81R8630 TRH-F

By: Turner of Harris H.B. No. 1604

A BILL TO BE ENTITLED

AN ACT

relating to this state's goal for energy efficiency, including load management and demand response in the Electric Reliability Council of Texas.

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

SECTION 1. Section 39.905, Utilities Code, is amended by amending Subsection (a) and adding Subsections (b-5), (b-6), (b-7), (b-8), (b-9), (b-10), (b-11), (b-12), (b-13), and (b-14) to read as follows:

(a) It is the goal of the legislature that:

(1) electric utilities will administer energy efficiency incentive programs in a market-neutral, nondiscriminatory manner but will not offer underlying competitive services;

(2) all customers, in all customer classes, will have a choice of and access to energy efficiency alternatives and other choices from the market, including load management programs, that allow each customer to reduce energy consumption, peak demand, or energy costs;

(3) each electric utility will provide, through market-based standard offer programs or limited, targeted, market-transformation programs, incentives sufficient for retail electric providers and competitive energy service providers to acquire additional cost-effective energy efficiency for residential and commercial customers equivalent to at least:

(A) 10 percent of the electric utility's annual growth in demand of residential and commercial customers by December 31, 2007;

(B) 15 percent of the electric utility's annual growth in demand of residential and commercial customers by December 31, 2008, provided that the electric utility's program expenditures for 2008 funding may not be greater than 75 percent above the utility's program budget for 2007 for residential and commercial customers, as included in the April 1, 2006, filing; and

(C) 20 percent of the electric utility's annual growth in demand of residential and commercial customers by December 31, 2009, provided that the electric utility's program expenditures for 2009 funding may not be greater than 150 percent above the utility's program budget for 2007 for residential and commercial customers, as included in the April 1, 2006, filing;

(4) each electric utility in the ERCOT region shall use its best efforts to encourage and facilitate the involvement of the region's retail electric providers and third-party load aggregators in the delivery of efficiency programs and load management [demand response] programs under this section;

(5) retail electric providers in the ERCOT region, and electric utilities outside of the ERCOT region, shall provide customers with energy efficiency educational materials; and

(6) by January 1, 2015, each electric utility in the ERCOT region, through voluntary load management agreements with retail electric providers or third-party load aggregators, shall use load management in an amount equal to at least two percent of the electric utility's projected load-proportionate share of ERCOT's peak demand, other than demand attributable to transmission-level industrial customers [notwithstanding Subsection (a)(3), electric utilities shall continue to make available, at 2007 funding and participation levels, any load management standard offer programs developed for industrial customers and implemented prior to May 1, 2007].

(b-5) The commission shall adopt rules and procedures to ensure that electric utilities in the ERCOT region can provide, through market-based programs, incentives sufficient for retail electric providers and competitive load aggregators to acquire cost-effective load management equivalent to at least two percent of each utility's peak demand, other than demand attributable to transmission-level industrial customers, by January 1, 2015.

(b-6) The commission shall adopt rules to ensure the continued cost-effectiveness of load management under this section. At a minimum, the rules must provide:

(1) for cost-effectiveness to be measured in terms of avoided demand costs of peak generation and transmission as determined under the commission's efficiency programs; and

(2) for cost-effectiveness and avoided demand cost to be recalculated at least once every two years.

(b-7) The commission shall develop appropriate measurement and verification procedures.

(b-8) The commission shall adopt rules to ensure that a utility designs programs so that the utility's load management resources, including procedures for aggregating resources and monitoring and verification of customer participation as resources, are provided from customers of all classes, other than transmission-level industrial customers.

(b-9) Any additional load reduction acquired because of a utility's load management program may be counted toward the utility's earned bonus under this chapter, but not toward the satisfaction of the legislature's goals under Subsection (a)(3).

(b-10) Each utility shall develop procedures to enable the utility to call on load management resources during periods of peak demand, peak transmission or distribution congestion, or emergency in the utility's service territory.

(b-11) The commission shall adopt rules to ensure that a utility's load management resources are also eligible to provide ancillary services to ERCOT in the event of a system-wide peak in demand, a system-level congestion, or another emergency.

(b-12) A utility may not enter into a contract directly with an end-use customer to provide load management services, unless the commission determines that the service is not a competitive energy service as defined by commission rule.

(b-13) In addition to existing demand response programs, ERCOT shall establish a summer system peak reduction program in which ERCOT may restrict service to participating loads between June 1 and September 30 of each year. The summer system peak reduction program shall consist of cost-effective demand response that:

(1) produces avoided demand cost of:

(A) at least two percent of ERCOT's projected peak load during the period specified by this subsection by September 30, 2010; and

(B) at least five percent of ERCOT's projected peak load during the period specified by this subsection by September 30, 2015;

(2) increases ERCOT's total avoided demand cost during the period specified by this subsection each year until September 30, 2015;

(3) makes participating loads available for restriction by ERCOT during the expected peak hours, as determined by ERCOT, in the period specified by this subsection; and

(4) ensures that a participating resource:

(A) may not be restricted more than eight times per year;

(B) may not be subject to a restriction that lasts for more than three hours;

(C) receives at least two hours notice before the imposition of a restriction under this subsection;

(D) is eligible to provide supplemental services to utilities to satisfy the requirements of Subsection (a)(6); and

(E) receives an additional payment for a voluntary load restriction in excess of the limits specified by this subsection.

(b-14) ERCOT shall incorporate demand response resources into its ancillary service markets and other programs by:

(1) establishing a minimum goal of 50 percent participation of demand response resources in ancillary service markets, where feasible, including non-spin reserves and ancillary service relating to the integration of wind energy and other renewable energy sources;

(2) expanding participation of demand response resources in handling changes in load capacity;

(3) not later than two years after the implementation of a nodal market system, establishing a program to allow demand to be bid into the energy market on a similar basis as generation, to mitigate the exercise of market power;

(4) eliminating all conditions of participation in ERCOT ancillary service and reliability markets, except for those conditions that are required to ensure system reliability to facilitate the participation of smaller loads;

(5) working with municipally owned utilities and electric cooperatives that have not opted into competition to allow customers within the municipally owned utility's or electric cooperative's service areas to participate in statewide demand response programs; and

(6) allowing demand response resources to participate in utility load management programs if the demand response resource can meet the performance requirements of each program.

SECTION 2. This Act takes effect September 1, 2009.