Tex.
Utils. Code Section 38.078
Transmission and Distribution System Resiliency Plan and Cost Recovery
(a)
In this section, “plan” means a transmission and distribution system resiliency plan described by Subsection (b).(b)
An electric utility may file, in a manner authorized by commission rule, a plan to enhance the resiliency of the utility’s transmission and distribution system through at least one of the following methods:(1)
hardening electrical transmission and distribution facilities;(2)
modernizing electrical transmission and distribution facilities;(3)
undergrounding certain electrical distribution lines;(4)
lightning mitigation measures;(5)
flood mitigation measures;(6)
information technology;(7)
cybersecurity measures;(8)
physical security measures;(9)
vegetation management; or(10)
wildfire mitigation and response.(c)
A plan must explain the systematic approach the electric utility will use to carry out the plan during at least a three-year period.(d)
In determining whether to approve a plan filed under this section, the commission shall consider:(1)
the extent to which the plan is expected to enhance system resiliency, including whether the plan prioritizes areas of lower performance; and(2)
the estimated costs of implementing the measures proposed in the plan.(e)
The commission shall issue an order to approve, modify, or deny a plan filed under Subsection (b) and any associated rider described by Subsection (i) not later than the 180th day after the plan is filed with the commission. The commission may approve a plan only if the commission determines that approving the plan is in the public interest.(f)
For a plan approved by the commission, with or without modification, an electric utility may request a good cause exception on implementing all or some of the measures in the plan if operational needs, business needs, financial conditions, or supply chain or labor conditions dictate the exception. The commission’s denial of a plan is not considered to be a finding of the prudence or imprudence of a measure or cost in the plan for the purposes of Chapter 36 (Rates) or this chapter.(g)
An electric utility for which the commission has approved a plan under this section may request that the commission review an updated plan submitted by the electric utility. The updated plan must comply with any applicable commission rules and take effect on a date that is not earlier than the third anniversary of the approval date of the utility’s most recently approved plan. The commission shall review and approve, modify, or deny the updated plan in the manner provided by Subsections (d), (e), and (f).(h)
An electric utility’s implementation of a plan approved under this section may be reviewed for the purposes of Chapter 36 (Rates) or this chapter. If the commission determines that the costs to implement an approved plan were imprudently incurred or otherwise unreasonable, those costs are subject to disallowance.(i)
Notwithstanding any other law, an electric utility may file with a plan an application for a rider to recover the electric utility’s distribution investment that is made to implement a plan and is used and useful to the electric utility in providing service to the public. The electric utility may file the application before the electric utility places into service the distribution investment to implement an approved plan. The commission may approve the rider application before the electric utility places into service the distribution investment to implement an approved plan. The commission may not approve a rider that would allow an electric utility to begin recovering the distribution investment before the utility begins to use the investment to provide service to the public. If the commission approves or modifies the plan, the commission shall determine the appropriate terms of the rider in the approval order. The commission shall adopt a procedure for reconciliation of an electric utility’s distribution-related costs to implement an approved plan.(j)
As part of a review described by Subsection (g), the commission shall reconcile the rider authorized under Subsection (i) to determine the electric utility’s reasonably and prudently incurred plan costs.(k)
If an electric utility that files a plan with the commission does not apply for a rider under Subsection (i), after commission review, the utility may defer all or a portion of the distribution-related costs relating to the implementation of the plan for future recovery as a regulatory asset, including depreciation expense and carrying costs at the utility’s weighted average cost of capital established in the commission’s final order in the utility’s most recent base rate proceeding in a manner consistent with Chapter 36 (Rates), and use commission authorized cost recovery alternatives under Sections 36.209 (Recovery by Certain Non-ercot Utilities of Certain Transmission Costs) and 36.210 (Periodic Rate Adjustments) or another general rate proceeding.(l)
Plan costs considered by the commission to be reasonable and prudent may include only incremental costs that are not already being recovered through the electric utility’s base rates or any other rate rider and must be allocated to customer classes pursuant to the rate design most recently approved by the commission.(b)
A circuit segmentation study must:(1)
use an engineering analysis to examine whether and how the transmission and distribution utility’s transmission and distribution systems can be segmented and sectionalized to manage and rotate outages more evenly across all customers and circuits, while maintaining the protections offered to critical facilities;(2)
include an engineering analysis of the feasibility of using sectionalization, automated reclosers, and other technology to break up the circuits that host significant numbers of critical facilities into smaller segments for outage management purposes to enable more granular and flexible outage management;(3)
identify feeders with critical facilities that, if equipped with facility-specific backup power systems and segmentation, can enhance the utility’s outage management flexibility; and(4)
include an estimate of the time, capital cost, and expected improvements to load-shed management associated with the circuit segmentation study.(c)
Each transmission and distribution utility shall submit a report of the conclusions of the utility’s study to the commission not later than September 1, 2024.(d)
The commission shall review each circuit segmentation study not later than March 15, 2025.
Source:
Section 38.078 — Transmission and Distribution System Resiliency Plan and Cost Recovery, https://statutes.capitol.texas.gov/Docs/UT/htm/UT.38.htm#38.078 (accessed Jun. 5, 2024).
