AUSTIN, Texas — ERCOT’s Board of Directors last week added their endorsement of the Southern Cross Transmission (SCT) merchant project’s last three regulatory directives, imposed to determine whether it can safely interconnect with the Texas grid.
The project, a long-haul HVDC transmission line that would connect the Texas Interconnection with systems in the SERC Reliability region, has been under regulatory review for seven years. It will be capable of carrying 2 GW of power between Texas and SERC over a 400-mile, double-circuit 345-kV line.
More important to the Texas Public Utility Commission and the state’s leadership, SCT has FERC approval and a waiver from its jurisdiction, keeping ERCOT free of federal overview and maintaining its status as an island unto itself.
The project’s developer, Pattern Energy, called the board’s Aug. 16 action an “important milestone” and thanked ERCOT staff for completing the studies ordered by the PUC.
“Today’s action … represent[s] the completion of all studies ordered by the [PUC] to confirm the Project can be reliably interconnected with the ERCOT grid,” said Glen Hodges, Pattern’s vice president of business development. “Once completed, Southern Cross Transmission will provide substantial reliability benefits to all Texans who rely on the ERCOT grid, providing access to alternate sources of reliable and affordable power during emergencies such as Winter Storm Uri and the recent extreme heat-related demands on the grid.”
“For the last five years or so, we’ve been resolving the directives and getting this project ship shape,” ERCOT assistant counsel Nathan Bigbee said. “These last three [directives] get closure and regulatory certainty to move forward with this project.”
The directives are:
1: creates a new market participant type, “Direct Current Tie Operator.” A nodal protocol revision request (NPRR857) approved in 2018 created the DCTO role, but SCT has told the grid operator it does not plan to join an appropriate market segment at this time. That led staff to conclude no bylaw revisions are needed yet.
11: finds that costs identified by the PUC have been appropriately addressed by resolving each of the commission’s 14 directives and through a memorandum of understanding between ERCOT and SCT. Under the agreement, Pattern will fund the projects needed to accommodate the tie; it has already been compensating ERCOT monthly for related costs.
12: determines that costs associated with DC tie exports have been sufficiently addressed by the other directives’ resolution and that no further revision to any cost-allocation mechanism is necessary.
Bigbee told directors that SCT will affect voltage on the eastern side of ERCOT’s system. He said an NPRR will need to be drafted to ensure the project provides voltage support in the region.
The PUC asked ERCOT to address 14 directives and determine whether DC ties should be economically dispatched or subject to a congestion-management plan. Only Directive 2, which requires the grid operator to enter a coordination agreement with the balancing authority on the project’s eastern end, has not been completed. The project’s developers have said that directive is not necessary to the commission’s review and can be closed later.
Garland Power & Light owns the project’s western endpoint and holds a certificate of convenience and necessity granted by the PUC in 2017. The project developers have not yet announced an eastern endpoint.
PUC Commissioner Jimmy Glotfelty has taken the agency’s lead on SCT and filed a memo in January that said it’s time that the commission and ERCOT “close a chapter” on the project and allow it to “stand or fail on its own economic merits.” He believes the review can be finished by the end of October (46304). (See Texas Regulators Boost Southern Cross Project.)
SCT supporters got a minor scare when Board Chair Paul Foster mistakenly tried to bring the meeting to an early end just before the project was due to be discussed.
“So that concludes our agenda, and we are now adjourned. Thank you all,” Foster began before he was quickly interrupted.
“No, no. Sorry … we have a few more voting items,” ERCOT General Counsel Chad Seely said, keeping the meeting on track.
Grid United Files CCN in West Texas
A second HVDC merchant project is taking shape on the western side of ERCOT’s system, where Grid United, led by a familiar face, has applied with the PUC for a CCN (53758).
Grid United’s Pecos West project consists of two proposed 1,500-MW HVDC converter stations in ERCOT’s West Texas region (near Bakersfield) and El Paso in WECC territory. The project would bridge two Texas markets with 250 to 300 miles of an HVDC intertie line.
The company was founded last year by Michael Skelly, who serves as its CEO. Grid United says it seeks to tie regional grids together to improve resilience, increase the reliability of cheap renewable energy and reduce health hazards from fossil fuel energy production.
Skelly was also behind Clean Line Energy Partners, another long-haul developer that was working on five projects at one time, capable of carrying 16.5 GW of energy. Faced with political, regulatory and landowner opposition, Clean Line eventually was forced to sell most of its projects and was out of business by 2019. (See Out of the Game, Skelly Still High on Wind Energy.)
“Texas is blessed with an evolving and abundant power supply. … However, this abundance presents unique challenges, including volatile commodity prices and reliability concerns due to market structures that were not designed for the evolving energy mix the Texas grid is faced with today,” Skelly said in testimony filed with the PUC.
“These challenges, which are especially acute in West Texas where renewable generation has proliferated, will only increase over the decades to come unless steps are taken proactively to address them,” he said.
Grid United’s Texas subsidiary is only seeking approval of the interconnection and will file for full CCN rights once the interconnection is approved. The company says it will obtain all necessary FERC approvals to maintain ERCOT’s jurisdictional status quo.
Former FERC and Texas PUC Chair Pat Wood says the federal commission has policies that would protect the Texas Interconnection from federal interference if it were to strengthen its existing connections to the two national grids.
“We have the ability to build gates to the outside and not become vassals of another king,” Wood said during a panel discussion earlier this year. “We [would still be] in charge of our own grid — and that was built into the federal law.”
Transmission developer LS Power was unsuccessful twice with the D.C. Circuit Court of Appeals last week in separate attempts to force MISO to open more projects to competition.
LS Power had sought appeals on two FERC complaints, one where it challenged FERC’s repeated refusal to compel MISO to lower its voltage threshold of competitive economic projects from 230 kV to 100 kV; and another where it contested MISO’s practice of not cost sharing baseline reliability projects (BRPs) beyond the transmission pricing zone in which they’re located.
In a pair of rulings issued Aug. 19, the D.C. Circuit Court declined to order FERC to revisit its rulings. It said the commission reasonably accepted 230 kV as the market efficiency project threshold (20-1465) and similarly acted sensibly when it kept the cost sharing of BRPs limited to the transmission pricing zone in which they’re physically located (20-1421).
LS Power argued to the D.C. Circuit Court that its business will suffer if MISO is allowed to keep the voltage threshold and local cost sharing of regionally beneficial BRPs in place. The company said those criteria deny it the opportunity to participate in more competitive solicitations for transmission projects.
MISO in 2020 overhauled its cost allocation procedures, lowering the voltage threshold for market efficiency projects that are regionally cost shared from 345 kV to 230 kV, adding two new benefit metrics and eliminating a 20% footprint-wide postage stamp allocation. (See MISO Cost Allocation Plan Wins OK on 3rd Round.)
FERC rejected LS Power’s rehearing requests and complaint that a further reduction to the kilovolt threshold to 100 kV was necessary, concluding that the 230 kV threshold would spur more economic projects and sufficiently expand the number of them eligible for competition. (See La. and Miss. Join MISO, TOs in Opposing Cost Sharing at 100 kV.)
FERC likewise refused LS Power’s joint 2020 complaint with the the Coalition of MISO Transmission Customers and the Industrial Energy Consumers of America, which alleged that MISO’s nearly 10-year old location-based cost allocation methodology for BRPs doesn’t comport with the commission’s principle that beneficiaries of transmission projects should pay for them.
In MISO, BRP costs are allocated only to local transmission pricing zones where project facilities are physically located; costs are recovered by the transmission owners developing the projects. They are not open to competitive bidding.
The court said LS Power’s examples of BRPs with benefits spillover “was limited to a relatively small number” and “did not necessitate a categorical finding that location-based cost allocation is unjust and unreasonable.” It said LS Power’s “crown jewel of new evidence” was a report containing a line-outage analysis that showed of 29 baseline reliability projects approved by MISO between 2013 and 2018, 12 showed they could deliver more than “de minimis” benefits beyond their transmission pricing zone.
The court added that FERC “need not consider cost allocation rules on a project-by-project basis, which would unravel the framework of ex ante tariffs established by Order 1000.”
In its voltage threshold ruling, the D.C. Circuit Court also rejected LS Power’s ask that MISO be prohibited from employing an “immediate need reliability exception,” where the RTO can bypass a competitive solicitation process for certain urgently needed reliability projects. The court borrowed a line from FERC’s Order 1000, noting that “if the time needed to solicit and conduct competitive bidding would delay the project and thereby threaten system reliability, then competitive bidding would not be required.”
CAISO issued a revised straw proposal last week for its planned day-ahead expansion of the Western Energy Imbalance Market, currently a real-time market that covers large portions of 10 states and one Canadian province.
The updated proposal, released Aug. 16, adds provisions on transmission commitment, resource sufficiency and firm energy contracts following a series of technical workshops and stakeholder meetings to iron out differences on the more difficult issues.
“This revised straw proposal for the extended day-ahead market (EDAM) reflects significant stakeholder input and design changes from the initial April 28, 2022, straw proposal,” the ISO said. (See CAISO Issues EDAM Straw Proposal for the West.)
Among the major changes are refinements to the EDAM’s proposed transmission commitment framework.
The initial straw proposal stated that unsold, firm available transfer capability (ATC) should be offered by EDAM participants to support transfers between balancing authority areas (BAAs) in the West.
An EDAM entity would be expected to “make available all remaining unsold firm ATC at an intertie with an adjoining EDAM BAA” by 10 a.m. in the day-ahead market and to stop open-access transmission tariff sales of firm ATC at the intertie between 10 a.m. and 1 p.m. while the day-ahead market was running, it said.
The EDAM could extend across much of the territory now included in the WEIM’s real-time market. | CAISO
Stakeholders and the ISO, however, did not settle on some specifics of the plan.
The revised straw proposal says that “unsold transmission by the transmission provider will be made available to the market hurdle-free. Transmission customers can voluntarily release transmission rights for EDAM optimization, and the ISO will allocate transfer revenue associated with those rights directly to the transmission customer.”
“The design also includes a proposed mechanism for transmission providers to recover potential foregone transmission revenues resulting from their participation in EDAM. This seeks to keep transmission providers as whole as possible from a transmission revenue recovery perspective.”
Resource Sufficiency
The proposal for a resource sufficiency evaluation (RSE) in the EDAM was left partially incomplete in April. The RSE test is intended to keep participants from leaning on the market for internal capacity needs, but consequences for failing the test — one of the most controversial issues in the EDAM stakeholder process so far — were not delineated in the first straw proposal.
Stakeholders had discussed financial penalties and transfer limits but did not reach agreement.
“Although there was no consensus regarding a particular approach, stakeholders generally preferred some form of financial consequence for failure, rather than a complete freezing of transfers in the day-ahead time frame, which could be detrimental to reliability,” the straw proposal said.
After multiple technical workshops, the revised straw proposal “focuses on an administrative surcharge[s] under all conditions to incentivize meeting the RSE. It also introduces mechanisms to address ISO [load-serving entities’] concerns regarding their discretion to manage supply above what the ISO needs to meet its RSE to better manage grid reliability challenges if conditions change between day-ahead and real-time.”
Firm Energy Contracts
The revised proposal also introduced a “tagging mechanism,” a means of electronically monitoring and recording an energy transaction, for firm energy contracts.
In a firm energy contract, the “supplier takes on the obligation to deliver the generation and make the necessary transmission arrangements” to get the supply to the purchasing or sink BAA, but “neither the source of the generation (or source BAA), nor the transmission path is known by the time of the day-ahead market (10 a.m.) when bids into the market are due.” That information “becomes known later,” it said.
“In a day-ahead market context, the lack of source specificity and transmission path pose a challenge in modeling the expected flows across the system,” it said. “Nevertheless, the ISO recognizes these arrangements are an important source of supply in the West today.”
Uncertainties about source and transmission require a tagging mechanism to “provide greater confidence in these arrangements,” it said. “Intertie bids at the ISO border that are under contract to an ISO LSE or otherwise have a contract under the ISO tariff will be eligible for the ISO RSE and will also be subject to the tagging requirements.”
Additional Features
Other provisions in the revised straw proposal include:
a convergence bidding proposal that maintains a one-year transition period to convergence bidding for EDAM entities. “After that first year, the EDAM entity will have the option to adopt convergence bidding in their area or elect for another year of transition,” it says. “After the second transition year, an EDAM entity would be expected to transition to convergence bidding, absent any findings that doing so poses adverse outcomes.”
an equal sharing of transfer revenues “across all interfaces between EDAM BAAs, subject to commercial arrangements that may require exceptions. In addition, in instances where congestion arises from an internal intertie constraint enforced within a BAA, the ISO will allocate the congestion revenue fully to the BAA where the constraint is modeled.”
a greenhouse gas accounting and reporting protocol in which the EDAM will start with a “resource specific approach to GHG accounting because this is a known, implementable approach that California ISO builds upon and enhances the current WEIM framework. Throughout this initiative, however, we will continue to vet and evaluate the alternate approaches.”
an EDAM administrative fee arrangement under which a “systems operations charge will be applied to metered flows in megawatt-hours of supply and demand. This is a similar assessment to the grid management charge system operations charge.”
Meetings to discuss the revised straw proposal are scheduled for Aug. 29 (virtual only) and Sept. 7-8 (virtual and in person.) The EDAM stakeholder initiative webpage contains additional information on the upcoming meetings and anticipated EDAM development milestones.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on 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.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Members will be asked to endorse revisions to Manual 6: Financial Transmission Rights as part of a periodic review and changes to conform with tariff revisions intended to increase transparency into and the efficiency of the RTO’s auction revenue rights and financial transmission rights markets. The changes were approved by FERC in March (ER22-797). (See FERC Accepts PJM ARR/FTR Market Changes.)
Endorsements (9:10-10:15)
1. Variable Environmental Costs and Credits (9:10-9:35)
The MRC will be asked to approve a proposed update to rules governing variable environmental charges and credits and their inclusion in cost-based energy offers. Generation units receiving production tax credits or renewable energy credits must reflect them in their fuel-cost policies when submitting non-zero cost-based offers into the energy market. The changes will include revisions to Manual 15: Cost Development Guidelines and Operating Agreement Schedule 2. (See “Variable Environmental Costs and Credits,” PJM MIC Briefs: May 11, 2022.)
The MRC will cast advisory votes on four alternative sets of capacity auction parameters as part of its 2022 Quadrennial Review. Members will be asked to select one of the packages from PJM, the Independent Market Monitor, Calpine and Cogentrix for a recommendation to the Board of Managers consideration. (See “2022 Quadrennial Review,” PJM MRC/MC Briefs: July 27, 2022.)
FERC last week accepted SPP’s proposed tariff revisions to add an uncertainty reserve product to its Integrated Marketplace (ER22-914).
SPP said the product will address the need for flexible capacity when realized generation, load and net scheduled interchange deviate from its forecasts. The rising penetration of renewable resources in the RTO’s resource mix has increased the variability that it must manage in its market and reliability operations, it argued.
The RTO will procure uncertainty reserves by reserving a portion of a dispatchable resource’s upward ramping capability to address increasing net obligations in future dispatch intervals.
Resources that can follow real-time dispatch instruction and increase and maintain its output, once the specified output is met, for at least one hour can provide the product. That applies to both online and offline resources.
The grid operator’s resources will make themselves available through self-certification but can opt out with qualification and dispatch status. SPP will derive the value of resources clearing online uncertainty reserve using a loss-of-opportunity metric, similar to how it treats its existing ramp capability-up product. Offline resources offering uncertainty reserves will have an offer cap of $1,000/MW and a $0/MW floor; a demand curve will price the product when its availability on the system is scarce.
The RTO will impose a nonperformance penalty on resources when cleared real-time uncertainty reserves does not operate in a responsive manner.
SPP’s Market Monitoring Unit intervened in support of the RTO, saying the changes would significant improvements over manual commitments and will provide a market solution for midterm ramp capacity. That will result in increased flexibility to meet ramping needs, increased price accuracy for online resources and increased price transparency of ramping capacity’s value, the MMU said.
In its Aug. 16 order approving the proposal, FERC agreed with SPP’s request for a placeholder effective date so that it can develop the necessary software changes to implement the revisions. The grid operator expects the changes to be ready later this year and committed to specify the effective date at least 30 days in advance.
The tariff revisions were filed with FERC after the SPP Board of Directors and stakeholders approved the proposal in July 2021 after several years of development. The uncertainty reserve product was one of 21 recommendations made in 2019 by the Holistic Integrated Tariff Team. (See “Uncertainty Product Endorsed,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)
FERC’s proposed overhaul of its transmission planning and cost allocation rules received mostly supportive comments from industry stakeholders, but some criticized its requirements as overly prescriptive and said 20-year planning horizons could lead to speculative and unnecessary projects.
Stakeholders also disagreed sharply over whether the commission should reinstitute a federal right of first refusal (ROFR) for incumbent transmission owners.
More than 180 comments had been filed by utilities, public interest groups, industrial consumers, RTOs and ISOs and state officials by Wednesday’s 5 p.m. ET deadline (RM21-17). Reply comments are due Sept. 19.
Congestion across regions is often higher than congestion within regions, suggesting interregional transmission could produce economic gains, Lawrence Berkeley National Laboratory found. | Lawrence Berkeley National Laboratory
The Notice of Proposed Rulemaking, approved by the commission April 21 on a 4-1 vote, would direct transmission providers to identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects.
The NOPR said the new rules would help planning entities prepare for the growth of renewables, new sources of demand such as electric vehicles and extreme weather events, expected to increase as climate change worsens. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
As always, numerous commenters urged the commission to allow regional flexibility and not to impede innovations already being pursued.
The ISO/RTO Council (IRC), representing the six FERC-regulated grid operators, said “many” of its members already engage in “long-term planning … or have ongoing initiatives” to develop such procedures. MISO, CAISO, NYISO and SPP employ a 20-year horizon in at least some of their planning processes, while PJM uses 15 years and ISO-NE uses 10 years, the IRC said.
The IRC said the commission was “overly prescriptive” on some issues.
“The proposed rule is very focused on process but needs to provide more clarity on how these processes produce actionable results,” the IRC said. “Without discretion to adapt the scenarios, factors and benefits to regional circumstances, the final rule could end up leading to more conflict, rather than useful transmission planning for needed infrastructure. Instead of prescribing detailed procedures, the IRC believes that the final rule should state high-level, long-term planning principles that transmission planners must consider, and then authorize them to craft their own processes that are tailored to their regional needs.”
ISO-NE cautioned the commission against setting uniform implementation requirements for long-term scenario analyses or “hardwiring these details into the region’s tariff.”
“In ISO’s experience with transmission planning based on scenario analysis, these actions will limit the efficacy of the studies,” it said.
SPP added: “If the commission specifies requirements that are expansive in scope and prescriptive in detail, this could become duplicative with SPP’s current processes and initiatives and place unnecessary burden on the future state of SPP planning.”
20-Year Planning Horizon
Commenters — including Minnesota’s Public Utilities Commission and Department of Commerce, the SPP Market Monitoring Unit and the U.S. Department of Energy — endorsed FERC’s call for a minimum 20-year time horizon for transmission planning, with reassessments and revisions to the scenarios at least every three years.
“Traditional transmission solutions that benefit an entire region can take more than a decade to site, permit, and construct and require planning that is more than a decade into the future. Creating long-term scenarios that are at least 20 years into the future will capture power sector changes that occur during transmission development,” DOE said. “However, for the evaluation period, the department encourages the commission to consider requiring an evaluation of transmission costs and benefits over a minimum of 30 years after in-service dates rather than the 20 years proposed in the NOPR.”
But others, including the Nebraska Power Review Board, said any 20-year horizon should be used only for guidance and not to identify transmission upgrades.
“While there is no crystal ball when it comes to transmission planning for the future, PJM continues to believe a 15-year planning horizon allows for sufficient time to identify, plan, and obtain siting and permitting approval and to construct regional transmission facilities while reducing input assumption risks associated with a 20-year horizon,” the RTO said.
Industrial Energy Consumers of America, the American Forest & Paper Association, the PJM Industrial Customer Coalition and the Coalition of MISO Transmission Customers said “a 20-year planning horizon for new transmission has not been shown to be just and reasonable.”
NRG Energy (NYSE:NRG) said a 20-year planning horizon should be “only for purely informational purposes and not as a basis to mandatorily allocate investment costs.” It said a 10-year maximum planning horizon was more appropriate when applying involuntary cost allocation.
“While it is true that transmission development takes time and thus can be served by a longer view forward, it is also true that identifying a transmission project solution up to 20 years in the future could prove to be problematically speculative,” said the Electric Power Supply Association (EPSA). “A longer view could also lock in a specific approach to the detriment of any other solution that could be developed on a more timely basis or close the door to options for a transmission project that does not reach the final phase of development, which is all the more likely decades out. This could also prove to be short-sighted based on the pace of technological change.”
WIRES, which represents transmission providers and developers, said FERC should allow variances from the 20-year requirement “in order to account for regional differences or circumstances that would render such a timeline inappropriate.”
Non-profit GridLab said the NOPR “conflates the planning horizon with the time horizon over which benefits and costs are calculated in benefit-cost analysis (BCA).”
“FERC should clarify the distinction between the two … while maintaining requirements for a 20-year planning horizon and a 20-year period for BCA. The main benefit of a longer planning horizon will likely be capturing changes in transmission value (benefits) over a longer time horizon, which assumes that the value of regional transmission will look very different in the 2030s than it does today. There is indeed evidence that this will be the case, though some of the forces driving change in regional transmission value will increase value (e.g., growth in wind and solar generation, increased risk of extreme events), while others will decrease it (lower cost energy storage, growth in distributed energy resources). The balance can only be determined through rigorous planning and risk assessment.”
Grid-enhancing Technologies
FERC’s support for grid-enhancing technologies received wide support, but the Los Angeles Department of Water and Power (LADWP) said the commission’s singling out of technologies such as dynamic line ratings (DLRs) and advanced power flow control devices (APFC) “seems inappropriate.”
“Transmission providers should have the range of available technologies for evaluation of solutions to meet economic, reliability and security needs in their respective regions,” LADWP said. “A rule that specifically calls out certain technologies as solutions is in danger of being biased, prescriptive and incomplete.”
ISO-NE said FERC should not mandate use of DLRs in lieu of transmission. “This technology cannot substitute for transmission facilities needed to solve system needs,” it said.
Potomac Economics, which performs market monitoring for MISO, NYISO, ISO-NE and ERCOT, said the commission should also require transmission providers to consider transmission switching and network optimization in addition to DLR and APFC. “Like GETs, network optimization can allow a transmission operator to circumvent a limiting transmission facility and substantially mitigate the associated congestion. In this case, investing millions in upgrading such a facility could prove wasteful and inefficient,” it said.
The Working for Advanced Transmission Technologies (WATT) Coalition, a trade group supporting GETs deployment, asked the commission to be more prescriptive, saying it should “specifically require evaluation of APFC for thermal overloads that fall within 50% of the line rating” and for network upgrades for new loads.
Right of First Refusal
There was also no consensus on the commission’s proposal to allow incumbent transmission owners a federal ROFR on regional projects on the condition that they partner with an unaffiliated company with a “meaningful level of participation and investment” in the project. (See ANALYSIS: FERC Giving up on Transmission Competition?)
Among those opposing the proposal were Electricity Consumers Resource Council, which represents large industrial consumers, and EPSA.
“Rather than less independence and accountability, there must be more independence and accountability in regional transmission planning processes to ensure that all options are offered and assessed to meet expected cost and time parameters pursuant to the planning process,” EPSA said.
“Because competition serves to discipline costs, allowing the incumbent transmission utility to exercise a ROFR, even if done in partnership with another entity, could expose load to higher costs,” said the Pennsylvania Public Utility Commission. “To the extent that FERC determines that the elimination of the ROFR by Order No. 1000 resulted in transmission providers focusing on local projects rather than regional projects, the solution is not to appease incumbent transmission owners’ reluctance to engage in competition from nonincumbent transmission developers, by restoring the ROFR. … Such a mechanism clearly grants preferential treatment to the incumbent transmission providers and discriminates against competitive transmission developers, in violation of the principle of an ‘open’ transmission planning process, as articulated in Order No. 890.”
NRG said FERC should withdraw the proposal “and instead eliminate formula ratemaking and other aspects to its regulatory scheme that have caused transmission developers to avoid regional projects.”
Transmission owners and the Edison Electric Institute expressed support for a renewed ROFR.
“Although in some instances, the lack of a ROFR may have arguably increased the number of innovative and/or cost-effective transmission options for consideration, it has also caused delays and limited opportunities for dialogue between transmission developers, market participants and RTOs/ISOs, in addition to not delivering regional transmission projects under the time frames necessary to meet increasingly aggressive climate targets,” WIRES said.
NEPOOL said it does not have a formal position on the conditional ROFR but noted it has previously advocated for competitive processes for transmission development. “To the extent the final rule provides for a conditional ROFR, the commission should maximize the opportunities and requirements for competitive processes to be used within that construct,” NEPOOL said. “This objective could be achieved potentially through guidelines for the criteria to be used in establishing joint ownership and development of regional transmission facilities.”
The Minnesota agencies noted that the state’s legislature has backed a state ROFR and said FERC’s joint ownership model “would create additional complexity but is not likely to provide the anticipated innovation and cost-control benefits.” (See Courts Uphold Minn. ROFR, MISO Cost Allocation.)
“Continuing to clearly align the responsibility to construct, own and maintain the high-voltage transmission system in our state with the related decision-making authority that has been given to the responsible utilities remains the best ownership model, at least for now,” they said.
States’ Roles
State regulators and others urged FERC to let states take a central role in planning.
ISO-NE noted that the New England States Committee on Electricity’s role in determining the range of scenarios to be plugged into the grid operators’ studies. Therefore, ISO-NE said, “the states should be responsible for determining whether to move forward with transmission and the associated cost allocation method, with the ISO playing a supporting, technical role.”
FERC should “explicitly authorize or allow for … greater state involvement in all aspects of policy-based transmission planning — not just the criteria for selecting and methodology for allocating costs of long-term transmission facilities,” ISO-NE said.
“FERC should reframe long-term regional transmission planning as an informational process with no attendant project selection or construction obligations unless the affected state regulators first support such actions consistent with their regulation of the public utilities subject to their respective jurisdictions,” said the Alabama Public Service Commission.
The National Association of State Energy Officials praised FERC’s creation of the Joint Federal-State Task Force on Electric Transmission as a “welcome advancement of federal-state coordination.”
But it said “FERC’s engagement on these issues needs to include additional state agencies, such as state energy offices.”
A study released Wednesday by the New Jersey Board of Public Utilities of the ratepayer impact from the state’s ambitious Energy Master Plan concluded that clean energy-conscious residents could see a 16% cost reduction under the plan.
But one board members immediately rejected the report, saying it ignored key costs.
The report, by The Brattle Group, sought to address the long-running concern from business groups, Republicans and others that the state had never calculated the cost of the state pursuing an aggressive set of climate change policies outlined in Democrat Gov. Phil Murphy’s 2019 Energy Master Plan.
Brattle quantified the total energy cost in 2030 for average customers, compared to the cost in 2020, and then assessed the 2030 ratepayer cost in various scenarios. They included the cost to ratepayers who adopted no energy efficiency or clean energy measures, those who adopted some measures — such as switching from a gasoline-powered vehicle to an electric vehicle — and those who embraced all available clean energy initiatives.
BPU President Joseph Fiordaliso | New Jersey Board of Public Utilities
The report found that the average non-low-income residential customer spent approximately $4,800/year in 2020 for electricity and natural gas bills and fuel costs for driving a non-electric car. Without any changes to their energy use, that figure would rise 16.7% to about $5,600 in 2030. About half the increase would be from the cost of the state adopting clean energy measures and the other half from inflation, the report concluded.
But the same customer in 2030 would save an equivalent amount if the they drove an EV, electrified their home and adopted energy-efficiency measures, the study concluded.
“The key here is energy efficiency,” BPU President Joseph Fiordaliso said at the board’s meeting Wednesday, shortly before it voted 3-1 to accept the report. ”The report we’re accepting today demonstrates that energy costs will be reduced for those ratepayers who embrace energy efficiency and electrify their homes and vehicles.”
Commissioner Zenon Christodoulou, who only joined the board Monday, did not vote on the report, nor on any other items at the meeting, saying he still needed time to become fully informed of the issues.
Calculating Costs
BPU Commissioner Dianne Solomon | New Jersey Board of Public Utilities
Commissioner Dianne Solomon voted against accepting the report, saying it was unusable as an aid to drafting policy.
“After reviewing the extensive stakeholder comments on the rate impact study, it is clear that there is agreement on all sides that the impact study missed the mark,” she said at the meeting. “No one should contemplate using this study to inform policy decisions on future BPU and utility programs.”
Solomon said the report “fails to provide to us as commissioners or the ratepayers we serve with the information that this report was supposed to give.” Specifically, it ignores some key factors that will contribute to consumer costs under the state’s clean energy strategies, such as capital costs.
Solomon’s concerns echoed those of business groups at a March 29 public hearing at which Brattle officials outlined their proposed framework for the study. The Chamber of Commerce of Southern New Jersey, for example, argued at the meeting that the report would not consider the capital costs needed to electrify a property.
At the same hearing, environmentalists argued that the report would exclude an estimation of benefits of clean energy, such as the reduced health care costs and the repair costs avoided because bouts of extreme weather would be less serious if carbon emissions were cut. (See Brattle Study of NJ Energy Master Plan Cost Under Scrutiny.)
Future Study
At a press conference after the meeting Wednesday, BPU staff defended the report, saying the board had from the start said it would focus only on the ratepayer impact.
BPU Chief Economist Ben Witherell presenting the Brattle Group report | New Jersey Board of Public Utilities
“We agree that there needs to be additional analysis on the capital costs,” said Abraham Silverman, chief counsel for the BPU. “But you need to have a good understanding of what the benefits are before you can treat the capital costs appropriately.
“For example, if you’re trying to calculate a return on investment … you need to know both the capital costs, and you need to know the benefits. So this is the first step in this process. We have identified now what are the savings associated with the investment.”
BPU Chief Economist Ben Witherell, who presented the report at the meeting, said the board would be looking at capital costs in the future. But the first step is what “most stakeholders were interested in, which was: what are the ratepayers going to be paying for their monthly energy bills to support these policies and programs.”
Low-income Ratepayers
The Energy Master Plan calls for the state to reach 100% clean energy by 2050, mainly by improving energy efficiency and shifting to clean energy generation, mainly wind and solar. It includes a goal of developing generate 7.5 GW of offshore wind power by 2035, with about half that to be generated by three projects so far approved in two solicitations. Another three solicitations are expected, with the first to take place early next year.
The state also has sought to position itself as an offshore wind industry hub, committing $500 million to $550 million to the creation of the New Jersey Wind Port, a logistics and manufacturing hub in South Jersey, and seeking to set up a “flagship” research and development center, both of which would serve not only New Jersey’s industry but also those of neighboring states.
It has also created several programs to incentivize the purchase of EVs, trucks and buses, and to stimulate the installation of electric chargers across the state.
Eric Miller, New Jersey energy policy director for the Natural Resources Defense Council, welcomed the report and said the limitations of its scope were not important.
“Overall, we think that’s a really positive report,” he said. “It’s good to see confirmed that customers who participate in the clean energy transition, whether it’s using an electric vehicle, participating in energy efficiency programs or electrifying their space and water eating, stand to see really big benefits by doing so.”
One especially encouraging element of the report is its conclusion that an aggressive escalation in the state’s approach to carbon emissions reduction would only increase the cost to ratepayers slightly. The report found that if the state shifted from the Energy Master Plan goal of reaching 100% clean energy by 2050, to an “ambitious pathway” of reaching that goal by 2035, the additional annual energy cost for the typical ratepayer would be only about 2% higher.
Miller also cited as important the report’s conclusion that the state should prepare to step up its incentive programs to include low-income residents.
The report found that a low-income resident — one with an annual income of $35,000 — would spend 7.3 to 10.8% of their salary on energy in 2020, rising to 9 to 12.5% in 2030 if they did not embrace relatively expensive energy-efficiency and clean energy methods.
“This implies that energy assistance programs targeting low-income customers may be necessary to help with upfront costs of electrification and energy-efficiency improvements,” the report says. “These programs may range from providing rebate assistance for the purchase of efficient appliances and electric vehicles, to on-bill financing for income-qualifying customers to be able to undertake projects with high initial capital cost requirements.”
VANCOUVER, Canada — At its quarterly meeting on Wednesday, NERC’s Finance and Audit Committee (FAC) approved the final business plans and budgets for NERC and the regional entities. With the FAC’s approval, the budgets will now go to NERC’s Board of Trustees for approval at its meeting on Thursday.
The final budgets are largely the same as the drafts that NERC unveiled in May after what board members on Wednesday called “the most comprehensive budget process” to date at the ERO. (See NERC Plans Big Budget Hike for 2023.) Only NERC and WECC’s final figures differed from those provided in the original versions. NERC’s overall projected budget now stands at $101 million, up from $100.8 million in the draft because of higher operating expenses. WECC’s final budget is up from $31.7 million to $31.8 million because of lower projected savings in some categories.
NERC posted the drafts for comment on its website. The organization received five comment submissions from Electricity Canada, Ontario’s Independent Electricity System Operator, the ISO/RTO Council’s Standards Review Committee, the National Rural Electric Cooperative Association, and other industry organizations. The ERO’s responses to the comments were incorporated into the final versions.
Comments from stakeholders followed three major themes, Andy Sharp, NERC’s vice president and CFO, said at the FAC meeting.
First, stakeholders encouraged the ERO to continue improving the development process for the business plans and budgets through “metrics that support budget assumptions and demonstrate effectiveness.” Sharp said the FAC is committed to “engaging and collaborating … for ideas” on effective metrics.
The total ERO Enterprise budget, including the regional entities and WIRAB, is set to rise to $250.1 million in 2023, a 10.1% increase over the 2022 budget. | NERC
Stakeholders also sought more collaboration in technology and cybersecurity investments, calling for increased transparency around investments like the ERO’s Align software tool and Secure Evidence Locker, and alignment between these investments and reliability metrics.
The third major theme concerned reducing the need for budget and assessment increases through improved efficiencies, reflecting concern about the economic pressures on the industry. (See ERO Warns Inflation, Cyber Investments to Keep Boosting Budgets.) Stakeholders’ suggestions in this area included using contractors instead of full-time equivalents, reassessing annual salary increases, and increasing use of virtual meetings, which have proven to reduce travel and related costs.
Sharp acknowledged the suggestions, promising that the ERO will seek to reduce burdens on the industry.
He also reminded listeners that some of the advanced projects that NERC is working on require a high level of expertise.
“We do continue to want to leverage subject matter experts in the industry, but we also want to remain sensitive to the level of demand we’re placing on you, especially in these scarce or high-demand resource areas, [and] reducing duplication with other organizations,” Sharp said.
Brian Evans-Mongeon, president of Utility Services, said that while he was happy with the ERO Enterprise’s willingness to incorporate industry feedback into its budget process, staff should also keep in mind the burdens placed on smaller organizations that lack the resources of larger companies.
“We very much appreciate the … openness and the collaboration, but we just want to make sure that that collaboration comes forward so that we can all meet these priorities in the most cost-effective way, because it’s going to require effort across the board,” Evans-Mongeon said. “And that means support from the smaller organizations as well, and they’re going to have to figure out how to match this.”
MISO is resisting clean-energy developers’ calls to allow penalty-free generator interconnection queue withdrawals for certain projects bogged down by SPP’s affected system studies.
The grid operator contends that respite for some projects is unnecessary because it already has provisions to extend commercial operation dates, and it offers chances at penalty-free withdrawals.
“Interconnection customers are already afforded a three-year grace period from the documented [commercial operation date] to bring a resource commercial,” Ryan Westphal, Interconnection Process Working Group liaison, told stakeholders Monday during an IPWG teleconference.
Westphal said MISO will also offer penalty-free exit after projects receive their affected system study results. However, projects that already have signed a generator interconnection agreement with MISO cannot back out without risking paid per-megawatt milestone fees.
In June, Clean Grid Alliance asked the RTO to consider penalty-free withdrawals or longer extensions for advanced-stage interconnection projects already in limbo while waiting on potentially expensive network upgrade costs from SPP’s study results. (See Clean Grid Asks MISO for Penalty-free IC Exits.)
CGA’s Rhonda Peters said upgrades from the affected system studies (AFS) can be staggering and upend once-promising generation projects.
MISO and SPP have rolled out a new, “first ready, first served” queue priority for generation projects that could affect system impact studies on the seams, affected-system studies and cost assignments for network upgrades. The initiative replaces the grid operators’ previous practice of first studying projects with the earliest queue entry dates. That practice didn’t account for a project’s preparedness. (See FERC OKs New Queue Priority for MISO, SPP Seams Studies.)
Batches of projects that entered MISO’s queue in 2018 and 2019 were left out of the new priority. Staff said those project cycles are destined for GIAs before the changes take effect.
Upon hearing CGA’s pitch for free-and-clear withdrawals and extensions, staff expressed concerned that allowing the penalty-free exits could potentially harm lower-queued projects. MISO usually keeps departing interconnection customers’ milestone fees to minimize the costs of network upgrades on lower-queued projects.
Peters argued that the AFS-assigned upgrades can go as high as $100 million, a figure no one initially expects.
“This is such an extreme level of uncertainty, and it’s such a tough situation for these projects to be in,” she said. “This is unprecedented. The level of uncertainty that these projects face is so extreme that no one could have ever predicted it.”
Peters advocated again for a limited waiver for 2018 cycle projects affected by system impact studies.
Staff pointed out that developers can always seek individual waivers of interconnection procedures through FERC.
Invenergy’s Sophia Dossin said generation developers are in a “Russian roulette situation with these massive, project-killing upgrades.”
Other stakeholders argued that SPP keeps delaying its final batches of system impact studies, making affected system upgrades even murkier.
MISO is refreshing its longstanding “parking lot” of improvement ideas submitted to the grid operator, some of which have been in a holding pattern for the better part of a decade.
The RTO has conducted an internal review on how it handles issues relegated to the parking lot until MISO stakeholder committees deem it’s time to reexamine them. Some stakeholders have said topics they’ve brought forward can languish on the list.
Alison Lane, stakeholder relations lead, said during a Steering Committee teleconference Wednesday that MISO will now refer to inactive recommendations and will commit to their biannual reviews, beginning in 2024.
Staff will go before its large stakeholder committee meetings with a review and cleanup of the suggested improvements, Lane said. MISO will keep the issues that advance its imperative reliability work or that can be handled within the next three years and are supported by “the state of the industry’s” policies and technologies.
MISO currently has 36 issues in the parking lot, some of which are more than seven years old. Staff said some of the proposals have already been addressed with FERC rulemakings, as is the case with Order 2222 and allowing aggregators of distributed resources into the wholesale energy markets.
“We have every intention of being much more diligent on parking lot items” Lane promised earlier this year.
The parking lot designations were used under the RTO’s Integrated Roadmap process, where stakeholder input was used to annually prioritize a list of market tasks and improvements. MISO ended the practice last year. (See MISO Keeps Reduced Schedule for Rest of 2022.)
The grid operator is also encouraging a more standardized method for stakeholders to submit new issues that they think deserve MISO’s attention. After the roadmap process was scrapped, stakeholders said in public meetings they were left wondering how to broach ideas for improvements.
Staff stressed that stakeholders who want their ideas discussed in public meetings should complete its issues submission form. From there, the item is either directly considered by a stakeholder group or, when the assignment is less clear, the Steering Committee determines which stakeholder groups will take up the issues for consideration.
Michael Skelly, Grid United | © RTO Insider LLC
