Xcel challenged to provide natural gas to growing mountain towns
Xcel Energy’s Marshall Compressor Station, in Boulder County, is the little engine that can’t. It must push natural gas all the way to Breckenridge, Grand Lake and Keystone and it is finding that some days it is harder and harder to do.
A company analysis found that at “peak hour” gas demand there could be “insufficient pressure at the tail ends of the natural gas system during the coldest days” leading to unreliable and unsafe service for those mountain communities.
Now it isn’t all the fault of the Marshall Compressor Station. The station is downstream from Xcel Energy’s Denver and northern Colorado systems — so growth on the Front Range siphons off some of the gas and pressure.
And then there is the population growth in Grand, Lake, Summit and Eagle counties — with an 8% increase in Xcel Energy mountain customers between 2019 and 2023 — adding to the pressure, or rather the lack thereof. The system now serves 33,500 people in the mountains.
A natural gas outage could lead to a shutdown of gas appliances, including furnaces and boilers, Xcel Energy said, and re-pressurizing the system and returning it to service could take days — not a good scenario for winter in the mountains.
The solution — in the past — would have been more compressors, more pipelines, a solution that Xcel Energy calculated could cost up to $300 million.
However, a 2021 state law requires gas utilities to cut their greenhouse gas emissions 22% by 2030, for the most part by selling less gas. Xcel Energy’s Clean Heat Plan projects a 14% drop in gas sales between 2024 and 2028.
The risk in building new gas infrastructure as gas sales decline is that it will become a stranded asset and not pay for itself.
Xcel Energy has been spending an average of $500 million a year on gas infrastructure, according to Justin Brant, utility program director at the nonprofit Southwest Energy Efficiency Project or SWEEP.
“Investing half a billion a year in gas infrastructure is not compatible with the state’s greenhouse gas reduction targets and the Clean Heat Plan that is going to reduce gas sales,” Brant said,
But Xcel Energy’s remedy to the mountain problem, which was submitted in January to the Colorado Public Utilities Commission for approval, involves no new pipelines or compressors.
“We are still digging into the details but cautiously optimistic in the approach,” Brant said.
The Mountain Energy Project proposes dealing with the natural gas pinch by shifting some demand from gas to electricity, reducing demand through energy efficiency and using so-called demand management programs to deal with peaks.
The utility has developed small projects that look to avoid new pipelines, such as a $4.5 million pilot to electrify about 65 mainly commercial customers along the Pearl Street Mall in Boulder rather than replace a gas main.
The Mountain Energy Project on a grander scale, The plan is “the culmination of years of evolution” said Stephen Martz, Xcel Energy vice president of integrated planning. “It is also the largest at-scale, non-pipeline initiative in the country.”
Xcel Energy’s proposed price tag for the project is $155 million.
SWEEP’s Brant, who participated in discussion about the plan with the utility, said, “a project like this is essential to slowing gas infrastructure spending.”
The first part plan is a group of “non-pipeline alternative” programs. One initiative would switch some demand from natural gas to electricity, replacing gas appliances with electric ones, such as swapping gas furnaces for electric heat pumps.
“Whole building electrification measures are included,” the company said in a utility commission filing. “These measures will be offered over the planning period to residential, commercial, combination transport, and potential new customers.”
Xcel Energy estimates this part of the plan could raise electricity demand in the mountains by 8.3 megawatts, a 5% increase.
This would require a total of $28 million in grid upgrades including upgrades of four four feeder lines, which carry power from a substation to homes, in Leadville, two feeder upgrades in Dillon and $20 million in transformer upgrades at the Breckenridge substation.
Liquid natural gas “bridge” does not comport with clean energy goals
A second part of the non-pipeline alternatives aim to increase energy efficiency and management through improving insulation of homes and buildings and, where necessary, upgrading to high-efficiency gas appliances.
Xcel also proposes starting a demand response program in which customers would be incentivized to reduce the use of gas during peak periods and be encouraged to adopt energy-saving behaviors.
The cost of the non-pipeline alternative portfolio would be $48.7 million, with a 15% cushion, bringing total costs to as much as $56 million.
While Xcel Energy has target reductions for all the non-pipeline programs there is no guarantee they will get all of the reductions they need to make the system work, so there are still risks of peak demand on the existing gas distribution system causing failures.
To deal with this, Xcel Energy is proposing to install a long-term, modular liquified natural gas, or LNG, facility in Breckenridge and a compressed natural gas facility at Keystone.
The LNG unit would consist of LNG storage tanks, pumps, a vaporization unit and an odorizer. “During periods of high demand, LNG will be converted from a liquid state to a gaseous state before being injected into the natural gas system,” the company said.
The compressed natural gas unit would use a pump to reduce the pressure of the gas from storage tanks to the appropriate line pressure and then inject it into the gas system used by customers. Both facilities will also need some additional pipes and valves to tie into the existing system.
The cost of the Breckenridge LNG unit would be $55.8 million and the Keystone compressed natural gas facility $22.8 million, making the natural gas component about half of the total cost of the Mountain Energy Project.
The installations are modular which gives Xcel Energy the flexibility to increase or decrease their size depending on the needs, Martz said.
These natural gas investments are expected to be fully depreciated in 20 years compared to 72 years for a pipeline, thereby reducing the risk of a stranded asset, the company said in a filing.
“We’ve been in discussions with Xcel to better understand what the alternatives to expanding natural gas are,” Jessica Burley, Breckenridge’s sustainability and parking manager, said. “We don’t feel that the expansion of natural gas coincides with the town’s goals.”
Breckenridge is part of a county goal of reducing its greenhouse gas emissions by 50% from 2017 levels 2030 and has its own renewable energy mitigation plan aimed at offsetting the greenhouse gases from outdoor amenities, including pools, driveway snow-melt systems and gas grills.
“We are excited about the plans for beneficial electrification,” Burley said. “I think they heard us on beneficial electrification.”
Still, Burley said “we are concerned about using LNG to be the bridge … and the risk of stranded assets.”
Burley said there are discussions “on a regional level” to decide if mountain communities want to seek to intervene in Xcel Energy’s case before the PUC seeking approval for the Mountain Energy Project.
“We are still talking to Xcel and there will be some level of comment to the PUC,” Burley said.