The bottleneck for AI data centers is not GPUs — it is power. Using only public sources linked as footnotes and explicitly stated assumptions, this page sets out ① the structural power bottleneck, ② constraints of alternative sources (gas turbines, SMR, fuel cells), ③ the cost structure as low-carbon pre-investment and applicable policy benefits, and ④ a three-scenario economic analysis with Blue Energy carbon-neutral alignment. No CAYNMARS trade-secret information is included.
Data center power demand is surging with global hyperscaler AI investment, while supply takes time. The IEA estimates that building new transmission lines takes four to eight years in advanced economies, putting around 20% of planned data center projects at risk of delay[2]. In Korea, grid connection waits of 18 months to over 4 years have been reported[7], intensified by concentration in the Seoul metropolitan area.
Gartner press release (2026-06-10): 447→565TWh (+26.4%), power demand 104→132GW · IEA Energy & AI: approx. 945TWh by 2030 (more than doubling)
Korean grid connection waits of 18 months to 4+ years reported [7] · Fuel cell build period is a company assumption based on industry norms
Electronic Times (2024-10-23) · Korea Energy Agency price statistics — annual figures are representative approximations
That the initial levelised cost of fuel cell self-generation sits somewhat above the KEPCO tariff is not simple inefficiency — it reflects pre-investment in high-efficiency generation and carbon-reduction technology (capture-ready design, a low-carbon hydrogen pathway, and lifecycle MRV measurement). Grid electricity carries neither verifiable low-carbon attributes nor immediate availability without a connection queue; that value sits inside this gap. Once Distributed Energy Special Zone exemptions and hydrogen and fuel cell support schemes are taken into account, the effective gap narrows substantially.
Continuous, low-noise, high-efficiency generation configured for data center loads. Meeting the efficiency threshold can qualify for an uplift in renewable energy certificate (REC) weighting[8].
Capture-ready design and a low-carbon hydrogen transition pathway are built in from the start — internalising future carbon regulation costs at the outset.
If designated, direct power trading exemptions create room to reduce standing charges and ancillary costs[9]; participation in the hydrogen power bidding market is possible (2026 volumes: 930GWh/yr general, 500GWh/yr clean)[10].
Lifecycle MRV measures and reports carbon intensity, producing data anchor customers can use directly for Scope 2 carbon accounting.
The net LCOE deducts assumed policy benefits of roughly 20% from the gross cost — room to reduce standing charges and ancillary costs under special-zone direct trading, revenue from hydrogen power bidding, REC and efficiency weighting, and heat recovery (company assumptions). Special-zone designation and bid awards are not confirmed, and actual benefits will depend on designation, award terms and contract structure. Item-by-item derivations are provided in the data room after NDA.
Comparing the KEPCO general tariff with fuel cell LCOE for 2026–2045. Starting values: KEPCO general average selling price 172.99 KRW/kWh (2025)[4] and fuel cell LCOE of 290 KRW/kWh gross · 232 KRW/kWh net of policy benefits (company assumptions). Given that Korean industrial tariffs rose over 60% in three years (approx. 17%/yr)[3] and the grid investment burden created by AI demand, we set three scenarios with tariff growth of 5–9% and LCOE decline of 2–4.5% from technology maturity and volume production. All are assumptions, in nominal terms. The chart cycles through the scenarios automatically; the basis can be switched between gross and net below.
| Year | Tariff (KRW/kWh) | LCOE (KRW/kWh) | Gap | Annual saving (100m KRW) |
|---|
KEPCO general tariff starting at 172.99 KRW/kWh (2025)[4] · fuel cell LCOE starting at 290 KRW/kWh gross and 232 KRW/kWh net (policy benefits assumed at approx. 20%) · 40MW-class × 8,760h × 60% utilisation assumed · nominal prices · NPV discount rate 7% assumed · cumulative saving = Σ max(0, tariff − LCOE) × generation. These are scenario calculation results based on the selected assumptions, not company forecasts or commitments.
The LCOE build-up (capex, fuel cost, utilisation, financing cost, O&M, stack replacement, carbon cost, and item-level policy benefits) is project trade-secret and provided with the full methodology through the data room after mutual NDA · This page does not constitute investment solicitation · As of
AI data centers are a 24/7 baseload, so intermittent sources alone cannot satisfy carbon-neutral requirements. Our Blue Energy framework designs a staged pathway on high-efficiency fuel cells — capture application → low-carbon hydrogen → blue-to-green transition — and measures each stage through lifecycle MRV. It allows one asset to serve both the tightening carbon policy of the 2030s and anchor customers' demand for 24/7 carbon-free energy (CFE).
Gas-based high-efficiency fuel cells — lower emissions than grid supply, available 24/7
Exhaust CO₂ capture and utilisation pathway reflected — further reduction in carbon intensity
Blending ratio expanded in stages as hydrogen supply allows — linked to the hydrogen power bidding market[10]
Clean hydrogen conversion stage — carbon-free power supply as a long-term target
These stages are our own internal framework, not an official certification grade. Reaching each stage depends on hydrogen supply, policy and technology maturity, and the term “carbon neutral” is used only after third-party verification of operating data.
In short, the initial unit gap is a price that already reflects 2030s carbon regulation costs and anchor customers' low-carbon requirements. With policy benefits applied that gap halves, and where rising tariffs meet technology maturity in the early-to-mid 2030s it can invert into a cost advantage.
Gas turbines are constrained by supply chains; SMRs by time. Fuel cells are the realistic on-site option you can start building now. The initial cost gap is a pre-investment in low-carbon technology, and with special-zone and hydrogen policy benefits applied it narrows to roughly 59 KRW/kWh — less than half. Where rising tariffs meet technology maturity in the early-to-mid 2030s, it can invert into a cost advantage (under the stated scenario assumptions). Project Nexus builds on this analysis with site rights and community consent secured and generation licensing in preparation.