Reality check: It takes around five years, on average, for generation and transmission projects to move through review. “The current permitting system is broken,” Xan Fishman, vice president of energy at the Bipartisan Policy Center, told Energy Central over email.

But the grid quickly needs new gigawatts (and transmission lines) to meet a tsunami of demand. To cut through all that red tape ASAP, Congress is racing to broker a deal by August recess.

But first, why does the permitting process take so long? It’s “fractured across federal, state, and local authorities, and it attracts litigation that can last a long time with uncertain outcomes,” Tom Sharp, director of permitting intelligence at analytics firm Arbo, told us via email.

That litigation often stems from federal rules like the National Environmental Policy Act (NEPA) and the Clean Water Act, which were intended to safeguard US ecosystems and communities. These court battles can add years to the process and even kill some projects.

So, what’s the progress on permitting reform? In recent years, the House has introduced a flurry of bills. Roll the tape:

• You’ve got the SPEED Act, which aims to streamline NEPA and cut down litigation.

• There’s also the PERMIT Act, which has similar goals for the Clean Water Act.

• Both are sitting in the Senate but aren’t likely to pass, Sharp and Fishman agreed.

What’s more likely: A deal that wraps up these goals (along with accelerating the transmission buildout) into one hefty package. Senate committees are in negotiations right now, Fishman said. This potential deal would likely also tackle President Trump’s crusade against renewable projects, he added.

These talks have run into some speed bumps, but the stakes are high to wrap things up by next month’s Congressional recess: “If we don’t get this done, energy costs are going to rise and chances of blackouts will increase,” Fishman said.

Load data from the National System Operator (ONS) for the first half of 2026 confirms the structural dominance of the Southeast/Center-West subsystem within Brazil's National Interconnected System (SIN), which accounted for approximately 55% of total average energy demand over the period, more than three times the combined share of the Northeast (17%) and Sul (18%) subsystems, with the North contributing the remaining 10%.

This concentration reflects the subsystem's industrial and demographic weight, but it also reinforces its role as the primary swing factor in national load behavior: average demand in Southeast/Center-West declined from roughly 46.1 GW average in January to 40.6 GW in June, a contraction of nearly 12% that alone drove most of the observed reduction in total SIN load across the semester.

Seasonal effects were evident across all subsystems, consistent with the transition from Brazilian summer to the milder autumn-winter period.

> The South subsystem exhibited the highest volatility in the dataset (standard deviation of approximately 2,135 MW versus 305–915 MW in the other regions), with average demand falling from 15.1 GW in January to 13.3 GW in June, a pattern typical of a subsystem more exposed to temperature-sensitive cooling load and to the variability of hydrological conditions in the South.

> The Northeast subsystem showed a comparatively moderate and steady decline, from 13.9 GW to 12.9 GW, while the North subsystem stood out as the only region with a slight upward trend, rising from 8.2 GW to 8.4 GW, likely reflecting more stable industrial and residential consumption patterns less affected by seasonal temperature swings.

From a system planning and market perspective, these findings carry direct implications for curtailment risk, transmission constraint management, and commercialization strategy in the Northeast

> The combination of a declining Southeast/Center-West subsystem load base and comparatively stable Northeast subsystem demand narrows the historical gap between subsystems, a dynamic that merits close monitoring given its potential influence on inter-regional transmission flows, marginal cost formation (PLD), and the relative attractiveness of new renewable capacity additions across regions.

As the second half of 2026 unfolds, tracking how these load trajectories interact with hydrological reservoir levels and the pace of intermittent generation additions will be essential for accurately assessing curtailment exposure and structuring bankable PPAs in the region.

#RenewableEnergy #EnergyTransition #PowerGrid #Brazil #EnergyMarkets #GridReliability #EnergySector #Sustainability #CleanEnergy #EnergyStorage #SolarEnergy #EnergyPolicy #PowerSystems #Curtailment #EnergyConsulting

Conventional wisdom suggests using residential demand response (DR) to help offset growing electricity demand from data centers. We wanted to test that assumption - and also examine the impact of rapidly growing EV ownership.

Our analysis produced two surprising results:

• Residential DR does not reduce the utility peak associated with data center growth because residential and data center peak loads occur at different times. Rebound effects largely offset temporary residential load reductions.

• Managed EV charging produces the opposite result. Under every G&T cost structure evaluated, the program generated net savings after program costs—and in some cases reduced annual residential electric costs by nearly $8/residential customer base while avoiding $40/residential customer base in unmanaged EV costs.

 For example, an electric cooperative with rate Structure II serving a suburban residential customer base of 20,000 with 10% EV ownership could increase annual revenue/reduce customer prices by $93,000.  

Study results are based on the MAISY® Utility Customer Database, Grid Impact Model analysis and industry EV data. Our paper includes the complete methodology, assumptions, and example calculations for four representative G&T cost structures and is available at https://maisy.com/dcevrates.htm

Over the past several years, utilities have invested heavily in modernizing grid infrastructure, digitizing assets, and improving operational visibility.

As these efforts mature, another concept has rapidly gained attention: the digital twin.

The promise is compelling. A virtual representation of physical assets, networks, or even entire grid operations that can provide real-time visibility, predictive insights, and scenario-based decision support.

But amid the growing enthusiasm, an important leadership question remains:

Are digital twins delivering measurable value, or are they becoming another technology buzzword in the grid modernization journey?

Beyond the Buzzword

Most utilities already possess elements of what many would describe as a digital twin:

• Asset models

• GIS platforms

• SCADA and EMS environments

• Operational analytics

• Asset performance management systems

The challenge is not creating another model. The challenge is creating a living, connected representation that remains synchronized with operational reality. That distinction matters.

A static model provides information. A digital twin should provide insight.

The Real Value Proposition

When implemented effectively, digital twins can help utilities move beyond historical analysis toward proactive decision-making.

Potential applications include:

• Asset health monitoring and predictive maintenance

• Grid planning and capacity analysis

• Storm preparedness and restoration simulations

• DER integration studies

• Workforce training and operational readiness

The value is not simply in visualization. The value lies in reducing uncertainty before decisions are made. In many ways, digital twins represent another step in the industry's progression from visibility to operational intelligence.

Why Many Digital Twin Initiatives Struggle

Despite the promise, many organizations find it difficult to scale digital twin initiatives beyond pilots. A common misconception is that a digital twin is primarily a technology project.

In reality, success depends on:

• Data quality and governance

• Asset model accuracy

• Integration across OT and IT systems

• Clear ownership and lifecycle management

• Defined operational use cases

Without these foundations, even sophisticated digital twin environments can quickly become disconnected from reality. And once trust erodes, adoption follows.

The Trust Challenge

Like AI and decision intelligence, digital twins ultimately depend on confidence. Operators, engineers, and planners must believe that the representation accurately reflects the state of the physical system.

The question is not: Can we build a digital twin?

The more important question is: Can we maintain trust in it over time?

That requires continuous synchronization, governance, and accountability.

From Technology Asset to Operational Capability

One of the most common mistakes is treating digital twins as standalone technology investments. Leading organizations are increasingly approaching them differently.

Rather than asking: How do we build a digital twin?

They ask: What operational decisions are we trying to improve?

This shift changes the conversation from technology deployment to business outcomes. The digital twin becomes a means to an end, not the end itself.

Strategic Necessity or Hype?

The answer is neither simple nor universal. Not every utility needs a highly sophisticated digital twin environment today. However, as grid complexity increases through distributed energy resources, electrification, resilience requirements, and AI-enabled operations, the ability to model, simulate, and predict system behavior will become increasingly valuable.

The question is no longer whether digital twins have potential.

The question is where they create the greatest value and how utilities can operationalize them effectively.

Closing Thought

Digital twins are unlikely to transform utilities simply because they exist. Their value will be determined by how well they improve planning, operations, and decision-making. Like many aspects of digital transformation, success will depend less on technology and more on execution, governance, and trust.

The future may not belong to the utilities with the most sophisticated digital twins. It may belong to those that use them most effectively to make better decisions.

Grid Forward, a member-based non-profit organization promoting grid modernization, announced the winners of the 2026 Grid Innovator of the Year Awards during its Annual Member Meeting on June 30. This year’s honorees, Southwest Power Pool, Amperon, and SMUD CEO Paul Lau, were recognized for their leadership and impactful contributions in driving electric grid innovation. Read the entire announcement here >

Grid Innovator Award Winner, Grid Operator: SPP

SPP has shown extraordinary leadership this year in advancing market design and enabling the next generation of grid flexibility. Through initiatives like the CPP, CHILLS and HILLS tariff frameworks, SPP has established a clear and forward-looking approach to integrating new generation and large, flexible loads while supporting reliability and economic growth across its footprint.

Grid Innovator Award Winner, Solution Providers: Amperon

Amperon was honored for helping utilities, retailers, grid operators, and energy market participants plan with greater confidence through its standout AI-powered forecasting platform. By turning complex grid, weather, and market signals into clearer demand, renewables, and price forecasts, Amperon equips the industry to navigate an increasingly dynamic and volatile energy landscape.

Grid Innovator Award Winner, Individual Lifetime Achievement: Paul Lau

Paul Lau is this year’s individual recipient in recognition of his nearly 45-year career at SMUD, where he championed grid modernization, clean energy innovation, and a culture of forward-thinking leadership. As CEO, he led the development of SMUD’s nation-leading 2030 Zero Carbon Plan, proving that ambitious decarbonization can go hand-in-hand with affordability and reliability.

See all the finalists in the award announcement >

• PJM has issued a hot weather alert for its 13-state region through July 3 (temps are forecast to hover in the 90s for several days). Over this period, peak demand could surpass 166 GW (and blow past the 2006 record of 165 GW). As the heat builds, PJM hopes to order large loads like data centers to run on back-up generators (with FERC permission).

• In other grid news: The planned NextEra-Dominion merger keeps catching criticism. The latest naysayer? Sen. Angus King (I-ME) is pushing FERC to reject the deal. He claims that NextEra has a “documented record of using its market position and political resources to suppress competition that threatens its merchant revenues.

• The numbers: Also in 2025, domestic electricity generation grew by more than 3%, “a marked acceleration relative to its long-term trend,” per the Energy Institute's latest report. This was largely due to rising electrification (and, of course, the influx of data centers).

• Plus, a surprising reversal: After coal consumption peaked in 2007, it had been declining consistently since. Last year, that changed: Domestic use of the fossil fuel grew by 13% (the report attributes this to high gas prices). 

• The issue: The country’s power system has just 26 GW of surplus generating capacity, a recent ICF report notes. And “in high-growth markets like ERCOT and PJM, there is no spare capacity to support new demand beyond next year,” the authors wrote. Within a few years, SERC and NYISO could end up in the same boat.

• The fix: 445 GW of nameplate capacity is set to hit the grid through 2030…but less than half will meet peak load. While those new projects sit in the pipeline, ICF thinks demand flexibility will be key to easing the grid pressure.

This study evaluates the technical and economic feasibility of integrating Lithium Iron Phosphate (LFP) Battery Energy Storage Systems (BESS) into agrivoltaic photovoltaic (PV) arrays in the Vale do São Francisco.

Additionally, a recent project commissioned by a public sector client demonstrates the deployment of BESS frameworks designed to benefit local populations through energy credit compensation, specifically managing the injection schedule of stored energy into the local electrical distribution grid. The multi-objective dispatch strategy complies with ANEEL Resolution 1059/2023, leveraging Time-of-Use (TOU) tariff arbitrage while ensuring an uninterrupted power supply for drip irrigation pumping systems.

Energy modeling indicates that the proposed topology increases the self-consumption rate from 61% to 89%, mitigates daytime injection peaks by 34%, and guarantees 100% supply for nocturnal pump loads. Discounted cash flow analyses, incorporating tariff compensation benefits and water-use efficiency gains, demonstrate a simple payback period of 6 to 9 years and an Internal Rate of Return (IRR) of 14% to 19%. Ultimately, coupling BESS with agrivoltaic plants constitutes a robust solution for decarbonizing irrigated processes, optimizing distributed generation assets, and delivering socio-economic benefits to semi-arid regions.

#Agrivoltaics #BESS #EnergyStorage #SolarPV #ValeDoSaoFrancisco #SmartGrid #EnergyCredits #PublicSector #DistributedGeneration #Irrigation #LFP #TariffArbitrage #Decarbonization #WaterEfficiency #SustainableAgriculture

• In the Empire State, a new 100-mile, $1.5B transmission project is now complete. The new substations and rebuilt lines will broaden the reach of 1 GW of renewable energy. They’ll also offer over $400M in annual ratepayer savings, officials said. It’s part of the biggest investment in NY’s grid in five decades.

• Down in AZ, Enlight has raised $2.6B for a 1.2-GW/4-GWh solar and storage project. It’s set to hit the grid beginning in 2027, and Enlight has inked deals with Salt River Project and Arizona Public Service.