.”
No Easy Solutions
Amber Mahone, E3 | NARUC
Mahone acknowledged that decarbonizing existing buildings is difficult and expensive, but she said their contribution to climate change is too important to ignore.
“All of the options on the table have challenges and costs if you look at the economics today. But we also know that reducing greenhouse gases is difficult in many sectors of the economy, including in the industrial sector and aviation and heavy-duty trucking,” she said. “So, if we shied away from one area where it looks hard, we might find ourselves not taking action anywhere. So, I do think it’s important to tackle greenhouse gases for buildings.”
Costs Vary by Region
Mahone also said the economics of replacing gas heating with electricity varies by region. In the Bay Area, she said, there has been a trend toward all-electric new construction, particularly in multifamily buildings, because of the cost savings and reduced permitting time from avoiding natural gas hookups.
Berkeley, one of the first cities to adopt a gas ban, has “a relatively mild climate. … We get an occasional winter frost and that’s about it,” she said. “We do see that electrification can reduce energy bills in some cases.”
Some colder regions are opting for dual-fuel heating systems, “where you can gain the benefit of high-efficiency heat pumps during most hours of the year and still have access to backup thermal heat in colder times,” she said.
She noted that Pacific Gas and Electric supported the Berkeley gas ban to avoid investments in new gas assets that may later prove to be underutilized. “That’s a pretty remarkable statement, I think, coming from a gas utility.”
Mahone noted that gas pipelines and distribution systems are typically financed and amortized over 30 to 50 years, meaning a gas line installed today would not be paid off until as late as 2070. “So, I don’t think that it’s exactly right to look at the economics of a gas ban just purely from the [position] of an individual customer, because the gas infrastructure that our regulatory environment supports is actually … socialized over many customers.
“The alternatives to electrification are quite expensive as well,” she added. “Renewable natural gas has supply limitations. We see it costing about $10/MMBtu today — three to five times the cost of fossil natural gas.”
She noted that while some research suggests the cost of green hydrogen — which uses renewable energy to produce hydrogen from water — may be reduced to between $11 and $20/MMBtu, it would still be well above the cost of fossil natural gas.
Geoengineering?
Costello said policymakers also could consider options for adapting to climate change rather than attempting to eliminate GHG emissions, such as geoengineering, which includes CO2 removal and solar radiation management, or sunlight reflection.
“If you look at the history of mankind, humans have adapted to very drastic conditions of climate and other things over time, and that’s sort of one way to deal with this. But I think the savior of all this is technology, innovation,” Costello said.
“Geoengineering … is somewhat controversial, but still, it’s an option that’s on the table. In fact, some of the best minds now are saying that we have to have a portfolio of different actions to deal with climate change. So far, we have disproportionately focused in on emission reductions.”
Four present and former regulators told the National Association of Regulatory Utility Commissioners last week they are skeptical that carbon pricing and mandatory capacity markets would achieve decarbonization goals.
Instead, consultant Rob Gramlich, who served as an aide to former FERC Chair Pat Wood III, touted the energy-only market his former boss helped design in ERCOT. Former Montana regulator Travis Kavulla cited the simplicity of a clean energy credit market, saying it could save PJM billions annually. Rhode Island regulator Abigail Anthony warned against mixing clean energy goals with economic development, while Kentucky regulator Talina Mathews predicted the role of PJM’s capacity market would diminish.
Speaking at the NARUC conference on clean energy and markets were (clockwise from top left) moderator Judith Jagdmann, Virginia State Corporation Commission; Abigail Anthony, Rhode Island Public Utilities Commission; Talina Mathews, Kentucky Public Service Commission; Rob Gramlich, Grid Strategies; and Travis Kavulla, NRG Energy. | NARUC
Judith Jagdmann, a three-term member of the Virginia State Corporation Commission, moderated the general session discussion on clean energy and the markets at NARUC’s Annual Meeting and Education Conference. The session Nov. 10 came less than a week before Monday’s deadline for comments on FERC’s proposed policy statement inviting states to introduce carbon pricing in wholesale electricity markets (AD20-14). (See FERC: Send Us Your Carbon Pricing Plans.)
Don’t Mix Economic Development with Energy Goals
Anthony, who was appointed to the Rhode Island Public Utilities Commission in 2017, opened the session by listing the criteria she said were needed for a wholesale market design to meet state clean energy objectives: It should deliver incremental carbon reductions; allow clean energy projects to secure financing; include penalties for facilities that fail to deliver; and internalize externalities that are associated with the markets.
Abigail Anthony, Rhode Island PUC | NARUC
What the market should not attempt to do, she said, is “deliver on policies that are not direct externalities of power generation,” including economic development.
“It’s going to take many billions of dollars in investments to mitigate climate change and achieve our states’ greenhouse gas reduction targets, and we risk not having the means to meet those greenhouse gas-reduction goals when we make economic development and local jobs the primary purpose of clean energy,” she said. “So, I think that for our own good — kind of to save us from ourselves — we need markets that are designed to deliver maximum carbon reductions at the least cost.
“I think that [ISO-NE] can certainly design a market that internalizes carbon externalities. The Forward Clean Energy Market seems to be a good example of a market structure that internalized the carbon value of clean energy and provides the stable medium- or long-term revenue stream that allows projects to be financed,” Anthony said. “But to realize cost savings over current practice, states would have to cede control and allow the market to deliver the most efficient projects.”
Carveouts for in-state resources would make the market less efficient, she said. “States have a lot of policies, and very few of them should be reflected in wholesale markets.”
Similarly, the market should not attempt to internalize externalities such as concerns about the land-use impact of solar generation, Anthony said. “The loss of farmland, or pollinator habitat — those are externalities of land development, and the externality needs to be internalized via the price of developing land so that those additional costs flow to whatever development goes on that land, whether it’s solar or condominiums.”
Asking Markets to do More than they Can
Mathews, who joined the Kentucky Public Service Commission in 2017, said markets are best at security-constrained economic dispatch: “The megawatts get to the customers at the least cost available.”
But she said their success depends on a large footprint and a uniform commodity. “I think when you start to carve out the footprint and then you start to change [to] green megawatts, blue megawatts, red megawatts, black megawatts, then you’ve suddenly started segmenting that market and it becomes less efficient.”
Talina Mathews, Kentucky PSC | NARUC
That, she said, is PJM’s problem: dealing with a patchwork of state laws and executive actions, including goals for renewable energy, clean energy, carbon and energy efficiency.
“You’re kind of asking the market to do more than it was designed to do or that it can do efficiently,” she said. “I think fundamentally you will get to a point in an RTO like PJM where there will be state policies that get promoted at the expense of other state policies, and I think you’ll see then either [state] commissions making the decision to pull their utilities out [of the RTO], or maybe in other states, they’ll tell their utilities they have to [use] fixed resource requirements … to acquire their own resources to meet their load, and the capacity market will just be residuals.”
Clean Energy Credit Market, not Carbon Pricing
Kavulla, vice president of regulatory affairs for NRG Energy, noted that 30 jurisdictions have adopted clean energy standards (CES) or renewable portfolio standards and a quarter of the U.S. population is in areas that have declared 100% clean energy goals. But only a handful of them, such as members of the Regional Greenhouse Gas Initiative (RGGI), price carbon.
Travis Kavulla, NRG | NARUC
“For PJM, which has both CESes, RPSes and carbon pricing, the market for [renewable energy credits] is about four times as large as the market for emission allowances within RGGI. … So, if FERC and states are really going to be speaking the same policy language here, it really needs to center around that trade in credits — renewable energy credits or something hopefully more technology-neutral so you can fulfill Commissioner Anthony’s mandate for the same value for the same increment of carbon reduction.
“I think states and FERC alike would be well advised to consider setting up state-led, RTO-facilitated markets for these clean energy credits,” continued Kavulla, who served as NARUC president during his term on the Montana Public Service Commission. “The Forward Clean Energy Market is one type of market design that could facilitate that; there are real efficiencies to be wrung out of the system now.”
RPS and CES programs are often targeted toward particular technologies or include locational requirements, he said. And they are usually secured through long-term contracts that undermine RTO markets’ shift of risk to generation owners like NRG, he said. “So, that same basic model that’s worked fairly well for restructured jurisdictions is something that I think can apply to a trade in clean energy credits to get it to look a little bit more like a competitive market where investors have to take risk.”
Kavulla cited a study published last month by Energy and Environmental Economics that found an efficient regional CES could save $2.5 billion annually in PJM. The study also said that existing state carbon policies and subsidies will increase electricity costs by more than $3 billion in 2030 and achieve less than half of emissions reductions that could be achieved through a competitive, market-based approach. (See Study Recommends Carbon Price for PJM.)
“That study shows that a regional, efficient CES can also rival the efficiency of a regional carbon price” without concern over the kind of carbon leakage seen in RGGI, Kavulla said. “In a regional carbon price configuration, in order for it to really work, you need price uniformity across an entire region. And it’s going to be hard to achieve that in a mix of states as diverse as West Virginia and Maryland, to use two neighbors.”
In contrast, a CES market would provide “a lot more flexibility for the states, as well as more of a seat at the table in terms of governance and market design oversight, simply because they ultimately control the spigot of demand.
“I think a more voluntary market like a regional clean energy standard or a clean energy market is probably a more politically appealing way to go, simply because a lot of states have voluntarily expressed the quantity they want as well as the reserve price — the price ceiling. And you don’t have to worry about FERC playing carbon referee on leakage,” Kavulla continued. “I think it’s worth FERC considering carbon pricing … but they really need to be considering alongside that a policy for a regional clean energy standard. Because without it, I fear, states and FERC are still going to end up two ships passing in the night.”
ERCOT Model
Gramlich, president of Grid Strategies and executive director of Americans for a Clean Energy Grid and the WATT Coalition, said he was confident the U.S. can achieve more than 80% renewable penetration and up to 95% carbon-free generation with existing technologies.
Rob Gramlich, Grid Strategies | NARUC
“But you operate that system differently, and so, we’re going to have to think about how do we not only get the long-term procurement for the carbon-free, clean renewable resources … but also the flexible and firm resources, because we need to acknowledge there will be three-day periods where there isn’t a lot of wind or sun.”
Gramlich said he supports ERCOT’s energy-only model, which makes competitive retailers responsible for resource adequacy. “Of course, if a state has more ambitious clean energy objectives, they can pass a CES or carbon price and do that if they wish. If a state is not interested in that much retail competition … they can do a New Jersey-style [basic generation service auction] under that same market structure, where … you still get the benefit of competitive generation.
“Right now, it’s really unclear between a lot of different entities who has the responsibility” for resource adequacy, he said.
Commissioner Jagdmann noted that Texas has shown reserve margins as low as 3%. “Are you comfortable with that?” she asked Gramlich.
“Every year is another test of the ERCOT model, and every year it works,” Gramlich replied. “And then every skeptic or every fan of central capacity markets says, ‘Oh well, there was something unique about last year. We’ll see how it goes next year.’ You know, we’re in Year 20. … It’s been working great every year. I don’t think reserve margin is necessarily the right metric of reliability; it will be different in the future if you get that active demand-side” response.
“Texas isn’t perfect,” Gramlich continued. “They need more dynamic retail rates, like most states do — some type of real-time, time-of-use [pricing] or some other type of pricing on the retail end.
“We all need to get used to scarcity pricing in any RTO. I think all of them should have prices that go … well into the four digits, because there are times when the accurate wholesale price in terms of the value of energy is up there. Now the key from a consumer protection standpoint … is you want to make sure nobody actually has to pay that. And you do that by making sure there is forward contracting or hedging. And that basically is what happens in Texas. You get to $9,000[/MWh] prices, but you look around and pretty much everybody is hedged. So, it’s sort of like: You don’t want to get the speeding ticket, but you didn’t have to speed.”
Pricing Carbon in Electricity but not Heating, Vehicle Fuel
Anthony said the focus on carbon pricing in wholesale power markets alone is myopic.
“What we’re really, really going to need if we’re going to achieve our goals is an economy or energy sector retail carbon price, which theoretically would be a much more efficient tool to achieve the New England states’ goals around transportation and heating electrification.
“If we continue to price carbon in electricity like we do through RGGI and all of our other clean energy goals and continue to ignore it in the price of natural gas and heating oil and transportation fuels, we’re going to fail at our electrification efforts because we’re just going to keep driving up the price of electricity even more relative to its substitute fuels.”
ISO-NE asked FERC on Friday whether it was free to seek its directions on how to improve its fuel security following the commission’s ruling last month rejecting the RTO’s proposed Energy Security Improvements (ESI) market design (ER18-1509, EL18-182, ER20-1567).
“The region is at a crossroads with respect to energy security and its reserve markets,” ISO-NE said. “The ISO does not believe that it is prudent to move forward without the opportunity to speak freely with the commission and its staff. Accordingly, we are stalled.”
In July 2018, FERC found that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns, prompting a nearly two-year-long effort that resulted in the ESI proposal. (See FERC Rejects ESI Proposal from ISO-NE.)
ISO-NE told FERC that it, along with New England states and other stakeholders, “expended considerable resources and time evaluating the region’s fuel and energy security and possible market design enhancements.” Still, its efforts, which included more than a year of stakeholder meetings, “did not benefit from a consultation” with the commission because of ex parte communication rules following the 2018 order.
The RTO requested confirmation of its understanding that the commission’s rejection of ESI left it up to ISO-NE “to determine whether to pursue market solutions to the region’s needs” and that it does not have a pending obligation from the 2018 order to file another proposal.
ISO-NE spokesperson Matt Kakley said that the filing explicitly seeks clarity on whether “ex parte communication rules that are part of a [Federal Power Act Section] 206 proceeding still apply” following the commission’s decision. Kakley noted that the RTO did not request a rehearing of the decision.
The RTO asked that FERC act on its request by Dec. 1, contingent on no other party filing a rehearing request.
ESI would have allowed the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter, when natural gas shortages can leave generators without fuel. Option awards would have been co-optimized with all energy supply offers and demand bids in the day-ahead market.
FERC ruled that the products “do not provide enough time for resources to take the steps necessary to perform during stressed conditions if they have not already taken them” as arranged fuel, for example. The proposal would have allowed resources that have not made advance arrangements to not participate because of its voluntary nature, undermining its ability to address fuel security, the commission said.
The commission also rejected an alternative proposed by NEPOOL, which would have had lower costs to ratepayers than the RTO’s proposal but contained the same deficiencies.
