Tex. Utilities Code § 36.216 — TX Code / Code ut / Chapter 36 / Section 36.216
§ 36.216. RECOVERY OF ANNUAL CAPACITY-RELATED COSTS.
Status: in_force

(a) This section applies only to an electric utility that operates solely outside of ERCOT in areas of this state included in the Southeastern Electric Reliability Council.

(b) It is the intent of the legislature that certain changes to the level of an electric utility's capacity-related costs and capacity-related revenues due to wholesale rate decisions and determinations by a federal agency or a regional transmission organization subject to federal jurisdiction should be timely reflected in the utility's rates.

(c) On application by an electric utility that has not exceeded the utility's authorized return on equity as shown in the utility's most recent earnings monitoring report at the time of the application, the commission shall establish a capacity cost recovery rider that must be annually updated and that allows:

(1) recovery of the utility's costs that are eligible as provided by Subsection (d); and

(2) return to ratepayers of the utility's revenues that are eligible as provided by Subsection (d).

(d) In this section, eligible costs and revenues are capacity-related costs and revenues associated with the electric utility's participation in a multi-state capacity auction operated by a regional transmission organization or independent system organization authorized by the Federal Energy Regulatory Commission, to the extent the costs and revenues are not already being recovered through the utility's base rates.

(e) Amounts recovered through a capacity cost recovery rider are subject to reconciliation in the next base rate proceeding for the electric utility. As part of the reconciliation, the commission shall review the costs and revenues to determine if they were reasonable and prudently incurred and to ensure the electric utility is only recovering costs allocable to retail customers in this state and is not over-recovering costs. In each base rate proceeding following the establishment of a capacity cost recovery rider, the commission shall remove from the electric utility's base rates all cost and revenue items eligible for recovery through the electric utility's capacity cost recovery rider.

(f) The annual revenue requirement and rates for a proposed capacity cost recovery rider must include:

(1) the electric utility's calculated costs and revenues for the upcoming year beginning on the June 1 associated with the utility's participation in a multi-state capacity auction; and

(2) a true-up amount that accounts for any difference between the utility's actual eligible costs and revenues and the utility's actual collections under any capacity cost recovery rider put into effect two years before the proposed effective date of the proposed rider, plus:

(A) an amount to account for any mathematical error identified in the utility's most recent capacity cost recovery rider application proceeding; and

(B) an amount to account for any refunds or surcharges ordered by the Federal Energy Regulatory Commission or by a regional transmission organization or independent system organization related to a previous year's capacity auction that:

(i) are identified on a regional transmission organization or independent system operator settlement statement; or

(ii) were directed by a Federal Energy Regulatory Commission order issued in the preceding 12-month period.

(g) The capacity cost recovery rider charges must be derived using:

(1) the same production demand allocation factors approved in the electric utility's most recent base rate case; and

(2) the projected billing determinants for the rate effective period.

(h) The billing determinants must be derived using each customer class's projected kilowatt-hour usage, except for customer classes with demand meters for which the billing determinants must be derived using each customer class's projected kilowatt billing demand.(a) This section applies only to an electric utility, other than a river authority, that:

(1) operates solely inside ERCOT; and

(2) was identified by the commission as responsible for constructing transmission as part of the reliability plan for the Permian Basin approved by the commission under Section 39.167, as added by Chapter 892 (H.B. 5066), Acts of the 88th Legislature, Regular Session, 2023.

(b) An electric utility that makes total capital expenditures that exceed 300 percent of annual depreciation in a calendar year may elect in the following calendar year to file a single annual proceeding to adjust nonfuel rates on a system-wide basis to reflect changes in transmission and distribution invested capital in lieu of adjustments to retail and wholesale transmission and distribution rates authorized under Section 36.210, Section 38.078, as added by Chapter 836 (H.B. 2555), Acts of the 88th Legislature, Regular Session, 2023, and commission rules adopted under Section 35.004.

(c) An electric utility seeking to make an election under this section shall:

(1) except as provided by Subsection (d), use the filing requirements adopted by the commission for the adjustment proceedings described by Subsection (b);

(2) file a notice with the commission of the utility's intent to make the election and supporting documentation of the capital expenditures described by Subsection (b) at least 60 days before the date the utility makes a filing under Subsection (b);

(3) provide evidence of the utility's ongoing eligibility in the annual proceeding under Subsection (b); and

(4) notify the commission if the utility determines that the utility no longer qualifies for continued use of the adjustment under this section.

(d) An electric utility that makes an election under this section:

(1) may defer all or a portion of the costs, including depreciation expense and carrying costs, associated with the transmission and distribution invested capital 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 for invested capital, as described by Section 36.053, not currently reflected in the utility's rates for recovery as a regulatory asset; and

(2) shall:

(A) update the allocation of costs among customer classes to reflect customer growth; and

(B) take into account changes in the number of the utility's customers and the effects, on a weather-normalized basis, that energy consumption and energy demand have on the amount of revenue recovered through the utility's base rates.

(e) Unless otherwise agreed to by an electric utility that makes an election under this section, the commission shall:

(1) include the regulatory asset in rates set under this section; and

(2) authorize amortization of the regulatory asset over:

(A) a period not to exceed 18 months; or

(B) if a recovery period described by Paragraph (A) would cause the utility to earn more than the utility's allowed return on investment as normalized for weather, a longer recovery period.

(f) During a period when an electric utility that makes an election under this section earns more than the utility's allowed return on investment, on a weather-adjusted basis, the utility shall apply the over-earnings to the balance of the regulatory asset under Subsections (d) and (e).

(g) The commission shall approve an adjustment under this section not later than the 120th day after the date an electric utility files a request for the adjustment.

(h) The electric utility shall provide notice to retail electric providers of rates approved under this section not later than the 45th day before the date the rates take effect.roved in the electric utility's most recent base rate case; and

(2) the projected billing determinants for the rate effective period.

(h) The billing determinants must be derived using each customer class's projected kilowatt-hour usage, except for customer classes with demand meters for which the billing determinants must be derived using each customer class's projected kilowatt billing demand.

(i) Until the time the electric utility removes from base rates the costs eligible for rider recovery under Subsection (d), and the costs eligible for rider recovery described in Subsection (g)(2), and these costs are recovered solely through the capacity cost recovery rider, the calculation of the capacity cost recovery rider must include a load growth adjustment to take into account changes in the number of the utility's customers and the effects, on a weather-normalized basis, that energy consumption and energy demand have on the amount of revenue recovered through the utility's base rates.

(j) The commission shall process an application to establish or update a capacity cost recovery rider in accordance with Subsections (k)-(o).

(k) For a capacity cost recovery rider that will include an electric utility's costs to be incurred beginning on June 1 of a given year, the utility must submit the rider application not later than:

(1) May 15 of that year; or

(2) if the regional transmission organization or independent system operator publishes its capacity auction cost results after the 20th business day of April of that year, a date that is the same number of days after May 15 of that year as the number of days after the 20th business day of April the results were published.

(l) The application must be fully documented, including testimony and all supporting work papers in native format.

(m) A response to the electric utility's filing that is made by commission staff or an intervenor:

(1) must be filed not later than the 15th day after the date of the utility's filing; and

(2) may address only whether the application conforms with any rule the commission adopts to implement this section and the mathematical accuracy of the utility's proposed capacity cost recovery rider revenue requirement and rates.

(n) Any other inaccuracy identified under Subsection (m)(2) may be addressed only in the electric utility's next capacity cost recovery rider application.

(o) The commission may review costs and revenues and shall issue an order approving, modifying, or denying an electric utility's proposed or updated capacity cost recovery rider not later than the 60th day after the date the application is filed.

(p) This section expires September 1, 2035.f the regulatory asset under Subsections (d) and (e).

(g) The commission shall approve an adjustment under this section not later than the 120th day after the date an electric utility files a request for the adjustment.

(h) The electric utility shall provide notice to retail electric providers of rates approved under this section not later than the 45th day before the date the rates take effect.

(i) If the commission does not issue a final order in the period described by Subsection (g) and the electric utility complies with Subsection (h), the utility may place the requested rates into effect on a temporary basis not earlier than the 165th day after filing the request. The utility shall refund or credit against future bills any difference between the temporary rate and the final rate along with interest at the current interest rate as determined by the commission.

(j) An electric utility that makes an election under this section may not petition for another adjustment under this section, Section 36.210, Section 38.078, as added by Chapter 836 (H.B. 2555), Acts of the 88th Legislature, Regular Session, 2023, or commission rules adopted under Section 35.004 before the first anniversary of the date the utility files a request under Subsection (b).

(k) Notwithstanding any other law, in setting the rate of return in a comprehensive base rate proceeding for an electric utility receiving a rate adjustment under this section, the commission may expressly consider the effect of the adjustment on the utility's financial risk and rate of return.

(l) An electric utility's use of this section terminates when the utility no longer qualifies for an adjustment under this section, except that the utility's rates in effect on the date the utility no longer qualifies remain in effect until modified in a future proceeding.

(m) Nothing in this section is intended to:

(1) conflict with a provision of a financing order issued under Subchapter I;

(2) affect the limitation on the commission's jurisdiction under Section 32.002;

(3) limit the jurisdiction of a municipality over the rates, operations, and services of an electric utility under Section 33.001 or limit the ability of a municipality to obtain a reimbursement under Section 33.023;

(4) prevent an electric utility, including a river authority, from requesting cost recovery or rate relief under a mechanism authorized under Chapter 36 or other provisions of this title if the utility or authority is ineligible or becomes ineligible to make an election under this section; or

(5) prevent the commission from:

(A) reviewing the investment costs included in an adjustment under this section in the electric utility's next comprehensive base rate proceeding to determine whether the costs were prudent, reasonable, and necessary;

(B) refunding to customers any amount improperly recovered through an adjustment under this section, with appropriate carrying costs; or

(C) if applicable, refunding to customers the realized equity portion of carrying costs deferred under Subsection (d)(1) on a transmission project associated with the reliability plan described by Subsection (a) if the in-service date is unreasonably delayed beyond December 31, 2030, due to the utility's actions, unless the utility demonstrates through contemporaneous documentation of the utility's analysis and decision-making that the delay is necessary to maximize the load serving capability of other transmission projects.

(n) This section expires December 31, 2035.