Net Metering in Michigan

Net Metering

Only 30 ft tall kicks in at 6mph and at 12mph produces 36kw enough to power 30 average homes

Last Updated November 24, 2015

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      Michigan

    • Incentive Type:

      Net Metering

    • Start Date:

      05/26/2009

    • Eligible Renewable/Other Technologies:

      Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Municipal Solid Waste, Landfill Gas, Tidal, Wave, Hydroelectric (Small), Anaerobic Digestion

    • Applicable Sectors:

      Commercial, Industrial, Investor-Owned Utility, Local Government, Nonprofit, Municipal Utilities, Residential, Cooperative Utilities, Schools, State Government, Federal Government, Agricultural

    • Applicable Utilities:

      Investor-owned utilities, MPSC rate-regulated electric cooperatives, all alternative electric suppliers

    • System Capacity Limit:

      150 kW

    • Aggregate Capacity Limit:

      0.75% of utility’s peak load during previous year

    • Net Excess Generation:

      Credited to customer’s next bill at retail rate for systems 20 kW or less; credited to customer’s next bill at power supply component of retail rate for larger systems. Carries over indefinitely.

    • Ownership of Renewable Energy Credits:

      Customer owns RECs

    • Meter Aggregation:

      Not addressed

Summary

In October 2008, Michigan enacted P.A. 295, requiring the Michigan Public Service Commission (MPSC) to establish a statewide net metering program for renewable energy systems. On May 26, 2009 the MPSC issued an order formally adopting revised net metering and interconnection rules to implement P.A. 295 of 2008.

Availability

Michigan’s net metering law applies only to rate-regulated utilities and alternative electric suppliers. The designation “rate-regulated utility” presently includes investor-owned utilities and rural electric distribution cooperatives that have not opted for member regulation. As of April 2011, only Cherryland, Alger Delta, and Tri County electric cooperatives have opted for member regulation. Municipal utility rates are not regulated by the MPSC.

Eligible Technologies and System Size

Renewable energy systems using solar, wind, biomass, geothermal, anaerobic digester gas, landfill gas, municipal solid waste, and moving water are eligible for net metering. The definition of biomass is very broad and includes agricultural crops and crop wastes; energy crops; animal wastes; paper and pulp products; and a variety wood waste materials. Moving water technologies include those using waves, tides, and currents as well as traditional hydropower using water released through a dam.

Net metering billing practices are split into two distinct categories. All qualifying customer generators up to 20 kilowatts (kW) are eligible for “true” net metering, while most systems between 20 kW and 150 kW are eligible for “modified” net metering.*

In general, the capacity of an individual system is limited to that which will meet their own needs. The rules describe several options a customer can use to arrive at this value.

Aggregate Cap

True net metering is available until the aggregate net metered capacity reaches 0.5% of a utility’s peak load. Modified net metering is available until the aggregate net-metered capacity reaches an additional 0.25% of a utility’s peak load for systems of 150 kW or less and 0.25% for systems larger than 150 kW.

Nondiscriminatory Rates Requirement

Utilities must provide net metering customers with electric service at nondiscriminatory rates that are identical to those that would be charged if the customer were not participating in net metering.

Net Excess Generation

For systems of 20 kW or less, net excess generation (NEG) during a billing period may be carried forward to the next billing period at the retail rate.

Modified net metering (facilities up to 150 kW) allows NEG carry over at the power supply component of the retail rate (i.e., energy avoided cost) or the monthly average real-time locational marginal price for energy at the commercial pricing node within the electric provider’s distribution service territory each billing period.

Customers on time-of-use rates may carry forward NEG at the applicable retail rate for each time-of-use pricing period within a billing period.

NEG can be carried forward indefinitely.

Credits associated with modified net metering may not be applied against distribution charges.

Systems larger than 150 kW must pay standby charges. This practice does not meet the definition of net metering as it is generally understood, thus this summary considers only systems up to 150 kW as eligible for net metering.

Renewable Energy Credit Ownership

Customer-generators own the renewable energy credits (RECs) associated with electricity generated under the program.

Metering

Utilities serving more than 1 million customers (i.e., Consumers Energy & DTE Electric) are required, if necessary, to supply true net metering customers with a net metering compatible meter or meters at no cost to the customer. Utilities with fewer than 1 million customers must supply the appropriate meter or meters to the customer at cost, not to exceed the incremental cost above that for meters provided by the utility to similarly situated non-net metering customers. Metering configurations and cost allocations for modified net metering customers are slightly different (see R 460.648 for details).

Net metering application fees may not exceed $25 and the combined total of net metering application and interconnection review fees may not exceed $100.

Reporting

Annual net metering reports from individual utilities and alternative electricity suppliers are contained in Case U-15787, available through the PSC E-Docket System. 

Interconnection

Interconnection standards for systems up to 2 megawatts (MW) were adopted by the MPSC as part of the same administrative proceeding that addressed net metering. The forms and procedures are available here.

* Methane digesters up to 550 kW are eligible for “true” net metering or “modified” net metering, depending on its size. 

Authorities

    • Date Enacted:
      10/06/2008

    • Effective Date:
      10/06/2008

    • Date Enacted:
      05/26/2009

    • Effective Date:
      05/27/2009

    • Date Enacted:
      12/20/2012

Contact

  • Julie Baldwin

  • Organization:

    Michigan Public Service Commission

  • Address:

    P.O. Box 30221
    Lansing, MI 48909

  • Phone:

    (517) 284-8318

  • E-Mail:

Memos

Loading…

  • 11/24/2015 by Ben Inskeep

    Annual review; policy has not substantively changed; edited entry for clarity

Net Metering in New York

Net Metering

Last Updated April 8, 2017

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      New York

    • Incentive Type:

      Net Metering

    • Eligible Renewable/Other Technologies:

      Solar Photovoltaics, Wind (All), Biomass, Combined Heat & Power, Fuel Cells using Non-Renewable Fuels, Wind (Small), Hydroelectric (Small), Anaerobic Digestion, Fuel Cells using Renewable Fuels

    • Applicable Sectors:

      Commercial, Industrial, Local Government, Nonprofit, Residential, Schools, State Government, Federal Government, Agricultural, Institutional

    • Applicable Utilities:

      Investor-owned utilities

    • System Capacity Limit:

      Solar: 25 kW for residential; 100 kW for farms; 2 MW for non-residential
      Wind: 25 kW for residential; 500 kW for farm-based; 2 MW for non-residential
      Micro-hydroelectric: 25 kW for residential; 2 MW for non-residential
      Fuel Cells: 10 kW for residential; 1.5 MW for non-residential
      Biogas: 2 MW (farm-based only)
      Micro-CHP: 10 kW (residential only)

    • Aggregate Capacity Limit:

      No specific aggregate capacity limit. It was previously set at 6% of utility’s 2005 demand for solar, farm-based biogas, fuel cells, micro-hydroelectric, and residential micro-CHP, and 0.3% of utility’s 2005 demand for wind.

    • Net Excess Generation:

      Existing Net metered Customers: Generally credited to customer’s next bill at retail rate (except avoided-cost rate for micro-CHP and fuel cells); excess for residential PV and wind and farm-based biogas is reconciled annually at avoided-cost rate; excess for micro-hydro, non-residential wind and solar, and residential micro-CHP and fuel cells carries over indefinitely
      Phase One transition tariffs: Credits carried over to the next monthly billing period, and over annual periods, however unused credits will be forfeited at the end of the contract.

    • Ownership of Renewable Energy Credits:

      Generally not eligible for trading or Tier I RES compliance with exceptions for Community Distributed Energy projects.

    • Meter Aggregation:

      Allowed for non-residential and farm-based customers with solar, wind, farm-based biogas, and micro-hydroelectric systems.
      Community net metering is allowed.

Incentives

This program has 1 Incentives

    • Technologies:
      Solar Photovoltaics, Wind (All), Hydroelectric (Small)

    • Sectors:
      Residential

    • Parameters:
      The system size has a maximum of 25.00 kW

Summary

NOTE: In March 2017, the NY Public Service Commission issued an order regarding the future of net metering in the state. The order is one of the major milestones in the Reforming the Energy Vision (REV) proceeding, and addresses the transitional steps from traditional net metering into a Value of Distributed Energy Resource (VDER) tariff that accurately values and compensates distributed energy resources. Starting March 9, 2017 distributed energy projects will transition into a VDER tariff in a phased process. All projects interconnected prior to March 9, 2017 will retain their previous compensation through net energy metering. 

Introduction

New York’s original net-metering law, enacted in 1997, applied only to residential photovoltaic (PV) systems up to 10 kilowatts (kW). Over the years, the law was expanded to include other forms of electric generation equipment including farm waste, wind, micro-hydro, fuel cell, and combined heat and power systems. Net metering is available on a first-come, first-served basis to customers of the state’s major investor-owned utilities, subject to technology, system size and aggregate capacity limitations. Net metering allows the electric customers who own eligible electricity generation system to offset their utility electricity bill on a volumetric basis from the electricity generated by the system owned by the customer.

In 2015, the Public Service Commission (PSC) initiated the Reforming the Energy Vision (REV) proceeding with a vision towards a comprehensive reform in the state’s electric utility practice and regulatory paradigm. The REV initiative seeks to create a next generation of utility business models that are customer-centric and driven by technological innovation and private investments to provide resilient, affordable, and clean energy in the State. As a part of the REV proceeding, the PSC recognized the need for the development of a more accurate method of valuing distributed energy resources beyond net metering.

In March 2017, the PSC published an order on transiting from compensating distributed energy resources (DER) through net metering to the development of Value of Distributed Energy Resource (VDER) tariffs that more accurately reflect the costs and benefits of DERs on the grid. The PSC order provides a gradual transition process from net metering to VDERs over phases to avoid drastic changes in the market.

Grandfathering and the transition plan

All distributed energy projects that were interconnected prior to March 9, 2017 will be grandfathered and will continue to be compensated through net energy metering as before, unless the customer opts for the VDER tariff.

Phase One: Phase One of the transition includes two components- i) Phase One Net Energy Metering (NEM) and ii) Phase One Value Stack. Phase One NEM is identical to the previous net energy metering except the term limit of the contract is set to 20 years. Starting March 9, 2017 until January 1, 2020 all the mass market DER projects interconnected to the grid will be compensated through Phase One NEM tariff. Remote net metered customers, large on-site, and community distributed generation projects that have already paid 25% of interconnection costs, or have an executed Standard Interconnection Contract will be compensated through the Phase One NEM. Projects that don’t qualify for the Phase One NEM will be compensated based on Phase One Value Stack tariff.

Phase One Value Stack is only available to technologies and projects that were previously eligible for net metering. The Value Stack tariff will be based on monetary crediting for net hourly electricity exported to the grid. Excess credit will be eligible for carry over to subsequent billing and annual periods. Projects eligible for the Value Stack will have a term length of 25 years from their in-service date. The Value Stack for net hourly electricity exported to the grid will be calculated based on the value of:

  1. Energy Value based on Day Ahead hourly zonal locational-based marginal price (LBMP),
  2.  Capacity Value based on retail capacity rate based on performance during the peak hour in the previous year
  3.  Environmental value based on the higher of the Clean Energy Standard Tier 1 Renewable Energy Credit (REC) price or the Social Cost of Carbon (SCC)
  4. Demand Reduction Value (DRV) and Locational System Relief Value (LSRV) based on de-averaging of utility marginal cost of service studies

Community Distributed Generation (CDG) projects on the Phase One Value Stack Tariff will also receive Market Transition Credit (MTC) equal to the difference between the retail rate and the value stack. The MTC capacity for CDG is allocated into three Tranche buckets with decreasing values from the base rate

Phase Two: On May 2017, the PSC will commence the discussion on Phase Two of the transition process.

Eligible Technologies 

The eligible technologies and the system size limits remain the same for the Phase One of the net metering transition process. Publicly-owned utilities are not obligated to offer net metering; however, PSEG Long Island offers net metering on terms similar to those in the state law. Below is listing of the system size limitations, organized by technology and eligible sector.

  • Solar: 25 kW for residential, 100 kW for farms, 2 MW for non-residential
  • Wind: 25 kW for residential, 500 kW for farm-based, and 2 MW for non-residential
  • Fuel Cells: 10 kW for residential, 1.5 MW for non-residential
  • Micro-hydroelectric: 25 kW for residential, 2 MW for non-residential
  • Biogas: 2 MW (farm-based only)
  • Micro-CHP: 10 kW (residential only)

Energy Storage projects paired with eligible DER will be eligible for compensation under Phase One NEM or Value Stack tariff for mass market on-site projects. Community Distribution Generation (CDG) and Remote Net metered (RNM) projects, or large on-site systems will be compensated at Value of Stack tariff.

Aggregate Capacity

The total amount of net metering available in the state is capped at aggregate limit determined by the Public Service Commission (PSC). The aggregate limit was previously set at 1.0%, which was tripled to 3% by PSC in October 2012, and doubled again in 2014 to 6% of the utility’s 2005 electric demand. In 2015, the PSC in response to utilities reaching the 6% aggregate capacity limit, allowed the aggregate capacity to float until the successor to net metering policy was developed.

The March 2017 PSC order on the net metering transition plan eliminated the previous aggregate cap based on a peak load calculation. The PSC instead provided that all the projects interconnected after March 9, 2017 should not impact more than 2% of each utility’s incremental net annual revenue. The provision is put in place to limit the impact of VDER tariff on non-participants.

As a way of monitoring the impacts of the DERs the PSC requires the utilities to report when they hit 85% of the recommended capacity size allocations for each of the utilities. This will provide the PSC time to determine the subsequent action if necessary.

CHGE O&R NGrid NYSEG CE RGE
MWs 30 25 100 20 90 5
85% capacity (MW) 25.50 21.25 85.00 17.00 76.50 4.25

Net Excess Generation

For most types of systems, customer net excess generation (NEG) in a given month is credited to the customer’s next bill at the utility’s retail rate. However, for residential micro-CHP and fuel cell systems NEG is credited at the utility’s avoided cost rate. A slightly different methodology using a monetary credit ($ as opposed to kWh/volumetric) is used for customers on demand meters. At the end of each annual billing cycle, most customers (i.e., residential PV and wind and farm-based wind and biogas systems) will be paid at the utility’s avoided-cost rate for any unused NEG. Compensation for unused NEG produced by non-residential wind and solar systems is not addressed by the statute, however, the New York Public Service Commission (PSC) determined in its February 2009 order that unused NEG for such systems should be carried forward from one year to the next. Likewise, residential micro-CHP and fuel cell customer-generators are not permitted to monetize NEG after a year or any other period, but may carry forward unused credits indefinitely. Recently enacted S.B. 1149 did not identify a specific annual reconciliation protocol for micro-hydroelectric facilities, but the recently approved utility tariffs provide for indefinite carryover.

In May 2011 the PSC issued an order addressing two aspects of the NEG crediting process for customer generators. First, the order requires utilities to adopt consistent NEG credit calculations that include all kWh-based customer charges beginning June 1, 2011. Prior to this, some utilities did not include certain charges (e.g., the System Benefits Charge (SBC) and Renewables Portfolio Standards (RPS) surcharge) in the calculation of NEG credits. Second, the order also requires utilities to allow customers eligible for an annual cash-out of unused NEG at avoided cost, such as residential solar customers, to make a one-time selection of the annual period in question. This provision will apply to both existing and new net metering customers and is intended to avoid circumstances where the time period used for the annual cash-out is disadvantageous for some customers (i.e., large amounts of NEG being cashed-out at a lower rate). Several utilities already permitted customer-generators to make such an election.

Any excess credit from VDER Phase One tariff can be carried over to next monthly billing period, including over the end of the annual period, however at the end of the contract these unused credits will be forfeited.

Remote Net Metering

In June 2011 the state enacted legislation (A.B. 6270) allowing eligible farm-based and non-residential customer-generators to engage in “remote” net metering of solar, wind, and farm-based biogas systems. Micro-hydroelectric facilities were added as eligible for this arrangement in August 2012. The law permits eligible customer-generators to designate net metering credits from equipment located on property which they own or lease to any other meter that is located on property owned or leased by the customer, and is within the same utility territory and load zone as the net metered facility. Credits will accrue to the highest use meter first, and as with standard net metering, excess credits may be carried forward from month to month. Revised utility tariffs incorporating this change for solar, wind, and farm-based biogas systems became effective December 1, 2011. The August 2012 extension to micro-hydroelectric customer-generators will require further tariff revisions.

In October 2015, the PSC issued an order requiring the utilities to i) allow customers to assign credits from multiple host accounts to one satellite account such that the sum of all the credits do not exceed 2MW per satellite account; and ii) permit the satellite accounts with less than 2MW in host account credits to be interconnected on site generation.

The legislation and subsequent PSC orders also establish rules relating to customer responsibility for interconnection costs (e.g., new meters, transformers, or other equipment) and limitations on such costs. Cost treatments vary by customer type and system size (see § 66-j and 66-l for details).

Community Net-Metering

In July 2015 the NY Public Service Commission (PSC) issued an order that established a Community Net-metering in the State. The community net-metering allows multiple customers subscribe and receive credits to the electricity produced from off-site renewable generation facility. This policy makes it possible for renters, low-income residents, and homeowners to receive credits for renewable energy who previously could not install renewable generation facility in their homes.

In general a community energy project requires a minimum of 10 members. In March 2017, the commission allowed a waiver for a minimum ten member requirement for community distributed generation projects that are located on the site of a property serving multiple residential or non-residential customers.  The group may include a single individual subscriber that has demand greater than 25kW, who will be limited to 40% of the total facility’s output. Other subscribers will be limited to individual demand less than 25kW, and their total energy use must aggregate to at least 60% of the facility’s output. The maximum size of the community energy system is limited to 2 MW. Any single entity, including facility developer, ESCO, municipal entity, business, non-profit, LLC, partnership, or other form of business or civic association can be the sponsor of the community energy facility. The sponsor will be responsible for building and operating the facility.

Implementation of the program is divided into two phases. First phase of the program will last till April 30, 2016, during which the community net metering will serve as an introductory phase. During this period, the projects will be limited to siting distributed generation in areas where it provides greatest locational benefits to the larger grid, and in areas that promote low-income customer participation. The second phase will begin in May 1st 2016 when the community net metering projects will fully implemented throughout the other utility service territories.

Environmental Attributes

New York Generation Attribute Tracking System (NYGATS) tracks the attributes of electricity generated in or imported into the State and eligible to create and certify Renewable Energy Credits (REC). 1 REC represents the environmental attributes of 1 MWh of electricity generated through a qualifying renewable energy source. REC can be traded as commodities to demonstrate compliance to the State’s Tier I Renewable Energy Standard requirement or retired voluntarily to claim the environmental attribute of renewable energy generation.

Under previous net metering and Renewable Portfolio Standard (RPS) policy, the issue of RECs generated by net metering customers was not addressed as New York did not have a standard REC market. The current Clean Energy Standard in New York includes a Renewable Energy Standard (RES) that requires the utilities comply with the requirements via purchase or RECs or through compliance payment.

Behind the meter projects that were previously eligible to bid into Renewable Portfolio Standard (RPS) Main Tier solicitations will not be eligible to bid into Tier 1 solicitation by NYSERDA (exemptions apply). No behind the meter projects will be eligible to bid into Tier 1 solicitation conducted by NYSERDA. The RECs from these projects will be provided to the system owners for voluntary retirement, they cannot be traded or exchanged. These RECs will not be eligible for compliance for Tier 1 RES requirement, however they will be counted towards overall Statewide 50% by 2030 renewable resource goal.

DER project enrolled in the Phase One NEM including on-site mass market, small wind projects, RNM, and on-site large projects will be ineligible to bid into RES Tier 1 solicitation and will not count towards the utility’s compliance mandate, it will instead be retired on customer’s account. RECs from Community Distributed Generation projects will be counted by default towards the Utility’s Tier 1 obligation unless the customer choose to opt out.

All the RECs from the customers interconnected on the Value Stack tariff will be transferred by default to the utility for compliance for Tier I for exchange of environmental value component. The customer may choose to retain the RECs however and forgo the credit from environmental value on the tariff.

Authorities

    • Date Enacted:
      (subsequently amended)

    • Date Enacted:
      02/13/2009

    • Effective Date:
      02/27/2009

    • Date Enacted:
      06/22/2009

    • Effective Date:
      07/01/2009 (generally)

    • Date Enacted:
      02/12/2010

    • Effective Date:
      02/26/2010

    • Date Enacted:
      05/23/2011

    • Effective Date:
      05/23/2011

    • Date Enacted:
      11/21/2011

    • Date Enacted:
      06/18/2012

    • Date Enacted:
      10/18/2012

    • Date Enacted:
      06/13/2013

    • Date Enacted:
      12/15/2014

    • Effective Date:
      01/02/2015

    • Date Enacted:
      03/09/2017

    • Effective Date:
      03/09/2017

Contact

  • Organization:

    New York State Department of Public Service

  • Address:

    Agency Building 3, Empire State Plaza
    Albany, NY 12223

  • Phone:

    (518) 486-2889

  • E-Mail:

Memos

Loading…

    • 04/08/2017 by Achyut Shrestha

      In September 2016, a petition was filed before the PSC requesting a limted waiver of the ten member minimum requirement for Community Distributed Generation projects. The waiver would allow community projects on residential properties encouraging on-site solar development. In March 2017, the PSC granted the waiver. THe ten member minimum requirement will not apply to CDG projects that are located on the site of a property serving multiple residential or non-residential customers.

    • 03/14/2017 by Achyut Shrestha

      In March 2017, the NY Public Service Commission issued an order regarding the future of net metering in the state. The order as one of the major milestones in the Reforming the Energy Vision (REV) proceeding stipulates steps to transition from traditional net metering into a robust Value of Distributed Energy Resource (VDER) tariffs that accurately values and compensates the distributed energy resources in the State.

    • 01/17/2017 by Achyut Shrestha

      On November 2016, the Public Service Commission increased net metering threshold from 1 MW to 2 MW for farm waste electric generating equipment.

    • 10/28/2015 by Achyut Shrestha

      On October 16, 2015 the NY Public Service Commission issued an order addressing two of the issues raised under remote net metering. Under “one host limitation” the utilities do not allow customers to assign multiple host accounts (site of generation) to one satellite account (remote site), and under “net metering limitation” the utilities prohibit interconnection of net metering generation at sites designated as satellite account. The Commission ordered the utilities to i) allow customers to assign credits from multiple host accounts to one satellite account such that sum of all the credits do not exceed 2MW per satellite account; and ii) permit the satellite accounts with less than 2MW in host account credits to be interconnected on site generation. (Case No 15-E-0267)

    • 10/27/2015 by Achyut Shrestha

      On October 16, 2015, the NY Public Service Commission denied the Orange and Rockland Utility’s petition to cease offering net-metering and interconnections once the 6% net metering cap was met. The Commission ordered the all the NY utilities to continue accepting the applications irregardless of the cap until the issue of net metering is ultimately addressed as a part of the NY REV.

    • 08/03/2015 by Achyut Shrestha

      In July 2015, the Orange and Rockland Utility (O&R) notified the Public Service Commission (PSC) that based on applications received it had exceeded its net metering cap set at 6% of 2005 peak load (62 MW). O&R has proposed PSC to treat applications beyond 6% cap as “buy all, sell all” arrangement, where the customers pay the electricity delivered to them at normal rates, and their exported electricity will be credited at avoided cost. O&R will continue to accept netmetering applications but will notify customers that the new requests will be treated under different rate treatment as determined in the future by the PSC. (Case 15-E-0407)

    • 07/23/2015 by Achyut Shrestha

      In July 2015, the NY Public Service Commission (PSC) issued an order that established a Community Net-metering in the State.

    • 06/26/2015 by Achyut Shrestha

      In Feb 2015 NY Public Service Commission (PSC) instituted a proceeding (case no 15-E-0082) to develop community net metering program in the State. Along with the proceeding the PSC provided proposed rules for implementing community net metering. The deadline to submit comments to the proposal ended in April 2015.

  • 05/21/2015 by Achyut Shrestha

    NY Public Service Commission order (Case 14-E-0422) institutes a Transition Plan to move away from volumetric credit into monetary crediting for non-demand remote net metered systems. The commission also has instituted another proceeding (Case 13-E-0267) to reconsider tariffs that restrict generation at satellite locations for a single host remote net metering arrangement.

Net Metering in Wisconsin

Net Metering

Only 30 ft tall kicks in at 6mph and at 12mph produces 36kw enough to power 30 average homes

Last Updated November 23, 2015

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      Wisconsin

    • Incentive Type:

      Net Metering

    • Utilities:

      Algoma Utility Comm, Arcadia City of, City of Argyle, Bangor City of, City of Barron, Village of Belmont, Village of Benton, Village of Black Earth, City of Black River Falls, Bloomer Electric & Water Co, City of Boscobel, Brodhead Water & Lighting Comm, Village of Cadott, Village of Cashton, Cedarburg Light & Water Comm, Village of Centuria, Clark Electric Coop, City of Clintonville, City of Columbus, Consolidated Water Power Co, City of Cornell, City of Cuba City, Cumberland City of, Dahlberg Light & Power Co, City of Eagle River, City of Elkhorn, City of Elroy, City of Evansville, City of Fennimore, Florence Utility Comm, Village of Gresham, Hartford Electric, Village of Hazel Green, Hustisford Utilities, Jefferson Utilities, Juneau Utility Comm, City of Kaukauna, City of Kiel, La Farge Municipal Electric Co, Lake Mills Light & Water, City of Lodi, Madison Gas & Electric Co, Manitowoc Public Utilities, City of Marshfield, Village of Mazomanie, City of Medford, City of Menasha, Merrillan Village of, Mt Horeb Village of, Village of Muscoda, Village of New Glarus, City of New Holstein, City of New Lisbon, New London Electric&Water Util, Northern States Power Co – Wisconsin, Northwestern Wisconsin Elec Co, Oconomowoc Utilities, Oconto Falls Water & Light Comm, Village of Pardeeville, Pioneer Power and Light Co, City of Plymouth, Village of Prairie Du Sac, City of Princeton, Reedsburg Utility Comm, Rice Lake Utilities, City of Richland Center, City of River Falls, Rock Energy Cooperative, Village of Sauk City, Shawano Municipal Utilities, City of Sheboygan Falls, City of Shullsburg, Slinger Utilities, Spooner City of, Stoughton City of, Village of Stratford, Sturgeon Bay City of, Sun Prairie Water & Light Comm, Superior Water, Light and Power Co, Village of Trempealeau, Two Rivers Water & Light, Village of Viola, Waterloo Light & Water Comm, Village of Waunakee, Waupun Utilities, City of Westby, Whitehall Electric Utility, Wisconsin Dells Electric Util, Wisconsin Electric Power Co, Wisconsin Power & Light Co, WPPI Energy, Wisconsin Public Service Corp, Wisconsin Rapids W W & L Comm, Wonewoc Electric & Water Util, Westfield Electric Co

    • Eligible Renewable/Other Technologies:

      Geothermal Electric, Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Municipal Solid Waste, Combined Heat & Power, Wind (Small), Hydroelectric (Small), Other Distributed Generation Technologies

    • Applicable Sectors:

      Commercial, Industrial, Residential

    • Applicable Utilities:

      Investor-owned utilities, municipal utilities

    • System Capacity Limit:

      20 kW (some utilities allow larger systems to net meter)

    • Aggregate Capacity Limit:

      No limit specified

    • Net Excess Generation:

      Varies by utility

    • Ownership of Renewable Energy Credits:

      Not addressed

    • Meter Aggregation:

      Not addressed

Summary

The Public Service Commission of Wisconsin (PSC) issued an order on January 26, 1982, requiring all regulated utilities to file tariffs allowing net metering to customers that generate electricity with systems up to 20 kilowatts (kW)* in capacity.

Eligibility and Availability

The order applies to investor-owned utilities and municipal utilities, but not to electric cooperatives. All distributed-generation (DG) systems, including renewable energy and combined heat and power (CHP) systems, are eligible. There is no limit on total enrollment.

Net Excess Generation

The PSC has not adopted administrative rules for net metering.** Utilities’ net-metering tariffs contain some variations. Customer net excess generation (NEG) is generally credited at the utility’s retail rate for renewable energy, and at the utility’s avoided-cost rate for non-renewable energy. NEG credit is carried over to the customer’s next bill. If NEG credit exceeds $25, then the utility must issue a check for the amount, payable to the customer.

In December 2011, the PSC approved a process for Xcel Energy to reconcile NEG credits to customers on an annual basis at the avoided-cost rate.

Investor-Owned Utility Net Metering Tariffs

For more information on net metering, refer to the applicable utility net metering tariffs listed below. Contact your utility or visit their website if their net metering tariff is not listed below.

* Some utilities allow net metering for systems larger than 20 kW. In these cases, excess generation rates, carry-over processes, and capacity limits vary by utility. These provisions are specified in the utility tariffs.

** Subsequent PSC decisions issued June 21, 1983 in docket numbers 05-ER-11, 05-ER-12 and 05-ER-13, further implemented Sections 201 and 210 of the federal Public Utility Regulatory Policy Act of 1978 (PURPA). These decisions were confirmed by an order issued September 18, 1992, in docket number 05-EP-6. This last order addresses net metering as it applies to Wisconsin’s investor-owned utilities.

 

Authorities

    • Date Enacted:
      09/18/1992

    • Date Enacted:
      12/22/2011

Contact

  • Organization:

    Public Service Commission of Wisconsin

  • Address:

    610 North Whitney Way
    Madison, WI 53707-7854

  • Phone:

    (608) 266-1124

Memos

Loading…

    • 11/23/2015 by Ben Inskeep

      Added links and brief synopsis of net metering tariffs for four investor-owned utilities in Wisconsin

  • 05/01/2015 by Heather Calderwood

    In April 2015 the Public Service Commission approved the Northern States Power Company of Wisconsin’s request for a community Solar Garden program – “Solar Connect Community”

Net Metering in Vermont

Net Metering

Only 30 ft tall kicks in at 6mph and at 12mph produces 36kw enough to power 30 average homes

Last Updated March 17, 2017

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      Vermont

    • Incentive Type:

      Net Metering

    • Eligible Renewable/Other Technologies:

      Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Combined Heat & Power, Landfill Gas, Wind (Small), Hydroelectric (Small), Anaerobic Digestion, Fuel Cells using Renewable Fuels

    • Applicable Sectors:

      Commercial, Local Government, Nonprofit, Residential, Schools, State Government, Federal Government, Agricultural, Institutional

    • Applicable Utilities:

      All utilities

    • System Capacity Limit:

      2.2 MW for military systems; 20 kW for micro-CHP

    • Aggregate Capacity Limit:

      None

    • Net Excess Generation:

      Credited to customer’s next bill at the blended residential rate; excess credits not used within 12 months of generation granted to utility

    • Ownership of Renewable Energy Credits:

      Utility owns RECs unless the customer elects to retain ownership. Customers granting RECs to the utility receive a positive 3 cent/kWh credit adjustor applicable to all system production for 10 years. Customers electing to retain ownership of their RECs receive a negative 3 cent/kWh credit adjustor in perpetuity.

    • Meter Aggregation:

      Group net metering allowed

Summary

Note: Vermont has adopted new net metering rules, effective January 1, 2017. Net metering customers with a complete Certificate of Public Good filed prior to this date are grandfathered under Vermont’s former net metering rules for a period of 10 years from the date of commissioning.

Any electric customer in Vermont may net meter after obtaining a Certificate of Public Good from the Vermont Public Service Board (PSB). Solar net metered systems 15 kilowatts (kW) or less follow an expedited process for the Certificate of Public Good, if the customer successfully completes registration (that is, informing the PSB about the project) and complies with his/her electric utility interconnection requirements. In this case, ten days after receiving the certificate of compliance with the interconnection requirements, a Certificate of Public Good is automatically “deemed issued,” and the customer may proceed with installation. An application for a Certificate of Public Good for Interconnected Net Metered Power Systems for all other systems that are less than 150 kW is available on the program website listed above. Systems greater than or equal to 150 kW must make a filing for the Certificate of Public Good.

Eligible Technologies

“Renewable energy” is defined as “energy produced using a technology that relies on a resource that is being consumed at a harvest rate at or below its natural regeneration rate.” Biogas from sewage-treatment plants and landfills, and anaerobic digestion of agricultural products, byproducts and wastes are explicitly included. (The term “renewable energy” explicitly excludes solid waste that is not agricultural or silvicultural, as well as nuclear fuel, coal, oil, propane, and natural gas.)

System Capacity Limit

Net metering is generally available to systems up to 500 kW in capacity that generate electricity using eligible renewable energy resources, including combined heat and power (CHP) systems that use biomass. CHP systems that use a non-renewable fuel are limited to 20 kW and must meet an efficiency standard.

Aggregate Capacity Limit

As of January 1, 2017, Vermont no longer has an aggregate cap on net metering. Previously, the cumulative capacity of net-metered systems was limited to 15% of a utility’s peak demand during 1996 or the peak demand during the most recent full calendar year, whichever was greater.

Net Excess Generation

Any customer net excess generation (NEG) is credited at the blended residential rate and carried over to the customer’s next bill. The blended residential rate is the lowest of the following:

  • For electric companies whose general residential service tariff does not include inclining block rates, the per-kWh charge in the company’s general residential service tariff;
  • For electric companies whose general residential service tariff does include inclining block rates, a blend of those rates determined by adding together all of the revenues to the company during the most recent calendar year from kWh sold under those block rates and dividing the sum by the total kWh sold by the company at those rates during the same year; or
  • The weighted average of the blended residential rates for all Vermont electric companies (weighted by the annual retail sales of the electric companies.)

Any NEG shall be used within twelve months of the month earned; if not, it is granted to the utility with no compensation for the customer. Beginning January 1, 2017, credits may no longer be applied to non-bypassable charges.

System Size and Siting Credit Adjustors

Effective for customers filing a Certificate of Public Good January 1, 2017 and later, credit adjustors will be applied to customer bills based on system size and siting. Adjustors are applied to all production, as measured by a separate production meter. Positive adjustors are applied for 10 years, while negative adjustors are applied in perpetuity.

The credit adjustors are as follows:

  • Category I Systems (non-hydro facilities 15 kW or less) = 1 cent per kWh
  • Category II Systems (non-hydro facilities greater than 15 kW and less than or equal to 150 kW, sited on a “preferred site”) = 1 cent per kWh
  • Category III Systems (non-hydro facilities greater than 150 kW and less than or equal to 500 kW, sited on a “preferred site”)
  • Category IV Systems (non-hydro facilities greater than 15 kW and less than or equal to 500 kW, not located on a “preferred site”)
  • Hydroelectric Facilities = 0 cents per kWh

A “preferred site” means one of the following:

  • A new or existing structure whose primary use is not the generation of electricity
  • A parking lot canopy over a paved parking lot
  • A tract previously developed for a use other than siting a plant on which a structure or impervious surface was lawfully in existence prior to July 1 of the year preceding the year in which an application  for a Certificate of Public Good was filed
  • A brownfield
  • A sanitary landfill
  • The disturbed portion of a gravel pit, quarry, or simlar site for the extraction of a mineral resource
  • A specific location designated in a duly adopted municipal plan for the siting of a renewable energy plant
  • A site listed on the National Priorities List, provided development will not compromise or interfere with remedial action on the site and the site is suitable for development of the plant
  • The same parcel as, or directly adjacent to, a customer that has been allocated more than 50% of the net metering system’s electrical output.

Renewable Energy Credit Ownership & Credit Adjustors

Beginning January 1, 2017, the utility owns the renewable energy credits (RECs) generated by a customer’s net-metered system, unless the customer elects not to transfer ownership of these RECs at the time of application. Customers transferring RECs to the utility will receive an additional monthly bill credit for 10 years equal to $0.03/kWh multiplied by all kWh produced by the system during the billing period. Customers electing to retain REC ownership will be charged each month in perpetuity $0.03/kWh multiplied by all kWh produced during the billing period.

Prior to 2017, net-metered customers retained default ownership of RECs unless the customer elected to transfer ownership to the utility.

Interconnection

Utilities may require a customer to comply with generation interconnection, safety and reliability requirements, as determined by the PSB, and may charge reasonable fees for interconnection, establishment, special metering, meter reading, accounting, account correcting, and account maintenance of net-metered systems. (Interconnection requirements for systems 150 kW or less are accessible at the program website listed above. Interconnection requirements for systems greater than 150 kW must follow the interconnection procedures specified in PSB Rule 5.500).

Grandfathering

Net metering systems with a complete Certificate of Public Good application filed with the PSB prior to January 1, 2017 (as long as the application was filed at a time when the electric company was accepting net metering systems, based on the state’s former aggregate capacity limit) are grandfathered under the state’s former net metering rules for a period of 10 years from the date of the system’s commissioning. For this 10-year period, credits may be applied to all bill charges, including non-bypassable charges. Following this period, customers will be credited for NEG at the blended residential rate and may not apply credits to non-bypassable charges. Grandfathered systems are not subject to any REC or system size/siting credit adjustors.

Group Net Metering

Vermont allows “group net metering.” In order to set up such a net metering system, the group must file with the PSB and other relevant parties, the following information:

  • The customers and meters that are to be included as part of the group;
  • The method for adding/removing meters and information regarding credit allocation to each customer-meter;
  • The contact person responsible for communications, but not those related to billing, payment, or disconnect; and
  • A dispute resolution process.

The utility is required to bill all customers of the group individually. For group net metering systems placed behind-the-meter, electricity used on-site will be netted one-to-one against the host customer’s consumption. All NEG will be credited at the applicable blended residential rate and allocated to group members. For group net metering systems directly interconnected to the utility grid (in front of the meter), electricity produced is allocated to group members and monetized at the applicable blended residential rate. REC and system size/siting credit adjustors also apply to group net metering systems.

Biennial Update Proceeding

The PSB must conduct a biennial update in 2018 and every two years thereafter to update REC adjustors, system size/siting adjustors, the statewide blended residential rate, and criteria applicable to the different categories of net metering systems.

Other Provisions

Customers are responsible for the cost of installing a mandatory production meter. Electric companies may also require customers to install advanced metering infrastructure prior to serving the net metering customer.

Vermont’s net metering rules provide electric companies with the authority to require energy efficiency audits for customers seeking to install net metering systems if they are commercial or industrial customers, or residential customers with historic energy consumption of 750 kWh or more per month.

History

Vermont’s original net metering legislation was enacted in 1998, and the law has been expanded and modified several times, most recently by H.B. 702 of 2014. This legislation created a process to result in the establishment of a revised net metering program by January 1, 2017. Specifically, the legislation required the Department of Public Service to prepare a report by October 1, 2014, evaluating the current state of net metering in Vermont. This report is available here. The PSB followed up this report with workshops involving interested parties, and finally, a rulemaking process. More information is available here.

Authorities

    • Date Enacted:
      2013 (subsequently amended)

    • Effective Date:
      01/01/2017

    • Date Enacted:
      2001 (subsequently amended)

Contact

Memos

Loading…

    • 03/17/2017 by Autumn Proudlove

      Vermont’s new net metering rules became effective 1/1/2017. The new rules include several credit adjustors based on REC ownership, system size, and siting. Systems filing a complete CPG prior to 1/1/2017 are grandfathered for 10 years from the date of commissioning. The new rules no longer contain an aggregate cap on net metering in the state and will now credit net excess generation at the applicable blended residential rate. All website and authorities have been updated.

  • 08/04/2015 by Autumn Proudlove

    Annual review; updated REC ownership details, as per H.B. 40, enacted in June 2015. Added a link to the Department of Public Service’s 2014 net metering report.

Net Metering in Utah

Net Metering

Only 30 ft tall kicks in at 6mph and at 12mph produces 36kw enough to power 30 average homes

Last Updated May 25, 2016

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      Utah

    • Incentive Type:

      Net Metering

    • Eligible Renewable/Other Technologies:

      Geothermal Electric, Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Hydrogen, Combined Heat & Power, Landfill Gas, Wind (Small), Hydroelectric (Small), Anaerobic Digestion

    • Applicable Sectors:

      Commercial, Industrial, Local Government, Nonprofit, Residential, Schools, State Government, Federal Government, Agricultural, Institutional

    • Applicable Utilities:

      Investor-owned utilities, electric cooperatives

    • System Capacity Limit:

      2 MW for non-residential; 25 kW for residential

    • Aggregate Capacity Limit:

      20% of 2007 peak demand for Rocky Mountain Power; 0.1% of utility’s 2007 peak demand for co-ops

    • Net Excess Generation:

      For RMP residential and small commercial customers, excess kWh credits are applied to the customer’s next bill at retail rate; any credits remaining at end of 12-month billing cycle are granted by the utility to a low-income assistance program or other purpose approved by the PSC. For RMP large commercial and industrial customers with demand charges, customers may choose between valuing net excess generation at an avoided cost-based rate or at an alternative rate based on utility revenue and sales contained in FERC Form No. 1.
      For co-op customers, net excess generation is credited at avoided cost rate.

    • Ownership of Renewable Energy Credits:

      Customer owns RECs

    • Meter Aggregation:

      Allowed at same or adjacent location

Summary

Note: S.B. 208, enacted in May 2014, requires the Utah Public Service Commission (PSC) to convene a process to evaluate the costs and benefits of net energy metering, and to determine a “just and reasonable” rate structure considering those costs and benefits. The PSC opened a docket, 14-035-114, for comments and proceedings related to the costs and benefits of net metering. The PSC issued an Order in November 2015 accepting a framework for assessing net metering costs and benefits that will utilize a comparison between a cost of service study assuming no net metering customers and the results of a cost of service study for net metering customers. Rocky Mountain Power must file the two studies no later than the date it files its next general rate case.

Eligibility and Availability

Utah law requires the state’s only investor-owned utility, Rocky Mountain Power (RMP), and most electric cooperatives* to offer net metering to customers who generate electricity using solar energy, wind energy, hydropower, hydrogen, biomass, landfill gas, or geothermal energy. Net metering is available for residential systems up to 25 kilowatts (kW) in capacity and non-residential systems up to two megawatts (MW) in capacity, whether owned by the utility customer or a third party.

The PSC has regulatory authority over RMP and was authorized by the state legislature to change certain aspects of their net metering rules, but the PSC does not have authority over the cooperative utilities. As a result, a February 2009 order issued by the PSC changed some of the net metering rules for RMP, but the cooperatives are not obligated to adopt them and may continue offering net metering under the minimum terms established by the state legislature.

Rocky Mountain Power

Aggregate Capacity Limit

The PSC’s February 2009 ruling raised the aggregate capacity limit for RMP from 0.1% to 20% of the utility’s 2007 peak demand. In establishing a significantly higher enrollment limit, the PSC also requires RMP to submit an annual net metering report, due by July 1 of every year, informing the commission of the number of net-metered systems, the capacity of each installation, the total capacity of net metering systems, and any problems or barriers with the net-metering tariff.

Net Excess Generation

For residential and small commercial customers, RMP will issue a kWh credit (at the retail rate) for monthly net excess generation produced by the net metering facility and apply that credit to the next billing period. Large commercial and industrial customers with demand charges that generate excess generation will be given a choice between valuing excess generation at an avoided cost based rate; or valuing excess generation at an alternative rate based on utility revenue and sales contained in FERC Form No. 1.

Any net excess generation at the end of an annualized billing period will expire with no compensation to the customer. The annualized billing period is a 12-month billing cycle beginning on April 1 of one year and ending on March 31 of the following year. Utilities may also establish one additional annualized billing period. RMP opted to make their additional billing cycle run from September to October for irrigation customers on Schedule 10.

Utilities must reserve the avoided cost value of any net metering credits remaining at the end of an annualized billing cycle, and apply those funds to their low income assistance programs, or another purpose determined by the governing authority.

Minimum Bill & Additional Charges

The PSC also ruled that net metering customers are not exempt from the minimum bill charge that all customers must pay. In August 2014, the PSC declined RMP’s proposed facilities charge for net metered customers until it has completed the legislatively mandated review of net metering costs and benefits.

Meter Aggregation

If a net metering customer has multiple meters at one location or an adjacent location, the meters may be aggregated for billing purposes. The customer must notify the utility of the order in which they want the kWh credits to be applied to the meters.

REC Ownership

The PSC also clarified in its ruling that all renewable energy credits associated with the electricity produced by the system remain with the customer, unless otherwise agreed to or designated by the customer.

Click here for Rocky Mountain Power’s interconnection agreement and application for net metering service.

Electric Cooperatives

Aggregate Capacity Limit

Cooperatives are obligated to provide net metering until net metered systems account for 0.1% of the utility’s 2007 peak demand.

Net Excess Generation

If a customer generates more electricity than the customer uses during a billing period, then the utility must credit the customer for the net excess generation at a rate equal to the utility’s avoided cost or higher. Customer net excess generation is carried over to the next customer’s next monthly bill during a 12-month period. Any net excess generation at the end of an annualized billing period will expire with no compensation to the customer. The annualized billing period is a 12-month billing cycle beginning on April 1 of one year and ending on March 31 of the following year. Utilities may also establish one additional annualized billing period.

Electric cooperatives must apply the avoided cost value of any net metering credits remaining at the end of an annualized billing cycle to their low income assistance programs, or another purpose determined by the Public Service Commission (PSC).

Additional Charges

Electric cooperatives may not levy additional charges unless authorized by its board of directors. Members of a cooperative who disagree with the charges approved by the board of directors may file a complaint with the PSC after filing a complaint with the cooperative’s board or directors.

* Beginning in March 2008, electric cooperatives serving fewer than 1,000 customers in Utah may discontinue making net metering available to customers that are not already net metering. In addition, electric cooperatives not headquartered in Utah that serve fewer than 5,000 customers in Utah are authorized to offer net metering to their Utah customers in accordance with a tariff, schedule or other requirement of the appropriate authority in the state in which the co-op’s headquarters are located.

Authorities

    • Date Enacted:
      3/15/2002 (subsequently amended)

    • Effective Date:
      5/6/2002

    • Date Enacted:
      2/12/2009

    • Effective Date:
      4/1/2009

Contact

  • Organization:

    Utah Public Service Commission

  • Address:

    160 East 300 South
    Salt Lake City, UT 84111

  • Phone:

    (801) 530-6711

  • E-Mail:

Memos

Loading…

    • 05/25/2016 by Autumn Proudlove

      Annual review; no formal policy updates. The PSC issued an Order in November 2015 accepting a framework for assessing net metering costs and benefits that will utilize a comparison between a cost of service study assuming no net metering customers and the results of a cost of service study for net metering customers. Rocky Mountain Power must file the two studies no later than the date it files its next general rate case.

  • 04/10/2015 by Brian Lips

    SB 110 made one minor change. Previously, any NEG returned to the utility after the annual billing period had to be applied to low-income customers, or be used for some other purpose determined by the PSC. SB 100 changed the language so that the “governing authority” has the say.

Net Metering in South Carolina

Net Metering

Only 30 ft tall kicks in at 6mph and at 12mph produces 36kw enough to power 30 average homes

Last Updated January 25, 2016

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      South Carolina

    • Incentive Type:

      Net Metering

    • Eligible Renewable/Other Technologies:

      Geothermal Electric, Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Hydrogen, Combined Heat & Power, Tidal, Wave, Wind (Small), Hydroelectric (Small), Fuel Cells using Renewable Fuels

    • Applicable Sectors:

      Commercial, Investor-Owned Utility, Nonprofit, Municipal Utilities, Residential, Cooperative Utilities, Schools, Institutional

    • Applicable Utilities:

      All utilities with more than 100,00 customers, excluding cooperatives.

    • System Capacity Limit:

      20 kW for residential; 1000 kW for non-residential

    • Aggregate Capacity Limit:

      2% of average retail peak demand for previous 5 years

    • Net Excess Generation:

      Credited to customer’s next bill on a monthly basis. Annual pay out to customer at the avoided cost rate zeros out monthly carry-over.

    • Ownership of Renewable Energy Credits:

      Not addressed

    • Meter Aggregation:

      Explicitly prohibited

Summary

In April of 2014 the South Carolina legislature unanimously passed S.B. 1189 to create a voluntary Distributed Energy Resource Program. In March 2015 the Public Utilities Commission approved a settlement agreement among  solar stakeholders detailing how the new net metering mandates laid out in S.B. 1189 would be fulfilled.

The settlement agreement approved by the Public Service Commission stipulates that utilities will offer net energy metering at the full retail rate.. Additionally, no new charges or fees distinctly separate from new net metering rates will be imposed upon customer generators until the expiration of the agreement on January 1, 2021.

The settlement agreement also stipulates that utility-specific distributed energy resources net metering incentive (DER NEM incentive) will be applied to customer-generators receiving service under new net metering tariffs prior to January 1, 2021. Customer-generators whose net energy metering facilities were operational prior to the availability of net energy metering rates approved by the commission under the terms of the settlement agreement may remain in historic net energy metering programs through December 31, 2020.

Eligibility and Availability

Resident net metering customers of independently owned utilities (IOUs) can install renewable systems of 20 kW or less and nonresidential customers can install systems with a cap of the lesser of 100% of demand or 1 MW. Renewable systems are defined as solar photo-voltaic, solar thermal, wind, hydroelectric, geothermal, tidal, wave, recycling, biomass, and combined heat and power and hydrogen fuel derived from renewable sources. These systems must be owned, leased, or operated by the customer-generator and must meet all interconnection, performance, safety, and reliability standards established by relevant authorities.

Cooperatives are required by S.B. 1189 to examine net metering policies but are not bound by law to implement new programs.

Net Excess Generation

The utility is responsible for maintaining an account of total electricity produced and consumed. When less electricity is produced than consumed in a month, then the customer-generator pays the difference. When more electricity is produced than consumed in a month, excess kilowatt-hour credits roll over to the next month. Utilities must annually pay out for any excess electric production at the avoided cost rate to zero-out electric bills and re-start the monthly carry-over process. Excess generation credits cannot be used to pay for non-volumetric charges.

Authorities

    • Date Enacted:
      03/20/2015

    • Effective Date:
      03/20/2015

Contact

Memos

Loading…

    • 04/03/2015 by Ethan Case

      Entry clarified and updated.

  • 03/18/2015 by Ethan Case

    Settlement agreemet approved; more directive on future NEM tariffs available.

Net Metering in Virginia

Net Metering

Last Updated May 24, 2017

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      Virginia

    • Incentive Type:

      Net Metering

    • Eligible Renewable/Other Technologies:

      Geothermal Electric, Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Municipal Solid Waste, Tidal, Wave, Wind (Small), Hydroelectric (Small)

    • Applicable Sectors:

      Commercial, Industrial, Local Government, Nonprofit, Residential, State Government, Agricultural, Multifamily Residential, Low Income Residential, Institutional

    • Applicable Utilities:

      Investor-owned utilities, electric cooperatives

    • System Capacity Limit:

      Residential : 20 kW
      Non-Residentail : 1,000 kW
      Agricultural: 500 kW (aggregated capacity)
      Systems must be sized not to exceed customers annual load.

    • Aggregate Capacity Limit:

      1% of utility’s adjusted Virginia peak-load forecast for the previous year

    • Net Excess Generation:

      Credited to customer’s next bill at retail rate. After 12-month cycle, customer may opt to roll over credit indefinitely or to receive payment at avoided-cost rate.

    • Ownership of Renewable Energy Credits:

      Customer owns RECs

    • Meter Aggregation:

      Allowed for agricultural customers for contiguous sites

Summary

Net metering in Virginia is available on a first-come, first-served basis until the rated generating capacity owned and operated by customer-generators reaches 1% of an electric distribution company’s adjusted Virginia peak-load forecast for the previous year. Net metering is available to customers of investor-owned utilities (including competitive suppliers) and electric cooperatives, but not to customers of municipal utilities.

Eligibility:

Virginia’s net-metering law applies to electric customers who generate electricity from renewable fuel sources* that are up to 20 kilowatts (kW) capacity for residential customers and 1,000 kW in capacity for non-residential customers. The generation systems must be located on the customer’s property and must be sized to primarily offset the customer’s electricity requirements. Systems installed after July 1, 2015 shall not exceed the expected annual energy consumption based on 12 month of billing history or annualized calculation if the billing history is not available.

Prospective net metering customers must receive approval to interconnect from their electric supplier prior to installation of the generation system. The electric distribution company must notify within 30 days if the customer meets the requirements for net metering. The net metering application is considered automatically approved if the electric company fails to notify within 30 days for residential customers and 60 days for non-residential customers.

Standby Charges:

HB 1983 that was passed in March 2011, requires that residential facilities with an AC capacity of greater than 10kW must pay a monthly standby charge. The amount of standby charge will be developed by the electric supplier and be approved by the Commission after it determines that the charge is reasonable to allow the supplier to recover portion of the infrastructure cost. The customers must also pay inspection fee of $50 for inverter based systems greater than 10 kW.

Any residential net-metering customer of Dominion Virginia Power who owns and operates, or contracts to own and operate, an electric generation system with a capacity greater than 10kW and less than 20kW is required to pay transmission and distribution standby charges. Customers will be required to pay $2.79 per kW in monthly distribution standby charges and $1.40 kW in monthly transmission standby charges. The SCC denied Dominion’s proposal for generation standby charges, but Dominion may reapply for approval for these charges in the future.

Net Excess Generation:

Net-metered energy is measured by a meter capable of gauging electricity flow in both directions. Monthly net excess generation (NEG) is carried forward to the next month. At the end of each 12-month period, the customer has the option of carrying forward eligible excess NEG to the next net metering 12-month period or selling the NEG to the utility. The amount of credit to be carried forward to a subsequent net metering period may not exceed the amount of energy purchased during the previous annual period.** In the case of selling the NEG to the utility, the customer must submit a written request to establish a power purchase agreement with the utility prior to the beginning of the net metering period to be covered by the power purchase agreement. The investor-owned utility must pay avoided cost (or higher if agreed upon). Net metering is also available to customers on time-of-use tariffs (with time-of-use applicable NEG calculations).

Meter aggregation

In 2013, HB 1695 created net metering programs for agricultural customers of investor-owned utilities and electric cooperatives. Agricultural customers are allowed to aggregate their electric meters in a single account such that they are located at contiguous sites and served under an appropriate tariff. The aggregated generation capacity is limited to 500 kW for agricultural businesses.

Community Solar Pilot Program

S.B. 1393 enacted in March 2017, required the state’s two investor owned utilities- Dominion Virgina and Appalachian Power- to develop community solar pilot programs for their retail customers. The community solar projects must i) exclusively use solar ii) be placed in service on or after July 1, 2017, iii) not constructed by the utility, but acquired through a purchase agreement from a third party, and iv) sized no larger than 2 MW per project. The pilot program has a duration of three years. Appalachian Power must have program between 0.5 MW and 10 MW, while Dominion’s program must be between 10 MW and 40 MW.  The program design and the voluntary rate schedule for participants in the community solar programs will be approved by the Commission.

Renewable Attributes:

Customer-generators own all of the renewable energy credits (RECs) their system generates. Virginia’s net metering law states that at the time a customer enters into a power purchase agreement with the utility for net excess generation, the customer has a one-time option to sell RECs to the utility. This provision does not preclude the customer and utility (or other entity) from voluntarily entering into an agreement for the sale and purchase of RECs at any other time.

*According to the VA statutes § 56-576 renewable energy includes energy derived from sunlight, wind, falling water, biomass, sustainable or otherwise, energy from waste, landfill gas, municipal solid waste, wave motion, tides, and geothermal power. It also includes proportion of thermal or electric energy from a facility that results from co-firing of biomass 

 **For example, if a customer-generator bought 1,500 kilowatt-hours (kWh) from a utility during the first 11 months of the annual period, and then generated 2,000 kWh of excess electricity in the12th month, the customer could carry forward 1,500 kWh to the following month, and the remaining 500 kWh would be granted to the utility.

Authorities

    • Date Enacted:
      1999 (subsequently amended)

    • Effective Date:
      7/1/2000

    • Date Enacted:
      2000 (subsequently amended)

    • Effective Date:
      5/25/2000

    • Date Enacted:
      04/13/2010

    • Effective Date:
      04/28/2010

    • Date Enacted:
      03/13/2013

    • Date Enacted:
      03/23/2015

    • Effective Date:
      07/01/2015

    • Date Enacted:
      03/16/2017

    • Effective Date:
      07/01/2017

Contact

Memos

Loading…

    • 05/24/2017 by Achyut Shrestha

      S.B. 1393 enacted in March 2017 requires Dominion Virginia Power and Appalachian Power to develop community solar pilot programs for its customers. The pilot program must be between 500kW – 10 MW for Appalachian Power and between 10 MW and 40 MW for Dominion.

    • 12/01/2015 by Achyut Shrestha

      On November 24, 2015 the VA State Corporation Commission (SCC) published its final version of the regulations pursuant to SB1395 which included several amendments to net metering regulation including: i) increased capacity limit of nonresidential customers in net metering program from 500 kW to 1MW, ii) eliminated authority for electric utilities allow higher capacity limit than 1 MW, iii) require the capacity of the generation system not to exceed the expected annual energy consumption based on the previous twelve month of billing history or annualized calculation if it is not available, iv) require customers to receive interconnection approval prior to installation of the system, and v) require the customers to pay for any additional cost incurred during interconnection.

    • 03/26/2015 by Achyut Shrestha

      HB 2267 was approved by Governor on 03/23/2015. Effective 7/1/2015 the netmetering cap for nonresidential customers have been increased from 500kW to 1MW.

  • 03/11/2015 by Achyut Shrestha

    SB 1395 approved by both Senate and the House, increases net-metering cap for non-residential customers to 1,000 kW. The Governor has until May 29 to take action, after which the bill automatically becomes law.

Net Metering in West Virginia

Net Metering

Last Updated March 16, 2015

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      West Virginia

    • Incentive Type:

      Net Metering

    • Eligible Renewable/Other Technologies:

      Geothermal Electric, Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Combined Heat & Power, Fuel Cells using Non-Renewable Fuels, Landfill Gas, Wind (Small), Hydroelectric (Small), Fuel Cells using Renewable Fuels

    • Applicable Sectors:

      Commercial, Industrial, Local Government, Nonprofit, Residential, Agricultural

    • Applicable Utilities:

      All utilities

    • System Capacity Limit:

      IOUs with more than 30,000 customers: 2 MW for industrial; 500 kW for commercial; 25 kW for residential.
      IOUs with fewer than 30,000 customers, municipal utilities and co-ops: 50 kW for commercial and industrial; 25 kW for residential.

    • Aggregate Capacity Limit:

      3% of peak demand during the previous year

    • Net Excess Generation:

      Credited to customer’s next bill at retail rate with no annual true-up (perpetual rollover)

    • Ownership of Renewable Energy Credits:

      Not addressed

    • Meter Aggregation:

      Allowed

Summary

Note: On March 12th, 2015 HB 2201 was signed by the Governor of West Virginia. Notably, the bill prohibits cross-subsidization of ratepayers potentially caused by net metering tariffs, requires the Public Utility Commission to investigate current and adopt new net metering and interconnection rules, and limits IOUs from allowing more than 3% of aggregate load to be generated by solar power.
 
Eligibility and Availability
Net metering in West Virginia is available to all retail electricity customers. System capacity limits vary depending on the customer type and electric utility type, according to the following table.
Customer Type IOUs with 30,000 customers or more IOUs with fewer than 30,000 customers, municipal utilities, electric cooperatives
Residential 25 kW 25 kW
Commercial 500 kW 50 kW
Industrial 2 MW 50 kW
Systems that generate electricity using “alternative” or “renewable energy” resources are eligible for net metering, including photovoltaics (PV), wind, geothermal, biomass, landfill gas, run of the river hydropower, biofuels, fuel cells, and combined heat and power (technically called “recycled energy” in the rules).
Net metering may be accomplished using a single, bi-directional meter or two meters. In the event that two meters are used, the net number of kWh for billing purposes will be determined by subtracting the amount of electricity flowing from the customer to the utility from the amount of electricity flowing from the utility to the customer. Net-metering tariffs must be identical in rate structure, retail-rate components, and monthly charges, to the tariff for which the customer would qualify if that customer were not a customer-generator. Customers on a time-of-use (TOU) tariff are permitted to net meter.
Each customer with a net-metered system up to 50 kW must carry a minimum of $100,000 in liability insurance. Customers with systems greater than 50 kW and up to 500 kW are required to carry a minimum of $500,000, and customers with systems greater than 500 kW must carry a minimum of $1 million in liability insurance.
Net Excess Generation
Net excess generation (NEG) may be carried over to a customer-generator’s next bill as a kilowatt-hour (kWh) credit at retail rate and may be rolled over, indefinitely. The credits may only be applied to the energy portion of the bill (not fixed costs or demand charges, for example).
Alternative Energy Credits
Based upon the Alternative and Renewable Energy Portfolio Standard, alternative energy credits can be generated by renewable OR non-renewable sources that are not net-metered.
General Order 184.32 states that in order to claim alternative energy credits, customer generators and behind the meter generators (BTMs) must certify their resource with the Public Utiliity Commission and then file an Alternative or Renewable Meter Generation. Customer generators and BTMs shall own alternative energy credits unless they have contracted by a third party to provide generation, in which case the third party owns the credits.
Customer generators and BTMs with systems above 10 kW must have meters that meet American National Standards Institute (ANSI) C-12 meter standards. Systems below 10 kW are permitted to make generation measurements based upon system inverters or may also have meters that meet ANSI C-12 standards.
Meter Aggregation
Customers may aggregate meters (either physically or virtually) and apply net metering credits earned on one meter to additional meters, as long as they are located within two miles of the point of generation. The associated costs of meter aggregation are the responsibility of the customer.
History
The West Virginia Public Service Commission (PSC) approved consensus filings regarding net metering and interconnection guidelines in December 2006. The approved consensus provisions include proposed rules that apply to all electric utilities in the state. Utility tariffs incorporating the consensus net-metering provisions took effect in March 2007. In June 2010, the PSC adopted new net metering and interconnection procedures. In May 2011,  the PSC clarified the definition of “run-of -river hydropower” to match the definition in the Alternative and Renewable Energy Portfolio Standard.

Authorities

    • Date Enacted:
      06/02/2009

    • Effective Date:
      07/01/2009

    • Date Enacted:
      06/30/2010

    • Effective Date:
      08/30/2010

    • Date Enacted:
      05/19/2011

    • Effective Date:
      07/18/2011

    • Date Enacted:
      03/12/2015

    • Effective Date:
      06/10/2015

Contact

  • General Information – PSC

  • Organization:

    West Virginia Public Service Commission

  • Address:

    201 Brooks Street
    Charleston, WV 25323

  • Phone:

    (800) 344-5113

Memos

Loading…

  • 03/16/2015 by Ethan Case

    HB 2201 passed. Stops net metering “cross subsidization,” mandates new NEM and interconnection study and rules, limits NEM to 3% of aggregated load, with 0.5% for residential customers.

Net Metering in Minnesota

Net Metering

Last Updated November 23, 2015

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      Minnesota

    • Incentive Type:

      Net Metering

    • Eligible Renewable/Other Technologies:

      Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Municipal Solid Waste, Combined Heat & Power, Landfill Gas, Wind (Small), Hydroelectric (Small), Anaerobic Digestion, Other Distributed Generation Technologies

    • Applicable Sectors:

      Commercial, Industrial, Local Government, Nonprofit, Residential, Schools, State Government, Federal Government, Tribal Government, Agricultural, Multifamily Residential, Institutional

    • Applicable Utilities:

      All utilities

    • System Capacity Limit:

      Net Metering Facility: 1 MW
      Community Garden Project: 5 MW

    • Aggregate Capacity Limit:

      No limit
      The Minnesota Public Utilities Commission *may* limit cumulative net metering generation once generation has reached 4% of annual retail electricity sales

    • Net Excess Generation:

      Systems under 40 kW: Reconciled monthly; customer may opt to receive payment or credit on next bill at the retail utility energy rate
      For systems 40 kW -1 MW, NEG is credited at the avoided cost rate, or customers may elect to be compensated in the form of a kWh credit. Excess credit will be reimbursed at the end of the calendar year at the avoided cost rate.

    • Ownership of Renewable Energy Credits:

      Customer owns RECs

    • Meter Aggregation:

      IOU customers may aggregate meters for net metering

Summary

Note: Ongoing issues related to Minnesota’s Community Solar Garden rules and program implementation are being considered in Docket No. E002/M-13-867. This entry will be updated as necessary to reflect any final changes arising from this Docket.

Minnesota’s net metering law, enacted in 1983, applies to all investor-owned utilities, municipal utilities, and electric cooperatives.

Minnesota has also finalized a methodology for a value of solar tariff in lieu of a net metering billing mechanism; however, no utility has elected to implement such an alternative tariff as of November 2015.

System Size

Customers with “qualifying facilities”* less than 1,000 kilowatts (kW) in capacity at investor-owned utilities and less than 40 kW in capacity at municipal utilities and electric cooperatives are eligible for net metering.

Investor-owned utilities may require customers with a net-metered facility of 40 kW or greater to limit total generation capacity to 120% of the customer’s on-site annual electric consumption for solar PV and other distributed generation systems, and to 120% of customer’s on-site maximum electric demand for wind generation systems.

Aggregate Cap

There is no aggregate cap limiting the total amount of systems eligible for net metering. However, an investor-owned utility may request the Minnesota Public Utilities Commission (MPUC) limit net metering once net-metered generation has reached 4% of the utility’s annual retail electricity sales. The MPUC has authority to limit the cumulative generation of net metered facilities “only if it determines that additional net metering obligations would cause significant rate impact, require significant measures to address reliability, or raise significant technical issues.”

Additional Fees and Charges

Investor-owned utilities are not permitted to impose a standby charge on net-metered facilities with a capacity of 100 kW or less.

A cooperative electric association or municipal utility may charge an additional fee to recover the fixed costs not already paid for by the customer through the customer’s existing billing arrangement.

Net Excess Generation

Each utility must compensate customers with systems less than 40 kW in size for net excess generation (NEG) at the “average retail utility energy rate,” defined as “the total annual class revenue from sales of electricity minus the annual revenue resulting from fixed charges, divided by the annual class kilowatt-hour sales.” Compensation may take the form of an actual payment (i.e., check for purchase) for NEG or as a credit on the customer’s bill.

For systems sized 40 kW or greater but less than 1,000 kW in size, NEG will be credited at the avoided cost rate. Alternatively, a customer may elect to be compensated in the form of a kWh credit.

NEG credits will be reimbursed at the end of the calendar year at the avoided cost rate for customers of investor-owned utilities. NEG credits expire at the end of the year for customers of municipal utilities and electric cooperatives.

Meter Aggregation

Investor-owned utilities are required to offer meter aggregation for customers that request it. The meter must be owned or leased by the customer requesting aggregation, and must be located on contiguous property owned by the same customer. The total aggregate of all meters is subject to the same net metering size limitations described above. Utilities must comply with aggregation requests within 90 days. The aggregation of meters only applies to charges that use kWhs as the billing determinant. NEG is credited to the next monthly bill in the form of kWh credits. Utilities may request permission from the MPUC to charge administrative fees for meter aggregation.

Renewable Energy Credits

The customer-generator retains ownership of any RECs associated with the energy generated by a qualifying facility.

Community Solar Gardens

On December 12, 2014, Xcel Energy launched its Solar Rewards Community program pursuant to community solar legislation enacted in Minnesota. Subscribers can purchase subscriptions to a solar garden system developed by a Garden Operator who must have a state certificate of good standing. A garden must always have at least 5 subscribers, of which no single subscriber may have more than a 40% interest, and each subscription must be no less than 200 watts of the system’s generating capacity. Subscribers must be retail customers of the utility and located in the same county or a county contiguous to where the facility is located. There is no limit to the number of solar gardens which can be placed on a property, but no single garden can exceed 1 megawatt.

In August 2015, the MPUC approved a settlement agreement between Xcel Energy and a group of solar developers, placing an initial 5-MW cap on co-location for existing solar-garden applications. For applications submitted from September 25, 2015, through September 15, 2016, community solar gardens will be limited to 1 MW at a given site.

Subscribers will receive a credit on their electric bill for the energy produced by the garden. Subscribers are compensated at the applicable retail rate. Community projects may also be eligible for the solar performance based incentives offered by  Xcel Energy or the Department of Commerce.  The utility that offers the program may own the PV system, or another entity may own the project. Systems may be ground- or roof-mounted, must be located within the utility service territory, and may not exceed system capacity and generation limits that apply to all net-metered systems.

The term “qualifying facility” is defined in the federal Public Utility Regulatory Policies Act of 1978 (PURPA). It generally includes most renewable energy systems and combined heat and power (CHP) systems.

Authorities

    • Date Enacted:
      1983

    • Effective Date:
      1983

    • Effective Date:
      2000

    • Effective Date:
      2000

    • Date Enacted:
      07/22/2014

    • Effective Date:
      07/22/2014

    • Date Enacted:
      06/03/2015

    • Effective Date:
      06/03/2015

Contact

Memos

Loading…

    • 11/23/2015 by Ben Inskeep

      Updated entry with latest community solar program information, finalized new net metering system size and net excess generation credit rules, and edited entry for clarity.

    • 06/26/2015 by Heather Calderwood

      In June 2015, the Public Utility Commission signed a settlement between Xcel Energy and developers that would cap project size at 5 MW.

    • 06/18/2015 by Heather Calderwood

      Beginning July 1st, a municipal utility or a co-op can begin charging new net metering customers a “reasonable and appropriate” fee.

    • 05/19/2015 by Heather Calderwood

      Stearns Electric Association will offer community solar in St. Joseph to members this June.

  • 05/04/2015 by Heather Calderwood

    Xcel Energy’s Community Solar Garden policy has changed.

Net Metering in Indiana

Net Metering

Last Updated November 24, 2015

Program Overview

    • Implementing Sector:

      State

    • Category:

      Regulatory Policy

    • State:

      Indiana

    • Incentive Type:

      Net Metering

    • Start Date:

      09/01/2004

    • Utilities:

      Indianapolis Power & Light Co, Indiana Michigan Power Co, Northern Indiana Pub Serv Co, Southern Indiana Gas & Elec Co

    • Eligible Renewable/Other Technologies:

      Solar Thermal Electric, Solar Photovoltaics, Wind (All), Biomass, Hydroelectric, Hydrogen, Fuel Cells using Non-Renewable Fuels, Wind (Small), Hydroelectric (Small), Fuel Cells using Renewable Fuels

    • Applicable Sectors:

      Commercial, Industrial, Local Government, Nonprofit, Residential, Schools, State Government, Federal Government, Agricultural, Multifamily Residential, Institutional

    • Applicable Utilities:

      Investor-owned utilities

    • System Capacity Limit:

      1 MW

    • Aggregate Capacity Limit:

      1% of utility’s most recent peak summer load

    • Net Excess Generation:

      Credited to customer’s next bill as a kWh credit (i.e., at retail rate); carries over indefinitely

    • Ownership of Renewable Energy Credits:

      Not addressed

    • Meter Aggregation:

      Not addressed

Summary

The Indiana Utility Regulatory Commission (IURC) adopted rules for net metering in September 2004, requiring the state’s investor-owned utilities (IOUs) to offer net metering to all electric customers.

Eligible Resources and System Size

Facilities with a maximum capacity of 1 megawatt (MW) are eligible for net metering. Eligible net metering energy resources include wind, solar, hydro, fuel cells, hydrogen, organic waste biomass and dedicated crops powered generation.

Aggregate Cap

A utility may limit the aggregate amount of net-metering nameplate capacity to 1% of its most recent summer peak load.  Nameplate capacity for inverter-based net metering facilities is defined as “the aggregate output rating of all inverters in the facility, measured in kW.” At least 40% of a utility’s net metering capacity must be residential customers.

IOUs may choose to offer larger net metering capacity limits.

Net Excess Generation (NEG)

NEG during a billing period is credited to the customer’s next monthly bill in the form of a kilowatt-hour (kWh) credit at the retail rate. NEG credits rollover indefinitely. If a customer elects to cease net metering, any unused credit will revert to the utility.

Interconnection

An interconnection agreement between the utility and the customer must be executed before the facility may be interconnected. Net-metered systems must comply with Indiana’s interconnection standards (170 IAC 4-4.3).

Metering

Either a single meter or a dual-meter arrangement may be used. Utilities may not charge customers any fees for additional metering for single-phase configurations installed by the utility, for customers’ requests to net meter, or for an initial net-metering facility inspection.

Insurance

Net metering customers must maintain homeowners, commercial, or other insurance providing coverage of at least $100,000 against loss arising out of the use of a net metered facility. Utilities may not require additional liability insurance in excess of this limit.

Reporting

The IURC’s 2014 net metering report is available here.

Authorities

    • Date Enacted:
      9/8/2004

    • Effective Date:
      10/22/2004

    • Date Enacted:
      05/11/2011

    • Effective Date:
      07/13/2011

Contact

  • Organization:

    Indiana Utility Regulatory Commission

  • Address:

    101 West Washington Street, Suite 1500E
    Indianapolis, IN 46204

  • Phone:

    (317) 232-2304

  • E-Mail:

Memos

Loading…

    • 11/24/2015 by Ben Inskeep

      Annual review; no changes to policy; edited entry for clarity

  • 05/13/2015 by Heather Calderwood

    No changes to program policy.