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Newsom’s Oil Mandate Passes the California Assembly: Another Step Towards Higher Gas Prices for Arizona and Nevada
On Tuesday, the California State Assembly approved Governor Gavin Newsom’s new refinery supply mandate, which now heads to the state Senate. The proposed legislation will require oil refiners to keep a minimum gas reserve on hand, and gives the California Energy Commission the power to require oil refiners to provide resupply plans to address losses in production caused by refinery maintenance.
Central Valley Republicans Oppose Proposal, Select Democrats Abstain
The proposal passed through the State Assembly with wide Democratic support on a vote of 44-17, but also had bipartisan opposition. Several Democrats abstained from voting and all Republicans voted against the mandate.
“Newsom’s scheme won’t do a damn thing to lower gas prices, and he knows it. As long as Democrat politicians refuse to stand up to the governor, costs at the pump are only going to increase.”
Assembly Democrats Esmeralda Soria and Jasmeet Bains both voted against the proposal. While Bains declined to comment, Soria voiced concerns that Newsom’s proposal was risky and unproven. Another Democrat who does not support the proposal, Assembly Member Blanca Rubio, who abstained, said she could not support the measure because of “concerns regarding worker safety, practicality and the actual impact this measure would have on prices at the pump and on working class families.”
Energy Producers Warn Supply Mandates Will Mean Higher Prices at The Pump
Gallagher’s concern over the proposal raising gas prices, rather than reducing them, is echoed by warnings from the state’s oil industry. The industry has said the analysis by the Division of Petroleum Market Oversight at the CEC, which led to Newsom’s proposal, does not capture the realities of the operations of oil refineries.
“Without a deep understanding of the complexities of refinery operations, policymakers are gambling with consumers’ wallets,” CEO of the Western States Petroleum Association Catherine Reheis-Boyd said in a press release.
California’s own regulations have resulted in complex bottlenecks in their energy supply chain, which contribute to the state’s high gas prices. Establishing a minimum fuel storage requirement will do nothing to address the current issues, and will only increase gas prices more, which now average $4.67 per gallon – $1.48 more than the national average of $3.19.
Union Workers and Raise the Alarm Over Worker Safety
Higher gas prices aren’t the only issue on the horizon if the bill is to pass – by giving the state more control and oversight of refineries’ planned maintenance schedules, the proposal could also compromise the safety and autonomy of the state’s refinery workers.
Politico reported in its California newsletter that the State Building and Construction Trades Council, a powerful union whose workers help maintain and construct refinery components, strongly opposes the proposal. Last week, union members who work at the state’s refineries packed into an Assembly meeting room to testify on the bill, with some workers suggesting that Newsom’s proposal prioritizes short-term economic or political gain over worker safety.
Chris Hannan, president of the state Building Trades Council, spoke to CalMatters after the assembly advanced the bill in committee last week:
“Hopefully they don’t move forward with something with this much uncertainty that could jeopardize worker safety and jobs in our state.”
The sponsor of the bill, Assembly member Gregg Hart, told the Assemblyhe is continuing to consider the safety concerns raised by the State Building and Construction Trades Councils of California.
Still, Politicoreports that the assembly did not make any amendments to the bill to consider the Building Trades’ position.
Impact Beyond California: Arizona and Nevada Brace for Price Hikes
Other critics of the proposal include Arizona Governor Katie Hobbs and Nevada Governor Joe Lombardo. In September, the two sent a bipartisan letter to Gov. Newsom urging him to reevaluate his oil refinery proposal. Both governors expressed concerns that Newsom’s proposed requirements threaten to slash oil supplies and send gas prices higher in both of their states.
Newsom’s legislation comes at a politically crucial moment in Arizona and Nevada, with both states expected to be tightly contested in next month’s presidential election. The decision by Newsom to call a special session and press the issue now is raising eyebrows among many political experts, especially given recent reported friction between the Harris campaign and Newsom.
Harris trails in NV. She might have questions about Newsom’s timing. -> “Newsom’s bad neighbor energy plan”https://t.co/ixLWHLqjeP
Despite warnings from peer governors of both parties and organized labor, Gov. Newsom appears intent on jamming the bill through the legislature. Senate President Pro Tempore Mike McGuire has already informed his members that they will reconvene to consider the bill on October 7th, and made it clear his chamber has the votes to pass the proposal.
BOTTOM LINE: Newsom’s plan is the last thing his political allies need in neighboring states like Arizona and Nevada. If ABX 2-1 passes, which is likely to happen in the State Senate, it will be the latest blow against working families in California, Arizona and Nevada, who can expect to see their already high gas prices only increase further.
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In today's rapidly evolving energy landscape, electric utilities face the challenge of balancing traditional financial metrics required for any good functioning business with broader social and environmental responsibilities. In this issue of “Watt’s on Mani’s mind” I offer the triple-bottom-line (TBL), a concept that offers a comprehensive framework going beyond profits to include people and the planet.
The TBL approach encourages utility executives to consider three key dimensions: financial performance, social responsibility, and environmental impact. Utilities can achieve sustainable growth by integrating these dimensions and still deliver strong financial results to their stakeholders while contributing positively to society and the environment.
Financial Performance
First and foremost, financial stability and performance (returns on investment) must always remain crucial. If the focus on this dimension is lost, the potential for the utility as a viable business entity will be in jeopardy. The TBL approach emphasizes long-term value creation over short-term gain and a quarter-over-quarter focus on returns. Utilities are already entities that get returns on their investments based on GRC (General Rate Cases) that go over a 3-5-year cycle and so, a long-term focus is already in their DNA. From an investment perspective, this involves investing in renewable energy sources, energy efficiency programs, and innovative technologies that reduce operational costs and enhance resilience.
Social Responsibility
Utilities have a monopoly franchise over a specific territory within which, for the most part, customers are locked into the services provided by them. Given the lack of competition within the franchise territory, the customers do not have any option to get their electricity as a service – which in turn prevents the utility from raising rates as performed by other private service entities. As a result, utilities play a vital role in communities by providing reliable electricity at affordable rates. The TBL framework encourages utilities to engage with stakeholders (customers and regulators), address social equity issues, and support local economic development. Programs that promote energy access for underserved populations and partnerships with community organizations are examples of this commitment.
Environmental Impact
Utilities, just like all business enterprises, are stewards of the environment. The US EPA estimated[i] that GHG emissions by the electric power sector accounted for 24% of total U.S. Greenhouse Gas Emissions by Economic Sector in 2022. #1 on this list is the transportation sector and they are making significant moves to reduce their carbon footprint by moving towards electric vehicles. By being second on this list, electric utilities have an additional responsibility to prioritize reducing their carbon footprint and mitigating climate change. They need to lead by example by focusing on transitioning to cleaner energy sources, implementing sustainable practices, and complying with environmental regulations. By doing so, utilities not only protect natural resources but also enhance their reputation and build trust with customers. Of course this must be done in a responsible manner with a focus on total cost to the customer as well.
The Impact of Scaling Back DEI Programs
Recently, several leading companies have scaled back or cut their Diversity, Equity, and Inclusion (DEI) programs due to economic pressures and fear of political backlash. This trend raises concerns about the broader implications for TBL due to a direct impact on one of the dimensions, “Social Responsibility”. The focus on “Social Responsibility” cannot just be on the affordability of rates to customers – it needs to be on treating all customers and employees with respect, empathy, and sensitivity. DEI initiatives are crucial for fostering an inclusive and equitable workplace, which can lead to improved performance and innovation. Reducing focus on DEI may hinder progress in social responsibility and negatively impact organizational effectiveness.
Closing Thoughts
Focusing on “financial performance, social responsibility, and environmental impact” is not new by any measure. Most business enterprises focus on them at some level, some more than others. However, by combing them into a singular focus and calling it the triple-bottom-line, I am asking utility senior executives to make a shift in their mindset and make a commitment to transparency and accountability and measure their success through the lens of economic, social, and environmental outcomes. By optimizing across these three dimensions, electric utilities can drive meaningful change and lead the way toward a more sustainable future.
[i] https://www.epa.gov/ghgemissions/electric-power-sector-emissions
The high cost of living, primarily driven by inflation, has become a major concern in political discussions across North America. Political parties have recognized this issue as a top priority for voters, made various promises, and implemented policies to ease these financial burdens. As a result, addressing the cost of living has become a central objective of recent elections.
Climate Watch
Carbon dioxide removal incentives are the antithesis of this objective.
In 2022, Climate Watch ranked the World’s Global Emitters according to their incomes, and the United States and Canada ranked first and fourth amongst the high-income nations.
Both have promised to reduce their emissions, but in reality, they both subsidize this accumulation through fossil fuel subsidies.
In 2022, the U.S. government spent around $757 billion on fossil fuel subsidies, including $3 billion in explicit subsidies and $754 billion in implicit subsidies, which included the $500 billion the IMF estimated was borne by society due to the negative externalities of fossil fuel use, such as environmental degradation, health impacts, and climate change. And the $196 billion foregone tax revenue due to underpricing or exemptions for fossil fuel production and consumption.
In Canada, Environmental Defence revealed that in 2024, Canada provided nearly $30 billion in direct subsidies and public financing to oil and gas companies and projects, and over $74.6 billion over the last five years.
In 2024 alone, the pollution costs from oil and gas operations were estimated at $53 billion.
In addition to the subsidies it receives, the fossil fuel industry in both countries is now seeking “incentives” to remove the emissions it has contributed to the atmosphere over the decades, an offshoot of the generation for which it pocketed massive profits.
In the U.S., the 45Q Tax Credit incentivizes up to $85 per metric ton of CO₂ permanently stored underground and $60/ton for CO₂ used for enhanced oil recovery and applies to Direct Air Capture (DAC) projects and point-source capture from power plants or industrial facilities.
As shown in the Climate Watch graphic, the U.S. produced 11.5% of the 2024, global CO2 emissions of 41.6 billion tonnes for a total of 4.8 billion tonnes. At $85 per ton this would be a $408 billion a year liability.
It should be noted that this would be over twice the cost of President Trump’s Golden Dome missile defense project.
45Q is controversial because fossil fuel companies can claim public funds for capturing CO₂ from their operations. When used for enhanced oil recovery, this would increase oil production, particularly if no emissions cap is in place.
However, the 2022 Inflation Reduction Act shifted the 45Q incentive away from fossil capture towards atmospheric removal.
It funds over $3.5 billion for DAC hubs and tens of billions more for clean energy manufacturing, green hydrogen, and electric vehicles, and it boosts Department of Energy research into carbon removal and storage technologies. The aim is to target “hard-to-abate” emissions, not fossil business as usual. It prioritizes permanent CO₂ storage, not temporary offsets, and requires monitoring, reporting, and verification of carbon storage. The risks are that some DAC hubs are located in fossil fuel-producing states like Texas and Wyoming, raising concerns that the hubs can be used to extend fossil infrastructure.
Without guardrails, these hubs can co-opt public funds under the guise of carbon removal.
In Canada, the government is actively engaging with the Pathways Alliance, a consortium of six major oil sands producers, on a proposed $16.5 billion carbon capture and storage (CCS) project in northern Alberta. A federal government tax credit of up to 50% of eligible capital costs is offered for the project. Plus, the $15 billion Canada Growth Fund seeks to support through Carbon Contracts for Difference to de-risk investments in low-carbon technologies by guaranteeing a minimum price for carbon credits or emissions reductions. And the federal government has indicated a further willingness to allocate up to $7 billion in funding through special contracts aimed at de-risking large-scale CCS investments.
The consequences of these kinds of subsidies are the distortion of market signals, leading to the overconsumption of fossil fuels, contributing to pollution, climate change, and environmental damage.
The health impacts are linked to various health problems, including respiratory illnesses, cardiovascular diseases, and cancers. Taxpayers bear the economic costs associated with addressing these impacts and mitigating climate change.
Prorated based on Canadian/US emissions, the health impacts alone would be an annual burden of $65 billion on the $2.5 trillion Canadian economy.
Fossil fuel subsidies break the covenant that the current U.S. and Canadian governments have made to their citizens to reduce their economic burden. They are the ultimate hypocrisy.
The U.S. and Canadian governments have made numerous promises and enacted policies aimed at lowering costs for their citizens, particularly in the face of recent inflation and rising living costs. They have also promised to bring down fossil fuel subsidies, aligning with broader goals to combat climate change and transition to renewable energy sources.
The recent U.S. federal budget proposal included eliminating tax breaks for fossil fuel companies, such as the Intangible Drilling Costs deduction and the Percentage Depletion Allowance. And some lawmakers introduced bills aimed at phasing out fossil fuel subsidies and redirecting those funds toward renewable energy development.
In 2023, Canada became the first G20 country to publish a comprehensive framework to eliminate fossil fuel subsidies ahead of the 2025 deadline set by the group. This framework applies to existing tax measures and 129 non-tax measures, aiming to ensure that federal support for the fossil fuel sector aligns with Canada's climate objectives.
Under this policy, federal support identified as a fossil fuel subsidy can no longer be provided unless it fulfills one of six criteria, such as enabling significant net greenhouse gas emissions reductions or supporting clean energy initiatives. However, the framework includes exemptions that may allow certain subsidies to continue, particularly those related to carbon capture technologies and projects with credible plans to achieve net-zero emissions by 2030.
Canada currently emits approximately 700 million tonnes of CO2 annually. The cost of CO2 removal with Saskatchewan’s Boundary Dam 3 carbon capture project is estimated to be CAD 100-120 per tonne, and it sequesters only about 800,000 tonnes. So, achieving net-zero emissions by 2030 would cost about $77 billion a year.
The public won’t stand for it, particularly when they can access energy orders of magnitude cheaper than fossil fuels, which cools the surface and sequesters atmospheric CO2 at no additional cost.
Instead of being bit players in the global energy market, they should provide life-sustaining energy to the other 87% of emitters shown in the Climate Watch graphic.
The World faces a new danger of ‘economic denial’ in the climate fight, André Aranha Corrêa do Lago, Brazil's Secretary for Climate, Energy and Environment, and leader of this year’s COP30 UN climate summit, says in an exclusive Guardian article. “The new populism is trying to show [that tackling the climate crisis does not work],” he said. “
That life can’t come soon enough. Scientists now predict the world could experience a year above 2°C of warming by 2029 while others say the Earth is heading for 2.7°C warming this century.
Subsidizing carbon dioxide removal is just another DANGEROUS exercise in economic denial.
U.S. electric utilities are facing an unprecedented rise in electric demand, driven in part by supply chain issues, the increased development and deployment of AI and data centers, electrification, and shifts in national energy policy. For example, a recent resolution was signed rolling back energy efficiency standards on appliances, which will, in turn, increase energy demand as appliances without these mitigations are adopted in the market. With material goods shortages and steep tariffs on renewable energy exports, electric utilities are challenged to meet demand with fewer resources. Fortunately, behind-the-meter distributed energy resources (DERs) provide opportunities for utilities to leverage these devices for use in demand flexibility programs like virtual power plants, demand response, and EV charging.
The best part: these devices are already in your communities just waiting to be included in your customer programs.
Costs of Upgrading the Grid
Not quite two years ago, the projected total cost to upgrade the U.S. electric grid ran over $2.5t by 2035. Since then, costs have risen to parallel increases in demand, as well as the growing volume of damaging extreme weather events. In fact, analysts say climate change incurred damage costs around $16m per hour globally, a staggering figure that only promises to grow. These costs and challenges further complicate upgrading the grid to meet demand, creating a long-term, circular problem. For perspective, in 2023, U.S. utilities spent a combined $78.6 billion on transmission and distribution infrastructure costs, which include replacing aging equipment, modernizing existing assets for resiliency measures, and installing new lines and transformers.
How Supply Chain Issues Challenge This
In addition to the already high costs mentioned, supply chain issues will further complicate meeting rising demand. Already, transformer shortages have loomed over the American electric grid, with wait times that can take up to three years to receive. The supply chain is further challenged by tariffs, specifically tariffs imposed upon renewable energy technologies like solar and battery energy storage systems, which are already fostering market uncertainty in the industry. Additionally, tariffs have caused tension between neighboring energy markets that can further impact regional U.S. electric demand. While these same pressures are present for distributed energy resources (DERs), many U.S. consumers already have behind-the-meter DER assets to leverage through a Grid-Edge distributed energy resource management system (DERMS) to use in demand flexibility programs.
More Virtual Power Plant Capacity Is Needed
According to the Department of Energy (DOE), the U.S. needs between an 80-160 GW increase in virtual power plant capacity, which is about 10-20% of peak load, by 2030 to meet rising demand. For context, as of 2023, the U.S. produced around 30-60 GW of virtual power plant capacity, primarily attributable to demand response programs. By leveraging distributed energy resources (DERs), virtual power plants can improve grid resiliency and defray high peak energy market purchases by shifting power to off-peak usage periods. In fact, a new law in the state of Virginia—the start of more to come—requires Virginia utilities to propose virtual power plant pilots to state regulators by December, paving the way for increased energy resiliency.
Types of Demand Flexibility Programs & Their Benefits
Demand flexibility programs have existed for more than four decades, dating back to the mid-70s. The earliest demand flexibility program is demand response, a strategy that shifts load to off-peak hours of usage as a conservation tactic. The earliest programs operated relied upon radio switches to enact device control, with switches typically attached to devices like HVACs. With the Internet of Things, device control has become comparably easy, especially with the proliferation of WiFi and Broadband. Now, modern DERMS can aggregate an array of distributed energy resources like solar, battery energy storage systems, electric vehicles (EVs) and EVSE chargers, and smart devices like thermostats and water heaters.
Because these programs minimize usage and shift load, they defray high peak energy market costs while improving grid resiliency. This, in turn, lowers the slowly increasing energy bills, causing growing concern to customers; as a customer priority, helping decrease rates while improving grid resiliency is a net positive for utilities. Now, let’s look at the demand flexibility options that distributed energy resources provide.
Virtual Power Plants
The DOE report demonstrates one simple concept fresh to the industry: virtual power plants represent any aggregation of otherwise disparate DER assets for use in load management strategies. For example, virtual power plants can function as an aggregation of communally generated solar power by managing solar inverters and batteries to redistribute energy to repower the grid during peak periods of demand. Likewise, virtual power plants can function as an aggregate conservation program that shifts energy usage to off-period hours of usage to avoid high energy market costs and minimize demand across the system. Altogether, virtual power plants can rely on any distributed energy resource, meaning that the opportunity for leveraging VPPs for load shift is high, growing to parallel DER market penetration and demand increases: VPPs leverage the pre-existing DERs already in a community.
Demand Response
Simply put, demand response is a widespread conservation strategy that calls upon customers to minimize usage during peak periods of demand. Demand response programs often leverage smart thermostats and water heaters. Last year, research indicates that more than 16% of U.S. homes that have the internet have smart thermostats, a number that promises to grow. Likewise, the smart water heater market is equally robust, providing a secondary opportunity for demand response programs.
Irrespective of how demand response is run, as of 2022, more than 10 million customers were enrolled in residential demand response programs, yielding more than one terawatt of aggregate savings. Demand response is time-tested and trusted within the industry, such that it remains useful with increases in technology. For example, FERC recently issued a ruling expanding demand response windows to allow for a broader regulatory application of the strategy; demand response is and continues to prove useful in defraying high peak energy bills, while enhancing grid resiliency and minimizing the need for expensive grid upgrades.
EV Charging
As a distributed energy resource, electric vehicles provide many paths to meeting demand. Similar to demand response, EV charging minimizes electric demand by shifting charging times to off-peak periods of demand. While the EV market has slowed, EV production is still slowly increasing in the U.S., with newer, more affordable models increasingly common. EV charging efforts may also include V2G charging initiatives, which redirect stored battery charges from electric vehicles back into the grid. Likewise, EV telematics offers a granular look at the device data necessary to inform forecasting efforts to help utilities better plan for their upcoming needs.
TDC: Getting More From Less
The backbone of any demand flexibility program, not all DERMS are created the same. A grid DERMS aggregates utility-held distributed energy resources (DER) like solar or battery installations. Grid DERMS are often part of the operations side of a utility, as they are a dependable resource for utility operators who know what their devices are capable of and can rely on them to function at their discretion.
By contrast, a Grid-Edge DERMS manages behind-the-meter DERs that are found in places like residential, commercial, and industrial facilities, or rather, at the edge of the grid. While behind-the-meter DER management provides useful vectors for load management, customer opt-in/out rates and attrition over event windows can yield unreliable outcomes.
Topline Demand Control solves for this challenge by optimizing behind-the-meter distributed energy resources at a granular level to ensure a reliable outcome every time. Topline Demand Control combines AI, model predictive control, a Grid-Edge DERMS, and forecasting software to ensure a desired outcome for grid operators, removing uncertainty from grid ops. As opposed to modern event calling, which relies on factors like customer participation throughout an event, Topline Demand Control provides a reliable energy outcome every time.
Conclusion: How BTM Distributed Energy Resources (DER) Defrays New Construction Costs
Unfortunately, there is no universal solution to meeting rapidly growing demand. Building new power plants is not only costly and time-consuming, but requires an extraordinary amount of resources to accomplish. Fortunately, behind-the-meter distributed energy resources (DERs) provide an opportunity to meet demand and defray high peak energy costs, while simultaneously enhancing grid resiliency. Still, no matter what type, building new power plants is exorbitantly expensive, but don’t take our word for it. Download our Direct Comparison Guide: Launching a VPP versus Building a New Power Plant below for more information!
As the global energy transition accelerates, utilities are racing to modernize their infrastructure, integrate distributed energy resources (DERs), and meet the evolving needs of consumers. Yet many utilities face a fundamental challenge that hinders progress: They simply can’t see what’s happening across large swaths of their low-voltage (LV) networks in real time.
This lack of visibility—the visibility gap—is a quiet but critical roadblock. Without detailed, real-time insight into voltage, phase balancing, and transformer loading at the distribution edge, utilities are often left reacting to problems after they occur. It’s an unsustainable model in an era defined by rooftop solar, electric vehicles, and bidirectional energy flows.
And in a landscape where unexpected outages are becoming too common, from the Iberian Peninsula to Puerto Rico to New Orleans, customers are growing increasingly impatient. Fortunately, forward-thinking utilities are beginning to address this challenge head-on—by making the invisible visible.
The Visibility Gap: A Barrier to Proactive Grid Operations
Traditionally, utilities have relied on SCADA systems to monitor substations and medium-voltage feeders. They utilize AMI to collect data at the customer’s meter. But between these two endpoints lies a critical blind spot. Even with advanced AMI deployments, data remains delayed and limited in scope — leaving utilities with incomplete situational awareness across the LV distribution network.
This data lag leaves utilities operating in a reactive posture. Problems such as transformer overloads, phase imbalances, and voltage excursions often go undetected until customers complain or equipment fails. And when it comes to integrating new loads—like EV chargers or rooftop solar—utilities struggle to assess hosting capacity or forecast grid constraints.
The visibility gap not only hampers operations but also inflates capital costs. In the absence of real-time data, utilities often overbuild or over-upgrade infrastructure as a hedge against uncertainty.
From Reactive to Proactive: The Power of Real-Time LV Monitoring
The answer lies in closing this gap with real-time LV visibility—specifically, by monitoring transformer-level conditions and delivering granular, actionable data to utility operations teams.
Edge Zero works with utilities to implement cost-effective LV monitoring solutions that provide continuous insights into grid performance. These systems enable dynamic load management, early fault detection, and improved integration of DERs.
By transitioning from a reactive to a proactive operating model, utilities can use real time data to:
Detect and address voltage violations or phase imbalances before they escalate
Maximize use of existing infrastructure by understanding real-time capacity limits
Prioritize investments based on actual needs rather than assumptions
Visibility as a Foundation for Measurable Success
The benefits of real-time visibility go beyond troubleshooting. They establish a data-driven foundation for defining and tracking key performance indicators (KPIs) that align with the energy transition.
For example:
Voltage stability metrics can help measure power quality improvements.
Transformer loading patterns provide insights into asset utilization and life extension.
DER hosting capacity metrics support equitable access for customers installing solar or storage.
Armed with this information, utilities can make smarter operational decisions, justify investments to regulators, and build public trust through improved transparency.
Case Study Spotlights: Turning Visibility into Value
Endeavour’s Future Grid – Laying the Groundwork for the DSO Transition
Endeavour Energy deployed Edge Zero’s platform across the distribution network to support its Regulatory Proposal for 2024–2029. The utility’s aim: evolve into a Distribution System Operator (DSO) capable of managing dynamic DER behavior.
By targeting LV monitoring for 1 in 3 pole-top transformers (about 1 per 75 end customers), Endeavour built foundational data infrastructure to enable dynamic operating envelopes, defer capital expenditure, and optimize DER hosting.
The investment paid off. The project is forecast to generate a net present value (NPV) of $55.9 million AUD over the current regulatory period and set the stage for long-term improvements in reliability, voltage management, and regulatory alignment.
Vermont Electric Cooperative – Rural Visibility That Prevents Outages
In rural Vermont, the Vermont Electric Cooperative (VEC) piloted Edge Zero’s platform to gain visibility into its circuits. Within a month of deployment, the utility identified and resolved two critical issues:
A faulty transformer causing high voltage, which was corrected before an outage occurred. Four members were fed by the transformer, and all would have experienced an extended outage.
A phase imbalance disrupting a wastewater treatment plant member’s equipment, which was diagnosed and stabilized
End of line voltage visibility for feeder backup, allowing for real world visibility instead of relying on a engineering model that is run on an annual basis.
These early wins demonstrated the power of visibility—not just for solar integration or long-term planning, but for day-to-day reliability in rural contexts where outages can be costly and difficult to resolve.
SA Power Networks – Enabling World-Leading Rooftop Solar Uptake
South Australia leads the world in residential solar PV adoption, with over 40% of homes equipped with rooftop systems. SA Power Networks (SAPN) faced a unique challenge: how to maintain grid reliability amid rapid DER growth while overcoming the limitations of temporary, seasonal transformer monitoring. These ad hoc methods proved inefficient—especially during summer peaks, when accurate forecasting was most critical.
In partnership with Edge Zero, SAPN deployed continuous monitoring across 1,500 LV transformer sites. This shift allowed the utility to forecast load growth more accurately, reduce field crew dispatches, and avoid costly guesswork in network planning. The result: an estimated $5.3 million AUD in OpEx savings over five years and an NPV of $4.23 million AUD over the asset lifecycle. More importantly, SAPN’s improved data accuracy and availability now support proactive investment, improved customer service, and a more resilient grid for the solar-powered future.
Conclusion: From Visibility to Resilience
The utilities highlighted here show what’s possible when grid visibility becomes a strategic priority. Whether avoiding unnecessary capital costs, enhancing reliability, or enabling DER participation, real-time LV monitoring provides a tangible foundation for the grid of the future.
At Edge Zero, we believe the energy transition must be built on a deep, dynamic understanding of the grid’s most granular behaviors. Visibility is not a luxury—it’s a prerequisite for resilience, equity, and innovation. These principles are further highlighted in recent conversations Endeavour and its clients have had with Energy Central, highlighting at DistribuTECH 2025 how Edge Zero and Australian utilities have created the roadmap for other power companies adapting to DER growth.
By uncovering the invisible, utilities can finally stop reacting—and start leading.
