"The Grid Is Not Coming to You" - FENECON USA’s Andrew Dunn on Why 50–80% of Interconnection Sites Fail
By Keith Reynolds | Publisher & Editor, ChargedUp!
“The Grid Is Not Coming to You.”
FENECON USA’s Andrew Dunn argues that 50–80% of U.S. interconnection sites won’t get built—not for lack of technology or capital, but because execution fails. The grid isn’t the bottleneck; the process around it is. Here’s what actually breaks projects, how planners can move faster, and why behind-the-meter storage now functions as a core CRE asset strategy.
If you’re waiting for a bigger service from the utility, you’re timing your business to someone else’s capital plan. Speed to power has become a site-selection variable, and the penalty for getting it wrong shows up as stranded leases, missed openings, and repriced assets. That’s the through-line in Andrew Dunn’s field notes after two decades building distributed energy: the work fails less from physics than from process.
Who is Andrew Dunn (FENECON USA), and why listen?
Andrew Dunn has deployed energy systems in 40+ U.S. states and across four continents—microgrids in the Philippines, port infrastructure in South Carolina, and a lecture series at Clemson University on what the grid cannot deliver. He now serves as Energy Solutions Director at FENECON USA, the South Carolina-based subsidiary of German manufacturer FENECON turning surplus EV modules into commercial-scale storage since 2017.
“Maybe 50 to 80 percent of sites being developed and going to interconnection won’t get built. Not because of lack of aspiration. It’s that you didn’t work right, or have the knowledge of how to do it.” — Andrew Dunn
When Dunn talks about what breaks distributed energy projects, he is not reading from a policy brief. He is describing what he has watched happen on real sites, with real money, in real jurisdictions. When he sat down with ChargedUp! for a wide-ranging conversation recorded just after the ChargedUp! Pavilion at the American Planning Association's National Planning Conference in Detroit, he delivered a diagnosis that every building owner, developer, and urban planner should hear.
Why do 50–80% of interconnection sites never get built?
Because execution breaks under modern constraints—permits, equipment, sequencing, and stakeholder alignment—not because batteries or financing don’t exist.
Process risk: Interconnection studies arrive after notice-to-proceed and add 30–60% to costs, flipping IRR and killing debt tranches.
Equipment lead times: Distribution transformers commonly require 24–36 months; BESS hardware often needs 12–18 months from order to delivery.
AHJ variability: County-by-county NFPA 855 interpretation can add 6–18 months. UL 9540A test documentation and enclosure siting trigger additional reviews.
Financing simultaneity: Tax equity, debt, and sponsor equity must close together; slippage in any leg stalls the stack.
Track record gap:Teams without two or three comparable completions in similar jurisdictions experience preventable overruns.
Scale this against the queue: by late 2024, roughly 2,290 GW of generation and storage sought interconnection in the U.S., yet only ~14% of projects entering queues since 2000 reached operation (Lawrence Berkeley National Laboratory’s Queued Up 2025). The grid isn’t the bottleneck; the surrounding process is.
What market forces are raising the stakes in 2026?
Demand is outpacing governance, and costs are not waiting.
Data center load: U.S. demand projected at ~75.8 GW in 2026 and ~134 GW by 2030 (S&P Global’s 451 Research). Primary markets absorbed ~2,498 MW of new capacity in 2025.
Rate pressure: Utilities requested a record $31B in rate increases in 2025 (vs. $15B in 2024), per PowerLines. U.S. commercial rates rose ~10.7% YoY through Feb 2026; five-year increase ~21% (EIA).
BESS scale-up: North American BESS market reached ~$20.8B in 2025; projected CAGR ~15.5% to ~$49B by 2031 (Mordor Intelligence).
Owners and planners are competing with data centers for utility capacity, contractors, gear, and permits, which are often subject to legacy rules not written for distributed assets.
What actually breaks projects on the ground?
Technology is rarely the first failure. Sequence is.
Interconnection timing: Don’t trigger major equipment orders before system impact studies. If study outcomes require upstream upgrades (e.g., feeder reconductoring, substation transformer swaps), your cost base can jump 30–60%.
Transformer reality: Treat distribution transformers as a critical path item with 24–36 month lead times. Verify utility-owned vs. customer-owned responsibilities early.
AHJ alignment: Pre-meet with the fire marshal and building officials on NFPA 855, UL 9540/9540A, setbacks, fire access, and systems placement. Misalignment here regularly adds 6–18 months.
One-line completeness: Submit utility-grade one-lines with protective device coordination, metering, and clear point-of-common-coupling details. Ambiguity invites rework.
Financing simultaneity: Your tax equity timeline must match equipment delivery and COD dates. Delays can force repricing or loss of the tranche.
Track record and replication: Require documented comparables from EPCs and consultants in your specific utility territory and code regime. New-to-type teams have a steep—and costly—learning curve.
“If you can’t write down the cases you’ve done this once or twice previously, you can’t replicate it.”— Andrew Dunn
How does FENECON USA shorten time-to-power?
FENECON USA’s core product addresses a tangible blocker: equipment availability and cost. The company integrates surplus EV battery modules—often new but undeployed—into containerized BESS for commercial and industrial sites.
Scale: A single container holds up to ~5 MWh—comparable to the peak load of a small manufacturing facility or large municipal building.
Existing module systems: Uses the module’s native battery management and cooling, reducing engineering complexity and shortening procurement lead times relative to new cell supply.
Economics: Lower $/kWh hardware costs and earlier in-service dates can materially improve IRR, particularly in high-demand-charge territories.
U.S. inventory: FENECON USA is building inventory in South Carolina and developing a second CarBatteryReFactory for U.S. demand, replicating its Lower Bavaria manufacturing model.
For CRE owners, behind-the-meter BESS can protect NOI by reducing demand charges, shifting load out of peak-price windows, and offering backup to energy-sensitive tenants.
At a glance: numbers owners and planners ask for
Transformer lead time: ~24–36 months common.
BESS hardware lead time: ~12–18 months from order.
NFPA 855/AHJ review: Plan for +6–18 months unless pre-aligned.
Value-to-NOI rule of thumb: Every $1,000 in annual energy savings can add roughly $12,500–$20,000 in asset value at prevailing cap rates (CBRE).
Where do planners actually hold the lever?
Not in transmission builds (that’s a decade-long drumbeat) but in local governance, where weeks and months are won or lost.
Zoning modernization: Update codes so BESS and solar aren’t blocked by legacy setbacks, noise rules, or lot coverage definitions that never contemplated energy enclosures.
AHJ capacity: Budget small, steady advisor retainers ($5–10k/month) to guide multi-year code updates and utility coordination—rather than one-off procurements.
Comprehensive plan alignment: Bake distributed energy frameworks into comp plans to strengthen standing in interconnection proceedings.
Utility pre-engagement: Establish a documented process for pre-application meetings, data sharing, and milestone tracking.
Communities that do this move faster—Dunn’s observed it across 40+ states. The upside shows up in site selection for advanced manufacturing, data centers, logistics, and professional offices.
A pragmatic path to NOI protection for CRE owners
Storage has become an operating decision. A 100,000 sq. ft. office cutting energy costs by ~30% may add ~$55,800 to annual NOI, translating to roughly $700k–$930k in asset value depending on cap rate. Pair BESS with tariff analysis, tenant critical-load mapping, and a demand charge reduction strategy to turn volatility into a controllable line item.
Prioritize: Sites with high demand charges, predictable peaks, and outage-sensitive tenants (labs, healthcare, data rooms).
Sequence: AHJ pre-meeting → utility pre-application → one-lines → interconnection study → then major equipment orders.
De-risk: Require EPCs to produce two or more analogous completions in your code and utility environment.
Model: Run scenarios for TOU arbitrage, demand shaving, resilience value, and DR/ancillary revenue where available.
The through-line: power is local now
AI buildouts, EV adoption, reshoring, and building electrification are piling onto the same feeders. The grid can’t expand fast enough to meet them on their timelines. Distributed energy, flexible interconnection, and onsite storage have moved from optional to operational. The owners and communities treating energy like capital planning—not a utility afterthought—will accrue advantage through this decade.
“It’s not about data centers. It’s about doing things right for the community. The data centers get built as a result.”— Andrew Dunn
Frequently Asked Questions
What is FENECON USA and how is it different?
FENECON USA is the U.S. subsidiary of FENECON (Germany). It integrates surplus EV battery modules—often new but undeployed—into containerized battery storage systems for commercial and industrial sites. Using modules with existing battery management and cooling reduces lead time and hardware cost versus sourcing new cells, without changing core safety and code compliance requirements.
Why do so many interconnection applications stall or die?
Most failures trace to process, not technology: late-stage interconnection upgrade costs, 12–36 month equipment lead times, AHJ/NFPA 855 delays, and financing stacks that require simultaneous closings. Teams without comparable completions in similar jurisdictions are especially vulnerable to overruns and cancellations.
How long does it take to install a commercial BESS?
Assume hardware availability of ~12–18 months and plan for 6–18 months of permitting/AHJ review depending on NFPA 855 interpretation and site conditions. Civil, electrical, and commissioning windows vary with interconnection upgrades. Pre-meetings with utilities and fire officials often save months.
How does NFPA 855 affect schedule and design?
NFPA 855 governs energy storage installation safety. It influences setbacks, fire access, ventilation, and documentation (e.g., UL 9540/9540A). Local interpretation differs; engaging the fire marshal early to agree on siting and documentation frequently prevents redesigns and re-reviews.
What should CRE owners ask an EPC before notice to proceed?
Ask for two or more analogous projects completed in the same utility territory with NFPA 855 compliance; a transformer procurement plan; utility-grade one-lines; an interconnection study path; and a financing calendar aligned to delivery and COD. Require named references and site addresses.
Next Steps
If you own or plan sites that will need new capacity in the next 24–36 months, treat time-to-power as a gating risk. Start before the load arrives.
Hold a joint pre-meeting with your AHJ (fire/building) and utility to align on NFPA 855, metering, and PCC details.
Request a utility pre-application data packet; submit complete one-lines and protective device coordination.
Run a tariff/demand analysis to quantify demand charge exposure and storage value; socialize scenarios with finance early.
Ask EPCs for two analogous completions in your jurisdiction; verify references and commissioning dates.
Track transformer and BESS lead times weekly; tie your financing calendar to delivery and COD windows.
