H-4127.1
SUBSTITUTE HOUSE BILL 2510
State of Washington
65th Legislature
2018 Regular Session
By House Technology & Economic Development (originally sponsored by Representatives Morris, Hudgins, and Santos)
READ FIRST TIME 01/30/18.
AN ACT Relating to net metering; and amending RCW 80.60.010, 80.60.020, and 80.60.030.
BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF WASHINGTON:
Sec. 1.  RCW 80.60.010 and 2007 c 323 s 1 are each amended to read as follows:
The definitions in this section apply throughout this chapter unless the context clearly indicates otherwise.
(1) "Commission" means the utilities and transportation commission.
(2) "Customer-generator" means a user of a net metering system.
(3) "Electrical company" means a company owned by investors that meets the definition of RCW 80.04.010.
(4) "Electric cooperative" means a cooperative or association organized under chapter 23.86 or 24.06 RCW.
(5) "Electric utility" means any electrical company, public utility district, irrigation district, port district, electric cooperative, or municipal electric utility that is engaged in the business of distributing electricity to retail electric customers in the state.
(6) "Irrigation district" means an irrigation district under chapter 87.03 RCW.
(7) "Meter aggregation" means the administrative combination of readings from and billing for all meters, regardless of the rate class, on premises owned or leased by a customer-generator located within the service territory of a single electric utility.
(8) "Municipal electric utility" means a city or town that owns or operates an electric utility authorized by chapter 35.92 RCW.
(9) "Net metering" means measuring the difference between the electricity supplied by an electric utility and the electricity generated by a customer-generator over the applicable billing period.
(10) "Net metering system" means a fuel cell, a facility that produces electricity and used and useful thermal energy from a common fuel source, or a facility for the production of electrical energy that generates renewable energy, and that:
(a) Has an electrical generating capacity of not more than one ((hundred)) thousand kilowatts and is sized no greater than the capacity required to meet one hundred percent of the customer-generator's total electricity consumption during the previous year;
(b) Is located on the customer-generator's premises;
(c) Operates in parallel with the electric utility's transmission and distribution facilities; and
(d) Is intended primarily to offset part or all of the customer-generator's requirements for electricity.
(11) "Premises" means any residential property, commercial real estate, or lands, owned or leased by a customer-generator within the service area of a single electric utility.
(12) "Port district" means a port district within which an industrial development district has been established as authorized by Title 53 RCW.
(13) "Public utility district" means a district authorized by chapter 54.04 RCW.
(14) "Renewable energy" means energy generated by a facility that uses water, wind, solar energy, or biogas from animal waste as a fuel.
Sec. 2.  RCW 80.60.020 and 2007 c 323 s 2 are each amended to read as follows:
(1) An electric utility:
(a) Shall offer to make net metering available to eligible customers-generators on a first-come, first-served basis until the cumulative generating capacity of net metering systems equals ((0.25)) 2.5 percent of the utility's peak demand during 1996. ((On January 1, 2014, the cumulative generating capacity available to net metering systems will equal 0.5 percent of the utility's peak demand during 1996.)) Not less than one-half of the utility's 1996 peak demand available for net metering systems shall be reserved for the cumulative generating capacity attributable to net metering systems that generate renewable energy;
(b) Shall allow net metering systems to be interconnected using a standard kilowatt-hour meter capable of registering the flow of electricity in two directions, unless the commission, in the case of an electrical company, or the appropriate governing body, in the case of other electric utilities, determines, after appropriate notice and opportunity for comment:
(i) That the use of additional metering equipment to monitor the flow of electricity in each direction is necessary and appropriate for the interconnection of net metering systems, after taking into account the benefits and costs of purchasing and installing additional metering equipment; and
(ii) How the cost of purchasing and installing an additional meter is to be allocated between the customer-generator and the utility;
(c) Shall charge the customer-generator a minimum monthly fee that is the same as other customers of the electric utility in the same rate class, but shall not charge the customer-generator any additional standby, capacity, interconnection, or other fee or charge unless the commission, in the case of an electrical company, or the appropriate governing body, in the case of other electric utilities, determines, after appropriate notice and opportunity for comment that:
(i) The electric utility will incur direct costs associated with interconnecting or administering net metering systems that exceed any offsetting benefits associated with these systems; and
(ii) Public policy is best served by imposing these costs on the customer-generator rather than allocating these costs among the utility's entire customer base.
(2) In order to offer an alternative to net metering under this chapter, an electric utility that reaches the cumulative generating capacity threshold specified under subsection (1)(a) of this section must first engage in a distributed energy resources planning process that accomplishes the following:
(a) Identifies the data gaps that impede a robust planning process as well as any upgrades, such as but not limited to advanced metering and grid monitoring equipment, needed to obtain data that would allow the electric utility to quantify the locational and temporal value of resources on the distribution system;
(b) Proposes monitoring and metering upgrades that are supported by a business case identifying how those upgrades will be leveraged to provide net benefits for customers;
(c) Identifies potential programs and tariffs to fairly compensate customers for the value of their distributed energy resources, which may both produce and consume electricity and capacity from the distribution system individually or in groups, and ensure their optimal usage, including programs targeted at low-income customers;
(d) Forecasts, using probabilistic models, the growth of distributed energy resources on the utility's distribution system;
(e) Provides, at a minimum, a ten-year plan for distribution system investments and an analysis of nonwires alternatives for major investments. This plan should include a process whereby near-term assumptions regularly inform and adjust the long-term projections of the plan. The goal of the plan should be to provide the most affordable investments for all customers and avoid reactive expenditures to accommodate unanticipated growth in distributed energy resources. An analysis that fairly considers wire-based and nonwires alternatives on equal terms is foundational to achieving this goal. The electric utility should be indifferent to the technology that is used to meet a particular resource need. The distribution system investment planning process should utilize a transparent approach that involves opportunities for stakeholder input and feedback;
(f) Competitively procures the distributed energy resources needs identified in the plan through detailed requests for proposals that identify the specific needs at each identified location. Competitive procurements that are tailored to solve specific needs, rather than to procure a specific resource, increase an electric utility's ability to identify the lowest cost, most efficient means of meeting distribution system needs. If the projected cost of a procurement is more than the calculated system net benefit, the electric utility should then establish a pilot process that mimics the efficiencies of a competitive procurement;
(g) Includes the distributed energy resources identified in the plan in the electric utility's integrated resource plan developed under this chapter. Distribution system plans should be used as inputs to the integrated resource planning process. Distributed energy resources may be used to meet system needs when they are not needed to meet a local distribution need. Including select distributed energy resources in the integrated resource planning process allows those resources to displace or delay system resources in the integrated resource plan;
(h) Includes a high level discussion of how the electric utility is adapting cybersecurity and data privacy practices to the changing distribution system and the internet of things, including an assessment of the costs associated with ensuring customer privacy; and
(i) Includes a discussion of lessons learned from the planning cycle and identify process and data improvements planned for the next cycle.
(3) If a production meter and software is required by the electric utility to provide meter aggregation under RCW 80.60.030(4), the customer-generator is responsible for the purchase of the production meter and software.
Sec. 3.  RCW 80.60.030 and 2007 c 323 s 3 are each amended to read as follows:
Consistent with the other provisions of this chapter, the net energy measurement must be calculated in the following manner:
(1) The electric utility shall measure the net electricity produced or consumed during the billing period, in accordance with normal metering practices.
(2) If the electricity supplied by the electric utility exceeds the electricity generated by the customer-generator and fed back to the electric utility during the billing period, the customer-generator shall be billed for the net electricity supplied by the electric utility, in accordance with normal metering practices.
(3) If electricity generated by the customer-generator exceeds the electricity supplied by the electric utility, the customer-generator:
(a) Shall be billed for the appropriate customer charges for that billing period, in accordance with RCW 80.60.020; and
(b) Shall be credited for the excess kilowatt-hours generated during the billing period, with this kilowatt-hour credit appearing on the bill for the following billing period.
(4) If a customer-generator requests, an electric utility shall provide meter aggregation.
(a) For customer-generators participating in meter aggregation, kilowatt-hours credits earned by a net metering system during the billing period first shall be used to offset electricity supplied by the electric utility.
(b) Not more than a total of one ((hundred)) thousand kilowatts shall be aggregated among all customer-generators participating in a generating facility under this subsection.
(c) Excess kilowatt-hours credits earned by the net metering system, during the same billing period, shall be credited equally by the electric utility to remaining meters located on all premises of a customer-generator at the designated rate of each meter.
(d) Meters so aggregated shall not change rate classes due to meter aggregation under this section.
(5) On April 30th of each calendar year, any remaining unused kilowatt-hour credit accumulated during the previous year shall be granted to the electric utility, without any compensation to the customer-generator.
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