Colorado’s Mountain Energy Project: What the PUC Decision Signals for Gas Planning

A Turning Point in Gas Infrastructure Planning

The Colorado Public Utilities Commission recently issued its decision in Proceeding No. 25A-0044EG, approving Public Service Company of Colorado’s Mountain Energy Project (MEP) but with significant modifications.

The project addresses projected winter supply constraints in Xcel’s Eastern Mountain Gas System through a hybrid portfolio of supplemental liquefied natural gas (LNG)/compressed natural gas (CNG) facilities and non-pipeline alternatives (NPA).

While the Commission approved near-term reliability measures, the decision introduces refinements that may shape future gas infrastructure proceedings in Colorado.

The decision highlights three emerging themes:

Continued scrutiny of peak demand modeling
Greater emphasis on electrification-driven non-pipeline alternatives
Ongoing oversight of infrastructure cost recovery

Together, these elements reflect a more integrated approach to reliability and decarbonization.

I submitted testimony on behalf of the Mountain Community Coalition examining peak demand assumptions, electrification pathways for boiler-based heating systems, upstream system interactions, NPA program design, and cost recovery considerations. Several aspects of the Commission’s decision directly engage with those topics.

Key Takeaways from the Mountain Energy Project Case

The MEP proceeding offers a set of emerging best practices in gas system planning:

Ground peak forecasts in physical system constraints.
Reflect HVAC sizing standards, equipment limits, and real-world customer behavior in design-day assumptions.
Treat non-pipeline alternatives as core reliability resources.
Evaluate demand-side measures alongside supply investments—not as secondary options.
Align electrification strategy with building stock.
Explicitly analyze technologies capable of replacing dominant systems (e.g., boilers in hydronic regions).
Use measured data to validate savings.
Use AMI and interval data to strengthen peak reduction estimates and improve future planning.
Preserve flexibility through structured review.
use interim reassessment and prudence review to help manage long-term infrastructure risk in a changing demand environment.

Together, these principles reflect a more integrated approach to gas planning—one that evaluates peak demand adequacy and decarbonization objectives within the same analytical framework.

Reliability Cannot Be Built on Unexamined Peak Assumptions

The Company’s modeling relied on a –39°F design day temperature to estimate peak demand. That temperature drove the projected shortfall—and, in turn, the scale of the proposed infrastructure.

In testimony, I examined how HVAC system design limits, local building codes (based on an approximately –13°F heating design temperature), and operational constraints may affect peak gas consumption at extreme temperatures. In practice, heating systems are not designed to increase output indefinitely as temperatures fall below their design limits. Accounting for those constraints can materially influence projected peak shortfalls.

The Commission did not modify the –39°F design day in this proceeding. However, it required a formal Interim Regulatory Filing by December 1, 2028, for Commission review and approval of any changes to:

forecasting methodology,
design day methodology or temperature value, and
related planning inputs.

By establishing this structured review process, the Commission ensured that foundational peak demand assumptions remain subject to continued validation as new data and system conditions emerge.

Large Discrete Loads Must Reflect Real-World Operation

The decision also addresses the treatment of gas-fired outdoor snowmelt systems.

Testimony raised questions about whether these systems operate during extreme cold conditions in the manner assumed in the Company’s modeling. In practice, snowmelt systems are often designed to shut off at very low temperatures due to safety and operational considerations.

The Commission directed the Company to:

identify likely snowmelt customers,
better understand how these systems operate at extreme temperatures, and
develop targeted demand response or alternative strategies.

This reinforces an important planning principle: modeling of discrete, high-load customers must be based on observed operational behavior rather than generalized assumptions.

Non-Pipeline Alternatives Move to the Center of Reliability Strategy

The Commission endorsed immediate implementation of the NPA portfolio, describing it as a “no-regrets” strategy.

It also refined program design by:

requiring removal of gas boiler upgrade rebates from the NPA portfolio because they do not contribute to achieving necessary peak demand reductions;
emphasizing measurement and verification, including use of AMI data and potential interval metering pilots; and
setting an expectation that air-to-water heat pump (AWHP) incentives be offered no later than July 2026.

The AWHP directive is particularly significant. Mountain communities have a high prevalence of hydronic heating systems powered by gas boilers. My testimony identified the absence of AWHP analysis in the Company’s NPA potential study as a notable gap, since these systems represent one of the primary electrification pathways for boiler-dominated building stock.

By elevating AWHP deployment within the NPA framework, the Commission aligned reliability planning more closely with the characteristics of the local building stock.

Broader System Dynamics Remain Relevant

In my testimony, I also examined upstream system interactions—specifically, how reductions in gas demand outside the mountain region, driven by electrification and state decarbonization policies, could influence available capacity downstream.

The decision does not directly resolve this issue. However, in rejecting proposals to assign MEP costs exclusively to mountain-area customers, the Commission emphasized the integrated nature of the gas system.

That recognition underscores an important planning consideration: gas infrastructure, cost allocation, and demand dynamics operate within a system-wide framework. As demand patterns evolve across regions, upstream and downstream interactions may become increasingly relevant in future capacity assessments.

Infrastructure Investment Remains Subject to Oversight

The Commission approved Hybrid Portfolio 2, a combination of NPAs and modular LNG and CNG facilities intended to address projected winter capacity shortfalls in the Eastern Mountain Gas System. The LNG and CNG facilities are expected to have an approximate 20-year useful life.

The Commission limited the presumption of need to a defined period and clarified that its approval does not confer a presumption of prudence on supplemental supply costs. Those costs must be reviewed in a future general rate case.

This preserves regulatory oversight as:

NPA performance data becomes available;
electrification trends evolve; and
peak demand assumptions are reassessed through the Interim Regulatory Filing process.

Infrastructure approvals therefore remain subject to continued scrutiny under changing policy and market conditions.

What This Decision Signals

The MEP decision does not halt gas infrastructure expansion. However, it reinforces several principles that may shape future gas planning in Colorado:

Foundational modeling assumptions require continued validation.
End-use operational behavior matters in peak forecasting.
NPAs are integral to reliability strategies.
Electrification technologies require evaluation in light of actual building stock.
Infrastructure approval does not eliminate future cost review.

The decision suggests that evaluation of gas infrastructure proposals will entail an increasingly integrated framework—one that considers peak modeling assumptions, demand-side alternatives, electrification pathways, and long-term policy trajectories together.

The MEP proceeding illustrates how peak demand adequacy and decarbonization are increasingly evaluated as interconnected elements of long-term system planning rather than as separate objectives.