NARUC Issues Draft Manual on Distributed Energy Resources

Posted on July 28, 2016 by Jeff Bayne

Last week, the National Association of Regulatory Utility Commissioners (NARUC) released a draft Manual on Distributed Energy Resources (DER) Compensation.  The manual is intended to provide state regulators with possible options for developing policies relating to compensation for DER.

The draft manual outlines six methodologies that regulators could consider, either individually or in combination:

  • Net Energy Metering (NEM) – NEM is the simplest and least expensive DER compensation methodology to implement, and it has received significant attention in states across the country.  The main concern with NEM is that it may overcompensate DER customers and leave non-DER customers to pay for the costs of integrating DER into the grid, although proponents of NEM argue that the benefits of DER justify this methodology.
  • Valuation Methodology – This methodology separates what a customer is charged for consumption from what she is paid for generation.  The payment portion can be determined based on either the “Value of Resource,” which attempts to identify all of the costs and benefits of a DER, or the “Value of Service,” which attempts to identify and quantify all of the services that a DER can provide, such as generation, voltage support, ramping, or reliability.
  • Demand Charges – Demand charges are designed to account for the capacity needs of a customer.  Many DER customers still rely on the grid during peak times (in general, the times of peak rooftop solar generation and peak residential consumption do not coincide).  If a demand charge is in place, a DER customer would be assessed this charge even if her import of energy from the grid equaled her export of excess energy to the grid over the course of a billing cycle.
  • Fixed Charges and Minimum Bills – As the names imply, fixed charges are rates that do not vary based on a customer’s consumption or generation, and minimum bills establish a floor for energy bills where NEM is in place.  Both of these methodologies ensure that a DER customer cannot offset his entire electricity bill with the energy exported to the grid.
  • Standby and Backup Charges – Standby charges compensate utilities for the energy and capacity required to instantaneously provide DER customers with enough electricity to meet their needs in the event of DER outages.  Backup service is similar, only it applies to planned outages and is typically not instantly available.  While NARUC’s draft manual notes that there do not appear to be standby and backup charges applied to DER currently, this may be an option utilities consider pursuing in the future.
  • Interconnection Fees and Metering Charges – Interconnection fees cover the one-time cost of setting up a DER on a utility’s system, whereas metering charges cover the cost of the meter, its maintenance, meter reading, and data services.  While these fees and charges are based on cost causation principles, they do not address all DER-related costs and may also slow DER adoption by increasing the payback period of DER investment.

NARUC is soliciting comments on the draft manual and plans to release a final manual in November 2016.  Comments can be submitted through close of business September 2, 2016 to responses@naruc.org.

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Hourly Electricity Information Now Available from EIA

Posted on July 28, 2016 by Jeff Bayne

The U.S. Energy Information Administration (EIA) is now providing hourly U.S. electricity operating data.  The tool allows users to view electricity supply and demand on a national and regional level in nearly real-time.  The site also provides comparisons to the previous day, week, and year, as well as a status map showing the actual and forecasted demand for each of the 66 balancing authorities that comprise the U.S. electric grid.

EIA hopes that the data can be used to both provide close-to-real-time information after power interruptions and help in evaluating the impact of increased renewable energy, smart grid technology, and demand response programs on grid operations.

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FERC and Army Corps of Engineers Take Action to Streamline Non-Federal Hydroelectric Permitting

Posted on July 26, 2016 by Amber Martin

On July 20, 2016, the Federal Energy Regulatory Commission (FERC) and the U.S. Army Corps of Engineers (USACE) signed a new Memorandum of Understanding (MOU) which they say is aimed at speeding review and approval of hydroelectric applications for non-Federal projects at USACE dams.  The new MOU updates a 2011 version of the agreement between FERC and USACE.

Under the MOU, FERC and USACE commit to early coordination, increased data sharing, and informal communication.  The MOU sets out a two-phase approach under which the agencies will first engage in an environmental review, followed by a detailed technical, engineering, and safety review phase.  During the first phase, which is meant to result in issuance of a FERC license, FERC and USACE staff will coordinate to discuss a developer’s proposal and assess information needed to move the agencies’ permitting processes forward.  FERC and USACE will also jointly undertake evaluation of the environmental effects of the proposed project and issue an environmental impact statement as required under the National Environmental Policy Act.  In the second, technical review phase, FERC and USACE staff will coordinate with the developer to finalize project design for review and approval by FERC and USACE so that construction can begin.

According to statements from FERC Chairman Norman Bay and Assistant Secretary of the Army for Civil Works Jo-Ellen Darcy, the MOU will facilitate development of hydroelectric development at USACE dams.

Unlike solar and wind, hydroelectric capacity additions have not seen rapid development in recent years, due in part to the long and costly permitting and licensing timeline for hydropower development.  The MOU is intended to make the permitting and licensing process more efficient and less risky for new hydropower development at existing USACE-owned dams.  Currently only 3% of the nation’s 80,000 existing dams are being used to generate electricity. While the Energy Information Administration (EIA) reports that roughly 300 megawatts (MW) of new electric generating capacity from non-powered dams is expected to come online in 2016, accounting for roughly 92% of all hydroelectric capacity additions in 2016, this is only a small fraction of the 12,000 MW of additional generating capacity that the U.S. Department of Energy has estimated non-powered dams could provide.

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Nuclear Energy in DOE’s Quadrennial Energy Review

Posted on July 21, 2016 by Jessica Bell

The Nuclear Energy Institute (NEI) offered comments earlier this month on DOE’s Quadrennial Energy Review.  NEI argues that preserving and expanding nuclear energy infrastructure is key to both an “all of the above” energy policy and CO2 emission reduction efforts.  NEI identifies priority areas as:

  • Preserving existing nuclear capacity;
  • Continuing construction of large Generation III+ light water reactors;
  • Working on small modular reactor deployment; and
  • Financing development, demonstration, and deployment of advanced nuclear technologies.

NEI lists a number of ideas for preserving nuclear generation in current market conditions, including the adoption of mass-based compliance plans under the CPP.  Additionally, NEI notes that a predictable regulatory framework could aid existing plants in seeking further license renewals.

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Fifth Circuit Grants Stay of EPA’s Implementation of Regional Haze Rule

Posted on July 19, 2016 by Jeff Bayne

On July 15, 2016, the U.S. Court of Appeals for the Fifth Circuit granted a judicial stay on EPA’s Regional Haze Rule federal implementation plan for Texas and Oklahoma.  Unlike the Clean Power Plan, the Regional Haze Rule does not have the explicit purpose of reducing CO2 emissions from power plants.  However, challengers in this case argued (among other things) that EPA was using the Regional Haze Rule to improperly target coal-fired power plants, and that 3,000 MW to 8,400 MW of generating capacity in Texas would be forced to retire under EPA’s plan.

The Clean Air Act requires states and the federal government to set and seek to achieve targets for visibility in certain protected federal lands (this rulemaking covered the Wichita Mountains Wildlife Refuge, Big Bend National Park, and Guadalupe Mountains National Park). In 1999, EPA promulgated the Regional Haze Rule to establish guidelines for state compliance with these Clean Air Act visibility requirements.  States are responsible for implementing standards set by the federal government, and only if a state has not complied with the requirements of the Clean Air Act can the EPA create its own implementation plan for that state.  Earlier this year, EPA partially rejected Texas and Oklahoma’s state implementation plans, and imposed its own federal plan.  EPA based part of its rejection on Texas’s failure to conduct source-specific analysis, and EPA’s own plan looked at specific emission controls for the fifteen electrical generating units with the greatest visibility impact on protected areas.

After rejecting EPA’s argument that this case should be dismissed or transferred to the D.C. Circuit, the Fifth Circuit held that the petitioners had satisfied the requirements for a judicial stay.  The Fifth Circuit noted that they had demonstrated a strong likelihood of success in arguing that the EPA acted arbitrarily, capriciously, and in excess of its statutory authority, and in particular that EPA’s requirement of a source-specific analysis was not supported by the Clean Air Act or the Regional Haze Rule.  Although the Fifth Circuit granted the challengers’ motion for a stay, it has not yet issued a decision on the merits of the case.

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