Solutions · energy
A transformer that fails in July does not wait for your October budget.
Aging faster than budget cycles can replace it.
Utilities run thousands of substations, miles of conductor, and transformer fleets installed when demand was half what it is today. We map equipment condition to grid consequence, so engineers prioritize by cascading risk, not age.
Why grid risk compounds faster than it appears
The transformers keeping the lights on were installed when electronics ran on vacuum tubes. Budget cycles are measured in years, equipment aging in decades, and load growth is outpacing both.
01N-1Contingency planning assumes all other equipment is healthy. Deferred maintenance erodes that assumption dailyWhat it costs
N-1 works when the rest of the system is in good condition. When three substations in a corridor are running aging transformers with dissolved gas issues, the contingency is theoretical. One failure at peak can cascade.
02DGADissolved gas analysis reveals transformer degradation. Only if someone is trending the results over timeWhat it costs
A single DGA reading is a snapshot. The trend over 18 months tells you whether acetylene and ethylene are accelerating toward a failure. Most utilities sample annually and trend manually, if they trend at all.
03NERCCIP compliance requires documented evidence of physical and cyber controls at every BES facilityWhat it costs
Audit readiness is not a one-time exercise. Every maintenance action, access event, and equipment change at a CIP-classified facility must be documented and retrievable. Penalties start at $1M per violation per day.
04RateRate-case filings need defensible evidence that capital investments are prudent and necessaryWhat it costs
Public utility commissions are rejecting recovery requests that lack structured risk justification. Engineering gut feel does not survive a cost-of-service hearing. A transformer-by-transformer risk model grounded in condition data does.
How Rivolq helps utility teams
See which failures would cascade into broader reliability events
We map transformer, breaker, and relay dependencies across substations and corridors. When DGA trends accelerate, you see the load carried and the corridor-level consequence.
Track DGA trends, loading history, and age-adjusted failure probability across the fleet
Dissolved gas, thermal imaging, load factor, and lifecycle curves combine into one health score per unit. Prioritize replacements by consequence-weighted risk, not nameplate age.
Audit-ready compliance for every BES facility without the manual burden
Every maintenance action and security event is timestamped and linked to CIP-classified assets it affects. Compliance packages generate on demand, not in a scramble.
Build the evidence record regulators need to approve recovery
Every proposed replacement is backed by condition trends, failure probability, and consequence modeling that holds up to PUC scrutiny. Engineering recommendations become approved filings.
Energy and utility questions, answered.
Common questions from utility operations, reliability, and capital planning teams evaluating Rivolq.
How does Rivolq help us get ahead of peak season?
Rivolq projects failure windows on transformers, substation assets, and other critical infrastructure by combining condition, load, and history, so a unit drifting toward failure surfaces before summer peak rather than during it. You schedule the work around the season instead of reacting to an outage in July.
Can Rivolq support rate-case capital and NERC CIP documentation?
Yes. Rivolq produces dollar-quantified, defensible capital plans suited to rate-case justification, and every risk score and maintenance action carries a timestamped audit trail that supports compliance documentation rather than a year-end scramble.
Does Rivolq replace our existing CMMS or EAM?
It does not have to. Rivolq includes a full CMMS for work orders and preventive maintenance, but it can also import asset and work-history data from your current system and add risk scoring and capital planning on top of what your team already runs.
How long does a pilot take?
A scoped pilot typically runs about 90 days from the first site to a capital plan you can take to leadership. Most teams start with one substation or corridor or one critical asset class to prove the workflow on real assets before expanding.
Reading for utility infrastructure decisions.
Articles on quantifying the cost of waiting, building capital requests leadership will approve, and what a scoped first-facility pilot should deliver.
Go deeper in the Help Center
How predictive risk signals, downtime tracking, and dependency analysis work on generation and grid-adjacent assets.
See corridor-level risk before the next peak season.
Map transformer health, substation dependencies, and compliance exposure into one infrastructure risk picture.
