What regulatory or permitting risks remain that could delay or alter the project scope? | ET (Aug 06, 2025) | Candlesense
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What regulatory or permitting risks remain that could delay or alter the project scope?

Regulatory and permitting risks that could still delay or reshape Energy Transfer’s Transwestern Desert‑Southwest pipeline expansion

Regulatory/Permitting Area What is still required / at risk Why it matters for the project timeline or scope
Federal Energy Regulatory Commission (FERC) – Certificate of Public Convenience & Necessity (CPCN) • Even after the internal FID, Energy Transfer must still obtain a final FERC “certificate” that formally authorises the expansion.
• The filing triggers a 30‑day “notice of filing” and a 30‑day “comment” period, during which interested parties (state regulators, environmental NGOs, tribal groups, land‑owners) can raise objections.		 • Any substantive comment or objection can extend the review by months and may force Energy Transfer to modify routing, capacity, or operating standards.
National Environmental Policy Act (NEPA) – Environmental Impact Statement (EIS) / Environmental Assessment (EA) • If the project crosses federal lands (e.g., BLM‑administered desert, U.S. Forest Service, or Bureau of Indian Affairs), a NEPA review is mandatory.
• The agency (usually BLM or the Department of the Interior) must issue a Record of Decision (ROD) after public scoping, draft and final EIS, and a 30‑day public comment period.		 • NEPA can uncover previously un‑identified “significant impacts” (e.g., on endangered species, water resources, cultural resources) that may require route changes, additional mitigation measures, or even project redesign.
State‑level permits (Arizona & New Mexico) • Arizona: Arizona Corporation Commission (ACC) pipeline safety and siting approvals; Arizona Department of Environmental Quality (ADEQ) air‑ and water‑quality permits; state water‑right approvals for any river or aquifer crossings.
• New Mexico: New Mexico Public Regulation Commission (PRC) and the Environment Department (NMED) permits; state water‑use permits; possible “State Environmental Review” (SER) if the project impacts state‑listed resources.		 • State agencies often have separate “public interest” standards and can impose additional mitigation (e.g., stric‑er erosion‑control, air‑emission caps). Delays can arise from parallel state‑level environmental reviews, especially if the project triggers the state’s own NEPA‑like process.
Bureau of Land Management (BLM) / Federal land‑use authorizations • Right‑of‑way (ROW) on BLM‑administered lands requires a “Right‑of‑Way” (ROW) application, environmental analysis, and a “Finding of No Significant Impact” (FONSI) or a more detailed NEPA review.
• If the pipeline traverses tribal lands, the Department of the Interior – Office of Indian Energy and the relevant tribal governments must be consulted and may need to issue Tribal‑Land‑Use permits.		 • Federal land‑use approvals can be a bottleneck, especially when the BLM must coordinate with multiple land‑use plans (e.g., Wilderness Areas, National Conservation Areas). Tribal opposition can lead to litigation or the need for additional routing changes.
Clean Water Act (CWA) – Section 404 permits (U.S. Army Corps of Engineers) • Any in‑water work (e.g., river crossings, wetlands disturbance) requires a Section 404 permit. The Corps’ “public interest” review includes a 30‑day comment period and can be subject to “veto” by the EPA if the project is deemed to have unacceptable water‑quality impacts. • CWA permits can be delayed by “significant impact” findings, especially concerning endangered aquatic species or critical habitats.
Clean Air Act (CAA) – Emission‑source permits • Construction‑‑related emissions (e.g., diesel equipment, fugitive gas releases) and the long‑term operation of compressor stations may need state‑level “major source” permits and/or EPA “New Source Review” (NSR) determinations. • Air‑quality modeling disputes can trigger additional mitigation (e.g., low‑NOx equipment) or even limit the size of compressor stations, affecting the project’s capacity.
Endangered Species Act (ESA) – Biological Opinions • If the pipeline corridor intersects known habitats of federally listed species (e.g., desert‑bighorn sheep, Mexican gray‑wolf, or threatened aquatic species), the U.S. Fish & Wildlife Service (or the National Marine Fisheries Service) must issue a Biological Opinion (BiOp). • A “negative” BiOp can halt construction until required mitigation (e.g., habitat offsets, timing restrictions) is implemented, potentially altering the alignment or reducing the number of new facilities.
Cultural‑resource and Tribal‑consultation requirements • Section 106 of the National Historic Preservation Act (NHPA) requires consultation with the State Historic Preservation Office (SHPO) and potentially with tribal cultural‑resource agencies if historic or archaeological sites are present. • Discovery of a significant site can force a “route‑change” or extensive mitigation (e.g., data‑collection, monitoring), adding time and cost.
State‑level climate‑policy or ESG‑related reviews • Both Arizona and New Mexico have enacted “climate‑resilience” statutes that may require demonstration that the pipeline will not exacerbate greenhouse‑gas emissions beyond state‑set caps.
• ESG‑screening by investors (e.g., S&P ESG ratings) can lead to additional disclosure or design‑change requirements.		 • Failure to meet emerging climate‑policy thresholds could result in conditional financing, forcing Energy Transfer to adopt lower‑emission technologies (e.g., electrified compression) that could reshape the project scope.
Potential litigation / third‑party challenges • Environmental NGOs, land‑owner groups, or tribal entities may file lawsuits challenging any of the above permits (e.g., alleging insufficient NEPA analysis, violation of water‑rights, or inadequate mitigation). • Litigation can result in injunctions that stop work, force re‑filing of permits, or demand additional environmental studies—each adding months to the schedule and potentially prompting redesign.

How these risks could translate into project delays or scope changes

  1. Permit‑stacking and sequencing – Because multiple agencies (FERC, BLM, EPA, state commissions, tribal governments) must each issue a permit, the overall “critical path” can be extended if any agency’s review timeline exceeds the projected schedule. A missed or late submission (e.g., an incomplete NEPA scoping document) can add 30‑90 days per agency.

  2. Conditional approvals – Agencies often grant permits with “conditions” (e.g., additional monitoring, reduced operating pressure, or specific mitigation measures). If the conditions are more stringent than originally planned, Energy Transfer may need to redesign compressor stations, add extra monitoring stations, or even reduce the intended capacity—altering the original scope.

  3. Route‑change mandates – Environmental or cultural‑resource findings can force the pipeline to be rerouted around a protected habitat or an archaeological site. A reroute can increase the length of the line, add new right‑of‑way negotiations, and increase construction costs.

  4. Capacity‑restriction requirements – Air‑quality or climate‑policy reviews may limit the maximum allowable throughput, prompting Energy Transfer to re‑evaluate the “economic supply” assumptions that underpinned the FID.

  5. Financing contingencies – Many project financiers (e.g., banks, ESG‑focused investors) attach “permit‑completion” covenants to credit facilities. If a key permit is delayed, lenders may withhold draw‑downs, forcing the developer to seek alternative funding or pause construction.

Bottom‑line assessment

  • Regulatory risk is still “high‑medium”: The FID confirms internal financial approval, but the external permitting pipeline—dominated by FERC, NEPA, state, and federal land‑use approvals—still contains several “critical‑path” steps that can each add 3‑12 months of delay if objections, additional studies, or litigation arise.
  • Scope‑alteration risk is moderate: Most of the identified permitting risks would first manifest as schedule extensions; however, if a permitting authority imposes substantive environmental or cultural conditions (e.g., mandatory route change, capacity caps, or new mitigation infrastructure), the project’s original design and economic assumptions could be materially altered.

Key mitigation actions Energy Transfer should prioritize

  1. Accelerate FERC filing and proactively engage in the 30‑day comment window to address likely concerns early.
  2. Complete NEPA scoping and public outreach with a focus on tribal consultation and endangered‑species analysis to reduce the chance of a “significant impact” finding.
  3. Secure early BLM and state water‑right agreements to avoid later “right‑of‑way” bottlenecks.
  4. Develop a robust environmental‑mitigation plan (e.g., habitat offsets, air‑emission controls) that can be offered up‑front to regulators and stakeholders.
  5. Maintain a “contingency” schedule and budget (≈10‑15 % of total project cost) to absorb potential permit‑related extensions or design modifications.

By addressing these permitting fronts now—while the FID is fresh—Energy Transfer can lower the probability that any remaining regulatory or permitting risk will evolve into a material delay or a fundamental change to the Transwestern Desert‑Southwest pipeline expansion.

Other Questions About This News

How will the expansion of the Transwestern Pipeline affect Energy Transfer's cash flow and earnings forecasts? Will the FID lead to any changes in Energy Transfer's balance sheet, such as increased debt or equity issuance? How will the increased natural gas supply to Arizona and New Mexico influence the regional utility markets and downstream demand? What is the anticipated impact of the expansion on the company's dividend outlook and stock price valuation? How might the new supply corridors impact the pricing dynamics of natural gas in the Southwest versus the broader U.S. market? How does this pipeline expansion compare to recent capacity upgrades by competitors like Williams, Kinder Morgan, or TC Energy? Will the expansion enhance Energy Transfer's market share in the Permian Basin corridor and improve its transportation utilization rates? What are the projected capital expenditures for the Desert Southwest pipeline expansion and how will they be financed? What is the expected timeline for project completion and when will the additional capacity be available?