Relating to the planning for, interconnection and operation of, and costs related to providing service for certain electrical loads and to the generation of electric power by a water supply or sewer service corporation.

89(R) SB 6 - Enrolled version - Bill Text

S.B. No. 6

AN ACT

relating to the planning for, interconnection and operation of, and

costs related to providing service for certain electrical loads and

to the generation of electric power by a water supply or sewer

service corporation.

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

SECTION 1. Section 35.004, Utilities Code, is amended by

adding Subsections (c-1) and (c-2) to read as follows:

(c-1)

The commission by rule shall ensure that a large load

customer who is subject to the standards adopted under Section

37.0561 contributes to the recovery of the interconnecting electric

utility's costs to interconnect the large load to the utility's

system.

(c-2)

An electric cooperative or municipally owned utility

that has not adopted customer choice shall pass through to a large

load customer who is subject to the standards adopted under Section

37.0561 the reasonable costs to interconnect the large load in a

manner determined by the electric cooperative or municipally owned

utility.

SECTION 2. Subchapter B, Chapter 37, Utilities Code, is

amended by adding Section 37.0561 to read as follows:

Sec.

37.0561.

PLANNING FOR AND INTERCONNECTION OF LARGE

LOADS. (a) For the purposes of this section, a large load customer

includes an entity requesting an interconnection that exceeds the

demand threshold adopted under Subsection (c) and a successor in

interest to such an entity.

(b)

The commission by rule shall establish standards for

interconnecting large load customers in the ERCOT power region in a

manner designed to support business development in this state while

minimizing the potential for stranded infrastructure costs and

maintaining system reliability.

(c)

The standards must apply only to customers requesting a

new or expanded interconnection where the total load at a single

site would exceed 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 (b).

(d)

The standards must require each large load customer

subject to Subsection (c) to disclose to the interconnecting

electric utility or municipally owned utility whether the customer

is pursuing a substantially similar request for electric service in

this state the approval of which would result in the customer

materially changing, delaying, or withdrawing the interconnection

request.

The disclosure may withhold or anonymize competitively

sensitive details.

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 other than a disclosure to the commission or the

independent organization certified under Section 39.151 for the

ERCOT power region, subject to appropriate confidentiality

protections.

(e)

The standards must require each interconnected large

load customer subject to Subsection (c) to disclose to the

interconnecting electric utility or municipally owned utility

information about the customer's on-site backup generating

facilities and require the interconnecting electric utility or

municipally owned utility to provide the information to the

independent organization certified under Section 39.151 for the

ERCOT power region.

For the purposes of this subsection, "on-site

backup generating facilities" means generation that is not capable

of exporting energy to the ERCOT transmission grid and that, in the

aggregate, can serve at least 50 percent of on-site demand. The

independent organization shall establish a threshold before or

during an energy emergency alert at which the organization may

issue reasonable notice that large load customers with on-site

backup generating facilities may be directed to either deploy the

customer's on-site backup generating facilities or curtail load.

After the independent organization deploys all available market

services, except for frequency responsive services, the

independent organization may direct the applicable electric

utility or municipally owned utility to require the large load

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

facilities or curtail load.

The independent organization shall

include a deployment under this section as firm load shed when

calculating any price adjustments for reliability deployments.

This subsection does not:

(1)

authorize or require 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 customer from participating

in a service authorized by Section 39.170(b).

(f)

The standards must set a flat study fee of at least

$100,000 to be paid to the interconnecting electric utility or

municipally owned utility for initial transmission screening

studies for large loads subject to Subsection (c). A large load

customer that requests additional capacity following the screening

study must pay an additional study fee based on the new request.

The interconnecting electric utility or municipally owned utility

shall apply any unused portion of the initial transmission

screening study fee as a credit toward satisfying financial

obligations for procurement or interconnection agreements at the

same geographic site.

(g)

The standards must include a method for a large load

customer subject to Subsection (c) to demonstrate site control for

the proposed load location through an ownership interest, lease, or

another legal interest acceptable to the commission.

(h)

The standards must include uniform financial commitment

requirements for the development of transmission infrastructure

needed to serve a large load customer subject to Subsection (c).

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) contribution in aid of construction;

(3)

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

(4)

a form of financial commitment acceptable to the

commission other than those provided by Subdivisions (1)-(3).

(i)

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

refunded, in whole or in part, after the security is applied to any

outstanding amounts owed:

(1)

as the large load customer meets the customer's

load ramp milestones and sustains operations for a prescribed

period as determined by the commission;

(2)

if the large load customer withdraws the

customer's request for all or a portion of the requested capacity;

or

(3)

if capacity subject to a financial commitment will

be reallocated to one or more other customers.

(j)

The commission shall establish uniform requirements for

determining when capacity that is subject to an outstanding

financial commitment under this section may be reallocated.

(k)

The standards must establish a procedure to allow the

independent organization certified under Section 39.151 for the

ERCOT power region to access any information collected by the

interconnecting electric utility or municipally owned utility to

ensure compliance with the standards for transmission planning

analysis. Any customer-specific or competitively sensitive

information obtained under this subsection is confidential and not

subject to disclosure under Chapter 552, Government Code.

(l)

The commission may not limit the authority of a

municipally owned utility or an electric cooperative to impose

electric service requirements for large load customers on their

systems in addition to the standards adopted under this section.

(m)

Notwithstanding the forecasted load growth and

additional load currently seeking interconnection required to be

considered under Section 37.056(c-1), the commission by rule shall

establish criteria by which the independent organization certified

under Section 39.151 for the ERCOT power region includes forecasted

large load of any peak demand in the organization's transmission

planning and resource adequacy models and reports.

SECTION 3. 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 4. 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 LARGE LOAD CUSTOMER WITH

EXISTING GENERATION RESOURCE. (a)

A power generation company,

municipally owned utility, or electric cooperative must submit a

notice to the independent organization certified under Section

39.151 for the ERCOT power region before implementing a net

metering arrangement between an operating facility registered with

the independent organization as a stand-alone generation resource

as of September 1, 2025, and a new large load customer as described

by Section 37.0561(c).

(b) This section does not apply to a generation resource:

(1)

the registration for which included a co-located

large load customer at the time of energization, regardless of

whether the load was energized at a later date; or

(2)

a majority interest of which is owned indirectly

or directly as of January 1, 2025, by a parent company of the

customer that participates in the new net metering arrangement.

(c)

The electric cooperative, transmission and distribution

utility, or municipally owned utility that provides electric

service at the location of the new net metering arrangement may for

reasonable cause including a violation of other law, object to the

arrangement, provided however, that no reasonable cause objection

may be raised after a final decision by the commission is issued

under this section.

(d)

The independent organization certified under Section

39.151 for the ERCOT power region shall study the system impacts of

a proposed net metering arrangement and removal of generation for

which the independent organization receives a notice under

Subsection (a) after the independent organization receives all

information regarding the arrangement required by the independent

organization to be submitted to the independent organization.

The

independent organization must complete the study and submit the

results to the commission with any associated recommendations not

later than the 120th day after the independent organization

receives all required information regarding the arrangement.

Not

later than the 60th day after the date the commission receives the

study results from the independent organization, the commission

shall approve, deny, or impose reasonable conditions on the

proposed net metering arrangement as necessary to maintain system

reliability, including transmission security and resource adequacy

impacts.

The conditions must require a generation resource that

makes dispatchable capacity available to the ERCOT power region

before the implementation of a net metering arrangement under this

section to make at least that amount of dispatchable capacity

available to the ERCOT power region after the implementation of the

arrangement at the direction of the independent organization in

advance of an anticipated emergency condition.

The conditions may

include:

(1)

requiring the retail customer who is served

behind-the-meter to reduce load during certain events;

(2)

requiring the generation resource to make capacity

available to the ERCOT power region during certain events; or

(3)

requiring customers to be held harmless 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.

(f)

If conditions imposed under Subsection (d) are not

limited to a specific period, the commission shall review the

conditions at least every five years to determine whether the

conditions should be extended or rescinded.

(g)

The parties to a proceeding under this section are

limited to the commission, the independent organization certified

under Section 39.151 for the ERCOT power region, the

interconnecting electric cooperative, transmission and

distribution utility, or municipally owned utility, and a party in

the net metering arrangement.

(h)

The commission shall post the decision made on each

notice submitted under this section on the commission's Internet

website.

The commission may not post information regarding the

decision that is competitively sensitive or otherwise considered

confidential.

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, transmission and distribution

utility, and municipally owned utility serving a

transmission-voltage customer develops a protocol, including the

installation of any necessary equipment or technology before the

customer is interconnected, to allow the load to be curtailed

during firm load shed. The electric cooperative, transmission and

distribution utility, or municipally owned utility shall confer

with the customer to the extent feasible to shed load in a

coordinated manner. 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 with a demand of at

least 75 megawatts to be deployed in the event of an anticipated

emergency condition. The rules governing this service must:

(1)

specify the periods when the service may be used to

assist with maintaining reliability during extreme weather events;

(2)

ensure that the independent organization provides

at least a 24-hour notice to large load customers and requires each

large load to remain curtailed for the duration of the energy

emergency alert event or until the load can be recalled safely; and

(3)

prohibit participation by any large load customer

that curtails 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 participates

in a different reliability or ancillary service.

(c)

The independent organization certified under Section

39.151 for the ERCOT power region shall include a deployment under

this section when calculating any price adjustments for reliability

deployments.

SECTION 5. Subchapter A, Chapter 67, Water Code, is amended

by adding Section 67.0115 to read as follows:

Sec.

67.0115.

ELECTRIC GENERATION. (a) A corporation may

generate electric power for use in the corporation's operations,

limited to:

(1)

powering water well pumps, service pumps, and

other equipment for the production, treatment, and transportation

of raw water; and

(2)

powering infrastructure for the treatment and

delivery of potable drinking water.

(b)

For the purposes of Subsection (a), a corporation

operating solely as a wholesale water supplier or sewer service in a

county with a population of less than 350,000 may generate excess

electric power in conjunction with the uses described in Subsection

(a) for sale in the ERCOT power region to provide revenue for the

corporation only if the corporation:

(1)

primarily generates electric power solely for the

uses described in Subsection (a); and

(2)

registers as a power generation company under

Section 39.351, Utilities Code.

(c)

A corporation that generates electric power for sale

under Subsection (b) shall account for and use the revenue from

those sales in a manner that complies with Section 67.004. The

revenue that accrues from those sales of electric power may be used

by the corporation only for:

(1)

the corporation's costs of producing and selling

electric power, including administration, employees, equipment,

fuel, and maintenance; or

(2) a purpose described by Section 67.002.

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

evaluate whether the existing methodology used to charge 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:

(1) whether the current four coincident peak

methodology used to calculate wholesale transmission rates ensures

that all loads appropriately contribute to the recovery of an

electric cooperative's, electric utility's, or municipally owned

utility's costs to provide access to the transmission system;

(2) whether alternative methods to calculate

wholesale transmission rates would more appropriately assign the

cost of providing access to and wholesale service from the

transmission system, such as consideration of multiple seasonal

peak demands, demand during different length daily intervals, or

peak energy intervals; and

(3) the portion of the costs related to access to and

wholesale service from the transmission system that should be

nonbypassable, consistent with Section 35.004(c-1), Utilities

Code, as added by this Act.

(b) The Public Utility Commission of Texas shall evaluate

whether the commission's retail ratemaking practices ensure that

transmission cost recovery appropriately charges the system costs

that are caused by each customer class.

(c) The Public Utility Commission of Texas shall begin the

evaluation required under Subsection (a) of this section not later

than the 90th day after the effective date of this Act. After

completion of the evaluation project and not later than December

31, 2026, the commission shall amend commission rules to ensure

that wholesale transmission charges appropriately assign costs for

transmission investment.

SECTION 7. Section 35.004(c-1), Utilities Code, as added by

this Act, applies only to an interconnection agreement entered into

on or after the effective date of this Act.

SECTION 8. 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.

______________________________

______________________________

President of the Senate

Speaker of the House

I hereby certify that S.B. No. 6 passed the Senate on

March 19, 2025, by the following vote: Yeas 31, Nays 0; and that

the Senate concurred in House amendments on May 29, 2025, by the

following vote: Yeas 31, Nays 0.

______________________________

Secretary of the Senate

I hereby certify that S.B. No. 6 passed the House, with

amendments, on May 27, 2025, by the following vote: Yeas 103,

Nays 25, two present not voting.

______________________________

Chief Clerk of the House

Approved:

______________________________

Date

______________________________

Governor