FERC, CFTC, and State Energy Law Developments

Interest in microgrids is on the rise in the United States as over half of states explore ways to modernize the grid and promote distributed energy resources (DER), including innovative renewable energy, storage, and demand response technologies. However, microgrids are not defined by law or regulation in most states and are more complex than other types of DER because they involve both the generation and distribution of energy. This raises several policy questions, including who should pay for microgrid development and use and whether microgrid operators that technically distribute energy to retail customers should be classified as public utilities and subject to regulations ordinarily imposed on such entities. California is currently exploring the potential benefits of microgrids and the role of state regulation.

FERC issued a notice of proposed rulemaking (NOPR) on September 19 announcing its intent to revise key rules governing the status and rights of Qualifying Facilities (QFs). These revisions include proposed changes to the rules for measuring QF size that could make it more difficult for certain projects to maintain QF status. The NOPR also proposes to provide greater flexibility to states in regulating the rates that QFs can receive from their interconnected utilities, as well as a number of other fundamental changes in the regulation of QFs.

For the first time, FERC has found that significant investments in an existing licensed hydroelectric facility by a licensee will be considered when establishing the license term in a relicensing proceeding, potentially aiding the licensee in obtaining a longer license term.

Section 15(e) of the Federal Power Act (FPA) provides that any license issued shall be for a term that FERC determines to be in the public interest, but no less than 30 years or more than 50 years. Under its 2017 Policy Statement on Establishing License Terms for Hydroelectric Projects, FERC established a 40-year default license term policy for original and new licenses. The Policy Statement included exceptions to the 40-year license term under certain circumstances, including establishing a longer license term upon a showing by the license applicant that substantial voluntary measures were either previously implemented during the prior license term, or substantial new measures are expected to be implemented under the new license.

The Council on Environmental Quality (CEQ) published draft guidance on June 26 to address how agencies implementing environmental reviews under the National Environmental Policy Act (NEPA) should consider greenhouse gas (GHG) emissions. The new guidance would replace the Obama administration’s 2016 guidance, which has been on hold since April 5, 2017, pending “further consideration” pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth.

If adopted, the guidance could impact every federal agency proceeding that requires a NEPA analysis, including FERC natural gas pipeline certificate proceedings, liquefied natural gas (LNG) facility certificate proceedings, nuclear power plant decommissioning projects, and independent spent fuel storage installation facilities.

The guidance specifies that under the NEPA “rule of reason,” which defers to agency expertise in conducting NEPA analyses, as well as existing CEQ regulations, “[a]gencies preparing NEPA analyses need not give greater consideration to potential effects from GHG emissions than to other potential effects on the human environment.”

The Federal Energy Regulatory Commission (FERC or Commission) on July 18 issued a rule, initially proposed in July 2016,[1] restructuring the way it collects certain data for market-based rate (MBR) purposes and significantly expanding the information it collects from MBR holders. Under the Final Rule, FERC will now collect MBR application and certain compliance information in a new database with multiple data tables relating to one another via entity-specific, unique identification numbering (FERC’s new “relational database”), an intricate and entirely new electronic reporting system that will become compulsory in early 2021.[2] Order 860 also adopts changes to the ownership and the gas and electricity “affiliate” information required in an MBR Seller’s compulsory disclosures.

The Final Rule will take effect on October 1, 2020, and baseline submissions will be due by February 1, 2021.[3] As of February 1, 2021, prior to filing an application for initial MBR authority, a new Seller will be required to make a submission into the relational database, which will itself create the required asset appendices and indicative screens that filers had previously prepared independently. FERC affirmed that after January 31, 2021, a Seller will no longer report its affiliated generating and related electric and gas assets in the current .XLS format (an Appendix B Excel spreadsheet).[4] Instead, the information will now be submitted in XML format and the data to be collected in the relational database, which the Final Rule claims will generate an asset appendix.[5]

For the second time, PJM Interconnection, LLC (PJM) has suspended its 2019 Base Residual Auction (BRA) as directed by the Federal Energy Regulatory Commission (FERC). FERC found that delaying the auction until the Commission establishes a replacement rate would provide greater certainty to the market than conducting the auction under the existing rules.

PJM previously suspended the 2019 BRA when FERC granted PJM’s request to waive the auction timing requirements of its tariff to allow for a delay from May to August 2019.

Read FERC’s order.

Consolidated Edison Company of New York, Inc. (Con Edison) and Orange and Rockland Utilities, Inc. (O&R) issued a draft joint Request for Proposals (RFP) on May 31 to competitively procure scheduling and dispatch rights from new energy storage projects. Through this initial solicitation, Con Edison and O&R are targeting at least 300 megawatts (MW) and 10 MW, respectively, of new energy storage facilities to meet the in-service deadline of December 31, 2022, set by the New York Public Service Commission (NYPSC) in its December 2018 Order (Storage Order) establishing New York’s three gigawatt (GW) energy storage deployment goal.

Both utilities will accept bids only for new storage projects sized over five MW and connected to the transmission or distribution system that can directly participate in New York Independent System Operator (NYISO) markets and provide distribution benefits, if applicable. These front-of-meter systems must be able to discharge for at least four hours 100 to 350 times per year, have at least 85% roundtrip efficiency, and maintain 98% availability for dispatch each contract year.

A recent grid reliability report issued by staff members of the Offices of Electric Reliability and Enforcement within FERC evaluating the upcoming operating season underscored the changing generation resource mix in the United States and its implications for grid operations.

As we reported in December 2018, to jumpstart the energy storage market as envisioned by Governor Andrew M. Cuomo, the New York Public Service Commission (NYPSC) issued an order establishing an aggressive 3 GW energy storage goal by 2030, with an interim target of 1.5 GW by 2025, and directing investor-owned electric utilities (IOUs) to engage in competitive procurements for energy storage. The IOUs will issue draft requests for proposals (RFPs) this summer following a stakeholder process that kicks off on March 29.