Note: this is a composite case based on recurring patterns we see across mid-sized Mexican manufacturing companies. It combines representative elements from several clients to illustrate a typical MEM migration without exposing any specific client's information.
When an auto-parts company with three plants in the Bajío region came to us in late 2024, the opening conversation was about electricity cost. The consolidated annual bill exceeded MXN 65 million and was growing 18% year over year despite operational efficiencies. The CEO's question was direct: "Do we have room to move this, or have we hit the ceiling?"
Twelve months into the migration to the Wholesale Electricity Market (MEM) as a Qualified User, sustained net savings sit at 28%. But the headline number is only the visible part. The project was as much an operational redesign as an energy migration, and that explains why the result exceeded the base-model projections. This case documents how we got there, which decisions moved the needle, and what didn't work as expected.
The client: auto-parts manufacturer in the Bajío
Base profile:
- Sector: auto-parts manufacturing (stamping and sub-assembly for automotive OEMs)
- Operation: 3 plants across Bajío states, all under the same corporate RFC
- Aggregated contracted demand: 4.2 MW (1.6 + 1.4 + 1.2 MW per plant)
- Consolidated annual consumption: 22,500 MWh
- Operation: 3 shifts, 6 days/week, scheduled holiday shutdowns
- CFE contract: industrial GDMTH tariff at each plant
- Consolidated annual electricity cost (2024 reference): approx. MXN 65 million
The three plants individually qualified as Qualified Users by the 1 MW threshold, opening the possibility of independent or coordinated migration. That decision —migrate the three together or in stages— was one of the project's first friction points.
The challenge: rising bill despite efficiencies
The paradox the client arrived with: each year the operations team documented consumption reductions —between 2% and 4% from efficiency initiatives—, yet the bill rose 15–20%. The explanation came in three layers:
- CFE Basic Supply tariff adjustments (energy and demand components)
- Recurring power-factor penalties at two of the three plants
- Excess-demand charges at the largest plant
Additionally, the parent corporation —headquartered in the United States— had set Scope 2 emissions targets that required justifying reductions in electricity footprint. The local team had no mechanism to access CELs or to demonstrate a renewable component.
The diagnostic: four key findings
The first 6 weeks were diagnostic, not sales. What we found:
1. Consolidated load factor of 64%. Good for migration. Three-shift operation makes consumption predictable and improves the firm-component cost.
2. Power factor of 0.86 at two plants. Below the required 0.90, with accumulated penalties of approximately MXN 1.8 million annually. Compensable with capacitor banks —investment near MXN 800,000 with payback shorter than 6 months—.
3. Partial Grid Code compliance. The large plants met essentials; the small one had harmonic distortion out of spec and unstable voltage regulation. Risk of sanction and CENACE observations post-migration.
4. Metering system not compatible with the CENACE Metering Manual. Two of the three plants required meter replacement to participate in the MEM.
The diagnostic was delivered with a 6-month plan that included fixing the four points before initiating CRE registration. That decision —not to take shortcuts— was central to subsequent results.
The strategy: staggered migration by plant
The initial temptation was to migrate the three plants simultaneously to maximize negotiation leverage. We decided the opposite: staggered migration with the largest plant first, the other two at 90 days.
Reasons:
- Controlled operational learning: if something went wrong with the first, the other two stayed on CFE as backup during adjustment
- Real MEM operational data to refine quotes for plants 2 and 3
- Distributed financial capacity: financial guarantees were staggered instead of hitting in one quarter
- Internal team trained plant by plant, not in a big-bang
For the contract, we negotiated with a supplier featuring 30% renewable generation under physical PPA, protected indexation (natural gas with cap), 25% flexibility bands above committed demand, and decreasing exit penalties.
Product structure: 80% firm (fixed price with protected indexation), 20% spot-exposed. That ratio was chosen specifically for the high-stability load profile.
The 12-month results
| Indicator | Before (2024) | After (12 months post-go-live) |
|---|---|---|
| Annual electricity cost | $65 M | $46.8 M |
| Savings vs base | — | $18.2 M (28% net) |
| Power factor (avg) | 0.86 | 0.95 |
| PF penalties | $1.8 M / year | $0 |
| Renewable component | 0% | 30% |
| Grid Code compliance | Partial | Certified |
| ESG reporting (Scope 2) | Not reportable | Reportable with CELs |
Importantly, the 28% is net savings, with the following already discounted:
- Consulting fees (one-time + maintenance)
- Financial guarantees
- Capacitor bank investment
- Metering system replacement
- Grid Code remediation at the small plant
Surface gross savings were 34%, but for honesty's sake that is not the number we report to senior management. The calculation methodology is detailed in How much do you really save as a Qualified User?.
Replicable lessons
Four decisions significantly moved the result:
Don't shortcut the diagnostic. The 6 weeks of initial audit could have been compressed to 2–3 had we wanted to sell faster. Without that depth, Grid Code findings would have surfaced as post-migration observations and cost double.
Staggered migration, not simultaneous. Although theoretical gross ROI was better with parallel migration, real ROI with staggering was higher due to fewer operational corrections and applied learning.
Power-factor investment before migration. Eliminating penalties under CFE first, and entering the MEM with PF 0.95 instead of 0.86, improved the quotes because the supplier perceived lower technical risk.
Structured RFP with 5 suppliers. The awarded price was 7% lower than the best candidate's initial offer, simply because transparent competition produced better terms in the final round.
What did NOT work as expected
In the spirit of technical honesty, it's also worth documenting what was adjusted:
- The original schedule was 5 months. It ended at 7 due to a CRE observation at plant 2 that required additional technical clarification. Not a client delay, but a regulatory-flow delay.
- The spot component performed below expectations in the first quarter. Due to a short drought that stressed the system, spot price was high for a few months. The 80/20 structure protected, but it was identified as a learning for the next renewal: shift to 90/10 for the stable profile.
- Integration with the client's ERP for monthly settlement audit took 3 months —not 4 weeks as projected—. Lesson: underestimating technology integration was our error.
How this case is replicated
The case is replicable for industries with: load factor above 50%, contracted demand per plant above 1 MW, operational horizon of 3+ years, willingness to invest in technical compliance (power factor, Grid Code), and availability of an internal project owner.
It is not replicable for operations with load factor below 35%, high operational volatility, or no budget for compliance investments.
For the full picture of the regime, see the Complete Guide to Qualified Users. And review our portfolio of case studies with other industries.
How Enerlogix approaches cases like this
Plan 360 Management is designed precisely for this kind of mid-sized multi-site operation: rigorous technical diagnostic, staggered implementation plan, structured RFP, and continuous operational audit. The formula isn't secret —it's just applying it with discipline—.
If your operation has a similar profile (manufacturing, high load factor, improvable compliance, corporate ESG targets), request a free evaluation. In 2 weeks we deliver an initial diagnostic with no obligation, an honest projection of available savings, and an implementation plan.
