APPA, APGA ask CFTC to investigate high natural gas prices

March 29, 2021

by Paul Ciampoli
APPA News Director
March 29, 2021

The American Public Power Association (APPA) and the American Public Gas Association (APGA) have asked the Commodity Futures Trading Commission (CFTC) to launch an investigation to determine whether any potential wrongdoing led to historic natural gas price spikes during Winter Storm Uri last month.

In a March 26 letter to CFTC Acting Chairman Rostin Behnam, APPA and APGA noted that Uri brought snow, ice, and record low temperatures to many states, including those not accustomed to harsh winters and the disruptions that can accompany them.

“Throughout this severe weather, many communities across the U.S. relied on their public gas utilities to maintain delivery of safe, traditionally affordable, and reliable natural gas for use in space and water heating and cooking. Public power utilities likewise worked around the clock to maintain reliable and affordable electric service to their customers,” the letter pointed out.

“Unfortunately, many of these not-for-profit municipal gas and public power utilities, and consequently their customers, were subject to exorbitant price increases throughout the crisis,” the trade groups said in asking the CFTC initiate an investigation to determine whether any potential wrongdoing led to these historic price spikes.

APPA and APGA noted that during Presidents’ Day weekend, natural gas prices, which have hovered around $3/MMBtu in recent years, skyrocketed to upwards of $300/MMBtu and even higher in some cases.

“With demand for natural gas rising in response to the cold temperatures, our members had no choice but to purchase gas at the inflated prices or pay even steeper penalties to ensure their customers could continue to heat their homes or to allow natural gas-fueled electric generation to continue operating,” the trade groups said.

In one case, a municipal utility spent its monthly gas budget each day over that weekend. In another, a joint action agency expended three times its annual gas purchasing budget just to buy gas for its customers for four days. In southern Kansas, the city of Winfield, a public gas and power system serving a city of 12,300, which normally pays $1.6 million a year for natural gas, “is looking at a February bill of an almost unbelievable sum of nearly $10 million.”

APPA and APGA said that similar stories “abound throughout the Midwest, south-central, and other regions that were most severely impacted by the storm, and have brought into question how many of these communities will be able to purchase needed gas throughout the remainder of the winter, let alone the rest of the year.”

Publicly-owned utilities across the country “are now struggling to pay the bills they incurred, while trying to minimize the impacts to their customers. Some are receiving demands for collateral and margin calls from sellers who are threatening to cut off further gas supplies. Without relief, however, these high prices will be passed directly to their consumers,” the groups said.

APGA and APPA asked that the CFTC evaluate the clearing price of natural gas before, during, and after the cold weather event to determine if prices charged during the period would be considered price gouging or an unfair act and, if so, identify the recipients of unfairly gotten gains in addition to seeking remedies for those negatively impacted.

APGA and APPA noted that their members are locally owned and governed. “They are accountable to their customers, not corporate boards or investors — community support, affordability, and quality service are mandates for these utilities, and they plan accordingly.“

The prices experienced by APPA and APGA members during this event “were unforeseeable, even with such careful planning. Our members are also uniquely concerned with how the market reacted in this emergency because publicly-owned utilities’ rates are set at the local level. Consequently, we believe an objective investigation is warranted.”

The letter was signed by APPA President and CEO Joy Ditto and APGA President and CEO Dave Schryver.

Chelan PUD outlines potential new approach to energy sales contracts

March 23, 2021

by APPA News
March 23, 2021

Washington State’s Chelan PUD is evaluating its strategies to sell carbon-free, surplus power as long-term energy output contracts expire over the next decade.

Chelan PUD General Manager Steve Wright on March 15 presented a plan that would support more economic growth locally, while also allowing the PUD to capitalize on favorable market conditions, the PUD said.

“With the current long-term market, we’re seeing the opportunity to create revenue that could lead to rate stability for our customer-owners,” Wright said. “We believe the market sees value now in renewable hydropower that can support carbon emission reduction goals.”

Chelan PUD said that its revenue from wholesale purchasers is the reason its customer-owners enjoy some of the lowest rates in the nation, noting that it produces more than enough power to meet local demand for electricity.

“We are heavily dependent on these revenues to maintain the low rates in Chelan County,” Wright said.

Chelan PUD currently sells the energy it produces based on a formula roughly calculated as 50-30-20:

50% is sold at wholesale as cost-of-production based, long-term slice of the hydroelectric contracts, including an Alcoa contract that expires in 2028, and Puget Sound Energy which expires in 2031;
30% is sold at wholesale in market-based, 5- to 10-year slices of the hydro system;
20% is used to serve customer-owners (residential, commercial and industrial) in Chelan County.

Wright proposed that commissioners consider a new formula that retains the basic structure for wholesale transactions while creating room for local loads to grow over time.

Specifically, 40-50% would be sold as long-term slice contracts based on cost of operations and the value of hydroelectricity. These contracts could serve customers outside Chelan County, or new large-load customers in Chelan County.

Under the proposal, 20-30% of energy would be sold in fixed-price, market-based contracts over 5 to 10 years. This amount may be reduced over time to serve unanticipated local load growth.

In addition, 20-30% would be used to serve local customer-owners as local load growth occurs.

Chelan PUD Commissioners will consider the proposal over the next month.

FERC affirms small utility opt-in element of DER aggregation order backed by APPA

March 22, 2021

by Paul Ciampoli
APPA News Director
March 22, 2021

The Federal Energy Regulatory Commission recently issued an order affirming the small utility opt-in feature supported by the American Public Power Association of a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets.

At the same time, contrary to APPA’s position, FERC found that demand response resources participating in aggregations with other types of DERs are not subject to the state and local regulator opt-out/opt-in framework that FERC adopted for demand response aggregations in Order Nos. 719 and 719-A.

At its monthly open meeting, FERC issued an order (2222-A) that responded to requests for rehearing and clarification of FERC Order No. 2222, which addresses the participation of distributed energy resource (DER) aggregations in markets administered by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs). FERC approved Order 2222 in September 2020.

In November 2020, APPA and the National Rural Electric Cooperative Association urged FERC to reject objections to a small utility “opt in” mechanism that the Commission adopted in Order No. 2222, a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets. In addition, APPA and NRECA said that FERC should not carve out an exception to the small utility opt-in for energy efficiency resources.

In Order No. 2222-A, FERC considered requests for rehearing and clarification of FERC Order No. 2222.

Among the important features of Order No. 2222, FERC provided an “opt-in” mechanism for small distribution utilities — including most public power utilities.

Specifically, the Commission determined that customers of utilities that distributed 4 million MWh or less in the previous fiscal year may not participate in distributed energy resource aggregations unless the relevant electric retail regulatory authority affirmatively allows such customers to participate in distributed energy resource aggregations. The small utility opt-in mechanism was supported by APPA, and FERC affirmed it in Order No. 2222-A.

Order No. 2222-A also addresses the participation of demand response resources in DER aggregations.

Under regulations adopted in 2008-2009 in FERC Order Nos. 719 and 719-A, an ISO or RTO may not accept bids from a demand response aggregator of retail customers served by utilities that distributed more than 4 million MWh in the previous year if the relevant electric retail regulatory authority (RERRA) affirmatively prohibits wholesale market participation (opt-out).

In the case of customers served by utilities that distribute 4 million MWhs or less, the ISO/RTO may not accept bids from an aggregator unless the RERRA affirmatively permits it (opt-in).

In Order No. 2222, FERC said that demand response resources seeking to participate in DER aggregations would still be subject to the opt-out/opt-in regulations. FERC modifies this ruling in Order No. 2222-A, concluding that the opt-out/opt-in rules ordinarily applicable to demand response resources would apply only “to aggregations made up solely of resources that participate as demand response resources, consistent with our regulations.”

The opt-out/opt-in rules will not apply “to demand response resources that participate in heterogeneous distributed energy resource aggregations—i.e., those that are made up of different types of resources including demand response as opposed to those made up solely of demand response.”

Order No. 2222-A clarifies a number of other aspects of FERC’s DER aggregation rules, including jurisdiction over interconnection of PURPA QFs and various implementation issues.

The revisions take effect 60 days after publication in the Federal Register.

Danly, Christie offer dissents

Commissioner James Danly and Commissioner Mark Christie offered dissents to the order.

For his part, Christie said FERC’s majority was doubling down “on siding with commercial interests seeking entry into the RTO/ISO markets and against the states and other authorities whose job is to defend the public, not private, interest. By doing so, the majority also sides against the consumers who for years to come will almost surely pay billions of dollars for grid expenditures likely to be rate-based in the name of ‘Order 2222 compliance.’” (Christie discusses Order No. 2222-A, among other topics, in the most recent episode of APPA’s Public Power Now podcast).

Instead of making the states, municipal and public power authorities and electric cooperatives “truly equal partners in managing the timing and conditions of deployment of behind-the-meter DERs in ways that are sensitive to local needs and challenges — both technical and economic — today’s order denies them any meaningful control by prohibiting any opt-out or opt-in options except in relatively tiny circumstances,” wrote Christie.

“This order — and its predecessor — intentionally seize from the states and other authorities their historic authority to balance the competing interests of deploying new technologies while maintaining grid reliability and protecting consumers from unaffordable costs,” he said.

A rapid concentration of behind-the-meter aggregated DERs at various locations on the local grid “will inevitably require costly upgrades to a distribution grid that has largely been engineered to deliver power from the substation to end-user retail customers. Meeting the technological challenges of this re-engineering of the local grid are not insuperable but there are substantial costs and we all know these costs will ultimately be imposed on retail consumers. States, public power authorities and cooperatives are far better positioned to manage these costs and competing interests in their own areas of responsibility than FERC,” Christie said.

Moreover, he argued that Order No. 2222-A is not “cooperative federalism,” but rather its opposite. “It undermines the overarching policy framework that Congress incorporated into the Federal Power Act decades ago: federal regulation of wholesale rates and the bulk power system; state regulation of retail rates and the local distribution grid,” he wrote in the dissent.

“Any argument that allowing state policies to determine the entry of aggregated DERS into capacity or other markets will result in a ‘checkerboard’ or ‘patchwork’ of different policies, is an argument against state authority itself. The existence of fifty states by definition means a patchwork of 50 state retail regulatory structures, but that goes with the territory in our constitutional structure and is entirely consistent with the Federal Power Act’s basic division of federal and state authority. This panoply of diverse state policies is exactly what Justice Brandeis celebrated when he recognized states as laboratories of democracy.”

While encouraging the development of DERs “is a good thing, eviscerating the states’ historic authority in the name of encouraging DER development is not,” Christie said.

“On the contrary, it is the states and other local authorities that are far better positioned than FERC to manage successfully the development and deployment of DERs in ways that serve reliability needs, that protect consumers from inflated costs, and that are far more sustainable in the long run.”

For his part, Danly said he was “dissenting from this order on rehearing of Order No. 2222, the Commission’s distributed energy resource aggregations mandate, for the same reasons that I dissented from the original. It oversteps the reasonable exercise of the Commission’s authority at the expense of the states.”

Danly acknowledged the recent cases upon which the Commission relies to exercise its jurisdiction in the order, “but these cases concerned whether the Commission possesses claimed authority, reserving the question of whether the Commission has discretion to exercise it. Clearly the Commission has the power, exclusive jurisdiction or not, to establish a state opt-out.”

He would “decline to exercise our jurisdiction to obstruct the states from asserting authority over distributed energy resource aggregations. The Commission owes fidelity to the clear division of jurisdiction between the federal government and the states, a due regard for federalism that is embedded in the very structure of the Federal Power Act. This order unnecessarily invades an area best left to the states, burdening them with another of our Good Ideas, the details of which we leave them to figure out, and the burdens of which we leave to them to bear.”

FERC issues NOI

In related action, FERC on March 18 also issued a notice of inquiry on the potential impacts of eliminating the ability of states to prevent demand response resources from participating in organized wholesale markets.

FERC is asking whether the circumstances relevant to this demand response opt-out have changed since the opt-out was established in Order Nos. 719 and 719-A, and what are the potential benefits or burdens of removing it.

Comments are due 90 days after publication in the Federal Register, with reply comments due 30 days after that.

Glick

In comments at the Commission meeting, FERC Chairman Richard Glick praised Order No. 2222-A as a further improvement to the rules adopted in Order No. 2222.

“By allowing demand response providers located in states that have opted out of Order No. 719 to participate as part of a DER aggregation as long as other DER technologies are included in the aggregation, the Commission is further expanding our opportunities for DER aggregation in our wholesale markets,” he said at the meeting.

With respect to the NOI, “a lot has changed” since Order No. 719 was first issued “and I think it is prudent for us to reconsider whether the opt out remains appropriate,” he said.

“I recognize that certain state regulators have been frustrated with the” approaches FERC has taken over the last several years, specifically in Order No. 841, which dealt with energy storage, and Order No. 2222.

“With regards to the potential participation of behind-the-meter resources in RTO and ISO wholesale markets, it is not a simple matter,” Glick said. “FERC has the duty pursuant to the Federal Power Act to eliminate undue discrimination in terms of access to jurisdictional wholesale markets. The states have a legitimate interest in ensuring the reliability of their distribution systems.”

Some are concerned that the participation of behind-the-meter resources in wholesale markets will make it more difficult for the states to address distribution reliability, Glick said.

In his view, the states still retain important tools such as jurisdiction over DER interconnections and the ability to condition DER participation in retail markets in a manner that ensures DER participation in wholesale markets won’t impair reliability.

“But we need to continue this dialogue with our state colleagues, which I am very much committed to doing,” he said. “This Commission over the last several years has run roughshod over the states’ responsibilities over resource decision making all in an effort to raise prices in mandatory capacity markets.”

In his comments at the meeting, Commissioner Christie said that if he were to describe the order in one word it would be hubris. “It’s based on the belief that the members of this Commission know better how to manage the complicated issues of timing, grid reliability and the costs of behind-the-meter DER deployment than all the state regulators in all the fifty states who, by the way, are tasked with defending the public interest just like we are here at FERC. Better than all the dedicated people who run the public power and the municipal power authorities. Better than all the dedicated people who run the electric coops do,” he said.

“And it’s based on the false belief that state regulators, public power authorities, municipal power authorities and coops are opposed to behind-the-meter DER deployment, and so these people can’t be trusted to manage the deployment of DER deployment and I know that’s just not true,” Christie said.

“States have been dealing with these issues for years and taking the lead in DER deployment. So have the munis, so have the public power authorities, so have the coops,” he said.

“Consumers are going to pay a lot for this,” Christie said.

Investor-owned utilities are “going to seek to put billions of dollars into rate base and the argument to the state regulators will be, oh, we have to do this to comply with FERC’s Order 2222 and so you state regulators have to approve it. And as a former state regulator who sat on a lot of rate cases, I’ve heard this argument before and it’s very hard – frankly it’s almost impossible – for a state regulator to deny cost recovery when the utility says we have to spend this money to comply with federal regulations. That’s a very hard argument to rebut and so the costs of this are going to be substantial.”

Prior to becoming a FERC Commissioner, Christie served as a Chairman and Commissioner with the Virginia State Corporation Commission.

FERC directs revisions to market power mitigation in PJM capacity market

March 22, 2021

by Paul Ciampoli
APPA News Director
March 22, 2021

The Federal Energy Regulatory Commission on March 18 told the PJM Interconnection, its market monitor and market participants in the region that the existing default market seller offer cap fails to allow for adequate review of potential market power concerns in the capacity market, because it is based on an unreasonable expectation of the number of performance assessment intervals PJM will experience in a given delivery year.

The Commission directed parties to propose alternative methods for market power review and mitigation in the capacity market.

FERC’s order stems from two complaints filed in 2019 by the market monitor and consumer advocate groups in the region, alleging that PJM’s calculation of the default market seller offer cap in the capacity market is unjust and unreasonable.

The complaints were supported by the American Public Power Association.

The default market seller offer cap originally was established as part of PJM’s 2015 capacity performance construct, in response to the 2014 polar vortex.

FERC found PJM’s existing rate unjust and unreasonable, but said it needs additional evidence to set the appropriate replacement rate and therefore ordered additional briefing.

FERC’s action on the complaints will not interfere with PJM’s upcoming May 2021 capacity auction for delivery year 2022-2023, FERC said. The auction should take place as scheduled under current rules.

FERC noted that it will continue to exercise its oversight of the upcoming auction and any anticompetitive conduct observed may be referred to the Office of Enforcement.

The order is available here.

Bitcoin mining operation to add flexible load to NPPD’s area

March 17, 2021

by Peter Maloney
APPA News
March 17, 2021

Compute North is expanding its operations in Kearney, Nebraska, potentially adding as much as 70 megawatts (MW) to Nebraska Public Power District’s (NPPD) load.

The Eden Prairie, Minn.-based company, which provides energy-intensive computing capacity for blockchain, cryptocurrency mining, and other clients with high-performance computing needs, already has a 30-MW computing facility in Kearney’s Tech oNE Crossing technology park.

The expansion deal has been in the works for a little over a year, and “it’s finally coming to fruition,” Pat Hanrahan, general manager of NPPD’s retail division, said. “It is pretty exciting.”

Compute North said it chose the Kearney location for its “direct access to a variety of primarily renewable energy sources.” Nebraska, the only state in the union that is served entirely by public power, gets about 61 percent of its electric power from carbon dioxide free sources.

Another part of the attraction are the electric rates NPPD can offer, Hanrahan said. Nebraska has below average electric rates, ranking 15 in the nation, according to government data. NPPD also has economic development rates for new customers and other rate products that make the area “pretty attractive,” Hanrahan said.

The deal to expand Compute North’s operations was also facilitated by support from the Economic Development Council of Buffalo County – Kearney is the county seat – and the City of Kearney, and the Nebraska Department of Economic Development.

Bitcoin, or cryptocurrency, consumes huge amounts of energy to run specialized computers that perform complex calculations that are used to generate new bitcoins for “miners,” making energy costs a key consideration is deciding where to locate a mining operation.

Interest in cryptocurrencies, like bitcoin, and the mining operations that expand the supply of cryptocurrencies often surges when prices rise. Bitcoin prices right now are booming, recently hitting about $56,700 for a single bitcoin and marking a quadrupling of prices since late 2020.

Compute North, which also has data processing centers in Texas and South Dakota, said it anticipates the expanded Kearney facility will “fill up quickly,” and noted several new customers for its services, including Foundry Digital LLC, Bit Digital Inc., and “several other emerging players in the bitcoin mining space.”

The volatility of cryptocurrencies was a concern initially, said Hanrahan, but Compute North is “putting in a significant investment to be here. It really is a partnership.”

Hanrahan said NPPD would have to build a new substation to serve the expanded load from the industrial park, but the utility has worked out commitments from Compute North to cover those costs.

In addition to the shear size of the planned expansion, another attraction of the new Compute North is that the load is interruptible. Cryptocurrency mining is usually an around-the-clock operation, but miners have the ability to suspend operations depending on prices and conditions on the electric grid.

An increase in renewable generation on the grid is creating a desire to have more flexible generation, but another way of looking at it is having load that is flexible on the other side, Hanrahan said. “It offers more opportunities to respond and to take advantage of market conditions,” he said.

“NPPD is pleased to see Compute North grow in Kearney, where they can take advantage of our low costs and reliable service. “We too look forward to working with Compute North in meeting their needs for renewable energy, while also looking at how we can both benefit from their flexible demand for power,” Tom Kent, president and CEO of NPPD, said in a statement.

Western EIM governing body adopts initiatives for summer reliability

March 13, 2021

by Paul Ciampoli
APPA News Director
March 13, 2021

The Western Energy Imbalance Market (EIM) governing body on March 10 unanimously approved market and operational enhancements for Western EIM entities participating in the California Independent System Operator’s (CAISO) real-time energy market.

The enhancements are intended to help maintain grid reliability this summer.

CAISO said the governing body’s decision will improve the resource sufficiency evaluation to ensure each balancing authority area participates in the Western EIM with the necessary resources and enhance real-time energy market models to provide better operational coordination among balancing authority areas in the Western EIM.

These items will be on the ISO Board of Governors’ next meeting agenda.

Additionally, the Western EIM Governing Body provided, in its advisory capacity, support for a market-pricing enhancement for contingency reserves that will strengthen incentives during tight supply conditions.

This item requires the approval of the ISO Board of Governors, which is scheduled to consider it and other Market Enhancements for Summer 2021 Readiness initiatives later this month.

The Western EIM governing body’s action is the first of several improvements identified by the ISO to be better prepared for summer following the extreme heat event that enveloped California and the West in August 2020.

The final root cause analysis published in January 2021 found that extreme heat, resource adequacy deficiencies, and planning and market processes that were not designed to fully address an extreme heat storm contributed to rotating outages for two days in August 2020.

CAISO President and CEO Elliot Mainzer discussed the grid operator’s plans for this summer in a recent APPA Public Power Now podcast episode.

The Western EIM governing body oversees the Western EIM, an energy market comprised of 11 balancing authorities in eight states.

By 2023, 22 active Western EIM participants will represent over 83 percent of load within the Western Electricity Coordinating Council footprint.

Governor declares correction of any billing errors tied to ERCOT as legislative emergency item

March 10, 2021

by Paul Ciampoli
APPA News Director
March 10, 2021

Texas Gov. Greg Abbott on March 9 declared the correction of any billing errors related to the Electric Reliability Council of Texas (ERCOT) as an emergency item for the current legislative session in the state.

The emergency item includes any inaccurate excessive charges and any issues regarding ancillary service prices, Abbott’s office noted.

The Public Utility Commission of Texas (PUCT) recently declined to take action in response to a report from the independent market monitor (IMM) for ERCOT that a decision by ERCOT last month resulted in $16 billion in additional costs to ERCOT’s market, of which roughly $1.5 billion was billed to load-serving entities (LSEs) to provide make-whole payments to generators for energy that was not needed or produced.

The decision in question was made by ERCOT as the grid operator grappled with extreme stress on the state power grid in the wake of an arctic blast.

Texas Lt. Governor calls for correction to $16 billion error

In related news, Texas Lt. Gov. Dan Patrick on March 8 called on the PUCT and ERCOT to correct the emergency pricing error.

Patrick said that ERCOT has a procedure for correcting pricing errors but has declined to act so far.

“According to the ERCOT Nodal Protocol Section 6.3 (6) (a), ERCOT has 30 days from the event to correct errors in pricing. Today I am calling on both the PUC and ERCOT to follow the recommendations of the IMM and correct these mistakes,” he said. “Correcting this $16 billion error will require an adjustment, but it is the right thing to do. It will ultimately benefit consumers and is one important step we can take now to begin to fix what went wrong in the storm.”

Texas House members unveil series of bills in wake of power outage hearings

Meanwhile, Texas House Speaker Dade Phelan on March 8 unveiled the first phase of House legislative reforms in the wake of recent hearings in the Texas Legislature that examined rotating outages implemented by ERCOT in February after an arctic blast hit the state.

Energy storage deployments had a record fourth quarter

March 10, 2021

by APPA News
March 10, 2021

The United States set a new record for energy storage deployments in the fourth quarter, according to the just released U.S. Energy Storage Monitor from Wood Mackenzie and the U.S. Energy Storage Association.

A total of 2,156 megawatt-hours (MWh) of new energy storage capacity came online in fourth-quarter 2020, a 182 percent increase from third-quarter 2020, and a new quarterly record, according to the report’s authors.

Energy storage deployments also set a record in the fourth quarter in terms of power rating, that is, how much power can flow in or out of a battery at any instant.

Energy storage deployments reached 651.2 megawatts (MW), a 37 percent increase from third-quarter 2020 to fourth-quarter 2020, and 3.5 times increase from fourth-quarter 2019.

The report attributed most of the increase to two storage projects in California installed as four-hour capacity resources and totaling 400 MW.

The authors of the report also noted the prominent role front-of-the-meter (FTM) projects had in the surge in energy storage deployments. Four out of every five megawatts deployed in the fourth quarter were in front of the meter, contributing 529 MW out of the 651 MW of deployed in the quarter, they said.

Residential storage deployments also had a strong showing, with 90.1 MW installed in the fourth quarter, setting a new quarterly record and representing a 73 percent increase over the previous quarter. Residential deployments accounted for 14 percent of the storage projects deployed in the fourth quarter. The rise in residential storage deployments was driven in large part by homeowner interest in California, the report’s authors said.

The non-residential storage sector is growing more slowly, however, deploying only 76.5 MW in the fourth quarter, a 13 percent increase from the previous quarter. The relatively weaker showing of non-residential installations was partly the result of a project slowdown as a result of COVID-19 restrictions, the report said.

“The data truly speaks for itself,” Dan Finn-Foley, head of energy storage at Wood Mackenzie, said in a statement. “The US installed 3,115 MWh of storage from 2013 through 2019, a total that 2020 beat in a single year. This is the hallmark of a market beginning to accelerate exponentially, and momentum will only increase over the coming years,” he said.

For the full year, a total of 1,464 MW, 3,487 MWh of new energy storage projects came online in 2020, a 179 percent increase in megawatt terms over storage additions in 2019.

The “ability of solar-plus-storage to provide backup is increasingly driving sales even in markets without additional incentives, particularly states that suffer from regular power outages. We expect an uptick in home battery sales in Texas in the aftermath of February’s devastating outages,” Chloe Holden, Wood Mackenzie research analyst, said in a statement.

Looking ahead, the report’s authors expect the U.S. energy storage market will add five times more megawatts of storage in 2025 than was added in 2020, with FTM storage continuing to contribute between 75 percent and 85 percent of the new additions each year.

“2020 is the first year that advanced energy storage deployments surpassed gigawatt scale – a tremendous milestone on the path to our aspiration of 100 GW by 2030,” Jason Burwen, U.S. Energy Storage Association’s Interim CEO, said in a statement.

Texas House members unveil series of bills in wake of power outage hearings

March 9, 2021

by Paul Ciampoli
APPA News Director
March 9, 2021

Texas House Speaker Dade Phelan on March 8 unveiled the first phase of House legislative reforms in the wake of recent hearings in the Texas Legislature that examined rotating outages implemented by the Electric Reliability Council of Texas (ERCOT) in February after an arctic blast hit the state.

Members of the Texas House have filed or will file the following legislation:

Reforming Electric Reliability Council of Texas Leadership: HB 10 restructures the ERCOT board, replacing the unaffiliated members with members appointed by the Governor, Lt. Governor, and Speaker of the House. HB 10 also requires all board members to reside in the state of Texas and creates an additional ERCOT board member slot to represent consumer interests.

Protecting Consumers and Hardening Facilities for Extreme Weather: HB 11 requires electric transmission and generation facilities in the state to be weatherized against the spectrum of extreme weather Texas may face. Utilities will be required to reconnect service as soon as possible and prevent slower reconnections for low-income areas, rural Texas, and small communities, Phelan’s office said.

Alerting Texans During Emergencies: HB 12 creates a statewide disaster alert system administered by Texas Division of Emergency Management (TDEM) to alert Texans across the state about impending disasters and extreme weather events. The alerts will also provide targeted information on extended power outages to the state’s regions most affected. This system builds off the model used in Amber, Silver, and Blue Alert systems.

Improving Coordination During Disasters: HB 13 establishes a council composed of ERCOT, Public Utility Commission of Texas, Railroad Commission, and TDEM leaders to coordinate during a disaster. The committee will identify challenges with fuel supplies, repairs, energy operations and prevent service interruptions from the wellhead to the consumer.

Weatherizing Natural Gas Infrastructure: HB 14 requires the Railroad Commission to adopt rules requiring gas pipeline operators to implement measures that ensure service quality and reliability during an extreme weather emergency, which covers winter and heat wave conditions.

Defending Ratepayers: HB 16 bans variable rate products for residential customers. These types of speculative plans resulted in exorbitant bills. “This bill will provide consumer protection to residential customers while still allowing the competitive market to flourish,” Phelan’s office said.

Protecting Homeowner Rights: HB 17 prevents any political subdivision or planning authority from adopting or enforcing an ordinance, regulation, code, or policy that would prohibit the connection of residential or commercial buildings to specific infrastructure based on the type or source of energy that will be delivered to the end user.

Texas lawmakers hold series of hearings over recent power outages

Texas lawmakers in early March held a series of hearings tied to ERCOT last month entering emergency conditions and initiating rotating outages in the state in the wake of an arctic blast.

Texas Lt. Governor says there may be a move to make ERCOT a state agency

March 9, 2021

by Paul Ciampoli
APPA News Director
March 9, 2021

In the wake of rotating outages implemented by the Electric Reliability Council of Texas (ERCOT) in February after an arctic blast hit the state, there may be a move to turn ERCOT into a state agency, Texas Lt. Gov. Dan Patrick recently said.

In an interview with a local Texas television show, Patrick was asked whether he thinks ERCOT should be “brought back into the fold” as a state agency. ERCOT is a membership-based 501(c)(4) nonprofit corporation, governed by a board of directors and subject to oversight by the Public Utility Commission of Texas and the Texas Legislature.

“I don’t have that answer today,” Patrick said. “I’m starting with a clean sheet of paper. I’m starting from scratch and if that needs to happen then it should happen.”

ERCOT is a “private company that was basically hired by the PUC to” run the grid, he said. “But we as elected officials are held responsible for those actions. I don’t like being held responsible to a company that I have little to no control over,” Patrick said.

“I think that we may see a move to bring ERCOT back in as a state agency or if it’s still a private company, we’ll have many more controls including who sits on the board because we want to know who those people are,” he said.

Patrick calls for correction to $16 billion error

Meanwhile, Patrick on March 8 called on the Public Utilities Commission of Texas (PUCT) and ERCOT to correct the emergency pricing error that continued after the power shortage had ended and the major threat to the Texas grid had passed.

Patrick noted that in response to grid wide power shortages starting February 15, the PUC ordered ERCOT to institute the $9,000 per megawatt hour cost cap, which is designed to encourage increased power generation during an extreme shortage.

However, according to ERCOT’s Independent Market Monitor (IMM), Potomac Economics, ERCOT incorrectly extended that pricing intervention after the power shortage had ended. The $9,000 price should have ended at 11:55 PM on February 17. Instead, it continued throughout the entire day of February 18 into February 19th — 32 hours total – which resulted in an additional $16 billion in charges, Patrick said.

“The IMM identified a second significant error that also must be corrected immediately. ERCOT failed to cap ancillary service prices at $9,000 which resulted in prices rising as high as $24,000 a megawatt hour at intervals during the storm. Pricing should never have exceeded the $9,000 cap at any time,” he said in a news release.

The IMM has recommended that the PUCT exercise their authority to direct ERCOT to correct both these pricing errors, but the PUCT has declined to do so, Patrick noted.

The PUCT on March 5 declined to take action in response to a report from the IMM for ERCOT that a decision by ERCOT resulted in $16 billion in additional costs to ERCOT’s market, of which roughly $1.5 billion was billed to load-serving entities (LSEs) to provide make-whole payments to generators for energy that was not needed or produced.

Patrick also said that ERCOT has a procedure for correcting pricing errors, but has also declined to act so far.

PUC Commissioner resigns

In other news, PUC Commissioner Shelly Botkinhas resigned her role with the PUCT, effective immediately, the Commission said on March 8.

DeAnn Walker on March 1 resigned as chairwoman of the PUCT, days after she faced questions from state lawmakers at a hearing that examined the rotating outages implemented by ERCOT in the wake of an arctic blast.

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