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Despite Possible Fuel Constraints, FERC Sees Sufficient Supplies For This Winter

October 27, 2022

by Peter Maloney
APPA News
October 27, 2022

Despite some possible regional fuel constraints, electricity markets will have sufficient capacity to maintain reliable operations this winter, under normal winter conditions, according to a report from staff at the Federal Energy Regulatory Commission (FERC).

“All regions anticipate adequate reserve margins, although extreme winter events may stress operations,” the authors of the report, Winter Energy Market and Reliability Assessment 2022-2023, wrote.

Extreme weather events aside, this winter could be mild for much of the country, implying lower-than-average electric and natural gas demand, the report said citing data from the National Oceanic and Atmospheric Administration (NOAA).

Although prolonged cold weather could cause disruptions and price impacts, the long-term NOAA data suggests a 50 percent to 80 percent likelihood of higher-than-average temperatures in Southern California, the Desert Southwest, Texas, and the Eastern Seaboard, with lower-than-average temperatures expected for the Northwest and the West North Central regions.

Natural gas prices, which set the marginal cost of wholesale electric power for much of the country, are expected to remain higher than they have been in recent years, the report said.

Despite the expectation that natural gas production will be 3.2 percent above last winter and will outpace the expected 2.4 percent increase in domestic natural gas demand growth, forecasts anticipate that continued growth in net exports, including from liquified natural gas (LNG) export facilities, that will place additional upward pressure on natural gas prices this winter. The Henry Hub natural gas futures contract price is averaging $6.82 per million British Thermal Units (MMBtu) for winter 2022-2023, up 30 percent from last winter’s settled price, the report said.

Natural gas supplies will continue to experience constraints in New England and California may also face constraints this winter due to ongoing pipeline outages, which could lead to higher natural gas and electricity prices, the report said. The authors, however, added that ISO-NE expects to maintain reliability this winter under mild and moderate winter conditions and has concluded it does not need a dedicated winter reliability program, unlike in past years.

The report also noted that supply constraints may affect coal deliveries and coal stockpiles this winter across regions that have relied on increased coal-fired generation during recent stress periods, including the Southwest Power Pool, the Midcontinent ISO (MISO), the Electric Reliability Council of Texas, the SERC Reliability Corp. in the Southeast, and the PJM Interconnection.

Meanwhile, the generation addition and retirement patterns that have prevailed for the past several years will continue through the winter.

The U.S. will add 43 gigawatts (GW) of net winter capacity between March 2022 and February 2023, mostly from wind and solar power, while 15 GW of net winter capacity, mostly coal-fired plants, are expected to retire during the same period, the report said.

Nearly 6,700 line-miles of new transmission lines and transmission upgrades are expected to have come online through this winter, mostly in the MISO, PJM, and Southeast regions, the report said.

Forecast generation and transmission additions could change or be delayed, however, as regions are reporting some projects are being impacted by component unavailability, shipping delays, and labor shortages, the report said.

Department of Energy Seeks Input on Bolstering Cybersecurity for Public Power

October 24, 2022

by Paul Ciampoli
APPA News Director
October 24, 2022

The U.S. Department of Energy (DOE) recently issued a request for information (RFI) seeking public input on a new $250 million program to bolster the cybersecurity posture of rural, municipal, and small investor-owned electric utilities.

The Rural and Municipal Utility Advanced Cybersecurity Grant and Technical Assistance (RMUC) Program will help eligible utilities cyber harden energy systems, processes, and assets; improve incident response capabilities; and increase cybersecurity skills in the utility workforce, DOE said.

The RMUC program will provide financial and technical assistance to help rural, municipal, and small investor-owned electric utilities improve operational capabilities, increase access to cybersecurity services, deploy advanced cyber security technologies, and increase participation of eligible entities in cybersecurity threat information sharing programs.

Priority will be given to eligible utilities that have limited cybersecurity resources, are critical to the reliability of the bulk power system, or those that support our national defense infrastructure. 

The Office of Cybersecurity, Energy Security, and Emergency Response (CESER) will manage the RMUC Program, providing $250 million dollars in funding over five years.

To help inform program implementation, DOE is seeking input from the cybersecurity community, including eligible utilities and representatives of third parties and organizations that support or interact with these utilities.

The RFI seeks input on ways to improve cybersecurity incident preparedness, response, and threat information sharing; cybersecurity workforce challenges; risks associated with technologies deployed on the electric grid; national-scale initiatives to accelerate cybersecurity improvements in these utilities; opportunities to strengthen partnerships; the selection criteria and application process for funding awards; and more.  

DOE hosted a series of listening sessions for utilities and stakeholders to ask questions and provide feedback that will help inform the development and implementation of the RMUC program. The final listening session will take place on October 25, 2022. For more information and to register, go here. 

Responses to the RFI must be submitted via email to DE-FOA-0002877@netl.doe.gov by 5:00 p.m. ET on December 19, 2022. Download the RFI to see the full list of questions, topics of interest, and submission guidelines. 

The American Public Power Association plans to submit comments in response to the RFI and welcomes member feedback. Members can contact Bridgette Bourge, Senior Director for Cybersecurity at APPA, at Bbourge@publicpower.org with thoughts on this RFI.

For additional information, visit the RMUC Program webpage on CESER’s website. 

Electrify America Unveils First Application of Megawatt-Level Battery Storage System

October 22, 2022

by Paul Ciampoli
APPA News Director
October 22, 2022

Electrify America recently unveiled its first application of a megawatt-level battery energy storage system (BESS) for electric vehicle (EV) charging stations.

The move builds upon the company’s existing BESS installations at over 150 stations across the U.S., including more than 100 installations in California. 

The megawatt-level energy storage system combined with a solar canopy goes a step further than Electrify America’s existing BESS in managing energy costs and reducing stress on the grid by acting as a buffer to supplement power to charging stations when local utilities limit the amount of power a station can draw from the grid, it said.

“This application leverages energy storage and solar as a ‘non-wires alternative’ in lieu of relying on additional utility ‘wired’ infrastructure (i.e. power lines) that may not be feasible,” Electrify America said.

Such innovative approaches become critical to expand EV charging into more remote areas to reach more consumers where utilities may not be able to deliver the capacity needed to install or expand charging infrastructure, it added.

Electrify America selected the Baker station in California for the first deployment of the megawatt-level energy storage system because of its remote location and its utility capacity constraints. The project involves the integration of roughly 1.5 MW/3 MWh energy storage system with 66 kW of generation potential from the solar canopy.

The energy storage deployment builds upon Electrify America’s previous announcement of having surpassed over 30 megawatts of installed energy storage now featured at over 150 locations.

In California, over 50 charging stations coupled with energy storage constitute the largest operating Virtual Power Plant (VPP) of its kind shifting the use of on-peak energy to lower carbon intensity off-peak hours in the California Independent System Operator’s wholesale energy market.

Electrify America, a subsidiary of Volkswagen of America, is the largest open DC fast charging network in the U.S.

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.