FERC on Wednesday accepted an uncontested settlement agreement between SPP and Northwest Iowa Power Cooperative (NIPCO) over the latter’s annual transmission revenue requirement, formula rate template and formula rate implementation protocols as a transmission-owning member of the RTO (ER15-2115).
The commission last year rejected a settlement filed by SPP, saying that, because it was contested, it couldn’t be approved under its guidelines and precedent set by a 1999 case. FERC in February then denied NIPCO’s rehearing request. (See “Co-ops Rebuffed in Settlement Rehearing Requests,” FERC Denies Rehearing in Z2 Remand Order.)
Northwest Iowa Power Cooperative has agreed to an annual transmission revenue requirement with SPP. | NIPCO
NIPCO had argued that when TOs join regional grids, even indirect modifications to grandfathered agreements can trigger a threshold analysis under the Mobile-Sierra doctrine, which holds that negotiated, fixed-rate contracts are to be presumed just and reasonable under the Federal Power Act and cannot be revised by FERC without a finding that the public interest requires modification.
The commission said the Mobile-Sierra “public interest” presumption applies to an agreement only if the agreement has certain characteristics that justify the presumption.
In its latest order, FERC clarified the framework that would apply if it was required to determine the standard of review in a later challenge to the settlement by a third party or by the commission acting on its own authority.
SPP was given 30 days to file a compliance filing.
Despite a severe spike in unemployment and some project delays amid the COVID-19 pandemic, industry stakeholders remain upbeat about the long-term prospects of renewable energy, as indicated by a panel during the National Association of Regulatory Utility Commissioners’ Summer Policy Summit on Tuesday.
Gregory Wetstone, CEO of the American Council on Renewable Energy, opened the panel with some sobering unemployment figures: 514,200 people in the clean energy sector are out of work as of this month. But most of this is on the residential solar side.
ACORE CEO Gregory Wetstone | NARUC
“The bigger issues from the standpoint of utility-scale have been availability of tax equity and finance,” Wetstone said, though these have been mitigated somewhat by the U.S. Treasury Department’s deadline extensions in May for projects to qualify for federal tax credits.
There’s also been “a big uptick in a focus on sustainability investing,” which has been helpful, Wetstone said. He noted BloombergNEF data suggesting that though 2020 will not see as much renewable development as expected before the pandemic hit, it will still be mostly on par with that of 2019 and more than rebound next year. (See Renewable Investors See Light at End of COVID Tunnel.)
Wetstone cited “key drivers” for continued investor confidence, including decreasing costs; increased demand from residents, companies and utilities; increasing state and local renewable and emission goals; and climate change as an ever more resonant political priority for residents.
ACORE said that confidence in mid-term sector growth remains strong consistent with its 2018 and 2019 surveys. | ACORE
Xcel Energy CEO Ben Fowke, who serves as chairman of Edison Electric Institute, also expressed confidence. “I happen to be of the mindset that we can do more with clean energy to jumpstart the economy and overcome some of the economic impacts of COVID-19,” he said.
“We have seen some delays with some of our wind farms [because of] the supply chain disruption. Fortunately, we still qualify for the 100% production tax credits for our customers because of the safe harbor extension. … So things are going OK at Xcel, and we’re looking forward to being able to be part of the solution to get the economy rolling again.”
Xcel CEO and EEI Chair Ben Fowke | NARUC
Fowke’s company, which has set a goal to be 100% carbon-free by 2050, expects 80% of its power to come from renewables. He is not so concerned about reaching that renewable milestone as in securing the last 20% of zero-carbon resources — the unknown on which he urged investors to focus.
“I think it’s really important we get started today in nurturing those resources so we can all meet those zero-carbon goals by midcentury,” Fowke said. “I don’t know what those resources will be.” He listed advanced nuclear, carbon capture, geothermal and hydrogen as candidates. “The important thing is we need to get started today. And we need to recognize the fact that we can’t do it with 100% renewables. It defies the laws of the grid.”
Federal Aid Unlikely
The discussion occurred amid a surge in coronavirus cases in the U.S., an increase in deaths from the virus and an uptick in unemployment claims, just as federal unemployment benefits and eviction moratorium are about to expire. Congress and the White House are in the middle of negotiations on what to do next to address the crisis.
Both Fowke and Wetstone expressed a desire for aid to the renewable sector in the form of tax credit extensions or refunds, or a measure to make it easier to site interregional transmission.
But in comments before the panel, Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, said energy-specific measures are likely going to be left out of any forthcoming stimulus legislation. She listed some measures she said there has been discussion on: extension of the tax credits; a short-term waiver of Nuclear Regulatory Commission fees for “challenged” nuclear plants; and a program to provide personal protective equipment for nonprofit utilities.
Sen. Lisa Murkowski (R-Alaska) joined the webinar from a phone booth in the Senate Press Gallery. | NARUC
“I am hoping we can find common ground in some of these areas,” she said. “Now I can’t tell you which of these items will make it into a final package; only that, in my view, they make good sense and I think that they would enhance it.”
Murkowski also used her time to plug her American Energy Innovation Act, which faltered on the floor of the Senate in March. “If anybody has an opportunity to raise these issues with the folks on the [Environment and Public Works] Committee to separate [hydrofluorocarbons] from our energy bill, I’d appreciate it,” she said. (See FERC Targeted in Energy Bill Amendments.)
Government efforts to ensure the security of the bulk power system run the risk of hampering utilities’ ability to operate effectively, industry representatives warned at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit on Tuesday.
“I think it would be one thing if we get a blacklist. ‘Here are two or three vendors not to use’ — we’ll deal with that,” Mike Kormos, senior vice president of transmission and compliance at Exelon, said during the “Managing Supply Chain Risks in Critical Energy Infrastructure” panel. “If we’re being told [we’re] only allowed to use one or two, because they’ve been certified and the rest have not … [that] may not be able to fully support this industry with what we have going on.”
Mike Kormos, Exelon | NARUC
NARUC organized the panel in response to President Trump’s declaration of a national emergency in May aimed at restricting the purchase of BPS equipment from suppliers suspected of connections with foreign adversaries, defined as any foreign government or nongovernmental person connected with threats against the U.S. or its allies. (See Trump Declares BPS Supply Chain Emergency.)
Both NERC and the Department of Energy followed up on Trump’s executive order earlier this month. NERC issued a Level 2 alert requesting information on transformer control and protection systems, while DOE filed a request for information focusing on utilities’ practices for identifying and mitigating supply chain vulnerabilities. (See NERC Issues Level 2 Supply Chain Alert.) Both DOE and NERC have identified China and Russia as the most pressing adversaries, with Iran, Cuba, North Korea and Venezuela also mentioned as significant threats.
Industry Fears Compliance Costs
While Kormos said that Exelon and its industry peers understand the need for the executive order and the urgency of the information requests, he reminded the panel of the compliance burden facing companies asked to review all of their equipment by the Aug. 21 deadline for NERC’s alert. The restriction of the alert to equipment purchased in the last 10 years helps reduce the amount of work needed, but entities might be unable to provide some of the information being demanded, he said.
“It’s one thing for us to recognize and figure out who we bought from. … We probably have those records going back 10 years,” Kormos said. “But when you start talking about potential subcomponents of these systems … [we] might have bought a transformer from one vendor, [and] who that vendor was using for subcomponents in that is something we don’t have, quite frankly.”
Kormos also voiced industry concerns over the longer-term implications of the order, particularly the possibility that utilities could be asked to “rip and replace” equipment deemed vulnerable to foreign interference. Such a requirement could leave entities with dangerously reduced inventory, unable to muster enough spare parts to repair damage from major storms or other events.
Engaging Vendors, not Punishing Them
Representatives of both DOE and NERC emphasized that they were aware of industry’s concerns and would aim to keep their communications transparent. Manny Cancel, senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center, told the panel that the intent of the executive order and the follow-on actions by NERC and DOE were not meant “to drag vendors through the mud,” but to engage with them and their expertise to protect the power grid.
NERC Senior Vice President and E-ISAC CEO Manny Cancel | NARUC
“We see this order as complementing NERC’s work. … We kind of knew it was coming … and what our response would be once the order was published,” Cancel said. “The purpose of this alert is … really to establish extent of condition — how much of this effort is out there, where is it — and that will help inform subsequent actions and efforts around this.”
New Jersey has released a plan detailing how it will procure 7,500 MW in offshore wind resources in the next 15 years as part of its goal to reach 100% clean energy by 2050.
The 82-page draft of the New Jersey Offshore Wind Strategic Plan and its 428 pages of appendices, released last week, calls for the development of the resources while protecting the environment, as well as commercial and recreational fishing areas. The plan anticipates that by 2050, offshore wind will provide 23% of electricity to customers statewide.
A public meeting to discuss the plan originally scheduled for July 20 was rescheduled for Aug. 3.
Rendering of proposed New Jersey Wind Port located at Lower Alloways Creek | New Jersey Board of Public Utilities
The recommendations contained in the plan are supported by analyses of environmental and natural resources, ports to support the needed infrastructure, supply chains and the levelized cost of energy.
“The development of New Jersey’s offshore wind infrastructure will create thousands of high-quality jobs, bring millions of investment dollars to our state, and make our state a global leader in offshore wind development and deployment,” Gov. Phil Murphy said in the preamble of the report.
Murphy first introduced the 7,500-MW goal last November when he signed Executive Order 92 at the Liberty Science Center in Jersey City, where he was joined by former Vice President Al Gore. (See New Jersey Doubles OSW Target.)
East Coast offshore wind areas and leases | New Jersey Board of Public Utilities
The plan includes using public and private financing to encourage investment in the New Jersey Wind Port, a proposed 200-plus acre manufacturing facility set to be built in Lower Alloys Creek in 2021, as the region’s first major offshore wind construction and marshaling port.
It also includes ideas for working with equipment manufacturers, developers and potential ports on the development of manufacturing facilities in New Jersey to meet the projected building demands by the 2024-2026 time frame. It also incorporates utilizing the state’s WIND Institute to support research, innovation, stakeholder engagement and training.
Officials also cited continuing collaborations with PJM on offshore wind interconnection and finding the most efficient transmission expansion to accommodate future projects. The plan calls for the evaluation and incorporation of energy storage and smart grid technology.
“We are fortunate to live in a state with abundant coastline and some of the best wind resources in the world, so it is natural for New Jersey to expand this reliable, renewable, cost-effective energy source,” said Robert Asaro-Angelo, commissioner of the Department of Labor and Workforce Development. “This industry has the potential for exponential growth, with tens of thousands of good-paying, family-sustaining jobs.”
While the draft does not detail the potential costs of the plan, it acknowledges that the upgrade of port facilities and the New Jersey Wind Port will require hundreds of millions of dollars in investment.
“Offshore wind represents a once-in-a-generation opportunity for New Jersey,” BPU President Joseph Fiordaliso said. “By investing in this renewable resource, we can provide jobs, clean energy and millions of dollars in economic activity for our state.”
The New England Power Pool Reliability Committee on Tuesday narrowly approved changes to ISO-NE’s gross load forecast reconstitution methodology, recommending Participant Committee approval next month in order for Tariff changes to be filed with FERC with a requested effective date of Oct. 5.
The committee voted 60.62% in favor of the motion, just over the required 60% threshold. If approved by the PC and the commission, the RTO anticipates starting to use the methodology in the fourth quarter for its 2021 Capacity, Energy, Loads and Transmission (CELT) forecast.
A primary objective of the gross load forecast is to ensure that passive demand resources (PDRs) are not double-counted in the Forward Capacity Auction. PDRs receive compensation as a supply-side resource and reduce demand; thus, their demand-reducing impact becomes embedded in historical load data.
As presented by ISO-NE Load Forecasting Manager Jon Black, the proposed methodology ensures that PDRs are appropriately embedded in the gross load forecast by creating a smooth historical reconstitution time series.
“The smoothing enables us to include recent auction outcomes that extend beyond the historical period,” Black said. By calibrating the amount of PDRs being reconstituted to the capacity supply obligations (CSOs) from the most recently completed FCA, there are a couple of associated improvements, he said.
Application of the proposed methodology to the state of Vermont (summer) is illustrated as it would have applied to CELT 2020. Using June 2016 as a starting point results in a reconstitution trend line with a negative slope (i.e., it suggests a decreasing amount of PDR over time), which does not reflect the longer-term CSO trend. | ISO-NE
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
“No. 1 is what we originally set out to improve upon, which is we shall not be reconstituting energy efficiency installations that are in excess of their CSO, so the accounting would no longer reflect the overperformance,” Black said.
Second, smoothing in conjunction with using the most recently completed primary auction outcomes enables the capture of more recent trends, especially expiring EE measures that are no longer participating as supply in the Forward Capacity Market, he said. The new methodology provides a framework to adjust the gross load forecast to reflect differences in FCA CSOs and those of annual reconfiguration auctions.
“I see these as very significant improvements that I believe are needed in the current forecasting environment in New England,” Black said.
At the June RC meeting, a stakeholder asked whether June 2016 rather than June 2006 would serve as a better starting point for the development of the reconstitution history.
Black said that using June 2016 as a starting point results in a reconstitution trend line with a negative slope, suggesting a decreasing amount of PDR over time, which does not reflect the longer-term CSO trend.
“Using all of history is better, right out of the gate,” Black said. “Picking sub-trends within the overall history of all the FCA outcomes is probably ill-advised.”
The revised reconstitution methodology needs to be implemented for all long-term gross forecast modeling, which is performed for the region and all states separately, and for both summer and winter months, Black said.
Changes to Operating Procedures
The RC discussed proposed changes to several operating procedures, starting with a redline review of changes to OP-17, which describes how ISO-NE monitors and performs analyses to determine allowed load power factor.
If approved by the RC next month and in September by the PC, the changes would be effective Sept. 3.
ISO-NE would use supervisory control and data acquisition system information to perform a survey that would allow it to examine points for every hour of the year instead of the current six selected annually for monitoring, said Dean LaForest, the RTO’s manager of real-time studies.
It would also determine noncompliance based upon adverse impacts to reliability or unit commitment, and would relieve market participants from having to submit annual load power factor survey data, except in cases of noncompliance to determine responsible parties.
The RC also accepted revisions to OP-12 Appendix B to support data change updates in a revision last month to OP-12 related to voltage and reactive control, effective July 20. The changes allow more frequent updates to OP-12B data by using a new format and notifying the RC of changes by email instead of their inclusion on the monthly agenda.
Lastly, the RC discussed changes to OP-21 regarding energy forecasting and actions during an energy emergency, with a proposed effective date of Oct. 18 if approved by the committee in September and the PC in October. The revisions leave existing processes substantively unchanged but would incorporate the annual Generator Winter Readiness Survey process in order to enhance ISO-NE’s situational awareness of generator pre-winter preparations.
The revisions also would incorporate the annual Natural Gas Critical Infrastructure Survey process in order to ensure critical infrastructure of the interstate natural gas system is not on electrical circuits subject to automatic or manual load-shedding schemes.
Committee Actions
The RC’s notice of actions included approval of several motions, noting that all sectors had a quorum.
The RC approved the 19.8 MW SR Litchfield Solar Project proposed plan application (PPA) in Harwinton, Conn. from Eversource Energy (ES-20-G167); the 7 MW BD Solar Winslow II Solar Project from Central Maine Power (CMP-20-G40); the Wareham Transformer #2 Addition Project in Wareham, Mass. from Eversource (ES-20-T33); the 10 MW SR Stonington Solar Project in North Stonington, Conn. from Eversource (ES-20-G168); the Gravel Pit Solar Generation and related Transmission Project from Gravel Pit Solar and Eversource (ES-20-G169; ES-20-T34; ES-20-T35); and the Vineyard Wind Revisions Project PPAs from Vineyard Wind (VW-19-G01-Rev. 1; VW-19-T01[through 5]-Rev. 1.
The RC also approved $6 million in Pool-Supported PTF cost recovery for transmission upgrades to address asset condition issues at the Berlin Substation of the Vermont Electric Power Company (VELCO).
FERC on Wednesday approved a market power mitigation plan for an investment fund’s $4.3 billion purchase of El Paso Electric and rejected rehearing requests challenging the commission’s approval of the deal (EC19-120).
The commission’s March 30 order approving the transaction directed the companies to file a mitigation plan to address market power concerns that could arise from a premature termination of power purchase agreements for Mesquite Power, part owner of the 595-MW Mesquite Generating Station in Arizona. Mesquite Power is owned by EPE’s purchaser, the Infrastructure Investments Fund (IIF). (See FERC Conditionally OKs Purchase of EPE.)
The applicants offered two options to reduce their controlled capacity if the “surplus output contracts” for Mesquite are terminated before their scheduled expiration on May 1, 2021.
Under the first option, EPE would sell a 14-MW block of firm energy during peak periods. The energy would be supplied by an EPE generation facility that would be economic during the seasons and load periods with market power screen failures and backed by system power if the designated unit is unavailable.
EPE’s Rio Grande Plant in Sunland Park, N.M. | El Paso Electric
Under the second option, EPE would sell a 14-MW block of firm energy from its share of the Palo Verde nuclear plant during peak periods to a nonaffiliated third party at the Four Corners trading hub. EPE would pay liquidated damages if it is unable to deliver.
“Either option would be sufficient to mitigate the competitive harms identified by applicants’ sensitivity analysis,” FERC said in approving the proposal. It required the applicants to notify it if the contracts are terminated and which mitigation proposal will be enacted within 60 days of Mesquite receiving notice of early termination.
The commission rejected a request to rehear the March order by Public Citizen, which contends JPMorgan Chase should be considered an affiliate of IIF in FERC’s analysis of the merger. J.P. Morgan Investment Management has acknowledged it is an investment adviser of IIF, but FERC ruled that its market power analysis showed the transaction would have no adverse effect on rates even if J.P. Morgan were considered an affiliate.
“The commission did not, as Public Citizen argues, ignore the information it provided in its various pleadings. Indeed, it was partly in response to Public Citizen’s various pleadings, and applicants’ responses to them, that commission staff took the extra step of requesting additional information and explanation from applicants,” FERC said.
The commission also rejected a rehearing request on similar grounds from U.S. Sens. Jeff Merkley (D-Ore.), Ed Markey (D-Mass.) and Bernie Sanders (I-Vt.), saying they lacked standing because they did not file motions to intervene in the proceeding and were not otherwise made parties to it.
A panel discussion Tuesday on natural gas’s role in a clean-energy grid during the National Association of Regulatory Utility Commissioners’ virtual Summer Policy Summit revealed a divide between single-state ISOs and multistate RTOs.
Mark Rothleder, CAISO’s vice president of market policy and performance, said his ISO is driven by California legislation to reach a 50% renewable energy target by 2026 and a 100% clean-energy system by 2045.
“We’ve had as high as 80% renewables, and almost 100% carbon-free energy, for a few hours,” he said. “Now we need to know how to do this over a longer period of time.”
“It’s interesting to listen to people running ISOs that have single state. Policy direction is clear to them. They’re much more strongly putting forward their point of view,” PJM CEO Manu Asthana said. “PJM is unique. PJM has a diverse footprint. We have some states very dedicated to decarbonizing and others that are dependent on fossil fuels. Others have done well with shale and have cheap natural gas.”
Officials from CAISO, MISO, NYISO and PJM discussed the importance of gas plants during a NARUC Summer Summit session July 21. | Panda Power Funds
Within PJM’s footprint, gas has grown to 37% of the fuel mix, Asthana said. Coal-fired resources have dropped from nearly 60% of the fuel mix 15 years ago to about 23%, resulting in a 34% drop in carbon emissions.
“Our fuel mix has been shifting to a significantly more decarbonized system. We see that just continuing,” he said.
MISO CEO John Bear said the fuel mix in the RTO’s 15-state footprint is also seeing a “significant” reduction in coal usage, nearly halved from 76% of the fuel mix in 2005 to 39% last year. It expects that to fall further to 27% by 2030, when gas will account for 28% of the mix.
That is emblematic of natural gas’s role as a transition fuel, providing reliability as intermittent renewable resources take the place of coal-fired generation. Nowhere is that more evident perhaps than in MISO, which Bear said has more than 50% of the U.S.’ gas storage resources.
“There are a lot of tools for us to use when things get challenging,” he said. “As we get to higher levels of renewable-energy penetration and have frequency- and voltage-stability needs, understanding the transmission system and how we can move those [gas-fired] attributes around is really critical to keeping reliability high and costs low.”
“We see a role in the near term for gas,” Rothleder said. “It provides local reliability in constrained areas. It provides a fuel source when we have evening peaks and the sun is going down, but we still have high load. It provides resiliency to meet those times when solar production is down. Lastly, the gas fleet has attributes that provide essential reliability service.”
Dewey said that to meet NYISO’s goal of 100% carbon-free electricity system by 2040, “that’s where you start to look at the value of the attributes of the gas resources.”
“Even when we’re hitting renewable targets, there’ll still be hours when we need that dispatchable resource,” he said. “Storage will be critically important. It will offset a lot of those instances … but it’s still a long way to meet reliability needs. As a bridge mechanism, natural gas will be critical to achieve those goals.”
And the future?
“The future is finding replacement resources that can match that dispatchability,” Dewey said.
The most abundant element in the universe could reduce greenhouse gas emissions and solve the problem of storing wind and solar energy if the cost of producing it comes down, advocates told NARUC’s Summer Policy Summit Tuesday.
Hydrogen is getting a lot of attention these days for its potential to store energy from intermittent resources and generate megawatts when the sun doesn’t shine or the wind doesn’t blow. But its cost remains prohibitively high.
The National Fuel Cell Research Center estimates that the expense of producing power from hydrogen fuel cells, now around $4,000/kW, needs to fall by more than 60% for it to become a competitive market player. (See Calif. Rushing Microgrids for Fire Season Shutoffs.)
Panelists said cost reduction is already underway.
Neva Espionza, generation director with the industry nonprofit Electric Power Research Institute, pointed to billions of dollars of investments in hydrogen technology in Western Europe, Saudi Arabia and Australia as developments that could spur less-expensive hydrogen production.
Kristine Wiley — director of the Hydrogen Technology Center at GTI, an Illinois-based research group founded by the natural gas industry — asked those listening to name the “top barrier to enabling the hydrogen economy.” More than half of those voting via cell phone app said “cost.” Wiley said GTI was using its well-funded research and development programs to bring costs down.
Advocates say solar-powered electrolyzers that produce hydrogen could help solve the West’s need for long-term storage of wind and solar energy. I McPhy Energy SA
Laura Nelson, executive director of the Green Hydrogen Coalition, assured listeners that costs are “falling fast” and will keep going down as production increases.
“From our perspective it’s not really a technology problem,” she said. “It’s a matter of scale and market design.”
“Green hydrogen is a super game changer,” Nelson continued. “We can attain a 100% renewable energy system that’s affordable, reliable and I would also say flexible and resilient.”
Methane Plus Hydrogen
To produce hydrogen without carbon emissions, excess wind and solar energy are used to power an electrolyzer that splits water molecules into hydrogen and oxygen. The electrolysis consumes large amounts of electricity, but the hydrogen can be stored for months — meaning ample summer solar power can make hydrogen for winter heating.
Hydrogen can also be used for storage in place of lithium-ion batteries, which currently have a maximum discharge time of about four hours. With lifespans of thousands of hours, hydrogen fuel cells can run indefinitely, important during extended outages.
Some industry advocates — including Tuesday’s panelists — are promoting a controversial plan to use green hydrogen as a partial substitute for natural gas, making use of existing gas pipelines and other infrastructure.
Nelson, who until recently served as energy advisor to the Utah governor’s office, said one big plan is already in the works.
The Intermountain Power Plant, a coal-fired facility in central Utah, is being repurposed to burn 30% green hydrogen combined with natural gas. The 1,800-MW plant, owned by the Intermountain Power Agency and operated by the Los Angeles Department of Power and Water, sends electricity to Southern California.
Nelson said the plant — which is scheduled to undergo a $500 million, years-long refit — is an ideal test case for combining methane and hydrogen.
“You have a big production capacity. You’ve got big offtake, and you’ve got all of the infrastructure to deliver a clean energy resource,” she said.
The plant is “strategically located near some salt formations,” where hydrogen can be stored in caverns large enough to hold the Empire State Building, with plenty of room to spare, Nelson said. There’s enough room near the power plant for 100 salt caverns.
Opponents have repeatedly argued, however, that mixing hydrogen with methane won’t help California achieve its goal of using zero-carbon energy by 2045 and will only extend the use of natural gas as a primary energy resource in the West. Owners of gas infrastructure are pushing the plans as a way to keep their assets from becoming “stranded” and worthless, they contend.
During the Q&A session, an unnamed participant questioned the planned ratio of hydrogen and methane at the Intermountain plant. (The written query was read aloud by Minnesota PUC Commissioner Valerie Means, who co-moderated the panel with fellow Minnesota Commissioner Matt Schuerger.)
Nelson responded that the mix would lower greenhouse gas emissions from the plant by up to 75% when it comes online by 2030 and that LADWP was hoping to eventually eliminate all GHGs.
CAISO on Monday issued a proposal outlining the leading edge of its plan to bring day-ahead trading to the Western Energy Imbalance Market.
The extended day-ahead market (EDAM) straw proposal represents the culmination of an effort set out two-and-a-half years ago in CAISO’s 2018 Policy Roadmap after a second attempt to regionalize the ISO’s market failed in the California legislature and the grid operator faced new competitive efforts from other potential market providers, including CAISO Plan Extends Day-Ahead Market to EIM.)
The proposal released Monday addresses only the first “bundle” of topics in CAISO’s EDAM initiative: resource sufficiency rules; use of transmission; and the distribution of congestion and “transfer” revenues — the last being a new concept introduced in the plan to accommodate flows across balancing authority areas in the West.
CAISO says the second bundle of the EDAM initiative will deal with greenhouse gas accounting, ancillary services, implementation of phase two of the extension of the ISO’s full network model and the administration fee. The third, and final, bundle will deal with price formation, convergence bidding, external resource participation, market power mitigation improvements and “any additional topics identified through the consideration of the first two bundles.”
Monday’s proposal also offered an important assurance to potential market participants — and state regulators — still wary of enlisting in an organized market, particularly one dominated by California. (See Tx Summit Explores California’s Link to Rest of West.)
“The approach contemplated in this effort does not require full integration into the CAISO balancing authority area as participating transmission owners (PTO), nor does it require formation of or participation in [a] regional transmission organization,” CAISO said in the executive summary of the plan.
The proposal makes explicit the promise of flexibility around the EDAM for EIM members, who would still retain their own balancing authority and planning functions — unlike entities participating in an RTO/ISO.
“The EDAM will incorporate the same principles of the Western EIM: voluntary participation, low-entry cost, no exit fees and retention of balancing authorities’ operational control over their resources and transmission,” CAISO said. “Participation in EDAM will be optional for EIM entities. Therefore, the proposed design must contemplate that some EIM entities may still elect to participate only in the CAISO’s real-time market and not EDAM. However, participating in the EDAM requires participation in the EIM.”
The proposal touted the expected benefits of EDAM, including using CAISO’s existing day-ahead market capabilities “for more efficient hourly shaped economic transactions across the West,” lower renewable integration costs because of increased geographic and resource diversity and reduced renewable curtailments.
It also cited improved reliability through better coordination among Western BAs, a conclusion that aligns with the preliminary findings of a WECC study released early this year showing that the reliability benefits of EDAM will likely outweigh any risks. (See Study Gauges Reliability Benefits of EIMDay-ahead.)
No Leaning
The EDAM straw proposal makes clear that participating load-serving entities — and their state or local regulators — retain responsibility for resource adequacy. But CAISO envisions EDAM will rely on a day-ahead resource sufficiency evaluation similar to the one currently in place for the real-time EIM to ensure that no participating BA leans on other BAs to meet its RA requirements.
Western stakeholders “expressed explicit concerns that leaning can enable balancing authority areas to systematically avoid self-sufficient forward procurement practices, which would erode the regional diversity benefits that can be obtained through the EDAM,” CAISO said. “Given the potential incentive to avoid forward procurement to serve their load, several stakeholders suggested the resource sufficiency evaluation should serve in a preventative mitigation function rather than a retroactive financial penalty as it would be difficult to determine the appropriate level of financial penalty.”
CAISO’s proposed resource sufficiency evaluation timeline for the EIM extended day-ahead market | CAISO
CAISO’s proposal calls for the resource sufficiency evaluation to require that all participating BAs “offer sufficient resources to meet their bid-in demand, reliability capacity to meet forecasted net load, … ramp capability to meet their 24-hour net demand variation and their forecasted ancillary service and imbalance reserve requirements.” Any BA that fails the evaluation will not be permitted to engage in transfers within the EDAM “beyond the amount of contracted capacity and transfer capability” demonstrated by the evaluation.
The ISO plans to run the resource sufficiency evaluation at 9 a.m. of each trading day, three hours after the conclusion of the region’s bilateral trading and one hour before the deadline for receiving EDAM bids. Market results would be published at 1 p.m.
The resource sufficiency aspect of the plan could also entail implementation of a “diversity benefit” that allows EDAM participants to share obligations for flexible ramping resources needed to cover load forecast error for the EDAM footprint. Under the program, the ISO would calculate the imbalance requirement for each BAA independently, then for the EDAM footprint as a whole based on the pooling of resources, then credit back to each BAA a prorated share of the savings derived from the pooling in order to reduce its resource sufficiency requirement.
“The CAISO views the diversity benefit as foundational to the benefit of EDAM and believes, if correctly applied, it will not result in unequitable leaning by any single participant,” the ISO said.
Transmission an Open Question
The straw proposal’s plan for transmission provision under EDAM is less developed than that for resource sufficiency.
Currently in the EIM, participants make transmission available to support real-time energy transfers by donating interchange rights or available transmission capacity. The latter category represents “residual” capacity unused after the T-20 e-tagging deadline, with the EIM given the lowest priority. If any portion of that capacity is used for a bilateral trade, the EIM redispatches the real-time market to ensure its transfers stay within the unused portion.
“EDAM will require a different approach than EIM,” the proposal explains. “Transmission customers can use transmission in real time up until just prior to the operating hour; however, the EDAM design cannot assume all transmission available in the day-ahead time frame will remain unused by real time. At the same time, transmission for EDAM day-ahead schedules for energy, ancillary services, reliability capacity and imbalance reserves must [be] available with high confidence, since each balancing authority area remains responsible for meeting its balancing authority area reliability requirements.”
CAISO is proposing a system in which EDAM BAs provide the ISO with limits for the use of their transmission systems ahead of the day-ahead market process.
“The EDAM balancing authority area may elect not to release all transmission to the day-ahead market, since transmission customers can elect to use transmission, for example, to support bilateral trades, up until 20 minutes prior to the operating hour (T-20),” CAISO said. “If the transmission is used to support day-ahead schedules, and subsequently if a transmission customer elects to use transmission after the day-ahead market, the real-time market will need to redispatch EDAM participating resources.”
The cost of that redispatch would be included in the EIM’s real-time congestion offset, which is calculated individually for each BAA to avoid cost-shifting among them.
But the ISO cautioned that day-ahead congestion could occur when transmission capacity is not included in the day-ahead market but a transmission customer chooses not to use it in real time: “The cost of this inefficiency may sometimes be greater than the potential for redispatch resulting in real-time congestion offset charges.”
A New Concept
The EDAM proposal presents a new concept of “transfer revenue” — similar to congestion revenue — that CAISO plans to introduce into both the EIM day-ahead and real-time markets as part of the EDAM effort. The ISO created the concept in response to stakeholder concerns that the voluntary nature of transmission provision in the EDAM could impede procurement of transmission rights while also incentivizing participants to withhold those right to maximize their congestion revenues.
Under the ISO’s plan, a transmission provider would be allowed to make transfer capability available in the day-ahead market at a usage fee. That fee would be included in the market optimization, generating transfer revenue to be collected by the provider.
“The CAISO believes that this approach will encourage transmission providers to offer additional unsold transmission into EDAM,” the ISO said.
CAISO also envisions allowing EDAM participants to adopt the ISO’s congestion revenue rights (CRRs) approach within their own BAAs. “An EDAM balancing authority area may choose to utilize the CAISO’s congestion revenue rights design to distribute congestion revenue to its transmission customers that are participating in the EDAM, in which case the CRR holder will be compensated directly by the CAISO. Remaining congestion revenue payments to the EDAM entity scheduling coordinator will be further allocated to its transmission customer based upon its [tariff],” it wrote.
EDAM participants choosing not to adopt CRRs will need to develop another method to settle congestion costs with transmission customer, the ISO said.
CAISO has scheduled stakeholder meetings on July 27 and 29 to discuss the EDAM proposal. Stakeholder comments on the plan are due Sept. 10. It expects to seek approval from its Board of Governors and the EIM Governing Body in late 2021 or early 2022.
New York on Tuesday announced its largest-ever package of renewable energy solicitations, seeking a combined 4 GW of offshore wind, onshore wind and solar power.
The New York State Energy Research and Development Authority seeks up to 2,500 MW of offshore wind energy this year in a solicitation authorized three months ago but the issuance of which was delayed by the COVID-19 pandemic (18-E-0071). (See NYPSC Greenlights 2,500-MW Offshore Wind RFP.)
The request for proposals includes a requirement that developers partner with any of the 11 prequalified state ports “to stage, construct, manufacture key components or coordinate operations and maintenance activities.”
The agency also is coordinating with the New York Power Authority on two separate RFPs to procure more than 1,500 MW of land-based renewable energy projects, with those selected to be fast-tracked for construction under the recently enacted Accelerated Renewable Energy Growth and Community Protection Act, which provides for expedited transmission upgrades.
NYSERDA’s solicitation calls for procuring about 1.6 million Tier 1 renewable energy certificates, while NYPA’s calls for projects that will produce an annual output of up to 2 million MWh or more. NYPA can elect to purchase a percentage of NYSERDA’s acquired RECs to fulfill its own requirements.
NYSERDA 2019 OSW contract awards, lease and project areas, and proposed points of interconnection | NYSERDA
NYSERDA also issued a request for information so that stakeholders can nominate sites for the new Build-Ready Program, initiated as part of the new siting law. The agency will prioritize areas such as dormant power plants, former industrial sites and existing or abandoned commercial sites.
Other notable provisions in the solicitations include requiring that workers be paid the applicable prevailing wage; encouraging near-term economic recovery activities in communities hosting projects; requiring that developers demonstrate a commitment to community engagement; and encouraging developers to pair renewable energy with advanced energy storage technologies to help meet the state’s commitment to deploy 3,000 MW of storage resources by 2030.
“During one of the most challenging years New York has ever faced, we remain laser-focused on implementing our nation-leading climate plan and growing our clean energy economy, not only to bring significant economic benefits and jobs to the state but to quickly attack climate change at its source by reducing our emissions,” Gov. Andrew Cuomo said in a statement.
“Together, taking into account the value of avoided carbon emissions, these solicitations are expected to deliver a combined $3 billion in net benefits over the 20- to 25-year life of the projects,” the governor’s office said.
Initial submissions for NYSERDA’s RFP are due Aug. 27; bids for NYPA’s solicitation are due Sept. 14; and those for the combined offshore wind and ports solicitation are due Oct. 20. Winners for all solicitations are expected to be announced in the fourth quarter.
“This enormous solicitation will not only jumpstart the state’s transition toward reducing climate pollution and meeting the goals of the nation-leading climate law passed last year, but it will also help boost the state’s economic recovery from the COVID-19 crisis,” said Lisa Dix, state director of the Sierra Club. “These projects will create family-supporting jobs for New Yorkers and specifically [target] low-income communities to benefit from the investments.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, said the organization “will be examining all of these RFPs in great detail in the coming days, but based on a cursory review, we note that the NYSERDA Tier 1 RFP … is the first to offer index REC contracts and has new requirements with respect to community engagement and agriculture mitigation.”
