Tag: FERC

FERC Staff Issues Assessment of Demand Response and Advanced Metering

On November 7, the Federal Energy Regulatory Commission (FERC) issued their 13th annual report on demand response and advanced metering, which is required by the Energy Policy Act of 2005.

They discussed the penetration rates for advanced meters, as well grid modernization. The report noted that data has recently indicated that advanced meters have become the main type of meters in the United States. The penetration rate for advanced meters has approached 50 percent. In the last year, several states have requested advanced meters to be deployed on a larger scale; a number of them were approved to carry on.

The summer of 2018’s high temperatures and high fire risks led to utilities and operators in multiple states asking their customers to participate in voluntary conservation, emergency demand response, and/or critical peak pricing.

FERC also provided information on survey data from the U.S. Energy Information Administration (EIA) on recent actions that were taken at the state, federal, and regional levels, as well as by industry. EIA’s data shows that the biggest increase in customer enrollment in retail demand programs was in the radio frequency region, which increased by 50 percent. EIA says this increase was mostly due to the higher reported enrollment programs that are run by DTE Electric Company, Delmarva Power, and Potomac Electric Power Company.

The data shows that the enrollment in retail demand response programs went up by 8.2 percent between 2015 and 2016, and the enrollment in time-based rate programs went up by 4.8 percent.

FERC also responded to Advanced Energy Economy’s (AEE) petition for declaratory order pertaining to their “jurisdiction to regulate the participation of certain energy efficiency resources in the wholesale electricity markets.” FERC found that it indeed has jurisdiction in those markets, exclusively.

They approved the proposed modifications to PJM’s tariff to “improve the ability of certain resource types to participate in PJM’s capacity market.”

The assessment also included information on Order No. 841, the Electric Storage Resource Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, which is intended to remove any barriers for “the participation of electric storage resources in the RTO and ISO markets,” by requiring RTO and ISO to revise their tariffs and establish a model for participation that recognizes the operational and physical characteristics for the storage of electric resources.

FERC discussed the different issues and developments in demand response, specifically state legislative and regulatory activities regarding those and time-based rates. Several states have approved time-based rate pilot programs, “some in combination with proposed electric vehicle charging infrastructure investments, due to an interest in incenting off-peak charging of electric vehicles.” Other states have begun to consider what their next steps will be in regard to time-based rate programs and demand response.

FERC Acts on Tax Reductions for Energy Customers

On November 15, the Federal Energy Regulatory Commission (FERC) took steps to help ensure that their ratepayers will receive beneficial tax deductions from the December 2017 Tax Cuts and Jobs Act. They issued a Note of Proposed Rulemaking, several orders, and a policymaking during this meeting, all related to the Tax Act. The Tax Act cut the corporate tax rate from 35 percent to 21 percent, which came into effect on January 1, 2018.

The Notice of Proposed Rulemaking, RM19-5-000, is proposing to require that each public utility transmission provider with a transmission owner tariff or a rate schedule to revise their rates to account for any changes that fall under the Tax Act. FERC says these proposed rules are intended to address the effects the Tax Act has had on the Accumulated Deferred Income Taxes (ADIT), which is reflected in their transmission rates.

According to the Washington Examiner, “FERC’s proposed tax rule would apply to the interstate transportation of energy only, where it has jurisdiction over the wholesale electricity and natural gas markets.”

The utilities FERC is calling public in this instance are electric utilities, but they are owned by investors, not municipal utilities. Under these reforms the public utilities will:

“include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases
include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT
incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT”

Every public utility with transmission stated rates will determine the amount of excess and deferred income tax that is due to the reduced federal corporate income tax rate, and they are to recover or return that amount from or to their customers.

FERC did not provide a specific mechanism to adjust the rate bases, nor did they give a specific method to return the excess ADIT.

FERC says “We estimate that the total number of public utility transmission providers with formula rates that would have to develop revisions to their formula rates, including the addition of a new permanent worksheet, and make compliance filings in response to this Proposed Rule is 106.”

During that meeting, they also addressed policy statement PL19-2-000, which provides guidance on accounting and ratemaking for ADIT, for all natural gas and oil pipelines and public utilities that fall under FERC’s jurisdiction.

“Among other things, the policy statement states that for a public utility or natural gas pipeline that continues to have an income tax allowance, any excess of deficient ADIT associated with an asset must continue to be amortized in rates even after the sale or retirement of that asset,” FERC said.

FERC will also be considering if it needs to make more changes to its calculation of base returns on equity and to transmission incentives.

“I think we all agree that our policies are overdue for a fresh look with input from all interested stakeholders, not just those that happen to be parties to a pending complaint proceeding,” Chairman Neil Chatterjee said. “Further, with 13 years having passed since Congress established Section 219 of the Federal Power Act, I think it’s high time we look at whether these two sets of policies are producing the level and type of transmission investment that the nation needs.”

“FERC is the federal agency that regulates and oversees interstate transmission of electricity, natural gas and oil and is composed of five commissioners nominated by the president and confirmed by the U.S. Senate,” according to the Nevada Independent.

FERC will be receiving comments on these proposals 30 days after this proposed rule is published in the Federal Register. FERC will also be putting the full text of the proposal on their website, and it will be available in FERC’s Public Reference Room from 8:30 a.m. to 5:00 p.m. Eastern time at 888 First Street, N.E., Room 2A, Washington D.C. 20426.

FERC Acts on Cybersecurity Risks

On October 18, The Federal Energy Regulatory Commission (FERC) approved new mandatory reliability standards that are intended to address risks to cybersecurity. These new standards will augment the current Critical Infrastructure Protection (CIP) standards in order to mitigate the current risks to cybersecurity that are in the supply chain for grid-related systems.

The standards require transmission grid operators and electric utilities to create and implement plans that have security controls for supply chain management for industrial control systems, software, hardware, and services.

“Reliability of the bulk power system requires our attention to security issues as well as ensuring that the system serves consumers during peak-demand times,” FERC Chairman Joseph T. Kelliher said. “These proposed standards are intended to provide the adequate safeguards and training to help us do that.”

These standards have been in the works since September 2017, when they were first proposed by the North American Electric Reliability Corporation (NERC) as a response to a FERC directive that identified some possible threats to the utility center. NERC has a period of 18 months to implement the new standards; according to FERC the longer timeline to implement everything was justified because of the technical upgrades needed.

FERC also told NERC to implement the new standards into Electronic Access Control and Monitoring Systems (EACMS) associated medium and high Bulk Electric System Cyber Systems that fall under the supply chain risk management standards; they have 24 months to implement these changes. According to FERC, the EACMS can include authentication servers, intrusion detection systems, firewalls, and alerting systems. Once an EACMS has been compromised, the Bulk Electric System can be controlled.

The standard does not “require that every contract with a vendor include provisions for each of the listed items,” NERC said. The utilities would instead need to “ensure that these security items are an integrated part of procurement activities, such as a request for proposal or in the contract negotiation process.”

As part of a bigger security risk study, NERC will be giving FERC any cybersecurity risks they uncover in Physical Access Control Systems and Protected Cyber Assets, instead of developing new standards for those. These include things like electronic locks, motion sensors, networked printers, local area network switches, badge readers, and file transfer services.

In January 2018, FERC outlined the new standards in a Notice of Proposed Rulemaking, and this final ruling on the changes follows that notice closely. In FERC’s outline, they had initially given a 12-month timeline for implementation, even though NERC had requested 18 months, but they decided to allow for 18 months in the final rule.

FERC specified in Order No. 829, that the standards should focus on four security objectives: (1) software integrity and authenticity; (2) vendor remote access protections; (3) information system planning; (4) vendor risk management and procurement controls.

In March 2018, the American Public Power Association and other groups urged FERC to approve the proposal. At the same time, they requested that FERC wait to include EACMS in the new policies, which were given a longer timeline for implementation.

“The proposed standards fulfill Order No. 829’s directive and would mitigate supply chain cybersecurity risks to the BES while appropriately focusing on the systems and assets that are most critical to reliable operation of the BES,” the Association told FERC.

“While the standard is not a panacea, it is an important step forward to tackle a tough problem,” Commissioner Neil Chatterjee said. “It will be particularly important to revisit the standard after several years of experience to see what is working and what aspects could be improved. But again, today’s order is a good step in the right direction.”

The final rule will take effect 60 days after it is published in the Federal Register.