FERC Approves CAISO Intertie Penalty Price Revisions

FERC on Thursday approved CAISO tariff revisions that will increase the penalty prices associated with the relaxation of intertie transmission constraints in the ISO’s market processes (ER22-1246).

In its March 10 filing requesting approval for the changes, CAISO explained that the tariff amendments would affect two of its market processes: the residual unit commitment (RUC) process, which occurs in the day-ahead market, and the hour-ahead scheduling process (HASP), which takes place in the real-time market.

CAISO said that the amendments fix a defect in those processes, preventing the ISO’s market optimization software from inaccurately representing the supply available to meet demand and reducing the reliability risk of overscheduling on the interties during tight supply conditions.

In the filing, CAISO explained that the ISO’s market optimization software schedules and prices resources in two successive runs in both the day-ahead and real-time markets. The first is the scheduling run, which produces resource schedules and “involves clearing bids, enforcing the priorities of self-schedules, and potentially relaxing constraints.” Following that, the pricing run produces the locational marginal prices used in settlements.

CAISO said the software its employs to optimize its day-ahead and real-time markets uses “configurable market scheduling and pricing parameters to reach a feasible solution and set appropriate prices for the market in instances where effective economic bids and self-schedules are insufficient to reach a feasible solution.”

To accommodate those situations, the market parameters used in both the day-ahead and real-time include administratively determined “penalty” prices that apply when constraints enforced by the CAISO market are relaxed or violated. When the ISO relaxes a constraint, its market software calculates scheduling run LMPs based on penalty prices, although the penalty prices — and their associated LMPs — at issue in the filing are only used in the scheduling runs of the RUC and HASP to ensure constraints and not used in market settlements.

CAISO’s market software clears economic bids and self-schedules for imports at interties based on a supply curve. If the LMP in the scheduling run is lower than the LMP for an economic import bid, that import bid will not clear the market. The same condition applies to import self-schedules at an intertie: it will be cut if the LMP is lower than an applicable penalty price used for adjusting the import self-schedule, “and because penalty prices for import self-schedules are negative, the LMP must be more negative than the import penalty prices for the import self-schedule not to clear,” FERC noted.

Over the past two years, CAISO has learned that when faced with having to relax both the power balance constraint (which ensures that supply is balanced with demand) and an intertie transmission constraint to reach a feasible market solution, the resulting LMPs for imports at the intertie can be too high relative to penalty prices to avoid the overscheduling of imports on that intertie.

The ISO said it observed the issue in the RUC at the Malin and Nevada-Oregon Border interties on Aug. 19, 2020, and again in the HASP at those same interties on July 9, 2021. In both instances, the region was dealing with extreme weather-related events.

“CAISO explains that overscheduling creates issues for both reliability and market efficiency because when the market software clears intertie schedules that exceed the intertie scheduling limit, CAISO operators must then manually curtail those excess intertie schedules after the market clears,” FERC noted in its order. “CAISO asserts that overscheduling poses an especially large reliability risk during tight supply conditions and when overscheduling occurs, the market clearing process accounts for import supply that is not actually available, resulting in inaccurate market signals and an inefficient market solution.”

Flexible Parameters

To prevent the problem from recurring, CAISO proposed to increase the scheduling parameter values for intertie transmission constraint relaxation in both the RUC and the HASP at a level high enough that “even when the power balance constraint and the intertie transmission constraint are relaxed at the same time, they will produce an LMP that reflects the scarcity of available intertie capacity,” the commission said.

The ISO’s proposal includes:

- - increasing the scheduling parameter for intertie transmission constraint relaxation in the RUC from $1,250/MWh to $3,200/MWh when the soft energy bid cap of $1,000/MWh is in effect;
  - increasing the scheduling parameter in the RUC from $1,250/MWh to $6,400/MWh when the hard energy bid cap of $2,000/MWh is in effect;
  - increasing the scheduling parameter for intertie constraint relaxation in the real-time market from $1,500/MWh to $2,900/MWh when the soft bid cap is in effect and from $3,000/MWh to $5,800/MWh when the hard cap is in effect.

“CAISO has performed counterfactual simulations showing that, if the tariff revisions had been in place when the overscheduling at the Malin and NOB interties occurred in the summers of 2020 and 2021, no overscheduling would have occurred,” the ISO said in its filing.

In approving the changes, the commission agreed with CAISO that previous FERC rulings stated that the scheduling parameters were “flexible” parameters that the ISO could propose to revise as needed. The commission also agreed that the revised parameters should help prevent overscheduling at the interties and boost reliability and market efficiency, especially in the face of tight supplies.

“As CAISO explains, preventing overscheduling when both the power balance constraint and intertie transmission constraints are relaxed will prevent the need for manual operator intervention to curtail excess intertie schedules under these conditions,” the commission concluded.

In a separate concurrence, Commissioner James Danly urged his fellow commissioners to initiate a Section 206 investigation “to fulfill our statutory duty to ensure just and reasonable rates,” reiterating his previously stated concerns about the California electricity market.

“The CAISO market has been in a perpetual state of emergency since it experienced rolling blackouts in August 2020, largely because of insufficient generation resources, distorted prices and an over-reliance on less reliable renewable resources combined with out-of-market subsidies in support of the same,” Danly said.

May 22, 2022

Biden to Re-nominate Glick as FERC Chair

The White House announced Friday that President Biden will nominate FERC Chair Richard Glick for another five-year term.

If confirmed, Glick could be on the commission well into 2027 and could remain chair as long as Biden remains president or another Democrat succeeds him after 2024. If a Republican is elected, Glick would be demoted, but the commission could retain a Democratic majority until 2026, when Commissioner Willie Phillips’ term expires.

Glick was originally nominated alongside Republican Neil Chatterjee by President Donald Trump and joined FERC in November 2017, when the commission’s sole member was acting Chair Cheryl LaFleur. Glick filled the seat left open by Colette Honorable’s resignation and was the lone Democrat — and often voice of dissension — for more than a year, between when LaFleur resigned in August 2019 and Commissioner Allison Clements joined in December 2020.

Before joining the commission, Glick was general counsel for the Democratic members of the Senate Energy and Natural Resources (ENR) Committee.

Glick was unavailable for comment over the weekend and had not tweeted anything as of press time.

Transmission Planning, Gas Policy Highlight First Term

His tenure has so far been marked by efforts to re-examine the commission’s policies on transmission planning, natural gas pipeline certificates and RTO capacity markets. Those efforts have been appreciated by renewable energy interests and environmentalists and criticized by the fossil fuel sector and the commission’s Republican minority, especially Commissioner James Danly.

In February, he and his fellow Democrats received more widespread criticism for a pair of policy statements on how the commission would more closely scrutinize evidence of need for pipeline projects and evaluate the impacts of their greenhouse gas emissions in environmental analyses. The statements were released without notice for comment and would have applied retroactively to all projects already pending before the commission.

The Democratic majority was later excoriated for the move by members of the ENR Committee — mostly Republicans, but also Chair Joe Manchin (D-W.Va.), whose support may prove necessary for Glick to continue in his post. (See Glick: No Regrets over Gas Policy Statements.)

A month later, FERC walked the policy statements back, labeling them as drafts and saying any new rules would apply only to future projects. (See FERC Backtracks on Gas Policy Updates.)

Glick won plaudits for his outreach to state regulators in a bid to accelerate transmission development. (See FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues,)

But he has come under criticism for proposing a reinstatement of federal rights of first refusal (ROFR) in the commission’s April 21 Notice of Proposed Rulemaking on transmission planning and cost allocation. (See ANALYSIS: FERC Giving up on Transmission Competition?)

Former FERC Chair Jon Wellinghoff and Paul N. Cicio, chairman of the Electricity Transmission Competition Coalition and CEO of the Industrial Energy Consumers of America, called the ROFR proposal “a costly giveaway” to incumbent utilities that have circumvented FERC Order 1000’s rules encouraging competition in transmission development, citing data that only 3% of all transmission projects are competitively bid.

In a May 15 op-ed in The Hill, Wellinghoff and Cicio said that transmission costs in RTO/ISO markets “increased by $74.9 billion or 78.7%, while electricity demand was flat” from 2014 to 2020.

“Competition brings out innovation, a solution to inflation and an American norm — but the power sector is different,” they wrote. “Utilities make money by spending money and recover it in consumer rates with a 10 to 12% annual after-tax return on investment. The more they spend the more they earn.”

Reaction

On Friday, Chatterjee — himself a former Senate adviser, on the other side of the aisle — tweeted that Glick “is a great person and dedicated public servant. He’ll have to answer some tough questions, but if he continues to strive for bipartisan consensus on the contentious issues before FERC, he’ll be in a strong position for a second term.”

Responses to the news from stakeholders ranged from celebratory to tepid.

Both Advanced Energy Economy and the American Council for Renewable Energy “applauded” the announcement, with AEE Managing Director Jeff Dennis saying Glick “has provided steady leadership at FERC” and ACORE CEO Gregory Wetstone saying he has been “exceptionally effective as chair.”

WATT Coalition Chair Ted Bloch-Rubin congratulated Glick, saying that “FERC has made great strides towards policy to improve the United States’ transmission system planning and operation” under his leadership.

Electric Power Supply Association CEO Todd Snitchler was less enthused, saying that the organization “looks forward to a robust conversation around issues critical to the Federal Energy Regulatory Commission’s jurisdiction with the re-nomination. … [It] comes at a time when FERC’s mission to ensure reliable, safe, secure and economically efficient energy for consumers has never been more important.”

EPSA is challenging PJM’s narrowed minimum offer price rule (MOPR) in the 3rd U.S. Circuit Court of Appeals. The group contends it threatens the competitiveness of the capacity market and that FERC failed to give adequate reasoning for allowing the rules to go into effect. (See PJM MOPR Challenge May Set Legal Precedent on FERC Deadlocks.)

Glick was among four other intended nominees “to serve as key leaders” in the administration that the White House announced late Friday afternoon; none of the four other posts is related to energy policy.

May 22, 2022January 30, 2024

Michigan Adding EV Chargers to State Parks

LANSING, Mich. — Thirty electric vehicle chargers will be installed in 12 of Michigan’s most popular parks along the Lake Michigan shoreline beginning in June, the start of a multi-year effort to offer charging at most of the state’s more than 100 parks.

The plan is designed to take advantage of the huge Chicago-area tourist traffic to Michigan’s western shore, and to work with officials in Wisconsin, Illinois and Indiana to promote the Lake Michigan shoreline tour.

Currently, the Michigan Department of Natural Resources has just three chargers in three of its parks in the eastern half of the state, including Belle Isle State Park in Detroit and Bay City State Park along Lake Huron.

Scott Whitcomb, DNR director of the Office of Public Lands, said the roll out of the chargers this year is an effort to make sure EV drivers from Chicago and Detroit know they will have a source to charge their vehicles.

In 2023, chargers will be added to some parks in the Upper Peninsula, including the state’s largest state park, Porcupine Mountains State, and going north along I-75 from Metro Detroit, including the popular Hardwick Pines State Park.

The chargers will be Level Two chargers, meaning a full charge could take an hour. Because the parks have campsites and most have beaches, visitors are expected to be in the parks more than long enough to accommodate a full charge, Whitcomb said.

The chargers will be free for the first two years, Whitcomb said, thanks to corporate sponsorship.

The parks run from Berrien County, at the very southwest of Michigan and the closest locale to Chicago, to Emmet County at the tip of the Lower Peninsula at the Lake Michigan side of the Mackinac Strait.

There will be two chargers each in the state parks of Warren Dunes in Berrien County, P. J. Hoffmeister in Muskego County, Charles Mears in Oceana County, Ludington in Mason County, Orchard Beach in Manistee County, Leelanau in Leelanau County, Interlochen in Grand Traverse County, Young in Charlevoix County, and Petoskey and Wilderness parks and the Oden State Fish Hatchery in Emmet County.

Holland and Grand Haven parks in Ottawa County will receive four chargers each.

May 22, 2022

SPP, MISO Propose Scrapping Affected System Studies

MISO and SPP said Friday they plan to ditch their current affected systems study process for more interregional transmission analyses like their joint targeted interconnection queue (JTIQ) transmission effort.

The RTOs announced the transition to more transmission planning at the seams to allow generation interconnections during a conference call Friday.

“Essentially, we’re proposing a framework … whereby we believe the JTIQ and subsequent studies could serve as a replacement for the affected system studies,” SPP Director of Seams and Tariff Services David Kelley told stakeholders.

Kelley said for the current $1.65 billion JTIQ portfolio and other transmission studies to replace affected system studies, the new studies should occur at least every two years. He also said the grid operators’ proposal is proactive when considering FERC’s advanced notice of proposed rulemaking to improve transmission planning, cost allocation and generator interconnections (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“We’ve been listening to stakeholders over the last several months,” Kelley said. “MISO and SPP have reflected on these comments and concerns. … The affected system study process (AFS) is problematic, even from our perspective of administering these studies.”

Kelley said MISO and SPP have come to regard the AFS process as “a separate layer of inefficiency.”

“We need to design a more optimized transmission system around these seams,” he said.

While conducting the JTIQ study, Kelley said, MISO and SPP have noticed several similarities to the AFS: they detect the same constraints, seek to bring more generation online through transmission construction and dole out cost assignments for system upgrades to interconnecting generation.

The RTOs are attempting to distribute JTIQ portfolio costs based on the projects’ beneficiaries, including their respective loads, and a share to interconnection customers on either side of the seam whose generation will flow between the footprints. They have also said they might assign costs based on added benefits like increased flows or more economic dispatch. (See Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation.)

The grid operators have kicked around using a per-megawatt charge to allocate costs based on the interconnecting generation distribution factor’s effect on the JTIQ portfolio.

MISO and SPP intend to replace the AFS’ upgrade costs with the predetermined cost per megawatt

Kelley said, “more generation can afford to interconnect” under the new flat fee because it “eliminates unknown cost exposure from other RTOs.”

SPP’s Neil Robertson said the RTOs will determine the per megawatt charge for new generation based on the first JTIQ portfolio and refresh the amount in subsequent interregional transmission planning cycles.

“I just don’t want to see a situation where the charge escalates until load ends up holding the bag,” Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission, said of the fluctuating charge.

Stakeholders appeared to approve replacing the AFS, even though the RTO staffs admitted they still must work through several details.

“At a high level, I think this is a good step … and needs to happen to produce higher levels of certainty early on at the beginning of the process instead of the end,” Advanced Power Alliance’s Steve Gaw said.

“It’s a creative proposal, and I think it has the potential to introduce more timing certainty and cost certainty,” Clean Grid Alliance’s Natalie McIntire said.

But multiple stakeholders pointed out that the JTIQ study and cost-allocation design remains untested and unproven.

EDF Renewables’ Arash Ghodsian said he is worried that MISO and SPP might not be able to adhere to a biennial schedule.

“It is concerning that MISO and SPP spent two years evaluating this portfolio,” Ghodsian said.

Robertson said the RTOs envision the JTIQ becoming “a more enduring process” that’s conducted on a regular basis.

Under the proposal, the grid operators said they will likely create a “JTIQ affected system zone,” where they identify new transmission facilities near their seams that are likely to be impacted by their neighbor’s generation-interconnection requests. Nearby interconnecting generators will be assigned the per-megawatt charge based on their zonal impact. Staff said the zonal charge will be adjusted prospectively based on successive JTIQ studies.

Gaw said assigning costs to generators based on their zone seems like “rough justice.”

Kelley said the zonal method would eliminate individual developers depending on other higher-queued interconnection customers’ upgrades to get their own projects online.

Rafik Halim of National Grid Renewables asked how the RTOs will transition existing projects working their way through the respective queues to the new JTIQ charge. He said he was particularly concerned about the projects cycles that entered the MISO queue in 2018 and 2019 and have yet to receive AFS results from SPP.

“We have projects that are effectively being held hostage by an affected system study process,” he said.

Kelley said MISO and SPP have yet to work through a transition plan, but he said they will continue processing their queues until the new system can take effect.

“What MISO and SPP can’t afford to do is to put on hold any of our current study processes,” Kelley said.

The RTOs promised more meetings on the proposal beginning next month.

MISO Director of Resource Utilization Andy Witmeier asked stakeholders to provide their input on the proposal

“We want to really see if this new avenue is worthwhile,” he said.

May 22, 2022January 20, 2024

FERC Clears GridLiance Offload of Missouri Transmission Assets

FERC last week approved GridLiance High Plains’ sale of controversial Missouri transmission assets to the nonprofit Missouri Joint Municipal Electric Utility Commission (MJMEUC) (EC22-24).

The commission ruled Thursday that GridLiance’s deal for a 4-mile, 161-kV line, four small 69-kV lines and terminal equipment is in the public interest. The transaction marks MJMEUC’s first foray into transmission ownership; it already owns generation in MISO and SPP.

GridLiance purchased the transmission facilities from the city of Nixa, Mo., in 2018 and placed them under SPP’s control. The transmission-only utility has been involved in an unresolved dispute with the RTO and some of its members over the facilities’ inclusion into one of SPP’s transmission pricing zones. GridLiance’s annual transmission revenue requirement for the facilities has raised costs for the zone’s other transmission customers. (See FERC Remands GridLiance ATRR Settlement.)

FERC considered ongoing disagreement as out of scope, sticking to narrow, predefined criteria to approve the sale. It said the sale will not adversely affect transmission rates, though MJMEUC said it will recover the assets’ net book value through its ATRR. The commission noted that ownership is changing hands from a for-profit business to a not-for-profit utility, which comes with a different capital structure, tax obligation and return on equity.

GridLiance estimated that MJMEUC’s ATRR is about 32% lower than its own because of the latter’s nonprofit status. The TO said the commission has lower administrative expenses and does not pay property or income taxes, thus enjoying a lower cost of debt.

FERC said the transaction won’t disturb competition, state or federal regulation, or wholesale power rates because the sale does not involve the transfer of generation facilities.

Nearby city utilities in Missouri and Arkansas involved in the SPP transmission pricing dispute — Paragould Light Water & Cable, Paragould Light Commission, Poplar Bluff Municipal Utilities, Kennett Board of Public Works, City of Piggott Municipal Light Water and Sewer, and the City of Malden — asked FERC not to presuppose that the transmission facilities will continue to be included in the zonal cost allocation.

The commission declined to address the request, explaining its order focused on the transaction and not the facilities’ rate treatment.

May 22, 2022

PJM MRC Preview: May 25, 2022

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Stakeholders will be asked to endorse proposed revisions to Manual 3: Transmission Operations resulting from a periodic review. The changes include updating stability limitation process language in accordance with FERC docket ER21-1802 and aligning language with the current TO/TOP matrix language.

C. The committee will be asked to endorse proposed revisions to Manual 11: Energy & Ancillary Services Market Operations, Manual 12: Balancing Operations and Manual 28: Operating Agreement Accounting addressing conforming changes for stability limits in markets and operations. FERC ruled in February that PJM has the right to refuse lost opportunity cost payments to generators that are temporarily required to limit output to prevent loss of synchronization and additional strain on the system during transmission outages. (See FERC: PJM Right to Block Gen Stability Limit Payments.)

D. Members will be asked to endorse proposed revisions to Manual 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis addressing an effective load-carrying capability model run timing update. PJM rules allow voluntary submission of unit-specific wind and solar parameters for development of backcasts for newer resources, but current manual language has an expiration date of March 1 for voluntary submissions. The quick fix would remove the March 1 expiration date.

E. Stakeholders will be asked to endorse proposed revisions to Manual 36: System Restoration resulting from a periodic review. The minor changes include replacing System Restoration Coordinators Subcommittee with System Operations Subcommittee and updating the under-frequency load shed table with new data.

Endorsements (9:10-10:20)

1. Start-up Cost Offer Development (9:10-9:30)

The committee will be asked to endorse a revised PJM/Independent Market Monitor proposal addressing start-up cost offer development worked on through the Cost Development Subcommittee, including revisions to the tariff, Operating Agreement and Manual 15: Cost Development Guidelines. Stakeholders endorsed the proposal at the Market Implementation Committee’s meeting April 13. (See “Start-up Cost Offer Development Endorsed,” PJM MIC Briefs: April 13, 2022.)

2. Dynamic Line Ratings (9:30-9:50)

Members will be asked to endorse a proposal — and corresponding revisions to Manual 1: Control Center and Data Exchange Requirements, Manual 3: Transmission Operations and Manual 3A: Energy Management System Model Update and Quality Assurance — to address interim measures for the integration of dynamic line ratings (DLRs) into PJM operations. PPL is tentatively scheduled to go live in June with a DLR system on some of its transmission lines, and PJM wants to have operational implementation in place pending submission of the RTO’s FERC Order 881 compliance filing.

3. Application of Designated Entity Agreement (9:50-10:20)

Stakeholders will be asked to endorse a proposed solution and corresponding OA revisions addressing the application of the designated entity agreement. FERC rejected a filing in February by PJM in its Order 1000 compliance docket that would have updated the definition of “designated entity,” agreeing with a coalition of stakeholders that it infringed on their due process rights. (See FERC Rejects PJM Redefinition of ‘Designated Entity’ Under Order 1000.)

May 22, 2022

FERC OKs MISO’s Bifurcated Cost-allocation Tx Design

FERC last week approved MISO’s separate-but-equal postage stamp rate divided between its Midwest and South footprints for some of its major transmission buildout. The Thursday order gives MISO a clear-cut cost allocation for its long-range transmission plan’s (LRTP) first two cycles of projects (ER22-995).

The 100% postage stamp-to-load rate will be used to divide costs on MISO’s $10 billion long-range transmission package, the first of four portfolios the RTO plans to recommend. (See MISO Updates Stakeholders on $10B Long-range Tx Package.)

MISO will limit cost sharing on the first half of its LRTP projects to MISO Midwest, where the projects will be physically located, thus shielding its southern states from the transmission costs. The grid operator has said the allocation design is temporary and that it will seek approval for a new cost-allocation design when it begins studying transmission needs in MISO South and increasing its Midwest-to-North transfer constraint in a few years. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)

FERC said that MISO’s proposal to limit regional cost assignments is fair because it follows the commission’s cost-causation principles that benefits be roughly commensurate with allocation. The agency cited a Brattle Group analysis commissioned by MISO that showed the benefits of Midwestern transmission projects would be overwhelmingly confined to the Midwest unless the RTO secures more transfer capability between the subregions. (See MISO Finalizes Long-range Tx Cost Sharing Plan.)

The design “appropriately reflects the transfer limits between the Midwest subregion and the South subregion,” the commission said.

FERC also noted that MISO replicated its established cost allocation from its 2011 Multi-Value Projects to divvy up long-range transmission costs.

MISO’s clean energy organizations called the allocation design a “prudent interim solution to the transfer limits.” However, industrial customers argued that the RTO didn’t present enough evidence that it will allocate costs commensurate with benefits. They also derided MISO’s method of analyzing the first cycle of transmission projects as a portfolio instead of individually and said applying a uniform postage-stamp-to-load rate is clumsy because project benefits fluctuate over time.

The Mississippi Public Service Commission agreed with separating the Midwest from the South but asked that FERC not consider the postage stamp rate as the default method when MISO begins prescribing projects for its South region. The PSC said it would protest the rate as not specific enough if it were applied to Southern projects.

FERC disagreed and said the postage stamp is an appropriate allocation tool. The commission quoted itself from Order 1000 and reminded industrial customers and the PSC that a postage stamp method is “appropriate where all customers within a specified transmission planning region are found to benefit from the use or availability of a transmission facility or class or group of transmission facilities, especially if the distribution of benefits associated [therewith] is likely to vary considerably over the long depreciation life of the transmission facilities amid changing power flows, fuel prices, population patterns and local economic considerations.”

The commission also reminded Mississippi that the postage stamp rate is already the default allocation style under MISO’s past Multi-Value Projects, even though that portfolio predated MISO South’s integration and none of those project costs were ever assigned to the South. FERC said it considered the PSC’s ask a collateral attack on its past rulings.

FERC pointed out that the U.S. Seventh Circuit Court of Appeals has held that FERC “need not ‘calculate benefits to the last penny, or for that matter to the last million or ten million or perhaps hundred million dollars,’ but rather must have ‘an articulable and plausible reason to believe that the benefits are at least roughly commensurate with’ the allocation of the costs.”

The commission also blessed MISO’s portfolio approach to the LRTP and again referenced itself, this time quoting from its acceptance of the RTO’s portfolio style for its 2011 Multi-Value Projects.

“The portfolio approach will help [MISO] to prioritize its transmission expansion projects in such a way as to ensure global benefits from the projects afforded regional cost sharing and maximize the number of system users who will share in those benefits,” the commission said.

FERC also dismissed as premature some stakeholders’ concerns that MISO would design a different and more favorable cost allocation for the South, thus violating FERC’s cost allocation principle that inconsistent allocations must not be applied to the same class of projects. The commission said that was speculation because MISO has yet to develop the cost allocation it plans to apply for projects concerning MISO South.

Christie’s Cautious Concurrence

Commissioner Mark Christie wrote separately to concur with the order, hinting that MISO may not be doing enough to ensure thorough cost allocation.

“In a large, geographically sprawling transmission entity — MISO stretches from the Gulf of Mexico to Canada — it simply makes sense to allow for more granular cost allocation arrangements that may be subregional rather than imposing an identical cost allocation framework across the entirety of MISO,” Christie wrote.

However, he expressed misgivings with the “pure socialization” of the postage stamp rate and said he hoped MISO and stakeholders could arrive at a more granular allocation for the second half of the long-range transmission effort.

“While MISO’s case for postage stamp cost allocation is weak, I do not believe there has been a showing that this method is unjust and unreasonable,” he said, adding that he was ultimately swayed by the Organization of MISO States’ support of the allocation’s design.

Christie said he is concerned that Brattle’s benefits spread analysis rested on MISO’s internal benefit evaluation of its Multi-Value Project portfolio, and not an outsider’s view of the projects’ benefits. The Brattle Group’s Johannes Pfeifenberger “apparently accept[ed] the benefit-cost ratios in MISO’s 2017 report as self-proving,” Christie said.

He added that the Brattle Group should not accept MISO’s benefit claims “on faith,” especially when billions of dollars are at stake.

“There is nothing in the record to indicate whether MISO’s 2017 analysis was ever introduced into evidence in a rate case or other formal proceeding; whether discovery by other parties ever took place to glean information about the methods, bases and benefit calculations of the 2017 analysis; whether it was ever sponsored by a witness who had to take the stand and be cross-examined on the report by lawyers who knew how to conduct cross; or whether other parties had the opportunity to put their own expert witnesses, friendly and hostile, on the stand who could testify about the MISO analysis,” Christie wrote. “Indeed, ideally, a third-party report without a witness who can authenticate it and be cross-examined on it would not even be admitted as evidence in any serious evidentiary proceeding … the evidence in support of assigning billions of dollars in new costs to consumers should certainly get the same scrutiny as in a routine rate case involving far lower amounts of costs.”

Christie urged “state regulators and all affected stakeholders throughout MISO, especially those representing both residential and industrial consumers, to scrutinize very closely the planning criteria and cost allocation for future [long-range portfolio cycles] as well as claims of projected benefits used to justify regional cost allocation proposals because billions of dollars of consumer costs will be allocated here.”

May 22, 2022June 14, 2023

Ex-ERCOT CEO Hopes Focus Stays on Reliability

Bob Kahn, TMPA | Texas RE

Former ERCOT CEO Bob Kahn on Wednesday said he hopes Texas regulators and lawmakers continue to focus on reliability as they move ahead with changes to the state’s power market.

Addressing the Texas Reliability Entity Board of Directors’ quarterly meeting, Kahn said the market is working well and that suggestions for a capacity market — a verboten concept in Texas — or even a capacity-light market would do little to help reliability.

“I don’t know how much it might increase reliability, but I think it would increase costs for ratepayers,” he said. “That’s a big concern for the commission and all of us who want to keep rates as low as possible. We just need to make sure there’s enough money out there for the generators.”

Kahn noted that ERCOT’s energy-only market is dependent on high prices during scarcity periods, the theory being that those prices will compensate generators that are running and incent more to be build. However, the Public Utility Commission last year dropped the $9,000/MWh cap to $5,000/MWh when prices stayed at their limit for more than four days during the winter storm. ERCOT’s conservative operations approach, in which it procures more reserves than it previously had, has also reduced scarcity.

“The more reserves you have, the more it impacts scarcity. Generators are counting on those few hours a year,” Kahn said. He also argued that operating reserves are suppressing market prices, an opinion shared by others in the market.

Kahn, who served as ERCOT’s CEO for almost two and a half years (2007-2009) and was a director on the grid operator’s early Board of Directors (2002-2006), was involved in the energy-only market’s construct from the very beginning. He recalled a market-design meeting in the 1990s that was crashed by Texas Lt. Gov. Bob Bullock.

“He said five words: ‘This is all about money.’ He was right.” said Kahn, now general manager of Texas Municipal Power Agency, a nonprofit owned by its four-member cities of Bryan, Denton, Garland and Greenville.

Staff in ‘Shields-up’ Posture

Texas RE CEO Jim Albright said the organization is maintaining a “shields up” philosophy against cyber threats, and he encouraged the industry to do the same.

“Given what’s going on overseas and the uptick in ransomware across the world, as tensions get high, we should be on high alert,” he said. “The major alerts coming out this year are from Russian state sponsored cyber threats. So obviously, given what’s happening overseas, there’s been an uptick.”

Albright said the federal Cybersecurity and Infrastructure Security Agency’s cyber alerts this year are on pace to pass last year’s. Seven of those have come out of Russia, he said.

“There’s a lot of ransomware and a lot of malware. … They’re exploiting basically vulnerabilities,” Albright said. “Some of the big ransomware, the big players, if you will … started back in 2017, and we’re still seeing these type of things in the United States.”

Registered Entities up to 289

Staff told the directors that Texas RE has added 38 registered entities since 2020. It now has 289 registered entities in 516 functions. (Entities can register in any of six functions.)

The board approved its 2023 business plan and budget and a clean audit of its financial statements. The budget, up 3.3% to $17.7 million from 2022’s $17.2 million budget, will be sent to FERC and NERC in June. Texas RE’s statutory assessment in 2023 will be $17.2 million, a 14.3% increase from the 2022 assessment of $15 million.

The RE’s 2022 workplan has five focus areas:

expand a risk-based focus in standards, compliance monitoring and enforcement programs;
assess and accelerate steps to mitigate known and emerging risk to reliability and security;
build a strong Electricity Information Sharing and Analysis Center-based security capability;
strengthen engagement across North America’s reliability and security ecosystem; and
promote effectiveness, efficiency and continuous improvement.

May 22, 2022December 7, 2023

MRO Annual Reliability Conference Spotlights Need for Generation and Transmission

Midwest Reliability Organization’s annual reliability conference last week emphasized the inevitability of the transition to clean energy and avoiding future supply shortfalls with more generation and transmission.

“I don’t have to tell you that we’re seeing a transition in the resource mix,” Mark Lauby, NERC senior vice president and chief engineer, told conference attendees Wednesday.

Lauby said it’s not that today’s fuels are “inherently less secure,” but they are more uncertain. He said reliability should extend beyond the one day in 10-year standard to more multidimensional rules of thumb. He also said he “very forcefully believes” that the country is going to need more transmission projects, although they may be difficult to build.

Lauby said the grid needs more energy, not capacity, to serve future load.

“Capacity was king, but the king has no clothes,” he said. “It was a good trick and we got away with it for a while.”

MRO COO Richard Burt said energy and load are now unreliable variables, to the point where he questions reserve margins. He said that from 2010 to 2020, capacity in North America has dropped by 23 GW while load has grown by 85 GW.

“We’ve created a 100-GW gap,” Burt said.

Currently, MRO estimates that its footprint contains almost 51 GW of wind generation and about 1 GW of solar generation between MISO, SPP, Saskatchewan Power and Manitoba Hydro. But those entities’ interconnection queues show that 43 GW of wind generation and a whopping 102 GW of solar are planned by 2031.

“We could have more solar than wind in 10 years,” Burt said, adding that if all the potential solar is built, it will cover a surface area that spans “all the Disney parks” 40 times over.

Lauby said the transition to renewables is a “good thing” for the country but will require a rethink of reliability.

“It’s time now to no longer admire the problem. It’s time to solve the problem,” he said, noting solutions will require participation from not only the industry, but also state and federal government.

NERC’s Energy Reliability Assessment Task Force might lean toward requiring a new energy reliability assessments standard, Lauby said, but NERC must tread carefully and continue to abide by its policy of not prescribing generation or transmission construction.

“If shedding load is the answer, then that’s the answer,” Lauby said.

Mark Ahlstrom, NextEra Energy Resources’ vice president of renewable energy grid integration, called the resource shift “huge and inevitable.” He said that although “there’s no shortage of technology” to aid the transition, wholesale markets will have to adapt to the disruption.

“We’re talking changing not just the hardware, but markets. … It can be overwhelming, or it can be fascinating,” Ahlstrom said.

He said every renewable energy prediction that the U.S. Department of Energy or the National Renewable Energy Laboratory issued about 15 years ago has now been “far exceeded.” He also pointed out that the nation had about 100 years to perfect reliable electricity delivery using thermal generation.

“It’s not that they were prefect; they have their quirks,” Ahlstrom said of thermal generators, adding that new software is necessary to furnish services that complement clean energy sources.

Despite supply chain issues and solar panel tariff disputes with China, Ahlstrom was bullish on investing in renewable energy and storage facilities. He predicted that prices on commodities like gas, oil and coal will continue to rise.

He said grid operators’ GI queues are hampering new generation and the wait times are so long that some study models must be revised because better technology options are available by the time generation can connect. He said a five-year IC timeline doesn’t make sense when inverters available to developers change and advance about every two years.

Ahlstrom criticized MISO and SPP’s affected system study process for being inconsistent, sluggish and resulting in pricey network upgrades that upend projects.

“We can’t build a future transmission system using band aids from one generator at a time,” he said. “If we’re going to get to [net-zero emissions by] 2050, we’ve got less than 28 years to build massive transmission.”

Ahlstrom said the nation can use an HVDC national backbone and, though it may be unpopular, a national transmission planning committee to recommend projects.

“Society will still do this; it’ll just be twice as expensive,” he said of the pendulum swing to clean energy.

May 22, 2022December 26, 2023

FERC Orders More Refunds from 2020 Western Heat Wave

FERC on Thursday continued to tell utilities to refund premiums they earned on top of extraordinarily high prices in August 2020 during a heat wave that strained the Western grid and caused blackouts in California.

The commission ordered Uniper Global Commodities North America, Tri-State Generation and Transmission Association, and Brookfield Renewable Trading and Marketing to refund premiums earned above the average index prices at the Palo Verde hub in Arizona and other market hubs on Aug. 18-19 (ER21-62, ER21-65 and ER21-59).

The average index prices at Palo Verde of $1,400.50 on Aug. 18 and $1,639.60 on Aug. 19 resulted from scarcity conditions. Premiums above the index prices were unjustified, even though buyers offered the premiums as an inducement to sell to them, FERC said.

Tri-State, for example, sold 150 MW of electricity to Arizona’s Salt River Project for $1,500/MWh on Aug. 18 and for $1,700/MWh on Aug. 19, more than the average prices at Palo Verde.

In contrast, the average price at Palo Verde from June to August 2020, excluding the high prices of Aug. 18-19, was $52/MWh, Southern California Edison and Pacific Gas and Electric said in protests to FERC.

“Tri-State’s rationale for its sales above the index price is that Tri-State was a price-taker, the sales were consistent with published market index prices, and the prices reflected emergency conditions due to record high temperatures in the Southwest,” FERC wrote. “However, the Palo Verde price index already reflects scarcity conditions, evident based on a comparison of the index prices on the days of Tri-State’s sales to the index prices for other days in August 2020.”

Sellers in the Western Interconnection, excluding CAISO’s footprint, are required to justify prices above WECC’s $1,000/MWh soft price cap, including premiums.

FERC said Macquarie Energy had failed to justify premiums above hub index prices and in some cases had failed to justify sales above the WECC soft price cap (ER21-64).

The commission denied motions by Macquarie and other sellers to raise WECC’s soft price cap to $2,000/MWh, the same as CAISO’s soft cap, saying the question was outside the scope of the proceedings.

It ordered all four sellers to make appropriate refunds within 30 days of the orders.

Thursday’s decisions followed seven similar orders in April for utilities to refund premiums for sales into CAISO on Aug. 18-19 as the ISO struggled to keep the lights on following rolling blackouts on Aug. 14-15. (See FERC Tells PacifiCorp to Refund Premiums and Sellers Urgse FERC to Raise WECC Soft Price Cap.) In those cases, FERC also denied motions to raise WECC’s soft price cap.

Commissioner James Danly dissented both in the April cases and in the latest batch, contending that FERC does not have the authority to “abrogate a contract to sell electricity pursuant to market-based rate authority when the contract price is above a commission-imposed ‘soft’ price cap, absent a finding that the public interest so demands,” Danly wrote in each case.

In all four cases decided Thursday, “buyers willingly purchased power during a reliability crisis at a modest premium above prevailing market index prices … [and] there is no showing in the record that these prevailing market prices seriously harmed the public interest,” he said. “Any such argument appears absurd on its face, particularly when internal CAISO prices are capped at levels much higher than the … contract price[s]” in the August 2020 heat wave.