Colorado regulators are grappling with how to manage a major increase in electricity demand driven by data centers, electrification and economic growth, while preventing sharp increases in household energy bills.
A new analysis from the Colorado Public Utilities Commission suggests that the surge in electricity demand could significantly increase profits for Xcel Energy while also raising costs for consumers.
According to the report, Xcel Energy’s profits in Colorado could climb to $1.9 billion by 2031 as the utility invests heavily in power plants, transmission lines and other infrastructure needed to meet growing electricity demand. At the same time, residential electricity rates could rise sharply if the expansion is not carefully managed.
The report is part of a broader directive from Jared Polis, who has asked state agencies to coordinate efforts to balance climate policy, economic development and energy affordability.
In an October 2024 letter to regulators, Polis stressed the need to protect consumers from rising costs during the energy transition.
“This effort is important to maintaining affordable energy costs for Colorado residents,” Polis wrote.
“Other states that have not carefully managed the electrification transition are seeing large increases in utility rates.”
Colorado’s shift toward renewable energy began more than a decade ago when the state started retiring coal-fired power plants and expanding wind and solar generation.
During the early years of the transition, favorable economic conditions helped offset the costs of clean energy investments. Natural gas prices were relatively low, borrowing costs were modest and renewable technologies were becoming cheaper each year.
According to the commission’s report, shutting down coal plants produced “quantifiable fuel and other cost savings” that allowed utilities to maintain stable electricity prices while reducing greenhouse gas emissions.
However, the financial landscape has changed in recent years. Inflation, rising interest rates and supply chain disruptions following the COVID-19 pandemic have pushed up the cost of equipment and infrastructure.
Global events also played a role. The outbreak of the war in Ukraine in 2022 created volatility in natural gas markets, increasing uncertainty for long-term energy planning.
Looking ahead, the state may also lose some of the cost advantages that came from retiring coal plants. After 2030, those facilities will no longer provide the savings that previously helped offset the cost of renewable energy investments.
One of the biggest uncertainties facing Colorado’s electricity system is the potential growth of data centers.
These facilities power cloud computing, artificial intelligence platforms and digital services, but they require vast amounts of electricity to operate.
In projections submitted to regulators, Xcel Energy estimated that electricity demand from large customers such as data centers could range from 3 terawatt-hours to as much as 20 terawatt-hours annually — representing growth 10 to 25 times faster than historical averages.
In addition to data centers, electricity demand is expected to rise due to electric vehicles and the electrification of heating systems in homes and commercial buildings.
Energy planners must design the grid to handle peak demand — the highest level of electricity consumption that may occur during extreme conditions. Even if those peaks happen only a few hours per year, the grid must be capable of meeting them.
To prepare for future demand, Xcel Energy has proposed significant investments in energy infrastructure.
Even under the lower-demand scenario approved by regulators, the utility will need to add approximately 7 gigawatts of new generation capacity — nearly a 50% increase compared with current capacity levels.
The expansion would also require more than $12 billion in new transmission projects to move electricity across the state.
Overall, the company is expected to spend about $37 billion on infrastructure through 2031, compared with the current value of about $12.5 billion for its existing plants and grid assets.
Utilities typically earn revenue not from selling electricity itself but from building and maintaining infrastructure that regulators allow them to recover through customer rates.
In 2025, Xcel Energy’s Colorado subsidiary, the Public Service Company of Colorado, recorded a net profit of $678 million. With new infrastructure investments, that profit could rise to $1.9 billion by 2031.
Residential electricity prices could increase by 20% to 30% by 2027 and by as much as 55% by 2029 compared with 2024 levels.
“The commission may want to consider if this relationship might raise concerns about the general alignment between customer and utility interests,” Alexandra Rozen, a PUC research analyst, said in presenting the report.
While the growth in electricity demand creates potential risks for ratepayers, regulators say large new customers could also help stabilize the system financially.
“Our analysis suggests that new customer demands and revenues may provide an opportunity to create value for the electric system if they could be flexibly and thoughtfully integrated into the grid by time of day and location,” Rozen said. “But if these demands are not planned strategically, they might pose a risk of increasing existing customer rates.”
To address those concerns, regulators are considering policies that would require major electricity users — particularly data centers — to make long-term commitments.
Current proposals include requiring nonrefundable deposits, contracts lasting up to 15 years and early exit fees if companies cancel their projects.
The commission has also directed Xcel Energy to develop a specialized “large-load tariff,” a separate electricity pricing structure designed specifically for high-demand customers.
The commission’s report outlines several strategies that could help limit future electricity rate increases.
One option would be reducing overall utility spending by about 12%, which analysts say could keep rate increases closer to the pace of inflation.
Another approach would involve lowering the financial returns utilities earn on projects that support public policy goals — such as wildfire mitigation programs, pipeline safety upgrades and replacing aging infrastructure — but do not directly generate revenue.
Regulators are also reviewing policies used in other states to manage large electricity users.
For example, in Ohio, major electricity customers must pay for at least 85% of the capacity they request regardless of how much power they actually use. Meanwhile, New Jersey has implemented caps on electricity rate increases.
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“This provides more insights into ensuring that we can really manage that peak system growth, and therefore manage those investments,” Commissioner Megan Gilman said.
However, regulators acknowledge that existing oversight tools may not fully address the scale of changes facing the electricity sector.
“I just think the concern is that this evolving — call it clean energy 2.0 — plan may not be the one that optimizes the company’s capital spending and earnings,” said PUC Chairman Eric Blank, “so it may be challenging to achieve under existing regulatory approaches.”
Colorado’s situation reflects a broader challenge faced by many states transitioning toward electrification and renewable energy.
As demand grows from data centers, electric vehicles and new building technologies, utilities must expand infrastructure while regulators work to ensure the costs are distributed fairly.
How Colorado balances those competing priorities — economic development, environmental goals and consumer affordability — could influence energy policy decisions across the United States in the coming years.
Originally reported by Mark Jaffe in Colorado Sun.
