CARMEL, Ind. — MISO this week said it agrees with its stakeholders it has onerous transmission service requirements for energy storage resources charging from the grid and should relax requirements.
Until now, the RTO has operated under the assumption that storage resources would secure long-term, firm, point-to-point transmission service before they began charging.
Members of MISO’s Environmental Sector argue FERC’s Order 841 doesn’t require storage to obtain firm, point-to-point transmission service and instead allows as-available transmission service. After reviewing Order 841, MISO agreed it should loosen its requirement that storage secure yearly, firm point-to-point transmission service. (See Stakeholders Puzzled by MISO Transmission Service Requirements for Battery Storage.)
Manager of Resource Utilization Kyle Trotter said battery storage should be treated like any other intermittent load in MISO.
Speaking at an Oct. 11 Planning Subcommittee meeting, Trotter said MISO agrees storage resources should be afforded the option to use either non-firm, point-to-point transmission service or its Network Integrated Transmission Service under any length of time.
“You’re not restricted to firm, you’re not restricted to duration,” Trotter said during an Oct. 11 Planning Advisory Committee. He said MISO expecting long-term, firm, point-to-point is an “overly restrictive transmission service requirement” for charging storage resources.
“Operationally, batteries do not charge 24/7; nonfirm is available down to the hour and provides more flexibility to the customer,” Trotter said.
Trotter said MISO believes storage resources in charging mode are willing to be curtailed when prices are high from transmission congestion or emergency conditions. He said the RTO doesn’t require other capacity resources to acquire firm fuel supply or firm station service load, so storage shouldn’t be treated differently. He also said long-term service is unnecessary for storage because their charging behavior is mostly price-driven and occurs off-peak.
“I think this is really important to straighten out for energy storage resources,” Southern Renewable Energy Association’s Andy Kowalczyk said.
Trotter said he will return to the Nov. 15 Planning Advisory Committee meeting with suggested revisions to the business practice manuals to strike the requirement.
MISO cannot wait until 2030 to roll out the welcome mat for DER aggregations in its markets, FERC ruled Tuesday.
FERC said MISO must submit a new date to achieve Order 2222 compliance in a more “timely manner.” The commission also ruled MISO has more work ahead of it to be fully compliant with its order unlocking participation in wholesale markets to distributed energy resource aggregations (ER22-1640).
MISO requested FERC allow it until Oct. 1, 2029, to register DER aggregations, with the first offers to follow in the first quarter of 2030. The RTO explained it first needed to replace its market platform before it has the technological capability to register, enroll and facilitate offers from DER aggregations. (See MISO Stakeholders Protest RTO’s Order 2222 Implementation Timeline.)
FERC said while MISO “persuasively explained” why its new market engines are a prerequisite for DER aggregator software and participation systems in its markets, the RTO didn’t justify the need for an additional five-year gap between completion of the new market platform in 2024 and the first DER aggregation registrations in late 2029.
“We find that MISO’s proposed effective date of Oct. 1, 2029, is not timely because, once MISO implements the [market platform replacement] project, MISO proposes to defer Order No. 2222 implementation for several years,” FERC said.
FERC said while it understood MISO wants to create a multiple configuration resource modeling, it said that shouldn’t also keep the RTO from opening its markets to DER aggregations for multiple years. MISO had said it should prioritize introducing a multi-configuration resource participation model before it tackles offers from DER aggregations because the former will yield more economic and reliability benefits.
However, FERC said, “facilitating distributed energy resource participation … will provide many of these same benefits.”
Single or Multiple Pricing Nodes?
FERC sent MISO back to the drawing board on several other aspects of its Order 2222 compliance.
Notably, FERC said MISO’s plan to limit aggregations to a single pricing node rather than across multiple nodes might be counter to the order’s directive that the locational requirements of DER aggregations be geographically broad as technically feasible.
MISO’s DER aggregation proposal specified that DER aggregations be at least 0.1 MW, be wholly located within MISO and limited to a single pricing node and self-commit their output in the MISO markets based on their own forecasts.
FERC said it understood MISO has concerns about congestion management challenges that could arise if DERs are aggregated at the opposite sides of a transmission constraint; however, it said “MISO has not demonstrated that it is not technically feasible for DERs to aggregate across a broader geographic area than a single node, at least for some nodes or groupings of electrical facilities that have similar impacts on the same transmission constraints.”
FERC told MISO it should better explain whether a broader aggregation is technically infeasible, not just challenging. It also said MISO’s potentially incomplete compliance with the locational requirements of Order 2222 raises the question of whether MISO must establish market rules that address distribution factors. MISO originally said its single-node pricing framework would not require distribution factors.
Commissioner Mark Christie said he thought MISO’s proposed pricing was fair and that pricing aggregations at more than one node would create a different compensation method for one category of resources and thus, undue preference.
“MISO’s proposal to price [aggregation] compensation at the node is technically feasible and is economically efficient, non-discriminatory and fair because it treats all resources similarly,” Christie said in a concurrence.
Christie said FERC should accept MISO’s pricing proposal “right now rather than make MISO produce more paperwork.” He said he only wrote a concurrence instead of a dissent because FERC didn’t outright reject MISO’s pricing plan.
Danly: A ‘Good Faith Effort’ on a Daunting Task
In a concurrence again lambasting Order 2222’s “micro-management” of RTO activities, Commissioner James Danly said MISO made a “good faith effort” to comply with the order but came up short.
“While I continue to disagree with Order No. 2222 itself, I agree that MISO failed to fully comply with its scores of dictates. I do not envy MISO the task we imposed upon them. One hundred percent compliance probably is impossible in a first, or perhaps even second, attempt. We shall see,” Danly wrote.
Other Compliance Shortcomings
FERC asked MISO to clear up several other aspects of its plan, including the role of relevant regulatory authorities over distribution systems. The commission said although regulatory authorities can choose to conduct their own distribution technical reviews and establish other rules that can override aggregators’ operations, MISO didn’t explicitly describe that role in Tariff revisions.
FERC also ruled MISO must add Tariff language that requires DER aggregators submit attestations that their aggregations comply with the operating procedures of distribution companies and the rules and regulations of their regulatory authorities. MISO’s plan should include an instruction to aggregators to provide a list of the individual DERs in their aggregations, FERC added.
The commission rejected MISO’s proposal to use a 10-MW threshold for aggregations before applying some market mitigation rules. FERC pointed out that MISO doesn’t use a size-based threshold for mitigation rules for any other class of resources.
FERC said MISO’s compliance plan didn’t explicitly spell out that aggregators will submit offers up to 30 minutes to the operating hour to reflect capability and must update offers in real time if DER availability changes.
FERC told MISO its proposed double-counting and technical review process of DER aggregations exceeded Order 2222’s 60-day limit. It also said MISO didn’t specify how it would share information about specific DERs provided to it by a distribution utility with aggregators as part of the distribution utility review process.
FERC also said MISO should be clearer on its protocols for sharing metering and telemetry data and should explain how such protocols will minimize costs while addressing privacy and cybersecurity concerns.
Beyond that, the commission said MISO needs to define how it will handle possible disputes over the potential impact of DER aggregations’ interconnections on the transmission system. MISO additionally must clarify how it will manage dispute resolution under its proposed distribution utility review process. The commission said while it agreed with MISO that many disputes are best left to the relevant regulators of DER aggregations, some disputes — especially those concerning information sharing during distribution utility review — will need to be resolved by MISO.
Finally, FERC said though MISO proposed that distribution companies could perform eligibility reviews, that section didn’t contain any criteria or standards distribution companies might use to establish whether a DER is capable of participating in an aggregation. The commission ordered MISO to explain whether it would incorporate additional eligibility criteria beyond those related to the required double-counting review.
FERC similarly said MISO’s proposed distribution utility review process to determine whether a DER will pose harm to the distribution system lacked criteria.
The commission said MISO should continue to coordinate with distribution utilities on those processes. It gave MISO 60 days to address its compliance imperfections.
SEATTLE — The state-led Committee on Regional Electric Power Cooperation (CREPC) should spearhead an effort to boost development of new transmission in the West, according to the findings of an initiative that included contributions from former FERC Chair Richard Glick.
The findings were the product of the Western States Transmission Initiative (WSTI), a partnership between CREPC and decarbonization nonprofit Gridworks formed to gather input from electricity sector stakeholders on what actions the committee can take to help give Western transmission planning a more interconnection-wide perspective.
The WSTI proposals came just two days after the Western Power Pool (WPP) floated a plan to create a new group intended to spur the kind of interregional transmission development envisioned in the WSTI effort. (See Plan Seeks to Boost Prospects for New Transmission in the West.)
Key among the WSTI recommendations: CREPC should create a Transmission Working Group that would seek federal funding to hire staff and consultants to examine the state of the Western grid with an eye to fostering a shift from the region’s current “bottoms-up” approach to transmission planning, which favors smaller projects that satisfy local needs, to a process that prioritizes meeting the needs of the wider West with larger-scale projects.
The group also would be tasked with identifying specific interregional projects and possibly could seek National Interest Electric Transmission Corridor (NIETC) designations for some of those projects. That would allow them to reduce investment risk by tapping federal funding, Glick pointed out during an Oct. 4 discussion of the WSTI recommendations at the fall joint meeting of CREPC and the Western Interconnection Regional Advisory Body (WIRAB) on Seattle’s waterfront.
“There’s also one other element to it that people may not agree with, especially state regulators: It would also give FERC backstop siting authority for those particular routes that were essentially rejected by one or more states,” Glick said.
The Transmission Working Group also would focus on potential approaches to allocating costs for interregional projects and seek to coordinate approaches among Western states.
The WSTI also recommended the group host a Western transmission conference that would include multiple stakeholders, including officials from U.S. states and Canadian provinces.
“I think the idea of hosting a conference is to get input from … various stakeholders,” Glick said. “Not just utilities and [independent power producers] and transmission developers, but also other entities as well — voices that are normally not heard, whether it be communities, consumer groups, the business community [and] big industrial customers.”
The Transmission Working Group’s other “potential actions” could include encouraging “independent” planning processes; promoting “forward-looking and inclusive” planning; monitoring and participating in FERC transmission planning and cost allocation rulemaking and compliance proceedings; and participating in other regional transmission planning efforts.
‘Meaningful’ Planning
Sharing the dais with Glick at the CREPC-WIRAB meeting, Gridworks Director Kate Griffith said the WSTI recommendations were the product of a six-month project that included interviews with 40 organizations, which included state agencies, non-governmental organizations, utilities, tribes and other stakeholder groups from across the West.
Key themes emerging from those interviews included the “insufficient” pace of transmission development in the West, the lack of “meaningful” interregional and interconnection-wide transmission planning, and the impediment to development caused by the lack of agreement over cost allocation.
Interviewees also said most utilities lack the resources to build major projects on their own and that state/provincial coordination could play a key role in transmission development but would need more resources.
“Today’s presentation and discussion really just starts a conversation at CREPC,” Griffith told the audience at the Seattle conference. “After today’s conversation, CREPC co-chairs will be encouraging you all to share your feedback with them, and we’ll be scheduling a follow-up conversation about whether or not to pursue these recommendations.”
If CREPC decides to advance on the recommendations, Griffith said, Gridworks plans to announce the formation of the Transmission Working Group by the end of October and begin efforts to identify transmission corridors and seek consultants to engage in the effort.
State officials attending the conference largely seemed to support a larger role for CREPC in transmission planning.
Washington Utilities and Transportation Commissioner Ann Rendahl said it is “critical” to bring the states together to participate in the process. Rendahl described her experience with NorthernGrid, the Northwest’s planning entity, as one in which the group tells regulators, “‘We’ll check in with you and see if you have any thoughts’ — and that doesn’t really feel like being included in the process and having a perspective.
“With changes in state policies across the board in the West, it’s important to … get everybody’s views as to what’s important and what’s needed for the states to accomplish” their goals, Rendahl said.
“What happens next depends on the feedback we get from all of you today and over the course of the rest of the conference … and the follow-up conversation that we have,” Megan Decker, CREPC co-chair and chair of the Oregon Public Utility Commission, told meeting participants.
Dare to Dream
“I know how much CREPC enjoys an October surprise,” WPP CEO Sarah Edmonds joked during an Oct. 5 panel at the conference as she described why she released WPP’s “concept paper” for the Western Transmission Expansion Coalition (WTEC) two days ahead of the Seattle meeting.
“I posted that for all of you on [Oct. 3] knowing that we could really leverage this opportunity to be together knowing what the Gridworks recommendations were going to be and what we’re trying to do as well, where I see a lot of potential overlap,” Edmonds said.
Edmonds explained that the WTEC concept took shape after Bonneville Power Administration CEO John Hairston told her he saw a need for BPA to be a strong leader for transmission development in the Northwest but thought the conversation should be held in a forum bigger than what the agency offered.
“I said to him I was interested in it as long as it was a West-wide, inclusive activity,” said Edmonds, whose organization operates the Western Resource Adequacy Program (WRAP) and facilitates the functions of NorthernGrid.
WTEC would intend to take a “top-down” approach to Western transmission planning, one that would include the Southwest transmission planning entity WestConnect, CAISO, BPA and the Western Area Power Administration, and not seek to upend the region’s transmission planning groups, Edmonds said.
“This is not a proposal that fits under FERC-jurisdictional activities,” she said, calling it “an exploratory effort” to engage in a new approach to planning, with FERC-related processes possibly addressed further in the future.
Edmonds also sees the potential for partnership between the WTEC and the WSTI. She said engagement between the two efforts could identify “a range of things we could shoot for” while avoiding coming into conflict or harming each other.
“We might dare to dream of harmonizing, but what about synchronizing?” Edmonds said. “I’m really open for discussion on all those points because I know, and I also would say because BPA … knows, how important the state partnership is on these decisions. The entities that will build transmission and seek cost recovery also understand that critical part of the relationship. It would be new and different to think of a partnership like this, and I know the devil is in the details.”
Washington state officials expect to soon decide whether to join the California-Quebec cap-and-trade program.
The decision could come later this month or in early November, Joel Creswell, climate pollution reduction program manager at the Washington Department of Ecology, told the state’s House Environment and Energy Committee Monday.
Washington’s decision to join the program would require approval by California and Quebec, setting the stage for a final contract to be signed in 2025.
Creswell said joining the bigger program would likely reduce Washington carbon allowance prices from the high levels seen in this year’s quarterly auctions. Critics of Washington’s cap-and -invest program blame it for the state having the highest gasoline prices in the U.S this past summer.
Carbon prices in the Washington auctions have climbed steadily in the first year of the program, clearing at $48.50 in the first quarter, $56.01 in the second quarter and$63.03 in the third. Republican critics of the program believe the increases have driven up prices at the pump.
The Oil Price Information Service has estimated that a $50 allowance price would translate into a 40- to 50-cent increase in gasoline prices. The state’s oil sector has acknowledged it has passed the price of allowances to consumers to account for its extra costs.
However, the gas price tracking service GasBuddy showed that prices in Washington and Oregon (which does not have a cap-and-trade program) had been roughly the same from 2014 to 2022. On Jan. 1, 2023, about two months before the first cap-and-trade auction, Washington’s average price was 10 cents higher than Oregon’s, with the gap expanding to 36 cents by Sept. 27. That 26-cent increase could be theoretically linked to cap-and-invest, Ecology Department spokesperson Andrew Wineke said.
On Monday, state Sen. Liz Lovelett (D) asked: “Why would California want to link with us?”
Creswell said that Washington joining with California and Quebec would boost the manufacture and sales of green technologies in all three areasas industries seek to trim their carbon emissions.
California conducted its first cap-and-trade auction in November 2012, with prices clearing at $10 per allowance. Prices hit $14 by the third quarterly auction before declining.
In 2014, Quebec joined California to create a cap-and-trade market that is six times the size of Washington’s.California-Quebec prices increased from $19 in 2021 to $36.14 this summer, according to data from the California Air Resources Board.
One reason Washington’s carbon prices have exceeded those in California is the comparatively steeper rate of carbon reductions in the Evergreen State, saidJessica Spiegel, Northwest Region senior director at the Western States Petroleum Association, to NetZero Insider.
Two new reports released Wednesday document the progress and challenges in the global effort to reduce greenhouse gas emissions.
DNV issued the 2023 edition of its Energy Transition Outlook, concluding that the transition is still at the starting line, with new renewable generating capacity growing at the same rate as demand.
The outlook is not sunny — the report projects global warming well beyond the 2100 target of 1.5 degrees Celsius — but there are some points of optimism: It predicts slight reductions of emissions starting as soon as next year and dropping 4% lower by 2030. It predicts a 46% reduction in emissions by 2050, when it expects non-fossil energy to supply 52% of world demand.
The Energy Information Administration covers some of the same ground in its annual International Energy Outlook.
The two reports are not directly comparable, as EIA extrapolates future models from an unchanging 2023 policy baseline. It projects global fossil fuel consumption and carbon dioxide emissions would rise through 2050 without major policy adjustments to the current trajectory.
DNV Outlook
An introductory message from DNV Group President Remi Eriksen begins with a simple assessment: “If ‘energy transition’ means clean energy replaces fossil fuel in absolute terms, then the transition has not truly started.”
High prices have had opposite effects on energy industry sectors, making oil and gas exploration more lucrative and complicating the buildout of renewables, he said.
But DNV projects that emissions from oil will peak in 2025 and from natural gas in 2027.
Policy changes already are showing results in the US and EU, where per-capita greenhouse gas emissions are among the highest in the world, it said. However, in the next decade, transmission constraints and supply chain shortfalls pose a threat to progress.
Another trend playing out now is the rise of oil and natural gas prices, which tarnished the status of gas as a bridge fuel during the transition and prompted an increase in coal-fired generation in several countries. But increased fossil use in lower-income countries is gradually balanced over the next decade by increased renewables in wealthier countries, DNV projects.
Advanced economies will drive development of the technologies that will help to enable the transition, but that will not bring as much benefit to medium- and low-income regions, which need de-risked funding to accelerate the transition.
Overall, the energy mix is projected to transition from 80%/20% fossil-renewable in 2023 to 48/52 renewable by 2050, with a 10-fold increase in wind generation and 17-fold increase in solar power.
Energy security has become a motivating factor since Russia invaded Ukraine, disrupting energy supplies and prices. Local energy production is now a priority in many countries, whether it be renewable, nuclear or coal.
So while progress is being made, DNV concludes, it is not being made fast enough. Global emissions would need to be cut 50% by 2030 to achieve a net-zero energy system by 2050, but the report does not project a 50% emission reduction even by 2050.
The global target held out by some activists and scientists — keep the planet from warming more than 1.5 C by 2100 — keeps getting harder to reach, DNV said. It calculates a 2.2-degree increase through 2100 under the emissions forecast in the outlook.
EIA Outlook
EIA said its projections in the IEA conclude that while zero-carbon technology such as renewables and nuclear would meet the bulk of new demand through 2050, that is not enough to counter the increase in other sources of CO2 emissions. These include global population growth, increased regional manufacturing and the push for higher standards of living.
The projections are not forecasts, nor are they even likely scenarios; they assume the policies in place as of late 2022/early 2023 will remain unchanged for the next 27 years. (In fact, the authors note, some policy changes already have occurred as of late 2023.) Rather, the projections are a policy-neutral baseline against which future policy decisions can be considered, the report says.
EIA highlighted three main takeaways from the report.
All cases modeled show global energy consumption rising, with the fastest growth coming in the residential and industrial sectors and the greatest increase in use of liquid fuels coming in industrial applications. As more electric vehicles hit the road, applications such as chemical production account for a greater share of the liquid fuels used.
Global electric generation capacity grows anywhere from 55 to 108% from 2022 to 2050, depending on the case modeled, and actual electricity generated rises 30 to 76%. Renewables, nuclear and battery storage account for most of the increase in both metrics, but renewables grow fastest in cases that assume high economic growth and greater electricity demand.
Energy security is a driving concern in both directions: It hastens the transition away from fossil fuels in some countries and prompts increased fossil consumption in others.
“IEO2023 fills an important niche among global outlooks by focusing on a plausible but sober assessment of global energy trends through the first half of the century,” EIA Administrator Joe DeCarolis said in a news release. “There is considerable uncertainty in the energy landscape over the next 30 years, and the IEO provides a set of policy-neutral baselines that will help guide sound decision-making.”
MISO’s Independent Market Monitor is angling for demand response offer floors and attestations of expected levels of energy consumption in the wake of an Arkansas steel mill’s gaming of the MISO demand response market.
Meanwhile, a second demand response resource in MISO might be under fire for promising load reductions and not delivering them.
In late August, FERC accepted a $35 million total settlement between Big River Steel in Osceola, Ark., Entergy Arkansas and FERC’s Office of Enforcement, of which $21 million will be returned to MISO customers. The steel mill for years collected payments from MISO for demand response while not actually reducing electricity use. (See FERC OKs $21M Settlement in Arkansas Steel Mill’s DR Scheme in MISO.)
Carrie Milton, of the Independent Market Monitor’s team, said the IMM is advising MISO to reinforce its rules for demand response resources (DRRs) “to prevent similar gaming in the future.”
“After seeing this kind of conduct, we have recommended [that] MISO establish an offer floor for DRRs and that DRRs indicate their forecasted, pre-curtailment expected consumption,” Milton said during an Oct. 5 Market Subcommittee meeting.
Milton said IMM staff recently referred another MISO DRR to the Office of Enforcement for offering “phantom load reductions” similar to Big River Steel. In this case, the unnamed company collected more than $35 million in payments from MISO.
Neither MISO nor the IMM revealed the name of the company involved with the possible new investigation. MISO said the IMM’s screening first uncovered the “information that led to FERC’s investigation” of Big River Steel.
Milton said the IMM team is working with MISO to gain support for the DRR rule changes.
MISO did not say whether it agrees with the IMM’s proposal but said it is open to exploring with stakeholders what improvements might be necessary.
“Following any situation like this, MISO is closely collaborating with the IMM and FERC to evaluate potential enhancements to help prevent similar conduct in the future, which will be vetted through MISO stakeholder process in an open and timely fashion,” spokesperson Brandon Morris said in an emailed statement to RTO Insider.
LANSING, Mich. — Michigan’s Public Service Commission would oversee siting of major renewable energy projects under a package of legislation introduced in the state’s House of Representatives, which immediately drew praise from supporters and outrage from opponents.
HB 5120 and companion bill HB 5121 would preempt local zoning and give the PSC authority for siting of wind, solar and energy storage facilities of 100 MW or more. HB 5122 and HB 5123 are identical except that they would apply to solar energy storage facilities between 50 and 100 MW. No hearing has been set on the legislation at this time.
An official with the Michigan Townships Association (MTA) immediately blasted the legislation as an “authoritarian” attempt to force small, rural areas to accept large energy facilities and bar local voter referendums on the projects.
“Yes, renewable energy facilities can be contentious in some communities. But the answer is not — and is never — to silence the voices of the impacted residents and communities,” said Neil Sheridan, executive director of the association.
Also opposing the package is the Michigan Farm Bureau, which has said the legislation could harm Michigan’s agriculture industry, as well as the Michigan Association of Planning and the Southeast Michigan Council of Governments (SEMCOG). SEMCOG represents all the city and county governments in Michigan’s largest population area, including Detroit and Wayne, Oakland and Macomb Counties (though those entities also have their own lobbyists).
Not taking a position on the bills thus far are two other significant local government interest groups: the Michigan Association of Counties and the Michigan Municipal League. The Municipal League represents the state’s cities and villages, including Grand Rapids and Ann Arbor (the second- and fifth-largest cities in Michigan, respectively), two communities that have been more aggressive in dealing with climate change issues.
The Municipal League also recently supported HB 5028, which would prohibit homeowners’ associations from barring solar panels on houses.
The MTA represents the more than 1,200 townships in the state — ranging from Canton Township in Wayne County, with a population of greater than 90,000, to Pointe Aux Barques Township in Huron County, population 15 — where most of the major disputes about building renewable energy projects have taken place.
Backing the bills is a coalition of industrial groups that work on and for renewable energy, including the Michigan Energy Innovation Business Council and the American Clean Power Association. Erika Kowall, director of Midwestern Affairs for the ACP, said the legislation showed Michigan was “taking a meaningful step to help counter project delays and ensuring that a clean energy future will unlock economic investment and jobs across the state while protecting the environment.”
Peder Mewis with the Clean Grid Alliance said Minnesota and Wisconsin have systems similar to what Michigan is proposing that maintain local oversight on smaller projects while having state oversight on larger projects.
In keeping with its winter estimates from previous years, MISO said it could run into trouble in January should it experience high load or high outages.
In a winter outlook published last week, MISO said it should fare well over the season under typical demand and generation outages. However, the RTO said it may need to declare an emergency in January if a deep freeze spurs either unusual generation outages or elevated demand.
Otherwise, MISO said it should have sufficient firm resources to cover winter peak load forecasts.
The grid operator predicts a 96.4-GW peak in December under typical circumstances or 101.5 GW in a high-load scenario. It said it should have nearly 115 GW of firm resources to cover peak, though that could be downgraded to 110.7 if generation outages creep up.
MISO said its system most likely will realize a nearly 102-GW peak in January under typical demand or up to 107 GW in an amplified demand situation. It said it should have as much as 121.8 GW or as little as 100.7 GW of firm resources available in its fleet, all but guaranteeing the need for emergency procedures and resources.
System strain will ease in February, MISO said, with a 97.6-GW peak or a less likely 102.4-GW peak. In either case, the RTO said it should be able to handle demand without an emergency, having anywhere from 121.6 GW to 111 GW available in firm resources.
MISO anticipates it will have access to about 10 GW worth of load-modifying resources and other operating reserves this winter if it orders emergency procedures.
MISO declared one maximum generation event last winter during a Dec. 23 arctic blast, a product of high load and high generation outages. (See MISO Winter Recap Centers on December Emergency.)
FERC on Friday rejected a rehearing request by a solar developer of the commission’s denial of its complaint and a tariff waiver over SPP’s interconnection studies for the planned facility (EL22-89).
The commission, citing Allegheny Defense Project v. FERC, denied the rehearing request by “operation of law.” FERC modified the discussion in its previous order but arrived at the same conclusion.
The D.C. Circuit Court of Appeals’ 2020 ruling in Allegheny found the commission no longer could grant rehearing requests “for the limited purpose of further consideration.”
The developer behind Cage Ranch Solar and Cage Ranch Solar II, a 900-MW project in West Texas, sought to reverse the commission’s May decision that found Cage Ranch had not met its burden to show that SPP violated its tariff or conducted its studies in an unjust and unreasonable manner. FERC said the solar facility did not demonstrate the study models underlying the cluster study were defective. (See FERC Sides with SPP Over Interconnection Study Complaint.)
Cage Ranch argued FERC erred by finding its interconnection was the “but for” cause of network upgrades, failing to address the developer’s cost-causation arguments; and that its waiver request did not address a concrete problem.
The commission said it was unpersuaded by the rehearing arguments and continued to find that Cage Ranch had not met its burden under the Federal Power Act to show SPP violated its tariff or that its allocation of costs was otherwise unjust and unreasonable.
“Nothing in the rehearing request demonstrates that the [SPP] study models underlying [SPP’s study] are defective,” FERC said. “Accordingly, we continue to find that Cage Ranch has failed to demonstrate that the network upgrades assigned to Cage Ranch … and the associated [study] payment amount that Cage Ranch was required to post, are unjust and unreasonable and unduly discriminatory or preferential. … None of the issues raised in the rehearing request persuade us that the commission’s conclusions were in error.”
Cage Ranch had said the SPP study in question should not have been used to determine interconnection costs for the solar farm and other customers in the study group because SPP failed to resolve alleged nonconvergence issues. FERC pointed out that the grid operator assigned Cage Ranch network upgrade costs using a modeling approach it applies to all interconnection customers.
Cage Ranch Solar also filed a challenge of FERC’s earlier ruling in August with the D.C. Circuit. It said the orders violate the Federal Power Act and the Administrative Procedure Act and are arbitrary, capricious and an abuse of discretion (23-01227).
Independent entities cannot review and challenge tank congestion charges and revenue credits in the annual true-up process for the cost-of-service agreement between ISO-NE and the Mystic Generating Station, FERC ruled Friday (ER18-1639).
The commission also ruled against a request by a group of municipally owned utilities for additional audit disclosures related to the agreement, saying that ISO-NE’s existing audit procedures and disclosures are adequate.
The ruling responded to both the municipal utilities’ request for additional information and a request for rehearing by Constellation Mystic Power, which argued against FERC’s determination that “interested parties” can review and challenge the true-up. That “could be read to allow interested parties to obtain information that is commercially sensitive, and that poses a security risk,” the company said.
In contrast, the utilities argued that the significant costs of the agreement — which they estimated to be more than $400 million over the first 10 months — necessitated the disclosure of additional information to allow interested parties to challenge the credits and charges. (See Public Power Groups Seek Information on Mystic Agreement.)
Credits account for revenues that Mystic earns from sources other than the agreement, while tank congestion charges refer to any costs associated with the increased need for uneconomic self-scheduling or short-term vaporization LNG.
FERC sided with Constellation, reversing its previous determination and also agreeing that shared revenue from third-party natural gas vapor sales should not be included in the true-up process. The commission said these contested issues are inconsistent with the Mystic agreement’s true up process because “none of them are projected in advance, but rather they are each settled and audited on a monthly basis.”
The commission also denied the municipal utilities’ request for additional audit information, which is “not supported by the Mystic agreement and unnecessary, given the attention that ISO-NE, its auditors and the Market Monitor give these items on a regular basis.” The request “goes beyond the terms of the Mystic agreement, which vests ISO-NE with audit rights and requires ISO-NE to maintain the confidentiality of audit-related information.”
“Allowing all interested parties to review Mystic’s revenues and revenue credit could require disclosure of proprietary information about Mystic’s actual fuel costs,” FERC wrote. “We recognize the potential competitive harm to Mystic, Constellation LNG and the market that could ensue from the disclosure of unmasked, offer-specific, commercially sensitive information to third parties.”
FERC wrote that it is “sympathetic” to the concerns about the high costs of the Mystic agreement, but “there is no record evidence that the Mystic agreement formula rate is being improperly executed.”
“The existing cost review and audit processes, which are facilitated by ISO-NE, its auditors and the Internal Market Monitor … are sufficient to ensure that Mystic adheres to its filed rate,” FERC added.
FERC also accepted a proposal ISO-NE had filed as an intermediate solution, which stopped short of the broad disclosures requested by the public power groups but allows for releasing redacted audit reports, providing summaries of its discussions with Constellation about fuel supply decisions, and making a member of Levitan & Associates’ tank congestion audit team available for questions at several points throughout the agreement.
“We are pleased that the commission has recognized the significant information the ISO has made available regarding the ongoing auditing of Constellation’s fuel supply decision,” an ISO-NE spokesperson told RTO Insider via email. “We will continue to work with Constellation and our stakeholders on ways to provide additional information while protecting confidentiality.”
