Public utility commissions have stopped waiting until after the fact to review gas procurement decisions. They want to see the hedge rationale and the forecasting methodology before the next heating season, while there’s still time to act on it. For gas utilities running procurement on spreadsheets and institutional memory, that’s a hard shift.
The pivot from prudence to foresight
For decades, purchased gas cost (PGC) proceedings followed a familiar rhythm. Utilities bought gas, passed costs through to ratepayers, and defended the reasonableness of those decisions in retrospective filings. Commissions reviewed the numbers, consumer advocates pushed back on a few line items, and settlements landed somewhere in the middle. The standard was prudence: did the utility act reasonably given what it knew at the time?
That standard is getting replaced by something harder to satisfy. Foresight.
In Pennsylvania alone, recent PGC settlements have required utilities to increase hedging volume targets, extend hedge horizons to two years, evaluate storage capacity optimization, and explore modern analytical tools — with recommendations due in subsequent proceedings. Each one is a condition of settlement. The expectation behind them: show the commission your procurement operation can see around corners.
The pattern is worth studying, because the utilities navigating it best are the ones diagnosing themselves. In several recent cases, the utility commissioned its own assessment, bringing in an outside firm to evaluate its procurement analytics before the commission or the consumer advocate forced the question. The consultant’s findings are candid: long-dated demand forecasts running consistently below actual load, hedge plans sized on those optimistic numbers. But because the utility surfaced the gaps itself, it entered settlement negotiations holding the pen. The commitments that followed — raise the hedge target, extend the horizon, evaluate storage, explore analytical tools — were shaped by the utility’s own roadmap rather than imposed from outside.
Notably, the most recent of these commitments came with no named vendor, no prescribed scope, and no cost ceiling. That’s not regulatory overreach; that’s latitude. The commission is saying: you found the problem, now show us your answer. The utilities that treat that as an invitation, and arrive at the next filing with a credible one, set the terms of their own modernization. The ones that wait get someone else’s.
The same pressure is building in every jurisdiction. Winter Storm Elliott in December 2022 forced a reckoning across the gas-electric interface. Gas generators caused 70% of PJM’s forced outages during the event. The Eastern Interconnection lost 90,000 MW of generation it hadn’t planned to lose. Marcellus production dropped 23%. Utica dropped 54%. The supply chain got fragile fast: demand spiked, pipelines constrained, and most operators couldn’t see their real position until the invoices arrived.
NARUC responded by convening the Gas-Electric Alignment and Reliability (GEAR) Working Group in November 2023, aimed at the coordination gaps Elliott exposed. The NARUC Gas Committee followed with a dedicated session on natural gas hedging strategies in March 2024. The message from regulators at every level has been consistent: the status quo is inadequate, and utilities need to prove they’re building something better.
What “better” actually looks like
When a PUC settlement says “explore analytical tools for gas procurement modernization,” what does that translate to operationally? Three things, mostly.
First, real-time position management. Knowing your net open position at the pipeline, point, and book level — continuously — while you can still do something about it. When Henry Hub moves 40 cents in a week, your exposure changes by the hour. A utility that reconciles monthly is flying blind between filings.
Second, weather-driven demand forecasting that ties directly to procurement decisions. The failure mode showing up in portfolio reviews is instructive: long-dated forecasts used to build seasonal hedge plans run consistently below actual realized demand, while short-term operational forecasts perform fine. The hedge gets sized on an optimistic load number, and the gap only shows up in hindsight, after the gas has already been purchased at spot. Rolling 30-day forecasts at the meter and LDC level, stress-tested against polar vortex scenarios and sustained cold events, close that gap. And the forecast has to feed the nomination, which has to feed the financial view. One system.
Third, hedge analytics with an audit trail. Two-year hedge horizons mean more instruments, more counterparties, more complexity. Commissions want the rationale documented at the moment of execution. Reconstructing it months later reads as exactly what it is. Mark-to-market reporting, backcasting against actual weather, and scenario analysis that shows the team evaluated alternatives before committing. This is gas risk management as a daily discipline.
None of this is exotic. Competitive gas marketers and retail energy suppliers have operated this way for years. But plenty of regulated utilities still run gas scheduling on legacy on-premise systems and track storage in Excel. The gap between that and what commissions now expect is wide.
The build-vs.-buy trap
The natural instinct when regulators demand modernization is to issue an RFP for a new system. And for some utilities, that’s the right path. But enterprise gas ETRM implementations take 12 to 24 months and cost seven figures. They also assume internal IT resources that most distribution utilities don’t have sitting idle.
Meanwhile, the next PGC filing is due in months. The commission wants to see progress by then, and a project plan won’t count.
This is where managed services change the equation. Instead of building an internal gas operations team from scratch or spending two years implementing an ETRM, a utility can bring in experienced gas professionals who already operate inside a modern platform — handling nominations, balancing, storage optimization, WACOGS analysis, and position management on day one.
The utility keeps full visibility and control. The managed services team works as an extension of the organization, and every nomination, every hedge decision, every settlement reconciliation is documented inside the platform with an audit trail that holds up in a PGC proceeding.
It also gives the utility something to show the commission now: live operational data and documented procurement analytics from a system that’s already running.
What does that look like in practice? During the December 2025 cold snap, when sustained cold drove sharp volatility across North American gas markets, ennrgy.com’s weather forecasting and real-time market analytics flagged capacity constraints and pricing escalation ahead of the event. The recommendation to a gas client: fully utilize 100% of contracted pipeline capacity for December. The result was an approximate $1.70/Dth reduction in average cost of gas supply, and the month closed as a strong margin period despite extreme conditions. Early procurement locked in lower prices before volatility was fully priced in. Excess capacity was monetized at premium rates as the market tightened. Every invoice was reconciled, every deviation documented, every cost allocation auditable. That’s what a commission wants to see in a filing. (Read the full case study.)
Storage optimization is the next frontier
The settlement language around storage capacity evaluation deserves attention. Most gas utilities manage storage as a seasonal buffer: inject in summer, withdraw in winter, reconcile at the end of the season. That approach leaves real value on the table.
Modern storage optimization treats capacity as a portfolio asset. Injection and withdrawal decisions respond to daily price signals, weather forecasts, and pipeline economics instead of a fixed seasonal schedule. Optimizing daily instead of seasonally can save meaningful money per decatherm, and it compounds across millions of decatherms a year.
When regulators ask utilities to “evaluate storage capacity optimization,” this is the gap they’re pointing at. A utility that can show its injection and withdrawal decisions responding to market signals is a utility that sails through its next PGC review.
The bottom line for gas utility leadership
PUCs are moving from backward-looking prudence reviews to forward-looking modernization mandates — and the pace is picking up. Utilities that get ahead of it, with real-time position visibility and weather-driven forecasting already running, will have an easier conversation at every filing.
The ones that don’t will find each PGC proceeding harder than the last, with consumer advocates armed with increasingly specific questions about why the utility’s gas procurement operation still looks like it did in 2015.
Winter doesn’t wait for IT projects to finish. Neither do regulators.
Managed gas operations — running today, audit-ready tomorrow.
ennrgy.com operates gas procurement, nominations, hedging, risk management, and settlement operations for energy companies across the U.S., powered by the Risk360 platform and backed by 200+ years of combined gas market experience.