MISO and SPP on Monday laid out a percentage-based cost allocation for their $1-billion Joint Targeted Interconnection Queue (JTIQ) transmission study that will assign most costs to interconnecting generation.
The grid operators plan to assign 90% of project costs to interconnection customers and 10% to an aggregate of MISO and SPP load. The RTOs said they will allocate a fixed, per-megawatt charge to interconnection customers that have a 5% or greater impact on a facility in the neighboring region to pay for the portfolio.
“We think a 90-10 split would work well for this portfolio and for future portfolios,” MISO’s Andy Witmeier told stakeholders during a JTIQ study teleconference Monday.
National Grid Renewable’s Rafik Halim said he thought a 50-50 allocation between load and new generation would be more suitable. He asked for a rationale behind the cost split.
“If MISO and SPP believe a 90%-10% split is appropriate, we need to see why. This is a billion dollars of investment,” he said.
Halim also asked for an analysis to show how the grid operators arrived at the 5% impact threshold for new generators.
American Clean Power Association’s Daniel Hall seconded the ask for the 90-10 cost allocation’s justification.
The RTOs staff remained steadfast in asserting that the JTIQ’s main purpose is to enable new generation, making it only fair that interconnection customers bear the brunt of the costs. They also said the 5% impact factor is a well-established approach that both grid operators use today.
Other stakeholders asked whether the RTOs plan to create protections that ensure transmission facilities get built should generation developers balk at network upgrade costs and withdraw from the queue. How would the portfolio remain funded, they asked.
SPP’s Neil Robertson said staff’s plan is to assign a fixed, one-time upfront charge to eliminate unexpected sticker shock and cut down on the number of queue dropouts. He said the process will ensure the upgrades’ expense is spread evenly across generation and that no project is encumbered with an eye-popping upgrade bill.
David Kelley, SPP’s director of seams and market design, said the RTOs are confident that enough generation developers will continue to construct projects near the seams and fund JTIQ projects.
The study’s portfolio was initially priced at $1.65 billion. However, it contained two project duplicates with MISO’s recently approved $10.3-billion long-range transmission portfolio. Staff said SPP’s benefits from the projects were negligible and independently pursued the duplicates under its regional process, reducing the JTIQ to about a billion-dollar investment. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)
The current JTIQ portfolio includes:
the $476-million Bison-Hankinson-Big Stone South 345-kV line located in MISO’s footprint that touches both Dakotas and Minnesota;
the $331-million Brookings County-Lakefield 345-kV line from South Dakota into Minnesota in MISO territory;
the $144.4-million Raun-S3452 345-kV line on the Iowa-Nebraska border, straddling both MISO and SPP;
the $90.5-million Auburn-Hoyt 345-kV line from Nebraska into Kansas in SPP’s region; and
the nearly $19 million Sibley 345-kV bus reconfiguration in SPP’s portion of northwest Missouri.
The RTOs announced in late June that they plan to ditch their current affected systems study process for more interregional transmission studies like the JTIQ study. (See MISO, SPP Commit to Replacing Affected System Studies.)
Robertson said the portfolio began as a “one-off” process and has since evolved into an “enduring, repeatable” design.
The grid operators plan to hold another meeting Sept. 30 to finalize cost-allocation details. Kelley asked stakeholders to send their improvement suggestions for the concept to the RTOs.
The D.C. Circuit Court of Appeals issued rulings Tuesday on a variety of petitions relating to the Mystic Generating Station, granting review to a group of state regulators and rejecting several requests from the plant’s owner (20-1343).
First, Mystic argued that FERC mistakenly applied the “original cost test” to calculate the rate base for Units 8 and 9, which were kept operating by the agreement.
The original cost test says that a utility “may only earn a return on (and recovery of) the lesser of the net original cost of the plant or, when plant assets change hands in arms-length transactions, the purchase price of the plant.”
Mystic’s parent company valued Units 8 and 9 as part of a merger in 2012 around $925 million and claimed that “sale” price should determine its rate base.
The commission rejected that approach as inconsistent with the original cost test because of the units’ full purchase history.
The D.C. Circuit sided with FERC on that question and did not grant review, saying the decision “accorded with [the commission’s] precedent and was supported by reasoned explanation.”
The court also dismissed Mystic’s challenge to the capital structure adopted by the commission for ratemaking purposes, because a subsequent order made the challenge moot.
Another order examined in the court’s ruling was related to the cost recovery for Everett, an LNG terminal attached to the plant. Both Mystic and state regulators challenged FERC’s approach.
The regulators argued that the commission lacked jurisdiction to regulate the rates charged by Everett and that FERC’s decision to allocate 91% of Everett’s operating costs to Mystic — and therefore ultimately to ratepayers — was arbitrary and capricious.
The court agreed with those arguments but not with Mystic, which argued that “the commission erred in excluding Everett’s purchase price from Everett’s rate base.”
Next, both Mystic and the states challenged the “true up” mechanism approved by FERC, designed to allow parties to “reconcile cost projections with actual expenditures via surcharges and refunds as necessary.” Mystic argued that “the true-up mechanism will lead to relitigation of its historic costs.”
The court said that was unfounded. It accepted, however, the states’ arguments that FERC failed to address a request for clarification about how it calculated revenue credits and Everett’s tank congestion charges. Those issues were remanded by the court for clarification.
Finally, the states took issue with parts of a “clawback” provision that would require Mystic to reimburse ratepayers for some expenses if it re-enters the New England energy markets after the agreement is over.
The states argued that Everett’s costs shouldn’t have been excluded from the clawback rules, and the court agreed. It also granted review of the states’ claim that FERC “failed to address their argument that the Mystic agreement will induce Mystic to delay capital projects into the term of the agreement.”
Entergy has responded to criticism filed at FERC that the utility is purposefully undermining transmission planning in MISO South.
In a statement to RTO Insider, Entergy countered Southern Renewable Energy Association’s (SREA) claim that the company is deferring and hindering the region’s transmission planning by saying it “strongly supports” investment in transmission, but that it must pay attention to costs.
The company said that since joining MISO in late 2013, it has invested $6 billion in new transmission infrastructure, resulting in nearly 600 miles of new lines. Entergy said that level of investment is above the industry average.
“Entergy strongly believes that new transmission will play an important role in MISO South as we integrate additional solar resources and evolve our generation portfolio to be more sustainable,” it said. “We recognize that creating a carbon-free future calls for more investments in renewable energy.”
Commenting in FERC’s Notice of Proposed Rulemaking on transmission planning, SREA accused Entergy of habitually proposing new generation plants just in time to thwart MISO transmission recommendations, thus harming reliability in MISO South. (See SREA Criticizes Lack of MISO South Planning in FERC Tx Proceeding.)
Entergy said it’s working with its regulators and stakeholders to “responsibly expand access to renewable energy … under a framework that balances reliability, affordability and environmental stewardship.”
The company said MISO’s planning decisions have “major cost implications to our customers, nearly 30% of whom live in poverty and already struggle to pay their monthly bills.” It said the $30 billion to $100 billion of transmission investment that MISO expects with its long-range transmission plan’s (LRTP) four portfolios will invariably raise costs for its ratepayers.
The grid operator approved its first LRTP portfolio in late July. The $10.3 billion transmission investment in 18 projects is aimed at MISO Midwest only. It will be several years before their planners seek projects in MISO South. (See MISO Board Approves $10B in Long-range Tx Projects.)
“Even at the low end of that range, Entergy’s customers would be responsible for hundreds of millions of dollars per year in transmission costs. When we express our views, along with numerous other utilities and stakeholders, we do so based on what we believe is in our customers’ best interests — just as every other stakeholder does in MISO’s process,” Entergy said.
The utility pointed out that MISO ultimately decides which transmission projects to place before MISO’s Board of Directors for its approval.
Entergy also addressed the more potent storms that have formed in the Gulf of Mexico in recent years and their impact on its existing transmission infrastructure.
“Ultimately, Entergy and other utilities have to answer to our customers and our state regulators for the reliability and cost of the essential service we provide,” it said. “In a world where climate change is happening and we are experiencing more severe weather events and other challenges, there are important policy decisions to be made about what investment is needed to better prepare electric systems and other infrastructure to withstand those events.”
Entergy said it welcomes “a reasoned and fact-based discussion with our regulators and stakeholders about what that investment should look like and how to fund it, without imposing burdensome additional costs on our customers.”
After ISO-NE issued a comprehensive study in April looking at possible regional decarbonization solutions, there was hope around the region’s energy and environmental sectors that it would jumpstart the states into action.
Among the study’s key findings was that the status quo — New England states largely continuing to individually, unilaterally advance their own decarbonization policies through procurements — would be more costly for the region than any of the modeled alternatives, including carbon pricing, a forward clean energy market (FCEM) or a hybrid of the two.
But the gears are turning slowly in the states, which one regulator compared to aircraft carriers chugging out to sea.
And the approaching gubernatorial elections may also have a paralyzing effect, pushing the earliest point for decisive action beyond November and into 2023.
In interviews with RTO Insider, three New England state energy officials defended their deliberative processes and urged patience from those who are pushing them to move faster.
“I think the thing I would emphasize is what a dynamic moment we’re in, in terms of this longstanding question of harmonizing markets and decarbonization mandates,” said Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection.
She pointed to FERC’s recent approval of an ISO-NE plan to phase out the contentious minimum offer price rule, as well as the action in Washington over the past few weeks, culminating in President Biden signing the landmark Inflation Reduction Act, with new incentives and support for all sorts of clean energy technology.
“I know that there’s a lot of eagerness from stakeholders to hear the states’ views on next steps,” Dykes said. “At the same time, there’s a lot going on in the current moment that needs to be taken into account with which solutions make the most sense.”
June Tierney, commissioner of the Vermont Department of Public Service, said that regulators are tasked with taking a comprehensive view and carefully working through complex issues.
“When the Navy deploys for a military action, they don’t just all hop on the carrier and go to battle. They’re accompanied by a flotilla, and a lot of the flotilla are speedboats, things that can maneuver more nimbly and move out ahead and show the way. And then comes the carrier in the wake,” Tierney said in an interview.
“My point is, there are many stakeholders in this process who do move more quickly, more nimbly. They help pull us along. And we’re the aircraft carriers, the six states. We move slowly but steadily,” Tierney said.
Those pulls and pushes have come from environmental advocates and the renewable industry, but also from generators more broadly.
“The inaction of the moment is a choice in and of itself to maintain the status quo,” said Dan Dolan, president of the New England Power Generators Association in an email to RTO Insider. “That is the one pathway that the states, generators and ISO-NE all agreed was the worst possible outcome.”
Dolan urged the states to forge ahead and not fear political vulnerability.
“The reality is that with all six states in the midst of gubernatorial elections, a final decision is likely going to have to wait,” he said. “While I respect the politically awkward timing of the moment, I sincerely hope the next several months are not lost to the campaign season, and that important work can still progress.”
Tierney said that it is progressing.
“We’re all showing up to our meetings. We’re all having the conversations,” she said. “What we’re doing is trying to figure out what can we do while we await election results.”
Wrestling with FCEM Governance Questions
While a straight up price on carbon has support in large swaths of the region’s energy industry and inside ISO-NE, the states have uniformly said that its political challenges make carbon pricing a nonstarter.
Instead, they’re eyeing an FCEM, a centralized auction in which sellers (producing energy through means including wind, solar, nuclear, hydro) and buyers (states, cities, companies, retailers, utilities and more) would exchange clean energy credits.
An FCEM could be enacted on its own or in a hybrid configuration along with a slimmed down carbon pricing mechanism. It could bring New England’s clean energy procurement more into concert, instead of the states relying on individual contracts.
But because an FCEM would be a brand new market structure, there are a host of governance and structural questions that the states and ISO-NE would have to hash out.
“Would implementation of these measures be something that would be supported within a FERC-jurisdictional tariff advanced by ISO-NE, or would they require individual state legislatures to authorize them?” Dykes said. “These are important questions, and we’re taking our time to think through it and looking at the best model.”
But Tierney said that her observations of the current FERC commissioners suggest otherwise.
“Sometimes I think what has been missing here is that FERC has been very intent on ensuring that nobody gets out in front of the states,” Tierney said. “I am going to be bullish on how FERC might respond to an FCEM mechanism that has the support of the states.”
Massachusetts is working on developing a proposed framework for an FCEM, which officials there hope can be a jumping-off point for regional discussions in the next few months.
“Massachusetts believes an appropriate next step is to develop a design structure that addresses detailed mechanics along with defining governance and state involvement,” Patrick Woodcock, commissioner of the state’s Department of Energy Resources, said in a statement to RTO Insider. “To move away from the state-based procurement process into a regional framework will require full confidence from the states in their role in decision-making and alignment with state laws.”
NYISO’s first 20-year economic planning forecast paints a daunting picture of the challenge facing New York in meeting its climate goals: More than 95 GW of new zero-emission resources must be added to the grid by 2040, 20 GW within the next seven years.
“That is significant,” NYISO’s Jason Frasier said in presenting the inaugural System & Resource Outlook to the Business Issues Committee on Wednesday. The 2030 goal represents half of the ISO’s current 40-GW fleet.
Complicating matters, as fossil generation is eliminated, the state will need new clean energy generation technologies — potentially hydrogen, renewable natural gas and small modular nuclear reactors — which the report calls “dispatchable emission-free resources.”
Also daunting: building the transmission needed to deliver that power. “The current New York transmission system, at both local and bulk levels, is inadequate to achieve currently required policy objectives,” the ISO says in the report. “Some renewable generation pockets throughout the state already face curtailments. More curtailments will be experienced in the future [absent transmission upgrades] as an increasing number of intermittent generation resources interconnect.”
The Need for Change
The outlook, which will be performed every two years, replaces Phase 1 of the Congestion Assessment and Resource Integration Study (CARIS).
The new planning process was prompted by the 2020 Accelerated Renewable Energy Growth and Community Benefit Act, which mandated a statewide transmission planning study to achieve the targets of the 2019 Climate Leadership and Community Protection Act (CLCPA): 70% renewable energy by 2030 (70×30) and 100% zero-emissions by 2040.
The “plan further supports the state’s mission by quantifying the evolving challenges in the electricity sector resulting from widespread beneficial electrification,” the ISO said.
NYISO won FERC’s approval for the new process last year, telling the commission in its transmittal letter that “no single NYISO planning study summarizes and evaluates the totality of New York state’s transmission system needs” (ER21-1074).
Cumulative contracted renewable capacity additions by online year | NYISO
The ISO said the shift from CARIS’ 10-year horizon to a 20-year study period would “better capture trends in system congestion[,] the full benefits of potential transmission upgrades” and the long-term impacts of the CLCPA mandates. It also aligns with the 20-year study period that the ISO uses to evaluate proposed transmission solutions to address congestion in the Economic Transmission Project Evaluation (previously CARIS Phase 2).
The outlook assesses congestion statewide, in contrast with CARIS, which focused on only the top three congested transmission paths based on production costs — ignoring congested paths with lower production cost impacts but potentially higher benefit-to-cost ratios.
Under the previous process, NYISO also limited its transmission planning to the bulk power transmission facilities (BPTF) portion of the state’s transmission system (generally 230 kV and higher), leaving its transmission owners to plan their local systems. Under the outlook, the ISO will identify congestion throughout the transmission system, although its evaluation of proposed transmission solutions will remain limited to the BPTFs, supplemented by transmission owners’ local plans.
“Much of the transmission congestion identified in the 70×30 scenario resulted from local transmission constraints, which would likely not be identified in the top three most congested paths on the New York state transmission system,” the ISO said.
The ISO said the new process will improve its analysis of the benefits of interregional transmission. “Based on past CARIS studies, interregional congestion has not risen to the top three most congested paths in order for it to be analyzed,” it said.
Under the new process, the ISO will conduct its assessments of “generic” solutions (transmission, generation, demand response and energy efficiency) to the Requested Economic Planning Study (formerly the “Additional CARIS Study”) and the Economic Transmission Project Evaluation.
Unchanged is the ISO’s process for evaluating proposed economic transmission projects or identifying load-serving entities that benefit from projects. The 80% voting threshold required for LSEs to approve such projects also is unchanged.
Four Futures
The outlook considered four potential futures:
The Baseline Case assumed little change from the status quo.
The Contract Case includes nearly 9,500 MW of renewable capacity procured by the state (4,262 MW of solar, 899 MW of land-based wind and 4,316 MW of offshore wind).
The Policy Case looks at two futures selected from dozens of preliminary scenarios that varied based on factors such as capital costs and demand forecasts. “Among all factors tested, the demand forecast demonstrated the largest impact on the resulting capacity expansion,” the ISO said.
Scenario 1 envisions high demand (57,144 MW winter peak and 208,679 GWh energy demand in 2040) with fewer restrictions on renewable generation buildout options and land-based wind largely used to meet emission targets.
Scenario 2 used assumptions consistent with the New York Climate Action Council’s Integration Analysis and sees a moderate peak but a higher overall energy demand (42,301 MW winter peak and 235,731 GWh energy demand in 2040) with a mix of land-based wind and solar.
DEFRs
The 20 GW of new generation needed in the next seven years dwarfs the 12.9 GW of generation developed since wholesale electricity markets began more than 20 years ago, the report notes. Over the past five years, 2.6 GW of renewable and fossil-fueled generation came into service — while 4.8 GW was deactivated.
NYISO’s two “Policy Case” scenarios use land-based wind (LBW), offshore wind (OSW), utility-scale solar (UPV), behind-the-meter solar (BTM-PV) and energy storage (ESR) to meet the state’s climate policy mandates through 2035. | NYISO
The 9,500 MW of new contracted renewable resources projected would be a five-fold increase in the ISO’s current utility-scale renewable fleet. “Without any major transmission upgrades planned to specifically address this large influx of contracted renewables, transmission congestion increases. When the contracted renewable projects are added, several additional constraints appear, causing a 23% increase in congestion statewide by 2030.”
Most of the renewable projects are expected to be upstate solar or downstate offshore wind projects scheduled for installation before 2026. (In 2021, zero-emission resources made up 91% of upstate production, while fossil units dominated downstate (89%).)
The future will also mean an increase in dispatchable generator starts and stops and daily ramping to address the variability of wind and solar generation. While flexible units will be dispatched more frequently, they will operate for fewer hours within the year.
To achieve the CLCPA target, all fossil generation is assumed to be retired by 2040, replaced by “dispatchable emission-free resources” (DEFRs), “a proxy technology that will meet the flexibility and emissions-free energy needs of the future system but are not yet mature technologies that are commercially available.”
Scenario 1 assumes 45 GW of DEFR capacity by 2040 because of a 35% higher peak load forecast than Scenario 2, despite a 13% lower annual energy demand. The report notes that New York’s current fossil fleet is only 26 GW. Scenario 2 envisions 27 GW of DEFRs by 2040.
A scenario in which DEFRs are not available because of a lack of investments in research, development and commercialization “exhausts the amount of land-based wind built and results in the replacement of 45 GW of DEFR capacity in Scenario 1 with 30 GW of offshore wind and 40 GW of energy storage,” the outlook says.
That would also necessitate system reinforcements to address voltage support and dynamic stability problems that would arise without the fossil fleet or DEFRs.
Transmission Curtailments
New York is expected to see a major reduction in congestion on its Central East interface once the AC Transmission Public Policy projects in the Mohawk and Hudson Valleys are completed in 2024 and more than 10 GW of nuclear plant capacity in Ontario is retired or shut down for refurbishments by 2025. Nearly all of the economic energy exports to NYISO from the Ontario Independent Electric System Operator are delivered via the Central East interface.
But the reduced congestion will be short-lived as new renewables are connected upstream of the Central East interface, the outlook says.
A lack of sufficient transmission would result in increasing curtailments of both renewable and dispatchable generation, with renewable generators averaging 5 GWh per year in the Baseline Case, rising to 163 GWh in the Contract Case. Most of the curtailments affect offshore wind projects connected to Long Island, the report says.
The report predicts curtailment of at least 5 TWh of renewable energy in 2030 and 10 TWh in 2035 because of transmission limitations in renewable pockets. “This equates to roughly 5% less renewable energy that can be produced, and thus may not be counted toward the CLCPA targets.”
Generation Pockets
The report identifies four “generation pockets” that will need transmission expansions to avoid “persistent and significant limitations” to deliverability:
Long Island offshore wind: NYISO is currently evaluating proposals submitted in response to the Long Island Offshore Wind Export Public Policy Transmission Need, which could reduce projected congestion “significantly,” according to the report. The solicitation seeks to deliver at least 3,000 MW of offshore wind by increasing the export capability of the LIPA-Con Edison interface connecting Zone K to Zones I and J and upgrading associated local transmission. “However, offshore wind resource additions of up to 20 GW that are under discussion may necessitate additional transmission to deliver offshore wind energy to New Yorkers,” the outlook says.
The Watertown/Tug Hill Plateau renewable generation pocket (designated as X3 on the ISO’s map): The 115-kV network can’t deliver all of the already-contracted wind and solar generation in the area, and congestion will worsen with integration of more renewables.
Southern Tier (Z1) and Finger Lakes (Z2) renewable generation pockets: The areas are attractive to wind and solar developers. “Transmission expansion from this pocket to the bulk grid would benefit New York consumers statewide,” the report says.
Comments
The outlook was generally well received by BIC members, who voted to recommend it to the Management Committee. That committee is scheduled to vote on it on Aug. 31, which will be followed by a vote by the ISO’s Board of Directors in late September. The ISO will then hold a public information session on the report.
Chris Hall, of the New York State Energy Research and Development Authority (NYSERDA), praised the report, although he said the authority “didn’t necessarily agree with every single modeling assumption” and will propose changes in the future. NYSERDA would have liked more time for the study, he said, “but we recognize pencils have to be put down at some point.”
Mark Younger of Hudson Energy Economics noted that while the outlook considered major changes in New York, it did not address the scale of changes occurring in neighboring regions. He argued that NYISO should not draw any conclusions about how it should address its interface with its neighbors without more analysis on the degree to which they can provide each other excess energy when it is needed.
Attorney Doreen Saia, of Greenberg Traurig, said she was concerned that the outlook’s executive summary focuses on changes needed as the state approaches 2040.
“There’s a very significant need now and in the near term. And I don’t want that to get muted,” she said. “We have to presume that there will be some subset of folks who only read the executive summary.”
Zach Smith, NYISO vice president of system and resource planning, said the ISO’s communications about the report will note the timing considerations at issue.
Next Steps
NYISO said data from the outlook will be used in the 2022 Reliability Needs Assessment (RNA) to identify commitment and dispatch trends and reliability impacts, as well as in the 2022 Grid in Transition study.
The ISO will open a 60-day comment period at the end of August or early September for its 2022-2023 Public Policy Transmission Planning cycle.
“The challenges identified in the outlook cannot be solved by any single entity,” the report says. “The full set of comprehensive electric system requirements will need participation among policymakers, generator owners, transmission owners and consumers. Communication and collaboration between stakeholders is essential to making progress toward achieving policy objectives while maintaining an efficient power market and reliable power grid.”
Attorneys general for California, Oregon and Washington asked FERC Monday to deny an application to expand the capacity of a pipeline system that delivers natural gas to the three states.
Their argument: all three states have taken legal measures to trim their methane emissions while the pipeline expansion would increase those same emissions.
Gas Transmission Northwest (GTN) is seeking permission from FERC to expand the capabilities of three compressor stations — Athol Compressor Station in Kootenai County, Idaho; the Starbuck Compressor Station in Walla Walla County, Wash.; and the Kent Compressor Station in Sherman County, Ore. The improvements would add a transmission capacity of 150 million cubic feet per day (CFD) to the pipelines that move gas from Canada to Washington, Oregon and California.
That translates to 3.47 million extra tons of carbon dioxide annually for the next 30 years in those three states, according to the joint filing to FERC by the three states. The project’s budget is $335 million with the costs being passed on to GTN’s current ratepayers. The joint filing contends Houston-based GTN has not guaranteed that new customers will pay for the proposed expansion.
GTN currently delivers up to 2.7 billion CFD in natural gas to customers in in the Northwest and California. The company owns 1,377 miles of pipelines in those three states and Idaho.
“This project undermines Washington state’s efforts to fight climate change,” Washington Attorney General Bob Ferguson said in a news release. “This pipeline is bad for the environment and bad for consumers.”
Ferguson argued that GTN is pitching its proposal to FERC as improvements in reliability to the existing pipeline system when it really wants to expand.
“The West Coast is experiencing very real impacts of climate change and leading the climate fight, so it is fitting that Oregon, Washington and California band together on this joint motion asking FERC to take a hard look at this pipeline proposal,” Oregon Attorney General Ellen Rosenblum said in the same release.
California Attorney General Rob Bonta added: “Expanding the capacity of this pipeline would have significant environmental and public health impacts and is out of step with state and federal climate goals, and FERC can’t honestly say otherwise. The reality is, when we expand gas infrastructure, it’s all too often minority, low-income and Indigenous communities that pay the price.”
GTN provided NetZero Insider with a statement that did not specifically address the complaints laid out by the three attorneys general in their filing.
“Natural gas is a critical component of any strategy to meet our North American energy needs today and in the future and has contributed to reduced greenhouse gas emissions on the continent,” the company said. “The Gas Transmission Northwest XPress Project (GTNXP) is designed to upgrade our system to meet increased demands from our customers in the region, providing the reliable energy to communities throughout the Western U.S. in a safe, responsible, and reliable manner.”
Washington’s legislature passed a law to incrementally trim statewide GHG emissions to 95% of the 1990 level by 2050. By 2045, retail electricity must be 100% emissions-free. In mid-2023, the use of natural gas for HVAC systems in new buildings will be outlawed.
Oregon has required its major investor-owned utilities, Portland General Electric and PacifiCorp, to become 100% renewable by 2040. Those utilities represent 87.8% of greenhouse gasses that electricity suppliers emitted as of 2020, the joint filing said.
California’s targets include reducing the state’s overall GHG emissions to 40% below 1990 levels by 2030 and 80% below that level by 2050.
California and Washington have the nation’s only two cap-and-trade programs to reduce carbon emissions.
A working group of MISO and SPP state regulators addressing rate pancaking issues agreed Monday that their work is finished and ready to be turned in to the Seams Liaison Committee (SLC).
Marcus Hawkins, executive director of the Organization of MISO States, said during a virtual meeting that the Rate Pancaking Working Group’s (RPWG) strawman has been tweaked since its initial draft. It includes four recommendations for the SLC’s consideration, or “next steps … you all could consider to further this work,” he said.
The working group identified the treatment of unreserved use charges for transmission configuration changes and emergency ties on the seam as its key issue. It suggested the SLC request both RTOs develop comparable treatment of unreserved use with criteria that is simple, fair and easy to administer, and to also comparably treat the billing of firm network reservations.
The RPWG also looked at the inability of market participants to obtain congestion hedges for firm transmission procurement. The group suggested the RTOs explain to regulators how firm transmission reservations should be obtained and the issues that prevent awarding hedges for firm service customers. The RPWG proposed asking stakeholders to share their experiences with procuring financial transmission rights and whether it affected resource procurement, and to monitor SPP’s work on counterflow optimization.
The grid operator has scheduled a virtual workshop Aug. 30 to discuss adding counterflow optimization to its market mechanism that hedges load against congestion charges. SPP and its stakeholders have been unable to reach consensus on the initiative, which began in 2019. The RTO still hopes to bring a solution to the October board meeting. (See “Counterflow Optimization not Dead Yet,” SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)
The RPWG’s other findings and recommendations included:
Investigate how rate pancaking can be eliminated or reduced for long-term contracts, beginning with consideration during the Nov. 9 Common Seams Initiative joint stakeholder meeting of a long-term interregional rate that can reduce pancaking costs and increase revenue generated. The group suggested hearing from SPP on its rate-pancaking initiative and from MISO on whether it has any strategic actions related to the seams, and to request the RTOs assess different ways to adjust rates on the seams and increases transmission service sales.
Determine how interregional projects can cause unintended pancaking issues. The group advocated that during the next SLC meeting, the grid operators describe how the projects could change flows on the system and corresponding charges for load that didn’t exist before.
The SLC formed the RPWG to inventory rate pancaking along the grid operators’ seams. The group surveyed staff and stakeholders in developing their recommendations.
Like solar, wind generation in the U.S. faces a challenge of rising penetration and falling value on the grid.
Wind energy power purchase agreement prices are still trending below natural gas prices, according to the Department of Energy’s 2022 Land-Based Wind Market Report. But “the regions with the highest wind penetrations (SPP at 35%, ERCOT at 24% and MISO at 12%) have generally experienced the largest reduction in wind’s value relative to average wholesale prices,” the report says.
For example, the wholesale market value of wind in SPP in 2021 was $19/MWh versus $46/MWh for “24/7 flat profile” generation.
DOE released three wind energy market reports on Aug. 16 — one each on land-based, offshore and distributed resources — which together provide a view of the push and pull of forces now shaping the growth of the industry in the U.S.
The land-based report shows that while the solar industry is addressing intermittency issues with a growing number of hybrid solar and storage deployments — 67 new projects in 2021 — only two wind-and-storage projects were added to the grid last year.
Further, wind-and-storage hybrids are not providing the same capacity and flexibility as solar-and-storage. “The average storage duration of these [hybrid wind] projects is 0.6 hours, suggesting a focus on ancillary services and limited capacity to shift large amounts of energy across time,” the report says.
Offshore
A similar push-and-pull can be seen in the unprecedented $4.37 billion paid for six offshore wind leases in the New York Bight auction in February. While the sale was widely seen as demonstrating the intense interest in offshore development, it also triggered concerns about the impact of those high prices — estimated at $763/kW — on consumers’ electricity bills, according to DOE’s 2022 Offshore Wind Energy Market Report. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
Capacity for “Permitting” and “Site Control” categories are assigned to the state where the wind energy area (WEA) is geographically located. All other categories are assigned to the state where the power will be delivered. | DOE
In response, the U.S. Bureau of Ocean Energy Management changed the auction rules for its May offshore auction, for two sites off the coast of the Carolinas, which sold for a modest combined total of $315 million. (See North Carolina OSW Auction Nets $315 Million.)
The “multifactor” bidding rules discounted prices by providing credits for up to 20% of the total sale amount to bidders committing to workforce or supply chain development as part of their projects. A similar multifactor approach will be used for upcoming Pacific Coast offshore wind auctions, the report says.
Driving down costs will be a continuing challenge for offshore wind, with DOE reporting global levelized costs for fixed-bottom projects in 2021 ranging from $75/MWh to $116/MWh, versus a U.S. average of $32/MWh for onshore wind. Adding to cost pressures in the U.S., the report says, “the [offshore] industry will need to tackle new technical challenges, such as hurricane survival, deeper water and lower average wind speeds.”
Onshore
While the U.S. onshore wind market continues to grow, with a total capacity of 136 GW by the end of 2021, the country still lags behind a number of European countries — including Denmark, Spain, Germany and the U.K. — which each get more than 20% of their power from wind.
2021 was also a year of contraction for the U.S. market, according to the land-based report. New onshore capacity grew by 13.4 GW last year — a 20% drop from the 16.8 GW installed in 2020 — but still enough to keep wind as the second-largest source of new generation on the U.S. grid. Solar was No. 1 at 45% of new generation with wind power following at 32%.
The domestic supply chain also contracted, with blade manufacturing taking a 50% nosedive as three U.S. manufacturing plants closed or idled, the report says. Like the solar and storage industries, wind relies heavily on imports, which were worth $3.1 billion last year, with Mexico, Spain and India the country’s key suppliers.
The U.S. market also relies on four turbine manufacturers, with only one — General Electric — homegrown, according to DOE. The others are Vestas, Siemens Gamesa Renewable Energy and Nordex.
Like solar, domestic wind is being slowed by projects caught in RTO and ISO interconnection queues. DOE reports 247 GW of wind are currently waiting for interconnection.
More promising, in terms of future growth, the market is diversifying in terms of who owns, sells or is buying wind-generated power. Utilities accounted for 44% of new wind power on the grid last year, but direct retail purchasers, including corporations, were close behind, with 35%. Merchant or quasi-merchant projects, with revenues tied to short-term contracts or wholesale spot markets, made up another 7%.
Distributed Wind Energy
DOE also reported its latest data on the distributed wind energy fleet, which totals 89,000 turbines with a nameplate capacity of 1,075 MW.
Iowa and Minnesota, which have strong wind resources and active project developers, have received a significant number of U.S. Department of Agriculture Rural Energy for America Program wind grants, DOE says. | DOE
In 2021, 15 states added 1,751 turbines totaling 11.7 MW, representing a $41 million investment, about 75% of which was installed in Rhode Island, Kansas and Minnesota. That was a drop from the 21.9 MW ($44 million) added in 2020 and 20.4 MW ($59 million) added in 2019.
Of the 11.7 MW added last year, 8.7 MW came from projects using large-scale turbines (greater than 1 MW), while 1.2 MW came from mid-sized turbines (101 kW to 1 MW) and 1.8 MW came from small wind turbines (up to 100 kW). DOE said small turbine manufacturers are reporting that potential customers are increasingly expressing interest in microgrids or hybrid systems.
Distributed wind energy caters to a diverse group of customers, including military operations, municipal water systems, prisons, parks and tribal governments. In 2021, utility customers accounted for 56% of the total distributed wind capacity, while agricultural customers accounted for 56% of the total number of new projects installed. Between 2012 and 2021, 90% of the distributed wind projects were interconnected for on-site use, while the remaining 10% served local loads on distribution systems.
Although distributed wind occupies a tiny niche now, the National Renewable Energy Laboratory’s Distributed Wind Energy Future Study says it has an economic potential of 919 GW behind the meter and 474 GW in front of the meter.
“The projections increase substantially in a 2035 scenario that includes more policy support, namely the extension of the federal investment tax credit and relaxed siting conditions,” DOE said.
New Jersey’s solar sector will need to significantly ramp up the pace of installations to reach the state’s goal of 12.2 GW by 2030, even after a growth spurt in the first half of 2022 that helped the state reach an installed capacity of 4 GW.
The New Jersey Board of Public Utilities (BPU) said it expects to reach the goal by nearly doubling the annual installation capacity to about 750 MW though 2027. That will be achieved through the implementation of a permanent community solar program, replacing the current pilot, and the launch of a new program approved by the board last year to support the development of grid-scale solar projects, spokesman Peter Peretzman said.
The state’s ambitious solar goals, set out in Gov. Phil Murphy’s Energy Master Plan, call for New Jersey to install 5.2 GW of capacity by 2025, add another 7 GW by 2030 and reach 17.2 GW by 2035.
Data released by the BPU last month showed that the state added 195.2 MW of capacity in the first six months of the year. If it continues to add capacity at that pace through 2022, the state would add 390.4 MW in total, the highest amount in a year since 2019, when it added 453 MW.
The acceleration in installation follows a dramatic increase in the state’s solar project queue: from 523 MW in January 2021 to 1.6 GW a year later. BPU officials said in March that they expect the elevated capacity to be converted into strong installation figures this year. (See NJ Solar Pipeline Surges While Installations Drop.)
In a statement released last month to mark the state’s achievement of 4.03 GW, BPU President Joseph Fiordaliso called it a “significant milestone” in the sector’s development.
“New Jersey has been a leader in solar, and our solar initiatives are a key part of our clean energy future,” he said. The release predicted that the state’s solar capacity would “double in the next four years.”
Yet the figures also highlight how much the state will have to do to reach its goals. At an annual increase of 390.4 MW of new capacity, the state would surpass the 2025 goal but fall far short of the 2030 goal, reaching only about 7.5 GW. And even if the state does install 750 MW/year, as the BPU hopes, the sector would fall short of both targets.
The BPU said the fourth quarter of the year is usually a strong one, so the annual installation total for 2022 may be slightly higher than an estimate based on present figures. Yet much of the capacity needed to reach 750 MW will come from new programs, according to agency calculations, coupled with what Peretzman called “an extremely strong 2022.”
“This strong performance from the residential and smaller [commercial and industrial] sectors is expected to continue,” he said in an email. He added that the installation pace would especially pick up once the “federal incentives under the Inflation Reduction Act kick in.” (See Biden Signs Inflation Reduction Act.)
Scott Elias, senior manager of Mid-Atlantic state affairs for the Solar Energy Industries Association (SEIA), said it is “amazing” that New Jersey has reached 4 GW but said that it has nevertheless lost ground in recent years compared to other states.
That decline was demonstrated in the Solar Market Insight Report, compiled by SEIA and Wood Mackenzie and released earlier this year, which showed New Jersey falling significantly in national rankings based on megawatts installed per year. In 2019, the state took the No. 9 spot but dropped to 12 in 2020 and 20 in 2021.
“We don’t yet know the results for 2022,” Elias said in an email. “But that trend appears likely to continue. New Jersey needs to increase annual installation rates, not decrease them, or it will risk falling short of Gov. Murphy’s Energy Master Plan.”
New Program Capacity
The aim of the permanent community solar program, which the BPU expects to be in place next year, is to install 150 MW of capacity a year, though it could take a while to see those projects in action.
The BPU has awarded 150 projects totaling 240 MW in the two phases of the pilot program. But three years after the first batch was approved, the state has only installed 17 projects totaling 35.6 MW (as of the end of June).
The board earlier this month celebrated the completion of the first project in the second phase, a 500-kW installation covering the six roofs of a storage facility in Neptune Township. But solar projects across the nation have struggled with supply chain issues in the aftermath of the COVID-19 pandemic, and developers say getting municipal approvals has sometimes been slow in New Jersey. (See NJ Celebrates Completion of First Phase 2 Community Solar Project.)
The BPU hopes that a sizable chunk of future installed capacity, about 300 MW, will come from the Competitive Solar Incentive (CSI) program, which it approved in July 2021 as part of a two-pronged reshaping of the Successor Solar Incentive Program (SuSI). Under CSI, developers of solar projects above 5 MW would participate in a competitive bid to set the level of payment they would receive for solar renewable energy credits (SRECs) for their projects. Both behind-the-meter and grid-tied projects above 5 MW could participate, and the BPU would rank the bids and award the incentives to the lowest bidder. (See NJ Hearing Debates 300 MW Competitive Solar Solicitation.)
Although the BPU has approved the program, the rules have yet to be put in place, and no auctions have taken place. The board expects to launch it in the last quarter of 2022. (See Proposed NJ Solar REC Program Wins Initial Support.)
“The CSI program is scheduled to procure 300 MW of solar as part of one large competitive solicitation,” Peretzman said. “In other words, this single auction, scheduled to launch later this year, will procure almost as much new solar as all of the board’s other programs combined. These larger projects have longer development timelines, so this capacity is expected to come online over the next few years.”
He said the board also expects to see installation growth from the second element of the SuSI program, known as the Administratively Determined Incentive (ADI) program. Under this program, the BPU sets the incentive levels for net-metered residential projects, net-metered nonresidential solar projects of 5 MW or less, and community solar projects.
The incentive levels — ranging from $70 to $100, depending on the type of project — are lower than in the past. But BPU officials said that after years of the state nurturing the sector, there is enough demand for the state to stimulate new projects at the recast incentive level.
That program should also eventually generate 300 MW of installation year, adding to the existing increase in the state’s installation performance, Peretzman said.
About 40% of the proposed capacity seeking interconnection in NYISO’s class year 2021 is not deliverable without expensive transmission upgrades, the ISO told the Operating Committee Aug. 18.
To obtain capacity resource interconnection service (CRIS) — required for projects to participate in the NYISO’s wholesale capacity market — projects must be found “deliverable” at their requested CRIS level. If a project fails the applicable deliverability tests, system deliverability upgrades (SDUs) are required to obtain CRIS. Projects can proceed without committing to accept SDUs if they are willing to participate only in the ISO’s energy market.
The ISO’s Facility Studies Preliminary Deliverability Analysis Draft Report, which was approved by the committee Thursday, estimated that if all projects in the 2021 Class Year accept their cost allocations in the initial decision round, almost $1.5 billion in upgrades would be required for the 16 projects found not deliverable, 10 of them on Long Island.
If all 10 of the projects on Long Island proceed, the SDUs would cost an estimated $914 million (±50%) in upgrades, including two phase angle regulator (PAR)-controlled 138-kV lines, uprating of six 69-kV lines, and addition of a third circuit between the EGC tap and Valley Stream 138-kV line.
Five solar projects in the Thousand Island area near the St. Lawrence River that failed the deliverability test would require an estimated $200 million (±50%) to rebuild 25 miles of the Taylorville-Boonville lines 5 and 6 if all five projects proceed with their requested CRIS.
The 650-MW Swiftsure Energy Storage project in New York City would need to commit to funding an SDU, including a PAR-controlled 345-kV line between the Goethals 345-kV station and the W. 49th Street 345-kV station, at an estimated $382 million (±50%), to obtain CRIS.
Developers whose projects failed the deliverability tests have been given 10 days to decide whether to proceed to additional SDU studies, which would provide binding cost estimates.
The 2021 class year included 55 projects totaling 10,148 MW that requested CRIS, including seven wind projects totaling 3,076 MW; 22 solar projects (2,650 MW); 23 energy storage projects (2,902 MW); and one 270-MW solar/storage hybrid project. Also in the class were two projects related to the Champlain Hudson Power Express’s plans to inject 1,250 MW at the New York Power Authority’s Astoria Annex 345-kV substation.
New York City (Zone J, 13 projects, 2,818 MW), Long Island (Zone K, 10 projects, 2,867 MW) and the Central area (Zone C, seven projects, 785 MW) had the majority of the projects.
Interconnection Study Process Questioned
The ISO’s review of the reliability impact study for an 80-MW solar project seeking to connect to a 115-kV line on National Grid’s Niagara Mohawk Power (NYSE:NGG) system prompted questions about the grid operator’s study processes from Operating Committee Chair Matt Antonio, an operations manager at National Grid’s control center.
The Tabletop Solar Project (queue #869) would connect on the Clinton Substation-Clinton Tap 115-kV line in Montgomery County, N.Y.
The ISO found the project caused N-1-1 thermal overloads and N-1-1 over- and under-voltages in the study area. The thermal overloads were fully mitigated by re-dispatching the generation at the Moses-Saunders dam on the St. Lawrence River. The high-voltage violations observed were mitigated or brought to pre-project voltages by turning on a reactor at Coopers Corner. The low-voltage conditions observed were mitigated by changing the tap positions of Rotterdam transformers 7 and 8 and the Inghams PAR after the first level contingency.
“I don’t believe that [the report] reflects reality, and how the system would actually be operated,” said Antonio. Re-dispatching Moses-Saunders “may be an answer, but it isn’t necessarily the answer that would be taken in real-time.”
Antonio also questioned the report’s finding of an instability problem, which the ISO ultimately determined was present in the pre-project base case. He said such reports should be subject to a “sanity check” before they are released to ISO members for approval. “The report was put out saying there’s a stability issue pre-project. So that’s worrisome,” he said.
The ISO said the issue appears to be a modeling discrepancy in the pre-project case and agreed to investigate the modeling issue further.
The ISO’s Thinh Nguyen said the grid operator didn’t find it necessary to hold off on Operating Committee approval of the study report, saying there was no need “to hold the project hostage” when the problem is with the base case and not because of the project itself. He said finding the cause of the modeling discrepancy is “like finding a needle in a haystack,” but committed to investigate it further to avoid confusion in future studies.
Antonio said he would like to see the ISO’s process “more streamlined … more thorough and more accurate.”
Nguyen closed the meeting by announcing that ISO officials will present plans for improving the interconnection process at the next Transmission Planning Advisory Subcommittee meeting Sept. 1.
He said the ISO improved its portal to increase the transparency to project stakeholders in April and is seeking to hire two project managers to provide “one-on-one service” to project developers. In addition, the ISO is seeking to add two stakeholder services representatives to help manage stakeholder inquiries related to the interconnection process.
Antonio asked if the ISO was attempting to shorten the process, saying National Grid must refer potential customers to the ISO for connecting loads larger than 10 MW. “It’s tough to explain to a customer, and occasionally they make the decision that New York isn’t the place for them because of how long it takes,” he said.
Nguyen responded that the ISO plans to “streamline the scope without jeopardizing the reliability of the system.”
