The NEPOOL Markets Committee last week signed off on changes to the Inventoried Energy Program that are intended to get the winter reliability program back in line with global energy markets.
If approved by the full Participants Committee at its next meeting, the changes will incorporate an indexed forward rate to automatically adjust to changes in gas market prices ahead of next winter.
The tariff changes also alter the program’s gas contracting eligibility provisions, an effort to help increase the amount of inventoried energy brought to the region for the next few winters.
In approving the changes, the committee also rejected an amendment from Generation Bridge, which owns four natural gas units in Connecticut. The company wanted ISO-NE to change the maximum amount of stored fuel to be counted in the program from 72 hours to 120 hours.
Changing to 120 hours, Generation Bridge argued, would increase incentives to fill large tanks or arrange for more LNG in preparation for extended cold snaps. And it would improve the likelihood that units with oil capability but no capacity supply obligation would be available in the coming winters, the company said.
The committee, however, ultimately rejected that proposal.
Drilling down on DAS
The MC also continued to discuss ISO-NE’s proposed framework for a day-ahead ancillary services (DAS) market, diving into eligibility for the “flexible response services” (FRS) and energy imbalance reserves (EIRs) that will make up the core of the market.
Energy sources eligible for FRS will have to be dispatchable and located physically within ISO-NE (so no imports or virtual resources would be eligible). They would have to be unconstrained by transmission, not part of first-contingency supply loss and sustainable for a minimum of an hour.
EIR resources would also have to be physical supply resources located within the bounds of ISO-NE and either committed in the energy market already or a fast-start resource.
The committee also discussed settlement rules for the DAS market, which would be “largely unchanged from those proposed during Energy Security Improvements discussions in 2019-2020.”
Is Cryptocurrency the Answer to ERCOT’s Market Volatility?
AUSTIN, Texas — An executive with the Texas Blockchain Council extolled the virtues of bitcoin mining as an answer to the ERCOT market’s volatility last week.
Steve Kinard, the council’s director of bitcoin mining analytics and president of the Bitcoin Mining Foundation, told the Texas Reliability Entity’s quarterly meeting of its Board of Directors on Wednesday that he has made more than a dozen visits to ERCOT’s nearby headquarters. That includes meetings of the grid operator’s Large Flexible Load Task Force, which is developing policies on how best to integrate the large loads into the market.
“We’ve been having a fruitful conversation there. … The desire there is really to have a discussion on how we can maximize the benefit for all Texans of having a flexible load that can respond to economic incentives and help balance the grid,” said Kinard, a self-described cryptocurrency skeptic turned advocate.
“This is both the traditional demand response, but we’ve also seen miners effectively provide frequency response that helps balance [the grid] in times of unexpected outages,” he said. “Those are two different avenues that we’ve explored in terms of ancillary services that the industry can use. We’re trying to bring more transparency around that, and I think a lot of progress is being made.”
Bitcoin miners have flocked to Texas to take advantage of ERCOT’s low energy prices and the state’s business-friendly environment. The miners rely on the energy to run the massive banks of computers that produce the cryptocurrency. The computers solve complicated math problems, which then get added to the open-source blockchain; the miner is awarded bitcoins.
The average financial exchange can use more than 1,700 kWh of electricity, which is almost twice the monthly amount used by the average American home.
Kinard said mining isn’t a technical term, but “something that kind of snuck into the vernacular over time.” He said a white paper’s author used an analogy to gold miners who “expend energy to mine the scarce gold resource.”
“The bitcoin miners have to expend energy to bring new bitcoin into circulation, which is also a scarce resource,” Kinard said.
ERCOT has welcomed the industry and its terms because wind energy’s penetration has created market volatility. The coincidence of negative prices and a $5,000/MWh cap creates opportunities and the need for flexible loads, Kinard said.
“As ERCOT has evolved over time, particularly with more and more wind, we see more volatility and regional differences of power,” he said. “A lot of miners are seeking out power at the lowest cost to generate these computations. As result of that sort of [wind] boom that you’ve seen in Texas … often on a windy day, the power prices there will be zero.”
Texas Blockchain Council
Kinard’s background is in oil and gas banking. It only took two years of due diligence for him to change his mind on cryptocurrency.
He went from “thinking bitcoin is a scam and ridiculous, as most traditional bankers and perhaps some of you in the room would understandably think,” he said, “and then 180-ing to really believing that this is a transformational opportunity for the industry and for the state of Texas.”
AEP Texas (NASDAQ:AEP) CEO Judith Talavera updated the board on the Lower Rio Grande Valley System Enhancement Project, a series of 345-kV lines and interconnections in South Texas, saying the project is expected to be in service by January 2027.
The Texas Public Utility Commission approved the $1.28 billion transmission project in September. It will add 351 miles of lines radiating from a new substation and another link into the Lower Rio Grande Valley. AEP, South Texas Electric Cooperative and Electric Transmission Texas are among those involved in the construction. (See Texas PUC Directs Tx Construction in Valley.)
The valley has long been a high-growth area in both population and industrial facilities, “as long as I can remember,” said Talavera, with 22 years at AEP. However, limited transmission capacity has trapped renewable resources’ output in the region and prevented additional energy from coming in.
“I don’t think I’m going to tell any of you in this room that we’re seeing a tremendous amount of change in our industry,” Talavera told the directors. “And with that change comes some risks, sometimes for a variety of reasons. …
“These projects will certainly help enhance the reliability and, most importantly, the resiliency of the system in that part of the state,” she said. “They’re also going to add more flexibility for how generation as assets can be dispatched or scheduled.”
Talavera said the project will also improve ERCOT’s ability to schedule transmission outages.
The project’s developers are currently conducting open houses and gathering feedback from landowners. They plan to file five certificates of convenience and necessity by September for various portions of the project, Talavera said. Construction is expected to begin late this year or early 2024, she said.
85 ‘System Events’ in 2022
Less than two years after collaborating on the joint NERC–FERC report on the deadly February 2021 winter storm, Texas RE staff will again engage with the organizations on a review of the December winter storm.
While the ERCOT region held together and met demand with plenty of supply to spare, it also saw fossil fuel outages exceed expectations and load forecasts underestimate projected loads. The grid operator sought federal permission to ignore air-quality limitations should it have to declare an energy emergency alert, a move that was never necessary. (See “DOE Grants ERCOT’s Emergency Request,” FERC, NERC Set Probe on Xmas Storm Blackouts.)
“We generally fared [well], but we are in the process of doing some follow-up on some of the things that occurred during [the storm], most notably with some concerns about how we can get our load forecasts analyzed or better … as well as, we had a number of units that had some issues,” said Mark Henry, Texas RE’s director of reliability services and registration.
He said staff “at least took a look” at 85 system events last year. Nearly half (41) involved loss of generation, while there were 16 physical security events. The most significant events were the December storm, the second Odessa disturbance in June, a loss of wind generation in the Panhandle in March, and a loss of generation and transmission in Texas City and its refineries and petrochemical-manufacturing facilities. (See NERC Repeats IBR Warnings After Second Odessa Event.)
Equipment failures accounted for 31% of the events analyzed, and weather was identified as the cause of 25%.
Texas RE added 27 registered entities during the year. The organization now has 310 such entities, the growth being driven by wind, solar and storage resources.
“They tend to want to be independent,” Henry said. “Each site wants to be registered as its own entity. That makes it hard on us.”
Regional Standards Process Approved
The board and Members Representative Committee both approved staff’s proposed Regional Standards Development Process (RSDP) document that will now be submitted to NERC for a 45-day public posting period. Assuming NERC’s approval, the document will then be filed with FERC.
The RSDP defines the open process for adoption, approval, revision, reaffirmation and retirement of Texas RE’s regional standard for ERCOT. The process also details how to obtain a Texas RE regional variance to a NERC reliability standard.
In other actions, the board approved nominations for several of its committees:
Suzanne Spaulding, Milton Lee, Curt Brockmann and alternate Jeff Corbett to the 2023-24 Hearing Body, a non-standing committee that only meets when a contested case hearing is requested;
Spaulding as chair, and Corbett, Brockmann, Daniela Hammons and Texas RE CEO Jim Albright to the Director Compensation Committee; and
Crystal Ashby, Corbett and Hammons to the Nominating Committee.
FERC on Thursday granted waivers to eight renewable generation projects, allowing them more time to have their interconnection studies approved by NYISO’s Operating Committee before entering the 2023 Class Year (CY23) study.
Current NYISO tariff procedures require projects participating in a class year study to have their system reliability impact study (SRIS) approved by the OC before entering the study, which begins Monday.
Invenergy, York Run, Boralex, Barrett Hempstead, ConnectGen, Gravel Road, Microgrid Networks and Thousand Island each asked the commission for its SRIS to have until the completion date of the Annual Transmission Baseline Assessment base cases for CY23 to be voted on by the OC (ER23-803, ER23-787, ER23-798, ER23-783, ER23-786, ER23-830, ER23-785, ER23-780).
The eight projects were unable to meet the Monday deadline. Their requests were supported by NYISO, other state agencies and the Alliance for Clean Energy New York (ACE NY).
The developers argued that they performed procedural due diligence, requested NYISO to expedite their SRISes and kept the ISO informed about their progress.
NYISO told FERC that study delays occurred from a variety of factors, including multiple revisions or material alterations. ACE NY and agencies including NYSERDA said further development delays could limit both health benefits to citizens and emissions reductions.
Each request also cited how FERC had granted similar waivers to the Clean Path New York transmission project.
FERC said it granted the waivers because the facility projects “acted in good faith,” made requests “limited in scope” that related to “a single timing requirement,” could experience significant delays in their development and because granting them would not have “undesirable effects” on other CY23 participants.
WASHINGTON ― State energy offices have a key role to play in transmission planning, and they can and should take action even before FERC finalizes its rules on regional planning and cost allocation, Commissioner Allison Clements told a packed ballroom at the National Association of State Energy Officials’ (NASEO) Winter Policy Summit on Wednesday.
“There’s a feeling around Washington, perhaps, that FERC’s got this under control; we’re going through this transition,” Clements said, referring to the commission’s much-debated notice of proposed rulemaking on transmission planning issued last April. “FERC can cross every ‘t’ and dot every ‘i’ [for] the perfect transmission planning and cost allocation rule, but if the states [haven’t] bought in and if the rest of the pieces related to getting transmission done, from cost allocation to siting, aren’t considered together, we won’t get it done. …
“You have an opportunity to decide by being proactive in your state in these federal jurisdictional planning processes how you want this to play out,” she said.
State regulators and utilities are generally seen as having the primary power for transmission planning at the state level, but Clements and others at the conference argued that energy offices can act as hubs for bringing together public, private and community stakeholders, as well as fostering regional and cross-state collaborations. Such state-level efforts could include not only planning for new transmission, but also upgrading lines with grid-enhancing technologies (GETs).
“Transmission is the No. 1 solution to the reliability, costs and security of our system. That is the reality today,” Clements said. “The other reality is that money is going to be spent. … And the question is how are we going to direct that money? How can we make that money be spent well, so that customers 10 years from now, 15 years from now, 20 years from now are not left holding the bag on a system that is under-matched for the challenges at hand?”
The development of transmission for offshore wind is ripe for regional planning, Clements said, pointing to the efforts of five New England states to secure up to $250 million in federal funding from the Infrastructure Investment and Jobs Act. (See New England States Group up to Push for Federal Transmission Funding.)
“Current transmission system planning wasn’t designed to create a whole new grid, which is effectively what a regional offshore wind system is,” she said.
The first offshore wind projects now under development are being laid out with radial lines connecting them to onshore substations, which is “not the most cost-effective way to get significant capital transition investment done,” Clements said.
“If we start as a group of willing states, whether it be offshore or onshore in your region, and start talking about what a robust set of investments look like 10 years forward, you have the opportunity to not slow down the current procurements, which your states are very focused on, but to have a parallel track to be thinking forward about what you want that to look like,” she said.
Clements also encouraged state energy offices to actively promote the use of GETs — such as dynamic line ratings and advanced conductors — to increase the capacity of existing lines while saving millions for grid operators and customers.
Citing a 2021 report from the Brattle Group, for example, Clements said a combination of GETS could double the amount of renewable energy that could be interconnected on existing lines.
While some projects have been successfully completed, GETs are not being widely adopted, Clements said, first because of misaligned incentives. “Why would a transmission owner or a utility want to make an investment that would actually decrease its need to increase its rate base?” she said.
A bigger challenge, however, is the jurisdictional split between FERC and the states, and transmission and distribution, Clements said. “FERC usually focuses on the bigger transmission investments; states are usually focused on the distribution system,” she said. “We have to close that gap, and I think it is incumbent on all of us to talk to our regulators about the opportunity for grid-enhancing technologies; to ask our utilities about it; to put a little friendly pressure on; to say, ‘What are you doing on this?’”
Spurring Private Investment
Estimates vary of just how much new transmission the U.S. will need to achieve a carbon-free grid by 2035 and a net-zero economy by 2050. A much cited 2021 study from Princeton University called for a threefold increase in transmission capacity, while a recent study from the National Renewable Energy Laboratory said the amount of new transmission needed will depend on the generation mix, setting a range of 1.3 to 2.9 times current capacity.
The IIJA includes $10.5 billion for a new Grid Resilience and Innovation Partnerships program, and Maria Robinson, director of the Department of Energy’s Grid Deployment Office, said the first round of funding for the program, totaling $3.8 billion, had drawn hundreds of concept papers.
“What excites me most about what’s going on here is that there are lots of really phenomenal ideas for rapid resilience … whether that is coming from utilities directly, or munis or co-ops, you have lots of terrific ideas on how they want to modernize,” Robinson said.
Echoing Clements, Robinson sees state energy offices as being able to extend the reach of federal funding to look “at how we continue to use this momentum to spur greater investments moving forward from the private sector as well … to ensure we’re getting the best bang for our buck.” Ongoing collaboration between DOE and state energy offices is an integral part of Robinson’s vision for “figuring out where the needs are.”
Robinson acknowledged some of the frustrations raised by the funding limitations, specifically that some of the IIJA funds for grid resilience cannot, at this time, be used to include generation from microgrid projects. “It’s just terrible,” she said. “We are working really hard to figure out if there are other places where we might be able to find that money” for microgrids to be included in grid resilience projects, she said.
Convening, Informing, Engaging
Karen Wayland, CEO of the GridWise Alliance, sees the blurring of lines between state and federal jurisdiction as a result of the higher profile states are taking in setting their own clean energy targets. As a result, she said, state energy offices need to be actively engaged with their governors, legislatures and grid operators.
According to the U.S. Energy Information Administration, 31 states and the District of Columbia have set renewable portfolio or clean energy standards.
“We’re trying to design a system to meet state and federal goals, and so that means that the states have to be involved in the infrastructure that’s necessary to be that platform to meet their decarbonization and their security goals,” Wayland said in an interview with RTO Insider. “They have a really important role to play in convening the relevant stakeholders at the state and local level to kind of guide them to an understanding of the goals that that expanded transmission would address.”
State energy offices also “have a big role to play” in coordinating stakeholder discussions on high-voltage transmission lines being planned to connect nodes within their states, to help determine “whether and how and where a transmission line will be built.”
NASEO President David Terry sees state energy offices being able to take a broader view of energy market evolution than state regulators typically can because of the statutory limitations of their work.
State energy offices can “work with local communities on behalf of your governor, on behalf your legislature, to inform them of why the state is going in a certain direction with their energy activities,” Terry said. “Why a transmission line may be important; what’s the value to them … what’s the long-term benefit. For the average voter or consumer, this is not exactly top of mind.”
While “kind of soft and a little bit amorphous,” Terry said, the stakeholder engagement and public education roles of energy offices do have an impact on state-level decision making. They can “look across all of these new demand[-and-]supply issues … and they can take in some of those concerns that private sector industry has,” he said. “I think that informs the process. Nothing will make it easy, but it informs it so at least the best decisions can be made.”
The latest rage in green electricity procurement is hourly matching of carbon-free (green) supply with customer load.[1]The impetus is recognition that the standard practice of annual matching involves non-green generation to balance supply and load throughout the year. This seemingly simple “next frontier”[2] in procurement is anything but simple.
Some Background
By way of background, let’s recall that no consumer physically gets a given supply of electricity. The grid is akin to a giant swimming pool with thousands of hoses dumping water in (generation) and millions of hoses taking water out (consumers). The grid operator is charged with maintaining the water level (balancing). No one physically gets water from a specific water hose.
This is a crude analogy because, among other things, when it comes to electricity, no one gets anything physical at all (matter) — not even electrons, which don’t actually move.[3]Instead generators supply electric energy, and that’s what consumers use. With me so far?
So when a consumer buys green electricity, it’s basically getting a contract commitment of some form that X megawatt-hours of green electricity are generated by the seller, and the seller hasn’t sold these green attributes elsewhere.[4]
With annual matching there is total annual green generation equal to total annual consumer load. But because of large differences between generation and load throughout the year, the grid operator has to procure and deliver other generation when that green consumer’s load exceeds the green generation. And when green generation exceeds the green consumer’s load, the excess is delivered to other consumers (or curtailed).
Now consider this situation with hourly matching instead of annual matching. Every green consumer has to pay the cost of covering its hourly load with green supply. Each hourly load has to be covered from some combination of green generation and storage. The extra green generation to cover peak hours will be under-utilized during other periods, and storage, especially long-duration storage, is hugely expensive, so the cost of this hourly matching is huge.[5]
Proponents of this “next frontier” of hourly matching vis-à-vis annual matching say that the former incents much more actual green generation because of the basic phenomenon described above. But there are multiple problems with this vision — as we shall see.
Hourly Matching Is an Irrational Way to Reduce Emissions
The incremental cost of hourly matching versus annual matching is many times greater than the incremental green generation from hourly matching versus annual matching. The modeling by the proponents of hourly matching shows this.
If you look at this emissions reduction chart for annual matching versus hourly matching, you’ll see that annual matching for the sample participation rate in California modeling yields 2.4 million tons/year, compared with 5.7 million tons/year for hourly matching, a ratio of 2.4 to 1.[6]
Jesse D. Jenkins
And now if you look at the cost premium chart for annual matching versus hourly matching, you’ll see that annual matching has a cost premium of $1.60/MWh, compared with a $19.90/MWh cost premium for hourly matching, a ratio of 12.4 to 1.[7]
Jesse D. Jenkins
So, instead of spending more for hourly matching, the green customer should use extra dollars for more annual green purchases.[8] The same dollar creates much more emissions reductions when spent on annual matching instead of hourly matching.
The Premises for Hourly Matching Are Wrong
Proponents of hourly matching presume that this consistently matches green generation with load. This is not the case for at least three reasons.
An hour is unpredictable, arbitrary and wrong. Proponents of hourly matching presume that within any given hour the green generation is matching the green consumer’s load. Of course a typical consumer’s load fluctuates widely; can a given consumer accurately forecast its load hour-by-hour and then communicate that to a generator such that the generator tracks that forecast with its output?
Wind power forecast and actual wind power values, for one day, in five-minute intervals | Pacific Northwest National Laboratory
And even where the consumer’s load tends to be flat (such as at a data center), green generation is not. This is illustrated by wind generation data for a typical balancing authority (region) for five-minute intervals.[9] You can see that wind generation varies greatly among 12 five-minute intervals comprising an hour.
If hourly matching is used, load will be matched to the average of the 12 five-minute intervals. During any given five-minute interval when load exceeds wind generation, other resources will be dispatched to cover the difference. And, similarly, when load is less than wind generation, the excess will be delivered to other consumers.
Just like annual matching!
Location, Location, Location
PJM real-time load-weighted average LMP for 2021 | Monitoring Analytics
To further complicate matters there is the stumbling block of transmission constraints throughout the grid. In PJM for example, there are thousands of such constraints which, by definition, keep lower-cost energy from reaching load (aka “congestion”). This happens all the time all over PJM and is indicated by higher energy prices in constrained areas.[10]This map of varying energy prices in PJM illustrates the phenomenon.[11]
Now let’s consider a consumer inside a transmission-constrained area for a given hour. If the consumer’s green supply is on the other side of the constraint, then that green supply does not supply that consumer. Other generators, inside the transmission-constrained area, are being dispatched to supply that consumer (and other load within the constrained area).
The proponents of hourly matching say that generators and consumers will be grouped together by “the same electricity grid region,”[12]thus ignoring these transmission constraints.
Marginal Emissions
If things weren’t complicated enough, unless and until all non-green resources are eliminated from the grid, there is the nagging problem of marginal emissions. These come from the last (most expensive) resources dispatched to meet demand at any given point in time. And they typically would be fossil fuel resources because of their higher variable cost than green resources.
If we take a consumer that has an hourly matching supply arrangement, it can point to a matching green supply for its hourly load. But the sheer presence of its hourly load could cause the marginal resource to be fossil fuel instead of green. Now this consumer could argue that this is not the right “but for” test because without its load it wouldn’t be providing the green supply, and therefore the marginal fuel would be fossil fuel in any event.
But then again, once the green generation exists it would run regardless of whether it’s part of the supply committed to that consumer. So whether hourly matching always causes zero emissions (putting aside the arbitrary hour and transmission constraint issues discussed above) is somewhat of a metaphysical question.
Wrapping Up
Hourly matching is wasteful, and the premises for it are wrong. The climate challenge is tough enough without wasting money.
Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.
[3] “Energy is transmitted, not electrons. Energy transmission is accomplished through the propagation of an electromagnetic wave. The electrons merely oscillate in place, but the energy — the electromagnetic wave — moves at the speed of light. The energized electrons making the lightbulb in a house glow are not the same electrons that were induced to oscillate in the generator back at the power plant.” -Brief Amicus Curiae of Electrical Engineers, Energy Economists and Physicists, at 2, New York v. FERC, 535 U.S. 1 (2001), https://www.findlawimages.com/efile/supreme/briefs/00-568/00-568.mer.ami.engineers.pdf
Stakeholder committee chairs last week restored a MISO stakeholder governance group to manage matters related to the RTO’s stakeholder governance guide.
MISO’s Steering Committee, comprising stakeholder group heads, on Thursday approved the Stakeholder Governance Working Group’s (SGWG) charter that describes the group as an “open forum” for stakeholders to “oversee and manage” the RTO’s Stakeholder Governance Guide.
The guide lays out how the various committees, work groups and task forces are structured and how meetings should be conducted. The SGWG will conduct periodic reviews of the governance guide, address stakeholders’ suggestions to improve the stakeholder process and discuss concerns over meeting facilitation.
The working group will meet twice per year or as needed. Meetings are open to all interested stakeholders.
The SGWG was disbanded about seven years ago, leaving only members of MISO’s advisory and steering committees to propose and develop revisions to the governance guide. (See MISO Members Want to Revive Stakeholder Governance Group.)
MISO’s stakeholder relations group will request leadership nominations via email and schedule the first meeting later this month.
Reliability Subcommittee Chair Ray McCausland, with Ameren, proposed reviving the small stakeholder group last year and volunteered to chair it.
“I’m really excited to see this invigorated again,” said Steering Committee Vice Chair Sarah Freeman, who sits on the Indiana Utility Regulatory Commission. “It’s great to see so many stakeholders interested in how we conduct our business at MISO.”
Xcel Energy’s Carolyn Wetterlin, vice chair of the Cost Allocation Working Group, said it was reassuring to have the stakeholder community’s “governance geeks” back on the job.
Freeman said she would like to see the SGWG tackle how the Advisory Committee can have more input into tariff change filings before MISO sends them to FERC.
“I think the governance process has suffered to some extent because of the stakeholders that can talk about it,” McCausland said, a reference to the years that only Advisory Committee and Steering Committee members could direct governance guide changes.
The Smart Electric Power Alliance (SEPA) last week released its latest assessment gauging utilities’ progress and identifying actions to accelerate the industry’s transition to a carbon-free energy system.
SEPA recognized a dozen utilities in its 2023 Utility Transformation Challenge as being ahead of the curve in the clean energy transformation. Most of those are in California, with glowing reviews to Palo Alto Utilities, Pacific Gas and Electric, Sacramento Municipal Utility District and Southern California Edison.
The organization said Snohomish County Public Utility District in Washington and Portland General Electric in Oregon also made good progress.
On the East Coast, SEPA praised Vermont’s Green Mountain Power, New Jersey’s Public Service Enterprise Group and National Grid, which supplies New York and Massachusetts. Austin Energy, the Texas city’s municipal provider, and Minnesota-based Xcel Energy were the only commended utilities between the two coasts.
Those recognized had to complete SEPA’s Utility Transformation Challenge survey to be considered. The organization said it collected data from 118 utilities in 41 states, representing more than half of U.S. customer accounts.
SEPA said the utilities that made its final cut supply “a substantial percentage” of their retail energy with clean resources, including energy efficiency and demand response; have strong commitments to carbon reduction; feature publicly available climate-adaptation strategies; and have plans for an equitable energy transition.
It said it’s also noticing an asymmetrical transition to clean energy, though utilities have rolled out more aggressive decarbonization targets, better climate action plans, improved visibility into their distribution systems, and have made strides to a more equitable power system.
The group said 66% of utilities responding to its survey have expanded their clean energy sources and 80% have a carbon-reduction goal in place. SEPA said it expects those goals will take decades to achieve and recommended utilities establish interim reductions goals.
“Utilities will need to navigate supply chain disruptions, transmission and interconnection bottlenecks, the effects of natural disasters on resource acquisition and costs,” SEPA said, adding that utilities cited labor shortages and supply chain hitches for delaying new renewable energy. Those scuttled plans have led to 40 coal plants keeping 17 GW of capacity online past their planned retirement dates, SEPA said.
It said 69% of respondents are piloting or investing in early stage, carbon-free technology, including hydrogen, long-duration energy storage, floating offshore wind, tall wind turbines, small modular nuclear reactors, and carbon capture and storage.
SEPA said gridlocked interconnection queues have also hampered utilities trying to bring renewable generation online. It said PJM’s current backlog is preventing it from reviewing new interconnection requests until early 2026.
The organization also said droughts in the West contributed to a 14% reduction in hydroelectric generation from 2020 to 2021 and continue to threaten the carbon-free resource. SEPA warned that some utilities may be forced to purchase fossil-fired energy to replace the output.
To avoid that, SEPA recommended utilities use more demand-side management programs and pull together climate investment plans that consider the impact of climate change on operations.
FERC on Friday approved the tariff for the Western Power Pool’s Western Resource Adequacy Program, a groundbreaking reliability effort covering much of the Western Interconnection that is meant to ensure members have sufficient resources to meet summer and winter peak demands (ER22-2762).
The commission’s approval means the WRAP can move forward with its plans to begin a binding phase of the program by 2025, including penalties for members that fail to meet their obligations.
“Through increased coordination, we find that the WRAP has the potential to enhance resource adequacy planning, provide for the benchmarking of resource adequacy standards and more effectively encourage the use of Western regional resource diversity compared to the status quo,” FERC said in its decision.
At least 11 utilities had committed by December to joining the binding iteration of the WRAP. The nonbinding phase of the program has 26 participants, many of whom are expected to move into the next phase. (See Western RA Program Secures First ‘Binding’ Phase Participants.)
WPP has been developing the WRAP since 2020. The program initially was meant to address concerns that Northwest utilities had been increasingly and unknowingly drawing on the same shrinking pool of reliability resources, but interest in the effort spread quickly to other areas of the West.
WPP selected SPP to develop and operate the technical aspects of the program, providing the market’s forward-showing functions, modeling and system analytics, and real-time operations.
In a move that signified its expanding reach across the Western Interconnection, the Northwest Power Pool rebranded itself as the Western Power Pool in February 2022. The WPP board approved the tariff in August, sending it to FERC. (See Western Power Pool Board Approves WRAP Tariff.)
The commission responded in November with a deficiency letter that asked WPP to provide clarifications on the tariff filing, including about the program’s proposed requirement that participants secure transmission rights well in advance and about its intent to hire an independent evaluator to assess its performance. (See FERC IDs Deficiencies in Western RA Program.)
WPP responded to FERC’s questions Dec. 12, leading to the commission’s determination Friday.
FERC addressed a number of comments, protests and concerns, including questions about transmission commitments. The program’s forward-showing component requires participants to show they have sufficient capacity and 75% of the transmission necessary to deliver it seven months ahead of each summer and winter. Penalties will apply to those who do not.
The Northwest & Intermountain Power Producers Coalition (NIPPC) argued that the “required use of firm transmission contradicts the commission’s allowance for use of non-firm transmission in similar circumstances,” FERC said.
NIPPC also had “concerns with the 75% forward-showing transmission requirement, including the lack of support for the specific figure of 75%, the potential for market power being exercised by incumbent firm transmission rights holders and transmission providers, and the practical reality that transmission providers regularly release sufficient short-term [available transfer capability] well after the WRAP’s forward-showing deadlines to meet program needs.”
“NIPPC states that this will lead to regular requests for exceptions,” the commission said.
FERC disagreed with NIPPC’s protest. WPP’s forward-showing program “includes reasonable requirements to ensure deliverable resource adequacy, while also providing necessary flexibility to participants. Further, we find that the requirements of the proposed program can help to enhance price formation in the Western Interconnection by sending price signals to market participants regarding the availability of capacity and firm transmission service and the need for future market entry.”
With respect to the independent evaluator, FERC staff had asked WPP in November whether the evaluator’s report would be made public.
WPP responded that the evaluator’s annual reports are “intended to be made public” and proposed a tariff revision to explicitly state that the “independent evaluator’s annual reports shall be made available to the public, except to the extent that they contain information designated as confidential under this tariff, or information designated as confidential by the independent evaluator.”
FERC accepted WPP’s clarification and tariff revision.
“We recognize that for the commission, state regulators, participants and other stakeholders, the independent evaluator’s reports will be a key source of information and analysis on the WRAP’s operation,” FERC said. “Further, the WRAP is a novel design for the Western Interconnection, and as the program matures, the insight into its functioning will provide useful information and transparency to all stakeholders.”
In a news release Friday, WPP CEO Sarah Edmonds said, “We’re so pleased that FERC shared the industry’s appreciation for the value of a regionwide resource adequacy program and supported our vision for it. This is a critical step for the West to help ensure that we can achieve a clean energy future, without sacrificing reliability.”
The WPP will next make governance changes required by the tariff by seating an independent board of directors that it named in October.
“Our governance model, including an independent board of directors, is a critical piece of the WRAP,” Edmonds said. It “was demanded by our stakeholders and establishes the standard for regional organizations like this one.”
Duke Energy (NYSE: DUK) on Thursday reported higher earnings for the full year of 2022 because of higher electricity volumes, more favorable weather and rate case contributions.
The company reported adjusted earnings of $5.27/share, compared with $4.99/share in 2021, though unadjusted earnings came in at $3.33/share, compared to $4.94/share the previous year.
“We achieved results solidly within our updated guidance range while making significant progress on our strategic goals, responding to external pressures and delivering constructive outcomes across our jurisdictions,” CEO Lynn Good said during an earnings call.
The company is in the process of selling Duke Energy Sustainable Solutions, a non-regulated renewables developer that has 5,319 MW worth of projects spread around the country, and it took an impairment charge of $1.3 billion related to the sale.
“I think the thing to recognize on an impairment charge is it’s an accounting adjustment that’s really driven by the earnings profile of renewables where a lot of the profit sits in the early part of the life, [and] you then depreciate it over a longer period of time,” Good said. “So, when you make a decision to exit before the end of the useful life, you’ve kind of set yourself up for an impairment.”
Duke announced plans to sell its commercial renewables business in November, and it hopes to complete that process later in 2023.
While it is getting out of the business of developing competitive renewable projects, most of Duke’s expected spending in the coming years will be on shifting its regulated utilities to cleaner generation, with a $65 billion capital plan for all of its regulated businesses.
In North Carolina, the next steps for that capital spending have been laid out in the firm’s first carbon plan, which was approved by state regulators late last year. The state approved Duke to build 3,100 MW of solar and 1,600 MW of energy storage in the near term, with limited development activity for longer-term projects, including small modular nuclear reactors.
The North Carolina Utilities Commission also authorized Duke to plan for about 2,000 MW of new natural gas plants that Good said are needed for reliability.
“Through its order, the commission reinforced the importance of maintaining a diverse generation mix while conducting an orderly clean energy transition and was clear that ensuring replacement generation is available and online prior to the retirement of existing coal units is a shared priority,” Good said.
The carbon order supports Duke’s own capital plan, giving it the clarity that it needs to advance critical near-term investments, she added. Duke plans to spend $4.7 billion over the next three years, largely on transmission and distribution enhancements, though with some earmarked for the solar and storage approved by the NCUC.
While Duke is focused on solar and storage in the short-term, Good said the company would need to build 10 to 15 GW of “zero-emitting load-following resources in the late 2030s, or 2040s.
“That could be hydrogen; it could be small modular reactors; it could be [carbon capture, utilization and storage]; it could be longer-duration storage,” Good said. “So, the key being, again, though, we’re not going to invest until they are affordable for our customers, and we can invest at the commercial scale necessary to make a difference.”
Duke is spending time on small modular nuclear reactors because it is the largest “regulated” operator in the country and is in part of the world where the technology is generally viewed favorably, Good said.
The company has also worked with neighboring utilities in the Southeast on a hydrogen hub because Good expects it will have plenty of extra solar energy that could be used to produce the fuel.
“We’re not ready to put our finger on any specific technology as the solution,” she added. “But we are advancing our work, piloting, advising, working as actively as we can to make sure these technologies are developing at pace so that when we do need them and are ready to invest, there will be something that makes sense for our customers.”
Soaring natural gas prices drove up wholesale electricity costs in the CAISO energy market by roughly $4 billion in December and January, making it one of the more expensive periods in recent years, an ISO report said this week.
About $3 billion of that amount came in December, when natural gas prices in California far outpaced the national benchmark Henry Hub in Louisiana. On Dec. 21, for example, spot prices at Henry Hub averaged $6.14/MMBtu, while those in California reached $53.59/MMBtu, nearly nine times more, the U.S. Energy Information Agency reported.
High natural gas prices impacted large swaths of the West in December, including the Desert Southwest and the Pacific Northwest.
“Next-day natural gas prices for Western hubs reached a maximum value of about $57/MMBtu on Dec. 22,” a day when CAISO’s wholesale costs surged toward $300 million, far beyond its standard cost of $50 million, the CAISO report said.
“Prices for other Western hubs traded at similarly elevated levels across the month of December … [while] Henry Hub prices remained comparatively low,” it said.
In the fourth quarter of 2022, total electricity costs in CAISO reached $7.4 billion, just short of the third quarter’s $7.6 billion total during a severe heat wave that brought CAISO to the verge of ordering rolling blackouts Sept. 6 and pushed electricity prices past $2,000/MWh. (See CAISO Reports on Summer Heat Wave Performance.)
The third quarter costs reflected “summer conditions where record-high demand levels were settled at relatively higher prices given the tight supply conditions,” the report said. “The cost of fourth quarter of 2022 came fairly close to the same level of the third quarter, at about $7.4 billion, even though electric demand was lower.”
“This is a twofold and threefold increase relative to the fourth quarters of 2021 and 2020, respectively,” it said.
The sudden and largely unexplained jump in energy prices in California and the West led Gov. Gavin Newsom to urge FERC to act. In a letter Monday to FERC Chair Willie Phillips, Newsom asked the commission to “immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior or other anomalous activities are driving these ongoing elevated prices in the Western gas markets.”
Wholesale natural gas prices directly affect electricity costs because California relies heavily on gas-fired power plants, which often act as the marginal unit setting the price for all units clearing CAISO’s day-ahead and real-time markets. The gas costs are passed on to ratepayers by the state’s investor-owned utilities, doubling and tripling bills for millions of customers, especially in Southern California.
“California’s residential customers are, consequentially, suffering the economic burden of extreme and unexpectedly high gas and electric utility bills,” Newsom wrote.
The California Public Utilities Commission, state Energy Commission and CAISO held a joint meeting Tuesday to try to understand the factors that led to the extraordinary price hikes. Market analysts and utilities weighed in, citing conditions such as an El Paso Natural Gas pipeline that exploded in Arizona in August 2021, impacting one supply line to California, and CPUC limits on storage at Southern California Gas Company’s Aliso Canyon, where a massive methane leak occurred in October 2015.
A cold snap in December increased heating demand from residential customers in California and across the West, panelists said.
In his letter to FERC, Newsom said the cold weather certainly “exacerbated” the gas price increases but lower-than-normal temperatures and other “known factors cannot explain the extent and longevity of the price spike,” which began in late November and lasted through January.
“It is clear that the root causes of these extraordinary prices warrant further examination,” he said.
