Skip Navigation

Missouri public power utilities bring power back to customers in wake of ice storms

January 4, 2021

by Paul Ciampoli
APPA News Director
January 4, 2021

Missouri public power utilities in recent days have been hard at work restoring power to customers who lost power in the wake of ice storms that hit the state.

In the wake of ice storms that swept through Missouri on January 1, line crews from several public power utilities volunteered to help restore power to the cities of Hannibal and Monroe City, Mo., the Missouri Public Utility Alliance (MPUA) reported in a news release.

The response was coordinated through a mutual aid network of utilities that are members of the MPUA.

The 84 utilities in the network are public power electric utilities that have agreements in place allowing staff to assist neighboring communities and states during widespread outages in other communities. Assisting utilities are reimbursed by the communities receiving assistance.

In Hannibal, after significant outages were caused by downed tree limbs hitting power lines, line crews from Columbia Water & Light, Harrisonville, Macon Municipal Utilities and Rolla Municipal Utilities responded to assist the Hannibal Board of Public Works (HBPW) utility staff in power restoration and repair work.

The combined four-city mutual aid response to HBPW included 17 lineworkers with 11 utility work vehicles, including bucket and digger trucks.

In a Facebook post, HBPW reported with continued efforts the morning of Jan. 3, “we have restored service to all parts across our service territory. We estimate we have 25 or fewer individual services that need to be restored. Several of those require additional repairs from electricians before our crew can reconnect service but we are standing by when needed.”

The quick recovery efforts “could not have been possible without the assistance of our mutual aid partnership and the extra tree removal assistance,” the utility said.

In Monroe City, electric crews repairing outages were assisted by a crew of four lineworkers from the city of Higginsville. After power restoration at Monroe City was complete by noon on Jan. 2, the Higginsville crew traveled to Hannibal to join in the HBPW restoration effort.

Meanwhile, City Utilities (CU) Electric Department in Springfield, Mo., on Jan. 1 reported that it responded to numerous outages throughout the CU service territory. “Overnight, CU line and tree crews began responding to outages as weather permitted. The majority of the outages have been created by limbs and trees contacting the power lines. However, there is at least one utility structure that has been damaged. Additional line and tree crews are arriving to assist CU crews,” the utility reported.

On Jan. 2, the utility said that its crews were working on the final remaining outages from the New Year’s Day ice storm, with approximately 70 customers remaining without electric service as of mid-day.

“While our goal and efforts are to restore power to all of our customers there are some that will require work to be completed by a licensed electrician before we can reestablish service,” CU noted.

The storm created outages throughout the CU Electric service territory with approximately 50 percent of feeders being impacted.

City Utilities line crews began responding to outages shortly after 1:00 a.m. on New Year’s Day as the storm began impacting the city. Response was slowed and affected by the continuing weather pattern as it dropped rain and ice as temperatures fell in the Springfield area, CU said. Line crews were assisted by numerous contract line and tree crews to restore service to customers.

EPA finalizes ozone NAAQS, retains current standards

January 4, 2021

by Paul Ciampoli
APPA News Director
January 4, 2021

The U.S. Environmental Protection Agency (EPA) on Dec. 23 announced its decision to retain, without changes, the 2015 ozone National Ambient Air Quality Standards (NAAQS) set by the Obama-Biden Administration.

The EPA said it is following the principles established by the Trump Administration to streamline the NAAQS review process and to fulfill the statutory responsibility to complete the NAAQS review within five years. The action marks the second time in Clean Air Act history that the agency has completed an ozone NAAQS review within the congressionally mandated five-year timeframe, according to the EPA.

The agency noted that since the beginning of the Trump Administration, it has re-designated  eight nonattainment areas  as in attainment with the 2008 eight-hour ozone standards.

In May 2018, EPA issued a “Back-to-Basics” memo to improve EPA’s process for reviewing the NAAQS. The memo laid out goals to get EPA back on track with Clean Air requirements, statutory deadlines, and the issuance of timely implementation rules. The Dec. 23 action is the first NAAQS review to do so and charts a path to continue this statutory responsibility in the future.   

The Clean Air Act requires EPA to set NAAQS for “criteria pollutants.” Currently, ozone and related photochemical oxidants and five other major pollutants are listed as criteria pollutants.

The law requires EPA to periodically review the relevant scientific information and the standards and revise them, if appropriate, to ensure that the standards provide the requisite protection for public health and welfare.

In the prior review of the ozone standards, which was completed in 2015, the Obama-Biden EPA increased the stringency of the levels of the ozone standards to 70 parts per billion (ppb), from the 2008 standard of 75 ppb.

Additional information about EPA ozone standards is available at: https://www.epa.gov/ground-level-ozone-pollution. APPA submitted comments in support of retaining the  2015 primary (public health) and secondary (public welfare) standards at 70 ppb.

EPA is making the ozone NAAQS rule

Great Lakes Utilities seeks front-of-meter, behind-the-meter solar proposals

January 4, 2021

by APPA News
January 4, 2021

Wisconsin-based joint action agency Great Lakes Utilities (GLU) is seeking proposals for front-of-meter and behind-the-meter solar projects under a recently issued request for proposals (RFP).

The Energy Authority is the administrator for the RFP.

GLU, which provides various services to its 12 member owners, is seeking bids for power purchase agreements and build-transfer submissions with a commercial operation date between 2021-2023 for:

Battery energy storage will also be considered for the behind-the-meter projects as outlined in the RFP.

GLU is looking to procure energy, capacity, and renewable energy credits for a term between 10-20 years.

Key elements of project consideration are project viability, price, congestion risk, and deliverability and GLU is only seeking bids for projects physically located within MISO Capacity Zone 2.

GLU is a member of MISO and its average system peak for 2019 was 370 MW with similar load projected for 2020 and beyond.

The projects sought under the RFP are intended to meet capacity shortfall requirements due to upcoming expiration of existing power purchase agreements and to reduce future transmission cost and delivery risk.

Additional details about the RFP are available here.

Tennessee public power utilities restore power in wake of snowstorms

December 30, 2020

by Paul Ciampoli
APPA News Director
December 30, 2020

Public power utilities in Tennessee in the last week of December restored power to customers affected by snowstorms that hit the state.

On Dec. 24, Knoxville Utilities Board (KUB) tweeted that its crews were working to restore power throughout the day and monitoring and responding to any outage events throughout the night as snow fell. Crews worked overnight to reduce outages to less than 9,000 after the heavy snow, KUB subsequently reported on Dec. 25.

KUB in a Dec. 26 update said that approximately 60 crews were working to restore power including assistance from Lenoir City Utility Board and Appalachian Electric Cooperative, crews from Nashville and Jackson, Tennessee, and crews from Alabama, Kentucky, and North Carolina.

In the update, KUB reported that large numbers of trees and wires were reported down following the storm. “Although KUB has made significant progress since yesterday, the heavy, wet snow and freezing temperatures are causing additional limbs and trees to fall, creating additional outages,” the public power utility reported in the Dec. 26 update.

KUB noted that crews have had challenges accessing the lines due to the number of downed trees and other damage. “Even getting to the job has been difficult in some cases where snow and ice has made travel treacherous.”

Every job is different, but a typical repair job can take up to four to six hours, while replacing a pole can take a minimum of six to eight hours, the utility said.  Given these challenges, a definite time frame for restoration of specific areas was not available, as of the Dec. 26 update. At the time of the 9 a.m. update, KUB reported approximately 3,300 customers without power.

In a Dec. 28 tweet, KUB said that crews continued restoration efforts for just under 20 customers, down from more than 31,000 customers who lost power after Thursday’s snow.

Meanwhile, Tennessee public power utility Newport Utilities (NU) reported on Dec. 30 that as of 9:00 a.m. it had 227 outages remaining. “Multiple crews from surrounding areas are assisting NU electric crews in replacing broken poles and untangling the gnarly mess of downed spans of electric wire. The goal is to restore power to the remaining areas today,” it said in a Facebook post.

And less than 1,000 Sevier County, Tenn., residents remained without power following a Christmas Eve blackout that impacted more than 20,000, reported Tennessee’s WVLT on Dec. 28.

The latest updates on power outages can be found on Sevier County Electric System’s website.

FERC approves SPP’s resubmitted proposal for a Western Energy Imbalance Service market

December 24, 2020

by Paul Ciampoli
APPA News Director
December 24, 2020

The Federal Energy Regulatory Commission on Dec. 23 approved the Southwest Power Pool’s resubmitted Western Energy Imbalance Service (WEIS) Market tariff, Western Joint Dispatch Agreements and Western Markets Executive Committee Charter, effective February 1, 2021.

SPP had resubmitted the WEIS proposal after the Commission rejected its initial proposal on July 31. In that order, FERC cited a number of reasons for rejection of the proposal and provided guidance for a new submission if SPP chose to do so.

While APPA has been monitoring developments related to the SPP WEIS, it has not taken a position on SPP’s proposal.

A number of protests of the resubmittal were filed at FERC including Colorado Springs Utilities and Platte River Power Authority. SPP resubmitted the proposal in early October.

The Commission in its Dec. 23 order found that the WEIS Market “will yield diverse benefits to the participating utilities and customers in the Western Interconnection, and that SPP has both addressed the concerns presented by the Commission in the July Order and demonstrated that its proposal presents a just and reasonable regional solution.” 

Expected benefits described in the order include having a broader pool of resources available to serve load, which allows participants to meet their energy imbalance needs at lower cost; improved reliability; and better integration and management of higher levels of variable energy resources.

The protestors were aligned in their concerns on most issues.

In the order, the Commission made findings regarding the issues raised by at least one of the protestors.

Among other things, FERC found that:

The FERC order is available here.

East Bay Community Energy board OKs policy to set target of 100 percent clean power by 2030

December 22, 2020

by Paul Ciampoli
APPA News Director
December 22, 2020

The East Bay Community Energy (EBCE) Board of Directors on Dec. 16 approved a policy to set a target of providing its customers with 100% clean power by 2030, which would be 15 years before the state’s energy standard.

EBCE said that the board action sets the local community choice aggregator as one of the largest electricity providers in the country to commit to 100% clean power by 2030 and the largest of other local community choice energy providers that have set similar goals.

Dan Kalb, Chair of the Board for EBCE, noted that the CCA’s commitment to procuring clean energy has already resulted in contracts for over 500 megawatts of new wind, solar, and energy storage. In 2021, EBCE expects to contract for several hundred more megawatts of clean energy.

EBCE on Oct. 29 issued a request for offers to procure long-term renewable energy and storage resources.

The EBCE staff report that the board acted on is available here.

EBCE operates a community choice energy program for Alameda County and eleven incorporated cities, serving more than 550,000 residential and commercial customers throughout the county.

The American Public Power Association has initiated a new category of membership for community choice aggregation programs.

LIPA board approves time-of-use rate proposal

December 22, 2020

by Paul Ciampoli
APPA News Director
December 22, 2020

The Long Island Power Authority’s Board of Trustees on Dec. 16 unanimously approved a time-of-use (TOU) rate proposal.

LIPA files a Utility 2.0 and energy efficiency plan each year for consideration by the LIPA Board. The annual plan proposes and requests funding for new initiatives related to modernizing the customer experience, distributed energy resources integration, grid modernization, beneficial electrification, and energy efficiency. 

In the 2018 Utility 2.0 plan, LIPA approved a rate modernization initiative, which included funding for an “add-on” to the existing billing system to provide the capability to program and bill advanced metering infrastructure (AMI) enabled rate designs, which serves as the foundation for a phased rate modernization roadmap.

LIPA began work on developing the new TOU rate designs, which include four new residential TOU rates (including one targeted at electric vehicle owners) and one new small commercial TOU rate. 

The TOU rates use industry best practices in rate design and customer engagement strategies, fine-tuned through significant upfront research, including visiting and learning from other utilities experienced in AMI-enabled rates and billing.

The new TOU rate designs contain elements intended to improve customer take-up and response, as compared to LIPA’s existing time-of-use rates, Justin Bell, LIPA’s Vice President of Public Policy and Regulatory Affairs said.

The new elements include shorter – three or four hour — peak periods, the ability for a customer to select a peak period suitable for its household from among several options, and super-off-peak nighttime rates. 

They will be combined with new tools that enable customers to estimate their potential savings from the new rates and learn how much savings is possible based on their own household’s energy profile, frequently used appliances, and ability to shift usage, Bell said.

The tariffs containing the new TOU rate designs were issued for public notice and comment in September 2020, providing over two months for stakeholders to review and comment on the proposed rates.  Public hearings were held in November 2020.

The final TOU rate proposal incorporates feedback received from stakeholders. The tariffs will become effective on Feb. 1, 2021.

DOE issues order aimed at reducing risks to bulk-power system from China-related entities

December 21, 2020

by Paul Ciampoli
APPA News Director
December 21, 2020

U.S. Secretary of Energy Dan Brouillette on Dec. 17 issued an order designed to reduce the risks that entities associated with the People’s Republic of China pose to the U.S. bulk-power system (BPS).

The order only applies to utilities that have been designated as defense critical electric infrastructure (DCEI). The Department of Energy informed a small number of public power utilities that they had been designated as DCEI in 2019.

The order invokes the authority delegated to the Secretary of Energy by Executive Order 13920, “Securing the United States Bulk-Power System” (EO 13920) and takes effect January 16, 2021. 

The order prohibits utilities that supply critical defense facilities from procuring from the People’s Republic of China specific BPS electric equipment that poses an undue risk to the BPS, the security or resilience of critical infrastructure, the economy, national security, or safety and security of Americans, the DOE said in a news release related to the order.

President Trump issued EO 13920 on May 1, 2020 and granted implementation authority to the Secretary of Energy.

The DOE order provides a compliance grace period of several weeks to minimize potential procurement and supply chain disruptions.

The order specifically prohibits utilities that supply critical defense facilities at a service voltage of 69-kV or above from acquiring, importing, transferring, or installing BPS electric equipment, and is specific to select equipment manufactured or supplied by persons owned by, controlled by, or subject to the jurisdiction or direction of the People’s Republic of China.

The order applies from the point of electrical interconnection with the critical defense facility up to and including the next “upstream” transmission substation.

Utilities subject to the order will be notified no later than five days from the issuance of the order.

Additional information including a link to the order is available here.

LaGrange, Georgia, negotiating solar power deal with local Walmart store

December 21, 2020

by Peter Maloney
APPA News
December 21, 2020

The city council of LaGrange recently authorized the city’s utility to sign agreements that would allow the Georgia city to offer renewable power to the local Walmart store.

Walmart has a goal to serve at least 50% of their stores nationwide with renewable power by 2025 and 100% by 2035.

Buying renewable solar power through the city allows Walmart to realize better prices and keeps revenues from one of the city’s largest customers in the local economy, Patrick Bowie, the city’s director of utilities, said.

Walmart provides the city with about $1.3 million in annual revenues.

The solar power purchase will require multiple agreements, which are still under negotiation. “We are trying to finalize them by year end,” Bowie said.

As a member of the Municipal Electricity Authority of Georgia, LaGrange relies on MEAG Power for its generation and transmission resources. For actual power sales, the city uses The Energy Authority.

MEAG Power is in the process of wrapping up negotiations with the developer of a large solar power project in southern Georgia. LaGrange, meanwhile, is finalizing a deal with Walmart for sales of solar power that will be matched by a back-to-back purchase agreement for a portion of the output from the solar project with which MEAG is contracting. It would be MEAG Power’s first participation in a solar power project.

Walmart’s electrical load in LaGrange is between 17 million and 18 million kilowatt hours (kWh) per year, which would require between 5.5 megawatts (MW) and 6 MW of capacity.

The deal is complicated by the fact that LaGrange currently has excess power and that Walmart’s load does not synch up with intermittent solar output. To protect itself from purchasing more power than it needs or paying more for solar power than it pays for its conventional power, LaGrange is negotiating a sales agreement with Walmart under which the retailer would be responsible for the difference between the cost of solar and the cost of wholesale power the city buys from The Energy Authority. If solar power is more expensive, Walmart would absorb that cost. If solar power is less expensive, Walmart would benefit from the lower costs.

LaGrange is also signing an agreement with Electric Cities of Georgia, which provides LaGrange and 51 other public power communities with distribution support services. Under the agreement, Electric Cities of Georgia would provide LaGrange with the billing services to balance the books on power sales between LaGrange and Walmart.

To help mitigate the risks associated with the solar sales, Walmart would be able to shift power sales to its other retail locations in Georgia.

One of the details that still needs to be worked in the negotiations is to see what level of participation other cities want in the solar power deal, Bowie said.

LaGrange is an industrial center, but so far none of the city’s other large commercial customers have requested renewable power. It is hard for solar power to compete with the city’s current low power rates, Bowie said.

FERC issues NOPR proposing incentive rate treatment for voluntary cybersecurity investments

December 21, 2020

by APPA News
December 21, 2020

The Federal Energy Regulatory Commission on Dec. 17 issued a notice of proposed rulemaking (NOPR) proposing incentive rate treatment for certain voluntary cybersecurity investments that go above and beyond the requirements of the North American Electric Reliability Corporation’s (NERC) mandatory Critical Infrastructure Protection (CIP) reliability standards.

The NOPR (Docket No. RM21-3-000) was issued by the Commission at its monthly open meeting. It was the first FERC open meeting for Commissioner Allison Clements, who was sworn in on December 8, 2020. Clements did not vote on any of the agenda items.

FERC white paper

In June, FERC staff sought comments on a white paper that proposed “a new framework for providing transmission incentives to utilities for cybersecurity investments.” FERC staff cited “the evolving and increasing threats to the cybersecurity of the electric grid” as the impetus for the Cybersecurity Incentives Policy white paper (Docket No. AD20-19-000).

In response to the white paper, the American Public Power Association in August said that an incentive program for cybersecurity investments is not needed to encourage investment in cybersecurity measures and could lead to investment that raises transmission costs for customers without providing meaningful cybersecurity benefits in return.

Details of NOPR

Reflecting many of the features included in the FERC Staff white paper, the new NOPR would allow FERC-jurisdictional utilities to seek Commission approval, pursuant to section 205 of the Federal Power Act, of two types of incentives for cybersecurity investments:  a rate of return adder of 200 basis points or deferred cost recovery for certain cybersecurity-related expenses.

Qualifying expenditures would be eligible for either, but not both, incentives. The total cybersecurity incentives requested would be capped at the top of the return on equity “zone of reasonableness” used by FERC to establish allowed equity returns for public utilities.

The incentives would be available for certain investments that voluntarily apply specific CIP reliability standards to facilities that are not subject to those requirements and/or implement standards and guidelines from the National Institute of Standards and Technology’s (NIST) voluntary framework for improving critical infrastructure cybersecurity.

Deferred cost recovery would be allowed for three categories of expenses: (1) expenses associated with third-party provision of hardware, software and computing networking services; (2) expenses for training to implement new cybersecurity enhancements undertaken pursuant to this rule; and (3) other implementation expenses, such as risk assessments by third parties or internal system reviews and initial responses to findings of such assessments.

Prior or continuing costs would not be eligible for incentives. Deferred regulatory assets whose costs are typically expensed would be amortized over a five-year period.

Utilities seeking to implement the proposed incentives must obtain prior Commission approval, and the proposed rule would impose initial and annual reporting requirements.

Comments on the NOPR are due 60 days after publication in the Federal Register, with reply comments due 30 days later.