NYPA Resumes Work On Projects That Were Suspended Due To Pandemic
June 17, 2020
by Paul Ciampoli
APPA News Director
Posted June 17, 2020
The New York Power Authority has resumed work on certain projects that were suspended so that the Authority could focus on the continued safe operation of its power plants and transmission system in response to the COVID-19 pandemic.
Several large NYPA projects were underway when New York Gov. Andrew Cuomo announced New York PAUSE as the COVID virus began to appear in New York State.
At that time, NYPA suspended various types of non-critical repair work and capital project work and focused on the continued safe operation of its power plants and transmission system.
NYPA recently reported that several of its North Country projects are in various stages of restarting.
The Authority has restarted work on a vital transmission infrastructure project to rebuild and strengthen the Moses-Adirondack transmission lines, an 86-mile line running North-South through St. Lawrence and Lewis Counties in the North Country.
The project, known as the Moses-Adirondack Smart Path Reliability Project, supports Cuomo’s plan to modernize New York’s energy system.
NYPA has also restarted work on a project to restore a small hydroelectric power plant that feeds power to the Village of Potsdam.
NYPA is providing approximately $4 million in financing and technical assistance to the village for the overhaul and upgrade of their hydro facility, which is expected to be back in service by the end of the year.
NYPA has also resumed work on a $5.6 million concrete rehabilitation project at the Massena Intake. The project consists of replacing the concrete roadway deck and sidewalks and the installation of a railing system.
Meanwhile, NYPA has set a target date of mid-July to restart work on its North Country Battery Storage Project.
NYPA will resume work shortly on a $29.8 million, 20-megawatt battery storage demonstration facility adjacent to an existing substation in Franklin County.
The project, which is anticipated to be in service by the end of the year, supports the state’s nation-leading 3,000 MW by 2030 storage goal.
NYPA is continuing to take proactive measures to guard against COVID-19
NYPA noted that it is continuing to take proactive measures to protect the health of its employees, and communities in which it operates, by limiting situations in the virus can be transmitted.
Employees are surveyed daily for wellness and are asked to stay home if they are displaying signs of illness.
Health checks require both NYPA employees and contractors to answer questions regarding themselves and their families, related to physical symptoms associated with COVID. Depending on the work situation, additional personal protective equipment will be worn as warranted for the health and safety of its workers, customers and the general public.
Through an Incident Command Structure, NYPA continues to monitor the pandemic and will make adjustments to these precautions as necessary.
Platte River Power Authority To Retire Coal-Fired Unit 16 Years Ahead of Schedule
June 17, 2020
by Paul Ciampoli
APPA News Director
Posted June 17, 2020
The Platte River Power Authority on June 16 said that its coal-fired Rawhide Unit 1 generating resource will cease producing electricity by 2030, 16 years before its planned retirement date.
Platte River’s board approved a resource diversification policy in December 2018, which calls for a 100% noncarbon energy mix by 2030, and planners immediately began studying future energy mix options without the use of the 280 MW coal-fired unit as part of its integrated resource planning process.
While the IRP is currently on hold until public meetings and stakeholder engagement resumes, Platte River’s leadership needed to announce Unit 1’s retirement to support state regulatory timelines that align with the broader objectives for a noncarbon future, Platte River said.
Platte River is a not-for-profit wholesale electricity generation and transmission provider that delivers energy and services to its owner communities of Estes Park, Fort Collins, Longmont and Loveland, Colorado for delivery to their utility customers.
The last IRP that Platte River completed in 2016 did not call for additional generating capacity. Platte River nevertheless added 30 MW of new solar energy, studied the feasibility of a zero-net carbon energy mix, signed a power purchase agreement (PPA) for an additional 150 MW of wind power and later increased the amount to 225 MW, and will soon add 22 MW of additional solar power with 2 MWh of battery capacity.
It is currently negotiating another PPA for up to 150 MW of new solar generation.
Platte River noted that Rawhide Unit 1 has earned national recognition for its reliability, capacity and environmental performance. Throughout its life, Unit 1 has operated with an equivalent availability factor of 97.28%, running thousands of hours between planned or unplanned outages, delivering energy up to its nameplate capacity. When built, the unit featured state-of-the art emissions controls that most plants were not required to have and more were added before regulatory mandates.
From the beginning, Unit 1 provided more than half of the energy needs for Platte River’s owner communities, supplemented by federal hydropower contracts, natural gas resources, market purchases, wind and solar resources.
By the end of 2020, more than 50% of the energy delivered by Platte River will come from noncarbon resources including wind, solar and hydro facilities, and Platte River continues to take steps needed to achieve its 100% noncarbon goal.
In addition to Unit 1, the 4,560-acre Rawhide Energy Station also hosts five natural gas combustion turbines and a 30 MW solar farm, along with another 22 MW of solar power (with battery storage) currently under construction.
Energy from the 225 MW Roundhouse wind farm located in southern Wyoming will be delivered to the Rawhide Energy Station and then to Platte River’s owner communities.
Platte River’s ownership interest in the Craig station will also conclude when Unit 1 is retired in 2025 and Unit 2 follows, thereby ending the use of all coal-fired generating capacity by 2030.
The Rawhide Energy Station has multiple generation resources, and workers will be needed for those facilities, Platte River noted.
Jason Frisbie, general manager and CEO of Platte River, said that plans will be developed to smoothly transition workers to new roles after closure.
Following its retirement, Unit 1 will undergo a lengthy decommissioning process.
APPA Urges FERC To Dismiss Petition Tied To Net Metering Jurisdiction
June 17, 2020
by Paul Ciampoli
APPA News Director
Posted June 17, 2020
The Federal Energy Regulatory Commission should dismiss a petition asking it to find that it has jurisdiction over energy sales from rooftop solar facilities and other distributed generation located on the customer side of the retail meter whenever the output of these resources exceeds the customer’s demand, the American Public Power Association said on June 15.
Granting the petition could jeopardize public power net metering programs and render the distributed generation output of hundreds of thousands of public power utility customers subject to federal regulation, APPA said in its protest (Docket No. EL20-42-000).
Moreover, the petition for a declaratory order submitted by the New England Ratepayers Association (NERA) in April should be dismissed because it does not present an appropriate case for a declaratory ruling, APPA said, noting that FERC’s policy with respect to authority over retail net metering programs has been well-settled for years.
NERA is seeking a declaratory order that there is exclusive federal jurisdiction over energy sales from distributed generation located on the customer side of the retail meter whenever the output exceeds the customer’s demand or the energy from such a generator is designed to bypass the customer’s load.
The petition argues that a wholesale sale occurs when the output from behind-the-meter generation exceeds demand, and the rates for such sales must be priced in accordance with section 210 of the Public Utility Regulatory Policies Act (PURPA), or sections 205 and 206 of the Federal Power Act (FPA), as applicable.
NERA also asks the Commission to “find unlawful, and therefore reject, state net metering laws which assert jurisdiction over such wholesale sales and establish a price in excess of what PURPA or the FPA allows for wholesale sales subject to this Commission’s exclusive jurisdiction.”
Public power net metering programs could be jeopardized
APPA noted hundreds of self-regulated public power utilities across the country accommodate their customers’ behind-the-meter resources through retail net metering programs.
Local control over these programs allows public power utilities to structure retail net metering approaches that respond to the policy preferences of their states and local communities, while seeking to ensure that the costs and benefits associated with distributed generation deployment are appropriately reflected in retail rates.
“Although the petition does not specifically address the use of net metering by public power utilities, the declarations requested by NERA, if granted, could jeopardize public power net metering programs in addition to the state laws that NERA asks the Commission to ‘reject,’” APPA said.
Granting the petition could render the distributed generation output of hundreds of thousands of public power utility customers subject to federal regulation, under the FPA or PURPA, APPA told FERC.
APPA urges FERC to dismiss petition
FERC should dismiss the petition without reaching the merits, APPA argued, saying that the matters on which NERA seeks a declaratory order are neither the source of controversy nor uncertainty.
It pointed out that the Commission’s policy with respect to authority over retail net metering programs has been well-settled for years, and was recently reaffirmed in FERC Order Nos. 841 and 841-A, relating to storage resources.
“Granting the petition and upsetting the regulatory certainty that the Commission has fostered would be a recipe for creating, not terminating, controversy and regulatory uncertainty. The petition is potentially sweeping in scope and broadly applicable, yet it is not grounded in any concrete proposal or specific facts and circumstances, nor does the petition include sufficient information for the Commission to analyze and address the requested declarations,” APPA said.
Referring to criticisms leveled at net metering by the NERA petition, APPA agreed that there are legitimate policy issues associated with the practice, including cost allocation and cross-subsidization concerns arising from net metering’s impact on recovery of a utility’s fixed costs. APPA said it “recognizes that it is important that all distributed generation customers pay a fair share of the costs of keeping the grid operating safely and reliably, recognizing the benefits provided by those customers.” APPA argued, however, that these are issues that state and local regulators can address.
If FERC does not dismiss the petition outright, it should deny the declarations requested by NERA and reaffirm that its jurisdiction under the FPA or PURPA is not implicated when a retail net metering customer is a net consumer of energy over the applicable billing period, APPA said.
“This policy appropriately acknowledges the authority of state and local regulators over the rates, terms and conditions of retail electric service,” APPA argued, adding that D.C. Circuit rulings cited by NERA do not require reconsideration of the Commission’s approach.
Moreover, the Commission’s policy is also in accord with a section of PURPA that requires state and local regulators to consider net metering programs for electric consumers, “a directive that is inconsistent with the notion that retail electricity delivered by the distribution utility cannot be netted against the energy generated by a retail customer’s distributed generation.”
APPA said that even if the Commission conceivably could conclude that retail net metering customers are making wholesale sales subject to federal regulation, “it is an entirely reasonable and legally permissible policy choice for the Commission to conclude that its jurisdiction is not implicated where a retail customer is a net purchaser of retail power over the applicable billing period.”
Public Power Executives Detail How Their Utilities Successfully Prepared And Adapted To Pandemic
June 16, 2020
by Paul Ciampoli
APPA News Director
Posted June 16, 2020
Leaders of public power utilities across the U.S. recently detailed how their utilities were prepared to successfully respond and adapt to a myriad of challenges presented by the COVID-19 pandemic.
They made their remarks on June 8 during a panel at the American Public Power Association’s Public Power Connect: Virtual Summit & Business Meeting that was moderated by Joy Ditto, President and CEO of APPA.
New York Power Authority President and CEO Gil Quiniones
The New York Power Authority’s experience with the pandemic started in January, said Gil Quiniones, President and CEO of NYPA.
He pointed out that it is not uncommon for NYPA to have employees travel to Asia and Europe doing factory acceptance testing and quality control of the equipment that the Authority purchases from these parts of the world. “Our employees actually gave us a heads up that there was this COVID in Asia and in Europe, so we brought them back right away” and quarantined them.
In February, NYPA refreshed its pandemic plan and its business continuity plans and stood up in the first working day of March its emergency operations center.
“Since then, we’ve made sure that we keep the health and safety of our employees” as a top priority, he said. NYPA pivoted to a work from home posture in early March “and also we made sure that we kept the lights on, that we would keep our generation and transmission going no matter what.”
The Authority paused all of its capital and O&M activities “and hunkered down” to make sure it knew what the situation was going forward before doing anything.
In addition, NYPA made sure that it had enough financial liquidity. In March, the Authority went to the markets and issued $1.2 billion of long-term bonds, of which $800 million were green bonds “to make sure that we can restart and hit the ground running when there’s better visibility,” Quiniones said.
In addition, NYPA sequestered around 85 employees — control room and transmission control operators – for 30 days at a time. “We did that for two months,” he noted.
“We have un-sequestered everyone at this point and we are now returning to work.” He said around 55 percent of NYPA workers are going back to work either full time or part time, while another approximately 44 percent of employees will continue to work from home.
From a broader leadership perspective, he said that “it is important for leaders to personally be the messengers in all matters affecting employees. I think that’s one thing that I learned in this crisis because our employees will remember how they were treated during this moment.”
Manitowoc Public Utilities General Manager Troy Adams
Troy Adams, who recently became general manager of Wisconsin public power utility Manitowoc Public Utilities, discussed the pandemic in the context of his time as general manager of Minnesota public power utility Elk River Municipal Utilities. Adams became general manager of Manitowoc Public Utilities at the start of June.
Regardless of size or location, “the way that public power leaders have handled this pandemic or any other issue is really very similar because our criteria for this decision making always comes back to our value system,” Adams said.
At Elk River, “we had the good fortune of just going through some business continuity planning,” he noted. In February, disaster planning training occurred, which utilized an APPA resource.
This was fortuitous timing, Adams said, “because my leadership team already was in the mindset of dealing with a problem when the pandemic came to us.”
In addition, Elk River Municipal Utilities has been a participant in APPA’s Reliable Public Power Provider (RP3) program.
Elk River Municipal Utilities “would not have been in the position it was in if we hadn’t been an RP3 utility,” he said. “Those best practices and those experiences and the exposure to other things outside of your city limits helped us to evolve into a better utility and we were in a great place to be able to address a pandemic or any other challenge.”
Also, the Minnesota public power utility had established a clear authority to act. When the pandemic hit, Elk River Municipal Utilities didn’t need to wait for board approval to take immediate action and the utility had reserve policies in place and sufficient funds. “We already knew we were in a position to be able to handle anything,” he said.
Meanwhile, Elk River Municipal Utilities prioritized the safety of employees and customers. Essential service and critical functions were areas that the utility had just looked at with its business continuity planning “and we were able to act pretty quickly to pivot and modify our plan to meet the needs for the pandemic.”
With respect to mitigation of risk and limiting COVID-19 exposure, employees that could work remotely did so, while “those that had to come in had to practice best practices and safe social distancing and use all the PPE.”
The utility staggered shifts and created a work environment “where they were better protected and able to minimize their contact with other employees, which helped protect them from maybe contracting anything, but also helped the utility” because if someone got sick, “you don’t have cross contamination or exposure through all your employee base.”
Responding to a question from Ditto on lessons learned from the pandemic, Adams said that “communication was really hard at first and if I had to do it all over again, I would have done more video.” Adams said he heard from employees that video “is a better way to engage them and they feel like you’re taking the time to do something special and communicate differently with them.”
City of Tallahassee Electric and Gas Utility General Manager Rob McGarrah
Rob McGarrah, general manager of the City of Tallahassee, Fla.’s Electric and Gas Utility, noted that early in the year, as the pandemic started to become an issue, “we took our storm plan and started making modifications to it to deal with COVID.”
When concerns were raised that Florida could be hard hit by the pandemic, the public power utility moved into a second stage of a preservation of staff plan.
Among other actions, the utility separated its system operators between the main control center and the backup control center.
In mid-March, the utility took shift workers at the utility’s two main power plants and at the control center and backup control center “and we took half of the team and we sequestered them on site and half the team shelter in place at home and we rotated those folks every week,” McGarrah said.
Since early May, the utility has unwound the sequestration and the sheltering at home, “so all of our field crews are back. Virtually all of our telework folks are still teleworking and I don’t expect that to change until later in the summer at the earliest.”
McGarrah noted that the utility has been hard at work the last few months “to start figuring out how we would manage a large-scale mutual aid event in Tallahassee if we needed to do it under the COVID work rules.”
The utility has been “working with our Florida partners through FMEA [Florida Municipal Electric Association] on how each of us would look at attacking a mutual aid event to make sure we’re all comfortable with how we would do housing, work rules, feeding and all of those things with a large mutual aid event.”
Debra Smith, General Manager/CEO, Seattle City Light
Debra Smith, General Manager and CEO at Seattle City Light, noted that Seattle was ground zero when the pandemic initially hit the U.S. earlier in the year.
In March, Washington State Gov. Jay Inslee issued a stay at home order. “We sent our employees home. At that point, many of them were already teleworking,” Smith said. “We went to what we call the continuity of operations plan.”
In terms of the utility’s operational response to the pandemic, Smith noted that 95 percent of Seattle City Light’s office workers have been teleworking for quite some time. The city has officially extended that through September 7. “I would expect that most of my employees will continue to telework through most of this year.”
As of June 17, City Light’s operations employees have returned to normal hours and staffing levels and are working through the backlog of customer service connections and utility maintenance and capital projects that were delayed due to reduced on-site/in-the-field staffing in response to the stay at home order.
Seattle City Light took the lead role in helping to develop the process for the city-wide continuity of operations plan. Smith has also participated in the process of bringing the city’s operations back to full force.
EIA Forecasts 2020 Summer Electricity Demand To Be The Lowest Since 2009
June 16, 2020
by Paul Ciampoli
APPA News Director
Posted June 16, 2020
The U.S. Energy Information Administration (EIA) on June 10 said it expects U.S. electricity demand to total 998 billion kilowatt hours this summer, the lowest level of summer electricity consumption in the United States since 2009 and 5% less than last summer.
EIA expects electricity consumption to be lower this year largely as a result of efforts to reduce the spread of COVID-19.
Most of the expected decline in retail electricity sales occurs in the commercial and industrial sectors, which EIA forecasts to be 12% and 9% less, respectively, than during summer 2019. EIA said it expects residential electricity sales to grow by 3% this summer because more people are working from home and following social distancing practices.
In its “Today in Energy” report, EIA noted that normally, weather is one of the primary factors in determining electricity demand in the residential and commercial sectors.
The National Oceanic and Atmospheric Administration (NOAA) is projecting that U.S. cooling degree days for June, July, and August 2020 will be 1% lower than last summer.
“This summer, however, other factors are affecting electricity demand more than temperature,” EIA said. “Although state and local governments are relaxing stay-at-home orders, social distancing guidelines will likely result in Americans spending more time at home than usual this summer. In addition, many people that had worked in offices are now working from home, shifting electricity demand from the commercial sector to the residential sector.”
EIA noted that macroeconomic indicators are primary drivers in its forecasts for electricity consumption in the commercial and industrial sectors.
EIA’s short-term economic assumptions are based on a macroeconomic model from IHS Markit. This model projects non-farm employment will fall by 13% in 2020 and that the electricity-weighted industrial production index will contract by 12% in 2020, EIA said.
Chelan County PUD Commissioners Hear Details on Plans To Boost Reliability
June 16, 2020
by Paul Ciampoli
APPA News Director
Posted June 16, 2020
Chelan County PUD commissioners on June 15 heard proposals from PUD staff to bring the utility to the top quartile of reliable electrical service, in line with other high-performing U.S. public power providers.
If approved in future budgets, the utility would make annual investments of an additional $2 million throughout its electrical system for a total of $4.3 million each year, the Washington State PUD noted.
Through these investments, PUD staff aim to reduce overall outages by an average of 36 minutes annually per customer, a reduction of 73 percent systemwide. The PUD is targeting meeting this goal by 2025.
By some measures, the PUD already is meeting top quartile performance and is now seeking to remove any doubts, Chelan said.
“In setting this goal, we looked at reliability metrics at some of the top performing electric utilities in the country, based on data from the American Public Power Association,” said Chad Rissman, director of district asset management.
Additional investments would be made in the areas of trimming vegetation around utility lines and replacing underground electrical cable. These investment areas deliver the most “bang for the buck,” according to Rissman.
“Providing benchmarking data to help with reliability efforts is a core element of what APPA offers to members such as Chelan,” said Alex Hofmann, Acting Vice President of Engineering Services at APPA. “Improving and maintaining reliability to keep the lights on longer in our communities is what public power is all about,” he said.
Chelan also plans to continue its commitment to improvements that reduce instances of animal-related outages and upgrade equipment such as fuses, transformers, insulators and other devices.
When looking at the largest causes of outages over the past five years, the PUD notes that 65 percent fell into the four areas where it’s proposing to make additional improvements or maintain its level of reliability work.
“If there’s a great place where we can put extra effort and provide benefits to the people of Chelan County, this is it,” said PUD Commissioner Randy Smith.
The PUD will revisit the proposed reliability investments during its budget process later this year.
Calif. CCA Group Concerned About Level Playing Field In Wake of Procurement Decision
June 15, 2020
by Paul Ciampoli
APPA News Director
Posted June 15, 2020
The California Community Choice Association (CalCCA), which represents community choice aggregators in the state, on June 11 expressed disappointment in a California Public Utilities Commission decision that designates Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) as central buyers to procure local, multi-year resource adequacy.
In the wake of the CPUC decision, CalCCA said it remains concerned “that the playing field will not be level under such a framework, nor will it be transparent and neutral.”
CalCCA said it continues to support the terms of a settlement agreement that would have established a residual central buyer framework, and put a competitively neutral, independent and creditworthy entity in the role of central buyer.
CalCCA and several energy market stakeholders — Calpine Corporation, Independent Energy Producers Association, Middle River Power, NRG Energy, Inc., investor-owned San Diego Gas & Electric Company (SDG&E), Shell Energy North America, and the Western Power Trading Forum — reached the settlement agreement last year.
The parties in August 2019 filed a joint motion for adoption of the settlement agreement with the CPUC.
CalCCA argued that the June 11 CPUC decision:
* Is a significant departure from the current framework for ensuring local reliability;
* Limits the scope of costs that CCAs can control for their customers;
* Will have a significant effect on the resource adequacy (RA) market, moving from a market with many buyers of local RA to one dominated by PG&E and SCE;
* Will blunt incentives for CCAs to invest in “behind the meter” resource solutions, allocating costs to all customers on the same basis, regardless of the unique efforts of their load-serving entities; and
* While characterized as a “local RA” mechanism, it allows the central procurement entity to procure any associated system and flexible RA capacity with mandatory allocation of these rights to LSEs without sufficient time to position their portfolios for annual compliance.
CalCCA said that the settlement agreement would achieve the state’s aims by reducing the need for California ISO backstop procurement, maintaining and enhancing a liquid and robust bilateral capacity market, while also preserving the self-procurement autonomy of load-serving entities including community choice aggregators.
Details on CPUC decision
Under the PUC’s decision, beginning in 2021, PG&E and SCE will serve as the central procurement entities for their respective distribution service areas and begin procuring local resource adequacy for the 2023 compliance year.
The CPUC said its decision adopts a hybrid procurement model that tasks the central procurement entities with the responsibility to procure the entire amount of required local resource adequacy on behalf of all LSEs, while still allowing individual LSEs the opportunity to procure their own local resources.
If an LSE procures its own local resource, it may:
* Sell the capacity to the central procurement entities;
* Utilize the resource for its own system and flexible resource adequacy needs, or
* Voluntarily show the resource to meet its own system and flexible resource adequacy needs and reduce the amount of local resource adequacy the central procurement entities will need to procure for the amount of time the LSE has agreed to show the resource
The CPUC said that it is open to considering a compensation mechanism for local capacity requirement reduction achieved through shown local resources by LSEs.
The decision directed parties to form a working group to develop proposals for a local capacity requirement reduction compensation mechanism and the treatment of existing contracts.
The CPUC said it would address any proposed local capacity requirement reduction compensation mechanisms in a subsequent decision to be issued prior to the central procurement entities’ 2021 procurement (for the 2023 and 2024 compliance years).
SDG&E
With respect to SDG&E’s distribution service area, the decision declined to adopt the central procurement entities framework.
The PUC said it recognizes that the SDG&E service area is uniquely situated in that the local resource adequacy requirements, which must meet a higher reliability threshold than system capacity requirements, exceed the system resource adequacy requirements for most months of the year.
Given that local capacity procured by the central procurement entities would also count towards LSEs’ system resource adequacy requirements, LSEs would have very little procurement autonomy for system resource adequacy requirements if a central buyer were to procure all needed local capacity, the CPUC said.
Decision directs filing of independent evaluator report
In addition to directing the creation of a working group to develop a local capacity requirement reduction compensation mechanism, the decision directs an independent evaluator report to be filed annually with the central procurement entities’ compliance filing, “which will increase transparency into any gas-fired procurement by including the basis for any fossil fuel procurement that exceeds the minimum multi-year requirements,” the CPUC said in a news release.
The independent evaluator report will also assess the neutrality of the procurement process, any market power or aggregate pricing concerns, procurement of preferred resources (e.g., on what basis preferred resources were not selected), and consideration of disadvantaged communities in the procurement process, according to the CPUC.
The decision also directs the CPUC’s Energy Division to prepare a report assessing the effectiveness of the central procurement entities structure by 2025.
The proposal voted on last week by the PUC is available here.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
Company Plans to Build 15 Utility-Scale Storage Plants in Texas
June 15, 2020
by Peter Maloney
APPA News
Posted June 15, 2020
Independent power producer Broad Reach Power plans to build 15 utility-scale battery storage plants totaling 150 megawatts (MW) in areas near Houston and Odessa, Texas.
The Houston-based company is building the storage plants on a merchant basis “on our balance sheet” and aims to sell the output into the wholesale power market run by the Electric Reliability Council of Texas (ERCOT), Steve Vavrik, managing partner and CEO, said.
The company is also targeting public power utilities, retail electricity providers and even individual large industrial customers to enter into financial contracts that can help ensure those entities a reliable and predictably priced stream of electric power.
“We are essentially selling risk management products with a fleet of batteries behind us,” Vavrik said.
Vavrik anticipates that much of his sales into ERCOT will be in the ancillary services market where batteries can sell power in microbursts to balance out the intermittency of renewable resources on Texas’ grid.
Texas leads the nation in wind power with over 29,000 MW of installed wind turbines. Solar power is also gaining ground in Texas with ERCOT reporting 1,500 MW of installed utility scale solar projects and 4,300 MW of solar projects, out of 40,000 MW under study, that have already signed interconnection agreements and could be in service by year end.
“Power is getting cheaper and cleaner in Texas,” Vavrik said. The problem, he said, is matching supply and demand, not just when renewable output declines but also when it overproduces.
Batteries can inject power into the grid when the wind dies, but they can also absorb power when there is more than enough wind power to meet load. That gives Broad Reach Power more flexibility in designing financial products, such as swaps, that can allow energy providers and consumers to better manage their energy budgets. There are more risks to reliability, “so grid players have to come up with new risk management tools,” Vavrik said.
Though he declined to name individual utilities, Broad Reach Power is approaching large public power utilities in Texas, as well as retail electric providers, that want more certainty and predictability in the cost of wholesale power that they buy.
“Peak demand in ERCOT is at about the same level it was before the pandemic,” Vavrik said. “All municipalities are facing this challenge.” In addition, large technology companies are seeking sites for facilities or data centers and, often, they want the assurance that their power supply will not only be reliable but clean. A financial instrument that can pair price stability with Texas’ low emission generation mix is a strong selling point for those companies. And, for public power utilities, it could be a “real opportunity” for economic development, Vavrik said.
Despite the large amount of wind power on its system, energy storage has been slow to take hold in ERCOT. States that have legislated energy storage mandates have taken the lead in energy storage, but Vavrik is bullish on the Texas energy storage market.
“Texas is designed to be very open to private ownership,” and is not subject to federal regulation, Vavrik said. More specifically, the transmission of electric energy occurring wholly within ERCOT is not subject to the Federal Energy Regulatory Commission’s jurisdiction under sections 203, 205, or 206 of the Federal Power Act.
“ERCOT has been leaning into this. We are working with them to change the rules.”
As of January 2019, ERCOT reported 89 MW of operating utility-scale battery resources in its region. As of December 2019, there were interconnection requests submitted for 7,214 MW of battery capacity in ERCOT’s queue.
Broad Reach Power expects six of its planned energy storage plants to be in operation this summer with the other nine under construction by this fall.
The company is also planning more similarly sized projects, as well as larger storage projects, in Texas’ Panhandle and Rio Grande Valley regions and has some early stage storage projects under way in California and solar and storage projects in Montana.
Broad Reach Power says it has begun the development or construction of nearly $100 million of storage assets since it was formed in July 2019. The company has financial backing from EnCap Investments, Yorktown Partners, and Mercuria Energy.
APPA, Others Urge Lawmakers To Include Nuclear Measure In Defense Legislation
June 12, 2020
by Paul Ciampoli
APPA News Director
Posted June 12, 2020
The American Public Power Association and several utility and nuclear industry stakeholders recently urged the chairman and ranking member of the Senate Armed Services Committee to include legislation that would accelerate the commercialization of a new generation of nuclear reactors in the fiscal year (FY) 2021 National Defense Authorization Act (NDAA).
The June 9 letter was sent to Sen. James Inhofe, R-Okla., Chairman of the Senate Armed Services Committee, and Sen. Jack Reed, D-R.I., Ranking Member of the committee.
APPA and the other stakeholders urged Inhofe and Reed to include the bipartisan Nuclear Energy Leadership Act (S. 903) in the FY2021 NDAA.
The bipartisan committee amendment on nuclear energy filed by several senators would add important provisions from NELA to the NDAA, “and we support the amendment,” the groups said.
“NELA would accelerate the commercialization of a new generation of nuclear reactors that are designed to provide energy in multiple ways beyond traditional large-scale nuclear electricity production,” the groups pointed out.
These new nuclear energy products “are important components in a modern, clean, resilient energy system that can meet civilian and defense needs. With China and Russia now developing and exporting advanced reactors to strategically significant countries throughout the world, it is critical that the U.S. reassert leadership in this geopolitically important field,” APPA and the other stakeholders told Inhofe and Reed.
NELA, introduced by Senate Energy and Natural Resources Committee Chairman Lisa Murkowski, R-Alaska, has twenty-two bipartisan co-sponsors, including Ranking Member Joe Manchin, D-W.Va.
The legislation would direct federal research and development related to advanced nuclear power, including advanced reactor demonstration, the development of a national nuclear strategic plan, and the creation of university nuclear leadership program.
NELA would also authorize long-term federal power purchase agreements increasing the current maximum from ten years to up to forty years, allowing upfront capital costs to be recouped over a longer period.
Last September, the legislation was reported out of the Senate Energy and Natural Resources Committee by a voice vote.
EPA Finalizes Water Quality Certification Rule
June 12, 2020
by Paul Ciampoli
APPA News Director
Posted June 12, 2020
The Environmental Protection Agency (EPA) on June 1 issued its final Clean Water Act (CWA) section 401 rule to clarify timeframes for water quality certification, the scope of certification review and conditions and related certification requirements and procedures.
The final rule, which was issued is in accordance with Executive Order 13868, “Promoting Energy Infrastructure and Economic Growth,” clarifies that a state’s review and action under section 401 must be limited to water quality impacts to waters of the U.S. resulting from a potential point source discharge from a proposed federally licensed or permitted project.
The water quality certification may not address matters unrelated to water quality (e.g., greenhouse gas emissions or transportation impacts) or the applicant’s activity as a whole.
Also, the regulations clarify that a state waives its certification authority if it does not act upon a request for certification within a reasonable period of time, which cannot not exceed one year. This time period does not pause or stop for any reason once the state has received the certification request.
Changes from the proposed rule include requiring a project proponent to request a pre-filing meeting with state officials before formally seeking a section 401 certification and clarifying that federal agency review of a state’s certification decision document is focused on compliance with the procedural requirements of the CWA section 401 process rather than the substantive aspects of the document.
The final rule is effective 60 days after publication in the Federal Register.
The final rule is significant to members of the American Public Power Association because it should ensure consistent implementation of section 401 and timely issuance of water quality certifications. While the rule may provide clarity for some project proponents, some states have indicated they plan to challenge the final rule on the grounds the rule usurps states’ rights under the CWA.
Additional information about the final here is available here.