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Fitch Outlines Public Power Supply Risks Tied to Crypto Currency Mining

February 2, 2022

by Paul Ciampoli
APPA News Dierctor
February 2, 2022

Digital asset or crypto currency mining in the U.S. could present power supply risks to public power utilities unless they are sufficiently mitigated, Fitch Ratings said on Jan 24.

Crypto mining “is energy intensive and requires a considerable amount of power that can significantly increase a utility’s overall electrical load. Utilities must balance the revenue prospect of increased electrical sales with the commitment to procure or generate large amounts of power for crypto mining operations,” Fitch said.

The rating agency noted that crypto mining operations are price-sensitive entities that may be quickly scaled back or shut down if mining becomes uneconomical.

To date, Fitch’s rated public power utilities “have successfully limited their risk by restricting the scope of crypto mining operations in their service area or by defining their power procurement commitments in a way that protects the utility from nonpayment, including due to a sudden closure of the mining facility,” Fitch said.

It noted that utilities that have excess generation capacity may have the ability to meet the power supply requirements of crypto mining operations from existing power supplies. “This is the case in the state of Washington, where energy-intensive aluminum smelting operations have gradually closed over the last two decades and wind energy production has increased available energy supplies over the last decade. This, coupled with abundant low-cost hydroelectric generation, made the region an attractive location for data centers historically and crypto-mining operations in recent years.”

A utility with excess capacity “must evaluate the opportunity costs and benefits of a new large crypto load versus retaining capacity for other economic development opportunities,” according to the rating agency.

Crypto mining operations “typically bring in very little additional economic benefits in the form of jobs or ancillary business to a local economy,” Fitch said. While crypto mining operations have a wide range of sizes, in some instances they can become the largest customer in a rural service territory.

“The volatile and unregulated nature of crypto mining and the large influx of load requests led a number of Washington utilities to adopt new practices beginning in 2014 to mitigate exposure to crypto mining entities, including crypto-currency load moratoriums, evolving rate structures to capture the departure risk of a high-risk industry, and defined customer concentration limits,” the rating agency said.

Much of the recent cryptocurrency mining expansion is occurring in Texas, Fitch noted. “Unlike Washington, Texas utilities generally do not have excess generation capacity, but the structure of the regional energy market offers other perceived business advantages. For utilities with a supply and demand imbalance, utilities may need to invest in new generation facilities, sign new long-term power purchase agreements or procure power via real-time market purchases in order to serve additional crypto mining load.”

Fitch said that the first two of these three options pose the greatest risk to the utility should the crypto mining operation shut down, “as utilities could be left with stranded assets and costs that then must be recovered, typically by customers in the form of rate hikes, although the utility may utilize reserves to recover costs if there is little rate flexibility.”

Increased costs or a reduction in reserves could lead to negative credit pressure if operating margins are compressed; similarly, lower liquidity could lead to a weaker overall financial profile.

To date, Fitch-rated utilities have opted to use short-term market purchases with pass-through cost arrangements to mitigate financial risk to the utility, the rating agency said.

Court Sides With San Francisco PUC In Dispute With PG&E Over Power Grid Connections

January 31, 2022

by Paul Ciampoli
APPA News Director
January 31, 2022

The U.S. Court of Appeals for the District of Columbia Circuit recently sided with the San Francisco Public Utilities Commission (SFPUC) in a dispute with Pacific Gas & Electric (PG&E) over electricity connections. In its opinion, the appeals court directed the Federal Energy Regulatory Commission (FERC) to conduct further proceedings related to matters addressed in the decision.

The dispute centers on PG&E’s wholesale service to SFPUC under rules approved by FERC. The SFPUC purchases access to PG&E’s distribution system in San Francisco — paying PG&E about $20 million per year — to serve facilities providing city services.

PG&E, “in an attempt to stymie competition from the SFPUC, has been obstructing public projects for years, demanding the installation of unnecessary and expensive equipment before hooking up those projects to the electric grid,” SFPUC said in a news release related to the court’s decision.

The court’s decision covers two separate appeals from San Francisco, challenging a series of FERC orders.  

One, a San Francisco complaint in January 2019 about what SFPUC claimed were PG&E’s demands for costly and unnecessary equipment designed for high-voltage primary power connections. San Francisco argued that secondary connections, which carry lower voltages, are the appropriate connection types for these projects. FERC sided with PG&E, and San Francisco appealed to the D.C. Circuit Court, which ruled in the city’s favor. 

The appellate court, in a unanimous ruling by a three-judge panel, found that FERC had not justified its decision to uphold PG&E’s refusal to provide SFPUC interconnections at secondary voltage. Focusing on the Commission’s finding that PG&E’s actions were justified by safety and reliability concerns, the court found that FERC’s decision-making was flawed, noting in the ruling that FERC “does not provide sufficient justification for its conclusion,” “does not meet its burden of reasoned decision-making,” and that FERC’s “‘passing reference to relevant factors,’ … is not sufficient to satisfy [FERC]’s obligation to carry out ‘reasoned’ and ‘principled’ decision making.”

The court also said that the orders on review “present a troubling pattern of inattentiveness to potential anti-competitive effects of PG&E’s administration of its open-access tariff.”

The court said that “More than a century ago, Congress authorized the Hetch Hetchy System not only to provide San Francisco with a source of cheap power but also to ensure competition in its retail power market. Faced with claims that PG&E was frustrating that competition by treating its own retail service preferentially and refusing service for customers San Francisco had served for decades, [FERC] fell short of meeting its ‘duty’ to ensure that rules or practices affecting wholesale rates are ‘just and reasonable.’”

The second case addressed by the court started with a San Francisco complaint in 2013 regarding grandfathered customers who were served up until 1992.

The court found that FERC’s orders on grandfathering, which limited the city’s ability to continue to serve many of the customers it was serving in 1992, “are arbitrary and capricious.”

The court’s decision invalidated FERC’s orders on these topics and sent the matters back to FERC for “further proceedings consistent with this opinion.”

The SFPUC is a department of the City and County of San Francisco. It delivers drinking water to 2.7 million people in the San Francisco Bay Area, collects and treats wastewater for the City and County of San Francisco, and generates power for municipal buildings, residents, and businesses.

Platte River Power Authority To Join Market Operated By Southwest Power Pool

January 26, 2022

by Paul Ciampoli
APPA News Director
January 26, 2022

Colorado’s Platte River Power Authority, Xcel Energy-Colorado and Black Hills Colorado Electric on Jan. 25 announced plans today to join the Western Energy Imbalance Service (WEIS) Market, operated by the Southwest Power Pool (SPP).

Platte River, based in Fort Collins, and the two investor-owned utilities expect to join the WEIS in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market.

An energy imbalance market is a real-time market in which energy generation from multiple power providers is dispatched at the lowest possible cost to reliably serve the combined customer demand of the region.

“Joining the WEIS will expand the benefits we gained from the joint dispatch agreement (JDA) on behalf of our owner communities,” said Jason Frisbie, general manager and CEO of Platte River, in a statement. “We’ve created excellent partnerships through the JDA that currently provide great value to our customers. Moving into an energy imbalance market brings Platte River one step closer to a noncarbon energy future.”

Xcel Energy-Colorado currently operates under a JDA that enables sharing generation between Platte River, Black Hills Colorado Electric and public power utility Colorado Springs Utilities within its Balancing Authority Area.

The group explored participation in the Western Energy Imbalance Market operated by the California Independent System Operator as well as the WEIS operated by SPP.

Xcel Energy took a step back from joining the Western Energy Imbalance Market last year after one of its energy partners joined the WEIS.

After further analysis, the group decided the best interim option was to move into the WEIS due to geographic diversity and existing interconnections. The utilities’ participation in the WEIS will replace the JDA and is expected to bring additional production cost savings to customers.

The three organizations remain committed to evaluating a longer term and broader regional market structure that will ensure system reliability and improve the integration of wind and solar energy on the system.

In October, they announced participation in the Western Markets Exploratory Group (WMEG) and are committed to working with the WMEG to evaluate different market options that reduce costs, increase reliability, and help promote their strategies to create a carbon free electricity system.

Participants in the WMEG will consider market structures that expand on energy imbalance markets and will evaluate broader market designs for the western region, including a staged approach to new market services, to see if those designs can enhance their ability to provide clean, reliable and low-cost energy service to their customers.

The agreement to join the WEIS still requires approval through appropriate regulatory processes.

APPA Offers A Number Of Recommendations To DOE On Energy Supply Chain Issues

January 24, 2022

by Paul Ciampoli
APPA News Director
January 24, 2022

The American Public Power Association (APPA) and the Large Public Power Council (LPPC) recently provided comments including recommendations to the Department of Energy (DOE) in response to a request for information (RFI) that DOE issued on energy sector supply chain issues.

Among other things, APPA and LPPC said that DOE should utilize a risk-based framework for supply chain security and further recommended that DOE study domestic and international supply of both distribution and bulk electric system transformers and the components needed to manufacture these transformers.

Background

DOE was instructed to issue a report on supply chains for the energy sector industrial base in Executive Order (EO) 14017, “America’s Supply Chains,” issued last February. DOE will use the information gathered from the RFI to compile its report to the White House by February 24, 2022, as directed by the EO.

DOE sought input from stakeholders on “approaches and actions needed to build resilient supply chains for the energy sector,” with a focus on 14 categories.

While most, if not all, of the categories are of at least some relevance to public power and the electric industry as a whole, APPA decided to focus its comments on this subset of categories most directly affecting public power currently: Electric Grid – Transformers and HVDC; Carbon Capture, Storage and Transportation Materials; and Cybersecurity and Digital Components.

Cybersecurity and Digital Components

APPA and LPPC noted that public power utilities “take very seriously their responsibility to maintain a secure and reliable electric grid.”

The electric utility sector has a mandatory and enforceable federal regulatory regime in place for reliability, including cybersecurity. Under this standards regime, utilities are responsible for assessing the cybersecurity of vendors and manufacturers of digital components.

According to the two trade groups, public power utilities have found that not all vendors and manufacturers of digital components feel compelled to respond to utilities as they seek to conduct these vendor assessments.

“Public power utilities believe the responsibility for demonstrating the cybersecurity of their supply chain for all equipment, components, and subcomponents used for critical electric infrastructure should rest with the vendors and manufacturers.”

For this reason, APPA and LPPC recommended that, with regards to the electric utility sector supply chain, DOE should:

Electric Grid – Transformers/HVDC

APPA provided comments on the supply chain constraints affecting distribution transformers to DOE’s Office of Energy Efficiency and Renewable Energy in December 2021 in response to the proposed rule, “Energy Conservation Program: Energy Conservation Standards for Distribution Transformers.”

In those comments, APPA primarily raised concerns with the domestic supply of distribution transformers.

“While APPA and LPPC recognize that the questions in this inquiry are about new large power transformers (LPT) and high voltage direct current technology (HVDC) initiatives, the same supply chain constraints identified in APPA’s earlier comments will impact the successful implementation of any LPT and HVDC initiatives,” the trade groups told DOE.

“As APPA communicated to DOE in its prior comments for both bulk power system and distribution system transformers, the supply chain for steel will significantly impact future transformer production and supply. Moreover, any efficiency standard for transformers will greatly impact transformer supply.”

Of immediate concern to public power utilities is how limitations on distribution transformer supply would play out in response to extreme weather events across the U.S., LPPC and APPA said.

“If an extreme weather event were to disable a significant number of distribution transformers, supply chain constraints could severely limit the availability of replacement devices, jeopardizing utilities’ ability to restore or maintain reliable electric service. Even if distribution transformers are available, supply and demand imbalance may result in significant price increases that would ultimately be borne by electric consumers. Importantly, these same concerns could eventually impact Bulk Power System (BPS) transformers.”

APPA and LPPC are concerned that this current supply shortage may last several years and exacerbate the current slowdown of domestic and international transformer deliveries. The minimum impact of this constraint is a significant increase in transformer prices, they said.

“However, the worst-case scenario could be a rationing of transformers that could slow down local economies and impede new construction and infrastructure investments.”

APPA and LPPC recommended that DOE study domestic and international supply of both distribution and bulk electric system transformers and the components needed to manufacturer these transformers “so that any well-intentioned LPT and HVDC supply chain initiatives do not result in transmission-level transformers competing for the same resources needed to restart the domestic supply chain for distribution transformers.”

More broadly, the electricity sector is dependent on numerous supply components, fuel, and technology for the generation, transmission, distribution, and consumption of electricity, the comments noted.

This would include entities involved with the following:

“A slow down or disruption in any part of this supply system may have an adverse impact on the delivery of safe, reliable, and cost-effective electricity,” APPA and LPPC said. 

Carbon Capture, Storage and Transportation Materials

Meanwhile, the groups noted that a broad portfolio of technologies is needed to achieve deep carbon dioxide (CO2) emissions reductions practically and cost-effectively. Energy efficiency and renewable resources are needed for such emissions reductions, but other technologies and strategies have a major role to play as well.

Carbon capture, utilization, and storage (CCUS) technologies are critical for putting energy systems on a sustainable path, they said.

“Despite the importance of CCUS for achieving the clean energy transition, deployment has been slow to take off — there are only around 20 commercial CCUS operations worldwide. But momentum is building. Plans for more than 30 commercial CCUS facilities have been announced in recent years, and despite the COVID‑19 pandemic, in 2020, governments and industry committed more than $4.5 billion to CCUS.”

APPA and LPPC said that CCUS could play an important role in proposed plans to reduce greenhouse gas (GHG) emissions from the U.S. power sector.

“The trend of increasing penetration of variable renewable power into the energy grid is clear. However, concerns for the rate at which variable renewable sources can be installed and the reliability of the grid caution for the continued need for reliable fossil power. CCUS could enable fossil power to fill this role while limiting CO2 emissions or supporting a clean energy standard.”

APPA and LPPC said that successful use of CCUS to remove significant CO2 from the national inventory requires not only reliable and effective capture technology, but an entire “value chain” of activities.

The key steps in this value chain are CO2 compression, transport, disposition in a safe and ideally useful manner, and analytical and monitoring techniques. The creation and maintenance of a successful supply-chain to support these activities is equally important to CO2 capture for CCUS, the groups told DOE.

CO2 compression will require large compression equipment and large diameter steel pipe. APPA and LPPC recommended that DOE survey the compression equipment manufactures to assess current and future capacity.

They noted that the transport of CO2 via pipelines is the principal means by which CO2 is, and will continue to be, distributed for enhanced oil recovery or deep saline geologic injection.

A significant expansion of the existing pipeline network is projected to be necessary to support CO2 emission reductions, based on an analysis by the National Energy Technology Laboratory, petroleum industry, and Great Plains Institute.

“Further the availably of domestically supplied steel needed to construct pipelines remains an issue not only for the power sector but for other industrial processes and equipment.”

Ditto Highlights Public Power Funding Opportunities That Will Flow From Infrastructure Law

January 21, 2022

by Paul Ciampoli
APPA News Director
January 21, 2022

While 2022 could present some challenges for the energy sector, public power utilities are well positioned for success this year and beyond thanks to, among other things, a wide range of funding opportunities that will flow from a new federal infrastructure law, said Joy Ditto, President and CEO of the American Public Power Association (APPA), on Jan. 20.

Ditto made her remarks during the U.S. Energy Association’s (USEA) 18th Annual State of the Energy Industry Forum.

Ditto said that implementation of the new infrastructure law “helps with many elements of grid modernization.” The law will result in a “ton of money flowing to our industry and various elements of it and we’re excited to take advantage of it and help our members take advantage of getting those funding opportunities down on the ground and implementing them.”

APPA members now have access to a webpage dedicated to keeping them up to date on activity and funding opportunities related to implementation of the Infrastructure Investment and Jobs Act.

“We’re supportive of robust funding across the board” in areas like electric vehicle infrastructure, hydrogen energy storage, advanced nuclear energy, and carbon, capture, utilization and storage.

She pointed out that public power utilities are leaders when it comes the development of small modular reactors (SMRs) and other advanced nuclear options.

APPA also appreciates the fact that the infrastructure law takes steps to bolster hydropower, Ditto said, noting that the association continues to believe strongly “that we have to maintain and enhance hydropower as a generating source.”

Moreover, APPA is pleased to see that the infrastructure law includes funding to bolster cybersecurity, not just for the overall power sector, but also for APPA and public power utilities specifically.

In 2022, APPA will continue to help bring electricity to Navajo Nation residents through its Light Up Navajo initiative with the Navajo Tribal Utility Authority (NTUA), Ditto noted.

Light Up Navajo III will start in the spring of this year. “We welcome support for that effort,” Ditto said. [Interested public power utilities should contact lightup-navajoproject@ntua.com for more information on this important event].

One of the challenges that Ditto sees as likely to continue in 2022 involves interdependency issues, which she said was highlighted during Winter Storm Uri in early 2021. Uri hit the Texas power grid and many other states in the middle of the country.

Ditto pointed out that APPA in 2010 published a report, “Implications of Greater Reliance on Natural Gas in the Electric Sector,” which was presented to the USEA that year. “There were challenges we identified back then in that report that we’re seeing come to fruition.”

But pinpointing challenges that could come about doesn’t always translate into being able to successfully meet those challenges without a visible reference “to what the implications could result in and we, unfortunately,” saw that reference play out with Winter Storm Uri, she said.

“I hope that we can utilize that challenge and make it into an opportunity to address these issues inter-sector and intra-sector to see how we can go back and focus on reliability, as well as maintaining affordability.”

Cybersecurity is another challenge that will remain in 2022 and going forward, Ditto said, noting the continued growth in placing digital components on to the grid.

For its part, the public power community is focused on the value of collaboration with the federal government and with others in the electric sector to proactively address cybersecurity threats, Ditto said. Public power utilities will continue to make cybersecurity a priority this year and beyond.

On a day-to-day basis, when it comes to cybersecurity efforts, there is probably a need to think differently as an industry, she said. For public power, “we’re thinking about how we provide collective services to our smaller members.”

Meanwhile, on Capitol Hill, questions remain in 2022 about the fate of President Biden’s Build Back Better legislative proposal.

With respect to the climate change element of the proposal, APPA supports a legislative solution “to addressing climate, but with that three-legged stool of sustainability, affordability and reliability at the forefront at all times,” Ditto said.

“Given the uncertainty of what’s going on in Congress on climate, we’re of course anticipating EPA regulation. We know that there are some court decisions pending that could also impact what EPA does in this space.”

Supply chain issues are coming into sharper focus as a 2022 challenge. The supply chain has been on public power’s radar for quite some time, Ditto said, specifically in the context of how secure supply chains are related to digitization and cyber security.

“Now we’re thinking about supply chain more fundamentally,” she said. For example, what is the availability of distribution transformers.

She praised the move by the Department of Energy to issue a request for information (RFI) on energy sector supply chain issues. APPA and the Large Public Power Council recently submitted joint comments in response to the RFI.

MEAG Power Formally Joins Southeast Energy Exchange Market

January 18, 2022

by Paul Ciampoli
APPA News Director
January 18, 2022

The Municipal Electric Authority of Georgia (MEAG Power), a nonprofit, statewide generation and transmission organization, has joined the Southeast Energy Exchange Market (SEEM) effective Jan. 13, 2022.

The new SEEM platform will facilitate sub-hourly, bilateral trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Participation in SEEM is open to other entities that meet the appropriate requirements.   

Other founding members of SEEM include Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, N.C. Municipal Power Agency No. 1, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company and TVA.

Santee Cooper, South Carolina’s state-owned electric and water utility, joined SEEM effective Jan. 4, 2022.

The founding members represent nearly 20 entities in parts of 11 states with more than 160,000 megawatts (MW) (summer capacity; winter capacity is nearly 180,000 MW) across two time zones. These companies serve the energy needs of more than 32 million retail customers.

FERC Report Finds Advanced Meter, Demand Response Penetration Growing

January 18, 2022

by Peter Maloney
APPA News
January 18, 2022

Utility customer enrollment in both retail demand response and dynamic pricing programs increased from 2018 to 2019 and data suggests that as more advanced meters are deployed utilities will continue to see increasing enrollment levels, according to a new report from the staff of the Federal Energy Regulatory Commission (FERC).

Among the highlights of the report, 2021 Assessment of Demand Response and Advanced Metering, FERC staff found that the number of advanced meters in operation in the United States from 2018 to 2019 increased by about 8 million to 94.8 million, representing a 9 percent annual increase.

The 94.8 million advanced meters in operation represents about 60.3 percent of the 157.2 million meters in the United States, and, despite regional variations, estimated advanced meter penetration rates nationwide for residential, commercial, and industrial customer classes were greater than 50 percent in 2019, according to the report.  

In 2019, utilities in the South Atlantic census division, essentially southern seaboard states, reported over 21 million advanced meters in operation, while utilities in the East North Central (Ohio Valley states and Michigan), Pacific, and West South Central (Texas and its three contiguous states to the north and east) census divisions each reported over 14 million advanced meters in operation, the report said.

The total number of advanced meters reported by utilities in the East North Central, East South Central, Pacific, South Atlantic, and West South Central areas represent advanced meter penetration rates greater than 65 percent, FERC staff said.

The report also noted that state regulators continue to support the deployment of advanced meters. Connecticut and New Jersey, for instance, are initiating proceedings and establishing frameworks for advanced metering proposals and proposal analysis.

In the assessment, FERC began using nine census regions instead of North American Electric Reliability Corp. regions to present some data because of changes NERC has made in recent years. For example, the transfer of entities in the Florida Reliability Coordinating Council footprint to the SERC Reliability Corp. To present accurate trends and to provide continuity, FERC presented its findings by census divisions for the last two years.

Demand Response

Demand resource participation in the wholesale markets decreased by about 1,383 MW, or 4 percent, from 2019 to 2020, even though demand response resource totals increased in four of the seven wholesale markets, the report found.

The largest annual difference was in the PJM Interconnection area where there was a 1,270 MW drop, representing a 12.5 percent decline in demand response resources from 2019 to 2020.

Despite the decline in demand resource participation, the percent of peak demand that could be met by demand response resources increased from 6 percent in 2019 to 6.6 percent in 2020 because of lower peak loads, the report found.

Meanwhile, customer enrollment in retail incentive-based demand response programs increased by 1.1 million from 2018 to 2019, a 12 percent increase, and customer enrollment in retail dynamic pricing programs increased by 1.7 million, a 19 percent increase, the report said.

Overall, customer enrollment in incentive-based demand response and dynamic pricing programs increased in six census divisions with utilities in five divisions reporting aggregate annual increases of 20 percent or more.

Utilities in the South Atlantic region reported the greatest absolute increase, with over 669,000 additional customers enrolled while utilities in the West South Central region saw the largest annual increase, 88 percent, in customer enrollment from 2018 to 2019. New England utilities reported the second highest annual increase with a 43 rise in enrollments, the report found.

Not all regions saw increases, however. Utilities in the Pacific region saw 348,000 fewer customers enroll in 2019 compared with 2018 even as individual utilities such as San Diego Gas and Electric and Portland General Electric in Oregon saw enrollments rise.

Even with rising numbers, the report noted that the total number of customers enrolled in retail dynamic pricing and retail demand response programs is still relatively low compared with the total number of retail customers.

Regulatory barriers to customer participation in demand response programs continue to exist. Demand response programs can result in lower energy costs for customers, but “regulatory approval processes required for technologies that unlock the value of demand response and time-based rate programs, like advanced metering, can slow the development and implementation of new programs,” FERC staff wrote in the report.

In addition, many regional transmission organizations (RTOs) and independent system operators (ISOs) “limit the ability of demand flexibility to participate at the wholesale level as demand response because demand response is often defined as a reduction in expected consumption,” the report said.

“While some RTOs/ISOs incorporate demand response and demand-side resources into planning and resource adequacy processes, the full suite of demand flexibility capabilities are not currently accounted for in utility, state, and RTO/ISO planning processes,” the report said.

The FERC assessment report is the 16th in a series of reports the commission issues each year as required by the Energy Policy Act of 2005.

Wholesale Electric Prices Rose From 2020 To 2021, EIA Reports

January 12, 2022

by Peter Maloney
APPA News
January 12, 2022

Average wholesale electricity prices rose in 2021 compared with 2020 levels pushed, in part, by higher natural gas costs, according to the Energy Information Administration (EIA).

Constraints on electricity supply as a result of cold weather in the central United States created price spikes in February 2021, EIA said, but the overall rise in electricity prices was particularly steep in the second half of 2021, the EIA noted.

Electricity prices were particularly volatile in the Electric Reliability Council of Texas (ERCOT) market where record low temperatures in February resulted in emergency conditions and rotating outages. The cold weather also restricted the flow of natural gas for power generation, and many wind turbines froze. Those factors combined to push hourly wholesale prices at the ERCOT North trading hub above $6,000 per megawatt hour (MWh) for 70 percent of the time. For the month of February, Texas’s wholesale electricity price averaged $1,485/MWh.

The cold weather also caused near record high spikes in the price of natural gas throughout the country, leading to high electricity prices in other wholesale markets. In the PJM Interconnection, February wholesale electricity prices averaged $42/MWh. In ISO-New England prices averaged $73/MWh.

After the February spike, natural gas prices continued to rise through October as economic recovery contributed to overall growth in natural gas demand, which outpaced the ability of gas supply growth to replace inventories drained during the winter storm.

The price of natural gas, which is used to fuel many peaking power plants, is often the main driver of wholesale power prices. And while natural gas prices have been low in recent years – the cost of natural gas delivered to electric generators averaged $2.40 per million British thermal units (MMBtu) in 2020 – prices are rising.

Last year the delivered cost of natural gas to generators rose from $3.19/MMBtu in January 2021 to an estimated $5.04/MMBtu in the fourth quarter of 2021, EIA said.

EIA is estimating that 2021 will prove to be a record year for U.S. natural gas production.

In 2020 wholesale electricity prices were generally lower than they were in 2019. Wholesale power prices were 5 percent lower in the California Independent System Operator (CAISO) market and 45 percent lower in ERCOT, EIA reported..

Wholesale electricity prices in ERCOT were less volatile and averaged $22/MWh in 2020 compared with $38/MWh in 2019, EIA said.

In CAISO, wholesale electricity prices were 34 percent lower in the first half of 2020 than they were in the first half of 2019, mostly as a result of near record-low natural gas costs and reduced electricity demand resulting from pandemic-related stay-at-home orders, EIA said. However, higher than expected electricity demand in the second half of the year caused rolling outages and resulted in an average wholesale price of $77/MWh in August.

Fitch Says New Denton, Texas, Cryptocurrency Load Unlikely To Impact Credit Quality

January 11, 2022

by Paul Ciampoli
APPA News Director
January 11, 2022

A purchase power agreement (PPA) the City of Denton, Texas, has entered into with Core Scientific to provide power to the company’s anticipated digital asset mining operation is unlikely to affect the credit quality of the city’s utility revenue bonds, Fitch Ratings recently said.

The new mining operation will more than double the city utility’s existing electrical load by 2023, but specific power supply acquisition requirements and terms of the PPA limit credit and financial risk to the city, the rating agency said.

Core Scientific’s load for its blockchain data center is expected to be approximately 300 megawatts. Denton has agreed to purchase power on behalf of Core Scientific through the organized power market operated by the Electric Reliability Council of Texas (ERCOT).

“The PPA terms are designed to minimize electric commodity price risk to the city. The settlement arrangements and collateral agreements with Core Scientific are designed to protect the city’s financial position from an unexpected closure or payment default once energy has been purchased on Core Scientific’s behalf,” Fitch said.

The PPA arrangement “preserves the flexibility of the digital asset mining facility to shut down or reduce operations in the event that ERCOT energy prices are too high to allow it to operate economically,” Fitch said. It noted that Core Scientific is able to operate as a controllable load resource within ERCOT, “which provides value in that ERCOT can purchase grid reliability products from Core Scientific, and ERCOT has the ability to require the load to cease operations in an energy shortage position, which occurred during Winter Storm Uri.” Uri hit the Texas power grid in early 2021.

Core Scientific is working with Tenaska Energy Inc. on this project. Tenaska will build the high voltage interconnection and transformer equipment needed to provide the high volume of electricity to the facility. There will be no additional capital expenditures required of the city, Fitch noted. Tenaska will also provide power management services to the project.

Fitch noted Denton adopted a renewable resource plan in 2018 that sets a goal of providing the city with 100% renewable energy. The city has contracted for renewable supplies, but also owns a natural gas plant, the Denton Energy Center, which firms the intermittent production of renewable energy and acts as a cost hedge. Core Scientific has a net carbon-neutral goal that aligns with the city’s plan, and the company has committed to using emissions-free power supplemented by renewable energy credits to power the Denton facility.

“Increased customer concentration introduced by the Core Scientific facility will not diminish the utility’s very strong revenue defensibility assessment. Financial risk to the city is largely mitigated due to the terms of the PPA. The unexpected closure of the facility, should it occur, would not negatively impact the city’s economy or utility rates, since the facility will not be a large employer,” the rating agency said.

NAESB Is Developing Standards To Aid Extreme Weather Electric-Gas Coordination

January 9, 2022

by Peter Maloney
APPA News
January 9, 2022

The North American Energy Standards Board (NAESB) is developing standards to aid the coordination between gas and electric markets during periods of extreme weather.

In several regions of the country, extreme cold weather can present challenges between the need for natural gas as a fuel for space heating and for electric power generation. The potential impact of cold weather on the electric power sector was most recently demonstrated last February when winter storm Uri left millions without power.

On Dec. 9, NAESB’s board of directors voted unanimously to support the addition of a new standards development project to its 2022 work plans aimed at improving electric and gas market coordination.

NAESB’s Gas Electric Harmonization Committee has been meeting since June to discuss potential activities that the organization could undertake to complement the joint inquiry of the Federal Energy Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC), and the regional entities into 2021 Cold Weather Grid Operations following Winter Storm Uri.

Staff from FERC and NERC in September issued a report of preliminary findings and recommendations related to Uri, which affected the Electric Reliability Council of Texas (ERCOT), Southwest Power Pool (SPP), Midcontinent Independent System Operator (MISO), and other regions.

NAESB’s new standards development project, as presented by SPP, is intended to build upon the organization’s existing body of standards and to focus on commercial information sharing between critical parties during impending extreme weather conditions.

NAESB is in the process of making assignments to initiate its standards development within its subcommittees supporting the wholesale and retail gas and electric markets and will be working with FERC, NERC and the National Association of Regulatory Utility Commissioners to align its efforts with the recommendations included in its finalized staff report.

NAESB provides an industry forum that convenes wholesale and retail natural gas and electric market participants, regulators, and other stakeholders to develop business practice standards that underpin the commercial transactions of the markets.