As Massachusetts begins to measure progress on net-zero emissions, the state’s Energy Facilities Siting Board approved a new liquefied natural gas facility in Charlton on Friday.
The board determined in its final decision that “there is a need for additional natural gas facilities … to meet reliability, economic efficiency and environmental objectives” in the state.
Alternatives to building an LNG facility in the area, such as expanding interstate natural gas pipelines, trucking gas from other facilities or using oil and propane to heat homes, are more harmful to the environment, said Andre Gibeau, attorney with the EFSB. (See Mass. Considers Approval of LNG Facility in Environmental Justice Community.)
“Even with the mandatory goal of achieving a net-zero carbon profile in 2050, the commonwealth’s 2050 climate roadmap acknowledges that natural gas will continue to have a role,” Gibeau said at the combined EFSB and Department of Public Utilities hearing on the LNG facility.
Developed by the Northeast Energy Center, the facility will provide 168,500 gallons/day of natural gas liquefaction capacity and 850,000 gallons of storage capacity for National Grid (NYSE: NGG).
The facility has double the liquefaction and storage capacity of that needed to fulfill firm commitments to National Grid, and Northeast Energy “intends to market the facility’s remaining production and storage capacity,” Gibeau said.
Northeast Energy is also interested in selling the LNG to heavy transportation markets, such as trucking or ocean vessels if technology allows, to displace the use of oil.
The Mystic Generating Station, the power station with the highest natural gas capacity in the state, is slated to retire in 2024, so the new facility in Charlton has “significant importance in the market as we see it today,” Gibeau said.
In a Lessons Learned report published Monday, NERC reviewed the electric industry’s response to the COVID-19 pandemic and provided possible paths for the future based on the experience.
More than 45 million cases of the novel coronavirus have been reported to the Centers for Disease Control and Prevention (CDC) since January 2020, and more than 730,000 deaths. NERC first indicated it was working on a report about the industry’s pandemic response more than a year ago, but the idea dates back to the earliest stages of the outbreak, when utilities began to adjust their business practices to reduce the risk of losing critical personnel while still providing full service to customers. (See NERC Planning Lessons Learned on COVID-19 Response.)
Last year NERC noted that the arrival of a pandemic had exposed vulnerabilities that many utilities’ business continuity plans had not anticipated. (See Pandemic Poses Long-term Reliability Challenges.) The Lesson Learned: Pandemic Response report covers common elements of these plans and adjustments that NERC believes the experience of the pandemic has shown to be useful.
In the report, NERC noted that many utilities took similar steps in the early stages of the pandemic: for example, reducing staff presence in corporate offices in favor of promoting remote work arrangements and limiting staffing in generating plants and transmission/distribution control centers to essential workers.
To keep these workers safe utilities set up various forms of “reverse quarantine” — isolating a known healthy population from a presumed-infectious population, as opposed to traditional quarantines which require isolating the infected to protect the rest of the populace.
Utilities relied on these “generic actions” at first because little was known about the nature of the new virus, including how it spread and which populations were most vulnerable. As a result, and mindful of their responsibility for providing stable electric service, organizations erred on the side of caution by attempting to “cover a wide range of circumstances.”
As the pandemic went on, registered entities refined their initial approaches based on experience and recommendations from the CDC. Actions became more varied as entities had to exercise their own judgment and adjust their response in real time. Differences could be minor — for example, the software used for remote work and teleconferencing — or more significant, such as the procedures for sequestering and separating employees, and the degree of sanitizing and movement required upon discovery of an infected worker.
In its recommendations, NERC recognized that “the particulars of a pandemic response plan have to be in generic terms” as scientists come to terms with the new outbreak. However, the agency said this does not mean that utilities’ pre-COVID response plans are fine as is; new continuity plans that take into account the experiences of the last year can ensure better reliability when the next outbreak occurs.
NERC said the “main transportable experience” was the proficiency many organizations and their employees gained with remote work tools and processes. While these tools were widely deployed as a health measure, NERC noted that entities reported “many cases of reduced overall costs” and efficiency savings, due to lowered electricity and water costs in less populated offices. The organization said many entities are considering keeping these arrangements in some form even after coming out of their emergency postures.
NERC’s report noted that social distancing is not always possible during maintenance and construction activities, and that entities may need to review their practices so that essential system reliability work can continue safely during future pandemics. Entities should also review their methods of communication with neighbors to ensure crews from different utilities working in the same area can maintain a safe separation.
Milestones and procedures for ending remote work and social distancing should also be considered carefully ahead of time and communicated to employees to avoid confusion. This includes the conditions under which employees should return to the office, along with whether to continue reopening when those criteria are no longer met — for example, in the event of a surge in infections.
Finally, entities must consider “the psychological and mental health needs of employees … so they can concentrate on business related matters and remain productive,” NERC said. Since different workers may have varying levels of comfort with resuming in-person work, employers may also consider allowing staff to choose between varying levels of remote or face-to-face engagement.
In addition, NERC reminded entities of the resource it produced in 2020 along with the Department of Energy, FERC, and the North American Transmission Forum on pandemic response, which “has been updated as additional tactics have been incorporated.” (See NERC, FERC Release Pandemic Response Resource.)
With net-zero emissions a “precondition” for limiting global warming, the 26th Conference of the Parties is going to be “a reality check for global ambition on climate,” according to Joseph Majkut with the Center for Strategic and International Studies (CSIS).
The countries that have considered or committed to net-zero emissions targets cover 72% of global emissions, but their actions would only limit warming to about 2.5 degrees Celsius, said Majkut, who is director of the CSIS energy security and climate change program.
“In terms of the Paris agreement target, we’re operating behind the ball,” he said during a CSIS press call on Monday.
Paris agreement signatories agreed to limit global warming to below 2 degrees, but Majkut says there is “tension” among G20 nations as well as between developed and developing countries over how far below 2 degrees the world can or should go.
Heat-trapping greenhouse gases in the atmosphere reached a new record last year, according to the World Meteorological Organization’s (WMO) Greenhouse Gas Bulletin released on Monday.
The bulletin “contains a stark, scientific message for climate change negotiators at COP26,” WMO Secretary-General Petteri Taalas said in a statement. “At the current rate of increase in GHG concentrations, we will see a temperature increase by the end of this century far in excess of the Paris agreement targets of 1.5 to 2 degrees Celsius above pre-industrial levels.”
Concentration of carbon dioxide reached 413.2 parts/million in 2020 and is 149% of the pre-industrial level, the bulletin said.
The big factors at play at COP26 will be the extent to which countries are willing to make further commitments toward achieving net-zero emissions this century, and how quickly they are willing to realize those commitments, according to Majkut.
“It’s important … that net-zero goals don’t become an excuse to punt on near-term progress,” he said. In a world governed by net-zero commitments, he added, climate outcomes will be tied to how quickly large emitters are able to reduce their current GHG emissions.
The conference opens in Glasgow on Sunday, and President Biden will attend Nov. 1-2.
Whether his presence will have a positive influence on global climate ambition is not clear because Biden “is standing on slightly shaky ground,” Majkut said. Biden needs to be able to demonstrate at the conference that his Build Back Better Act has the necessary provisions and support to achieve his pledge to reduce emissions 50% by 2030.
But the act “is getting winnowed away in Congress,” Majkut said.
More to Watch
Sectoral approaches to emission reductions will be on the rise at COP26, according to Majkut.
The U.S. and the European Union, for example, are leading an effort to reduce emissions from methane 30% from 2020 levels within the decade, particularly in oil and gas production. Big producers, including Saudi Arabia, have signaled their support for the Global Methane Pledge announced in September, but other countries, such as Russia, are reluctant to participate, he said.
The pledge will launch formally during the conference.
Majkut also expects coalitions backed by private companies to make announcements during the conference about reducing emissions from hard-to-abate sectors, such as steel, shipping or aviation.
“The extent to which those groups are able to ensure long-run emissions reductions … depends on how large those coalitions can be built,” he said. “And voluntary actions from the private sector are not necessarily as robust as government commitments.”
In addition, Majkut said, climate finance could govern COP26 discussions as they relate to phasing out traditional coal technologies, one of the largest emitting sectors.
Commitments to phase out coal are a central goal of the conference, but it’s a challenge for developing countries.
“They’ve made very clear that that’s a hard thing to do without a significant amount of financial support from developed countries,” Majkut said. Developed countries promised $100 billion a year in Paris to developing countries, and they have missed that target.
“Developing countries are asking for more,” he said. “It’s not clear to the extent to which the developed countries are able to make firm commitments for climate finance.”
Texas regulators are wasting little time in redesigning the ERCOT market as they rush to meet a self-imposed deadline to release a new blueprint by Dec. 19.
The state’s Public Utility Commission staff is expected to release a strawman on the new market design this week. Stakeholders have until Nov. 12 to comment on the draft design, with further discussion possible during two PUC work sessions Nov. 4 and Dec. 9 (52737).
That compares with the years of work that went into constructing the ERCOT market in the late 1990s and the ISO’s nodal redesign that was implemented in 2010.
“We’ve got to choose a path to go down relatively soon,” PUC Chair Peter Lake said during a commission work session Thursday. “We don’t have luxury of years of study.”
The commissioners appear to have consensus on reforming the operating reserve demand curve and emergency response service (ERS) and continuing ERCOT’s development of fast-responding regulation service and contingency reserve service products.
However, Lake’s push for a load-serving entity reliability obligation met with resistance from all three of the other commissioners over the proposal’s uncertain costs and its effects on ERCOT’s competitive retail market. The LSE obligation addresses resource adequacy concerns by introducing a formal reliability standard and a mechanism to ensure sufficient resources meet this standard. (See Study Suggests Texas LSEs Can Provide Reliability.)
Jimmy Glotfelty, among those who helped design the ERCOT market 25 years ago, called the LSE obligation a “massive market change.” He shared the fears of some that the obligation would result in the state’s largest retailers consolidating their positions.
“I don’t want to go to four generation retailers that have monopolies in the state,” Glotfelty said. “If [the LSE obligation] is detrimental to customers and retail competition, it’s going to be really hard to get over that hump. I want to have a robust retail market, and I don’t yet have any assurances this will incent new generation.”
Lori Cobos, who led the consumer-focused Office of Public Utility Counsel before being appointed to the PUC, asked that ERCOT’s Independent Market Monitor protect the market should the LSE obligation lead to fewer retailers.
“We’ve spent a lot of time working … stabilizing the ERCOT market. Part of that stability is protecting the crown jewel of our retail market,” she said. “I want to ensure all this hard work we’ve put [in] is not destroyed at the back end because we’re looking for reliability in all the wrong places.”
Doug Lewin, president of Stoic Energy and a proponent of demand response and energy efficiency measures, echoed Glotfelty’s comments that the proposed changes “are massive departures from Texas’ competitive market.”
“As noted by all of the commissioners, they could have negative impacts on competition and increase the already significant market power of the largest ‘gentailers’,” Lewin said.
“Gentailer” has become a common expression within the ERCOT market for large power providers such as Vistra and NRG Energy that have both generation and retail affiliates. Their retailers, TXU Energy and Reliant Energy, respectively, already control 70% of the market.
PUC Chair Peter Lake explains his memo on the ERCOT market’s redesign. | Texas PUC
“There will be lots of unintended consequences if the PUC doesn’t thoroughly vet and understand these proposals before adopting any of them,” Lewin said. “No one knows yet what any of the proposed market overhauls would cost.”
As he pointed out, several of the proposals add extra costs to renewable energy in favor of dispatchable thermal energy. Lake has suggested imposing a firming requirement of up to 60% of a generator’s nameplate capacity.
“Many of these proposals likely won’t increase reliability but would certainly raise energy costs for Texans and Texas businesses.”
Those costs are expected to be passed on to consumers. Prices on the state’s Power to Choose website, where customers can search for electric providers, are up 50% from a year ago to an average of 12 cents/kWh.
Cobos warned that the LSE obligation could turn into a “potentially litigated process.”
“All I’m asking is that for the next couple of months we take a look at the LSE obligation,” Lake said. “I don’t know how we can say we are doing our job without taking a serious, serious look at this.”
Lake initiated the discussion with a pre-meeting memo calling for the commission’s focus on “refining the concepts that will bring reliability to our grid.” He noted his list of recommendations was a starting point “and by no means an exhaustive list.”
“This is my version of what an LSE obligation could look at,” Lake said. “It’s a draft of a draft of a draft. The only thing I’m certain of is I got a lot of this wrong.”
Commissioner Will McAdams said he had significant questions about the LSE obligation proposal’s effect on the market and that those questions “must be answered before any type of endorsement from the PUC.”
The commission agreed it will need further analysis from The Brattle Group and other outside consultants in the few weeks that remain before Dec. 19.
“We have to have breathing room to study firming requirements now for down the road,” McAdams said, pointing to the wave of intermittent resources poised to hit the ERCOT market in the next few years.
The commission also discussed whether it could increase ERCOT’s budget for the ERS’ winter period and whether it could direct the grid operator to deploy the service before an energy emergency alert. The ISO is scheduled to send out a request for winter ERS bids on Nov. 8.
ERCOT staff said they would need a rule change to eliminate the ERS $50 million budget cap. The ISO procures the service over four contract periods during the ERS year, which runs from December to November.
PUC staff said they would review the rules and work with ERCOT legal and bring back a response this week.
Weatherization Rules in Effect
The PUC approved a two-step plan to ensure generation plants and transmission facilities are properly protected against a repeat of February’s severe winter storm that nearly toppled the ERCOT grid (51840).
Under the new rules, generators must implement winter weather readiness recommendations from a post-event analysis of a 2011 winter weather event and fix any “known, acute issues” from last winter. The generation owners are required to file a notarized attestation from their highest-ranking executive that the resource has met its required actions by Dec. 1. (See “Weatherization Rule Published,” PUC Workshop Takes First Stab at Market Changes.)
“This is a good first step to ensure the physical resilience of the grid is vastly improved over last winter,” Lake said.
Generators will be allowed to submit a “good cause exemption” if they fail to comply. However, the PUC and ERCOT will have to sign off on the exemptions.
The rules also direct ERCOT to inspect generators before the end of the year. Staff plans to inspect nearly 300 units, focusing on those responsible for the 80% of lost megawatts from the February storm. (See ERCOT’s Jones Looks Ahead, not Behind.)
Transmission service providers must comply with similar requirements, using a FERC/NERCreport on the 2011 event as a baseline.
Stronger year-round weatherization standards are scheduled to be implemented next year once a comprehensive weather study is completed by the state’s climatologist and ERCOT staff. That study is expected in February.
Securitization Orders Finalized
The commission made several minor changes during a brief open meeting on Oct. 13 before approving a pair of orders granting ERCOT’s requests for debt-obligation orders that would allow the grid operator to securitize $2.9 billion in market debt as a result of high charges incurred during February’s storm. (See Texas PUC Finances Market Debt over Lt. Gov.’s Objections.)
ERCOT said last week it will begin issuing bonds and collecting default charges from market participants in November to finance $800 million owed to the market by cooperatives and municipalities (52321).
The grid operator won’t begin issuing bonds for the $2.1 billion uplift balance to the market until the first quarter of 2022, staff told the Board of Directors on Friday. ERCOT has proposed that the bonds be issued through a special purpose entity (52322).
Canadian hydropower is one of the lowest-emission energy generating options on the planet. This statement is not based on interpretation or extrapolation. It is based on science rigorously developed over decades by independent researchers, including myself. Science that is regularly updated as through my own study published this year.
RTO Insider recently published an inflammatory article in which the claim is made that “scientists say Canadian hydropower is not clean” and that Canadian hydropower’s carbon emissions levels compare unfavorably to those of natural gas and even coal-based generation. (See Scientists, First Nations Say Hydropower is Not Clean Energy.)
This is completely inconsistent with the preponderance of scientific evidence.
The study of greenhouse gas emissions from Québec hydroelectric reservoirs began in the early ‘90s, and these studies show that emissions peak immediately after reservoir creation and decline to natural lake levels within about ten years.
Greenhouse gas emissions from any energy source is expressed in gCO2-eq/kWh, which represents the amount of GHG emitted per unit of energy produced. For hydropower, the intensity varies according to multiple factors, such as temperature, the density of vegetation flooded, powerhouse energy output, etc. Biological and climatic conditions that prevail in a cold boreal climate such as Québec result in a mean value of 34 gCO2-eq/kWh for Hydro-Québec’s generating fleet (Levasseur et al., 2021). This is low compared to coal power plants, with mean values higher than 875 gCO2-eq/kWh.
Additionally, reporter E. Hayes points to scientific studies to support her claims but she does so erroneously. For example, she is using a specific high value of emissions taken from Scherer and Pfister (2016) that is the result of modelling data from the Hertwich (2013) model without any model validation and calibration with field data. Comparing Churchill Falls, situated in cold Canadian boreal zone, to natural gas is incorrect. Bastien et al. 2009 has clearly showed that GHG emissions from that reservoir were very low and similar to surrounding lakes. Similar field values are also observed on Caniapiscau and Laforge reservoirs (Québec) sharing similar biological, climatic and geological characteristics (Tremblay et al., 2005). The reporter should get her facts right.
We are faced with a global climate crisis. Our society must reduce its carbon footprint and move toward lower-emitting sources. Hydropower generated in Québec is one of those sources. Misinformation will not help us make the right decisions on climate change, but taking bold actions like collaborating across the border to bring clean sustainably developed energy will.
Annie Levasseur is Professor, École de technologie supérieure, Montréal, Canada and Chairholder of the Canada Research Chair on Measuring the Impact of Human Activities on Climate Change.
Levasseur and her co-authors said their study earlier this year “did not receive any specific grant from funding agencies in the public, commercial or not-for-profit sector.
“The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported” in the paper, they added.
References
Hertwich, E.G., 2013. Addressing Biogenic Greenhouse Gas Emissions from Hydropower in LCA. Environmental Science and Technology, 47, 9604-9611. Dx.doi.org/10.1021/es401820p.
Bastien, J., A. Tremblay & L. LeDrew, 2009. Greenhouse Gases Fluxes from Smallwood Reservoir and natural water bodies in Labrador, Newfoundland, Canada. Verh. Internat. Verein. Limnol. Vol 30, Part 6, p. 858-861.
Levasseur, A., S. Mercier-Blais, Y.T. Prairie, A. Tremblay & C. Trpin, 2021. Improving the accuracy of electricity carbon footprint: estimation of hydroelectric reservoir greenhouse gas emissions. Renewable & Sustainable Energy Reviews, 136. https://doi.org/10.1016/j.rser.2020.110433.
Tremblay, A., L. Varfalvy, C. Roehm & M. Garneau, (Eds.), 2005. Greenhouse Gas Emissions: Fluxes and Processes, Hydroelectric Reservoirs and Natural Environments. Environmental Science Series, Springer, Berlin, Heidelberg, New York, 732 pages
FERC approved an uncontested settlement between Southern California Edison (NYSE:EIX) and a coalition of clean-energy developers and trade associations that reduces potential costs and smooths the way for interconnecting battery storage resources on the utility’s distribution system (ER19-2505).
The parties reached the agreement over SCE’s Wholesale Distribution Access Tariff (WDAT) in July after two years of negotiations, which resulted in a 60% reduction in the utility’s proposed wires charges for standalone energy storage, the Solar Energy Industries Association said in a statement.
“By securing this reduced charge, we’ve helped preserve the regulatory intent of FERC orders 841 and 2222, which pave the way for distribution resources to have fair access to wholesale markets,” SEIA Director of Regulatory Affairs Gizelle Wray said in a statement. “SEIA will continue its work to ensure that utilities don’t attempt to add more unnecessary and onerous fees for market participants to use their wires.”
FERC Administrative Law Judge Stephanie Nagel wrote in her certification of the settlement that it “represents the first tariffed rates, terms and conditions for inbound charging distribution service applicable to energy storage resources interconnected at the distribution-system level and participating in the wholesale market. However, trial staff asserts that this does not constitute an issue of first impression because the establishment of rates, terms and conditions for such service has been approved by the commission in the past.”
The case began in March 2018, when SCE, California’s second largest utility, filed proposed revisions to its WDAT intended to accommodate storage interconnection on its distribution system. The filing included only an “as-available charging distribution service to account for the needs of energy storage resources” and a “provision that SCE would, when necessary to maintain distribution system reliability, curtail charging demand for energy storage resources ahead of retail and wholesale distribution load,” Nagel wrote.
As-available battery charging is allowed when a utility has enough capacity to serve its retail and wholesale customers at the same time.
FERC rejected SCE’s proposed approach, saying the utility had failed to show it was just and reasonable and not unduly discriminatory. It urged SCE to come up with a plan to give storage resources the same curtailment priority as the utility’s other wholesale loads.
In response, “SCE elected to provide free as-available charging distribution service to customers on a case-by-case, off-tariff basis,” Nagel wrote. “However, as a result of the rapidly growing demand for storage and the consequent increased demand for interconnection requests received by SCE for inbound charging distribution service, SCE again filed proposed amendments to its WDAT in July 2019.”
SCE proposed to offer both an as-available charging distribution service and a firm-charging distribution service, which is available absent a grid emergency, under different rate plans.
FERC accepted the plan in January 2020 but suspended the proposed WDAT amendments and rates, subject to refund, and established settlement procedures.
In addition to SCE and SEIA, parties to the proceeding included the California Public Utilities Commission, the Energy Storage Alliance, Calpine, NextEra Energy Resources, Tesla and 10 others. They reached a settlement with SCE under which “more customers are eligible for exemption from the charges applicable to the as-available charging distribution service, and therefore the settlement provides value to more customers,” Nagel wrote. “The settlement rates are meaningfully reduced from SCE’s as-filed rates for both the as-available and firm-charging distribution services.”
The settlement also provides for customers taking firm-charging distribution service to be subject to either a monthly demand charge or the actual cost of facilities, whichever is higher. The parties agreed to the “higher-of” method, the judge said.
Higher-of pricing methods have been approved by the commission in past proceedings, Nagel wrote.
“Therefore, trial staff finds the settled as-available and firm-charging distribution service rates and the higher-of pricing terms fair, reasonable and in the public interest,” she said.
Coordinating grid operations with distributed energy resource aggregations as directed in FERC Order 2222 demands a bottom-up approach in order to avoid wholesale market inefficiencies, a panel of experts said on Thursday.
The U.S. Department of Energy last week hosted a meeting of its Electric Advisory Committee, with back-to-back sessions focused on transmission and distribution coordination and operational coordination.
Paul De Martini, Newport Consulting | DOE
“Ultimately, if the idea is to do value stacking — as the industry has been discussing for many years, trying to use distributed resources to provide a range of services — then you really need to contemplate what the implication is for each service at each tier, in between each tier and what that’s going to look like,” said Paul De Martini, managing partner of Newport Consulting.
“For each service there’s a different set of actors, a different set of devices operating in a different set of operating mechanisms, whether autonomous or direct physical control, and perhaps a price-based formation that’s potentially influencing that same device, so how do we think about those combinations? How do we think about those architectural issues?”
Integrating DERs into decarbonization modeling involves integrating “market layers,” from local to retail to wholesale, said Lynne Kiesling, research professor at the University of Colorado Denver.
One thing that connects the layers is co-optimization models, she said.
Robert Cummings, Red Yucca Power Consulting | DOE
“We do a lot of top-down optimal power flow modeling, and perhaps if we think more in terms of co-optimization, that might be a framework for incorporating the perspectives and opportunity cost to the customer and their devices,” Kiesling said.
“The challenge is again that if you don’t reconcile the bottom-up issues, you can’t quite get to the optimization,” De Martini said. “You get stuck at the conceptual level. So yes it’s possible, but you really need to think through that lower level to see where the overlaps are.”
It’s “heartening” to see people promoting a bottom-up approach, said Robert Cummings, president of Red Yucca Power Consulting. “One of our ruling principles was you had to use security-constrained dispatch at all times for aggregated functions, and I think that’s something that’s so easy to ignore when you start talking from top-down in a market, so it’s important that that gets put forward.”
Donnie Bielak, PJM | DOE
PJM may need a lot of flexibility on Order 2222, considering that its jurisdiction is 13 states and D.C., said Donnie Bielak, manager of reliability engineering for the RTO.
“Each of the individual distribution companies is probably going to want to have a different level of involvement with the DER integrations, and they’re also going to have different tariffs on file, and have different agreements with their state commissions,” Bielak said.
There are going to be times when the distribution system simply cannot handle injections from DERs, and that is going to be identified by the utility, Bielak said.
“The utility really is driving this section of the coordination; they are the ones doing the reliability analysis; they’re doing the planning of the distribution systems; so, between them and the market agent communicating with the individual DERs, they need to collectively come up with market offer parameters and outage reporting and submit that to PJM,” Bielak said.
Our July whitepaper, Stretched to the Breaking Point: RTOs and the Clean Energy Transition, emphasized the point that if an RTO was going to clear a centralized auction to form a single marginal price payable to all megawatt hours generated, then that RTO had better “get the price right.” Everything else (and we mean that literally) flows from getting price right: reliable operations, demand response and efficient consumption decisions, generator investment and retirement, accurate transmission planning, and an efficient financial transmission rights regime to manage congestion. Textbook economics instructs that the “right” price is a function of the cost of production and supply and demand.
In the real world, prices are rarely perfectly “right.” Distortions of various types are introduced. Not to mention the perfectly competitive conditions required to form the “right price” do not always exist. In the realm of RTOs, the term conceding this reality — a description one used to encounter more frequently in FERC orders and RTO commentary — was to aspire to “workably competitive” markets.
The question of price in RTOs surfaced again recently in the commission’s split decision on PJM’s “focused” minimum offer price rule (MOPR) filing. Last week, FERC Chairman Richard Glick and Commissioner Allison Clements published a joint statement comprehensively explaining why they support the PJM MOPR proposal (the “Joint Statement”). Regardless of whether one agrees with the ultimate conclusion in the Joint Statement, the broader question about RTO market design and its durability to handle industry transformation would benefit from reaching a shared understanding on key points. (See related story, ‘Good Riddance’ to Old PJM MOPR, Glick Says.’)
Tony Clark
The first such point is dismissing those that complain about state subsidies that support particular generation as wedded impractically to what the Joint Statement terms an “abstract concept of market integrity.” What the Joint Statement calls “market integrity” is what we call “getting the price right.” It’s hardly an abstraction. As we’ve pointed out, it’s the heart of the engine that drives RTO markets and it deserves thoughtful consideration.
The second and related point involves state actions that affect this engine and the nature of these actions. More specifically, it is the need to distinguish actions which are problematic “distortions” from actions that, while they affect price, create no problem for RTO markets. By noting that all manner of public and private action affect price, including actions that increase (as opposed to suppress) price, the Joint Statement essentially throws up its hands and concludes there is no “principled distinction” to be drawn and any effort to do so would result in “arbitrary and burdensome line-drawing.”
There is a point here. Toward the goal of “workably competitive” markets, throughout its history at PJM, MOPR tried to separate actionable subsidies from those that could be ignored, or had to be accepted, while conceding all subsidies created price suppression. We fear the Joint Statement gives up too quickly and justifies surrender based on a false equivalence of subsidy compared to a cost imposed by tax or regulation.
Again, price starts with cost. As noted by the Joint Statement, “Siting policies, tax rules, and labor regulations, for example” or a carbon tax all work to increase the cost of production that will be captured in the generator’s offer and ultimately inform the marketplace of the full and true cost of generating a megawatt hour. However, imposing a cost through regulation on a negative externality, be it lost workdays in the labor context or carbon in the climate context, is very different from subsidization. Different not just in approach, but in outcome.
For example, the superior efficiency and environmental outcomes that result from putting a cost on carbon as opposed to subsidizing carbon-free activity are well accepted. Undoubtedly, however, the commission’s job is not to disfavor subsidies compared to alternatives that economists find preferable. But the commission is an economic regulator and it should be worried about the different economic consequences that a subsidy will cause to market structures it has sanctioned as compared with regulations or taxes that price the externality.
And here is where we believe the Joint Statement falls short. The commissioners are not wrong to accept that states will prefer certain resources and will take actions to support those resources, regardless of what type of MOPR is in place. But once subsidy is accepted as a given, then the commission must ask whether the RTO market structure, predicated on a single-clearing marginal price, remains able to function as intended — and if not, what changes must occur. This gets to the very heart of the commission’s statutory duty to ensure wholesale rates remain just and reasonable.
The fact that RTO markets wholly depend on “getting price right” means offers must reflect accurate costs of production. The Joint Statement appears to contort subsidies as a kind of reduction in the cost of production to then conclude that a market riddled with subsidy “will provide accurate price signals … by allowing capacity market sellers to include state support in their offers.” In reality, what is meant by “include” here is that subsidized sellers will be able to exclude actual costs of production from their offers.
Nobel prize winning economist William Nordhaus extensively details the economic distortions that separate a subsidy from a regulatory tax or cost in his book, A Question of Balance: Weighing the Options on Global Warming Policies. The distortions from subsidy that he identifies in general markets relative to policies that impose cost by way of tax or regulation also show up, perhaps more acutely, in the designed, single-clearing price RTO markets. Though the Joint Statement’s conflation of hand outs and imposed regulatory costs weakens its argument, what we find more troubling is the risk that needed changes to RTO market design — changes we argue will be profound and foundational — may be ignored at the very moment when they most require attention.
Former FERC Commissioner Tony Clark is a senior adviser at Wilkinson Barker Knauer. Vincent Duane is principal of Copper Monarch and the former SVP for law, compliance and external relations for PJM.
Stakeholders last week discussed NYISO’s comprehensive mitigation review proposal and presentations on related consumer and market impacts from implementing changes to the ISO’s buyer-side mitigation (BSM) rules.
The ISO is developing a proposal to help ensure that the capacity market still results in just in reasonable outcomes after an influx of thousands of megawatts of state-supported resources and will at the same time succeed with FERC and avoid any unnecessary litigation, Michael DeSocio, NYISO director of market design, told the Installed Capacity (ICAP) Market Issues Working Group.
“We’re very focused on making sure that the package of changes supports the goal here,” DeSocio said.
New York’s Climate Leadership and Community Protection Act (CLCPA) requires the state to procure large amounts of renewable energy to get to zero-emission electricity by 2040, and similar efforts around the country are challenging regulators, as well as grid and wholesale electricity market planners.
NYISO also presented on the methodology used to measure market impacts, and the Market Monitor, Potomac Economics, presented on capacity accreditation and related consumer impacts evaluation.
The NYISO MMU says that marginal accreditation allows the more efficient resource to be selected. | Potomac Economics
“The intent here is to assess the marginal accreditation of all resources … and we have about a six-week window to do that from when the [Installed Reserve Margin] studies are finalized and when we need to have these accreditation values determined,” DeSocio said.
“We are proposing to value the capacity accreditation of all resources based upon their marginal reliability contribution,” said Zachary Smith, manager of capacity market design.
NYISO wants to complete these reforms in time for the Class Year 2021 BSM evaluations and intends to address capacity accreditation in different phases, with the Phase 1 tariff changes to be discussed through year-end 2021, and Phase 2 discussion of procedures and details expected to start around January and run throughout 2022. (See NYISO Reviews Mitigation Efforts, Updates Timeline.)
Market Outcomes Analysis
NYISO in August introduced Analysis Group’s study that is modeling 10-year capacity supply and demand curves and identifying the resulting market outcomes to support BSM rule revisions, and the consultants presented the draft study results on Friday.
The purpose of the analysis is to determine whether the NYISO capacity market will support the continued achievement of resource adequacy in the state of New York through competitive capacity market auctions administered in concert with the rollout of CLCPA resources, said Paul Hibbard, Analysis Group principal.
Specifically, the study seeks to answer two questions:
a) With the proposed BSM reforms in place, will the NYISO capacity market continue to produce competitive market outcomes?
b) With the proposed BSM Reforms in place, will the NYISO capacity market continue to provide financial incentives for the retention and addition of resources needed to maintain power system reliability?
Importantly, while the results for 10 years out – 2032 – are necessarily more uncertain, the results of modeling various scenarios in 2032 are consistent with the observations based on the 2026 model year, the study said.
Analysts realized that the “load scenario in the 2021 Gold Book was closer to the progression of peak load over time in the Grid in Transition study, which is the basis of our load generation assumption, so we adapted peak load to be consistent with that,” Hibbard said.
Changes underlying the results for 2026 include significant changes to the assumed resources on the system compared to 2022. Specifically, in the four years since 2022:
Fossil fuel ICAP has decreased by 2,834 MW;
Onshore wind has increased by 244 MW;
Offshore wind has increased by 1,200 MW;
Grid-connected solar photovoltaic capacity has increased by 5,000 MW;
Battery storage resources (two-hour and four-hour) has increased by 1,571 MW.
Despite the significant addition of zero-offer CLCPA resources by 2026, the market retains 31,485 ICAP MW (29,309 UCAP MW) of thermal, hydro and nuclear capacity, and 5,772 ICAP MW (5,650 UCAP MW) of other resources (e.g., biogen, pumped storage, imports, Special Case Resources). In total, the market supply curve includes 42,939 ICAP MW (37,985 UCAP MW) in 2022, and 48,021 MW ICAP (37,034 MW UCAP) in 2026.
The tables contain the results of the analysis for the New York Control Area (NYCA) as a whole, and for each of the NYISO capacity market localities, providing expected prices in dollars per kilowatt-month ($/kW-mo) and clearing quantities in unforced capacity megawatts (UCAP MW) by year, season, and locality. | Analysis Group
Several stakeholder expressed concern that all fossil fuel resources would be treated comparably for capacity accreditation going forward.
“The intent is to evaluate all fossil fuel resources when we move forward with the accreditation approach,” DeSocio said. “We expect to run some sensitivities with more rigor in the next phase of the process.”
NYISO is proposing to adopt the MMU…s recommendation to translate the ICAP Reference Price to a UCAP Reference Price using the derating factor of the peaking unit underlying each ICAP Demand Curve. | NYISO
The ISO’s intent is to try to perform that analysis and lay out some of those comparisons in the next phase, but at the moment “we don’t have the tools with the ability to run that type of analysis, so we need to work with GE to help develop those tools,” DeSocio said.
NYISO will address any stakeholder feedback at the October 29 ICAP meeting, including updates to tariff language if necessary, and at the November 2 meeting Potomac Economics and NYISO will present the consumer impact analysis of the capacity accreditation proposal.
The ISO plans to bring tariff updates before the Business Issues Committee and Management Committee in November.
The ISO-NE Planning Advisory Committee on Wednesday received a project list update for the Regional System Plan (RSP) from Rudi Vega, the RTO’s principal engineer for transmission planning, that included 12 new projects to resolve thermal overloads and voltage violations in New Hampshire and Maine.
Eight of the projects are for Maine and involve rebuilding 21.7 miles of an existing 115-kV line with additional work on MVAR synchronous condensers, capacitors and reactors. The total cost across all projects is $158.6 million.
The other four projects, in New Hampshire, will cost a total of $134.9 million. They also involve the installation of MVAR synchronous condensers and capacitors, in addition to 115-kV and 345-kV breakers.
ISO-NE also informed the PAC that it had changed the cost estimates for two projects since the previous list in June: an increase of $7.1 million for the Southeast Massachusetts/Rhode Island Reliability Project (SEMA/RI), based on a transmission cost allocation application submitted in August; and a reduction of $8 million for the Greater Boston Project.
Three projects have been canceled since the June update, as they are no longer needed because of the New Hampshire and Maine solutions:
a new, $62.7 million 115-kV line section and upgraded section between Coopers Mills and Highland substations at the Maine Mid-Coast Spur;
adding a second 115/345-kV autotransformer at the existing 115-kV Kimball Road substation in Maine, along with moving one of the 115-kV/30-MVAR capacitor banks, which would have cost $3.3 million; and
installing a transfer trip at Kimball Road to disconnect the town of Lovell, Maine, from 115 kV for an estimated $0.5 million.
Eversource Details Phase II of Wood Structure Replacement Program
Eversource Energy (NYSE:ES) will replace 241 laminated wood structures across five 115-kV transmission lines in New Hampshire and one 345-kV line in Connecticut with weathering steel monopoles, installation of lightning arrestors and counterpoise grounding, according to a presentation from the utility.
According to Eversource’s Dave Burnham, the new monopoles would allow the utility to comply with current clearance and strength code requirements, improve reliability and storm resilience, and support larger conductor sizes if needed in the future.
Burnham also said recent cross-sectional inspections of removed wood structures uncovered significant damage not detected in previous, visual inspections, such as:
rot present throughout the length;
open joints at the top, allowing free entry of water;
damp wood at the center, soft with rot;
voids between layers of varying size and location, but present on each cross-sectional cut; and
additional splitting behind surface cracks.
Replacements performed since March have continued to uncover structural damage. (See “Eversource Replacing Wood Structures in NH,” ISO-NE Planning Advisory Committee Meeting Briefs: March 17, 2021.) Eversource says it will coordinate replacement schedules with ongoing projects to maximize mobilization, permitting and outreach efforts, and shared right-of-way access.
The current work addresses priority lines at the cost of $55.6 million, with in-service dates ranging from the first quarter of 2022 to the first quarter of 2023, Eversource said. Additional structures removed during these projects will continue to be assessed for internal damage. The utility will assess the remaining lines with laminated wood structures in the coming months, and additional replacement projects will be presented to the PAC in 2022 for Phase III.
