William Driscoll – pv magazine USA

Utilities plan hydrogen power projects that crowd out renewables

William Driscoll — Thu, 22 Aug 2024 18:34:52 +0000

Several utilities have proposed hydrogen-capable generating units in their resource plans, a research center reports. But hydrogen projects face hurdles such that they “may not work,” and they conflict with renewables, another research group says.

The NC Clean Energy Technology Center has reported that “increasingly,” utilities are proposing “unspecified ‘clean dispatchable’” generation in their resource plans, with “the most common example” being hydrogen-capable gas combustion units.

The center also reported that U.S. utilities that have recently filed integrated resource plans expect to add 92 GW of solar, 50 GW of wind, and 42 GW of methane gas units. The center did not publicly evaluate whether the amounts of solar and wind for those utilities, over the 15 to 20 years typically covered by a resource plan, could be seen as good news or a disappointment.

As for “clean dispatchable” capacity, the report lists several utilities proposing such projects: Evergy in Kansas and Missouri, Ameren Missouri, PacifiCorp, and Xcel Energy in the Upper Midwest.

One timeline for reaching 100% hydrogen power has been announced by developers of a pioneering project in Utah that is projected to use 30% hydrogen by volume mixed with 70% methane by 2025, and to reach 100% hydrogen by 2045.

Yet a report from the Institute for Energy Economics and Financial Analysis (IEEFA) says “it takes a lot of hydrogen” by volume to cut carbon dioxide emissions. That’s because hydrogen has a lower energy density than methane.

A hydrogen concentration of 50% by volume yields only a 24% emissions reduction, according to calculations by SS&A Power Consultancy cited by IEEFA, and a concentration of 93% is needed to reduce emissions by 80%.

The same calculations show that until 77% hydrogen by volume is reached, “hydrogen-capable” generating units will be powered primarily with methane.

Unknown costs

The IEEFA report documents proposals for “hydrogen-ready” projects from utilities and merchant developers in 18 states.

While the costs of wind, solar and storage are known today, the report says the ultimate cost of any “hydrogen-capable” gas project will not be known for years.

Hydrogen-related power projects, the report says, “require significant additional investments that will be extremely costly for ratepayers, may not actually work and will conflict with readily available and cheaper renewable options.”

The report sees “three key hurdles” that will “slow and perhaps entirely halt the widespread use of hydrogen as a replacement for methane” in turbine generators: inadequate hydrogen supply, a lack of pipeline infrastructure to transport hydrogen, and a lack of capacity to safely store hydrogen.

The pioneering Utah project has addressed those hurdles by co-locating green hydrogen production, hydrogen storage in salt domes, and gas combustion turbines.

The IEEFA report said state regulators should require utilities to compare the costs of hydrogen projects with costs of zero-carbon resources including renewables, battery storage, efficiency and virtual power plants.

Blending high levels of green hydrogen into methane, the report says, that “would consume vast amounts of renewable energy that would be better used directly to replace existing fossil fuel generation.”

Green hydrogen’s role

The policy consultancy Energy Innovation found last year that production of green hydrogen for industrial use can be profitable in much of the US, but did not evaluate hydrogen’s use for electricity production.

Current industrial uses of hydrogen include production of ammonia, largely for fertilizer, and oil refining. Ammonia could also be used as a fuel for shipping. The Green Hydrogen Coalition says that green hydrogen could also decarbonize the production of steel and cement.

The public version of the NC Clean Energy Technology Center’s report is titled “50 States of Power Decarbonization: Q2 2024 Quarterly Report Executive Summary.” The full report is available free to state policymakers and regulators, and to others for a fee.

The IEEFA report is titled “Hydrogen: Not a solution for gas-fired turbines.”

California advances flexible demand that can absorb renewable power

William Driscoll — Tue, 20 Aug 2024 13:15:54 +0000

With flexible demand appliance standards for pool controls set to take effect in California next year, the state is now developing standards for electric storage water heaters, to be followed by standards for five more types of appliances.

The California Energy Commission expects to issue flexible demand appliance standards for electric storage water heaters “hopefully” within months, said Michael Sokol, director of the efficiency division at the California Energy Commission (CEC), on a webinar hosted by the Clean Energy States Alliance.

The CEC issued a flexible demand appliance standard for pool controls last October. CEC Commissioner Andrew McAllister said at the time that a standard for electric storage water heaters would be next, noting that ten of the largest heat pump manufacturers had committed to help California reach its goal of 6 million heat pumps for water or space heating by 2030.

Flexible demand appliance standards in California will work in tandem with flexible rates for electricity, enabling appliances to operate when rates are lower, for example when renewable generation is high.

EV chargers, batteries, and more

The CEC has set a tentative sequence for developing flexible demand appliance standards for five more types of appliances, based on “our early analysis” and preliminary stakeholder planning discussions, Sokol said.

The third standard, after pool controls and electric storage water heaters, is expected to cover electric vehicle supply equipment, such as EV chargers. Next would be standards for battery energy storage systems.

The next three standards to be developed would have “end-user time impacts,” Sokol said, namely low-voltage thermostats, electric clothes dryers and dishwashers.

McAllister said last year that California aims to reach 7 GW of load flexibility by combining 3 GW of price-responsive demand from appliances with 4 GW of traditional demand response, in which some customers “drop load” during the 100 highest-demand hours of the year.

A Californian who owns a pool and operated a flexible demand pool control unit on its default schedule would save about $100 per year, Sokol said. Customers will have the ability to override the default schedule and operate a pool control unit at times of their choosing.

CalFlexHub

Much of the research underlying the new standards is conducted by the California Load Flexibility Research and Deployment Hub (CalFlexHub) at Lawrence Berkeley National Laboratory.

CalFlexHub will hold an all-day symposium on September 24.

Most states with renewables targets are meeting them

William Driscoll — Mon, 19 Aug 2024 13:18:07 +0000

Nearly all states with a renewable portfolio standard have met or nearly met their current standard. Four states have yet to meet their solar carve-out requirements.

All but three of the 29 states plus DC that have a renewable portfolio standard (RPS) are meeting their current targets, according to an analysis by Lawrence Berkeley National Laboratory.

Vermont’s current RPS target of nearly 60% is the highest of any state, as shown in the featured image above, provided in the analysis. Every bar in the image without a light blue segment at the top means that state has met its current RPS.

The study says that “large shortfalls” in New York and Illinois are “expected to close” as contracted projects come online.

The study counts a state as meeting its RPS if the state’s utilities have retired renewable energy credits (RECs) equal to the amount of the RPS requirement. States award RECs for renewable power generation.

A state may also permit utilities to comply with its RPS by submitting “alternative compliance payments.”

Delaware’s “large shortfall,” the study says, is due to its low cost for alternative compliance payments compared to other states in the region.

Puerto Rico is not included in the analysis but also has a large shortfall in meeting its renewables target. The territory stands at 12% renewables, compared to its current target of 20% by 2022.

Solar carve-outs

Of the 15 states plus DC that have RPS carve-outs that require a certain amount of solar and/or distributed generation, all but four have met or nearly met the goals, as shown in the nearby image.

Drivers

While the study says that “parsing out the incremental impact of individual drivers” for the growth in renewables generation is “challenging,” it observes that RPS policies have been a “larger driver” of renewables deployment in three regions:

The Northeast, where almost all renewable capacity additions—mostly onsite and community solar in recent years—are serving RPS demand
The Mid-Atlantic, thanks to solar carve-out capacity and RPS-certified projects with corporate power purchase agreements, which “potentially sell RECs into compliance markets”
The West, where added renewables are driven by “aggressive” long-term RPS and clean energy standard (CES) targets throughout the region, and where non-RPS additions are mostly onsite solar.

Regions where RPS standards have been a “smaller driver” are:

Texas, which achieved its final RPS target in 2008, so that all renewables growth since then is not influenced by the RPS
The Midwest, where there is “lots of wind development,” some of which is contracted to utilities with RPS needs
The Southeast, where renewables growth is primarily driven by utility procurement and qualifying facilities under the Public Utility Regulatory Policy Act (PURPA).

In all but two regions, renewable generation well exceeds the combined RPS targets for the states in the region, as shown in this graph from the study:

Ultimate targets

Across the 29 states plus DC with an RPS, 16 have ultimate RPS targets of at least 50% of retail electricity sales, and 4 have a 100% RPS. Sixteen states have adopted a 100% clean energy standard, which can be met by renewables and typically also nuclear and hydroelectric generation as well.

RPS and CES policies will require 900 TWh of new clean electricity by 2050, the study says, “equivalent to roughly 3x the historical rate of RPS buildout.”

Berkeley Lab is hosting a webinar on August 28 to present the study’s complete findings. The study is titled “U.S. State Renewables Portfolio & Clean Electricity Standards: 2024 Status Update.”

Solar+storage microgrids to provide reliability for Northern California tribes

William Driscoll — Fri, 09 Aug 2024 13:00:16 +0000

Solar-plus-storage microgrids to be built, owned and operated by three tribes in Humboldt County, California are expected to reduce outages by 90% at a lower cost than undergrounding power lines.

Three solar-plus-storage microgrids will “transform” a 142 mile-long distribution circuit that serves three tribes in eastern Humboldt County, California from “one of the state’s least reliable” circuits into a “highly resilient” system, says the Schatz Energy Research Center at Cal Poly Humboldt University.

The Schatz Center, which is leading the microgrid system design, says the microgrids will have a total of 9 MW of solar and 14 MW / 37 MWh of storage. The rural location will also enable 2 MW of small-scale, fish-safe hydropower and 1 MW of small-scale generation powered by forest residues.

A microgrid will serve each of the three tribes served by the “Hoopa 1101” distribution circuit—the Hoopa Valley, Yoruk and Karuk Tribes. The microgrids are expected to reduce outage hours in the area served by 90%. The cost will be about half the cost of improving reliability by undergrounding power lines, the Schatz Center said.

Chairman Russell Attebery of the Karuk Tribe said the project will “provide the safeguards needed to survive along the river. Our people will no longer fear losing their food or vital medical resources, like vaccines, as we have in the past.”

Each microgrid will be located “in front of the meter” and thus will be capable of powering a portion of the distribution circuit during local outages. The microgrids will be “nested,” enabling them to function either jointly or independently, as immediate circumstances along the power line require.

The project, known as the Tribal Energy Resilience and Sovereignty (TERAS) project, will advance sovereignty through tribal construction, ownership and operation of the advanced microgrid systems, and will include career development and education components.

The design has wide applicability, suggested Schatz Center Director Arne Jacobson, saying the center is “excited to radically expand the capacity of microgrids to provide energy reliability in high-risk locations.”

The Schatz Center previously designed California’s first front-of-the-meter, 100% renewable energy microgrid at the Redwood Coast Airport, and the first iteration of the Blue Lake Rancheria Tribe’s microgrid in Humboldt County. The center is now designing an expansion of that microgrid into four nested, behind-the-meter microgrids, which will provide a demonstration site for the controls system that will subsequently be deployed along the Hoopa 1101 circuit.

The $177 million TERAS project is being supported with a federal cost share of $88 million, awarded in the latest round of grants under the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program. In making the award, DOE said the project will “develop a replicable public-private partnership model for equitable and community-driven grid modernization.”

DOE says the GRIP program is designed to “enhance grid flexibility and improve the resilience of the power system against growing threats of extreme weather and climate change.”

The Schatz Center is also developing a campus-wide microgrid at Cal Poly Humboldt.

8 GW of solar-plus-storage at resilience hubs in California could save lives

William Driscoll — Thu, 01 Aug 2024 14:00:16 +0000

Solar and storage at almost 20,000 community sites across California could help protect its population during power outages, especially during heat and smoke events, a study found.

California faces public safety power shutoffs, wildfires and heat waves that “increasingly trigger outages across the state,” creating a “pressing need” to support increased community resilience, says a research paper.

To help meet its climate resilience needs, the state could add rooftop solar and storage to about 20,000 schools, community centers and places of worship, creating what the authors call “resilience hubs.”

Resilience hubs could provide clean, cool air for those “who might otherwise die” in heat waves or smoke events, the study says, adding that the elderly and those with chronic health conditions are particularly vulnerable to heat waves.

Each site could, as a baseline, add an amount of solar-plus-storage that is economically optimal for everyday use, such that it could be financed, perhaps with state loan guarantees. Across all the sites, 5.5 GW of rooftop solar and 1.8 GW of storage could be financed to power everyday operations. In an emergency, if grid power is available, the sites could provide smoke-free, conditioned air for 40% of California’s 39 million people, and also power communication and medical devices, the study projected.

Increasing the rooftop solar to nearly the 8 GW maximum potential across all sites and increasing storage would increase resilience capacity. Because that increased capacity could not be financed at current electric rates, it would require grant funding, incentives, or more favorable rate designs.

The community sites considered could only partially help the state meet its needs for resilient power, the study found.

The nonprofit PSE Healthy Energy, which employs most of the study’s authors, said on a landing page for the study that resilience hubs are unlike emergency cooling centers as they are “built in trusted community spaces and provide resilience-building services on an ongoing basis,” such as helping vulnerable communities “to address underlying risk factors and improve resilience to disaster over time.”

Hybrid systems

The study evaluated resilience hubs powered by solar-plus-storage, but acknowledged that hybrid systems that add fossil generation “may be more economical, particularly when high levels of resilience are required.” Even so, fuel-based backup requires regular testing and maintenance, they study says, citing research finding that half of poorly-maintained generators fail within 48 hours during a long-duration outage.

The study used the REopt model, developed by the National Renewable Energy Laboratory, in its analysis of the solar-plus-storage potential at the community buildings it considered.

The open-access study, published in the journal Risk Analysis, is titled “Modeling and design of solar + storage-powered community resilience hubs across California.”

Six states offer grants to help local governments automate solar permitting

William Driscoll — Mon, 29 Jul 2024 14:14:34 +0000

Solar trade groups in Washington, Colorado and Minnesota advocated for grant programs to speed permitting for rooftop solar, using software such as SolarAPP+. Three other states also offer grants, with two requiring automated permitting.

Automated permitting for distributed solar and storage is set to expand well beyond California, as five states follow California’s lead in offering grant support to localities to help them switch to automated permitting.

An automated process can issue a permit “instantly” to a distributed solar project that meets all permitting requirements, according to the U.S. Department of Energy. Standard permitting can take months, says the New York Solar Energy Industries Association, “resulting in delays and higher costs for homeowners and solar companies.”

The best-known automated permitting software for solar and storage is SolarAPP+, developed by the National Renewable Energy Laboratory. NREL provides free support to local governments before and during implementation of SolarAPP+, and a spokesperson said the software will always be free for local governments to use, while solar installers pay user fees.

While the software is free to local governments, grants can help them meet the costs for staff time to transition to automated permitting. Once the transition is completed, automated permitting can save substantial staff time.

NREL reports that SolarAPP+ is now used by 138 local governments in California and 14 local governments in nine other states, including several large cities and counties. The software is also being pilot tested by 56 local governments.

California has been helping local governments make the switch to automated permitting by offering them grant support and technical assistance, in a program launched in 2022.

Five other states are now following California’s lead in offering grants and technical assistance to local governments adopting automated permitting.

In Washington, state legislators early this year allocated $600,000 for a grant program. The state’s solar trade group WASEIA provided written testimony to the Washington House Appropriations Committee and a policy brief supporting the budget provision “to help speed rollout of SolarApp+,” said Bill Will, the association’s senior policy advisor.

Colorado has launched an “Automated Permit Processing for Solar” grant program with $1 million in funding for local governments. The state’s solar trade group COSSA “was the main advocacy organization to push for” a state law that created the grant program, said Mike Kruger, president and CEO of COSSA, as the group worked with bipartisan sponsors and other stakeholders “to lower red tape and speed up solar permitting,”

Minnesota has budgeted $2 million to support a grant program for local governments to adopt SolarAPP+. Passing the legislation “was a multi-year, bipartisan effort,” said Logan O’Grady, executive director of the state’s solar trade group MnSEIA. The group “was proud to collaborate with advocacy partners on this initiative, boosting the residential solar market and enabling Minnesotans to go solar faster and easier,” he said.

Illinois plans to use a portion of its federal Solar for All grant to fund a program to help communities automate permitting, according to Environment America.

Maryland has announced an upcoming SolarAPP+ Implementation Grant Program.

Automation requirements

California and Maryland have also set requirements for local governments to automate solar permitting.

California requires all but the smallest local governments to use either SolarAPP+ or another automated permitting software. Larger cities and counties were required to comply by last September, and medium-sized cities and counties are required to comply by this September.

The California Energy Commission says that “enforcement lies outside of CEC jurisdiction but may be enforced through private claims.”

California last month completed awards of $19 million in grants to 334 cities and counties to make the switch to automated permitting, according to an analysis by Permit Power, a new advocacy organization dedicated to advancing automated permitting.

Maryland’s Brighter Tomorrow Act, enacted in May, requires local governments to adopt automated solar permitting software, according to the law firm Saul Ewing. Montgomery County, Maryland, with a population of 1 million, already uses SolarAPP+.

In New York, the solar trade group NYSEIA recently called for automated permitting in the state.

Advocacy partners

The nonprofit group Solar United Neighbors joined with others in advocating for the automated permitting grant programs in Minnesota and Maryland, said a spokesperson.

Environment America Senior Campaign Director Johanna Neumann said the nonprofit group’s Maryland director identified legislative sponsors for the state’s automated permitting policy, recruited allies, and helped guide the legislative strategy.

Permit Power also contributed to the Maryland effort, Neumann said.

A path to 20 GW of distributed solar in New York

William Driscoll — Wed, 24 Jul 2024 15:31:37 +0000

Accelerating deployment of rooftop and community solar with supportive policies would help New York meet its goal of 70% renewable power by 2030 at lower cost, says a solar trade group.

The New York Solar Energy Industries Association has called for “high-impact policy interventions” to move the state beyond its distributed solar goal of 10 GW by 2030 to reach 20 GW by 2035. The call comes in a report seeking to influence state policymakers.

Of New York’s current 5.8 GW of solar, 93% is rooftop and community solar, which NYSEIA counts as distributed solar. New York has about 3 GW of rooftop solar and nearly that amount of community solar.

Utility-scale solar is lagging in the state, and has faced “recent setbacks,” says NYSEIA. Those setbacks have created “a significant gap between New York’s pipeline of clean energy projects and what’s needed to comply” with the state’s legislated 70% renewables mandate by 2030, the report says.

Yet New York is “ahead of schedule toward the state’s goal of deploying 10 gigawatts of rooftop and community solar by 2030,” and the state’s distributed solar industry is “well-positioned to help New York close the gap” by deploying an additional 10 GW of solar “while delivering significant benefits.”

The largest projected benefit would be $50 billion in customer savings over 25 years, as 10 GW of additional distributed solar would provide about $1.65 billion in annual electricity bill savings for New Yorkers who install solar panels or subscribe to a community solar project.

Increasing the amount of distributed solar plus storage to help meet New York’s 2030 renewables goal would also result in lower costs than relying “heavily” on large-scale renewables and transmission buildout, saving a projected $28 billion, the report says, citing a 2021 analysis by Vibrant Clean Energy.

To to accelerate distributed solar deployment, NYSEIA calls for new approaches to local permitting and utility interconnection, “targeted” incentives, “smart” electric rate design, and virtual power plant programs. The group’s 11 policy recommendations could, in aggregate, “transform and accelerate New York’s clean energy progress,” the report says. Specific recommendations include:

State-level permitting support for community solar projects that face restrictive local laws
Automated permitting for residential solar plus storage, using software such as the National Renewable Energy Laboratory’s SolarAPP+
Faster interconnection
Flexible interconnection, to address hosting capacity constraints and mitigate costly grid upgrades
Grid investments to support solar plus storage deployment that can supply clean power to new loads
Improvements to New York’s Value of Distributed Energy Resources electric rate tariff
Support for virtual power plant programs
Continued improvements in the state’s community solar programs
Improvements to the residential solar tax credit and the distributed solar incentive program.

NYSEIA’s report is titled “Raising New York’s Distributed Solar Goal: 20 Gigawatts by 2035.”

DOE offers conditional loan guarantee for 200 MW solar, 285 MW storage in Puerto Rico

William Driscoll — Mon, 22 Jul 2024 14:00:35 +0000

Two solar-plus-storage projects in Puerto Rico eligible for a loan guarantee would double the territory’s utility-scale solar capacity.

The Loan Programs Office of the U.S. Department of Energy (DOE) has made a conditional commitment for a loan guarantee for up to $861 million to finance construction of solar-plus-storage projects and standalone storage projects in Puerto Rico.

The project developer and prospective borrower, Clean Flexible Energy LLC, is an indirect subsidiary of AES Corporation (AES) and TotalEnergies Holdings USA, Inc., and is managed under a joint venture agreement between the two.

The planned facilities, located in the municipalities of Guayama and Salinas, include two sites encompassing 200 MW of solar co-located with 285 MW of 4-hour batteries (1.14 GWh). Two other standalone battery storage sites would have a storage capacity not disclosed by DOE.

Puerto Rico currently has 154 MW of utility-scale solar, according to the U.S. Energy Information Administration.

The U.S. territory’s distributed solar capacity reached 842 MW by April this year, while residential storage has reached 1.6 GWh. The consultancy Wood Mackenzie has projected that over the next ten years more than 90% of Puerto Rico’s solar additions will be distributed solar.

Puerto Rico’s Act 17 calls for reaching 40% renewable generation by 2025—a target that is now very challenging to meet—and to reach 60% by 2040 and 100% by 2050.

Puerto Rico’s technical potential for utility-scale solar ranges from 14.2 GW under a “less land” scenario to 44.7 GW under a “more land” scenario, according to the National Renewable Energy Laboratory’s “PR 100” summary report published early this year. A technical potential analysis does not consider the financial viability of projects.

To secure the loan guarantee, Clean Flexible Energy LLC must first satisfy certain technical, legal, environmental, and financial conditions before DOE enters into definitive financing documents.

AES operates 19 GW of renewables capacity globally as part of its 35 GW generating portfolio, according to an investor presentation. AES also operates electric utilities.

TotalEnergies aims to reach 28 GW of installed renewable capacity globally this year, according to an investor presentation. The firm is also involved in fossil fuel production, refining and sales and electricity generation.

Grid operator PJM to start talks on regional transmission

William Driscoll — Wed, 17 Jul 2024 16:37:47 +0000

The nation’s largest grid operator told renewables trade groups that it will launch a transmission planning process ordered by the Federal Energy Regulatory Commission.

PJM Interconnection, which provides transmission from Chicago to New Jersey, said it will launch a stakeholder engagement process in August to “help inform inputs” into scenario analyses for long-term regional transmission planning.

PJM and other transmission providers are required by the Federal Energy Regulatory Commission’s (FERC’s) Order No. 1920 “to plan for the transmission we know we will need in the future,” FERC has explained. Scenario analyses are part of the planning process.

PJM announced the stakeholder engagement process in its response to a letter from three renewables-focused trade groups and other entities asking PJM to “shift its current long-term regional transmission planning proposal to focus on Order No. 1920 directives.”

PJM region

Image: PJM

One of the trade groups, American Council on Renewable Energy, said last year that 167 GW of large-scale solar, wind and storage projects awaited interconnection studies by PJM. The group said that a lack of transmission capacity due to “insufficient” transmission planning is a “root cause of the unprecedented backlog” of interconnection requests across grid operators nationwide. Trade groups Americans for a Clean Energy Grid and Advanced Energy United also signed the letter.

In the works

PJM issued a regional transmission expansion plan last year that “identified” 93 transmission projects at a cost of $180 million to support generation seeking interconnection, and 48 new baseline projects at an estimated cost of $6.6 billion to maintain grid reliability, said a FERC staff report in March, while PJM “evaluated” 227 supplemental projects put forward by transmission owners that would cost $2.4 billion.

A major “national interest” transmission corridor in the PJM region has been proposed by the U.S. Department of Energy (DOE) that would help PJM “maintain and improve reliability, lower consumer costs, and meet future generation and demand growth,” DOE said.

Nationwide, a DOE transmission needs study found that 54,500 GW-miles of within-region transmission must be added for a clean grid under “the most likely power sector future.”

“Ultimate directives”

The trade groups expressed a concern in their letter that “PJM’s recent rehearing request to FERC suggests that PJM may seek to avoid implementing some important components of Order No. 1920.”

Responding to that concern, PJM said its rehearing request sought “flexibility” to implement the FERC order’s requirements “in a less prescriptive way such that PJM can tailor its approach to reflect its unique circumstances and regional needs.” PJM said that FERC will rule on “the numerous rehearing requests filed,” and said it “will comply in full with [the] Commission’s ultimate directives.”

States’ role

FERC said that its order “expands states’ pivotal role throughout the process of planning, selecting, and determining how to pay for transmission facilities.”

The governors of four states served by PJM—Illinois, Pennsylvania, Maryland and New Jersey—said in a letter to PJM last month that transmission planning is important in “developing large-scale low-and-zero emission energy resources.”

The governors said they “applaud” the grid operator’s steps to prepare for scenario discussions “that include each of our states,” and look forward to extensive engagement with PJM management and stakeholders “in shaping regional transmission planning and cost allocation approaches.”

All 13 states served by PJM had called for the grid operator to make faster progress on interconnection of renewable generation projects in 2022, in comments to FERC from the Organization of PJM States, Inc. (OPSI).

State do not have representation in PJM’s governance structure, but PJM says in a website document that it “works closely with state regulatory commissions to identify and respond to local matters,” explaining that OPSI, made up of the state commissions in PJM’s region, acts as a “liaison group” to PJM and its members.

Sixty-nine state legislators from 10 states served by PJM called this week for the grid operator to “work without delay” to implement FERC Order No. 1920, saying that “effective implementation” of the order is “critical to our responsibility to ensure that our constituents have access to reliable, affordable and clean electricity,” in a letter organized by the National Caucus of Environmental Legislators.

Protecting smart inverters from cyberattack

William Driscoll — Mon, 15 Jul 2024 16:36:02 +0000

The National Institute of Standards and Technology has flagged a cybersecurity risk for smart inverters, and is developing guidelines to prevent cyberattacks.

Cybersecurity guidelines for smart inverters used in small-scale solar deployments are available in draft form from the National Institute of Standards and Technology (NIST).

NIST observes that when smart inverters are “configured to behave in a grid-friendly, supportive manner,” they assist the local electric utility in “addressing anomalies” on the electric grid.

But an improperly configured inverter, NIST says, “can respond in inappropriate ways that exacerbate anomalies,” and “a large number of misconfigured smart inverters could have a negative impact on a utility’s efforts to address anomalies.”

That raises the specter of a cyberattack, as NIST states that “if a malicious actor were able to deliberately misconfigure many smart inverters, grid stability and performance could be impacted.”

The draft guidelines recommend that manufacturers incorporate cybersecurity capabilities into their smart inverters. The guidelines are based on NIST’s baseline “internet of things” cybersecurity capabilities guidance, which NIST has made more specific to smart inverters.

How smart inverters communicate is a key focus of the draft guidelines, said Midhat Mafazy, regulatory program engineer with the Interstate Renewable Energy Council.

The NIST draft guidelines note that smart inverters may communicate with the electric utility, third-party operators, the device manufacturer, or other devices in the local environment. Yet “this communication capability also provides an opportunity for cyberattack,” NIST said.

NIST gave several examples of ways to protect smart inverter communications from “malicious actors” while still allowing needed communications.

NIST also made a draft recommendation to disable unused features and capabilities that are not used in a particular device deployment, giving three examples: remote access protocols and interfaces, wireless communications, and “guest” access to smart inverter features or capabilities.

Mafazy said the draft guidelines do not explicitly state how smart inverters’ autonomous functions should be handled. Those autonomous functions can help regulate voltage on a distribution circuit, thereby boosting hosting capacity. Mafazy expressed hope that NIST’s final guidelines could clarify how those autonomous functions should be handled.

On a related issue, Mafazy pointed to the operational difficulty and cost of making changes to smart inverter settings on an already-deployed system, if changes are warranted and initiated by the utility. “This underscores the importance of activating and enabling voltage regulation functions as default during initial deployment,” he said.

NIST said that its recommended cybersecurity capabilities in smart inverters will enable smart inverter owners and installers to implement seven categories of cybersecurity guidelines.

NIST tested five smart inverters to determine whether their capabilities would enable owners and installers to meet the draft guidelines. NIST found, for example, that regarding the ability to disable unused features, only two of the five smart inverters tested had that ability.

Threat level

In a smart inverter vulnerability survey that NIST conducted in 2022, the agency identified 15 vulnerabilities to cyberattacks in 2021, and 30 more going further back in time. The survey used data from NIST’s National Vulnerability Database. “This research identified real cybersecurity concerns that the guidelines should address,” NIST stated.

The NIST draft guidelines are titled “Cybersecurity for smart inverters: Guidelines for residential and light commercial solar energy systems.” The agency has solicited comments on the draft guidelines and is preparing a final version of the guidelines.

Louisiana allows firms to buy 500 more MW of renewable power

William Driscoll — Tue, 09 Jul 2024 17:50:07 +0000

Louisiana’s large electricity customers will be allowed to purchase up to 500 MW of renewable power through a new type of agreement with renewable project owners.

The Louisiana Public Service Commission has issued a rule giving large commercial and industrial customers in the state a new way to access up to 500 MW of renewable power, stating that customers need renewable power “in order to remain competitive.”

Louisiana currently has 600 MW of solar power, providing less than 1% of the state’s electricity, according to the national solar trade group Solar Energy Industries Association.

The member companies of the Gulf States Renewable Energy Industries Association “are greatly encouraged by this consumer-driven demand for renewable energy expansion,” said Monika Gerhart, the group’s executive director. GSREIA and many other parties intervened, or participated, in the four-year regulatory proceeding that led to the rule.

Under the rule, a large electricity customer may notify the utility that provides its electric service of its intent to seek a “sleeved” power purchase agreement (PPA). A sleeved PPA, the rule says, is an agreement for the capacity, energy and renewable attributes of a renewable generator that is negotiated between the customer and the generator’s owner, and then executed by those parties and the customer’s utility.

The rule provides an additional option for procuring renewable energy beyond the standard PPA option. For example, McDonalds has two PPAs with Lightsource bp to purchase solar power from Louisiana projects, one for the entire output of a 180 MW project and another, alongside eBay, to purchase part of the output of a 345 MW project.

After a customer notifies a Louisiana utility of its intent to seek a sleeved PPA, the utility must within 60 days design a rate schedule and propose it to state regulators. Regulators then have 90 days to approve or deny the rate schedule.

The utility must state in the rate schedule the customer charges and credits for a sleeved PPA and how they will be determined. Typically included will be a credit for the accredited capacity provided by the renewable generator.

For each utility, the rule limits the maximum amount of renewable capacity eligible for sleeved PPAs to 5% of the utility’s peak summer demand. Entergy Louisiana, the state’s largest utility, recently had a peak summer demand of almost 10,000 MW, so for that utility alone, 500 MW of renewable capacity (5% of 10,000 MW) would be eligible for sleeved PPAs.

The Louisiana rule is available on pages 29-37 of this document.

How to speed interconnection studies

William Driscoll — Wed, 03 Jul 2024 15:40:22 +0000

Automation of interconnection study processes is already underway and has room to grow, said executives from Pearl Street Technologies and Nira Energy on an industry panel. Other panelists discussed developing the engineering workforce.

About 80% of interconnection study tasks could be automated, allowing transmission providers to focus on “the harder problems where their judgment and experience are really necessary,” said David Bromberg, co-founder and CEO of software firm Pearl Street Technologies, at the Transmission and Interconnection Summit held outside Washington, DC.

Pearl Street has built software for transmission providers that accelerates interconnection studies, and similar software for renewable energy developers “to better manage risk and uncertainty in interconnection and clear more of their projects,” Bromberg said.

Pearl Street’s software has modeled more than 1,000 generation and storage projects, including 180 GW of renewables projects, the company’s website says.

Andrew Martin, head of transmission for software firm Nira Energy, said transmission providers and utilities “should have a goal of communicating” an interconnection study process that is reproducible. Once there’s a reproducible process—for example, once an engineer can replicate the study results—“then the market can continue to build upon that reproducibility” by developing software, he said.

“These study processes that we all do are very deterministic,” Martin added. “There is a right and a wrong way to do them, and that’s something that software is super helpful with.” On a related note, he said “we should strive to get to a place where transmission planning engineers are not needing to do repetitive tasks.”

Martin said that grid operators MISO, PJM and SPP have interconnection study processes that are reproducible, and that for those three markets, Nira Energy offers software for project developers.

Once developers get their phase one study results, Martin said, “they’re determining whether or not they want to stay in the queue,” based on what they think their results will be at phase three and the generator interconnection agreement phase. “For them to be able to do that, they need to first be able to replicate the phase one results, so they can take a step forward and do more complicated things on top of that, while being able to trust what they’re doing.”

Bromberg said his work was initially inspired by the electronic design automation industry that simulates and designs electronic chips. He said that a chip can be “an extremely complex electronic system with billions of components, and there are software tools that help automate the design and analysis and optimization of those chips, and those tools are very, very powerful.” In comparison, he said, “the power grid is geographically very large, but network-wise, it’s orders of magnitude smaller, and switching at lower frequencies.”

Anupam Gopal, president and CEO of the consultancy Enerzinx, said his firm performs power system modeling for project developers and utilities in the U.S. and three other countries. In a discussion on the engineering workforce, he said that “in other parts of the world, they offload” interconnection studies to project developers, “so that way it is not centralized to one organization. It’s spread around all the developers” and the transmission provider “basically only approves or disapproves.”

Caitlin Marquis, managing director with the trade group Advanced Energy United, whose members develop large-scale generating projects, said that both the group’s members and transmission providers rely on consulting firms. She said the group surveyed transmission providers and found that using third-party consultants is a “benefit” and “improves the throughput of studies” but can cause “challenges with coordination” due to “reliance on multiple different external parties that might have different engineering judgment or different conclusions.”

Demand for engineers

Shankar Chandramowli, director for energy power markets at the consultancy ICF and the panel’s moderator, cited a study finding that one of three engineering jobs goes unfilled in the U.S., and added that many grid operators, known as ISOs and RTOs, “don’t have power system engineers to run the models themselves.”

Noting the 2600 gigawatts of active queue capacity in the U.S., Chandramowli called for reconciling the “competing objectives” of speed and accuracy in interconnection studies, by automating the study process and having a skilled power systems engineering workforce to use and advance the process.

Radha Soorya, vice president for interconnections and grid analysis for Invenergy, said that “as the developer on the panel, I can surely address this, because I took two years to fill an engineer position.” She said Invenergy has committed to train and develop 2500 individuals “so they can enroll, train and develop a career in the energy industry.”

High school and undergraduate students are familiar with career opportunities in robotics, AI and medicine, Soorya said, but not in energy or electrical engineering. Invenergy plans to share a curriculum with students and teachers “about the foundation of electrical engineering, so that it can be a skill set they can bring when they graduate,” and that Invenergy will also provide career counseling and internships during college.

The conference session was titled “Innovative solutions to increase the pace of interconnection studies and system planning while reducing labor intensity.” The conference was produced by Infocast and supported by 15 sponsors.

Experts consider speedy utility-scale interconnection in Texas going nationwide

William Driscoll — Mon, 01 Jul 2024 19:02:13 +0000

Some experts shared data to back up their praise for the “connect and manage” approach used by Texas grid operator ERCOT, while others speaking on an industry panel explained their reservations.

National goals for utility-scale interconnection for the rest of the country are already being met in the ERCOT grid region in Texas, which uses a “connect and manage” approach, said Mario Hayden, director, transmission at Enel North America, at the Transmission and Interconnection Summit held outside Washington, DC.

It takes just a year, Hayden said, for a solar or storage developer that has filed an interconnection request with ERCOT to progress through the full interconnection study process and reach an interconnection agreement.

Noting a key downside of the “connect and manage” approach, namely the risk of curtailment if transmission capacity is inadequate, Mike Tabrizi, founder and president of Zero Emission Grid, said that although a project developer in the ERCOT region can interconnect to transmission at their own risk, and not be responsible for transmission costs upfront, once the project becomes operational, “then you are fully exposed what’s going to happen with transmission.”

ERCOT says it takes three to six years to energize transmission lines in Texas, said panel moderator Tom Kleckner in his introductory statement. Kleckner, the ERCOT/SPP correspondent for RTO Insider, related that ERCOT says energizing transmission elsewhere in the U.S. takes seven to 13 years. As a single-state entity, ERCOT is not subject to Federal Energy Regulatory Commission rules, Kleckner said, “so it saves some four years in federal compliance and two years in signing and construction.”

Regan Fink, manager, transmission & interconnection policy for Pine Gate Renewables, described two issues related to managing the need for more transmission, which she called the “manage” aspect of “connect and manage.” First, ERCOT lacks proactive transmission planning, she said, adding that while “it’s really hard” to do, “some of it needs to be done.”

Second, she said that as a generator, “there’s no formal process to sponsor your own upgrades. If you’re facing a lot of curtailment and congestion, but it’s not enough” for ERCOT as a system to decide whether to build upgrades, “then we might be stuck with that. While we’ve been told by ERCOT that we can coordinate with the transmission service providers” in the grid region about sponsoring upgrades, “we would like to see a more formal process.”

Pranay Reminisetty, team lead for resource integration at the consultancy DNV, said that because of ERCOT’s “big backlog in transmission,” interconnecting a project to ERCOT’s grid without knowing how much production will be curtailed presents a financial risk for developers. “So we need more transmission in order to go into energy-only resources,” he said.

Yet in the nation’s other grid regions, he said the financial risks come from uncertainty over both the network upgrade costs that will be assigned to a project to interconnect, and the grid operator’s affected system study cost for a project, which he called a “surprise cost” for the developer.

Tyler Norris, a former Cypress Creek Renewables executive and current Ph.D. candidate, said that “it’s no secret” that staff of the Federal Energy Regulatory Commission (FERC) “are quite interested in the topic of flexible interconnection options,” such as ERCOT’s approach.

Flexible interconnection was “really front and center in the U.S. Department of Energy’s interconnection roadmap,” he said, “and I think that really caught the attention of FERC staff.” FERC will hold a workshop on innovations and efficiencies in generator interconnection on September 10 and 11, he noted.

With electric loads projected to increase, creating “more pressure to get more generation on the system,” Norris predicted that “we’re going to see a significant increase in demand for more flexible interconnection options in the years ahead, including energy-only interconnection, ”such as ERCOT’s approach, as well as “provisional service, and potentially other fast track options.”

Norris said his team’s ongoing analysis of 3500 interconnection studies for solar projects shows that upgrade costs for energy-only interconnection have been nearly equivalent to upgrade costs for network resource interconnection. The lack of cost savings for energy-only interconnection, he suggested, shows that energy-only interconnection is “not living up to (FERC’s) original intent,” when FERC created that service option in its Order 2003, as a “credible alternative to network resource interconnection service that would be faster and cheaper.”

“There’s a lot we can do to improve energy-only interconnection service and provisional service,” he said.

Regan said in the question period that “we don’t expect a major order” from FERC to result from its September workshop.

DNV Principal Consultant Morgan Putnam said in a comment posted in the question-ranking app that “Our collective desire for 0% curtailment has greatly misled the industry.“

The panel discussion’s theme was “Can the ERCOT ‘connect and manage’ approach lead to faster and cheaper grid interconnection nationwide?”

The conference was produced by Infocast and supported by 15 sponsors.

Smart inverter adoption is generally slow nationwide, says Sunrun executive

William Driscoll — Fri, 28 Jun 2024 16:26:19 +0000

To greatly increase hosting capacity for distributed solar and storage, Sunrun executive Steven Rymsha calls for faster adoption of smart inverters using default settings, along with related consumer protections, and ultimately a plug-and-play experience for customers buying rooftop solar.

The pace at which states and utilities are requiring smart inverters for new distributed solar and storage installations “generally continues to be slow,” said Steven Rymsha, Sunrun’s director of grid solutions, public policy.

That matters because work in Hawaii, he said, has shown that hosting capacity for distributed solar and storage can increase by as much as 500% on a distribution circuit where smart inverters use default settings that regulate voltage. Hawaii’s main utility has greatly expanded its hosting capacity by requiring smart inverters that meet a global standard known as IEEE 1547-2018. Rymsha made his comments in an interview.

By regulating voltage, smart inverters enable more distributed solar and storage on a distribution circuit without the need for costly utility voltage regulation hardware. That’s true not just for a primary distribution circuit, Rymsha said, but also on a customer’s secondary circuit, or service connection from the customer’s service transformer—a circuit that may serve up to 10 or more customers.

In Hawaii, California and Illinois, the earliest adopters of smart inverter capabilities, Rymsha said “the research and the real-world experience” show that the IEEE default settings for the smart inverter functions known as volt-var and volt-watt “make a lot of sense.” Even before that, in the IEEE standards development process, he said the default settings were “well vetted by utilities and other stakeholders.”

Rymsha said that while the smart inverter settings being selected by states “should go through stakeholder processes,” enabling smart inverter voltage regulation functions quickly “is going to make interconnection easier for customers today and long into the future.”

Not-smart inverters

Eight states, along with certain utilities in 13 states, now require that distributed solar and storage installations use smart inverters that meet the IEEE 1547-2018 standard, according to a tracker maintained by the nonprofit group IREC.

Yet IREC’s tracker shows that some of the states and utilities that have adopted smart inverters specify that the inverters must use a volt-var setting that does not help control voltage on a distribution circuit. Without controlling voltage, the setting, which IREC’s tracker refers to as “unity power factor,” does not improve the circuit’s hosting capacity for solar and storage.

Rymsha noted that smart inverters also have functionalities that can support the transmission grid, and that settings enabling those functionalities are now required for newly installed smart inverters in the New England grid region ISO-NE. Yet the volt-var and volt-watt settings that regulate voltage on a distribution circuit “are still not being used across that entire region,” he said.

Other states, he said, are in a similar circumstance, as they are requiring the latest inverters, but without the voltage management settings enabled. “The pace of function activation should be accelerated,” Rymsha said.

Asked whether it would be feasible for a state to call for updating the settings in smart inverters used in rooftop solar systems after the systems are installed, Rymsha said that for inverters that have an internet connection, “I am aware of new grid codes being pushed to inverters, but the process in Hawaii to do this was complicated as it required customer consent in some form.”

Consumer protection

In Puerto Rico, where the distribution utility is expected to require smart inverters starting July 1, Rymsha said Sunrun is advocating for consumer protections as it participates in stakeholder discussions about smart inverters.

Rymsha anticipates the utility will require smart inverters to use the IEEE’s default volt-var and volt-watt settings, and if so, there should be “a consumer protection package, similar to what Hawaii has rolled out,” he said. California and Maryland have also set consumer protection packages when they required that both functions be activated, he added.

Hawaii, working in collaboration with the National Renewable Energy Laboratory, used a custom setting similar to the IEEE default setting for the volt-var function, and activated volt-watt for all customers, Rymsha said, “which really revolutionized the interconnection process for everyone.” Hawaii’s main utility uses advanced metering infrastructure data to monitor voltages, he said, plus the volt-watt function which enables curtailment to maintain voltage within the proper range when needed. But “if there is excessive curtailment, the utilities are responsible to upgrade the infrastructure within a predetermined amount of time.”

“We think something like that’s needed for Puerto Rico as well,” he said.

Plug and play

Beyond seeing “a lot of opportunity” to use smart inverter settings to enable greater adoption of distributed solar and storage, Rymsha sees an opportunity to “make it like buying any other product you like,” where a customer buys the product, “and very quickly it’s being delivered to your house and operating.”

“For a lot of customers today,” he said, their expectations start out “very high, and then when they get involved in the utility processes, delays can occur without any visibility from the development community—just big, big bottlenecks.”

“As we look to electrify society, we need to look at how we can radically change utility processes on the interconnection side, to really make distributed energy resources an attractive, consumer-friendly solution. And as these get built out at scale, there’s a lot of opportunities to provide grid services; ideally, that’s all packaged up front.”

Maine may design a distribution system operator to advance distributed energy resources

William Driscoll — Mon, 24 Jun 2024 13:30:30 +0000

Maine has hired a consulting firm to evaluate whether forming a distribution system operator could speed deployment of distributed energy resources and support other state goals. Consultants are reviewing how the approach is used in five other countries.

Maine has hired the consulting firm Strategen to evaluate whether a distribution system operator (DSO) could be designed to achieve growth in distributed energy resources and help the state meet other goals: lower electricity costs, improved electric system reliability, and the state’s overall climate goals.

The state law calling for the study defines roles for a DSO including overseeing integrated system planning, operating the state’s electric grids, and administering a market for distributed energy resources (DERs).

Speaking on a webinar about the study, Strategen Advisor Matthew McDonnell said the firm will evaluate the potential to reduce customers’ electric bills by first considering the “base case” for the state of Maine—that is, investment priorities that have already been established through integrated resource planning or other means. The firm will then “look at how a differentiation from that base case to more of a high DER state, as facilitated by a prospective DSO, can enable some potential cost savings going forward through load flexibility and other opportunities.”

Responding to a question about distributed storage, McDonnell added “certainly we’re thinking about distributed energy storage and its use either as a standalone asset or in conjunction with distributed solar or other energy resources.”

Standalone distributed solar was not mentioned on the webinar, which was hosted by the Maine Governor’s energy office.

The energy office said in a statement that no jurisdiction in the U.S. now has a DSO. McDonnell said Strategen is “looking to draw learnings” from similar distribution network operator approaches used in parts of the United Kingdom, Australia, Germany, France, and Ontario, Canada.

If Strategen’s initial study concludes that a DSO can be designed to help achieve the state’s objectives, and the Governor’s energy office agrees with that conclusion, Strategen will conduct a second part of the study to develop a DSO design proposal that identifies the scope and characteristics of a DSO.

A DSO design “may not include the acquisition or ownership of any transmission and distribution utility assets,” the state law says. The law calls on the Maine governor’s energy office to ensure opportunities for stakeholder engagement throughout the study process.

The Strategen team includes consultants Lorenzo Kristov, who previously worked for California’s grid operator CAISO, and Mark Patterson, principal at Energy Catalyst in Australia.

Strategen expects the draft of its initial study to be released in late summer. If a second part of the study is authorized, that part is expected to be completed by year-end.

The nonprofit Clean Coalition, based in California, has advocated for the formation of distribution system operators in that state.

NREL guide for anyone seeking more solar and storage in utility resource plans

William Driscoll — Tue, 18 Jun 2024 13:30:54 +0000

A guide to utility resource plans aims to help state regulators and others engage effectively with utilities in reviewing the plans, which have often been challenged for limiting solar and storage in projections of new generating capacity needed.

The National Renewable Energy Laboratory (NREL) has published a guide to understanding the integrated resource plans (IRPs) that utilities prepare to project the generating capacity they will need in the future. Most states require utilities to develop IRPs, as shown in the map below reflecting requirements as of March 2022.

Screenshot

NREL’s guide was requested by the National Association of State Energy Officials (NASEO), the National Association of Regulated Utility Commissioners (NARUC) and the U.S. Department of Energy.

To develop an IRP, a utility uses a power system model together with data inputs and assumptions. A utility’s data, assumptions and modeling approach are often challenged by state regulators, solar trade groups, and nonprofit groups that make a case for including more solar and storage in the plan to achieve a least-cost, reliable system.

NREL says the guide “can help planners and stakeholders understand power system model results and ask the right questions of utilities” when reviewing utility resource plans. The guide is divided into beginner and advanced levels.

NASEO requested the guide to support state and territory energy offices in their work with the private sector “to accelerate energy-related economic development and support meeting state energy goals,” said Kirsten Verclas, NASEO senior managing director for electricity and energy security. To conduct that work, staff “need to have a profound understanding of energy modeling” and how utilities use models to plan for the “grid of the future,” she said.

Verclas said NASEO hopes the guide will enable energy offices “to ensure that utilities’ modeling approaches include state energy goals.”

Maggie Shober, research director for the Southern Alliance for Clean Energy, said that integrated resource plans “are notoriously difficult to understand, let alone engage in.” The NREL guides will help SACE make resource planning “more accessible to everyone,” she said. That could help regulators be more responsive to what members of the public are interested in, she said, such as deployment of solar and storage resources “at an accelerated pace and in an equitable manner.”

Wesley Cole, an energy analyst with NREL and point person for the guidebook project, said “more people are engaging in the utility planning process than ever before, and many are new to planning the grid with resources such as wind and solar.” He said the guide, beyond helping people “get up to speed,” can also “help everybody because it should lead to better decisions in the end.”

Three states have taken a step further on resource planning, as Arizona, New Mexico and Michigan now require utilities to make their resource modeling transparent. Those policies follow a proposal put forth by Anna Sommer, a principal of the consulting firm Energy Futures Group, for states to require transparent modeling to save consumers money. Under her proposal, each utility preparing a resource plan would provide to the state and selected intervening parties the data sets it used, a license to use the same model that it used, and a manual for that model.

The two-part NREL guide to resource plans is titled “Understanding Power System Model Results for Long-Term Resource Plans.”

The nonprofit Regulatory Assistance Project previously published a guide to integrated resource plans.

Reshore solar manufacturing but don’t stall construction with tariffs, suggests union official

William Driscoll — Mon, 17 Jun 2024 13:20:38 +0000

A leader of a union whose members work in construction and maintenance said the union supported a moratorium on tariffs on certain imported solar panels, as domestic panel output increases, to preserve opportunities in solar construction and installation.

Two-thirds of jobs in the solar industry are in construction and installation, versus 13% in manufacturing, said a union leader on a webinar hosted by the American Clean Power Association (ACP).

“We’re a little concerned that the “tail” of manufacturing “could wag the dog,” said Jeff Soth, legislative and political director of the International Union of Operating Engineers, referencing his union’s support for a moratorium on solar panel tariffs that support domestic solar manufacturing. “We’ve adopted the ACP position,” he said.

Chiming in, Bill Parsons, American Clean Power (ACP) senior vice president and political director, said Soth had “articulated a really important principle, which I think our member companies would subscribe to, which is a very firm desire and commitment to reshore as much of the supply chain as we can, as quickly as we can, consistent with deployment.”

“If you cut off” foreign solar panel supply “too quickly,” Parsons said, “you haven’t really helped anything. You’ve just slowed down the construction jobs and the benefits for the grid and for the economy.” Parsons said companies are faced with a dilemma, “the choice to buy stuff that doesn’t exist yet.”

Two-thirds of operating engineers work in construction, Soth said, typically operating equipment such as cranes and backhoes, while one-third are maintenance engineers. Operating engineers work across all energy industries, he said.

Union support for projects

Turning to the potential for union support of new projects, Brad Markell, principal with Clean Energy Labor Advisors, said “you see some opposition” to both utility-scale solar projects and transmission projects. Yet “local unions, that are everywhere, are a key locus for local participation,” he said. Unions can add value “early in community involvement, because union members are living in these communities, and once they understand there’s a potential project coming through their area that they would like to work on, they become advocates.”

Soth said three unions had responded to a request from the solar industry, which led to a tri-trades agreement among the unions representing “the three essential crafts to build solar generation,” namely operating engineers, electricians and laborers. “We’re in the business of meeting the needs of owners and developers,” he said, “and they demanded, frankly, a streamlined project labor agreement with the three essential crafts, and that’s what we gave them.”

Wages, apprenticeships

“The skills and productivity” of union members, Soth said, give the union “a competitive edge, and frankly, allow us to command at the negotiating table the kinds of wages and benefits that our folks receive.”

Noting that a prevailing wage requirement is a condition for receiving energy tax credits, Soth said the requirement “provides some support for our role in the workplace and ensures that the green jobs of the future are, in fact, good jobs.” Clean energy industries have struggled, he said, “to be able to demonstrate that those are family sustaining jobs, particularly in the solar industry, historically, and that’s a function of residential deployment, small projects.”

Noting that women represent less than 25% of construction workers, Soth said his union is “doing everything we can” to recruit women and people of color into the trade, including marketing apprenticeships to students in high school. The operating engineers’ union offers training and apprenticeship programs.

“Apprenticeship is the primary pathway into a career in the operating engineers,” Soth said, adding that apprenticeship is “the best kept secret in career and vocational training.” He suggested that government investment in apprenticeship preparedness would be worthwhile, such as providing young people with “an introduction into the variety of craft unions out there and the opportunities that exist in the construction business.”

Five Puerto Rico reservoirs could host 596 MW of floating solar

William Driscoll — Tue, 11 Jun 2024 15:58:19 +0000

Potential sites for solar in Puerto Rico include reservoirs, brownfields, closed landfills, fossil generating plants after closure, and transmission rights of way, determined analysis by the National Renewable Energy Lab.

The National Renewable Energy Laboratory (NREL) has estimated that five reservoirs in Puerto Rico could host 596 MW of floating solar, although the costs would be about 25% higher than for ground-mounted solar. NREL published its analysis in a report and a technical annex.

The analysis grew out of a concern, NREL said, that “Puerto Rico’s commitment to achieving 100% clean energy by 2050 will require identification of suitable sites for new generation projects.”

An additional 190 MW of “economically viable” solar projects are possible across seven sites designated as “Superfund” sites by the U.S. Environmental Protection Agency (EPA), the study found. For six of the sites, analysts assessed “how much grant money is needed” to meet economic targets for solar projects under municipality-owned and third-party owned models.

Image: Dennis Schroeder, NREL

In comparison to those estimates, both in the hundreds of megawatts, Puerto Rico has the potential for tens of gigawatts of both rooftop and large-scale ground-mounted solar, according to NREL’s “PR 100” summary report published early this year.

Across all residential buildings, Puerto Rico has the “technical potential” for 20.4 GW-dc of rooftop solar, that report estimated. A technical potential analysis does not consider the financial viability of projects. The U.S. territory reached 680 MW of rooftop solar last October.

Puerto Rico’s technical potential for utility-scale solar ranges from 14.2 GW under a “less land” scenario to 44.7 GW under a “more land” scenario, the PR 100 summary report said.

In both scenarios, modeled development of utility-scale solar was “restricted from” roadways, water bodies, protected habitats, flood risk areas, slopes greater than 10%, and agricultural reserves. But in the “less land” scenario, solar was also restricted from areas identified for agricultural use in the Puerto Rico Planning Board’s 2015 Land Use Plan.

NREL’s new analysis also estimated technical potential for 1–2.5 GW of solar across 160 contaminated sites, a total of 636 MW of floating solar on 55 water bodies, 213 MW of solar on 41 closed landfills, 78 MW of solar at two fossil generating plants once they are closed, and 21–50 MW of solar on transmission line rights-of-way.

The new NREL analysis adapted a methodology from an EPA decision tree tool titled “RE-Powering America’s Land Initiative.”

Flexible interconnection with curtailed output can benefit everyone, analyst says

William Driscoll — Tue, 11 Jun 2024 13:00:31 +0000

Allowing flexible interconnection for large solar projects can reduce costs and speed deployment, benefiting developers, ratepayers and utility staff, said a presenter at a North Carolina conference of utility regulators.

Duke Energy Progress has announced network upgrade costs of $470 million to interconnect about 1.9 GW of solar and solar-plus-storage projects in North Carolina and South Carolina that were proposed in response to its 2023 resource solicitation, with an average lead time until interconnection of 4.5 years.

A “significant” portion of the identified upgrades could be avoided “with minimal or zero impact to reliability” if a more flexible interconnection service that provided for occasional curtailment of solar generation could be used, said Tyler Norris, a Duke University Ph.D. candidate and former Cypress Creek Renewables executive, at a meeting of the Southeastern Association of Regulatory Utility Commissioners.

Under flexible interconnection, a project would be required to curtail its output when transmission is congested.

Norris said North Carolina does not currently allow flexible interconnection for state-jurisdictional projects. Yet he said flexible interconnection would yield benefits for solar developers, ratepayers, and utility staff.

Speed of interconnection is one benefit. Norris noted that Texas, where the grid operator ERCOT allows a form of flexible interconnection, has quickly added solar in recent years. Although North Carolina ranked second in utility-scale solar deployment in 2019, Texas “sort of blew past us, they blew past Florida, and now they’ve surpassed California as well.”

ERCOT’s approach to flexible interconnection, known as “connect and manage,” suits the grid operator’s energy-only electricity market, Norris has previously written, and could be adapted for use elsewhere in the U.S. where electricity markets have a capacity market alongside an energy market.

Norris said the Duke utility’s expected network upgrade costs for the 1.9 GW of projects follow an approval by the North Carolina Utilities Commission for about $600 million in network upgrades “which was precisely intended to integrate more utility-scale solar and solar-plus-storage.”

North Carolina does not permit flexible interconnection, Norris said. So the utility’s cost study did not consider the “ability to curtail those resources in real time during peaks” as a way to avoid the upgrades. Many large network upgrades that are allocated to projects in interconnection studies “may be triggered due to rare or even extremely rare contingencies,” he said.

“This isn’t to pick on Duke by any means,” he said. “I think they’re doing a great job on a lot of fronts.”

Norris plans to work with team members at Duke University to analyze the network upgrade costs for the 1.9 GW of solar and solar-plus-storage projects under a scenario in which energy-only interconnection was allowed.

Avoiding network upgrade costs through flexible interconnection would ultimately help ratepayers, Norris said. “All these costs end up going to the ratepayers. We assign them to the projects, but either it shows up for the ratepayers in the form of a higher power purchasing agreement (PPA) price, or in the form of going directly into the rate base.”

Flexible interconnection could reduce the burden on a utility too, Norris said. “We already have a lot of other transmission and network upgrades going on for other reasons,” he said, and “layering more and more” upgrades for particular projects puts “more burden on already strained utility construction teams and planning teams.”

More generally, Norris said that “we’ve already invested a huge amount” in the existing transmission network, and that “if we can get more generators on the system that don’t require more and more network upgrades, we’re making more efficient use of that expenditure we’ve already made.”

Norris noted that in the U.S. Department of Energy’s recent interconnection roadmap, “one of the key themes that came out of it was offering fast track and more flexible interconnection options as a priority solution.”

Norris expects that a Federal Energy Regulatory Commission interconnection workshop set for September 10-11 will address issues related to flexible interconnection.

More states now require smart inverters, enabling more distributed solar

William Driscoll — Mon, 10 Jun 2024 18:32:29 +0000

Pennsylvania and Minnesota have joined six other states in requiring smart inverters for distributed solar and storage. Certain utilities in 13 states and Puerto Rico also require smart inverters, while six states are considering the requirement. Smart inverters enable more solar on distribution circuits.

The Interstate Renewable Energy Council (IREC) has launched a spreadsheet tracker and map showing that eight states and certain utilities across the U.S. now require smart inverters for new distributed solar and storage installations.

Installers working in those states and utility service areas must use inverters that are certified to meet the smart inverter standard known as IEEE 1547-2018. Inverters meeting the standard can regulate voltage on a distribution circuit, and that capability allows more solar to be installed on each circuit without utility-supplied voltage regulation hardware.

Pennsylvania and Minnesota adopted the smart inverter standard early this year, after Minnesota had deferred its adoption based on the previously limited market availability of qualifying inverters, said an IREC spokesperson.

The Puerto Rico distribution utility Luma adopted the standard this month; Puerto Rico last year led the nation in the amount of residential solar installed per capita.

Smart inverters’ capability to regulate voltage becomes increasingly important as the amount of distributed solar on a given circuit increases. In Hawaii, for example, which reached high levels of solar on distribution circuits by 2021, a Sunrun executive said at the time that thanks to the smart inverter settings required by the utility HECO, which serves nearly the entire state, most customers could “instantly interconnect” new solar. California has also had good success with smart inverters, while Oregon this year adopted the standard and also made it easier for export-limiting distributed storage projects to receive interconnection approval.

Other states with smart inverter requirements, according to the IREC adoption tracker, are New Mexico, Maryland and Massachusetts.

In New York, which set a state-wide smart inverter requirement with different deadlines for its utilities, several utilities have already adopted the standard.

Regulators in six other states are in the process of adopting smart inverter requirements: Colorado, Texas, Wisconsin, Illinois, Ohio and New Jersey.

In 11 other states at least one utility has adopted the standard.

The tracker shows that the grid operator PJM, which serves a region stretching from Chicago to New Jersey, has recommended a smart inverter adoption date and inverter settings for the states and utilities in the region.

To compile the tracker, IREC investigated the smart inverter adoption status of every state and more than 100 utilities. The tracker presents inverter performance criteria, or settings, specified by the various states and utilities. IREC plans to update the tracker on a quarterly basis.

A new federal transmission rule won’t help renewables projects anytime soon

William Driscoll — Tue, 04 Jun 2024 18:25:33 +0000

Although promptly deploying grid-enhancing technologies and advanced conductors could speed interconnection in the short term, a new federal transmission rule will improve interconnection only once new transmission is built, said panelists on a webinar.

A new Federal Energy Regulatory Commission (FERC) order on transmission planning will not help renewables projects connect to the transmission grid “in any sort of timeframe that would benefit” a project now awaiting interconnection, said Kat Gamache, a partner with the law firm Norton Rose Fulbright, on a webinar hosted by the firm.

FERC Commissioner Allison Clements agreed with Gamache, saying “this new transmission rule is not going to help today’s projects,” except to the extent that grid-enhancing technologies including advanced conductors “are brought into economic planning processes and reliability planning processes right away.” Doing so would be “a material improvement,” she said.

FERC Order 1920 requires transmission owners to consider these grid-enhancing technologies in developing the 20-year transmission plans that the order requires.

But Clements, while acknowledging three barriers to deploying the technologies, made the case for their prompt deployment. The first barrier is financial, she said, agreeing with a concern related by the webinar’s moderator that grid-enhancing technologies cost less than new transmission and do not add much to a utility’s rate base, whereas utilities aim to grow by adding to their rate base.

Then there are operational barriers to using grid-enhancing technologies, Clements said, because “even though many of these technologies are common around the world, they haven’t been deployed in the US.” Grid analysts have challenged the federally owned utility Bonneville Power and other transmission providers for yielding to operational barriers.

“There are also corporate barriers,” Clements said, because engineers, their group leaders and executives “are not incentivized to make more room on the grid now.”

But because FERC’s transmission rule will “take years to bear fruit,” Clements advised that “any transmission provider in a state that wants economic development, wants re-onshoring of advanced manufacturing, wants load growth for the value it brings to its state for other reasons, should be saying, ‘Let’s line up these grid-enhancing technologies, because right now they can make space on the system.’”

Turning to FERC’s role, Clements said “there’s a lot more to be done” to improve interconnection, following FERC’s Order 2023 last year to reform the interconnection processes of transmission providers.

“There’s a lot of opportunity” for standardization in the way interconnection applications are processed, she said, and for machine learning “to help us do these studies very quickly.” In addition, there are some “really interesting conversations going on” within grid operator SPP about possibly setting a standard fee per megawatt for interconnecting a generator, she said.

Clements expressed hope that a FERC workshop on September 10 and 11 to consider further improvements to interconnection will involve some of those questions.

Grid Strategies President Rob Gramlich said he expects that in the medium term, transmission regions “that actually follow through and implement” FERC’s new transmission rule will see a great improvement in interconnection speed and cost once new transmission is built.

He gave the example of the midcontinent grid operator MISO, where in late 2008 an agreement was reached to build new transmission to connect 300 MW of wind projects to the grid. Five years later, by 2013, the lines were built, “and almost instantaneously, when those lines were energized, interconnections became extremely fast and cheap” compared to previous years, he said.

Clements reminded listeners that “we have 2.6 terawatts of generation in line to hook up to the grid, and 90-plus percent of that is solar, wind and storage.”

Grid analysts challenge Bonneville Power’s pace in adopting advanced conductors

William Driscoll — Wed, 29 May 2024 14:28:46 +0000

As the White House encourages utilities to use advanced conductors to help interconnect new renewable generation, the federally-owned utility Bonneville Power is moving slowly to use the high-capacity conductors, analysts said.

Grid analysts have said that the Bonneville Power Administration, a generation and transmission utility owned by the U.S. Government that serves northwestern states, is moving too slowly to adopt advanced conductors.

Advanced conductors are high-capacity conductors that can replace existing conductors on existing transmission towers.

BPA has “begun the process” to analyze and qualify advanced conductors to increase the capacity of its grid, the utility said in January, adding that the process “can take months or years of physical testing and analyses.”

Analysts at Energy Innovation and GridLab challenged BPA’s approach and that of many other transmission providers, saying that “studying the technology itself rather than relying on real-world deployments or other peer organizations’ testing to approve the technology appears to be the status quo among transmission organizations. This ‘bottom-up’ adoption strategy considerably slows integration of many emerging technologies, not just advanced conductors.” They said BPA’s approach is commonly used at other utilities as well.

The analysts presented their views in a companion report to a technical analysis that found reconductoring could enable 764 GW of transmission-connected solar by 2035.

The U.S. Department of Energy last month flagged reconductoring as having substantial potential to increase transmission capacity, in a “liftoff” report calling for a national collaboration to deploy such technologies.

The White House this week announced a federal-state initiative involving 21 states to modernize the grid, in alignment with its effort to mobilize public and private sector leaders to upgrade 100,000 miles of transmission lines over the next five years. Substantial federal funding for reconductoring is available through three programs made possible through the Inflation Reduction Act (IRA) and the Bipartisan Infrastructure Law (BIL).

One indicator of reconductoring’s potential within BPA’s service area is that from 2000 to 2023, the utility completed six high-voltage projects that enabled interconnection of 7 GW of wind power and 525 MW of solar.

The Federal Energy Regulatory Commission’s recent Order 1920, which requires utilities to develop and periodically update a long-term transmission plan, requires each utility to “consider” advanced conductors when developing their plan.

Two approaches to save net metering in Puerto Rico

William Driscoll — Tue, 14 May 2024 16:21:37 +0000

A solar trade group wants the White House to appoint new pro-solar members to the federal oversight board that has challenged Puerto Rico’s net metering law, while the former president of the Puerto Rico Senate advises considering amending the law.

To protect Puerto Rico’s solar net metering law, the Solar and Energy Storage Association of Puerto Rico has called on the White House to replace six members on a federal oversight board that has challenged the law, including five whose terms have expired, said SESA-PR President PJ Wilson on a webinar.

Counseling another approach, former president of the Puerto Rico Senate Eduardo Bhatia said on the webinar that the federal oversight board, in its April letter to the Puerto Rico government challenging net metering, included one sentence saying that “we could amend the law.” Bhatia said “we have to sit down with the oversight board” to “see what could be amended in the law.” He expressed hope that “we can all work together.”

Bhatia noted that the board—formally the Financial Oversight and Management Board (FOMB) for Puerto Rico—has the authority to challenge a Puerto Rico law in court and request that the law be repealed.

Wilson said “we are calling upon President Biden” to appoint six new members to the seven-member FOMB “who are supportive of Puerto Rico, supportive of solar power and supportive of dissolving the board as soon as possible.”

Wilson said that five FOMB members continue to serve after their terms expired last December, as shown below, while one seat is vacant and one member just began serving in January.

Benefits

Wilson recapped points he made in an April webinar on the value of net metering in Puerto Rico, noting an independent report projecting that Puerto Rico’s distributed generation would increase 18% per year with continued net metering, and a study finding that the value of net metering to Puerto Rico’s grid exceeds the retail rate paid for net metered energy of $0.24/kWh.

Wilson added that the National Renewable Energy Laboratory’s “PR 100” study shows that rooftop solar adoption would not start to drive rates up until after 2030, and said that under Puerto Rico’s net metering law, net metering may be “revisited” in 2030.

Bhatia said the FOMB “indeed has a responsibility to look at the finances of Puerto Rico.” But he said net metering is saving money for the people of Puerto Rico, and that the 800 MW of solar installed due to net metering is reducing the number of blackouts in Puerto Rico. As Puerto Rico’s coal units “constantly” break down, he added, rooftop solar is allowing for repairs to take place. “And finally, there is the dramatic reduction in the purchase of fossil fuels” for generation.

Missing 450 MW

Wilson said that the current FOMB “is not supportive of solar.” He said that in 2021, the FOMB “issued a letter very similar” to its letter last month, “announcing the cancellation of 450 MW of utility-scale solar,” after “years of negotiation” among multiple utility-scale developers, the Puerto Rico utility, and the territory’s energy regulator. The projects had received approval from the energy regulator “but the oversight board stepped in to squash it,” Wilson said. “We still don’t know why; there’s still no published analysis. They just said ‘that’s too expensive.’”

Had the FOMB not “killed” those solar projects, Wilson said “we probably would have that 450 MW of solar built today, and instead of being at 12% renewables we’d be at 17%.” Puerto Rico has a legislated goal of 40% renewables by 2025.

As a result of that FOMB action, Wilson said, “all those developers—some were local Puerto Rico developers, some were international developers—all of them deemed Puerto Rico to be a very high-risk market, and a lot of them left the market.”

Deadlines and responses

Puerto Rico Governor Pedro Pierluisi has asked the FOMB for more time to respond to both FOMB’s April 10 letter and a second letter that FOMB sent on May 2 calling for repeal of the net metering law, Wilson said. Both letters set deadlines for government action.

The Puerto Rico Energy Bureau has also responded to the FOMB’s April 10 letter, which said that the energy bureau had not yet determined whether to make changes to the net metering law, as required by the FOMB-certified fiscal plan for the Puerto Rico legacy utility PREPA. Wilson said the energy bureau responded that it is continuing to conduct that study, and that, in Wilson’s words, the energy bureau’s understanding was that Puerto Rico’s net metering law “doesn’t prevent them from doing the study, but only prevents them from having any consequences as a result of doing the study until 2030.”

DOE proposes ten “national interest” transmission corridors

William Driscoll — Thu, 09 May 2024 11:00:52 +0000

Eight of the ten transmission corridors proposed by the U.S. Department of Energy would facilitate transmission between grid regions; one would expand transmission within the Mid-Atlantic’s PJM grid region; and one would expand transmission in the Northern Plains.

The U.S. Department of Energy has proposed ten National Interest Electric Transmission Corridors, as shown in the featured image above, and invites public comment on the potential NIETCs.

DOE previously sought industry input for the first stage of the NIETC designation process.

A NIETC designation, once final, “unlocks” federal financing and permitting tools to spur construction of transmission projects “to alleviate consumer harms,” DOE said. Such harms could result from transmission capacity constraints or congestion “currently or in the future,” and could show up as lower reliability or higher costs.

When transmission is congested, for example, some lower-cost renewable power must be curtailed instead of delivered to customers.

In terms of transmission financing, a NIETC designation can unlock public-private partnerships through the Bipartisan Infrastructure Law’s $2.5 billion Transmission Facilitation Program, as well as direct loans through the Inflation Reduction Act’s $2 billion Transmission Facility Financing Program.

A NIETC designation also allows the Federal Energy Regulatory Commission to issue permits for the siting of transmission lines within the NIETC if state siting authorities either do not have authority to site the line, or have not acted on an application for over one year, or have denied an application.

DOE has presented in a report its preliminary findings of transmission capacity constraints or congestion within each of the ten geographic areas that it proposed for NIETCs. Streamlined generator interconnection is one of the expected benefits of transmission development resulting from NIETC designation, DOE said.

One of DOE’s ten proposed NIETCs would expand transmission within the Mid-Atlantic’s PJM grid region, helping the PJM grid operator to maintain and improve reliability, lower consumer costs, and meet future generation and demand growth.

Another proposed NIETC in the Northern Plains would particularly aid Native American tribes to develop energy resources, stabilize energy costs and spur local economic development.

Those two proposed NIETCs reflect a finding in DOE’s National Transmission Needs Study that 54,500 GW-miles of within-region transmission must be added for a clean grid under “the most likely power sector future.”

Eight of the ten proposed NIETCs would facilitate transmission between grid regions, reflecting a finding in the needs study that interregional transfer capacities to transmit electricity between regions would need to increase by nearly 125 GW under the most likely power sector future.

Here are those eight proposed NIETCs and the regions they would connect:

A New York-New England NIETC would increase transmission capacity between the New York and New England grid regions.
A New York-Mid-Atlantic NIETC would increase transmission capacity between the New York and PJM grid regions and facilitate interconnection of offshore wind.
A Mid-Atlantic-Canada NIETC would connect the PJM grid region with a Canadian grid region.
A Midwest-Plains NIETC would facilitate interregional transmission among the PJM, MISO, and SPP grid regions.
A Delta-Plains NIETC would improve transmission between the SPP and MISO grid regions, and potentially connect the Eastern and Western Interconnections.
A Plains-Southwest NIETC would facilitate transmission among the WestConnect, SPP, MISO, and PJM grid regions, and potentially the CAISO grid region.
A Mountain-Plains-Southwest NIETC would link the Eastern and Western Interconnections and potentially facilitate transmission between the WestConnect and SPP grid regions.
A Mountain-Northwest NIETC would facilitate interregional transmission between the CAISO and NorthernGrid regions.

DOE will present a webinar on the current phase of the NIETC designation process on May 16.

DOE previously said it anticipates re-opening the NIETC designation process after each publication of its triennial National Transmission Needs Study or as determined by the Secretary of Energy.

Colorado co-op United Power is free to pursue renewables after exiting Tri-State

William Driscoll — Tue, 07 May 2024 14:57:33 +0000

To build out its renewables portfolio, United Power is the latest electric utility co-op in Colorado to exit its long-term power supply contract, while other co-ops plan to let their contracts expire.

Colorado electric co-op United Power stopped buying power from the Tri-State Generation and Transmission Association on May 1, and has started buying power from Guzman Energy, a wholesale power supplier that says it focuses on “cheaper, better and cleaner energy sources.”

United Power says in its planning roadmap that independence from Tri-State will allow higher levels of self-supply through local renewable energy sources, and the opportunity to partner on more utility-scale projects. With its newfound freedom, United Power is initially developing a microgrid that will combine floating solar with storage.

United Power had been working to exit its contract with Tri-State for several years.

Two other co-ops, the Kit Carson co-op in New Mexico and the Delta Montrose co-op in Colorado, have already exited Tri-State, and now buy wholesale power from Guzman Energy.

Two more Colorado co-ops will soon follow suit. The Mountain Parks Electric co-op will exit Tri-State in early 2025, and has lined up a 20-year wholesale power contract with Guzman. The La Plata Electric co-op has voted to exit its contract with Tri-State in 2026.

The largest electric co-op in Colorado, known as CORE, has a power supply contract with Xcel Energy that ends late next year. CORE said that a wholesale power supply partnership it entered with Invenergy last year “signals CORE’s transformation to a fully independent electric utility with control of its power supply future.”

The partnership with Invenergy will provide CORE with 1.2 TWh of renewable energy per year, including 400 MW of new solar and wind projects and 100 MW of battery storage, backed up by 300 MW of existing natural gas generation, starting in 2026.

CORE says that given Colorado’s mandate to reduce 2005 carbon emission levels 80% by 2030, “we are using this mandate as a target for our emissions goals,” adding that “part of our mission is to listen to and implement the wishes of our members, which largely align with the state on this issue.”

CORE recently announced it will partner with co-op Holy Cross Energy to buy power from a 75 MW solar project in Colorado. HCE plans to reach 100% renewable electricity by 2030.

CORE’s planned departure from its Xcel Energy agreement follows a CORE lawsuit over a year-long power outage at a coal plant that is majority owned by Xcel and partly owned by CORE. The lawsuit resulted in a damages award that required Xcel to pay $26 million to CORE.

Groups sue FEMA and HUD to focus energy funds on distributed solar and storage

William Driscoll — Fri, 03 May 2024 13:36:05 +0000

Two federal agencies that provide billions of dollars for energy-related projects should fund renewable energy, a number of groups have argued in two lawsuits and two rulemaking petitions.

The Center for Biological Diversity has filed lawsuits against the Federal Emergency Management Agency (FEMA) and the U.S. Department of Housing and Urban Development (HUD), alleging the agencies have withheld public records and failed to outline plans to use “resilient” renewable energy to “rebuild communities ravaged by the climate emergency.”

FEMA “focuses almost exclusively on restoring centralized fossil fuel-based energy systems as it spends billions of taxpayer dollars each year rebuilding communities after disasters,” the center said in a statement.

Last year the center filed a lawsuit aiming to redirect toward solar power FEMA’s $13 billion to rebuild Puerto Rico’s grid. That lawsuit cited a study that recommended equipping every home in Puerto Rico with 2.7 kW of PV and 12.6 kWh of battery storage. Last month the judge handling that FEMA lawsuit transferred the case, at the government’s request, to the U.S. District Court for the District of Puerto Rico.

The new lawsuit against FEMA says the agency has failed to comply with a 2018 congressional requirement to define the term “resiliency.” The center says FEMA’s definition of resiliency would show whether the agency is focused on ensuring that communities rebuild “to both withstand and address the climate emergency.”

Meanwhile, HUD “spends billions annually” on utilities in public and assisted housing, the center said, “further propping up the fossil-fuel economy, without significant effort to encourage the use of renewable energy.”

The center’s lawsuit against HUD says the agency violated the Freedom of Information Act (FOIA) by withholding public records detailing its spending on energy-related projects to help communities rebuild after disasters. Those public records “should show how much HUD spends on fossil-fuel related projects compared to sustainable renewable energy alternatives,” the center said. The lawsuit asks the court to compel HUD to disclose the records that the center requested in its FOIA request.

The Center for Biological Diversity also submitted formal rulemaking petitions to FEMA and HUD, each supported by 22 other organizations, to develop regulations that would redirect each agency’s resources toward distributed renewable energy, energy efficiency, and building electrification. The lawsuit against FEMA asks the court to require the agency to complete such a rulemaking, specifically to define the terms “resiliency” and “resilient.”

Speaking for a co-plaintiff in the FEMA lawsuit, Ruth Santiago, attorney for Comite Dialogo Ambiental, a community environmental group in Puerto Rico, said that both FEMA and HUD must direct public funds to “resilient energy alternatives” such as onsite solar and storage “that can provide energy security, justice, and equity, and promote community empowerment.”

“FEMA and HUD are stuck in the fossil fuel past,” said Roishetta Ozane, director of the nonprofit Vessel Project of Louisiana, another co-plaintiff in the FEMA lawsuit. “Hurricanes, tornadoes, flooding, you name it, communities across the Gulf Coast are overwhelmed by the climate emergency,” she said, adding “it’s time for FEMA and HUD to center energy justice and build a renewable future.”

Speaking for FEMA co-plaintiff New York Communities for Change, the group’s Campaign Director Alicé Nascimento said “people in low-income communities living in flood zones like Southeast Queens have borne the brunt of climate change, facing high tides and flash flooding, and the destructive effects of Superstorm Sandy and Hurricane Ida. Every dirty energy project FEMA funds brings us more destroyed livelihoods.”

New green bank to support distributed solar and storage in the Appalachian region

William Driscoll — Mon, 29 Apr 2024 13:15:42 +0000

The Green Bank for Rural America will support community lenders in Appalachian communities to finance climate-supporting projects including distributed solar and storage. The bank and four others received a total of $6 billion in federal awards.

The Green Bank for Rural America has won a $500 million federal award to advance clean energy technology projects in the 13-state Appalachian region and in “energy communities” with a connection to the coal industry.

The green bank expects to leverage private capital to finance $2.25 billion in 2,750 clean energy projects, including distributed solar and storage projects. Other eligible project types under the federal award program are new or renovated buildings with low carbon emissions, and projects supporting zero-emission transportation.

The U.S. Environmental Protection Agency (EPA) made a total of $6 billion in awards to five green banks through the Clean Communities Investment Accelerator, all of which “will flow to low-income and disadvantaged communities,” said a White House press release.

Each of the five green banks receiving the awards will allocate the funds to community lenders, primarily to make loans to projects. A small portion of funds will be used to provide technical assistance to those lenders. The Green Bank for Rural America will provide technical assistance on topics including structuring contracts with local utilities for the sale of solar or wind power.

The Green Bank for Rural America expects to provide capitalization funding to about 100 participating community lenders and investors serving rural areas, with most funding provided in commitments of $10 million or less, and a few commitments ranging up to $50 million. The bank, established by Appalachian Community Capital, will be structured to be a self-sustaining entity.

The support to community lenders will not only finance near-term deployment of climate and clean energy projects, the White House said, but also build the lenders’ capacity to “finance projects at scale for years to come.”

Nationwide, public and private investments in projects supported by green banks reached about $10 billion last year, according to the Coalition for Green Capital.

The five green banks selected through EPA’s competitive application process, most of which have one to five decades of experience, are:

Opportunity Finance Network ($2.29 billion award), which provides capital and capacity building for a national network of 400+ community lenders in all 50 states and several U.S. territories.
Inclusiv ($1.87 billion award), which provides capital and capacity building for a national network of 900+ credit unions.
Justice Climate Fund ($940 million award), a purpose-built nonprofit with a national network of more than 1,200 community lenders, supported by ImpactAssets, a nonprofit with $3 billion under management.
Appalachian Community Capital ($500 million award), which launched the Green Bank for Rural America to deliver clean capital and capacity building assistance to hundreds of community lenders working in coal, energy, underserved rural, and Tribal communities.
Native CDFI Network ($400 million award), a nonprofit that serves the 60+ U.S. Treasury-certified Native community lenders, which have a presence in 27 states across rural reservation communities as well as urban communities.

Improve transmission planning and interconnection cost allocation, says SEIA-affiliated group

William Driscoll — Fri, 26 Apr 2024 13:33:58 +0000

Federal regulators should consider specific reforms to improve transmission planning, lower interconnection costs and provide cost certainty, says a group affiliated with the Solar Energy Industries Association.

The Solar and Storage Industries Institute (SI2) has proposed two transmission interconnection reforms for consideration by the Federal Energy Regulatory Commission (FERC).

The reform proposals are motivated by concerns that connecting new solar and storage to the transmission grid is “increasingly expensive,” while interconnection wait times and the size of the waiting list have grown.

The first of the two proposals is to develop comprehensive regional transmission planning processes that “integrate the interconnection queue” into overall transmission planning.

The second proposal offers a formula to fairly allocate transmission system buildout and local upgrade costs to interconnection customers.

SI2 is the charitable and educational arm of the Solar Energy Industries Association (SEIA).

SI2 proposed that the transmission needs of generation projects that have met certain readiness milestones should be entered into the regional transmission planning process. Planners should also evaluate, SI2 said, network upgrades that have been identified multiple times in the generator interconnection process, but have not been constructed due to the withdrawal of the upgrade-triggering interconnection requests.

The proposed interconnection fee would begin with a non-refundable entry fee to enter the interconnection waiting list, or queue. That fee would be applied toward transmission system upgrades identified in the grid operator’s long-term regional transmission plan. SI2 proposed a three-part formula for calculating this fee, based on the cost of planned regional, subregional and local lines.

The second part of the interconnection fee would cover only those local transmission upgrades needed to connect the project to the grid. The paper suggested that under current practice, interconnection customers are sometimes asked to cover the costs of “a massive transmission upgrade located hundreds of miles away.”

The paper said the cost proposal is based on a planning framework in FERC’s proposed transmission planning regulation.

The cost proposal would lower overall interconnection costs and provide cost certainty, SI2 said. Higher upfront costs would reduce the number of projects entering the queue, while with “more rational” costs for interconnection-related upgrades, interconnection customers would be “less likely to withdraw from the queue and less likely to cause restudies that would delay the interconnection process.”

SI2’s paper says that FERC’s Order 2023, which requires grid operators to make certain interconnection reforms, “is a step in the right direction” to resolve transmission interconnection wait times and costs, yet “the underlying problems remain unaddressed” and “there is more work for the commission to do.”

Abigail Ross Hopper, SEIA’s president and CEO, said “We need the solutions detailed in SI2’s report to serve growing demand for electricity with reliable, low-cost solar and storage.”

Caitlin Marquis, managing director at Advanced Energy United, said the report “offers thoughtful solutions to making lasting reforms.”

The paper is titled “Game changing interconnection reform: Reshaping transmission planning and realigning incentives.”

Reconductoring could enable 764 GW of transmission-connected solar by 2035

William Driscoll — Wed, 24 Apr 2024 16:00:11 +0000

Replacing existing transmission lines, known as conductors, with advanced conductors could enable 764 GW of transmission-connected solar by 2035 even if transmission in new corridors was limited, found a study by UC Berkeley and GridLab researchers.

Large-scale reconductoring can “unlock” renewables near the existing transmission network, says a report from a team of researchers from University of California, Berkeley and the consultancy GridLab.

While other technologies, such as those reviewed in a U.S. Department of Energy (DOE) “liftoff” report, could also enable a near-term increase in transmission capacity, the report says reconductoring with advanced conductors “offers the greatest potential to provide substantial capacity increases—up to double, within existing rights-of-way”—a finding consistent with DOE’s report. The authors say that reconductoring projects typically cost less than half the price of new lines for similar capacity increases.

A comparison of legacy conductors and advanced conductors is shown in the image below.

Advanced conductor and ACSR conductor.
Source: Energy Institute at the UC Berkeley Haas School of Business

Reconductoring could enable 764 GW of transmission-connected solar by 2035 in “indicative transmission corridors” in a scenario in which the build rate of new right-of-way transmission is constrained, according to a map linked from the report.

Advanced conductors are available from U.S. manufacturers 3M, CTC Global and TS Conductor, the report notes.

DOE aims for a national collaboration to help deploy advanced conductors, energy storage and other technologies to boost grid capacity.

The authors, noting that more than 2 TW of proposed clean generation and storage resources are “stuck in interconnection queues” across the country, say that clean energy project developers face extended delays as “first, multiple interconnection studies must be conducted, and then the necessary transmission improvements must be completed.” Increasing the transmission capacity of the existing system will “unlock” much-needed capacity, they say, not only to integrate clean energy projects already queued, but also to encourage continued renewables development near existing transmission infrastructure.

Savings

Across all scenarios considered in the report, the largest system savings would result from pursuing a strategy of simultaneously reconductoring with advanced conductors and addressing barriers to new greenfield transmission. That strategy would yield cumulative savings of over $400 billion by 2050 compared to a business-as-usual case.

The authors used the ReEDS model to conduct the study, and reached additional findings beyond those they presented in a working paper last fall.

The new study projected that the optimal added transmission capacity by 2050, allowing for reconductoring, would be about 110,000 GW-miles with restricted buildout or about 210,000 GW-miles with unrestricted buildout. The U.S. Department of Energy has estimated that 54,500 GW-miles of additional within-region transmission capacity is needed for a clean grid.

The new report includes reconductoring case studies from around the world, and the report’s landing page offers a paper with policy recommendations.

The report is the fourth in a series of “2035 reports,” following a 2020 report finding that clean power from 2035 is challenging but feasible, a 2021 report showing that electric vehicles could substitute for bulk transmission at lower cost, and a report on the role of offshore wind.

The new report is titled “Reconductoring with advanced conductors can accelerate the rapid transmission expansion required for a clean grid.”

DOE aims for national collaboration to deploy advanced grid technologies

William Driscoll — Mon, 22 Apr 2024 14:00:38 +0000

Advanced conductors and energy storage are among the technologies that have substantial potential to increase transmission capacity, says a Department of Energy “liftoff” report.

The U.S. Department of Energy (DOE) aims to spark a national collaboration to accelerate near-term deployment of advanced grid technologies.

Deploying these technologies on the existing grid could support 20-100 GW of incremental peak demand if installed individually, says a DOE report, or significantly more when installed in “strategic combinations.” If deployed “overnight,” they could help defer an estimated $5-35 billion in transmission and distribution infrastructure costs over the next five years.

The technologies and their “full deployment potential” for expanding capacity on the existing transmission and distribution grids are shown in the image below.

DOE found that advanced conductors have the greatest potential. Energy storage as a transmission and distribution asset, with a potential nearly as high, has recently “started to see greater interest,” the report says.

DOE plans to invest $10.5 billion in deployment of the technologies through its Grid Resilience & Innovation Partnerships program.

Achieving “liftoff” for the technologies within three to five years is possible, DOE said, by deploying for each technology “6-12 large operational, no regrets deployments across a diverse set of utility contexts.”

Deploying the technologies can help utilities and regulators respond to “grid pressures including rapid demand growth, extreme weather, and new energy generation connections,” DOE says.

With efficient investment and cost allocation strategies, the deployments “could happen without directly increasing costs to ratepayers,” says a DOE summary of the report.

New transmission capacity “is still critically needed,” says the report, to interconnect new generation and increase transfer capabilities between regions. Yet the advanced technologies “can help serve as a bridge” as new transmission is developed, and can be incorporated in new expansion as well.

To build industry confidence in the technologies, DOE’s first priority is to foster transparent sharing of outcomes from early deployments of the technologies, “including lessons learned from successes and failures.”

DOE also aims to “advance industry execution know-how, robust planning and investment case approaches, and economic model innovation.”

Seeing roles for grid operators, utilities, regulators, policymakers, and technology providers, DOE suggested for each group “priority actions to pursue today.”

DOE will host a webinar on the report on May 13 at 10:30 a.m. Eastern time. The 96-page report is titled “Pathways to Commercial Liftoff: Innovative Grid Deployment.”

Allow solar developers to choose “connect and manage,” says DOE roadmap

William Driscoll — Thu, 18 Apr 2024 13:58:22 +0000

To speed interconnection of utility-scale renewables and storage projects, a U.S. Department of Energy roadmap sets forth 35 solutions and proposes actions to implement the solutions. The roadmap was developed through a DOE stakeholder process known as i2X.

Transmission interconnection processes “need to evolve” to handle the larger number of interconnection requests seen in recent years, says a U.S. Department of Energy “roadmap” report.

The report presents 35 interconnection improvement solutions developed through a DOE stakeholder engagement process launched 22 months ago, known as the Interconnection Innovation e-Xchange (i2X) program.

DOE will have an ongoing role in implementing the solutions, it said in a news release, including facilitating solution adoption, providing funding and technical assistance, and supporting the research community.

One of the solutions presented is to “ensure” that generators have the option to elect energy-only interconnection and agree to be “re-dispatched”—that is, curtailed—as needed rather than paying for network upgrades. This approach, known as “connect and manage,” is key to speedy interconnection in Texas.

To achieve this solution, the roadmap proposes actions by the Federal Energy Regulatory Commission (FERC), transmission providers, and interconnection customers.

One of the roadmap’s “long-term” solutions is to “explore options” to allow interconnection customers to self-fund and provide their own interconnection studies, subject to transmission provider oversight, rules, and requirements. Tesla said in late 2022 that with access to grid models, the company could estimate a project’s interconnection costs with an informational study in less than two weeks, while two trade groups at that time renewed their call to allow third-party interconnection studies.

To achieve this self-funding solution, the roadmap recommended actions by FERC, transmission providers, researchers at DOE and elsewhere, and interconnection customers.

Five of the solutions relate to workforce development, and include highlighting in higher education settings “the important role of interconnection policy and practice in the clean energy transition.”

The report states target timeframes for key metrics, including a 12-month timeframe for a “completed project” to advance from the interconnection request to an interconnection agreement. Among projects that enter the third and final interconnection study phase, the targeted completion rate is 70%, compared to a recent actual percentage of 45%.

While transmission providers “play a central role” in managing and implementing interconnection process improvements, the report notes that “ideas and actions often come from other stakeholders.”

Many stakeholder groups participated in the i2X process to brainstorm and develop solutions, including interconnection customers, state agencies, federal regulators, load serving entities, equipment manufacturers, consumer advocates, equity and energy justice communities, advocacy groups, consultants, and researchers both within and outside DOE.

“Members from all these stakeholder groups should continue to participate in the implementation” of the solutions, the report said, adding that “reform is thus a group effort.”

As DOE developed the roadmap, FERC issued Order 2023, which also aims to reform interconnection. The roadmap “introduces additional ideas that support longer-term interconnection process evolution,” says the report, and its solutions “are intended to complement and support” Order 2023.

DOE will hold a webinar on the roadmap on May 8 at 1 p.m. Eastern time, focused on the roadmap’s solutions and targets.

The department’s 125-page roadmap report is titled “Transmission Interconnection Roadmap: Transforming Bulk Transmission Interconnection by 2035.”

Puerto Rico’s solar net metering law at risk from federal oversight board

William Driscoll — Tue, 16 Apr 2024 14:09:36 +0000

Puerto Rico led the nation in per-capita residential solar installations last year, but continued progress is threatened because a law extending solar net metering through 2031 has been challenged by a federal oversight board.

Puerto Rico added more rooftop solar per capita than any U.S. state last year, said PJ Wilson, president of the Solar and Energy Storage Association of Puerto Rico (SESA-PR), on a webinar.

The U.S. territory has increased its renewable generation to 12% from 4% three years ago, he said, and could reach 18-20% next year, in comparison to the 40% goal set by Puerto Rico law.

Given current trends, Ohm Analytics Founder Chris Collins said that Puerto Rico will account for 10% of the entire U.S. market for residential solar in 2028.

Central to Puerto Rico’s future success with residential solar is a law that extended the territory’s net metering policy for solar through 2031. Yet that law, known as Act 10-2024, has been challenged by the Financial Oversight and Management Board (FOMB) for Puerto Rico, a body created by federal law.

The FOMB stated in a letter that the fiscal plan that it certified for Puerto Rico’s legacy utility known as PREPA requires the Puerto Rico Energy Bureau to determine whether to make changes to the net metering system. Because the energy bureau has not yet done so, FOMB said that Act 10 is “directly at odds” with the PREPA fiscal plan.

The FOMB included with the letter its resolution directing the Puerto Rico legislature and governor to repeal Act 10 or amend it “in a manner consistent with the fiscal plans.”

Positive impact

Wilson said that residential solar net metering “not only doesn’t have a negative impact on the finances of Puerto Rico, but it has a positive impact.”

Backing up that statement, SESA-PR released a report that assessed the financial value of net metered solar energy in Puerto Rico at $0.33 per kWh, substantially more than the net metering credit of $0.24 per kWh. The value of solar is mostly due to avoided energy costs of $0.27 per kWh, with additional value from avoided transmission and distribution costs and avoided reliability-related economic losses.

The energy consulting firm Gabel Associates prepared the report.

“Every net metering law in the nation,” Wilson said, was “created by local legislatures and local governors signing off to create a law. And the same thing happened in Puerto Rico in 2009. In 2019, there was a five-year extension to that law. That was legal. And in January, there was another seven-year extension to the law, which is being opposed by this unique federal agency, three months after the law was signed into effect.”

Noting that the FOMB was created to resolve debt issues of PREPA and other entities in Puerto Rico, Wilson expressed hope that once the Puerto Rico government submits its reply to the FOMB’s letter, FOMB will change its position and focus on PREPA, “the only agency for which debt is not settled.”

PREPA’s debt has been “negotiated down to less than $3 billion from over $11 billion,” Wilson said. “It seems within sight for the PREPA debt to be settled,” and “the oversight board needs to focus exclusively” on that “until it gets done.”

Wilson said the FOMB was established by federal law as a temporary entity “to help solve all the debt and then dissolve,” and that the oversight board has a federal mandate to support the economic growth of Puerto Rico. Estimating the annual revenues from Puerto Rico’s residential solar-plus-storage market at $1.5 billion, Wilson expressed hope that the oversight board “dissolves as quickly as possible while supporting the economic growth of Puerto Rico along the way.”

Renewables and storage interconnection backlog grew about 30% last year

William Driscoll — Thu, 11 Apr 2024 12:17:15 +0000

The wait for transmission interconnection studies constitutes a “major bottleneck” for solar, storage and wind projects, which accounted for over 95% of all active capacity awaiting studies at the end of 2023, Lawrence Berkeley National Laboratory has reported.

A research report from Lawrence Berkeley National Laboratory found that 1,080 GW of solar projects and about 1,030 GW of storage projects await interconnection studies, so they may connect to the transmission grid.

Solar and battery storage accounted for over 80% of new capacity entering the queues in 2023, driving a 30% increase in the waiting lists, known as queues, for interconnection studies.

Storage capacity in the queues grew more than 50% last year. Over half of the battery storage capacity in the queues is paired with some form of generation, typically solar. Wind capacity in the queues rose to 366 GW, while only 79 GW of fossil gas and 2 GW of coal capacity await interconnection studies.

The values were nearly the same as preliminary values published last month in a staff report from the Federal Energy Regulatory Commission (FERC).

The growing backlog of projects awaiting grid interconnection studies “has become a major bottleneck” for project development, the study said, as proposed projects are “mired in lengthy and uncertain” interconnection study processes. Based on past experience, the study said that “most interconnection requests are ultimately cancelled and withdrawn,” while projects that are built are taking longer on average to reach commercial operation.

Although FERC adopted major interconnection reforms in 2023, the study says most reforms “have not yet taken effect in most regions, with project developers continuing to cite grid interconnection as a leading cause of project delays and cancellations.”

The authors pointed to other project development stages beyond submitting an interconnection request, and then waiting for the grid operator to complete interconnection studies, saying that “projects must also have agreements with landowners and communities, power purchasers, equipment suppliers, and financiers, and may face transmission upgrade requirements.”

Even so, the authors said that data from the queues provides a “general indicator for mid-term trends” in power sector activity and energy transition progress.

Berkeley Lab compiled and analyzed data from the seven organized electricity markets in the U.S. known as RTOs and ISOs, and an additional 44 balancing areas outside of RTOs and ISOs, which together represent over 95% of currently installed U.S. electricity generation.

Total generation plus storage capacity in the queues at year-end 2023 equaled 2.6 terawatts, as shown in the image below, which the authors noted is about eight times larger than the interconnection queue in 2014, and more than twice the current U.S. generating capacity of 1.28 TW.

Berkeley Lab has made available a study abstract, an overview and slide deck, an interactive visualization of the queue data, interactive maps and a data file.

The study’s authors will host a webinar to describe the research and answer questions on April 23 at 1 p.m. Eastern time.

Citizens groups criticize TVA’s decision to build a 1.5 GW gas plant

William Driscoll — Fri, 05 Apr 2024 15:00:53 +0000

TVA decided not to choose solar and storage despite 15 GW of such projects in its interconnection queue. TVA’s board of directors could overturn the gas plant decision, said an environmental law group spokesperson.

TVA has announced it will build a fossil gas plant with at least 1.5 GW of capacity at the site of the Kingston coal plant in eastern Tennessee. The federally owned utility rejected the option of building solar and battery storage to replace the coal plant.

TVA said that although 15 GW of solar or solar-plus-storage projects are waiting in its transmission interconnection queue, “to maintain stability on TVA’s transmission system, TVA would need to accommodate the decreased influx of generated power” from the Kingston coal plant “as well as ensure that the multiple (15+) solar generating locations can be connected without impacting the existing grid for the areas surrounding the new solar sites.”

The TVA board, six of whose nine members were appointed by President Biden, “still has the power to reverse this reckless decision,” said Eric Hilt, a senior communications manager with the Southern Environmental Law Center (SELC). “We hope federal leaders will urge board members to scrap this proposed gas plant and invest in cleaner and cheaper energy options. As for SELC and our partners, we are evaluating our legal options.”

Gaby Sarri-Tobar, a campaigner with the Center for Biological Diversity’s (CBD’s) energy justice program, said “TVA CEO Jeff Lyash’s approval of yet another costly, climate-killing” gas plant that would “jack up utility costs” and an associated 122-mile gas pipeline is “beyond reckless.” She added that TVA’s board “should fire” the CEO.

Citizens groups

Citizens groups have long advocated for TVA to transition to clean energy.

SELC early last year called for TVA’s board, with its new Biden appointees, to pause TVA’s plans to add gas generation.

CBD then co-sponsored a study by Synapse Energy Economics that found that 50 GW of solar and storage for TVA by 2035, plus electric vehicles, could save customers about $200 billion through 2050.

QCells USA Corporation joined citizens groups in signing a letter to TVA’s board last June calling for greater public engagement in the utility’s 2024 resource planning process.

The Southern Alliance for Clean Energy (SACE) last August called on the Federal Energy Regulatory Commission to evaluate replacing TVA’s Kingston coal plant not with gas but with renewables, energy efficiency and storage, as part of the commission’s review of a proposed gas pipeline for the proposed gas unit.

CBD followed up by co-sponsoring a clean energy plan for TVA, again conducted by Synapse, which found that TVA could reach 100% clean energy by 2035 by adding 35 GW of solar and 13 GW of wind capacity. The plan was presented at a citizens hearing, and CBD and SACE called for TVA’s board to ensure that TVA reached the 100% target.

Just days before TVA’s Kingston gas plant announcement, SACE flagged that the U.S. Environmental Protection Agency (EPA) had notified TVA that the utility’s final environmental impact statement for the Kingston gas plant had “serious deficiencies,” including a lack of transparency around the planning and decision-making processes.

A joint news release from SELC and Appalachian Voices about TVA’s gas plant decision said that EPA had raised additional “substantial concerns,” including underestimating climate and air pollution impacts, failing to reasonably consider clean energy alternatives, and preparing an unlawfully “inadequate” analysis. EPA also warned the gas plant could lead to higher power bills across the region, the groups said.

Eric Hilt with SELC said, however, that “it is our understanding that the window for EPA to refer the Kingston decision to the Council on Environmental Quality has closed.”

In their release, SELC and Appalachian Voices said that “recently, the public learned” that TVA’s board of directors “made a backroom deal to return final decision-making authority” on the proposed Kingston gas plant “back to the TVA CEO.” The groups added “the board’s abdication of decision-making power was buried in a general budget resolution that was not made public until months later and came shortly after the board publicly voted to take back authority over the Kingston decision.”

Gabi Lichtenstein, Tennessee energy democracy field coordinator at Appalachian Voices quoted in the release, posed the question: “Why is CEO Jeff Lyash, the highest paid federal employee in the country, making a decision that could cost ratepayers over a billion dollars more than the alternative?”

TVA serves 10 million customers across Tennessee, substantial portions of Kentucky, Mississippi, and Alabama, and parts of three other states.

Give distributed resources a greater role in grid reliability, say four law professors

William Driscoll — Wed, 03 Apr 2024 13:39:49 +0000

Distributed solar and storage, along with demand response, “perform during extreme weather events” and deserve a greater role in reliability planning, the law professors say, while a new public office of grid reliability could guide transmission planning.

With “blackouts on the rise,” the primary cause of “our unreliable grid” is not the changing energy mix but “a failure of grid governance,” say four law professors in a white paper published by the Kleinman Center for Energy Policy at the University of Pennsylvania.

Pointing to the “correlated failures of gas and electricity supply,” the authors say policy makers should focus on distributed energy resources (DERs) such as rooftop solar, battery storage and demand response to ensure that “resources that perform during extreme weather events” are available in the future.

Solutions proposed in the paper include eliminating the ability of states to “veto” the participation of demand response providers in wholesale markets, and speeding up and enhancing regional rules for the participation of DERs in those markets.

In another set of recommendations, the authors call for reform of “overly privatized governance systems.” They say both the North American Electric Reliability Corporation (NERC), which is responsible for writing and enforcing grid reliability standards, and regional grid operators known as RTOs, which are responsible for designing and operating the markets that ensure resource adequacy in many regions, are private membership organizations.

Both NERC and RTOs are “dominated by entrenched, large industry players” who, as voting members, select each organization’s governing board and vote on the standards to be approved by the board. “This structure produces decision-making processes and rules that favor incumbents,” the authors say, which “lack adequate input from numerous public stakeholders, who have much to gain or lose from reliability-related decisions.”

The authors recommend strengthening public control of grid reliability by enhancing the Federal Energy Regulatory Commission’s (FERC’s) oversight of NERC and RTOs.

They also recommend creating a public office of grid reliability in place of NERC that “might also function as the central locus of planning for new transmission lines—a process that will be critical to ensure reliability in coming decades.” In a “more modest” proposal, they call for requiring NERC and RTOs to include more public representatives across their voting sectors and boards and “better balanced authority among stakeholders.”

“Most ambitiously,” the authors say in a final set of recommendations, “Congress should vest more authority in FERC to write and enforce reliability standards.”

“Those interested in shoring up grid reliability,” the paper concludes, “should focus on these institutions and their pathologies as the first step to real and durable grid reliability in the coming decades.”

The paper’s four authors are Alexandra Klass, Joshua Macy, Shelley Welton and Hannah Wiseman. They teach law, respectively, at the University of Michigan, the University of Chicago, the University of Pennsylvania and Pennsylvania State University. The white paper draws from ideas first presented in two law review articles by the authors, and is titled “The Key to Electric Grid Reliability: Modernizing Governance.”

Shelley Welton has previously called for considering public control of grid operators to speed interconnection of utility-scale solar, wind and storage projects.

In related work, Harvard law lecturer Ari Peskoe has called for overhauling regional grid operators to speed interconnection of renewables.

DOE funds heated sand energy storage project pilot

William Driscoll — Tue, 02 Apr 2024 15:21:03 +0000

A modeled commercial-scale project storing energy in heated sand could produce 135 MW of power for five days. The U.S. Department of Energy is funding a pilot project intended to demonstrate commercial viability.

Researchers at the National Renewable Energy Laboratory (NREL) working on a multi-day energy storage system using heated sand have developed a prototype, shown in the featured image above, which has set the stage for a pilot demonstration project.

The sand used in the thermal energy storage (TES) system could be heated to the range of 1,100 degrees Celsius using low-cost renewable power. The nearby diagram shows that when electricity is needed, the system will feed hot sand by gravity into a heat exchanger, which heats a working fluid, which drives a combined-cycle generator.

Image: NREL

The NREL team’s computer modeling has shown that a commercial-scale system would retain more than 95% of its heat for at least five days, the national laboratory said in a news release.

The U.S. Department of Energy will provide $4 million to fund a pilot demonstration project sized with a 100 kW discharge capacity and a 10-hour duration, with groundbreaking set for next year at NREL’s Flatiron campus outside Boulder, Colorado. The pilot project is intended to show the technology’s commercial potential.

At commercial scale, when the sand is fully heated and stored in five silos, the technology could produce 135 MW of power for five days, according to an NREL report.

A targeted levelized cost of storage of 5¢/kWh could be achieved under a variety of scenarios, the report said.

“Building upon existing thermal power plants” would help facilitate a commercial path for the technology, the report said, while additional factors to improve economic returns “may include utility capacity payment, community benefits around retiring thermal power plants, and continuing decline of renewable electricity price.” In addition, “designing the system for dynamic operation (e.g., faster startup, option for gas addition) is likely to increase revenue by tapping into daily storage operation.”

NREL’s report said a technology-to-market transition plan has been developed for the TES system but was not included in the publicly available report “due to the business sensitivity of NREL and partners.”

Babcock & Wilcox, one of five project team members supporting NREL’s research, announced in 2021 that it had signed an agreement with NREL, which gave it “field-limited exclusive rights” to negotiate a licensing agreement that would allow it to market the technology.

Several other energy storage technologies have storage durations longer than the typical four-hour limit for battery storage. For example, Hydrostor is developing a 500 MW/4,000 MWh compressed air energy storage project in California. A pumped storage project under development in Montana would have a capacity of 400 MW and an estimated annual energy generation of 1,300 GWh. And flow batteries have a global market estimated by a research firm at $289 million in 2023.

For seasonal energy storage, hydrogen storage in salt caverns is an option. A project in Utah is expected to have a storage capacity of 150 GWh matched with an 840 MW hydrogen-capable gas turbine combined cycle power plant.

Rural electric co-ops lend money to customers to improve energy efficiency

William Driscoll — Thu, 28 Mar 2024 16:58:40 +0000

Some rural electric cooperative utilities allow customers to pay off energy efficiency improvement loans through their utility bills. That contributes to energy efficiency’s role in the renewables transition.

Reducing building energy usage is key to achieving a least-cost 100% renewable grid, a study by the National Renewable Energy Laboratory has found.

Residential energy efficiency gains also save money and improve comfort. Those two factors are motivating customers of some rural electric co-ops to borrow from their co-op to pay for energy efficiency improvements. The loan is then repaid through the customer’s utility bill.

In central and western Kansas, 2,475 of co-op Midwest Energy’s customers, or 8% of its customer base, have taken out such loans to date, according to a post by the Rural Power Coalition.

The coalition, noting that rural Americans spend as much as 40% more on energy than urban residents, recommends the loan approach to help co-op customers save money and help co-op utilities build resilience to extreme weather events.

A customer can initiate an energy efficiency loan by selecting from a set of cost-effective upgrades for their home, farm or business, such as insulation, air sealing, efficient HVAC equipment, on-site solar or an electric vehicle charger. The utility funds the upgrades with a loan, which the customer pays back through a monthly charge that is less than the estimated savings from the upgrade, the coalition said.

If the customer moves before the loan is paid off, the monthly charge transfers to future customers at that site.

The coalition calls the approach “inclusive utility investment,” because a customer’s financial liquidity or creditworthiness is not assessed in the loan origination stage; instead, the utility assesses the energy savings potential of the building.

Electric co-ops and other rural utilities may access 0% financing for such investments, offered by the Rural Energy Savings Program operated by the U.S. Department of Agriculture. The interest rate charged to customers is capped at 5% and is often lower, the coalition said.

The coalition presented two additional case studies in its post. The Roanoke Electric Cooperative in North Carolina has enrolled more than 10% of its residential customers in energy efficiency financing; about half of the residential buildings receiving upgrades first required repairs.

In southern Arkansas, the Ouachita Electric Cooperative has seen an average demand reduction of 18% among residential customers who have borrowed for weatherization and HVAC upgrades, and up to 70% to 80% for those who also add solar. Across all residential weatherization and solar projects, the co-op utility has seen an average reduction in peak demand of 1.5 to 2 kW for each home upgraded. Savings from boosting customer efficiency and adding solar allowed the utility to reduce rates for residential customers by 4.5%, the coalition said.

The Rural Power Coalition is a collaboration of 17 organizations working to advance clean energy investments by rural electric cooperatives in 14 states.

1100 GW solar and 1000 GW storage now await transmission interconnection

William Driscoll — Tue, 26 Mar 2024 16:50:04 +0000

Solar, wind and battery storage accounted for nearly 95% of the capacity in transmission interconnection queues as of year-end 2023, based on preliminary data from Berkeley Lab, presented in a staff report from the Federal Energy Regulatory Commission.

By year-end 2023, 1086 GW of solar projects awaited transmission interconnection, along with 503 GW of standalone storage, according to preliminary data from Lawrence Berkeley National Laboratory (LBNL). The amount of storage in hybrid projects, such as solar-plus-storage projects, awaiting interconnection at year-end was estimated at 525 GW by LBNL, based on imputed values for missing data when storage capacity for hybrid projects was not reported.

The data were reported in a staff report from the Federal Energy Regulatory Commission (FERC).

LBNL’s preliminary values for all but one of the resource types awaiting interconnection are presented in the table below from the FERC staff report. The exception is hybrid storage, which FERC staff shows as 299 GW in the table, not LBNL’s preliminary 525 GW, because FERC staff excluded hybrid storage projects for which capacity was not reported.

Solar, wind, and battery storage represented nearly 95% of the total capacity in interconnection queues as of year-end 2023, the staff report said.

Pending transmission interconnection requests at year-end 2023 rose to 11,841, according to LBNL’s preliminary data, representing a 16% increase since year-end 2022 and more than a four-fold increase since year-end 2019, as shown in the table below.

The FERC staff report includes summaries of transmission plans submitted by grid operators to FERC last year, including plans for transmission that could help bring solar and storage projects online.

The transmission plan from California grid operator CAISO included 21 transmission projects at a cost of $5.5 billion to help meet the renewable generation requirements set by state regulators. Some of those projects would enable importing wind power from outside CAISO.

Mid-continent grid operator MISO planned 142 transmission projects to interconnect new generators.

The PJM grid operator stretching from Chicago to New Jersey “identified” 93 transmission projects at a cost of $180 million to support generation seeking interconnection, and “evaluated 227 supplemental projects put forward by transmission owners,” the report said, that would cost $2.4 billion.

The ERCOT grid region in Texas added the most solar of any region last year, as shown in the following chart from the report, showing capacity additions by grid region.

The geographic areas of seven of the nine grid regions referenced in the chart are shown in the map below. The other two regions are the “SERC region,” which is the SERC Reliability Corporation (SERC) area in the Southeast, and the “WECC* region,” which is the Western Electricity Coordinating Council area in the Western states without California’s CAISO region.

The CAISO and ERCOT grid regions account for most of the growth in transmission-connected batteries in the past three years, as shown in the following chart from the report.

Oregon makes it easier to connect distributed solar and storage

William Driscoll — Mon, 18 Mar 2024 14:13:15 +0000

Oregon has enabled more solar on each distribution circuit by setting smart inverter requirements, and has made it easier for export-limiting distributed storage projects to receive interconnection approval.

Solar and storage connected to Oregon’s distribution grid will be required to use smart inverters that meet the global standard for inverters known as IEEE 1547-2018, starting this June.

The requirement will enable Oregon’s grid to “accommodate more renewable energy with fewer costly upgrades,” said Radina Valova, regulatory vice president for the Interstate Renewable Energy Council. IREC joined utilities and regulators in workshops that led to the requirement.

Oregon also recognized that distributed storage projects may be designed with export-limiting capability, and has established approved methods for projects to control power export, and new interconnection review processes for such projects.

In areas where export-limiting capability is not recognized, distributed storage projects may face barriers to interconnection because review processes may be based on inaccurate assumptions about how the systems will operate, IREC said in a statement.

New Mexico has also recognized export-limiting capabilities of distributed storage and updated its interconnection process for such projects, with regulators saying they drew on some provisions recommended in IREC’s “BATRIES” report.

States that have already adopted the IEEE smart inverter standard, according to IREC, include Hawaii, California, New Mexico, Maryland, New York and Massachusetts, while in some other states, individual utilities have adopted the IEEE standard.

Without the use of smart inverters, each new solar installation on a distribution circuit would slightly increase the circuit’s voltage, which ultimately would require a circuit upgrade or a limit on new solar. But smart inverters can sense conditions on the circuit and regulate a resource’s voltage to support grid stability.

California and Hawaii have required smart inverters for several years, with good results.

Smart inverters that meet the IEEE standard can be set to a variety of voltage regulation settings. Oregon has required utilities to determine by June the voltage regulation settings for smart inverters to be used in their respective service areas.

IREC Regulatory Program Engineer Midhat Mafazy expects that “some form of voltage regulation will be activated by default,” based on IREC’s discussions with utilities as it participated in the workshops that led to Oregon’s requirements.

In Hawaii, thanks to that state’s smart inverter settings, Sunrun Policy Director for Grid Solutions Steven Rymsha said in 2021 that most customers in the state could “instantly interconnect” new solar despite high levels of solar already on distribution circuits.

Hawaii achieved this result by requiring the smart inverter setting known as volt-var for all new distributed solar, with the option for customers also to activate the volt-watt setting if the utility would otherwise require a study and circuit upgrades. Each setting works to keep voltage stable on distribution circuits as more solar is added.

Rymsha said that other states could follow Hawaii’s lead when evaluating smart inverter requirements, noting that delays in setting requirements could lead to “wasted infrastructure.”

Group challenges anti-renewables messaging of 50-state policy network

William Driscoll — Tue, 12 Mar 2024 14:35:16 +0000

The pro-renewables Energy and Policy Institute has challenged the state-level energy policy work of the State Policy Network, which reports annual revenues of $24 million and combined annual revenues across its 150 think tank members of $188 million.

The State Policy Network (SPN) maintains that the adoption of “more intermittent energy sources such as wind and solar” in several states “is leading to an unreliable grid and soaring costs.”

The network, which has announced that energy is one of its four priority issues “in the 2024 state legislative sessions,” says it is working “to prevent states from adopting unreliable, intermittent sources that make the grid less stable and increase costs,” adding that it favors nuclear and geothermal power.

The pro-renewables Energy and Policy Institute (EPI) has called attention to SPN’s 2024 state-level energy policy work, and has rebutted SPN’s claims about renewables in a brief report on the network.

“In reality,” EPI says, “methane gas failures have been primarily to blame for major blackouts during extreme weather events in recent years,” citing a Union of Concerned Scientists report.

As for increased electricity prices, EPI says that higher fuel costs for power plants that burn coal, gas and petroleum have driven those increases, citing a U.S. Energy Information Administration analysis.

EPI describes SPN as “the national organization at the center of a 50-state network of think tank affiliates that is at the forefront of disinformation campaigns against wind and solar power, and is funded by right-wing donors and fossil fuel interests.”

SPN reports annual revenues of $24 million and combined annual revenues across its 150 think tank members totaling $188 million. The network says that its 150 think tank members include 64 state-focused think tanks in 50 states.

The American Legislative Exchange Council is an SPN partner group that is “a frequent source of ‘model’ legislation that targets state clean energy and climate change policies,” says EPI.

SPN’s annual meetings, EPI adds, are co-sponsored by a fossil fuel industry group as well as “multiple groups backed by Charles Koch,” a billionaire who is CEO and chairman of Koch Industries, a privately held multinational conglomerate with subsidiaries operating in the petroleum and energy sectors.

SPN says its mission is to “catalyze thriving, durable freedom movements in every state, anchored with high-performing independent think tanks.”

EPI has also prepared profiles of three think tanks it said are affiliated with SPN and “involved in coast-to-coast efforts to block renewable energy projects”:

Texas Public Policy Foundation
Caesar Rodney Institute
Cascade Policy Institute.

EPI provides brief descriptions of additional groups it says are affiliated or associated with SPN that have “also been ramping up efforts to block renewable energy”:

Buckeye Institute
Center for the American Experiment
John Locke Foundation
Mackinac Center for Public Policy
Energy and Environment Legal Institute
Cato Institute
Heartland Institute
Manhattan Institute

EPI describes itself as “a watchdog organization working to expose attacks on renewable energy and counter misinformation by fossil fuel and utility interests.”

Amazon Web Services helps Duke Energy complete power flow studies in hours, not months

William Driscoll — Mon, 04 Mar 2024 14:28:40 +0000

Adding residential solar or commercial-scale electric vehicle chargers on a utility’s distribution feeder may require the utility to conduct power flow calculations. Duke Energy can now complete those studies in hours, an Amazon executive said at a policy forum held by ACORE.

A residential customer of Duke Energy who wants to put solar on their roof, or a commercial customer that wants to electrify its fleet of vehicles, may get a faster response from the utility now that it can complete power flow calculations much more quickly.

Amazon Web Services has worked with Duke Energy to develop a custom solution that speeds the power flow simulations, said Nate Hill, head of energy policy for Amazon Web Services. “That’s not even an artificial intelligence product,” it’s “just a solution” that AWS “custom-built” with Duke, he said, speaking at a policy forum held by the renewable energy trade group ACORE.

The solution is designed to help Duke Energy anticipate future energy demand and identify where and how to “update” the distribution grid, said an AWS spokesperson.

Hill predicted “amazing” AI applications in the utility industry and with power grid operators, especially by “combining our forces and brainpower” with the capability of exascale computing at the Department of Energy, and “all the resources and scientists they have in their national lab network.”

AWS was in discussions with grid operator SPP in 2022 about using AI to speed interconnection studies for utility-scale solar, while a NextEra executive was bringing the idea to other grid operators at that time.

Hill added that Amazon is “bullish” on grid-enhancing technologies and similar approaches, saying they should be studied “very seriously,” but added “it’s not a panacea.”

Speaking of the work of Amazon Web Services, Hill said firms are “early in the process” of switching from on-premise data services to cloud services, “and now you layer on top of that this big transition to machine learning, AI.” He said transmission infrastructure “is going to be one of the key ingredients to allow the U.S. to be a dominant force in this big revolution that’s happening right now.” To maintain U.S. leadership, he said “there’s a role for AWS and the datacenter community” to start planning early and providing “accurate forecasts to our partners,” so they can plan ahead and “plan the right grid.”

Transmission build cycle

Jeff Dennis, deputy director for transmission development at the Department of Energy’s Grid Deployment Office, said at the policy forum that “if we improve transmission planning, like we want to, and if we improve permitting, like we want to, we’re going to build a lot of transmission in a short amount of time. That means we’re going to need a lot of workers, we’re going to need a lot of equipment, we’re going to need a lot of supply. DOE is focused on that for sure. And I know many of you are also, but it will be a tremendous build cycle.”

Dennis also spoke about building “no regrets” transmission lines. He referenced DOE’s 2023 National Transmission Needs Study, which projected a need for 54.5 TW-miles of within-region transmission capacity and 125 GW of interregional transfer capacity by 2035, under future scenarios with moderate load but high clean energy assumptions.

Part of the transmission need, Dennis said, is “simply to relieve congestion that is costing consumers hundreds of millions of dollars a year, especially in extreme weather events.” He said “even if we disagree on what the future looks like,” among 200 different scenarios, “we should build the high value connection options that pop out at you,” because those are “no regrets” options.

Cyberattacks and microgrids

Bill Murray, senior vice president of corporate affairs for Dominion Energy, spoke on the same panel and drew a reaction from the audience when he said the utility fields 3 billion cyberattack attempts per month.

“We have robust cyber defenses,” he said, thanking the utility’s federal, state and private sector partners. “But part of it is also looking at the absolute critical parts of your system.” Saying that “all customers are critical; don’t get me wrong” he added that “microgridding is an opportunity that we’re starting to look at more and more.”

This article was amended on March 11, 2024 to state that the power flow calculations performed using the new solution relate to Duke Energy’s distribution feeders, not to its transmission system.

Grid operators in California and Texas earn “B” grades, others score poorly

William Driscoll — Thu, 29 Feb 2024 14:30:54 +0000

With two million megawatts of generation and storage projects awaiting interconnection studies across the U.S., a report gives grid operators grades for their interconnection processes ranging from B to D-.

Grid operators in California and Texas received grades of B for their processes to enable interconnection of new generators, primarily renewables and storage, while others received low Cs to a low D, in a scorecard report prepared by the consultancies Grid Strategies and The Brattle Group.

Project developers are awaiting interconnection studies to identify the transmission facility upgrades needed for their respective projects, so they may sign interconnection agreements for construction of the upgrades.

“As is widely recognized, and this scorecard confirms, the progress towards completing those interconnections is slow and puts system reliability at risk,” says the report, published by the trade group Advanced Energy United, which backs carbon-free electricity.

Grades were based on a survey of interconnection customers and analysis of the recent results of each grid operator’s interconnection process.

The ERCOT grid operator in Texas has a “relatively fast and consistent interconnection process, with reasonable costs,” says the report, while noting “challenges” to transmission network upgrade construction that can “slow the process towards the end and result in curtailment of projects that do get built.”

ERCOT uses a “connect and manage” approach to generator interconnection, which a former Cypress Creek Renewables executive has reasoned could also be used in the rest of the U.S.

Executives from Clearway Energy Group and Enel North America have called for combining the connect-and-manage approach with comprehensive regional transmission planning to efficiently interconnect large-scale renewables and storage.

California’s grid operator CAISO “also had a relatively fast and consistent process” for projects submitted before 2020, but since then, CAISO’s process has been “unable to efficiently process applications” due to the large increase in the number of new generator interconnection applications, the report says.

ERCOT and CAISO completed interconnection agreements for more capacity of new generators by the end of 2022 for applications submitted in 2018-2022 than the other five grid regions, as shown in the nearby graph. The graph provides an apples-to-apples comparison because it shows the interconnection agreement capacity executed in each region as a percentage of system peak load.

Most of the grid operators “are undergoing significant efforts” to reform their interconnection practices and policies, the report says, “in response to stakeholder concerns and Federal Energy Regulatory Commission Order 2023.”

While the report used generator interconnection process results as the primary scoring factor, the grades were also based on five other factors:

Pre-queue information
Interconnection process design
Assumptions, criteria and replicability
Availability of interconnection alternatives
Use of regional transmission planning.

The report, titled Generator Interconnection Scorecard, is the first-ever attempt to evaluate the grid operators, and may be repeated in future years to assess their progress, the authors said.

Grid operator PJM could add 5.5 GW of renewables with grid-enhancing technologies

William Driscoll — Thu, 22 Feb 2024 16:30:05 +0000

Deploying GETs technologies in the PJM grid region would have a 70-to-1 benefit-cost ratio, finds an analysis by Quanta Technology. The nonprofit RMI published the analysis, and aims for it to be replicated to evaluate GETs in interconnection studies.

The PJM grid operator could enable interconnection of 4.8 GW of solar and 0.7 GW of wind capacity by 2027 through 95 deployments of grid-enhancing technologies (GETs), found an analysis produced by the nonprofit RMI. GETs would also enable 1.1 GW of stand-alone storage plus additional storage co-located with new solar.

The GETs would cost $100 million and yield production cost savings of $7 billion over six years, mostly due to the lower cost of operating renewable energy generators enabled by GETs, the report says. That translates to a 70-to-1 benefit-cost ratio, as shown in the graph below.

GETs could save project developers collectively “hundreds of millions of dollars” in interconnection costs compared to default network upgrades, the study says, as shown in the image below, while the project-level savings “could be the difference” that allows a developer to build a project “instead of dropping out of the queue.” GETs can also be installed more quickly than other network upgrades.

GETs were compared to the network upgrade options of reconductoring (using existing transmission towers to support new high-capacity advanced conductors) and rebuilding transmission lines (replacing both the towers and the conductors). These other options would yield an approximate 10-to-1 benefit-cost ratio, as indicated in the image above comparing their costs to GETs costs.

The $7 billion in production cost savings from installing GETs would not accrue to project developers, although under the current participant-funded upgrade paradigm, developers would pay for the $100 million in GETs installation costs.

GETs can enable rerouting of power flows to avoid congested lines, and provide real-time weather data to enable more power to flow through a line when conditions allow, for example due to the cooling effect of wind. The three GETs considered are dynamic line ratings, advanced power flow controls, and topology optimization, all of which are explained in the report. GETs have been used in Europe for decades, the report says.

To take advantage of GETs, the study says grid operators and utilities will need to adopt new modeling approaches, such as including GETs in power flow studies, and operational changes such as integrating GETs into existing energy management system software.

A previous study by The Brattle Group found that GETs could enable 40 MW more solar and 2.6 GW more wind power in Kansas and Oklahoma within four years.

Federal Energy Regulatory Commission (FERC) Order 2023 requires transmission providers such as PJM to evaluate, when conducting interconnection studies, several advanced transmission technologies listed in the order, according to the law firm Hunton Andrews Kurth. The listed technologies include advanced power flow control devices and advanced conductors but not dynamic line ratings or topology optimization, the firm says, noting that the order requires transmission providers to explain their evaluation results, but gives them sole discretion whether to use any given technology.

The RMI report says PJM and other grid operators “should build on FERC’s order and include GETs as standard network upgrade options for generator (and new load) interconnection.” RMI adds that “enhanced transmission planning and build-out is the long-term solution to addressing our capacity-constrained electric grid.”

Methods

In what the study says is a first-of-its-kind analysis, Quanta Technology started with a dataset of projects in five states that are waiting in PJM’s interconnection queue. Quanta conducted power flow modeling—a key step in any interconnection study—to consider each GET individually and then in combination. Quanta projected cost savings through production cost modeling.

RMI said its goal was to develop a “transparent and replicable approach” for analyzing GETs in interconnection studies.

Amazon provided funding for the analysis and report, in line with its commitment to power its operations with 100% renewables by 2025, said Abhishek Sharma, head of energy strategy for Amazon Web Services. An Amazon executive previously described how artificial intelligence could speed interconnection studies for large-scale renewables projects.

Other contributors to the study included GETs vendors such as LineVision and Smart Wires, which provided data and technology-specific information for the modeling, and NewGrid, which conducted topology optimization modeling.

RMI offered detailed recommendations for applying the study’s findings within PJM and nationwide:

PJM should institute robust evaluation of GETs for interconnection and transmission planning
Transmission owners should deploy their first GETs projects and create systems for routine deployment
Renewables project developers should propose GETs as part of their interconnection requests
State regulators should provide utility oversight and guidance to maximize the potential for cost-saving GETs adoption
FERC should pursue a comprehensive national regulatory framework that supports GETs adoption.

PJM is the world’s largest wholesale electricity market, the report says, serving 65 million people; its service area is shown on map above. Wind and solar combined provided less than 5% of generation in the PJM region last year. PJM has instituted a pause on new interconnection applications until 2026.

Groups call on TVA’s board to pursue 100% clean energy

William Driscoll — Tue, 20 Feb 2024 14:09:16 +0000

The federally owned utility TVA has not held a public hearing on its resource planning process, so advocacy groups held their own hearing, presenting a plan for TVA to reach 100% clean energy by 2035. Two groups called for TVA’s board to ensure the utility reaches that target.

The utility TVA would add 35 GW of solar and 13 GW of wind capacity to reach 100% clean energy by 2035 under a resource plan presented by clean energy groups at a nongovernmental public hearing in Nashville. The federally owned utility now has 1 GW of wind capacity and less than 1 GW of solar capacity.

The hearing was modeled after a regulatory proceeding, with testimony from expert witnesses and comments from citizens, and was moderated by former Chairman of the Arkansas Public Service Commission Ted Thomas.

The clean energy groups convened the hearing after their June 2023 letter to TVA’s board of directors calling for greater public engagement in the utility’s 2024 resource planning process yielded an “insufficient response,” and a follow-up “petition to intervene” yielded no response, said a post-hearing brief.

Synapse Energy Economics developed the 100% clean energy plan for TVA. The nonprofit consultancy GridLab and the Center for Biological Diversity sponsored Synapse’s analysis.

TVA’s board of directors was invited to participate in the Nashville hearing, but when the chairman called the proceeding to order, “no one representing TVA responded,” said the post-hearing brief.

The TVA board is scheduled to vote this summer on whether to approve the utility’s final resource plan, which TVA staff are drafting in consultation with a utility working group, said Gabriela Sarri-Tobar, energy justice campaigner with the Center for Biological Diversity.

The board has the power to reject a plan that is not aligned with the Biden administration’s federal climate and clean energy goals for 100% clean energy by 2035, she said.

TVA’s board, “and especially the six board members nominated by the president,” should “make it a priority to align TVA’s energy planning with federal climate targets,” Sarri-Tobar said, citing the “tremendous” financial and public health benefits of transitioning to 100% clean power as shown by the Synapse study. TVA’s board has nine members.

Asked about the engagement of the Biden-appointed TVA board members, Bryan Jacob, solar program director for the Southern Alliance for Clean Energy (SACE), said “TVA is out of sync with reality and out of step with the Biden Administration’s direction and commitments. It doesn’t matter which president originally nominated the Board members. If they ultimately endorse a resource plan that includes new gas resources now, it will ensure that the nation’s largest public power utility fails to achieve 100% clean energy by 2035 and will increase the risks of high bills and grid failures for the people of the Valley for decades to come.”

Maggie Shober, research director at SACE, made the case that TVA is using a National Environmental Policy Act (NEPA) process as a “stand-in” for “genuine” public and stakeholder engagement to inform its resource planning process. “NEPA was not intended to be used that way,” she wrote in a post, and “it falls far short of what is needed for the public to be able to interact with and inform key decisions that will impact our lives for decades.”

Peter Hubbard, a clean energy advocate with the Georgia Center for Energy Solutions, testified at the hearing that TVA “must account” in its resource planning “for the remarkably poor track record of failure” for carbon capture and storage projects “such as Southern Company’s failed Kemper project in Mississippi and NRG’s failed Petra Nova project in Texas, when accounting for the possibility that this troubled technology could work for TVA.”

Groups signing the petition to intervene were Appalachian Voices, Center for Biological Diversity, Energy Alabama, Southern Alliance for Clean Energy, Sunrise Movement Nashville and Vote Solar.

Those groups also signed the June 2023 letter along with three other entities: QCells USA Corporation, Sierra Club and the Southern Renewable Energy Association.

TVA serves 10 million customers across Tennessee, substantial portions of Kentucky, Mississippi, and Alabama, and parts of three other states.

Puerto Rico distributed solar climbs to 680 MW, residential storage to 1.6 GWh

William Driscoll — Wed, 14 Feb 2024 16:15:07 +0000

While distributed solar and storage are advancing quickly in Puerto Rico, utility-scale solar and storage procurements ordered by Puerto Rico regulators in 2020 have made little progress.

Puerto Rico’s 1.6 GWh of residential-sited batteries represents the “largest untapped virtual power plant” in the world, said Javier Rúa-Jovet, chief policy officer at the Solar and Energy Storage Association of Puerto Rico (SESA-PR).

Puerto Rico has also reached 680 MW of distributed solar, according to a U.S. Department of Energy study, triple the amount of two years ago.

Rúa-Jovet credits the progress with batteries to Puerto Rico’s “professional, well-informed” transmission and distribution utility Luma Energy, as well as the private sector and “a good regulator.”

The amount of storage keeps growing, Rúa-Jovet said, as 4,500 rooftop solar systems are being added each month with a battery attachment rate of 100% and an average of 1.2 batteries per system. Puerto Rico’s storage “is going to deal with hosting capacity concerns at the distribution level,” he said.

Meanwhile, Puerto Rico’s newly launched battery emergency demand response program has created the first virtual power plant in Latin America and the Caribbean, he said. “Uptake is slow” for the pilot program, he noted, suggesting that the compensation offered to battery owners to participate in the program could be higher, or another program model could be tried.

Rúa-Jovet made his comments at a San Juan meeting headlined by U.S. government officials to announce the summary findings of a study led by the National Renewable Energy Laboratory (NREL) to identify how Puerto Rico can reach 100% renewables.

It is “100% possible” for Puerto Rico to reach that goal by 2050, said U.S. Secretary of Energy Jennifer Granholm, but “we’ve got to work harder” to reach 40% renewables by 2025.

Both goals were set by Puerto Rico’s Act 17, enacted in 2019.

SESA-PR President P.J. Wilson said that Puerto Rico hasn’t yet reached 10% renewables, and that reaching the law’s mandate of 40% renewables by year-end 2025, or coming as close as possible, is “what’s relevant.”

Six U.S. national laboratories said in a report last year that by rapidly deploying 3.75 GW of utility-scale solar and 1.5 GW of storage, as regulators had specified in 2020, Puerto Rico could reach 36% renewables by 2025, but that would require speedier procurement by PREPA, the utility that owns Puerto Rico’s generation units.

PREPA is managing the first of several utility-scale solar and storage procurements that were intended to fulfill the 40% renewables goal by 2025, while the Puerto Rico Energy Bureau is managing two more procurements, and Genera, which operates Puerto’s generation units, is managing a 400 MW procurement for large-scale storage.

The majority of the projects in the PREPA procurement “are looking favorable to succeed,” Wilson said, “primarily because most of the viable projects have secured or are securing project support from DOE’s Loan Programs Office, which assumes up to 80% of the risk for the projects.” The success or failure of the two energy bureau procurements “hinges on the outcome” of the PREPA procurement, he added.

Rooftop solar and storage could provide 75% of Puerto Rico’s power, a report by nonprofit groups Cambio and IEEFA found in 2021. The report said that distributed solar and storage should be the focus for $9.6 billion in Federal Emergency Management Agency (FEMA) funds allocated for Puerto Rico’s grid reconstruction.

In line with that recommendation, the Center for Biological Diversity filed a lawsuit last April aiming to require FEMA to allocate funds designated for PREPA to rebuild the grid to fund distributed renewable generation.

Speaking at the San Juan meeting, FEMA Regional Administrator David Warrington said FEMA has “obligated over $10 billion towards stabilizing the energy grid, to get to the point where renewables are possible.”

The final NREL-led study on how Puerto Rico can reach 100% renewables by 2050 is expected to be released in March.

Alaskan tribal communities form independent power producers for renewables projects

William Driscoll — Tue, 06 Feb 2024 15:23:42 +0000

Alaskan tribal communities are improving the payback on renewables projects by forming independent power producers, thus gaining access to a state subsidy.

Alaska’s Northwest Arctic Borough is working with nine tribal communities located near the Arctic Circle that have renewable energy systems to create a legal structure for each system converting it into an independent power producer (IPP). Forming an IPP will give each community access to a state subsidy that will lower the cost of renewable power, said Ingemar Mathiasson, the borough’s energy manager, on a webinar sponsored by the Alliance for Clean Energy.

As he spoke, he said the temperature was -45 F in the tribal community of Ambler, and “under those circumstances it’s really hard to keep holding on to renewable energy systems with batteries and everything else involved.”

The communities’ renewable energy systems were built over the past 15 years to reduce the need for costly diesel fuel. As a point of reference, Mathiasson said that the price of stove oil and gasoline in Ambler just went up to $18 per gallon.

Early renewables systems built by the communities relied on wind and hydropower, while newer systems rely more on wind and solar power, Mathiasson said. The year-round average solar capacity factor in the area is 11%, based on the borough’s own measurements.

Unfortunately, although the renewables projects have reduced each community’s use of diesel fuel, the communities have also received a lower subsidy under the state’s Power Cost Equalization (PCE) program, which provides a per-gallon diesel subsidy to support remote utilities dependent on diesel fuel.

Fortunately, however, those working on the renewables projects learned that a tribal community could form an IPP and sell the renewable power to the local utility, in which case the utility’s purchase of the power is considered a fuel cost, thus qualifying for the PCE subsidy.

The Northwest Arctic Borough has helped three communities form IPPs since 2021. One of these, the community of Noatak, recently completed an IPP project with 281 kWdc of solar (250 kWac), and 2-hour lithium iron phosphate (LFP) battery storage with 442 kWh capacity.

The six other communities could also add solar and storage and form IPPs if a pending borough grant proposal to the U.S. Department of Energy’s Office of Clean Energy Demonstrations secures funding.

Mathiasson shared a projection that the nine Arctic tribal communities plus the nearby town of Kotzebue would have, “at full build-out” of solar IPP projects, a combined 5 MW of solar capacity and 16 MW of battery storage. Those projects would reduce diesel consumption by 328,000 gallons per year and yield annual IPP revenue of $1.8 million.

The grant proposal also requests funding for heat pumps for all households in the region, which would further reduce annual diesel consumption by 223,000 gallons.

The opportunity for similar renewables IPPs across rural Alaska is “very widespread,” said Brian Hirsch, founder and president of Deerstone Consulting. The 15-person consulting firm works primarily in rural Alaska, providing multiple services to support renewable project development.

Hirsch said that achieving 50% renewable penetration on an annual basis “is a big deal, so if you’re at 50%, you’re way ahead of the pack.” Because “the other 50% of your power is still coming from diesel fuel, it’s a partial solution,” but “if you can create a job, you can put some revenue back into the community, that’s great.”

Mathiasson countered that “there is a money restraint, right? Everybody is competing for these monies that are coming out. And it’s not inexpensive to put these systems in. We have a lot of communities out there that could do the same thing. But where would the funding come from for all of them?”

The Alliance for Tribal Clean Energy sponsored the webinar to provide a platform for considering the formation of IPPs within the context of Alaska’s PCE program.

Tribes to sponsor 1 to 3 GW of renewables to help retire dams and restore salmon

William Driscoll — Mon, 29 Jan 2024 16:00:10 +0000

Four Native American tribes, two states and the U.S. Government have agreed to work together to replace the energy now produced by hydroelectric dams. The U.S. Congress could then vote to breach the dams to restore native fish populations.

An agreement among the U.S. Government, Washington, Oregon and four Native American tribes will facilitate the buildout of at least 1 GW to 3 GW of tribally sponsored clean energy capacity, the Biden Administration said.

Federal funding potentially reaching more than $1 billion will support the agreement, which began as a proposal to the Biden Administration from the four tribes and two states. The agreement encompasses the original proposal, known as the Columbia Basin Restoration Initiative, and has the ultimate goal of restoring salmon, steelhead and other native fish populations in the river basin.

A key feature of the agreement is the goal of breaching four dams on the lower Snake River, whose locations, all in southeast Washington, are shown in the image below from Trout Unlimited with the labels 5, 6, 7 and 8.

Salmon populations in the river system have been dwindling due to the presence of hydroelectric dams, the National Oceanic and Atmospheric Administration has reported. Salmon and steelhead populations on the lower Snake River are listed as threatened under the Endangered Species Act.

A 2022 report sponsored by Washington Governor Jay Inslee and U.S. Senator Patty Murray from Washington recommended that the services of the dams on the lower Snake River be replaced before any dams were breached.

The new agreement is aligned with that recommendation. It specifies actions by the parties to deploy renewable generation that would serve as replacement power for the lower Snake River hydroelectric dams, to pave the way for an authorization by Congress to breach the dams.

Under the agreement, the U.S. Departments of Energy and Agriculture will work with the signatory tribes to provide technical assistance, planning and funding for whatever role tribes want to take with regards to renewables projects, such as “individual or collective ownership, leasing, power procurement, etc.”

The four tribal nations that signed the agreement are the Confederated Tribes and Bands of the Yakama Nation, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and the Nez Perce Tribe. Dates of their treaties with the U.S. Government are shown below.

The U.S. Department of Energy will also provide funding to the Pacific Northwest National Laboratory and potentially other DOE labs to complete a regional energy needs planning process.

DOE said it would work with the Bonneville Power Administration, a federal agency that operates the region’s transmission, to “continue to advance reforms to BPA’s interconnection processes, aiming to significantly speed the interconnection process and identify means for more efficient use of existing transmission.”

Chairman Shannon F. Wheeler of the Nez Perce Tribe said in a statement “As Nimiipuu (Nez Perce) we are bound to the salmon and the rivers – these are our life sources. We will not allow extinction to be an option for the salmon, nor for us. The United States is bound to salmon and to us by Treaty where we reserved all our fisheries – our Treaty is the supreme law of the land under the United States Constitution.”

The recommendations issued by Governor Inslee and Senator Murray in 2022 called for immediate action to deploy the scale of clean energy infrastructure necessary to confront the climate crisis, regardless of whether Congress authorizes the breaching of the lower Snake River dams.

Several of the parties signing the agreement are parties to pending lawsuits to protect native fish populations in the Columbia River Basin, who agreed to put their lawsuits on hold in favor of pursuing the agreement.

Regarding the planned replacement of hydropower with renewables, Nancy Hirsh, executive director of the NW Energy Coalition, said that in the past decade the region has replaced 2 GW of coal generation with new wind, solar, battery storage and energy efficiency. She highlighted a 2022 study by the consultancy Energy Strategies that her group sponsored, which found that building 1.3 GW of solar, 1.4 GW of wind and 0.2 GW of battery capacity would be the least-cost option for replacing the four dams’ annual generation in a way that would balance the region’s substantial remaining hydropower generation.

The Bonneville Power Administration estimated that the agreement will have an annual average rate impact of 0.7%.

Hirsh said “no one is saying these replacement energy services are free, but the cost of maintaining the lower Snake River dams is substantial and managing salmon to extinction is unacceptable.”

The 92-page agreement among the tribes, states and the U.S. Government was filed in the Federal District Court in Oregon, and is available in three parts: the memorandum of understanding, the Columbia Basin Restoration Initiative, and the federal government’s commitments.

Concerns over $77 billion in DOE funds for mostly “blue” hydrogen

William Driscoll — Mon, 22 Jan 2024 18:24:00 +0000

Groups raised concerns regarding federally funded hydrogen hubs over emissions, safety, lack of community input and wasted funds, on a Clean Energy Group webinar.

Numerous concerns about federally funded hydrogen hubs add up to “a lot of bad news,” said Abbe Ramanan, a project director with Clean Energy Group, on a webinar with energy research group IEEFA and the Pipeline Safety Trust.

The hydrogen hubs are intended to pair large-scale clean hydrogen production with industrial and other end-uses for hydrogen. Yet most of the hydrogen hubs to be funded by the U.S. Department of Energy (DOE) will produce “blue” hydrogen, Ramanan said.

Blue hydrogen involves fossil fuel combustion and is “not clean or low-carbon,” said Anika Juhn, an analyst with research group IEEFA. A report from the group says blue hydrogen “will be very dirty.”

“Green” hydrogen, made from electrolysis of water powered by renewables, has been seen as an option for multi-day or seasonal storage of renewable energy—for example, where salt caverns can be created to store hydrogen on-site. Research group Energy Innovation last year projected that green hydrogen production could be profitable in “wide swaths” of the U.S., mostly in the central U.S.

The seven hydrogen hubs selected for federal support are now engaged in an award negotiation process. Yet even though DOE committed, Ramanan said, to “heavily weigh community benefit plans and community engagement” in the negotiation process, Clean Energy Group has heard from “a lot” of community groups that have been unable to learn how to engage with the hubs, what hydrogen projects will be involved in each hub, or how those projects will impact and possibly benefit their communities.

No matter how hydrogen is produced, transporting it in pipelines presents risk, said Amanda McKay, policy manager with the Pipeline Safety Trust. Small hydrogen molecules interact with steel and certain polyethylene pipes, she said, leading to embrittlement and cracking. She said that a hydrogen pipeline is “more likely to explode” than methane pipelines. McKay began her presentation with a tragic story of a gasoline pipeline leak and fireball in Washington State that claimed the lives of three boys.

Regarding proposals to mix a small portion of hydrogen with methane, McKay said that because hydrogen has less energy content than methane per unit of volume, mixing 10% hydrogen with 90% methane reduces combustion CO2 emissions by only 3%. Moreover, hydrogen is an indirect greenhouse gas, she said.

The seven hydrogen hubs selected by DOE for $7 billion in awards would also receive federal tax incentives estimated by Clean Energy Group at $70 billion in over ten years, consisting of hydrogen production incentives for all projects and carbon capture incentives for blue hydrogen production.

Carbon capture incentives are key to the economics of blue hydrogen projects, said IEEFA’s Anika Juhn, yet federal incentives will not lead to a high rate of carbon capture. She described a project in Louisiana to produce hydrogen from coal gasification that is set to receive $425 million per year in carbon capture credits, while capturing only 64% of the associated lifetime CO2-equivalent emissions.

Juhn critiqued the GREET model used by DOE to project a hydrogen project’s carbon emissions, challenging four assumptions used in the model.

David Schlissel, an analyst at IEEFA, said “there’s not enough demand” for the hydrogen to be produced by “these projects that we’re going to pay to build.” He forecasted potential markets for hydrogen for ammonia production and iron production, but not for transportation or home heating.

Schlissel and Suzanne Mattei, also an IEEFA analyst, wrote in an op-ed last fall that “full funding of these projects is not yet guaranteed. DOE will now enter into negotiations with the selected project sponsors about funding, which will be allocated in four decision-making phases.”

Utility trade groups call for $1.2 billion to boost transformer manufacturing

William Driscoll — Mon, 08 Jan 2024 17:36:07 +0000

To cure a shortage of distribution transformers, trade groups representing the utility and housing industries have called for federal funding to boost U.S. manufacturing of the equipment.

Seven trade groups have called for $1.2 billion in federal funding to help manufacturers of distribution transformers boost their production capacity, in a letter to U.S. Senate leadership.

“Robust domestic production” of distribution transformers “is essential to ensuring a reliable U.S. grid while reducing dependence on foreign products,” the letter says.

Distribution transformers step down the voltage of electricity on a distribution circuit so the power may be used by customers.

The trade groups say that ongoing supply chain challenges and “unprecedented demand” for grid components have resulted in a distribution transformer shortage.

About 80% of transformers of all types are manufactured abroad, the Niskanen Center reported last year.

A limited global supply of transformers for large-scale energy storage projects has become a bottleneck for those projects, a Wood Mackenzie analyst told pv magazine in October.

The seven trade groups calling for federal funding support for transformer manufacturing include four utility groups, two homebuilder groups, and an association of equipment manufacturers.

In their letter, the groups said that the Senate Appropriations Committee last July unanimously passed language specifying $1.2 billion in repurposed supplemental funding for the Department of Energy to “bolster the transformer and critical grid component supply chain.”

The groups called for this language to remain in the Senate’s final Energy and Water Development Appropriations bill, and urged the inclusion of the Senate Appropriations Committee language in any forthcoming House-Senate conference negotiations.

The groups’ letter said that more manufacturing capacity “means home construction can be completed, communities can modernize their infrastructure to incorporate IIJA investments, and regions can bounce back quickly from natural disasters.” The IIJA, or Infrastructure Investment and Jobs Act, is also known as the Bipartisan Infrastructure Law.

President Biden invoked the Defense Production Act in 2022 to mobilize federal resources to support production of distribution transformers and other electric grid components, the Bloomberg Law news service has reported.

Yet last July, the news service said, Energy Department and Labor Department officials interviewed pointed to a systemic workforce shortage and supply chain issues that would be difficult to fix quickly, and a lack of funding from Congress that limited what the departments could do.

The seven trade groups signing the letter were:

American Public Power Association
Edison Electric Institute
GridWise Alliance
Leading Builders of America
National Association of Home Builders
National Electrical Manufacturers Association
National Rural Electric Cooperative Association.

DOE seeks input on high-priority areas for transmission

William Driscoll — Tue, 02 Jan 2024 14:00:21 +0000

The Department of Energy has begun a process to designate National Interest Electric Transmission Corridors, and invites industry input on the first stage of the process by February 2.

The U.S. Department of Energy is working to “independently identify narrow areas” where transmission development is “urgently needed,” and will work with states, tribes, local communities and industry to accelerate the development of transmission projects in those areas, the department said.

DOE aims to “pinpoint” areas where consumers are harmed by inadequate transmission, whether by higher electricity prices, more frequent power outages from extreme weather, or longer outages.

Designation of a National Interest Electric Transmission Corridor (NIETC), as authorized by the Federal Power Act, makes federal financing and permitting tools available for transmission deployment.

NIETC designations will be based on:

Findings from DOE’s National Transmission Needs Study
Input from affected states, tribes, local communities, industry, and stakeholders
Information and recommendations “relevant to transmission capacity constraints or congestion” that cause consumer harm or will do so in the future, and “ongoing roadblocks” to transmission development in those areas, such as permitting, siting, or regulatory issues
Information on whether one or more transmission projects are under development in those areas.

DOE’s National Transmission Needs Study found that 54,500 GW-miles of within-region transmission must be added for a clean grid under “the most likely power sector future.” Interregional transfer capacities to transmit electricity between regions would also need to increase by nearly 125 GW, the study said.

DOE invites information and recommendations regarding NIETC designation by February 2, as detailed in its guidance. The department expects to release a preliminary list of potential NIETC designations in the spring, and will then invite information in response to that list. DOE is hosting a webinar on the process on January 3.

Federal financing available for transmission projects in NIETC corridors includes public-private partnerships through the Transmission Facilitation Program under the Bipartisan Infrastructure Law, and direct loans through the Transmission Facility Financing Program under the Inflation Reduction Act.

NIETC designation also allows the Federal Energy Regulatory Commission to issue permits for the siting of transmission lines within a NIETC corridor “under certain circumstances” where state siting authorities do not have authority to site the line, have not acted on an application for over a year, or have denied an application.

DOE anticipates re-opening the NIETC designation process after each publication of its triennial National Transmission Needs Study or as determined by the Secretary of Energy.