The Energy Department Put $250 Million Into a Transmission Line Through Lamar, Colorado. It's One of 31 Bets on Finding Gigawatts in Wires We Already Own.

On September 24th, the Department of Energy put $1.9 billion behind 31 transmission projects in 26 states, the latest round of a program called SPARK — Speed to Power through Accelerated Reconductoring and other Key Advanced Transmission Technology Upgrades, a name only a federal agency could write and then compress into something that sounds like a tagline. Strip the acronym away and the idea underneath it is simple, and by the standards of grid policy this year, almost boring: instead of spending five to ten years permitting and building new transmission corridors, pay utilities to get more capacity out of the ones they already have. One of the 31 projects runs through Lamar, Colorado, population a little over 7,500, on a line most people reading this have never heard of. It's as good a place as any to see whether "speed to power" survives contact with an actual interconnection queue, actual state and federal approvals, and an actual utility whose own regulators just told it its outages are getting worse, not better.

What $1.9 billion actually buys

DOE's Office of Electricity isn't funding new power plants or new rights-of-way with SPARK. It's funding reconductoring — pulling old aluminum-core conductor off existing transmission towers and restringing the same corridor with advanced composite-core conductor that carries more current at the same sag and clearance — plus what the industry calls grid-enhancing technologies: dynamic line rating sensors that tell operators a line's real-time carrying capacity instead of a conservative fixed number, advanced power-flow control, and better analytics layered onto wires that are, in most cases, decades old. Across the 31 selected projects, DOE expects recipients to reconductor or rebuild more than 1,500 miles of transmission line and deploy grid-enhancing technologies across nearly 21,000 miles more, for a total of $5.25 billion once the $1.9 billion in federal money is matched by $3.35 billion from the utilities themselves. DOE's own estimate is that the combined projects make more than 23 gigawatts of additional capacity available across territories serving upward of 39 million customers. Energy Secretary Chris Wright framed it as a low-regret bet: "These investments will get more out of the infrastructure we already have, move more electricity across the grid, and help deliver affordable, reliable, and secure power that will fuel American prosperity for decades to come." The announcement itself was staged in Allentown, Pennsylvania, where PPL Electric Utilities is doing some of the most instructive work in the whole portfolio — up to $71.5 million in SPARK funding for 29.3 miles of its Montour corridor, combining CTC Global's ACCC advanced conductor with the sensor-based dynamic line rating PPL has already been running on nine congested PJM lines since 2022.

The piece that runs through eastern Colorado

The Colorado Energy Office and Xcel Energy Services together landed $250 million of that federal money for a project called the Colorado-to-Texas Western-Eastern Intertie Modernization Initiative — CO2TX, in the inevitable abbreviation — on the transmission tie that runs from Finney, Texas to Lamar, Colorado. Xcel is matching the federal award at roughly four-to-one, putting the total project cost at $1.2 billion. The plan is 12 miles of new transmission and 16 miles of existing line rebuilt with higher-capacity conductor, raising the tie's transfer capacity from 210 megawatts to 700 megawatts, with Xcel saying the same corridor could technically carry up to 2,000 megawatts without further equipment changes if a future upgrade warranted it. On the Colorado side, the power moves from Lamar to the Sun Valley Substation east of Pueblo, tying into the rest of Xcel's eastern Colorado system. "Modernizing the Lamar Tie will strengthen the connection between the Western and Eastern electric grids," said Robert Kenney, president of Xcel Energy-Colorado, in the utility's announcement — undersold phrasing for a line that happens to be one of a small number of points anywhere in the country where the Western Interconnection and the Eastern Interconnection, two AC grids that otherwise don't synchronize with each other, can trade power at all.

Why 210-to-700 is a bigger number than it looks

Most of the continental U.S. grid runs on one of two separate, asynchronous AC systems — the Western Interconnection and the Eastern Interconnection — plus Texas's own ERCOT island. They don't share power directly; any transfer between them has to run through one of a handful of back-to-back DC conversion ties, the Lamar Tie among them. That's a narrow, specific kind of scarcity, different from a normal transmission bottleneck inside a single interconnection: there's no way to just route around it by building a parallel line somewhere else in the region, because the number of places the two grids touch at all is small to begin with. Tripling the capacity of one of those ties, with headroom engineered in for a further jump to 2,000 megawatts, is a meaningfully different kind of grid asset than 29 miles of reconductored line inside PJM, even though both show up as line items in the same $1.9 billion SPARK round. It's also arriving into a Colorado grid that isn't short on reasons to want more flexibility. Colorado Public Utilities Commission staff told regulators on September 29th that Xcel customers have logged an above-average number of outages in every single month of 2024, 2025, and the first half of 2026, with average outage minutes per customer already back up to 89 in just the first six months of this year against a 2015–2023 average of 95 for the full year. "We are somewhat disappointed that we are not seeing any improvement yet," PUC deputy director Erin O'Neill said. A $1.2 billion tie upgrade doesn't fix local distribution reliability — it's a different layer of the system entirely — but it's worth saying plainly that this federal money is landing on a utility whose own regulators are, in the same week, on the record saying things haven't gotten better yet.

A selection isn't a signed agreement

Here's the caveat DOE's own release is upfront about: September 24th was a selection, not a grant. Formal financial assistance agreements between DOE and each of the 31 recipients are expected to be negotiated between October 2026 and January 2027, and individual project scope, budget, and terms remain subject to that negotiation — standard language for a federal award of this type, and not a reason to doubt the money is real, but a real gap between announcement and binding commitment all the same. CO2TX has its own separate approval chain on top of that federal process: as an interstate transmission project, it still needs sign-off from the Colorado Public Utilities Commission and from the Federal Energy Regulatory Commission before Xcel can build it, on a timeline neither the company's announcement nor the state's has yet put a date on. CenterPoint Energy's $50 million SPARK award for Siemens Energy grid-stabilizing technology in greater Houston — part of a $176.7 million total project the company says will support more than 500 local construction and installation jobs — carries the same status: selected, not yet a signed federal agreement, and still ahead of its own state regulatory process in Texas.

The diligence angle

We've written before about two very different federal and regional responses to the same underlying problem — PJM's emergency backstop capacity auction, which spreads a 6.8-gigawatt shortfall's cost across ratepayers who didn't cause it, and Texas's interconnection deposit rule, which makes developers post collateral against megawatts they claim they'll actually use. Both of those are rationing mechanisms, built because the grid doesn't have enough capacity and someone has to decide who pays for that shortage or who gets priced out of the queue. SPARK is a genuinely different kind of answer: money aimed at making more capacity exist, on the theory — a reasonable one, and the industry's own term for it — that the fastest new gigawatt is the one sitting latent in a transmission corridor that was conservatively rated decades ago, not the one that requires a new plant and a new right-of-way. That's worth taking seriously as actual progress, not just a press release, and it's the kind of story we'd rather write more of.

It still belongs on the same evidence ladder we apply to everything else in a Kill Test. A DOE selection announcement is a real and meaningfully positive data point for any site evaluation that touches the corridors it affects — it tells you the federal government has prioritized that specific line, and that the utility has committed real matching capital to it. It is not, on its own, an executed interconnection agreement, a signed federal grant, or a completed state regulatory approval, and for CO2TX specifically it isn't yet a CPUC or FERC approval either. For a load site anywhere near the eastern Colorado corridor this touches, "CO2TX is funded" belongs several rungs below "CO2TX is under construction" and further still below "CO2TX is energized and the Lamar Tie is rated at 700 megawatts," and the gap between those rungs, on current public timelines, is years rather than months. The date worth putting on a calendar isn't September 24th. It's whenever DOE and Xcel actually sign the financial assistance agreement this winter, and whenever the Colorado PUC docket for CO2TX gets opened — because that's the point this stops being a selected project and starts being one with an enforceable schedule attached.