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November 18, 2024

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NREL Examines Gulf of Mexico OSW Transmission Needs

A National Renewable Energy Laboratory report offers insight on transmission infrastructure needs for future offshore wind development in the Gulf of Mexico. 

NREL said the needs are significant but have not been researched previously.  

Offshore wind development in the Gulf presents challenges beyond those facing present-day efforts along the northeast U.S. coast. And developers so far have shown little willingness to meet those challenges — the Gulf wind lease auction planned for later this year was canceled for lack of interest. 

But the Gulf is believed to hold 37% of the nation’s potential offshore wind generation capacity, and federal leaders hope to exploit it. 

NREL’s report looks at some of the steps that would need to be taken well in advance of wind turbine construction so their megawatts of power could be brought ashore. 

A key takeaway: The oil and gas industry already has infrastructure and personnel in the Gulf. Shared transmission systems and workforce could support offshore wind. 

Also, about 18,000 miles of abandoned pipelines remain on the seabed and could be used to transmit clean hydrogen — generation of which is a potential use of offshore wind energy. 

But the NREL report also suggests that offshore wind transmission planning in the Gulf is not so different from other regions: Planners will have to limit the impact of their projects on existing communities, industries and ecosystems while navigating local, state, federal and tribal regulations and sensibilities. 

The report’s authors identify some gaps in existing planning and knowledge needed for buildout: 

    • RTOs and utilities have not incorporated Gulf of Mexico offshore wind power in their long-term transmission planning. 
    • Siting considerations for offshore wind transmission routing in the region have not been identified in published literature. 
    • Focused community and workforce engagement on stakeholder priorities has been lacking. 
    • Engagement and research would inform how offshore wind transmission would fit into the region’s energy generation portfolio and how it serves the needs of industries in the Gulf Coast states. 

The NREL report recommends the Department of Energy and Bureau of Ocean Energy Management convene a Gulf Coast version of the Atlantic Offshore Wind Transmission Study workshop series they began hosting in 2022. 

The Biden administration, as part of its push to build a new emissions-free power sector, envisions fixed-bottom wind turbines in shallower parts of the Gulf and floating turbines in deeper areas. 

But slower average wind speeds punctuated by severe winds from hurricanes and tropical storms present a significant engineering challenge for designers of the wind turbines to be placed in the Gulf. (See Hurricane Threat to OSW Turbines Quantified.) 

In 2023, the first of four planned Gulf wind energy area auctions drew only three bids from two bidders on one of the three areas offered. The single sale came at a rock-bottom price. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

The planned 2024 auction drew early interest from only one potential bidder and was called off. (See BOEM Cancels Gulf of Mexico Wind Lease Auction.) 

As the 2024 auction was heading to cancellation, however, another developer submitted an unsolicited request to BOEM for two other lease areas off the Texas coast. 

And Louisiana has been advancing offshore wind development in state waters closer to shore. The Climate Action Plan developed during the administration of Gov. John Bel Edwards (D) set a goal of 5 GW of offshore wind capacity by 2035, and the state signed agreements with two developers in late 2023, during the closing days of his administration. 

A previous NREL study identified 25 plausible points of interconnection for offshore wind export cables but concluded that, as in other regions, many of them would need significant upgrades to handle gigawatt-scale injections. 

The new NREL report was funded by the DOE’s Wind Energy Technologies Office and Grid Development Office. 

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AEP Planning for 15 GW of Data Center Load

American Electric Power executives say they’re embracing large loads and, fortunately for them, they say they have firm commitments for more than 15 GW of load coming from just data centers by 2030.

AEP told financial analysts during its July 30 second quarter earnings call with financial analysts that it’s seeing “unprecedented” load growth, split primarily between Texas and its PJM footprint. Commercial load has increased 12.4% over the second quarter of last year as new data processing facilities came online, the company said.

“We continue to see strong interest in Ohio and Texas, as well as several of our vertically integrated states, from customers looking to develop new data processing facilities,” interim CEO Ben Fowke said during the company’s call. “Affordability remains top of mind, and we’re working to ensure that the investments made in the grid to support this increased demand are allocated fairly and provide benefits to all customers.”

Noting AEP’s system-wide peak at the end of last year was 35 GW, Fowke said the company continues working with data center customers to meet their increased demand, but also ensuring contracts and new initiatives are “fair and beneficial” for all customers. He said AEP would provide details on its generation and transmission capital investment necessary to meet demand later this year.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly and the right investments are made for the long-term success of our grid,” Fowke said.

AEP subsidiary Public Service Co. of Oklahoma (PSO) in June announced it will seek regulatory approval of an agreement to purchase Green Country, a 795-MW natural gas facility. Peggy Simmons, executive vice president of utilities, said the transaction will help PSO meet SPP’s higher planning reserve margin, which was increased to 15% from 12%.

“This was a very proactive approach that the team took to go out and find some affordable assets that we can bring onto the system,” she said.

AEP reported second-quarter earnings of $340 million ($0.64/share), down from 2023’s second quarter earnings of $521 million ($1.01/share). The company reaffirmed its 2024 operating earnings guidance range of $5.53-$5.73/share and its 6%-7% long-term growth rate.

Incoming CEO Bill Fehrman, who takes over AEP’s top job Aug. 1, did not participate in the call. Fehrman replaced Julie Sloat in June after his predecessor parted ways with AEP in February following just one year as CEO. (See AEP Selects Industry Veteran as Next CEO.)

“With Bill’s expertise and diverse background, you can anticipate a smooth transition and continuity of strategic direction. Expect more focus on execution,” said Fowke, who served as interim CEO and will advise Fehrman during a transition period.

The company’s share price rallied late July 30 to close at $98.14, up $1.07 from its previous close.

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ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns

As ISO-NE undertakes major capacity market accreditation reforms, New England storage developers are voicing concerns that potential flaws in the RTO’s modeling methodology could discourage new investments in storage resources. 

The resource capacity accreditation (RCA) project has been in motion for more than two years, and the development process could continue into 2027 following the RTO’s three-year delay of its 19th capacity auction, which applies to the 2028/29 capacity commitment period. (See NEPOOL Markets Committee Restarts Work on Capacity Market Changes.) 

The RCA project is intended to better align the capacity procurements with real-world reliability benefits, mirroring similar reform efforts in MISO, NYISO and PJM.  

Prior to FERC’s approval of the full three-year delay — which will give ISO-NE time to reform the timing of the capacity auction process along with accreditation — the RTO published RCA impact analysis results that painted a dire picture for storage resources. (See FERC Approves Additional Delay of ISO-NE FCA 19.) 

While the analysis indicated that the accreditation changes would increase the overall pool of capacity revenue by 11%, it showed a 37% revenue reduction for storage resources, equivalent to about $58 million. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

While these results are subject to change as ISO-NE refines the methodology and accounts for the transition from a forward annual capacity market to a prompt-seasonal capacity market, the analysis served as a wakeup call for many of storage companies participating in the capacity market. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.) 

The concerns about storage accreditation derating come as several New England states are looking to rapidly ramp up the deployment of storage resources; Connecticut, Massachusetts, Maine and Rhode Island all have storage targets in the hundreds of megawatts. 

State programs also are a key revenue component for storage developers, as the current levels of revenue from ISO-NE wholesale markets alone are not enough to support the resources, said Alex Chaplin of New Leaf Energy, adding that “storage provides significant reliability benefits to New England which need to be adequately measured and compensated for in the ISO-NE markets.” 

Chaplin noted that most storage in the region is concentrated in Connecticut and Massachusetts due to their state incentives for storage. Massachusetts’ clean peak energy standard, which is aimed at cutting emissions and air pollution from fossil peaker plants, is a key revenue source for storage resources in the state. (See Panel Provides Update on Energy Storage in Mass.) Decreasing capacity revenue could lead to more pressure on states to support the resources to hit their storage deployment goals and cut emissions. 

“Capacity market revenues are typically an irreplaceable and indispensable source of revenue for the financeability and viability of resources, and storage is no exception,” said Alex Lawton of Advanced Energy United. He added that the energy market and ancillary services market do not provide “the scale or certainty needed for investors to back storage projects.” 

The crux of the issue, Lawton said, appears to stem from how ISO-NE is artificially scaling up load in its model to evaluate the reliability benefits of different resource types, which ultimately will determine how much capacity each resource can sell into the market. This modeling shows capacity scarcity events that significantly exceed the duration of events historically experienced in the region.  

While the longest capacity scarcity condition New England has experienced since the implementation of pay-for-performance rules in 2018 lasted two hours and 40 minutes, the RCA project is modeling events that typically exceed four hours, and — according to a March presentation — 36% of modeled shortfall events lasted more than eight hours.  

“As soon as you exceed four hours in duration — because most storage is between two and four hours — the marginal reliability impact (MRI) of storage just tanks,” Lawton said. 

There is broad consensus that the region’s power grid will face longer-duration periods of shortfall risk in the future as it trends toward a winter peaking system, but there is uncertainty around when these longer-duration risks will show up, and how they should be weighed against higher-likelihood, shorter-duration events.  

Over the long term, ISO-NE has stressed the need for dispatchable resources that can balance intermittent generation over extended periods of time. (See ISO-NE Outlines Economic Challenges of Decarbonization.) 

Frank Swigonski of Jupiter Power said the weighting of extreme winter storms in the methodology compared to more frequent, shorter-duration events “is an open question … that stakeholders should explicitly discuss in this process.” 

Swigonski noted the stakeholder engagement process for PJM’s accreditation reforms did not spend significant time discussing this question, which led to rehearing requests with FERC. 

“It ultimately had a massive impact on the final accreditation numbers,” Swigonski said. “We’re hoping that we don’t have the same experience in New England.” 

Swigonski also disagreed with the notion that shorter-duration storage resources are unable to provide significant resource adequacy benefits during longer-duration events. Storage resources likely still will be able to recharge off-peak during extended events, and operators eventually will gain experience with dispatching storage to avoid depleting all available storage in the first hours of an event, he said. 

Responding to questions about the RCA methodology, ISO-NE spokesperson Mary Cate Colapietro emphasized that the methodology is still a work in progress and that stakeholder engagement is ongoing. ISO-NE recently solicited comments on the scope of its Capacity Auction Reform (CAR) project, which included requests from storage companies for ISO-NE to evaluate the underlying modeling methodology. 

“Establishing a durable capacity market that provides the necessary reliability services as the power system evolves is a vital component of New England’s clean energy transition,” Colapietro said. “While we plan to continue pursuing an accreditation design based on capacity’s marginal reliability impact, the additional time afforded by the delay gives us time to work with stakeholders on possible improvements to that design.” 

Bruce Anderson of the New England Power Generators Association declined to comment on the treatment of specific resource types but stressed the need for ISO-NE to prioritize implementing a “sound market design” that provides efficient signals for resources to enter and exit the market. 

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ERCOT Evaluating RMR, MRA Options for CPS Plant

ERCOT has issued a request for proposal seeking alternatives to a reliability-must-run contract with CPS Energy, compensating for the utility’s planned retirement of a power plant. 

The ISO said in a July 25 market notice that CPS Energy’s decision to retire three aging coal-fired units, with a combined summer seasonal net maximum sustainable rating of 859 MW, would have a “material impact on identified ERCOT system performance deficiencies.” The grid operator’s staff has said the units’ retirement would load existing transmission facilities above their normal ratings under pre-contingency conditions.  

ERCOT’s determination triggered the grid operator’s obligation to issue an RFP for must-run alternatives (MRAs) and begin RMR negotiations with CPS Energy. The San Antonio utility has proposed suspending the three V.H. Braunig units after March 2025. (See CPS Energy Plans to Retire 859 MW of Gas Resources.) 

Qualified scheduling entities (QSEs) can submit proposals for one or more MRA resources to address system performance deficiencies more cost effectively than by committing one or more Braunig units through a more expensive RMR contract. QSEs can offer the resources for one or more seasons during April 1, 2025, through March 31, 2027. Eligible resources include types of generation, storage and demand response. 

RFP offers are due Sept. 9. ERCOT will host a workshop Aug. 15 to discuss the RFP and answer questions. After reviewing all proposals, staff will make a recommendation to the ISO’s board during its October meeting. 

An RMR contract would be ERCOT’s first since 2016. The grid operator entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Works to Address Loss of San Antonio Units.) 

$24.4B in Energy Fund Requests

The Public Utility Commission said July 29 it has received 72 applications for loans through the Texas Energy Fund’s in-ERCOT Generation Loan Program. The applications request $24.41 billion to finance 38.37 GW of proposed dispatchable, or thermal, power generation. 

Lawmakers have set aside $5 billion for this TEF program, one of four. 

“Texans have made it clear that they expect reliable electricity today and well into the future, and I am pleased to see industry leaders responding to that call and planning for major investments in dispatchable power for the state,” PUC Chair Thomas Gleeson said in a news release. 

Commission staff will evaluate the applications before the commission determines which projects will proceed to due diligence during the PUC’s Aug. 29 open meeting. The in-ERCOT program will provide low-interest loans to finance up to 60% of new construction or upgrades to existing dispatchable facilities. A proposed project must add at least 100 MW of new generation to the ERCOT grid to be eligible. Approved loans’ initial disbursements will be issued by Dec. 31, 2025.  

The in-ERCOT program and three other TEF programs were established in March because of state legislation passed last year. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

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Electric Sector Added just 55 Miles of New Transmission in 2023

The U.S. electricity industry added just 55 miles of new high-voltage transmission to the grid last year, despite estimates the system will need to expand rapidly in the near future, Americans for a Clean Energy Grid said in a report released July 30. 

“Fewer New Miles: The US Transmission Grid in the 2020s” was prepared by Grid Strategies with support from ACEG. 

“The findings of this report are a wakeup call. With only 55 new miles of transmission built in 2023, we are not keeping pace with the growing demand for power,” ACEG Executive Director Christina Hayes said in a statement. “The slowdown in new construction not only impacts our ability to meet future energy needs, but also risks increasing costs for consumers and reducing grid resilience. It is essential that we address these challenges to ensure a secure, reliable and affordable energy future for all Americans.” 

The U.S. Department of Energy’s Transmission Needs Study found the grid should expand by 57% by 2035, while Princeton University’s “Net-Zero America Study” found it would need to double or 80% of the potential greenhouse gas cuts from the Inflation Reduction Act would not be met, said the ACEG report. (See Will DOE’s Transmission Needs Study Spur New Regional, Interregional Lines?) 

While 2023 saw few miles of new lines built, the industry spent $25 billion on the grid (a record high), with 90% driven by reliability upgrades and the replacement of aging equipment. The decline has been felt for years, with the country building only 20% as much transmission so far this decade as it did in the early 2010s. 

“This trend began over a decade ago, when the average of 1,700 miles of new high-voltage transmission built per year from 2010 to 2014 dropped to only 925 miles from 2015 to 2019, and has fallen further to an average of 350 miles per year from 2020 to 2023,” the report said. 

So far this year up to May, the industry has completed one major transmission line, adding 125 new miles from completion of the 500-kV Delaney-Colorado Transmission Project that links Arizona and California. 

About 50% of recent spending is based on local planning criteria, which is usually below 345 kV and does not go through regional planning processes. Such lines focus only on reliability, ignoring maximized ratepayer benefits from multivalue projects, the report said. 

The 2010s saw massive greenfield projects, especially in Texas and the Midwest. Texas’ Competitive Renewable Energy Zone program saw $7.5 billion invested in ERCOT lines to bring wind power to population centers, cutting wind curtailment from 17 to 0.5% and leading to unexpected benefits like solar development in West Texas and electrification of oil and gas drilling in the regions. 

MISO’s Long Range Transmission Planning (LRTP) Tranche 1 Portfolio is another example, investing $10.3 billion to build out 2,000 miles of lines that offer at least 2.6:1 benefits to load. 

Recent federal action like FERC Order 1920 and DOE’s Transmission Facilitation Program to help finance new transmission lines should help, but the report said private capital needs to be invested to expand the grid. 

“Utilities are still currently incentivized to prioritize low- voltage upgrades focused on reliability and asset replacement,” the report said. “Both policymakers and regulators must capitalize on FERC’s issuance of Order No. 1920 to ensure the momentum brought about by federal action truly changes the incentives for transmission investment and helps spur a massive investment in the construction of new high-voltage transmission lines to ensure a reliable and affordable transition to a cleaner grid.” 

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PJM MRC Briefs: July 24, 2024

Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee endorsed one of two proposals to revise how PJM uses reserve resources, approving a deployment scheme where instructions are sent by basepoints, while rejecting a parallel proposal to grant operators the ability to dynamically increase market procurements. (See “First Read on 2 PJM Proposals to Revise Reserve Markets,” PJM MRC/MC Briefs: June 27, 2024.)  

PJM’s Emily Barrett said updating basepoints with reserve instructions provides more clarity around how resources are expected to respond and allows for units to be dispatched for less than their full reserve assignment. Resources being asked to respond at less than their assignment will be committed at the greater of their economic minimum parameter or the pro rata instruction. 

Stakeholders rejected a second proposal to determine the amount of 30-minute reserves PJM commits using a formula rather than the static 3,000-MW figure. The equation would select the greater of the load forecast error and forced outage rate together multiplied by the forecast peak load, the primary reserve requirement or the largest active gas contingency. 

The package also would have allowed operators to increase one of the three reserve categories without having to increase all three. Under the status quo language, any out-of-market increase in the 30-minute, primary or synchronized reserve requirement must be mirrored across all three. Barrett said the language tying the three reserve products together is viewed by staff as an oversight. 

Prior to the vote, PJM’s Executive Director of System Operations Dave Souder said the static reserve threshold is not sufficient and does not account for risks identified by dispatchers. The proposal would revert to the reserve procurement formula in place before the reserve price formation redesign. 

Paul Sotkiewicz, president of E-cubed Policy Associates, said outages experienced in Alberta, Canada, in April demonstrated the importance of having dispatchers able to match reserves with expected risk. 

“The Alberta outage a few months ago shows why this is needed. The renewable forecast was inaccurate, energy commitments were too low and firm load had to be shed. That provides a cautionary tale that lends support for the ability to commit more reserves available,” Sotkiewicz said. 

According to the PJM summarized voting report, the reserve procurement package had little support among electric distribution companies, which were 93.1% opposed, and end-use consumers, who voted 82.4% against. The Other Suppliers sector was split at 57.1% support, while generation and transmission owners were united in support. 

Responding to a stakeholder question about whether PJM would consider moving forward with the proposed tariff changes without stakeholder endorsement, PJM Vice President of Market Design and Economics Adam Keech said staff had not envisioned the vote failing and will have to consider next steps. 

Schedule Selection Formula Endorsed

Stakeholders endorsed a proposal to use a formula to sift through market sellers’ energy offers into the real-time market and select one schedule for each resource to be modeled in the market clearing engine (MCE). (See “Stakeholders Discuss Path Forward on Multi-Schedule Modeling,” PJM MIC Briefs: June 5, 2024.) 

PJM brought the issue before stakeholders as part of its effort to implement multi-schedule modeling in the real-time market, which staff have said would result in a significant increase in computation times, in part due to the number of configurations combined cycle units can operate under. The introduction of multi-schedule modeling is one part of a larger overhaul of the engine under PJM’s Next Generation Markets (nGEM) initiative. 

An earlier schedule selection proposal was endorsed by stakeholders but rejected by FERC in March. The commission cited a “crossing-offer-curves” scenario the Independent Market Monitor raised, under which PJM’s proposed formula would select market-based offers based on its dispatch cost at EcoMin even if it would be notably more expensive than a cost-based offer at higher outputs.  

The proposal endorsed July 24 is built around the same formula but aims to address the crossing curves issue by selecting price-based offers only when a resource passes the three pivotal suppliers (TPS) test and mitigating resources to their cost-based offers should they fail the TPS test. The tariff and operating agreement (OA) revisions are set to go before the Members Committee on Aug. 21 for an endorsement vote. 

The proposal was sponsored by PJM and the GT Power Group at the Market Implementation Committee and received the second-highest amount of support at the MRC in December. (See “Stakeholders Endorse Multi-schedule Modeling Solution,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

Monitor Joe Bowring said the joint proposal would not resolve an issue with how dual-fuel units are committed. Since only one schedule is considered, the Monitor has argued that dual fuel units may be selected to run on a schedule using a fuel that is not economical for a portion of the day. 

Stakeholders had discussed waiving truncated voting rules and widening the vote to include a joint proposal from the Monitor and GT Power, which would allow generators to determine which of their offers would result in the lowest production cost and should be modeled in the MCE. 

Vote on Enhanced Know Your Customer Deferred

The committee delayed voting on a proposal to tighten PJM’s “know your customer” (KYC) requirements to require more due diligence checks on principals and key decision makers among member entities. (See “First Read on Expanded ‘Know Your Customer’ Rules,” PJM MRC/MC Briefs: June 27, 2024.)  

The proposal would require PJM background checks on beneficial owners, board of director members and principals of non-publicly traded members. Those entities would be responsible for providing a list of names for each of those categories and government-issued identifications, though the latter does not apply to boards unless requested by PJM. The proposal is aimed specifically at collecting more information on non-public members not required to report ownership information to the Securities and Exchange Commission. 

The beneficial owner definition is applicable to those who own, control or hold 10% or more voting power of an entity, either directly or with family. Since the June 27 first read, Assistant General Counsel Eric Scherling said the definition of family members was clarified to state that ownership split across spouses, domestic partners, parents, children or siblings counts toward triggering the requirement. 

The proposed definition of “principals” also was revised to add the phrase “corporate-level strategy” regarding the control individuals have over the member entity’s operations. Scherling said the change is meant to address feedback that the definition could be too broad and capture staff with day-to-day operational control over assets. 

Several stakeholders said they would need more time to review the changes and expressed continued concerns about the scope of the requested information. 

Sotkiewicz said the principal definition remains nebulous when considering parent corporations and subsidiaries with split ownership. He motioned to defer voting until the Aug. 21 MRC meeting to provide more time to review the revised language.

“This is an arduous process for people [who] happen to be partners but don’t necessarily have full decision-making authority. … This could turn into a paperwork nightmare and for what reason we’re not entirely sure” when the parent company is publicly traded and the ownership is clear, he said. 

John Horstmann, senior director of RTO affairs for Dayton Light and Power, said some members have widespread operations that go far beyond PJM markets and that principals managing activities unrelated to PJM could be captured in the KYC requirements. He gave the example of an international corporation that does business in the U.S. and overseas, questioning whether information about corporate staff overseeing activities in Bulgaria or Vietnam would be requested by PJM. 

Scherling said PJM’s focus is on its markets and intends to take a closer look at individuals who are high enough in the corporate structure they would have a hand in all operations, including PJM. 

PJM Chief Risk Officer Carl Coscia said the KYC structure is about following where PJM revenues are going, what they’re being used for and where investments are coming from, so it does need to go to the highest corporate-level strategy. 

“We want to make sure these markets are being used for good. That’s the good we’re talking about, not having money that shouldn’t be here,” he said. 

Scope for Deactivation Task Force Widened

Stakeholders endorsed a wider scope for the Deactivation Enhancement Senior Task Force (DESTF) to include proposals to establish cost-effective alternatives to reliability-must-run (RMR) agreements and technologies that could expedite resolution of transmission violations prompted by resource deactivations. The proposal passed with 89% support. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.)  

The revisions to the issue charge also include education on the alternatives to RMR contacts that other RTOs have developed to keep generators operating past their desired deactivation date and a follow-up to ongoing discussion on proposals to allow capacity interconnection rights (CIRs) to be transferred from deactivating generators to planned resources. The proposal is sponsored jointly by the Illinois Citizens Utility Board (CUB) and Maryland Office of People’s Counsel (OPC). 

The issue charge language includes education around using grid-enhancing technologies (GETs) and storage as a transmission asset (SATA) to expedite transmission upgrades necessary to allow a generator to retire. 

Souder said PJM is neutral toward the technology that resolves an identified violation and it’s up to project proposers to submit solutions, including GETs. 

Clara Summers, of CUB, said the proposed language was revised from the draft presented at the June 27 first read to allow partial solutions, with the goal of avoiding any interruption to the existing discussions on compensation and deactivation notification timelines. 

Vistra’s Erik Heinle said he is concerned about having too wide of a scope for the task force, stating that the wide-ranging issue charge governing the Resource Adequacy Senior Task Force (RASTF) caused the group to die under its own weight while the Reserve Certainty Senior Task Force (RCSTF) has benefited from a narrower scope. 

“I want to make sure these important issues get the consideration they deserve but don’t slow down the ongoing work,” he said. 

Bowring questioned whether the advocates believe the issue charge should be phased to focus on deactivation notification requirements and compensation first before initiating work on the newly added items. 

Phil Sussler, of the Maryland OPC, responded that stakeholders may be too optimistic that the deactivation notification changes will be approved in August and said the overall work areas of the DESTF may take longer than expected to complete. 

Reserve Requirement Study Updated with ELCC Accreditation Values

The committee voted by acclamation to endorse revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2023 Reserve Requirement Study (RRS) to reflect the implementation of PJM’s marginal effective load carrying capability (ELCC) approach to accrediting resources. The proposal also was endorsed by the Members Committee on July 24.  

The reanalysis recommended increasing the installed reserve margin (IRM), which sets the targeted capacity level above expected loads, to 18.6%, up from the 17.6% stakeholders endorsed last year for the 2023 RRS. The forecast pool requirement (FPR), which accounts for generator accreditation, would decrease from 11.65% to 9.37.  

The shift to marginal ELCC accreditation was part of a package of capacity market redesigns approved by FERC in January (ER24-99). The RRS figures are used to set the supply curve for the 2026/27 delivery year. (See PJM Presents Revised Reserve Requirement Study Values.) 

In addition to the ELCC accreditation values, the reanalysis updated the expected resource mix to include planned resources that submitted a notice of intent to offer into the 2026/27 Base Residual Auction. Gas generators that submitted dual fuel attestations were sorted into the corresponding ELCC classes, and resources that are scheduled to deactivate prior to the start of the delivery year were removed from the analysis. Generators expected to operate on reliability-must-run (RMR) contracts through the delivery year were included in the resource mix. 

Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), questioned how PJM would incorporate nuclear capacity being removed from the market to serve data center load, referring to a FERC filing from Talen Energy to reduce the amount of energy the Susquehanna nuclear plant sells into PJM. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.) 

PJM’s Andrew Gledhill said the megawatt value of that unit would be effectively derated to the new CIR amount. 

Bowring asked how PJM considers the reliability impact of amending interconnection service agreements (ISAs) with generators to reduce their maximum output and whether it considers not approving revisions if there are reliability impacts identified.  

PJM’s Pat Bruno said reliability analysis is conducted like generation deactivation studies. 

PJM Proposes Increased CONE Parameters

PJM’s Skyler Marzewski presented a first read on a proposal to revise two financial parameters used to calculate the cost of new entry (CONE) input to the 2027/28 Base Residual Auction (BRA). (See PJM MIC Briefs: July 10, 2024.) 

After consulting with The Brattle Group, PJM recommended increasing the after-tax weighted average cost of capital (ATWACC) from 8.85 to 10% and using a 0% bonus depreciation rate for the 2027/28 delivery year and beyond. The original quadrennial review included a 20% bonus depreciation value for the 2026/27 year. The proposed changes to the quadrennial review also would update the Bureau of Labor and Statistics (BLS) indices used in capital cost escalation rates. 

The changes increase values for all five CONE areas by an average of $79/MW-day, with CONE Area 5 seeing the largest increase at $90/MW-day and Area 4 increasing by $65/MW-day. 

The review was triggered by market participants reaching out to PJM regarding the impact of high interest rates since the quadrennial review was approved last year. (See FERC Approves PJM Quadrennial Review.) 

Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), said some advocates are frustrated that components of the review are being cherry-picked in a manner that increases consumer costs, both in terms of the financial parameters and the creation of an additional CONE area for Illinois. (See PJM Stakeholders Approve New CONE Area for ComEd over Consumer Opposition.) 

Summers questioned how PJM determines when it is appropriate to make changes to CONE outside of the quadrennial review. 

Marzewski said PJM and Brattle opted to not include automatic adjustments to the quadrennial review financial parameters to account for changing market conditions, instead leaving that discussion for the next quadrennial review. 

Sotkiewicz said the adjusted figures would be a short-term fix, but major issues remain with the CONE inputs, namely the use of a combined cycle generator as the reference resource at a time when few such units are under construction within PJM and none have been financed in recent years. 

New Economic DR Parameters Discussed

PJM presented a proposal to add two new parameters for demand response resources offering into the energy market, allowing providers to set a maximum dispatch period and a minimum interval before they can be committed again after being released from a previous dispatch. The Market Implementation Committee endorsed the proposal last month. (See “Additional Parameters for Demand Response Endorsed,” PJM MIC Briefs: June 5, 2024.) 

PJM’s Pete Langbein said the proposal would allow DR providers to enroll consumers that are only economic for set periods of time and need a recharge before being committed again. While some of that capability exists under the existing market structure using hourly updates, it is administratively difficult. 

Bowring questioned whether a DR resource could submit an offer into the capacity market even if it can operate only according to the proposed parameters. Langbein said such a resource would be subject to capacity performance (CP) penalties if it did not deliver during a performance assessment interval (PAI). 

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Maryland PSC Opens Debate on Future of Gas

Maryland wants to cut its greenhouse gas emissions by 60% by 2031 and have a carbon-free electricity system by 2035, which means the use of natural gas, and the need for ongoing investments in pipelines and other gas infrastructure, also should wind down, according to a People’s Counsel petition to the Public Service Commission.

Filed in February 2023, the petition asked the PSC to open a docket on the future of gas in the state, and whether gas utilities should be allowed to continue such rate-based infrastructure investments. The commission has yet to act on the petition, but on July 25, it held a daylong public hearing on whether it should open such a docket. A second session is scheduled for July 31.

Electric heat pumps, more efficient than gas furnaces, already are eating into the gas utilities’ market, according to People’s Counsel David S. Lapp. Yet utility spending on replacing and updating existing infrastructure could total more than $700 million this year, which pencils out to close to $2 million in utility spending per day ― and rising gas utility bills.

“There’s a massive disconnect between the technology, climate policy and what’s actually going on with the state’s gas utilities,” Lapp said. Even so, investors are willing to provide capital for gas infrastructure because the commission continues to approve the utility investments and rate increases.

“We would argue that is a state subsidy to the gas utilities funded by utility customers who have no choice but to pay those rates or get off the gas system,” Lapp said. “So, in that sense, regulation is failing customers today.”

The OPC petition also raises the possibility of a gas utility “death spiral” as customers electrify their homes and drop off the system, leaving a diminishing base of customers, many of them low-income, to cover system costs through higher rates.

“As customers leave the system, rates will go up further, and then more customers will leave the system,” Lapp said. “So, this is not an economically sustainable path.”

However, Lapp stressed that the petition does not seek to shut down gas utilities; rather, it calls on the commission to open a proceeding that would consider a “wide spectrum” of pathways for these companies to plan for substantially downsized demand and capital spending.

Following Lapp’s presentation, a panel of gas company executives mostly stayed away from the topic of rate increases, arguing instead that maintaining and investing in their pipelines and other infrastructure could be critical for ensuring grid reliability even if natural gas demand does decrease.

Demand reduction “doesn’t necessarily mean there would be a proportionate reduction in gas infrastructure,” said Lauren Urbanek, senior manager of decarbonization strategy at Baltimore Gas and Electric. “That’s really dependent on the geographic nature of where customers may choose to electrify and whether they would choose to electrify completely or partially, potentially maintaining gas as a backup for some of the winter peaking days.”

Upgrading gas systems also can cut down on leaks, Urbanek said, noting that BGE has cut gas leaks on its system 25% since 2015. She also stressed BGE’s support for electrification, such as a planned study on “targeted electrification.”

“This is going to help us better assess what the potential is on the BGE system of geographically targeting heat pumps, network geothermal [or] other technologies in the BGE service territory,” Urbanek said. Potential savings “could either be used to support building electrification … or be returned to gas ratepayers as well.”

Ted Gallagher, general counsel for Columbia Gas of Maryland, similarly countered that his company has increased the number of customers it serves in Western Maryland — up 9.7% since 2005 — but has cut its emissions 5.7%.

He also urged the PSC to expand any potential docket to a more holistic examination of the future of energy in the state.

“The proper scope of [any] commission proceeding … should address Maryland’s whole energy future and not just focus on the future of natural gas,” Gallagher said. “The focus should not be based upon a foregone and unsupported conclusion that natural gas should be or will be phased out in order for Maryland to achieve its GHG emission-reduction goals.”

The STRIDE Act

The debate over gas utility spending in Maryland ― and the OPC’s petition ― trace their roots to a 2013 law called the Strategic Infrastructure Development and Enhancement (STRIDE) Act (S.B. 8/H.B. 89).

Passed in the wake of the deadly 2010 explosion of a Pacific Gas and Electric natural gas pipeline in San Bruno, Calif., the bill was intended to encourage Maryland utilities to upgrade and improve the safety of their pipelines by allowing them accelerated recovery of their infrastructure investments.

Specifically, customers have for the past 10 years paid an extra surcharge on their bills so gas utilities could start to recover their infrastructure investments while improvements and upgrades were being made. The law also requires the utilities to submit STRIDE plans to the PSC every five years, as well as yearly reports on current investments.

While the law does not set any safety standards or require long-term planning, its impact on rates has been dramatic, according to the OPC. BGE’s distribution fees for natural gas went from 26 cents/therm in 2010 to 85 cents in 2024, with another jump to 96 cents in 2026 already approved by the PSC.

Distribution fees at Columbia Gas jumped more than threefold, from 30 cents/therm in 2010 to $1 in 2024, or more than three times the rate of inflation, the OPC said.

The STRIDE program is set to continue through 2043, by which time total utility spending under the program could hit $9.5 billion, in addition to another $12 billion in system investments outside STRIDE, according to a 2023 OPC report.

A bill to require utilities to use modern leak detection technology and repair pipes before replacing them (S.B. 548/H.B. 731) was introduced in the General Assembly earlier this year but did not make it out of committee in either house.

Maryland’s ambitious climate goals could result in less demand for gas, yet gas utilities in the state continue to increase spending on pipelines and other infrastructure and raise their rates. | Maryland Office of People’s Counsel

In light of the bill’s failure, views differed on whether the legislature or the PSC has the authority to make any changes to the program. Urbanek said BGE would be “supportive of some kind of working group or other forward-looking proceeding that really does relate to the future of gas. … But really, the decision is still to be made by the General Assembly about the exact pathway to follow.”

Lapp argued that the PSC has the authority, as regulators, to require the gas utilities to provide the commission with long-term plans on their infrastructure investments based on the expected decline in gas demand, and that the need to act is urgent.

“The idea that the commission has to wait for somebody else to set the policy, for the General Assembly to set the policy, ignores the critical point that right now there is a policy, and that policy is one of accelerated spending,” he said. “It is leading to massive rate increases; it is leading to investments that are highly likely to be stranded and to result in a lot of litigation going forward. That is the policy, and waiting means the inertia will just keep that going.”

‘Stop Digging’

The PSC also heard a wide range of views from environmental advocates, union representatives, county officials and Maryland residents and utility customers.

Emily Scarr, director of the consumer advocacy nonprofit Maryland PIRG Foundation, supported the OPC’s call for a docket on the future of gas, pointing to the increases in BGE and Columbia Gas distribution fees.

“When you find yourself in a hole, stop digging,” Scarr said. “We’re asking you to put the shovel down and exercise your authority to require utilities to serve the public interest by providing safe, reliable and affordable energy. We can only achieve that goal with proper planning and data-driven decisions. The cost of inaction is clear. … You can direct investments wisely in the projects that will lower energy bills.”

Clara Vondrich, senior policy counsel at Public Citizen, said Maryland’s “energy policy as manifested through the proceedings and decisions of this honorable commission, as well as through legislation like the STRIDE Act, are incompatible with the state’s climate goals and in fact may make them impossible to meet.”

Vondrich told the commission she lives with her 85-year-old mother, who has become a little forgetful and has lost her sense of smell. Recently, Vondrich woke up to find her mother had left the gas on overnight and had not smelled the methane.

“We’re no longer in an era where we need to take those kinds of risks,” she said.

Brian Terwilliger, a business manager for the International Brotherhood of Electrical Workers Local 410, raised the concerns of the BGE workers his union represents. BGE’s gas system is one of the oldest in the country, which makes STRIDE upgrades essential, he said.

“Just a few months ago, we dug up a wooden main just down the road here, about 20 feet of it,” he said. “Our infrastructure has generational gaps; so, we have from wood to the most up-to-date stuff for our pipes.”

But Terwilliger warned that downsizing the gas system could trigger a mass exodus of skilled workers.

“They’re thinking about where they’re going to go, how this transition is going to work, and it’s going to be extremely difficult for Baltimore Gas and Electric to retain employees,” he said. “Our ask today … is really to look at the workers at the companies and think about how we’re going to continue to keep those employees employed.”

A transition period “needs to be at the forefront of this conversation,” he said.

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NYISO Stakeholders Continue Debate over Battery as Proxy Unit

NYISO analysts continue to recommend a two-hour battery electric storage system (BESS) resource as the proxy unit for the ISO’s capacity market demand curve.

“Based upon our review of the comments and the results developed to date, we continue to recommend the two-hour battery storage system as the peaking plant technology,” Paul Hibbard, vice president of Analysis Group, told the Installed Capacity Working Group on July 23.

This was the second-to-last working group meeting focused on its quadrennial demand curve reset for 2025-2029, and the first since stakeholders submitted comments on the recommendation earlier this month. (See Stakeholders Battle over Battery as Proxy in NYISO Demand Curve Reset.)

“There are no established minimum thresholds regarding the quantity or duration of energy a peaking plant must be capable of producing during peak periods to be considered a viable technology option for the purposes of the demand curve reset,” said Hibbard, responding directly to comments in opposition to the recommendation.

When asked if Analysis Group had done any reliability analysis to determine whether a two-hour duration was sufficient for maintaining reliability, Hibbard said that his group did not do reliability modeling.

“We’re not trying to model a system that’s operating entirely on two-hour batteries; the two-hour batteries are the peaking technology for the purpose of setting the demand curve,” Hibbard said.

“Another risk of the two-hour BESS is that it is very heavily reliant on reserve revenues, and it’s a reserve provider for 95% of the intervals,” said Mark Younger, of Hudson Energy Economics. “Did you at all consider if there is a risk, say, if the reserve price dropped in half, or if the reserve price dropped by three-quarters?”

“We haven’t tried to forecast reserve prices,” answered Todd Schatzki, principal of Analysis Group. “Ultimately that gets reflected in the net EAS [energy and ancillary services offset] calculation over time.”

One stakeholder noted that commenters had expressed concern with a battery’s capacity accreditation factors (CAFS) diminishing very rapidly.

“We don’t really feel we have a sufficient quantitative basis to assume the CAFs will decline over time,” Schatzki said. “We recognize that a lot of commenters believe that is going to be the case.”

Schatzki said that there were a lot of uncertainties with respect to calculating future CAFs for any technology and that final financial parameters had not yet been set.

1898 and Co., a consulting and analysis firm brought in by Analysis Group, presented some modifications to their calculations for capital and equipment costs for two-hour batteries. Based on feedback from stakeholders, real estate and land-lease costs in New York City were adjusted upward.

Discussion of how 1898 had calculated the costs of battery construction dominated the second presentation.

“Essentially it’s the supply and demand of electric vehicles that drives what happens in the lithium carbonate market,” said Kieran McInerney, a consultant with 1898. “If you look at the numbers for stationary storage verses EV demand for the raw material, it’s like 95% to 5%.”

McInerney said that currently the lithium carbonate market is relatively stable and that the numbers had returned to pre-COVID pandemic prices.

“I do not intend to predict the future; anything could change at any time,” he said. “But we do think that the costs that we are going to include in the final report are indicative of where the market is right now. … There’s a decent amount of stability in the raw material price.”

There was some discussion of how to properly account for inflation, which one stakeholder said is “crushing everything.” McInerney said that he wanted the inflation indices to reliably track costs.

“We believe it’s settling. It’s been a crazy last nine months, [or] year, with the reductions,” he said. “There’s cost increases and reductions that are due to materials; there’s technology changing. I can’t sit here today and tell you anything. Four years ago, we all thought the price was going to be lower today.”

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Prelim NYISO Analysis: 1-GW Shortfall by 2034

New York will be short 1 GW of resources by 2034, driven by increased demand, large load growth and lack of natural gas, according to the preliminary results of NYISO’s biennial Reliability Needs Assessment.

“Preliminary results show criteria violations that will result in reliability needs,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee on July 25. “However, we are not defining those needs today. These are still preliminary results.”

New York City will experience a security margin baseline deficiency beginning as early as 2031, driven by the retirement of the New York Power Authority’s small gas plants. Altman said this could be expected to grow to 275 MW by 2034 because of demand growth.

“This is driven both by New York City load growth and also the assumption of the retirement of several small gas plants that NYPA is required by law to retire or replace,” Altman said.

Altman said that the final results of the RNA, to be presented in August, would identify some needs but that there would be more detail in the solicitations for next year.

Assumptions

The preliminary RNA assumes that many large generation projects will be online and contributing to the grid, including both the Empire Wind 1 and Sunrise Wind 2 offshore wind projects.

“This is a fairly small list, but we are tracking a much wider pool of projects,” said Altman. “This is a fairly conservative assumption. These are only the projects that we have high confidence on because they’ve met their milestones.”

NYISO

Approximately 6,400 MW of generation fueled by non-firm gas was modeled as unavailable. Altman said this modeling change was consistent with recently adopted changes to New York State Reliability Council rules. Dual-fuel sources with non-firm gas were modeled running on their alternate fuels.

“We wanted to highlight dual-fuel units that have non-firm gas contracts; we do not assume those out,” said Altman. “We just model what their capability is when they’re operating on their alternate fuel source.”

Additionally, roughly 2,100 MW of additional large loads were added to the system. Electrical imports from Chateauguay, Quebec, were set to 0 MW during winter months.

“We are setting those imports to zero in winter peak months consistent with our coordination with Hydro-Quebec and what we’re seeing in operations,” said Altman.

Preliminary Results

Ten years from now, NYISO estimates a loss-of-load expectation as high as 0.283.

“We need resources at that point to bring the LOLE to 0.1,” said Laura Popa, a manager of resource planning for NYISO.

NYISO

Popa walked stakeholders through alternate 2034 scenarios in which additional risk factors and potential solutions were modeled, including the inclusion of 9,000 MW of offshore wind, construction delays on the Champlain Hudson Power Express transmission project and the removal of certain large loads. Delaying the CHPE project would significantly impact the LOLE, bumping it up to 0.327 by 2034. Adding extra wind power or removing 1,900 MW of large load would bring the state below the 0.1 LOLE threshold.

Most questions from stakeholders centered on the math and assumptions of the model. Some wondered whether gas was being appropriately modeled as unavailable. Altman pointed out that New England was particularly dependent on natural gas and that it would continue to be used for heat, even if new construction was electrified.

“I don’t think anyone should take these results as ‘the sky is falling,’” Altman said. NYISO would prefer market-based solutions to the problem and believes it could identify an appropriate solution if it went through a solicitation process, he said.

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Counterflow: Hydrogen Flub

Last November, I wrote about the insanity of green hydrogen electricity. And I’ll return to that below.

But I’d like to start with green hydrogen generally, focusing on the first of DOE’s funded “hydrogen hubs” located in — where else? California!

From the PR materials, we can piece together a somber tale. Let’s start.

When is a Hub not a Hub?

Steve Huntoon

The term “hub” is a misnomer. There will be 10 or more hydrogen production sites (at renewable energy facilities), with hydrogen transported to four ports, 60 truck/bus fueling stations, two power plants, etc. There does not appear to be a central location that would receive and store hydrogen for transshipment to end-use locations.

The funding statute, the Bipartisan Infrastructure Law, defines a hydrogen hub as a network of hydrogen producers and hydrogen consumers “located in close proximity.”  Instead, with this “hub,” hydrogen production sites span most of the state, and hydrogen consumers in San Diego and Lodi are 473 miles apart.

So much for Congress’ “close proximity” requirement.

Making Global Warming Worse

This hydrogen “hub” is going to make global warming worse. Here’s why.

This project is going to use electricity from 10 or more renewable production sites across California to make hydrogen, and then store and transport the hydrogen to, among other consumers, two or more power plants. In my prior column, I showed how the losses in converting renewable energy to hydrogen, storing and transporting the hydrogen, and then converting the stored medium back into electricity, would take 7 MWh of green electricity at the source to end up with 1 MWh of green electricity delivered to end-use consumers.

And that’s what will happen here. Every 7 MWh of renewable generation at production sites that otherwise would have been delivered directly to the grid, displacing natural gas generation, instead will be diverted to this hydrogen “hub,” ultimately becoming 1 MWh of renewable generation delivered to the grid. So, every metric ton of carbon emissions avoided at the point of consumption will result in 7 metric tons of incremental carbon emissions from non-displaced natural gas generation.

Does that make any sense to anybody?

Cost of Carbon Emission Reduction

This hydrogen “hub” is a $12.6 billion project. Let’s ballpark a 10% annual revenue requirement for return of (depreciation) and return on capital, so $1.26 billion annually. DOE says this hydrogen hub will reduce carbon emissions by “2 million metric tons per year.”

That can’t be so for the reason given in the prior section, but giving DOE the benefit of the doubt, if we do the math, that’s a cost of $630 per ton of carbon emission reduction.

That cost is a multiple of the per ton cost of dozens of other carbon mitigation options, including 10 in the energy sector alone, as this IPCC table (see page 1,254, Table 12.3, Energy Sector portion) shows. All listed options are $200/ton cost or less.

Detailed overview of global net GHG emissions reduction potentials (GtCO2-eq) in the various cost categories for the year 2030. | IPCC

Which begs the question, why spend many billions on a hydrogen “hub” that, even assuming DOE’s figures, still costs more than a multiple of myriad other carbon mitigation options?

Job Creation

DOE claims this hydrogen hub will create 90,000 permanent jobs. This appears to be typical sleight of hand that ignores the fact that what taxpayers must pay for this program will reduce their disposable income, thereby reducing their spending and thereby reducing the jobs their spending would otherwise support. And those would be jobs providing products and services that people actually choose to pay for, instead of jobs artificially created by government agencies using taxpayer money.

Let’s take an example: DOE says the hub will fund 5,000 hydrogen trucks and 1,000 hydrogen buses. But the truck drivers and bus drivers driving new hydrogen trucks and buses instead would have kept driving diesel/gas trucks and buses. No new jobs.

Water

Have I mentioned all the water that will be needed for the electrolysis to produce hydrogen (9 kg of ultrapure water for every 1 kg of hydrogen)? This in a state not known for having a lot of spare water. Just sayin’.

Backup for Well Water Pump

Speaking of water, DOE says it “will use hydrogen to provide backup power to community well water pumps to ensure clean drinking water during power outages.”

This use of taxpayer dollars is wrong for at least three reasons. First, the recipient, the Rincon Band of Luiseno Indians, is a small tribe (about 500 members) that owns Harrah’s Resort Southern California — an enormous hotel/casino/events center. This tribe does not need subsidies from the rest of us.

Second, the tribe’s water well pump already has backup generation in the form of a 130-kW diesel generator. DOE’s implication that the tribe would get backup generation it doesn’t already have is wrong.

Third, the tribe already is using taxpayer funds for a new solar/battery system. Is the plan to substitute some sort of hydrogen system for this solar/battery system? Or perhaps have three systems (in addition to the grid): the diesel generator, the solar/battery system and the hydrogen system? Yikes.

OK I’ll stop the hydrogen rant here.

P.S. Re. last column’s P.P.S. about “(What’s So Funny ‘Bout) Peace, Love, and Understanding,” I came across this live Elvis Costello cover where the Bangles show up. It seems like it’s over at four minutes but somehow rocks on. And oh yeah, the Boss with Bon Jovi. And Sheryl Crow covers it not too shabby. And Bob Geldof — thank you for Live Aid! — gives a reading that explains it before killing it. Thank you again Bob Geldof!

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.