King Grid Bill Puts Transmission Cost Rules After The Election

The text as introduced · 1,871 words

89R12894 JXC-F

By: King, Schwertner
S.B. No. 6

A BILL TO BE ENTITLED

AN ACT

relating to electricity planning and infrastructure costs for large

loads.

BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:

SECTION 1. Section 35.004(d), Utilities Code, is amended to

read as follows:

(d) The commission shall price wholesale transmission

services within ERCOT based on the postage stamp method of pricing

under which a transmission-owning utility's rate is based on the

ERCOT utilities' combined annual costs of transmission, other than

costs described by Subsections (d-2) and (d-3), divided by the

total demand placed on the combined transmission systems of all

such transmission-owning utilities within a power region. For

purposes of establishing the postage stamp rate, each

distribution-owning utility in ERCOT shall report the additional

billing determinants that would be created by applying the minimum

transmission charge calculation under Section 36.010 to the

distribution-owning utility's service area. An electric utility

subject to the freeze period imposed by Section 39.052 may treat

transmission costs in excess of transmission revenues during the

freeze period as an expense for purposes of determining annual

costs in the annual report filed under Section 39.257.

Notwithstanding Section 36.201, the commission may approve

wholesale rates that may be periodically adjusted to ensure timely

recovery of transmission investment. Notwithstanding Section

36.054(a), if the commission determines that conditions warrant the

action, the commission may authorize the inclusion of construction

work in progress in the rate base for transmission investment

required by the commission under Section 39.203(e).

SECTION 2. Subchapter A, Chapter 36, Utilities Code, is

amended by adding Section 36.010 to read as follows:

Sec. 36.010. MINIMUM TRANSMISSION CHARGE. To ensure that

all users of the transmission system in the ERCOT power region

contribute to transmission cost recovery, the commission shall

implement minimum rates that require all retail customers in that

region served behind-the-meter to pay retail transmission charges

based on a percentage of the customer's non-coincident peak demand

from the utility system as identified in the customer's service

agreement. A municipally owned utility or electric cooperative

that has not adopted customer choice shall pass through the minimum

wholesale transmission rate to the utility's or cooperative's

retail customers in a manner determined by the utility or

cooperative.

SECTION 3. Subchapter B, Chapter 37, Utilities Code, is

amended by adding Section 37.0561 to read as follows:

Sec. 37.0561. PLANNING REQUIREMENTS FOR LARGE LOADS. (a)

The commission by rule shall establish standards for

interconnecting large load customers at transmission voltage in the

ERCOT power region in a manner designed to support business

development in this state while minimizing the potential for

stranded infrastructure costs.

(b) The standards must apply only to customers with a load

that exceeds a demand threshold established by the commission based

on the size of loads that significantly impact transmission needs

in the ERCOT power region. The commission shall establish a demand

threshold of 75 megawatts unless the commission determines that a

lower threshold is necessary to accomplish the purposes described

by Subsection (a).

(c) The standards must require each large load customer

seeking interconnection to disclose to the interconnecting

electric utility or municipally owned utility whether the customer

is pursuing a duplicate request for electric service, inside or

outside this state, the approval of which would result in the

customer materially changing or withdrawing the interconnection

request. The commission by rule shall prohibit an electric utility

or municipally owned utility from selling, sharing, or disclosing

information submitted to the utility under this subsection.

(d) The standards must require each interconnected large

load customer to disclose to the independent organization certified

under Section 39.151 for the ERCOT power region information about

the customer's on-site backup generating facilities. To achieve

firm load shed during an energy emergency alert, the independent

organization certified under Section 39.151 for the ERCOT power

region may, after reasonable notice, direct the applicable electric

utility or municipally owned utility to require the large load

customer to deploy the customer's on-site backup generating

facility. This subsection does not:

(1) authorize a violation of any emissions limitation

in state or federal law or a violation of any other environmental

regulation; or

(2) prohibit a large load from participating in a

service authorized by Section 39.170(b).

(e) The standards must set a flat study fee of at least

$100,000 for initial transmission screening studies for large loads

above the minimum demand threshold determined under Subsection (b).

Any unused portion of the initial transmission screening study fee

must be applied as a credit toward security for procurement or

interconnection agreements at the same geographic site.

(f) The standards must include a method for a large load

customer to demonstrate that the customer controls the site where

the load will be located through an ownership interest or another

legal interest acceptable to the commission.

(g) The standards must include uniform financial commitment

standards for the development of transmission infrastructure

needed to serve a large load customer before an electric utility or

municipally owned utility may submit a project for review by ERCOT

based on the large load customer's demand. The standards must

provide that satisfactory proof of financial commitment may

include:

(1) security provided on a dollar per megawatt basis

as set by the commission;

(2) security provided under an agreement that requires

a large load customer to pay for significant equipment or services

in advance of signing an agreement to establish electric delivery

service; or

(3) another form of financial commitment acceptable to

the commission.

(h) Security provided under Subsection (g)(1) must be

refunded, in whole or in part, as the large load customer meets the

customer's requested load ramp milestones and sustains operations

for a prescribed period of time as determined by the commission.

(i) The commission may not limit the authority of a

municipally owned utility or an electric cooperative to impose

retail electric service requirements for large load customers in

addition to the standards adopted under this section.

SECTION 4. Section 39.002, Utilities Code, is amended to

read as follows:

Sec. 39.002. APPLICABILITY. This chapter, other than

Sections 39.151, 39.1516, 39.155, 39.157(e), 39.161, 39.162,

39.163, 39.169, 39.170, 39.203, 39.9051, 39.9052, and 39.914(e),

and Subchapters M and N, does not apply to a municipally owned

utility or an electric cooperative. Sections 39.157(e) and 39.203

apply only to a municipally owned utility or an electric

cooperative that is offering customer choice. If there is a

conflict between the specific provisions of this chapter and any

other provisions of this title, except for Chapters 40 and 41, the

provisions of this chapter control.

SECTION 5. Subchapter D, Chapter 39, Utilities Code, is

amended by adding Sections 39.169 and 39.170 to read as follows:

Sec. 39.169. CO-LOCATION OF RETAIL CUSTOMER WITH EXISTING

GENERATION RESOURCE. (a) A power generation company, municipally

owned utility, or electric cooperative must submit a notice to the

commission and the independent organization certified under

Section 39.151 for the ERCOT power region before implementing a new

net metering arrangement between a facility registered with the

independent organization as a generation resource and an

unaffiliated retail customer if:

(1) the retail customer's demand would exceed 10

percent of the nameplate capacity of the existing generation

resource; and

(2) the facility owner has not proposed to construct

an equal amount of replacement capacity in the same general area.

(b) For the purposes of Subsection (a)(2), nameplate

capacity from dispatchable thermal generation is considered to be

replaced only if the replacement capacity is from dispatchable

thermal generation.

(c) The new net metering arrangement must be requested or

consented to by the electric cooperative, electric utility, or

municipally owned utility certificated to provide retail electric

service at the location.

(d) With input from the independent organization certified

under Section 39.151 for the ERCOT power region, not later than the

180th day after the date the commission receives the notice under

Subsection (a), the commission shall approve, deny, or impose

reasonable conditions on a proposed net metering arrangement

described by Subsection (a) as necessary to maintain system

reliability. The conditions may include requirements:

(1) that behind-the-meter load ramp down during

certain events;

(2) that generation reenter energy markets in the

ERCOT power region during certain events; and

(3) that the generation resource will be held liable

for stranded or underutilized transmission assets resulting from

the behind-the-meter operation.

(e) If the commission does not approve, deny, or impose

reasonable conditions on a proposed net metering arrangement

before the expiration of the deadline established by Subsection

(d), the commission is considered to have approved the arrangement.

Sec. 39.170. LARGE LOAD DEMAND MANAGEMENT SERVICE. (a) The

commission shall require the independent organization certified

under Section 39.151 for the ERCOT power region to ensure that each

electric cooperative, electric utility, and municipally owned

utility serving a transmission-voltage large load customer that is

subject to the standards adopted under Section 37.0561 installs, or

requires to be installed, before the customer is interconnected,

equipment that allows the load to be remotely disconnected during

firm load shed. This subsection applies only to a load

interconnected after December 31, 2025, that is not:

(1) load operated by a critical load industrial

customer, as defined by Section 17.002; or

(2) designated as a critical natural gas facility

under Section 38.074.

(b) The commission shall require the independent

organization certified under Section 39.151 for the ERCOT power

region to develop a reliability service to competitively procure

demand reductions from large load customers subject to the

standards adopted under Section 37.0561 in advance of a projected

energy emergency alert event. The service must provide at least a

24-hour notice to large load customers that participate in the

service and shall require each participating large load to remain

curtailed for the duration of the energy emergency alert event or

until the load can be recalled safely. A large load customer may

not offer for the service megawatts that curtail in response to the

wholesale price of electricity, as determined by the independent

organization certified under Section 39.151 for the ERCOT power

region, or that otherwise participate in a different reliability or

ancillary service.

SECTION 6. (a) The Public Utility Commission of Texas shall

evaluate whether the existing methodology used to allocate

wholesale transmission costs to distribution providers under

Section 35.004(d), Utilities Code, continues to appropriately

assign costs for transmission investment. The commission shall

also evaluate whether:

(1) the current methodology, including the four

coincident peak methodology, for allocating transmission costs by

transmission and distribution utilities in the ERCOT power region

to their customer classes results in a just and reasonable

allocation; or

(2) alternative methodologies should be considered.

(b) The Public Utility Commission of Texas shall open a

rulemaking project regarding the evaluation required under

Subsection (a) of this section not later than the 90th day after the

effective date of this Act. If the commission determines in the

project that a commission rule should be amended, the commission

shall adopt the final rule not later than December 31, 2026.

SECTION 7. This Act takes effect immediately if it receives

a vote of two-thirds of all the members elected to each house, as

provided by Section 39, Article III, Texas Constitution. If this

Act does not receive the vote necessary for immediate effect, this

Act takes effect September 1, 2025.