Salt Lake City area (Salt Lake, Tooele, Davis and Utah counties): key gate stations are projected at their limits

By Sam Strong, Vice President of Business Development, Discovery Energy. Technical review by Tara Dugger, Chief Operating Officer. Updated October 2026.

Metro used: the Salt Lake City area: Salt Lake, Tooele, Davis and Utah counties, Utah. The Discovery Energy crosswalk for the Salt Lake City metropolitan area (CBSA 41620) lists Salt Lake and Tooele counties. Davis and Utah counties are added under playbook rule 9, because Enbridge Gas Utah serves all four counties from one integrated system and they function as one market: the utility says its ability to shift gas between gate stations in the Salt Lake area counties is becoming more limited, and its gate station table names stations in Davis County (Sunset) and Utah County (Eagle Mountain). Items are classified inside, outside or unclear using the place names in the utility's plan; items outside the four counties are shown as system context.¹

Key takeaways

Which parts of the record fall inside the Salt Lake City area?

Enbridge Gas Utah's plan names gate stations by location, and it names Davis County only through the city of Sunset. The table classifies each item against the four counties; where the plan names no county the item is unclear and is not counted as inside.¹

Classification of items in Enbridge Gas Utah's 2026-27 plan against the four counties; unclear items are not counted as inside.

Has the Salt Lake City area had gas supply problems since 2020?

In February 2025 Enbridge Gas Utah called on its Magna LNG plant to cover a same-day supply shortfall. In a presentation to the Commission in April 2025 the utility said actual temperatures were dramatically colder than forecast, that the upstream pipeline called for matching demand and supply but too late in the day to buy more, and that it called on the plant for an additional 70,000 Dth of same-day supply. Supply began flowing in 15 minutes and reached the full requested rate in 1.5 hours. The utility's 2025 resource plan names the pipeline: MountainWest Pipeline notified the utility that demand at the gate stations it serves was exceeding the supply available from the pipeline.⁶

The utility's Key Accounts group notified customers to limit usage to match their scheduled supply. The filings do not say which customers were notified, how many, or whether any customer lost service. The Commission's January 2026 order records the event in one footnote and made no finding on cause. The same quarter was otherwise warmer than the plan forecast for December 2024 through February 2025.⁶

Discovery Energy's classification: a one-day upstream supply and balancing event after a forecast miss, met by on-system LNG. It shows a reliability exposure at the pipeline interface. It does not show a chronic shortage of local delivery capacity. The record is the utility's own; no pipeline notice from February 2025 survives, because the pipelines post only about 90 days. The utility says other major supply events since 2020 occurred elsewhere and did not have a major impact on its physical supply. Winter 2025-26 was warmer than normal, with 45 colder-than-normal days and 137 warmer-than-normal days in the utility's count.⁶⁹

How much spare gas capacity does the Salt Lake City area have on the coldest day?

Enbridge Gas Utah plans for a design day of 70 heating degree days in the Salt Lake region, 9.5 mph mean wind and a day that is not a Friday, Saturday, Sunday or winter holiday. For that day it forecasts firm sales demand of 1.29 MMDth at the city gates for 2025-26 and 1.30 MMDth for 2026-27, company-wide figures. Its modeling shows adequate supplies to meet that demand, and it says contracted transportation is adequate. Volumes above its firm rights on MountainWest's no-notice service are provided "on a best-efforts basis" and could be interrupted unless firm peaking service is used. These are utility forecasts. The Commission acknowledged the 2025 plan in January 2026 as generally complying with its standards and made no finding that capacity is adequate. The 2026-27 plan was filed in June 2026; the Division of Public Utilities and the Office of Consumer Services filed comments in September 2026 and the utility replied in October 2026. No order has been issued.²

The plan also projects each gate station's coldest-day flow against that station's capacity. Where a gate station is near its capacity, the utility starts a review of when to upgrade it once projected use reaches 80 percent.³

Selected gate stations in Enbridge Gas Utah's 2026-27 plan inside or unclear against the four counties: coldest-day projections (utility projections, not measured flows).³

System context: two stations in the plan are outside the four counties. Central, in the St. George area, is projected at 100 percent with flow of 75.1 MMcfd above its capacity of 47.5 MMcfd, and its capacity is set by Kern River's guaranteed delivery pressure; Rockport, in Summit and Wasatch counties, is projected at 90 percent (15.0 of 16.7 MMcfd).³

Each percentage is one station's projected maximum flow divided by that station's own capacity; the stations are not interchangeable, so the margins should not be added together. Riverton has no margin in the projection. The utility says it can shift gas between Salt Lake-area gas stations, but that "with population growth and large industrial customers coming onto the system, this flexibility is becoming more limited", and that there is a particular need to send more gas into Tooele County through two feeder lines from Riverton. Hunter Park, at 92 percent, is not expected to need more capacity soon, the utility says, because of its remaining margin, the nearby Rose Park station and the planned Riverton expansion.³

Stations limited by the upstream pipeline

Two stations inside the four counties are limited by the pipeline that feeds them rather than by the station itself. The utility says Sunset's capacity is limited "not by the facility, but due to upstream limitations on MWP's system", and that at Eagle Mountain the capacity upstream of the transfer of custody with Kern River is only 9.5 MMcfd, well below the 25.4 MMcfd it had assumed. Sunset is in Davis County and Eagle Mountain in Utah County. System context: a third station, Central near St. George, is outside the four counties; its design capacity is set by the minimum delivery pressure Kern River guarantees.⁴

The Magna LNG plant adds a cushion. Its send-out rate of 150,000 Dth per day is described by the utility as about 10 percent of Wasatch Front design-day load; against the 1.294 MMDth design-day total in its 2025-26 supply plan the rate is 11.6 percent (illustrative calculation, 150,000 divided by 1,294,000). The tank was full in July 2026. Keeping that cushion ready has a cost: the utility's filings forecast about $2.2 million of gas and $0.9 million of electricity to fill the tank for 2025-26. The filings reviewed do not say how those costs are recovered from customers, or what the February 2025 send-out cost.⁹

What is driving new natural gas demand?

Enbridge Gas Utah says "Since the early 2020s the Company has been seeing an increase in the number of large industrial service requests", largely associated with data centers and general power generation, with a higher concentration on the west side of the Salt Lake valley, specifically West Jordan. Large power-generation customers earlier ran at a partial contract load until paid pipeline improvements were completed, which is why the utility corrected its 2025 design-day growth figure to 1.1 percent. Across the whole system, design-day demand has grown about 1.3 percent a year and customers about 2.1 percent a year over five years.⁵

Large-load requests at Enbridge Gas Utah (utility statements to the Commission; counts only).⁵

The utility says it is unlikely that all inquiries will be built, since some prospective customers declined to contract after learning the estimated costs. Whether the in-service agreements are for data centers or for other onsite generation is not stated; the utility describes them as "for this type of facility". The utility also expects growth on the west side of Salt Lake City to require a new Kern River gate station in the mid-to-long term, with no date or cost given; it says data-center or power-generation growth there could accelerate that station with cost support from the new customers. The Office of Consumer Services says all incremental costs to serve new large loads should be assigned to those customers and asked in September 2026 for a load-scenario sensitivity analysis. The utility replied in October 2026 that it can do the analysis and wants to agree the study design first.⁵

Official records beyond the utility's filings add one proposed load in the four counties. In February 2026 Will-Power UT, LLC submitted a Notice of Intent to the Utah Division of Air Quality to build a power generation facility at 1499 N Pony Express Parkway, Eagle Mountain, in Utah County, with 17 natural gas-fired simple cycle turbines to provide primary power exclusively and directly to a nearby, separately owned and operated data center.¹⁴ The application states the turbines would use pipeline-quality natural gas but does not name a pipeline or utility, a gas volume or a service date, so the load is reported here and does not count toward the outlook. An exhibit filed with the Commission in May 2026 (see note 14) lists Will-Power UT, LLC's power generation air permit, UDEQ Site ID 16322, as pending, and it also states no in-service date, pipeline or gas volume.¹⁴ EIA's September 2026 generator inventory lists no planned natural gas-fired generator in Salt Lake, Tooele, Davis or Utah County, and a search of FERC notices since January 2025 found none naming those counties with a natural gas pipeline docket.¹⁴

Are upgrades arriving in time?

Remedies operating, planned or proposed (dates are utility plans stated in filings, not Commission approvals of each project).¹⁰

Timing is the issue the filings leave open. Riverton is projected at 100 percent of its own capacity in 2026-27, and its expansion is not expected to begin construction until 2029, three heating seasons later (illustrative calculation from the utility's dates). Between the utility's July 2025 and July 2026 presentations, the Central gate station project moved from 2028 to 2030 and the Eagle Mountain project from 2029 or 2030 to 2031; Riverton held at 2029. The Eagle Mountain project is the station whose upstream capacity is limited, and its date moved later. A new large customer that signed in late 2026 would not be built before 2027 or 2028 on the utility's timeline of at least 18 months. No filing links any specific remedy to a specific new load, and this page does not either. Kern River told a Utah legislative committee in June 2026 that new capacity "is not immediately available", needs federal approval that may take two years or more, and must be funded by its project customers.¹⁰

What does this mean for business gas costs?

Who pays has been decided for now, with a large-load study still open

The Commission's December 2025 order in Enbridge Gas Utah's rate case (note 8) approved an increase of about $60.2 million in distribution rates, on a stipulated revenue requirement of $604 million. On cost allocation, Enbridge Gas Utah spreads capacity-related costs using a factor weighted 60 percent to design-day demand and 40 percent to throughput. Position by party, as the order reports them: Nucor Steel-Utah asked to keep 60/40 but measure throughput by winter months; the Federal Executive Agencies asked for 60 percent excess demand and 40 percent throughput; the Utah Association of Energy Users asked for 66/34; the Division of Public Utilities asked to keep 60/40 but base the load factor on actual peaks. The Commission kept 60/40.⁸

No party recommended changing the utility's practice of excluding interruptible customers from design-day costs, and the Commission affirmed it. The Commission also temporarily closed the TBF class, a discounted transportation class, to new customers pending a study of new large loads, including data centers, due by the end of 2026. The Office of Consumer Services said it was concerned that new large customers on the discounted rate could burden residential and small commercial ratepayers; the utility agreed the class needed study. The order also observes that the utility may have added TBF customers without required Commission approval and directs it to file a list. The order does not state the effect of these allocations on any other customer class, and this page does not either. Amounts above are approved amounts; nothing here shows what any customer was billed or paid.⁸

Service terms matter before rates change

Interruptible customers carry the exposure. Tariff section 3.01 says they are "solely responsible for all financial and other consequences" of failing to interrupt, and section 3.02 sets a $40 per dekatherm penalty plus a move to firm service for three years. These are tariff terms; the filings reviewed do not show that any penalty was assessed. As an illustration, a plant using 1,000 Dth a day that kept using interruptible gas through a notice would face about $40,000 in penalties for each day of unauthorized use.¹¹

Who gets gas first in a shortage?

Enbridge Gas Utah's tariff PSCU 800 puts interruptible customers first. Section 3.02, Periods of Interruption, reads:

• "subject to temporary periods of interruption upon notice by the Company whenever the Company determines interruption is required"
• "no later than two hours from the issuance of the notice to discontinue use"
• "will incur a $40-per-dekatherm penalty for all interruptible volumes utilized during the course of an interruption"
• "interruptible transportation and sales customers will be required to interrupt partially on a pro rata basis based on representative daily use levels"

¹¹

Emergency restrictions in a major disaster or pipeline break: order of restriction in tariff section 7.03.¹¹

The tariff states that "restrictions will be made in the following order", to the extent practicable and prudent. Section 5.07 adds that firm sales service has priority over interruptible sales and all transportation service, and that firm transportation has priority over interruptible transportation. The tariff states no ranked order among interruptible customers. The utility's design-day models assume interruptible demand is curtailed. Its 2025 interruption analysis estimates the temperature at which curtailment of interruptible customers becomes likely at -6 degrees F for the zones covering southern Salt Lake County, northern Salt Lake County and Tooele County; these are utility estimates. The filings do not say whether any interruption notice was issued in February 2025.¹¹

Winter and market context

Context only, as of October 2026. It does not set the outlook level and makes no prediction of outages. Its sources are listed separately under Market and weather sources and are refreshed on the publication date.

NOAA's Climate Prediction Center said on October 15, 2026 that its November 2026 to January 2027 outlook favors above-normal seasonal mean temperatures for the northern tier and western third of the contiguous United States, a discussion that names regions and not counties.^A1 The U.S. Energy Information Administration said on October 6, 2026 that it expects U.S. natural gas inventories to enter the winter heating season 2% above the previous five-year average,^A2 and its October 2026 Short-Term Energy Outlook says prolonged periods of cold weather could increase withdrawals beyond its forecast.^A3 These are national and regional facts, not statements about Enbridge Gas Utah's system, and none of them is used to set the outlook on this page.

What is the outlook for Salt Lake City-area gas capacity through 2029?

Discovery Energy rates the outlook for Salt Lake City-area natural gas capacity through 2029 as High (confidence: High): the utility's own projections put the Riverton gate station in southwest Salt Lake County at 100 percent of its capacity in 2026-27, three heating seasons before its expansion is due to begin in 2029, which sets a base level of Elevated, and two documented risk factors raise it by one step.³⁷ Documented risk factors: a recent supply event (F3), since MountainWest Pipeline notified Enbridge Gas Utah in February 2025 that demand at its gate stations was exceeding the supply available, the utility called on its Magna LNG plant and its Key Accounts group told customers to limit usage;⁶ and an upstream limit (F5), since the utility says the Sunset gate station in Davis County is limited by upstream limitations on MountainWest's system and the Eagle Mountain gate station in Utah County is limited upstream of its handover point with Kern River, both inside the four counties.⁴¹³ Three developments would change the assessment: a Commission order or utility filing stating a design-day shortfall or a customer interruption on the Salt Lake, Tooele, Davis or Utah County systems; the Riverton 2029 date slipping or projected use rising above 100 percent in a later plan, or Riverton and Porter Lane work brought forward or use falling below 80 percent, or the utility reporting that the Sunset or Eagle Mountain upstream limits have been lifted; the large-load study due by the end of 2026, or the utility's load-scenario analysis, naming a constraint in the four counties.

Outlook levels, from least to most concern: Stable, Watch, Elevated, High, Severe. Levels describe the public record of capacity and supply risk; confidence is reported separately. They are qualitative assessments, not forecasts of outages.

Other dates to watch: the Commission's order on the 2026-27 plan, the storage decision, any federal filing on the MountainWest interconnect transfer expected in 2027, and Discovery Energy's download of both pipelines' postings for December 2026 through February 2027 around March 2027, because Kern River and MountainWest keep only about 90 days of capacity data.¹²

What should Salt Lake City-area manufacturers check now?

• Tariffs and charges, through a utility audit. Confirm each account is on the right rate class and tariff, and that riders, demand charges and capacity-related charges are billed correctly. Over 70% of the clients Discovery Energy has audited were billed incorrectly. An audit verifies tariffs and charges and recovers overcharges before winter costs rise.
• Your actual service election. Confirm whether each meter is firm sales, firm transportation or interruptible, and which class you are in (TBF, TSS, TSM, TSL or IS). The emergency restriction order in section 7.03 and the priority in section 5.07 depend on it.
• Interruption and penalty terms. Interruptible customers must stop within two hours of notice, face a $40 per dekatherm penalty and a three-year move to firm service if they fail, and bear their own losses. Check your contact details on file, because notice can go out by text or email.
• Backup arrangements. Interruptible customers must keep a backup system or be able to fully interrupt. Test it, and check fuel supply for the length of a winter event.
• Large-load and rate case developments. If you plan new or increased load, tariff section 9.02 lets the utility approve service only when it will not impair service to existing customers. Watch the TBF large-load study due by the end of 2026 and the Commission's order on the 2026-27 plan.

Frequently asked questions

Related case studies

Discovery Energy publishes gas capacity case studies for other metros, using the same method and outlook scale.

• Boise natural gas capacity case study (outlook: Watch)
• Pittsburgh natural gas capacity case study (outlook: High)
• Detroit natural gas capacity case study (outlook: High)
• Boston natural gas capacity case study (outlook: High)

Notes

1. Scope and boundary: the gas distribution system of Enbridge Gas Utah. The metro crosswalk for CBSA 41620 lists Salt Lake and Tooele counties; Davis and Utah counties are added under playbook rule 9 (decision by Tara Dugger, October 25, 2026). The extent of the service territory in each county is not confirmed from a tariff map; the plan names gate stations in all four. Davis County: the county's own city list includes Sunset (Davis County, Cities page, retrieved October 2026). West Jordan is assigned to Salt Lake County manually. Classifications are in slc_metro_classification.csv. Periods covered: 2025 to October 2026. Not established: customer-level impacts, winter pipeline postings, and any Commission finding on capacity adequacy. ↩
2. Utility forecast: Enbridge Gas Utah 2026-27 resource plan, docket 26-057-02, PDF 5 and 6; Commission order of January 2026 in docket 25-057-02, PDF 1 and 7. Company-wide figures; the Commission acknowledged the plan and made no finding that capacity is adequate. ↩
3. Gate-station projections come from Table 4.2 of the 2025-26 and 2026-27 resource plans (stations with an expected maximum design-day flow above 5 MMcfd; 28 rows each year). Percentages are printed in the plan and were recomputed in code; Central's flow exceeds its capacity and is printed as 100 percent. The capacity-minus-flow column is calculated here and is illustrative. A seventh station above 80 percent, Evanston South in Wyoming, is outside the four counties and not shown. The 2025-26 plan's table prints Riverton at 90 percent while its text calls Riverton "listed as 100% utilization". ↩
4. Upstream-limited stations: 2026-27 resource plan, PDF 47 and 48 (Sunset, Central, Eagle Mountain). The plan states no county for Sunset; Davis County is from the county's city list (note 1). Eagle Mountain's county is stated in the plan. Utility statements, not Commission findings. Counted under Outlook Scale v2.3 factor F5 and playbook rule 10 because both stations are inside the four counties. ↩
5. Data-center figures: this page uses counts only. The September 2025 reply comments give a total of 1,038 mmcf/day if all inquiries then pending were built and describe requested daily volumes of 2 to 240 mmcf/day per inquiry; the June 2026 plan gives about 4 Bcf/day if all 17 were built without saying whether the figure is requested, peak, annual or contracted volume. The second total is 3.85 times the first with fewer inquiries, and no document explains the change, so the units and basis could not be confirmed. Inquiries are not operating demand. No generator size or heat rate appears in the reviewed filings, so no gas-burn calculation was run. ↩
6. February 2025 event: Enbridge Gas Utah presentation to the technical conference of April 2025, PDF 19; 2025 resource plan, PDF 143; Commission order of January 2026, footnote 7; third quarter variance report, docket 24-057-04. Utility statements. ↩
7. Riverton expansion: 2026-27 resource plan, PDF 62 and 66; utility slide of July 2026, PDF 6. Cost not yet estimated. ↩
8. Rate case: Commission order of December 2025 and Order Altering of April 2026 in docket 25-057-06; party positions are as the order reports them, not findings. The order's class tables are not reproduced here because the order states no class-level bill effect. Storage-cost allocation was not addressed in the order text reviewed. ↩
9. Context and calculations are illustrative: the 11.6 percent LNG rate is 150,000 Dth per day divided by 1,294,000 Dth, the design-day total in the 2025-26 supply plan, whose chart labels it in thousand Dth; the three heating seasons for Riverton are the years from 2026-27 to the 2029 construction start. LNG tank figures: 2026 resource plan, PDF 145; utility slide of July 2026, PDF 15. ↩
10. Remedy dates are utility plans from its July 2025 and July 2026 presentations and its June 2026 plan, not Commission approvals of each project; Kern River statement: slides to the Utah legislative interim committee, June 2026. ↩
11. Tariff PSCU 800 text is from the compliance tariff filed in January 2026 and acknowledged by the Commission in February 2026; later corrections concerned only the volumetric rates for one class. Utah has no separate gas curtailment-priority rule that we found; the administrative rules on gas service were not read. Penalty provisions are exposure, not evidence that any penalty was assessed or paid. ↩
12. Pipeline postings: the Kern River and MountainWest capacity postings cover about 90 days. Tested in October 2026: the first day with real scheduled flows on the MountainWest page was July 2026. Winter 2025-26 and February 2025 are therefore not available, and no utilization figure for a delivery point is given on this page. The Kern River capacity form requires a browser; the MountainWest page can be read by script. Critical notices on both sites reach back only to mid-2026 and name no Enbridge Gas Utah delivery point. ↩
13. Risk factors, Outlook Scale v2.3: F3 and F5 are counted (notes 6 and 4). F1, F2 and F4 are not counted: no filing states a single source's share of the design day (Magna LNG is described as about 10 percent of Wasatch Front design-day load with no defined denominator), no key contract is named as ending without a decided replacement, and no new load has a filing-confirmed service date. F6 and F7 are not documented. F5 for Central is not counted because the station is outside the four counties. ↩
14. R3 (expanded) search, October 2026: EIA-860M September 2026 Planned sheet filtered by county and Federal Register FERC notices since January 2025 searched by county for pipeline (CP) dockets, both computed by code; Utah Division of Air Quality Notice of Intent, Will-Power UT, LLC, Eagle Mountain, February 2026 (PDF 4, 5 and 7), an applicant filing as submitted, not an agency decision. The air permit application states no in-service date. The Commission's docket 26-2660-01, Exhibit E (Will-Power UT, LLC, Project Aquila permits, PDF 2, dated May 7, 2026 by its file name), a regulator docket exhibit as filed, shows the power generation air permit, UDEQ Site ID 16322, as pending. Not established by code: the Utah DAQ permit database as a whole (searched by web only), and interconnection records for non-ISO utilities. News is leads only and none is used. ↩

Market and weather sources

Official public sources retrieved October 25, 2026. They are separate from the record notes above.

1. A1. NOAA Climate Prediction Center, Prognostic Discussion for Long-Lead Seasonal Outlooks, October 15, 2026. Link ↩
2. A2. U.S. Energy Information Administration, press release, "EIA expects a mixed picture for winter fuel costs this year," October 6, 2026. Link ↩
3. A3. U.S. Energy Information Administration, Short-Term Energy Outlook, October 2026. Link ↩

Sources

1. Utah Public Service Commission, Order, Enbridge Gas Utah Integrated Resource Plan for plan year June 2025 to May 2026, docket 25-057-02, January 2026 (Commission order).
2. Enbridge Gas Utah, Integrated Resource Plan for plan year June 2026 to May 2027, docket 26-057-02, filed June 2026 (utility filing, not yet acted on by the Commission).
3. Enbridge Gas Utah, Integrated Resource Plan for plan year June 2025 to May 2026, docket 25-057-02, filed June 2025 (utility filing).
4. Enbridge Gas Utah, Reply comments, docket 25-057-02, September 2025 (utility filing).
5. Enbridge Gas Utah, Presentations to technical conferences, docket 25-057-02: April 2025 and July 2025; docket 26-057-02: May 2026 and July 2026 (utility presentations).
6. Enbridge Gas Utah, Third quarter variance report, December 2024 through February 2025, docket 24-057-04, filed May 2025 (utility filing).
7. Division of Public Utilities; Office of Consumer Services; Enbridge Gas Utah, Initial comments (September 2026) and reply comments (October 2026), docket 26-057-02 (party comments).
8. Utah Public Service Commission, Order, application of Enbridge Gas Utah to increase distribution rates, docket 25-057-06, December 2025, and Order Altering, April 2026 (Commission order).
9. Enbridge Gas Utah, Utah Natural Gas Tariff PSCU 800, compliance filing, docket 25-057-06, January 2026; Commission acknowledgment letter, February 2026 (effective tariff).
10. Kern River Gas Transmission, Slides to the Utah Public Utilities, Energy, and Technology Interim Committee, June 2026 (pipeline statement).
11. Kern River Gas Transmission; MountainWest Pipeline, Public informational postings and notices, retrieved October 2026 (pipeline notices).
12. Will-Power UT, LLC, Notice of Intent to the Utah Division of Air Quality, Eagle Mountain, Utah, February 2026 (applicant filing); the Commission's docket 26-2660-01, Exhibit E, Will-Power, UT LLC, Project Aquila Permits (file dated May 7, 2026); Davis County, Utah, Cities page (county government); U.S. Energy Information Administration, EIA-860M Preliminary Monthly Electric Generator Inventory, September 2026, and Federal Register notices of the Federal Energy Regulatory Commission searched by county.

Figures are as reported in the sources above, as of October 2026. Requested amounts, approved amounts and customer charges are kept separate.