Utilities across the United States routinely develop separate demand forecasts for their gas and electric systems, often producing contradictory outlooks that justify redundant infrastructure investments – a practice that inflates ratepayer bills by billions of dollars annually. New York is now advancing legislation that would require the state’s major utilities to adopt a single, integrated planning process, potentially establishing a national model for aligning gas and electric capital expenditure.
How fragmented forecasting became standard utility practice
Most investor-owned utilities operate gas and electric divisions as distinct business units, each with its own planning cycle, regulatory docket, and incentive structure. The electric side typically produces an Integrated Resource Plan (IRP) every two to three years, projecting load growth, resource adequacy, and decarbonization compliance. The gas side files a separate Long-Range Plan or capital investment plan, often on a different schedule, forecasting throughput, peak-day demand, and pipeline replacement needs. Neither plan is required to reference the other’s assumptions.
This siloed approach made sense when gas and electric systems interacted primarily at the power-plant level. But the energy transition has fundamentally altered that relationship. Electrification of heating, cooking, and transportation shifts load from the gas system to the electric system. Meanwhile, gas-fired generation remains the marginal resource in most wholesale markets, meaning electric reliability increasingly depends on gas delivery infrastructure. When the electric IRP assumes aggressive heat-pump adoption but the gas plan assumes flat or growing residential throughput, both sides build for a future that cannot simultaneously materialize.
New York’s Climate Leadership and Community Protection Act (CLCPA) mandates 70% renewable electricity by 2030 and 85% economy-wide emissions reductions by 2050. The law implicitly requires coordination: achieving those targets means deliberately shrinking the gas system while expanding the electric one. Yet Con Edison, National Grid, and the state’s other major utilities have continued to file gas capital plans that include main replacements and pressure upgrades in neighborhoods simultaneously targeted for building electrification pilots. The result is ratepayers funding assets that may be stranded before depreciation schedules end.
Cross-cutting analysis: the gas-electric planning gap mirrors wholesale market failures
The same misalignment that distorts distribution-level investment also plagues wholesale markets. ISO-NE, NYISO, and PJM all rely on gas-electric coordination protocols that were designed for reliability events, not long-term planning. During Winter Storm Elliott in December 2022, roughly 90 GW of generation across the Eastern Interconnection was forced offline – the majority gas-fired units unable to secure fuel. Post-event analyses from FERC and NERC identified inadequate communication between gas pipelines and grid operators as a root cause. That operational failure is the real-time manifestation of the planning failure described in the source material: if the gas system doesn’t know what the electric system needs, and vice versa, both overbuild and under-deliver.
Quantifying the cost of this disconnect is difficult because utilities rarely disclose the overlap. But a 2023 analysis by the Regulatory Assistance Project estimated that coordinated gas-electric planning could avoid 10-15% of combined distribution capital expenditure over a 20-year horizon in a typical Northeastern service territory. For a utility spending $1.5 billion annually on gas and electric distribution combined, that implies $150-225 million per year in avoidable spend – roughly $3-5 billion in present-value savings over two decades. Those figures are approximate, based on general industry benchmarks, but they align with the scale of duplicative main replacements and substation upgrades documented in recent rate cases in Massachusetts and New York.
That points to a broader structural issue: the regulatory compact still treats gas and electric as separate monopolies with separate rate bases. Performance-based regulation (PBR) frameworks in Hawaii, Illinois, and the UK’s RIIO model have begun tying allowed returns to outcomes like peak-demand reduction or emissions intensity, which naturally incentivize cross-fuel optimization. But most U.S. jurisdictions remain on cost-of-service regulation, where every dollar of prudent capital earns a return regardless of whether a cheaper cross-fuel alternative existed.
Who this affects
- Utility planner: Must reconcile electric IRP load scenarios with gas throughput forecasts in a single filing; expect regulators to demand sensitivity analyses showing how building electrification rates change gas peak-day design criteria.
- Storage or generation developer: Gas-fired peaker projects face heightened stranding risk if integrated plans reveal that battery storage or demand response can meet the same reliability need at lower system cost.
- Policy analyst: State energy offices and PUC staff need new modeling tools – such as combined gas-electric capacity expansion models – to evaluate utility filings; current tools like PLEXOS or AURORA rarely optimize both systems simultaneously.
- Investor: Rate-base growth assumptions for gas LDCs should be stress-tested against electrification pathways embedded in electric utility IRPs; divergence between the two signals regulatory risk.
What to watch next
- New York Public Service Commission’s forthcoming order on Case 20-G-0131 (gas planning proceeding) – specifically whether it mandates a unified gas-electric planning template for all major utilities.
- FERC’s proposed rulemaking on gas-electric coordination (Docket RM23-10) – watch for requirements that pipelines and generators share long-term demand forecasts with RTOs/ISOs.
- Con Edison’s next electric rate case filing (expected 2025) – the first test of whether the utility presents a genuinely integrated capital plan or merely appends a coordination appendix.
- Massachusetts DPU 20-80-B order implementation – the state’s “future of gas” proceeding has ordered utilities to file integrated plans by 2025; early filings will reveal whether the industry adopts a common methodology.
Bottom line
Integrated gas-electric planning is not a technical novelty – it is a prerequisite for any jurisdiction serious about decarbonization without rate shock. New York’s legislative push, if enacted with enforceable modeling standards, would force the first real test of whether U.S. utilities can plan a managed gas-system contraction alongside electric-system expansion. The alternative is continuing to charge customers for two incompatible futures.
Read the full report at Utility Dive
Note: facts and figures attributed above to Utility Dive reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
Leave a Reply