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Schumer Urges FERC to Act on Transmission Planning and Cost Allocation, Backstop Siting Rules

July 25, 2023

by Paul Ciampoli
APPA News Director
July 25, 2023

Senate Majority Leader Chuck Schumer (D-NY) recently sent a letter to the Federal Energy Regulatory Commission noting his “strong interest” in FERC “expeditiously finalizing a strong transmission planning and cost allocation rule, as well as a federal backstop electric transmission siting rule.”

In the July 20 letter, Schumer also writes that FERC has “more work to do on rules that make further progress” on generator interconnection queue reforms and interregional transfer requirements” to deliver reliable, affordable, and clean power to Americans.”

FERC’s agenda for its July 27 monthly meeting includes its proposed rulemaking on Improvements to Generator Interconnection Procedures and Agreements.

With respect to the transmission and cost allocation rule, Schumer said he is concerned that the proposed rule is not strong enough.

He argued that a final rule must:

As for the federal backstop siting authority rule, Schumer urged FERC to finalize a rule that “preserves state primacy over transmission permit applications while ensuring a project can move forward with a direct application to FERC after one year, and this should include allowing transmission projects to use [FERC’s] long-standing pre-filing process to decrease the risk of further delays of project approval.”

As Renewable Portfolio Grows, Texas Becoming More Vulnerable to Curtailments: EIA

July 25, 2023

by Peter Maloney
APPA News
July 25, 2023

Renewable generation is growing quickly in Texas’ electric market, but the state is at risk of rising curtailments unless transmission resources also increase, according to the Department of Energy’s Energy Information Administration.

In A Case Study of Transmission Limits on Renewables Growth in Texas, the EIA projects that wind and solar generating capacity in the Electric Reliability Council of Texas region will double by 2035.

In a November 2022 study supporting the Public Utility Commission of Texas’ proposed market reforms, the PUCT projected total variable renewable capacity additions in its base case scenario to be 33 gigawatts by 2035, with the vast majority coming from solar installations.

Over the past two years, solar capacity additions exceeded all competing alternatives, representing 46 percent of all additions from 2020 to 2022 compared with 37 percent for wind, 10 percent for battery storage, and 7 percent for natural gas.

In 2022, solar capacity represented about 5 percent of ERCOT’s generation, the EIA report said, adding that by 2024 Texas is projected to lead the nation in solar power growth, overtaking California.

Much of the growth in Texas’ solar power is occurring in the sparsely populated western region where daytime solar power complements the region’s abundant wind generation that is more productive in the evening and night.

In its analysis, EIA said it assumed there would be “no significant upgrades” made to the ERCOT transmission grid, which allowed the agency to isolate how the existing transmission system affects future renewable generation.

On days with more wind and solar generation and strong demand, limited transmission capacity restricted wind and solar generation flows and curtailments occurred, accounting for 36 percent of the projected curtailments in 2035, the EIA report found, adding that transmission-constraint curtailments could be reduced by upgrading the transmission system.

The EIA analysis also found that 64 percent of the wind and solar curtailments happened when the energy supply from high wind and solar resources outpaced low demand. An increase in demand, such as through battery charging, could potentially reduce those types of curtailments, the report found.

In 2022, ERCOT curtailed 5 percent of its total available wind generation and 9 percent of total available utility-scale solar generation. By 2035, however, the EIA projects wind curtailments in ERCOT could increase to 13 percent of total available wind generation, and solar curtailments could reach 19 percent.

“Understanding the source of the renewable curtailments is key to developing a long-term plan that not only includes renewable capacity, but one that seeks to maximize the value of renewable assets to the grid by investing in curtailment mitigation to support load-shifting programs or assets, ranging from time-of-use pricing to utility scale batteries,” the report concluded.

Senate Committee Passes Bill that Includes $1.2 Billion to Boost Grid Supply Chain

July 24, 2023

by Paul Ciampoli
APPA News Director
July 24, 2023

The Senate Committee on Appropriations on July 20 approved the Fiscal Year 2024 Energy and Water Development appropriations bill, which includes $1.2 billion to be spent through 2026 to “enhance the domestic supply chain for the manufacture of electric grid components.”

This supply chain funding is being reprogammed through various programs authorized under the Infrastructure Investment and Jobs Act. These include sections 40101, Grid Resilience for State and Tribal Formula Grants, 40106, Transmission Facilitation Program, 40107, Smart Grid Grants, and 40125(d) Modeling and Assessing Energy Infrastructure Risk.

The new funding provided under the appropriations bill can be used for “financial assistance, procurement, technical assistance, and workforce support.”

The provision was added as part of a “manager’s amendment” to the original version of the appropriations bill and authored by Senator Joe Manchin (D-WV), a member of the Committee on Appropriations and Chairman of the Senate Committee on Energy and Commerce.

Also, the report accompanying the appropriations bill expresses concerns over a notice of proposed rulemaking to increase energy conservation for distribution transformers.

The report’s language follows a provision in the House Committee on Appropriations Energy and Water Development Bill delaying the distribution transformer proposed rule by five years.

The American Public Power Association strongly supports the report language, the $1.2 billion in additional funding and the House provision blocking the proposed rule.

Combined, these provisions provide funding to address the underlying supply shortage issue and affirm that the Department of Energy needs to take into consideration concerns voiced by APPA relating to increasing efficiency standards, it said.

For over a year, the electric sector has been informing DOE about the severity of the supply chain challenges that have prolonged and complicated distribution transformer production and availability.

In June, 47 U.S. senators sent a letter to Secretary of Energy Jennifer Granholm saying that DOE should reconsider its proposed rule to increase conservation standards for distribution transformers.

In April, more than 60 House members urged Granholm to withdraw the proposed rule.

In February APPA, the Edison Electric Institute, the National Rural Electric Cooperative Association, and other impacted trade groups, sent a letter strongly urging DOE to reconsider its intention to increase energy conservation standards for distribution transformers.

Overall, the appropriations bill would provide $17.3 billion for the Department of Energy’s non-defense energy programs — $17.7 billion if excluding the proposed savings from a proposed $400 million rescission from the Strategic Petroleum Reserve account. Also excluding the effects of past and proposed SPR rescissions, the Senate Appropriations Committee bill provides a $293 million increase over FY 2023 spending, a $825 million increase over the House Committee on Appropriations bill, but a $2.2 billion cut from President Biden’s proposed budget.

The Senate Committee bill joins with the House Committee on Appropriations in rejecting the Biden administration proposal to move the State and Community Energy Programs, Manufacturing and Energy Supply Chains Program, and the Federal Energy Management Program from the Office of Energy Efficiency and Renewable Energy to become their own separate offices.

However, unlike the House, the Senate bill agrees with the administration proposal to move the Grid Deployment program from within the Office of Electricity to become a standalone office within DOE.

Fitch Outlines Threat of Battery Storage System Degradation

July 20, 2023

by Paul Ciampoli
APPA News Director
July 20, 2023

Battery energy storage systems, especially those used for arbitrage, could face faster degradation and higher capital expenditures volatility than renewables and thermal peaking plants, according to Fitch Ratings.

In a July 13 article on Fitch Wire, the ratings agency said, “we may raise our metrics thresholds” for battery energy storage systems to reflect risks related to volatility of arbitrage margins, use profiles and capex.

Battery energy storage systems can combine revenue streams from arbitrage, capacity and ancillary services under merchant schemes, long-term offtake agreements and regulated frameworks, Fitch said, noting that arbitrage strategies, such as buying energy when prices are low and selling it when they are high, are riskier and require active management, implying “margin volatility and less visibility over when and how much the asset will be charged and discharged.”

Batteries are subject to fast degradation with the useful life of utility-scale lithium-ion versions far below the estimate for solar panels, Fitch explained.

It said that degradation rates and life expectancy of battery storage mainly depend on how a system is used, especially with respect to frequency, depth of discharge and mode of operation, as well as battery chemistries and external conditions, such as temperature. In addition, in order to mitigate potential under performance, batteries require more frequent replacement than other energy technologies, Fitch said.

The ratings agency noted that battery degradation is affected by use. So, batteries that provide ancillary services for short-duration grid frequency regulation may face a different degradation rate than those that provide capacity for longer periods. And battery systems that have a high reliance on arbitrage revenue could also face even higher levels of degradation because optimal charging and discharging intervals often do not coincide with optimal arbitrage opportunities.

Overall, therefore, battery energy storage systems are exposed to higher levels of capital expenditure volatility compared with renewables or thermal peaking plants, Fitch concluded.

In terms of operational risks, battery systems, like renewable generators, can achieve high availability levels because they are relatively simple to operate. Thermal plants also can achieve high availability levels, but they are more complex to operate, Fitch said.

In terms of revenue risk, however, conventional thermal generators operate on a price-taker model when they sell in the spot market because they dispatch if prices exceed their variable cost of electricity generation, Fitch said. Renewable generators are less sensitive to market prices because they sell power when wind or solar resources are available and have low or no marginal costs.

Battery system operators, however, face a more difficult challenge because they need to consider both merchant sale and purchase prices in order to optimize margins, according to Fitch.

APPA Urges EPA to Reconsider Key Element of Coal Combustion Residual Proposal

July 20, 2023

by APPA News
July 20, 2023

The Environmental Protection Agency should withdraw and re-propose provisions related to coal combustion residual management units included in a proposed rule once it performs the requisite risk assessment and determines whether and how to regulate coal combustion residual disposal practices not currently regulated under federal regulations, the American Public Power Association said in July 17 comments submitted to EPA.

At issue is the proposed rule, “Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals from Electric Utilities: Legacy Coal Combustion Residual (CCR) Surface Impoundments.”

The proposed rule was issued by EPA in response to a decision in the U.S. Court of Appeals for the District of Columbia Circuit that vacated and remanded the provisions that exempted inactive impoundments at inactive facilities from federal CCR regulation.

In addition, the proposal seeks to establish post-closure care requirements for all CCR management units regardless of how and when CCR was placed at a regulated CCR facility.

APPA Has a Long-Standing Interest in the Implementation of CCR Rule

APPA’s members have a long-standing interest in the implementation of the 2015 CCR rule and the types of CCR management practices that are subject to federal regulation, the trade association noted in its comments.

“Since the initial development of federal CCR regulations almost a decade ago, public power utilities have had a history of collaboration with EPA as the agency developed rules to ensure the safe, sustainable, and affordable disposal of CCRs. We take seriously our responsibility to comply with all applicable requirements,” APPA said.

The 2015 CCR Rule established national rules for coal ash disposal “and the industry has worked consistently to implement the rule and its subsequent amendments through a commonsense approach that achieves the environmental goals in a workable and effective manner.”

APPA noted that the focus of the 2015 Rule sought to ensure the safe disposal of CCR at operating surface impoundments and landfills, “which is substantially different from this proposal’s focus on addressing historic CCR management practices.”

The proposed rule addresses site-wide remediation similar to programs implemented under the Comprehensive Environmental Response, Compensation, and Liability Act and Resource Conservation and Recovery Act Subtitle C.

Along with its recommendation that EPA withdraw and re-propose the CCRMU provisions, APPA also offered a series of other recommendations for EPA.

APPA recommended that the agency establish an applicability date for determining what constitutes a legacy impoundment based on a final rule.

“Establishing an early applicability date is impractical, if not impossible, for legacy impoundments that have closed prior to the effective date of any final rule. These units would have to re-close in accordance with the 2015 CCR Rule closure performance standards despite having closed under other existing requirements,” APPA said.

The group also recommended that EPA separate the two regulatory actions (legacy impoundment and CCRMU provisions) and analyze the impact of the CCRMU provisions on the universe of small entities under the Regulatory Flexibility Act. The Proposed Rule broadly defines CCRMUs; as a result, it significantly undercounts the number of CCRMUs at small utilities.

APPA also recommended that EPA exclude units from the rule which have undergone or are currently undergoing post-closure care under a state program. In many cases, state programs are robust and include closure requirements as stringent, if not more so, than the federal CCR regulations.

Energy Northwest Signs Agreement for Up to 12 Small Modular Reactors

July 19, 2023

by Paul Ciampoli
APPA News Director
July 19, 2023

Washington State-based Energy Northwest and X-Energy Reactor Company LLC on July 19 announced the signing of a joint development agreement for up to 12 advanced small modular reactors in central Washington capable of generating up to a total of 960 megawatts of electricity. Energy Northwest expects to bring the first module online by 2030. 

Under the agreement, the project is expected to be developed at a site controlled by Energy Northwest adjacent to Columbia Generating Station. 

Energy Northwest owns or operates numerous clean energy generating facilities throughout the Northwest region of the United States, including Columbia Generating Station in Richland, which is the only commercial nuclear energy facility in the region.

Each Xe-100 module can provide 80 megawatts of full-time electricity or 200 megawatts of high-temperature steam.

Energy Northwest and X-energy have engaged extensively on plans for an Xe-100 facility in central Washington since 2020.

The JDA defines and details the scope, location, and schedule under which the commercial development of the project will move forward.

Energy Northwest and X-energy will also work together to determine the best approaches to licensing and regulatory matters, as well as the project delivery model. 

Energy Northwest is a Washington state public power joint operating agency. Energy Northwest comprises 28 public power member utilities, serving more than 1.5 million customers.

Other Public Power Entities and SMRs

The Tennessee Valley Authority, Ontario Power Generation, Synthos Green Energy, and GE Hitachi Nuclear Energy in March 2023 said that they are teaming up to advance the global deployment of a small modular reactor.

TVA, OPG and SGE will invest in the development of the GE Hitachi Nuclear Energy BWRX-300 standard design and detailed design for key components, including reactor pressure vessel and internals.

Meanwhile, participants’ governing boards in the Carbon Free Power Project being developed by Utah Associated Municipal Power Systems are moving forward with the development and deployment of a small modular reactor project, UAMPS reported on Feb. 28. With the commitments, the CFPP Project Management Committee approved a new budget and plan of finance.

And in January, the Nebraska Public Power District said it is beginning the process of studying sites that could have the potential to host advanced small modular nuclear reactors.

Lansing Board of Water & Light Unveils Plan to Build More Than 650 MW of Clean Energy Projects

July 19, 2023

by Paul Ciampoli
APPA News Director
July 19, 2023

The Lansing Board of Water & Light on July 19 announced its plan to build over 650 megawatts of clean energy projects to support its clean energy goals and meet future regional load growth.

The projects will be complemented by a new 110-MW Reciprocating Internal Combustion Engines gas plant on the site of Delta Energy Park for flexible capacity to be completed by 2026, and a possible additional gas plant at a location to be determined later dependent on future load requirements and regional energy regulations, the Michigan public power utility said.

All of these projects and costs are still under negotiations with the proposed developers and are subject to change pending contract agreements.

The clean energy projects are expected to be complete between 2025-2027, and include:

The portfolio will bring a capital investment of approximately $750 million and is expected to be finished in the next 10 years.

The projects are the result of BWL’s All Source Request for Proposals, which received 96 offers totaling 8,330 MW.

“Once implemented, this will bring BWL’s total generational portfolio to around 58 percent renewable and reduce our carbon footprint by 75 percent compared to 2005,” said BWL General Manager Dick Peffley. “This continues to position BWL as a leader in the State of Michigan as a clean energy provider, and puts us on the path to carbon neutrality by 2040.”

As part of Governor Gretchen Whitmer’s “MI Healthy Climate Plan,” which calls for 1,000-MW of energy storage by 2025, this portfolio would supply 16 percent of the state’s energy storage goal even though the BWL only supplies 6 percent of the state’s total energy.

BWL received $12 million from the Michigan Public Service Commission to support building 10 MW of solar and 40 MW of 4-hour battery storage on the Delta Energy Park site. 

“This is the largest planned growth in BWL’s nearly 140 year history and ensures we’re able to provide our customers with reliable and affordable energy for decades to come,” said Peffley.

The BWL has approximately 100,000 electric customers, 58,000 water customers, 155 steam customers and 19 chilled water customers.

New York Grid Operator Warns of Reliability Deficit in New York City Area by 2025

July 18, 2023

by Peter Maloney
APPA News
July 18, 2023

The New York City area could have a deficit as large as 446 megawatts as early as summer 2025, according to the New York Independent System Operator.

The deficit in reliability margins for the New York City area is driven primarily by the combination of a forecasted increase in peak demand and the unavailability of certain generators, according to the NYISO report, Short-Term Assessment of Reliability:2023 Quarter 2.

Specifically, some generating plants affected by legislation known as the Peaker Rule will not be available, leaving NYISO’s New York City zone with a deficiency of as much as 446 MW for a duration of nine hours on the peak day during expected weather conditions when accounting for forecasted economic growth and policy driven increases in demand, the report said.

The Peaker Rule, adopted by the New York State Department of Environmental Conservation in 2019, limits nitrogen oxides emissions from simple-cycle combustion turbines used as peakers to meet spikes in demand.

As of May 1, 2023, 1,027 MW of affected peakers have deactivated or limited their operation, and an additional 590 MW of peakers are expected to become unavailable beginning May 1, 2025, all of them in New York City, the report said.

Beyond 2023, the New York City transmission security margin is expected to improve in 2026 if the Champlain Hudson Power Express connection from Hydro Quebec to New York City enters service on schedule in spring 2026, but the margin gradually erodes thereafter as expected demand for electricity grows, the report said.

Forecasted reliability margins within New York City may not be sufficient if the Champlain Hudson Power Express project experiences a significant delay, additional power plants become unavailable, or demand significantly exceeds current forecasts, according to the report.

Without the Champlain Hudson Power Express project in service or other offsetting changes or solutions, the reliability margins continue to be deficient for the report’s 10-year planning horizon, NYISO said. In addition, while Champlain Hudson Power Express is expected to contribute to reliability in the summer, it is not expected to provide any capacity in the winter.

Beginning in August 2023, NYISO said it plans to solicit market-based solutions to the reliability need that could include supply or demand-side solutions, such as generation, storage, and/or new participation in programs that aim to reduce demand.

In October and November 2023, after the solicitation window has closed, NYISO said it would evaluate the submitted proposals. If they are not viable or sufficient to meet the reliability need, interim solutions will need to be put in place, NYISO said.

One potential outcome could be relying on generators that are subject to the Peaker Rule to remain in operation until a permanent solution is in place, NYISO said.

In anticipation of such a scenario, the Peaker Rule authorized NYISO to designate certain units to remain in operation beyond 2025 on an as-needed basis for reliability.

Based on the findings its Short-Term Reliability Process, NYISO said it may designate certain units, in sufficient quantity, to remain in operation for an additional two years, until May 1, 2027, with the potential of an additional two-year extension to May 1, 2029, if a permanent solution has been selected but is not yet online.

NYISO said it would only temporarily retain peakers as a last-step approach if it does not expect solutions to be in place by the time the identified reliability need is expected in 2025.

PJM Met Demand Through December 2022 Event, but Extreme Cold Stressed Grid

July 18, 2023

by APPA News
July 18, 2023

The PJM Interconnection was able to maintain system reliability and serve customers throughout the extreme weather that affected the regional transmission organization from Dec. 23 through Dec. 25, 2022, according to a PJM report.

The Winter Storm Elliott Event Analysis and Recommendation Report noted that PJM operators were able to avoid electricity interruptions and even support its neighbors during certain periods, although the operators had to implement multiple emergency procedures and issue a public appeal to reduce energy use.

Winter Storm Elliott’s rapidly falling temperatures coincided with a holiday weekend that combined to produce unprecedented demand for December, which was further complicated by unexpectedly high resource unavailability and/or failures to perform, the report said.

On Dec. 23, the first day of the storm, the stress on PJM’s neighbors began to signal extreme conditions headed for the PJM region. The Southwest Power Pool set a new winter peak on that day. The Tennessee Valley Authority experienced the highest 24-hour electricity demand supplied in its history. PJM was able to export energy to TVA, Duke Carolinas and Duke Energy Progress before having to curtail most exports during peak conditions in the face of emergency conditions.

PJM’s forecast for Dec. 23 was about 127,000 megawatts, and load came in at about 136,000 MW, about 25,000 MW above a typical winter peak day. In preparation, PJM had approximately 158,000 MW of operating capacity plus available generation able to be called upon in real time and was able to meet load with the help of a Maximum Generation Action and Demand Response.

The next day, the coldest of the weekend, PJM said its operators decided to schedule conservatively in terms of reserves. PJM anticipated approximately 155,700 MW should have been available for Dec. 24, but complications arose from the unanticipated failure of generation resources that were called on that day. At one point, almost a quarter of the generation capacity, 47,000 MW, was on forced outages, the report said.

Across the entire PJM generation fleet, natural gas generators accounted for 70 percent of the outages on Dec. 24, most of them caused by equipment failure likely resulting from the extreme cold with broader issues of gas availability also contributing to the outages, the report said.

Winter Storm Elliott was the first wide-scale use of PJM’s Capacity Performance rules that were introduced in 2016 in the wake of the 2014 Polar Vortex. The high outage rates for generators during Winter Storm Elliott resulted in substantial Non-Performance Charges that are part of Capacity Performance rules.

PJM estimates there are approximately $1.8 billion in Non-Performance Charges based on the current rules, which call for the charges to be allocated to suppliers that exceeded their committed capacity level.

While PJM operators were able to keep electricity flowing in the region throughout the storm “Elliott also provides some clear lessons for PJM and its stakeholders that drive” the 30 recommendations contained in this report,” PJM said.

The recommendations are broadly focused on:

PJM said many of the recommendations are being developed through the Critical Issue Fast Path–Resource Adequacy process or other forums, including the Electric Gas Coordination Senior Task Force, Operating Committee and Market Implementation Committee.

Company Achieves Key Technology Breakthrough in Geothermal Energy Pilot Project

July 18, 2023

by Paul Ciampoli
APPA News Director
July 18, 2023

Fervo Energy on July 18 announced that it has successfully completed the well test at its full-scale commercial pilot, Project Red, in northern Nevada.

The successful well test confirms the commercial viability of Fervo’s drilling technology and establishes Project Red as the most productive enhanced geothermal system in history, Fervo said.

The 30-day well test, a standard for geothermal, achieved a flowrate of 63 liters per second at high temperature that enables 3.5 MW of electric production, setting new records for both flow and power output from an enhanced geothermal system.

Fervo said it is the first company to successfully drill a horizontal well pair for commercial geothermal production, achieving lateral lengths of 3,250 feet, reaching a temperature of 191 °C, and proving controlled flow through tracer testing.

Fervo notes that it implemented an induced seismicity mitigation protocol following best practices established by the U.S. Department of Energy and completed the project without incident.

“Data collected through the course of this pilot will enable rapid advancement in geothermal deployment, with Fervo’s next horizontal well pair planned to achieve more than double the power output of the pilot design,” it said.

In 2021, Fervo and Google signed the world’s first corporate agreement to develop next-generation geothermal power. The goal of the partnership is to power Google’s Cloud region in Las Vegas with an “always-on,” carbon-free resource.

Fervo said its results from Project Red support the findings of the DOE Enhanced Geothermal Earthshot and show that geothermal energy could supply over 20% of U.S. power needs and compliment wind and solar to reach a fully decarbonized grid.

“Fervo’s drilling and well test results pave the way for the U.S. to meet this goal ahead of schedule; with Fervo’s breakthrough, no technological barriers to geothermal deployment remain,” it said.