Integrated resource planning (IRP) for electric utilities is a long-range planning document, typically 15 to 30 years forward, that combines load forecast, generation supply, demand-side resources, transmission, and rate impact into a single least-cost portfolio submitted to the state public utility commission. Most investor-owned electric utilities file an IRP every two to five years; electric cooperatives, municipal utilities, and federal power marketers file voluntarily or under wholesale supplier requirements. A modern IRP integrates AMI hourly load data, demand response, distributed energy resources, and clean-energy mandates into the same model the utility uses to decide which generating units to build, retire, or contract for.
The IRP filed this year shapes capital allocation for the next two decades. Getting it wrong is expensive both ways: overbuild and ratepayers overpay; underbuild and the utility imports power at spot prices or sheds load.
This guide explains what an IRP is, who has to file one, the six components, the steps to build one, the supporting software, and how CIS and billing data feed the load forecast. Electric utilities running CIS, billing, and AMI on a modern cloud platform should look at SMART360 for electric utility management, which produces hourly load shapes by customer class that any credible IRP forecast depends on.
IRP filing requirements vary by utility type, state, and wholesale relationship. The pattern across the United States:
FERC does not set IRP requirements; state PUCs do. NERC sets resource adequacy standards that any credible IRP must meet. For utilities navigating overlapping state and federal compliance, electric utility compliance software centralizes the evidence and reporting that supports both IRP and parallel filings.
Every credible IRP, regardless of state, addresses six components. The IRP's analysis layer integrates them into a single least-cost portfolio under multiple future scenarios.
The load forecast is the foundation. A 1% error in the 20-year forecast propagates into hundreds of millions of dollars of supply-side decisions. Utilities that historically forecast from monthly billing aggregates now use AMI hourly data to build class-specific load shapes.
How clean is your historical consumption data?
The IRP load forecast is only as credible as the consumption history feeding it. Utilities running on three or four billing systems over fifteen years often have gaps, format breaks, and rate-class definition changes. The forecast modeler ends up reconciling exports from systems no one fully understands anymore. The fix is rarely a forecasting tool. It is a clean, queryable, hourly-class CIS extract the forecast team can trust.
A full IRP cycle from data gathering to PUC filing typically runs 12 to 18 months at an IOU and 6 to 12 months at an electric cooperative. The path is consistent across utility types.
The IRP cycle rarely runs cleanly the first time. Most utilities iterate steps 4 through 6 as portfolios fail reliability tests or fuel-price scenarios shift. Steps 1 through 3 drive the cost of every iteration. A bad load history makes every iteration partially wrong.
No single IRP platform covers every step. Most utilities run three to five tools plus their CIS, billing, and AMI systems as data sources.
The expensive tools are PLEXOS, AURORA, and the production cost models. The under-invested layer is almost always the data foundation. Utilities on legacy billing systems often spend more on consulting hours to clean the load history than on the capacity expansion model itself.
Does your CIS export hourly load by class?
Many CIS platforms cannot natively export hourly consumption by rate class with stable definitions across multi-year history. Forecasters end up requesting custom extracts as one-off SQL queries that break when the CIS is upgraded. A modern cloud CIS that treats hourly-class export as a first-class API removes a recurring planning bottleneck. Utilities evaluating CIS or billing platforms for IRP support should look at the electric utility billing platform comparison and ask each vendor to demonstrate the hourly-class export.
The connection between billing and IRP feels distant: billing is monthly, IRP is decadal. The connection is structural. Every hour of historical consumption informing the load forecast comes from the same database that produced last month's bills. The fidelity of that database, the stability of its rate-class definitions, and the accessibility of its hourly export determine the quality of the IRP forecast.
Three concrete linkages:
State PUC requirements for IRP content are expanding:
The traditional IRP focused on least-cost generation expansion. The modern IRP tests portfolios against reliability, affordability, decarbonization, and equity. For a broader view, the electric utility industry trends overview covers the policy and technology forces shaping the next IRP cycle.
SMART360 is not an IRP modeling tool. PLEXOS, AURORA, and the production cost models occupy that layer. SMART360 sits beneath, as the CIS, billing, and AMI foundation that produces the consumption history those IRP models depend on. Hourly-class export is a first-class API. Rate-class definitions are versioned. AMI reads flow into the same data model as billed consumption, so the forecast team can compare delivered-kWh and billed-kWh without manual joins.
Island Water Authority deployed SMART360 in 10 weeks and achieved a 47% operational cost reduction and a 92% reduction in billing errors. The foundation that makes those numbers possible is the same one that makes IRP-grade load forecasting possible. Utilities planning a CIS or billing modernization that will feed downstream planning should also look at the ERP integration automation guide.
Integrated resource planning is a long-range planning document, typically 15 to 30 years forward, that electric utilities submit to state public utility commissions every two to five years. It combines load forecast, supply-side resources, demand-side resources, transmission, and rate impact into a single least-cost portfolio under multiple future scenarios. The IRP shapes capital allocation, rate cases, and generation decisions for the next two decades.
Investor-owned electric utilities are required by state law in most states every two to five years. Electric cooperatives taking wholesale power from a G&T cooperative often have their obligations met at the G&T level. Distribution cooperatives that self-supply file their own. Municipal electric utilities generally are not required by state PUCs but often file voluntarily or under federal power supplier requirements.
Most utilities run three to five tools across the cycle. Load forecasting commonly uses Itron MetrixIDR, Itron Forecast Manager, or Siemens Spectrum. Capacity expansion modeling commonly uses Energy Exemplar PLEXOS, EnCompass, or EPIS AURORA. Production cost modeling commonly uses PLEXOS, GE MAPS, PROMOD, or ABB GridView. CIS, billing, and AMI platforms supply the historical consumption data.
A full IRP cycle from data gathering to PUC filing typically runs 12 to 18 months at an IOU and 6 to 12 months at an electric cooperative. Data gathering and forecasting account for 4 to 8 months. Capacity expansion and production cost modeling iterate over 3 to 6 months. Drafting, review, stakeholder consultation, and filing take 2 to 4 months.
The IRP load forecast is built from historical hourly consumption by rate class. CIS data quality determines whether that history is reliable. Utilities running on multiple billing systems often have gaps, format breaks, and rate-class re-mappings that distort trending. A modern CIS that exports hourly-class load data through a stable API removes the recurring data-cleaning burden.
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