Enbridge Gas Utah outlines transport, storage and hedging plans ahead of 2025–26 IRP year

Enbridge Gas, Utah told a technical conference with the Utah Public Service Commission and utility oversight staff on March 4 that it plans to add seasonal pipeline capacity, pursue new storage options and maintain a blended hedging program for the 06/01/2025–05/31/2026 integrated resource plan year.

The utility described a transportation-focused near-term plan that includes newly acquired winter-only capacity from Kern River, a proceeding agreement for Northwest Pipeline capacity contingent on project completion, and participation in non-binding interest for a potential Fiddler-to-Goshen expansion. Enbridge also reviewed storage holdings and possible new storage concepts, and defended its mix of fixed-price purchases and indexed, daily products used to manage winter risk and summer injections.

The discussion matters because the IRP feeds the commission’s annual oversight of resource adequacy and customer cost exposure. Commissioners and utility division staff pressed Enbridge for clearer scenario modeling of extreme events, for more detail on the timing and deliverability of proposed pipeline and storage projects, and for explicit explanation of how hedging choices trade off cost and supply reliability.

Steve Wall, gas supply lead for Enbridge Gas, summarized the company’s commercial strategy as “to be reliable, but also at the same time, staying cost efficient or effective for our customers,” and walked participants through current and prospective firm transportation, storage, and hedging positions. Wall said Enbridge recently secured a winter-only Kern River contract won in a February open season that begins November 2026 and is shaped to peak winter demand — “This capacity finally became available. We’ve been on it. We’ve been on it for 15 years, and we ended up getting it,” he said.

On pipeline capacity, Enbridge reported: - Mountain West is the pipeline with the largest share of the company’s firm winter transportation (the slide described “just over a BCF” of winter-only capacity at that gate). - A proceeding agreement for 25,000 dekatherms per day on Northwest Pipeline is contingent on the counterparty’s project schedule; company staff said the project might complete in 2025 but that permit/land issues make 2026 more likely. - A small CIG (Colorado Interstate Gas) contract — 400 dekatherms per day — serves the town of Wamsutter, Wyo.; that contract comes up for extension in late 2025. - Enbridge submitted a non‑binding interest for a proposed Fiddler-to-Goshen expansion that would offer up to two blocks of 250,000 dekatherms per day and include partial access to the White River hub; the project sponsor is testing market interest and would later run a binding open season and define the construction scope (compression and potential loop or replacement pipe).

On storage, the company said it recontracted its Clay Basin firm storage through 2030 and holds 2 BCF of Spire Storage West with a 22,000‑dekatherm daily withdrawal capability. Mountain West made 8 BCF of interruptible storage available; Enbridge said it declined to rely on interruptible storage because injection and withdrawal rights are non‑firm and therefore do not add dependable deliverability. Enbridge also discussed longer‑term storage concepts including caverns near Delta (referred to in the session as a possible Magland option) and brainstorming on using depleted wells for company‑developed storage, noting such projects would require pipeline tie‑ins and likely an anchor tenant to be economic.

Regulators and division staff repeatedly asked Enbridge to run retrospective modeling on major cold events. Commissioners asked the company to simulate how alternative storage/transport mixes would have performed in events such as the Yuri winter event, and Enbridge agreed to pursue scenario runs that compare outcomes (for example, whether increased deliverability from aquifer expansions or additional LNG/magnet storage would have materially changed end‑of‑event constraints).

On hedging and fixed‑price purchasing, Enbridge described a layered program: must‑take base load deals, peaking and call‑on products, monthly indexed buys and a set of fixed‑price purchases placed in late summer through RFPs. For the 2024–25 heating season the company said it purchased about 80,000 dekatherms per day in fixed‑price deals during August RFPs (smaller than a prior year’s 84,000) and reported total fixed‑price costs of roughly $43.88 million for the season, compared with about $56.19 million the prior year. The company reported that replacing those fixed deals with daily market purchases at Opal would have cost a different amount in many months; Enbridge characterized the roughly $19 million difference as the premium paid for price certainty — a risk‑management ‘‘insurance’’ cost the utility factors into customers’ exposure.

The company also emphasized production from WexPro: on a typical winter peak day WexPro supplied about 22% of Enbridge’s system demand, while WexPro supplies a much larger share of typical summer injection volumes. Staff and commissioners pressed the company to avoid an impression that WexPro provides more winter deliverability than its actual winter‑day contribution; Enbridge acknowledged the distinction and told the group it would emphasize the 22% winter contribution in future IRP materials.

Utility staff flagged several follow‑up items for the IRP and near‑term filings: clarifying timing for variance report data (some datasets lag by two months), possibly extending reply comment deadlines to incorporate lagged data, providing more detailed day‑by‑day deliverability modeling for interruptible versus firm storage, and producing scenario recreations of past extreme events (for example, Yuri) comparing proposed alternative portfolios.

Enbridge and the commission staff agreed to a confidential technical meeting to dive deeper on data center demand and to run additional scenario analyses before the next IRP milestone.

The conference included commissioners and a mix of commission, division and consumer‑service staff, legal counsel and Enbridge Gas representatives; there were no formal votes taken during the session.

Looking ahead, Enbridge identified near‑term items the company will pursue for the IRP year: finalize participation and timing for the Northwest and Fiddler pipeline opportunities, continue discussions about Magland/depleted‑well storage concepts, evaluate whether aquifer deliverability expansions are cost‑effective relative to LNG or peaker products, and provide the commission requested scenario modeling of historic extreme events to better quantify trade‑offs between reliability and cost.