Public Power Credit Unaffected by Glen Canyon Dam Drought Measures: Fitch
May 14, 2022
by Paul Ciampoli
APPA News Director
May 14, 2022
Against the backdrop of recent urgent drought response actions at Lake Powell, which are intended to preserve water levels and power generation at the Glen Canyon Dam, the credit effect of generation shortages is limited because the dam constitutes only one of multiple generation sources for public power utilities rated by Fitch Ratings, the rating agency said on May.
Fitch noted that the U.S. Bureau of Reclamation (BOR) recently announced urgent drought response actions at Lake Powell, which are designed to preserve water levels and power generation at the Glen Canyon Dam, the second-largest hydroelectric power source in the Southwest.
“The announced actions will preserve minimum levels of power supply from this low-cost, carbon-free hydroelectric resource for regional public power utilities in the short term. Still, consensus is needed among the entities that rely on Lake Powell for water and power to address declining hydrology in the Colorado River Basin if power generation is to be sustained longer term,” said Fitch.
Reduced hydroelectric output, as a result of the Colorado River Basin drought, is driving replacement power supply of purchasing utilities higher, but the increases are manageable, the rating agency said.
The BOR increased project energy and capacity rates charged to purchasing utilities by 8% and reduced available allocations in December 2021, given the region’s increasingly severe drought conditions.
The BOR indicated it would no longer purchase power in order to firm deliveries to purchasing utilities, given increasing market energy prices in the western U.S., Fitch said.
Utilities rated by Fitch “are absorbing the incremental cost caused by reduced supply in 2022 by replacing the lower generation with additional purchased power costs, increased output from other owned generation, or reduced off-system (optional, non-customer) sales. To the extent the project’s power supply remains curtailed, the replacement costs in relation to overall power supply costs for Fitch-rated public power issuers are expected to be recovered through rate adjustments.”
The Colorado River Storage Project (CRSP), which includes the 1,320-megawattt Glen Canyon Dam power plant, provides cost-based energy supply at typically below market prices to 130 public entity customers: 53 native American tribes, 60 municipalities, cooperatives and irrigation districts, and 17 other entit
Four Fitch-rated utilities receive between 5% and 18% of their total power supply from the project: Colorado Springs, Colorado; Platte River Power Authority, Colorado; Tri-State Generation and Transmission Association, Inc., Colorado; and the Utah Municipal Power Agency, Utah. Two additional rated systems, Fort Collins, Colorado and Provo, Utah, purchase power from these utilities.
“The Glen Canyon Dam constitutes only one of multiple generation sources for the Fitch-rated utilities, limiting the credit effect of generation shortages, even in the event of full cessation of power from the facility,” Fitch said.
But the rating agency said that the reduction of low-cost power supply from Glen Canyon “is just one example of the sector’s broader operating cost pressures. “Additionally, lower generation from Glen Canyon reduces carbon-free electricity as the sector is pursuing cleaner, non-emitting electric sources.”
Glen Canyon Dam, Lake Powell, and the Glen Canyon Dam power plant together form the largest project of the CRSP and are collectively owned and managed by the BOR. The project controls water releases from the Upper Colorado River Basin to the Lower Basin and generates hydroelectric power, accounting for approximately 75% of CRSP’s generating capacity.
Fitch noted that the entire Colorado River Basin is experiencing progressively worse drought conditions since 2000.
The BOR in early May announced drought response actions that it said would help prop up Lake Powell by nearly 1 million acre-feet of water over the next 12 months (May 2022 through April 2023).
On May 3, Lake Powell’s water surface elevation was at 3,522 feet, its lowest level since originally being filled in the 1960s.
A critical elevation at Lake Powell is 3,490 feet, the lowest point at which Glen Canyon Dam can generate hydropower. “This elevation introduces new uncertainties for reservoir operations and water deliveries because the facility has never operated under such conditions for an extended period. These two actions equate to approximately 16 feet of elevation increase,” BOR said.
BOR invoked its authority to change annual operations at Glen Canyon Dam for the first time. The measure protects hydropower generation and the water supply for the city of Page, Arizona, and the LeChee Chapter of the Navajo Nation, it said.
OPPD Employees Organize Collection To Assist Ukrainian Refugees
May 12, 2022
by Paul Ciampoli
APPA News Director
May 12, 2022
Omaha Public Power District’s (OPPD) employee resource group, OPPD Global Connections, recently organized a collection to assist local Ukrainian refugees in need.
OPPD Global Connections is committed to promoting, supporting and advancing a workforce that embraces inclusive diversity through respectful interactions.
The group works to build a greater OPPD workforce by welcoming all immigrants, refugees, and interested employees to connect with and educate one another through diverse skills, expertise and cultural values resulting in opportunities for better career pathways and professional growth.
Collection boxes were setup at seven different OPPD locations and OPPD employees were encouraged to purchase LED light bulbs since they are more energy-efficient and longer lasting, but any light bulbs were acceptable.
A total of 326 light bulbs were collected and on May 10, the light bulbs were dropped off to Lutheran Family Services to be given to local Ukrainian refugees.
Public Power Groups Weigh In On Bond Private Use Rules
May 11, 2022
by Paul Ciampoli
APPA News Director
May 11, 2022
The American Public Power Association (APPA) and the Large Public Power Council (LPPC) recently sent a letter to Tom West, Deputy Assistant Secretary for Tax Policy at the U.S. Treasury Department, related to bond private use rules.
The May 3 letter follows a meeting in April with West, his staff, and personnel from the Internal Revenue Service to discuss the issue. The letter was signed by LPPC President John Di Stasio and APPA President and CEO Joy Ditto.
It has been over 30 years since the enactment of private use rules for public power in the Tax Reform Act of 1986 and nearly 20 years since the related regulations in Section 141 for output facilities were updated, the letter noted.
“The changes to the regulations that were made in 2002 were, in part, made in response to significant changes that had occurred in the electric industry. Given the changes that have occurred in the electric industry since 2002, the private use rules need to be modified again,” wrote Ditto and Di Stasio.
APPA and LPPC are focused on the two most significant issues affecting public power: the impact of output contracts with large retail customers and the issues created by the section 141(d) “Rostenkowski Rule” on the ability of the members of the groups to use tax-exempt bonds to acquire existing electric resources needed to serve their customers.
Contracts With Retail Customers
A growing trend in the industry is that large retail electric customers — both existing customers and new customers — are seeking to negotiate customized contracts for electric service with public power and other utilities. Private use rules limit the ability of public power utilities to enter into customized contracts and put them at the risk of losing these important customers.
“These customers can be extremely important to their communities and the inability provide them with satisfactory electric service arrangements could be devastating for both the utility and the local community. At the same time, if these customers are not obligated to remain as customers for a significant enough period, the utility and its other customers are at risk that they will bear the cost of the improvements required to serve these customers if they go out of business or relocate,” the letter said.
Under current regulations, the only approach that can be used by public power utilities with large, retail customers is to enter into contracts with terms of not more than three years, which is not sufficient for the public power utility to ensure that its other customers will end up bearing the cost of any necessary improvements and often does not provide a long enough contract term for the customer.
“Oddly, the regulations contain a more generous rule for contracts with wholesale customers that permits contracts, subject to certain conditions, with terms of up to five years,” Ditto and Di Stasio said.
APPA and LPPC proposed the adoption of an exception to the private use rules for contracts with retail customers that tracks the requirements for short-term contracts in section 1.141-7(f)(3) and that would apply if:
- The term of the contract is not more than 10 years (including renewal options);
- The contract either is a negotiated, arm’s-length arrangement that provides for compensation at fair market value, or is based on generally applicable and uniformly applied rates; and
- The output facility is not financed for a principal purpose of providing that facility for use by that nongovernmental person.
“We believe that an expansion of the short-term use rule as described above as not giving rise to private use is consistent with both the underlying regulatory framework of the output regulations (i.e., such a contract does not shift the ‘benefits and burdens of ownership’ to the taker), and Treasury’s economic policy of accommodating certain industry changes to foster competition,” Ditto and Di Stasio said.
Acquiring Existing Output Facilities
The letter notes that Section 141(d) (the “Rostenkowski Rule”) was enacted in 1987 and regulatory guidance on this provision has yet to be provided.
Although designed to prevent tax-exempt bonds from being used to “municipalize” privately owned facilities, the rule contains an exception designed to permit the acquisition of existing facilities by a public power utility to serve its existing customers — the “Existing Service Area Exception.”
“This exception is very difficult and burdensome for utilities to apply: it requires that the utility use virtually all of the electricity from the acquired facility to serve customers in its historic service area throughout the term of the bond issue and monitor compliance with this rule,” wrote Ditto and Di Stasio.
The Existing Service Area Exception was meant to permit public power utilities to use tax-exempt bonds to acquire electric facilities that were to be used to serve the existing customers of the acquiring utility.
The requirement that 95 percent of the electricity from the acquired facility be used to serve those existing customers subject only to the ability to make non-service area sales with terms of up to 30 days has significantly limited the use of this exception and prevented public power utilities from using tax-exempt bonds to acquire facilities despite the underlying rationale for the Existing Service Area Exception.
The Existing Service Area Exception presents practical and economic issues that make it difficult and costly to comply with, the letter said.
The public power groups said that many public power utilities that have short-term excess energy to sell make those sales on a “system” basis, meaning that the electricity being sold does not come from any particular generating unit.
As a result, even with on-going monitoring, it is difficult to prevent the electricity from a facility that is subject to 141(d) from being sold outside the utility’s service area without restricting the entire system.
A second, related difficulty is that in making system sales, all of a utility’s electricity derived from other bond-financed generating facilities can be sold for up to three years, but the facility that is subject to section 141(d) prevents the utility from making system sales of more than 30 days because of the need to comply with section 141(d).
The existing three-year short-term sale exception that applies for other output sales for purposes of section 141 was included in the regulations so that private use rules did not impact the typical, day-to-day functioning of public power utilities.
This private use exception is consistent with the “benefits and burdens” framework of the output regulations.
As an example of the problem with a 30-day exception under Section 141(d), short-term sales of electricity are often made on a seasonal basis to reflect situations, such as a utility that has its peak load during warm months may have excess electricity in the winter.
Ditto and Di Stasio suggested two possible approaches that can be used to address these issues. The first is to simply provide that the existing short-term sale exception to private use of output facilities applies to section 141(d).
Alternatively, a safe harbor could be adopted that permits public power utilities to base compliance on either reasonable expectations or based on historical use of electric generation to satisfy customers in their historic service areas, the groups said.
This approach would be modeled after section 148(b)(4)(B), related to bonds issued to finance natural gas prepayments.
“The rule based on historical use has proven to be very workable. Under this approach, a new safe harbor would permit public power utilities to use their historic sales of electricity in their service areas to determine compliance with the existing service area exception of the Rostenkowski Rule,” the letter said.
APPA Regional Exercise On Mutual Aid Yields High-Level Lessons Learned
May 11, 2022
by Paul Ciampoli
APPA News Director
May 11, 2022
A recent regional mutual aid held by the American Public Power Association (APPA) that was hosted by Ohio-based American Municipal Power (AMP) resulted in a series of high-level lessons learned.
The exercise took place on April 27 in Columbus, Ohio, and involved over 50 in-person public utility participants from four states and over 27 communities, including local county emergency managers and DOE regional emergency support function (ESF) #12.
The ESF #12 Annex is a construct established within the National Response Framework. ESF #12 helps manage the resources required to support energy infrastructure systems, and public and private services and resources.
The exercise was kicked off by introductory remarks from Brandi Martin, Program Manager at DOE’s Office of Cybersecurity, Energy Security, & Emergency Response.
The full day exercise featured in-depth discussion of emergency response issues including mutual aid and coordination with state, local and federal government. The scenario for the exercise was a major tornado event causing widespread grid disruptions. This exercise began after the tornado made impact and did not deal with preparatory actions.
Notable discussions during exercise or captured in a post-exercise review included the following:
- Supply chain concerns, specifically transformers. An interesting discussion (noted by most breakout groups) was about how to ensure public power utilities get needed materials during an emergency;
- Challenges of small utilities vs. large utilities. For example, one participating utility has only one lineworker;
- Mutual Aid agreements with non-public power utilities;
- Business Continuity vs Emergency Management topics;
- Discussion of elevating from local to state to regional to federal in terms of mutual aid needs;
- Identification of gaps in the Emergency Action Plans: decision making, delegations, backup personnel;
- Communication challenges and limitations, including use of communication groups and talk groups;
- Safety/operations issues;
- Impacts of social media and need to keep customers informed; and
- Knowledge transfer and generational employee differences
In terms of high-level lessons learned, the exercise was very well received. Participants commented on the importance of addressing emergencies during “blue sky” days.
Participants also commented that they appreciated the chance to participate and that DOE and APPA efforts made this possible.
Another lesson learned is the Importance of knowing peers at adjacent utilities and communities and sharing information with likely mutual aid participants.
The importance of having connections with local government decision-makers before the emergency response was another lesson learned.
Another lesson learned is the importance of having local experts as part of the facilitation teams. Each small group breakout session was led by a local power utility expert and an emergency management/exercise expert. The small groups and the local utility expertise helped draw participants into the discussions.
AMP is the nonprofit wholesale power supplier and services provider for 134 members in Ohio, Pennsylvania, Michigan, Kentucky, Virginia, West Virginia, Indiana, Maryland and Delaware.
The exercise was held under DOE CESER Cooperative Agreement DE-CR0000012.
APPA Urges FERC To Ensure Reliable And Affordable Supply Of Natural Gas
May 11, 2022
by Paul Ciampoli
APPA News Director
May 11, 2022
The Federal Energy Regulatory Commission (FERC) should clarify or revise aspects of draft gas policy statements issued in March by FERC that could interfere with FERC’s pursuit of policies that help ensure a reliable and affordable supply of natural gas in order to support a reliable and resilient power grid and reasonable electric rates for consumers, the American Public Power Association (APPA) said.
FERC on March 24, 2022, voted to seek additional comments on two policy statements it issued in February that provide guidance regarding the certification of interstate natural gas pipelines and consideration of greenhouse gas emissions (GHG) in natural gas project reviews.
“Public power utilities across the country continue to reduce their GHG emissions through a variety of means, such as fuel switching to lower-emitting resources, investments in renewable and other non-emitting resources, the integration of distributed energy resources, and a host of energy efficiency measures,” APPA said in comments submitted to FERC on April 25 (Docket Nos. PL18-1, PL21-3).
Public power utilities “also have been reducing GHG emissions by facilitating the electrification of the transportation sector in their communities, and by promoting the electrification of water and space heating, as well as appliances. As new technologies become commercially available and additional investments are made in clean energy technologies, public power utilities will further reduce their GHG emissions,” APPA said.
Meanwhile, natural gas-fired generation continues to play — and is expected to continue to play — an important role in the nation’s resource mix. In its most recent Annual Energy Outlook, the Energy Information Administration projects that natural gas resources will remain relatively constant as approximately one-third of the generation mix at least through 2050. “These resources, moreover, are expected to be critical to the overall reliability of the bulk electric system as the resource mix transitions to more intermittent renewable energy, a point that has been emphasized by the North American Electric Reliability Corporation,” APPA noted.
Public Power Utilities Rely On Gas-Fired Generation
Many public power utilities rely on natural gas-fired generation, either owned or contracted through bilateral or organized wholesale markets, and these utilities continue to have a critical interest in access to reliable and affordable supplies of natural gas.
“Even leaving aside the importance of natural gas to electric reliability, the price of natural gas often directly impacts the wholesale price of electricity, both within and outside the organized wholesale markets, and higher natural gas prices are likely to mean higher electricity bills for public power customers,” the trade group noted.
It said that a reliable and affordable supply of natural gas depends on adequate transportation infrastructure. APPA supports Commission policies that streamline the permitting process for needed interstate natural gas pipeline infrastructure, consistent with the Congress’ principal aim in enacting the Natural Gas Act to “encourage the orderly development of plentiful supplies of . . . natural gas at reasonable prices” and “protect consumers against exploitation at the hands of natural gas companies.”
“It is axiomatic that regulatory predictability and certainty help promote investment in necessary infrastructure; indeed, that is one of the stated purposes of the Commission’s revisitation of its gas pipeline certificate policies. APPA is concerned, therefore, by the degree of uncertainty and opposition that the Draft Gas Policy Statements have engendered among natural gas companies and other key stakeholders,” APPA said.
APPA agrees that it may be appropriate to reassess the Commission’s existing policies for evaluating the need for new pipeline infrastructure, particularly with respect to cases involving precedent agreements with pipeline affiliates, to ensure that costs are not being unfairly shifted to captive customers for unnecessary expansions.
But the Commission’s “proposed shift in focus from the economics of proposed pipelines to a more open-ended public interest balancing, however, could create significant uncertainty for the gas industry in trying to gauge the standards for pipeline approval. Such uncertainty could, in turn, constrain natural gas supply availability, potentially increasing electric prices and degrading grid reliability.”
APPA also said that uncertainty regarding how the Commission’s certificate policy will be applied may also perversely undermine decarbonization efforts by influencing electric utilities to retain older, less efficient generating units that might otherwise be displaced due to concerns about inadequate natural gas infrastructure, “notwithstanding the suggestion that the Commission will consider evidence that a proposed project ‘will displace more pollution-heavy generation sources’ in assessing project benefits.”
In this respect, a policy under which the Commission broadly examines the entirety of a proposal and balances all its benefits against all of its adverse impacts “is likely to leave a great deal of uncertainty in the minds of pipeline developers and their potential electric generation customers.”
APPA also urged the Commission to further consider and clarify the suggestion that the Commission will encourage applicants to mitigate indirect GHG emissions “given the substantial uncertainty that the proposed policy has created for natural gas pipeline companies, and the potential deleterious effects that such uncertainty could have on developing needed pipeline infrastructure.”
Voters in Barton Village, Vt., Decide Not To Sell Public Power Utility To Cooperative
May 11, 2022
by Paul Ciampoli
APPA News Director
May 11, 2022
Voters in Barton Village, Vt., elected not to sell Barton Electric to Vermont Electric Cooperative (VEC) in a ballot vote on May 10.
The decision allows Barton Village to continue owning and operating the public power utility that serves more than 2,000 customers in Barton, Brownington, Charleston, Irasburg, and Westmore.
“I’d like to thank the Barton Village residents for the commitment they’ve shown to their municipal electric utility,” said Ken Nolan, Vermont Public Power Supply Authority (VPPSA) General Manager.
“Over the past several weeks, voters dedicated themselves to learning as much as possible about the electric utility industry so they could make an informed decision,” he said. “Please know that VPPSA stands ready to assist the community as you move forward and explore the options for serving residents and customers of Barton Electric.”
Barton Village Trustees first announced their recommendation to sell the electric utility to VEC in March. Two informational meetings were held prior to the vote on May 10.
For more than 40 years, VPPSA has assisted Barton Electric with services and solutions to ensure safe, reliable, and affordable electric service, VPPSA noted.
VPPSA is a joint action agency. Its membership includes 12 consumer-owned municipals in Vermont and the Authority has broad statutory powers that enable it to provide such services as may be required in support of the activities of its member municipal utilities and to market its services to non-member utilities as it deems appropriate.
MISO Warns It Could Face Supply Shortfalls This Summer
May 10, 2022
by Peter Maloney
APPA News
May 10, 2022
The Midcontinent Independent System Operator (MISO) region could face electricity shortages this summer, according to a recent assessment by the grid operator.
MISO in late April projected a summer peak forecast of 124 gigawatts (GW) compared with 119 GW of projected regularly available generation within the ISO’s territory because of forecasted warmer-than-normal temperatures in the region.
“Under typical demand and generation outages, MISO is projecting insufficient firm resources to cover summer peak forecasts,” MISO said in a presentation during a late April workshop on summer readiness.
The projected shortfall would have to be filled with increased, non-firm imports and possibly emergency resources, it said.
“The seasonal assessment aligns with the cleared resources identified in the 2022-2023 Planning Resource Auction, which indicated capacity shortfalls in both the north and central regions of MISO and leaving those areas at increased risk of temporary, controlled outages to preserve the integrity of the bulk electric system,” J.T. Smith, MISO’s executive director of market operations, said in a statement.
Severe weather poses one of the key threats to the MISO region. “There is evidence that severe weather events that impact electric reliability have been increasing since the early 2010s,” a January 2022 MISO report found. “For example, in January 2021 the Electric Power Research Institute found that hurricanes are increasing in intensity and duration, extreme heat events are increasing in frequency and intensity, and cold events are increasing in frequency.”
At the same time, MISO today “operates with less excess capacity than in the past because MISO’s large footprint has facilitated the sharing of reserve capacity, a direct benefit to customer rates,” the report said. “Nevertheless, many thermal resources have recently retired from service due to economic, regulatory, and environmental pressures, and the aging thermal assets that remain in service may be more prone to unplanned outages and face supply chain issues.”
MISO said it is possible to reliably operate its system with substantially lower levels of thermal resources, but “we need to ensure that the resources that replace them provide the commensurate capabilities needed to ensure reliable operations,” it said.
Looking forward, MISO also is concerned that the growing trend toward electrification – of transportation and heating, for instance – “could transform the region’s grid from a summer-peaking to a winter-peaking system, and that uncontrolled vehicle charging and daily heating and cooling load could result in two daily power peaks in nearly all months of the year.”
In preparation for the summer season, MISO said it has implemented training sessions and is conducting exercises with member companies “to prepare for the worst-case scenarios and to implement lessons learned and best practices,” but added, “during real-time operations, unplanned outages and other variables may require additional actions to maintain grid reliability.”
“We closely monitor the many challenges the summer season can bring and coordinate with our members and other grid operators for situational awareness,” Jessica Lucas, MISO’s executive director of system operations, said in a statement.
BPA Joins CAISO’s Western Energy Imbalance Market
May 10, 2022
by Peter Maloney
APPA News
May 10, 2022
The Bonneville Power Administration (BPA) is one of the newest members of the California Independent System Operator’s (CAISO) Western Energy Imbalance Market (WEIM).
“Joining the Western EIM is a monumental and meaningful step in the modernization of our operations that unlocks a range of benefits for Bonneville and our customers,” John Hairston, BPA administrator and CEO, said in a statement.
BPA is a nonprofit federal power marketer that sells hydropower from 31 federal dams in the Columbia River Basin, as well as power from the region’s only nuclear plant. BPA delivers nearly one a third of the power generated in the Northwest to more than 140 electric utilities.
BPA was joined in its May 3 entry into WEIM by Tucson Electric Power (TEP), which provides electric service to more than 438,000 customers in southern Arizona.
“The Federal Columbia River Power System is a vital source of clean energy that will bring significant resource diversity and transmission capability to the WEIM,” Elliot Mainzer, president and CEO of CAISO, said in a statement. “And with the participation of Tucson Electric Power, we have another highly valued partner in the Desert Southwest.”
The WEIM uses its technology to find and deliver the lowest-cost energy to members across a broad, multi-state region. With the addition of the new members, the WEIM will be better able to provide increased reliability and environmental gains through the real-time transfer of energy, CAISO said.
CAISO has operated the WEIM since late 2014 and now has 19 participants serving 77 percent of electric demand in the Western United States. In March, Tacoma Public Utilities and Avista Utilities joined the WEIM.
Building on the growth of the Western Energy Imbalance Market, CAISO has been working with WEIM members to develop an Extended Day-Ahead Market (EDAM).
On April 28, CAISO released its EDAM straw proposal. The straw proposal seeks to establish the framework for key design elements of the day-ahead market, as well as areas requiring additional work and stakeholder input.
Current plans call for implementation testing in 2023 and onboarding the first set of EDAM participants in early 2024.
Minnesota’s Brainerd Public Utilities Details Reliability Efforts, Cryptocurrency Response
May 10, 2022
by Paul Ciampoli
APPA News Director
May 10, 2022
Scott Magnuson, Superintendent for Minnesota public power utility Brainerd Public Utilities, recently detailed the steps that the utility has taken to maintain high levels of reliability and safety and explained how Brainerd Public Utilities is responding to cryptocurrency data mining operations.
“In the last several years, we have put a lot of effort into vegetation management and system protection. Making sure that when we do have an event, the damage is very limited, and crews are able to dispatch to the problem very efficiently, do some switching and get most, if not all, meters back on right away,” Magnuson noted in a Q&A with Public Power Current.
Brainerd Public Utilities has received a Reliable Public Power Provider designation from the American Public Power Association (APPA).
“Our crews, water, wastewater and hydro, along with the electric crew take great pride in our safety record,” he noted.
“We use the services of our state association, the Minnesota Municipal Utilities Association (MMUA), for our safety training for all employees, and also the JT&S for the electric crews. I am currently a MMUA board member, and my Operations Manager is on the JT&S committee, so we have direct input to what is needed for safety training, and the MMUA does an excellent job at it.”
Magnuson also provided details on cryptocurrency data mining operations being set up in the region served by Brainerd Public Utilities and detailed how Brainerd Public Utilities is responding to these operations.
“This is definitely a new one for us,” he noted.
Back in 2006, the utility started engineering a substation and feeder upgrade project. “At the time, we served a papermill in town, and population was supposed to triple by 2025. So, we decided on three 47 MVA transformers for the substation.”
However, in 2014, the papermill shut down and the population growth did not happen. “We ended up with 141 MW worth of transformers and a summer peak of 43 MW. That meant we had a lot of extra capacity. Word got out, and we were contacted by some parties interested in setting up crypto mining operations in Brainerd,” he said.
“We are currently working with one group for a 50 MW load, and a local company for a 20 MW load. Contracts are signed, and both parties are procuring their equipment. One item both parties agreed to was they would be responsible for any upgrades, or new lines, that needed to be built for their loads, which we have completed,” Magnuson noted.
He also addressed the topic of supply chain issues.
“We have not yet been impacted too bad by this dilemma,” he said. “Some equipment has been delayed a couple weeks, but we have been able to continue with our projects. Transformers are another issue; for now, we have a decent inventory, but we think single phase transformers may become an issue for us in 2023. We have not seen the influx of home EV chargers yet, but we know it is coming and are making plans.”
Magnuson said his long-term goal for Brainerd Public Utilities “is to continue to move the utility forward in an everchanging environment, and provide our customers with safe, reliable and environmentally friendly utility services. Our team takes great pride in what they do, from the staff in the office, to the guys in the field, and everyone in between. We have really formed a good bond, and my goal is to keep it that way,” he said.
“Things are changing fast in all aspects of the utility business, from state and federal mandates, to technology, to customers, and what they expect from us. We need to stay on top of the changing landscape, and make sure we are giving the customers what they demand, while maintaining an affordable product, and protecting Mother Earth.”
Additional information about the utility is available here.
Fayetteville, N.C., Utility Planning To Install 1.5-MW Biogas Fuel Cell
May 9, 2022
by Peter Maloney
APPA News
May 9, 2022
Fayetteville PWC in North Carolina plans to install a 1.5-megawatt (MW) fuel cell that would be powered by multiple biogas streams.
The project is designed to use biogas captured from the public power utility’s Cross Creak Water Reclamation facility, an adjacent landfill, and methane gases captured from local and neighboring swine farms.
The Bloom Energy fuel cell is planned to sit next to the utility’s P.O. Hoffer water treatment facility and will be one of the first of its kind to blend multiple waste gas sources to produce clean, carbon dioxide-neutral electricity, Fayetteville PWC said.
“This project is an anchor for the broader plan to remediate and establish a Cleanfields Renewable Energy Demonstration Park in the community,” Elaina Ball, CEO and general manager of Fayetteville PWC, said in a statement.
The waste-to-energy project will complement the utility’s existing renewable energy sources and help the utility meet North Carolina Renewable Energy and Energy Efficiency Portfolio Standard requirements, by reducing harmful landfill and agricultural gases and providing pollution free electricity, PWC said.
“This is an innovative project that addresses both our challenging renewable energy mandates and one of the state’s largest industrial polluted sites,” Ball said. “We are excited that the project not only brings creative solutions but numerous other benefits including producing renewable energy, cutting power costs and productive use of local waste gases.”
The fuel cell installation would also border the former Texfi industrial site, which is considered one of North Carolina’s most polluted sites because of residual industrial pollution and contaminated groundwater that poses a threat to the community’s drinking water and the Cape Fear River Basin.
After seeking funds since the early 2000s, the City of Fayetteville and PWC received $220,000 in funding from the state to help launch a pilot program for removing the contaminated groundwater, which is now under way.
Fayetteville PWC is also contributing an additional $220,000 for the project. If proven successful, the pilot technology would be used in full-scale remediation efforts.
Once remediated, plans call for a 250-acre park to be developed into the state’s second Cleanfield Renewable Energy Demonstration Park, where renewable energy resources like fuel cells would be located.
Fayetteville PWC provides electricity to 80,000 customers and water services to 225,000 customers.