ChargedUp!

The True Cost of Power: A 5.12% Treasury Yield and $108 Oil Put the Squeeze on Net Operating Income

ChargedUp! — Wed, 21 Oct 2026 15:06:00 GMT

The 10-year Treasury yield closed at 5.12% on October 20, and Brent crude settled at $108.79 per barrel. Both numbers feed the same line on a property pro forma: net operating income. Lenders price debt off the first, utilities and suppliers pass through the second, and the Federal Reserve meets October 27 and 28 with a second rate increase live.

Key Facts at a Glance

10-year Treasury: The yield closed at 5.12% on October 20, below the October peak of 5.31% on October 5, according to the U.S. Department of the Treasury.
Oil: Brent crude settled at $108.79 per barrel and West Texas Intermediate at $97.82 on October 20, as Iran talks and tanker attacks near the Strait of Hormuz kept prices volatile.
Inflation: The Bureau of Labor Statistics (BLS) reported September consumer prices up 3.7% year over year, with energy up 20.4%, gasoline up 9.1% on the month and electricity up 4.4% year over year.
Federal Reserve: The Fed raised rates a quarter point in September. Reuters reported on October 14 that futures priced about a 45% chance of another increase at the October 27 to 28 meeting.
Commercial electricity: The Energy Information Administration (EIA) forecasts 14.00 cents per kilowatt-hour for 2026, up from 13.41 cents in 2025.

The Yield and the Barrel Hit the Same Pro Forma

The 10-year Treasury closed at 5.12% on October 20. The October high was 5.31%, reached on October 5. Commercial mortgage pricing follows that benchmark, so refinancing math that assumed a lower base rate no longer holds for loans maturing in the next 12 months.

Energy prices add pressure from the operating side. Brent settled at $108.79 on October 20, and Fortune reported an intraday quote of $112.85 that morning. EIA forecasts Brent near $105 in the fourth quarter. Oil does not set electricity prices directly in most U.S. markets, but the BLS data show how energy inflation travels: electricity prices rose 4.4% year over year in September, while the broader energy index rose 20.4%.

A $1,000 reduction in annual operating expense adds about $12,500 of value at an 8% capitalization rate. The reverse also holds. Every unmanaged utility increase subtracts value at that ratio, and it does so while buyers face higher financing costs.

The Federal Reserve Keeps October Live

The Fed raised rates in September. After the September inflation report, with core prices at 2.6% against 2.5% expected, Reuters reported that futures markets put the odds of an October increase near 45%, up from about 22% before the report. The October Beige Book from the Fed described rising diesel and fuel costs moving into transportation and supplier pricing.

The September increase lifted the federal funds target range to 3.75% to 4.00%, according to Northmarq. September payrolls rose only 29,000 and unemployment held at 4.2%, so the Fed weighs 3.7% inflation against a slowing labor market. Northmarq’s October commentary says an October increase may be unlikely, while Reuters reported odds near 45% on October 14. The spread between those readings shows how divided the market is.

Underwriters should model two cases for the October 28 decision, a pause and a second increase, and test debt service coverage under both. Odds shift daily, so confirm the current pricing before the meeting.

Regional Winter Exposure Decides Which Buildings Feel It First

EIA projects higher household electricity bills of about 4% this winter and heating oil expenditures up 21%, while natural gas costs fall 9%. Those national averages mask wide regional differences, which the previous column in this series examined. Electric-heat buildings carry the most exposure to the electricity increase, and gas-heated buildings benefit from lower gas costs.

Grid strain adds to the fuel effect. PJM Interconnection reached a record 162.6 GW on July 2, and ERCOT reached 91.1 GW on July 22, 6.5% above its 2024 record. EIA expects commercial electricity demand to grow 2.8% in 2027, and the North American Electric Reliability Corporation forecasts summer peak demand up 224 GW over 10 years. Federal Energy Regulatory Commission and Nuclear Regulatory Commission commissioners meet October 22 on how to manage that load growth.

Commercial electricity at 14.00 cents per kilowatt-hour sets the energy cost baseline, but the bill reflects more than the energy rate. Demand charges, which price a building by its single highest interval of use, and fuel or purchased-power adjustment riders vary by utility tariff. Pull the tariff and read both line items before forecasting 2027 operating expenses.

Three Levers Sit Inside the Owner’s Control

JLL studied 4,437 offices in seven markets and found the most efficient buildings cost $1.58 to $5.13 less per square foot each year to operate than the least efficient buildings in the same city. Each lever below targets that gap.

Lease language. Gross and modified gross leases leave utility escalation with the owner. Consumer Price Index-linked utility escalators and expense stops move part of the increase to tenants at renewal.
Onsite generation and virtual power plants. Solar with storage lowers the energy purchased and cuts the peak that sets demand charges. Enrolling the battery in a utility or aggregator virtual power plant program adds a revenue line during grid peaks. Program terms vary, so confirm payment rates and dispatch rules in the enrollment contract.
Commercial Property Assessed Clean Energy (C-PACE). The financing repays through the property tax bill, which allows a retrofit to proceed without a bank loan priced off the Treasury. Counsel at Hodgson Russ note that under triple net leases the assessment can pass to tenants, that unpaid assessments can create a senior lien requiring existing lender consent, and that some leases exclude PACE assessments from the definition of taxes or operating expenses. Review those definitions before closing. The Department of Energy adds that the assessment transfers to a new owner on sale, so it affects exit pricing.

Every dollar of operating expense removed adds about $12.50 of value at an 8% cap rate.

Three Actions for This Week

1. Run debt service coverage on both October 28 outcomes for every loan maturing in the next 12 months.
2. Pull each property’s utility tariff and list demand charges and adjustment riders by line item.
3. Audit lease expense definitions for utility escalators and for C-PACE treatment before the next renewal cycle.

The Bottom Line

Capital costs and energy costs moved against owners in the same week. Operating levers (tenant cost recovery, peak reduction and low-cost financing) are the part of the pro forma that owners control, and each one converts directly to net operating income.

Sources

Fourth Quarter Sets the First Clean Test of U.S. EV Demand Against a 234,000-Unit Base

ChargedUp! — Wed, 21 Oct 2026 13:02:58 GMT

Photo by Hyundai Motor Group on Unsplash

U.S. electric vehicle sales rose 6.1% in the third quarter of 2026 to 262,649 units, according to Cox Automotive, which already exceeds the roughly 234,000 sold in the fourth quarter of 2025. That fourth quarter was the first after the federal tax credit expired, so the fourth quarter of 2026 is the first quarter that compares against a post-incentive base rather than a credit-driven peak.

Key Takeaways

U.S. EV sales reached 262,649 in the third quarter of 2026, up 6.1% from the second quarter and down 39.5% from the record third quarter of 2025, according to Cox Automotive.
Fourth quarter 2025 sales fell to about 234,000, down 46% from the prior quarter, so the fourth quarter of 2026 is the first to compare against a post-credit period.
September brought a 6.5% new EV share, incentives near 11% of the average transaction price, and a record 3.3% used EV share.
Benchmark Mineral Intelligence reports Europe up 39% in September while North America fell 44% and China fell 18%. Those figures include plug-in hybrids.

The 2025 Deadline Distorted Both Sides of the Comparison

The federal $7,500 EV tax credit ended September 30, 2025. Buyers rushed to use it, which made the third quarter of 2025 a record, and the fourth quarter paid for it. Cox Automotive reported that fourth quarter 2025 sales fell to about 234,000 units, down 46% from the third quarter and 36% from the fourth quarter of 2024, the lowest volume since the fourth quarter of 2022. EV share of new-vehicle sales dropped from 10.5% to 5.8%.

Every 2026 quarter through the third compared against a 2025 period that included credit-driven demand. That is why the third quarter shows a 39.5% year-over-year decline even as volume climbs from one quarter to the next. The fourth quarter breaks the pattern. Its comparison period is the post-credit trough.

The base effect deserves a caution. A fourth quarter above 234,000 would show year-over-year growth that partly reflects an easy comparison. Two tests separate recovery from arithmetic: whether the quarter also exceeds the 262,649 sold in the third quarter, and whether share, pricing and inventory improve together.

The 2026 Data Shows Sequential Recovery and Used Market Strength

Cox and Kelley Blue Book estimate that EV share reached about 6.4% in the third quarter, up from 5.8% in the second. Electrified vehicles, a category that adds hybrids and plug-in hybrids, made up nearly 25% of new-vehicle sales. Tesla sales fell 20% from a year earlier but still account for more than half of the market. Toyota and Lexus EV sales rose nearly fivefold, Rivian rose 46% and Subaru 31%. Stephanie Valdez Streaty, director of Industry Insights at Cox Automotive, said that “improvement through 2026 suggests the reset phase is largely behind us.”

The September EV Market Monitor adds pricing and inventory detail. New EV sales were 86,632 units, down 40.7% from September 2025, with share at 6.5%, up from 6.3% in August. The average new EV transaction price was $55,842, down 3.1% from a year earlier. Incentives averaged about $6,117 per vehicle, or 11% of the transaction price, down from 14.2% a year ago. The premium over comparable conventional vehicles was $5,611, against an average of $8,665 in 2025.

Used EVs show the strongest momentum. Used EV sales reached 47,862 units in September, up 21.2% from a year earlier, and captured a record 3.3% of used-vehicle sales. Used EV supply tightened to 35 days. New EV supply stands at 68 days, up 64.2% from a year earlier, which gives dealers room to keep discounting.

Global Markets Move in Different Directions

Benchmark Mineral Intelligence reports 2.15 million EVs sold worldwide in September, down 2% from a year earlier, bringing 2026 sales to 15.5 million, up 3%. Benchmark counts battery electric and plug-in hybrid vehicles together, so its percentages are not comparable with Cox’s battery electric series.

Europe sold almost 600,000 EVs in September, a record and 39% above a year earlier, and is up 30% year to date. China fell 18% in September and is down 13% year to date. North America fell 44% in September and is down 24% year to date.

The International Energy Agency (IEA) had projected about 23 million electric car sales worldwide in 2026, after sales passed 20 million in 2025, according to its Global EV Outlook 2026. The IEA notes that U.S. sales held just under 10% of new car sales in 2025 and fell toward year end when the credits ended. The Benchmark year-to-date total sits well below that pace, and the projection needs rereading against it.

Fuel Costs and Hybrids Shape Consumer Choice

Ember reports that EVs in oil-importing countries saved about $20 billion in crude costs between March and August, displacing roughly 200 million barrels, according to its October 14 analysis. The group also finds that battery electric vehicles reached 6% of U.S. light-duty sales in the first eight months of 2026, Fifteen countries passed the United States in battery electric sales share this year, and that 49 of the 56 countries it tracks now post a higher share.

U.S. fuel prices frame the domestic choice. The EIA’s October Short-Term Energy Outlook forecasts retail regular gasoline at $3.91 per gallon on average for 2026, against $3.10 in 2025, with Brent crude averaging $105 per barrel in the fourth quarter. Higher pump prices improve the running-cost case for electrified vehicles of every type.

Hybrids capture much of that demand. EIA data show hybrids at 16% of third quarter new light-duty sales, and hybrids, battery electric and plug-in hybrid vehicles combined at 23%, against 24% a year earlier. Battery electric share fell from 10% to 6% over the same period. Buyers have kept moving toward electrified vehicles while shifting from plug-in models to hybrids.

Used EV Supply Builds Through 2027

Manheim’s third quarter data point to a growing supply pipeline. Used retail EV sales reached about 124,000 units, up 11.4% from a year earlier, and EVs hit a record 4.9% of Manheim wholesale transactions. Off-lease EVs made up about 10% of off-lease supply in the first half of 2026 and are expected to reach about 16% in the second half and about 19% by summer 2027, according to Cox Automotive.

Each off-lease EV that enters the used market moves into a household that may lack a home garage. That pattern raises the importance of multifamily parking, workplace lots and retail dwell-time charging, all of which depend on property owners rather than individual drivers for access.

Five Indicators Define the Fourth Quarter

Quarterly volume. Exceeding 234,000 beats the base. Exceeding 262,649 extends the recovery.
Share. A reading above the 6.5% September level confirms adoption growth independent of swings in total auto sales. Cox’s January outlook expected EV share near 8% in the year ahead, a level the market has not reached.
Pricing and incentives. The transaction price, the incentive share of price and the premium over conventional vehicles show whether automakers can attract buyers without federal credits.
Used EV adoption. Used share and days of supply show whether EVs are reaching a broader, more price-sensitive buyer base.
Inventory. New EV supply of 68 days against a used supply of 35 days points to continued new-vehicle discounting.

Charging Investment Follows the Installed Fleet

Charging investments are underwritten over many years, and a single quarter of sales does not define their return. The installed fleet, local registrations and measured utilization carry more weight than the quarterly headline. As EVs move into the used market, charging demand reaches drivers without home garages, which raises the importance of multifamily, workplace and public parking sites.

Overestimating near-term demand leaves equipment underused, and underestimating it leaves strong locations without capacity. Staged electrical capacity, with conduit and service sized for future stalls and stall counts that follow measured sessions, limits both errors. A charging program that adds $1,000 of annual net operating income supports about $12,500 of asset value at an 8% cap rate, so utilization determines the return.

A companion update after the quarter closes in January will show whether the market recovered or benefited from an easier comparison.

Frequently Asked Questions

How many EVs did the United States sell in the third quarter of 2026?

Cox Automotive reports 262,649 EVs, up 6.1% from the second quarter and down 39.5% from the record third quarter of 2025.

What is the fourth quarter 2025 baseline?

Cox Automotive reported about 234,000 EVs in the fourth quarter of 2025, down 46% from the third quarter, with a 5.8% share of new-vehicle sales.

How is the used EV market performing?

Cox reports 47,862 used EVs sold in September 2026, up 21.2% from a year earlier, a record 3.3% of used-vehicle sales.

How do global EV sales compare?

Benchmark reports Europe up 39%, China down 18% and North America down 44% in September 2026. The figures include plug-in hybrids.

Sources

Four-Hour Batteries Beat Gas Peakers on Cost in All 43 Markets Wood Mackenzie Modeled

ChargedUp! — Tue, 20 Oct 2026 21:41:30 GMT

Photo by Gez Xavier Mansfield on Unsplash

Wood Mackenzie’s latest levelized cost of electricity analysis finds four-hour battery storage cheaper than open-cycle gas turbines in all 43 markets where both were modeled. Turbine procurement runs two to four years, which gives storage a speed advantage alongside the cost advantage for any site waiting on capacity.

Key Takeaways

Wood Mackenzie finds four-hour battery storage cheaper than open-cycle gas turbines in all 43 markets where both technologies were modeled.
Open-cycle turbines take two to four years to procure, and closed-cycle waitlists extend into the early 2030s, according to TechCrunch reporting on the analysis.
PJM Interconnection fast-tracked two battery projects totaling 1,660 MW and one 455 MW gas uprate in its first Expedited Interconnection Track round, all due in mid-2029.
North American solar faces tariff pressure: Section 232 duties of 15% on polysilicon through modules take effect December 4, 2026, per the Solar Energy Industries Association (SEIA).

Wood Mackenzie Prices Storage Below Gas Peaking Worldwide

Wood Mackenzie published its global levelized cost of electricity (LCOE) analysis on October 8, 2026. Four-hour battery storage came in cheaper than open-cycle gas turbines in all 43 markets where both were modeled, according to the Wood Mackenzie release. Single-axis tracker solar is the lowest-cost new-build technology in 43 of 48 modeled markets, and onshore wind leads in the other five.

Ahmed Jameel Abdullah, principal analyst at Wood Mackenzie, said: “This economic shift is decisive and widening.” He added that gas turbine shortages and rising fuel volatility are driving up peaking costs.

The regional results show how widely the pricing varies. In the Middle East and Africa, four-hour storage costs $120 per megawatt-hour in 2026 and falls 33% to $80 by 2035. Across Asia Pacific, China’s storage benchmark sits more than 55% below the regional average of $134 per megawatt-hour. In Europe, turnkey battery capital costs rose about 2%, the first increase in three years, as cell prices rebounded roughly 10% from their 2025 low.

Turbine Scarcity Widens the Cost Gap

TechCrunch reported the findings on October 9 and tied them to data center demand. AI data center developers have driven up turbine prices by buying nearly any available model. Open-cycle turbines take two to four years to procure, and waitlists for closed-cycle units extend into the early 2030s.

Utilities use open-cycle turbines as peaking plants, so higher turbine prices raise the cost of covering the hours of highest demand. Wood Mackenzie also finds solar the lowest-cost new-build option in nearly every modeled market, which positions storage as the partner that moves midday solar into the evening peak.

Turbine Backlogs Run Through 2030 Across Major Manufacturers

POWER Magazine’s September survey of turbine manufacturers shows why the lead times run long. GE Vernova reports 116 GW under contract, up from 100 GW three months earlier, with 53 GW in firm backlog and 63 GW under slot reservation agreements. The company expects at least 125 GW by year end and describes its heavy-duty production as mostly sold out through 2030, with more than half of 2031 production expected to be contracted by year end.

Aeroderivative units can be commissioned in about six months, while heavy-duty units may need about 18 months of site work after shipment. Heavy-duty machines shipping in 2030 and 2031 are expected to enter service in 2032 and 2033. Siemens Energy reports a 95 GW backlog, and Mitsubishi Heavy Industries reports 80 large-frame units totaling 35 GW. Hiroshi Nishio of Mitsubishi said: “Order pricing has not declined, and the profitability of newly booked projects continues to improve gradually.”

Developers combine the technologies. Pacifico Energy’s GW Ranch in Pecos County, Texas, is permitted for up to 7.65 GW and includes 1.8 GW of batteries and up to 750 MWac of solar, with first power expected in the first quarter of 2027. The mix shows a large load buyer pairing gas with storage to shorten the path to first power.

North American Solar and Storage Face Tariff and Equipment Pressure

The Wood Mackenzie analysis flags component price risk in North America. Utility-scale solar holds 168 GW of safe-harbored capacity, and module prices are expected to rise about 5% a year through 2030. Residential and commercial module prices are forecast to rise 6% in 2027 and 14% in 2028. North American storage LCOE falls 10% by 2060, with a cost spike expected after the investment tax credit phases out from 2038.

SEIA and Wood Mackenzie’s Q3 2026 Solar Market Insight adds the trade picture. A Section 232 action imposes a 15% tariff plus minimum import prices on polysilicon through modules, effective December 4, 2026. The Federal Communications Commission added foreign-produced inverters to its Covered List on July 28, and an August 26 executive order restricts imports of power generation equipment from covered foreign entities. Solar and storage together made up 70% of new U.S. electricity-generating capacity added in the first half of 2026.

PJM Interconnection Puts the Speed Premium in Practice

The PJM selections apply the cost finding to a live interconnection queue. PJM Interconnection (PJM) accepted the first three projects under its Expedited Interconnection Track on October 8: an 860 MW battery project in Crawford, Pennsylvania, an 800 MW battery project in Morrow, Ohio, both from ENGIE IR Holdings, and a 455 MW gas uprate at the Hunterstown plant in Adams, Pennsylvania, as Utility Dive reported. The three total about 2.1 GW and target mid-2029 service.

Batteries make up roughly 1,660 MW of that 2.1 GW. PJM calls the track one part of a broader response that includes a pending reliability backstop procurement, updates to surplus interconnection service rules and a reformed generator interconnection process. The American Public Power Association notes that the track also lets individual states accelerate selected projects based on their resource adequacy needs.

Safety Data Strengthens the Storage Case

Insurers and lenders weigh storage safety alongside cost. An Electric Power Research Institute (EPRI) analysis released October 5 found that the global failure rate for lithium-ion storage systems per GWh fell about 98% from 2018 to 2025 and 50% between 2024 and 2025, as Utility Dive reported. Annual failure rates for stationary systems range from 0.04% to 0.14%, which EPRI compares with 0.1% for oil-filled transformers.

About 93% of the safety incidents EPRI reviewed caused no injuries or fatalities, and no U.S. injuries or fatalities from storage failures have been reported since April 2019. Facilities commissioned before 2021 make up about 3% of global capacity, and indoor facilities fail more often and sustain more damage than outdoor ones. Lakshmi Srinivasan, EPRI principal investigator, said: “There are things we know in 2026 that were not necessarily understood in 2019 or 2020.”

The findings shape procurement. Owners underwriting onsite storage should specify outdoor siting or propagation barriers between units, current NFPA 855 compliance and gas detection inside enclosures, and should schedule risk assessments for any pre-2021 systems in a portfolio. Energy Storage News reports that EPRI could not isolate cell chemistry as a risk factor.

Efficiency Cuts the Base Load Beneath the Peak

Storage trims the peak, and efficiency lowers the base. JLL studied 4,437 offices in seven global markets and found that the most efficient buildings cost 43% to 75% less to run each year than the least efficient in the same city, a gap worth $1.58 to $5.13 per square foot annually. Across six markets, commercial electricity prices rose 11% to 91% faster than local inflation between 2020 and 2024, according to the JLL analysis of the efficiency premium.

Los Angeles shows the direction of travel: savings from top-performing offices rose 46%, from $2.78 to $4.06 per square foot between 2019 and 2024. JLL cites Lawrence Berkeley National Laboratory projections of $100 billion to $200 billion in cumulative U.S. power system savings by 2040 from grid-interactive efficient buildings. Pairing efficiency upgrades with storage lets one capital plan address both the size of the load and the shape of the peak.

Utility-Scale Findings Carry Property-Level Consequences

The Wood Mackenzie comparison covers utility-scale systems. Onsite storage economics depend on the local tariff, demand charges, interconnection cost and the site’s load shape, so each project needs its own model. The direction of the finding still bears on site decisions:

Time to power. A site waiting years for new utility capacity can add onsite storage to serve load growth in phases while the substation upgrade proceeds.
Demand charges. Storage that shaves peak draw lowers the largest variable line in a tenant’s utility bill, which supports occupancy and rent growth.
Procurement risk. Tariffs take effect in December. Owners comparing quotes should ask vendors who holds tariff exposure, which inverter supplier is specified and what transformer lead times apply.
Valuation. Every $1,000 of durable annual NOI improvement supports about $12,500 of asset value at an 8% cap rate. Demand charge savings that persist through the lease term flow directly into that math.

Frequently Asked Questions

Is battery storage cheaper than gas turbines?

Wood Mackenzie finds four-hour battery storage cheaper than open-cycle gas turbines in all 43 markets where both were modeled, on a utility-scale levelized cost basis.

How long does a gas turbine take to procure?

TechCrunch reports two to four years for open-cycle turbines and waitlists into the early 2030s for closed-cycle turbines.

What did PJM fast-track?

PJM accepted three projects totaling about 2.1 GW: two batteries (860 MW and 800 MW) and a 455 MW gas uprate, all targeting mid-2029 service.

Does the Wood Mackenzie finding apply to onsite storage?

The analysis covers utility-scale costs. Onsite results depend on tariffs, demand charges and interconnection costs at each site.

Sources

Reconfigurable Packs, Sodium-Ion and Silicon Anodes Extend EV Range and Battery Life

ChargedUp! — Tue, 20 Oct 2026 21:07:47 GMT

Photo by Markus Spiske on Unsplash

Three battery technologies now carry measured claims: reconfigurable packs from Chalmers University of Technology that extend lifetime by more than 20% in an idealized model, sodium-ion cells in production at 175 Wh/kg, and silicon-carbon anodes rated 20% to 40% denser than graphite. Each changes how far an EV travels, how long its pack lasts or how it performs in cold weather.

Key Takeaways

Chalmers University of Technology researchers report that reconfigurable battery packs extend lifetime more than 20% in an idealized model and defer replacement by about 14 months in a representative case.
Changan’s Nevo A06 uses a 45 kWh CATL sodium-ion battery with cell energy density up to 175 Wh/kg and carries more than 400 km of CLTC range.
Sila raised $300 million on July 21 to scale a silicon-carbon anode rated 20% to 40% denser than graphite at its Moses Lake, Washington plant.
Longer pack life supports used EV values and second-life storage, two variables that shape charging demand and onsite energy plans.

Reconfigurable Packs Bypass Weak Cells

A conventional EV battery pack connects its cells in fixed series, so the weakest cell sets the limit for the whole pack. Researchers at Chalmers University of Technology in Sweden studied packs that use switches and control systems to isolate or bypass degraded cells so the rest of the pack keeps working. The team published the results in Nature Communications (doi:10.1038/s41467-026-74951-8), and Scientific Frontline summarized the work on October 8.

In an idealized model where every cell is individually controlled, battery lifetime rises more than 20% for certain high-voltage vehicles. The researchers describe that figure as a theoretical upper bound. In a representative case of an 80 kWh pack driven 12,000 kilometers a year over an 18.8-year vehicle life, battery replacement is deferred by about 14 months.

The added hardware raises total pack cost by about 9%, below the break-even threshold of about 12%. When upfront cost stays below roughly 7% and annual mileage below 12,150 kilometers, the architecture is cost-effective in at least 99.7% of tested scenarios. The estimates assume prototype-scale volumes of 1,000 units. Benefits grow with the number of cells in series and rise substantially at 400 volts. Changfu Zou, professor of electrical engineering at Chalmers, said: “Reconfiguration is not an on-or-off choice. It is a spectrum.” Albert Škegro, the doctoral student who led the work, said: “For a private EV owner, this could mean postponing a battery replacement.”

No mass-produced car or truck uses the architecture yet. Volvo Cars has shown a concept called SmartCell, and a major manufacturer has begun road testing a prototype passenger car, according to the researchers. A companion study in Nature Energy (doi:10.1038/s41560-026-02131-5) quantifies how cell-to-cell inconsistency drives degradation.

Sodium-Ion Reaches Production With Cold-Weather Strength

Sodium-ion batteries replace lithium with sodium, a cheaper and more abundant material. The Changan Nevo A06, launched February 5, 2026, is described as the first mass-produced passenger vehicle powered by a sodium-ion battery, according to CarNewsChina. The pack is a 45 kWh unit from Contemporary Amperex Technology Co. Limited (CATL), branded Naxtra, with cell energy density up to 175 Wh/kg.

Range reaches more than 400 kilometers under the China Light-Duty Vehicle Test Cycle (CLTC), below the 510 and 630 kilometer ratings of the lithium-ion A06 variants. Cold weather is the advantage. Discharge power at minus 30 degrees Celsius is nearly three times higher than comparable lithium iron phosphate models, and the battery reportedly retains more than 90% of capacity at minus 40 degrees. Changan said its Avatr, Deepal, Nevo and Uni brands will progressively adopt the Naxtra battery.

Material costs add context. Wood Mackenzie expects lithium prices to roughly double in 2029 and reports that European turnkey battery capital costs rose about 2% in 2026 as cell prices rebounded roughly 10% from their 2025 low, a backdrop that gives alternative chemistries a pricing case. The Nevo A06 launched in China, so U.S. availability depends on trade policy and manufacturer plans. For properties in northern climates, cold-weather charging behavior is the variable to watch.

Silicon-Carbon Anodes Scale in Washington State

Silicon stores more lithium than the graphite used in most anodes, which raises energy density. Sila announced $300 million in private funding on July 21, 2026, led by Atreides Management and Sutter Hill Ventures with participation from 8VC, Bessemer Venture Partners, Matrix Partners and T. Rowe Price Associates funds, according to Pulse 2 and electrive.

Sila says its silicon-carbon anode offers 20% to 40% higher energy density than conventional graphite. The company began operations at its 160-acre Moses Lake site in fall 2025. Phase one has 2 GWh of capacity, and the site is designed to expand to 250 GWh of annual capacity over five years. Sila names no vehicle customers in the announcement, and target markets include EVs, drones, satellites, robotics and AI infrastructure.

Faster Charging Hardware Arrives Ahead of New Chemistries

Charging equipment is scaling alongside the cells. Paren’s Q3 2026 report, summarized by EV Infrastructure News, found that 73% of new U.S. fast-charging ports were rated at least 250 kW, up from 60% a year earlier. Non-Tesla ports rated 400 kW or more made up 35% of additions, up from 10%. Tesla added 303 ports at 500 kW across 26 new sites, and IONNA and Walmart added 378 and 344 ports at 400 kW or more.

Heavy-duty charging moves higher still. The Pilot and Tesla site in Ellabell, Georgia, opened October 9 with six stalls delivering up to 1.2 MW each, and Tesla says a Semi recovers 60% of its charge in 30 minutes. The EV Report lists 12 more sites under construction.

National fast-charger utilization held between 15.7% and 16.5% for five straight quarters, reaching 15.9% in the third quarter, according to the same Paren data. Higher power ratings raise the value of vehicles that accept them, and flat utilization places the emphasis on site selection and dwell time. Owners comparing stall power should match ratings to the vehicles that visit, since a pack that cannot accept 400 kW leaves that capacity idle.

Three Signals Show Which Technology Reaches U.S. Buyers First

Each technology sits at a different stage. Reconfigurable packs have academic cost models and a prototype in road testing but no production vehicle. Sodium-ion has a production vehicle, sold in China. Silicon-carbon anodes have a funded plant in Washington State and no named vehicle customer. Owners tracking the U.S. market should watch for three announcements: a U.S. automaker commitment to a switched-pack architecture, a sodium-ion model with a U.S. import path, and the first named vehicle program using Sila’s anode. The commercial case is visible in the Chalmers cost range. A hardware premium of about 9% sits below the 12% break-even, and the margin narrows or widens as volumes move from the 1,000-unit prototype assumption toward mass production.

Vehicle Prices Frame Technology Adoption

Pricing shapes which innovations reach buyers. Cox Automotive’s September EV Market Monitor puts the average new EV transaction price at $55,842, down 3.1% from a year earlier, with incentives near 11% of price. The premium over comparable conventional vehicles stands at $5,611, against an average of $8,665 in 2025.

The U.S. Energy Information Administration (EIA) reports that battery electric vehicles were 6% of new light-duty sales in the third quarter of 2026, down from 10% a year earlier, while hybrids reached 16% of sales. Luxury battery electric share fell from 31% to 12%. Average transaction prices for all new vehicles passed $50,000 for the first time this year.

A shrinking premium and a smaller EV share put pressure on cost. Technologies that lower pack cost or defer replacement carry the most weight in the mainstream segment, where buyers compare a total ownership figure against a $5,611 premium.

Longer Pack Life Shapes Charging Demand and Onsite Energy

Pack longevity feeds the used EV market. Manheim recorded used retail EV sales of about 124,000 units in the third quarter, up 11.4% from a year earlier, and expects EVs to rise from about 10% of off-lease supply in the first half to about 16% in the second half of 2026. Technologies that defer battery replacement protect residual values and keep more vehicles in service. Second-life use connects vehicles to distributed energy. The Chalmers team notes that reconfigurable packs make reuse of intact packs easier. Used packs repurposed as onsite storage give owners another source for peak shaving and backup power at a lower cost than new systems.

Three site decisions follow. Dwell-time charging stays valuable as range grows, because drivers charge for convenience and price. Cold-climate sites benefit from chargers sized for vehicles that hold power in low temperatures. Electrical rooms designed with spare capacity accommodate higher charging power as vehicles with new cell chemistries arrive. A property that adds $1,000 of annual net operating income from charging or storage supports about $12,500 of value at an 8% cap rate.

Frequently Asked Questions

What is a reconfigurable EV battery pack?

A pack that uses switches and controls to bypass degraded cells so the remaining cells keep working, rather than letting the weakest cell limit the whole pack.

How much longer could a reconfigurable pack last?

Chalmers reports more than 20% longer lifetime in an idealized model and about 14 months of deferred replacement in a representative case.

Are sodium-ion EVs on sale?

The Changan Nevo A06, launched February 5, 2026 in China, is described as the first mass-produced passenger vehicle with a sodium-ion battery.

What do silicon-carbon anodes change?

Sila says its anode provides 20% to 40% higher energy density than graphite, with phase one production of 2 GWh at Moses Lake, Washington.

Sources

PJM Fast-Tracks 2.1 GW of Generation as San Francisco Pauses Data Centers for 45 Days

ChargedUp! — Tue, 20 Oct 2026 20:49:56 GMT

Photo by Wesley Tingey on Unsplash

PJM Interconnection accepted its first three Expedited Interconnection Track projects, totaling more than 2,100 MW and due online in mid-2029, while San Francisco supervisors passed a 45-day citywide data center moratorium on October 6. Approvals now move at two speeds, and sites that pair local permitting support with deliverable power hold a clear advantage.

Key Takeaways

PJM Interconnection accepted its first three Expedited Interconnection Track projects on October 8, totaling more than 2,100 MW and targeting mid-2029 service.
Applicants need at least 250 MW, a commitment from a state siting authority to expedite permitting, and the ability to operate within three years. PJM approves up to 10 requests a year, and the track sunsets at the end of 2027.
The San Francisco Board of Supervisors passed a 45-day citywide data center moratorium on October 6, which could extend up to 22 months.
Permitting posture now separates sites that move quickly from sites that stall.

PJM Selects Two Batteries and a Gas Uprate

The Expedited Interconnection Track (EIT) accepted three projects on October 8, as Utility Dive and the American Public Power Association reported. ENGIE IR Holdings submitted two battery storage projects: 860 MW at the Wayne 345 kV site in Crawford, Pennsylvania, and 800 MW at the Galion 345 kV site in Morrow, Ohio. LS Power’s 455 MW uprate at the Hunterstown 500 kV facility in Adams, Pennsylvania, completes the group. All three are scheduled to enter service in mid-2029.

The track exists because supply has tightened. PJM describes little new generation in recent years while data centers push demand forecasts higher, and Utility Dive links the tight supply to a sharp rise in capacity costs that is raising utility bills in some areas.

State Permitting Support Opens the Door

The Federal Energy Regulatory Commission (FERC) approved the EIT in June 2026, and the application window opened July 31. Applicants must offer at least 250 MW of unforced capacity, hold a commitment from a primary siting authority to expedite site permitting, and be able to begin operating within three years. Projects are expected to sign a generation interconnection agreement within 10 months of submission.

PJM will approve up to 10 interconnection requests per calendar year in 2026 and 2027, taking proposals on a rolling basis until each year’s limit is reached. The process sunsets at the end of 2027. The permitting requirement ties the interconnection queue to state and local governance: the fastest path to the grid runs through a siting authority that has already said yes.

San Francisco Pauses Construction for 45 Days

San Francisco shows the opposite end of the same permitting spectrum. The Board of Supervisors passed a citywide data center moratorium on October 6, effective immediately for 45 days, as Mission Local reported and the San Francisco Standard covered. The measure halts construction of new data centers, including a proposed 160,000-square-foot facility at 1215 Michigan St. in Dogpatch, and pauses the planned expansion of the NOVVA data center at 400 Paul Ave. in Bayview from nine to 36 megawatts by 2028.

During the pause, the Planning Department will study effects on water, energy, air quality, land use and surrounding communities. If it finds significant environmental impacts, the moratorium could extend up to 22 months or lead to permanent controls. Supervisor Shamann Walton, who proposed the measure, said: “We need to know what these impacts are.” He added: “Until we know what that is, it needs to stop.” Sources close to Walton say he hopes the pause leads to a permanent ban, and his term ends in January 2027.

The definition is broad. The legislation covers any facility housing computing infrastructure for processing, storing or distributing electronic data, which brings mixed-use and industrial buildings that host computing tenants into scope for diligence.

Reliability Standards Define the Rules for Large Computational Loads

The North American Electric Reliability Corporation (NERC) announced on October 15 that stakeholders approved a package of standards for computational loads on a final ballot, as POWER reported and Utility Dive covered. The standards apply to AI data centers, crypto mining and other computational loads of at least 50 MW connected at 100 kV or above. The NERC Board of Trustees votes next, and adopted standards then go to FERC. FERC’s July order requires NERC to file initial standards and registration criteria by December 31, 2026.

The rules cover interconnection studies and modeling data, operating instructions from grid operators and protection coordination. NERC cites a July 2024 Eastern Interconnection event in which about 1,500 MW of data center load dropped offline. For sites with large computing tenants, the standards add study and modeling obligations before interconnection, which belongs in lease and development agreements.

Tight Markets Raise the Value of Delivered Power

CBRE’s North American Data Center Trends report for the first half of 2026 shows how scarce deliverable power has become. Vacancy across the eight primary markets stands at 1.4%, and Northern Virginia vacancy fell to 0.2% from 0.7% a year earlier. Developers have 7,481 MW under construction, up 24.8%, and more than 80% of that capacity is preleased.

Stu Dyer, CBRE executive vice president, said: “Power is the deciding factor in Northern Virginia right now.” CBRE expects power constraints and infrastructure bottlenecks to limit how quickly new capacity arrives. Sites with an interconnection path therefore command value that sites with land alone do not.

Large-Load Tariffs Move Cost to the Operator

Utilities increasingly pair new supply with new rate classes. A Microsoft agreement with NiSource, reported by Data Center Dynamics, adds about 1.1 GW to NiSource’s portfolio for a planned northern Indiana campus under a 20-year term, with power starting in 2028. The campus falls under a new large-load rate class in which users fund the generation and infrastructure needed to serve them. NiSource Generation Company holds a 600 MW, 2,400 MWh battery storage tolling agreement with an affiliate of AGP Group, with aggregate payments of about $2.2 billion over the term, according to a NiSource filing with the Securities and Exchange Commission.

Jeff Riles, Microsoft senior director of energy markets, said that “our data centers don’t increase electricity prices for other ratepayers.” The structure answers the same ratepayer concern that drives moratorium debates, and it gives owners a template: a site that funds its own capacity and storage meets a regulator’s affordability test.

Statehouses Take Up Moratorium Proposals

Virginia shows the next phase. Senator Russet Perry introduced Senate Bill 843, which would bar state agencies from approving data center planning applications for three years beginning July 1, 2027, as Data Center Dynamics reported. Perry said: “We cannot keep rubber-stamping new data centers when we can’t even manage the ones already built.” New York, Texas and Oregon have introduced statewide moratorium bills, and Loudoun County is advancing a 12-month pause on legislative approvals.

The Davidson County Board of Commissioners in North Carolina voted 4-2 on September 28 to put a four-month moratorium on its October 26 agenda, per WUNC. Together with the PJM track and the NERC standards, the proposals show approvals and obligations tightening at the same time.

Two Speeds Reshape Site Value

Permitting friction extends beyond data centers. SEIA reports that permitting issues affect an estimated 30% of early-stage solar projects, per its Q3 2026 Solar Market Insight, which places local approval risk alongside interconnection risk for onsite generation.

The two actions mark the range of outcomes for power-intensive projects. PJM rewards sites that bring both a state permitting commitment and a deliverable megawatt count. San Francisco shows that a project without community review can stop for months or longer.

Screen for siting authority support. A parcel with documented state or local backing is more valuable to a generation developer or large-load tenant than a parcel without it.
Map substation adjacency. The first EIT projects sit at 345 kV and 500 kV interconnection points. Land near high-voltage substations carries optionality for storage or generation.
Use the window. The EIT approves only 10 requests a year and sunsets at the end of 2027, so developers with ready sites have a narrow filing period.
Add moratorium risk to diligence. Entitlement reviews for any asset with computing tenants should list pending local moratoria and the definition each ordinance uses.

The valuation effect is direct. Time to power sets rent commencement dates, and every $1,000 of durable annual NOI supports about $12,500 of asset value at an 8% cap rate. A site that reaches power a year sooner starts collecting rent a year sooner.

Frequently Asked Questions

What is the PJM Expedited Interconnection Track?

A temporary process approved by FERC in June 2026 that accepts up to 10 large generation requests a year in 2026 and 2027 from projects of at least 250 MW with state permitting support and a three-year path to operation.

Which projects did PJM accept first?

An 860 MW battery in Crawford, Pennsylvania, an 800 MW battery in Morrow, Ohio, and a 455 MW gas uprate in Adams, Pennsylvania, totaling more than 2,100 MW and targeting mid-2029.

What does the San Francisco moratorium cover?

A 45-day citywide halt on new data center construction passed October 6, 2026, which could extend up to 22 months if the Planning Department finds significant environmental impacts.

When does the PJM track end?

The Expedited Interconnection Track sunsets at the end of 2027.

Sources

Electrification Roundup: News You May Have Missed (October 21, 2026 Edition)

ChargedUp! — Tue, 20 Oct 2026 20:27:43 GMT

43 of 43. That is the count of modeled markets where four-hour batteries now cost less than open-cycle gas turbines, according to Wood Mackenzie. Turbine backlogs that run through 2030, 950,000 storm outages in the Southeast and a 50 MW threshold for new data center reliability rules show that delivered power sets site value.

Grid Stress, Storms and Resilience Economics

Hurricane Isaias peaks near 950,000 outages as underground lines outperform overhead

Isaias made landfall as a Category 2 storm near the Florida-Alabama border, and the Edison Electric Institute put peak outages at about 950,000 customers. Florida Power and Light reported 435,000 outages and said underground lines performed more than eight times better than overhead lines in initial forensics, while its smart grid technology avoided more than 130,000 outages. The Energy Information Administration reported about 1.3 million barrels per day of Gulf crude production shut in ahead of landfall. Owners in storm-exposed markets can weigh feeder undergrounding, onsite storage and backup generation against outage exposure in tenant retention.

SOURCES

PJM, ERCOT and SPP set summer peak load records

PJM reached 162.6 GW on July 2, up 1.3% from its 2025 record. ERCOT reached 91.1 GW on July 22, 6.5% above its 2024 record, and the Southwest Power Pool reached 58.0 GW on July 27, 3.5% above its 2023 record. The EIA expects commercial sector electricity demand, which includes data centers, to grow 2.8% in 2027, so capacity pressure carries into the next summer.

SOURCES

FERC and NRC commissioners meet October 22 on load growth and grid reliability

The Federal Energy Regulatory Commission (FERC) holds its annual Reliability Technical Conference October 21, and FERC and Nuclear Regulatory Commission commissioners meet October 22 at NRC headquarters on grid reliability, managing load increases, nuclear power and cybersecurity. NERC staff will brief the commissioners. NERC forecasts summer peak demand to grow by 224 GW over 10 years, a 24% increase from the 2025 peak.

SOURCES

Turbine and transformer lead times keep new capacity scarce

GE Vernova reports 116 GW under contract and describes heavy-duty production as mostly sold out through 2030. Transformer lead times for high-capacity units run as long as four years, according to PwC analysts cited in a May report, and Wood Mackenzie measured generator step-up transformer demand up 274% from 2019 to 2025. Equipment queues set the pace for any site that needs new service capacity.

SOURCES

Electrification Economics at the Property Level

EIA forecasts commercial electricity at 14.00 cents per kilowatt-hour in 2026 and 14.21 in 2027

The October Short-Term Energy Outlook puts commercial electricity at 14.00 cents per kilowatt-hour for 2026, up from 13.41 cents in 2025, and residential at 18.21 cents. Henry Hub natural gas averages $3.48 per million Btu in 2026 and Brent crude is forecast at $105 per barrel in the fourth quarter. Operating expense lines tied to electricity keep rising, which supports underwriting for demand charge management and onsite generation.

SOURCES

Winter bills: electricity up 4%, heating oil up 21%, natural gas down 9%

The EIA forecasts average household electricity bills up 4% this winter, heating oil expenditures up 21% with prices 34% higher, natural gas down 9% and propane down 3%. Electricity heats more than 40% of U.S. homes. Multifamily owners that pass through utility costs face the largest exposure in electric-heat buildings.

SOURCES

JLL: the most efficient offices cost 43% to 75% less to run

JLL studied 4,437 offices in seven markets and found a gap of $1.58 to $5.13 per square foot annually between the most and least efficient buildings in each city. Commercial electricity prices rose 11% to 91% faster than local inflation across six markets from 2020 to 2024. JLL’s earlier research cites power premiums of 49% in some cases for properties with dependable power.

SOURCES

Solar, Storage and VPPs

Solar installs rise 45% in the second quarter as safe-harbored pipeline reaches up to 240 GWdc

The Solar Energy Industries Association (SEIA) and Wood Mackenzie report 11.4 GWdc installed in the second quarter. The commercial segment added 638 MWdc, up 11% from a year earlier, with California at 256 MWdc. Annual additions are forecast near 44 GWdc through 2031, and permitting issues affect an estimated 30% of early-stage projects.

SOURCES

Pivot Energy closes a $173 million term loan on 51 community solar projects

The 135 MWdc portfolio spans six states, and lenders are First Citizens Bank, Huntington Bank and BankUnited. The loan is Pivot’s first term financing and refinances projects from its construction warehouse. Take-out debt for distributed solar signals lender appetite for rooftop and ground-lease income streams.

SOURCES

EPRI: battery storage failure rates fall 98% from 2018 to 2025

The Electric Power Research Institute reports that failures per GWh fell 98% globally from 2018 to 2025 and 50% from 2024 to 2025. Annual failure rates of 0.04% to 0.14% compare with 0.1% for oil-filled transformers. Indoor facilities fail more often than outdoor ones, and EPRI recommends risk assessments for systems commissioned before 2021.

SOURCES

Small-scale solar generation reaches 92,979 GWh, up from 18,812 GWh a decade ago

EIA data show generation from systems under 1 MW grew about fivefold since 2016. California produced 37% of the total in 2025, with Arizona, Texas and Florida following. Growth has slowed since 2022, and the EIA expects solar to supply 9% of U.S. generation by 2027, up from 7% in 2025.

SOURCES

Policy and Market Rules

FERC drafts a NEPA overhaul for natural gas projects

FERC issued a draft policy statement (docket PL26-3-000) that ends its request for air dispersion modeling from applicants for Natural Gas Act projects. Comments are due November 16. Chairman Laura Swett called the effort surgical, strategic, aggressive reform. FERC also launched its first LNG authorization program on October 15. Faster gas permitting affects the timeline for onsite and utility generation near large loads.

SOURCES

FERC orders further PJM interconnection compliance filings

At its October 15 meeting, FERC accepted in part and rejected in part PJM’s tariff revisions complying with Order Nos. 2023 and 2023-A on generator interconnection and directed further compliance filings (docket ER24-2045-005). FERC also granted a 24-month commercial operation extension to a Midwest wind project and accepted the 2027 budgets for NERC and the regional entities.

SOURCES

FCC inverter restrictions and a December 4 solar tariff change procurement

The Federal Communications Commission added foreign-produced power inverters to its Covered List on July 28. New models cannot be authorized, and previously authorized models are not affected. Conditional approval applications are due by January 1, 2028. A Section 232 tariff of 15% on polysilicon through modules takes effect December 4. Owners should assign FCC authorization risk to vendors by contract.

SOURCES

Local Governance and Federal Policy

Loudoun County moves to pause data center and substation approvals for up to 12 months

The Board of Supervisors considers a resolution October 20 that pauses final votes on data center and substation applications requiring legislative approval, retroactive to September 15. The county says its legal opinion found a moratorium on approvals is not lawful, so it chose a pause of up to 12 months, the maximum under Virginia law. The board may grant exceptions for grid reliability.

SOURCES

Davidson County, North Carolina, schedules an October 26 moratorium vote

Commissioners voted 4-2 on September 28 to add a four-month data center moratorium to the October 26 agenda after a 3-3 deadlock five weeks earlier. Surry County approved a 24-month moratorium in July, and Greensboro and Yadkin County have weighed pauses. A developer withdrew a Raleigh annexation request on August 15.

SOURCES

Virginia Executive Order 22 bans nondisclosure agreements on state data center projects

Governor Abigail Spanberger signed the order September 18. It bans nondisclosure agreements among state agencies for data center projects, speeds noise regulations, reviews backup generation and creates a toolkit for localities. Her legislative priorities include requiring local approval for data centers above 25 MW. Developers should expect public process and disclosure to precede entitlement.

SOURCES

EV Charging in Real Places

U.S. fast charging passes 80,000 ports as new sites grow larger and faster

Paren counts 80,964 fast-charging ports at 14,614 locations after 4,106 additions in the third quarter. Of the new ports, 73% are rated at least 250 kW, up from 60% a year earlier, and new non-Tesla sites average five ports. National utilization held at 15.9%, and the Tesla non-member price rose 15% to 56.9 cents per kilowatt-hour. Tesla’s share of ports fell from 54.3% to 49.3%.

SOURCES

Pilot and Tesla open a six-stall, 1.2 MW Megacharger site in Georgia

The Pilot travel center in Ellabell, Georgia, opened October 9 with six heavy-duty stalls, each delivering up to 1.2 MW. Tesla says a Semi recovers 60% of its charge in 30 minutes. Twelve more sites are under construction along I-5, I-10 and other freight corridors in California, Georgia, Indiana, Nevada and Texas, with four to eight stalls each.

SOURCES

A Montréal airport terminal brings 120 Level 2 chargers online

Wallbox and edp électrique deployed 120 chargers at the YHU Terminal at Aéroport métropolitain de Montréal, with 48 more planned for a building under construction. The Level 2 hardware tops out at 11.5 kW, which suits employees and long-stay parkers. The project shows dwell-time charging at a transport hub in a cold-climate market.

SOURCES

EV Market Signals

Ember: EVs saved oil importers about $20 billion from March to August

Ember estimates 200 million barrels displaced, with China at $14 billion and European Union countries at $3.1 billion. Fifteen countries passed the United States in battery electric sales share this year, and 49 of 56 tracked countries now post a higher share than the 6% recorded in the United States.

SOURCES

EIA: hybrids reach 16% of new sales while battery electric share drops to 6%

Hybrid, battery electric and plug-in hybrid vehicles together made up 23% of third quarter new light-duty sales, down from 24% a year earlier. Luxury battery electric share fell from 31% to 12%, and the average new vehicle transaction price passed $50,000. Cox Automotive puts electrified sales near 25% of the quarter.

SOURCES

CATL’s battery-swap network reaches 2,520 stations as Huawei’s car unit joins

Huawei-backed automotive technology company Yinwang signed a cooperation framework with CATL and its battery-swapping subsidiary on October 19. The agreement aims to integrate Huawei’s intelligent-driving systems with CATL’s Choco-swap network, which reached 2,520 stations across approximately 200 Chinese cities as of September 29, up from 1,020 at the end of 2025. CATL is targeting more than 3,000 stations by year-end. The companies envision automated battery exchanges taking 99 seconds, although no compatible vehicle models or launch dates were announced. The partnership highlights China’s growing investment in battery swapping as an alternative to conventional plug-in charging.

SOURCES

Data Center Demand and Innovation

Amazon and AEP explore up to 960 MW of X-energy reactors at a retired Indiana coal site

The joint development agreement covers 12 Xe-100 reactors of 80 MW each at the retired Breed Generating Station in Sullivan County, subject to a final investment decision. Amazon would fund development and be the first power buyer, and AEP says the agreement is designed to shield existing customers from project risk. Amazon targets more than 5 GW of U.S. nuclear capacity by 2039.

SOURCES

Pacifico Energy secures 7.65 GW gas-generation permit for Texas private-grid campus

Pacifico Energy has secured a Texas air permit for up to 7.65 GW of natural-gas generation at GW Ranch in Pecos County, a private-grid campus designed to supply hyperscale data centers. Plans also include 1.8 GW of battery storage and up to 750 MWac of solar. Pacifico targets initial power delivery in 2027 and more than 5 GW of capacity by 2031. The company is separately developing Fort Spunky in Hood County, with 432 MW of planned gas generation and 80 MW of batteries. Turbine manufacturer Ansaldo Energia has contracted to supply eight gas turbines for a Pacifico Texas data-center power project, with deliveries beginning in 2027, but has not publicly identified the project receiving them.

SOURCES

Wisconsin projects 72% of peak growth from three data center campuses

The Public Service Commission of Wisconsin’s draft assessment projects peak demand rising from 14.2 GW to more than 20 GW by 2032, with more than 72% tied to data center campuses in Mount Pleasant, Port Washington and Beaver Dam. We Energies filed an engineering plan for a 750 MW gas plant, Fox North, next to its Fox Energy Center in Wrightstown, with commercial operation expected in late 2032. The company has not said the plant would serve a data center.

SOURCES

The True Cost of Power: A 3.7 Percent Inflation Shock Just Tied Your Energy Bill to Your Interest Rate

ChargedUp! — Wed, 14 Oct 2026 16:46:43 GMT

Photo by Katharina Kammermann on Unsplash

The September Consumer Price Index came in hot at 3.7 percent, led by energy, and the bond market reacted instantly. The 10-year Treasury jumped to about 5.28 percent, the 30-year to 5.58 percent, and the odds of a Federal Reserve rate hike at the end of October roughly doubled to near 50 percent. For commercial owners, the report exposed a trap. When inflation is energy-led, the same energy costs raising a building's operating expenses are also feeding the inflation that drives up its cost of capital. Energy now hits owners on both fronts at once, through the meter and through the rate, which makes controlling it the rare move that defends both net operating income and financing.

Key Facts at a Glance

September headline CPI accelerated to 3.7 percent year over year, above the 3.6 percent forecast, with core at 2.6 percent, and energy was the main driver.
The 10-year Treasury jumped to about 5.28 percent and the 30-year to 5.58 percent on the report.
Market-implied odds of a late-October rate hike roughly doubled to about 50 percent, up from near 22 percent before the release.
Brent crude held near $106 and WTI near $95 on Middle East attacks, with analysts saying the Russian diesel deal will not meaningfully ease fuel prices.
Natural gas stayed the moderate anchor near $3.20 per million BTU, firming with cold weather but not spiking.

What the Inflation Report Said

The number that moved markets this morning was the September CPI. The U.S. Bureau of Labor Statistics reported headline inflation at 3.7 percent year over year, above the 3.6 percent consensus, with core inflation at 2.6 percent and a hot 0.3 percent monthly core reading. Higher energy prices were the main driver, though the pressure was fairly broad. The bond market did not wait. The 10-year Treasury, the benchmark for commercial mortgage pricing, jumped to about 5.28 percent and the 30-year to 5.58 percent, and futures lifted the odds of a rate hike at the October 28 meeting to roughly half, from about one in five the day before.

The Trap: Energy-Led Inflation Hits You Twice

Here is the link that matters for a building owner, and it is easy to miss in the market noise: This inflation reading was driven by energy. That means the cost of power is doing two things to a commercial property at the same time, and they compound.

The first is direct. Higher energy prices raise a building’s operating expenses, and energy is a quarter to a third of operating costs for a typical commercial building. That flows straight out of net operating income. The second is indirect, and larger. Energy-led inflation is precisely what is pushing the Federal Reserve toward higher rates and driving the 10-year toward levels that reprice every refinancing and every valuation. The same barrel and the same kilowatt-hour that inflate the utility bill are inflating the cost of capital. A building owner feels energy through the meter and, a step removed, through the mortgage.

This is why energy cost has become more than an operating line. In an energy-led inflation, the one expense an owner can control is also the one input to the macro story an owner can act on. Cutting a building’s energy use does not move the national CPI, but it is the only lever that defends against both sides of the squeeze that CPI just tightened.

The Fuel Side: The Headline Did Not Reach the Meter

On the energy complex itself, the week delivered a lesson in the gap between a policy headline and a building’s bill. Brent crude held near $106 and WTI near $95 as Houthi strikes on Saudi energy facilities and tanker attacks in the Strait of Hormuz kept a floor under prices. The much-discussed US-brokered deal to bring Russian diesel to market was supposed to ease the distillate squeeze. It did not reach the meter. Goldman Sachs and other analysts concluded the added supply will not meaningfully lower fuel prices, because the shortage is a refining-capacity problem, not a raw-supply one. For owners heating with oil or running diesel, the relief was a headline, not a line-item.

Natural gas remains the shelter. Henry Hub held near $3.20 per million BTU, firming modestly as cold weather approaches but far from a spike, kept in check by strong domestic production. The split this column has tracked for weeks holds: buildings on natural gas and on self-generated power are insulated on the fuel side, while oil-heated and diesel-dependent properties absorb the volatility.

What This Means for Owners

The practical conclusion is sharper than usual because the two fronts converged on a single cause. An owner cannot lower the national inflation rate or the Treasury yield. But an owner can lower the building’s energy cost, and in an energy-led inflation that single move does triple duty. It cuts operating expense directly. It lifts net operating income and, through it, the value that a rising cap rate is eroding. And it reduces the building’s exposure to the fuel volatility feeding the inflation in the first place.

The playbook is the one this issue lays out in full. For owners facing maturities, this week’s deep dive on the 6 percent scenario shows how to stress-test the capital stack before the refinancing hits. For the energy side, the features on behind-the-meter storage and virtual-power-plant revenue, on the winter fuel switch away from heating oil, and on the data-center forces reshaping grid cost, together describe how to turn the meter from a liability into a controllable asset. The roundup carries the supporting detail, from the commercial-solar tax-credit deadline to the transformer bottleneck.

Two financing and revenue tools are worth keeping on the list as owners act. Commercial Property Assessed Clean Energy (C-PACE) offers fixed-rate funding repaid through the property tax bill that does not compete with senior debt, a useful bridge when conventional capital is expensive. And enrolling a building’s controllable loads and storage in a virtual power plant converts that flexibility into a contracted payment. Neither is a cure, but both are resources worth evaluating against the specific building and market.

The Bottom Line

The September inflation report did more than push rates up. It revealed that energy sits on both sides of the squeeze facing commercial real estate, raising the operating bill and feeding the cost of capital at once. That is unwelcome news for owners who treat power as a fixed expense, and clarifying news for those who do not. In an energy-led inflation, the building that controls its own power is hedged against the one force now driving both its costs and its financing. The meter, it turns out, was never just an operating line. This week it became a macro position.

Sources

U.S. Bureau of Labor Statistics, Consumer Price Index: https://www.bls.gov/cpi/
CNBC, 10-year Treasury yield jumps as September core inflation runs hotter than expected: https://www.cnbc.com/2026/10/14/us-treasury-yields-cpi-inflation-report.html
Federal Reserve Bank of St. Louis (FRED), 10-year Treasury yield: https://fred.stlouisfed.org/series/DGS10
EnergyNow, oil prices rise as attacks on Saudi energy facilities heighten supply fears: https://energynow.com/2026/10/oil-prices-rise-as-attacks-on-saudi-energy-facilities-and-middle-east-tankers-heighten-supply-fears/
U.S. Energy Information Administration, Short-Term Energy Outlook: https://www.eia.gov/outlooks/steo/

ChargedUp! Moves to Substack to Foster Continued Growth

ChargedUp! — Wed, 14 Oct 2026 16:12:52 GMT

Photo by Daniel Thomas on Unsplash

Our publication has undergone big changes over the past 12 months. First, we expanded our editorial focus beyond EV charging to include all electrification efforts across eight content pillars. Then, we transferred to new management under the ownership of marketing agency PublioSTUDIO. Our move to Substack reflects our latest chapter as a media property that continues to evolve in response to how audiences discover and engage with information.

Why Substack?

Substack serves as a leading all-in-one digital platform for publishers, podcasters, journalists and independent creators. It allows these voices to amplify their messages through long-form articles, livestreams and real-time conversation. For ChargedUp!, it expands our capabilities to foster conversation among real estate owners, facilities managers and planners about how to respond to today’s energy transition efficiently, equitably and sustainably.

What Readers Can Expect

A cleaner design: Substack offers the functionality of a modern media platform. Moving here allows our team to spend less time on technical configuration and more energy on content and audience engagement.
An enriched reader experience: Readers who join the Substack community can engage with ChargedUp! through a live feed, interactive chats and newspaper-style home page. As always, we’ll continue to deliver weekly stories to your inbox, along with facilitating dialogue on LinkedIn and all of your preferred social platforms.
Expanded partnerships: Our new home offers greater opportunity for companies to reach decision-makers with clarity, authority, and trust. To inquire and learn more, visit our Advertising and Sponsorship Opportunities page.
What doesn’t change: Quality reporting and reader commitment.

What’s Ahead

Same publishing cadence: We’ll continue to publish new stories each Tuesday along with Wednesday’s newsletter and True Cost of Power column. Current subscribers will automatically remain on our mailing list.
Current subscribers who stay on the list are directed to the new platform automatically. No action is required.
Domain transfer: For a brief period, new stories will be posted at chargeduppro.substack.com. Soon, the ChargedUp! domain will point to Substack directly, and you’ll be able to find all our content.
In-app experience: Create a Substack account unlocks the live feed, short-form updates and chats. Should you choose to join us, we recommend using the same address where you receive ChargedUp! emails.

Support Our Transition

Share your feedback: Let us know what works in the new format and areas where we can improve. Email us at info@chargeduppro.com, submit your comments here, or contact us directly on social media or Substack.
Complete our survey: Complete our reader survey to let us know the content and formats you’d like to see in the future.

We look forward to continuing to serve our growing reader community. Thanks for your readership and support.

Electrification Roundup: News You May Have Missed (10/14/26 Edition)

ChargedUp! — Wed, 14 Oct 2026 14:47:27 GMT

Grid Stress, Storms and Resilience Economics

Oil climbs back above $107 on a Gulf storm and Middle East attacks

Brent traded above $107 and WTI near $94 as a Gulf of Mexico hurricane shut in offshore production and tanker attacks continued in the Strait of Hormuz, even as exports recovered toward pre-conflict levels. For owners, the signal is continued fuel-price volatility heading into winter, concentrated in oil-linked fuels.

Sources: Trading Economics, Brent crude · EnergyNow, oil ends week higher as hurricane disrupts US Gulf production

Natural gas stays the anchor as production eases but Permian output holds

US natural gas production dipped on pipeline maintenance even as warm-weather cooling demand rose, yet strong Permian output kept Henry Hub near $3.20 per million BTU. Cheap, stable gas is the reason the broader power system has not spiked, and why gas-heated and electric buildings are insulated this winter.

Sources: Trading Economics, natural gas

Transformer and grid-equipment lead times stay stretched

High-voltage transformers and switchgear remain in short supply, with multiyear lead times that can strand a project even after it clears the interconnection queue. For developers, securing equipment is now a scheduling risk on par with financing and permitting.

Sources: Utility Dive, transformer supply bottleneck threatens grid as load grows · Manufacturing Mag, grid transformer shortage and three-year backlog

Electrification Economics at the Property Level

This winter’s fuel split cuts both ways: gas and propane users catch a break

While heating-oil costs climb, EIA’s winter outlook expects natural gas and propane households to pay about the same or slightly less than last year on full storage and ample supply. For owners, the divergence is a reminder that the fuel a building burns, not just the weather, sets the winter bill.

Sources: EIA, mixed outlook for energy expenditures this winter

Commercial electricity rates keep grinding higher

National commercial electricity rates continue to rise year over year as utilities recover grid-modernization spending and data-center demand lifts wholesale costs. The increase lands on commercial bills regardless of a building’s own consumption, making peak management and onsite generation the practical offsets.

Sources: U.S. Energy Information Administration, Short-Term Energy Outlook

Office distress climbs even as discount buyers circle

Office CMBS distress remains near record levels with a large share of maturing office loans troubled, yet cash buyers are stepping in at steep discounts. For those acquiring repositioning plays, energy retrofits that cut operating cost and lift net operating income are becoming part of the value-add playbook.

Sources: CRE Daily, cap rates may still have room to rise in 2026 · 24/7 Wall St, commercial real estate’s trillion-dollar refinancing wall

Solar, Storage and VPPs

ENERGYRE closes $815 million, a record South Carolina solar financing

ENERGYRE closed one of the largest solar-only financing packages in South Carolina history, a sign that capital for distributed and utility-scale solar remains available even as traditional real estate debt tightens. For owners, abundant project capital is what makes third-party-owned onsite power viable without upfront cost.

Sources: PR Newswire, ENERGYRE closes $815 million financing

Storage financing keeps flowing: GridStor and Permanent Power close new deals

GridStor secured $220 million and Permanent Power Company raised $600 million for solar-and-storage projects, part of a steady stream of capital into grid-edge assets. The volume signals that lenders and investors view distributed storage as a bankable, cash-flowing asset class.

Sources: Mercom Capital, GridStor secures $220 million · Mercom Capital, Permanent Power secures $600 million

Colorado’s Xcel virtual power plant advances under state mandate

Colorado law requires Xcel to run a performance-based virtual power plant program, and the utility’s advanced VPP, built with Itron and Tesla, continues to develop. For commercial owners in the state, it is another market where onsite flexibility can be compensated.

Sources: Utility Dive, Colorado law requires Xcel VPP with performance-based tariff · Itron, Xcel Energy to deploy advanced VPP in Colorado with Itron and Tesla

Policy and Market Rules

FERC directs Southwest Power Pool to revise its tariff for data centers

FERC ordered the Southwest Power Pool to revise its tariff to expedite data-center development, extending the federal push on large-load rules beyond PJM. The decisions shape how quickly, and on whose dime, large loads connect to the grid.

Sources: Akin Gump, FERC directs SPP to revise tariff for data center development

FERC’s large-load overhaul puts every data center over 20 MW in scope

FERC has directed grid operators to revise or justify how large loads connect, with the rulemaking reaching loads as small as 20 megawatts. The outcome determines cost allocation and interconnection timelines that ripple into commercial power prices.

Sources: White & Case, FERC orders grid operators to revise interconnection rules for large loads · Utility Dive, takeaways from FERC’s data center interconnection decision

The real commercial-solar deadline is December 31, 2027

The July 2026 construction-start safe harbor for the 30 percent commercial solar Investment Tax Credit has passed, and projects that missed it can still claim the credit only if placed in service by December 31, 2027. New sourcing and domestic-content rules compress timelines further, though storage retains a longer runway.

Sources: Internal Revenue Service, Clean Electricity Investment Credit · Native Solar, the 2026 ITC deadline for commercial solar

Local Governance and Federal Policy

Colorado regulators call Xcel’s grid data ‘totally useless’

Colorado regulators questioned whether Xcel will comply with demand-response and grid-transparency expectations tied to data-center load, calling the utility’s grid data inadequate. The dispute is a home-state window into the broader fight over data-center cost and transparency.

Sources: Energy-Storage.News, Colorado regulators question Xcel grid data

Data-center moratoriums keep spreading across states

More states and localities added moratoriums or restrictions on data-center development, driven by concerns over power demand, water use and rising bills. Entitlement and siting risk continues to climb for power-intensive projects.

Sources: Rockefeller Institute, more moratoriums on data centers · MultiState, voters target data centers with local and statewide ballot measures

Data centers emerge as a flashpoint in 2026 races

Data-center siting, power demand and tax incentives are becoming campaign issues in the 2026 races, adding political uncertainty to project timelines. For developers, local and electoral risk now sits alongside utility service as a gating factor.

Sources: The National Desk, data centers emerge as a flashpoint in 2026 races

EV Charging in Real Places

EV Realty opens its flagship 9-megawatt truck-charging hub

EV Realty brought its Inland Empire truck-charging hub online, with 76 ports and 9 megawatts on a major freight corridor, moving from land acquisition to operation. It underscores that power-equipped industrial land is becoming its own real estate asset class.

Sources: CCJ, EV Realty opens flagship truck-charging hub

A developer will build a 4-megawatt fleet-charging depot in the Bay Area

Renewable Properties announced a 4-megawatt fleet-charging depot in the San Francisco Bay Area, another example of real estate developers treating charging-ready sites as a product. For logistics landlords, charging capacity is becoming a leasing differentiator.

Sources: EV Infrastructure News, Renewable Properties to build 4 MW fleet charging depot

EV Market Signals

Used EV demand stays the steadier signal after the credit lapse

Recurrent’s latest report shows used electric vehicle demand holding as prices settle, a more durable signal than new sales following the September 30 federal credit expiration. Used EV owners are more likely to charge away from home, favoring multifamily, workplace and retail sites.

Sources: Recurrent, used electric vehicle buying report

US EV sales adjust, not collapse, after the credit ended

A year into the post-credit market and weeks after the latest expiration, US EV sales are adjusting rather than cratering, with the market finding a new level. Owners should underwrite charging to observed local utilization rather than national headlines.

Sources: OPB, one year after the end of the EV tax credit

Record diesel strengthens the fleet case for electrification

With retail diesel near record highs and EIA raising its outlook, the total cost of ownership math increasingly favors electric fleets. For logistics-adjacent property, that supports demand for onsite and depot charging.

Sources: DTN, ULSD futures and diesel market · U.S. Energy Information Administration, Short-Term Energy Outlook

Data Center Demand and Innovation

NRG advances a 1.2-gigawatt hyperscaler supply deal amid a Texas pause

NRG Energy continues to advance a roughly 1.2-gigawatt power supply deal with a hyperscaler even as Texas weighs slowing new data-center connections. Secured power, not land, remains the gating factor, which keeps onsite and behind-the-meter generation at a premium near data hubs.

Sources: Utility Dive, NRG nears 1.2-GW hyperscaler deal amid Texas pause

NERC forecasts peak demand up 24% over a decade on data-center loads

The North American Electric Reliability Corporation raised its 10-year peak-demand forecast by about 24 percent, driven overwhelmingly by new data-center load. The scale of the revision underscores why grid capacity, and the cost of it, will keep climbing for every connected building.

Sources: Utility Dive, NERC 10-year peak demand forecast jumps 24% on data center loads

The Data Center Next Door: How the AI Power Race Reshapes Your Reliability, Your Rates and Your Community

ChargedUp! — Wed, 14 Oct 2026 14:09:46 GMT

Photo by sergey raikin on Unsplash

The AI data center boom is now the dominant force on the US grid, and it reaches every commercial building through three channels: reliability, rates and local politics. Hyperscalers are contracting the scarcest asset in energy, firm power that exists today, with Google signing roughly 3,590 megawatts from Constellation one week after Amazon’s Calvert Cliffs deal. Regulators are writing new reliability rules for these loads, and their demand is pushing wholesale power costs up across regions. Meanwhile, local fights over data center siting are turning into a political risk for development. An owner controls none of this directly, which is exactly why it belongs in their risk planning.

Key Facts at a Glance

Google signed a 20-year agreement for about 890 megawatts of new nuclear capacity plus a 15-year, 2,700-megawatt supply deal with Constellation, roughly 3,590 megawatts in total across Illinois, New Jersey and Pennsylvania.
It followed Amazon’s Calvert Cliffs deal by a week, underscoring a race for firm, carbon-free power that already exists.
NERC set mandatory reliability rules for large loads at 50 megawatts and 100 kilovolts, after grid disturbances tied to sudden data center load losses.
PJM wholesale power costs are running roughly 50 percent higher, with the grid’s market monitor attributing about 9 percent of 2026 wholesale costs to data center load.
Local data center siting fights are intensifying, with a Memphis moratorium vote collapsing into protests and moratoriums spreading across states.

The Race for Existing Power

The defining move is hyperscalers contracting firm power directly. Google signed a deal with Constellation for roughly 890 megawatts of new nuclear capacity on a 20-year agreement, plus 2,700 megawatts of supply from existing plants, about 3,590 megawatts across Illinois, New Jersey and Pennsylvania. It came a week after Amazon’s deal to uprate Maryland’s Calvert Cliffs plant. The pattern is unmistakable: the scarcest asset in American energy is not a reactor that might arrive in the 2030s, it is firm, carbon-free power available now, and the largest buyers are contracting it for decades.

For a commercial owner, the read-through is about scarcity. When hyperscalers lock up the firm power that already exists, less of it is available to everyone else, and the price of what remains rises. The owner is not competing for a reactor, but is competing, indirectly, for the same megawatts and the same grid capacity.

How Power Reaches Your Building, Part 1: Reliability

The first channel is reliability. Data center loads are large, concentrated and can drop off the grid suddenly, and those sudden losses have caused disturbances serious enough that NERC set mandatory reliability rules for large loads at 50 megawatts and 100 kilovolts, a threshold federal regulators had declined to name. The rules are aimed at keeping a single large load from destabilizing the grid everyone else depends on. For owners, the signal is that grid reliability is now being actively managed around these loads, and that resilience, onsite backup and the ability to ride through disturbances, has risen in value.

How Power Reaches Your Building, Part 2: Rates

The second channel is cost. Data center demand is pushing wholesale power prices up, and the increase flows to commercial bills. In PJM, the largest US grid region, wholesale power costs are running roughly 50 percent higher, and PJM’s independent market monitor attributed about 9 percent of 2026 wholesale costs specifically to data center load. That is a direct, measurable addition to what commercial customers pay, before any capacity charges. The owners least exposed are those who have lowered their own peak demand and generate power onsite; the most exposed are those buying all their power from an increasingly expensive grid.

How Power Reaches Your Building, Part 3: Community and Politics

The third channel is environment. Data center siting has become a political flashpoint. A Memphis moratorium vote collapsed into protests, and moratoriums are spreading across states as communities weigh power demand, water use and rising bills. For developers and owners of power-intensive property, this adds an entitlement and reputational risk that did not exist a few years ago. A project’s access to power is no longer the only gating question; its social license is now part of the calculus.

What Owners Should Plan For

None of these forces reverse on their own, so the planning question is how to reduce exposure to each. On reliability, that means securing critical load with onsite backup so a grid disturbance does not become a tenant’s problem. On rates, it means lowering the building’s peak demand and evaluating onsite generation, since the cost of grid power is set to keep climbing regardless of any single owner’s actions. On siting, for those developing power-intensive property, it means treating community engagement and local approval as early-stage risks, not late-stage formalities. The data center boom is the backdrop every commercial owner now underwrites against. The response is not to fight it, but to reduce the building’s dependence on the grid it is straining.

Frequently Asked Questions

Why should a data center deal between Google and a utility affect my building?

Because it tightens the supply of firm power. When large buyers contract the generation and grid capacity that already exist, less remains for other customers, which pressures prices and reliability for everyone on the same grid. The effect is indirect but real, and it shows up on commercial bills.

Is the 9 percent PJM figure the whole data center impact?

No. The market monitor’s roughly 9 percent is the share of wholesale energy costs attributed to data center load in 2026. It does not include the separate capacity charges, which have risen sharply, or the longer-term grid investment these loads require. The total effect on a commercial bill is larger than that single figure.

What can a mid-market owner actually do about this?

Reduce dependence on the grid the data centers are straining. Lowering peak demand cuts exposure to rising capacity and energy charges, onsite backup protects against reliability disturbances, and onsite generation hedges against the climbing cost of grid power. None of it stops the boom, but all of it reduces how much the boom costs the building.

Sources

SiliconANGLE, Google goes nuclear with Constellation (890 MW new, 2,700 MW supply): https://siliconangle.com/2026/10/06/google-goes-nuclear-to-power-its-ai-data-centers-committing-to-purchase-890-megawatts-of-energy-from-constellation/
Microgrid Knowledge, NERC sets data center reliability rules at 50 MW and 100 kV: https://www.microgridknowledge.com/distributed-energy/demand-response/article/55394284/
Utility Dive, data center load made up 9% of PJM wholesale costs in 2026: https://www.utilitydive.com/news/data-center-load-pjm-wholesale-market/828917/
Action News 5, Memphis data center moratorium vote ends amid protests: https://www.actionnews5.com/2026/10/06/data-center-moratorium-vote-ends-abruptly-amid-protests-fistfight/

The 6 Percent Scenario: How to Stress-Test Your Capital Stack Before the Maturity Hits

ChargedUp! — Tue, 13 Oct 2026 15:54:29 GMT

Photo by Jorge Salvador on Unsplash

One of the largest bond managers in the world says the 10-year Treasury could reach 6 percent for the first time since 2000. Against a trillion-dollar maturity wall, that is the single biggest risk on a commercial owner's board. In the following article, we break down how to prepare.

Underwrite your assets against sustained high rates now, not the lower rates you financed them at. PIMCO has warned that the 10-year Treasury could hit 6 percent for the first time since 2000, and with roughly $1.26 trillion in commercial real estate debt maturing into a market priced near a 24-year high, the risk is a wave of refinancings at rates far above the original loans. The defense is a stress test: model each asset’s debt service and value at a 6 percent-plus world, identify the loans that break, and act early on the three levers that remain, raising net operating income, restructuring the debt, and preserving value through the operating costs you control. This deep dive walks through each, with the sources to verify them.

Key Facts at a Glance

PIMCO’s chief investment officer warned the 10-year Treasury yield could reach 6 percent for the first time since 2000.
Roughly $1.26 trillion in US commercial real estate debt is maturing, with the broader maturity wall projected to peak in 2027.
Permanent fixed-rate commercial debt is pricing well above 7 percent, far above the 4 to 5 percent on many maturing loans.
Property value moves inversely with cap rates: a one-point rise in the cap rate on a $1 million NOI cuts value by more than $2 million.
The controllable defense is net operating income, where every durable $1,000 of annual savings adds roughly $12,500 to $16,700 in value at today’s cap rates.

What PIMCO Said, and Why It Matters

The warning came from one of the most-watched voices in fixed income. PIMCO’s chief investment officer, Dan Ivascyn, told the Financial Times that the 10-year Treasury yield risks hitting 6 percent for the first time since 2000, citing persistent inflation and heavy government borrowing. The 10-year is already trading near a 24-year high, and its path matters to commercial real estate more than almost any other number, because it is the benchmark that sets permanent mortgage pricing. The daily level is published by the Federal Reserve, so owners can track it themselves.

A forecast is not a certainty, and PIMCO’s call is one view among many. But risk management is not about predicting the single outcome. It is about knowing what happens to each asset if the adverse case arrives, and whether the owner can survive it. A 6 percent 10-year is a defensible stress case, and an owner who has modeled it is prepared whether or not it comes to pass.

The Maturity Wall Is Real, but the Repricing Is the Problem

The exposure is large. Industry analysts count roughly $1.26 trillion in commercial real estate debt coming due, and S&P Global projects the broader maturity wall to peak in 2027. The wall itself is not the danger. Loans mature all the time. The danger is the repricing: many of these loans were written at 4 to 5 percent and now face refinancing at rates ranging from roughly 6.4 to 9 percent depending on asset and sponsor. That spread is the funding gap, and it is what forces owners to bring fresh equity, accept a workout, or sell.

The useful way to frame it, as some analysts put it, is that the maturity wall was never the real issue. The repricing is. A loan that comes due is only a problem if it cannot be refinanced on terms the asset can carry, and at a 6 percent benchmark, more loans fall into that category.

The Math: How Rates Become Value

Rising rates damage a property twice, and both effects compound. The first hit is debt service. A loan refinancing from 4.5 percent to 7.5 percent on the same balance roughly doubles the interest cost, which can push the debt service coverage ratio, the ratio of net operating income to debt payments, below the level lenders require. When it does, the owner must inject equity to close the gap or risk default.

The second hit is valuation. Commercial property is valued by dividing net operating income by a market capitalization rate, and cap rates move with interest rates. As rates rise, cap rates rise, and value falls even if the building’s income is unchanged. The arithmetic is unforgiving. A property with $1 million in net operating income is worth about $16.7 million at a 6 percent cap rate, $14.3 million at 7 percent, and $12.5 million at 8 percent. A two-point rise in the cap rate erases a quarter of the value, with no change in the building’s performance. Analysts widely expect cap rates to keep rising while rates stay elevated, which is why value protection is now as urgent as debt management.

The Stress Test: What to Model Now

The exercise is concrete and worth doing on every asset before its maturity arrives. For each property, model the refinancing at a 6 percent-plus benchmark, roughly 7.5 to 8 percent all-in, rather than the rate on the existing loan. Recalculate the debt service coverage ratio at that rate, and flag any asset that falls below the lender’s threshold. Then recalculate value at a cap rate consistent with the higher-rate world, and compare it to the outstanding loan balance to see whether the asset is approaching or past the point where the debt exceeds the value. The assets that fail both tests, thin coverage and loan near or above value, are the ones that need action first, and the sooner the better, because options narrow as the maturity date approaches.

The Three Levers That Remain

Once an owner knows which assets are exposed, three levers are available, and the strongest strategies use all three.

First, raise net operating income. This is the only lever fully within an owner’s control, and it does double duty: it improves the coverage ratio that determines whether a refinancing works, and it lifts the value that determines whether the asset is underwater. Because value is NOI divided by the cap rate, every durable $1,000 of annual savings adds roughly $12,500 to $16,700 in value at today’s cap rates. Energy is the largest controllable operating cost in most buildings, which is why cutting it, through efficiency, onsite generation and demand management, has become a capital-stack strategy rather than a facilities decision.

Second, restructure the debt. Owners facing maturities should open the conversation with lenders early, when extensions, modifications and workouts are still available, rather than at the deadline. Fixed-rate alternatives that do not compete with senior debt, including long-term energy financing tied to the property, can fund value-adding improvements without consuming the balance-sheet capacity a refinancing requires.

Third, protect optionality. For assets that cannot carry a refinancing at stress-case rates, a proactive sale or recapitalization while the asset still has value beats a forced transaction at the deadline. The buyers acquiring distressed assets today are underwriting to sustained high rates and prizing durable, controllable cash flow, which is exactly the profile an owner can build toward before deciding to sell.

The Bottom Line

The 6 percent scenario may or may not arrive, but it is the right case to plan against, because the downside of being unprepared is severe and the cost of preparing is low. Model each asset at stress-case rates, find the loans that break, and act early on the levers that remain. The one an owner controls completely is net operating income, and the fastest way to move it is the energy bill. In a market where the cost of capital is set in Washington and the bond market, the cost of power is set, increasingly, in the building itself.

Sources

U.S. News / Reuters, PIMCO’s Ivascyn: 10-year Treasury could hit 6 percent: https://money.usnews.com/investing/news/articles/2026-10-09/us-10-year-treasury-yield-risks-hitting-6-for-first-time-since-2000-pimcos-ivascyn-tells-ft
Federal Reserve Bank of St. Louis (FRED), 10-year Treasury yield (DGS10): https://fred.stlouisfed.org/series/DGS10
CoStar, the looming $1.26 trillion CRE debt wall: https://www.costar.com/article/1122236114/why-commercial-property-pros-say-a-looming-1-26-trillion-debt-wall-can-be-scaled
S&P Global Market Intelligence, CRE maturity wall peaks in 2027: https://www.spglobal.com/market-intelligence/en/news-insights/research/commercial-real-estate-maturity-wall-950b-in-2024-peaks-in-2027
Select Commercial, commercial mortgage rates (Oct 2026): https://selectcommercial.com/commercial-mortgage-rates.php
CRE Daily, cap rates may still have room to rise in 2026: https://www.credaily.com/briefs/cap-rates-may-still-have-room-to-rise-in-2026/

Heating Oil Is Set to Cost 21 Percent More This Winter. Time to Switch the Fuel You Burn?

ChargedUp! — Mon, 12 Oct 2026 19:25:18 GMT

Photo by Peter Herrmann on Unsplash

EIA projects heating-oil households will pay about 21 percent more this winter, while natural gas and propane users see little change. That divergence turns the fuel a building burns into one of the few energy costs an owner can actually change. Converting an oil boiler to a heat pump or, where available, natural gas removes the most volatile fuel on the property and locks in a lower, steadier operating cost. The decision is building-specific, but the direction of oil-linked fuel prices argues for running the numbers now rather than after another winter of oil bills.

Key Facts at a Glance

EIA’s Winter Fuels Outlook projects heating-oil households will spend about 21 percent more this winter than last.
Natural gas and propane users are expected to see flat to slightly lower heating costs, widening the gap between fuels.
The heating-oil increase is driven by a structural distillate shortage, with diesel and heating oil inventories running below the five-year average.
Heating oil is concentrated in the Northeast, where legacy commercial and multifamily buildings still rely on it.
Fuel switching, to a heat pump or natural gas, is one of the few energy moves fully within an owner’s control.

Why Heating Oil and Natural Gas Are Moving Apart

The two fuels are diverging because they come from different places in the energy system. EIA’s latest outlook projects heating-oil households paying about 21 percent more this winter, while natural gas and propane stay roughly flat. Heating oil is a refined distillate, the same barrel family as diesel, and global distillate supply is tight, with inventories below the five-year average and refining capacity stretched. Natural gas, by contrast, is abundant: strong domestic production and full storage are keeping prices moderate. A building’s winter bill now depends heavily on which side of that divide its heating system sits.

This is the regional story made specific. Heating oil is concentrated in the Northeast, where a large stock of older commercial, office and multifamily buildings still burns it. Those owners face a rising, volatile fuel bill this winter. An owner of an identical building on natural gas or electric heat does not. The weather is the same; the fuel is the difference.

What Fuel Switching Actually Means

For most oil-heated commercial buildings, two paths exist. The first is a heat pump, an electric system that moves heat rather than burning fuel and runs several times more efficiently than a boiler. Modern cold-climate heat pumps perform in Northeast winters, and electrifying heat removes exposure to oil entirely, replacing it with a more stable electricity cost the owner can further hedge with onsite power. The second, where a gas line is available, is conversion from oil to natural gas, which captures the fuel-price gap directly without changing the building’s reliance on combustion.

Neither path is free, and the economics turn on the spread between oil and the alternative, the building’s heating load, the condition of the existing system, and available incentives. The case is strongest for buildings facing an aging boiler replacement anyway, where the incremental cost of switching fuels is small against a capital cost the owner was going to bear regardless.

Why This Is a Cost Owners Control

The theme running through this market is that most energy costs are set elsewhere: interest rates, crude prices, capacity auctions. The fuel a building burns is the exception. An owner cannot change the price of heating oil, but can change whether the building depends on it. That makes fuel switching one of the clearest levers available, and a durable one. A conversion made this year pays back across every winter that follows, and it compounds with the broader electrification an owner may already be pursuing, since a heat pump pairs naturally with onsite solar and storage.

The savings also behave like any other operating-cost reduction. In an owner-paid or gross-lease building, lower heating cost flows into net operating income, and property value rises with NOI at the market capitalization rate. A building that sheds a volatile, rising fuel line is worth more to a buyer who no longer has to underwrite that exposure.

What Owners Should Do This Winter

The immediate move is an audit. An owner of an oil-heated building should know its annual heating-oil spend, the age and condition of the boiler, and whether a natural gas line is accessible. From there, the comparison is concrete: the cost of a heat pump or gas conversion against the avoided fuel cost, adjusted for any state or utility incentives, many of which are generous in the Northeast states where heating oil dominates. Buildings with aging boilers or lease events on the horizon are the first candidates, because the switch rides on a capital decision the owner faces anyway. The point is not to convert every building this winter. It is to stop treating the heating-oil bill as fixed when it is, uniquely, a cost the owner can design out.

Frequently Asked Questions

Do heat pumps work in cold Northeast winters?

Modern cold-climate heat pumps are rated to perform at the low temperatures typical of Northeast winters, and many buildings pair them with a backup for the coldest hours. The technology has advanced significantly, and the efficiency advantage over an oil boiler is large across a full heating season.

Is switching to natural gas better than a heat pump?

It depends on the building. Natural gas conversion captures the current price gap with lower upfront complexity where a gas line exists, but keeps the building on combustion. A heat pump removes fuel-price exposure entirely and pairs with onsite power, at a higher upfront cost. The right answer turns on gas availability, the building’s load, and the owner’s longer-term electrification plan.

Should I wait to see if heating oil prices fall?

Prices may ease, but the distillate shortage behind this winter’s increase is structural, and heating oil has been volatile for years. The stronger approach is to make the decision on the building’s own economics, especially when a boiler is near replacement, rather than timing a fuel market that has repeatedly surprised to the upside.

Sources

CNBC, EIA Winter Fuels Outlook: heating oil bills up about 21 percent: https://www.cnbc.com/2026/10/07/home-heating-oil-costs-winter.html
U.S. Energy Information Administration, Winter Fuels Outlook: https://www.eia.gov/outlooks/steo/report/winterfuels.php
U.S. Department of Energy, heat pump systems: https://www.energy.gov/energysaver/heat-pump-systems

Can an Onsite Battery Pay You to Sit There? New VPP Programs Say Yes

ChargedUp! — Mon, 12 Oct 2026 15:25:49 GMT

Photo by Sungrow EMEA on Unsplash

A new wave of virtual power plant programs pays owners a fixed amount for letting their onsite battery discharge or curtail load when the grid is stressed. New Jersey just proposed paying up to $200 per kilowatt per year over 10 years for behind-the-meter storage, and the capital funding these systems is still flowing in by the billions. For a commercial owner, the significance is control: a battery that already protects the building during an outage can now also lower demand charges and earn a contracted payment, making onsite storage one of the few energy moves with a defined return rather than a hope.

Key Facts at a Glance

New Jersey proposed paying up to $200 per kilowatt per year, over a 10-year term, for behind-the-meter storage that discharges during grid dispatch events.
The program is the first distributed block of the state’s larger effort to reach 2 gigawatts of storage by 2030, and it transitions to a market-based VPP tariff in 2029.
A virtual power plant (VPP) aggregates many onsite batteries and flexible loads into a single resource the grid pays to dispatch.
Capital for these systems remains abundant: IPX Power alone closed $4.95 billion in solar-and-storage financing this period.
Onsite storage earns three ways at once: lower demand charges, VPP or capacity payments, and resilience during outages.

What New Jersey Just Put a Price On

The clearest signal came from New Jersey. The state’s Board of Public Utilities proposed procuring up to 150 megawatts of behind-the-meter storage that can discharge when the grid needs it, paying up to $200 per kilowatt per year over a 10-year term. The program starts as a transitional virtual power plant and moves to a market-based, open-access tariff in 2029, part of the state’s goal to reach 2 gigawatts of storage by 2030. The number matters more than the state. A published, multiyear price on flexibility is what lets an owner underwrite a battery the way they would any other income-producing asset.

New Jersey is not alone. Utilities and regulators across the country are standing up programs that compensate distributed storage, from California and Illinois to Colorado, where state law requires a performance-based VPP tariff. The direction is consistent: the grid increasingly needs flexible capacity it does not have to build, and it is willing to pay building owners for theirs.

How a Building Earns From Storage

Onsite storage produces value on three separate lines, and a sound project counts all of them. The first is demand-charge reduction. A battery discharged during the building’s peak lowers the coincident peak that sets the monthly demand charge, often the largest and least understood item on a commercial electric bill. The second is grid revenue. Through a VPP or capacity program, the owner is paid to dispatch the battery or curtail load during grid stress, a contracted payment like New Jersey’s $200 per kilowatt. The third is resilience. When the grid fails, the battery keeps critical systems running, avoiding the cost of an outage entirely.

The three streams stack, but they also compete for the same battery capacity. A system optimized purely for grid revenue may not be sized for backup, and one sized only for resilience may sit idle most of the year. The strongest projects are designed around all three from the start, with the control software to arbitrate between them.

Why This Is the Control Play

Most of what drives a building’s energy cost is outside an owner’s hands: interest rates, oil prices, capacity auctions. Onsite storage is the exception. It is an asset the owner installs, controls and monetizes, and the capital to fund it is available even as traditional financing tightens. IPX Power closed $4.95 billion in solar-and-storage financing in this period alone, and third-party ownership structures let owners host a system with no upfront capital. The combination, a paid grid program on one side and available capital on the other, is what moves storage from a resilience nice-to-have to a financeable asset with a return.

What Owners Should Do Now

The first step is to find the programs in the building’s own market. VPP and storage-compensation programs are utility and state specific, so an owner in New Jersey, Colorado or California faces different published prices than one in a market without a program yet. The second step is to size the system to the building’s actual peak and load profile, not a generic template, so the demand-charge savings are real. The third is to decide the ownership structure, direct ownership to capture the tax credits and the full revenue, or a third-party agreement to avoid the capital outlay. The owners capturing this value are the ones treating storage as an income asset with a contract behind it, not a backup generator that happens to have a battery.

Frequently Asked Questions

Is the New Jersey price available to commercial buildings?

The proposed transitional program centers on residential and small commercial systems, with a market-based tariff opening access more broadly in 2029. The significance for larger owners is the signal: a regulator has put a firm, multiyear price on flexibility, and comparable programs in other states already compensate commercial storage directly.

Do I need solar to earn VPP revenue?

No. A battery alone can participate by discharging or shifting load during grid events. Pairing storage with solar increases how much a building can offer and when, but the VPP payment is for flexibility, which a standalone battery provides.

How certain is the revenue?

Program payments like New Jersey’s are contracted over a set term, which makes a baseline predictable. Market-based dispatch revenue varies with grid conditions. A conservative underwriting treats the contracted payment and demand-charge savings as the foundation and any market upside as a bonus.

Sources

Utility Dive, New Jersey seeks 150 MW of behind-the-meter storage to support VPP: https://www.utilitydive.com/news/new-jersey-seeks-150-mw-of-behind-the-meter-storage-to-support-vpp/828727/
Mercom Capital, IPX Power closes $4.95 billion solar-and-storage financing: https://mercomcapital.com/ipx-power-closes-4-95b-financing-solar-storage-projects/
Energy-Storage.News, US VPP programs advance with new partnerships and investment: https://www.energy-storage.news/us-virtual-power-plant-programmes-advance-with-new-partnerships-and-investment/
U.S. Department of Energy, Virtual Power Plants projects: https://www.energy.gov/edf/virtual-power-plants-projects

The True Cost of Power: A Two-Front Squeeze as Rates Hit a 24-Year High and Oil-Linked Fuels Spike

ChargedUp! — Wed, 07 Oct 2026 15:49:20 GMT

Since last week the squeeze tightened in two areas at once. The 10-year Treasury rose to 5.36 percent, a 24-year high, making refinancing more expensive, while attacks in the Strait of Hormuz and a Gulf storm pushed Brent crude back above $102 and lifted heating oil and diesel. Natural gas, meanwhile, stayed cheap. That split is the story for owners: buildings heated with oil or dependent on diesel face rising costs on both the fuel and the debt side, while gas-heated and electric buildings are exposed mainly on rates. The defense that works across all of it is cutting the fuel and power exposure an owner actually controls.

Key Facts at a Glance

The 10-year Treasury yield reached 5.36 percent, returning to 2002 levels, and the 30-year hit a 24-year high near 5.73 percent, up from about 5.24 percent a week ago.
Brent crude traded around $102 a barrel and WTI near $91, lifted by Strait of Hormuz tanker attacks and a Gulf of Mexico storm, though Saudi pipeline restoration and a G7 reserve release capped the rise.
Heating oil and diesel are tight and climbing, pointing to higher winter costs for Northeast oil-heated buildings and diesel-dependent logistics.
Natural gas stayed moderate near $3.18 per million BTU with full storage, and EIA expects gas and propane heating to cost less this winter than last.
Permanent fixed-rate commercial debt is now pricing well above 7 percent, deepening the refinancing gap for owners facing maturities.

What Changed Since Last Week

A week ago this column argued that winter's energy risk was regional rather than a national price shock. That holds, but two things moved against owners in seven days. First, rates broke higher. The 10-year Treasury, the benchmark for commercial mortgage pricing, climbed to 5.36 percent, a level last seen in 2002, and the 30-year reached a 24-year high. Second, the oil market reawakened. Attacks on tankers in the Strait of Hormuz and a storm threatening Gulf of Mexico production pushed Brent back above $102. The war premium that this column has tracked before is back, though not unchecked.

The Capital Side: The Refinancing Math Got Worse

At 5.36 percent on the 10-year and a 30-year near 5.73 percent, permanent fixed-rate commercial debt is pricing well above 7 percent. For an owner facing a maturity this quarter, the gap between an expiring loan written at 4 percent and a refinancing at 7 percent or more is now wider than it was a week ago. No relief is signaled. Today's Treasury note auction and the release of the Federal Reserve's latest meeting minutes reinforced a market that expects rates to stay high, not fall. The capital side of the building's cost structure offers nothing to work with, which pushes the entire problem onto the operating statement.

The Fuel Side: A Shock That Splits by Fuel

The more important development is where the fuel pressure is landing. Crude rose, but the sharper move is in the middle distillates, heating oil and diesel, where refining is tight. Northeast heating oil costs are set to rise this winter, with EIA projecting heating oil well above last year's levels, and diesel tightness is keeping logistics and distribution costs elevated. At the same time, natural gas remains moderate with full storage, and EIA expects gas and propane heating to cost less this winter than last.

That divergence is the heart of this week's story. The same winter is cheaper for a gas-heated building and more expensive for an oil-heated one. A legacy office or multifamily property in the Northeast still burning heating oil faces a rising fuel bill. A logistics operator running diesel equipment and trucks faces elevated distillate costs that flow into common-area charges. A building on natural gas, or one generating its own power, is largely insulated on the fuel side. The map of winter risk is not just regional. It is fuel-specific.

The oil move is two-sided, which matters for how owners read it. Prices rose on Hormuz attacks and the Gulf storm, but Saudi Arabia restored its East-West pipeline to 5.8 million barrels a day and the G7 agreed to release 100 million barrels from reserves. The risk premium is real, but relief valves are open, so this is elevated volatility rather than a runaway spike.

Who Is Exposed on Both Fronts

The owners under the most pressure this week are the ones caught by both forces at once: a near-term debt maturity and an oil-linked fuel bill. That describes a specific profile, often an older Northeast property on heating oil with floating-rate or expiring debt. For that owner, the squeeze is genuine, and the levers are limited to what the building itself can change. Owners on natural gas or with fixed-rate debt in place have more room, but the direction of both rates and oil-linked fuels argues against waiting to act.

What Owners Can Do Now

The conclusion this column keeps returning to is sharper this week because the exposure is more specific. Owners cannot move the Treasury market or the Strait of Hormuz, but they can reduce the fuel and power exposure they control. Three moves fit the moment. First, get off oil where the building can. Converting heating oil systems to heat pumps or natural gas, where available, removes the most volatile fuel on the property. Second, manage peak and heating load before the cold, since demand charges and heating spikes are set in the first cold weeks, not recovered later. Third, for owners weighing onsite generation, the case strengthens as both the cost of grid power and the cost of capital climb together.

ChargedUp! has covered the financing paths and the onsite and virtual-power-plant tools that make these moves practical, and this is the environment they are built for. The point of this column is the pattern. Week to week the external shock rotates, an oil war premium, a rate spike, a winter fuel squeeze, but it always lands in the same place, the operating statement, and the only consistent defense is the part of the bill an owner can control.

The Bottom Line

The true cost of power this week is a two-front squeeze that is no longer evenly distributed. Rates at a 24-year high raise the cost of every refinancing, and an oil-linked fuel shock raises the winter bill specifically for buildings that burn heating oil or run on diesel. Natural gas and self-generated power are the shelter. An owner cannot change the macro, but can decide which fuels and which loads the building depends on. In a week when both the debt and the fuel side moved the wrong way, that decision is the one that still belongs to the owner.

Sources

Federal Reserve Bank of St. Louis (FRED), 10-year Treasury yield: https://fred.stlouisfed.org/series/DGS10
Reuters, oil prices rise as storms and air strikes threaten supply (Oct 7, 2026): https://www.reuters.com/business/energy/oil-prices-rise-storms-air-strikes-threaten-supply-2026-10-07/
U.S. Energy Information Administration, Short-Term Energy Outlook: https://www.eia.gov/outlooks/steo/
The Hill, Northeast heating oil and diesel costs this winter: https://thehill.com/policy/energy-environment/6099110-northeast-heating-oil-costs-diesel/

Who Pays for the Data Center Power Crunch? A FERC Ruling Puts Building Owners on Notice

ChargedUp! — Wed, 07 Oct 2026 15:33:49 GMT

The fight is over who absorbs the cost of a 6.8-gigawatt power shortfall in the PJM grid, and FERC has signaled that data centers, not existing customers, should pay for the demand they drive. The Federal Energy Regulatory Commission conditionally approved PJM's emergency backstop procurement, an arrangement worth roughly $20 billion to secure scarce capacity, but paused it about five months and demanded changes so the costs fall on the large new loads causing the shortfall. For commercial owners across PJM's 13-state territory, this ruling will help determine how much of the data center boom shows up on their own electric bills.

Key Facts at a Glance

PJM faces a 6.8-gigawatt capacity shortfall and proposed an emergency backstop procurement, valued at roughly $20 billion, to secure power.
FERC conditionally approved the plan but paused it about five months and ordered revisions so data centers cover the costs they drive.
FERC's stated principle is that existing customers should not pay costs attributable to new demand.
PJM serves 13 states and Washington, D.C., so the cost-allocation decision reaches a large share of East Coast commercial property.
Capacity charges pass through to commercial electric bills, making this regulatory fight a direct NOI question for owners.

What Did FERC Actually Decide?

PJM Interconnection, the grid operator for the Mid-Atlantic and much of the Midwest, asked FERC to approve an emergency backstop procurement to cover a 6.8-gigawatt capacity shortfall driven largely by surging data center demand. FERC conditionally approved the plan but suspended it for roughly five months, directing PJM to revise how the costs are allocated. The regulator's message was that the customers already on the system should not foot the bill for demand that new arrivals create.

The backstop itself is large, an arrangement valued at roughly $20 billion to secure capacity that the normal auction did not deliver. The question FERC pushed back on was not whether to secure the power, but who pays for it. That distinction is the whole story for commercial owners.

Why This Lands on a Commercial Owner's Bill

Capacity charges are the part of an electric bill that pays generators to be available during peak demand, separate from the energy a building actually consumes. In PJM, those charges have climbed to record levels, and they pass through to commercial customers whether or not an owner ever reads an auction result. When a 6.8-gigawatt shortfall gets backfilled through an expensive emergency procurement, someone pays for it in their rates.

If FERC holds the line that data centers cover their own costs, existing commercial customers are partly shielded. If the costs spread across the rate base instead, every owner in PJM helps pay for the data center boom. That is the difference the revised plan will decide.

The Larger Shift This Signals

For years, the cost of serving new large loads was socialized, spread quietly across all ratepayers. The FERC ruling is part of a broader turn toward making the loads that drive grid investment pay for it directly. The same principle is appearing in state rate design, from dedicated data center rate classes to large-load tariffs. For commercial owners, the trend is favorable in direction but unsettled in detail, and the detail is where the dollars are. A plan that assigns costs cleanly to data centers protects other customers; one riddled with exemptions does not.

What Should Owners Do Now?

This is a watch-and-position item more than an act-today one, but it is not passive. Owners in PJM states should track how the revised cost-allocation plan treats existing customers, because it feeds directly into the capacity line on future bills. More broadly, the ruling reinforces the case for controlling the part of the bill an owner can influence. Capacity and demand charges are set by a building's contribution to peak, so demand response, onsite storage and load management reduce exposure regardless of how the regulatory fight resolves. The owners least affected by the who-pays outcome are the ones who have already lowered their own peak.

Frequently Asked Questions

What is a backstop procurement?

It is an emergency mechanism a grid operator uses to secure capacity when the normal auction falls short of what reliability requires. PJM proposed one to cover a 6.8-gigawatt gap. Because it buys power outside the standard process, it tends to be expensive, which is why who pays for it matters so much.

Does this affect owners outside PJM?

Directly, it affects the 13 states and Washington, D.C. that PJM serves. Indirectly, it sets a precedent. Other grid operators and state regulators are wrestling with the same question of who pays for data center demand, and a FERC decision shapes how those debates unfold.

Will this lower my bill?

Not by itself, and not immediately. At best, it prevents data center costs from being added to your rates. The reliable way to lower your own capacity and demand charges is to reduce your building's peak demand through load management, storage or onsite generation.

Sources

Utility Dive, PJM files backstop capacity auction at FERC: https://www.utilitydive.com/news/pjm-backstop-capacity-auction-ferc-data-centers/826792/
Data Center Knowledge, PJM's power shortfall puts data center growth in focus: https://www.datacenterknowledge.com/energy-power-supply/pjm-s-power-shortfall-puts-data-center-growth-in-focus
Reuters, FERC asks PJM to revise plan to shield homes from data center costs: https://www.reuters.com/business/energy/ferc-asks-grid-operator-pjm-revise-plan-shield-homes-data-center-costs-2026-09-30/

Is the Battery Gold Rush Over? What Texas's Storage Revenue Reset Means for Your Project Pro Forma

ChargedUp! — Tue, 06 Oct 2026 19:40:19 GMT

The easy money is gone, but the case for storage is not, it has just shifted. As Texas added batteries at scale, the price volatility that generated rich arbitrage profits flattened, and merchant revenues fell. Owners and investors who underwrote projects on the old revenue assumptions now face a gap. The lesson is not to avoid storage. It is to underwrite it on today's revenue stack, demand-charge savings, capacity value and resilience, rather than on the arbitrage returns that financed the boom and have since compressed.

Key Facts at a Glance

ERCOT, the Texas grid, added batteries rapidly, and the price volatility that drove early arbitrage profits has flattened as the market saturated.
Merchant battery revenues have fallen, pressuring projects underwritten on the old arbitrage assumptions.
The revenue model is shifting from price arbitrage toward demand-charge reduction, capacity value and resilience.
Behind-the-meter storage at a commercial building earns differently than merchant grid storage, which changes how owners should evaluate it.
A pro forma built on yesterday's volatility can overstate returns; the current revenue stack is lower but more predictable.

What Changed in Texas?

Texas became the proving ground for grid batteries, and the early returns were extraordinary. Batteries made money on arbitrage, charging when power was cheap and discharging into price spikes, and the ERCOT market produced plenty of spikes. That profit financed a building spree. But as the fleet grew, the volatility that fed those profits flattened, and merchant revenues collapsed. More batteries competing to capture the same price swings is exactly what erodes the swings. Battery profits have dropped as market saturation reshapes Texas storage.

This is a predictable arc for any asset that monetizes volatility. The first movers capture the spread, their success draws competitors, and the spread narrows. Texas reached that point faster than most markets expected because it added storage so quickly. The result is a revenue reset, not a collapse of the underlying need for storage.

Why This Matters for a Property Owner

Most commercial owners will never build a merchant battery that bids into the grid. But the Texas reset matters because the same optimistic revenue assumptions get carried into behind-the-meter proposals. An owner evaluating onsite storage may be shown a pro forma that leans heavily on grid-market revenue or arbitrage, the very returns that have thinned. If those numbers anchor the investment case, the project can disappoint.

Behind-the-meter storage earns its keep differently than merchant storage. Its core value is reducing the building's own demand charges, shifting load away from peak pricing, and providing resilience during outages. Those benefits are more stable than merchant arbitrage, but they are also smaller, and a sound pro forma counts them honestly rather than reaching for grid-market upside that may not materialize.

How to Read a Storage Pro Forma Now

Three questions separate a durable storage investment from a fragile one. First, where does the revenue come from? A proposal that depends on merchant arbitrage or volatile grid-market payments carries the risk the Texas market just demonstrated. One built on the building's own demand-charge savings and a contracted capacity or virtual-power-plant payment is steadier. Second, how sensitive is the return to that assumption? If a modest drop in grid revenue breaks the model, the model is too fragile. Third, does the resilience value stand on its own? For many buildings, avoiding a single costly outage justifies a meaningful share of the system regardless of market revenue.

An owner who asks those questions is protected from the gap that caught early Texas investors. The technology works, the need for storage is growing, and the costs keep falling. What changed is that the revenue has to be underwritten conservatively, on the value the battery delivers to the building, not on the market conditions that happened to exist when the boom began.

Frequently Asked Questions

Does this mean storage is a bad investment now?

No. It means the revenue has to be underwritten on current conditions. For a commercial building, storage still delivers demand-charge savings, resilience and, in many markets, capacity payments. Those values are more stable than the arbitrage returns that have compressed in Texas.

Is behind-the-meter storage exposed to the same revenue collapse?

Less so. Behind-the-meter storage earns mainly by cutting the building's own demand charges and shifting load, which does not depend on grid price volatility. The risk is in proposals that pad those real savings with optimistic grid-market revenue. Separate the two when you evaluate a project.

What revenue assumptions should I trust in a proposal?

Favor the ones tied to the building's own costs and to contracted payments: demand-charge reduction, load shifting, resilience value and contracted capacity or virtual-power-plant revenue. Treat merchant arbitrage or volatile grid-market revenue as upside, not as the foundation of the return.

Sources

Latitude Media, ERCOT batteries: boom, bust, or rebound?: https://www.latitudemedia.com/news/catalyst-ercot-batteries-boom-bust-or-rebound/
Enverus, ERCOT battery profits drop as market saturation reshapes Texas storage: https://www.enverus.com/newsroom/ercot-battery-profits-drop-as-market-saturation-reshapes-texas-storage/

Rate-Case Season: How Grid Investment Becomes Your Operating Expense, and Where Owners Can Push Back

ChargedUp! — Tue, 06 Oct 2026 19:24:00 GMT

A rate case is where a utility's grid spending turns into your utility bill, and the amount is far from fixed. In recent weeks Colorado approved a $157 million Xcel increase after cutting the request by more than half, Michigan trimmed a DTE Gas request from about $237 million to $74.5 million, and Indiana reopened an approved $71 million AES increase after public and political pushback. The pattern is clear: the gap between what utilities request and what owners ultimately pay is large, and intervenor scrutiny is what closes it. For commercial owners, the rate-case docket is an operating-expense line decided in a room most never enter.

Key Facts at a Glance

Colorado's PUC approved a $157 million Xcel electric increase, cutting the utility's request by 56 percent, with residential bills rising about $5 a month.
Michigan regulators approved a $74.5 million DTE Gas increase, less than half the roughly $237 million requested, after intervenors challenged unsupported capital spending.
Indiana regulators reopened a previously approved $71 million AES increase for reconsideration, with review stretching into 2027.
Much of the spending driving these cases is grid modernization and capacity to serve rising demand, costs that flow to commercial customers.
The size of the reductions shows that rate cases are contested outcomes, not fixed charges, and participation changes the result.

What Happened in Three States

Start with Colorado. The state's Public Utilities Commission approved a $157 million annual electric increase for Xcel Energy, cutting the request by 56 percent and pairing it with new consumer protections. Residential bills rise about $5 a month, roughly half what Xcel sought, to recover grid modernization costs.

Michigan tells a similar story on the gas side. The Michigan Public Service Commission approved a $74.5 million DTE Gas increase, less than half the roughly $237 million requested, after intervenors challenged capital spending the company could not fully support. In Indiana, regulators went a step further and reopened a previously approved $71 million AES increase for reconsideration, with hearings now stretching into 2027 after public and political objection.

Why This Is an Operating-Expense Story, Not a Policy One

Every dollar a regulator approves in a rate case becomes a cents-per-kilowatt-hour charge on commercial bills, and from there a direct hit to net operating income. The spending behind these cases is mostly grid modernization and capacity to serve load growth, including the data center demand reshaping regional grids. In other words, the cost of building the grid out for everyone else lands, in part, on the commercial customer's meter.

The striking fact across all three cases is the size of the cut. Colorado's regulators removed more than half of Xcel's request. Michigan cut DTE's by roughly two-thirds. Those reductions did not happen on their own. They happened because intervenors, consumer advocates, large customers and ratepayer groups, scrutinized the utility's spending and forced the commission to justify it. The difference between the request and the result is the difference participation makes.

What This Means for Owners

For a commercial owner, a rate case is not abstract policy. It is next year's energy budget being set, and the owner is usually absent from the room. Large energy users have standing to participate, directly or through coalitions, and the Michigan outcome shows what that participation is worth: a return on equity trimmed and tens of millions removed from the approved increase, savings that flow to every customer on the system.

The practical move is to know your utility's rate-case calendar. Major utilities file on a predictable cycle, the dockets are public, and large commercial customers can intervene or join an existing coalition. The cost of tracking a docket is trivial against a multi-year change in the rate you pay.

The Bigger Pattern

Rate cases are also becoming political, as Indiana shows, where a governor's objection helped reopen a settled decision. That cuts both ways. It can produce relief for customers, and it can add uncertainty to the timing and outcome of a case. Either way, the era of treating the utility bill as a fixed background cost is ending. The amount is negotiated, contested and, increasingly, fought over in public. Owners who understand that can plan around it, and in some cases influence it, rather than simply absorbing whatever arrives.

Frequently Asked Questions

Can a commercial owner really affect a rate case?

Yes, though rarely alone. Large energy users can intervene directly or, more commonly, participate through coalitions and ratepayer advocates. The Michigan and Colorado outcomes, where regulators cut requests substantially, reflect exactly that kind of organized scrutiny.

What is driving these rate increases?

Mostly grid modernization and new capacity to serve rising demand, including data centers and electrification. Utilities recover that capital spending through rates, which is why the increases keep coming and why what counts as justified spending is the heart of the fight.

How do I find my utility's rate case?

State public utility commission websites publish active dockets, and major utilities file on a regular cycle. Tracking the filing calendar, or working with a consumer advocate or energy coalition, lets an owner see a proposed increase well before it reaches the bill.

Sources

Colorado PUC, cuts Xcel electric rate request and expands consumer protections: https://puc.colorado.gov/press-release/puc-cuts-xcel-energys-electric-rate-request-and-expands-consumer-protections
Michigan PSC, approves DTE Gas increase below request: https://www.michigan.gov/mpsc/commission/news-releases/2026/09/10/mpsc-approves-dte-gas-co-infrastructure-investments
Indiana Capital Chronicle, review of $71M AES Indiana rate hike to stretch into 2027: https://indianacapitalchronicle.com/2026/09/18/review-of-71-million-aes-indiana-rate-hike-to-stretch-into-2027/

Can an AI Layer Cut Your Building's Energy Use 22 Percent Without New Equipment?

ChargedUp! — Tue, 06 Oct 2026 19:13:31 GMT

Yes, it can - and the savings are largest for exactly the buildings our readers own. Schneider Electric research released at Climate Week found that adding an artificial intelligence layer to a building's existing management system cuts whole-building energy use by up to 22 percent, worth between $13,600 and $49,300 per building each year at current commercial rates. It requires no new equipment. The AI connects data the building already produces, occupancy, weather and equipment performance, and optimizes heating and cooling in real time. Small and mid-sized buildings under 100,000 square feet stand to gain the most, because sophisticated energy management was previously too complex and costly for them.

Key Facts at a Glance

Schneider Electric found AI-enabled building management cuts whole-building energy use by up to 22 percent, with cloud-hosted configurations reaching 21.7 to 22.4 percent.
The savings run between $13,600 and $49,300 per building per year at current commercial electricity rates.
The AI layer requires no new equipment; it connects existing data on occupancy, weather and equipment performance to optimize HVAC in real time.
Buildings under 100,000 square feet benefit most, having historically been priced out of advanced energy management.
At an 8 percent capitalization rate, a durable $30,000 annual saving adds roughly $375,000 to a building's value.

What Did the Research Actually Find?

Schneider Electric, presenting at Climate Week in New York, reported that layering artificial intelligence onto a standard building management system cuts whole-building energy use by up to 22 percent, with the best results, 21.7 to 22.4 percent, coming from cloud-hosted configurations. The company put a dollar range on it: between $13,600 and $49,300 saved per building each year at current commercial rates. For a mid-market owner, those are not abstract efficiency percentages. They are a line item that drops straight to net operating income.

The detail that matters most is what the system does not require. According to the research, the AI layer does not replace existing equipment. It connects data the building already generates, occupancy patterns, weather forecasts and equipment performance, and uses it to optimize heating and cooling continuously. The capital cost is software and integration, not new chillers or rooftop units.

Why This Matters Most for Mid-Sized Buildings

For decades, advanced energy optimization was a large-building luxury. The analytics platforms, dedicated energy managers and engineered controls that cut consumption in a corporate tower were too expensive and too complex for a 60,000-square-foot office or a mid-market industrial building. Those owners ran their systems on basic schedules and absorbed the waste.

Schneider's finding is that the AI layer closes that gap. Because it works on top of existing controls and needs no dedicated staff to run, it brings tower-grade optimization to buildings that could never justify it before. The research is explicit that sub-100,000-square-foot facilities stand to gain the most. For the stewards of mid-market commercial property, this is the rare efficiency play where the economics favor the smaller building rather than penalize it.

How the Savings Reach Property Value

Energy savings do not stay on the utility bill. In an owner-paid or gross-lease building, a durable cut to energy cost flows directly into net operating income, and property value moves with NOI at the market capitalization rate. A building saving $30,000 a year, near the middle of Schneider's range, adds roughly $375,000 in value at an 8 percent cap rate. At the tighter cap rates seen in stronger markets, the figure is higher.

The capture depends on lease structure. In an owner-paid or gross-lease building, the savings are the owner's. In a triple-net building where the tenant pays the meter, the savings lower the tenant's total occupancy cost, which supports base rent and retention rather than landing directly in the owner's NOI.

What Should Owners Do With This?

The practical first step is to find out what the building already measures. Most commercial buildings installed in the last two decades have a building management system that collects far more data than it acts on. An AI optimization layer monetizes that stranded data without a capital project. Owners should ask their controls vendor or energy provider what an AI or analytics layer would cost against the building's current energy spend, run the simple payback, and prioritize the buildings with the highest energy bills and the oldest control logic. The move does not compete with a roof replacement or a solar installation for capital. It is a software decision with an operating return.

Frequently Asked Questions

Does this replace a building automation system?

No. It works on top of an existing building management system, using the data that system already collects. The value comes from analyzing and acting on that data in real time, not from new hardware.

Is 22 percent realistic for an older building?

The 22 percent figure is the upper end, from cloud-hosted configurations. Actual savings depend on the building's current control logic, how much waste exists to capture, and the local energy rate. Older buildings running basic schedules often have more waste to recover, which can make the return more attractive, not less.

Who captures the savings in a leased building?

It depends on the lease. In owner-paid and gross-lease buildings, the savings flow to the owner's net operating income. In triple-net buildings, the tenant pays the utility bill, so the savings reduce the tenant's occupancy cost and support rent and retention rather than landing directly in NOI.

Sources

Facilities Dive, adding AI to building management can cut energy use 22 percent: https://www.facilitiesdive.com/news/adding-ai-to-building-management-systems-can-cut-energy-use-by-22-schneid/831621/
Schneider Electric, AI-enabled buildings can cut energy use up to 22 percent: https://www.globenewswire.com/news-release/2026/09/21/3365434/0/en/schneider-electric-finds-ai-enabled-buildings-can-cut-energy-use-by-up-to-22-save-on-annual-utility-costs-and-carbon.html

Stories You May Have Missed This Week: EV, Charging & Intelligent Electrification Roundup (10/07/26 Edition)

ChargedUp! — Tue, 06 Oct 2026 18:50:54 GMT

Twenty percent of all US electricity, consumed by data centers by 2035. That forecast, nearly doubled this year, is the force now reshaping grids, rates and real estate. This week's roundup tracks where it is landing, and what owners can do about it.

Grid Stress, Storms and Resilience Economics

Mobile gas power scales up as a bridge around grid delays

EquipmentShare and Cummins announced a collaboration to deploy 1 gigawatt of mobile natural-gas generation, pitched at a 50 to 80 percent energy-cost cut versus traditional mobile power for construction and mission-critical sites. For developers waiting years on a grid connection, mobile gas is becoming the swing capacity that keeps a project moving.

Sources: Business Wire, EquipmentShare and Cummins 1 GW mobile power

Data center loads are wearing out grid equipment faster than it can be replaced

Industry reporting indicates AI data-center loads degrade grid equipment 2 to 3 times faster than conventional use, while high-voltage transformer lead times run 140 to 160 weeks and roughly 80 percent of large US transformers are imported. Energizing new development is now gated by the equipment queue, not just the interconnection study.

Sources: Tech Times, AI data centers and worn grid equipment · Manufacturing Mag, transformer shortage and three-year backlog

Diesel at record highs rewrites the backup-power math

Retail diesel has hit fresh record highs, and EIA raised its 2026 outlook as distillate stocks sit well below the five-year average. For buildings relying on diesel gensets for resilience, fuel cost is quietly shifting the resilience-versus-cost equation and the case for gas or battery backup.

Sources: Morningstar/Dow Jones, EIA raises diesel outlook as pump price hits record · U.S. Energy Information Administration, Short-Term Energy Outlook

Electrification Economics at the Property Level

Commercial electricity use is set to pass residential for the first time

EIA projects commercial electricity sales growing 5.3 percent in 2027 to surpass residential use for the first time on record, driven by data centers. Residential prices are rising about 5 percent this year, with some East Coast increases near 7 percent. The commercial sector is now both the load-growth story and the rate-pressure story.

Sources: Utility Dive, commercial electricity use to surpass residential in 2027 (EIA) · U.S. Energy Information Administration, Short-Term Energy Outlook

Office debt distress is shifting from vacancy to investor losses

Office CMBS delinquency reached about 12 percent in August, near a record, with reporting that a large share of office loans maturing this year and next is troubled. As price resets draw buyers, energy retrofits that cut operating expense and lift net operating income are becoming part of the repositioning playbook for distressed assets.

Sources: CRE Daily, office distress shifts from vacancies to investor losses

Solar, Storage and VPPs

Second-life EV batteries are delivering grid services in Texas

B2U Storage Solutions' project near San Antonio is delivering 28 megawatt-hours of grid services to ERCOT using repurposed EV batteries, part of a portfolio across Texas and California that qualifies for the domestic-content bonus. Second-life storage is proving bankable at lower cost than new cells, an option for budget-constrained projects.

Sources: Solar Power World, repurposed EV batteries delivering 28 MWh to ERCOT · Big Energy News, Houston battery project begins operations

A mid-market commercial battery finally fits the 50-to-400 kWh gap

TCL launched its X5 commercial storage system, scaling from 50 and 100 kWh base units to 400 kWh, VPP-ready, with islanding under 20 milliseconds and generator input. It targets sites too small for engineered systems but too demanding for residential gear, the mid-market segment that has been underserved.

Sources: PR Newswire, TCL X5 commercial energy storage system

The data center next door may unlock your community solar project

LandGate argues that data-center interconnection requests, from 100 megawatts to several gigawatts, are accelerating distribution-level grid investment and leaving behind parcels that do not fit a hyperscale footprint. Those dynamics are creating attractive community solar sites, sometimes with creditworthy anchor demand nearby.

Sources: LandGate, data center growth and community solar opportunities

Policy and Market Rules

The real solar ITC cliff is now December 31, 2027

The July 4, 2026 construction-start safe harbor for the 30 percent commercial Investment Tax Credit has passed. Projects that missed it can still claim the credit only if placed in service by December 31, 2027, and new sourcing and domestic-content rules compress rooftop and carport timelines further. Storage retains a longer runway.

Sources: Internal Revenue Service, clean electricity credit guidance · Native Solar, the 2026 ITC deadline for commercial solar

Rhode Island becomes the 33rd C-PACE state

Rhode Island enacted C-PACE, letting commercial owners finance solar and efficiency through a property-tax assessment with no upfront cost, non-recourse and transferable. In a high-rate state, it is pitched as the financing that finally makes onsite solar pencil for middle-market owners.

Sources: New England Real Estate Journal, C-PACE comes to Rhode Island · U.S. EPA, Commercial Property Assessed Clean Energy overview

Tennessee creates a separate, higher rate class for data centers

The TVA board approved a new data-center rate class carrying an average 10 percent billing increase, and Nashville Electric Service aligned with it effective in October. It is the local front of the national who-pays fight, and a template other utilities will study as they try to keep data center costs off other customers.

Sources: Data Center Dynamics, TVA imposes new rates on data center firms · Chattanooga Times Free Press, TVA to charge data centers more

Local Governance and Federal Policy

Amazon contracts firm nuclear power that already exists

Amazon signed a 20-year power purchase agreement with Constellation to add 190 megawatts of capacity at Maryland's Calvert Cliffs nuclear plant through an uprate, backing billions in investment and keeping the reactors running for decades. The scarcest asset in US energy is firm, carbon-free power available today, and hyperscalers are contracting it.

Sources: Constellation, 20-year PPA adding 190 MW at Calvert Cliffs · World Nuclear News, Constellation and Amazon nuclear PPA

Advanced nuclear is becoming a site-selection factor for powered land

TerraPower, with GE Hitachi and Hyundai E&C, is advancing its Natrium sodium-cooled reactor, 345 megawatts plus molten-salt storage peaking near 500 megawatts, toward 2027 construction in Kemmerer, Wyoming, explicitly targeting data centers and industrial campuses. The advanced-nuclear pipeline is starting to shape where powered land gets developed.

Sources: Construction Review Online, TerraPower data center reactor plan

EV Charging in Real Places

Hospitality is treating EV charging as guest-experience infrastructure

Green Rain Energy Holdings identified two more Driftwood Hospitality properties in Florida for EV charging and is expanding its solar-plus-DC-fast-charging platform into Las Vegas. High-traffic hospitality properties are becoming charging destinations, with owners framing chargers as an amenity rather than a utility.

Sources: GlobeNewswire, Green Rain Energy adds Driftwood EV charging and Las Vegas expansion

Mobile charging stands up fleets in days instead of 18 months

Xos showcased its Hub, a mobile, grid-independent storage and charging system, at APTA TRANSform, letting transit and commercial fleets begin charging in days rather than the year-plus a utility upgrade can take. For logistics and fleet-adjacent property, it removes the single biggest barrier to electrification.

Sources: GlobeNewswire, Xos brings grid-independent mobile charging to transit

Reliability, not plug count, is the real charging metric

Green Water & Power and Autel Energy passed 10,000 installed commercial chargers since 2023, across hotels, apartments, retail, schools, medical and fleets in 12 states, delivering 16.6 million kWh at 99.72 percent uptime. The lesson for owners: drivers do not count your plugs, they remember the one that failed.

Sources: CNHI News, Green Water & Power and Autel pass 10,000 chargers

EV Market Signals

The federal EV tax credit expiration hits one-year milestone on September 30

The federal clean-vehicle tax credit ended one year ago on September 30, closing the incentive that supported much of recent EV demand. Owners underwriting charging should watch how the expiration reshapes local adoption, and weight projects toward sites with proven utilization rather than national forecasts.

Sources: NPR, one year after the end of the EV tax credit · U.S. DOE Alternative Fuels Data Center, expired laws and incentives

Used EV demand remains the steadier signal

Used electric vehicles continue to draw value buyers as prices settle, a more durable demand signal than new sales after the credit lapse. Because used EV owners are more likely to rent or lack home charging, that demand points toward multifamily, workplace and retail charging.

Sources: Recurrent, used electric vehicle buying report

Data Center Demand and Innovation

Vertiv buys its way into behind-the-meter power

Vertiv is acquiring microgrid specialist UtilityInnovation Group in a roughly $1.45 billion deal, adding microgrid controls, onsite generation orchestration and behind-the-meter architecture for sites the grid cannot serve fast enough. When a data-center infrastructure giant buys into onsite power, it signals where building-level power is heading.

Sources: Data Center Dynamics, Vertiv acquires UtilityInnovation · Data Centre Magazine, Vertiv buys UtilityInnovation Group in $1.45bn deal

BNEF nearly doubles its US data center power forecast

BloombergNEF now projects US data centers consuming about 20 percent of the nation's electricity by 2035, nearly doubling its estimate from earlier in the year. The scale of the revision is the story: localized grid stress is arriving faster than utilities can build, reshaping where power-hungry tenants can site.

Sources: Latitude Media, BNEF nearly doubled its US data center power forecast · Bloomberg Law, data centers on track for a fifth of US power by 2035

Welcome to the Era of Electrified, Intelligent Infrastructure.

ChargedUp! — Mon, 05 Oct 2026 19:00:32 GMT

Photo by Andrey Metelev on Unsplash

Smart real estate and smart communities are deploying new, behind the grid solutions that improve NOI, get projects on track and enhance resiliency.

From Subsidies to Survival

The era of electrification driven by federal handouts is closing. It is being replaced by far more urgent drivers: operational survival and competitiveness.

As automakers recalibrate strategies and capital shifts toward infrastructure performance, the U.S. power grid has hit a structural wall. Manufacturing is resurgent, and data centers are placing city-scale demands on supply. The result? A 2,300-gigawatt interconnection queue and capacity delays stretching three to five years. In this constrained market, relying solely on the utility is no longer a strategy; it is a liability.

The New Asset Strategy: Behind the Meter

The current narrative is about more than going green for compliance; it’s about securing power to stay open. To bypass grid bottlenecks and rate inflation, real estate investors and operators are moving energy operations behind the meter, deploying onsite generation, storage, and microgrids.

Intelligence is the Operating System

Distributed assets are unmanageable without a new layer of intelligence. AI has emerged as the essential operating system to balance loads and optimize costs in real-time, while advanced connectivity acts as the nervous system linking every sensor and charger. This convergence transforms buildings from passive consumers into responsive, resilient nodes, turning energy volatility into a manageable, and even profitable, asset class.

Our Mission: Clarity in a Constrained World

We focus on where power technology, AI software, and wireless converge at the edge of the grid, in The Built Environment. We seek to share information and resources with commercial and corporate real-estate leaders, investors, developers and operators and urban planners to foster direct control over outcomes on both sides of the meter.

We serve the builders, backers, and operators of the built environment. From the boiler room to the boardroom, our promise is simple: We separate signal from noise.

We don’t just cover technology; we map the path to profitable, resilient infrastructure. Leadership today demands mastery of three converging fronts:

The New Asset Class: Energy, connectivity, and AI are no longer separate utilities - they are a single, investable asset class.
The "Behind-the-Meter" Advantage: As the grid stalls, value shifts to the edge. Microgrids, batteries, private 5G, and solar are now the primary tools to bypass delays, secure power for data centers and campuses, and drive Net Operating Income (NOI).
AI Enables Capacity: Hardware provides the power, but AI provides the scale. Without artificial intelligence to orchestrate these systems, modern infrastructure cannot function.

From EV to Everything Electrification

Founded to track the EV charging revolution, ChargedUp! has evolved with the market. Today, we cover the full spectrum of intelligent electrification, providing the data-grounded narratives and expert forums you need to build, finance, and operate America’s next generation of infrastructure.