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APPA Comments on DOE Implementation Strategy for Grid Resilience Program

October 21, 2022

by Paul Ciampoli
APPA News Director
October 21, 2022

The American Public Power Association (APPA) recently submitted comments in response to a Department of Energy (DOE) Request for Information (RFI) on its implementation strategy for the Grid Resilience and Innovation Partnerships (GRIP) program.

GRIP is part of the Infrastructure Investment and Jobs Act (IIJA). It is aimed at enhancing grid flexibility and improving the resilience of the power system. Under GRIP, $10.5 billion in grants are available through three programs: Grid Resilience Grants ($2.5 billion), Smart Grid Grants ($3 billion), and Grid Innovation Program ($5 billion).

Among other things, DOE asked for feedback on what actions it can take to best achieve the benefits of coordinating applications to all three Grid Resilience and Innovation Partnerships topic areas at the same time.

In response, APPA said it supports DOE’s initiative to stage the application process so that applicants are able to submit a white paper before being asked to complete a full application.

“DOE could further reduce the barrier that exists for smaller entities by establishing teaming lists, as it has done for other opportunities, so that utilities may find technology partners who wish to demonstrate innovative approaches at scale, and by staggering the initial application windows by topic area,” APPA said.

A single application window for all three programs in GRIP could cause smaller entities wishing to apply to more than one topic to choose just one area, while larger utilities with more resources to direct to the application process would be able to mount multiple applications, APPA said.

“Further, DOE could provide more than 30 days between receipt of an Encourage notification to mount a completed application.”

APPA also addressed the question of how can funding from the GRIP program can best overcome challenges impeding the development of transmission, grid solutions, and interconnecting new generation and storage to improve grid resilience and reliability.

APPA believes that “these challenges may be overcome by encouraging joint action between smaller public power utilities to collectively deploy grid-edge solutions for grid resilience.”

It noted that many smaller public power utilities do not have the resources or volume of meters necessary to deploy advanced metering infrastructure (AMI) and distributed energy resource management systems (DERMS) at an affordable scale, nor the capacity to analyze the data and manage distributed energy resources (DERs) to maximize benefits and reduce impacts to the grid.

“By funding joint action agencies to deploy and manage these systems on communities’ behalf, it will enable a more resilient, modern grid within rural public power communities. Access to acreage for renewable energy deployment behind the community’s meter is not readily available in many communities.”

Instead, communities can utilize behind-the-retail meter assets, such as rooftop solar photovoltaic generation and energy storage, to help stabilize the grid and dispatch loads to meet local and regional intermittent carbon-free generation resource availability, thus mitigating the need for increased transmission infrastructure, the trade group said.

Additionally, GRIP should take into consideration the ongoing costs of maintaining the additional capabilities dedicated to resilience. Most of these capabilities are not cost advantageous nor cost recoverable from customers, and are not viewed as a valued investment by shareholders, APPA added.

DOE also asked for feedback on whether existing or expected supply chain concerns are anticipated to delay or impact development of potential applications or project implementation, if awarded.

“APPA and other industry groups have done extensive surveying of utility supply chain concerns. Lead times for transformers prior to the COVID-19 pandemic were typically three to four months, but now most utilities are experiencing lead times of over a year, and many are seeing lead times of as much as 18-24 months.”

APPA said there are also significant backlogs in other essential components, including meters. “Additionally, supply constraints are impacting goods associated with advances in grid infrastructure. The microchip shortage, as well as increased constraints related to lithium-ion batteries, mean that projects involving these components may experience significant delays.”

Labor issues are also a concern, “as almost all parties – utilities, suppliers, manufacturers – are having trouble in hiring and retaining employees. This is only exacerbating the supply chain issues almost all utilities face and may create further backlogs. An increased flow of money into this sector will also increase demand for components, furthering potential delays.“

DOE will need to factor project delays into its timetable and be flexible regarding project timetables, APPA said. “Flexibility can be defined as tolerance for a marked-up product price within a grant budget and a no-cost extension of the project work plan for up to one-year, when requested by the awardee, to accommodate the longer window of time for performance due to the delayed delivery of a product.”

APPA also addressed the timing related to the first application cycle for the GRIP program, saying it is concerned with the relatively brief turnaround time.

Having the application cycle open in November may be too soon for DOE to thoughtfully incorporate public comments from the RFI process (due October 14) into the final funding opportunity announcement (FOA), it said.

“Utilities may struggle to identify projects that are good candidates for grant funding, particularly under section 40101(c).  Most utilities have an existing backlog of dozens, if not hundreds of projects, that fit the descriptions in the program, but this backlog of necessary projects is in some tension with the requirement of additionality.”

 Applicants are not accustomed to prioritizing projects based on grant program guidelines and may benefit from reviewing a revised draft FOA for several weeks, after DOE has incorporated comments from stakeholders and before the application window opens, APPA said. “Releasing the FOA in December, with concept papers due at the end of January and full applications due at the end of April would minimize conflicts due to the holidays and allow applicants more time to convene partnerships and obtain letters of support.”

APPA also said that smaller public power utilities often lack dedicated staff to work through the application process. “DOE could consider covering the cost of grant writers and compliance managers as this would be helpful to public power utilities who lack the requisite staff resources. A shorter application could also be helpful to smaller public power utilities. Any sort of assistance from DOE could also be coordinated through JAAs.” 

APPA and its members are also concerned about the $100 million cap on the federal share of grant allocations. “While DOE has expressed that this is not intended to be the target amount awarded for each project, many potential applicants may interpret by this cap to mean that only the largest and most ambitious efforts will be awarded. Since the federal share is no more than half of the project cost, smaller utilities will perceive the effective project costs to be $200 million or greater, and very few, if any, small utilities could reach this amount.” 

Lowering the federal share cap would provide additional room to make a greater number of awards, including awards to smaller utilities and smaller projects. This would allow DOE to have a larger impact by supporting a greater number of utilities, and with a wider geographic distribution (and for other factors) as opposed to a consolidation of funding in only a few companies in a few regions. A lower cap may also assuage the concerns of potential applicants who do not think their own efforts will receive serious consideration, the trade group said.

EV Fires in Wake of Florida Flooding Draw Scrutiny

October 21, 2022

by Paul Ciampoli
APPA News Director
October 21, 2022

U.S. Sen. Rick Scott, R-Fla., and other officials from the state are seeking answers from electric vehicle (EV) makers and the U.S. Department of Transportation (DOT) in the wake of EVs catching fire due to flooding that occurred with Hurricane Ian, which hit Florida in late September.

In an Oct. 13 letter to Pete Buttigieg, Secretary of Transportation, Scott said that along with the damage caused by the storm itself, “the saltwater flooding in several coastal areas has had further destructive consequences in the aftermath of Hurricane Ian by causing the lithium ion batteries in flooded electric vehicles (EVs) to spontaneously combust and catch fire.”

He said that this “emerging threat has forced local fire departments to divert resources away from hurricane recovery to control and contain these dangerous fires.”

Scott said that the current guidelines from EV manufacturers on the impacts of saltwater submersion on the operability of the vehicles does not adequately address the issue. “As increasing numbers of EVs come to market nationwide, this threat demands action by the U.S. Department of Transportation to develop guidance to properly caution consumers about this risk posed by EVs submerged in saltwater,” he wrote.

Scott asked Buttigieg to respond to the following questions:

In a separate Oct. 13 letter to EV manufacturers, Scott asked them to answer the following questions:

Florida Fire Marshal Also Seeks Answers

Meanwhile, Florida Chief Financial Officer (CFO) and State Fire Marshal Jimmy Patronis on Oct 17 sent a letter to more than 30 EV manufacturers, including Tesla, Rivian, Ford, GM, and others.

In the letter, Patronis asked EV manufacturers to do more in helping firefighters mitigate risks associated with battery fires caused by salty storm surge waters from Hurricane Ian.

He also asked nine questions of the manufactures to assess and identify methods to limit the risk of EV fires.

In his letter to Elon Musk, Tesla’s CEO, Patronis said that the National Highway Transportation Safety Administration (NHTSA) recently confirmed that test results specific to saltwater submersion show that salt bridges can form within the battery pack and provide a path for short circuit and self-heating, which in turn can lead to fire ignition.

The federal agency also confirmed that, “Lithium-ion vehicle battery fires have been observed both rapidly igniting and igniting several weeks after battery damage occurred.”

Patronis on Oct. 7 sent a letter to the NHTSA requesting information on the fire risks associated with saltwater on EVs.

EV makers Rivian and Tesla did not respond to questions from Public Power Current for the story.

Groups Urge DOE to Prioritize Funding Toward Production of Distribution Transformers

October 21, 2022

by Paul Ciampoli
APPA News Director
October 21, 2022

The American Public Power Association (APPA) and the National Rural Electric Cooperative Association (NRECA) recently sent a letter to Department of Energy (DOE) Secretary Jennifer Granholm urging the prioritization of funding toward the production of distribution transformers.

“Throughout 2022 we have been calling attention to the unprecedented challenges our members, representing the nation’s not-for-profit, community-owned and rural electric utilities, are facing in procuring basic equipment needed to provide reliable electric service to Americans, as well as in restoring power following storms and natural disasters, particularly with regard to distribution transformers,” wrote Joy Ditto, President and CEO of APPA, and Jim Matheson, CEO of NRECA in their Oct. 19 letter.

They noted that under Granholm’s leadership, the Electricity Subsector Coordinating Council stood up a Tiger Team to work with the federal government to address the supply chain crisis and identify solutions that will resolve current and long-term constraints.

“We’ve surveyed our members to provide the latest information to the Tiger Team and they report waiting on average a year or more for distribution transformers. Projects are now being deferred or canceled, and utilities are concerned about their ability to respond to more than one major storm in a season due to their depleted stockpiles,” noted Ditto and Matheson.

The Department of Energy (DOE) was allocated at least $250 million from the Inflation Reduction Act (IRA) to execute on Defense Production Act (DPA) authorities.

“To our knowledge, the IRA gives DOE discretion to use the funds on any technology invoked under DPA. We respectfully urge you to reconsider your plan to use the entirety of the funds for heat pumps and instead put at least some of the funds to immediately increase distribution transformer production,” the trade group leaders said.

Issues around labor have been identified as the most immediate challenge for manufacturers. “We urge DOE to establish a $220 million wage subsidy program that would assist manufacturers in attracting and retaining more workers, thus enabling them to move to 24/7 operations. We believe such a program could result in increased output of approximately 30 percent of distribution transformers in 2023 and support the workforce keeping the lights on in our country.”

While the trade groups support long-term investment in domestic manufacturing capacity for heat pumps, “we believe the current shortage of distribution transformers available to electric utilities poses an unacceptable risk to the electric reliability of our nation and urge you to alleviate this unprecedented situation by prioritizing available IRA funding for transformers,” Ditto and Matheson said.

“If we don’t act today, we risk being unable to recover from a storm tomorrow. In the longer term, it could mean being unable to meet the electrification goals envisioned by the Biden administration. In the meantime, the backlog for distribution transformers continues to grow.”

Household Energy Prices Expected to Increase Sharply This Winter: EIA

October 20, 2022

by Peter Maloney
APPA News
October 20, 2022

Household energy prices will increase broadly this winter on expectations of higher retail energy prices and a slightly colder winter, according to the latest short-term forecast from the Department of Energy’s Energy Information Administration (EIA).

Retail heating oil prices will be 19 percent higher than last winter, reflecting price pressures in the distillate fuel oil market: low inventories, low imports, and limited refining capacity, the EIA said in its Winter Fuels Outlook, which is part of its Short-Term Energy Outlook (STEO). Natural gas prices are expected to be 21 percent higher than last winter, but propane prices are forecast to fall by 2 percent this winter, according to the EIA. The Winter Fuels Outlook reflects consumption across all residential energy uses, not just home heating.

Changes in wholesale heating oil and propane prices pass through to retail prices much more quickly than changes in wholesale natural gas or electricity prices, the EIA said.

With almost 90 percent of U.S. homes heated primarily by natural gas or electricity and with higher expected wholesale prices for natural gas this winter, the EIA forecasts higher retail prices for both natural gas and electricity this winter.

The EIA is forecasting Henry Hub natural gas spot price to average about $7.40 per million British thermal units (MMBtu) in the fourth quarter and then fall below $6.00/MMBtu in 2023 as gas production rises.

Natural gas consumption, on the other hand, will average 87.9 billion cubic feet per day (Bcf/d) in 2022, up 3.9 Bcf/d from 2021, reflecting more consumption across almost all sectors, the EIA said. The agency sees natural gas consumption falling by 2.6 Bcf/d in the 2023 because of lower consumption in the electric power and industrial sectors.

The EIA also forecasts a rise in electricity sales of 2.7 percent in 2022, mostly as a result of higher economic activity but also because of slightly hotter summer weather than last year. The agency sees electricity sales falling by 0.9 percent in 2023.

Meanwhile, wholesale electricity prices will be about 20 to 60 percent higher on average this winter with the largest increases likely in New England because of possible natural gas pipeline constraints, reduced fuel inventories for power generation, and uncertainty regarding liquefied natural gas shipments given the tight global supply conditions, the EIA said.

On the residential side, the EIA expects electricity will average 14.9 cents per kilowatt hour in 2022, up 8 percent from 2021, reflecting the expected increase in wholesale power prices driven by higher natural gas prices.

Natural gas will fuel 38 percent of electricity generation in 2022, up from 37 percent in 2021, but will fall to 36 percent in 2023, the EIA forecasts.

Electric generation fired by coal is expected to continue to fall, from 23 percent last year to 20 percent in 2022 and 19 percent in 2023 because of the expected retirement of some coal-fired capacity, the EIA forecasts.

Renewable generation sources, meanwhile, continue to gain ground, providing 22 percent of generation in 2022 and 24 percent in 2023, up from 20 percent in 2021, the EIA said.

Ultimate Public Climate Spending Spurred by Inflation Reduction Act Could be Over $800 Billion: Credit Suisse

October 19, 2022

by Paul Ciampoli
APPA News Director
October 19, 2022

Citing the uncapped nature of tax credits and attractiveness of economics, investment firm Credit Suisse is estimating that the ultimate public climate spending enabled by the Inflation Reduction Act (IRA) could be over $800 billion.

“We see most of the upside coming from solar, wind, battery deployment and manufacturing, clean hydrogen, and carbon capture,” Credit Suisse analysts wrote in a recent report on the IRA. “With subsidized green financing and the multiplier effect on federal grants/loans, the total public plus private financing could reach ~$1.7 trillion over ten years,” it said.

President Biden on Aug. 16 signed into law the IRA, which will extend and expand various energy tax incentives and give public power utilities direct access to such credits through a refundable direct payment tax credit.

The report said that roughly two-thirds of the baseline IRA spending is “allocated to provisions where the potential federal incentive is uncapped, meaning the ultimate outlay is either based on units of production or upfront capital spent.”

Therefore, Credit Suisse believes the Congressional Budget Office “is significantly underestimating costs of certain provisions as the attractiveness of credits could propel much higher activity levels, particularly in green manufacturing, carbon capture and clean hydrogen.”

Using its own forecasts, “we see federal climate spending at over $800 billion, doubling the baseline of >$400 billion. Combined with the multiplier effect on private investments and green financing programs, total spending could reach nearly $1.7 trillion over the next ten years.”

Credit Suisse said that the new credits in the IRA provide long-term certainty, flexibility on the choice of credits and are technology-agnostic.

“Combined with the manufacturing tax credits, the US should benefit from the lowest levelized cost of clean electricity in the world,” the report said.

Permitting uncertainty remains the single biggest execution risk in Credit Suisse’s view in reaching the full potential of the IRA, particularly around transmission, carbon dioxide Class VI permits, and future green infrastructure buildouts.

In a recent article in the Atlantic, Robinson Meyer breaks down the Credit Suisse report’s key conclusions and offers his own predictions about the impact of the IRA on the energy sector.

APPA’s Joy Ditto Details How Public Power Will Benefit From Inflation Reduction Act

Joy Ditto, President and CEO of the American Public Power Association, recently detailed how public power utilities are poised to benefit from the IRA.

“We’ve been working on this for over twenty years,” said Ditto on a recent episode of White House Chronicle, which is hosted by Llewellyn King.

Since the 1992 Energy Policy Act, “we’ve been looking at this idea of parity or comparability in the tax code for publicly-owned utilities, for other not-for-profit utilities like rural co-ops so that we can really be unleashed in the marketplace as we continue to drive toward a cleaner energy future,” she said.

The mechanism in the IRA, a refundable direct pay credit, “allows us to take advantage of these tax credits that have been available to our for-profit brethren for many years both in the form of an investment tax credit and a production tax credit.”

Interconnection Costs Have Risen Steeply in MISO: Berkeley Lab Report

October 18, 2022

by Peter Maloney
APPA News
October 18, 2022

The costs to interconnect wind, solar and storage projects in the Midcontinent Independent System Operator (MISO) region have nearly doubled and, in some cases, nearly tripled over the last 18 years, according to a study by the Lawrence Berkeley National Laboratory.

For projects that have completed all required interconnection studies, average costs for more recent projects have nearly doubled relative to historical costs from 2000 through 2018, and for projects still moving through MISO’s interconnection queue costs have more than tripled over the last four years, the report, Generator Interconnection Cost Analysis in the Midcontinent Independent System Operator (MISO) territory, found.

Specifically, costs averaged $102 per kilowatt (kW) for projects that have completed interconnection studies between 2019 and 2021. Active projects had even higher interconnection costs of $156/kW on average. Withdrawn projects had the highest costs, $452/kW, on average, which was “likely a key driver for those withdrawals,” the report’s authors said.

Irrespective of request status, wind projects had the highest interconnection costs at $399/kW, followed by energy storage at $248/kW, and solar at $209/kW. Natural gas projects were at the lowest end of cost scale at $108/kW.

Wind projects that completed the interconnection study process in 2021 had even higher costs, $252/kW on average, nearly four times the historical average, the report found. And wind projects that ultimately withdrew from the queue had average interconnection costs of $631/kW, equivalent to 40 percent of total project costs.

Even though larger generators have greater interconnection costs in absolute terms, the study found that economies of scale exist on a per kilowatt basis with medium wind and solar projects facing twice the potential interconnection costs of very large wind and solar projects.

Interconnection costs also vary by location, the authors noted. Projects in eastern MISO reported overall lower costs, irrespective of request status – on average $50-$70/kW – than requests in northern MISO and parts of Texas with average costs of $508-$915/kW.  

Projects requiring network upgrades beyond the interconnecting substation explain most of the sharp rise in cost differences, the report found. For instance, among withdrawn projects broader upgrades accounted for an average of $388/kW for recent projects, or 85 percent of total interconnection costs, the authors said.

Berkeley Lab gathered estimated interconnection costs from project-specific MISO interconnection studies, representing nearly 50 percent of all projects requesting interconnection between 2010 to 2020, or 30 percent when going back to 2000.

While the data is “sufficiently robust for detailed analysis,” the authors noted that much data remains unavailable to the public, which “poses a significant information barrier for prospective developers, resulting in a less efficient interconnection process.”

At year-end 2021, MISO had over 160 gigawatts (GW) of generation and storage capacity actively seeking grid interconnection. Most of the projects are solar, 112 GW, followed by wind, 22 GW. MISO’s interconnection queue also has data for 366 GW of withdrawn projects and 62 GW of in-service projects.

MISO’s 2022 generator interconnection queue is set to break those past levels, increasing by 220 percent over 2021 levels, if all project submissions are accepted as valid. If that is the case, MISO’s queue would balloon to 289 GW, with more than 95 percent of the submissions either renewable or energy storage projects, the report said.

The capacity associated with those requests is more than twice as large as MISO’s peak load in recent years of about 120 GW, the report’s authors noted. And, if substantial amounts of those projects are built, they “will likely exert competitive pressure on existing generation,” the authors said, noting, however, that “most projects have historically withdrawn their applications, often in response to high interconnection costs.” Only 24 percent of all projects requesting interconnection between 2000 and 2016 have ultimately achieved commercial operation at the end of 2021, they noted.

Washington State Moves Closer to Launching GHG Cap-and-Trade Program

October 18, 2022

by Peter Maloney
APPA News
October 18, 2022

Washington State’s Department of Ecology is in the process of finalizing regulations for a greenhouse gas (GHG) cap-and-trade program, the second of its kind in the nation.

Under the state’s Climate Commitment Act, passed in 2021, the Department of Ecology is required to implement the program by Jan. 1, 2023.

Under the cap-and-invest program, businesses and organizations responsible for 75 percent of Washington’s greenhouse gas emissions will have to obtain allowances to cover their emissions. Over time, the number of allowances will be reduced, incentivizing businesses to cut emissions.

Some allowances will be awarded with no charge while others will be sold at quarterly auctions, with the first auction planned for the second half of February 2023. The proceeds of the auctions will be invested in emissions reduction programs and preparing Washington communities for the effects of climate change, especially those that deal with more air pollution than others.

The cap-and-invest program is the cornerstone of a suite of climate policies in Washington State that aim to increase the number of zero-emission vehicles on the road, accelerate the switch to cleaner transportation fuels, and move away from coal. State law requires those policies to meet Washington’s goal of reducing greenhouse gas emissions 95 percent by 2050, with remaining emissions to be offset.

California in 2013 began the first emissions cap-and-trade program in the United States. The program applies to emissions that cover about 80 percent of the state’s GHG emissions. In January 2014, California linked its cap-and-trade program with Quebec’s program.

On the East Coast, seven states signed a memorandum of understanding in 2005 to form the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort to reduce their carbon dioxide (CO2) emissions using a regional cap-and-invest market mechanism.

Each state sets CO2 emission limits from its electric power plants, issues CO2 allowances and establishes participation in regional CO2 allowance auctions. The program went into effect in January 2009.

Federal Government Sets California Offshore Wind Energy Lease Sale for December 6

October 18, 2022

by Paul Ciampoli
APPA News Director
October 18, 2022

The Bureau of Ocean Energy Management (BOEM) will hold an offshore wind energy lease sale on Dec. 6, 2022, for areas on the Outer Continental Shelf (OCS) off central and northern California, the Department of Interior said on Oct. 18.

This will be the first-ever offshore wind lease sale on America’s West Coast and the first-ever U.S. sale to support potential commercial-scale floating offshore wind energy development.

“This sale will be critical to achieving the Biden-Harris administration’s deployment goals of 30 gigawatts (GW) of offshore wind energy by 2030 and 15 GW of floating offshore wind energy by 2035,” Interior said. BOEM is part of Interior.

In May 2021, Interior Secretary Deb Haaland and California Governor Gavin Newsom joined Biden-Harris administration leaders to announce an agreement to advance areas for wind energy development offshore the northern and central coasts of California.

The California sale reflects the leasing path announced last year by Haaland and last month’s announcement of a new deployment goal of 15 GW of floating offshore wind energy by 2035.

BOEM will offer five California OCS lease areas that total approximately 373,268 acres with the potential to produce over 4.5 GW of offshore wind energy.

To date, BOEM has held 10 competitive lease sales and issued 27 active commercial wind leases in the Atlantic Ocean from Massachusetts to North Carolina.

The California Final Sale Notice (FSN), which will publish in the Federal Register later this week, provides detailed information about the final lease areas, lease provisions and conditions, and auction details. It also identifies qualified companies that can participate in the lease auction.

The FSN includes three lease areas off central California and two lease areas off northern California.

It also includes several lease stipulations designed to promote the development of a robust domestic U.S. supply chain and advance flexibility in transmission planning.

Among the stipulations announced Oct. 18, BOEM will offer bidding credits for bidders that enter into community benefit agreements or invest in workforce training or supply chain development; require winning bidders to make efforts to enter into project labor agreements; and require engagement with Tribes, underserved communities, ocean users, and agencies.

More information about the FSN and lease stipulations, a map of the area, the list of qualified bidders for the auction, and auction procedures is available on BOEM’s California website.

Newly Energized Kansas Transmission Line to Benefit Members of KPP Energy

October 18, 2022

by Paul Ciampoli
APPA News Director
October 18, 2022

The Kingman to Cunningham Direct Connect transmission line in Kansas was recently completed and put into service, KPP Energy announced. KPP Energy was formerly known as the Kansas Power Pool.

The project includes 4 ½ miles of 34,500-volt electric lines and a 115,000/34,500-volt substation, KPP Energy reported in the September 2022 issue of its “Lightning Round” newsletter.

The substation is an entirely new facility. The 4 ½ miles of line will connect the substation to a 34,500-volt electric line approximately two miles north of Cunningham built and owned by the City of Kingman, Kansas.

KPP Energy estimates the new facilities will cost its membership around $400,000 a year but will save those members $500,000 a year in avoided transmission service costs and full provision of services to Kingman.

In addition, KPP Energy estimates that Kingman will save over $100,000 a year in generation costs, an estimate made when natural gas costs were approximately 1/3 of what they are today, the Lightning Round article noted. Moreover, Kingman, as a member of KPP Energy, will also share in KPP Energy’s savings.

The project, combined with recent upgrades Kingman has made to its electric facilities in town, will allow Kingman’s generation to be fully utilized by the wholesale electric market, the article pointed out.

“Furthermore, as an added benefit, other nearby communities will benefit by having this important local source of generation available to provide wholesale generation service when other resources are not available or limited,” the article said.

Now, for the first time in its history, “Kingman is fully interconnected with the transmission grid and has the capability of providing electric service to all its current customers and to meet the needs of future development opportunities as they arise.”

Additional details about the project and its background are available in the Lightning Round newsletter by clicking here.

For additional information about KPP Energy, click here.

OPPD Reports Progress In Adding Solar, Gas Generation Despite Challenges

October 18, 2022

by Peter Maloney
APPA News
October 18, 2022

Omaha Public Power District says that, despite challenges, it is making progress on plans to add 600 megawatts (MW) of utility-scale solar and 600 MW of natural gas generation to its portfolio.

The Nebraska public power utility said the new generating resources, which are being built under its Power with Purpose initiative, will help maintain the long-term reliability and resiliency of its electric system while supporting its goal of becoming a net-zero carbon dioxide emitter by 2050.

OPPD is working on procuring the major equipment needed for its 81-MW Platteview Solar project in Saunders County for which about 30 percent of the civil and electrical design work is already complete.

OPPD is also developing a plan for pollinator friendly ground cover at the solar site that conforms with its Prairies in Progress project that aims to reduce landscape maintenance costs while providing habitat for butterflies and bees.

Progress on the solar project comes despite the challenges posed by the U.S. Department of Commerce’s investigation into foreign solar panel imports. In March, Commerce began an investigation into whether certain photovoltaic solar cells and modules imported from Southeast Asia are circumventing U.S. tariffs.

The deadline for a preliminary determination was pushed back from late August to November 28. A final determination is now likely in the spring of 2023, OPPD said. The utility said it continues “to closely follow developments to determine potential impacts and the best path forward as we bring on additional” solar projects.

OPPD has also completed the process of delivering nine Wärtsilä reciprocating internal combustion engines to Standing Bear Lake Station, the natural gas-fired generation balancing project that the utility is building.

Later this fall, OPPD said two Siemens simple-cycle combustion turbines and generators will be moved to the Turtle Creek Station, the site of its other new natural gas-fired generation balancing station project. Meantime, the utility’s construction team is building the infrastructure to support the plant. Both plants are scheduled to be completed by 2024.

Standing Bear Lake station will be capable of generating 150 MW, and the Turtle Creek station will be able to generate 450 MW, OPPD spokeswoman Julie Wasson said.

Separately, OPPD’s board of directors approved a recommendation by utility management to revise a policy directive to include a target of reducing carbon dioxide (CO2) emissions at its North Omaha Station (NOS) plant site by 3.5 million tons annually, compared with 2013 emission levels, by 2027.

The revision coincides with the utility’s anticipated timeline for the retirement of NOS Units 1-3, which were previously converted from low-sulfur coal to natural gas, and the conversion of Units 4 and 5 from low-sulfur coal to natural gas.

In August, the board approved a recommendation to temporarily postpone that transition until the utility’s new natural gas generation balancing plants are fully studied and approved for grid interconnection service in accordance with Federal Energy Regulatory Commission rules.