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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.

Rhode Island Utility Seeks Up to 1,000 MW of Offshore Wind Capacity

October 18, 2022

by Paul Ciampoli
APPA News Director
October 18, 2022

Rhode Island Gov. Dan McKee on Oct. 14 announced a request for proposals has been released by Rhode Island Energy for up to 1,000 megawatts of new offshore wind capacity.

In July, McKee signed into law legislation that seeks to expand Rhode Island’s offshore wind energy resources. The new law requires a market-competitive procurement for between 600 and 1,000 megawatts of newly developed offshore wind capacity. 

This offshore wind procurement will have the potential to meet at least 30 percent of Rhode Island’s estimated 2030 electricity demand.

When added to the 30-megawatt Block Island Offshore Wind Farm and the planned 400-megawatt Revolution Offshore Wind project, about half of the state’s project energy needs will be powered by offshore wind.

The offshore wind procurement RFP will be posted at the following website: https://ricleanenergyrfp.com/. 

Offshore wind project proposals by bidders will be due to Rhode Island Energy on February 1, 2023.

Recent California Energy Storage Battery Fire Draws Renewed Attention to Storage Safety Issues

October 17, 2022

by Paul Ciampoli
APPA News Director
October 17, 2022

A recent fire at a battery storage facility in California is bringing fresh attention to safety issues tied to energy storage as the technology grows in deployment across the U.S.

The fire occurred in September 2022 at Pacific Gas & Electric’s (PG&E) Moss Landing battery storage facility in California. The fire was isolated to a single battery pack at the facility, according to the County of Monterey, Calif.

PG&E in April announced the commissioning of its 182.5-megawatt (MW) Tesla Megapack battery energy storage system – known as the Elkhorn Battery – located at its Moss Landing electric substation in Monterey County.

The Elkhorn Battery system was designed, constructed, and is maintained by both PG&E and Tesla, and is owned and operated by PG&E.

An editorial in California’s Santa Cruz Sentinel newspaper said that while the move to energy storage will continue, the Moss Landing fire “was also a reminder that battery blazes are becoming increasingly common and destructive – and safety measures, including fire drills, for residents around storage facilities will have to be put in place and widely disseminated.”

Arizona Also Experiences Incidents With Storage Fires

California is not the only state where energy storage facilities have experienced fires.

In neighboring Arizona, investor-owned Arizona Public Service (APS) in 2020 released the findings of an investigation into an incident that occurred at an APS battery storage site in 2019.

Around 5 p.m. on April 19, 2019, there were reports of smoke from the building housing the energy storage system at APS’s McMicken site in Surprise, Ariz.

Hazardous Material units and first responders arrived on scene to secure the area. Approximately three hours after the reports of smoke and shortly after the door was opened, the site experienced a catastrophic failure. Injured first responders were transported to area hospitals.

An investigation led by APS, with first-responder representatives, the system integrator, manufacturers and third-party engineering and safety experts, was conducted to determine the cause of the incident and identify lessons that can be applied to future battery energy storage systems.

The investigation involved a number of key stakeholders, and APS commissioned several forensic experts and nationally recognized research institutions. Once the investigative work was completed, APS chose DNV GL to combine various forensic and expert inputs into the single, consolidated report.

Among other things, the report said that the suspected fire “was actually an extensive cascading thermal runaway event, initiated by an internal cell failure within one battery cell in the BESS [battery energy storage system].”

In August 2019, an Arizona utility regulator raised questions about the safety of certain lithium-ion batteries, following fires at APS battery storage facilities.

In a letter to her fellow commissioners, commission staff and other interested parties, Commissioner Sandra Kennedy, of the Arizona Corporation Commission, said the types of lithium ion chemistries used at those facilities “are not prudent and create unacceptable risks.”

Along with the April 19 fire, Kennedy’s letter also cited a November 2012 fire at an APS storage facility at its Elden substation.

More recently, a fire broke out an energy storage facility in Chandler, Ariz., in April 2022. The incident occurred at the Dorman battery storage system, a 10 MW, 40 megawatt-hour stand-alone battery storage system in Chandler. The BESS is interconnected with and provides service to the Salt River Project. It is owned by AES Corp.

The investigation “into what happened at Chandler is still underway. We expect a determination in the coming weeks,” said AES spokesperson Gail Chalef on Sept. 26.

Standards for Energy Storage Systems

A key player in addressing concerns about energy storage technology safety issues is the National Fire Protection Association (NFPA).

“NFPA is keeping pace with the surge in energy storage and solar technology by undertaking initiatives including training, standards development, and research so that various stakeholders can safely embrace renewable energy sources and respond if potential new hazards arise,” it notes on its website.

NFPA’s safety standard, NFPA 855, “provides insight into mitigating risks and helping to ensure all installations are performed appropriately, taking into account vital life safety considerations,” NFPA states. The standard “offers comprehensive criteria for the fire protection of ESS installations based on the technology used in ESS, the setting where the technology is being installed, the size and separation of ESS installations, and the fire suppression and control systems in place.”

And cities are proactively taking steps to address storage-related safety issues. The New York City Fire Department in 2019 adopted a final rule related to energy storage systems.

The Fire Department adopted the rule to establish standards, requirements and procedures for the design, installation, operation and maintenance of outdoor stationary storage battery systems that use various types of new energy storage technologies, including lithium-ion, flow, nickel-cadmium and nickel metal hydride batteries. The rule does not govern indoor battery installations.

Among other things, the rule sought to address fire safety concerns associated with new battery technologies by setting testing standards and establishing an equipment approval process for manufacturers.

“Establishing testing standards, and in particular, requiring full-scale testing of battery system components and pre-engineered products, will enable manufacturers to identify fire safety issues and eliminate them or engineer mitigating measures in the design,” the Fire Department said. “The evaluation of the performance of battery system components or products in this manner will also allow the Fire Department to eliminate or expedite its approval process for specific installations,” it said.

Virginia County Holds Off on Battery Storage Project Decision

Concerns over battery storage fires and safety prompted the James City County Board of Supervisors in Virginia to recently defer a decision on a proposed battery storage facility in the county.

At issue is a 22.35-MW lithium ion battery storage project proposed by Calvert Energy LLC.

At the Oct. 11, 2022 board meeting, several members of the James City County Board of Supervisors raised questions related to fire and safety issues involving the project.

Brian Quinlan, President and CEO of Calvert Energy, noted the NFPA standard for batteries “and this system is designed to meet or exceed the containment requirements for battery storage, which basically means that the fire is contained within the container, so it won’t burn through the container walls.”

The Calvert Energy project also includes blowout panels, he noted. This means that “gases won’t build up and cause an explosion.” In addition, there is also dry chemical fire prevention “built into the unit itself as well, so there’s a number of different levels of fire protection built into the system.”

The board voted to defer a decision on the project to its Nov. 8 meeting.

RFQ in Massachusetts Addresses Storage Fire Training

The City of Boston in late 2021 issued a request for qualifications (RFQ) to provide comprehensive engineering, design, and construction services in connection with the installation of a rooftop photovoltaic (PV) array, a commercial-scale battery energy storage system (BESS) and a residential-scale battery energy storage system at the Boston Fire Department’s Fire Training Academy on Moon Island, in Quincy, Mass.

The RFQ said that at a minimum the BESS “shall meet and fully satisfy the Standard for the Installation of Stationary Energy Storage Systems established by the National Fire Protection Association (NFPA 855), including any underlying standard adopted by and incorporated into NFPA 855, such as UL 9540A.”

The RFQ notes that the project is intended to complement the Boston Fire Department’s curriculum for firefighting trainees: in particular, to provide those trainees with an opportunity to become familiar with working examples of PV and BESS technologies.  

Joseph LaRusso, Energy Efficiency and Distributed Resources Finance Manager in the City of Boston’s Environment Department, told Public Power Current that the city has completed evaluating the qualifications statements that were submitted in response to the RFQ, and the city is currently negotiating the terms of an energy services agreement (ESA) with the firm that submitted the highest-ranked proposal.

The city plans to release the name of that company once the terms of the ESA have been successfully negotiated and the contract is awarded.

APPA Responds to FERC’s Generator Interconnection Reform Proposal

October 17, 2022

by Paul Ciampoli
APPA News Director
October 17, 2022

The Federal Energy Regulatory Commission (FERC) should consider a number of modifications and/or clarifications to a generator interconnection Notice of Proposed Rulemaking (NOPR) to help ensure that any final rule improves interconnection queue processing while not inadvertently creating problems that could impose unnecessary costs and inefficiencies on transmission providers, interconnecting generators, and existing transmission customers, the American Public Power Association (APPA) and the Large Public Power Council (LPPC) said.

The Oct. 13 comments filed by APPA and LPPC came in response to a NOPR issued by FERC in June 2022. In the NOPR, FERC proposed to reform its generator interconnection procedures and pro forma interconnection agreements to address interconnection queue backlogs.

Although the proposals in the NOPR are not directly applicable to public power transmission owners, public power utilities in regional transmission organization (RTO)/independent system operator (ISO) regions may be subject to the proposed requirements under RTO/ISO tariffs or other governing agreements. 

Also, as FERC specifically states in the NOPR, transmission providers that are not utilities subject to FERC’s general transmission jurisdiction (such as public power utilities) would be required to adopt the requirements of the NOPR as a condition of maintaining the status of any safe harbor tariff to satisfy the reciprocity requirements of FERC Order No. 888. 

In their comments, APPA and LPPC note that they generally support the initiatives in the proposed rule, “and we are gratified in particular by the NOPR’s focus on improving the incentives generation developers have to stand behind bona fide interconnection applications, which should have a substantial stabilizing effect.”

A common refrain in their comments is the need for flexibility in implementing certain of the NOPR’s proposals, particularly to accommodate existing generator interconnection processes that have made progress in addressing the types of challenges cited in the NOPR.

APPA and LPPC said that FERC should not adopt the NOPR’s proposal to require transmission providers to undertake informational interconnection studies. 

“Substantial information is already made available to prospective interconnecting customers, and the informational study requirement would transfer the current burdens associated with processing speculative interconnection requests to an extra-LGIP process.”

APPA and LPPC endorsed the proposed requirement to post certain interactive information for use by prospective generator interconnection customers, though they argued that the Commission should clarify that transmission providers would not be required to conduct any individualized analyses in response to use of these interactive tools.

While APPA and LPPC support the NOPR’s proposed requirement to use a cluster study approach in studying generator interconnection requests, they said the Commission should allow for an exception where there are too few interconnection applications to justify a cluster study approach. 

In addition, the groups said that FERC should allow for flexibility in the cost allocation methods used to allocate cluster study costs and to allocate costs of required transmission system network upgrades identified in the cluster study.

APPA and LPPC said they strongly support the Commission’s proposal to adopt financial commitment and readiness reforms for prospective generator interconnection customers. They said the Commission should not dilute these reforms by allowing an interconnection customer to provide a deposit in lieu of making a showing of commercial readiness. “It may be appropriate to permit deposits in lieu of demonstrating full site control in circumstances where an interconnection customer is genuinely prohibited by regulatory limitations from obtaining site control, or where particular regions have specific reasons to adopt a deposit-in-lieu-of-site-control framework,” they said.

The NOPR’s proposal to impose stricter study processing requirements on transmission providers, backed by penalties, is generally a reasonable complement to the application of stricter financial commitment and readiness requirements on interconnection customers, APPA and LPPC said. 

“The Commission, however, should allow for flexibility in transmission provider deadlines, particularly in Regional Transmission Organization and Independent System Operator regions, particularly where the transmission provider has been permitted to utilize a cluster study approach that differs from the pro forma LGIP requirements.”

FERC should not adopt a penalty framework under which RTOs and ISOs might be obligated to pass penalties through to RTO/ISO members that bear no responsibility for interconnection study delays, they said. “The Commission should adopt a reporting requirement for RTOs and ISOs as a substitute for imposing interconnection study delay penalties on these not-for-profit entities.”

The groups also said that:

APPA and LPPC also specifically responded to the NOPR’s statement that public power utilities would be obligated “to adopt the requirements of this Proposed Rule as a condition of maintaining the status of their safe harbor tariff or otherwise satisfying the reciprocity requirement of Order No. 888.”

While acknowledging that safe harbor tariff requirements will be modified pursuant to any final rule in this case, APPA and LPPC expressed concern that the Commission’s statement failed to acknowledge that the reciprocity requirements of Order No. 888 can also be satisfied through bilateral arrangements or by waiver.  APPA and LPPC asked FERC to make clear in any final rule that public power utilities would still be able to satisfy the reciprocity requirements under Order No. 888 through bilateral arrangements and/or waiver.