Mexico electricity: the economic cost of delayed usable capacity

01 — Commercial issue and boundary

Mexico's electricity expansion creates investment and procurement demand, but aggregate demand does not demonstrate that a particular site has access to deliverable power or that additional installed megawatts earn a positive return. LARGITAS examines the marginal contribution of an asset whose commissioning date changes, then asks which engineering, permitting or contracting intervention could alter the critical path at a defensible cost.

This study isolates one hypothetical 20 MW power asset, not a named generator, a signed PPA, a CFE construction package or a measured historical result. Its value is transparent mathematics applied to a decision boundary, not an invented claim of client savings. The real project alternative could be generation, a private energy service, flexible load or constrained grid-connected infrastructure, but contractual rights and economics will differ substantially.

02 — Actual Mexican electricity evidence

The first five figures are published in the Proyectos México electricity profile; the last two are from Mexico's published electricity development plan. A 2039 projection must never be subtracted from a 2025 SIN observed peak as if the series were methodologically continuous. If one reports a growth rate, use a consistent system perimeter, peak definition and starting year. [S1] [S2]

03 — What actually makes a power asset profitable

Commissioned MW generate economic value only when the output is produced, delivered, settled and monetized at a margin after variable costs and contractual losses. Three useful but different measures are plant nameplate capacity, dependable/contracted capacity and energy actually sold. Their distinction matters in intermittent renewable projects, thermal projects with outages, transmission-constrained nodes and high-load commercial facilities.

A project may be physically complete but unable to sell: a grid interconnection is pending, a transmission constraint creates curtailment, a customer has no effective take-or-pay obligation, metering is incomplete, fuel is unavailable, or the tariff/reference price is too low. Project scope, commercial structure, dispatch rights and risk allocation must precede an NPV claim.

04 — Hypothetical cash-flow contract

The model assumes 20 MW deliverable capacity; 70% effective use; 8,760 annual hours; MX$320 per MWh of incremental contribution after modeled variable expenses; MX$110m initial capital committed at time zero; 12% annual discount rate; and ten full operating years. The annual operating contribution is 20 × 0.70 × 8,760 × 320 = MX$39,244,800. The model is not an observed tariff, EBITDA margin, actual generation, awarded contract or forecast of any named company.

If the ten-year operating period starts one year later without shifting the capital already spent at time zero, the cash flows are at t=2 through t=11 instead of t=1 through t=10. That is the comparability rule. If actual equipment or construction disbursements also move, or a contract ends at the same calendar date, the two projects need different equations and the assumption must change.

05 — Derivation and reconciliation

• Annual contribution C = P × 8,760 × u × m, with P in MW, u a fraction, m in MX$/MWh.
• PV of the on-time stream = C × Σ(t=1..10) 1/(1.12)^t.
• NPV on time = PV of operating contribution − MX$110m = MX$111,741,873 (rounded).
• NPV delayed one year = C × Σ(t=2..11) 1/(1.12)^t − MX$110m = MX$87,983,815 (rounded).
• Incremental value from preventing a full-year deferral ≈ MX$23,758,058.

The difference is not one year's full undiscounted contribution and not a cash receipt at t=0. It represents the difference in present value of two equal-tenure contribution streams. The distinction between present-value benefit, extra revenue, free cash flow, realized profit and avoided capital spending must be maintained in marketing materials and engagement reports.

06 — What changes the result

Actual sensitivity must additionally vary the discount rate, full/partial-year delay, contracted or merchant exposure, ramp profile, dispatch priority, curtailment, availability, maintenance, financing structure, currency basis, reliability penalties and commodity-price scenarios. If contributions are negative, accelerating them can destroy value. Positive NPV is necessary for investment attractiveness but insufficient without bankability and execution certainty.

07 — Least-cost intervention rather than maximum acceleration

Suppose an engineering response can reduce a planned one-year delay but requires upfront incremental spending. The investment test is expected recovered discounted contribution plus other supported contractual benefits minus acceleration cost, downtime risk and additional operating expenditures. A proposed contractor incentive of MX$9m with an independently supported 30% chance of avoiding the full one-year delay has an expected gross benefit of 0.30 × MX$23.758m = MX$7.127m, and an expected incremental NPV of approximately −MX$1.873m before additional risks. Reject it under these assumptions. A MX$4m intervention at the same success probability would yield approximately +MX$3.127m before risks.

The success probabilities and incentive amounts in that comparison are hypothetical. Their purpose is to show why a higher-capacity or faster schedule option does not automatically deserve funding. In real projects, success probability should be derived from verifiable schedule controls, supplier lead-time distributions and independent engineering review rather than asserted without evidence.

08 — Engineering and economics must reconcile

The mathematical model requires delivered and monetized energy. Engineers must establish firm/nonfirm connection, load flow and protection results, voltage tolerance, outage performance, construction milestones, mechanical completion, energization, reliability requirements and actual meter-to-cash arrangements. For generation, confirm fuel availability or wind/solar resource, degradation, P50/P90 production, operational availability and curtailment exposure. For a large load, confirm dispatchable connection, backup generation restrictions and contractual demand charges.

A transmission line at 400 kV is not a 400 MW supply promise. A 675 MVA transformation project cannot be treated as 675 MW without an assumed power factor and usable capacity reserve. National generation balances do not establish the thermal ratings or stability limits at one specific nodal connection.

09 — Procurement and supply-chain mechanism

The relevant supplier opportunity is the contract package that sits on the path to first paid operation. Packages might include transformer supply, switchgear, tower and conductor delivery, engineering design, grid protection, SCADA, commissioning tests or O&M, depending on the project. Build the package-specific owner map and validate procurement stage, approved budget, specifications, imports, competitor pool, bonding and warranties. Neither 111,195 km of existing transmission nor the 2039 demand forecast is a tender list.

Each opportunity should be valued at contribution after incremental delivery costs, working-capital financing, bid spend, contractual penalties and collection risks. A procurement package that speeds the project's service date can be valuable to the owner but still unprofitable to a supplier if the contract price and exposure are wrong.

10 — Core commercial risks

Demand risk: no executed offtake, spot-market volatility or stranded output. Delivery risk: interconnection delay, curtailment or missing permits. Cost risk: foreign-exchange depreciation, OEM lead times and logistics. Financial risk: unhedged nominal-versus-real discount mismatches, interest during construction and cost of capital. Regulatory risk: eligibility, dispatch, wheeling, settlement and environmental requirements under the applicable 2025–26 framework. Counterparty risk: payment guarantees, invoice disputes and change-order collection.

The discount-rate basis must match nominal MXN cash flows if expenses, tariffs and inflation are modeled in nominal pesos. A cash-flow table mixing nominal MXN with a real or USD discount rate creates a false value number. Use an after-tax equity rate for equity cash flows and after-tax WACC for unlevered project cash flows; do not mix them.

11 — What would falsify the opportunity

Reject a delay-mitigation proposal if the planned delay is not actually critical, if output cannot be monetized earlier, if cash flow is not positive, if additional risks exceed expected present-value benefits, if the contract has different operating-life boundaries than assumed, or if the supplier can achieve similar performance with cheaper intervention. An alternative project with lower up-front CAPEX and later commissioning may also generate a higher risk-adjusted NPV. The research obligation is to rank defensible alternatives, including doing nothing.

12 — Client deliverables, model governance and economic attribution

An executive-grade mandate should produce: dated market source ledger; regulatory and grid-access summary; project schematic; phase-by-phase schedule and owner; demand/offtake analysis; bottom-up CAPEX/OPEX/cash taxes; scenario financial model with audit trail; financial-at-risk bridge; counterparty and supplier diligence; and a go/no-go statement that names the highest-value next action. Later performance attribution requires an agreed baseline, approved intervention, before/after commissioning evidence, actual energy sales and matched costs. Do not call prospective contribution a proven saving before those records exist.

13 — Evidence register and updates

[S1] Proyectos México electricity sector profile, 2025 metrics (official public-sector investment information); [S2] SENER published 2025–2039 electricity sector plan, 2024 baseline and 2039 scenario. Definitions and observation years are critical. The economic model is separately identified as a scenario. All recommendations are subject to contracts, verified physical access and acceptable risk-adjusted economics.

14 — Advanced annex: discount-rate, tenor and contract exposure

Holding annual cash contribution, ten-year life and one-year shift constant, the nominal present-value timing difference increases across these three rates because the cost of moving the same full stream later becomes larger. This does not mean a higher WACC makes the project intrinsically better: both scenario NPVs tend to be lower at a higher discount rate. For an actual asset, apply probabilities for partial curtailment, outages, merchant prices and offtaker default instead of assuming all 70% utilization is saleable.

Tax and capital-structure checks

Use after-tax free cash flow to the firm with after-tax WACC, or after-tax equity cash flow with the corresponding equity return. Revenue taxes, depreciation tax shield, working capital, asset retirement and deferred capital spending can materially alter value. A positive incremental timing NPV does not establish DSCR coverage or lender acceptance; build quarterly CFADS/DSCR and minimum cash balances under stress. Real versus nominal and MXN versus USD consistency must be enforced independently in the workbook.

15 — Attribution protocol for demonstrable savings

Before a mandate, obtain a client-approved baseline schedule, decision dates and competing alternatives. After an intervention, preserve commissioning certificates, invoices and collected contribution; compare performance under a common commodity-price and demand assumption, then separate effects of changing market prices. Report four columns: expected economic gain at approval, direct execution cost, realized incremental cash after acceptance, and unproven/alternative effects. Without actual records, only conditional model outputs can be reported.

15A — V5 battery reference: four-hour hypothetical tariff screening (superseded for operations)

The official January 2026 GDMTH Bajío electricity components are MX$0.8612/kWh base and MX$1.9418/kWh peak. Common variable charges are MX$0.1801/kWh transmission, MX$0.0076/kWh CENACE and MX$0.0069/kWh ancillary services. These are a historical tariff-month snapshot, not a current October bill or a verified contract. GDMTH demand/capacity charges remain outside the arbitrage model.

For each case, 22 assumed operating days per month, a hypothetical 4-hour peak discharge interval, 80% maximum depth-of-discharge and 90% retained end-of-life energy yield. Discharge power (kW) = delivered monthly peak kWh/(22 × 4h). Required installed energy (kWh) = monthly peak kWh/(22 × 0.80 × 0.90). Charging-energy purchased = peak kWh/efficiency. Every installed-cost case applies a hypothetical MX$18/US$ conversion strictly for sensitivity, NOT an observed FX quote. For comparison, reference US$192/kWh is the global 2024 utility-scale installed average and cannot be treated as a verified Mexican customer EPC offer.

Three-scenario decision analysis

The cases below are alternative assumptions, NOT a probability distribution. The central case is a documented reference scenario, not the arithmetic mean of three cases. Until defensible probability evidence is available, reporting a probability-weighted expected value would manufacture precision. No modeled gain is a realized client saving.

Formula (units MXN and kWh): gross monthly variable-charge benefit = peak displaced kWh × [(1.9418 + 0.1946) − (0.8612 + 0.1946)/η]. Net monthly benefit = gross − incremental operating costs. NPV = net monthly benefit × Σ(t=1..60) (1+r_month)^(-t) − installed kWh × assumed US$/kWh × assumed 18 MXN/USD. Here r_month = (1.12)^(1/12) − 1. Under all three cases, tariff-only energy shifting fails to recover the estimated installed battery cost. The answer is not a sale of batteries; it is a NO-GO for tariff-only capital approval until additional verified demand-reduction or reliability benefits outweigh the shortfall. Further bill, regulatory, engineering and supplier diligence may change the conclusion. Decision rule: report the CENTRAL scenario as the provisional working case and the full range separately. Do not take the mean of three hand-picked cases; use a probability-weighted expectation only when probabilities have an auditable empirical basis. Critical missing inputs: current GDMTH tariff month; 12–24 months of 15-minute measured load and true peak tariff windows; energy and demand/capacity bills; battery AC/DC losses; onsite space and fire-code compliance; degradation warranty; interconnection permissions; local turnkey bids; taxed capital structure; site-specific USD/MXN; cash-tax treatment; insurance; and actual duration of each peak window. [V5-S1] Diario Oficial de la Federación, 30 January 2026, January 2026 regulated electricity tariffs, División Bajío, GDMTH. [V5-S2] IRENA, Renewable Power Generation Costs in 2024 (published July 2025), utility-scale BESS average total installed cost US$192/kWh for 2024. [V5-S3] BloombergNEF, 9 December 2025, stationary battery PACK price US$70/kWh for 2025 — packs are not complete installed systems.

16 — V6 calendar-aware dispatch and investment decision (supersedes V5 flat peak-hour assumption)

The earlier V5 battery example assumes an identical four-hour peak window every operating day. The National Interconnected System (SIN) GDMTH schedule instead varies by season: weekday summer peak 20:00–22:00 (two hours), weekday winter peak 18:00–22:00 (four hours), and a two-hour winter Saturday peak (19:00–21:00). Summer runs from the first Sunday in April to the Saturday preceding the final Sunday in October. This new 60-month model uses calendar-day windows from November 2026 through October 2031 and replaces V5 for prospective operating decisions; V5 remains a historic four-hour sensitivity, not a year-round dispatch forecast.

Three coherent scenarios

Scenario parameter ledger

Daily shifted energy = dispatch-capture factor × min(discharge kW × eligible peak hours, original battery kWh × 80% usable depth × 90% engineering derating × (1 − annual degradation)^years). Charging kWh = delivered kWh / round-trip efficiency. Monthly modeled variable-charge difference = discharged kWh × (peak + common charges) − charged kWh × (base + common charges), each grown by assumed nominal tariff escalation; subtract operating cost escalated separately. NPV = sum of 60 discounted monthly net differences − initial illustrative installed cost. Break-even additional monthly cash = max(0, −NPV) / sixty-month discounted annuity factor.

These are three internally consistent judgments, not a sample distribution; use the central working reference, present the downside/upside range, and do NOT average the three outcomes. Tariff escalation, battery degradation, dispatch capture, installed cost and efficiency are unverified case assumptions. The January 2026 Bajío GDMTH tariff is the historical rate anchor rather than an asserted October 2026 price. Only weekday peak hours and the documented winter Saturday peak are counted; holidays have not been separately screened, so the dispatch-capture factor is an illustrative availability adjustment, not an audited holiday calendar.

The break-even cash requirement is NOT an assumed demand saving or contracted revenue: it is the additional independently verifiable net monthly value needed from demand-charge reductions, resilience, or other lawful benefits before an investment could be approved. Never add two benefit categories without checking for overlapping kWh or double-counted demand reductions. Actual client invoices, interval load records, battery warranties, accepted invoices from integrators, current schedules, FX and tax forecasts are needed to authorize capital.

[V6-S1] Official 2021 GDMTH SIN seasonal peak timing: https://sidof.segob.gob.mx/notas/docFuente/5747760 . [V6-S2] DOF Bajío January 2026 GDMTH variable-charge tariff: https://sidof.segob.gob.mx/notas/docFuente/5779203 . [V6-S3] IRENA 2024 globally weighted installed BESS cost (published 2025): https://www.irena.org/Digital-Report/Renewable-Power-Generation-Costs-in-2024 . Model, sixty-month ledger and test procedure: models/v6_seasonal_dispatch.json and models/v6_monthly_cashflows.csv.

October 2026 evidence refresh: The archived January 2026 Bajío GDMTH values were directly checked against the official 30 January 2026 DOF primary notice. Source verification confirms historical input accuracy, not a live 2026 customer tariff, billing classification or 2027–31 forecast. The 2025 official SIN calendar confirms the reference weekday peak windows; applicability to each later year, holidays and any contractual changes must be checked prior to a client recommendation.

17 — V10 correction: compare installed costs using usable capacity, not nameplate capacity

IRENA's published global 2024 installed battery-cost benchmark uses USD per usable kWh (Figure 9.2), not an unrestricted nominal/nameplate battery-energy denominator. The earlier V6 dispatch model multiplied its illustrative nominal battery capacity by those per-kWh costs; it is preserved as a historical calculation, but that CAPEX denominator is not equivalent to the source's stated denominator. [S3]

This corrective screen provisionally treats 80% of nominal battery capacity as initial usable capacity, following the explicitly assumed depth-of-discharge limit in the earlier sizing exercise. It does not multiply CAPEX by the separate 90% engineering/terminal-energy derating: that factor governs modeled dispatch and is not a demonstrated IRENA capacity definition. No particular Mexican supplier's warranted usable AC capacity has been verified; only a vendor/EPC quotation with matching kWh definitions can establish actual installed capital. Installed cost assumptions of US$260 / US$192 / US$150 per usable kWh and MX$18/US$ are illustrative scenario inputs, not supplier prices or current exchange rates.

For each scenario: provisional initial usable kWh = nominal kWh × 0.80; provisional CAPEX (MX$) = initial usable kWh × assumed installed USD/usable-kWh × assumed MXN/USD. Reuse the V6 independently audited 60-month tariff cash flows unchanged; corrected NPV = V6 discounted tariff net contribution − provisional corrected CAPEX. The remaining uncovered investment divided by the 60-month discounted annuity factor is a break-even threshold, not observed monthly savings.

The investment remains a NO-GO based solely on time-of-use variable energy tariffs in all three cases, even after the cost-denominator correction. The corrected central illustrative CAPEX is about MX$17.45 million, compared with MX$21.82 million in the previously published V6 arithmetic. That is a modeling correction, not a verified MX$4.36 million saving or a procurement discount. Any actual recommendation requires reconciled usable AC-kWh specifications, a Mexican turnkey EPC offer, interval load, current tariff schedule, tax/capital cost, warranted degradation and full stack of bill components. The central case is a reference scenario rather than an arithmetic mean or probability-weighted estimate. The original V6 result remains displayed above only for historical traceability. [S3]