TITLE 16. ECONOMIC REGULATION

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 24. SUBSTANTIVE RULES APPLICABLE TO WATER AND SEWER SERVICE PROVIDERS

The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §24.3 relating to Definitions, §24.25, relating to Form and Filing of Tariffs, §24.27, Notice of Intent and Application to Change Rates, §24.41, relating to Cost of Service, and §24.43, relating to Rate Design. The commission also adopts new 16 TAC §24.26, relating to Test Year and §24.28, relating to Review of Test Year. The commission adopts these rules with changes to the proposed text as published in the April 10, 2026 issue of the Texas Register (51 TexReg 2292). The rules will be republished.

The amended and new rules will implement Texas Water Code §§13.1831, 13.184(d), and 13.185(l) and (m) as enacted by House Bill (HB) 2712 during the Texas 89th Regular Legislative Session (89R). The adopted amendments will implement Texas Water Code §§13.183(a)(1), 13.184(a), 13.185(b), (d)(1), and (j) as amended by HB 2712 (89R); Texas Water Code §13.185(k) as enacted by HB 2712 (89R); as well as Texas Water Code §13.002 of the Texas Water Code, as enacted by Senate Bill (SB) 740, Section 2 (89R) by adding the definition of "public utility agency."

Implementation of HB 2712

Addition of combined test year and future test year

Prior to HB 2712, water utilities have only been authorized to use a "historic test year" when filing a comprehensive base rate change application under Chapter 13 of the Texas Water Code. A historic test year requires a utility to reference past operational performance to set rates (e.g., the most recent 12 calendar months of available operating data). In accordance with HB 2712, the adopted rules will enable water and sewer utilities to select and use a combined test year (i.e., a combination of past performance and predicted future performance) or a future test year (i.e., exclusively predicted future performance) in a comprehensive base rate proceeding. The adopted rules will also establish minimum requirements for a utility's test year selection in a rate change application, including requiring the usage of a "base period" for a combined test year or future test year. A base period serves as a historical reference and point of comparison for any forecasts, projections, or estimates a utility has provided for its anticipated future performance when applying for a base rate change. The adopted rules also include minor and conforming changes to the rule text.

Post-test year report (combined test year and future test year)

For utilities that select a future test year or a combined test year, the adopted rules require such utilities to file a post-test year report with the commission. A post-test year report requires a utility to verify and compare the utility's projected test year data against the utility's actual results.

Retrospective analysis (combined test year and future test year)

The adopted rules also require a utility that selects a combined test year or future test year to file a "retrospective analysis" for the commission to review the utility's projected test year report in the utility's next comprehensive base rate proceeding. The commission will review the utility's retrospective analysis to determine whether a refund is necessary based on an overall comparison of the utility's projected year data and the utility's actual results. The commission may also determine in the retrospective analysis whether a utility's projections for revenues and costs reasonably aligned with the utility's actual results accounting for any mitigating factors presented by the utility; and identify any rate base items that were not used and useful in providing service to customers.

Construction Work In Progress (CWIP)

HB 2712 requires CWIP projected to be placed into service through the end of a combined test year or future test year to be included in rate base, notwithstanding the higher burden of proof generally applied to CWIP for a utility that enters a historic test year.

Statutory refund (combined test year and future test year)

The adopted rules further require the commission to order a utility to issue a refund to customers through a regulatory liability if the utility's combined or future test year information used resulted in the utility's rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public. Specifically, the refund will be any money in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected.

Changes to commission-prescribed forms

The commission also adopts conforming changes to the Class A Utility Annual Report for a utility that elects to use a combined test year or a future test year such that a utility that selects a combined test year or future test year must indicate any differences (i.e., variance) between the amounts approved in the utility's last comprehensive base rate proceeding and the utility's actual results as they become available. The commission also adopts revisions to the Class A, B, C, and D Water and Sewer Annual Report General Instructions (Annual Report General Instructions) to conform with recent electronic filing changes.

The commission received comments on the proposed rule from Aqua Texas, Inc. (Aqua); the City of Houston; CSWR-Texas Utility Operating Company, LLC (CSWR); the Office of Public Utility Counsel (OPUC); SJWTX, Inc. d/b/a The Texas Water Company (SJWTX); and the Texas Association of Water Companies, Inc. (TAWC).

General Comments

CSWR emphasized that the adopted rules implementing HB 2712 should promote consolidation and rehabilitation of ailing water and wastewater utilities, including those in rural areas. Specifically, CSWR noted that the acquisition of such ailing systems requires significant initial capital investment to ensure the necessary repairs are made to benefit customers. CSWR also expressed general support for TAWC's comments.

Commission response

A primary policy rationale for the implementation of a combined test year or future test year for utility ratemaking is to promote consolidation and rehabilitation of ailing utilities. Specifically, the usage of future projections and estimates, which may include utility acquisitions that affect cost of service, instead of historical data implicitly reflects this consideration. In addition, adopted language in §24.28 explicitly contemplates acquisitions and consolidations as an example of an event that occurred during the test year that a utility must describe and quantify if it impacted the utility's actual test year results.

SJWTX and Aqua recommended the adopted rule implement a future test year process that is not unduly burdensome and does not create "negative incentives" or other unintended consequences. Specifically, SJWTX recommended the inclusion of specific mechanisms to ensure that (1) neither customers nor utilities are harmed or unjustly enriched; (2) forecasted and actual results are appropriately accounted for; and (3) completed capital investments are reflected in rates. SJWTX also recommended that the adopted rules do not include language that would result in retroactive ratemaking. SJTWX commented that, if prudently implemented, a future test year enables utilities to make essential upgrades to infrastructure while reducing the lag associated with cost recovery in accordance with the legislative intent of HB 2712. Similarly, Aqua recommended that the proposed rule should be revised to enhance regulatory certainty, reduce unnecessary administrative burdens, and effectuate the legislative intent of HB 2712. Specifically, the new legislation was intended to (1) provide flexibility for utilities in selecting a test year; (2) more accurately align a utility's rates with its actual costs of service; (3) promote infrastructure investment; and (4) decrease the frequency of rate cases and reduce the costs of such proceedings that are passed through to ratepayers.

Commission response

The adopted rule strikes the appropriate balance between regulatory certainty, utility flexibility, efficiency of rate proceedings, promotion of infrastructure investment, and ratepayer protections. Specific issues, such as the accounting of Construction Work In Progress (CWIP) and the retrospective analysis for a combined test year or future test year, are addressed under the appropriate header.

Questions for Comment

The proposal for publication included two questions for comments with two subparts each.

Question 1 (Revisions to commission-prescribed forms to implement HB 2712)

In addition to the proposed revisions to the Class A Annual Report Form and the Annual Report General Instructions in this rulemaking, the commission is contemplating a later rulemaking to update other commission-prescribed forms to accommodate utilities that select a combined test year and a future test year.

Question 1a (Specific water utility forms for comment and review)

The commission has identified the following commission-prescribed forms as potentially requiring changes. While the commission offers no edits to these forms and does not intend to change the forms in this rulemaking project, the commission requests comment from stakeholders to identify any necessary changes. Specifically, the commission requests redline edits or comments recommending changes to the following forms (15 total):

i. Class B-D Water Sewer Annual Report;

ii. CCN Form

iii. STM and Expedited STM Form

iv. Class A-C Utility Notice of Proposed Rate Change;

v. Class B- D Rate/Tariff Change Application/Instructions/Notice (Schedule).

Aqua recommended that the commission update the Rate Filing Packages (RFPs) and associated Instructions as well as the Annual Reports used by each of the Class A, B, C, and D utilities. TAWC commented that there are no additional forms that require revision beyond those listed under Question 1a. TAWC recommended that any adopted version of the forms be updated to reflect the latest version of Chapter 24 of the commission's substantive rules and include optionality for applicants to incorporate their specific test year selection (i.e., historic, combined, or future) with any corresponding information.

Commission response

The commission will open one or more subsequent rulemaking projects to address conforming revisions to the relevant commission-prescribed forms listed under Question 1a to accommodate a utility's test year selection, beginning with the Class A RFP.

OPUC's proposed forms (New Schedule 1A and Schedule 1B)

OPUC recommended that, in lieu of revising the forms listed under Question 1a, that the commission should instead adopt the Schedule 1A and Schedule 1B forms in the present rulemaking or in a later rulemaking. OPUC explained that its recommended schedules consolidate the combined test year and future test year into a single set of templates without requiring existing form revisions. Specifically, the new Schedules are intended to supplement the commission's existing forms and instructions for water and sewer rate cases. OPUC noted that its proposed forms "capture the forecast support, base-period bridge, materiality screen, post-test-year reconciliation, and refund computation in a single set of templates" for all classes of water and sewer utilities. OPUC commented that adopting its proposed Schedules avoid disruptive, simultaneous edits to several commission forms and instead provide a standardized presentation in a single form. OPUC emphasized that its proposed form would help facilitate more efficient review by the commission and promote intervenor participation and consumer protection without unduly burdening utilities. OPUC indicated that standardized forms are particularly important for combined test years and future test years, which use future data. Specifically, standardization ensures that data is presented consistently and can be meaningfully compared which in turn reduces discovery disputes, reduces costs, and benefits customers by promoting transparency and enforceability in the post-test year retrospective analysis. OPUC stated that Schedule 1A standardizes the presentation of "forecast assumptions, billing determinant forecasts, and material changes" while Schedule 1B standardize the disclosures required by Texas Water Code §13.185 and the retrospective analysis required by the proposed rule by establishing a defined set of reconciliation schedules. OPUC noted that the data required by Schedule 1B are intended "to assist in the retrospective analysis in determining whether the utility's forecast led to overcollection of rates, and if any refund should be issued to ratepayers" while maintaining base-rate case determinations, requiring true-up only for specific defined items, and producing a single refund for or credit for the covered period. OPUC commented that its schedules can be used by any class of water or sewer utility and only apply when a utility selects a combined test year or future test year.

Commission response

The commission declines to implement the new forms proposed by OPUC as they are out of scope. Specifically, other stakeholders have not had a reasonable opportunity to comment in accordance with Texas Government Code § 2001.029(a). OPUC's proposed Schedule 1A and 1B will be considered prior to publishing any revisions to commission-prescribed forms in a follow-on rulemaking. In the event a utility initiates a rate proceeding and selects a combined test year or future test year during the period between the adoption of the rules included in this rulemaking and the adoption of any conforming amendments or new commission-prescribed forms, the revisions to the Class A Utility Annual Report and the requirements of new §24.28 will be sufficient to address any discrepancies on an interim basis.

OPUC's proposed changes to the Class A Utility Annual Report

OPUC recommended that the Class A Utility Annual Report form be revised to incorporate the additional information recommended or referenced in its filed comments. Generally, OPUC recommended the Class A Utility Annual Report to be changed to include: (1) the refund determination required by Texas Water Code § 13.184(d); (2) the calculated variance between the utility's actual forecasted costs and revenues versus the authorized projected amounts; (3) identification of plant (i.e., CWIP) that was forecasted to be placed into service that did not materialized; and (4) identification of amounts collected under a SIC versus base rates to prevent double recovery. OPUC also recommended that the cover page or Schedule I of the Class A Utility Annual Report be revised to require disclosure of the utility's test year election. OPUC further recommended the addition of a column flagging the percent material change in specific schedules in the Class A Utility Annual Report if its proposed materiality screen is adopted. OPUC provided draft language for the Class A Utility Annual Report consistent with its recommendation.

Commission response

Variance columns

The commission agrees with OPUC regarding its proposed edits to the Class A Utility Annual Report adding variance columns in the relevant worksheets. Specifically, the commission adds an additional column in the worksheets of the Class A Utility Annual Report recommended by OPUC to account for the variance between the utility's projected test year data and the utility's reporting period results. The new columns specifically require the disclosure of the differences expressed as a numerical amount in dollars and as a percentage. The commission also adds variance columns to Schedule 615 for affiliated transactions and deletes the variance columns from Schedule 206 because they are unnecessary for long-term debt.

Test Year Disclosures

The commission also agrees with OPUC that the Class A Annual Report should require disclosure of the utility's selected test year. The commission accordingly adds several line items on Schedule I which require identification of: (1) the utility's selected test year; (2) the date the applicant's test year began and ended; and (3) the year the applicant's last comprehensive base rate proceeding was initiated and the associated docket control number or project number; and (4) the date the commission final order was issued in the last comprehensive base rate proceeding. The commission also adds requirements for a utility that selected a combined test year or future test year to disclose the project number where its post-test year report is filed. Lastly, the commission adds disclosure requirements for utilities that selected a combined test year to disclose the date range of the historic portion and future portion of the combined test year, including the number of calendar months in each portion.

Refund Information

The commission also revises Worksheet "200-4 Current Liabilities & Credits" of the Class A Utility Annual Report by adding new line item 22 which refers to NARUC Account 254 "Other Regulatory Liabilities" to account for any statutory refund ordered by the commission in accordance with Texas Water Code §13.184(d) and renumbering all subsequent rows. The commission declines to implement OPUC's more substantial revisions regarding the statutory refund in the Class A Utility Annual Report. Such changes are unnecessary because the refund is a general determination of whether the "test year information used for the utility resulted in the utility's rates yielding more than a fair return." If that condition is present, the commission will require the utility to "refund to customers money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected." (emphasis added) Therefore, the statutory refund applies to the utility's overall rate of return (i.e., excessive earnings above the utility's last commission-approved rate of return), not to specific line items (CWIP, operations and maintenance expense, etc.) Additional discussion of the statutory refund is provided under the appropriate header.

CWIP and SIC Information

The commission declines to implement OPUC's other proposed changes concerning specific identification of CWIP or amounts collected under a System Improvement Charge (SIC) because they are unnecessary. The statutorily required treatment of CWIP under Texas Water Code § 13.185(b) or (k) does not necessitate separate line-item treatment in the Class A Utility Annual Report. A utility that selects a combined test year or future test year is required to disclose in its post-test year report under §24.28 whether CWIP projected to be in service was actually placed into service during the test year. Additionally, the fact that CWIP may not have been placed into service may not be sufficient to trigger a refund under §13.184(d). Stated differently, when considering all billing determinants or cost of service components that a utility has projected it is not necessarily true that projected CWIP that is not placed into service will trigger a refund on its own. Regarding OPUC's proposed SIC addition, overlap between a future test year or combined test year is already prohibited under §24.76(c)(1)(E), relating to System Improvement Charge. Specifically, the provision establishes that, after September 1, 2026, a SIC application by such utilities is limited to cost recovery of eligible plant placed into service subsequent to the end of the future test year or combined test year. Therefore, OPUC's CWIP and SIC proposed additions to the Class A Utility Annual Report are unnecessary. Additional discussion on CWIP and SIC related changes can be found under the appropriate header.

Other Changes

The commission revises the proposed text added in various worksheets to state "[a]mounts authorized by the commission in last comprehensive base bate proceeding" for clarity. This phrasing is clearer than the proposed language requiring "amounts authorized for recovery" as some worksheets do not concern recoverable amounts. The commission also adds a footnote to the worksheets with the added variance columns indicating that "[t]o the extent that a specific line item was not specified in the commission final order or settlement for its comprehensive base rate proceeding, the utility may enter N/A in the applicable cells." The commission also revises the terminology used in the variance columns where appropriate (e.g., "gallons" instead of "dollars" in Schedule 403, Gallons sold). The commission also adds formulas for the new column cells identifying the percentage difference.

Question 1b (Revisions to other commission-prescribed forms not included in proposal)

If there are other forms that require amendment that are not listed above, identify the additional form and any necessary changes in the same manner as requested in Question 1a.

Commission response

No commenters responded to Question 1b other than OPUC. OPUC's proposed Schedule 1A and Schedule 1B are discussed in the appropriate header above.

Question 2 (Statutory framework of post-test year report)

Texas Water Code §13.185(l) and (m) require a "post test-year report" for a utility that elects to use a "fully projected future test year." In the proposed draft of §24.28, the commission has extended the requirement to perform a test year report to a utility that has elected to use a "combined test year." This is due to the requirement in §13.184(d), which applies to "a utility that uses a future or combined historic and future test year." Specifically, §13.184(d) requires the commission to determine in the next rate proceeding for that utility, whether the test year information resulted in rates yielding a fair return and, if so, "require the utility to refund to customers money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected."

Question 2a (Extension of post-test year report requirement to utilities that select a combined test year)

Should the commission extend the post-test year report requirement to a utility that enters a combined test year? Please include the rationale for a response to this question.

City of Houston, OPUC, and TAWC responded in favor of extending the post-test year report requirement to combined test year utilities. Aqua responded against the proposal and CSWR did not specify whether it supported or disfavored the reporting requirement for a combined test year. City of Houston agreed that the commission obligation to determine whether a utility's rates yielded a fair return or otherwise require a refund to customers applies regardless of whether a combined or future test year is used. City of Houston explained that any test year that includes a future period should be subject to the same reporting requirements and that different reporting requirements are only appropriate if the use of a combined test year reduces the risk that a utility over-recovers relative to a future test year. City of Houston noted, however, that a combined test year with a larger future period (e.g., 11 future months and one historical month) "could have the same potential for over-recovery and need for refund as a fully projected year." City of Houston further remarked that equal reporting requirements for combined and future test years removes the perverse incentive for a utility to select a combined test year to avoid regulatory reporting and favor more aggressive cost forecasting methods as a result. CSWR commented that no additional forms should be required "beyond those listed" in the proposed rule. Aqua opposed applying the post-test year reporting requirement to a utility that selects a combined test year. Aqua maintained that any reporting associated with the results of a combined test year should occur in the utility's next base rate case where the commission reviews the utility's rates. OPUC recommended that the proposed language requiring utilities that select a combined test year to file a post-test year report to be preserved as it is consistent with legislative intent. OPUC noted that Texas Water Code §13.184(d) requires the commission to determine, in the utility's next base rate proceeding, whether combined or future test year information previously used by the utility resulted in rates yielding a fair return or otherwise require a refund of any over-collection. OPUC explained that the post-test year report is the primary mechanism for effectuating the statutory language and omitting the requirement for combined test years would impede any commission determination as to whether a refund is necessary. OPUC stated that not requiring a post-test year report for a combined test year would result in gamesmanship, which could harm residential and small commercial consumers. TAWC commented that it is reasonable to extend the post-test year report for utilities that select a combined test year. TAWC alternatively proposed that, because a post-test year report is not specifically required for a combined test year by Texas Water Code §13.185(l)-(m), the commission could perform the review in the utility's next comprehensive base rate proceeding by requiring the same information as the post-test year report.

Commission response

The commission agrees with City of Houston, OPUC, and TAWC and preserves the proposed language extending the post-test year reporting requirement to a utility that selects a combined test year. Requiring a post-test year report for utilities that utilize a combined test year is consistent with HB 2712's directive to safeguard consumers from the uncertainty associated with the use of forecasted costs in ratemaking.

Question 2b (Alternative methods to reconcile a combined test year forecasted costs and revenues)

Are there alternative methods to ensure forecasted costs and revenues for a combined test year are properly accounted for to facilitate reconciliation in a later base rate proceeding?

SJWTX recommended five alternative mechanisms to account for and reconcile forecasted costs and revenues associated with future data used in a combined test year or future test year. Specifically, SJWTX recommended (1) a sales reconciliation mechanism (SRM); (2) expense offsets; (3) memorandum accounts; (4) balanci Ang accounts; (5) interim rates; and (6) rate base offsets. SJWTX explained that a SRM "addresses revenue fluctuations caused by drought, conservation, and fluctuating demand" by mitigating the inherent uncertainty associated with accurately forecasting water availability and usage. SJWTX indicated that it has observed water usage fluctuations of up to 10% due to drought in the south central regions of Texas. SJWTX explained that an SRM monitors the difference between the approved level of water sales against actual sales and therefore protects both customers and utilities against any extreme discrepancies. SJWTX noted that an SRM would be used for the time period between the end of one future test year and the beginning of the next future test year. If there is a variance of more than five percent, the SRM would automatically adjust rates to recover or refund half of the total variation. SJWTX commented that expense offsets pass through to customers any increases or decreases in certain costs that are beyond a utility's control and for which cost recovery by the utility is in the public interest. SJWTX noted that expense offsets are similar in nature to "energy cost adjustment clauses" but even more important in the context of rates based on forecasted amounts. In practice, a water utility would use a reserve account to track the difference between approved costs and actual costs for certain categories of expenses. Any over-collection or under-collection would then be subject to cost recovery or refund. Accordingly, the usage of expense offsets could potentially "eliminate separate minor tariff change proceedings to true-up and change purchased water pass-through rates because the test year amount for purchased water would be included in base rates with actual costs booked to a reserve account for future recovery or refund." SJWTX recommended that the commission adopt rules to allow expenses offsets such as purchase power costs or otherwise add language to proposed §24.26(l) since such costs are subject to fluctuations beyond the control of a utility. SJWTX commented that memorandum accounts are accounting tools similar to regulatory assets that enable a utility to record various historical costs it incurs for later recovery without engaging in retroactive ratemaking. Specifically, once the commission authorizes the use of a memorandum account, the utility would then track the costs recorded in the account for future recovery either through a compliance filing or in a future base rate proceeding. SJWTX emphasized that commission authorization to use a memorandum account does not guarantee cost recovery and that a utility would still be required to demonstrate through evidence the prudence, reasonableness, and necessity of incurred costs. SJWTX explained that a memorandum account is appropriate for expenses or capital projects costs that cannot be accurately forecasted in a base rate case but are expected to be incurred prior to the next base rate proceeding and are of such a significant amount to justify the cost and effort of maintaining and reviewing the account. SJWTX proposed that costs entered into a memorandum account be required to meet specific criteria, such as (1) the cost must be due to exceptional circumstances outside the utility's control; (2) the expense is not reasonably foreseeable as of the utility's last base rate proceeding and will occur before the utility's next scheduled rate case; (3) the cost is substantial or otherwise significant; and (4) ratepayers will benefit from usage of the memorandum account. SJWTX recommended that utilities be authorized to implement interim rates based on inflation if the commission is not able to issue a decision in time for new rates to become effective on the first day of the test year. SJWTX further recommended that the commission authorize utilities to track the difference between interim rates and the rates ultimately approved by the commission in a memorandum account for future recovery or refund. SJWTX stated that under Texas Water Code §13.187, a commission decision in a base rate proceeding must be rendered on or before the 185th day after a Class A utility files a statement of intent to change rates. SJWTX further commented that in base rate proceedings, rates must be effective as of the first day of the test year. SJWTX noted, however, that in some instances it can take more than 18 months for a final order to be issued, despite the statutory requirements. SJWTX remarked that the additional requirement for a retrospective analysis under §24.28(c)(2) for a utility that selects a combined test year or future test year would further extend the duration of a base rate proceeding.. SJWTX concluded that the statutory and rule requirements risk that the 18-month period between the filing of a statement of intent to change rates and the test year provides insufficient time for a final order approving new rates to be issued in a base rate proceeding. SJWTX commented that a balancing account would track costs that the commission has authorized for amortization. Specifically, when the commission approves a cost recorded in a reserve account or memorandum account for recovery, the utility would move that balance to a balancing account where it would be amortized through surcharges or credits on customer bills over a time period determined by the commission. SJWTX recommended that the adopted rules include a provision authorizing a utility to make a compliance filing for a rate base offset to become effective at the end of a test year. SJWTX further recommended a process be implemented to "ensure that there is not a lag in the recovery of capital investments" for the interim years between the end of the previous test year and the beginning of the next test year. SJWTX remarked that this could involve annual rate base offset filings or changes to the SIC rulemaking to account for future test years. SJWTX commented that the usage of rate base offsets enable a utility to adjust rates to account for changes in utility plants in service that affect rate base. SJWTX explained that rate base offsets would include adjustments to related expenses, such as depreciation and taxes, and to specific charges that depend on gross revenues, such as franchise taxes and "uncollectibles." SJWTX explained that a compliance filing is appropriate because the underlying costs and investments associated with the rate base offset were reviewed as part of the previous base rate proceeding.

Commission response

The commission declines to implement the alternative proposals suggested by SJWTX because they are variously unnecessary, impractical, and detrimental to ratepayers. Moreover, it is not immediately apparent that any of the alternative reconciliation mechanisms would be more effective or more clearly in the public interest than the proposed retrospective analysis framework. The commission currently does not authorize the use of a sales reconciliation mechanism, memorandum account, or balancing account for rate setting purposes in base or interim rate proceedings. The various mechanisms, if implemented, would seemingly authorize the pass-through of certain costs, revenue shortfalls, or other rate impact without commission review and approval or additional notice to ratepayers, which is required by the current pass-through minor tariff change application process under §24.25(b)(2) and §24.25(b)(2)(F), respectively. It is also not clear how such mechanisms would be available for review by the commission or otherwise visible to the public. As such, most of the proposed alternatives present risks to customers or are otherwise contrary to the public interest. For example, a sales reconciliation mechanism would shift revenue risk from the utility to captive ratepayers. Similarly, a memorandum account or balancing account would shift cost risk from the utility to captive ratepayers. Expense offsets would allow the direct pass-through of operating costs to customers between major rate cases and rate base offsets strongly resemble a SIC proceeding. The addition of interim rates as an alternative mechanism is unnecessary because commission rules already account for interim rates under §24.37, relating to Interim Rates. Specifically, §24.37(a) authorizes the commission to establish interim rates that will remain effective until a final decision is made in a base rate proceeding as authorized by Texas Water Code § 13.187(l) and §13.1871(s).

Aqua recommended that any data that is necessary to reconcile forecasted costs and revenues should be included as part of a utility's filing package for a base rate proceeding to avoid unnecessary and duplicative reporting obligations.

Commission response

The commission generally agrees with Aqua that the data necessary to reconcile a utility's projected test year information with its actual test year results should be specified in the associated commission-prescribed RFP for each utility class, or the associated RFP instructions. Any revisions to commission-prescribed forms to facilitate the implementation of a combined test year and future test year will be undertaken in a future rulemaking.

OPUC recommended the addition of an explicit CWIP category be added for the retrospective analysis under §24.28 and the creation of a limited, standalone expedited reconciliation proceeding for commission review of a utility's post-test year report to determine whether the utility is over-earning and if a refund is necessary.

Commission response

The commission declines to specifically highlight CWIP as a category for review for a retrospective analysis under §24.28. As stated previously, CWIP is one of several cost components that the commission will review in a retrospective analysis and base rate proceeding. Therefore, it is unnecessary for the commission to singularly emphasize CWIP for analysis. Any determination as to whether projected CWIP was actually placed into service during the test year will be reviewed as part of the retrospective analysis. The commission also declines to establish a standalone proceeding for a retrospective analysis because it is more administratively efficient to review a utility's actual test year results contemporaneously with its next base rate proceeding, both for statutory refund and rate setting purposes. CWIP and the retrospective analysis are discussed more substantively under the relevant headings.

City of Houston and CSWR stated that alternative methodologies for reconciliation of a combined test year are unnecessary. City of Houston commented that the rate information entered into the record of a base rate proceeding for a utility with a future or combined test year should be generally sufficient to determine in a subsequent rate proceeding whether the utility over-earned. City of Houston noted that alternative cost tracking methods, such as balancing costs, are typically only established if it is necessary to reconcile and recover certain specific costs. City of Houston indicated that the commission is obligated to determine whether the approved rates yielded a fair return or were excessive, which is a broader question. Accordingly, City of Houston recommended the commission utilize a comparative reporting approach to determine whether a utility that uses a future or combined test year has over-earned, assuming that there are no changes to the underlying accounting structure or methodologies used for recording the applicant utility's costs and revenues. City of Houston remarked that if a utility seeking a rate change believes that circumstances that are not directly related to the earned return should be considered by the commission, the utility can present evidence supporting such an argument in its comprehensive base rate proceeding. City of Houston emphasized that the commission should ensure that any rate case settlement contains sufficient information, including disaggregated account information, such that the commission can make a determination as to whether the utility has over-earned. CSWR noted that it has not identified any alternative methods for reconciling the forecasted costs and revenues for a combined test year in a later comprehensive base rate proceeding.

Commission response

The commission agrees with City of Houston and CSWR and declines to implement any alternative methodologies for reconciliation of forecasted costs and revenues for the reasons already stated.

Proposed §24.3 and proposed §24.3(17) - Definitions; Definition of "future test year"

Proposed §24.3 defines the terms used universally across Chapter 24. Proposed §24.3(17) defines the term "future test year" as a test year that includes only future data.

SJWTX recommended the commission expand the definition of "future test year" to also include reference to "historical data," rather than just "future data." Specifically, SJWTX recommended the definition be revised to "a test year that includes future data and forecasts, which may incorporate historical data." SJWTX noted that in many instances, a future test year is informed or based on historical data, such as historical expense averages which may be used to forecast future test year amounts. SJWTX indicated the revision would also more closely align the definition with §24.26(b). SJWTX provided draft language consistent with its recommendation.

Commission response

The commission agrees with SJWTX but revises the definition of "future test year" to mean "a test year that includes future data and forecasts, estimates, or projections, although such future data, forecasts, estimates, or projections may be derived in part from historical data."

Proposed §24.3(10) - Definition of "combined test year"

Proposed §24.3(10) defines the term "combined test year" as a test year that includes historic and future data.

The commission revises the definition of "combined test year" to refer to "a test year that includes historical data and future data" for clarity.

Proposed §24.3(40) - Definition of "historic test year"

Proposed §24.3(40) defines the term "historic test year" as a test year that includes only historic data.

TAWC recommended changing references to a "historic test year" be replaced with the term "historical test year" throughout the proposed rules as the latter is the grammatically correct term.

Commission response

The commission declines to implement the recommended change because the term "historic test year" is used by HB 2712, specifically Texas Water Code § 13.1831 and is a term of art. However, the commission revises all references of "historic data" to "historical data." The commission also makes minor revisions to the definition do indicate when a test must begin and end as well as minor grammatical revisions.

Proposed §24.25 - Form and Filing of Tariffs

New §24.25(b)(2)(A)(x) - Minor tariff changes; Refund or other commission action at conclusion of retrospective analysis for combined test year or future test year

OPUC recommended §24.25(b)(2)(A) be revised to include a commission-authorized refund or credit resulting from a retrospective analysis under §24.28 as a minor tariff change. OPUC explained that this revision would ensure the commission has flexibility in ensuring that a utility complies with the refund obligation without having to wait until the utility's next comprehensive base or otherwise requiring the utility to make a separate tariff filing at the commission's direction that would require full notice and review. OPUC further noted that allowing such a refund to be considered a minor tariff change would also ensure that customers are credited more quickly. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement OPUC's proposal because the statutory refund is not a minor tariff change and the addition is unnecessary. Texas Water Code §13.184(d) conditions a refund on a commission determination of whether the test year information used by a utility that selected a combined test year or future test year "resulted in the utility's rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public." If the commission determines the utility's rates did yield more than a fair return, the statute requires the commission to order the utility to "refund to customers money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected." Accordingly, any order for a refund requires an express determination by the commission and does not align with the list of minor changes under §24.25(b)(2). Moreover, the retrospective analysis where the refund determination is made will occur in the utility's next base rate proceeding. Therefore, any necessary tariff changes to account for the refund will be made in that proceeding.

Proposed §24.26 - Test Year

Proposed §24.26 establishes the procedures to facilitate a utility's selection of a test year. The section also establishes the tariff and application requirements for a utility's test year selection.

SJWTX recommended that §24.26 be revised to include language that explicitly authorizes interim rates because base rates must be effective on the first day of a future test year.

Commission response

The commission declines to implement the recommended change because it is unnecessary. As stated previously, under §24.37 commission staff or a utility can request that the commission authorize interim rates during the pendency of a comprehensive base rate proceeding until a final order is issued.

Proposed §24.26(b) and proposed §24.26(b)(1) - Definitions; Definition of "base period"

Proposed §24.26(b) includes defined terms within the section. Proposed §24.26(b)(1) defines the term "base period" as a consecutive 12 calendar month period that ends on or before the date the applicant files its statement of intent to change rates. A base period must include historical data and begin no earlier than five years before the date the statement of intent to change rates was filed.

OPUC recommended revising the definition of "base period" under §24.26(b)(1) to refer to the average of a consecutive 36-month period rather than a consecutive 12 calendar month period in the last five years. OPUC stated that a 36-month period is preferable as it provides a "sufficient historical context to validate forecast inputs and to mitigate the cherry-picking risk inherent in a 12-month window." OPUC noted that there may be substantive differences in costs and revenues within a five-year period, whereas the average of 36 calendar months creates a more normalized representation of test year operations, similar to the standard regulatory practice of normalizing billing determinants when establishing rates. OPUC emphasized that a 36-month average does not replace the 12-month test year concept. Instead, it "produces a more representative 12-month average from which the test-year revenue requirement is built." OPUC provided draft language consistent with its recommendation.

Commission response

The commission agrees with OPUC and changes the applicable timeframe for a base period from 12 months to 36 months but authorizes a shorter base period to be used for good cause shown. Additionally, the commission revises the definition to require a base period to begin on the first day of a calendar or fiscal year quarter to align with Texas Water Code § 13.1831(2). The base period should have the same timing requirements of a test year to ensure data aligns, but it is not necessary to limit it to the 18 months prior to the base rate case proceeding to ensure additional flexibility in a utility's selection of a base period. Specifically, the commission revises the general definition of the term "base period" as follows: "the most recent consecutive 36 month period beginning on the first day of a calendar- or fiscal-year quarter for which operating data for a retail public utility is available. A base period must include historical data. The commission may, for good cause shown, authorize a shorter base period for a utility that has operated for less than 36 months."

Proposed §24.26(b)(3) - Definition of "historical data"

Proposed §24.26(b)(3) defines the term "historical data" as data relied upon by the utility to support its actually incurred costs, usage, revenues, adjustments, and other information of the utility. Historical data may include, as one component, the utility's annual reports filed in accordance with §24.129 of this title (relating to Water and Sewer Utility Annual Reports).

OPUC recommended that the definition of "historical data" in proposed §24.26(b)(3) be revised to include specific additional accounting documentation and support to ensure compliance with Texas Water Code §13.184(d). OPUC specifically recommended the definition be revised to include "(i) tie-outs to audited or closed financial records; (ii) explanation of any normalizations or adjustments; (iii) a workpaper index; and (iv) an officer attestation specific to the base period." OPUC provided draft language consistent with its recommendation. OPUC stated that the definition should be revised to include information sufficient for the commission to determine whether a utility's proposed rates under a combined test year or propose test year would yield a fair return. OPUC noted that such a determination requires the commission to compare the utility's actual costs and revenues with its forecasted amounts and therefore necessitates the utility to provide representative data that is auditable and connected to specific records. OPUC maintained that such information is necessary to ensure that the retrospective analysis involves verifiable information, rather than cost summaries that cannot be tested.

Commission response

The commission declines to implement the recommended change because it is unnecessary and overly prescriptive. The recommended revisions would result in detailed requirements that are unnecessary for describing what constitutes historical data. OPUC's proposed changes are more suitable for the Class A RFP Instructions and other commission-prescribed ratemaking forms for water and sewer service. The commission will revise these forms in a future rulemaking to conform with the new and amended rules.

Proposed §24.26(c) and proposed §24.26(c)(1) - General requirements for tariffs; requirements applicable to new utilities.

Proposed §24.26(c) establishes the general requirements for tariffs when a utility designates a test year. Proposed §24.26 (c)(1) establishes the specific requirements applicable to new utilities that have obtained an approved tariff for the first time.

Aqua and TAWC recommended proposed §24.26(c)(1) be revised to explicitly specify that the provision only applies to utilities obtaining an approved tariff for the first time and not to existing utilities that receive a previously approved tariff for acquired systems through a Certificate of Convenience and Necessity (CCN) or Sale Transfer Merger (STM) proceeding. Aqua explained that approval of the tariff for an acquired system could be interpreted as a "new" tariff for the acquiring utility and therefore subject to the test year requirements under proposed §24.26(c)(1)(A) which require the filing of a rate change application within 30 months from the date service begins. Aqua noted such a revision would provide regulatory clarity and adhere to the legislative intent of HB 2712 in reducing the frequency of rate cases and associated expenses. Aqua noted implementation would effectuate Texas Water Code §13.3011 and §24.240, relating to Water and Sewer Utility Rates After Acquisition. Aqua provided draft language consistent with its recommendation.

Commission response

The commission agrees with Aqua and TAWC and implements Aqua's language with the condition "unless otherwise required by the commission." In some cases, an acquisition or merger may be so large or affect such a significant number of customers that a rate case should be required.

Proposed §24.26(c)(2); proposed §24.26(c)(2)(A) and new §24.26(c)(2)(C) - Utility designation of test year; compliance with definition; one test year limitation

Proposed §24.26(c)(2) establishes the requirements for a utility's designation of a test year. Proposed §24.26(c)(2)(A) requires a utility to present a test year that complies with the definition under §24.3(36). Proposed §24.26(c)(2)(B) requires the test year to include future data and identify a base period if the test year selected by the utility is a combined test year or a future test year.

The commission corrects the definitional cross-reference to §24.3 generally, rather than a specific definition. The commission also adds new §24.26(c)(2)(C) which provides that "[a] utility is limited to using one test year in a comprehensive base rate proceeding." This is to ensure a utility does not select a different type of test year for each type of service. (e.g., a historic test year for sewer service but a future test year for water). This addition is consistent with Texas Water Code §13.1831 which provides that the commission "shall fix rates for water and sewer services for a Class A, B, C, or D utility based on a test year the utility selects…" (emphasis added). The conjunctive "and" and the singular "test year" indicates the selection of only one test year is contemplated under the statute. The commission also makes clarifying revisions to proposed §24.26(c)(2)(B) to require the rate change application to identify a base period.

Proposed §24.26(c)(3) and proposed §24.26(c)(3)(A) - Application requirements; known and measurable changes

Proposed §24.26(c)(3) requires a utility to provide evidence in its rate change application that its proposed rates are just and reasonable using its selected test year, including providing all information in support of its selected test year used to establish rates. The provision further specifies the minimum required information. Proposed §24.26(c)(3)(A) requires a utility to include known and measurable changes in its rate case application. Such known and measurable changes must, at a minimum, include explicit and direct connections between the applicant's test year information and the applicant's audited financial accounts, billing system extracts, or other records such as the utility's annual report under §24.129 of this title.

TAWC recommended that language requiring "[a] utility [to] provide evidence in its rate change application that its proposed rates are just and reasonable using its selected test year" be preserved but omit the phrase "including providing all information in support of its selected test year used to establish rates." TAWC indicated that the latter phrase could be interpreted as suggesting that a utility's test year selection could be second-guessed. TAWC noted that Texas Water Code §13.1831 does not authorize the commission to countermand a utility's choice of test year.

Commission response

The commission disagrees with TAWC and declines to omit the language specified by TAWC. A utility may select a test year in accordance with Texas Water Code §13.1831, but that does not abrogate a utility's general burden of proof to show that rates are just and reasonable rates under Texas Water Code §13.184(c). Commission staff should therefore retain the discretion to review a utility's test year information which is not the same as reviewing the utility's test year selection. For example, if a utility selects a future test year and grossly over-projects its estimated costs without any supporting documentation, commission staff should be able to issue a recommendation stating that the test year data is not representative and request the utility provide additional justification or revision of the provided information. This would not alter the utility's selection of a future test year itself. However, the commission deletes the phrase "providing all" from the provision as all information supporting a utility's selected test year may not be necessary for the utility to meet its burden of proof. If additional information is necessary, commission staff can request it from the utility.

TAWC and CSWR recommended proposed §24.26(c)(3)(A) be revised to remove the requirement to "include explicit and direct connections between the applicant's test year information and the applicant's audited financial accounts, billing system extracts, or other records such as the utility's annual report under §24.129 of this title." TAWC and CSWR indicated that the proposed language is unnecessary and ambiguous. TAWC and CSWR explained that what may constitute explicit and direct connections is subjective and would likely cause disputes over sufficiency. TAWC alternatively recommended the provision be revised with the following language: "which must be demonstrated using the applicant's test year information, audited financial accounts, billing system extracts, or other records such as the utility's annual report under §24.129 of this title." Similarly, CSWR alternatively requested clarity on how the language will be applied if it is preserved.

Commission response

The commission agrees with TAWC and CSWR and implements TAWC's alternative language. Any additional clarifications regarding known and measurable changes will be undertaken in a future rulemaking revising the commission-prescribed ratemaking forms for retail water and sewer service.

Proposed §24.26(c)(3)(B); proposed §24.26(c)(3)(B)(i)-(iii); proposed §24.26(c)(3)(C); and proposed §24.26(c)(3)(C)(i) and (ii) - Information supporting test year selection; additional requirements for combined test year or future test year selection (inflation data and forecasts, estimates, and projections)

Proposed §24.26(c)(3)(B) requires a utility to include supporting documentation, testimony, or other relevant information for all provided data in its rate case application. Proposed §24.26(c)(3)(B)(i)-(iii) respectively require such information to at least consist of data that substantiates all costs, revenues adjustments, offsets, normalizations, and other changes; an identification and explanation of any adjustment, offset, or normalization that includes the quantity and percentage of the change; and evidence that all adjustments, offsets, or normalizations for costs, revenues or other changes that would affect rates have been properly accounted for. Proposed §24.26(c)(3)(C) specifies additional application requirements specific to a utility that selects a combined test year or future test year. Proposed §24.26(c)(3)(C)(i) and its sub-clauses requires a utility to provide documentation or testimony supporting inflation-related forecasts, projections and estimates that is categorized by and proportional to an inflation index published by the United States Department of Labor, Bureau of Labor Statistics for the portion of the combined test year that immediately follows the utility filing its statements of intent to change rates or the future test year. Proposed §24.26(c)(3)(C)(ii) and its sub-clauses requires a utility to provide documentation or explanation supporting the reasonableness of any forecasts, projections or estimates sufficient to substantiate the methodology or calculations associated with each forecast, projection, or estimate for the portion of the combined test year that immediately follows the utility filing its statements of intent to change rates or the future test year.

OPUC recommended that proposed §24.26(c)(3)(B) and (C) be revised to require both testimony and supporting documentation, rather than just testimony by itself. OPUC noted that the usage of the conjunction "or" suggests that a utility is authorized to provide testimony alone without any supporting documentation. OPUC explained that doing so is inconsistent with the commission's historical practice of requiring additional documentation that supports whether a utility's proposed rates are just and reasonable. OPUC additionally noted that a retrospective analysis performed in accordance with Texas Water Code §13.184(d) cannot occur without such documentation, which is inconsistent with HB 2712. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement OPUC's recommendation for §24.26(c)(3)(B) because it is unnecessary. However, the commission agrees with OPUC regarding changes to §24.26(c)(3)(C). Specifically, the commission omits §24.26(c)(3)(B)(i)-(iii) as that information is more appropriate for inclusion in a commission-prescribed form. The commission accordingly revises §24.26(c)(3)(B) to state "supporting documentation, testimony, or other relevant information that supports the utility's selected test year and requested amounts" rendering OPUC's added language redundant. The commission also makes conforming and clarifying revisions to §24.26(c)(3)(C) to omit the cross-reference to §24.26(c)(3)(B) as it is unnecessary. Specifically, the provision is revised to state: "if the utility selects a combined test year or a future test year, documentation, testimony or other information supporting the following." The commission also omits §24.26(c)(3)(C)(i)(I) and (II) and §24.26(c)(3)(C)(ii)(I) and (II) and revises §24.26(c)(3)(C)(i) and (ii) to instead refer only to "any portion of a test year with future data" for clarity.

Proposed §24.26(c)(3)(E) - Attestation by executive officer

Proposed §24.26(c)(3)(E) requires a utility to include an attestation in its rate case application by an executive officer or owner of the utility that all information provided under subparagraphs (A)-(E) are true, accurate, and complete.

TAWC recommended a technical revision to subparagraphs (A)-(E) in because the internal cross-reference is misnumbered.

Commission response

The commission implements the recommended change.

New §24.26(c)(3)(F)

OPUC recommended proposed §24.26(c)(3) be revised to implement a two-part "materiality screen" similar to that proposed in the discussion draft for the forecast period to highlight any significant impacts of a utility's actual costs on customer bills and utility earnings. Specifically, OPUC recommended that the materiality screen "consolidate the percent and bill-impact functions into a single percent-of-revenue-requirement screen paired with a per-line-item percent screen. OPUC further recommended that the percent screen be accompanied by a customer class-dollar screen at thresholds deemed appropriate by the commission. Under OPUC's proposal, utilities would be required to provide a list of all forecasted changes by cost category that identify: (1) the corresponding "base value, forecast value, and absolute variance" for each listed category; (2) the percentage and dollar variance; and (3) a flag for each category considered material. OPUC noted that its proposal provides a manageable standard for commission review that protects customers at a lower cost of compliance for utilities. OPUC emphasized that a materiality screen promotes more efficient review by focusing commission and intervenor attention on forecasted cost items that affect customer rates the most. OPUC noted that its proposal would also highlight discrepancies between a utility's forecasted costs and actual costs, particularly if the retrospective analysis is merged into a base rate case rather than made into a limited, standalone proceeding. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement a materiality threshold or screen because it is unnecessary. A materiality threshold would be highly dependent on the applicant utility's financial health, the economy as a whole, and other circumstances. Moreover, there is a high likelihood that the information included in a utility's rate case application would be subject to substantial discovery. Commission staff will, as part of its review of a base rate application, identify any cost items or discrepancies that require further review and request additional information from the utility. Therefore, prematurely flagging certain items as "material changes" is redundant and only has the potential to increase rate case expenses.

Proposed §24.26(d), proposed §24.26(d)(1) - Base rate application requirements for historic test year

Proposed §24.26(d) specifies the requirements for a base rate change application and requires compliance with form and content requirements included in the commission-prescribed forms and instructions applicable to the utility's class. Proposed §24.26(d)(1) requires a utility's base rate change application to comply with the requirements of §24.26(d)(1)(A) or (B) based on its selection of test year in addition to the requirements of §§24.26 and 24.27.

Proposed §24.26(d)(1)(A); proposed §24.26(d)(1)(A)(ii); proposed §24.26(d)(1)(A)(ii)(I)-(III); proposed §24.26(d)(1)(B); and proposed §24.26(d)(1)(B)(ii) - Historic test year content requirements; Combined test year or future test year content requirements

Proposed §24.26(d)(1)(A) requires a historic test year base rate change application to include comparative revenue and cost information across certain time periods. Proposed §24.26(d)(1)(B)(ii) and §24.26(d)(1)(B)(ii)(I)-(III) require, as specified and applicable in the commission-prescribed forms and instructions applicable to the utility's class, comparisons between the calendar years immediately preceding the date the historic test year was entered; the current year-to-date; and if available, the calendar year immediately subsequent to the date the historic test year ended. Proposed §24.26(d)(1)(B) requires a combined test year or future test year base rate change application to include comparative revenue and cost information across certain time periods. Proposed §24.26(d)(1)(B)(ii) requires information on, and comparisons of, revenues and costs in the combined test year or future test year, as applicable.

Aqua recommended proposed §24.26(d)(1)(A)(ii)(I) be revised to reference a single calendar year that precedes the historic test year to ensure filing requirements are accurate. Aqua provided draft language consistent with its recommendation. TAWC recommended deleting proposed §24.26(d)(1)(A)(ii)(I)-(III) as the provisions are unnecessary and ambiguous. TAWC indicated that the plain language of the Class A Rate Filing Package Instructions are sufficient without additional rule language. TAWC maintained that any specific requirements should be established in the Instructions and any Class A Rate Filing Package that the commission develops.

Commission response

The commission agrees with TAWC and deletes proposed §24.26(d)(1)(A)(ii)(I)-(III), rendering Aqua's proposed revision moot. The commission will clarify the time-specific parameters for comparison of costs and revenues applicable to each type of test year in a future rulemaking amending the relevant commission-prescribed forms. The commission therefore revises §24.26(d)(1)(A)(ii) to state "the time periods specified by the commission-prescribed forms and instructions applicable to utility's class." The commission also mirrors §24.26(d)(1)(A)(ii) under §24.26(d)(1)(B) as new §24.26(d)(1)(B)(ii), which is identical. The commission renumbers §24.26(d)(1)(B)(iii) and revises it to state "as applicable, the combined test year or the future test year, inclusive of any forecasts, projections, or estimates" for clarity.

Proposed §24.26(e) - Review of combined test year or future test year

Proposed §24.26(e) specifies that a combined test year or a future test year will be reviewed by the commission in accordance with §24.28 of this title.

As an alternative to adopting one of the cost recovery mechanisms SJWTX proposed in its response to Question 2b, SJWTX recommended that proposed §24.26(e) be revised to authorize a utility to implement cost recovery mechanisms that permit the tracking of forecasted and actual costs and enable rates to be adjusted through credits and surcharges to minimize the difference between the two. SJWTX explained that such an authorization promotes customer fairness, reduces lag in cost recovery of infrastructure investment, and prevents retroactive ratemaking. SJWTX emphasized that retroactive ratemaking would occur if the commission "authorizes or requires a utility to adjust current rates to make up for past errors in projections." SJWTX further emphasized that this revision is not proposed in response to Question 2b, but instead is recommended as a "a comprehensive approach to future test year ratemaking that results in just and reasonable rates for both utilities and the customers they serve." SJWTX provided draft language consistent with its recommendation.

Commission response

The commission declines to independently authorize the usage of alternative cost tracking or reconciliation mechanisms for the reasons previously stated under the heading for Question 2b. Moreover, under new §24.28(f)(2)(A), a refund will be tracked as a regulatory liability, rendering alternative tracking mechanisms unnecessary. In response to SJWTX's claim regarding retroactive ratemaking, the statutory refund is authorized by Texas Water Code §13.184(d). More substantive discussion of the refund and regulatory liability can be found under the appropriate headings.

Proposed §24.27 - Notice of Intent and Application to Change Rates

Proposed §24.27(b), proposed §24.27(b)(1), and proposed §24.27(b)(1)(E) - Contents of the application

Proposed §24.27(b) and (b)(1) identify the specific content requirements for a base rate change application. §24.27(b)(1)(E) requires a base rate change application to include the applicable information required under §24.26 for applicants that select a future or combined test year.

TAWC recommended the deletion of the portion of proposed §24.27(b)(1)(E) that limits the subsection's applicable only to applicants that select a future or combined test year. TAWC explained that the deletion would render the provision applicable to a utility that selects any of the three types of test year and is therefore more accurate under the proposed rule structure.

Commission response

The commission agrees with TAWC and implements the recommended change.

Proposed §24.28 - Review of Test Year

Proposed §24.28(a) - Applicability

Proposed §24.28(a) establishes that the subsection applies to a utility that elects to use a combined test year or a future test year under §24.26.

For clarity, the commission revises the provision to state that the section applies to a to a utility that elects to use a combined test year or a future test year under §24.26 and whose application was processed to a final decision and approval of a tariff by the commission

Proposed §24.28(b) - Post-test year report

Proposed §24.28(b) requires a utility that selects a combined test year or future test year to file a post-test year report with the commission. §24.28(b) also applies to the successor in interest of a utility that selects a combined or future test year. The provision further requires the post-test year report to be filed in a compliance docket opened contemporaneously with the utility's comprehensive base rate case.

Aqua and TAWC recommended that the post-test year report be limited only to the single filing required by Texas Water Code §13.185(l) rather than the three different instances required by proposed §24.28(b) which are needlessly duplicative. Aqua alternatively recommended that the desired effect could be reached if the additional filings are replaced with a requirement for the commission to reference the post-test year report filing compliance docket number in its annual report and as part of its rate filing package. Aqua explained that requiring multiple filings is unnecessary, costly, and increases administrative burdens. Aqua noted that Texas Water Code §13.185(l) only requires the filing of the post-test year report at the close of the test year, while the proposed rule also requires it to be filed in a separate compliance docket contemporaneous with the utility's comprehensive base rate proceeding and with the utility's annual report. TAWC specifically recommended that the post-test year report should be limited to filing in a single rate case docket. Alternatively, TAWC recommended that if the commission preserves the requirement to file the post-test year report in a compliance docket, the "contemporaneous base case" should be clarified to be the one where a combined or future test year is used, not the base rate case where the actual results of a combined test year or future test year are reviewed.

Commission response

The commission implements the recommended change. Specifically, the commission revises new §24.28(c)(1)(A) to state "[t]he information required under subparagraph (2)(A) of this subsection must be included as an attachment to or incorporated by reference into the utility's next annual report required by §24.129 of this title." This is reflected in Schedule I of the Class A Utility Annual Report where a utility must enter the project number where it has filed the post-test year report, as applicable. The entry further specifies that "[t]he utility may also file a copy of the post-test year report with this annual report." Similarly, new §24.28(d)(2)(A) only requires the usage of the information provided in the utility's post-test year report, rather than requiring the inclusion of the post-test year report itself. In response to TAWC's comment regarding the compliance docket and the "contemporaneous base rate case," the presiding officer has discretion in opening the compliance docket for the post-test year report. Stated differently, the compliance docket for the post-test year report does not necessarily have to be associated with the prior base rate proceeding where the utility set its rates using a combined test year or future test year. New §24.28(c) therefore omits the "contemporaneous rate proceeding" language and is revised to state "[t]he information required under this subsection must be filed in the commission-assigned compliance docket opened for that purpose." The commission also makes clarifying changes to new §24.28(c) to indicate that the provision applies to a "utility that selected a combined test year or future test year and whose application was processed to a final decision and approval of a tariff by the commission or its successor in interest"

Proposed §24.28(b)(2) and proposed §24.28(b)(2)(A)-(C) - Post-test year report filing and content requirements

Proposed §24.28(b)(2) requires a utility to file a post-test year report no later than the 30th day after the last day of the last quarter of a combined test year or a future test year. Proposed §24.28(b)(2)(A) requires the utility to file a written statement that describes the utility's actual cost and revenue results experienced in the future test year being reported and provides appropriate data to demonstrate the accuracy of the estimates used for the test year. Proposed §24.28(b)(2)(B) requires the utility to serve a copy of the written statement on the parties of record in the rate proceeding in which the final rate determination using the combined test year or the future test year was entered. Proposed §24.28(b)(2)(C) requires the utility to file proof of notice in the form of an affidavit that states notice was properly delivered in accordance with §24.28(b)(2)(B)

SJWTX recommended proposed §24.26(b)(2) be revised to extend the due date for the post-test year report to be no later than the 90th day after the last day of the last quarter of the combined or future test year.

Commission response

The commission declines to implement the recommended change because it is contrary to statute. Specifically, Texas Water Code §13.185(l) requires the post test year report to be filed "not later than the 30th day after the last day of the last quarter of the test year." Moreover, the proposed revision is unnecessary because Texas Water Code §13.185(m)(3) authorizes a utility that does not have the necessary results or data before the filing date to file the post-test year report "as soon as possible" when such results or data become available.

OPUC generally recommended consolidating definitions for §24.28 into a single subsection in a future rulemaking. OPUC also recommended proposed §24.28(b)(2)(A) be revised to define the terms "actual cost and revenue results" and "appropriate data" for the post-test year report because they are ambiguous. Specifically, OPUC recommended the term "actual cost and revenue results" to refer to "results means cost and revenue figures derived from the utility's general ledger, billing system extracts, and audited or closed financial records for each calendar month of the combined test year or future test year, presented in a format that mirrors the line-item presentation of the utility's rate filing package and identifies any normalization, annualization, or other adjustment applied to the figures. with the dollar amount and direction of each adjustment." Similarly, OPUC recommended "appropriate data" to refer to "data sufficient to enable the commission to determine whether the actual cost and revenue results for the combined test year or future test year align with the estimates used in the rate proceeding that established the rates being reviewed, including: "tie-outs to general-ledger trial balances and billing-system reports for the test year period identification of any project, asset, or expense category that was forecast to occur during the test year but did not occur or that occurred at a materially different magnitude than forecast and an explanation of any divergence between forecast and actual results that exceeds the materiality thresholds applied in the original rate proceeding under §24.26(c)(3)(F)." OPUC commented that the commission has an opportunity to establish clear standards and expectations for combined test years and future test years that protect ratepayers from potential malfeasance. OPUC explained one of the more straightforward means to do so is by providing clear definitions to terms that may be prone to misinterpretation and costly disputes. OPUC provided draft language consistent with its recommendation.

Commission response

The commission agrees with OPUC and adds new subsection (b) which defines the terms "actual test year results," "fair return," and "projected test year data." Revised subsection (b) also makes conforming revisions throughout the section to use the new terms where appropriate or necessary. The commission also renumbers all following subsections. Additionally, commission restructures proposed §24.28(b)(2)(A) for clarity. Specifically, the commission merges proposed §24.28(b)(2)(A)(i) into new §24.28(c)(2)(A) and changes proposed §24.28(b)(2)(A)(ii) to new §24.28(c)(2)(B) and renumbers all subsequent provisions. New §24.28(c)(2)(A) omits the term "future" to ensure the post-test year reporting obligation applies to a utility that selects either a combined test year or a future test year. Specifically, the provision requires the utility to "file a written statement that describes the utility's actual cost and revenue results experienced in the test year being reported." New §24.28(c)(2)(B) requires the utility to "provide appropriate data to demonstrate the accuracy of the projected test year data against the utility's actual results, including any necessary comparative analyses, testimony, workpapers, or other supporting documentation." The commission declines to define "appropriate data" as the general concept of the term are captured by "actual test year results," "projected test year data," and new §24.28(b)(2)(B). Moreover, the addition of variance columns to the Class A Annual Report form will also ensure a utility that is obligated to file the post-test year report adequately captures any differences between its projections and actual results. The term "actual test year results" is defined as "for a utility that selected a combined test year or future test year in its most recent base rate proceeding, the utility's actual costs and revenues incurred during the test year." The term "fair return" is defined as "the utility's overall rate of return established by the commission in the utility's most recently completed base rate proceeding." The term "projected test year data" is defined as "any combined test year or future test year information used to establish a utility's rates in the utility's most recently completed base rate proceeding." The definition also includes specific information that must be provided at a minimum, which includes capital projects inclusive of CWIP established by the utility to be used and useful through the end of the test year in accordance with §24.41; allocation and rate design information, including billing determinants; rate base information and underlying methodologies used for forecasted amounts such as accumulated deferred income taxes and accumulated depreciation); and expense information such operations and maintenance expense, depreciation, taxes including federal income tax. The commission also revises new §24.28(c)(2)(A)(i) to omit the term "future" to ensure the post-test year reporting obligation applies to a utility that selects either a combined test year or a future test year. Specifically, the provision requires the utility to file a written statement that "describes the utility's actual cost and revenue results experienced in the test year being reported." The commission also revises new §24.28(c)(2)(A)(ii) to require the utility's written statement to "include appropriate data to demonstrate the accuracy of the projected test year data against the utility's actual results, including any necessary comparative analyses, testimony, workpapers, or other supporting documentation." The commission declines to define "appropriate data" as the general concept of the term is captured by "actual test year results," "projected test year data," and revised §24.28(c)(2)(A)(i) and (ii). Moreover, the addition of variance columns to the Class A Annual Report form will also ensure a utility that is obligated to file the post-test year report adequately captures any differences between its projections and actual results.

OPUC provided alternative definitions for "actual costs and revenue results" and "appropriate data" if the commission elects to revise the Annual Report or other utility forms rather than the rule language. Specifically, OPUC alternatively recommended defining "actual costs and revenue results" as "cost and revenue figures derived from the utility's general ledger, billing system extracts, and audited or closed financial records for the test year period, identifying any normalization or adjustment applied to the figures" and "appropriate data" as "data sufficient to enable the commission to determine whether the actual cost and revenue results align with the estimates used in the rate proceeding that established the rates being reviewed, including tie-outs to source records and explanation of any divergence that exceeds the materiality thresholds applied in the original rate proceeding under §24.26(c)(3)(F)."

Commission response

The commission declines to implement the recommended change because it is moot. The terms "actual test year results," "projected test year data," and revisions to new §24.28(c)(2)(A)(i) and (ii) substantively address OPUC's concern.

CSWR and TAWC recommended that proposed §24.28(b)(2)(B) be revised to indicate that the post-test year report is only required to be provided to the parties of record at the conclusion of the utility's base rate proceeding, rather than be provided to entities that were parties of record at any time during the proceeding. CSWR and TAWC noted that in many instances, intervenors are dismissed for failure to participate or otherwise request to withdraw. Therefore, utilities should only be required to provide the report to entities that are parties at the closure of the base rate case. TAWC commented that interested persons that were not parties by the end of the base rate proceeding could locate a copy of the report on the commission Interchange after it is filed.

Commission response

The commission agrees with CSWR and TAWC and implements the recommended change by revising §24.28(c)(2)(B) to require the utility to serve the post-test year report on persons who were parties at the conclusion of the rate proceeding.

SJWTX recommended that proposed §24.28(b)(2)(C) be deleted because it is unnecessary and varies from standard service procedures. SJWTX explained that if the post-test year report is filed in a compliance docket for a base rate case, then the utility should be authorized to include "include a certificate of service stating that a copy of the report was served on all parties of record in the rate proceeding corresponding to the compliance docket."

Commission response

The commission revises new §24.28(c)(2)(C) to authorize either a certificate of service or a proof of notice affidavit and corrects the cross-reference to subparagraph (B).

Proposed §24.28(b)(3); proposed §24.28(b)(3)(A); and proposed §24.28(b)(3)(B) - Projected test year data; Delayed filing of post-test year report

Proposed §24.28(b)(3) and proposed §24.28(b)(3)(A) require a utility or its successor in interest that does not have the results or data required to file the post-test year report by date under §24.28(b)(1) to file a written notice with the commission that states the date on which the results or data will be available; provides a list of the results or data that are unavailable; and a brief explanation of why the results or data are unavailable. Proposed §24.28(b)(3)(B) requires a late post-test year report to be filed as soon as possible after the results or data are available, but no later than the 60th day after the last day of the last quarter of the combined test year or the future test year.

SJWTX recommended that the 60-day report deadline in §24.26(b)(3)(B) be revised to 120 days. Similarly, TAWC recommended that the 60-day deadline in proposed §24.28(b)(3)(B) be removed or otherwise be made to conform with Texas Water Code §13.185(m), which includes no deadline. SJWTX commented that its proposed changes appropriately balance between regulatory compliance and ensuring sufficient time is afforded to utilities "to prepare the most accurate and complete information possible." SJWTX noted, by way of example, that a future test year for January 1, 2028 to December 31, 2028 would require the post-test year to be filed on or before January 30, 2029, which is an insufficient time period for it to close its books for the prior year. SJWTX noted that the proposed requirement is impracticable for SJWTX to enable its parent company to comply with federal Securities and Exchange Commission requirements, which requires a 10-K filing 60 days from the end of the calendar year. SJWTX further commented that its proposed revisions are reasonable given that the post-test year report is only reviewed in the utility's next comprehensive base rate proceeding as part of the retrospective analysis and is consistent with the timelines in other jurisdictions that authorize a future test year. TAWC noted that Texas Water Code §13.185(m) only requires a utility to notify the commission when its results or data will be available if they are not available to file within the 30-day deadline established by Texas Water Code §13.185(l). TAWC remarked that the statute does not include a good cause exception to vary from this timeline.

Commission response

The commission extends the 60-day filing deadline under new §24.28(c)(3)(B) to 90 days for a late post-test year report. If a utility still does not have the required data by that time, it may request a good cause exception. In response to TAWC's contention regarding variance from the prescribed statutory timeline, Texas Water Code §13.185(m) does not prohibit the commission from imposing a timeline for filing a post-test year report. The commission also corrects the cross reference to paragraph (2) in §24.28(c)(3) and makes minor clarifying revisions to §24.28(c)(3)(A)(iii).

Proposed §24.28(c) and proposed §24.28(c)(1) - Commission review of forecasts or projections; accounting of actual costs and revenues

Proposed §24.28(c) establishes that the commission will review the actual costs and revenues incurred during the portion of the combined test year that immediately follows the utility filing its statement of intent to change rates or, as applicable, the future test year in the manner in accordance with the sub-provisions of the subsection. Proposed §24.28(c)(1) establishes the accounting of actual costs and revenues for the commission's review of a retrospective analysis under proposed §24.28(c)(2).

SJWTX requested clarification as to how proposed §24.28(c)(1) is incorporated into the commission's review of a utility's actual costs and revenues incurred during a future test year. SJWTX commented that if the standards prescribed by proposed §24.28(c)(1) are intended to be applied during the commission's review of a utility's retrospective analysis under proposed §24.48(c)(2), it is ambiguous because such standards are not specifically included in the latter provision.

Commission response

The commission confirms that the standards prescribed by proposed §24.28(c)(1) were intended to be applied in the commission's review of the utility's retrospective analysis under proposed §24.48(c)(2). The commission substantially revises proposed §24.28(c) and transfers specific requirements to new §24.28(d) and (f) and to §24.28(e). New §24.28(d) prescribes the utility's obligations regarding, and content requirements for, the retrospective analysis; revised §24.28(e) addresses the commission's review of the retrospective analysis, and §24.28(f) establishes the form and manner of the refund if one is ordered. The revisions are substantively addressed under the appropriate headings.

Proposed §24.28(c)(1)(A) and proposed §24.28(c)(1)(B) - Inclusion of CWIP and costs attributable to extraordinary circumstances

Proposed §24.28(c)(1)(A) provides that only capital projects that the utility reasonably projects to be used and useful in the combined test year or the future test year, as applicable, may be included in rate base unless otherwise authorized by the commission for inclusion as CWIP under §24.41.

Proposed §24.28(c)(1)(B) establishes that costs attributable to extraordinary circumstances within the portion of the combined test year that immediately follows the utility filing its statement of intent to change rates or the future test year, as applicable, may be included in rate base through an adjustment after a showing of good cause by a utility and an evidentiary finding by the commission. The provision further defines "extraordinary circumstances" as events affecting service to critical customers; natural disasters such as droughts, floods, hurricanes, tornadoes, winter storms; or other system emergencies that result in conditions on the utility's utility system that are likely to result in imminent, significant disruption of service to customers or is imminently likely to endanger life or property.

TAWC recommended the commission delete or otherwise clarify the phrase "may be included in rate base" in proposed §24.28(c)(1)(A) and (B) as it is ambiguous and unnecessary. TAWC explained that rate base will be determined in the base rate case prior to the one where costs and revenues for a combined or future test year will be reviewed, whereas total rate base will be reviewed de novo "even while past returns are analyzed for fairness." TAWC also recommended the term "extraordinary circumstances" be replaced with the term "unplanned circumstances" in proposed §24.28(c)(1)(B) if the commission intends to allow rate base additions after the test year to ensure the fairness of the utility's return.

Commission response

The comprehensive restructuring of §24.28 addresses TAWC's concern. Specifically, the language "may be included in rate base" in the context of capital projects under proposed §24.28(c)(1)(A) has been omitted. New §24.28(d) references capital projects and CWIP entirely through the new defined term "projected test year data." Specifically, new §24.28(d)(1) establishes the general requirements for a utility's retrospective analysis. New §24.28(d)(1)(A) requires a utility to file a retrospective analysis in its next base rate proceeding and new §24.28(d)(1)(B) requires a utility's actual test year results to be presented in a manner consistent and comparable with its projected test year data. New §24.28(d)(2) prescribes the required contents of a retrospective analysis as established under new §24.28(d)(2)(A)-(D). New §24.28(d)(2)(A) requires a retrospective analysis to include a full accounting of the utility's projected test year data presented in its immediately previous base rate case in comparison to its actual test year results using the information provided in the utility's post-test year report required under §24.28(c). New §24.28(d)(2)(B) requires a retrospective analysis to include information on the utility's actual rate of return earned during the test year that allows the commission to determine whether the utility's actual test year results yielded a fair return on its invested capital used and useful in rendering service to the public. New §24.28(d)(2)(C) requires a retrospective analysis to include to the docket number of the compliance docket in which the utility filed its post-test year report. New §24.28(d)(2)(D) requires a retrospective analysis to include a description and quantification of events that occurred during the test year that impacted the utility's actual test year results, which may include events affecting service to critical customers.

Aqua recommended proposed §24.28(c)(1)(A) be revised to clarify how extraordinary costs or costs related to critical customers would be incorporated into a pending base rate proceeding. Specifically, Aqua recommended the provision be revised to permit a utility to supplement or update its statement of intent for its base rate case within 45 days of the occurrence of the event giving rise to the expense. Aqua further recommended the provision be revised to authorize the creation of a regulatory asset to defer extraordinary or critical customer-related costs for future recovery. Aqua explained that deferred accounting treatment is appropriate for such costs because "in many instances, the full scope and magnitude of costs associated with natural disasters or other extraordinary events cannot reasonably be determined within the limited period between the occurrence of the event and the filing of a recovery request." Additionally, authorizing cost deferral in these instances would empower the utility to prioritize operational activities to restore continuous and adequate service to customers without delaying a pending rate proceeding, particularly if an extraordinary event is of such severity that it warrants a hearing during or after the base rate case.

Commission response

The commission declines to implement the recommended changes because they are unnecessary and out of scope. A utility may seek good cause to amend its base rate case application; specific rule language is not necessary. Concerning Aqua's recommendation regarding the creation of a regulatory asset for extraordinary costs, HB 2712 does not require deferred accounting treatment or the creation of such an asset. Therefore, this recommendation is out of scope.

Proposed §24.28(c)(2 - Retrospective analysis of combined test year or future test year

Proposed §24.28(c)(2) requires a utility to file a retrospective analysis in its next comprehensive base rate proceeding filed with the commission.

Aqua, TAWC, CSWR, and SJWTX recommended that proposed §24.28(c)(2) be revised to adopt a "range of reasonableness to evaluate the return earned by the utility" before a refund is required to be issued to customers. Aqua and TAWC noted that this approach has been successfully used in gas interim rate adjustments under Texas Utility Code §104.301(g), which uses a 75-basis point (i.e., .75%) variance above approved rates as a threshold for presumptive reasonableness. If the threshold is triggered, the utility must file a statement indicating the reasons why the rates are not unreasonable or otherwise in violation of the law. In contrast, a return that falls within the range of reasonableness would not be considered in excess of a fair return and would therefore not require a refund. Aqua commented that while the provision is consistent with the statute, it does not establish clear boundaries for commission review during the retrospective analysis. Aqua explained that given the forward-looking nature of future data, it is unrealistic to expect absolute accuracy in predicting costs and revenues year over year. Aqua noted that such an approach reduces litigation and rate case expenses by not considering normal or immaterial variations in financial performance as indicative of unjust or unreasonable rates. Instead, this approach addresses material differences between forecasted costs and revenues and actual results. TAWC explained that the threshold for whether a refund is required should not be limited only to whether the utility's revenues exceeded the return approved in the previous comprehensive base rate case as is suggested by proposed §24.28(c)(2)(B)(ii) and (v). Instead, there should be a range of reasonableness where a utility's return is not considered excessive given the impracticability associated with providing perfect forecasts of actual results. CSWR recommended that proposed §24.28(c)(2) be removed because it would constitute retroactive ratemaking. CSWR opposed proposed §24.28(c)(2) on the basis that refunds to customers should not be triggered if the utility's revenues exceed the rate of return approved by the commission in its prior rate proceeding. CSWR noted that utilities are incentivized to maximize efficiency to ensure there is a "reasonable opportunity to earn a reasonable return on their capital investment in excess of their approved cost of service." As such, it is impossible to determine whether previously approved rates allow for more than a fair rate of return because a utility's "earned rate of return depends on factors that cannot be determined at the time rates are approved," such as evaluating how cost-effective a utility operated its system or other factors such as customer growth. CSWR further remarked that a utility's earned return is also dependent on its capital budget management and whether the utility was "able to avoid making large capital improvements or repairs." CSWR also noted that the provision does not provide a means to surcharge customers if a utility earns less than what it projects. CSWR maintained that requiring refunds of a previously approved rate of return and cost of service "simply because the Company operated its system more efficiently or experienced higher than expected customer growth would constitute retroactive ratemaking." Alternatively, if a refund mechanism is adopted, CSWR recommended that the calculation of what a return constitutes should be clarified and implement a 1% "range of reasonableness" threshold to trigger the retrospective analysis or refund obligation. CSWR therefore recommended replacing the term "fair rate of return" with the term "reasonable return" as the latter is commonly used in the commission's rules whereas the former is not. CSWR further commented that the commission should acknowledge that what constitutes a reasonable or fair return is variable as it depends on external factors such as financial markets and interest rates. Accordingly, what is a reasonable rate of return in one test year could be different several years later. CSWR urged that any commission evaluation of a utility over-earning should be based on "current factors affecting a utility's revenue requirement and through retroactive review of the factors used to set current rates." CSWR noted that the proposed rule does not include such a method for determining what is a reasonable or fair return for the period for which a utility's projected costs are subject to a commission retrospective analysis. Therefore, the rule should include a minimum 1% range of reasonableness for what constitutes a fair return before any retrospective analysis or refund is triggered. SJWTX recommended that rate refunds or adjustments resulting from a retrospective analysis under proposed §24.28(c)(2) be limited to circumstances where there is one percent or greater variation between the utilities' commission-approved overall rate of return and the return resulting from actual costs and revenues. SJWTX explained that this change would ensure utilities are properly incentivized to operate efficiently while still protecting customers. SJWTX alternatively recommended that, if the commission has concerns about the rule being overly prescriptive, the provision be revised to state that such a one percent or greater variation would be considered a "rebuttable presumption" that the utility's return is excessive.

Commission response

The commission declines to implement a "range of reasonableness" for triggering the statutory refund because it is contrary to the statute and not in the public interest. Any range of reasonableness proposal risks conflict with the statutory mandate to refund amounts in excess of a fair return. Specifically, Texas Water Code §13.184(d) neither authorizes discretion in the commission's determination as to whether a refund is required nor the method for deriving the refund. The statute provides that "the regulatory authority shall require the utility to refund to customers money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected" (emphasis added) based on a commission determination in the utility's next rate proceeding that "the test year information used for the utility resulted in the utility's rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public." (emphasis added) As such, the intent of the statute appears to disincentivize utilities that select a combined test year or future test year from over-projecting costs. In response to CSWR's specific comments as to what constitutes a "fair return," new §24.28(b)(2) defines the term as "the utility's overall rate of return established by the commission in the utility's most recent comprehensive base rate proceeding." Therefore, any rate of return exceeding the utility's approved rate of return would trigger the refund and there is no inquiry as to external events that may have affected rates, even if reasonable. To do otherwise would effectively necessitate a comprehensive base rate case on what test year information would have yielded a fair return which could be inefficient and of little benefit depending on the circumstances. The discretionary commission review under new §24.28(e)(1)(B), if undertaken, will account for such mitigating factors (e.g., reasonable alternatives, system emergencies, etc.). However, commission action in response to that portion of a retrospective analysis is discretionary under new §24.28(e)(3)(B), which states that the commission will "perform any other action necessary to ensure just and reasonable rates at the conclusion of a retrospective analysis or the contemporaneous base rate proceeding, as determined by the presiding officer." (emphasis added) This could entail multi-step rates; adjustments to a utility's calculations or methodologies used for its forecasts, projections or estimates; or other actions the presiding officer deems necessary.

The commission also acknowledges the utilities' contentions regarding the impracticability of perfectly accurate forecasts and the inherent variability as to what constitutes a reasonable return year-over-year, but that is not the inquiry Texas Water Code §13.184(d) requires. It is also not apparent that a range of reasonableness would reduce rate case expenses instead of merely shifting litigation to the issue of whether the range was exceeded, rather than whether the utility's test year information resulted in rates yielding more than a fair return. In response to Aqua and TAWC's comments concerning Texas Utilities Code §104.301(g), that provision is not an appropriate comparison. That statute only requires gas utilities to file a statement with the Railroad Commission indicating the reasons why its rates are not unreasonable or in violation of law if its return on invested capital exceeds 75 basis points; not whether a refund is necessary. Moreover, if the legislature intended an earnings band or range of reasonableness to be added to the refund determination, it would have done so. In response to CSWR's specific contentions regarding retroactive ratemaking, the commission's implementation of the refund adheres closely to the statutory language--hence, the use of "fair return" in lieu of other, more commonly used terminology such as "reasonable return." The commission also disagrees with CSWR that a surcharge should be required if the commission earns less than its approved rate of return. As CSWR indicated, a utility is provided the reasonable opportunity to earn a reasonable return. The utility's commission-approved rate of return is therefore not a guaranteed rate of return and does not necessitate a surcharge if the utility does not receive exactly that amount.

OPUC recommended that a retrospective analysis should be a standalone and expedited proceeding that is limited in scope rather than be incorporated into the utility's next base rate proceeding. OPUC explained that having a standalone proceeding ensures that the retrospective analysis occurs on a defined and expedited schedule immediately after the combined test year or future test year ends, rather than being delayed for potentially years until the utility's next base rate case. Additionally, a standalone proceeding limits the scope of discovery and any potential hearing solely to the question of whether the utility's rates yielded a fair return and potential reconciliation. OPUC noted that this avoids any procedural issues or other complications that could arise if reconciliation is joined with forward-looking rate setting. OPUC further commented that it provides a separate means for the commission to order refunds if appropriate "with a clear evidentiary record specific to the reconciliation question." OPUC maintained that a standalone proceeding for a retrospective analysis would not be a "second rate case" that adds procedural and administrative costs. Instead, it would be a narrowly tailored expedited proceeding that is limited to reconciliation where assumptions from the utility's comprehensive base rate proceeding (i.e., rate design, cost allocations, etc.) are maintained. OPUC also indicated that the proceeding would not be automatic and only be initiated if the post-test year statement demonstrates that the utility's forecasts are inaccurate. OPUC commented that it is likely that most utilities will continue to use a historic test year, so the number of standalone reconciliation proceedings would be relatively small. OPUC further commented that any procedural costs associated with a standalone retrospective analysis proceeding would be "materially less than the cost of intermingling reconciliation with forward-looking rate setting in the next comprehensive [base rate] case."

Commission response

The commission declines to establish the retrospective analysis as a standalone proceeding because it is unnecessary, has a high likelihood of introducing additional complexity and costs, and would strain commission resources. The primary purpose of the retrospective analysis under the revised framework detailed below is to determine whether the commission will order the utility to issue a refund. Specifically, Texas Water Code §13.184(d) states: "For a utility that uses a future or combined historic and future test year in a rate proceeding, if the regulatory authority determines in the next rate proceeding for that utility that the test year information used for the utility resulted in the utility's rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public, the regulatory authority shall require the utility to refund to customers money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected." (emphasis added) The refund determination is therefore straightforward under the revised framework of §24.28. Under new §24.28(b)(2), the term "fair return" is defined as "the utility's overall rate of return established by the commission in the utility's most recent comprehensive base rate proceeding." Accordingly, any return that exceeds the utility's rate of return established in the prior rate proceeding where the utility selected a future test year would be subject to refund. For example, if a future test year utility is determined to have made a 10% rate of return but was only authorized to make a 9% rate of return- that utility would be obligated to refund amounts collected that represent the 1% overage. There is no statutory requirement for an individual review of a utility's individual billing determinants, costs, and revenues in a retrospective analysis. However, the revised framework authorizes this more in-depth review if the commission determines it to be necessary. The scope and extent of any additional review will be further informed by discovery and the feedback of intervenors. In response to OPUC's specific claims and contentions, it is not necessarily true that a utility will go years without a retrospective analysis. Commission staff routinely monitor all utility earnings included in their annual reports and can request the commission to order a utility to initiate a base rate case if it determines the utility is over-earning. This applies to both electric utilities and water and sewer utilities. See, e.g., Project 50655, Item #73 (commission order) and Project 54453, Item #265 (commission staff recommendation).

The commission also disagrees that a standalone proceeding would not introduce further complexity and increase administrative costs. It is not clear how a standalone proceeding would reduce costs relative to incorporating it into a base rate proceeding as there is a high probability of extensive discovery on any in-depth review of a utility's actual test year results undertaken in a retrospective analysis. Intensive discovery is more appropriate for a base rate proceeding where all data on the utility's past rates and applied-for rates will be available. Additionally, combining the retrospective analysis into the utility's base rate proceeding promotes administrative efficiency and reduces administrative costs. Specifically, any outcomes of the discretionary portion of the retrospective analysis could potentially be incorporated into the base rate case, such as revisions to a utility's models or calculations for forecasts, projections, and estimates. Regarding OPUC's contention over a "clear evidentiary record" for a retrospective analysis, it is not apparent what this would entail. Any retrospective analysis would be conducted separately from the rate-setting portion of the base rate proceeding unless the presiding officer determines otherwise. This flexibility is necessary to ensure the commission's obligation to order a refund under Texas Water Code §13.184(d) is met.

The commission also disagrees that a retrospective analysis would "not be automatic." The commission will always have to review a utility's post-test year report to determine if it is over-earning, even if the utility claims it is not. Revised §24.28(e) substantively addresses OPUC's concerns that revised provision establishes that "the commission will review a utility's retrospective analysis described under subsection (d) exclusively in the docket assigned to the utility's base rate case and in the manner described by this subsection." New §24.28(e)(1) prescribes the scope of the commission's review of a utility's retrospective analysis. Specifically, the commission's review is divided between the refund determination required by Texas Water Code §13.184(d) under new §24.28(e)(1)(A) and a more substantive but discretionary determination under §24.28(e)(1)(B). New §24.28(e)(1)(A) establishes that the commission will review the utility's retrospective analysis and actual revenues to determine whether the utility's projected test year data, in comparison to the utility's actual test year results, resulted in rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public. At the same time, §24.28(e)(1)(B) establishes that the commission may review the utility's retrospective analysis and actual revenues to determine whether the utility's projected test year data reasonably aligned with the utility's actual test year results, accounting for all mitigating factors provided by the utility.

OPUC recommended that a utility be required to perform a refund or any other commission-mandated action within a defined number of days after the final order is issued in a base rate proceeding, unless the commission orders a different method.

Commission response

The commission declines to implement the recommended change because it is unnecessary. The presiding officer will specify in the commission order the appropriate timeframe, which may vary depending on factors that are specific to the rate proceeding.

SJWTX recommended that proposed §24.28(c)(2) be revised to exclude extraordinary or critical customer costs under proposed §24.28(c)(1)(B). Specifically, SJWTX recommended proposed §24.28(c)(2) be changed to require that the portion of a utility's rate base, if any, approved under §24.28(c)(1)(B) be excluded from any retrospective analysis used to evaluate a utility's return under §24.28(c)(2)(B). SJWTX commented that if the commission were to make an explicit evidentiary determination that costs attributable to extraordinary circumstances are sufficient to justify deviation from the projections and estimates previously approved by the commission, then such costs should be omitted from the overall analysis of the utility's earnings.

Commission response

The commission disagrees with SJWTX and declines to implement the recommended change because it is unnecessary. The utility's prior rate base is not subject to revision in the retrospective analysis as that would effectively entail another base rate proceeding. Aside from the primary purpose of the retrospective analysis to determine whether a refund is needed in accordance with Texas Water Code §13.184(d), the commission may review the utility's actual test year results against the utility's projected test year data. The purpose of this discretionary, comparative review is to determine whether the commission should require the utility to adjust its calculations or methodologies used for its forecasts, projections, or estimates and identify whether any rate base items were not used and useful through the end of the test year. In some instances, there may be mitigating circumstances where a utility may have valid justifications for increasing costs and collecting a higher rate of return than was previously authorized or for specific capital projects not becoming used and useful. Specifically, under new §24.28(d)(2)(D), a utility must present all events that occurred during the test year that impacted the utility's actual test year results which may include events affecting service to critical customers, natural disasters, system emergencies, and other unplanned circumstances. Whether a utility is justified in deviating from its projected test year data and approved rate of return is a determination for the commission.

SJWTX commented that proposed §24.28(c)(2) constitutes retroactive ratemaking and discourages efficient utility operations. SJWTX highlighted the inherent impossibility in creating perfect forecasts of costs and revenues due to various factors, such as weather or economic conditions, that could lead to variations between the predicted and actual amounts. SJWTX emphasized that there will accordingly always be a difference between forecasted and actual costs and revenues. SJWTX further noted that Texas Water Code §13.184(d) "was added at the very end of the session via a Senate floor amendment, which limited the opportunity for public comment." SJWTX explained that requiring a utility to issue refunds or adjust rates "if a utility can reduce costs provides little incentive for utilities to explore cost-saving measures." SJWTX also indicated that any cost savings would be incorporated into forecasts or projections used by the utility in its next comprehensive rate proceeding because future test year forecasts should at least be partially based on historical data.

Commission response

As stated previously in response to utility comments regarding retroactive ratemaking, the statutory refund is authorized by Texas Water Code §13.184(d), and the commission's implementation is within the authority granted in that language.

Proposed §24.28(c)(2)(B) - Evaluation of retrospective analysis

Proposed §24.28(c)(2)(B) establishes that the commission will review the utility's retrospective analysis in a comprehensive base rate proceeding to determine whether the utility's forecasted costs and revenues reasonably align with the utility's actual costs and revenues and whether revenues yielded a fair return.

If the commission retains the retrospective analysis as part of the utility's next base rate case, OPUC recommended that §24.28(c)(2)(B) be revised such that the presiding officer would rule on a retrospective analysis before proceeding to the rate-setting phase of the base rate proceeding. OPUC recommended the refund also be accounted for separately in the final order to ensure proper oversight and accountability of the utility while protecting ratepayers from any over-collections. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines OPUC's recommendation because it may unduly restrict the commission's ability to implement Texas Water Code §13.184(d). Under the revised framework, the presiding officer has discretion as to when the retrospective analysis will occur based on the specific circumstances of the base rate proceeding, the utility's actual test year results, and the applicant utility itself. This allows the commission to appropriately effectuate the refund requirement on a case-by-case basis. Specifically, new §24.28(e)(2)(A) states: "[t]he presiding officer will account for a retrospective analysis in the procedural schedule for a base rate proceeding, including the appropriate scope of discovery." And new §24.28(e)(2)(B) provides that "[t]he presiding officer may open a compliance docket to effectuate a refund under subsection (f) of this section."

Proposed §24.28(c)(2)(B)(ii) and proposed §24.28(c)(2)(B)(ii)(I) and (II) - Commission ordered refund or other action for utility retrospective analysis

Proposed §24.28(c)(2)(B)(ii) authorizes the commission to perform specific actions at the conclusion of its evaluation of a utility's retrospective analysis in a comprehensive base rate proceeding upon an evidentiary finding that the utility's actual costs and revenues exceeded the return approved by the commission in the utility's last comprehensive base rate proceeding. Proposed §24.28(c)(2)(B)(ii)(I) authorizes the commission to order a refund in accordance with §24.28(c)(2)(B)(iv) as necessary to account for any over-collections for any customer class. Proposed §24.28(c)(2)(B)(ii)(II) authorizes the commission to perform any other action deemed necessary to ensure just and reasonable rates at the conclusion of a retrospective analysis.

OPUC recommended that the "may" in proposed §24.28(c)(2)(B)(ii) should be changed to a "must" if the commission retains the retrospective analysis in the utility's next base rate case rather than a standalone proceeding. OPUC explained that this change is necessary to effectuate the refund requirement of Texas Water Code §13.184(d) and therefore protect ratepayers from over-collections. OPUC noted that the requirement for the commission to order a refund if the criteria are met under Texas Water Code §13.184(d) is mandatory, not permissive. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is moot. The substantive revisions to §24.28 specifically address OPUC's concerns. New §24.28(e)(3)(A) states "[u]pon a finding that a utility's actual test year results yielded more than a fair return under subparagraph (1)(A) of this subsection, the commission will order a refund in accordance with subsection (f) of this subsection." New §24.28(e)(3)(B) provides that "[t]he commission will perform any other action necessary to ensure just and reasonable rates at the conclusion of a retrospective analysis or the contemporaneous base rate proceeding, as determined by the presiding officer." The use of "will" in each provision ensures that both actions will be undertaken.

CSWR recommended §24.28(c)(2)(B)(ii)(I) be revised to clarify that refunds are not class-specific, but instead only apply when the company's entire cost of service for all customer classes exceeds a commission-approved range of reasonable return. CSWR indicated that class-specific refunds would be overly complex and result in a utility being compelled to apply refunds to one class for which it is over-collecting while also potentially under-collecting among other customer classes. CSWR remarked that because it "cannot surcharge class-specific losses under the rule, it should not be required to provide class-specific refunds." CSWR emphasized that the refund obligation should be based on a utility's overall earned rate of return based on its entire cost of service and customer base.

Commission response

The commission disagrees with CSWR and declines to implement the recommended change. Any "money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected" under Texas Water Code § 13.184(d) must be tracked by customer class and rate type, where applicable. This will ensure a refund will be applied in a way that avoids cross-subsidization using the regulatory liability specified under new §24.28(f)(2)(A). In response to CSWR's concern, the commission adds new §24.28(f)(2)(B) which states "[w]ith regard to any allocations or rate design treatment, a refund under this subsection must be applied among customers in a manner reasonably proportional to the magnitude in which the excessive rates were collected relative to rates that would have yielded a fair return."

CSWR recommended the commission clarify the term "over-collections" within the context of proposed §24.28(c)(2)(B)(ii)(II). CSWR noted that refunds of over-collections should "only apply to amounts that exceed the criteria applicable to the earned rate of return and not to over- or under-collection of rates." CSWR explained that an over-collection of cost-of-service could occur when a utility is under-recovering its approved rate of return, such as when a utility experiences high growth contemporaneously with a period of high capital investment or otherwise incurs significant costs that decrease its overall earned return.

Commission response

The extensive rework of §24.28 substantively addresses SJWTX's concern because the "over-collections" language has been omitted. As stated previously, the refund determination is based on "whether the utility's rates yielded more than a fair return on the utility's invested capital used and useful in rendering service to the public" under the revised framework of new §24.28(e)(3)(A). Specifically, the mandatory portion of the commission's refund determination is a simple analysis as to whether the utility's actual test year results exceeded a fair return (i.e., the utility's authorized rate of return). The commission also makes clerical revisions to new §24.28(e)(4) regarding the presiding officer's authorization to require the utility to provide additional information for the retrospective analysis. The actual methodology for the refund is specified under new §24.28(f)(1) and its sub-provisions. New §24.28(f)(1) and new §24.28(f)(1)(A) and (B) collectively state "[i]f the commission determines a refund is required in accordance with subsection (e)(C)(3) of this section, the commission will…determine the rate for the utility that would have yielded a fair return on the utility's invested capital used and useful in rendering service to the public and require a refund to customers, which must include carrying costs; and…require the utility to refund to customers the difference between the revenues collected and the revenues that would have been collected under the rates that would have yielded a fair return plus any carrying costs." The provisions concerning carrying costs under proposed §24.28(c)(2)(B)(vi) have been moved to new §24.28(f)(3)

Proposed §24.28(c)(2)(B)(iv); proposed §24.28(c)(2)(B)(iv)(I); and proposed §24.28(c)(2)(B)(iv)(II) - Refund determination and obligation

Proposed §24.28(c)(2)(B)(iv) provides the form and manner for a refund ordered by the commission in accordance with §24.28(c)(2)(B) (ii)(I). Proposed §24.28(c)(2)(B)(iv)(I) establishes that the commission will determine the rate for the utility that would have yielded a fair return and require a refund to customers, which must include carrying costs. Proposed §24.28(c)(2)(B)(iv)(I) establishes that the commission will require the utility to refund to customers the difference between the excessive rate and the rate determined by the commission.

TAWC recommended the commission clarify whether the refund mechanism under proposed §24.28(c)(2)(B)(iv) is the regulatory liability mechanism under proposed §24.28(c)(2)(B)(v), and does not require individual refunds to customers. Specifically, TAWC noted that §24.28(c)(2)(B)(iv) refers to a refund to customers while §24.28(c)(2)(B)(v) indicates that any excessive return will be tracked as a regulatory liability in subject to refund in the utility's next comprehensive base rate proceeding. TAWC expressed a preference for the regulatory liability mechanism, which it interpreted as applying a credit to cost of service, as it would effectuate greater cost savings rather than requiring dispensation if individual refunds to each customer. TAWC also recommended proposed §24.28(c)(2)(B)(vi)(II) be revised to correct the typographical error referencing "electric utility." CSWR endorsed the usage of a regulatory liability under §24.28(c)(2)(B)(v) to effectuate any refund ordered as it simplifies the process. Specifically, it enables a utility to apply a credit to the total cost of service, instead of issuing individual refunds to customers, which is a difficult and costly process. CSWR further noted that direct refunds "would not account for customers that join or leave the system between rate proceedings."

Commission response

The commission agrees with TAWC and implements the recommended change in new §24.28(f)(3)(B). In response to CSWR, the usage of a regulatory liability for the refund is appropriate and consistent with standard regulatory accounting. Tracking any balance through the regulatory liability amortizing it back to customers in future rates achieves the intended outcome of the statutory refund. The commission also removes the term "electric utility."

SJWTX recommended that the commission define what constitutes an "excessive" return under proposed §24.28(c)(2)(B)(iv) to minimize disputes and therefore facilitate more expeditious processing of applications.

Commission response

The substantive rework of §24.28 addresses SJWTX's concern. As stated previously, the refund determination is based on "whether the utility's rates yielded more than a fair return on the utility's invested capital used and useful in rendering service to the public" under the revised framework (new §24.28(e)(3)(A)).

Proposed §24.28(c)(2)(B)(v) - Regulatory liability for refund

Proposed §24.28(c)(2)(B)(v) requires that earnings that exceed a utility's fair rate of return must be separately tracked as a regulatory liability that will be subject to refund in the utility's next comprehensive base rate proceeding.

OPUC recommended revising §24.28(c)(2)(B)(v) to account for CWIP if the commission retains the retrospective analysis in the utility's next base rate case rather than a standalone proceeding. Specifically, OPUC recommended the provision be revised to track CWIP-related over-collections for projected CWIP that did not come into service during the combined or future test year that is subject to refund per OPUC's recommended new §24.28(c)(4)(B)(iv). OPUC noted that if this provision were not included, the regulatory liability under proposed §24.28(c)(2)(B)(v) would not include "unused CWIP." OPUC further explained that the revision would provide clarity as to the scope of the refund when forecasted CWIP is not actually placed into service as projected. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement a recommended change because it is contrary to statute. Texas Water Code §13.184(d) does not explicitly require or necessarily entail a refund of each cost component that the utility exceeds. The sole inquiry for the statutory refund is whether the utility's test year information resulted in rates yielding more than a fair return. As stated previously, CWIP is only one component of a utility's costs and does not require separate or specialized treatment as OPUC recommends.

New §24.28(c)(2)(B)(vii)

OPUC recommended adding new §24.28(c)(2)(B)(vii) if the commission retains the retrospective analysis in the utility's next base rate case rather than a standalone proceeding. The new provision would require the utility to bear the burden of proof for showing the reasonableness of its selected test year and all associated test year information used to establish rates. If the utility does not satisfy its burden, then it is presumed by the presiding officer that the rates are unreasonable and will be refunded to customers based on the difference between the excess revenues collected and what would have been a fair return, with carrying costs. OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. A utility's burden of proof is established by Texas Water Code §13.184(c) which states "[i]n any proceeding involving any proposed change of rates, the burden of proof shall be on the utility to show that the proposed change, if proposed by the utility, or that the existing rate, if it is proposed to reduce the rate, is just and reasonable." (emphasis added) Therefore, citing that burden of proof is on the utility is unnecessary because it is implicit in every water and sewer rate proceeding. Moreover, §24.26(c)(3) already requires a utility to "provide evidence in its rate change application that its proposed rates are just and reasonable using its selected test year."

Proposed §24.41 - Cost of Service

Proposed §24.41(b), proposed §24.41(b)(1), §24.41(b)(1)(B), and §24.41(b)(1)(B)(i) - Allowable expenses; components of allowable expenses

Proposed §24.41(b) establishes that only those expenses that are reasonable and necessary to provide service to the ratepayers may be included in allowable expenses. The provision also requires that only the utility's test year expenses will be considered in computing a utility's allowable expenses and requires that any change in rates be based on a test year as defined in §24.3 and comply with the applicable requirements of §24.26. Proposed §24.41(b)(1) authorizes the inclusion of reasonable and necessary allowable expenses and provides a non-exhaustive list of such expenses. Proposed §24.41(b)(1)(B) authorizes the inclusion of reasonable and necessary depreciation expense provided that such expense is based on original cost and computed on a straight-line basis over the useful life of the asset, as approved by the commission. Proposed §24.41(b)(1)(B)(i) authorizes depreciation expense on all depreciable utility property owned by the utility, including CWIP reasonably projected to be in service during a combined test year or future test year. The provision also authorizes depreciation expense on all developer or governmental entity contributed property.

OPUC recommended that the depreciation extension under proposed §24.41(b)(1)(B)(i) should be revised to prevent double recovery and to ensure customers are refunded for projected CWIP that fails to materialize. Specifically, OPUC recommended that §24.41(b)(1)(B)(i) be revised to condition payment for forecasted CWIP depreciation should be conditioned on its actual in-service status. OPUC further recommended that failure of projected CWIP to be placed into service during the future or combined test year should result in a refund to customers under §24.41(c)(2). OPUC stated that the provision, in conjunction with proposed §24.41(c)(4)(B), requires ratepayers "to fund both the return on and depreciation of a utility's plant that has not yet been placed in service." OPUC noted that if forecasted CWIP fails to meet its in-service date, under the proposed language, any refund to customers is dependent solely on the retrospective analysis under proposed §24.41(c)(2) which could occur significantly later than the date the CWIP was projected to be in service.

Commission response

The commission declines to implement the recommended change for the reasons already stated. CWIP is only one component of a utility's costs, whereas Texas Water Code §13.184(d) bases the refund solely on whether the utility's test year information resulted in rates yielding more than a fair return.

New §24.41(b)(1)(B)(ii) and (iv)

OPUC recommended that new §24.41(c)(4)(B)(ii) and (iv) be added to ensure that (1) major projects under construction have been efficiently and prudently planned and managed; and (2) CWIP included that does not actually come into service by the end of the combined or future test year is tracked and a commensurate refund is issued to ratepayers. OPUC noted that the added provision should include a cross-reference to proposed §24.28(c)(2). OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change for the reasons already stated. CWIP is only one component of a utility's costs, whereas Texas Water Code §13.184(d) bases the refund solely on whether the utility's test year information resulted in rates yielding more than a fair return. Statutory analysis of Texas Water Code §13.185(b) and (k) is provided under the heading for proposed §24.41(c).

Proposed §24.41(c), proposed §24.41(c)(4), §24.41(c)(4)(A); and §24.41(c)(4)(B), and §24.41(b)(1)(B)(i) and (ii) - Return on rate base; Construction work in progress (CWIP)

Proposed §24.41(c) establishes that the return on rate base is the rate of return times rate base.

Proposed §24.41(c)(4) establishes the requirements applicable to CWIP based on a utility's selection of test year. Proposed §24.41(c)(4)(A) establishes the CWIP-related requirements for a historic test year. Specifically, the provision establishes that the inclusion of CWIP in rate base is an exceptional form of relief and that, under ordinary circumstances, rate base consists only of those items that are used and useful in providing service to the public. The provision further authorizes the commission to include CWIP in rate base in exceptional circumstances, to the extent that the utility has proven that the inclusion is necessary to the financial integrity of the utility; and major projects under construction have been efficiently and prudently planned and managed. Proposed §24.41(c)(4)(B) establishes the CWIP-related requirements for a combined test year or a future test year. The provision further establishes that the commission will review CWIP to determine the extent the utility projects some or all of CWIP to be in service through the end of the combined test year or future test year. The provision also specifies that projected CWIP will be in service by the end of the combined test year or the future test year will be included in rate base. Proposed §24.41(c)(4)(B)(i) requires the applicant to prove that CWIP is reasonably projected to be in service through the end of the combined test year or future test year. Proposed §24.41(c)(4)(B)(ii) requires the applicant to demonstrate that inclusion of CWIP is in the ratepayers' best interest and is necessary to the financial integrity of the utility through clear and convincing evidence.

OPUC recommended that the prudence requirement should be reinstated to review of CWIP by applying the "clear and convincing evidence" standard to all sub-elements of §24.41(c)(4)(B).

OPUC noted that existing §24.41 reflects the statutory classification of including CWIP in rate base is an "exceptional form of rate relief" and requires the utility to prove both that inclusion of CWIP is necessary to maintain the financial integrity of the utility and that major projects under construction have been efficiently and prudently planned and managed. However, the proposed rule relaxes those standards and only requires the lesser standard of whether including CWIP would be in ratepayers' best interest. OPUC maintained that historically, the "customer-protective doctrine" in Texas ratemaking requires a utility to demonstrate both that inclusion of CWIP is in the ratepayers' best interest and the projects were prudently managed. OPUC noted that the standards are not interchangeable, explaining that "best interests of ratepayers" is forward-looking and discretionary policy determination, whereas "prudent management" is a backward-looking factual finding focused on utility conduct. OPUC indicated that while CWIP projected to be in service during a future or combined test year is technically forward-looking because the in-service date has not yet occurred, the utility's management of the project is principally backward-looking at the base rate proceeding stage. This is because all of the planning, procurement, contracting, and construction actions are typically complete by the time of the base rate case. As such, the "prudent management" standard applies both to historical decisions and to in-service plants. Therefore, for the projected in-service date and remaining costs, the "prudent management" standard is an inquiry as to "whether the utility's current projections are reasonable based on present facts" which is consistent with how Federal Energy Regulatory Commission (FERC) and other jurisdictions have applied prudence review to CWIP. Stated differently, removing prudence review in lieu of a "ratepayers' best interest" standard would enable a utility to recover costs for projected CWIP even if management decisions were careless or negligent, provided that the overall outcome benefits ratepayers. OPUC stated that such an outcome is inconsistent with existing ratemaking practice and, if left unchanged, carries significant implications for rate cases in the future at the commission. OPUC provided draft language consistent with its recommendation.

Commission response

The commission disagrees with OPUC with respect to applying the clear and convincing evidence standard to CWIP that the utility reasonably projects to be in service through the end of a combined test year or future test year is contrary to statute. In relevant part, Texas Water Code §13.185(b) states that a utility's rates "shall be based on the original cost of property used by and useful to the utility during the test year in providing service, including if necessary to the financial integrity of the utility, construction work in progress at cost as recorded on the books of the utility." (emphasis added). The provision further states that "[t]he inclusion of construction work in progress is an exceptional form of rate relief to be granted only on the demonstration by the utility by clear and convincing evidence that the inclusion is in the ratepayers' best interest and is necessary to the financial integrity of the utility" (emphasis added). Lastly, Texas Water Code §13.185(b) prohibits CWIP from inclusion "in the rate base for major projects under construction to the extent that those projects have been inefficiently or imprudently planned or managed" (emphasis added). In contrast, Texas Water Code §13.185(k) states "[n]otwithstanding [Texas Water Code §13.185(b)], the regulatory authority shall allow inclusion in the rate base of facilities projected to be in service through the end of the test year" (emphasis added). The determinants for whether Texas Water Code §13.185(b) or (k) apply are (1) the time period of the utility's selected test year relative to the date the utility's base rate proceeding was initiated (i.e., whether the utility's test year occurred before, during, or after the base rate case) and, if the utility's test year occurs in the future, (2) whether the utility projected CWIP to be in service through the end of the test year. For the first determinant, Texas Water Code §13.185(b) will always apply to CWIP in a historic test year because the test year occurred prior to the comprehensive base rate case. Stated differently, CWIP for a utility that selects historic test year is only eligible for the treatment specified under Texas Water Code §13.185(b) which entails a higher level of scrutiny. This is because CWIP was not used and useful in a historic test year and therefore should not be included in rate base unless the clear and convincing standard is met. In contrast, Texas Water Code §13.185(b) can only ever apply to CWIP in a combined test year or future test year, because those test years contain future data (i.e., some or all of the test year occurs in the future as of the date the utility's comprehensive base rate case was filed). Therefore, a utility that selects a combined test year or future test year and projects CWIP to be in service through the end of the test year is not required to meet the higher clear and convincing evidence standard of Texas Water Code §13.185(b). The usage of "notwithstanding" in statute or rule language means "despite" or "in spite of." The commission interprets the phrase "notwithstanding [Texas Water Code §13.185(b)]" as not requiring the usual application of the clear and convincing standard.

Additionally Texas Water Code §13.185(b) could apply to CWIP in a combined test year or future test year if the utility does not project the CWIP to be in service during the test year, but nevertheless requests it to be included in rate base. In this scenario, the same policy rationale for a historic test year would apply because the CWIP is not projected to be "used and useful" during the combined test year or future test year. Accordingly, the commission revises §24.41(c)(4)(A) to state that "[t]his subparagraph applies to a utility that elects to use a historic test year or to a utility that elects to use a combined test year or future test year for CWIP that the utility projects to not be in service through the end of the test year. The inclusion of CWIP is an exceptional form of relief that must be proven by clear and convincing evidence." The commission also revises §24.41(c)(4)(B) to state "[t]his subparagraph applies to a utility that elects to use a combined test year or a future test year that projects CWIP to be in service through the end of its selected test year." The commission also deletes proposed §24.41(c)(4)(B)(ii), restructures §24.41(c)(4)(B)(i), and adds new §24.41(c)(4)(B)(ii), which respectively provide that "[t]he commission will review CWIP to determine the extent the utility projects some or all of CWIP to be in service through the end of the combined test year or future test year" and "CWIP that the utility projects will be in service by the end of the combined test year or the future test year will be included in rate base. The utility has the burden of proving that CWIP is reasonably projected to be in service (i.e., installed) through the end of the combined test year or future test year." The revised phrase "reasonably projected" appropriately describes the utility's burden of proof for CWIP under Texas Water Code §13.184(c). Commission approval of CWIP that a utility unreasonably projects to be in service through the end of a test year would be contrary to statute and not be in the public interest, even though Texas Water Code §13.185(k) does not use the phrase "reasonably projects." Moreover, the addition of the parenthetical clarifying that "in service" is equivalent to "installed" is consistent with the commission's determination of §24.76.

SJWTX recommended proposed §24.41(c)(4)(B)(i) be deleted because it would "create a higher burden of proof for the inclusion of an asset in rate base as opposed to a higher burden of proof for recovery of CWIP." SJWTX also recommended proposed §24.41(c)(4)(B) be revised to apply the "clear and convincing evidence" standard of review only to CWIP that will not be in service by the end of the test year. SJWTX explained that the existing rule effectuates Texas Water Code §13.185(b), which identifies CWIP as an extraordinary or exceptional form of rate relief. However, SJWTX noted that an asset is no longer included as CWIP once it is placed into service. Accordingly, including an asset or facility the utility projects will be used and useful by the end of the test year does not constitute recovery of CWIP and is therefore not an "extraordinary form of relief" necessitating a heightened burden of proof.

Commission response

The commission declines to implement the recommended change because it is moot. The restructuring of §24.41(c)(4)(A) and (B) substantively addresses SJWTX's concern. The commission agrees with SJWTX that the clear and convincing evidence standard only applies to CWIP that the utility reasonably projects will be in service through the end of the test year.

CSWR, Aqua, and TAWC recommended that the clear and convincing evidence standard should be omitted from proposed §24.41(c)(4)(B)(ii) as it is contrary to statute, undermines utility infrastructure investment incentives, and increases regulatory uncertainty. CSWR noted that the purpose of the proposed rule is "to allow for inclusion of capital projects that are in service by the end of the test year." CSWR indicated that imposing such a burden of proof requirement would only increase ambiguity and therefore create additional disputes and further litigation. Aqua commented that the provision contradicts Texas Water Code §13.185(k) which explicitly states that rate base must include facilities projected to be in service through the end of the test year. As such, inclusion of CWIP projects to be in service at the end of the future or combined test year is necessary to ensure that "the test year accurately reflects the utility's future investment and cost of service." Aqua noted that proposed §24.41(c)(4)(B)(ii) impermissibly mirrors the heightened requirement for CWIP for historic test year in contradiction of the statute. Aqua noted that excluding CWIP from a future or combined test year for reasons outside of whether the facilities will be in service by the end of the test year would be contrary to the legislative intent of aligning a utility's rates with its actual cost of service and promoting infrastructure investment. Aqua stated that requiring clear and convincing evidence based on an ambiguous "best interest" standard would create additional regulatory uncertainty by permitting eligible investments to be excluded based on a subjective determination. Aqua stated such exclusions would be to the financial detriment of investor-owned utilities that make investment and fiscal decisions based on "the reasonable expectation that prudently incurred plant projected to be in service during the future test year will be reflected in rates." Aqua commented that investments that satisfy the statutory in-service requirement should be the only criteria for inclusion of CWIP. Similarly, TAWC explained that Texas Water Code §13.185(k) does not implicate a higher standard of review for the inclusion of CWIP for a future or combined test year. Therefore, the only basis for review should be whether the utility "reasonably projected [the facilities] to be in service through the end of the combined test year or future test year" without requiring additional proof.

Commission response

The commission agrees with CSWR, Aqua, and TAWC and implements the recommended change for the reasons already stated.

OPUC recommended that proposed §24.41(c)(4)(B)(ii) be revised to apply the clear and convincing evidence standard should when evaluating a utility's projection that CWIP will be in service by the end of the test year. Specifically, OPUC recommended moving the clear and convincing evidence requirement to proposed §24.41(c)(4)(B) so that it applies to both elements of the test for inclusion of CWIP in a utility's rates. OPUC noted that, as proposed, a utility's burden of proof for such a projection is by a preponderance of the evidence only. OPUC further noted that the clear and convincing evidence standard only applies to the policy issue of whether the inclusion of CWIP is in the customer's best interest.

Commission response

The commission declines to implement the recommended change for the reasons already stated. Specifically, the clear and convincing evidence standard of Texas Water Code §13.185(b) only applies to CWIP that the utility reasonably projects will be in service through the end of the test year due to the exception written into Texas Water Code §13.185(k).

New §24.41(c)(4)(C)

OPUC recommended adding new §24.41(c)(4)(C) to account for circumstances in which a utility also has a SIC in effect to prevent double recovery. Specifically, OPUC recommended that the commission require utilities to map projects at the project level by: (1) identifying each project or cost category, (2) indicating the utility's planned method to recover identified project costs and cost categories such as base rates, a SIC, or other tracker; (3) identify each month covered in the forecasted test year period and whether any overlapping recovery method exists for the identified projects and cost categories; and (4) include the utility's required offset or exclusion amounts where the overlap occurs to ensure no double recovery occurs from ratepayers. OPUC stated that proposed §24.41 does not address what occurs if a SIC is effective when a utility files a base rate proceeding using a future or combined test year and the new base rates take effect. OPUC noted that the proposed rule creates a risk of double-recovery because a SIC may remain effective through the rate case and continue to recover revenue for the same plant that is not included in the utility's base rates using a combined or future test year. OPUC alternatively recommended that any SIC that a utility has in effect be set to zero on the same date a utility's base rates using a future or combined test year become effective, whether interim or final. OPUC commented that after the effective date of the new rates, a utility would be eligible to apply for a new SIC for any eligible plant added after the effective date of the new rates. OPUC stated this approach would not deprive a utility of cost recovery it is otherwise entitled to. OPUC explained that since a SIC is an additional charge for eligible plant that is not already included in rates, after the comprehensive rate proceeding those costs are now included in base rates, rendering the SIC unnecessary. OPUC noted that its alternative recommendation is consistent with the term "reconcilable cost" in §24.76 which is defined as "the original costs of an eligible plant placed into service after the... end of the test year used in the utility's most recent base-rate proceeding." OPUC further noted that its position is consistent with the prohibition under §24.76(e)(3), which limits a SIC to "the cost recovery of eligible plant that is not already included in the utility's rates and eligible plant that has been placed into service after the later of the ending date of the 2019 reporting period reflected in the utility's annual report filed with the commission as required by [§24.129] or the end of the test year used in the utility's most recent base-rate proceeding." OPUC provided draft language consistent with its recommendation.

Commission response

The commission declines to implement either of OPUC's recommendations because they are unnecessary. As stated previously, §24.76(c)(1)(E) already prohibits overlap between a SIC and combined test year or future test year by limiting a SIC application "to cost recovery of eligible plant placed into service subsequent to the end of the future test year or combined test year." Moreover, specific rule language regarding setting a SIC to zero once a utility's interim or final rates are established is unnecessary because this happens as a matter of course in a comprehensive base rate proceeding. Specific rule language would unnecessarily limit the presiding officer's discretion as to when the SIC should be set to zero.

Proposed §24.41(c)(6), §24.41(c)(6)(A); and §24.41(c)(6)(B) - Future test year and combined test year requirements.

Proposed §24.41(c)(6) establishes the future test year and combined test year requirements for purposes of §24.41.

Proposed §24.41(c)(6)(A) requires a utility that selects a future test year to comply with §24.26, as applicable. Proposed §24.41(c)(6)(B) requires a utility that selects a combined test year to meet the requirements of §24.26 only for the portion of the combined test year that incorporates future data."

The commission deletes proposed §24.41(c)(6) in its entirety because it is unnecessary. Section 24.26 is explicitly applicable to persons "under the original rate jurisdiction of the commission…seeking to obtain or amend an approved tariff in accordance with [§24.25] and establish rates using a test year" per §24.26(a). Moreover, §24.41(b) explicitly requires compliance with §24.26.

SUBCHAPTER A. GENERAL PROVISIONS

The amended rule is adopted under the following provisions of the Texas Water Code: Texas Water Code §13.002(16-a), which defines the term "public utility agency" for use in Chapter 13; §13.041(a), which provides the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by the Texas Water Code that is necessary and convenient to the exercise of that power and jurisdiction; Texas Water Code §13.041(b), which provides the commission with the authority to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; §13.1831 which requires a regulatory authority to fix rates for water and sewer services for a Class, A, B, C, or D utility based on a test year that, among other things, includes historic, future, or combined historic and future data; §13.183(a), which requires the regulatory authority to fix a utility's rates for water and sewer services at a level that will permit the utility a reasonable opportunity to earn a reasonable return on its invested capital used and useful in rendering service to the public, based on test year information, over and above its reasonable and necessary operating expenses; §13.184(a), which prohibits the utility commission from prescribing any rate that will yield more than a fair return on the invested capital used and useful in rendering service to the public based on test year information; §13.184(d), which requires the regulatory authority to require a utility that uses a future or combined historic and future test year, to refund to customers money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected if the regulatory authority determines in the next rate proceeding for that utility that the test year information used for the utility resulted in the utility's rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public; §13.185(b), which requires utility rates to be based on the original cost of property used by and useful to the utility during the test year in providing service, including, if necessary to the financial integrity of the utility, CWIP at cost as recorded on the books of the utility; §13.185(d)(1), which requires the regulatory authority to base a utility's expenses on test year information, as determined by commission rules; §13.185(j), which establishes that depreciation expense included in the cost of service includes depreciation on all depreciable utility property owned by the utility except for property provided by explicit customer agreements or funded by customer contributions in aid of construction and requires depreciation on all developer or governmental entity contributed property to be allowed in the cost of service; §13.185(k), which requires the regulatory authority to allow inclusion in the rate base of facilities projected to be in service through the end of the test year; §13.185(l), which requires a utility that selects a fully projected future test year to, not later than the 30th day after the last day of the last quarter of the test year, to file with the regulatory authority a statement that describes the utility's actual results experienced in the test year; and provides appropriate data to demonstrate the accuracy of the estimates used for the test year and serve a copy of such a statement on all parties of record in the rate proceeding in which the final rate determination using the test year was entered; and §13.185(m), which requires a utility that does not have the results or data required under §13.183(l) to file a notice with the regulatory authority stating the date on which the results or data will be available, serve a copy of that notice on all parties of record in the rate proceeding in which the final rate determination using the test year was entered, and perform the actions described under §13.185(l) as soon as possible after the results or data are available.

Cross Reference to Statute Texas Water Code §§13.002(16-a), 13.041(a) and (b), 13.1831, 13.183(a)(1), 13.184(a) and (d), 13.185(b), (d), (j), (k), (l), and (m).

§24.3. Definitions of Terms.

In this chapter, the following definitions apply unless the context indicates otherwise.

(1) Affected county--A county that:

(A) Has a per-capita income that averaged 25% below the state average for the most recent three consecutive years for which statistics are available and an unemployment rate that averaged 25% above the state average for the most recent three consecutive years for which statistics are available;

(B) Has an international border;

(C) Is located in whole or in part within 100 miles of an international border and contains a majority of the area of a municipality with a population of more than 250,000; or

(D) Has an economically distressed area which has a median household income that is not greater than 75% of the median state household income.

(2) Affected person--Any landowner within an area for which a certificate of public convenience and necessity is filed, any retail public utility affected by any action of the regulatory authority, any person or corporation whose utility service or rates are affected by any proceeding before the regulatory authority, or any person or corporation that is a competitor of a retail public utility with respect to any service performed by the retail public utility or that desires to enter into competition.

(3) Affiliated interest or affiliate--

(A) any person or corporation owning or holding directly or indirectly 5.0% or more of the voting securities of a utility;

(B) any person or corporation in any chain of successive ownership of 5.0% or more of the voting securities of a utility;

(C) any corporation owning or holding 5.0% or more of the voting securities of which is owned or controlled directly or indirectly by a utility;

(D) any corporation owning or holding 5.0% or more of the voting securities of which is owned or controlled directly or indirectly by any person or corporation that owns or controls directly or indirectly 5.0% or more of the voting securities of any utility or by any person or corporation in any chain of successive ownership of 5.0% of those utility securities;

(E) any person who is an officer or director of a utility or of any corporation in any chain of successive ownership of 5.0% or more of voting securities of a public utility;

(F) any person or corporation that the commission, after notice and hearing, determines actually exercises any substantial influence or control over the policies and actions of a utility or over which a utility exercises such control or that is under common control with a utility, such control being the possession directly or indirectly of the power to direct or cause the direction of the management and policies of another, whether that power is established through ownership or voting of securities or by any other direct or indirect means; or

(G) any person or corporation that the commission, after notice and hearing, determines is exercising substantial influence over the policies and actions of the utility in conjunction with one or more persons or corporations with which they are related by ownership or blood relationship, or by action in concert, that together they are affiliated within the meaning of this section, even though no one of them alone is so affiliated.

(4) Billing period--The period between meter-reading dates for which a bill is issue or, if usage is not metered, the period between bill issuance dates.

(5) Class A Utility--A public utility that provides retail water or sewer utility service to 10,000 or more taps or active connections. If a public utility provides both water and sewer utility service, the number of active water connections determines how the utility is classified.

(6) Class B Utility--A public utility that provides retail water or sewer utility service to 2,300 or more taps or active connections but fewer than 10,000 taps or active connections. If a public utility provides both water and sewer utility service, the number of active water connections determines how the utility is classified.

(7) Class C Utility--A public utility that provides retail water or sewer utility service to 500 or more taps or active connections but fewer than 2,300 taps or active connections. If a public utility provides both water and sewer utility service, the number of active water connections determines how the utility is classified.

(8) Class D Utility--A public utility that provides retail water or sewer utility service to fewer than 500 taps or active connections. If a public utility provides both water and sewer utility service, the number of active water connections determines how the utility is classified.

(9) Commission--The Public Utility Commission of Texas.

(10) Combined test year--A test year that includes historical data and future data.

(11) Corporation--Any corporation, joint-stock company, or association, domestic or foreign, and its lessees, assignees, trustees, receivers, or other successors in interest, having any of the powers or privileges of corporations not possessed by individuals or partnerships, but does not include municipal corporations unless expressly provided in TWC chapter 13.

(12) Customer--Any entity that purchases services from a retail public utility.

(13) Customer class--A group of customers with similar cost-of-service characteristics that take utility service under a single set of rates.

(14) Customer service line--The pipe connecting the water meter to the customer's point of use or the pipe that conveys sewage from the customer's premises to the service provider's service line.

(15) District--District has the meaning assigned to it by TWC §49.001(a).

(16) Facilities--All the plant and equipment of a retail public utility, including all tangible and intangible real and personal property without limitation, and any and all means and instrumentalities in any manner owned, operated, leased, licensed, used, controlled, furnished, or supplied for, by, or in connection with the business of any retail public utility.

(17) Future test year--A test year that includes only future data and forecasts, estimates, or projections, although such future data, forecasts, estimates, or projections may be derived in part from historical data.

(18) Historic test year--A test year that includes only historical data.

(19) Inactive connection--A water or wastewater connection is considered to be inactive when the ability to provide water or wastewater service is either physically removed or permanently closed.

(20) Incident of tenancy--Water or sewer service provided to tenants of rental property for which no separate or additional service fee is charged other than the rental payment.

(21) Landowner--An owner or owners of a tract of land.

(22) Member--A person who holds a membership in a water supply or sewer service corporation and who is a record owner of a fee simple title to property in an area served by a water supply or sewer service corporation, or a person who is granted a membership and who either currently receives or will be eligible to receive water or sewer utility service from the corporation. In determining member control of a water supply or sewer service corporation, a person is entitled to only one vote regardless of the number of memberships the person owns.

(23) Minimum Monthly Charge--The fixed amount billed to a customer each month even if the customer uses no water or wastewater.

(24) Municipality--Cities organized under the general, home rule, or special laws of this state.

(25) Municipally owned utility--Any retail public utility owned, operated, and controlled by a municipality or by a nonprofit corporation whose directors are appointed by one or more municipalities.

(26) Nonfunctioning system or utility--A system that is operating as a retail public utility and:

(A) is required to have a CCN and is operating without a CCN; or

(B) is under supervision in accordance with §24.353 of this title (relating to Supervision of Certain Utilities); or

(C) is under the supervision of a receiver, temporary manager, or has been referred for the appointment of a temporary manager or receiver, in accordance with §24.355 of this title (relating to Operation of Utility that Discontinues Operation or Is Referred for Appointment of a Receiver) and §24.357 of this title (relating to Operation of a Utility by a Temporary Manager).

(27) Person--Natural persons, partnerships of two or more persons having a joint or common interest, mutual or cooperative associations, water supply or sewer service corporations, and corporations.

(28) Point of use--The primary service connection point where water is used or sewage is generated.

(29) Potable water--Water that is suitable for drinking.

(30) Potential connections--Total number of active plus inactive connections.

(31) Premises--A tract of land or real estate including buildings and other appurtenances thereon.

(32) Public utility agency--A public utility agency created under Chapter 572 of the Texas Local Government Code.

(33) Rate--Every compensation, tariff, charge, fare, toll, rental, and classification or any of those items demanded, observed, charged, or collected, whether directly or indirectly, by any retail public utility, for any service, product, or commodity described in TWC §13.002(23), and any rules, regulations, practices, or contracts affecting that compensation, tariff, charge, fare, toll, rental, or classification.

(34) Requested area--The area that a petitioner or applicant seeks to obtain, add to, or remove from a retail public utility's certificated service area.

(35) Retail public utility--Any person, corporation, public utility, water supply or sewer service corporation, municipality, public utility agency, political subdivision or agency operating, maintaining, or controlling in this state facilities for providing potable water service or sewer service, or both, for compensation.

(36) Retail water or sewer utility service--Potable water service or sewer service, or both, provided by a retail public utility to the ultimate consumer for compensation.

(37) Service--Any act performed, anything furnished or supplied, and any facilities or lines committed or used by a retail public utility in the performance of its duties under TWC chapter 13 to its patrons, employees, other retail public utilities, and the public, as well as the interchange of facilities between two or more retail public utilities.

(38) Service area--Area to which a retail public utility is obligated to provide retail water or sewer utility service.

(39) Stand-by fee--A charge, other than a tax, imposed on undeveloped property:

(A) with no water or wastewater connections; and

(B) for which water, sanitary sewer, or drainage facilities and services are available; water supply, wastewater treatment plant capacity, or drainage capacity sufficient to serve the property is available; or major water supply lines, wastewater collection lines, or drainage facilities with capacity sufficient to serve the property are available.

(40) Test year--A consecutive 12-month period that begins on the first day of a calendar or fiscal year quarter selected by a Class A, B, C, or D utility to fix rates that includes historic, future, or combined historic and future data. A test year must begin not later than 18 months after the date the utility files a statement of intent to change rates and must end not earlier than 18 months before the date a utility files the statement of intent to change rates. A test year may be a combined test year, a future test year, or a historic test year.

(41) Tract of land--An area of land that has common ownership and is not severed by other land under different ownership, whether owned by government entities or private parties; such other land includes roads and railroads. A tract of land may be acquired through multiple deeds or shown in separate surveys.

(42) Water and sewer utility, utility, or public utility--Any person, corporation, cooperative corporation, affected county, or any combination of those persons or entities, other than a municipal corporation, public utility agency, water supply or sewer service corporation, or a political subdivision of the state, except an affected county, or their lessees, trustees, and receivers, owning or operating for compensation in this state equipment or facilities for the transmission, storage, distribution, sale, or provision of potable water to the public or for the resale of potable water to the public for any use or for the collection, transportation, treatment, or disposal of sewage or other operation of a sewage disposal service for the public, other than equipment or facilities owned and operated for either purpose by a municipality or other political subdivision of this state or a water supply or sewer service corporation, but does not include any person or corporation not otherwise a public utility that furnishes the services or commodity only to itself or its employees or tenants as an incident of that employee service or tenancy when that service or commodity is not resold to or used by others.

(43) Water supply or sewer service corporation--Any nonprofit corporation organized and operating under TWC chapter 67, that provides potable water or sewer service for compensation and that has adopted and is operating in accordance with bylaws or articles of incorporation which ensure that it is member-owned and member-controlled. The term does not include a corporation that provides retail water or sewer utility service to a person who is not a member, except that the corporation may provide retail water or sewer utility service to a person who is not a member if the person only builds on or develops property to sell to another and the service is provided on an interim basis before the property is sold.

(44) Water use restrictions--Restrictions implemented to reduce the amount of water that may be consumed by customers of the utility due to emergency conditions or drought.

(45) Wholesale water or sewer service--Potable water service or sewer service, or both, provided to a person, political subdivision, or municipality who is not the ultimate consumer of the service.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on July 30, 2026.

TRD-202603232

Katelyn Lewis

Rules Coordinator

Public Utility Commission of Texas

Effective date: August 19, 2026

Proposal publication date: April 10, 2026

For further information, please call: (512) 936-7044

SUBCHAPTER B. RATES AND TARIFFS

These new and amended rules are adopted under the following provisions of the Texas Water Code: Texas Water Code §13.002(16-a), which defines the term "public utility agency" for use in Chapter 13; §13.041(a), which provides the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by the Texas Water Code that is necessary and convenient to the exercise of that power and jurisdiction; Texas Water Code §13.041(b), which provides the commission with the authority to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; §13.1831 which requires a regulatory authority to fix rates for water and sewer services for a Class, A, B, C, or D utility based on a test year that, among other things, includes historic, future, or combined historic and future data; §13.183(a), which requires the regulatory authority to fix a utility's rates for water and sewer services at a level that will permit the utility a reasonable opportunity to earn a reasonable return on its invested capital used and useful in rendering service to the public, based on test year information, over and above its reasonable and necessary operating expenses; §13.184(a), which prohibits the utility commission from prescribing any rate that will yield more than a fair return on the invested capital used and useful in rendering service to the public based on test year information; §13.184(d), which requires the regulatory authority to require a utility that uses a future or combined historic and future test year, to refund to customers money collected in excess of a rate that would have yielded a fair return during the period in which the excessive rate was collected if the regulatory authority determines in the next rate proceeding for that utility that the test year information used for the utility resulted in the utility's rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public; §13.185(b), which requires utility rates to be based on the original cost of property used by and useful to the utility during the test year in providing service, including, if necessary to the financial integrity of the utility, CWIP at cost as recorded on the books of the utility; §13.185(d)(1), which requires the regulatory authority to base a utility's expenses on test year information, as determined by commission rules; §13.185(j), which establishes that depreciation expense included in the cost of service includes depreciation on all depreciable utility property owned by the utility except for property provided by explicit customer agreements or funded by customer contributions in aid of construction and requires depreciation on all developer or governmental entity contributed property to be allowed in the cost of service; §13.185(k), which requires the regulatory authority to allow inclusion in the rate base of facilities projected to be in service through the end of the test year; §13.185(l), which requires a utility that selects a fully projected future test year to, not later than the 30th day after the last day of the last quarter of the test year, to file with the regulatory authority a statement that describes the utility's actual results experienced in the test year; and provides appropriate data to demonstrate the accuracy of the estimates used for the test year and serve a copy of such a statement on all parties of record in the rate proceeding in which the final rate determination using the test year was entered; and §13.185(m), which requires a utility that does not have the results or data required under §13.183(l) to file a notice with the regulatory authority stating the date on which the results or data will be available, serve a copy of that notice on all parties of record in the rate proceeding in which the final rate determination using the test year was entered, and perform the actions described under §13.185(l) as soon as possible after the results or data are available.

Cross Reference to Statute Texas Water Code §§13.002(16-a), 13.041(a) and (b), 13.1831, 13.183(a)(1), 13.184(a) and (d), 13.185(b), (d), (j), (k), (l), and (m).

§24.25. Form and Filing of Tariffs.

(a) Approved tariff. A utility may not directly or indirectly demand, charge, or collect any rate or charge, or impose any classifications, practices, rules, or regulations different from those prescribed in its approved tariff filed with the commission or with the municipality exercising original jurisdiction over the utility, except as follows:

(1) A utility may charge the rates proposed under Texas Water Code (TWC) §§13.187, 13.1871, 13.18715, or 13.1872(c)(2) on or after the proposed effective date, unless the proposed effective date of the proposed rates is suspended or the regulatory authority sets interim rates.

(2) The regulatory assessment fee required in TWC §5.701(n) does not have to be listed on the utility's approved tariff to be charged and collected but must be included in the tariff at the earliest opportunity.

(3) A person who possesses facilities used to provide retail water utility service or a utility that holds a certificate of public convenience and necessity (CCN) to provide retail water service that enters into an agreement in accordance with TWC §13.250(b)(2), may collect charges for sewer services on behalf of another retail public utility on the same bill with its water charges and must at the earliest opportunity include a notation on its tariff that it has entered into such an agreement.

(4) A utility may enter into a contract with a county to collect solid waste disposal fees and include those fees on the same bill with its water or sewer charges and must at the earliest opportunity include a notation on its tariff that it has entered into such an agreement.

(b) Requirements as to size, form, identification, minor changes, and filing of tariffs.

(1) Tariffs filed with applications for CCNs.

(A) When applying to obtain or amend a CCN, or to add a new water or sewer system or subdivision to its certificated service area, each utility must file its proposed tariff with the commission and any regulatory authority with original rate jurisdiction over the utility.

(i) For a utility that is under the original rate jurisdiction of the commission, the tariff must include schedules of all the utility's rates, rules, and regulations pertaining to all its utility services when it applies for a CCN to operate as a utility. The tariff must be on the form prescribed by the commission or another form acceptable to the commission.

(ii) For a utility under the original rate jurisdiction of a municipality, the utility must file with the commission a copy of its tariff as approved by the municipality.

(B) If a person applying for a CCN is not currently a retail public utility and would be under the original rate jurisdiction of the commission if the CCN application were approved, the person must file a proposed tariff with the commission. The person filing the proposed tariff must also:

(i) provide a rate study supporting the proposed rates, which may include the costs of existing invested capital or estimates of future invested capital;

(ii) provide all calculations supporting the proposed rates;

(iii) provide all assumptions for any projections included in the rate study;

(iv) provide an estimated completion date for the construction of the physical plant;

(v) provide an estimate of the date service will begin for all phases of construction; and

(vi) provide notice to the commission once billing for service begins.

(C) A person under the original rate jurisdiction of the commission who is seeking to obtain or amend an approved tariff or has obtained an approved tariff for the first time must comply with the requirements of §24.26 of this title (relating to Test Year).

(D) A water supply or sewer service corporation must file with the commission a complete tariff containing schedules of all its rates, rules, and regulations pertaining to all its utility services when it applies to operate as a retail public utility and to obtain or amend a CCN.

(2) Minor tariff changes. Except for an affected county or a utility under the original rate jurisdiction of a municipality, a utility's approved tariff may not be changed or amended without commission approval. Changes to any fees charged by affiliates, the addition of a new extension policy to a tariff, or modification of an existing extension policy are not minor tariff changes. An affected county may change rates for retail water or sewer service without commission approval, but must file a copy of the revised tariff with the commission within 30 days after the effective date of the rate change.

(A) The commission, or regulatory authority, as appropriate, may approve the following minor changes to utility tariffs:

(i) service rules and policies;

(ii) changes in fees for customer deposits, meter tests, return check charges, and late charges, provided they do not exceed the maximum allowed by commission rules;

(iii) addition of the regulatory assessment fee payable to the Texas Commission on Environmental Quality (TCEQ) as a separate item or to be included in the currently authorized rate;

(iv) addition of a provision allowing a utility to collect retail sewer service charges in accordance with TWC §13.250(b)(2) or §13.147(d);

(v) rate adjustments to implement commission-authorized phased or multistep rates or downward rate adjustments to reconcile rates with actual costs;

(vi) implementation of an energy cost adjustment clause under subsection (n) of this section;

(vii) implementation or modification of a pass-through provision calculation in a tariff, as provided in subparagraphs (B) - (F) of this paragraph, which is necessary for the correct recovery of the actual charges from pass-through entities, including line loss;

(viii) some surcharges as provided in subparagraph (G) of this paragraph; and

(ix) modifications, updates, or corrections that do not affect a rate may be made to the following information contained in the tariff:

(I) the list of the cities, counties, and subdivisions in which service is provided;

(II) the public water system name and corresponding identification number issued by the TCEQ; and

(III) the sewer system names and corresponding discharge permit number issued by the TCEQ.

(B) The commission, or other regulatory authority, as appropriate, may approve a minor tariff change for a utility to establish reduced rates for a minimal level of retail water service to be provided solely to a class of customers 65 years of age or older to ensure that those customers receive that level of retail water service at more affordable rates. The utility may establish a fund to receive donations to cover the cost of providing the reduced rates. A utility may not recover the cost of the reduced rates through charges to other customer classes.

(i) To request approval of a rate as defined in this subparagraph, the utility must file a proposed plan for consideration by the commission. The plan must include:

(I) A proposed plan for collection of donations to establish a fund to recover the costs of providing the reduced rates.

(II) The account or subaccount name and number, as included in the system of accounts described in §24.127(1) of this title (relating to Financial Records and Reports--Uniform System of Accounts), in which the donations will be accounted for, and a clear definition of how the administrative costs of operation of the program will be accounted for and removed from the cost of service for rate making purposes. Any interest earned on donated funds will be considered a donation to the fund.

(III) The proposed effective date of the program and an example of an annual accounting for donations received and a calculation of all lost revenues and the journal entries that transfer the funds from the account described in this subparagraph of this clause to the utility's revenue account. The annual accounting must be available for audit by the commission upon request.

(IV) An example bill with the contribution line item, if receiving contributions from customers.

(ii) For the purpose of clause (i) of this subparagraph, recovery of lost revenues from donations is limited to the lost revenues due to the difference in the utility's tariffed retail water rates and the reduced rates established by this subparagraph.

(iii) The minimal level of retail water service requested by the utility must not exceed 3,000 gallons per month per connection. Additional gallons used must be billed at the utility's tariffed rates.

(iv) For purposes of the provision in this subparagraph, a reduced rate authorized under this section does not:

(I) Make or grant an unreasonable preference or advantage to any corporation or person;

(II Subject a corporation or person to an unreasonable prejudice or disadvantage; or

(III) Constitute an unreasonable difference as to retail water rates between classes of service.

(C) If a utility has provided notice as required in subparagraph (F) of this paragraph, the commission may approve a pass-through provision as a minor tariff change, even if the utility has never had an approved pass-through provision in its tariff. A pass-through provision may not be approved for a charge already included in the utility's cost of service used to calculate the rates approved by the commission in the utility's most recently approved rate change under TWC §§ 13.187, 13.1871, 13.18715, or 13.1872. A pass-through provision may only include passing through of the actual costs charged to the utility. Only the commission staff or the utility may request a hearing on a proposed pass-through provision or a proposed revision or change to a pass-through provision. A pass-through provision may be approved as follows:

(i) A utility that purchases water or sewage treatment and whose rates are under the original jurisdiction of the commission may include a provision in its tariff to pass through to its customers changes in such costs. The provision must specify how it is calculated.

(ii) A utility may pass through a temporary water rate provision implemented in response to mandatory reductions in water use imposed by a court, government agency, or other authority. The provision must specify how the temporary water rate provision is calculated.

(iii) A utility may include the addition of a production fee charged by a groundwater conservation district, including a production fee charged in accordance with a groundwater reduction plan entered in to by a utility in response to a groundwater conservation district production order or rule, as a separate line item in the tariff.

(iv) A utility may pass through the costs of changing its source of water if the source change is required by a governmental entity. The pass-through provision may not be effective prior to the date the conversion begins. The pass-through provision must be calculated using an annual true-up provision.

(v) A utility subject to more than one pass-through cost allowable in this section may request approval of an overall combined pass-through provision that includes all allowed pass-through costs to be recovered in one provision under subparagraph (D) of this paragraph. The twelve calendar months (true-up period) for inclusion in the true-up must remain constant, e.g., January through December.

(vi) A utility that has a combined pass-through provision in its approved tariff may request to amend its tariff to replace the combined pass-through provision with individual pass-through provisions if all revenues and expenses have been properly trued up in a true-up report and all overcollections have been credited back to the customers. A utility that has replaced its previously approved combined pass-through provision with individual provisions may not request another combined pass-through until three years after the replacement has been approved unless good cause is shown.

(D) A change in the combined pass-through provision may be implemented only once per year. The utility must file a true-up report within one month after the end of the true-up period. The report must reconcile both expenses and revenues related to the combined pass-through charge for the true-up period. If the true-up report reflects an over-collection from customers, the utility must change its combined pass-through rate using the confirmed rate changes to charges being passed through and the over-collection from customers reflected in the true-up report. If the true-up report does not reflect an over-collection from the customers, the implementation of a change to the pass-through rate is optional. The change may be effective in a billing cycle within three months after the end of the true-up period as long as the true-up clearly shows the reconciliation between charges by pass-through entities and collections from the customers, and charges from previous years are reconciled. Only expenses charged by the pass-through provider may be included in the provision. The true-up report must include:

(i) a list of all entities charging fees included in the combined pass-through provision, specifying any new entities added to the combined pass-through provision;

(ii) a summary of each charge passed through in the report year, along with documentation verifying the charge assessed and showing the amount the utility paid;

(iii) a comparison between annual amounts billed by all entities charging fees included in the pass-through provision with amounts billed for the usage by the utility to its customers in the pass-through period;

(iv) all calculations and supporting documentation;

(v) a summary report, by year, for the lesser of all years prior or five years prior to the pass-through period showing the same information as in clause (iii) of this subparagraph with a reconciliation to the utility's booked numbers, if there is a difference in any year; and

(vi) any other documentation or information requested by the commission.

(E) For any pass-through provision granted under this section, all charges approved for recovery of pass-through costs must be stated separately from all charges by the utility to recover the revenue requirement. Except for a combined pass-through provision, the calculation for a pass-through gallonage rate for a utility with one source of water may be made using the following equation, which is provided as an example: R=G /(1-L), where R is the utility's new proposed pass-through rate, G equals the new gallonage charge by source supplier or conservation district, and L equals the actual line loss reflected as a percentage expressed in decimal format (for example, 8.5% would be expressed as 0.085). Line loss will be considered on a case-by-case basis.

(F) A utility that requests to revise or implement an approved pass-through provision must take the following actions prior to the beginning of the billing period in which the revision takes effect:

(i) file a written notice with the commission that must include:

(I) each affected CCN number;

(II) a list of each affected subdivision public water system (including name and corresponding number issued by the TCEQ), and water quality system (including name and corresponding number issued by the TCEQ), if applicable;

(III) a copy of the notice to the customers;

(IV) documentation supporting the stated amounts of any new or modified pass-through costs;

(V) historical documentation of line loss for one year;

(VI) all calculations and assumptions for any true-up of pass-through costs;

(VII) the calculations and assumptions used to determine the new rates; and

(VIII) a copy of the pages of the utility's tariff that contain the rates that will change if the utility's application is approved; and

(ii) e-mail (if the customer has agreed to receive communications electronically), mail, or hand-deliver notice to the utility's customers. Notice may be in the form of a billing insert and must contain:

(I) the effective date of the change;

(II) the present calculation of customer billings;

(III) the new calculation of customer billings;

(IV) an explanation of any corrections to the pass-through formula, if applicable;

(V) the change in charges to the utility for purchased water or sewer treatment or ground water reduction fee or subsidence, if applicable; and

(VI) the following language: "This tariff change is being implemented in accordance with the minor tariff changes allowed by 16 Texas Administrative Code §24.25. The cost to you as a result of this change will not exceed the costs charged to your utility."

(G) The following provisions apply to surcharges:

(i) A surcharge is an authorized rate to collect revenues over and above the usual cost of service.

(ii) If authorized by the commission or the municipality exercising original jurisdiction over the utility, a surcharge to recover the actual increase in costs to the utility may be collected over a specifically authorized time period without being listed on the approved tariff for:

(I) sampling fees not already recovered by rates;

(II) inspection fees not already recovered by rates;

(III) production fees or connection fees not already recovered by rates charged by a groundwater conservation district; or

(IV) other governmental requirements beyond the control of the utility.

(iii) A utility must use the revenues collected through a surcharge approved by the commission to cover the costs listed in paragraph (G)(ii) of this subsection or for any purpose noted in the order approving the surcharge. The utility may redirect or use the revenues for other purposes only after first obtaining the approval of the commission.

(iv) The commission may require a utility to file periodic and/or final accounting information to show the collection and disbursement of funds collected through an approved surcharge.

(3) Tariff revisions and tariffs filed with rate changes.

(A) If the commission is the regulatory authority, the utility must file its revisions with the commission. If a proposed tariff revision constitutes an increase in existing rates of a particular customer class or classes, then the commission may require that notice be given.

(B) Each revision must be accompanied by a copy of the original tariff and a red-lined copy of the proposed tariff revisions clearly showing the proposed changes.

(4) Rate schedule. Each rate schedule must clearly state:

(A) the name of each public water system and corresponding identification number issued by the TCEQ, or the name of each sewer system and corresponding identification number issued by the TCEQ for each discharge permit, to which the schedule is applicable; and

(B) the name of each subdivision, city, and county in which the schedule is applicable.

(5) Tariff pages. Tariff pages must be numbered consecutively. Each page must show section number, page number, name of the utility, and title of the section in a consistent manner.

(c) Composition of tariffs. A utility's tariff, including those utilities operating within the corporate limits of a municipality, must contain sections setting forth:

(1) a table of contents;

(2) a list of the cities, counties, and subdivisions in which service is provided, along with each public water system name and corresponding identification number issued by the TCEQ and each sewer system name and corresponding discharge permit number(s) issued by the TCEQ to which the tariff applies;

(3) each CCN number under which service is provided;

(4) the rate schedules;

(5) the service rules and regulations, including forms of the service agreements, if any, and customer service inspection forms to be completed as required by the TCEQ;

(6) the extension policy;

(7) an approved drought contingency plan as required by the TCEQ; and

(8) the forms of payment to be accepted for utility services.

(d) Tariff filings in response to commission orders. Tariff filings made in response to an order issued by the commission must include a transmittal letter stating that the tariff attached is in compliance with the order, giving the docket number, date of the order, a list of tariff pages filed, and any other necessary information. Any service rules proposed in addition to those listed on the commission's tariff form or any modifications of a rule in the tariff must be clearly noted. All tariff pages must comply with all other sections in this chapter and must include only changes ordered. The effective date and/or wording of the tariff must comply with the provisions of the order.

(e) Availability of tariffs. Each utility must make available to the public at each of its business offices and designated sales offices within Texas all of its tariffs currently on file with the commission or regulatory authority, and its employees must lend assistance to persons requesting information and afford these persons an opportunity to examine any such tariffs upon request. The utility must also provide copies of any portion of the tariffs at a reasonable cost to a requesting party.

(f) Rejection. Any tariff filed with the commission and found not to be in compliance with this section must be returned to the utility with a brief explanation of the reasons for rejection.

(g) Change by other regulatory authorities. Each utility operating within the corporate limits of a municipality exercising original jurisdiction must file with the commission its current tariff that has been authorized by the municipality. If changes are made to the utility's tariff for one or more service areas under the jurisdiction of the municipality, the utility must file its tariff reflecting the changes along with the ordinance, resolution or order issued by the municipality to authorize the change.

(h) Effective date. The effective date of a tariff change is the date of approval by the regulatory authority, unless otherwise specified by the regulatory authority, in a commission order, or by rule. The effective date of a proposed rate increase under TWC §§13.187, 13.1871, 13.18715, or 13.1872 is the proposed date on the notice to customers and the regulatory authority, unless suspended by the regulatory authority.

(i) Tariffs filed by water supply or sewer service corporations. A water supply or sewer service corporation must file with the commission, for informational purposes only, its tariff showing all rates that are subject to the appellate jurisdiction of the commission and that are in force for any utility service, product, or commodity offered. The tariff must include all rates, rules, and regulations relating to utility service or extension of service, each CCN number under which service is provided, and all affected counties or cities. If changes are made to the water supply or sewer service corporation's tariff, the water supply or sewer service corporation must file the tariff reflecting the changes, along with a cover letter with the effective date of the change. Tariffs filed under this subsection must be filed in conformance with §22.71 of this title (relating to Filing of Pleadings, Documents, and Other Materials) and §22.72 of this title (relating to Formal Requisites of Pleadings and Documents to be Filed with the Commission).

(j) Temporary water rate provision for mandatory water use reduction.

(1) A utility's tariff may include a temporary water rate provision that will allow the utility to increase its retail customer rates during periods when a court, government agency, or other authority orders mandatory water use reduction measures that affect the utility customers' use of water service and the utility's water revenues. Implementation of the temporary water rate provision will allow the utility to recover revenues that the utility would otherwise have lost due to mandatory water use reductions. If a utility obtains an alternate water source to replace the required mandatory reduction during the time the temporary water rate provision is in effect, the temporary water rate provision must be adjusted to prevent over-recovery of revenues from customers. A temporary water rate provision may not be implemented if an alternative water supply is immediately available without additional cost.

(2) The temporary water rate provision must be approved by the regulatory authority having original jurisdiction in a rate proceeding before it may be included in the utility's approved tariff or implemented as provided in this subsection. A proposed change in the temporary water rate provision must be approved in a rate proceeding. A utility that has filed a rate change within the last 12 months may file a request for the limited purpose of obtaining a temporary water rate provision.

(3) A utility may request a temporary water rate provision for mandatory water use reduction using the formula in this paragraph to recover 50% or less of the revenues that would otherwise have been lost due to mandatory water use reductions. The formula for a temporary water rate provision for mandatory water use reduction under this paragraph is TGC = cgc + [(prr)(cgc)(r)/(1.0-r)] where: TGC = Temporary gallonage charge; cgc = current gallonage charge; r = water use reduction expressed as a decimal fraction (the pumping restriction); and prr = percentage of revenues to be recovered expressed as a decimal fraction (i.e., 50% = 0.5).

(A) The utility must file a request for a temporary water rate provision for mandatory water use reduction and provide customer notice as required by the regulatory authority, but is not required to provide complete financial data to support its existing rates. Notice must include a statement of when the temporary water rate provision would be implemented, a list of all customer classes affected, the rates affected, information on how to protest or intervene in the rate change, the address of the regulatory authority, the time frame for protests, and any other information that is required by the regulatory authority. The utility's existing rates are not subject to review in this proceeding and the utility is only required to support the need for the temporary rate. A request for a temporary water rate provision for mandatory water use reduction under this paragraph is not considered a statement of intent to increase rates subject to the 12-month limitation in §24.29 of this title (relating to Time Between Filings).

(B) The utility must establish that the projected revenues that will be generated by the temporary water rate provision are required by the utility to pay reasonable and necessary expenses that will be incurred by the utility during the time mandatory water use reductions are in effect.

(4) A utility may request a temporary water rate provision for mandatory water use reduction using the formula in paragraph (3) of this subsection or any other method acceptable to the regulatory authority to recover up to 100% of the revenues that would otherwise have been lost due to mandatory water use reductions.

(A) If the utility requests authorization to recover more than 50% of lost revenues, the utility must submit financial data to support its existing rates as well as the temporary water rate provision for mandatory water use reduction even if no other rates are proposed to be changed. The utility's existing rates are subject to review in addition to the temporary water rate provision for mandatory water use reduction.

(B) The utility must establish that the projected revenues that will be generated by the temporary water rate provision for mandatory water use reduction are required by the utility to pay reasonable and necessary expenses that will be incurred by the utility during the time mandatory water use reductions are in effect; that the rate of return granted by the regulatory authority in the utility's last rate case does not adequately compensate the utility for the foreseeable risk that mandatory water use reductions will be ordered; and that revenues generated by existing rates do not exceed reasonable cost of service.

(5) The utility may place the temporary water rate provision into effect only after:

(A) it has been approved by the regulatory authority and included in the utility's approved tariff in a prior rate proceeding;

(B) there is an action by a court, government agency, or other authority requiring mandatory water use reduction measures that affect the utility's customers' use of utility services; and

(C) issuing notice as required by paragraph (7) of this subsection.

(6) The utility may readjust its temporary water rate provision to respond to modifications or changes to the original required water use reductions by reissuing notice as required by paragraph (7) of this subsection. If the commission is the regulatory authority, only the commission or the utility may request a hearing on the proposed implementation.

(7) A utility implementing a temporary water rate for mandatory water use reduction must take the following actions prior to the beginning of the billing period in which the temporary water rate provision takes effect:

(A) submit a written notice, including a copy of the notice received from the court, government agency, or other authority requiring the reduction in water use, to the regulatory authority; and

(B) e-mail, if the customer has agreed to receive communications electronically, or mail notice to the utility's customers. Notice may be in the form of a billing insert and must contain the effective date of the implementation and the new rate the customers will pay after the temporary water rate provision is implemented. If the commission is the regulatory authority, the notice must include the following language: "This rate change is being implemented in accordance with the temporary water rate provision approved by the Public Utility Commission of Texas to recognize the loss of revenues due to mandatory water use reduction ordered by (name of entity issuing order). The new rates will be effective on (date) and will remain in effect until the mandatory water use reductions are lifted or expired. The purpose of the rate is to ensure the financial integrity of the utility. The utility will recover through the rate (the percentage authorized by the temporary rate) % of the revenues the utility would otherwise have lost due to mandatory water use reduction by increasing the volume charge from ($ per 1,000 gallons to $ per 1,000 gallons)."

(8) A utility must stop charging a temporary water rate provision as soon as is practicable after the order that required mandatory water use reduction is ended, but in no case later than the end of the billing period that was in effect when the order was ended. The utility must notify its customers of the date that the temporary water rate provision ends and that its rates will return to the level authorized before the temporary water rate provision was implemented. The notice provided to customers regarding the end of the temporary water rate provision must be filed with the commission.

(9) If the regulatory authority initiates an inquiry into the appropriateness or the continuation of a temporary water rate provision, it may establish the effective date of its decision on or after the date the inquiry is filed.

(k) Regional rates. The regulatory authority, where practicable, will consolidate the rates by region for applications submitted by a Class A, B, or C utility, or a Class D utility filing under TWC §13.1872(c)(2), with a consolidated tariff and rate design for more than one system.

(l) Energy cost adjustment clause.

(1) A utility that purchases energy (electricity or natural gas) that is necessary for the provision of retail water or sewer service may request the inclusion of an energy cost adjustment clause in its tariff to allow the utility to adjust its rates to reflect increases and decreases in documented energy costs.

(2) A utility that requests the inclusion of an energy cost adjustment clause in its tariff must file a request with the commission. The utility must also give notice of the proposed energy cost adjustment clause by mail, either separately or accompanying customer billings, by e-mail, or by hand delivery to all affected utility customers at least 60 days prior to the proposed effective date. Proof of notice in the form of an affidavit stating that proper notice was delivered to affected customers and stating the date of such delivery must be filed with the commission by the utility as part of the request. Notice must be provided on a form prescribed by the commission and must contain the following information:

(A) the utility name and address, a description of how the increase or decrease in energy costs will be calculated, the effective date of the proposed change, and the classes of utility customers affected. The effective date of the proposed energy cost adjustment clause must be the first day of a billing period, which should correspond to the day of the month when meters are typically read, and the clause may not apply to service received before the effective date of the clause;

(B) information on how to submit comments regarding the energy cost adjustment clause, the address of the commission, and the time frame for comments; and

(C) any other information that is required by the commission.

(3) The commission's review of the utility's request is not subject to a contested case hearing. However, the commission will hold a public meeting if requested by a member of the legislature who represents an area served by the utility or if the commission determines that there is substantial public interest in the matter.

(4) Once an energy cost adjustment clause has been approved, documented changes in energy costs must be passed through to the utility's customers within a reasonable time. The pass-through, whether an increase or decrease, must be implemented on at least an annual basis, unless the commission determines otherwise. Before making a change to the energy cost adjustment clause, notice must be provided as required by paragraph (5) of this subsection. Copies of notices to customers must be filed with the commission.

(5) Before a utility implements a change in its energy cost adjustment clause as required by paragraph (4) of this subsection, the utility must take the following actions prior to the beginning of the billing period in which the implementation takes effect:

(A) submit written notice to the commission, which must include a copy of the notice sent to the customers, proof that the documented energy costs have changed by the stated amount; and

(B) e-mail, if the customer has agreed to receive communications electronically, mail, either separately or accompanying customer billings, or hand deliver notice to the utility's affected customers. Notice must contain the effective date of change and the increase or decrease in charges to the utility for documented energy costs. The notice must include the following language: "This tariff change is being implemented in accordance with the utility's approved energy cost adjustment clause to recognize (increases) (decreases) in the documented energy costs. The cost of these charges to customers will not exceed the (increase) (decrease) in documented energy costs."

(6) The commission may suspend the adoption or implementation of an energy cost adjustment clause if the utility has failed to properly file the request or has failed to comply with the notice requirements or proof of notice requirements. If the utility cannot clearly demonstrate how the clause is calculated, the increase or decrease in documented energy costs or how the increase or decrease in documented energy costs will affect rates, the commission may suspend the adoption or implementation of the clause until the utility provides additional documentation requested by the commission. If the commission suspends the adoption or implementation of the clause, the adoption or implementation will be effective on the date specified by the commission.

(7) Energy cost adjustment clauses may not apply to contracts or transactions between affiliated interests.

(8) A proceeding under this subsection is not a rate case under TWC §§13.187, 13.1871, 13.18715, or 13.1872.

§24.26. Test Year.

(a) Applicability. This section applies to a person under the original rate jurisdiction of the commission who is seeking to obtain or amend an approved tariff in accordance with §24.25 of this title (relating to Form and Filing of Tariffs) and establish rates using a test year.

(b) Definitions. The following terms, when used in this section, have the following meanings unless the context indicates otherwise:

(1) Base period--the most recent consecutive 36 month period beginning on the first day of a calendar- or fiscal-year quarter for which operating data for a retail public utility is available. A base period must include historical data. The commission may, for good cause shown, authorize a shorter base period for a utility that has operated for less than 36 months.

(2) Future data--data relied upon by the utility to determine its forecasted, projected, or estimated costs, usage, revenues, adjustments, and other information of the utility that corresponds with the portion of the combined test year that immediately follows the utility filing its statement of intent to change rates, or the future test year, as applicable.

(3) Historical data--data relied upon by the utility to support its actually incurred costs, usage, revenues, adjustments, and other information of the utility. Historical data may include, as one component, the utility's annual reports filed in accordance with §24.129 of this title (relating to Water and Sewer Utility Annual Reports).

(c) General requirements for tariffs.

(1) Requirements applicable to new utilities. This paragraph applies only to a utility that has obtained an approved tariff for the first time and, unless otherwise required by the commission, is not applicable to an existing utility that has obtained an approved tariff for an acquired water or sewer system.

(A) Within 30 months from the date service begins, a utility must file a rate change application to revise its rates to be based on a test year. A Class D utility must file a rate change application under TWC §13.1872(c)(2) to satisfy the requirements of this paragraph.

(B) For a rate change application that utilizes a historic test year, any dollar amount collected under the rates that were initially approved by the commission that exceeds the revenue requirement established by the commission during the rate change proceeding must, for ratemaking purposes, be reflected as customer contributed capital going forward as an offset to rate base.

(2) Utility designation of test year.

(A) A utility must present a test year that complies with the definition under §24.3 of this title (relating to Definitions).

(B) If the test year selected by the utility is a combined test year or a future test year, the test year must include future data and the rate change application must identify a base period.

(C) A utility is limited to using one test year in a base rate proceeding.

(3) Application requirements. A utility must provide evidence in its rate change application that its proposed rates are just and reasonable using its selected test year, including information in support of its selected test year used to establish rates. Such information must include:

(A) known and measurable changes which must be demonstrated using the applicant's test year information, audited financial accounts, billing system extracts, or other records such as the utility's annual report under §24.129 of this title;

(B) supporting documentation, testimony, or other relevant information that supports the utility's selected test year and requested amounts;

(C) if the utility selects a combined test year or a future test year, any documentation testimony, or other information supporting the following.

(i) For a utility seeking an increase in its revenue requirement that is attributable to inflation, any forecasts, estimates, or projections based on inflation must be separately categorized by, and proportional to an inflation index published by the United States Department of Labor, Bureau of Labor Statistics (e.g., the Gross Domestic Product Price Index (GDPPI) or the Consumer Price Index (CPI)). Information accounting for inflation must be included for any portion of a test year with future data.

(ii) documentation and explanation supporting the reasonableness of any forecasts, projections or estimates sufficient to substantiate the methodology or calculations associated with each forecast, projection, or estimate (e.g., expected changes in cost and billing determinants, forecasted revenue adjustments,) for any portion of a test year with future data.

(D) a workpaper index or ledger for the information provided in accordance with subparagraphs (A) - (C) of this paragraph, as applicable, with cross-references identifying information category by page number; and

(E) an attestation by an executive officer or owner of the utility that all information provided under subparagraphs (A) - (D) of this paragraph is true, accurate, and complete.

(d) Base rate change application requirements. A base rate change application must comply with this subsection as well as the form and content requirements included in the commission-prescribed forms and instructions applicable to the utility's class.

(1) Application content based on test year. In addition to the requirements of §24.25 and §24.27, a base rate change application must comply with the applicable requirements prescribed under this paragraph based on the utility's selected test year.

(A) Historic test year content requirements. If the applicant selects a historic test year, the application must include information on, and comparisons of, revenues and costs between:

(i) the historic test year; and

(ii) the time periods specified by the commission-prescribed forms and instructions applicable to the utility's class.

(B) Combined test year or future test year content requirements. If the applicant selects a combined test year or a future test year, the application must include information on, and comparisons of, revenues and costs between:

(i) the base period;

(ii) the time periods specified by the commission-prescribed forms and instructions applicable to the utility's class; and

(iii) as applicable, the combined test year or the future test year, inclusive of any forecasts, projections, or estimates.

(2) Application content requirements. A base rate change application must, at a minimum:

(A) as applicable for each schedule or workpaper, be itemized by each individual rate or fee, usage, calendar month, type of expense, applicable utility account, and by each customer class;

(B) include the utility's actual costs and revenues, including any adjustments for known and measurable changes, annualizations, or normalizations but excluding inflation;

(C) include any relevant data, attachments, or supplementary materials filed in their native format and, if applicable, with formulas intact; and

(D) be word-searchable.

(e) Review of combined test year or future test year. A combined test year or a future test year will be reviewed by the commission in accordance with §24.28 of this title (relating to Review of Test Year).

§24.27. Notice of Intent and Application to Change Rates.

(a) Purpose. This section describes the requirements for the contents of an application to change rates and the requirements for the provision of notice of an application to change rates filed by a Class A, B, or C utility, or a Class D utility filing under Texas Water Code (TWC) §13.1872(c)(2).

(b) Contents of the application. An application to change rates is initiated by the filing of the applicable rate filing package, a statement of intent to change rates, and the proposed form and method of notice to customers and other affected entities under subsection (c) of this section.

(1) The application must:

(A) include the commission's rate filing package form; and

(B) include all required schedules;

(C) be based on a test year;

(D) indicate whether the test year is a historic, future, or combined test year; and

(E) include the applicable information required under §24.26 of this title (relating to Test Year).

(2) For an application filed by a Class A utility, the rate filing package, including each schedule, must be supported by pre-filed direct testimony. The pre-filed direct testimony must be filed at the same time as the application to change rates.

(3) For an application filed by a Class B utility, Class C utility, or Class D utility filing under TWC §13.1872(c)(2), the applicable rate filing package, including each schedule, must be supported by affidavit. The affidavit must be filed at the same time as the application to change rates. The utility may file pre-filed direct testimony at the same time as the application to change rates. If the application is set for a hearing, the presiding officer may require the filing of pre-filed direct testimony at a later date.

(4) Proof of notice. Proof of notice in the form of an affidavit stating that proper notice was mailed, e-mailed, or delivered to customers and affected municipalities and stating the dates of such delivery must be filed with the commission by the applicant utility as part of the rate change application.

(c) Notice requirements specific to applications filed by a Class A Utility under TWC §13.187.

(1) Notice of the application. In order to change rates under TWC §13.187, a utility must comply with the following requirements at least 35 days before the effective date of the proposed change.

(A) The utility must file a statement of intent (notice) with the commission and provide a copy of the notice to all customers of the utility affected by the proposed rate change, to the appropriate offices of each municipality affected by the proposed rate change, and to the Office of Public Utility Counsel.

(B) Notice must be provided using the commission-approved form and must include a description of the process by which a ratepayer may intervene in the proceeding.

(C) This notice must state the docket number assigned to the rate application. Prior to the provision of notice, the utility must file a request for the assignment of a docket number for the rate application.

(D) Notices to affected ratepayers may be mailed separately, e-mailed (if the customer has agreed to receive communications electronically), or may accompany customer billings.

(E) Notice is considered to be completed upon mailing, e-mailing (if the customer has agreed to receive communications electronically), or hand delivery.

(2) Notice of the hearing. After the rate application is set for a hearing, the commission will give reasonable notice of the hearing, including notice to the governing body of each affected municipality and county. The commission may require the utility to complete this notice requirement. The commission may delegate to an administrative law judge of the State Office of Administrative Hearings the responsibility and authority to give reasonable notice of the hearing, including notice to the governing body of each affected municipality and county.

(d) Notice requirements specific to applications filed by Class B, C, and D utilities.

(1) Notice of the application. In order to change rates, a Class B or C utility, or a Class D utility filing under TWC §13.1872(c)(2), must comply with the following requirements at least 35 days before the effective date of the proposed change.

(A) The utility must file a notice with the commission and provide a copy of the notice to all customers of the utility affected by the proposed rate change, to the appropriate offices of each municipality affected by the proposed rate change, and to the Office of Public Utility Counsel.

(B) Notice must be provided using the commission-approved form and must include a description of the process by which a ratepayer may file a protest under TWC §13.1871(i).

(C) The notice must state the docket number assigned to the rate application. Prior to providing notice, a Class B or C utility, or a Class D utility filing under TWC §13.1872(c)(2), must file a request for the assignment of a docket number for the rate application.

(D) Notices to affected ratepayers may be mailed separately, e-mailed (if the customer has agreed to receive communications electronically), or may accompany customer billings.

(E) Notice is considered to be completed upon mailing, e-mailing (if the customer has agreed to receive communications electronically), or hand delivery.

(2) Notice of the hearing. After the rate application is set for a hearing, the following notice requirements apply.

(A) The commission will give reasonable notice of the prehearing conference, including notice to the governing body of each affected municipality and county. The commission may require the utility to provide this notice. The commission may delegate to an administrative law judge of the State Office of Administrative Hearings the responsibility and authority to give reasonable notice for the prehearing conference, including notice to the governing body of each affected municipality and county.

(B) A Class B utility must mail notice of the prehearing conference to each affected ratepayer at least 20 days before the prehearing conference.

(C) A Class C utility, or a Class D utility filing under TWC §13.1872(c)(2), must mail, e-mail, or hand deliver notice of the prehearing conference to each affected ratepayer at least 20 days before the prehearing conference.

(D) A notice provided under subparagraph (B) or (C) of this paragraph must include a description of the process by which a ratepayer may intervene in the proceeding.

(e) Line extension and construction policies. A request to approve or amend a utility's line extension and construction policy must be filed in a rate change application under TWC §§13.187, 13.1871, 13.18715, or 13.1872(c)(2). The application must include the proposed tariff and other information requested by the commission. The request may be made with a request to change one or more of the utility's other rates.

(f) Capital improvements surcharge. In a rate proceeding under TWC §§13.187, 13.1871, 13.18715, or 13.1872(c)(2), the commission may approve a surcharge to collect funds for capital improvements necessary to provide facilities capable of providing continuous and adequate utility service, and for the preparation of design and planning documents.

(g) Debt repayments surcharge. In a rate proceeding under TWC §§13.187, 13.1871, 13.18715, or 13.1872(c)(2), the commission may approve a surcharge to collect funds for debt repayments and associated costs, including funds necessary to establish contingency funds and reserve funds. Surcharge funds may be collected to meet all the requirements of the Texas Water Development Board regarding financial assistance from the Safe Drinking Water Revolving Fund.

§24.28. Review of Test Year.

(a) Applicability This section applies to a utility that elects to use a combined test year or a future test year under §24.26 of this title (relating to Test Year) and whose application was processed to a final decision and approval of a tariff by the commission.

(b) Definitions. The following terms, when used in this section, have the following meanings unless the context indicates otherwise:

(1) Actual test year results- for a utility that selected a combined test year or future test year in its most recent base rate proceeding, the utility's actual costs and revenues incurred during the test year.

(2) Fair return- the utility's overall rate of return established by the commission in the utility's most recently completed base rate proceeding.

(3) Projected test year data- any combined test year or future test year information used to establish a utility's rates in the utility's most recently completed base rate proceeding. At a minimum, such data must include:

(A) capital projects, including construction work in progress (CWIP) established by the utility to be used and useful through the end of the test year in accordance with §24.41 of this title (relating to Cost of Service);

(B) allocation and rate design information, including billing determinants;

(C) rate base information and underlying methodologies used for forecasted amounts (e.g., accumulated deferred income taxes and accumulated depreciation); and

(D) expense information (e.g., operations and maintenance expense, depreciation, and taxes including federal income tax).

(c) Post-test year report. A utility that selected a combined test year or future test year and whose application was processed to a final decision and approval of a tariff by the commission or its successor in interest must comply with this subsection, as applicable. The information required under this subsection must be filed in the commission-assigned compliance docket opened for that purpose.

(1) The written statement required under subparagraph (2)(A) of this subsection must be included as an attachment to or incorporated by reference into the utility's next annual report required by §24.129 of this title; and

(2) No later than the 30th day after the last day of the last quarter of the combined test year or the future test year the utility must:

(A) file a written statement that:

(i) describes the utility's actual cost and revenue results experienced in the test year being reported; and

(ii) includes appropriate data to demonstrate the accuracy of the projected test year data against the utility's actual results, including any necessary comparative analyses, testimony, workpapers, or other supporting documentation;

(B) serve a copy of the written statement described under subparagraph (A) of this paragraph on the persons that were parties of record at the conclusion of the rate proceeding in which the final rate determination using the combined test year or the future test year was entered; and

(C) either file proof of notice in the form of an affidavit or include a certificate of service that states notice was properly served on all parties of record in the rate proceeding corresponding to the compliance docket in accordance with subparagraph (B) of this subparagraph.

(3) A utility or its successor in interest that does not have the actual test year results required to perform the actions listed under paragraph (2) of this subsection by the specified date must:

(A) file a written notice with the commission that:

(i) states the date on which the results or data will be available;

(ii) provides a list of the results or data that are unavailable; and

(iii) includes a brief explanation of why the results or data are unavailable;

(B) perform the actions specified by paragraph (1) of this subsection as soon as possible after the results or data are available, but no later than the 90th day after the last day of the last quarter of the combined test year or the future test year.

(d) Retrospective analysis of combined test year or future test year.

(1) General requirements for utility retrospective analysis.

(A) A utility must file a retrospective analysis in its next base rate proceeding.

(B) A utility's actual test year results must be presented in a manner consistent and comparable with its projected test year data.

(2) Contents of retrospective analysis. A retrospective analysis must include:

(A) a full accounting of the utility's projected test year data presented in its immediately previous base rate case compared to its actual test year results using the information provided in the utility's post-test year report required under subsection (c) of this section;

(B) information regarding the utility's actual rate of return earned during the test year that enables the commission to determine whether the utility's actual test year results yielded a fair return on its invested capital used and useful in rendering service to the public;

(C) the docket number of the compliance docket in which the utility filed its post-test year report; and

(D) a description and quantification of events that occurred during the test year that impacted the utility's actual test year results which may include:

(i) events affecting service to critical customers;

(ii) natural disasters or other system emergencies that result in conditions on the utility's system that were likely to result in imminent, significant disruption of service to customers or were likely to endanger life or property;

(iii) unplanned circumstances that affected or were likely to affect continuous and adequate service or otherwise resulted in deviation from its projected test year data; and

(iv) other circumstances resulting in a deviation from its projected test year data.

(e) Commission review of forecasts or projections. The commission will review a utility's retrospective analysis described under subsection (d) exclusively in the docket assigned to the utility's base rate case and in the manner described by this subsection.

(1) Scope of review.

(A) The commission will review the utility's retrospective analysis and actual revenues to determine whether:

(i) the utility's projected test year data, in comparison to the utility's actual test year results, resulted in rates yielding more than a fair return on the utility's invested capital used and useful in rendering service to the public; and

(ii) the approximate magnitude of any excess revenues collected.

(B) The commission may review the utility's retrospective analysis and actual revenues to:

(i) determine whether the utility's projected test year data reasonably aligned with the utility's actual test year results, accounting for all mitigating factors described under subsection (d)(2)(D) of this section that are provided by the utility; or

(ii) identify any rate base items that were not used and useful in providing service to customers through the end of the test year, including any attendant impacts on expenses or rates.

(2) Procedural schedule.

(A) The presiding officer will account for a retrospective analysis in the procedural schedule for a base rate proceeding, including the appropriate scope of discovery.

(B) The presiding officer may open a compliance docket to effectuate a refund under subsection (f) of this section.

(3) Commission action.

(A) Upon a finding that a utility's actual test year results yielded more than a fair return under subparagraph (1)(A) of this subsection, the commission will order a refund in accordance with subsection (f) of this subsection.

(B) The commission will perform any other action necessary to ensure just and reasonable rates at the conclusion of a retrospective analysis or the contemporaneous base rate proceeding, as determined by the presiding officer.

(4) Additional information. The presiding officer may require the utility to provide additional documentation necessary to evaluate the retrospective analysis under this subparagraph, including additional data, studies, or other information.

(f) Refund.

(1) If the commission determines a refund is required in accordance with subsection (e)(3)(A) of this section, the commission will:

(A) determine the rate for the utility that would have yielded a fair return on the utility's invested capital used and useful in rendering service to the public and require a refund to customers, which must include carrying costs; and

(B) require the utility to refund to customers the difference between the revenues collected and the revenues that would have been collected under the rates that would have yielded a fair return plus any carrying costs.

(2) The commission will determine the form and manner of a refund in accordance with this paragraph.

(A) Earnings that exceed a utility's fair return must be separately tracked as a regulatory liability.

(B) With regard to any allocations or rate design treatment, a refund under this subsection must be applied among customers in a manner reasonably proportional to the magnitude in which the excessive rates were collected relative to rates that would have yielded a fair return.

(3) Carrying costs for a refund will be determined in accordance with this clause:

(A) For the time period beginning with the date on which over-recovery is determined to have begun to the effective date of the new base rates, carrying costs must be calculated using the same rate of return that was applied to the investments in the utility's base rate proceeding that resulted in the over-recovery.

(B) For the time period beginning with the effective date of the new base rates, carrying costs must be calculated using the utility's rate of return authorized in the base rate proceeding.

§24.41. Cost of Service.

(a) Components of cost of service. Rates are based upon a utility's cost of rendering service. The two components of cost of service are allowable expenses and return on rate base.

(b) Allowable expenses. Only those expenses that are reasonable and necessary to provide service to the ratepayers may be included in allowable expenses. In computing a utility's allowable expenses, only the utility's test year expenses will be considered. A change in rates must be based on a test year as defined in §24.3 of this title (relating to Definitions of Terms) and, as applicable, comply with the requirements of §24.26 (relating to Test Year). Payments to affiliated interests for costs of service, or any property, right, or thing, or for interest expense are not allowed as an expense for cost of service except as provided in Texas Water Code (TWC) §13.185(e).

(1) Components of allowable expenses. Allowable expenses, to the extent they are reasonable and necessary, may include, but are not limited to, the following general categories:

(A) Operations and maintenance expense incurred in furnishing normal utility service and in maintaining utility plant used by and useful to the utility in providing such service.

(B) Depreciation expense based on original cost and computed on a straight-line basis over the useful life of the asset as approved by the commission.

(i) Depreciation expense is allowed on all depreciable utility property owned by the utility, including CWIP reasonably projected to be in service during a combined test year or future test year, and depreciable utility plant, property and equipment retired by the utility, subject to the requirements of subparagraph (c)(2)(C) of this section. Depreciation expense is not allowed for property provided under explicit customer agreements or funded by customer contributions in aid of construction. Depreciation expense is allowed for all developer or governmental entity contributed property. A utility must calculate depreciation on a straight-line basis over the expected or remaining life of the asset, but is not required to use the remaining life method if salvage value is zero. A utility that does not use group depreciation and proposes to change the useful life of an asset with an accumulated depreciation balance must not change the accumulated depreciation balance and must adjust depreciation expense going forward based on the changed useful life.

(ii) The depreciation accrual for all assets must account for expected net salvage value in the calculation of the depreciation rate and actual net salvage value related to retired plant. The utility must submit sufficient evidence with the application establishing that the estimated salvage value, including removal costs, is reasonable. For a utility that uses group accounting, salvage value will be applied to the asset group in depreciation studies. For a utility that uses itemized accounting, salvage value will be applied to specific assets

(C) Assessments and taxes other than income taxes.

(D) Federal income taxes on a normalized basis. Federal income taxes must be computed according to the provisions of TWC §13.185(f), if applicable.

(E) Funds expended in support of membership in professional or trade associations, provided such associations contribute toward the professionalism of their membership.

(F) Advertising, contributions and donations. The actual test year expenditures for advertising, contributions, and donations may be allowed as a cost of service provided that the total sum of all such items allowed in the cost of service must not exceed three-tenths of 1.0% (0.3%) of the gross receipts of the utility for services rendered to the public. The following expenses are the only expenses that may be included in the calculation of the three-tenths of 1.0% (0.3%) maximum:

(i) funds expended advertising methods of conserving water;

(ii) funds expended advertising methods by which the consumer can achieve a savings in total utility bills; and

(iii) funds expended advertising water quality protection.

(G) Credit card and electronic payment processing fees. Expenditures or fees charged by banks or companies for accepting and processing credit card, debit card or other forms of electronic payment from customers for water and sewer utility service may be allowed as a cost of service.

(c) Return on rate base. The return on rate base is the rate of return times rate base.

(1) Rate of return. The commission will allow each utility a reasonable opportunity to earn a reasonable rate of return, which is expressed as a percentage of invested capital, and will fix the rate of return in accordance with the following principles.

(A) The return should be reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties.

(B) The commission will consider the utility's cost of capital, which is the composite of the cost of the various classes of capital used by the utility.

(i) Debt capital. The cost of debt capital is the actual cost of debt, plus adjustments for premiums, discounts, and refunding and issuance costs.

(ii) Equity capital. For companies with ownership expressed in terms of shares of stock, equity capital commonly consists of the following classes of stock.

(I) Common stock capital. The cost of common stock capital must be based upon a fair return on its value.

(II) Preferred stock capital. The cost of preferred stock capital is its annual dividend requirement, if any, plus an adjustment for premiums, discounts, and cost of issuance.

(C) The commission will consider the efforts and achievements of the utility in the conservation of resources, the quality of the utility's services, the efficiency of the utility's operations, and the quality of the utility's management, along with other relevant conditions and practices.

(D) The commission may consider inflation, deflation, the growth rate of the service area, and the need for the utility to attract new capital.

(2) Rate base. The rate of return is applied to the rate base. Assets retired before June 19, 2009, must be removed from rate base before the rate of return is applied to the rate base. Components to be included in determining the rate base are as follows:

(A) If a utility or its facilities were valued using the process for establishing fair market value in Texas Water Code (TWC) §13.305, the dollar value of the "ratemaking rate base," as defined in TWC §13.305(a)(2) and §24.238(b)(4) of this title, relating to Fair Market Valuation, less accumulated depreciation.

(B) Original cost, less accumulated depreciation, of utility plant, property, and equipment used by and useful to the utility during the test year in providing service.

(C) Original cost, less net salvage and accumulated depreciation at the date of retirement, of depreciable utility plant, property and equipment retired by the utility.

(i) For original cost under this subparagraph or subparagraph (B) of this paragraph, the commission may adjust rate base and the rate of return on equity associated with the cost of plant and equipment that has been estimated by trending studies or other methods not based on or verified by historical records.

(ii) Original cost in this subparagraph or subparagraph (B) of this paragraph is the actual money cost, or the actual money value of any consideration paid other than money, of the property at the time it was dedicated to public use, whether by the utility that is the current owner or by a predecessor. Assets may be booked in itemized or group accounting, but all accounting for assets and their retirements must be supported by an approved accounting system.

(iii) On all assets retired from service, the original cost of an asset must be the book cost less net salvage value. If a utility calculates annual depreciation expense for an asset with allowance for salvage value, then it must account for the actual salvage amounts when the asset is actually retired. The utility must include the actual salvage calculation in its net plant calculation in the first full rate change application, excluding alternative rate method applications as described in §24.75 of this title, relating to Alternative Rate Methods, it files after the date on which the asset was removed from service, even if it was not retired during the test year. Recovery of investment on assets retired from service before the estimated useful life or remaining life of the asset must be combined with over-accrual of depreciation expense for those assets retired after the estimated useful life or remaining life and the net amount must be amortized over a reasonable period of time taking into account prudent regulatory principles.

(iv) Accelerated depreciation is not allowed.

(v) For a utility that uses group accounting, all mortality characteristics, both life and net salvage, must be supported by an engineering or economic based depreciation study for which the test year for the depreciation is no more than five years old in comparison to the rate case test year. The engineering or economic based depreciation study must include:

(I) investment by homogenous category;

(II) expected level of gross salvage by category;

(III) expected cost of removal by category;

(IV) the accumulated provision for depreciation as appropriately reflected on the company's books by category;

(V) the average service life by category;

(VI) the remaining life by category;

(VII) the Iowa Dispersion Pattern by category; and

(VIII) a detailed narrative identifying the specific factors, data, criteria and assumptions that were employed to arrive at the specific mortality proposal for each homogenous group of property.

(vi) Reserve for depreciation under this subparagraph or subparagraph (B) of this paragraph is the accumulation of recognized allocations of original cost, representing recovery of initial investment, over the estimated useful life or remaining life of the asset. Depreciation must be computed on a straight-line basis over the expected useful life or remaining life of the item or facility regardless of whether the salvage value is zero or not zero.

(I) If individual accounting is used, the following requirements apply to retirements:

(-a-) Accumulated depreciation must be calculated based on book cost less net salvage value of the asset.

(-b-) The utility must provide evidence establishing the original cost of the asset, the cost of removal, salvage value, any other amounts recovered; the useful life of the asset, or remaining life as may be appropriate; the date the asset was taken out of service; and the accumulated depreciation up to the date it was taken out of service.

(-c-) The utility must show that it used due diligence in recovering maximum salvage value of a retired asset.

(-d-) The utility must continue booking depreciation expense until the asset is actually retired, and the reserve for depreciation must include any additional depreciation expense accrued past the estimated useful or remaining life of the asset.

(-e-) The retirement of a plant asset from service is accounted for by crediting the book cost to the utility plant account in which it is included. Accumulated depreciation must also be debited with the original cost and the cost of removal and credited with the salvage value and any other amounts recovered.

(-f-) Retired assets must be specifically identified.

(-g-) The requirements relating to the accounting for the reasonableness of retirement decisions for individual assets and the net salvage value calculations for individual assets apply only to a utility using itemized accounting.

(II) For a utility that uses group accounting, the depreciation study must provide the information in subclause (I) except that retirements may be accounted for by category. Retired assets must be reported for the asset group in depreciation studies.

(III) TWC §13.185(e) applies to utility business transactions with affiliated interests involved in the retirement, removal, or recovery of assets.

(IV) For assets retired after June 19, 2009, the retired assets must be included in the utility's first application for a rate change after the date the asset was retired and must be specifically identified if the utility uses itemized accounting.

(vii) the original cost of plant, property, and equipment acquired from an affiliated interest may not be included in invested capital except as provided in TWC §13.185(e);

(viii) utility property funded by written customer agreements or customer contributions in aid of construction such as surcharges must not be included in original cost or invested capital.

(D) Working capital allowance to be composed of, but not limited to the following:

(i) reasonable inventories of materials and supplies held specifically for purposes of permitting efficient operation of the utility in providing normal utility service.

(ii) reasonable prepayments for operating expenses. Prepayments to affiliated interests are subject to the standards set forth in TWC §13.185(e); and

(iii) a reasonable allowance for cash working capital. The following will apply in determining the amount to be included in invested capital for cash working capital:

(I) Cash working capital for utilities must not exceed one-eighth of total annual operations and maintenance expense, excluding amounts charged to operations and maintenance expense for materials, supplies, fuel, and prepayments.

(II) For Class C and Class D utilities, one-eighth of operations and maintenance expense excluding amounts charged to operations and maintenance expense for materials, supplies, expenses recovered through a pass-through provision or through charges other than base rate and gallonage charges, and prepayments will be considered a reasonable allowance for cash working capital.

(III) For Class B utilities, one-twelfth of operations and maintenance expense excluding amounts charged to operations and maintenance expense for materials, supplies, expenses recovered through a pass-through provision or charges other than base rate and gallonage charges, and prepayments will be considered a reasonable allowance for cash working capital.

(IV) For Class A utilities, a reasonable allowance for cash working capital, including a request of zero, will be determined by the use of a lead-lag study. A lead-lag study will be performed in accordance with the following criteria:

(-a-) The lead-lag study will use the cash method. All non-cash items, including but not limited to depreciation, amortization, deferred taxes, prepaid items, and return, including interest on long-term debt and dividends on preferred stock, will not be considered.

(-b-) Any reasonable sampling method that is shown to be unbiased may be used in performing the lead-lag study.

(-c-) The check clear date, or the invoice due date, whichever is later, will be used in calculating the lead-lag days used in the study. In those cases where multiple due dates and payment terms are offered by vendors, the invoice due date is the date corresponding to the terms accepted by the utility.

(-d-) All funds received by the utility except electronic transfers will be considered available for use no later than the business day following the receipt of the funds in any repository of the utility, e.g., lockbox, post office box, branch office. All funds received by electronic transfer will be considered available the day of receipt.

(-e-) The balance of cash and working funds included in the working cash allowance calculation will consist of the average daily bank balance of all non-interest bearing demand deposits and working cash funds.

(-f-) The lead on federal income tax expense must be calculated by measurement of the interval between the mid-point of the annual service period and the actual payment date of the utility.

(-g-) If the cash working capital calculation results in a negative amount, the negative amount must be included in rate base.

(V) If cash working capital is required to be determined by the use of a lead-lag study under subclause (IV) of this clause and either the utility does not file a lead-lag study or the utility's lead-lag study is determined to be unreliable, in the absence of persuasive evidence that suggests a different amount of cash working capital, zero will be presumed to be the reasonable level of cash working capital.

(VI) A lead lag study completed within five years of the application for a rate or tariff change is adequate for determining cash working capital unless sufficient persuasive evidence suggests that the study is no longer valid.

(VII) Operations and maintenance expense does not include depreciation, other taxes, or federal income taxes, for purposes of subclauses (I), (II), (III) and (V) of this clause.

(3) Deduction of certain items from rate base. In the consideration of applications filed under TWC §13.187 or §13.1871, the commission will deduct certain items from rate base, including but not limited to the following:

(A) accumulated reserve for deferred federal income taxes;

(B) unamortized investment tax credit to the extent allowed by the Internal Revenue Code;

(C) contingency and property insurance reserves;

(D) contributions in aid of construction; and

(E) other sources of cost-free capital, as determined by the commission.

(4) Construction work in progress (CWIP).

(A) This subparagraph applies to a utility that elects to use a historic test year or to a utility that elects to use a combined test year or future test year for CWIP that the utility projects to not be in service through the end of the test year. The inclusion of CWIP is an exceptional form of relief that must be proven by clear and convincing evidence. Under ordinary circumstances, the rate base consists only of those items that are used and useful in providing service to the public. Under exceptional circumstances, the commission may include CWIP in rate base to the extent that the utility has proven that:

(i) the inclusion is necessary to the financial integrity of the utility; and

(ii) major projects under construction have been efficiently and prudently planned and managed.

(B) This subparagraph applies to a utility that elects to use a combined test year or a future test year that projects CWIP to be in service through the end of its selected test year.

(i) The commission will review CWIP to determine the extent the utility projects some or all of CWIP to be in service through the end of the combined test year or future test year.

(ii) CWIP that the utility projects will be in service by the end of the combined test year or the future test year will be included in rate base. The utility has the burden of proving that CWIP is reasonably projected to be in service (i.e., installed) through the end of the combined test year or future test year;

(5) Requirements for post-test year adjustments.

(A) A post-test year adjustment to test year data for known and measurable rate base additions may be considered only if:

(i) the addition represents a plant which would appropriately be recorded for investor-owned utilities in National Association of Regulatory Utility Commissioners (NARUC) account 101 or 102;

(ii) the addition comprises at least 10% of the utility's requested rate base, exclusive of post-test year adjustments and CWIP;

(iii) the addition is in service before the rate year begins;

(iv) the attendant impacts on all aspects of a utility's operations, including but not limited to, revenue, expenses and invested capital, can with reasonable certainty be identified, quantified and matched. Attendant impacts are those that reasonably result as a consequence of the post-test year adjustment being proposed; and

(v) the test year is a historic test year.

(B) Each post-test year plant adjustment described by subparagraph (A) of this paragraph will be included in rate base at the reasonable test year-end CWIP balance, if the addition is constructed by the utility, or the reasonable price, if the addition represents a purchase, subject to original cost requirements, as specified in TWC §13.185.

(C) Post-test year adjustments to historical test year data for known and measurable rate base decreases will be allowed only if:

(i) the decrease represents:

(I) plant which was appropriately recorded in NARUC account 101 or 102;

(II) plant held for future use;

(III) CWIP, not including mirror CWIP; or

(IV) an attendant impact of another post-test year adjustment.

(ii) the decrease represents a plant that has been removed from service, sold, or removed from the utility's books prior to the rate year; and

(iii) the attendant impacts on all aspects of a utility's operations, including but not limited to, revenue, expenses and invested capital, can with reasonable certainty be identified, quantified and matched. Attendant impacts are those that reasonably result as a consequence of the post-test year adjustment being proposed.

(d) Recovery of positive acquisition adjustments.

(1) When a utility acquires plant, property, or equipment for which commission approval is required under §24.239 of this title, relating to Sale, Transfer, Merger, Consolidation, Acquisition, Lease or Rental, a positive acquisition adjustment will be allowed to the extent that the acquiring utility proves that:

(A) the property is used and useful in providing retail water or sewer service at the time of the acquisition or as a result of the acquisition;

(B) reasonable, prudent, and timely investments will be made, if required, to bring the system into compliance with all applicable rules and regulations;

(C) as a result of the transaction:

(i) the customers of the system being acquired will receive higher quality or more reliable retail water or sewer service or that the acquisition was necessary so that customers of the acquiring utility's other systems could receive higher quality or more reliable retail water or sewer service;

(ii) regionalization of retail public utilities, meaning a pooling of financial, managerial, or technical resources that achieve economies of scale or efficiencies of service, was achieved; or

(iii) the acquiring utility will become financially stable and technically sound as a result of the acquisition, or the system being acquired that is not financially stable and technically sound will become a part of a financially stable and technically sound utility;

(D) any and all transactions between the buyer and the seller entered into as a part or condition of the acquisition are fully disclosed to the commission and were conducted at arm's length;

(E) the actual purchase price is reasonable in consideration of the condition of the plant, property, and equipment being acquired; the impact on customer rates if the acquisition adjustment is granted; the benefits to the customers; and the amount of contributions in aid of construction in the system being acquired; and

(F) the rates charged by the acquiring utility to its pre-acquisition customers will not increase unreasonably because of the acquisition.

(2) The owner of the acquired retail public utility and the final acquiring utility must not be affiliated. In a multi-stage transaction in which a purchase of voting stock or acquisition of controlling interest transaction under §24.243 of this title, relating to Purchase of Voting Stock or Acquisition of Controlling Interest in a Utility, is followed by a transfer of assets in what is essentially a single sales transaction, a positive acquisition adjustment is allowed only where the multi-stage transaction was fully disclosed to the commission in the application for approval of the initial stock or change of controlling interest transaction.

(3) The amount of the acquisition adjustment approved by the regulatory authority must be amortized using a straight-line method over a period equal to the weighted average remaining useful life of the acquired plant, property, and equipment, at an interest rate equal to the rate of return determined under subsection (c) of this section. The acquisition adjustment may be treated as a surcharge and may be recovered using non-system-wide rates.

(4) The authorization for and the amount of an acquisition adjustment will be determined only as a part of a rate change application.

(5) The acquisition adjustment will be included in rates only as a part of a rate change application.

(e) Negative acquisition adjustment. When a utility acquires plant, property, or equipment under §24.239 of this title, relating to Sale, Transfer, Merger, Consolidation, Acquisition, Lease or Rental, and the original cost of the acquired property less depreciation exceeds the actual purchase price, the utility must record the negative acquisition adjustment separately from the original cost of the acquired property. For purposes of ratemaking, the following will apply:

(1) If a utility acquires plant, property, or equipment from a nonfunctioning retail public utility through a sale, transfer, or merger, receivership, or the utility is acting as a temporary manager, a negative acquisition adjustment must be recorded and amortized on the utility's books with no effect on the utility's rates.

(2) If a utility acquires plant, property, or equipment from a retail public utility through a sale, transfer, or merger and paragraph (1) of this subsection does not apply, the commission may recognize the negative acquisition adjustment in the ratemaking proceeding, by ordering the amortization of the negative acquisition adjustment through a bill credit for a defined period of time or by other means determined appropriate by the commission. Except for good cause found by the commission, the negative acquisition adjustment will not be used to reduce the balance of invested capital.

(3) Notwithstanding paragraph (2) of this subsection, the acquiring utility may show cause as to why the commission should not account for the negative acquisition adjustment in the ratemaking proceeding.

(f) Subsections (d) and (e) of this section do not apply to plant, property, or equipment acquired through a transaction based on the fair market valuation process set forth in §24.238 of this title, relating to Fair Market Valuation.

(g) Intangible assets will not be allowed in rate base unless the requirements in paragraphs (1), (2) and (3) of this subsection are met. If the requirements in paragraphs (1) and (2) of this subsection are met, but the requirement in paragraph (3) of this subsection is not met, the amount will be amortized over a reasonable period and the amortization will be allowed in the cost of service as a non-recurring expense. Unamortized amounts will not be included in rate base. The requirements are as follows:

(1) The amount requested has been verified by documentation as to amount and exact nature;

(2) Testimony establishes the reasonableness and necessity and benefit of the expense to the customers; and

(3) Testimony establishes how the amount is properly considered an actual asset purchased or installed, or a source of supply, such as water rights.

§24.43. Rate Design.

(a) General. In fixing the rates of a utility, the commission shall fix its overall revenues at a level which will permit such utility a reasonable opportunity to earn a reasonable return on its invested capital used and useful in rendering service to the public, based on test year information, over and above its reasonable and necessary operating expenses (unless an alternative rate method is used as set forth in §24.75 of this title (relating to Alternative Rate Methods), and preserve the financial integrity of the utility.

(b) Conservation.

(1) In order to encourage the prudent use of water or promote conservation, water and sewer utilities shall not apply rate structures which offer discounts or encourage increased usage within any customer class.

(2) After receiving final authorization from the regulatory authority through a rate change proceeding, a utility may implement a water conservation surcharge using an inclining block rate or other conservation rate structure. A utility may not implement such a rate structure to avoid providing facilities necessary to meet the TCEQ's minimum standards for public drinking water systems. A water conservation rate structure may generate revenues over and above the utility's usual cost of service:

(A) to reduce water usage or promote conservation either on a continuing basis or in specified restricted use periods identified in the utility's approved drought contingency plan required by 30 TAC §288.20 (TCEQ rules relating to Drought Contingency Plans for Municipal Uses by Public Water Suppliers) included in its tariff in order to:

(i) comply with mandatory reductions directed by a wholesale supplier or underground water district; or

(ii) conserve water supplies, maintain acceptable pressure or storage, or other reasons identified in its approved drought contingency plan;

(B) to generate additional revenues necessary to provide facilities for maintaining or increasing water supply, treatment, production, or distribution capacity.

(3) All additional revenues over and above the utility's usual cost of service collected under paragraph (2) of this subsection:

(A) must be accounted for separately and reported to the commission, as requested; and

(B) are considered customer contributed capital unless otherwise specified in a commission order.

(c) Volume charges. Charges for additional usage above the base rate shall be based on metered usage over and above any volume included in the base rate rounded up or down as appropriate to the nearest 1,000 gallons or 100 cubic feet, or the fractional portion of the usage.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on July 30, 2026.

TRD-202603233

Katelyn Lewis

Rules Coordinator

Public Utility Commission of Texas

Effective date: August 19, 2026

Proposal publication date: April 10, 2026

For further information, please call: (512) 936-7044

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER C. INFRASTRUCTURE AND RELIABILITY

The Public Utility Commission of Texas (commission) adopts new 16 Texas Administrative Code (TAC) §25.63, relating to Distribution Pole Management and Inspection Plans, with changes to the proposed text as published in the March 27, 2026, issue of the Texas Register (51 TexReg 1940). New §25.63 implements Public Utility Regulatory Act (PURA) §38.103, as enacted by House Bill (HB) 144 during the Texas 89th Regular Legislative Session. New §25.63 requires each electric utility, municipally owned utility, and electric cooperative that owns or operates structures operating at distribution-level voltage to file with the commission a plan for the management and inspection of those structures. Additionally, new §25.63 requires those entities to file an annual compliance update pertaining to plan implementation. This section is adopted under Project Number 59431. This rule will be republished.

The commission received written comments on the proposed section from Texas Public Power Association (TPPA), Texas Electric Cooperatives, Inc. (TEC), Lower Colorado River Authority Transmission Services Corporation (LCRA TSC), Oncor Electric Delivery Company, LLC. (Oncor), CenterPoint Energy Houston Electric, LLC. (CenterPoint), Texas-New Mexico Power Company (TNMP), American Electric Power Texas Inc. and Southwestern Electric Power Company (collectively, AEP Companies), Southwestern Public Service Company (SPS), and Entergy Texas, Inc. (ETI).

General Comments

References to "distribution asset"

TPPA recommended that the commission replace all references in proposed §25.63 to "distribution asset" with "distribution pole."

Commission Response

The commission declines to replace the references in proposed §25.63 to "distribution asset" with "distribution pole" as recommended by TPPA and instead replaces the references with "structures operating at distribution-level voltage" for consistency with the terminology proposed by the commission under §25.61 in Project Number 59432.

Duplicative reporting requirements

TEC noted that PURA §38.103(c) "allows the commission to accept substantially similar information in lieu of a separate report" and recommended that the commission "consider combining the compliance requirements of Project 59431 and Project 59432" to eliminate duplicative reporting requirements.

TNMP commented that the May 1, 2027, annual compliance update deadline in proposed §25.63 overlaps with existing annual infrastructure-related filing and reporting deadlines and recommended that the commission "align or consolidate these reporting obligations to promote efficiency and reduce unnecessary administrative burden without sacrificing the purpose of the proposal."

Commission Response

The commission declines to combine the reporting requirements of this project with the requirements under Project Number 59432 or other existing reporting requirements as recommended by TEC and TNMP. However, to assist entities in complying with §25.63, the commission adopts §25.63(f) to provide that "An entity may fulfill the requirements of {adopted §25.63(d) or (e)(2)} by submitting any information required under other law that is substantially similar to the information required by {adopted §25.63(d) or (e)(2)}. An entity utilizing {adopted §25.63(f)} must clearly identify in its filing the requirement that the submitted information is intended to fulfill and include a description of why the submitted information is substantially similar to that requirement."

Proposed §25.63(a)

Proposed §25.63(a) establishes the applicability of the section to each electric utility, municipally owned utility, and electric cooperative that owns or operates a distribution asset in this state.

TPPA and LCRA TSC recommended that the commission modify proposed §25.63(a) to mirror the applicability language in PURA §38.103 by retaining the phrase "distributes electric energy to the public." TPPA additionally recommended that the commission modify proposed §25.63(a) by deleting the phrase "or operates" and replacing the term "distribution asset" with "distribution pole."

Commission Response

The commission agrees with TPPA and LCRA TSC and modifies proposed §25.63(a) to reflect the applicability language in PURA §38.103(a) by replacing the phrase "owns or operates a distribution asset" with the phrase "distributes electric energy to the public in this state." However, the commission declines to replace the references in proposed §25.63 to "distribution asset" with "distribution pole" as recommended by TPPA. Instead, the commission replaces the references with "structures operating at distribution-level voltage" for consistency with the terminology proposed by the commission under §25.61 in Project Number 59432.

Proposed §25.63(c)(1)(A)

Proposed §25.63(c)(1)(A) requires an entity to file an initial distribution pole management and inspection plan by January 1, 2027.

TNMP commented that the January 1, 2027, filing timeline under proposed §25.63(c)(1)(A) does not provide electric utilities with sufficient time to develop a plan that complies with this rule, the forthcoming transmission and distribution pole structural integrity standards under PURA §38.006, and other ongoing infrastructure-related rulemakings. Accordingly, TNMP recommended that the commission modify proposed §25.63(c)(1)(A) to provide "a later date that better reflects a plan development timeline."

Commission Response

The commission declines to modify the initial plan filing timeline under proposed §25.63(c)(1)(A) as recommended by TNMP because House Bill 144, §3, requires an entity to file a plan with the commission by January 1, 2027. However, to lessen the administrative obligation for entities, the commission aligns the subsequent plan filing timelines under adopted §25.63(c)(2) with the May 1 filing timeline for annual compliance updates under adopted §25.63(e).

Proposed §25.63(c)(1)(A) and (B)

Proposed §25.63(c)(1)(A) requires an entity to file an initial distribution pole management and inspection plan by January 1, 2027. Proposed §25.63(c)(1)(B) requires an entity to file subsequent distribution pole management and inspection plans by January 1 of years thereafter.

TPPA requested clarification on why proposed §25.63(c)(1)(A) and (B) would establish a January-based filing timeline when PURA §§38.006 and 38.103 both establish May-based filing timelines. TPPA recommended that the commission instead align proposed §25.63(c)(1)(A) and (B) with the May filing requirements found in statute "to avoid confusion and for administrative efficiency."

Commission Response

To more clearly delineate the initial and subsequent plan filing requirements, the commission redesignated the initial plan filing requirements under proposed §25.63(c)(1)(A) and (c)(1)(B)(i) as adopted §25.63(c)(1) and the subsequent plan filing requirements under proposed §25.63(c)(1)(B)(ii) as adopted §25.63(c)(2).

As related to the initial plan filing requirements under adopted §25.63(c)(1), the commission declines to align the January 1 timelines with the May 1 timelines established by PURA §§38.006 and 38.103 as recommended by TPPA. House Bill 144, §3, requires an entity to file a plan with the commission by January 1, 2027. Therefore, a January 1 timeline for initial plan filing is appropriate.

However, to streamline the administrative obligations associated with subsequent plan filings, the commission modifies the subsequent plan filing timelines under adopted §25.63(c)(2) to align with the May 1 annual compliance update filing timeline under adopted §25.63(e).

Proposed §25.63(c)(1)(B)(i)

Proposed §25.63(c)(1)(B)(i) requires an entity to file by January 1, 2028, either an affidavit that the entity's initial plan complies with the transmission and distribution pole structural integrity standards adopted by the commission under PURA §38.006 or a revised plan that complies with those standards.

TPPA expressed multiple concerns with the proposed requirements under §25.63(c)(1)(B)(i). First, TPPA asserted that "a MOU should not be asked to attest to compliance with standards adopted by the Commission {under PURA §38.006}, because the relevant standards are, for the MOU's purposes, those adopted by the MOU's governing body." Second, TPPA asserted that "this proposed language exceeds the scope of the rulemaking, as it includes a requirement for an attestation relating to transmission pole standards in a rule regarding distribution poles, as well as a requirement not noticed as part of the prefatory ‘Statutory Authority' language in the {proposal for publication}." Accordingly, TPPA recommended that the commission modify the proposed requirements under proposed §25.63(c)(1)(B)(i) by removing the phrase "transmission and" and adding the phrase "or governing body of the electric cooperative or MOU" from both proposed §25.63(c)(1)(B)(i)(I) and (II). TPPA provided redlines consistent with its recommendations.

Commission Response

The commission disagrees with TPPA that the standards adopted by the commission are not pertinent to MOUs, because PURA §38.006(d) specifies that "The governing body of a municipally owned utility or an electric cooperative shall adopt for the utility or cooperative, as applicable, the standards adopted by the commission {emphasis added} under {PURA §38.006(b)}." However, to address TPPA's concerns, and the potential concerns of individuals required to comply with the affidavit requirement, the commission modifies all references to "standards adopted by the commission under PURA §38.006" to remove the phrase "by the commission." This more general reference ensures that this rule appropriately captures the standards adopted by the commission and those same standards as adopted by the applicable governing bodies.

The commission agrees with TPPA that the reference to transmission poles in proposed §25.63(c)(1)(B)(i)(I) and (II) is confusing in context to the distribution-specific rule and replaces the references to "the transmission and distribution pole structural integrity standards adopted by the commission under PURA §38.006" in proposed §25.63 with "the standards adopted under PURA §38.006."

AEP Companies commented that the affidavit requirement under proposed §25.63(c)(1)(B)(i) "appears to be unnecessary as compliance {with the standards adopted by the commission under PURA §38.006} could be demonstrated in the initial plan filing due by January 1, 2027." Accordingly, AEP Companies recommended that the commission modify proposed §25.63(c)(1)(B)(i) to instead require entities to submit the affidavit with their initial plan.

Commission Response

The commission declines to modify proposed §25.63(c)(1)(B)(i) to require entities to submit with their initial plan an affidavit of compliance with the standards adopted under PURA §38.006 as recommended by AEP Companies. While some entities may be able to demonstrate compliance with the standards in their initial plan as indicated by AEP Companies, the commission expects that other entities will struggle to incorporate the standards into their plans by the January 1, 2027, filing deadline. Therefore, to alleviate compliance challenges, the commission adopts §25.63(c)(1)(A) and (B) to allow entities a one-year period to bring their initial plans into compliance with the standards adopted under PURA §38.006. If, as AEP suggests will often be the case, an entity's initial plan is in compliance with the applicable standards, it should not pose a material burden to delay filing the affidavit for one year.

Proposed §25.63(c)(1)(B)(ii)

Proposed §25.63(c)(1)(B)(ii) establishes plan filing requirements for after January 1, 2028. Specifically, proposed §25.63(c)(1)(B)(ii) requires an entity to file a revised plan by January 1 of every eighth year, starting in 2032 for electric utilities, 2034 for municipally owned utilities, and 2036 for electric cooperatives.

TPPA asserted that the requirement under proposed §25.63(c)(1)(B)(ii) for entities to file revised plans is inconsistent with the requirements of PURA §38.103 and recommended that the commission instead only require entities to submit annual updates on plan compliance, rather than additionally requiring periodic revisions to the plans themselves.

Commission Response

The commission declines to modify proposed §25.63(c)(1)(B)(ii) to remove the requirement for entities to file periodic updates to their plans and retain only an annual compliance update requirement as recommended by TPPA. While the annual compliance updates under adopted §25.63(e) will provide helpful insight into entities' year-over-year progress towards implementing their plans, the value of the information contained in those updates is directly tied to the currency of the plan itself. PURA §38.103(e) requires the commission to determine each entity's compliance with their plan objectives by reviewing each plan and annual compliance update. To ensure that the commission's determination is based on up-to-date information, it is necessary for entities to periodically update their plans.

AEP Companies expressed various concerns over the proposed plan update cycle in proposed §25.63(c)(1)(B)(ii). AEP Companies recommended that the commission modify proposed §25.63(c)(1)(B)(ii) to only require entities to file an updated plan if there are material changes to the entity's on-file plan. Alternatively, AEP Companies recommended that the commission modify proposed §25.63(c)(1)(B)(ii) to be "limited to a confirmation in the May 1 update filings, similar to {§25.53, relating to Electric Service Emergency Operations Plans}, under which utilities file annual updates and provide an attestation when no material changes have occurred."

Commission Response

The commission declines to modify proposed §25.63(c)(1)(B)(ii) to only require updates to an entity's on-file plan in response to a material change as recommended by AEP Companies. However, the commission agrees with AEP Companies that only changes to certain components of an on-file plan should trigger a required plan update. Specifically, if an entity makes changes to the scope and objectives of its plan or its methods for monitoring compliance with the plan, it must file an updated plan because accuracy of these plan components is essential for the commission's evaluation of the plan. For more operational components of the plan, such as the entity's processes for training personnel or responding to complaints, or the roles and responsibilities of the individuals responsible for carrying out the plan, an updated plan is only required for material changes. However, an updated plan is not required for changes in cost estimates or timeline projections, because these details frequently change and such as requirement would be a de facto annual filing requirement.

Accordingly, in addition to the periodic plan update cycle established under adopted §25.63(c)(2)(A), adopted §25.63(c)(2)(B) requires entities to file a plan if, in the prior calendar year, the entity made any changes to the information under adopted §24.63(d)(2) or (3) or any material changes to the information under adopted §25.63(d)(4) through (6).

Proposed §25.63(c)(2)

Proposed §25.63(c)(2) establishes requirements for the information that an entity's plan must contain as related to the management and inspection of distribution poles.

CenterPoint requested clarification regarding whether the phrase ‘distribution pole inspections,' as used under proposed §25.63(c)(2), is intended to include associated equipment such as transformers and crossarms. Additionally, CenterPoint recommended that the commission modify proposed §25.63(c)(2) to clarify that "the rule applies to distribution poles, consistent with PURA §38.103" and to either exclude associated equipment from the scope of required inspections and reporting or clarify that inspections of associated equipment are condition-based assessments and not subject to engineering compliance standards.

Commission Response

To maintain consistency between adopted §25.63 and the standards to be adopted by the commission under PURA §38.006 in Project Number 59432, the commission declines to specify in adopted §25.63 whether the distribution pole inspections referenced in proposed §25.63(c)(2) are intended to include equipment that is associated with distribution poles as recommended by CenterPoint. Further, the commission declines to specify in adopted §25.63(c)(2) that "the rule applies to distribution poles, consistent with PURA §38.103," or to discuss inspection specifications for equipment associated with distribution poles as recommended by CenterPoint. The commission instead specifies in adopted §25.63(b) that "An entity that owns or operates a structure to which the standards adopted under Public Utility Regulatory Act (PURA) §38.006 apply must file with the commission a plan for the management and inspection of structures operating at distribution-level voltage." Additionally, for consistency with the terminology proposed by the commission under Project Number 59432, the commission replaces the references in proposed §25.63 to "distribution pole" with "structures operating at distribution-level voltage."

Proposed §25.63(c)(2)(A)

Proposed §25.63(c)(2)(A) requires an entity's plan to contain a statement of the plan's scope and objectives for ensuring public safety through the effective management, inspection, maintenance, and repair of distribution poles.

TNMP recommended that the commission replace the phrase "or ensuring public safety," as used in proposed §25.63(c)(2)(A), with phrasing like "consistent with good utility practices" because the proposed language is "overly broad and potentially misleading as it suggests a guarantee of public safety akin to an insurance or indemnification obligation."

Commission Response

The commission declines to replace the phrase "or ensuring public safety" in proposed §25.63(c)(2)(A) with another phrase as recommended by TNMP because the proposed language mirrors that of PURA §38.103(b)(1).

Proposed §25.63(c)(2)(B)

Proposed §25.63(c)(2)(B) requires an entity's plan to contain a description of the roles and responsibilities of individuals responsible for overseeing and executing the plan.

SPS recommended that the commission modify proposed §25.63(c)(2)(B) to require entities to include in their plans "general job descriptions and business unit details, rather than individual contact information." SPS reasoned that, in addition to accounting for employee turnover and confidentiality concerns, a requirement for role-based descriptions "ensures continuity and accountability across plan cycles while avoiding unnecessary updates driven solely by routine personnel changes." SPS provided redlines consistent with its recommendation.

Commission Response

The commission agrees with SPS that routine personnel changes alone should not drive an entity's plan revision. However, the commission declines to replace the reference to "individuals" in proposed §25.63(c)(2)(B) with "each position or business unit" as recommended by SPS because the proposed language reflects that of PURA §38.103(b)(2). Instead, the commission specifies in adopted §25.63(d)(4) that entities must submit "A list of the roles and responsibilities of individuals responsible for overseeing and executing the plan, excluding personally identifiable information."

Proposed §25.63(c)(2)(C)

Proposed §25.63(c)(2)(C) requires an entity's plan to contain a description of the entity's processes for training and certifying personnel, including third-party vendors, who inspect distribution poles.

TPPA and CenterPoint requested clarification regarding the requirement for entities to describe their processes for training and certifying personnel, including third-party vendors, under proposed §25.63(c)(2)(C). CenterPoint recommended that the commission modify proposed §25.63(c)(2)(C) to clarify that "Utilities are not required to independently certify or audit contractor training programs" and "Compliance with this provision may be demonstrated through quality control and performance-based oversight of inspection results, rather than certification of personnel." CenterPoint reasoned that its recommendations would align the proposed rule with CenterPoint's current training and certification practices.

SPS noted that it relies on third-party vendors for "certain inspection and remediation work but does not directly certify individual vendor personnel." Accordingly, SPS requested that "Commission Staff confirm that an entity's ‘processes for training and certifying personnel' should focus on training and qualification processes the entity directly controls for its own employees." Additionally, SPS noted that it does not retain third-party vendors' training and certification records and requested clarification that "the Commission does not require internal documents from third-party vendors, which may contain proprietary or sensitive information."

ETI recommended that the commission clarify that "'certifying' personnel does not require a utility to develop or administer a formal educational or assessment procedure resulting in a certification, or to require that its personnel (including third-party vendors) do obtain such a certification."

TNMP expressed its strong objection to the requirement in proposed §25.63(c)(2)(C). Namely, TNMP asserted that "Utilities do not train or certify third-party vendors to perform their contracted for operations. Instead, utilities retain vendors that represent and attest they are qualified to perform the services for which they are hired. While utilities may provide materials describing utility-specific requirements, system characteristics, or safety expectations, they cannot, and should not, be deemed responsible for training and/or certifying vendors for their professional contracted for duties." TNMP recommended that the commission modify proposed §25.63(c)(2)(C) by clarifying that "utilities are not mandated to train and certify third party vendors" and limiting the requirement to "(1) the criteria used to select qualified vendors; (2) the expectation that vendors meet applicable industry, safety, and professional standards; and (3) the utility's coordination with vendors to ensure consistent evaluation measures when applying inspection methodologies to the utility's system."

Commission Response

The commission recognizes commenters' concern that an entity may not directly train or certify a third-party vendor that is hired to conduct inspections of structures operating at distribution-level voltage. Accordingly, the commission specifies in adopted §25.63(d)(5) that an entity's plan must contain "A description of the entity's processes for training and certifying personnel, or for verifying the training and certification of third-party vendors {emphasis added}, who inspect structures operating at distribution-level voltage."

Proposed §25.63(c)(2)(D)

Proposed §25.63(c)(2)(D) requires an entity's plan to contain an estimated timeline for completing inspections and remedial action required for any distribution pole identified as unreliable, unsafe, or needing repair that is consistent with the transmission and distribution pole structural integrity standards adopted by the commission under PURA §38.006.

Oncor expressed concern that the phrase "identified as unreliable, unsafe, or needing repair," as used in proposed §25.63(c)(2)(D), could cause confusion if "not ultimately used and/or defined in the Commission rule that will be adopted for pole structural integrity standards." Oncor recommended that the commission modify the proposed language to instead require entities' plans to include "an estimated timeline for completing any inspections and corrective actions that may be required for any distribution pole under the pole structural integrity standards rule adopted by the Commission under PURA § 38.006." Oncor provided redlines consistent with its recommendation.

TNMP noted that utilities' estimated timelines for completing inspections and remedial actions are "inherently dependent on the final form and effective dates of other Commission rulemakings addressing transmission and distribution pole structural integrity standards." Accordingly, TNMP recommended that the commission "recognize this crossover and consider related rulemaking in any final outcomes from this proceeding."

Commission Response

The commission agrees with Oncor and TNMP and specifies in adopted §25.63(d)(7) that an entity's plan must contain "An estimated timeline for completing any inspections and corrective actions required by the standards adopted under PURA §38.006 for structures operating at distribution-level voltage."

Proposed §25.63(c)(2)(E)

Proposed §25.63(c)(2)(E) requires an entity's plan to contain a description of the entity's processes for documenting and responding to a report or complaint made by a landowner regarding the condition or repair of a distribution pole.

CenterPoint recommended that the commission modify proposed §25.63(c)(2)(E) to clarify that "'As-you-go' inspections are excluded from the scope of required plans and reporting" and "At a minimum, entities are not required to separately track or report such activities for compliance purposes."

Commission Response

The commission declines to modify proposed §25.63(c)(2)(E) to clarify that ‘as-you-go' inspections should be excluded from the scope of entities' plans or annual compliance updates as recommended by CenterPoint. Adopted §25.63(d)(7) specifies that an entity's plan must contain "An estimated timeline for completing any inspections and corrective actions required by the standards adopted under PURA §38.006 for structures operating at distribution-level voltage." Further, adopted §25.63(e)(2)(E) requires an entity's annual compliance update to include "One or more tables detailing, for the prior calendar year, the results of the entity's inspections of structures operating at distribution-level voltage under the standards adopted under PURA §38.006, including the number of structures inspected and any corrective actions taken."

TNMP commented that, because "Utilities routinely receive landowner reports or complaints that, upon investigation, reveal no unsafe or noncompliant condition requiring remediation," "Requiring reporting in all instances of landowner notification would impose unnecessary administrative burden without additional safety benefit." Accordingly, TNMP recommended that the commission modify proposed §25.63(c)(2)(E) to only require description of an entity's process for documenting and responding to those landowner reports or complaints on a distribution pole's condition that result in a work order or corrective action.

Commission Response

The commission declines to modify proposed §25.63(c)(2)(E) to only require description of an entity's process for documenting and responding to landowner reports or complaints on a distribution pole's condition that result in a work order or corrective action as recommended by TNMP because such a limitation to scope is not contemplated by PURA §38.103(b)(5).

Proposed §25.63(c)(2)(F) and (d)(2)(B)

Proposed §25.63(c)(2)(F) requires an electric utility's plan to contain the estimated cost of implementing the plan. Proposed §25.63(d)(2)(B) requires an entity's annual compliance update to include the actual costs of implementing the plan to date, presented as a total and by compliance year.

Oncor expressed concern that, if retained in the adopted rule, the requirement under proposed §25.63(c)(2)(F) would lead to inaccurate estimates of plan implementation costs because "The further out into the future that implementation costs must be projected, the less accurate those cost projections are likely to be when compared against costs that are ultimately incurred." Accordingly, Oncor recommended that the commission modify proposed §25.63(c)(2)(F) to specify that electric utilities are only required to include in their plans a one-year--or, at most, a three-year--estimation of plan implementation costs. Oncor additionally recommended that, to balance a shorter cost estimate period in the plans, the commission modify proposed §25.63(d)(2)(B) to require entities to include in each annual compliance update an estimation of plan implementation costs for the upcoming year. Oncor reasoned that this additional reporting requirement is comparable to cost reporting requirements that electric utilities are subject to under other commission rules, including §§25.62, relating to Transmission and Distribution System Resiliency Plans, and 25.96, relating to Vegetation Management. Oncor provided redlines consistent with its recommendations.

Commission Response

The commission declines to modify proposed §25.63(c)(2)(F) or (d)(2)(B) to decouple the reporting requirements on plan implementation cost estimates and actuals from the 8-year plan update cycle as recommended by Oncor. To maintain one-to-one consistency between the information contained in an electric utility's plan and annual compliance update, adopted §25.63(d)(8) specifies that an electric utility's plan must contain "the estimated cost of implementing the plan, presented as capital expenditures, operations and maintenance (O&M) costs, and total costs for each calendar year," and adopted §25.63(e)(2)(D) specifies that entities' annual compliance updates must include "One or more tables detailing the actual costs of implementing the plan to-date, presented as capital expenditures, O&M costs, and total costs for each calendar year."

TNMP expressed concern that, in providing cost estimates under proposed §25.63(c)(2)(F) and reporting on actual costs under proposed §25.63(d)(2)(B), "Different entities may include different cost components, leading to confusion, lack of comparability, and potentially misleading outcomes." Accordingly, TNMP recommended that the commission provide "clear guidance" on standardized cost components under proposed §25.63(c)(2)(F) and (d)(2)(B).

Commission Response

The commission agrees with TNMP that the specification of standardized cost components is necessary and specifies in adopted §25.63(d)(7) and (e)(2)(D) that entities must present both plan implementation cost estimates and actuals "as capital expenditures, operations and maintenance (O&M) costs, and total costs for each calendar year."

Proposed §25.63(c)(3)

Proposed §25.63(c)(3) provides that a municipally owned utility or electric cooperative may fulfill the plan content requirements under proposed §25.63(c)(2) by submitting any information required under other law that is substantially similar to the information required by proposed §25.63(c)(2).

TEC asserted that the substantially similar language under proposed §25.63(c)(3) is "too narrow of an interpretation of PURA §38.103(c)." TEC expressed particular concern that the proposed language "limit[s] the application to only electric cooperatives and {municipally owned utilities} and limit{s} the allowable substitutions to only the information contained within a specific subsection." TEC recommended that the commission modify the proposed rule to "better reflect the statutory language" by relocating the language in proposed §25.63(c)(3) to a new §25.63(d), redesignating proposed §25.63(d) and (e) as adopted §25.63(e) and (f), and expanding the scope of the provision to all entities subject to the rule's requirements and all information required to be submitted under the rule. TEC provided redlines consistent with its recommendations.

ETI recommended that the commission modify proposed §25.63(c)(3) to "extend the applicability of this subsection to electric utilities." ETI reasoned that this modification would "align the scope of the subsection with that of PURA §38.103(e) and would maximize the efficiencies enabled by the provision for all qualifying filings."

Commission Response

The commission agrees with TEC and ETI and expands the scope of proposed §25.63(c)(3) to provide in adopted §25.63(f) that "An entity may fulfill the requirements of {adopted §25.63(d) or (e)(2)} by submitting any information required under other law that is substantially similar to the information required by {adopted §25.63(d) or (e)(2)}. An entity utilizing this subsection must clearly identify in its filing the requirement that the submitted information is intended to fulfill and include a description of why the submitted information is substantially similar to that requirement."

Proposed §25.63(d)

Proposed §25.63(d)(1)(B) requires an entity with a plan on file with the commission under proposed §25.63(c) to file an annual compliance update not later than May 1 of each year.

TPPA commented that "it is unclear whether an entity, having submitted a full plan on January 1, would need to submit a compliance update for that plan just four months later" and reiterated its recommendation that all filings under §25.63 be made by May 1.

Commission Response

The commission agrees with TPPA that a May 1 filing timeline for both plans and annual compliance updates would streamline the administrative obligation for entities. Accordingly, the commission aligns the filing requirements for subsequent plans under adopted §25.63(c)(2) with the May 1 filing timeline for annual compliance updates under adopted §25.63(e). Entities should note that initial plans under adopted §25.63(c)(1) are still subject to a January 1 filing timeline for consistency with the requirement under HB 144, §3.

Proposed §25.63(d)(1)(B)

Proposed §25.63(d)(1)(B) requires an electric utility's annual compliance update to include both the information required under proposed §25.63(d) and the information required under §25.94, relating to Report on Infrastructure Improvement and Maintenance.

Oncor recommended that the commission clarify the overlap in reporting expectations between §§25.63 and 25.94 by repealing §25.94, relating to Infrastructure Improvement and Maintenance Report, and replacing the reference to §25.94 in proposed §25.63(d)(1)(B) with a reference to PURA §38.101. Oncor provided redlines consistent with its recommendation. Oncor alternatively recommended that the commission revise §25.94 to "clarify that all information required thereunder should be reported in the May 1st report required under new §25.63," or that commission staff issue a memo "expressly setting forth this expectation for consolidated reporting."

Commission Response

The commission declines to repeal or revise §25.94, relating to Infrastructure Improvement and Maintenance, in this rulemaking project as recommended by Oncor because §25.94 is not a noticed rule section in the proposal for publication approved in this rulemaking project.

SPS noted that "cost reporting under § 25.63(d)(2)(B) that includes work executed through other programs which also have associated reporting may result in duplicative reporting of these costs" and recommended that the commission modify proposed §25.63(d)(1)(B) to "expressly permit incorporation by reference any required contents that are already reported under another substantive Commission rule." SPS provided redlines consistent with its recommendation.

Commission Response

The commission agrees with SPS that an entity with substantially similar information on file with the commission should be able to utilize that information to meet the requirements under §25.63. However, the commission declines to modify proposed §25.63(d)(1)(B) to "expressly permit incorporation by reference any required contents that are already reported under another substantive Commission rule." Instead, the commission adopts §25.63(f) to provide that "An entity may fulfill the requirements of {adopted §25.63(d) or (e)(2)} by submitting any information required under other law that is substantially similar to the information required by {adopted §25.63(d) or (e)(2)}. An entity utilizing this subsection must clearly identify in its filing the requirement that the submitted information is intended to fulfill and include a description of why the submitted information is substantially similar to that requirement."

Proposed §25.63(d)(2)(B)

Proposed §25.63(d)(2)(B) requires an entity's annual compliance update to include the actual costs of implementing the plan to date, presented as a total and by compliance year.

SPS requested that the commission clarify the scope of the phrase "actual costs of implementing the plan to date," as used in proposed §25.63(d)(2)(B), including whether the commission intends for entities to report on direct plan implementation costs--such as inspection labor, contractor inspection costs, program management, data collection/recordkeeping, and related overhead--or costs for pole remediation, reinforcement, and replacement that may be tracked under separate work orders.

SPS additionally recommended that the commission modify proposed §25.63(d)(2)(B) to provide entities with "flexibility to report costs at a practicable level of aggregation (e.g., total and by compliance year) using reasonable utility accounting and work-order practices, rather than requiring pole-by-pole cost assignment where work is bundled across multiple assets or programs." SPS reasoned that "Such flexibility would promote transparent reporting while maintaining consistency with auditable utility accounting and project-tracking practices."

Commission Response

The commission agrees with SPS and clarifies the intended granularity of plan implementation cost reporting by specifying in adopted §25.63(e)(2)(D) that entities must present cost actuals as "capital expenditures, operations and maintenance (O&M) costs, and total costs for each calendar year."

The commission declines to modify proposed §25.63(d)(2)(B) to specify that entities must report actual costs "using reasonable utility accounting and work-order practices, rather than requiring pole-by-pole cost assignment," as recommended by SPS because it is unnecessary. Under adopted 25.63(e)(2), an entity is not required to provide information on a pole-by-pole basis, either as related to cost assignment or reporting on inspection activities.

Proposed §25.63(d)(2)(C)

Proposed §25.63(d)(2)(C) requires an entity's annual compliance update to include the results of the entity's distribution pole inspections, including the total number of poles inspected; the number of poles inspected and identified as needing remediation, accompanied by an indication of the necessary remedial action and the entity's progress towards completing the action for each pole; the number of poles inspected and identified as needing replacement, accompanied by an indication of the entity's progress towards replacing each pole; and the number of poles inspected and identified as a danger pole, accompanied by an indication of the entity's progress towards making safe and replacing each pole.

Oncor expressed concern that the granularity of reporting detail required under proposed §25.63(d)(2)(C) would result in "an extremely time consuming, unduly burdensome, and voluminous reporting effort" for entities. Oncor additionally expressed concern that "there could be confusion if the terms in {proposed} §25.63(d)(2)(C)(ii)-(iv) differ from the terms used for required corrective actions under the pole structural integrity standards rule to be adopted by the Commission {under PURA §38.006}." Accordingly, Oncor recommended that the commission delete the requirements under proposed §25.63(d)(2)(C)(ii) through (iv) and instead require, as adopted §25.63(c)(2)(D)(ii), entities to include in their annual compliance updates "a table summarizing the number of poles inspected and identified as falling within each category of corrective action specified in the pole structural integrity standards adopted by the commission under PURA §38.006, accompanied by a statement for each category of corrective action summarizing the entity's overall progress towards completing the corrective action for the poles within that category." Oncor provided redlines consistent with its recommendations.

Commission Response

The commission agrees with Oncor and adopts §25.63(e)(2)(E) to require an entity's annual compliance update to include "One or more tables detailing, for the prior calendar year, the results of the entity's inspections of structures operating at distribution-level voltage under the standards adopted under PURA §38.006, including the number of structures inspected and any corrective actions taken."

Proposed §25.63(d)(2)(C)(iv)

Proposed §25.63(d)(2)(C)(iv) requires an entity's annual compliance update to include the number of poles inspected and identified as a danger pole, accompanied by an indication of the entity's progress towards making safe and replacing each pole.

AEP Companies noted that the term ‘danger pole,' as used in proposed §25.63(d)(2)(C)(iv), is not included in PURA §38.103, defined in the proposed rule, or consistently used by entities to describe pole condition and replacement prioritization. Accordingly, AEP Companies recommended that the commission "clearly define" the term ‘danger pole' to "ensure consistent interpretation and reporting across utilities."

SPS recommended that the commission modify proposed §25.63(d)(2)(C)(iv) to "expressly allow utilities to report utility poles constituting ‘danger poles' using their currently established internal classifications and operational workflows." SPS reasoned that "Clarifying that a danger pole may be reported using a utility's equivalent emergency designation would promote consistent and accurate reporting while preserving risk-based remediation practices."

Commission Response

The commission agrees with AEP Companies and SPS that the term ‘danger pole,' as used in proposed §25.63(d)(2)(C)(iv), is unclear. However, rather than defining the term or specifying that an entity should utilize in their annual compliance update a "comparable classification" as recommended by commenters, the commission removes all references to the term from adopted §25.63. Instead, under adopted §25.63(e)(2)(E), an entity's annual compliance update must include "One or more tables detailing, for the prior calendar year, the results of the entity's inspections of structures operating at distribution-level voltage under the standards adopted under PURA §38.006, including the number of structures inspected and any corrective actions taken."

Proposed §25.63(e)

Proposed §25.63(e) provides that commission staff will review each entity's plan and annual compliance update to determine compliance with the plan objectives under proposed §25.63(c)(2)(A) and issue notice of its determination to the submitting entity and to the commission.

TPPA asserted that the commission staff-led compliance review process under proposed §25.63(e) "does not satisfy the legislative directive" of PURA §38.103 and recommended that the commission modify the proposed language to provide that, while commission staff will offer a proposed determination on an entity's compliance, the commission will issue the final determination. TPPA provided redlines consistent with its recommendation. TPPA additionally recommended that the commission adopt procedural rules for how the commission will make a compliance determination, including whether existing contested case procedures will apply.

Oncor asserted that the compliance review process under proposed §25.63(e) is inconsistent with PURA §38.103(d) because the proposed language "places the obligation to conduct [the review of plans and annual compliance updates] and…notify the submitting entity on {Commission} Staff, rather than the Commission." Oncor recommended that the commission modify proposed §25.63(e) to provide that notice of a determination on an entity's compliance with its plan objectives will be based on a recommendation made by commission staff but be ultimately issued by the commission, or, if the commission delegates authority, by the executive director or a designee of the executive director. Oncor provided redlines consistent with its recommendation.

Commission Response

To further clarify the division of responsibilities between commission staff and the commission in the compliance review process as recommended by TPPA and Oncor, the commission specifies in adopted §25.63(g) that "Commission staff will annually review each entity's plan and annual compliance update to determine whether the entity is in compliance with the plan's objectives under {adopted §25.63(d)(2)} and file for consideration by the commission a report containing a recommended finding on each entity's compliance. Commission staff will notify each entity of the commission's determination on the entity's compliance."

The commission declines to adopt procedural rules for how the commission will make a compliance determination as recommended by TPPA and clarifies that the annual compliance review process under adopted §25.63(g) does not constitute a contested case. Under Section 2001.003 of the Texas Government Code, relating to Definitions, a contested case is "a proceeding, including a ratemaking or licensing proceeding, under which the legal rights, duties, or privileges of a party are to be determined by a state agency after an opportunity for adjudicative hearing." Because the annual compliance review process under adopted §25.63(g) does not encompass an opportunity for adjudicative hearing, nor will it result in the commission making a determination on the legal rights, duties, or privileges of an entity, it does not constitute a contested case.

SPS requested clarification from the commission on how an entity should demonstrate compliance with their plan's scope and objectives under proposed §25.63(c)(2)(A). Specifically, SPS requested clarification on: 1) whether an entity should demonstrate compliance by using "quantitative performance measures and…qualitative program controls" in the annual compliance update under proposed §25.63(d); and 2) whether an entity should "expressly reference--and incorporate by reference--{in its plan and annual compliance update} existing…inspection and pole integrity programs that already govern inspection frequency, defect identification, and corrective action."

Commission Response

Under adopted §25.63(e)(2)(C), an entity is required to include in its annual compliance update "A detailed description of the entity's compliance with the plan objectives under subsection (d)(2) of this section in the prior calendar year." Under adopted §25.63(d)(3), an entity is required to include in its plan "A description of the entity's methods for monitoring compliance with the plan." Regarding the first point of clarification requested by SPS, the commission anticipates that an entity will include, in both its plan and annual compliance update, appropriate methods and metrics for measuring its compliance with the plan's stated objectives.

Regarding the second point of clarification requested by SPS, the commission clarifies that an entity may decide how best to demonstrate that its plan complies with adopted §25.63(d)(7), which requires an entity to include "An estimated timeline for completing any inspections and corrective actions required by the standards adopted under PURA §38.006 for structures operating at distribution-level voltage." However, an entity may note the permission under adopted §25.63(f) for the entity to "fulfill the requirements of {adopted §25.63(d) or (e)(2)} by submitting any information required under other law that is substantially similar to the information required by {adopted §25.63(d) or (e)(2)}."

In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

This section is adopted under the following provisions of Public Utility Regulatory Act (PURA): §§14.001, which grants the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction; 14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; and 38.103, which requires each electric utility, municipally owned utility, and electric cooperative that distributes electric energy to the public to submit to the commission a plan for the management and inspection of distribution poles the cooperative or utility owns in the cooperative's or utility's distribution system.

Cross Reference to Statute: Public Utility Regulatory Act §§14.001; 14.002; and 38.103.

§25.63. Distribution Pole Management and Inspection Plans.

(a) Applicability. This section applies to each electric utility, municipally owned utility, and electric cooperative that distributes electric energy to the public in this state. The term "entity" as used in this section means an electric utility, a municipally owned utility, or an electric cooperative operating in this state.

(b) Distribution pole management and inspection plan. An entity that owns or operates a structure to which the standards adopted under Public Utility Regulatory Act (PURA) §38.006 apply must file with the commission a plan for the management and inspection of structures operating at distribution-level voltage.

(c) Plan filing. A plan must be filed in the control number designated for this purpose by commission staff, as a searchable pdf document, and in Microsoft Excel format for all included tables, with formulas intact.

(1) Initial plans.

(A) Not later than January 1, 2027, an entity must file an initial plan; and

(B) Not later than January 1, 2028, an entity must file:

(i) An affidavit that the initial plan under subparagraph (A) of this paragraph complies with the standards adopted under PURA §38.006 for structures operating at distribution-level voltage; or

(ii) A revised plan that complies with the standards adopted under PURA §38.006 for structures operating at distribution-level voltage.

(2) Subsequent plans.

(A) An entity must file a plan not later than May 1 of every eighth year, beginning in 2032 for electric utilities, 2034 for municipally owned utilities, and 2036 for electric cooperatives.

(B) An entity must file a plan not later than May 1 of any given year if, in the prior calendar year, the entity made:

(i) Any changes to the information under subsection (d)(2) or (3) of this section; or

(ii) Any material changes to the information under subsection (d)(4) through (6) of this section.

(d) Plan contents. An entity's plan must contain:

(1) Contact information for the entity, including:

(A) The entity's legal name;

(B) The entity's form of organization; and

(C) The entity's certificate of convenience and necessity (CCN) number.

(2) A statement of the plan's scope and objectives for ensuring public safety through the effective management, inspection, maintenance, and repair of structures operating at distribution-level voltage;

(3) A description of the entity's methods for monitoring compliance with the plan;

(4) A list of the roles and responsibilities of individuals responsible for overseeing and executing the plan, excluding personally identifiable information;

(5) A description of the entity's processes for training and certifying personnel, or for verifying the training and certification of third-party vendors, who inspect structures operating at distribution-level voltage;

(6) A description of the entity's processes for documenting and responding to a report or complaint made by a landowner regarding the condition or repair of a structure operating at distribution-level voltage;

(7) An estimated timeline for completing any inspections and corrective actions required by the standards adopted under PURA §38.006 for structures operating at distribution-level voltage; and

(8) For a plan submitted by an electric utility, the estimated cost of implementing the plan, presented as capital expenditures, operations and maintenance (O&M) costs, and total costs for each calendar year.

(e) Annual compliance update. An entity with a plan on file with the commission under this section must file an annual compliance update not later than May 1 of each year.

(1) Filing. An annual compliance update must be filed in the control number or other filing method designated for this purpose by commission staff, as a searchable pdf document, and in Microsoft Excel format for all included tables, with formulas intact.

(2) Contents. An entity's annual compliance update must include:

(A) Contact information for the entity, including:

(i) The information required under subsection (d)(1) of this section; and

(ii) The entity's primary contact name and title, mailing address, business telephone number, business e-mail address, and web address.

(B) The control number and item number associated with the entity's most-recently filed plan;

(C) A detailed description of the entity's compliance with the plan objectives under subsection (d)(2) of this section in the prior calendar year;

(D) One or more tables detailing the actual costs of implementing the plan to-date, presented as capital expenditures, O&M costs, and total costs for each calendar year; and

(E) One or more tables detailing, for the prior calendar year, the results of the entity's inspections of structures operating at distribution-level voltage under the standards adopted under PURA §38.006, including the number of structures inspected and any corrective actions taken.

(f) Substantially similar information. An entity may fulfill the requirements of subsections (d) or (e)(2) of this section by submitting any information required under other law that is substantially similar to the information required by subsections (d) or (e)(2) of this section. An entity utilizing this subsection must clearly identify in its filing the requirement that the submitted information is intended to fulfill and include a description of why the submitted information is substantially similar to that requirement.

(g) Annual compliance review. Commission staff will annually review each entity's plan and annual compliance update to determine whether the entity is in compliance with the plan's objectives under subsection (d)(2) of this section and file for consideration by the commission a report containing a recommended finding on each entity's compliance. Commission staff will notify each entity of the commission's determination on the entity's compliance.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on July 30, 2026.

TRD-202603235

Katelyn Lewis

Rules Coordinator

Public Utility Commission of Texas

Effective date: August 19, 2026

Proposal publication date: March 27, 2026

For further information, please call: (512) 936-7044

SUBCHAPTER E. CERTIFICATION, LICENSING AND REGISTRATION

The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §25.101 relating to Certification Criteria with changes to the proposed text as published in the April 17, 2026 issue of the Texas Register (51 TexReg 2648). This amendment will implement Public Utility Regulatory Act (PURA) §37.052(c) as revised by House Bill (HB) 3092 during the Texas 89th Regular Legislative Session. The amended rule will increase the minimum transmission line length, from three miles to five miles, that may be constructed without requiring an electric utility to amend its certificate of convenience and necessity when the line connects an existing transmission facility to a load-serving substation or metering point. Additionally, non-substantive clarifying and consistency edits were made to the rule language. This amendment is adopted under Project No. 59528. This rule will be republished.

The commission received comments on the proposed amendment from the AEP Companies, American Energy Works, CenterPoint Energy (CNP), LCRA Transmission Services Corporation (LCRA TSC), ONCOR Electric Delivery Company (Oncor), Texas New Mexico Power Company (TNMP), Texas Industrial Energy Consumers (TIEC), and Texas Public Power Association (TPPA).

General Comments

The AEP Companies (AEP Texas, Southwestern Electric Power Company, and Electric Transmission Texas) supported the amendment as proposed. The AEP Companies agreed that the amendment is administratively efficient and will streamline the transmission line construction process for certain transmission projects, including those that support load growth and economic development. The AEP Companies acknowledged the expanded mileage exemption operates within the Commission's existing regulatory framework and does not eliminate or supersede applicable CCN requirements related to exemptions, including those related to the acquisition of all rights-of-way and written consent of all affected landowners.

CNP supported the amendment as proposed. CNP acknowledged the proposed rule appropriately applied the increase to line miles connecting an existing transmission facility to a load-serving substation or metering point, while retaining the existing two-mile limit for connections to generation facilities. CNP described that the amendment does not expand or narrow the scope of CCN exemptions.

Oncor supported the amendment as proposed and presented that it directly follows statutory language and does not make changes to the conditions necessary for qualifying under the CCN exemption or alternative exemptions. Oncor stated the amendment does not expand eminent domain authority for electric utilities or limit landowners to intervene before the Commission if a landowner chooses not to consent the project. Oncor also suggested the proposed amendment will streamline the construction of transmission infrastructure, where the transmission line has been consented to by affected parties.

TIEC supported the amendment as proposed and stated the amendment accurately implements statute. TIEC recognized that individuals may have well-founded concerns regarding the siting of new transmission infrastructure and associated costs. However, TIEC presented those concerns are not applicable to the category of projects addressed by this proposed amendment. TIEC discussed that the exemption only applies to interconnections that have the unanimous consent of affected landowners, and the amendment is narrowly tailored to apply to the interconnection facilities under five miles long to help streamline short, low-cost transmission projects, that support load growth and economic development to the extent that they are acceptable to landowners whose property is directly affected. TIEC argued that projects which qualify under the amendment differ from those where a utility must propose multiple contested routes, and such contested routing cases involve evidentiary hearings, routing studies, and potential eminent domain proceedings that are not impacted by this amendment.

LCRA TSC, TNMP, and TPPA supported the amendment as proposed and described the amendment as correctly following HB 3092 (89th R.S.).

By contrast, American Energy Works recommended the commission decline to adopt the proposed amendment and gathered 1,228 signatures to support its recommendation. American Energy Works suggested the amendment would allow utilities to construct up to five miles of new transmission lines with reduced regulatory scrutiny, truncated public review, and strengthen utilities' eminent domain leverage over private landowners.

American Energy Works suggested a landowner has one opportunity to be heard, challenge transmission line routes, present alternatives, and protect their property. American Energy Works presented that reducing the time and scope of public comment to accelerate utility timelines is not progress, but a diminishment of rights. American Energy Works acknowledged that infrastructure development has a role in a healthy grid. However, it expressed grid challenges cannot be to run roughshod over landowners. American Energy Works suggested the commission balance the interests of utilities against the interests of the public.

Commission Response

The commission declines to reject the proposed amendment as recommended by American Energy Works. House Bill 3092 from the Texas Legislature 89th Regular Session (HB 3092) amended PURA §37.052(c)(1)(A) to increase the length of a transmission line, from three miles to five miles, connecting existing transmission facilities to a load-serving substation or metering point that may qualify for an exemption to the requirement to obtain a CCN amendment. The proposed amendment will align the commission's rules with this statutory requirement. The commission also notes that because this is a statutory exemption, it is already in effect. The commission cannot, by rule, overturn this statutory exemption.

With regards to the other concerns expressed by American Energy Works, the commission notes that the proposed amendment does not modify the conditions that must be met for the statutory exemption to apply and does not alter other criteria that may qualify a project for an exemption under applicable law. The proposed amendment also does not expand eminent domain authority for electric utilities and does not limit the ability of affected landowners to participate in applicable processes. The amendment still requires all landowners whose property is directly affected by the transmission line, as defined in §22.52(a)(3), to give written consent for the modification, construction, or extension to occur. If the transmission line modification, construction, or extension does not exceed one mile to provide service to a substation or metering point, written consent is only required by landowners whose property is crossed by the transmission line. If landowners do not provide written consent under the conditions stated above, the utility cannot rely upon the exemption.

In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

The amendment is adopted under Public Utility Regulatory Act (PURA) §14.001, which grants the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; and §37.052, which governs exceptions to certificate requirements for service extension.

Cross Reference to Statute: Public Utility Regulatory Act §§14.001; 14.002; and 37.052.

§25.101. Certification Criteria.

(a) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise:

(1) Construction or extension--Does not include the purchase or condemnation of real property for use as facility sites or right-of-way. Acquisition of right-of-way must not be deemed to entitle an electric utility to the grant of a certificate of convenience and necessity without showing that the construction or extension is necessary for the service, accommodation, convenience, or safety of the public.

(2) Generating unit--Any electric generating facility. This section does not apply to any generating unit that is ten megawatts or less and is built for experimental purposes only.

(3) Habitable structures--Structures normally inhabited by humans or intended to be inhabited by humans on a daily or regular basis. Habitable structures include, but are not limited to: single-family and multi-family dwellings and related structures, mobile homes, apartment buildings, commercial structures, industrial structures, business structures, churches, hospitals, nursing homes, and schools.

(4) Municipal Power Agency (MPA)--Agency or group created under Texas Utilities Code, Chapter 163 - Joint Powers Agencies.

(5) Municipal Public Entity (MPE)--A municipally owned utility (MOU) or a municipal power agency.

(6) Prudent avoidance--The limiting of exposures to electric and magnetic fields that can be avoided with reasonable investments of money and effort.

(7) Tie line--A facility to be interconnected to the Electric Reliability Council of Texas (ERCOT) transmission grid by a person, including an electric utility or MPE, that would enable additional power to be imported into or exported out of the ERCOT power grid.

(b) Certificates of convenience and necessity for new service areas and facilities. Except for certificates granted under subsection (e) of this section, the commission will grant an application and issue a certificate only if it finds that the certificate is necessary for the service, accommodation, convenience, or safety of the public, and complies with the statutory requirements in the Public Utility Regulatory Act (PURA) §37.056. The commission may issue a certificate as applied for, or refuse to issue it, or issue it for the construction of a portion of the contemplated system or facility or extension thereof, or for the partial exercise only of the right or privilege. The commission will render a decision approving or denying an application for a certificate within one year of the date of filing of a complete application for such a certificate, unless good cause is shown for exceeding that period. A certificate, or certificate amendment, is required for the following:

(1) Change in service area. Any certificate granted under this section must not be construed to vest exclusive service or property rights in and to the area certificated.

(A) Uncontested applications: An application for a certificate under this paragraph must be approved administratively within 80 days from the date of filing a complete application if:

(i) no motion to intervene has been filed or the application is uncontested;

(ii) all owners of land that is affected by the change in service area and all customers in the service area being changed have been given direct mail notice of the application; and

(iii) commission staff has determined that the application is complete and meets all applicable statutory criteria and filing requirements, including, but not limited to, the provision of proper notice of the application.

(B) Minor boundary changes or service area exceptions: Applications for minor boundary changes or service area exceptions must be approved administratively within 45 days of the filing of the application provided that:

(i) every utility whose certificated service area is affected agrees to the change;

(ii) all customers within the affected area have given prior consent; and

(iii) commission staff has determined that the application is complete and meets all applicable statutory criteria and filing requirements, including, but not limited to, the provision of proper notice of the application.

(2) Generation facility.

(A) In a proceeding involving the purchase of an existing electric generating facility by an electric utility that operates solely outside of ERCOT, the commission will issue a final order on a certificate for the facility not later than the 181st day after the date a request for the certificate is filed with the commission under PURA §37.058(b).

(B) In a proceeding involving a newly constructed generating facility by an electric utility that operates solely outside of ERCOT, the commission will issue a final order on a certificate for the facility not later than the 366th day after the date a request for the certificate is filed with the commission under PURA §37.058(b).

(C) An electric utility operating solely outside of the ERCOT region may, but is not required to, obtain a certificate to install, own, or operate a generation facility with a capacity of 10 megawatts or less.

(3) Electric transmission line. All new electric transmission lines must be reported to the commission in accordance with §25.83 of this title (relating to Transmission Construction Reports). This reporting requirement is also applicable to new electric transmission lines to be constructed by an MPE seeking to directly or indirectly construct, install, or extend a transmission facility outside of its applicable boundaries. For an MOU, the applicable boundaries are the municipal boundaries of the municipality that owns the MOU. For an MPA, the applicable boundaries are the municipal boundaries of the public entities participating in the MPA.

(A) Determination of need:

(i) Economic projects. Except as otherwise stated in this subparagraph, the following must be met for a transmission line in the ERCOT region. The applicant must present an economic cost-benefit study that analyzes the transmission project under a congestion cost savings test and a production cost savings test. The commission will give great weight to such a study if it is conducted by the ERCOT independent system operator. Adequately quantifiable and ongoing direct and indirect costs and benefits to the transmission system attributable to the project may be included in the cost-benefit study.

(I) Congestion cost savings test. ERCOT, in consultation with commission staff, must develop a congestion cost savings test.

(-a-) The congestion cost savings test must include an analysis of whether the levelized ERCOT-wide annual congestion cost savings attributable to the proposed project are equal to or greater than the average of the first three years annual revenue requirement of the proposed project of which the transmission line is a part.

(-b-) Prior to the effective date of the test developed by ERCOT under this subclause ERCOT may immediately, without updating its current protocols, utilize the generator revenue reduction test, effective Dec. 1, 2011 under ERCOT Nodal Protocols §3.11.2(6), as the congestion cost benefit test required under this clause. ERCOT may continue to rely upon completed calculations using the generator revenue reduction test to evaluate ongoing applications after the effective date of the test developed under this subclause.

(II) Production cost savings test. The production cost savings test must include an analysis of whether the levelized ERCOT-wide annual production cost savings attributable to the proposed project are equal to or greater than the first-year annual revenue requirement of the proposed project of which the transmission line is a part.

(III) Economic cost-benefit analysis must be studied for the projected in-service date of the project using the study case identified in the ERCOT planning guide.

(IV) ERCOT may recommend, and the commission may approve, a transmission line in the ERCOT region that demonstrates a savings under either a congestion cost savings test or a production cost savings test.

(ii) Reliability projects.

(I) The requirements of clause (i) of this subparagraph do not apply to an application for a transmission line that is necessary to meet state or federal reliability standards, including: a transmission line needed to interconnect a transmission service customer or end-use customer; or needed due to the requirements of any federal, state, county, or municipal government body or agency for purposes including, but not limited to, highway transportation, airport construction, public safety, or air or water quality.

(II) For a transmission line not addressed by clause (i) of this subparagraph, the commission will consider, among other factors, the needs of the interconnected transmission systems to support a reliable and adequate network and to facilitate robust wholesale competition. When evaluating reliability for a proposed project in the ERCOT region, the commission will consider and any review conducted by ERCOT must incorporate the historical load, forecasted load growth, and additional load currently seeking interconnection. The forecasted load growth and additional load currently seeking interconnection must be substantiated by quantifiable evidence of projected load growth. The commission will give great weight to:

(-a-) the recommendation of an organization that meets the requirement of PURA §39.151; and/or

(-b-) written documentation provided by a transmission service provider to ERCOT that the transmission line is needed to interconnect transmission service or retail customers.

(iii) Resiliency. ERCOT may recommend, and the commission may approve, a transmission project that is submitted as an economic or reliability project and does not demonstrate sufficient economic savings or reliability benefits to merit approval on those grounds if ERCOT determines the line would address a resiliency issue identified in the grid reliability and resiliency assessment required by subparagraph (E) of this paragraph. In determining whether to approve such a project the commission will consider:

(I) the margin by which the transmission project was unable to demonstrate sufficient economic savings or reliability benefits to merit approval on those grounds;

(II) whether the resiliency benefits the transmission project would provide by reducing the impacts to customers of potential outages caused by regional extreme weather scenarios are sufficient to compensate for the project's inability to demonstrate sufficient economic savings or reliability benefits to merit approval on those grounds.

(III) the cost effectiveness of the transmission project's ability to address the resiliency issue identified by ERCOT compared to other possible solutions,

(IV) other factors listed in PURA §37.056(c), as appropriate.

(B) Routing: An application for a new transmission line must address the criteria in PURA §37.056(c) and considering those criteria, engineering constraints, and costs, the line must be routed to the extent reasonable to moderate the impact on the affected community and landowners unless grid reliability and security dictate otherwise. The following factors must be considered in the selection of the utility's alternative routes unless a route is agreed to by the utility, the landowners whose property is crossed by the proposed line, and owners of land that contains a habitable structure within 300 feet of the centerline of a transmission project of 230 kV or less, or within 500 feet of the centerline of a transmission project greater than 230 kV, and otherwise conforms to the criteria in PURA §37.056(c):

(i) whether the routes parallel or utilize existing compatible rights-of-way for electric facilities, including the use of vacant positions on existing multiple- circuit transmission lines;

(ii) whether the routes parallel or utilize other existing compatible rights-of- way, including roads, highways, railroads, or telephone utility rights-of-way;

(iii) whether the routes parallel property lines or other natural or cultural features; and

(iv) whether the routes conform with the policy of prudent avoidance.

(C) Uncontested transmission lines: An application for a certificate for a transmission line will be approved administratively within 80 days from the date of filing a complete application if:

(i) no motion to intervene has been filed or the application is uncontested; and

(ii) commission staff has determined that the application is complete and meets all applicable statutory criteria and filing requirements, including, but not limited to, the provision of proper notice of the application.

(D) Projects deemed critical to reliability. Applications for transmission lines which have been formally designated by a PURA §39.151 organization as critical to the reliability of the system will be considered by the commission on an expedited basis. The commission will render a decision approving or denying an application for a certificate under this subparagraph within 180 days of the date of filing a complete application for such a certificate unless good cause is shown for extending that period.

(E) Grid reliability and resiliency assessment. ERCOT must conduct a biennial assessment of the ERCOT power grid's reliability and resiliency in extreme weather scenarios. Each assessment must:

(i) consider the impact of different levels of thermal and renewable generation availability;

(ii) identify areas of the state that face significant grid reliability and resiliency issues, taking into account the impact of potential outages caused by regional extreme weather scenarios on customers, including multiple element outage analysis when appropriate, and

(iii) recommend transmission projects that may increase the grid's reliability or resiliency in extreme weather scenarios.

(4) Tie line. An application for a tie line must include a study of the tie line by ERCOT. The study must include, at a minimum, an ERCOT-approved reliability assessment of the proposed tie line. If an independent system operator intends to conduct a study to evaluate a proposed tie line or intends to provide confidential information to another entity to permit the study of a proposed tie line, the independent system operator must file notice with the commission at least 45 days prior to the commencement of such a study or the provision of such information.

(c) Projects or activities not requiring a certificate. A certificate, or certificate amendment, is not required for the following:

(1) An extension of facilities as described in PURA §37.052(a) and (b);

(2) A new electric high voltage switching station, or substation;

(3) The repair or reconstruction of a transmission facility due to emergencies. The repair or reconstruction of a transmission facility due to emergencies should proceed without delay or prior approval of the commission and must be reported to the commission in accordance with §25.83 of this title (relating to Transmission Construction Reports);

(4) The construction or upgrading of distribution facilities within the electric utility's service area;

(5) Routine activities associated with transmission facilities that are conducted by transmission service providers. Nothing contained in the following subparagraphs should be construed as a limitation of the commission's authority as set forth in PURA. Any activity described in the following subparagraphs must be reported to the commission in accordance with §25.83 of this title. The commission may require additional facts or call a public hearing thereon to determine whether a certificate of convenience and necessity is required. Routine activities are defined as follows:

(A) The modification, construction, or extension of a transmission line that connects existing transmission facilities to a substation or metering point provided that:

(i) the transmission line modification, construction, or extension does not exceed:

(I) five miles if the line connects to a load-serving substation or metering point; or

(II) two miles if the line connects to a generation substation or metering point; and

(ii) all rights-of-way necessary for the modification, construction, or extension have been acquired, and

(iii) all landowners whose property is directly affected by the transmission line, as defined in §22.52(a)(3) of this title (relating to Notice in Licensing Proceedings), have given written consent for the modification, construction, or extension. If the transmission line modification, construction, or extension does not exceed one mile to provide service to a substation or metering point, written consent is only required by landowners whose property is crossed by the transmission line.

(B) The rebuilding, replacement, or respacing of structures along an existing route of the transmission line; upgrading to a higher voltage not greater than 230 kV; bundling of conductors or reconductoring of an existing transmission facility, provided that:

(i) no additional right-of-way is required; or

(ii) if additional right-of-way is required, all landowners of property crossed by the electric facilities have given prior written consent.

(C) The installation, on an existing transmission line, of an additional circuit not previously certificated, provided that:

(i) the additional circuit is not greater than 230 kV; and

(ii) all landowners whose property is crossed by the transmission facilities have given prior written consent.

(D) The relocation of all or part of an existing transmission facility due to a request for relocation, provided that:

(i) the relocation is to be done at the expense of the requesting party; and

(ii) the relocation is solely on a right-of-way provided by the requesting party.

(E) The relocation or alteration of all or part of an existing transmission facility to avoid or eliminate existing or impending encroachments, provided that all landowners of property crossed by the electric facilities have given prior written consent.

(F) The relocation, alteration, or reconstruction of a transmission facility due to the requirements of any federal, state, county, or municipal governmental body or agency for purposes including, but not limited to, highway transportation, airport construction, public safety, or air and water quality, provided that:

(i) all landowners of property crossed by the electric facilities have given prior written consent; and

(ii) the relocation, alteration, or reconstruction is responsive to the governmental request.

(6) Upgrades to an existing transmission line by an MPE that do not require any additional land, right-of-way, easement, or other property not owned by the MOU;

(7) The construction, installation, or extension of a transmission facility by an MPE that is entirely located not more than 10 miles outside of an MOU's certificated service area that occurs before September 1, 2021; or

(8) A transmission facility by an MOU placed in service after September 1, 2015, that is developed to interconnect a new natural gas generation facility to the ERCOT transmission grid and for which, on or before January 1, 2015, an MOU was contractually obligated to purchase at least 190 megawatts of capacity.

(d) Standards of construction and operation. In determining standard practice, the commission will be guided by the provisions of the American National Standards Institute, Incorporated, the National Electrical Safety Code, and such other codes and standards that are generally accepted by the industry, except as modified by this commission or by municipal regulations within their jurisdiction. Each electric utility must construct, install, operate, and maintain its plant, structures, equipment, and lines in accordance with these standards, and in such manner to best accommodate the public, and to prevent interference with service furnished by other public utilities insofar as practical.

(1) The standards of construction apply to, but are not limited to, the construction of any new electric transmission facilities, rebuilding, upgrading, or relocation of existing electric transmission facilities.

(2) For electric transmission line construction requiring the acquisition of new rights-of-way, an electric utility must include in the easement agreement, at a minimum, a provision prohibiting the new construction of any above-ground structures within the right-of-way. For this purpose, new construction of above-ground structures does not include necessary repairs to existing structures, farm or livestock facilities, storage barns, hunting structures, small personal storage sheds, or similar structures. A utility may negotiate appropriate exceptions in instances where the electric utility is subject to a restrictive agreement being granted by a governmental agency or within the constraints of an industrial site. Any exception to this paragraph must meet all applicable requirements of the National Electrical Safety Code.

(3) Measures must be applied when appropriate to mitigate the adverse impacts of the construction of any new electric transmission facilities, and the rebuilding, upgrading, or relocation of existing electric transmission facilities. Mitigation measures must be adapted to the specifics of each project and may include such requirements as:

(A) selective clearing of the right-of-way to minimize the amount of flora and fauna disturbed;

(B) implementation of erosion control measures;

(C) reclamation of construction sites with native species of grasses, forbs, and shrubs; and

(D) returning site to its original contours and grades.

(e) Certificates of convenience and necessity for existing service areas and facilities. For purposes of granting these certificates for those facilities and areas in which an electric utility was providing service on September 1, 1975, or was actively engaged in the construction, installation, extension, improvement of, or addition to any facility actually used or to be used in providing electric utility service on September 1, 1975, unless found by the commission to be otherwise, the following provisions prevail for certification purposes:

(1) The electrical generation facilities and service area boundary of an electric utility having such facilities in place or being actively engaged in the construction, installation, extension, improvement of, or addition to such facilities or the electric utility's system as of September 1, 1975, must be limited, unless otherwise provided, to the facilities and real property on which the facilities were actually located, used, or dedicated as of September 1, 1975.

(2) The transmission facilities and service area boundary of an electric utility having such facilities in place or being actively engaged in the construction, installation, extension, improvement of, or addition to such facilities or the electric utility's system as of September 1, 1975, must be, unless otherwise provided, the facilities and a corridor extending 100 feet on either side of said transmission facilities in place, used or dedicated as of September 1, 1975.

(3) The facilities and service area boundary for the following types of electric utilities providing distribution or collection service to any area, or actively engaged in the construction, installation, extension, improvement of, or addition to such facilities or the electric utility's system as of September 1, 1975, must be limited, unless otherwise found by the commission, to the facilities and the area which lie within 200 feet of any point along a distribution line, which is specifically deemed to include service drop lines, for electrical utilities.

(f) Transferability of certificates. Any certificate granted under this section is not transferable without approval of the commission and remains in force until further order of the commission.

(g) Certification forms. All applications for certificates of convenience and necessity must be filed on commission-prescribed forms so that the granting of certificates, both contested and uncontested, may be expedited. Forms may be obtained from Central Records.

(h) Commission authority. Nothing in this section is intended to limit the commission's authority to recommend or direct the construction of transmission under PURA §§35.005, 36.008, or 39.203(e).

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on July 30, 2026.

TRD-202603234

Katelyn Lewis

Rules Coordinator

Public Utility Commission of Texas

Effective date: August 19, 2026

Proposal publication date: April 17, 2026

For further information, please call: (512) 936-7044