MISO said it likely can take on fall with sufficient capacity and minimal operating challenges.
The grid operator issued a fall outlook last week, where it said it should have enough capacity to last the season. It anticipates having 119 GW in firm capacity to handle an expected 107-GW peak in September, 102 GW in October to cover an 89-GW peak and 106 GW in November for an 87-GW peak.
MISO said it should be able to operate squarely within its nonemergency resources through November. However, it said on the slim chance it experiences a confluence of load that could rise as high as 117 GW with unusually high generation outages, it could require all of its 10 GW in load-modifying resources on a September day. That’s the most serious possible scenario MISO foresees. The RTO first must issue a maximum generation emergency to access any of its load-modifying resources.
MISO’s record fall demand stands at 115 GW on Sept. 22, 2017.
On average, MISO experiences nearly 33 GW in generation outages over the fall; outages have hit almost 45 GW at certain times during past seasons.
The National Oceanic and Atmospheric Administration is anticipating a warmer-than-normal autumn for MISO South and average precipitation across the MISO footprint.
MISO may have the worst of summer high temps behind it after it declared a maximum generation emergency to manage heat-driven load and forced generation outages Aug. 24. The grid operator ordered load-modifying resources for more than seven hours and escaped the heat wave without taking the most serious step of load shed. (See related story, MISO Calls 1st Summertime Emergency amid Systemwide Heat Wave.) By Thursday night, it had terminated its maximum generation warning, capacity advisory, conservative operations instructions and hot weather alert for the entire footprint. However, it issued a fresh alert early Friday for lingering heat in MISO South.
CARMEL, Ind. — MISO is open to making edits to its process for approving transmission reconfiguration plans that reduce congestion costs to increase the programs’ odds of approval.
MISO has approved two congestion cost reconfigurations of 44 submittals to date, resulting in a 4.5% approval rate. The grid operator said it’s evaluating its market study process for reconfigurations “due to time commitment and low approval rates.”
Multiple stakeholders said the RTO’s low approval rate of reconfiguration proposals is disappointing. They said when load-serving entities submit a reconfiguration plan, it already has a healthy amount of study behind it.
At the Aug. 22 Reliability Subcommittee, Alliant Energy’s Mitch Myhre asked for MISO to conduct a nonpublic sit down with stakeholders to get a better understanding of study input and “why results are coming out the way they are.”
MISO said it may introduce some edits to its transmission reconfiguration study and approval process at a future Reliability Subcommittee.
MISO members have been paying more attention to transmission reconfigurations with congestion costs on the rise. Last year, MISO assembled a nonpublic Reconfiguration for Congestion Cost Task Team, which focuses on transmission owners’ plans to reroute transmission flows during times of heavy congestion costs. The task team maintains a monthly list of the top congested constraints within the footprint that might benefit from a reconfiguration.
Some MISO members have said it’s imperative MISO use reconfiguration plans because major transmission expansion that will ease congestion still is years away from being built.
The ERO’s communication with energy policymakers is becoming increasingly crucial to ensuring the reliability of the electric grid, according to NERC’s 2023 ERO Reliability Risk Priorities Report released this week.
NERC’s Reliability Issues Steering Committee (RISC) develops the report every two years, based on input from ERO Enterprise stakeholders and policymakers on the risk areas of most concern to them. The organization’s Board of Trustees accepted the report last week at its meeting in Ottawa, with Chair Ken DeFontes calling it “the best [reliability risk report] I’ve ever seen.”
Reliability risks in the 2023 report are grouped into five risk profiles:
Energy policy — on the federal, state and provincial levels;
Grid transformation — including grid planning, resource adequacy and performance and the changing resource mix;
Security risks — physical, cyber and electromagnetic pulse;
Resilience to extreme events; and
Critical infrastructure interdependence.
Energy policy is a new addition to the risk profiles; the others were present in the 2019 and 2021 reports. (See Grid Transformation, Cybersecurity Lead 2021 ERO Risk Report.) The new risk reflects the implementation of “decarbonization, decentralization and electrification” policies by federal, state and local governments across NERC’s footprint and their potential impact on reliability.
Speaking to the Board of Trustees last week, RISC Chairman Brian Slocum said that although energy policy has previously been considered “outside of the purview of NERC,” when committee members brought the topic up for inclusion they met with broad encouragement.
“We brought this as a topic to everybody [on the RISC] — are you comfortable with us putting this into the risk report? And [we] got support from all of the members that this is something that we need to talk about,” Slocum said. “Dealing with jurisdiction issues in the distribution-transmission interface and federal and state jurisdictional issues, we have to be able to talk about these things. I feel as though this is one of the most impactful things in the risk report … just bringing this opportunity for people to feel comfortable bringing up this topic and talking about it.”
The report’s authors explained that “energy policy can drive changes in the planning and operation” of the electric grid that “could present risks to its reliable operation.” Addressing this requires the ERO to develop “strong collaboration and partnerships” with policy makers to ensure that they understand the importance of grid reliability and prioritize it during their deliberations.
All five risk profiles are intertwined, the report said. Decarbonization and electrification initiatives are causing the deployment of non-synchronous generation as well as natural gas resources. The transformation also includes adoption of demand response, microgrids and other technologies that are more dependent on communication technology and electronics and thus introduce new security risks.
Extreme temperatures and disruption of wind and solar power supplies may also impact reliability. The introduction of new generation types also increases the critical infrastructure interdependencies. Just as the interruption of natural gas supplies can idle combined cycle facilities, outages in the telecommunications system may also “hamper situational awareness and real time [grid] operation.”
The interdependencies work both ways: For example, the electrification of transportation may make delivery of essential goods more difficult in power outages from a hurricane.
Trustee Larry Irving, who is CEO of a telecommunications consulting firm, warned at last week’s meeting that the communication industry is more vulnerable to electric outages than most customers realize, and emphasized the need for collaboration with NERC’s peers in other industries.
“When we had the [2003 blackout], 94% of American households had a landline phone; those landline phones had their own power,” Irving said. “Today, fewer than one in three households have a landline. We’re dependent upon [cellular] towers, which may or may not have electricity … so even if your battery and your phone work, you don’t have a phone.”
“The point I’m trying to make is, I don’t know if we do enough with the telecommunication industry,” he continued. “If we have a coordinated [cyber] attack in this country, the two places they’re going to go after, if they’re smart, would be the telecommunication industry and this industry.”
CARMEL, Ind. — MISO instated maximum generation procedures Thursday to manage a pervasive heat wave blanketing its footprint.
The grid operator called a maximum generation event to begin at noon ET as temperatures climbed to 95 degrees Fahrenheit and above throughout most of its system. It de-escalated the emergency into a maximum generation warning effective at 7:30.
MISO topped 122 GW of demand during the evening peak, short of its all-time peak demand record of 127 GW, set July 20, 2011. By 5 p.m., hub LMPs were around $220/MWh in MISO Midwest and $150/MWh in MISO South.
Ahead of the demand surge, MISO forecast a 127-GW peak by 5 p.m. with a little more than 121 GW in cleared offers.
Real-time prices at hubs at 5:30 p.m. Aug. 24 | MISO
MISO previously enacted a footprint-wide capacity advisory and conservative operations Monday, before a maximum generation alert for Thursday. As it geared up for the day, the RTO asked all members to update their market data with their best available information. MISO said it was contending with forced generation outages paired with abnormally high temperatures and higher load than forecast a day prior.
DTE Energy’s 1.1-GW Fermi 2 nuclear plant south of Detroit was offline during the week’s hottest weather. The company was forced to perform an unscheduled outage because of a coolant leak.
“We’ll see how this week shapes up. We’ve already sent out several hot weather alerts and capacity advisories,” MISO Director of Market Administration John Harmon said ahead of the emergency declaration and the most intense heat at the Reliability Subcommittee’s meeting Tuesday.
The Tennessee Valley Authority also struggled alongside MISO in the heat. On Thursday, the U.S. Energy Information Administration reported that TVA’s 27 GW in net generation was no match for 32 GW in forecasted demand. The federal utility had been relying on gigawatts of imports from MISO and its other neighbors since Sunday.
August had already been peppered with tricky operating conditions and alerts related to summer heat stressing MISO’s grid.
The RTO also declared conservative operations instructions to members in Wisconsin and parts of its northern footprint Aug. 3. At the time, MISO said it was experiencing tight capacity, a loss of generating units and low wind production.
MISO issued another round of conservative operations for MISO South on Aug. 11 and again on Aug. 14. In that timeframe, South was also subjected to multiple hot weather alerts and capacity advisories.
Before this week, MISO had not encountered a summertime energy emergency; it avoided ordering up load-modifying resources during another heat wave in late July. (See MISO Preps for Heat Wave, Anticipates Annual Demand Peak.) The blistering temperatures wrought a 121-GW peak July 27, which until now stood as MISO’s annual peak. Otherwise, systemwide load averaged 86 GW in July.
MISO achieved a little more than 3-GW all-time solar peak July 25. At the Reliability Subcommittee meeting, Harmon said the RTO expects to keep eclipsing solar output records as utilities bring more facilities online.
The North Carolina Utilities Commission on Wednesday approved two programs for on-bill efficiency funding in Duke Energy’s territories.
Both Duke Energy Carolinas and Duke Energy Progress (DEP) won approval for a residential tariff on-bill (TOB) program that is meant to offer customers a way to pay for energy efficiency upgrades over time through their monthly bills.
“By using premises-specific modeling based on an in-home assessment, applying all available rebates and incentives and utilizing an initial copayment, if necessary, the customer’s TOB monthly charge will not exceed the customer’s projected average monthly savings over the repayment term of up to 12 years,” NCUC said in its order.
In a separate order issued Wednesday, NCUC approved a pilot program for DEP’s “Multi-Family New Construction Tariffed on Bill Pilot.” The five-year pilot program is meant to evaluate the effectiveness of on-bill funding for upgrading the efficiency of apartment buildings as they are under construction.
The program will be focused on apartment complexes with 700 to 1,000 units, and DEP can implement eligibility requirements so that participants are spread around its footprint and not dominated by a few residential developers.
The upfront costs for energy efficiency improvements have long been identified as a significant obstacle for customers wishing to improve their homes. The TOB program is meant to overcome that barrier, the commission said in its order.
The residential TOB tariff is linked to the meter at a specific address, so even if the customer who signed up moves, it would stay with whoever buys the residence. The TOB charges will recover the initial investment plus interest equal to Duke’s utilities most recently approved weighted average cost of capital.
The TOB program for both utilities is open to individually metered residential customers who are served under the residential rate schedule, regardless of whether the owner occupies the residence or leases it. Customers need a 12-month billing history to establish the baseline consumption used to model projected energy savings.
Duke will maintain and repay any equipment as required. Customers must notify it when they notice something in need of repair, and the utility will fix it within five business days. Customers have 30 days to report malfunctions.
The TOB program covers heating ventilation and air conditioning equipment, including smart thermostats, thermal boundary improvements, heat pump water heaters and other equipment on a case-by-case basis.
Initially, Duke plans to target customers who would stand to reap the biggest benefits, but over time it expects many of its customers will want to use the TOB program.
Though the NCUC ordered some changes to Duke’s filing, it found the program was in the public interest. The changes involved clarifications over how customers can repay Duke early for its work, at which point the utility will no longer be obligated to repair equipment.
Duke agreed to notify customers of any other programs that could pay for efficiency upgrades at lower costs — or for free — to the extent it is aware of them. Duke also agreed to work with the state to see how funding from the federal Inflation Reduction Act could be coordinated with the TOB program.
DEP’s apartment building pilot program can be used to add wall insulation, improved heat pumps, Energy Star appliances and heat pump water heaters when new buildings are being constructed. Duke will pay the incremental costs for more efficient equipment and recover their costs from tenants’ monthly bills, minus any applicable efficiency incentives.
Property owners will be responsible for maintaining all installed equipment and for timely repair measures. They are able to pay off Duke after three years in the program and thus end the extra monthly payments.
The commission required DEP to change the prepayment plan so that when an apartment complex owner pays off the utility early, it does not have to pay the interest it would have over the full term of the program. The regulator reasoned that the utility would be able to invest that money in other areas while having fully recovered its upfront costs.
Commonwealth Wind potentially began a new chapter this week as it secured regulatory approval to back out of its power purchase agreements with three Massachusetts utilities.
Also this week, the same regulators approved an offshore wind solicitation that will allow the project to be rebid at higher cost.
The milestone comes nearly a year after developer Avangrid first said it could not proceed with the 1,230 MW offshore wind project under the PPAs it had negotiated with Eversource, National Grid and Unitil.
After a flurry of motions, rulings and appeals, the parties announced a deal in July: Avangrid would pay a combined $48 million to the utilities, and they would support its motion to cancel the PPAs.
The Department of Public Utilities “stamp approved” the agreements Wednesday.
Avangrid has said it remains committed to the project — it just needs more money to follow through on it. It said it hopes to rebid in the next offshore wind solicitation.
A draft version of this solicitation was issued in May. It’s the Bay State’s fourth and, at 3,600 MW, its largest. The DPU approved it Wednesday with few changes (docket DPU 23-42).
The state Department of Energy Resources will issue it in final form soon, a spokesperson told NetZero Insider on Thursday. Bids will be due by Jan. 31.
The Commonwealth Wind saga is far from unique — many of the nation’s first wave of contracted offshore wind projects from Cape Cod to Cape May have run into major cost escalations and are seeking more money before committing to proceed.
However, Commonwealth was the first to attempt to back out and hit the reset button.
SouthCoast Wind is seeking to do the same thing with 1,200 MW of PPAs with the same three Massachusetts utilities, and also hopes to rebid in the fourth solicitation.
These developments cast a shadow on the offshore wind pipeline Massachusetts is counting on to help it achieve its clean energy goals. In almost any scenario, offshore wind now will be slower to come online or cost ratepayers more, or both.
But there are bright spots. Vineyard Wind is under construction off the Massachusetts coast. It’s expected to start exporting power to land this year and reach full 800 MW capacity in 2024.
And state officials remain committed to the goal of 5,600 MW procured by 2027.
Energy and Environmental Affairs Secretary Rebecca Tepper told NetZero Insider via email:
“We’re extremely confident in the future of the offshore wind in Massachusetts. Pioneering a new industry doesn’t come without challenges, but we’re laying the groundwork for long-term success. DOER’s adaptive RFP demonstrates our commitment to moving this industry forward. As we’ve seen with the Vineyard Wind project currently under construction, this can be done, and we’re working to create fertile ground to get more projects up and running.”
Avangrid will not — as some observers had hoped — be excluded from rebidding Commonwealth Wind in this fourth solicitation because it backed out of its previous commitments.
But 15 points in the 100-point evaluation process will be based on bidders’ past performance, with potential demerits for any delays, cancellations or terminations.
The solicitation will give bidders the option of indexed pricing, allowing for subsequent adjustments to reflect future inflation and other macroeconomic trends like those now bedeviling offshore wind developers.
RENSSELAER, N.Y. — NYISO on Tuesday updated the Transmission Planning Advisory Subcommittee (TPAS) and Electric System Planning Working Group (ESPWG) about the New York City Public Policy Transmission Need assessment.
Ross Altman, transmission integration manager at NYISO, outlined the baseline case assumptions and methodology for the forthcoming viability and sufficiency assessment, which evaluates whether a proposed transmission solution would fulfill the deliverability requirements set forth by the state’s Public Service Commission.
The PSC called for solicitations from energy developers that could deliver at least 4,770 MW of offshore wind energy from Long Island’s coast to New York City and fulfill the state’s goals of producing 9,000 MW of OSW by 2035. (See “NYC PPTN,” NYISO Addresses NYC Near-Term Reliability Need.)
Developers will work with Consolidated Edison, the company responsible for Long Island’s transmission system, to design a solution that not only delivers energy to the city, but also upgrades the local buildout to be more resilient to higher voltage outputs.
Several attendees were apprehensive about the timing of the required technical conference on the PPTN and whether there would be enough time to have it by the end of the year, as the meeting will be the first chance to learn more about the PPTN and ask both NYISO and Con Ed questions before solicitations are issued. The conference is slated for the fourth quarter.
Altman told questioners to expect the meeting to happen before December, but that the ISO will provide details on the conference as soon as possible. The conference “is very much top of mind, and our intent is to get this kicked off soon,” he said.
Kevin Lang, partner at Couch White, asked how energy storage will be considered.
Altman responded, “We will certainly have certain amounts of storage modeled, especially projects that have gone through Class Year 2021; however, [the ISO] will be modeling them at zero output, so not injecting or absorbing.”
Lang also asked for clarification on the baseline case assumptions related to downstate renewable output and what the presumed energy production conditions will be in a proposal’s evaluation.
Altman said the assumptions are set around 10 to 15% for solar output and OSW at full output: “Imagine it will be a very windy, slightly sunny condition.”
Overview of NYISO’s PPTN lessons learned process | NYISO
Altman said the ISO is willing to consider all improvements to the process and wants stakeholders to provide feedback that could improve the current New York City PPTN and future solicitations.
Michael Mager, a partner at Couch White, said many developers were struck by the huge discrepancies that occurred between developers’ bids and the estimated cost by the ISO’s consultant —sometimes trillions of dollars.
Altman acknowledged the potential differences but expressed confidence in NYISO’s estimates. He said any further questions, concerns or suggestions should be sent to PublicPolicyPlanningMailbox@nyiso.com.
System & Resource Outlook
NYISO staff presented the preliminary outline for the second System & Resource Outlook report.
The biannual Outlook forecasts New York’s transmission system for the next 20 years and came in response to the state’s Climate Leadership and Community Protection Act, which mandated aggressive goals climate and energy goals that forced the ISO to adjust its system forecasting processes. (See “NYISO Releases the Outlook,” NYISO OC Discusses NOPR Comments, High Temps, EDS Results.)
The report will be benchmarked to 2021 and modeled on an hourly load profile. It will include new emission-allowance considerations and programs, such as the Ontario Carbon Price scheme or the Regional Greenhouse Gas Initiative.
Chris Wentlent, chair of the New York State Reliability Council’s Executive Committee, and Howard Fromer, who represents Bayonne Energy Center, asked whether NYISO considered the state’s cap-and-invest policy, which would establish dynamic limits on emissions-producing activities and is working its way through state agencies. (See NYISO to Comment on State’s Cap-and-invest Plan.)
NYISO responded that it could be considered as part of the Outlook’s base assumptions should it become pertinent.
Additional feedback or questions must be sent to Jfrasier@nyiso.com at least one week prior to the ESPWG’s meeting Sept. 21.
FERC Order 2023
The TPAS/ESPWG also received an update on the status of FERC Order 2023 compliance from NYISO, which said it is focused on the potential requests for rehearing or clarification on the order.
NYISO attorney Sara Keegan told members the deadline for requests is next Monday but the ISO has not made a final determination on whether to submit a request. It will work to develop a compliance strategy after all rehearing and clarification motions are addressed.
Mark Reeder, representing the Alliance for Clean Energy New York, asked how the commission’s order would fit into NYISO’s ongoing work on its interconnection queue.
Keegan responded that “the order was pretty generous about independent entity variations” and seems flexible enough to work NYISO’s own proposals into the compliance directives, but this avenue is still under consideration.
Keegan added that compliance filings are due within 90 days of the rule’s publication in the Federal Register, but she does not expect that date to be earlier than late November; also, extension requests could be filed, which would further delay the process.
FERC has approved a settlement over an Arkansas steel mill’s yearslong failure to reduce load as a registered demand response resource in MISO.
The commission on Monday sanctioned a $21 million reimbursement as part of an agreement involving Big River Steel in Osceola, Ark., Entergy Arkansas and the commission’s Office of Enforcement (IN23-11).
Big River will return nearly $16 million in profits it received from September 2016 through April 2022 for its participation in MISO’s demand response program. The company also will pay a $6 million civil penalty to the U.S. Treasury and pledge to provide compliance training to its traders if it ever intends to participate again as a demand response resource in MISO.
Entergy Arkansas, which served as the market participant for Big River, will return $5 million it received and credited to retail customers. Entergy also will coordinate with the Arkansas Public Service Commission to return to its ratepayers the approximate net $8 million they were charged for the demand response activity associated with Big River. Under its agreement with Big River, Entergy Arkansas collected a 10% administrative fee, as well as charges for the avoided energy consumption.
For years, Big River submitted offers in MISO’s day-ahead and real-time markets through Entergy Arkansas. Big River’s operations can require up to 300 MW at a time. However, FERC’s Office of Enforcement said that except for a seven-day period during the winter storm that lasted Feb. 16-22, 2021, the steel mill “did not change mill operations to alter energy consumption levels when MISO accepted its demand response offers.”
Enforcement staff concluded that Big River “operated its mill at the same load levels as it would have if it had not been” a demand response unit within MISO. They said MISO made demand response payments to Big River when its load was below its usual baseline, but those below-average usages still were in the normal course of mill operations.
From late 2016 to April 2022, MISO paid nearly $21 million for Big River’s participation as a demand response resource. The RTO charged Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas and other MISO South load-serving entities for the load reductions.
FERC said while Big River ultimately decided how much and when to offer reduced energy usage into MISO’s day-ahead and real-time markets, Entergy Arkansas also is culpable for the steel mill’s conduct. Under the settlement agreement, the two “neither admit nor deny the alleged violations,” according to FERC.
FERC said from 2016 to mid-2020, Big River submitted offers to MISO for load reductions that would correspond to expected outages. By the latter half of 2020, Big River usually offered 100 MW in reductions in the MISO market, even if it had no reason to expect an outage the next day.
Starting in 2019, FERC said Big River additionally would make small, 1-MW offers daily in MISO’s day-ahead market. FERC said by submitting the small offers, it received demand response payments daily, thereby allowing it to undermine MISO’s baseline use calculation that it performs for its demand response resources.
MISO and Big River staff reportedly clashed in 2019, when the steel mill requested a demand response payment for a previously planned outage. MISO refused and told Big River to pursue a settlement dispute.
FERC said Big River and Entergy Arkansas have committed to working with MISO to ensure that the amounts they’re surrendering will “be returned to the market participants that were charged those amounts.”
In an emailed statement to RTO Insider, Entergy Arkansas said it agreed with FERC’s findings that Big River operated its mill at load levels as if it weren’t a demand response unit and didn’t alter energy consumption when MISO accepted its demand response offers.
However, spokesperson Neal Kirby said Entergy Arkansas “is not aware of any evidence suggesting that Big River tried to game MISO’s demand response program.”
A working group focused on gas resource participation in CAISO-run markets held its second meeting this week, with stakeholders saying they don’t receive enough advance information to make good decisions on gas procurement.
CAISO is hosting the gas resource management (GRM) working group to explore challenges that stakeholders face while participating in the Western Energy Imbalance Market and potentially the extended day-ahead market, which is under development.
The working group process will result in an “action plan” that CAISO will use in potentially crafting future initiatives.
During Tuesday’s workshop and in written comments, stakeholders discussed the challenges of gas procurement.
Salt River Project (SRP) pointed to what it called a “mismatch between when gas is traded, when gas is scheduled, and when power awards are made by the organized market.”
“It is critical to know the quantity of gas required to meet load/market awards so that the correct amount can be scheduled,” SRP said in written comments.
SRP said reliability risks may be created, such as in situations when intraday gas isn’t available to buy.
Alan Meck, a business and economics advisor at San Diego Gas & Electric, described the problem as “lack of foresight.”
“You have to figure out … am I going to go ahead and buy the gas and then potentially be stuck holding the bag?” Meck said during Tuesday’s meeting. “Or am I going to not [buy the gas] and potentially get an energy schedule going into real time and then have to pay the real-time price?”
Stakeholders including SDG&E and PacifiCorp said their limited ability to store gas adds to the problem. And recent increases in variable energy resource capacity have made forecasts more uncertain when it comes to gas procurement.
Timeline Alignment
The working group is expected to revisit a topic CAISO has explored: a potential alignment of electric and gas market timelines.
CAISO said its previous analysis of such an alignment found it wouldn’t be in the interest of market participants. In particular, the switch would require business process changes, and earlier timelines might increase forecast inaccuracy.
The ISO has asked working group members to weigh in on whether those issues still are a concern.
On other topics, the Northern California Power Agency proposed a discussion of how hydrogen could be incorporated into the markets.
“Any effort or interest now in incorporating how hydrogen fits into gas resource management will only provide compounding benefits in the future,” NCPA said in written comments.
Salt River Project wants to see more discussion of multi-stage generators, which are units with multiple operating configurations.
“SRP would like to emphasize the importance of multi-stage generators (MSGs) and that enhancements in their management have the potential to significantly impact efficiency and reliability,” SRP said in written comments.
Existing Tools
Vistra Corp. noted that CAISO previously discussed gas resource management issues in a 2016 paper called “Commitment Cost and Default Energy Bid Enhancements” (CCDEBE). The CAISO board then approved a CCDEBE proposal in 2018.
“Vistra strongly encourages the CAISO to examine its existing tools and procedures’ effectiveness and to implement the remaining elements of CCDEBE as soon as possible,” Vistra Corp. said in written comments. “After which, a discussion on whether new tools and procedures are needed can be held.”
Mark Richardson of CAISO, who facilitated Tuesday’s session, said CAISO will examine what previously was approved — but hasn’t been implemented yet — before the next working group meeting.
In addition to Tuesday’s session, the GRM working group met on July 27. After each meeting, CAISO plans to release a discussion paper that summarizes the working group’s conversation.
The next working group meeting is scheduled for Sept. 18.
The Department of Energy on Thursday issued three reports on wind-generated electricity, projecting strong but not uniform growth for the nation’s onshore, offshore and distributed wind power sectors.
Wind was second only to solar in new generating capacity installed in the U.S. in 2022, DOE said in a news release, attracting $12 billion in capital investment and employing more than 125,000 Americans.
The flurry of policy changes made and financial incentives offered during the first two years of the Biden administration have significantly boosted near-term forecasts for future deployment of environmentally friendly wind power, DOE added.
This trend serves another purpose beyond climate protection — economic stimulus. DOE noted at least 11 announcements of opening or expansion of U.S. manufacturing facilities to serve the onshore wind industry.
The reports also touched on significant challenges facing the industry, primarily due to high costs, short supplies and constrained transmission.
The problems are such that the first generation of offshore wind development could be stunted for the next few years, the authors write.
It found that 8,511 MW of new utility-scale onshore wind generation capacity was added nationwide in 2022.
That was the smallest increase since 2018, due to a confluence of factors that included inflation, supply-chain constraints, rising interest rates, interconnection delays, siting challenges and — until passage of the Inflation Reduction Act last August — a reduction in the value of the Production Tax Credit.
Other key takeaways from the report include:
The U.S. is second only to China in wind power generation, but wind provides only 10% of the electricity generated in the U.S., far less than wind power leader Denmark (57%).
Iowa is the state wind power leader, deriving 60% of its power from wind.
New utility-scale turbines were installed in 14 states in 2022, with Texas accounting for nearly half the capacity, at 4,028 MW.
For the first time, corporations and other nonutility buyers bought more wind-generated electricity than utilities did in 2022; direct retail purchase of wind power accounted for at least 44% of the new capacity added last year.
The average nameplate capacity of newly installed onshore turbines was 3.2 MW in 2022, up 7% from 2021; the average hub height was 98.1 meters above ground, a 4% increase.
Wind power as a percentage of system load ranged from 37.9% in SPP to 3.1% in NYISO.
Offshore
The 2023 edition of the Offshore Wind Market Report was prepared by DOE’s National Renewable Energy Laboratory.
It found that the U.S. offshore wind pipeline reached 52,687 MW in 2022, up 15% over 2021. This breaks down to 40 projects in some stage of development totaling 47,606 MW, and 5,039 MW of potential capacity in planning stages. (The two U.S. projects already in operation have a combined 42 MW capacity.)
Other key takeaways from the report include:
The U.S. offshore wind industry invested $2.7 billion in ports, vessels, the supply chain and transmission capacity.
Offshore wind lease areas continued to grow in number and variety, as a late 2022 auction offered the first Pacific Coast leases and the first that will require floating wind turbine technology.
The policy and statutory goals of 13 states have reached 112,286 MW of nameplate capacity.
Many U.S. offshore wind projects are facing headwinds from supply chain constraints, inflation and interest rate hikes, particularly those with an expected commercial operation date in 2025 or 2026; project costs increased 11% to 30% in 2022.
Key indicators in the U.S. offshore wind energy market point toward sustained market growth, but macroeconomic hurdles could significantly stunt that growth for the first generation of commercial projects; incentives provided by the IRA may provide some relief.
It tallied 1,755 distributed wind turbines added in 13 states in 2022. Those 1,755 turbines had a combined capacity of 29.5 MW and required a total investment of $84 million.
Other key takeaways from the report include:
Cumulative distributed wind capacity has reached 1,104 MW from more than 90,000 turbines in all 50 states, the District of Columbia, Guam, Puerto Rico and the U.S. Virgin Islands.
California, Iowa and Nebraska had the most capacity additions last year, due in part to projects that entail large-scale turbines — those greater than 1 MW in size.
A visualization of new and existing wind power projects larger than 1 MW across the United States. | DOE
Minnesota led the nation again in smaller-scale capacity additions — turbines rated at 100 kW or less — due primarily to the continued push there to sell small-scale wind power to agricultural markets.
None of the distributed wind projects reported in 2022 used midsize turbines — those rated at 101 kW to 1 MW.
Iowa by a wide margin has the greatest installed distributed capacity, at 222 MW; runners up are Minnesota (128 MW) and California (83 MW).
Agriculture is the most common use for distributed wind installed in 2022, accounting for 33% of projects; residential and commercial were second, tied at 26%.
Only 10% of distributed wind projects completed in 2022 were interconnected to the grid; the great majority were intended to provide energy for on-site use.
