Dominion Energy (NYSE:D) on Wednesday announced a net loss for the fourth quarter of $42 million and net income of $994 million for the entire year of 2022.
Earnings were down according to GAAP, but operating earnings for the fourth quarter were $903 million, up from $752 million a year earlier. Differences between the two were from the impairment of some nonregulated solar generation facilities, the market-to-market impact of economic hedging activities, gains and losses on nuclear decommissioning trust funds, regulated asset retirements and other adjustments.
The firm delivered earnings and dividend growth in line with its guidance, while providing safe, reliable and affordable energy to consumers, CEO Robert Blue said on an earnings call.
“We’re very focused on ensuring that our customers are not priced out of the significant long-term benefits that will result from our decarbonization and resiliency investment programs,” Blue said. “On that same theme, 2022 was a significant year in terms of advancing our regulated, decarbonization and resiliency strategy.”
The Virginia State Corporation Commission approved several investment programs eligible for rate riders, including the company’s offshore wind farm, new solar and storage facilities, grid upgrades, and license renewals for its four nuclear reactors in the state at North Anna Power Station and Surry Power Station.
Additional rider-eligible investments currently under SCC review include additional solar and storage projects in Dominion’s third annual clean energy filing, and high-voltage transmission needed to serve growing customer demand and data center load.
Dominion also owns nuclear plants in other states, including the Millstone Nuclear Power Plant in Connecticut that is under a long-term contract with the state that proved beneficial to customers, Blue said, saving them $300 million last year as power prices in New England were up. The plant is important to the entire region of New England, especially in terms meeting its states’ goals of decarbonization reliably, he said.
“We see the possibility of being able to take action with policymakers to give us the certainty we would need in order to extend the life of millstone and have that valuable resource for New England for some time to come,” Blue said. “We don’t have, as yet, a specific approach to that, but we’re certainly interested in engaging with policymakers on that.”
Dominion has been involved in discussions in Richmond, Va., over the future of how it will be regulated in the state, with multiple bills moving through the legislature this session, which runs until Feb. 25. The legislature is working on two bills that Blue highlighted on the earnings call: one with a series of changes to how the SCC sets its rates, and another that would allow Dominion to get a partner to help it build its 2.6-GW Coastal Virginia Offshore Wind project.
The Virginia Senate passed Dominion-backed legislation on the SCC’s ratemaking authority in a 27-13 vote on Tuesday, with all but two of the “no” votes coming from Democrats.
Senate Bill 1265 included language about recovering deferred fuel costs, requiring the SCC to set its rates at the average of a peer group of other large utilities in the South and removing $350 million from rate riders and putting them into base rates. Its companion bill in the House of Delegates, House Bill 1770, passed by a 52-47 vote on Tuesday as well, with the no votes coming from Democrats.
The legislature has to work out any differences between the two bills and others involving the SCC’s authority. The governor would then have until March 27 to sign, veto, or offer amendments to legislation, which could kick the process back to the legislature that meets on April 12 to deal with the governor’s actions. Gov. Glenn Youngkin then has until mid-May to act on any legislation passed or amended during that reconvened session a month prior.
Blue resisted offering any predictions on what would ultimately come out of the process on the earnings call. Dominion is working on a review of its overall business, but the direction that will take will be dependent on legislative outcomes in Virginia.
“Having a clear and definitive understanding of the future Virginia regulatory construct is a key input for the business review,” Blue said. “Therefore, legislation timing will influence the cadence at which we’re able to share more details about the business review in the future.”
Ninety percent of new generation built to meet global electricity demand over the next three years will be renewables and nuclear, according to a new report from the International Energy Agency released Wednesday.
While worldwide energy demand grew only about 2% in 2022, Keisuke Sadamori, director of energy markets and security at IEA, predicted a more robust 3% growth rate in demand per year through 2025. Emerging economies’ demand for power will be a key driver, as will advanced economies’ push for electrification to decarbonize their transportation, industrial and food sectors, Sadamori said during a media briefing on the report Tuesday.
To meet that demand, renewables will add 2,449 TWh of power to global grids by 2025, with nuclear playing a more modest role with an additional 303 TWh, and fossil fuels edging down.
“Renewables will make up over one-third of the global generation mix by 2025,” the report says. “This trend is supported by government pledges to increase spending on renewables as part of economic recovery plans, such as the Inflation Reduction Act in the United States.”
“And we should note that the substantial growth in renewables will need to be accompanied by accelerated investments in grids and flexibility, such as energy storage systems, for their successful integration into the power system,” Sadamori said.
While the U.S. market is not a primary focus of the report, the global trends discussed correspond to the current opportunities and challenges of the electric power sector here.
For example, the report’s view on the U.S. industry is mixed, predicting only modest gains in demand in the next few years. While the U.S. surpassed prepandemic levels of electricity demand in 2022, IEA sees a 0.6% drop this year “due to an expected slowdown in economic activity, before returning to an annual growth of about 1.2% in 2024 and 2025.”
However, renewables will continue healthy growth, with wind energy up 19% over 2022 levels by 2025, and solar up 56%, supported by clean energy spending in the IRA.
The U.S. Energy Information Administration recently released its predictions for new electric power generation in 2023, with renewables, storage and nuclear providing about 86% of the expected growth in supply. Solar leads with more than half of the new generation, a total of 29.1 GW.
IEA also tracks a major shift in power demand, from the U.S. and Europe to Asia. Between 2015 and 2025, China will grow from using 25% of the world’s electricity to 33%.
US has Lowest Power Price Increases
But the growth of renewables may not necessarily result in the broad reductions in carbon emissions needed to meet the Paris Agreement’s target of a worldwide net-zero economy by 2050.
Carbon emissions climbed to record highs in 2022, pushing the world well off a path to net zero, Sadamori said.
Worldwide, the electric power sector produces about 40% of global CO2 emissions, he said. The 2022 increase was largely from increased fossil-fueled generation in Europe, with Russia’s invasion of Ukraine pushing up power prices, especially in the unregulated markets of some European countries. Despite record inflation, the U.S. saw the lowest level of wholesale power price increases among advanced economies, the report says.
Sadamori believes the increase in CO2 emissions is temporary and will come down as the U.S. and Europe ramp up programs for deploying renewables and nuclear. But the decrease in emissions in the West could be offset by ongoing fossil fuel generation in Asia.
Africa presents a particularly sensitive challenge. The continent represents about 20% of the world’s population but only 3% of its electric power generation. Whether it can build out a primarily renewable electric power system remains uncertain.
IEA also sees ongoing complexities in the interaction between increased renewables on the grid and the increased frequency and severity of extreme weather events, which can drive sudden spikes in demand while also exposing system vulnerabilities.
“Mitigating the impacts of climate change requires faster decarbonization and accelerated deployment of clean energy technologies,” the report says. “At the same time, as the clean energy transition gathers pace, the impact of weather events on electricity demand will intensify due to the increased electrification of heating, while the share of weather-dependent renewables continue to grow in the generation mix.”
Energy Efficiency First
“In such a world, increasing the flexibility of the power systems while ensuring security of supply and resilience will be crucial,” the report says. Diversity of supply will be needed to ensure security, Sadamori added.
Accelerating a clean energy transition should focus first on energy efficiency with substantial government support “because the energy efficiency will lead to smaller amounts of new energy requirements,” Sadamori said. “So, that means the renewables and nuclear can provide more of the growth of the entire electricity demand.”
The report also points to vulnerabilities in the U.S. grid, such as the widespread power outages during the December winter storm. Maintaining and making “wise use” of dispatchable fossil fuel resources, in particular for emergencies, should not lead to increased carbon emissions, Sadamori said.
He also said that IEA sees carbon capture and sequestration as a long-term solution for emissions reductions, but not in the next three years. The technology is “kind of a work in progress,” Sadamori said. “It is being developed, but I don’t think they can make a substantial dent in CO2 emissions in the coming years.”
House Republicans and Democrats squared off Tuesday over a series of 17 proposals from the new GOP majority to lessen environmental and other regulatory barriers to domestic energy production.
Each side made their points in exchanges with witnesses generally aligned with their own points of view, stressing the importance of passing or not passing the measures.
As more than one Democrat pointed out, however, entire pieces of the Republican package stand little chance of becoming law because of opposition from the Democrats who control the Senate and White House.
The joint Energy, Climate, and Grid Security Subcommittee and Environment, Manufacturing, and Critical Materials Subcommittee legislative hearing was titled “Unleashing American Energy, Lowering Energy Costs and Strengthening Supply Chains.”
As the name implies, the measures being discussed would codify some items on the wish lists of U.S. fossil fuel companies and their Republican allies.
The GOP took control of the House only a month ago, and most of the 17 bills and resolutions had not yet been formally introduced Tuesday morning as testimony started.
Among other things, the bills would:
bar a moratorium on fracking;
repeal the methane emissions tax included in the Inflation Reduction Act of 2022;
improve state and federal interagency cooperation to build interstate natural gas pipelines;
repeal all restrictions on import and export of natural gas;
repeal the greenhouse gas reduction fund;
authorize the Environmental Protection Agency to issue flexible air emissions permits for certain facilities; and
ban import of certain uranium from Russia.
Witness Testimony
The witnesses at the hearing ranged from a former FERC member to a leader in the environmental advocacy legal organization Earthjustice.
Rep. Brett Guthrie (R-Ky.) sprinkled personal experiences and world events into a statement on the importance of the U.S. producing enough fuel for itself and friendly nations and asked for witnesses’ thoughts.
Jeffrey Eshelman, II, CEO of the Independent Petroleum Association of America, said: “If we continue to produce oil here at home, those are jobs that remain; if we would stop exporting the oil, those jobs disappear. It actually helps when we’re producing more here and … exporting, to keep those wells pumping. … It helps our allies, and it helps our own national security.”
Rep. John Sarbanes (D-Md.) asserted that the GOP drive to “unleash American energy” is often designed to unleash profit-making by big oil companies by eroding bedrock environmental laws at the expense of the health and safety of American people. He asked if there was truly a binary choice between protecting the safety of communities and producing energy.
Raul Garcia, legislative director for healthy communities for Earthjustice, said: “We can absolutely do both. We have the technology, and, in fact, some of the legislation presented today would actually curtail that technology, which is sad to see.”
Rep. Morgan Griffith (R-Va.) spoke of the coal bed methane capture project underway in his district, at the largest coalmine in the state. This technology could work to capture other leaks of the potent greenhouse gas, he said, “but they don’t get any credit for having a clean, efficient way because it’s the dreaded fossil fuel, it’s natural gas.”
Bernard McNamee, appointed a FERC commissioner by President Trump in 2018, said American innovation has produced many advances in energy production, and the methane capture Griffith described is one more useful tool. “It’s great to talk about, ‘We think we can go 100% renewable,’ but the reality is, with the technology we have today, we have to have dispatchable energy, and that’s going to come from natural gas, from the methane that’s captured at the coal seam.”
Mark Menezes, a deputy energy secretary under Trump, said there are multiple existing technologies that can protect the climate. “Remember, our quest here is not to choose one type of energy over another, our quest here to solve the climate problem is to reduce emissions.”
Rep. Larry Bucshon (R-Ill.) called out those pushing for widespread electric vehicle adoption while simultaneously opposing U.S. mines that would produce the lithium, cobalt and other materials needed for EV batteries. America, he said, needs to not rely on slave labor in Africa and the output of Chinese factories for these materials.
Katie Sweeney, executive vice president of the National Mining Association, thanked Bucshon for his words and said the proposed legislation would make more people aware of the critical connection between minerals and energy. “There isn’t any form of energy that doesn’t rely on minerals as the base of that energy … it’s not just the mines themselves but the processing that needs to take place here in the U.S.”
Rep. Scott Peters (D-Calif.) took some swipes at his Republican colleagues but spoke of the need for bipartisan updates to energy policy; he found some agreement from witnesses on both sides of the aisle.
He asked Menezes — who helped negotiate the Energy Policy Act of 2005 — about streamlining the approval process for interstate transmission construction. Menezes replied that then as now, there are probably more difficult things to accomplish than siting and building interstate power lines, but he couldn’t think of any. Such power lines will be critical to the green energy transition, he said, and “I think this is something that’s certainly within this committee’s jurisdiction to take another look at.”
Peters asked Tyson Slocum, director of the energy program at Public Citizen, whether the oil and gas industry would reduce its emissions of methane without the incentives and oversight contained in the Inflation Reduction Act.
“I don’t think so,” Slocum said. “I think you need to have that regulatory structure in order for the industry to make those investments.”
GOP Proposals
The prepared testimony of the six witnesses and the wording of the 17 pieces of proposed legislation are available on the House Energy and Commerce Committee webpage.
A summary of the legislation follows.
Three bills introduced:
H.R. 150, Protecting American Energy Production Act: Prohibits a moratorium on the use of hydraulic fracturing unless authorized by an Act of Congress.
H.R. 484, Natural Gas Tax Repeal Act: Eliminates the tax added to the Clean Air Act last year.
H.R. 647, Unlocking Our Domestic LNG Potential Act of 2023: Amends the Natural Gas Act to repeal all restrictions on the import and export of natural gas.
Fourteen bills and resolutions expected to be introduced:
Promoting Cross-border Energy Infrastructure Act: Establishes a more uniform, transparent and modern process to authorize the construction, connection, operation and maintenance of international border-crossing facilities for the import and export of oil and natural gas and the transmission of electricity.
A concurrent resolution expressing disapproval of the revocation by President Biden of the presidential permit for the Keystone XL pipeline.
Promoting Interagency Coordination for Review of Natural Gas Pipelines Act: Improves coordination among federal and state agencies reviewing applications for the construction of interstate natural gas pipelines.
Securing America’s Critical Minerals Supply Act: Amends the Department of Energy Organization Act to require the secretary of energy to conduct an ongoing assessment of the nation’s supply of critical energy resources, the vulnerability of the critical energy resource supply chain and the importance of critical energy resources in the development of energy technologies.
Critical Electric Infrastructure Cybersecurity Incident Reporting Act: Amends the Federal Power Act to authorize DOE to promulgate regulations to require critical electric infrastructure owners and operators to share information regarding cybersecurity incidents with DOE.
A bill to require the secretary of energy to direct the National Petroleum Council to issue a report on the importance of petrochemical refineries to U.S. energy security, and the opportunity to expand their capacity.
A bill to amend the Clean Air Act to prohibit the phase-out of gasoline and prevent higher prices for consumers and for other purposes.
A concurrent resolution expressing the sense of Congress that the federal government should not impose any restrictions on the export of crude oil or other petroleum products.
A bill to repeal section 134 of the Clean Air Act, relating to the greenhouse gas reduction fund.
A bill to authorize the administrator of the Environmental Protection Agency to waive application of certain requirements, sanctions or fees with respect to processing or refining of critical energy resources at a critical energy resource facility, and for other purposes.
A bill to amend the Toxic Substances Control Act with respect to critical energy resources, and for other purposes to address repeated delays with EPA reviewing and making legally mandated, timely determinations of pre-manufacturing notices for new critical energy resources and new uses of existing critical energy resources.
A bill to amend the Solid Waste Disposal Act to treat the owner or operator of a critical energy resource facility as having been issued an interim permit for the treatment, storage and disposal of hazardous waste, and for other purposes.
A bill to require the EPA administrator to authorize the use of flexible air permitting with respect to certain critical energy resource facilities, and for other purposes.
A bill to prohibit the U.S. from importing unirradiated low-enriched uranium produced in the Russian Federation.
New Jersey officials are moving to overhaul the clean energy strategy that steered the state to becoming one of the most aggressive carbon reducers in the nation, with a year-long revamp of its Energy Master Plan in the works and a legislative initiative to mandate zero emissions by 2035.
The new plans emerged in a flurry of activity over the last two weeks, including the abrupt cancellation of stakeholder hearings aimed at revising the state 2019 Energy Master Plan. Some stakeholders said the effort is a necessary response to the maturation of the state’s clean energy sector and the massive support for clean energy in all states by the federal Inflation Reduction Act.
The push to retool comes after advancements stemming from the policies outlined in the last master plan, among them surging growth in solar generation, a new offshore wind sector and grid upgrades to handle the new power — and amid concerns about cost among business groups and Republicans.
The New Jersey Board of Public Utilities (BPU) initially planned to start a revamp of the master plan with stakeholder input solicited at public hearings scheduled for Jan. 26 and Feb. 16. But Gov. Phil Murphy cancelled the hearings on Jan. 20 when he announced his own plans for the development of a new Energy Master Plan, targeted for release in 2024.
In an apparently unrelated move, but one likely to have a big impact on the same terrain, Sen. Bob Smith on Jan. 27 released legislation that would reshape the state’s clean energy sector.
The bill, a substitute for an existing bill, S2978, would establish and implement a sweeping new clean electricity certificate program to cover all energy sources, replacing the certificates granted to individual sectors such as solar, wind and nuclear power. The bill would require electricity suppliers to purchase a certain number of certificates each year so that they account for 70% of their retail sales by 2026, 85% by 2030 and 100% by 2035.
Assessing State Progress
Both the Murphy master plan update and Smith proposal are “hugely important for how we expand clean, renewable energy in the state,” said Doug O’Malley, director of Environment New Jersey.
“So, it makes sense to kind of update the energy master plan based on the Inflation Reduction Act, and it makes sense to strengthen our state, clean, renewable energy targets.” He added that the state typically updates the master plan every five years, putting Murphy on that schedule.
In a release explaining his plan, Murphy said the state needs to not only “assess our progress to date, but renew our commitment to a clean energy economy while taking stock of the breadth of resources at our disposal.” The master plan sets a state goal of reaching 100% clean energy by 2050.
The release said that shooting to complete the master plan update by 2024 would give “additional time needed to focus on data-driven modeling” and ensure the plan “demonstrates the full economic and environmental impacts of clean energy policies.”
“Only by developing and diligently pursuing an updated climate mitigation strategy can we build upon our efforts to cultivate resilient and sustainable communities,” Murphy said in the release. “In addition to taking into consideration the implications of new state and federal policies, the 2024 Energy Master Plan will seek to better capture economic costs and benefits, as well as ratepayer impacts, throughout our journey toward a clean energy future.”
Murphy will convene a new Energy Master Plan Committee and reschedule the cancelled stakeholder meetings for later this year.
Cost vs Affordability
The revamp comes amid criticism that four years after release of the master plan, Murphy has not told the public how much it will cost to implement. A report released by the BPU in August showing that some residents could see a 16% energy cost reduction under the plan did little to quell the concern. Critics said the analysis didn’t consider the hefty investments needed to reap those savings, such as buying an electric vehicle and investing in electric home heating systems. (See NJ BPU Approves Report on Costs of Energy Master Plan.)
Raymond Cantor, vice president of government affairs at the New Jersey Business and Industry Association (NJBIA), one of the state’s largest business groups, said the reevaluation of the master plan is timely but raises concerns that it will repeat the focus of the last plan on cutting emissions by shifting the state to a reliance on electricity. NJBIA would like to see greater consideration of alternative fuels such as hydrogen and renewable natural gas.
“We need to understand what this is going to cost,” he said. “Energy is the fundamental basis of our economy and standard of living. We need to know if what they’re proposing is going to be affordable or not.
“They talk about least-cost. But least-cost is not necessarily affordable cost,” he said. “If people can’t afford energy, then they’re going to suffer.”
On the Smith bill, Cantor expressed concern that it sets “unrealistic” targets.
“Setting unrealistic targets, and then asking government to enact policies to meet that, is only going to result in unreliable energy sources — and that’s not acceptable,” he said. “We should be aggressively pursuing rational policies that will get us there, not setting unrealistic deadlines.”
Starting a Discussion
S2978 would provide generators with a clean electricity attribute certificate (CEAC) for each megawatt-hour of energy they produce. The bill would allow suppliers to retire existing energy certificates, among them Offshore Wind Renewable Energy Certificates (ORECs), Solar Renewable Energy Certificates (SRECs), and Transition Renewable Energy Certificates (TRECs) awarded in a now-closed temporary solar incentive program.
The bill also allows for the retirement of zero-emission credits (ZECs), awarded for nuclear generation, and limits the amount of the state’s electricity that can be sourced from nuclear plants to 40% of the 2017 generation figure.
Smith, who heads the Senate Energy and Environment Committee, said the aim of the bill is to “unify the energy incentive programs.”
“It’s going to be a pretty significant change from what we have been doing,” he said. “It’s going to start the discussion in how we do the energy policy in the state.”
“The point of it is to make our incentive programs more effective, and also, believe it or not, to lower costs,” he said. “At the end of the changes, we expect to see a reduction in rates.”
O’Malley said S2978 is needed, in part, because current state law sets a goal of achieving 50% clean energy by 2030 but sets no target beyond that. When that goal was set, for example, the state’s plans for offshore wind were minimal compared to the rapidly advancing sector underway, he said.
“This is where Sen. Smith is filling the gap,” he said. “Most states have clear clean energy goals and mandates through the next decade. We need to clarify that now for the electric market.”
Ed Potosnak, executive director of the New Jersey League of Conservation Voters, called it a “strong” bill, but one the organization couldn’t support in its present form because it allows six trash-burning incinerators around the state to generate some of the needed electricity.
“They’re not clean,” he said. “They shouldn’t be in a clean energy standard.”
The removal of the incinerator support would make the bill acceptable, although the group will also push for other changes, he said, including increasing the amount of clean energy that must be generated in-state to above the current 50% requirement, in part, because of the economic and employment opportunities for the state.
The master plan upgrade is needed because of the enactment of the Inflation Reduction Act, the availability of superior technology to model the impact of climate change and efforts to combat it, the changing social attitudes toward the problem and the apparent acceleration in the impact of climate change, he said.
“There’s both an urgency and a need, and also the ability,” he said. “And I think when those things converge, that’s when you get a real chance to update that plan.”
The electric sector must fundamentally reconsider how it measures and manages grid reliability in response to a changing climate and evolving generation mix that increasingly includes variable resources.
That was a key takeaway from an online panel hosted by WECC on Thursday, the first of the regional entity’s monthly discussion series this year on resource adequacy.
While the message is not necessarily a new one, panelists offered some fresh perspectives.
“I think [what] we’re really coming down to is [that] capacity used to be king; I like to say the king has no clothes,” said Mark Lauby, NERC senior vice president and chief engineer.
Lauby was referring to the industry — and NERC — requirement that an electricity network be designed to meet the one-in-10 loss-of-load expectation (LOLE) standard, which calls for utilities to manage their systems in a way that demand doesn’t exceed available supply for more than one day in every 10 years. At the heart of LOLE is a focus on carrying enough generating capacity to meet the highest expected loads with a safe reserve margin.
But the makeup of the grid has changed since the advent of the LOLE standard, Lauby noted, and so have the conditions under which it operates. With climate change, weather is becoming more volatile, and weather events such as cold snaps are lasting longer, particularly in areas not accustomed to such events. That change has prompted NERC to alter its approach to producing its reliability assessments.
“Now we’re actually laying out different types of scenarios and working with regional entities in the assessment areas to say, ‘OK, what about a cold winter?’ And let’s kind of figure out what that looks like,” he said. “What is extreme cold weather for a particular assessment area? And then we work with them to determine what might be the forced outage rates for the plants, because when things get cold, things kind of break a little bit at a higher rate.”
Instead of focusing on capacity, Lauby said, the industry must shift its lens to measures of energy and essential reliability services, such as frequency and voltage support and ramping capability.
“We were cheating by using capacity because we had firm fuel, and we don’t have that anymore in many cases [and conditions] are less certain, and we’re actually becoming more and more less certain. So how do we firm that up? What does that look like?” he said.
“We have to develop a whole new set of metrics to understand exactly what are the risks we’re dealing with as we transform this grid. And we can do it; we just got to do it in a way in which we can ensure that we can not only deal with the short ramps and the short conditions, but also the long-term widespread conditions,” Lauby said.
Small Perturbations, Bigger Impacts
Oregon PUC Commissioner Letha Tawney | WCPSC
Oregon Public Utility Commissioner Letha Tawney expanded the critique on industry convention, questioning long-held beliefs on what constitutes a reliable resource mix in a warming climate.
“I’m not sure the traditional generation stack is performing particularly well in the face of the stress of climate change,” Tawney said. She pointed out that, during a heat wave last summer, a large coal plant in the Northwest tripped offline because of water scarcity and heat stress, pushing two Oregon utilities into emergency alerts.
Tawney also warned that the changing climate is putting stress on the Northwest hydroelectric system. She said current high natural gas prices in the West are at least partly attributable to relatively low hydro flows.
“I think the variability we may see in the hydro system could really stress us as we get sort of to that outer edge. We’re running sort of with less margin in general, and so small perturbations create bigger impacts then maybe they did when we were much longer on [hydro] resources,” she said.
George Lynch, legal counsel for the Idaho Governor’s Office of Energy and Mineral Resources, echoed Tawney’s concerns about the Northwest hydro system. Lynch said that while his state has seen “really rapid development” of renewable resources, his office has “also worked to support dispatchable resources such as nuclear and geothermal, especially as we see our hydropower declining over time, or at least becoming a little less reliable than has historically been.”
Lynch said Idaho has historically enjoyed cheap electricity because of its hydro system, which has attracted businesses that have taken advantage of the low prices.
“We’ve also had really low natural gas prices, but I think natural gas prices across the region have increased up to threefold this last winter … due to the lower hydro output, so that’s something that we’ve been watching,” he said.
More Humility Needed
Tawney turned her attention to the broader West, pointing to the challenges the Western Area Power Administration faces in preventing Arizona’s Lake Powell from reaching “dead pool” status amid a record-long drought. That would curtail output from the Glen Canyon Dam and hobble the Southwest’s black start capability and ability to maintain a stable grid. “That’s a long-term challenge,” she said.
Tawney said the power sector hasn’t really grappled with the fact that even Oregon is enduring its longest drought in 1,200 years. “I think we don’t think ahead to [whether] the coal plants, or any of the thermal plants, [will] have the temperature of water that they need during one of these heat events to cool. Will they be able to access their water rights, or will they be supplanted because it’s a particularly bad year?”
The Oregon commissioner defended California’s response to the energy emergencies accompanying last September’s scorching heat wave, when CAISO was forced to rely on last-minute conservation measures and a high volume of imports to avoid blackouts in the face of record demand. She called for more “humility” among neighboring states that also would’ve struggled to meet loads that fell so far outside planning margins. (See California Runs on Fumes but Avoids Blackouts.)
Tawney said that while there’s “a lot of finger-pointing at California” around its grid issues, the state was actually confronted with “one-in-10” events.
“They’ve hit their LOLE, and there’s still a lot of focus around keeping them moving forward on staying reliable,” she said.
“Now, is one-in-10 good enough? I think that’s a different question, and it sure doesn’t seem like it is. It sure doesn’t seem like one-in-10 is actually acceptable any longer, and so that adds a real challenge,” Tawney said.
“For all of us in the West, nobody is immune,” concluded panel moderator Kristine Raper, WECC vice president of external affairs. “I think this is the lesson that we should have learned over the last handful of years.”
Commissioners Approve 90-10 Split on JTIQ Cost Allocation
SPP’s state regulators last week approved staff’s proposed cost allocation for the five projects in the RTO’s Joint Targeted Interconnection Queue (JTIQ) study portfolio.
The Regional State Committee, which has specific authority over cost allocation, accepted several recommendations from the Cost Allocation Working Group during a virtual quarterly meeting Jan. 30.
The JTIQ study with MISO was designed to find potential projects on the RTOs’ northern seam that could reduce congestion and allow additional resources, primarily wind farms, to interconnect with the two systems. The RTOs’ staff have proposed a cost allocation that assigns most of the portfolio’s $1.06 billion in costs to generation. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
The RSC unanimously approved the CAWG’s recommendations that:
generators bear 90% of the portfolio’s capital costs and that load cover the remaining 10%;
load’s portion of the JTIQ’s annual transmission revenue requirement (ATRR) be based upon adjusted production costs, as outlined by the RTOs’ joint operating agreement; and
allow each building transmission owner to recover the non-capital construction costs allocable to generator interconnection customers through the TOs’ formula rate template in their respective regions.
The commissioners also unanimously approved the CAWG’s recommendation that SPP staff ensure the portfolio is implemented in a “reasonable manner” to improve its chances of securing U.S. Department of Energy funding to improve the benefit-cost ratio for all SPP load. SPP and MISO have joined forces with the state of Minnesota and the Great Plains Institute to apply for DOE grants from the latter’s $10.5 billion Grid Resilience and Innovation Partnerships (GRIP) program. (See “SPP, MISO Applying for DOE Funds to Help with JTIQ Portfolio,” SPP MOPC Briefs: Jan. 17-18, 2023.)
The committee revised the CAWG’s motion by adding the word “reasonable” before “manner” to address a complaint from North Dakota Public Service Commissioner Randy Christmann.
“What I’m reading here is that we are willing to implement this in whatever manner the DOE comes up with in order to get them to pay for our desires,” he said. “That just basically commits us to agreeing to anything they come up with. I’m fine with pursuing the DOE funding, as long as we’re not committed to doing whatever they want.”
Three of the committee’s 11 members — representing Louisiana, North Dakota and Oklahoma — voted against the CAWG’s recommendation that SPP’s 10% load share in the current portfolio and the next study of the southern party of the MISO-SPP seam be regionally allocated on a load-ratio share basis consistent with previous RSC policies.
“I don’t think we should be making our allocation decisions based on balancing our regions,” Christmann said. “I don’t like the idea of passing something based on its pluses and minuses and saying we’re going to do this one regionwide, and in exchange, we’ll do whatever the southern end comes up with regionwide to whether it meets the criteria or not.”
David Kelley, SPP vice president of engineering, said the recommendation was consistent with other policies the RSC has reviewed and approved. He said the grid operator’s experience with importing and exporting power during winter storms proves additional transmission interconnections between regions provides “greater reliability and resiliency … going forward.”
Texas Public Utility Commissioner Will McAdams said he views the JTIQ portfolio as a “building block of a greater reliability framework” where everybody chips in.
“If you have a need on a seam, you’re going to build transmission just like road planners build highways. If you build a highway, everybody gets to use that,” he said. “We’re going to need to replace new generation, and the guiding principle for me is I would rather that new generation settle in our SPP footprint to where our RTO can control those resources … and then if they have excess, sell into MISO during scarcity periods at a profit to help reduce the cost on their loads.
“To me that makes sense, and if we see that occur in both the SPP northern area as well as the South, then that benefits everybody,” McAdams added.
Christmann proposed a separate motion that the JTIQ portfolio only receive construction notifications when the executed generator interconnection agreements can pay for 50% of the eligible engineering and construction costs.
“We’re preparing to do an approval to construct based on the fact that GI customers are going to pay 90%. That can be our plan, but if they don’t come through, somebody is going to pay the costs of that project or these projects,” he said.
Minnesota Public Utilities Commissioner John Tuma acknowledged Christmann’s concerns but pointed out that no one is forcing companies to invest in generation and that they’re capable of making their own judgments.
“I’m hoping they make the right judgment because they got to come in front of me for recovery,” Tuma said.
“If you’re a generator interconnection customer going through the process, you don’t have any certainty that the transmission will be there,” Kelley said. “Signing up to pay for transmission that may or may not be there is not something that they could get financing for.”
“My concern is that this unravels the way we normally get these people signed up for projects. … This solves a lot of the problems,” Tuma said. “I think it also jeopardizes the DOE funding because a condition like this could put a lot of the projects and ability for these projects to go forward in jeopardy. We are messing with some financial situations that I think are going to unravel what we’re doing with JTIQ and the ability to get this paid at a reasonable rate.”
Christmann’s motion failed, receiving only supporting approval from members representing Louisiana, Nebraska and Oklahoma.
Saying she valued the conversations during the discussion, SPP CEO Barbara Sugg expressed a “high degree of confidence that the generators will be there.”
“We still have a lot of work to do in the partnership with MISO that is already proving to be beneficial for both SPP and MISO and our states and our end-use customers,” Sugg said. “We’ve got to keep this moving forward.”
Missouri’s Rupp Opposes RCAR III
The RSC approved the Regional Allocation Review Task Force’s third Regional Cost Allocation Review (RCAR III) of SPP’s highway/byway transmission cost-allocation methodology.
The mechanism assigns 100% of all 300-kV or above transmission upgrades’ ATRR to all 17 transmission zones on a regional basis using a load-ratio share. One-third of upgrades with voltage ratings between 100 and 300 kV are allocated regionally and two-thirds to the host zone’s transmission customers.
RCAR III, the first such review since 2016, indicated every zone exceeded the RARTF’s 0.80 benefit-cost threshold and w above 1 when analyzing projects approved for construction since June 2010 and in service prior to 2020.
The review was conducted using the Integrated Marketplace’s daily results paired with analysis on transmission planning models, limited to those projects in service before 2020. The task force said the methodology is expected to provide more reasonable results and avoid technical issues from past RCAR studies.
Still, RCAR III drew the ire of Scott Rupp, chair of the Missouri Public Service Commission, who cast the only vote against its approval, saying he couldn’t in “good conscience” attach his name to something “that’s just so bad.”
“I feel like I’m Pontius Pilate. I’m just washing my hands with this,” Rupp said. “We’re being told that, ‘Hey, this is the one that’s the best. This is the one that’s going to fix everything and look, everybody’s great.’ I can tell you personally, that things are not great.”
Utilities in southern Missouri have long complained about the RCAR process, saying system congestion has limited their ability to move energy. The City Utilities of Springfield transmission zone was the only one found deficient in the 2016 study; it was also among six zones, mostly in the Midwest, that was deficient in the 2013 review. (See “Cost Allocation Review Cycle Could Extend to 6 Years,” SPP Markets and Operations Policy Committee Briefs.)
In December, the southern Missouri region experienced extremely low voltages caused by resource trips, lack of deliverability and parallel system flows. Empire Electric District had to shed about 25 MW of load for 15 minutes on Dec. 22.
“Basically, what SPP has done is they’ve just taken the formula and they’ve tinkered with the methodology again until they got a result that they wanted, that would just quiet everybody that’s been having concerns,” Rupp said. “Southern Missouri has been saying, ‘Hey, we need help down here’ for 10 years. Every year, we do a lessons learned after one of these things, but the lesson we’ve learned is [we’re] going to get hosed.”
Saying she felt compelled to defend SPP’s honor, Sugg said she is very aware of the region’s problems and that she respected Rupp’s position.
“This is not the place for me … or anybody else to try to unpack all of the things that you said,” she told Rupp. “I will say … I am committed to us working to … alleviate some of the challenges that we face in that area. You’ve not seen the last of this, and please don’t think that I’m dismissing anything that you’ve said.”
The previous RCARs were completed every three years. FERC in 2017 approved SPP’s request to conduct the review every six years; the grid operator said that would save staff time and consulting costs. (See FERC Approves 6-Year Cycle for SPP RCAR Review.)
Safe Harbor Criteria Unchanged
The RSC also approved the CAWG’s recommendation to keep the current $180,000/MW safe harbor criteria for a network study’s directly assigned upgrade costs (DAUC) after customers request transmission service.
To qualify for safe harbor treatment from some or all DAUC, transmission customers must meet three base-plan funding criteria: a five-year minimum commitment term; 125% or less of load in all designated resources; and, if the designated resource is wind, that 20% or less of the designated resources come from wind.
Customer can request a waiver of the criteria, and the RSC and SPP’s Board of Directors have approved the requests under certain circumstances.
The CAWG reviews the safe harbor limit and criteria each year and conducts a more in-depth analysis every five years. The group has also opened an action item to continue studying performance-based accreditation’s effects on the 20% wind rule and the 125%-of-load resource limit.
John Krajewski, who consults for the Nebraska Power Review Board, told the committee the safe harbor criteria keeps transmission customers from being charged the full rate for service and the cost of any upgrades.
This policy “basically keep customers with these long-term requests from paying twice for the same facilities,” he said.
Krajewski shared the CAWG’s recent analysis of the safe harbor requirements. It indicated 18 of 49 load-serving entities are over the 20% limit, but that a vast majority of requests qualified under the safe harbor limit.
Former Kansas regulator and past RSC President Shari Feist Albrecht has returned to SPP as the CAWG’s chair.
Albrecht chaired the Kansas Corporation Commission during much of her eight-year tenure as a commissioner. She was succeeded by Andrew French in June 2020 after her second term expired.
She has rejoined the commission as a part-time consultant. As a member of the Utilities Division’s SPP Workgroup, her responsibilities include representing Kansas on the CAWG.
The Lawrence Berkeley National Laboratory on Tuesday released updated data showing that the savings for new electric transmission lines were higher last year than at any point in the last decade.
“Generally high electricity prices coupled with extreme weather events and other factors helped drive the high value for transmission,” LBNL said in a fact sheet on its findings.
The lab looked at congestion values and found that building major new lines between important power trading hubs would lead to significant savings. Congestion is correlated with the national average of wholesale electricity prices.
“Extreme conditions and high-value periods have an outsized role in driving this value, though named extreme weather events oftentimes do not play as large a role as more normal but infrequent conditions, such as infrastructure outages or demand forecast misses,” LBNL said.
The report found that interregional transmission lines would offer the largest values, as most — but not all — the transmission links with a value above $200 million per 1,000 MW were interregional. Smaller regional lines had a significant valley, with many ranging from $100 million to $200 million per 1,000 MW.
A chart showing the mean and median values of LBNL’s hypothetical lines over the past decade | Lawrence Berkeley National Laboratory
LBNL looked into 64 hypothetical transmission projects, and their mean value was $220 million per 1,000 MW, or $25/MWh, while the median value was $193 million per 1,000 MW, or $22/MWh. Both the mean and median prices were higher than earlier years that LBNL studied.
The median value was significantly higher than in any other year, which indicates that higher transmission value in 2022 was a broad phenomenon across most of the country. That suggests a national cause, such as higher power prices, were behind the rise in transmission value.
LBNL saw higher mean values in 2018 and 2021, which indicates that certain events can drive extremely high transmission value in isolated regions. ERCOT and SPP saw transmission values spike in 2021 because of the February winter storm, the report said.
Transmission’s value is tied to high demand/high-priced hours, but the higher overall prices last year made that less true than some years. Some 50% of the lines’ studied value was from just 10% of hours and 37% was from only 5% of the hours in 2022, but from 2012 to 2021, a typical transmission line derived 50% of its value from just 5% of hours.
The final week of 2022 came with another major winter storm, which showed the role of transmission in helping to manage periods of grid stress as the average transmission link derived 7% of its annual value over that week. The total annual value of transmission lines was much more tied to the winter storm in PJM, MISO and the Northeast, where the storm provided 10 to 22% of transmission lines’ values.
The report noted that if all the hypothetical lines it studied were actually built, they would have diminishing returns. Because wholesale power markets use marginal pricing, the transmission value metric LBNL calculated represents the value of the next unit of transmission.
The lines studied would be impacted by a saturation effect as additional construction brings down their value, but LBNL said that the links connect “hub” pricing nodes that represent prices over a region and might not be as sensitive to saturation effects as a more localized pocket of demand.
WEC Energy Group’s (NYSE: WEC) leadership last week plugged the billions they will spend on transforming their utility’s energy mix in a year-end earnings call.
WEC reported fourth quarter earnings Feb. 2 of $252.7 million ($0.80/share), compared to the $224.2 million ($0.71/share) it netted for the same period last year. The utility recorded year-end net income of $1.4 billion ($4.45/share), compared to the $1.3 billion ($4.11/share) over 2021.
WEC Energy Group Executive Chairman Gale Klappa told financial analysts that the company plans to spend $20.1 billion over the next five years, up from $17.7 billion it initially targeted in 2022. He said the spend, as outlined in an updated environmental and social governance progress plan, is the “largest five-year investment plan in our history.”
Klappa said management expects the plan to drive compound earnings growth of 6.5% to 7% per year through 2027.
The plan will position WEC for “efficiency, sustainability and growth,” Klappa said. The plan includes more than $7.3 billion in new renewable investments in solar, wind and battery storage, a “major commitment to renewable projects” that is now a cornerstone of the utility, he said.
WEC announced last month it will acquire an 80% interest totaling $250 million for the first phase of the 250-MW Samson Solar Energy Center in northeast Texas.
WEC CEO Scott Lauber said the utility’s $160 million, 80-MW Red Barn wind farm in Wisconsin will come online in the next few months and its Badger Hollow II solar facility and the Paris Solar Battery Park in Wisconsin will likely go into service within the year, contingent on panel delivery.
Lauber noted that the Wisconsin Public Service Commission last year approved WEC’s purchase of the $451 million Darien Solar Energy Center. Its 225 MW of solar capacity and 68 MW of battery storage is expected online in 2024.
Laubner said the 300-MW Thunderhead Wind Farm in Nebraska is now in service; WEC has a $338 million, 80% stake in the project. He said he expects that the utility will finalize a $412 million, 90% interest in the 250-MW Sapphire Sky in Illinois in the coming weeks.
WEC plans to achieve carbon neutrality by 2050 and phase out coal use by 2030 so that it’s only a backup fuel.
PJM’s Independent Market Monitor has proposed a plan to eliminate performance assessment intervals (PAIs) and related penalties from the RTO’s capacity market, saying the non-performance charges stemming from the late-December cold snap have threatened the functioning of the market.
“Winter Storm Elliott provided the first real test of the [capacity performance] design. Elliott showed that the CP design does not provide effective incentives,” Monitor Joe Bowring said during the Jan. 31 meeting of PJM’s Resource Adequacy Senior Task Force.
Under the Monitor’s design concept, capacity resources would only be paid the capacity price when they are available in a given hour and would be required to have firm fuel, which entails access to dual fuel, multiple pipelines or a defined amount of onsite fuel storage, plus weekly testing to ensure that the resources can produce when called upon.
Capacity resources would also be subject to a must-offer requirement. When energy is valuable, resources that provide energy will be paid the high market prices for energy and reserves, as the energy market provides the correct energy pricing, Bowring said.
“If we can’t handle two days of cold weather without having a massive dislocation, we need to rethink how this market is designed,” Bowring said. “The penalties create potential threats to the incentives to invest in existing resources and to invest in the new resources that will be needed in the next three to five years.”
Bowring also said his design would replace the effective load carrying capability (ELCC) accreditation model for intermittent resources. By only paying such resources when they are delivering energy, he said the change would recognize that intermittent resources are not always available while still allowing them to be compensated for when they are online.
“ELCC is very quickly going to end up with a marginal value of zero for standalone solar and wind while continuing to have a performance obligation equal to its full capability. … What I’m proposing is something very different, which is paying capacity only when it’s available,” he said.
That tension between the reduced megawatts that qualify as capacity and the obligation to perform at the full megawatt value of the resource will make offering intermittent resources as capacity increasingly untenable under the ELCC approach.
The Monitor’s proposal would build on FERC’s 2021 rejection of the CP market seller offer cap (MSOC) and “would recognize that the capacity performance model was a failed experiment,” Bowring said. (See FERC Backs PJM IMM on Market Power Claim.)
“The only purpose of the capacity market is to make the energy market work. The fundamental mistake of the CP design was to attempt to recreate energy market incentives in the capacity market,” Bowring said. “The CP model was designed on the assumption that shortage prices in the energy market were not high enough and needed to be increased via the capacity market.”
Bowring noted that the CP design focuses on a small number of critical performance assessment hours, imposing large penalties on generators that fail to produce energy only during those hours. He said the use of capacity market penalties rather than energy market incentives created risk.
“While there are differences of opinion about how to value the risk, this CP risk is not risk that is fundamental to the operation of a wholesale power market. This is risk created by the CP design in order, in concept, to provide an incentive to produce energy during high demand hours that was even higher than the energy market incentive,” he said.
PJM has said that generators may be facing total penalties between $1 billion and $2 billion for as much as 46,000 MW in capacity being offline during the storm, including over a third of gas resources. That has raised concern about significant amounts of generation leaving the market, either through default or determinations that there is too much risk in the exchange. (See PJM Gas Generator Failures Eyed in Elliott Storm Re view.)
“Everybody knew what the potential penalties were. Nonetheless, the behavior did not match … that expectation. … Massive penalties are not the answer here,” Bowring said.
David “Scarp” Scarpignato, of Calpine, suggested that a third product may be needed alongside energy and capacity resources, noting the impact the fuel requirements would have on certain gas generators.
Combustion turbine plants connected to only one pipeline would no longer be able to participate as capacity resources and therefore lose their capacity interconnection rights. Without the guaranteed access to the transmission grid when shortage pricing is in effect, those units may no longer be economical, he said.
Steve Lieberman, of American Municipal Power, said the majority of generator conversations around the MSOC come down to properly defining their units’ capacity performance quantified risk (CPQR) — the risk that they will face non-performance penalties. AMP has proposed one of six design concepts currently being discussed by the RASTF, along with the IMM.
“I believe what Winter Storm Elliott has taught us is we need to put the scalpel away and it might be time for the chainsaw. … We do agree CP is a failure; it was an experiment that we implemented after the polar vortex,” he said.
AMP’s proposed design includes a higher degree of fuel availability for capacity resources, namely dual fuel or onsite inventory, and would expand the use of ELCC accreditation to thermal resources.
“An approach that’s similar for thermals and non-thermals alike is our preference,” Lieberman said, adding that he has reservations about ELCC, but feels that having one accreditation approach for all resources is best.
Stakeholders Seek More Clarity on Offer Caps
With deadlines approaching for June’s 2025/26 Base Residual Auction, Jeff Whitehead, of GT Power Group, said that generation owners will soon have to make decisions about their CPQR and unit-specific offer caps. He said guidance from PJM and the IMM on what will be allowable would aid in the drafting of those figures.
He noted that without changes to the current auction schedule, there are few parameters that can be changed in time, primarily the performance assessment hour assumption.
“I think we need to come to a common agreement on what is a reasonable basis for including Winter Storm Elliott, or I’ll say more broadly the changes in the penalty risk view that comes out of that event,” he said.
Bowring said he believes the current MSOC construct is correct and the best way to incorporate the winter storm data into offer caps is by rerunning the simulations the Monitor conducts with the data from Elliott added in. Part of his consideration of the storm’s impact is that to an extent the emergency conditions were the result of generators being unavailable.
“We have to operate in a rational defined space, and that space is going to be calculating what we think the impact on CPQR is of the actual facts of Elliott,” he said. “Given that this is the first significant PAI event since the introduction of the CP model, it is unlikely to have a large effect on CPQR.”
A study released by the Lawrence Berkeley National Laboratory last month found that interconnection costs have been steadily rising for decades in the PJM region and are disproportionately high for renewable resources.
“The core finding that we’ve had for PJM is overall interconnection costs have increased both for projects that have completed all the required interconnection studies, as well as for those projects still moving through the interconnection process,” said Jo Seel, principal scientific engineering associate with the lab. The study is part of a series looking at interconnection costs for each RTO in the U.S.
Drawing off available interconnection studies released by PJM, the study found that costs for generators that have successfully connected to the grid have doubled from 2000 through 2019. The average for completed projects has grown even more sharply over recent years, rising from $29/kW between 2017 and 2019, to $240/kW between 2020 and 2022.
Costs are highest for projects that ultimately dropped out of the interconnection process, at $563/kW, which Seel said could point to network upgrades being a driving factor behind projects leaving the queue.
“It seems to me pretty likely that high interconnection costs make a certain set of projects infeasible and they cannot move forward,” Seel said. “We see that especially well for solar projects, where the upgrade requirements for some of these solar projects is up to nearly 40% of the overall project [capital expenditures] … that just breaks project economics, so I think that’s a pretty good explainer of why some of these solar projects then do not move forward and ultimately withdraw.”
The study also found a wide gap in network upgrades for different resource types. Natural gas carries some of the lowest costs, with an average of $24/kW, while offshore wind was the highest at $385/kW. Onshore wind saw average interconnection costs of $136/kW, while solar projects had costs around $253/kW.
Scale of Rising Costs Questioned by PJM
PJM Senior Director of Interconnection Planning Jason Connell said he believes the study overrepresents the extent that network upgrade costs have grown because of the inclusion of feasibility studies in the data. Because the studies identify the upgrades that an individual project would require to interconnect prior to cost allocation between projects, he said it could result in double counting of costs if multiple projects needed the same upgrade.
“The issue is that those projects for which they’re scraping the data are in various stages of completion: some very early on in the feasibility stage, and some have signed and executed an interconnection service agreement. It doesn’t make sense to compare them as an aggregate, because those study costs get refined the further along a project is in the study process,” he said.
Seel said that wherever possible, the Berkeley team looked for the most recent and accurate data available, and only a small number of feasibility studies were included in their data. In those cases, they sought to correct for the possibility of double counting and, he believes, were able to formulate accurate findings.
“We used the best available data to categorize these costs,” he said.
Independent Market Monitor Joe Bowring said data accessibility at PJM has long been a challenge, making it difficult for studies to be conducted.
“If PJM wants more accurate studies done, they should provide more accurate data,” he said.
As the grid becomes increasingly complex and built up, Connell said costs are bound to rise to a degree. While the first few projects in a region may require replacing equipment at a substation, subsequent installations may necessitate the reconducting of lines or substation rebuilds. Despite the growing investments needed, there’s been no slowdown in the number of new requests for interconnection studies across resource types, including developers looking to install renewables.
“Each upgrade is an order of magnitude of difference for each of the newer projects,” he said.
The new approach for studying interconnection requests approved by FERC last year could provide more clarity on the costs developers could face, Connell said. The new methodology clusters projects together both for identifying network upgrades and allocating costs. It also requires that deposits be made throughout the process to discourage speculative filings. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
Seel pointed to the medium-term transmission plans conducted by MISO as another approach for lowering network upgrade costs. The RTO’s plans identify larger network upgrades, and it makes the necessary investments itself, rather than allocating the expense between individual generators based on interconnection requests. A more holistic and forward-looking approach to evaluating grid upgrades can create efficiencies that outweigh the investments, he said.
Bowring said he’s hopeful PJM’s new interconnection process will decrease costs by making the interconnection process more efficient and reducing speculative filings, but he believes that retaining competition and accurate costs in the buildout of transmission is important to ensuring that generation is sited in the most economical locations. Upgrade costs rising are appropriate so long as they reflect the reality of the cost to interconnect, he said.
