Brad Cebulko is a partner at Current Energy Group and Sarah Steinberg is a managing director at Advanced Energy United.
Energy bills are rising across the country, and for many households, the pain is coming from multiple directions.
Today’s national conversation about energy costs, load growth, aging 20th-century infrastructure and supply chain disruptions has been an unfortunate reminder that the U.S. is facing two affordability crises at once. Even as electric bills rise, the gas system remains especially vulnerable to price shocks in two ways: fuel price volatility and steep infrastructure replacement costs.
Take New York state, for example, where infrastructure costs (aka, delivery costs) make up 75% of New York heating bills and a similar share for electric bills — the largest driver of rising bills and the highest priority for cost containment.
No additional dollar of ratepayer money should be spent without due diligence that it is necessary and the lowest-cost option. In New York and many other places, utilities, regulators and stakeholders cannot yet say that this is the case. New research by Current Energy Group has highlighted an illustrative example of the problem.
In National Grid’s Niagara Mohawk territory, where the utility provides both gas and electric service to a set of customers, the electric utility forecasts over 30,000 more heat pump installations by 2030 than the gas division assumes. To meet this need, the utility will need to add capacity to its system and procure enough electricity to serve that increased load. Their gas business unit, serving the same customers, is planning around a future that does not account for this same electrification.
The study estimates that if National Grid’s gas planning used the same electrification assumptions as its electric planning, the gas utility would serve approximately 15,000 fewer customers than its plans include. Instead, the gas utility plans to spend $550 million by 2029 to support customer growth, based on a forecast of stagnant electrification that its own electric arm disagrees with.
These divergent forecasts will lead to over-investment and underutilization in at least one system, creating real dollar implications for customers who are already stretched thin.
That misalignment isn't a coincidence. Utilities earn profits by building infrastructure, so both divisions have every incentive to forecast a future that justifies more spending.
Integrated planning reduces that incentive by requiring both sides to reckon with the same assumptions before shovels go in the ground.
Already, under a business-as-usual scenario, National Grid customers could see bills rise by about $300 per year for both gas and electric service by the end of 2027. National Grid’s rising rates will stretch customers in a state where 1.2 million households were already more than 60 days behind on utility bills in 2025, $1.8 billion in utility arrears have accumulated, and 2.2 million households spend more than 6% of their income on energy.
National Grid is certainly not unique in this respect. Separate, fragmented planning has been standard practice for most, if not all, combined gas-and-electric utilities. But new risks, new analytical tools and new energy trends have made change an imperative.
A new utility planning approach — integrated gas and electric planning — can help.
Integrated gas and electric planning seeks to coordinate and optimize utility infrastructure spending across gas pipelines, electric wires and distributed energy resource systems in order to meet state goals in the most cost-effective and reliable way.
This holistic framework includes five major components: 1) procedural alignment, 2) data sharing, 3) aligned forecasting, 4) identification of the least-cost alternatives to traditional infrastructure, and 5) coordinated investments.
Done right, this should reduce costs to ratepayers by reducing duplicative investments, help meet state clean energy goals at lower cost, improve reliability by identifying and planning for system interdependencies during extreme weather events, and improve transparency and trust in utilities and state government.
New York and its utilities have been among the first to recognize the importance of moving in this direction. The state’s 2025 Energy Plan calls for proactive, long-term, integrated gas and electric planning that prioritizes non-pipeline alternatives and demand management, recommending that the Public Service Commission reform regulations to align with this new direction.
A proposal pending in the New York State Senate, SB 5995, also asks the PSC to take this on. This would help standardize the states’ utilities’ early efforts: Consolidated Edison published an “Integrated Long-Range Vision;” Central Hudson Gas & Electric noted its focus on “shifting the paradigm of distinct and separate ‘gas and electric’ planning and investment to a single ‘energy delivery’ paradigm;” and National Grid is piloting gas and electric collaboration as it designs various non-pipeline alternatives.
The case study unfolding in New York demonstrates that when utilities plan for vastly different versions of the future, ratepayers are left at risk. This misalignment carries measurable, high-stakes costs for today’s ratepayers — including duplicative infrastructure, stranded assets, reliability failures, and high energy bills for households already under financial pressure.
Integrated gas and electric planning offers an important lever to meet state policy goals, including affordability, reliability and decarbonization, in the most cost-effective and safest manner. By moving towards this coordinated approach, New York has an opportunity to set a national standard for how states protect ratepayers and move beyond siloed utility planning.
