Chelan PUD Commissioners Approve PUD Joining Resource Adequacy Program
December 12, 2022
by Paul Ciampoli
APPA News Director
December 12, 2022
Chelan PUD commissioners recently voted for the Washington State PUD to join the Western Resource Adequacy Program (WRAP), the first reliability planning and compliance program in the Northwest, which has been in the works since 2019.
About 26 utilities from Canada to northern California are participating in the voluntary, non-binding phase of WRAP.
Chelan said that while the Pacific Northwest typically produces abundant energy supply, “there are warning signs of a less certain future ahead: Increased demand for electricity, the rise of intermittent renewables like wind and solar, increased regulatory requirements, and more large-load industries moving to the West.”
WRAP has asked utilities to join the binding phase over the next several years, which means that utilities have guaranteed first priority to purchase energy from other member utilities in the event of a critical shortage. It also means that utilities may be subject to penalties if they don’t meet capacity requirements. The cost of joining is about $185,000 the first year, and $150,000 annually.
Chelan listed the benefits of WRAP as:
- Increased reliability as dozens of utilities coordinate a diverse portfolio of energy resources across a large geographical footprint. If one area is hard hit by a heat wave or cold snap, utilities can tap into an emergency supply of energy from WRAP instead of relying on the increasingly volatile energy market.
- Increased value of capacity, which means hydropower is well-positioned to become more valuable because of its flexible, 24/7 availability.
- Joining WRAP voluntarily makes legislative mandates less likely.
- Supporting the WRAP may increase the chance of success of future organized markets, which has had over 20 participants from the Pacific Northwest to the Desert Southwest. A resource adequacy program is a standard feature of an organized market. If Chelan PUD joins a future organized market, the organized market will most likely have similar rules to WRAP.
- Joining WRAP would allow Chelan PUD to have a lower planning reserve margin. That means Chelan PUD may have more energy available to sell and maintain low customer rates.
“If it doesn’t work out the way we anticipate, we can exit the program with a two-year notice at any time,” said Shawn Smith, Managing Director of Energy Resources.
SPP Takes Next Step in Expansion Of its Wholesale Market
December 12, 2022
by Peter Maloney
APPA News
December 12, 2022
The Southwest Power Pool (SPP) has taken the next step toward the centralization of day-ahead and real-time unit commitment and dispatch that the wholesale grid operator said would pave the way for the reliable integration of a rapidly growing fleet of renewable generation.
The Nov. 30 release of SPP’s detailed proposal for its Markets+ service provides the basis for stakeholders that expressed an interest in committing to Markets+ in December to formalize contractual commitments for phase one of the service.
Stakeholders interested in committing to funding further market development must sign a Markets+ Market Participant Phase One Funding Agreement by April 1, 2023, SPP said.
SPP has been working with western stakeholders since December 2021 to understand the features they would want in the grid operator’s proposed day-ahead and real-time market.
SPP describes Markets+ as “a conceptual bundle of services” that would centralize day-ahead and real-time dispatch using a hurdle-free transmission service across SPP’s footprint. “For utilities that see value in these services but who aren’t ready to pursue full membership in a regional transmission organization (RTO) at this time, Markets+ provides a voluntary, incremental opportunity to realize significant benefits,” SPP said.
SPP said it envisions a two-phase process for the continuing development of Markets+. In phase one, potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents. Phase two begins upon Federal Energy Regulatory Commission (FERC) approval. At that point, SPP would acquire necessary software and hardware while participating entities fully commit to fund and are integrated into the system.
Earlier in November, SPP announced the 2023 implementation of major components of the Markets+ governance structure and the exploration of a transitional real-time balancing market in 2024.
In August 2022, the Bonneville Power Administration became the first western utility to formally commit to funding further development of Markets+.
In September, Washington State’s Chelan County Public Utility District, Grant County Public Utility District, and Tacoma Power committed to Markets+. Arizona utilities, including Salt River Power also committed to Markets+ in September.
Interior Awards Five Leases for Offshore Wind in Northern California
December 12, 2022
by Peter Maloney
APPA News
December 12, 2022
The Bureau of Ocean Energy Management (BOEM), a division of the Department of the Interior (DOI), recently awarded five leases for offshore wind power development along the California coast.
The results of the BOEM lease sale represent the third major offshore wind lease sale this year and the first for the Pacific region, the DOI said. The sale drew competitive bids from five companies totaling $757.1 million, well exceeding the first lease sales that were held in the Atlantic, BOEM said.
The sale offered five lease areas covering 373,268 acres off central and northern California. The leased areas have the potential to produce over 4.6 gigawatts (GW) of wind energy, BOEM said.
The provisional lease winners are RWE Offshore Wind Holdings, California North Floating, Equinor Wind US, Central California Offshore Wind, and Invenergy California Offshore.
The lease sale included a 20 percent credit for bidders that committed to a monetary contribution to programs or initiatives supporting workforce training programs for the floating offshore wind industry, the development of a U.S. domestic supply chain for the floating offshore wind energy industry, or both. The DOI said the credit would result in over $117 million in investments.
The auction also included 5 percent credits for bidders that committed to entering community benefit agreements (CBA). One type of agreement is with communities, stakeholder groups, or Tribal entities whose use of the lease areas or use of the resources harvested from the lease areas is expected to be affected by offshore wind development. The second type of agreement is a general CBA with communities, Tribes, or stakeholders that are expected to be affected by the potential impacts on the marine, coastal or human environment from lease development.
Earlier this month, BOEM finalized two Wind Energy Areas (WEAs) in the Gulf of Mexico and said it planned to issue a proposed sale notice for the competition to lease the areas. The first WEA is approximately 27.6 miles off the coast of Galveston, Texas, and totals 508,265 acres. The second WEA is approximately 64.4 miles off the coast of Lake Charles, La., and totals 174,275 acres.
In February, the DOI announced the results of the nation’s highest-grossing competitive offshore energy lease sale in its history. The lease areas including oil and gas lease sales and six leases totaling more than 488,000 acres in the New York Bight for potential wind energy development, which drew winning bids from six companies totaling about $4.37 billion.
APPA’s Adrienne Lotto Emphasizes Importance of Layered Defenses for Grid Security
December 12, 2022
by Paul Ciampoli
APPA News Director
December 12, 2022
When it comes to grid security, the importance of layered defenses cannot be overstated, and while the power sector has a good overall understanding of the risk it is facing in this area, to the extent that more information can be shared from the federal government to entities and utilities, that is helpful for utilities to understand their risks and respond accordingly, said Adrienne Lotto, Senior Vice President of Grid Security, Technical & Operations Services, American Public Power Association (APPA), on Dec. 7.
She made her comments at a joint Department of Energy-Federal Energy Regulatory Commission supply chain risk management (SCRM) conference in Washington, D.C.
Lotto was a panelist at the conference that examined current supply chain risk management reliability standards, implementation challenges, gaps, and opportunities for improvement.
Other panelists were Jeffrey Sweet, Director of Security Assessments, American Electric Power, Shari Gribbin, Managing Partner, CNK Solutions, Scott Aaronson, Senior Vice President of Security and Preparedness, Edison Electric Institute, and Lonnie Ratliff, Director, Compliance Assurance and Certification, North American Electric Reliability Corporation.
Panelists were asked whether they think the currently effective supply chain risk management standards are sufficient to successfully ensure bulk power system reliability and security in light of existing and emerging risks to the cyber security supply chain.
“The simple answer is yes,” Ratliff said. “The standards provide a foundation to address and mitigate some of the supply chain challenges that we have across our industry. With this foundation, there’s always opportunities to improve so as we look at the effectiveness” of the standard, “NERC has taken several opportunities to assess those standards, bring up teams and evaluate the effectiveness and propose change to those standards.”
Lotto said that NERC and the power industry have shown a willingness to continue to partner and examine the NERC Critical Infrastructure Protection (CIP) standards as it relates to supply chain security and are continuing to do so.
As threats continue to evolve, the utility sector and NERC have also shown a willingness to evolve and take a second look at those standards and “that risk-based approach remains ongoing.”
At the same time, Lotto highlighted jurisdictional limitations to FERC “and the burden that that then places on the utilities trying to gain insight into the suppliers that they are utilizing in their systems.”
“I do believe that the standards that are in place today are effective and are appropriate,” said Sweet. “They provide the flexibility for the utilities to be able to address the risks that they realize within their organizations.”
The supply chain risk management standard requires entities to have a supply chain risk management plan.
Supply Chain Risk Management Plan
Panelists were asked to address the question of whether it would be beneficial to provide additional clarity for the supply chain risk management plan in a couple of areas.
“One is in identifying and assessing risks,” said David Ortiz, Director of the Office of Electric Reliability at FERC. “Identifying triggers that would require activation of the plan and then requirements in that plan to respond to risks that are identified.”
Addressing the question of whether the power sector needs help in identifying and assessing risk, Lotto said, “the short answer is yes.”
She said that to the extent that more information can be shared from the federal government to entities and utilities, large or small, that is helpful for utilities to understand their risks and respond accordingly.
Lotto cautioned against an idea floated earlier in the conference that proposed throwing out the definition of high, medium and low in the risk-based approach currently being used at NERC.
She warned against making a holistic change in this approach. “The NERC CIPS standards are effective. They are working and that is sound risk management practice in any sector – to understand what your high, medium, low impacts are, so a holistic change like that at this time I think would actually set us back, as opposed to enable NERC to continue doing what it’s doing with the utilities and move us forward towards greater supply chain security.”
Prior to joining APPA, Lotto was vice president, chief risk and resilience officer at the New York Power Authority, where she led a team of risk management professionals.
Meanwhile, Puesh Kumar, Director of the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response, noted that utilities “are trying to manage risk, but to do that they first need to understand the risk.”
He asked Lotto whether utilities “know the risk well enough and, if not, what are the gaps? What more could we be doing?”
Do utilities “have a good understanding of the risk that they’re managing to?”
“I would say holistically the answer is yes,” Lotto responded. There has been a “tremendous amount of work” done at the DOE, Department of Homeland Security, the Electricity Information Sharing and Analysis Center and the Multi State Information Sharing and Analysis Center “that helps to inform and provide industry insight into the risks. Now, that said, could we always do better? Of course.”
Lotto said that a recent incident involving an attack on Duke Energy substations in North Carolina “is a physical example where you see the risk in day-to-day life that the grid is exposed to, so continuing to foot stomp and provide situational awareness in a timely fashion with context and suggested solutions or guidelines, I think is important.”
She noted that APPA provides resources and guides and partners with the DOE through agreements “that enable us to do that. Particularly for the smaller members, it’s exceedingly helpful.”
EEI’s Aaronson said that “we understand the risk, but risk is always changing. Risk is a factor or a function of threat, likelihood and consequence.”
He said that “what is the consequence of something is also evolving, not just because the threat is evolving but the grid is constantly evolving.”
At a later point, Lotto emphasized the need for layered defenses when it comes to grid security. She said that while FERC and NERC have done a good job in addressing the baseline, the energy sector continues to collaborate, which includes discussing baselines and focusing on “getting even better and stronger.”
This continued coordination, not just in the regulatory arena, but also in terms of best practices, needs to continue to happen, she said.
“I think the greatest power that the federal government has is the power to convene,” Lotto said. Continuing to bring industry experts together with the federal government “to solve critical problems has to continue to evolve.”
She also said that the importance of economies of scale must not be overlooked “because individually we can’t do it alone. Our members can’t do it alone. The cyber threat, unfortunately, is advancing to the front lines where, fundamentally, our members are getting asked on a day-to-day basis to act as frontline defenders of networks and that’s an almost impossible task. They’re not set up to defend networks on a day-to-day basis from nation state adversaries that are attacking them.”
The power to convene at the federal government level, both through the NERC process “wherein they’re continuously looking and trying to evolve to meet the threat, together with best practices and advancing through groups that already exist or at the federal government level to achieve economies of scale and layered defenses is critical.”
ERCOT Creates Curtailment Program for Large Flexible Customers during Peak Demand Periods
December 10, 2022
by Paul Ciampoli
APPA News Director
December 10, 2022
The Electric Reliability Council of Texas (ERCOT) is implementing a voluntary curtailment program allowing large flexible customers, such as bitcoin mining facilities, to reduce their power use during periods of high demand, it said on Dec. 6.
“Our goal with this program is to work with large customers in supporting the reliability of the Texas power grid,” said Woody Rickerson, ERCOT Vice President of System Planning, in a statement. “These customers are large power users but have the flexibility and willingness to reduce their energy use quickly, if needed. By working with these large loads during peak demand periods, we will better serve all Texans while keeping the grid reliable and resilient.”
The program is primarily intended for large flexible customers, but any large customer directly connected to a transmission service provider’s facility can participate, subject to approval by ERCOT.
The program is temporary and completely voluntary until ERCOT establishes a long-term set of rules.
Registration for the program began on Dec. 6 and ERCOT anticipates the program going live in January 2023.
More information can be found in our Market Notice, including the registration form to participate.
Salt River Project Using Inflation Reduction Act to Build and Own Solar Plant
December 8, 2022
by Peter Maloney
APPA News
December 8, 2022
Arizona public power utility Salt River Project (SRP) is building a solar power project that will take advantage of recent changes in federal law that allows public power utilities to use tax benefits that were previously out of reach.
SRP’s board of directors recently approved the second phase of the 55-megawatt (MW) Copper Crossing Energy and Research Center in Florence, Ariz.
The utility-scale solar project is the first the utility is developing and will own and operate itself.
Historically, SRP has contracted for generation from renewable resources through power purchase agreements with developers that have access to federal tax credits for renewable energy projects.
The federal Inflation Reduction Act passed in August extended and expanded various energy tax incentives and gave public power utilities direct access to those credits by allowing allows public power utilities to receive direct federal incentive payments for renewable projects.
SRP said the change will give it greater ability to develop, operate and advance more renewable resources and potentially reduce costs for customers.
The first phase of the Copper Crossing project will add two natural gas-fired turbines with a total output of less than 100 MW, which SRP’s board approved in September. A third proposed phase for small-scale, long-duration energy storage system is expected to go to the utility’s board for approval in 2023.
SRP has not yet completed the design of the new solar portion of the Copper Crossing site. Engineering, material procurement and construction activities for the solar facility are expected to take approximately 24 months. The solar project is sited on land SRP owns next to its Abel substation adjacent to an existing 20-MW solar plant.
With this development and other recent awards, SRP is contracted for over 2,000 MW of our goal to add 2,025 MW of new utility-scale solar energy by 2025, SRP noted.
Puerto Rico Substation Modernization Initiative Gets Underway
December 7, 2022
by Paul Ciampoli
APPA News Director
December 7, 2022
LUMA Energy recently announced the launch of Puerto Rico’s federally funded Substation Modernization Initiative (SMI) with the modernization and reconstruction of the Manatí Substation in the municipality of Manatí.
In June 2020, Puerto Rico Electric Power Authority (PREPA) and the Puerto Rico Public-Private Partnership Authority selected LUMA Energy to operate, maintain and modernize the electricity transmission and distribution system of PREPA for fifteen years through a public-private partnership.
The Manatí SMI project represents an investment of more than $2.3 million in federal funding approved for phase one and over $55 million in federal funding estimated for the entire rebuild of the Manatí substation.
At the SMI launch event with LUMA were representatives of the Central Office for Recovery, Reconstruction and Resiliency and the Federal Emergency Management Agency (FEMA).
As part of the first SMI project, LUMA will replace outdated and obsolete oil circuit breakers with the industry standard 230-kilovolt gas circuit breakers, which it said will improve reliability and strengthen operational safety.
The Manatí SMI project, which is the first major work on this substation in the past 20 years, will include multiple phases with future improvements designed to replace aging equipment and reconfiguration of the entire substation, utilizing FEMA funding.
When completed, the Manatí SMI project will directly improve resiliency and reliability for the municipalities of Manatí, Barceloneta, Florida, Ciales, Morovis and Vega Baja, which are some of Puerto Rico’s most important industrial centers, LUMA noted.
Substation Modernization Initiative Details
The modernization of the Manatí substation is one of five substation modernization projects currently underway with a total of $58 million in already approved federal funds.
Among the projects that are estimated to begin construction in Q2 2023 include:
- Cataño substation project with an investment of $24 million,
- Costa Sur substation project (Phase 1) with an investment of $28 million,
- Culebra substation project with an investment of $2 million,
- Manatí substation project (Phase 1) with an investment of $2 million
- Vieques substation project with an investment of $2 million.
Over the last 17 months, LUMA has advanced federally funded FEMA projects, with 251 projects initiated representing over $6 billion in federally funded projects. A total of 23 projects are already under construction or in service.
Lansing Board of Water & Light Retires Last Coal-Fired Plant
December 7, 2022
by APPA News
December 7, 2022
The Lansing Board of Water & Light (BWL) has retired its last coal-fired power plant, which the public power utility said makes it the largest utility in Michigan to generate coal-free power by 2022.
The Nov. 27 retirement of the 160-megawatt (MW) Erickson Power Station aligns with the integrated resource plan BWL released in August 2020 that calls for the utility to deliver 50 percent of its power from clean energy sources by 2030 and to be a carbon dioxide neutral utility by 2040.
“In 2012, BWL burned 1.2 million tons of coal,” Dick Peffley, BWL’s general manager, said in a statement. “Today, 10 years later, BWL’s coal consumption is zero.”
The retirement of the Erickson plant, which began operation in 1973, was preceded by BWL’s retirement of its 350-MW Eckert station in 2020.
BWL is replacing its coal-fired power plants with natural gas-fired plants, as well as a mix of wind and solar generation. Compared with coal, natural gas generation represents an 80 percent reduction in carbon dioxide emissions, as well as a 99.9 percent reduction in sulfur dioxide emissions, BWL said.
BWL replaced the Erickson plant with the 250-MW natural gas-fired, combined-cycle plant Delta Energy Park that came online in August 2022.
BWL also has an agreement with Michigan Public Power Agency to purchase power from DTE Energy’s Belle River coal-fired plant in southeast Michigan’s St. Clair County. DTE has announced plans to convert Belle River to natural gas in 2025-2026.
“These coal-fired plants generated power that allowed Lansing’s automobile industry to grow and flourish and made the Lansing area a terrific place to live, work and raise a family,” Peffley said. “Now it’s time for the next generation of cleaner energy to power the region’s electric vehicle future and beyond. I started my BWL career at Erickson and the plant has had a great run. We appreciate its service to our community and all the employees that kept it operational throughout the decades.”
BWL recently issued an All-Sources request for proposals that the utility plans to use to evaluate electric supply or demand-side resources including wind, solar, battery storage and energy savings programs that can help meet all or part of the BWL’s capacity and energy needs.
The BWL has about 100,000 electric customers, 58,000 water customers, 155 steam customers and 19 chilled water customers.
Officials with Iowa’s Denison Municipal Utilities Detail Utility’s Response to Transformer Shortages
December 7, 2022
by Paul Ciampoli
APPA News Director
December 7, 2022
In a recent interview with Public Power Current, Rory Weis, General Manager of Iowa public power utility Denison Municipal Utilities (DMU), and Electric Manager Mike Wight, detailed how the utility is responding to delays for acquiring transformers due to ongoing supply chain challenges.
DMU’s Board of Trustees recently voted to allow utility staff to seek bids for a power transformer for a substation.
When asked to describe how supply chain issues have impacted the utility in terms of seeking bids for this transformer, Weis said, “the last substation transformer that we replaced approximately two years ago took close to a year to get. Supply chain issues now have pushed that out to, we’re being told, close to a two-year timeframe. We started the process a little sooner due to that fact so we can keep that project moving forward.”
Wight said that the utility has faced delays in orders for distribution transformers, noting that DMU ordered distribution transformers that were supposed to be delivered in July 2022 “and then we were told November and they’re still not here.” Wight said that the last email DMU got from its supplier indicated that the distribution transformer would be shipped this week.
With respect to the topic of pricing for transformers, Wight said that the last bid the utility received for the substation transformer was around $670,000 “and they’re estimating between $1.1 and $1.2 million on this one.”
As for the cost for distribution transformers, DMU has seen an increase in costs for 50 KVA single phase transformers in recent years.
With respect to the outlook for supply chain challenges and transformer delays, Weis said, “We hope we’re at the worst of it right now” and that it starts getting better, “but we have nothing to reference that to.”
Groups Urge DOE to Move Quickly to Alleviate Supply Chain Challenges With Transformers
December 6, 2022
by Paul Ciampoli
APPA News Director
December 6, 2022
The Department of Energy (DOE) should use Defense Production Act (DPA) authorities to prioritize distribution transformers, large power transformers, and other critical grid components ahead of other technologies, and it should act quickly to alleviate the most acute supply chain challenge with distribution transformers, the American Public Power Association (APPA), the Edison Electric Institute (EEI), and the National Rural Electric Cooperative Association (NRECA), said in joint comments submitted to DOE on Nov. 30.
The comments responded to a DOE request for information (RFI) that sought input from stakeholders on how DOE should use its authority under Title III of the DPA to address supply chain issues for clean energy technologies and distribution transformers.
“Recent surveys show our members are waiting longer than ever for transformers of all sizes, conductors, meters, circuit breakers, and other products,” the trade groups noted. “Industry cannot solve this challenge alone and thus we are pleased to see the government may use its authority under the DPA to address challenges created by shortages of transformers and other key components of the energy grid.”
“We respectfully urge DOE to prioritize distribution transformers, large power transformers, and other critical grid components ahead of the other technologies considered in the RFI,” APPA, NRECA and EEI said.
“Until we can address the shortages and supply chain challenges that are directly impacting reliability, we may not be able to accomplish many of the goals this administration has laid out for advancing clean technologies or expanding electrification,” they said.
“Most urgently, in the near-term, we urge DOE to act quickly to alleviate distribution transformer shortages, as this is the most acute supply chain challenge the electric industry is facing,” the groups said.
“We also ask DOE to establish longer-term efforts dedicated to supporting expanded domestic manufacturing capacity for large power transformers and other grid components that may take longer to address but are nonetheless critical to grid operations and therefore national security.”
The RFI comments also note that DPA authorities could be used for financial assistance, loan guarantees, and purchase commitments for transformer manufacturers that would help address labor shortages and the availability of materials that are hampering manufacturers’ ability to increase production.
Groups Urge Congressional Appropriators to Fund DPA Authorities to Address Supply Chain Shortages
APPA and the electric trades augmented their comments on DPA with a letter for action on Capitol Hill. The electric trades, along with building trade organizations, recently sent a joint letter to Congressional Appropriations leadership requesting funding for DPA.
The groups request that Congress appropriate $1 billion this year for the implementation of DPA authorities to specifically address the supply chain crisis for electric distribution transformers.
“Throughout 2022, the electric sector and representatives from residential and commercial building sectors have been calling attention to the unprecedented supply chain challenges both industries have been facing in procuring equipment used to maintain and grow the electric grid,” wrote APPA President and CEO Joy Ditto and leaders of the other groups. DPA authorities should be prioritized to immediately address increased production of distribution transformers.