Duke Energy (NYSE:DUK) on Monday filed a proposal with the North Carolina Utilities Commission (NCUC) that presents four broad paths to reducing carbon emissions by 70% by 2030 and achieving net-zero emissions by 2050.
Under development for months in a process that included stakeholder discussions with representatives of more than 300 interested organizations, the plan does not go into specifics. The company noted that the lack of specificity in its “all of the above” mix offers “regulators multiple options that balance affordability and reliability for customers.”
Under the proposal, Duke’s remaining coal-fired plants in the state would be retired by 2035, replaced by wind, solar, battery backup, “hydrogen-ready” gas turbines and perhaps a small modular nuclear plant, though the cost of any of these plans is not specified.
The company does point out that in the next two years, any of the multiple options it offers will have limited impact on costs. But beginning in 2025, customer bills would increase by 1.9 to 2.7% through 2035.
“The plan’s first portfolio achieves the 70% target by 2030, while the other three portfolios achieve the 70% target by 2032 or 2034 through increased reliance on both onshore and offshore wind and/or small modular nuclear generation, leveraging the law’s flexibility intended to help advance cutting-edge, carbon-free generation. All four portfolios reach carbon neutrality by 2050,” the company said in a statement issued with its filing.
“In the near term, the plan focuses on aggressive energy efficiency and demand-side management, along with grid upgrades to enable significant growth in renewables. That includes between 7,600 MW and 11,900 MW of new solar by 2035, depending on the portfolio, on top of the 5,000 MW of solar expected online by year-end and an additional 1,900 MW of solar currently planned or under development.
“Approaching the 2030s, wind and small modular nuclear come into play to diversify the carbon-free energy mix. This diversity is key to meeting the least-cost and reliability mandates required by state law.”
A coalition of advocacy groups — the Natural Resources Defense Council, Southern Alliance for Clean Energy and Sierra Club, represented by the Southern Environmental Law Center, along with the North Carolina Sustainable Energy Association — issued a statement following the company’s filing, noting that the organizations are preparing for NCUC hearings over the next 60 days and have already “commissioned expert analysis of the proposed Duke plan that will be filed along with an alternative plan on July 15.”
The company’s proposal includes four public hearings in July and a virtual hearing in August.
WASHINGTON — Anxiety over the clogged interconnection queues of RTOs and the ever more pressing need for more interregional transmission saturates the energy industry, and the near complete failure of the Texas Interconnection last year still looms large.
This was evident based on some of the discussions last week at the Energy Bar Association’s annual meeting, held in-person for the first time in three years at the Marriott Marquis Washington, DC hotel. Unlike several of the post-COVID-lockdown conferences, in which attendance might be capped or some speakers appear virtually, this was a fully in-person event; meeting rooms and the banquet hall were filled nearly to capacity.
In a panel on generation interconnection Wednesday, moderator Jason Stanek, chair of the Maryland Public Service Commission, paused to inform the audience that the front row of seats was open to those standing in the back of the room. It had remained open despite his joke at the beginning of the session, when he noticed “MISO people coming in late today. … You should be in the front row.”
Indeed, Stanek was sort of the odd man out: The panel was made up of both current and former MISO employees and a MISO stakeholder. But he noted that the lack of interstate transmission was a nationwide problem, referencing his state’s ambitious clean energy targets and neighboring Pennsylvania’s rejection last year of the Independence Energy Connection, which would have consisted of two lines in Western and Eastern Maryland connecting to existing lines across the border.
“The queue backlogs are not the problem, but a symptom of a much larger problem,” Stanek said, reporting what he has heard as a member of the Joint Federal-State Task Force on Electric Transmission at a meeting just the week before the conference. (See FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues.)
Aubrey Johnson, executive director of system planning and competitive transmission at MISO, noted that FERC recently approved an RTO proposal to give generators the opportunity to cut the number of days in its interconnection process. (See FERC Allows Quicker MISO Interconnection Queue Option.)
“So fundamentally, the queue is continuing to make improvements, but in many ways, we’re trying to use the queue today for things that it was not originally intended to do,” he said. “I certainly believe we should continue to work on queue reform and queue improvements. … But I also want us to think about what the real issues are.”
Johnson noted that MISO’s queue currently has about 800 projects worth about 126 GW, with about 60 to 70% of that being solar. “With a 200-GW system and a 130-GW peak — I don’t think all those projects in the queue are actually needed.” Only about 20% of projects that enter the queue actually reach a generator interconnection agreement, he said. “The real question should be: How do we deal with that 20%?”
Stanek quoted Massachusetts Department of Public Utilities Chair Matthew Nelson at the task force meeting: “‘Being in the queue should mean something.’
“The fact that only 20% of these projects, at most, ever actually make it to fruition shows us that we have an issue with gaming; with queue squatting,” Stanek said.
Jeff Bladen, global director of energy for Facebook parent company Meta, agreed that in general, not all of the projects in the queue are needed. But the former executive director of digital strategy for MISO noted that “there’s a lot more that needs to get built than has historically gotten built if we’re going to move forward with the electrification of many different sectors, and the growth of things like data centers is a signal of how much” clean energy is going to be needed. “It’s hard to believe it’s just going to be 20%.”
Meta is not just a rebranding of Facebook; it’s also the parent for photo-sharing service Instagram, messaging service WhatsApp and virtual reality producer Reality Labs (formerly known as Oculus), among other digital service companies. They collectively require a massive amount of data processing, which in turn requires a massive amount of energy for Meta’s 17 data centers across the U.S. — all of it renewable, according to the company.
More important than the queue backlogs, Bladen argued, is “the reliability of the grid. We’re starting to see the grid fray as we have more and more critical weather emergencies. … The reliability of the grid is an area of increasing and probably primary focus for us as we move forward.”
Meta has set a goal of net-zero emissions across its entire operations by 2030, “which is unlocked by transmission. Our core energy strategy is relatively simple: reliable, affordable and sustainable. And there are very few things that we think about as investments or areas of focus for policy that get us all three, and one of those few is transmission,” Bladen said.
Q&A
Stanek asked the panel if FERC needed to implement a rule on interconnection, or if the RTOs could fix their respective problems themselves.
“Having some leadership from FERC would generally be helpful,” Bladen answered. “Some general direction of what the expectations are is important so that the stakeholder processes have something to work towards. When they don’t have something to work towards … you end up with various vested interests running into each other, and it’s very difficult for an RTO to resolve those. …
“I think there’s a role for FERC to play; just don’t be overly prescriptive about exactly how you accomplish the outcome.”
Dehn Stevens, vice president of transmission development and planning at MidAmerican Energy, concurred. “I’ve heard someone say, or several someones say, that what we need is one interconnection queue, one system model, across everywhere. And I just have to say that’s the worst idea I’ve ever heard.
Rather, “an appropriate role for FERC would be to require accountability. If the regions are coming up with queue reforms, have a feedback loop about how it’s going,” with the RTOs filing annual reports on their progress.
One audience member told the panel that his clients often complain about what they see as unfair cost allocation, as their projects are somehow the ones that trigger the need for expensive transmission upgrades. At the same time, they are told that these upgrades are not showing up as needed in the RTOs’ transmission planning process. He asked what the difference was between interconnection studies and transmission planning studies, and “why, it seems to me, there’s a big disconnect between what’s showing up” in each.
“Fundamentally, generator interconnection planning is about trying to stress the local system — to make sure all the generators in a local area can operate reliably,” Stevens answered.
On the other hand, “long-term planning then looks at how all those generators will most likely be dispatched in the seasons that we’re trying to analyze. … So there’s a fundamental difference between the two paradigms in the way that the planners look at the world. …
“In order to make not every generator on the hook for some tiny slice of everything from coast to coast, we apply significance criteria,” which determine the amount of impact on a transmission facility a generator has to have before it’s responsible for upgrade costs. “What that means is there could be issues accumulating, but no one is yet held responsible … until the fateful day comes when a generator connects to the grid, and they have an impact above the significance factor cutoff,” Stevens continued.
“I would just say we can’t forget that all of the generators that came before that one all got the benefit of not having to have any responsibility to fix [the grid] because we all decided it was better to not hold everyone hostage across a wide area.”
Arash Ghodsian, senior director of transmission and policy for EDF Renewables North America — and another former MISO employee — said that proactive planning would eliminate that problem. “Unfortunately, until we get there, you’re going to hear that, because rather than me fixing the line for the X percentage that I have contributed to, I often get, ‘well, we need to rebuild the whole line.’”
Stakeholders at last week’s PJM Market Implementation Committee meeting peppered RTO staff with questions about a proposal on cost-based energy offers.
Melissa Pilong, lead analyst in PJM’s performance compliance department, provided a first read of the proposal by PJM and the Independent Market Monitor. Developed in the Cost Development Subcommittee (CDS), the plan is meant to provide guidance and updates to rules related to variable environmental charges and/or credits and their inclusion in cost-based energy offers.
Pilong said the proposal was initiated to ensure that PJM’s fuel cost policy is up to date. She said the key work activities and scope of the issue charge created by the CDS focused on the annual emissions review process and requirements to include environmental credits in non-zero cost-based offers.
Stakeholders affected by the proposal include sellers of generation receiving production tax credits and/or renewable energy credits and who also submit non-zero cost-based offers into the energy market. If both those conditions are met, the seller must account for the credits in the resource’s fuel cost policy, Pilong said.
One of the proposed changes includes adjusting review of emissions rates from an annual to a periodic basis and requiring that market sellers are responsible for updating the rates. Pilong said the change was made to align with the periodic fuel cost policy review process so that emissions rates do not change drastically year-to-year.
Another proposed change is for market sellers to “clearly document standards of review for emissions allowance adders.” Pilong said the change provides transparency around required information from market sellers, where the data must be submitted and the expectation for updating data.
Pilong said a minor change is proposed to remove a reference to “emissions policy” in Manual 15 because emissions policies are no longer utilized and emissions allowance information instead resides in the fuel cost policy.
He said the proposed deadline for implementation is six months following PJM’s FERC filing date to give market sellers an opportunity to update their fuel cost policies.
Heather Svenson, RTO strategy manager for PSEG, said her company was “surprised” to see the proposed solution brought to the MIC as a first read without first having taken a vote on the issue charge. Svenson said PSEG didn’t think that the CDS had approval authority over new issues, based on language in Manual 34.
Svenson said PSEG hoped PJM could compromise and consider bringing the proposed solution back to the MIC for a second first read to “make sure the right company resources are engaged on this topic so that we can make an informed decision.”
“Our concern is that solutions are being brought forward on an issue for a first read that maybe hasn’t received the same level of rigorous review as other issue charges in the stakeholder process,” Svenson said.
Dave Anders, PJM director of stakeholder affairs, said a subcommittee can undertake any work that fits within its charter. He said if there’s a lack of consensus by stakeholders on an issue charge at the subcommittee, then it will be voted on at its parent committee, in this case the MIC.
John Horstmann, senior director of RTO affairs at AES Ohio, asked if PJM could provide a list of CDS members who participated in the variable environmental costs and credits issue. He said discussions at the CDS have historically been about “determining how to report fossil fuel costs,” and he wanted to have a better idea whether there was representation from all the sectors at the subcommittee.
“I don’t know how well-attended the meeting was, and I don’t know whether this is representative of very few members, which typically attend the CDS, or whether it was well attended and a good cross section of stakeholders,” Horstmann said.
PJM said it plans to put the issue on the June MIC agenda as a voting item.
Stability Limit Changes Endorsed
Stakeholders endorsed manual changes regarding stability limits in markets and operations.
Last year, stakeholders endorsed PJM’s proposal on stability limits capacity constraints that included language limiting lost opportunity cost (LOC) credits for any generation reduction required to honor the stability limit in the RTO. The limiting of LOC compensation provoked debates among PJM members. (See “Stability Limits Endorsed,” PJM MRC/MC Briefs: Jan. 27, 2021.)
FERC ruled in February that PJM has the right to refuse LOC payments to generators that are temporarily required to limit output to prevent loss of synchronization and additional strain on the system during transmission outages. (See FERC: PJM Right to Block Gen Stability Limit Payments.) The tariff changes take effect June 1.
Zhenyu said PJM will use a new generator output constraint to enforce the stability limit for real power megawatt-only limits. He said the shadow price of the constraint will not be included or reflected in locational marginal pricing.
To provide greater transparency, Zhenyu said PJM added a new section to Manual 11 related to stability limits that describes the modeling, clearing and reporting process on the stability limit in the market. Updated language related to stability limits in Manual 28 included additional clarification that LOC credits are not paid for megawatts associated with a stability limit reduction.
“The revisions were relatively short,” Zhenyu said. “It’s about clarifying that generators will not be eligible for lost opportunity cost credits for reductions due to stability limit reasons.”
The manual changes will be voted on at the May 25 Markets and Reliability Committee meeting.
Intelligent Reserve Deployment Changes Endorsed
Stakeholders unanimously endorsed manual changes related to intelligent reserve deployment (IRD).
Damon Fereshetian, senior engineer in PJM’s real-time market operations, reviewed the updates to Manual 11 and Manual 28 associated with the IRD issue.
Stakeholders in December endorsed a PJM proposal to improve the deployment of synchronized reserves during a spin event. (See “Synchronous Reserve Endorsed,” PJM MRC/MC Briefs: Dec. 15, 2021.) The proposal created an IRD, which is a security-constrained economic dispatch (SCED) case simulating the loss of the largest generation contingent on the system and for which approval of the case will trigger a spin event.
The proposal also included taking the megawatts of the largest generator contingency and adding them to the RTO forecast to simulate the unit loss. PJM can then flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.
Fereshetian said in the verification section of Manual 11, PJM added clarifying language that the response to a synchronized reserve event is “based on the resource following dispatch instructions and is capped at the expected response.”
PJM originally intended to include new Manual 11 language that an approved IRD case “supersedes” any other approved real-time SCED cases for the same target time to be used as the reference case for the locational pricing calculator, but Fereshetian said discussion with stakeholders led to the language removal.
Manual 28 included minor clarifying changes.
The MRC will be asked to endorse the revisions at its May 25 meeting.
Manual 29 Revisions Endorsed
Stakeholders unanimously endorsed minor revisions to Manual 29: Billing as part of the periodic review.
Natasha Holter, manager of PJM’s market settlement operations, reviewed the Manual 29 revisions, saying there were no “substantive changes” in the language and mostly included updates to terminology and reference materials.
Several new subsections were added to the manual, Holter said, including one called “Billing Notifications” that provides guidance on how to obtain notifications for billing statements. Another subsection, “Billing Adjustments,” added language to describe what a billing adjustment is and how to identify one.
Stakeholders will be asked to endorse the revisions at the June 29 MRC meeting.
ATLANTA — A Southern Co. (NYSE:SO) official gamely defended the Southeast Energy Exchange Market (SEEM) last week in a debate with RTO proponents at the RE+ Southeast conference.
Noel Black, Southern’s vice president of federal regulatory affairs and chair of SEEM’s board of directors, battled with three skeptics at the conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA).
More than a dozen utilities and cooperatives, including Southern, the Tennessee Valley Authority and Duke Energy (NYSE:DUK), proposed SEEM to reduce the “friction” in bilateral trading by introducing automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions. It is expected to be operational in the third quarter of this year.
Black said SEEM would reduce curtailments of solar power and provide consumers cheaper power than an RTO.
“We wanted to get out of the way of solar, so if your loads are low in the shoulder periods, you have somebody else’s territory to take that energy. So it’s a really efficient way of dealing with that,” he said.
Others on the panel, however, said SEEM’s bilateral trading and limited transparency fall far short of what’s needed to incorporate as much renewable power as is required by efforts to decarbonize by midcentury.
“We believe that some type of wholesale market that’s organized in the Southeast is critical for integrating renewable energy, encouraging development and reducing emissions at the scale that’s required to actively combat climate change,” said Nick Guidi, federal energy regulatory attorney for the Southern Environmental Law Center.
Jamey Goldin, Google’s (NASDAQ:GOOG) energy regulatory counsel for global energy markets and policy, noted that the company has pledged to match its loads to carbon-free generation around the clock. “Just last week, we [committed] to net zero across all lines, including Pixel, Pixelbook, everything; it’s not just data centers anymore,” he said.
‘Nothing Burger’
But he said delivering on that commitment will be most difficult in Asia and the Southeastern U.S.
“Our carbon-free energy [availability] is abysmal in the Southeast, and we’re not going to get there without an RTO. … It’s just not going to happen,” he said, dismissing SEEM as “a nothing burger.”
“When you have true competition, a true, free market for generation, you have economic dispatch and multilateral opportunities for buyers and renewable developers to work together,” he said, citing Google’s work with AES to aggregate renewable projects in PJM. The economies of scale provided by such projects are “impossible in any of these vertically integrated monopoly states,” he said.
“I don’t know what the technical definition of a ‘nothing burger’ is, but it’s definitely not what SEEM is,” Black responded.
He and Goldin cited widely varying statistics on the installed solar power in the three states in which Southern operates. According to February 2022 data from the Energy Information Administration, Georgia ranks sixth among states with 3,088 MW. Alabama was 23rd with 424 MW, and Mississippi ranked 30th with 219 MW.
At a time when natural gas prices have more than doubled to $8/MMBtu, Black said SEEM’s joint dispatch, which will charge customers based on the weighted average cost of fuel, is better for consumers than the single price clearing mechanism used by RTOs.
“Let’s just say you have 80% of your generation from wind or solar. Pretty cheap, right? … Twenty percent of the energy is coming from gas at $8. You set a price at $8. I can’t quite understand how that’s fair to customers, so that they can’t see the real cost of that energy,” Black said. “That’s something that’s going to be under a lot of pressure as RTOs move ahead and get more zero-marginal-cost” resources.
SEEM’s website cites EIA data showing SEEM members’ average rates are below U.S. and RTO averages.
‘True Competition’
Black said SEEM provides “true competition” that would be lacking if a utility cedes to an RTO its transmission operations and planning, “the very things that differentiate me and my ability to best serve my customers.”
“I want to be held accountable. And with accountability comes the opportunity to differentiate. If I turn that over to someone else, you lose competition. It’s just a fact. I mean, I compete by doing the best job of serving my customers reliable, sustainable, affordable energy.”
Maggie Shober, director of utility reform for the Southern Alliance for Clean Energy (SACE), rejected Black’s definition of competition.
“We have this vertically integrated model [in which] you are able to set the rules, largely, on rooftop solar; you control a lot of the energy efficiency. Many customers literally do not have a choice except for their monopoly utility. And so calling that competition, I think, is a misuse of the term, quite frankly.”
Market Oversight
Guidi said SEEM won’t generate real-time energy market prices that would provide price signals to spur renewable development.
He also cited the lack of an independent market monitor to police market power and market manipulation.
“SEEM allows all market participants to toggle off other participants so they can choose who not to trade with. And we think this could be problematic if utilities … decide not to buy from [independent power producers], or merchant generators,” he said. “They might have a cost incentive to buy from them on an individual trade basis. But if they want to favor their generation long term, they might not want to provide those investment opportunities for developers to enter the market.”
He also noted that only load-serving entities will have a say in SEEM’s governance. “There’s no real stakeholder process where customers are represented, public interest organizations are represented, states are represented. And we think that’s problematic, because to have a real thorough market reform in the Southeast, everybody needs to be involved.”
Black insisted there is no incentive for SEEM members to discourage participation. “We’re doing everything in the world to outreach, to focus on participation,” he said. “I have heard that criticism that there’s an opportunity for us to hold people [out]. … It happens not to be true. We want you in the market; we encourage you to be in a market. That will be good for our customers.”
Black also said he was encouraged that more utilities in Florida are studying whether to join the effort. “I have a good feeling that hopefully in 2023 … they’re likely to join SEEM as well,” he said. Duke, whose Carolina utilities are part of SEEM, had previously expressed concern over peninsular Florida’s limited interconnections to the rest of the Southeast; PowerSouth Energy Cooperative, which serves the state’s panhandle, is already a member.
He also cited the clogged interconnection queues in RTOs such as PJM and MISO. “Southern Co. doesn’t have an interconnection problem,” he said.
‘Missed Opportunity’
Shober said SEEM is a “missed opportunity” for customers, citing SACE’s analysis that SEEM would save only $1 per customer per year.
She agreed that “there are issues with a lot of RTO structures out there.”
“So in the Southeast, I see that as a huge opportunity. We’re not trying to work within an existing system that was set up in the ’90s, before we had … all the benefits and technologies that we have today,” she said. “We know that the Southeastern utilities can come together and talk through this because they did so to develop SEEM. Let’s take that to the next level. Let’s look at, what does this Southeast RTO look like? Can we get there? I don’t think it’s going to happen in five years. But can we get there in in 10 years?”
Southern Co. “seems pretty happy with the trajectory we’re on,” Shober observed. “We’re not happy with the trajectory that we’re seeing in the Southeast. We look at [integrated resource plans] every year. We have some IRPs and some utilities that are not on track to get to zero carbon until after 2100 — not even 2050.
“We have a lot of work to do. And it’s just not going to happen in the current status quo.”
WASHINGTON — If SouthWestern Power Group had known how difficult and expensive its SunZia transmission project would be, the company probably wouldn’t have pursued it, General Manager David Getts said.
Getts has been working for 16 years on SunZia, a project to deliver wind power from sparsely populated New Mexico into Arizona for consumption there and in California. It’s taken so long that the company is now on its fourth law firm — and fourth presidential administration, dating back to that of George W. Bush. The Phoenix-based company has spent $200 million to date, thanks to backing from parent MMR Group, a large, privately held electrical contractor based in Baton Rouge, La.
Getts recounted his SunZia experience at the Energy Bar Association annual meeting last week, a cautionary tale with implications for the nation’s climate policy.
“It’s an incredible amount of money for a private company. Putting that much money at risk in one project is kind of crazy. I thank my chairman and his faith and support and my team over 16 years. But that’s not repeatable. Very few companies in the U.S. will ever do that again. I can tell you my company won’t.”
Conception
SouthWestern began discussing the idea of a transmission project with regional utilities and renewable developers in 2006.
“We knew that New Mexico had great wind energy. And New Mexico [population 2.1 million] has very few people,” meaning the power would need to be exported, Getts recalled.
The developers decided the project would run from near Corona in central New Mexico, where there is more than 4,500 MW of wind energy capacity. Two 500-kV lines would run 550 miles southwest to the existing Pinal Central substation in Pinal County, Ariz.
“It’s a really good place to get from there to the Palo Verde hub. That’s really important in the West; not only is it a liquid market, but it’s a gateway to California electrically,” Getts explained. “The California ISO can take delivery of electrical energy that’s delivered to Palo Verde, and there’s an awful lot of generation interconnected there.”
In 2011, FERC approved a request to commit half of the project’s capacity to anchor tenants. In 2016, SouthWestern selected a tenant through a solicitation: Western Spirit Wind Farm, a group of wind energy projects totaling 3,000 MW being developed by Pattern Energy.
“There’s hardly any available transmission capacity in the West. So the wind depends on the line, [and] the line depends on the wind,” Getts said. “That meant from the very early days, we knew that we would have to find someone to work with us. And in fact, the projects will be financed as a unit, because of what we call in financing circles project-on-project risk. That’s a real issue for any independent project.”
Siting
Having decided on its partner, the developers needed to site the line. “That’s a little more than just drawing lines on the map,” he said. “Siting is key because that will define your permitting destinies. Permitting is something that, you know, has really takes the lion’s share of time.”
Getts said even electric utilities with eminent domain rights work hard not to use them.
“The difference is, if you have them [and] everybody knows it, you’re in a much better position. Because if you don’t have it, or if what you have is arguable or questionable … then you’re at the mercy of your private landowners. We’ve experienced that. And the only solution is you pull out your checkbook, and you just pay.”
Southwestern and Pattern worked with the New Mexico Renewable Energy Transmission Authority, which was created to facilitate the development of transmission projects and has eminent domain rights that potentially could help transmission developers. “Our state permit, in theory, conveys the powers of eminent domain,” Getts said. “However, there’s a big question mark if it’s enforceable. And it has to do with the fact that we may or may not be a public service corporation.”
SouthWestern had to negotiate access with federal, state and private landowners. “We were able to try and address local concerns and issues because we could reroute. And we’ve done that a lot, particularly to get around private landowner concerns.”
NEPA
It took eight years to win approval from the Bureau of Land Management for a 400-foot-wide right of way over 183 miles of federal land. To get through its National Environmental Policy Act (NEPA) review the first time took seven years. Getts expects it will take another three years to win NEPA approval for its revised plan, which realigns about 100 miles of the route to add roadways, avoid conflicts with the White Sands Missile Range and add a DC-to-AC converter.
The developers avoided tribal lands. “And that’s difficult in the West because there are a lot of tribal reservations,” Getts said. “As a private sector developer — where it was 100% of my company’s private capital we were putting at risk — we felt it was to our advantage to try and not put our transmission line through reservations. Not saying it can’t be done; just add another maybe 10 years to your time.”
The developers now have all the right of way for line 1, which will be HVDC, with a capacity of 3 GW. They plan to build that before moving to the second line, which would be AC with a capacity of 1.5 GW. “We aren’t going to be able to get the second line done if we don’t get the first line into construction,” Getts said.
Construction of the transmission and the wind farms is expected to begin next year and take up to three years, meaning it all could be in operation by the end of 2025 — or 20 years from the beginning of development to commercial service. Of the project’s early utility investors, only Salt River Project remains, with SouthWestern having bought out the interests of Tri- State Generation and Transmission Association and Tucson Electric Power.
“Obviously, that’s not a very good model for building all of the bulk power system [capacity] that we need to … achieve the [decarbonization] policy goals,” Getts said.
“When we started doing this, there were 40 or 50 independent projects. Today, there’s maybe three that are viable. I think SunZia will get built. Not that it’s a unicorn, but it’s not probably easily repeatable.”
Getts said he had no answers for improving the process. “NEPA does work. It just takes ages,” he said. “I’m not sure there’s a lot the federal government can do to make it better.”
FERC Backstop Authority
He said the backstop siting authority given to FERC in the Infrastructure Investment and Jobs Act — which allows the commission to override state vetoes of transmission in areas designated by the Department of Energy as National Interest Electric Transmission Corridors — is no solution either.
“In my opinion, that’s never going to happen,” he said.
Kellie Donnelly, executive vice president and general counsel for government affairs and communications firm Lot Sixteen, also was skeptical that FERC will use the new authority.
“It is a potential tool, and it could be used for something like offshore wind,” said Donnelly, who served as general counsel to the Senate Energy and Natural Resources Committee under Sen. Lisa Murkowski (R-Alaska).
“But I think FERC would prefer to have a more collaborative process with the states,” she added, citing the Joint Federal-State Task Force on Electric Transmission created by FERC Chairman Richard Glick. (See Task Force Seeks ‘Right Balance’ in Spreading Tx Upgrade Costs.)
A group of environmental organizations petitioned the New York Public Service Commission Wednesday to speed up the statewide buildout of charging infrastructure for medium- and heavy-duty electric vehicles (18-E-0138).
Environmental Defense Fund (EDF), CALSTART, Natural Resources Defense Council, Sierra Club, South Bronx Unite and WE ACT for Environmental Justice also asked the commission to adapt the existing make-ready pilot program to support early adopters of zero-emission trucks and buses.
The PSC’s 2020 Make-Ready Program Order established a program to encourage development of electric vehicle level 2 and fast chargers throughout the state, providing incentives to offset utility and customer capital costs of eligible charging infrastructure.
NREL is working with other national labs to develop a megawatt-scale charging system for medium- and heavy-duty electric vehicles, enabling drivers to charge in less than 30 minutes at reasonable cost. | NREL
“Electric trucks and buses mean less climate pollution and cleaner air for New Yorkers. But for this to happen, these vehicles need charging infrastructure that meets their operational needs,” EDF attorney Elizabeth Stein said in a statement.
The PSC, she said, can and should work with utilities to support truck and bus fleet electrification in a way that optimizes how they interact with the electric grid.
At its regular session on Thursday, the commission approved utilities’ tariff amendments related to the Make-Ready program. The PSC also established a new regulatory proceeding to track efforts to meet the states’ climate goals, and Commissioner Diane X. Burman cited the EDF petition as a potentially overlapping proceeding that illustrates the complexity of assessing statewide compliance with statutory environmental goals. (See NYPSC Tracks Clean Energy Progress, Questions Process.)
New York’s investor-owned utilities in April reported a slow rollout of EV fast-charging stations under the state’s $701 million incentive program to build 50,000 such stations by 2025. (See New York Utilities Report Slow Start to EV Fast Charging.)
“Communities of color and areas of low-income have been plagued with diesel pollution for far too long,” Anastasia Gordon, energy and transportation policy manager with WE ACT, said in a statement. “Shifting to electric trucks and buses is critical to tackling climate change, improving air quality and health in overburdened communities across the state, and is a step in the right direction to addressing long-standing injustices.”
New York Attorney General Letitia James filed a lawsuit against three bus companies for illegally idling in New York City schools, busy yards and “other locations predominantly in low-income and communities of color throughout the five boroughs,” according to a statement Thursday from the AG’s office. The lawsuit alleges that the companies violated state law prohibiting idling for more than five minutes and New York City law prohibiting idling for more than one minute at schools.
PJM delayed a vote on the draft charter of the Interconnection Process Subcommittee at last week’s Planning Committee meeting after stakeholders requested changes to the charter language.
Jason Connell, PJM director of infrastructure planning, reviewed the draft charter of the subcommittee, which is being created to continue the discussion of interconnection process changes after the Interconnection Process Reform Task Force finishes its work. Stakeholders endorsed PJM’s proposal for a new interconnection queue process at the April Markets and Reliability Committee and Members Committee meetings. (See PJM Stakeholders Endorse New Interconnection Process.)
The IPS is intended to be a stakeholder forum to “investigate and resolve specific issues related to the interconnection process and associated agreements, governing documents and manuals,” the charter said, and will include discussion topics such as education on current and future interconnection processes and agreements with clarifications around implementation.
Connell said PJM staff routinely receive questions from developers on how interconnection processes not specifically described in the manuals or the tariff are implemented. He said PJM wants to use the subcommittee as an “incubator” for discussions on interconnection issues to come up with solutions.
PJM’s new services queue. | PJM
The IPS is designed to mainly report to the PC, Connell said, but some of the discussion may impact operations and markets, requiring reports to the Market Implementation Committee and the Operating Committee.
Connell said some stakeholders requested additional detail in the charter language regarding the governance and administration of the subcommittee. Clarifying language was added stating, “Any recommendations from the IPS will be forwarded to the PC for consideration and voting.”
Sharon Midgley of Exelon said her company is “excited to get this group started” to have ongoing conversations on changes in the interconnection queue process.
Midgley offered another suggestion in the administration section of the charter, saying it should include language that says “issue charges will be used at the subcommittee to support the work plan.” She said an issue charge wouldn’t necessarily have to come back to the PC for endorsement but could instead stay at the IPS where policy experts are working on the issue.
“That way the attendees would know what issues are being worked,” Midgley said. “They would see the work plan.”
Michelle Greening, manager of PJM’s stakeholder process and engagement department, said the subcommittee “can take on any issue charged within its purview under its charter” if it is within the scope of the existing charter and if no stakeholder objects to it at the subcommittee level.
If the issue charge goes beyond the charter and scope of the subcommittee or concerns are raised by a member, Greening said, then the issue charge will come back to the PC for endorsement.
Dave Anders, PJM director of stakeholder affairs, said the IPS will operate similarly to other subcommittees that report to a standing committee, citing the Cost Development Subcommittee as an example. Anders said Manual 34 stipulates that subcommittees are allowed to take on work that’s within the charter of the group.
Adrien Ford of Old Dominion Electric Cooperative suggested changing “PC” to “standing committee” in the administrative section stating, “Any recommendations from the IPS will be forwarded to the PC for consideration and voting.” Ford said it would be better to keep the term general in case issues need to go to the MIC or OC.
Connell recommended holding off on the charter vote until next month so that PJM staff can formulate clearer language.
RSCS Charter Endorsed
Stakeholders unanimously endorsed minor changes to the Reliability Standards & Compliance Subcommittee (RSCS) charter.
Monica Burkett, PJM senior lead knowledge management consultant, reviewed the changes to the charter, saying the RTO wanted to improve discussions and find more efficiencies in the RSCS, such as maintaining up-to-date information on issues. She said the changes improve what compliance information is provided and shared with stakeholders in the subcommittee.
Burkett said the charter updates included “simple tweaks” to language for clarification.
One item removed from the charter language is the development of a list of functions performed by other registered entities “in support of PJM compliance.” Burkett said the list of functions are reviewed at the RSCS, but they are not developed by the subcommittee.
Under the responsibilities section of the charter, PJM removed the item “cooperate with PJM with regard to data requests and submittals related to NERC and regional reliability standards” and inserted “allow for exchange of best practices and discussions surrounding upcoming data requests related to NERC and regional reliability standards.”
“We wanted to ensure that everything is specific to the RSCS,” Burkett said.
2022 RRS Assumptions
Jason Quevada, a senior analyst in PJM’s resource adequacy planning department, presented the 2022 reserve requirement study (RRS) assumptions developed in the Resource Adequacy Analysis Subcommittee (RAAS).
Quevada said the study results reset the installed reserve margin (IRM) and the forecast pool requirement (FPR) for the 2023/24, 2024/25 and 2025/26 delivery years and establish the initial IRM and FPR for the 2026/27 delivery year.
Quevada said the 2022 RRS assumptions are similar to those in the 2021 RRS and are an update of the specific historical period to be used for the winter peak week modeling.
For generator performance, Quevada said, the PRISM model uses each generating unit’s capacity, forced outage rate and planned maintenance outages to develop a cumulative capacity outage probability table for each week of the year, except the winter peak week. For the winter peak week, Quevada said, the cumulative capacity outage probability table is created by using actual historical PJM-aggregate outage data from the 2007/08 delivery year through the 2021/22 delivery year.
“The methodology to develop the winter peak week capacity model is to better account for the risk caused by the large volume of concurrent outages observed historically during the winter peak week,” Quevada said.
Generator unit model data will be available for review, Quevada said, with a July target for completion by generation owners. The load model time period analysis will be presented to the RAAS and PC in July, he said, and PJM will seek approval in August. The final report is scheduled to be presented to the RAAS and PC in September with final approval in October.
Transmission Expansion Advisory Committee
Generation Deactivation
Phil Yum of PJM’s system planning modeling and support department provided an update at last week’s Transmission Expansion Advisory Committee meeting on recent generation deactivation notifications, including Energy Harbor coal units in Ohio and West Virginia with a requested deactivation date of June 1, 2023.
Energy Harbor requested deactivation of coal-fired units 5-7 of the 1,504 MW W.H. Sammis Power Station in the American Transmission Systems Inc. (ATSI) transmission zone in Ohio. The company also requested the deactivation of the 13 MW diesel unit at Sammis.
Generation deactivation requests in PJM between 2020-2022. | PJM
Energy Harbor also requested deactivation of units 1 and 2 of the 1,278 MW Pleasants Power Station in the Allegheny Power Systems transmission zone at Willow Island, W.V.
Yum said reliability analyses are complete for the Sammis and Pleasants units, and a thermal violation was identified on the Beaver-Hayes 345 kV Line in Ohio. The recommended solution calls for replacing four 345 kV disconnect switches with 3000A disconnect switches, replacing substation conductors between bus bar and wave trap, replacing line drop and stranded conductor and upgrading transformer protection relays at two breakers at the Beaver substation.
The projected in-service date for the project is June 1, 2024, Yum said, and the estimated cost is $2.1 million. Yum said operating measures have been identified to mitigate reliability impacts in the interim since the requested deactivation date is a full year before the in-service date for the upgrades.
PJM also received two new deactivation requests, Yum said, including the 32-MW Morgantown CT1 and 2 oil-fired units in the Pepco transmission zone in Maryland and the 19.3-MW Carbon Limestone landfill in the ATSI transmission zone in Ohio. Yum said reliability analyses are underway for both deactivations.
PJM expects to have enough power supply to meet its summer electricity needs, according to a forecast released last week.
Todd Bickel, senior engineer in PJM’s transmission operations department, reviewed the results of the summer 2022 Operations Assessment Task Force (OATF) study at a meeting of the RTO’s Operating Committee, saying the peak load analysis did not identify any reliability issues.
According to the forecast, PJM has about 184,800 MW of installed generating capacity and is prepared to serve a forecasted summer peak demand of approximately 149,000 MW. Bickel said PJM has also performed reliability studies at higher loads of around 157,000 MW and still did not find any reliability issues.
“PJM works to ensure reliability, not just for ideal conditions, but we also plan for extreme events,” Bickel said.
Last year’s peak demand was about 149,000 MW, Bickel said, and PJM expects demand to be consistent with last summer. PJM’s all-time highest load was 165,563 MW in the summer of 2006.
Bickel highlighted PJM’s 2022 preliminary capacity expectation projections for the summer, saying the actual numbers may change slightly as the official summer months approach.
PJM anticipates discrete generator outages of 13,541 MW, Bickel said, where the value is determined by averaging the generation outages submitted during the top 10 peak days from the last three summers. The net interchange, or the RTO’s exports to its neighbors, is estimated to be 5,300 MW.
Bickel said the 2022 summer OATF case study is based on the 50/50 non-diversified peak load base case derived from the Load Analysis Subcommittee, which anticipates a load forecast of around 153,550 MW this summer. The preliminary RTO net interchange in the OATF estimates exports of 3,989 MW. Bickel said the net interchange case study number is different from the capacity projections because it accounts for 1,351 MW of pseudo ties in the OATF case model.
Stakeholders asked Bickel if the forecast’s net interchange number accounted for MISO’s announcement late last month that it could see a 1,200-MW capacity shortfall this summer. (See MISO Warns of Summer Emergencies, Load Shedding.)
Bickel said the numbers presented at the OC meeting don’t account for MISO’s latest report, but PJM is conducting several supplemental internal studies that do look at higher interchanges exporting from PJM.
“It is something that we definitely take into account as we approach the summer,” Bickel said. “One thing we look at in these additional studies is how far can we push the limits before we expect to see issues.”
For the 50/50 peak load study results, Bickel said no reliability issues were identified for the base case and N-1 analysis.
PJM also conducted sensitivity studies for external contingencies that could impact the RTO’s reliability and equipment within the footprint, and no reliability concerns were found.
Under N-1-1 relay trip conditions, Bickel said PJM identified no cascading outage concerns and all networked transmission overloads were controlled pre-contingency. The “max-cred” contingency analysis, which looks at maximum credibility scenarios, found no reliability concerns.
In the 90/10 load forecast study, which examined an elevated load of 156,928 MW, PJM observed no uncontrollable or unexpected issues, Bickel said.
PJM for the first time also ran a solar and wind generation sensitivity study for the summer and found no reliability concerns. The study assumed a loss of 4,200 MW of wind and a 10% solar scenario.
As part of preparations for the summer load, PJM said it has continued to work with transmission and generation owners to make sure all critical maintenance and system improvements are completed. The RTO has also continued conducting fuel inventories every two weeks to look for any issues of fuel supplies among the generation fleet, reporting that it has seen coal inventories begin to refill after running low during the winter.
“Predicting the demand for electricity helps PJM ensure that consumers have a reliable supply of power today and in the years ahead,” said Mike Bryson, PJM’s senior vice president of operations. “Load forecasting is something we do routinely, for both short- and long-term periods, to help ensure an adequate supply of power for reliable service at the most reasonable cost.”
[UPDATED on Monday, May 16, to include information about SPP’s second resource advisory.]
SPP said Thursday it expects to have enough generating capacity to meet regional demand through the summer season, hours after issuing a resource advisory for Friday and Saturday in its eastern reliability coordination footprint.
On Monday the RTO issued a second resource advisory, effective noon Wednesday through noon Thursday.
The RTO said it was declaring the advisory because of higher-than-normal temperatures, wind forecast uncertainty and system outages that may force its balancing authorities to use greater unit commitment notification time frames. It said generation and transmission operators have been provided instructions on applicable procedures to follow, including reporting any limitations, fuel shortages or concerns.
The advisory is in effect at noon CT on Friday and has a projected end of 8 p.m. Saturday.
Resource advisories are meant to raise awareness among generation and transmission operators to help ensure regional reliability and do not require the public to conserve energy, SPP said. However, the RTO encouraged individuals to contact their local utility for details specific to their area.
The grid operator expects demand to peak at 51.1 GW this summer, nearly 100 MW over its all-time peak of 51 GW set last July. It said its “diverse fleet of member utilities’ conventional and renewable” resources will be prepared to serve at least 55.5 GW, taking both planned and a margin of unplanned outages into consideration.
“SPP’s job is to prepare for both expected and unexpected scenarios that could affect electric reliability across our region,” Senior Vice President of Operations Bruce Rew said in a statement. “We know how much the 18 million people in our region depend on our services, and we do everything in our power to responsibly and economically keep the lights on.”
Rew said staff work closely with SPP’s member utilities to ensure forecasts are dependable and then maintain contingency plans and monitor the regional grid to be able to respond quickly “if things don’t go as planned.”
James Bryant, a meteorologist for KATV in Little Rock, Ark., told stakeholders during SPP’s annual summer preparedness workshop that a second year of the La Niña weather pattern will result in above-average temperatures in the months ahead.
“It’s going to be a hot summer,” he said Thursday, noting that second years of La Niñas are “notorious” for above-normal temperatures in the central and southern plains.
Drought conditions in much of SPP’s 14-state footprint are also expected to lead to greater chances of above-normal temperatures.
The RTO said its summer seasonal assessment did identify potential local issues that will be addressed with the responsible load-serving entities. It said it will address potential fuel-supply constraints with generator owners and operators on a case-by-case basis.
The heat, both weather-related and political, continues to build on ERCOT following another stress test this weekend.
It began Friday when the Texas grid operator was forced to ask customers in its footprint to conserve power after it said six gas-fired facilities went offline for a variety of reasons — transmission outages, maintenance and fuel supplies — during the afternoon, taking 2.9 GW of power with them. Interim ERCOT CEO Brad Jones asked Texans to set their thermostats to 78 degrees or above and avoid using large appliances between 3 and 8 p.m. through the weekend.
“ERCOT continues to work closely with the power industry to make sure Texans have the power they need,” Jones said in a statement that was posted on Twitter and issued as a news release.
Jones’ statement and the advisory — ERCOT’s first tweet and news release since Feb. 2 — came shortly after business hours Friday. Staff sent a corrected release out 32 minutes later, revising “all reserve generation resources available are operating” to “all generation resources available are operating.”
By then, the grid operator had already survived a slim 2 GW or so margin between supply (almost 65 GW) and demand (63.7 GW) around 3 p.m. It continued to add capacity and was eventually able to meet Friday’s peak demand of 65.2 GW during the hour ending at 5 p.m.
“There’s no good reason why ERCOT waited until 5 p.m. Friday to alert the public, outside of politics. ERCOT and [the] PUC really owe it to Texans to communicate earlier and clearer,” tweeted energy consultant Doug Lewin, with Stoic Energy. “The statement … was worded so vaguely and was so confusing that it basically made no sense. They’ve got to do better. There’s no excuse for the 5 p.m. notice or the lack of clarity.”
ERCOT’s supply and demand curves looked scary Saturday morning, but the grid operator was eventually able to find more capacity. | ERCOT
The first advisory came less than two and a half hours after Texas Gov. Greg Abbott posted a picture showing him meeting with ERCOT and PUC officials “to work closely to ensure Texas’ power grid remains reliable [and] meets the needs of Texans.”
It was a rare public statement on the grid from Abbott, who said in February that “the Texas power grid is more reliable and resilient than it has ever been.” (See ERCOT Breezes Through Latest Winter Storm.)
Coming on the heels of “categorically insane” heat and peak demand early last week that broke records for both May and June, the conservation call drew a more forceful response from Lt. Gov. Dan Patrick. (See ‘Insane’ Heat, Thermal Outages Stress ERCOT Grid.)
“This weekend’s energy conservation warning is another sign that we must have greater reliability,” Patrick said in a statement, noting he has “fought” for more gas-fired energy. “Work remains to be done. I will never waiver [sic] in my commitment to more reliable Texas power.”
Part of the problem is that about 20% of ERCOT’s thermal generation ha been on forced and planned outages near the May 15 deadline for completing maintenance work. That is partly because of the grid operator’s conservative-operations approach since last summer, when it has required more reserves to be online sooner and increased wear and tear on generating units.
ERCOT includes nuclear as thermal generation. One of the Comanche Peak nuclear plant’s two units, both of which have 1.25 GW of capacity, is returned from a refueling outage. It was operating at 45% Monday morning, according to the Nuclear Regulatory Commission.
On Saturday morning, ERCOT’s online dashboard showed the demand and supply curves meeting near 68 GW around 7 p.m. Mose Buchele, a reporter for Austin’s public radio station KUT, recalled a conversation he had had with Jones about his relationship with Abbott and other politicians.
“[Jones] said he ‘gets calls all the time’ saying ‘those lines look a little close today.’ [I] can only imagine the calls lately,” Buchele said, illustrating his tweet with ERCOT’s supply and demand chart.
Fortunately, five of the six gas units that were offline Friday returned to service as the percentage of thermal units offline dropped to about 13%. Demand reached nearly 66 GW before dropping off in the evening hours.
Demand peaked at 68.6 GW on Sunday as solar and wind power helped fill the gaps.
The grid operator on Monday extended its operating condition notice, its lowest-level communication in anticipation of a possible emergency condition, through Friday. It cited extreme hot weather, with forecasted temperatures above 94 degrees Fahrenheit in the North Central and South Central weather zones. Austin, in the center of the state, will flirt with 100-degree temperatures.
ERCOT was projecting demand to peak at 70.3 GW around 5 p.m. Monday. The grid operator said it would have 3.7 to 6.1 GW in operating reserves at that time.
Prices spiked Friday afternoon near ERCOT’s $5,000/MWh cap, settling between $4,408 and $4,681/MWh. Prices briefly broke triple digits twice during the rest of the weekend, with a peak of $305/MWh Sunday night.
Continued congestion in the Houston area helped hedged traders in the point-to-point market reap $137.9 million in profits May 9 through 11, one participant said.
