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FERC proposes to modify plan to revise its transmission incentives policy

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

The Federal Energy Regulatory Commission (FERC) proposed to modify a March 2020 plan to revise its electric transmission incentives policy meant to stimulate infrastructure development.

The supplemental Notice of Proposed Rulemaking (NOPR) proposes to codify FERC’s current practice of granting a 50-basis-point increase in return on equity (ROE) as an incentive for utilities that join a transmission organization, but also proposes to limit the duration of the adder.  

FERC currently allows a transmission utility in a transmission organization to collect the ROE adder for as long as the utility remains a member of the transmission organization.  Under the supplemental NOPR, a utility only would be eligible for the incentive for the first three years after the utility transfers operational control of its facilities to the transmission organization (Docket No. RM20-10).

The action took place at FERC’s April 15 monthly open meeting.

The Commission’s March 2020 NOPR had also proposed to increase the incentive for membership in a regional transmission organization (RTO), an independent system operator (ISO) or other FERC-approved transmission organization from 50 basis points to 100 basis points, but the supplemental NOPR proposes to hold the line at 50 basis points. 

The supplemental NOPR would also require utilities that have received the incentive for three or more years to submit, within 30 days of the effective date of a final rule, a compliance filing to eliminate the incentive from its tariff.  

Utilities currently receiving the incentive must either revise their tariffs to eliminate the incentive or to terminate the incentive three years from the date that they turned over operational control of their transmission facilities to a transmission organization.

The supplemental NOPR seeks comment on whether the incentive should be available solely to transmitting utilities that join a transmission organization voluntarily.  If so, the Commission wants to know how it should apply that standard and, in particular, how to determine whether the decision to join was voluntary. Some have challenged the incentive adder in cases where a utility’s participation in a transmission organization is not voluntary, such as where state law requires that a utility participate in a transmission organization.

In comments on the March 2020 proposed rule and an early FERC notice of inquiry, the American Public Power Association had urged FERC to scale back the ROE adder incentive awarded to utilities that participate in transmission organizations.

At FERC’s April monthly meeting, FERC staff estimated that the proposed rule changes could save ratepayers $350 million annually.

Comments are due 30 days after publication in the Federal Register. Reply comments are due 15 days after that.

Chatterjee, Danly dissent

FERC Commissioners Neil Chatterjee and James Danly dissented from FERC’s decision.

Section 219 of the Federal Power Act (FPA) requires FERC to offer incentives to a utility “that joins a Transmission Organization.”  Chatterjee said that the supplemental NOPR “mischaracterizes the plain language” of this provision in order to strip utilities of a transmission organization incentive, “even though the utility RTO/ISO membership has led to substantial consumer benefits and is vital to the energy transition and the development of much-needed transmission in the RTO/ISO regions.”

He said that the supplemental NOPR “does not even attempt to grapple with any of the Commission’s well-reasoned prior holdings. Rather, the majority merely offers a conclusory statement that a new interpretation is reasonable.”

Chatterjee said he could understand the majority’s proposal “to eviscerate the transmission organization incentive if doing so accomplished an important or even articulable policy objective. But the proposal is—bafflingly—contrary to the current Administration’s federal clean energy goals.”

To meet such aggressive goals, “we will need both robust organized markets and an enormous amount of investment in transmission, and we will need to put Americans to work building the grid of the future. If this Commission hopes to run fast toward these energy transition goals, it must not shoot itself in the foot by eliminating the transmission organization incentive,” wrote Chatterjee.

For his part, Danly said it is not FERC’s role to second guess Congress. “It is irrelevant whether the majority ‘believes’ the RTO adder is no longer necessary as an incentive for a utility ‘that joins’ an RTO to stay in the RTO. If the majority or anyone else has a problem with the statute, their sole recourse is through Congress.”

He said that “just as the statutory text is not limited to an incentive for a utility ‘to join’ an RTO, it also is not limited to a utility that ‘voluntarily’ joins a transmission organization. That word does not appear in the statute. I oppose inserting this further limitation into the statutory text.”

Danly also argued that the majority “also fails to consider the effects of its proposed change on utilities that have not yet joined an RTO.”

He said that there are large portions of the country that have no RTO. “Recent events suggest that utilities in these regions are contemplating joining an existing RTO or forming a new one. The Commission should be taking actions to encourage such decisions. Instead, we are proposing to reduce the benefits to utilities that join RTOs based on a strained, erroneous interpretation of the statute.”

Utilities considering RTO participation “are sure to take note not only of the reduction in benefits attendant to RTO participation that the Commission proposes today, but also of the Commission’s willingness to take extraordinary steps to reduce those benefits. This is not the signal we should be sending to utilities that, to date, have resisted RTO participation,” wrote Danly.

Christie offers concurrence

In a concurrence, FERC Commissioner Mark Christie said the Commission “has previously enumerated the benefits of RTO/ISO participation to both public utilities and consumers, so the costs and benefits of such membership are not at issue here. At a time, however, when transmission costs are already a significant and rising part of consumers’ retail bills, ROE adders needlessly burden consumers with substantial additional costs without demonstrable evidence that they actually incentivize the particular action they are aimed at incentivizing.”

He said he agrees with certain commenters that the RTO adder provides an unnecessary windfall with no nexus to utilities’ decisions to join or remain in a RTO.

“It may also be the case that such adders are duplicative of other Commission incentives already granted to public utilities by virtue of their participation in an RTO/ISO,” Christie wrote.

While section 219 of the FPA requires the Commission to provide certain incentives—such as an incentive for joining an RTO/ISO—it also requires that resulting rates continue to be just and reasonable, Christie said.

“As noted by the Delaware Division of Public Advocate and the Office of the People’s Counsel for of the District of Columbia, ‘Congress did not intend for [FPA section 219], or the rules promulgated pursuant to it, to unjustly enrich utilities and RTO members at the customers’ expense.’ I agree.”

He also agrees with the supplemental NOPR’s conclusion that section 219 of the FPA does not require an incentive for RTO/ISO participation to take the form of an ROE adder and with its request for commenters to propose alternative, non-ROE incentives that would qualify under section 219.

“Absent a clear declaration from Congress that a FERC-authorized incentive must take the form of an ROE adder — which it did not require for RTO participation incentives — awarding an ROE adder for any length of time as a “reward” for joining an RTO/ISO may be inconsistent with FPA section 219’s concurrent mandate that rates must be just and reasonable and not unduly discriminatory or preferential,” wrote Christie.

“Because this supplemental NOPR proposes to limit the use of ROE adders for RTO/ISO membership to three years after joining — a welcome first move — I respectfully concur. I look forward, however, to commenters’ responses regarding non-ROE incentives.”

In a recent episode of the American Public Power Association’s Public Power Now podcast, Christie discussed transmission issues.

FERC orders PacifiCorp to respond to allegations of reliability violations

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

The Federal Energy Regulatory Commission (FERC) on April 15 ordered PacifiCorp to explain why the company should not be assessed a proposed civil penalty of $42 million for violating FERC reliability standards on its bulk electric system.

PacifiCorp is a subsidiary of Berkshire Hathaway Energy.

In a FERC Staff Report attached to FERC’s order, FERC Office of Enforcement (OE) staff alleges that PacifiCorp violated the Federal Power Act and regulations by failing to comply with a Commission-approved reliability standard developed by the North American Electric Reliability Corporation (NERC) involving transmission line facility ratings methodology.

Specifically, PacifiCorp adopted a facility ratings methodology that required the consideration of clearance measurements consistent with the National Electric Safety Code (NESC), FERC said.

FERC enforcement staff found that clearance measurements on a majority of PacifiCorp’s bulk electric system transmission lines were incorrect under the NESC. As these clearance measurements were used to calculate PacifiCorp’s facility ratings, PacifiCorp’s facility ratings were thus inconsistent with its facility ratings methodology, FERC said. 

Moreover, FERC enforcement staff alleges that PacifiCorp was generally aware of incorrect clearances on its bulk electric system since at least 2007, when FERC’s reliability standards became mandatory, but failed to specifically identify all of the clearance problems and remedy them in a timely manner.

Enforcement staff alleges that PacifiCorp’s violations began on August 31, 2009, when the company implemented its facility ratings methodology policy, and that at least some of the violations continued until August 2017, when PacifiCorp completed remediation of all of its incorrect clearances to make them consistent with its facility ratings methodology.

Enforcement staff’s investigation into PacifiCorp’s incorrect clearances began in 2012 after learning of the Wood Hollow wildfire that lasted from June 23 to July 1, 2012 in Sanpete County, Utah. 

FERC enforcement staff alleges that the inadequate clearance involved in the fire was just one example of clearance violations prevalent on PacifiCorp’s bulk electric system.

FERC noted that its order makes clear that issuance of the decision does not indicate Commission adoption or endorsement of the Staff Report. 

PacifiCorp has 30 days to respond to the Commission’s order.

WAPA’s Colorado River Storage Project to explore membership in SPP

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

The Southwest Power Pool (SPP) recently received a letter from the Western Area Power Administration’s (WAPA) Colorado River Storage Project (CRSP) expressing interest in evaluating membership in the organization.

 CRSP is the sixth electric service provider in the West to publicly commit to exploring regional transmission organization (RTO) expansion in the Western Interconnection, SPP noted.

In November 2020, Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska (MEAN), Tri-State Generation and Transmission Association, and WAPA’s Upper Great Plains-West and Loveland Area Projects notified SPP of their intent to evaluate membership in the RTO. The entities’ letters indicate they will work with SPP to evaluate the terms, costs and benefits of putting western facilities under the RTO’s tariff.

 If these utilities pursue membership, they would become the first members of SPP’s RTO to place facilities in the Western Interconnection under the terms and conditions of SPP’s open access transmission tariff.

 The interested parties currently receive at least one of SPP’s contract-based Western Energy Services in the Western Interconnection. CRSP participates in two –Western Reliability Coordination and the Western Energy Imbalance Service Market.

Basin Electric, MEAN, Tri-State and WAPA’s UGP-East Region are already members of SPP, having joined the RTO in 2015 when they placed their respective facilities in the Eastern Interconnection under SPP’s tariff.

A Brattle study commissioned by SPP found that the move would be mutually beneficial and produce $49 million a year in savings for SPP’s current and new members.

The western utilities joining SPP would receive $25 million a year in adjusted production cost savings and revenue from off-system sales, and SPP’s members in the east would benefit from $24 million in savings resulting from the expansion of SPP’s market, transmission network and generation fleet.

SPP noted that its prior calculations of the value of RTO membership suggest that these benefits are only a portion of those current and new members will derive.

There is additional value not considered by the Brattle study in five-minute real-time economic dispatch, achievement of public policy goals, lowered reserve-margin requirements, consolidation and regionalization of planning and other processes and more, SPP said.

 Additionally, SPP said it anticipates its wholesale electricity market, resource adequacy program and other regionalized services can help western members achieve renewable-energy goals and reinforce system reliability.

Construction to start soon on collaborative microgrid project between Chattanooga, EPB

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

Chattanooga, Tenn., Mayor Andy Berke, EPB President and CEO David Wade, Chattanooga Police Chief David Roddy, and Chattanooga Fire Chief Phil Hyman on April 15 confirmed that construction would soon begin on a new collaborative microgrid project between the City of Chattanooga and EPB.

The project aims to increase resilience and redundancy of power supply to the city’s public safety agencies via on-site solar arrays, traditional backup generation, battery storage and a microgrid controller.

The project start date is April 28, 2021 and the scheduled completion date is October 30, 2021.

While the Tennessee Valley Authority and EPB “already provide some of the greatest energy reliability in the country, an ever-increasing potential for natural and man-made disruptions requires investment in additional fortification for our most critical services,” an April 15 news release related to the on ‘Power to Protect” microgrid project said.

The total project cost is approximately $1.8 million, with $732,000 coming from EPB in the form of a battery and microgrid controller and circuit modifications. The balance will be funded by the City of Chattanooga’s capital budget.

Wade said that the project is a next-generation microgrid that benefits the whole community by adding additional resilience to police and fire services while also helping to keep the overall cost of electricity a bit lower for all customers.

“What sets this microgrid apart is that on-site solar generation, high-capacity battery storage and diesel generators are fully integrated with Chattanooga’s advanced smart grid infrastructure which has the ability to automatically re-route power around damaged power facilities to reduce the incidence of outages,” said Wade. “In addition to this extra layer of resiliency for our community’s emergency services, we will be able to utilize this microgrid as a resource to help reduce peak demand charges which keeps costs lower for all of our customers.”

Project specifications include 430-kilowatts (kW) total solar generation once complete, a 175-kW diesel generator, a 100-kW natural gas generator, 275-kW/1100-kWh battery storage, microgrid controller and interconnection.

OPPD signs PPA for output of 81-MW solar farm

April 16, 2021

by Peter Maloney
APPA News
April 16, 2021

The Omaha Public Power District (OPPD) has signed a power purchase contract with Community Energy for an 81-megawatt (MW) solar farm.

Renewable energy sources are central to OPPD’s Power with Purpose project, which includes a commitment to its board of directors to add up to 600 MW of utility-scale solar to OPPD’s fleet, along with modernized natural gas backup generation at its Turtle Creek and Standing Bear Lake stations, according to The Wire, the utility’s online newsletter.

The planned Platteview Solar project will be one of several solar facilities supporting OPPD’s 13-county service territory, according to The Wire. OPPD also plans to grow its renewable energy portfolio, which includes wind, hydro, landfill gas, and a 5-MW community solar facility, from its current 38.4 percent of retail sales as of 2020.

 OPPD is striving to be a net-zero carbon utility by 2050 under a strategic directive set up by its board of directors. Power with a Purpose came out of the board’s directive. OPPD has also begun a broader study, Pathways to Decarbonization, that is looking at the utility’s generation portfolio, internal operations, buildings, fleet and inventory, as well as community engagement regarding customer-owned generation, OPPD spokesman Cris Averett said. “We want to be part of that conversation,” he said.

The study is slated to continue for the rest of the year. OPPD would then report back to its board, which would then make recommendations to the utility.

The Platteview Solar project is sited on about 500 leased acres south of Yutan, Neb., in eastern Saunders County. It will be owned and operated by Radnor, Penna., based Community Energy, which was chosen for the project through a competitive bidding process.

Community Energy is in the process of securing a conditional use permits for the solar project. Pending approval, construction of the solar project would begin early in 2022 and take nine to 12 months to complete. “We are hoping for a green light by the summer,” Averett said.

In February, Saunders County passed a solar ordinance, stipulating required setbacks and a plan for funded site decommissioning at the end of the solar farm’s useful life, approximately 30 years.

The project will employ more than 150 people for up to a year. Longer term, up to three full-time employees would operate and maintain the site and Saunders County would receive around three decades of tax revenue with little to no effect on local services and infrastructure, according to The Wire. “It will be an economic boon for the county,” Averett said.

CPS Energy unveils pilot programs that incentivize EV home charging during off-peak hours

April 16, 2021

by Paul Ciampoli
APPA News Director
April 16, 2021

Texas public power utility CPS Energy on April 15 said it is introducing two pilot programs that incentivize electric vehicle home charging during off-peak energy demand hours and that help address drivers’ range anxiety.

CPS Energy said the addition of the two new programs for customers who charge their EV at home is in line with its Flexible Path strategy.

With the introduction of its FlexEV brand, “the utility recognizes the need to improve the environment by being a major supporter of EV adoption. CPS Energy is therefore unveiling new products and services to encourage drivers to consider alternative vehicles,” it said.

Under the FlexEV Smart Rewards program, participants will receive a one-time $250 enrollment credit on their utility bill. The customer will also receive a $5 monthly credit, equivalent to about 120 miles of driving, for allowing CPS Energy to remotely connect and carefully manage the customer’s charging device, as needed.  This would only occur when energy demand is high, between the hours of 2 p.m. and 9 p.m., Monday through Friday.  Specifically, if needed, CPS Energy would manage the flow of energy to the charger to help take pressure off the grid, the utility said.

Under the FlexEV Off-Peak Rewards program, a participant will receive a one-time $125 enrollment credit on their utility bill. The customer will also receive a $10 monthly credit for voluntarily choosing to limit charging to no more than two times a month between the hours of 4 p.m. and 9 p.m., Monday through Friday.

CPS Energy noted that it has 76 local ChargePoint charging stations in its FlexEV Public Charging program. In support of public charging, the utility’s program includes a flat-rate pilot program. This program has an annual fee of $96 for unlimited access to charging stations at any time of day or night.

If customers do not subscribe to the flat rate pilot program, they can still use the charging stations on a pay-as-you-go basis.

Public power utilities recognized for their efforts to shift to modern, carbon-free energy systems

April 15, 2021

by Paul Ciampoli
APPA News Director
April 15, 2021

Five public power utilities have been recognized by the Smart Electric Power Alliance (SEPA) for their efforts to transition to a modern and carbon-free energy system.

SEPA noted on April 14 that it launched the inaugural Utility Transformation Challenge to make a comprehensive, honest assessment of U.S. electric utilities’ progress towards a modern, carbon-free energy system.

SEPA said it conducted and analyzed multiple surveys designed to measure meaningful progress across multiple dimensions of utility infrastructure, programs, strategy and operations. Insights derived from these survey results form the basis for a new report: the 2021 Utility Transformation Profile.

SEPA received survey responses from 135 individual utilities, representing more than 83 million customer accounts, or approximately 63% of all U.S. electric customer accounts.

The report examines the utility industry’s transition to a clean and modern energy system by exploring four dimensions of utility transformation: clean energy resources, corporate leadership, modern grid enablement, and aligned actions and engagement.

With respect to what was learned from evaluating the utilities leading the clean energy transition, SEPA listed the following:

Utility Transformation Leaderboard

SEPA also unveiled the 2021 Utility Transformation Leaderboard, which SEPA said recognizes the ten utilities that have demonstrated the greatest progress in the transition.

Five of the 10 utilities on the leaderboard (in alphabetical order) are public power utilities (bolded):

“I am grateful for this prestigious recognition from the Smart Electric Power Alliance and appreciate the hard work of HG&E employees,” said James Lavelle, Manager of Holyoke Gas & Electric.

“As a municipal public power utility, HG&E is committed to providing innovative and sustainable energy solutions to our community through investments in a diverse power supply portfolio, energy storage, efficiency and conservation programs, as well as development of emerging clean energy technologies,” he said. “The State of Massachusetts has established a road map to net-zero by 2050 and HG&E is well positioned to meet this goal, as well as the incremental targets set for 2030 and 2040.”

“We are honored to be a part of SEPA’s Utility Transformation Challenge,” Seattle City Light General Manager and CEO Debra Smith said. “I think we all recognize the need to transform is a constant in our lives, businesses, and society. Creating a carbon-free energy system is never truly complete. City Light will continue to lead these efforts as our region moves toward a cleaner energy future.”  

“We’re proud to be leading the way in decarbonizing our economy,” said SMUD CEO and General Manager Paul Lau. “We’re at a point where we must commit to ambitious goals in order to achieve meaningful carbon reductions that benefit our community and the world.  Creating an inclusive, clean, green economy will improve economic, health and environmental outcomes, as well as drive a new, clean workforce and that’s something everyone can be excited about,” said Lau.

“We are honored to be on SEPA’s 2021 Utility Transformation Leaderboard,” said Jackie Sargent, Austin Energy General Manager. “Austin Energy is committed to grid modernization and affordable, carbon-free energy as approved by the Austin City Council. Inclusion on this list reinforces how important it is for the utility to continue these efforts and remain an industry leader.”

SEPA offers recommendations

SEPA provided recommendations for utilities of all sizes, types and geographies as they pursue their own path of transformation.

SEPA recommended utilities strengthen carbon reduction commitments by setting ambitious, science-based targets with interim goals and detailed plans to achieve them.

It also recommended that utilities address the transformation comprehensively across the organization through changes to processes, programs and structures that will accelerate clean energy adoption. 

Examples include pursuing integrated distribution planning, interconnection processes, evaluating non-wires alternatives (energy efficiency, demand flexibility, storage, etc.) to meet demands, developing a transportation electrification strategy and efficiently integrating and leveraging distributed energy resources.

Utilities should also embrace the clean energy transformation as a core element of the utility mission and culture. “This will require changes, such as linking executive compensation to reduced carbon emissions, establishing transparent emissions tracking and reporting programs and pursuing internal sustainability and carbon reduction programs (e.g., fleet electrification and supply chain programs),” SEPA said.

SEPA also recommended that utilities engage customers, technology partners, peer utilities and regulators early and often. “Common understanding and shared vision of new initiatives and technology deployments is critical to facilitate innovation,” it said.

In addition, SEPA said that utilities should integrate equity considerations and goals into efforts and programs to ensure all community members are able to participate in and benefit from the clean energy transformation.

The 2021 Utility Transformation Profile report and Utility Transformation Leaderboard are available here. Download the executive summary here.

DEED research in Texas studies how to mitigate EVs’ deterioration of transformer life

April 14, 2021

by Peter Maloney
APPA News
April 14, 2021

The Bryan Texas Utilities (BTU) used a Demonstration of Energy & Efficiency Developments (DEED) student research grant from the American Public Power Association to support a student to analyze mitigation strategies for the potential deleterious effect electric vehicles could have on utility transformers.

With the adoption of electric vehicles expected to rise rapidly in the future, BTU wanted to look at the use of rooftop solar power and battery storage to offset potential degradation of transformers caused by the expected increase in electric vehicle adoption and charging.

Studies showing average electric vehicle adoption rates can be misleading, Mladen Kezunovic, a professor of electrical engineering at Texas A&M University and the education advisor overseeing the DEED project, said. It is more likely that electric vehicle adoption will not occur evenly and will be concentrated in certain neighborhoods. In those neighborhoods, utilities could see much higher loads on their distribution transformers, possibly even a doubling of loads, Kezunovic said. And higher loads lead to higher heat in a transformer, which can shorten the expected useful life of the equipment.

Using the DEED grant, which took the form of a $5,000 scholarship, Milad Soleimani, a doctoral student at Texas A&M, developed a series of calculations to study the effect of overloading on transformers and mitigation strategies to offset those effects. The DEED study ran from December 2019 to December 2020.

The case study considered a residential area with a transformer with a nominal power of 63 kilovolt amps (kVa) and a total solar generation capacity of all the buildings of 10 kilowatts (kW). The rated power of the battery storage inverters was 5 kW, and it was assumed that the electric vehicles only operate in grid-to-vehicle mode.

For the study, Soleimani used load data available from the National Renewable Energy Laboratory (NREL) on OpenEI. Solar generation was calculated using NREL’s PVWatts Calculator. Weather data was extracted from the Iowa State University’s Environmental Mesonet archive. And electricity price data came from the Electric Reliability Council of Texas records.

The case study looked at seven different scenarios, ranging from a baseline with no electric vehicles, solar generation or battery storage to a scenario with a high penetration of electric vehicles with no solar or battery storage to a scenario in which there is solar generation, a high penetration of electric vehicles and battery storage is optimized by considering both electricity prices and transformer loss of life estimates.

Among the results, Soleimani found that the loss of energy in the charging and discharging of battery systems increases total energy consumption and presents challenges to the sole use of battery storage to mitigate transformer loss of life.

The study found that using battery storage, both with and without solar generation, optimized based on electricity prices, but did not mitigate transformer loss of life and had a negative impact on utility profits. The most successful approaches in the study were those that modeled the optimization of solar and storage based on prices and transformer loss of life calculations.

“Utilities as the owners of the distribution transformers benefit from the transformer loss of life mitigation strategy,” Soleimani wrote in the DEED report. “In the long term, the lower expenses for the utility will lead to cheaper electricity delivery to the end consumer. Thus, utility and consumers are both benefitting.” There should be incentives from utilities for consumers to make the investment viable, he said.

Broadly speaking, Kezunovic said the DEED study looked at three broad strategies: staggering electric vehicle charging times to minimize load, using solar photovoltaic panels and battery energy storage to minimize increased loads on transformers, and a combination of the first two options that uses algorithms to reduce the loads on transformers. The third option proved to be the most realistic, but it requires an algorithm for optimization that is not available today, Kezunovic said.

Today, “there is a disconnect between utilities and customer owned resources,” Kezunovic said. Utilities need to gain a better understanding of what customer resources, such as solar panels and electric vehicles, can do to their systems, he said, “and customers need to get on board with what utilities want them to do” and maybe utilities could incentivize them to do that.

CMPAS board announces hiring of Jay Anderson as agency’s new CEO

April 14, 2021

by Paul Ciampoli
APPA News Director
April 14, 2021

The Central Municipal Power Agency Services (CMPAS) Board of Directors announced the hiring of Jay Anderson as the agency’s new CEO.

Anderson, who will join CMPAS on May 3, 2021, comes to CMPAS from Bay City Municipal Electric Utility in Bay City, Mich., where he most recently served as Director of the Electric Utility.

Prior to working at Bay City, Anderson served for thirty years in various capacities with the Omaha Public Power District in Omaha, Nebraska, including as Project Director of the Power Forward Initiative. 

Anderson has spent his professional career in the Upper Midwest. CMPAS noted he is a tireless advocate for public power, most recently serving as at large member of the Executive Committee of the Michigan Public Power Association. 

In the past, he led the Large Public Power Association Rates Committee and spearheaded a sub-category of the LB901 “Condition Certain” legislation relating to what extent retail rates had been unbundled in Nebraska.

CMPAS conducted an extensive national search over the last eight months working with a search team consisting of CMPAS Board members and its General Counsel; Preferred Consulting LLC; and R. Bauman & Associates of Wisconsin.

CMPAS is a public power joint action agency providing power management and utility services for its electric utility members and affiliates.

CMPAS operates as a project-oriented, partial or full-requirements agency. CMPAS provides a wide range of services including strategic management, long-term power supply planning and procurement, energy market scheduling services, transmission ownership, project development and administration, utility accounting and finance support, and distribution mapping and modeling.

NCPA is exploring a hydrogen production facility with help from a DEED grant

April 13, 2021

by Peter Maloney
APPA News
April 13, 2021

The Northern California Power Agency (NCPA) is exploring the possibility of building a “green” hydrogen project, thanks in part, to the support of a Demonstration of Energy & Efficiency Developments (DEED) grant from the American Public Power Association.

The aim of the proposed project would be to build a hydrogen production and storage facility that could use over-generation associated with renewable energy resources to produce green hydrogen via electrolysis.

“We have been looking at the emerging technologies that can provide storage for renewable generation and hydrogen seems to check all the boxes,” Joel Ledesma, assistant general manager, generation services, at NCPA, said. “Producing hydrogen is not new but producing it at scale for the electric power grid is what is emerging.” The state of California, and the whole nation, is struggling with storage and generation that can be used to phase out fossil fuel generation, he added.

NCPA has evaluated other storage technologies but has found that lithium-ion battery storage is expensive for long term storage, pumped hydro storage is capital intensive and heavily regulated, and flywheel storage is difficult to scale up to meet commercial needs. NCPA has also evaluated technologies such as flow batteries, thermal salt storage, and compressed air energy storage and thus far deemed them not beneficial to its objectives.

NCPA would store the hydrogen produced at an electrolyzer and then blend with natural gas to be used as fuel at its Lodi Energy Center (LEC), a fast-start 300-megawatt (MW) combined-cycle plant the joint action agency uses to provide power during times of high demand.

NCPA’s current generation portfolio includes geothermal, hydropower, and natural gas-fired power plants with about half of the portfolio being emission free.

NCPA commissioned Black & Veatch to study the feasibility of a hydrogen production and storage facility. About half of the $96,600 study cost was covered by the DEED grant, which ran from December 2020 to February 2021.

Based on preliminary analysis and input from the turbine equipment manufacturer, NCPA believes its Lodi plant could co-fire up to 45 percent of hydrogen by volume.

“The blended fuel would provide about a 20 percent reduction in emissions from the Lodi plant and would be a step toward transitioning the facility to be fueled 100 percent by hydrogen,” Scott Tomashefsky, regulatory affairs manager at NCPA, said.

NCPA is considering siting the electrolysis facility near the Lodi plant, which would provide the dual benefit of being able to provide hydrogen for the transportation sector as well as using it for power generation. “To make hydrogen viable for the electric grid, it needs to be produced at a large scale,” so adding transportation could help make the project economics work, Ledesma said.

Among the primary conclusions of the study were that producing hydrogen using water electrolysis is technically feasible using commercially available technology and several vendors with commercial experience are available.

But even though there are several electrolyzer facilities operating around the world, the hydrogen energy storage facilities on the scale considered in the study are a relatively new phenomenon. The study also found that capital costs for hydrogen production and storage equipment is high and that electricity pricing contributes significantly to overall levelized costs. Nonetheless, projected pricing through the life of such a facility would appear to be “reasonable,” according to the DEED report.

In the study, Black & Veatch said it sees the potential for levelized cost of energy (LCOE) parity for a hydrogen facility that is used for co-firing a generator, as long as capital costs are reduced as much as possible, recovery and sales of oxygen from the facility are pursued, and renewable energy credit (REC) revenues can be shared with the renewable energy providers.

“Hydrogen may be feasible and practicable with the right incentives,” Ledesma said. The areas that need more study or follow-up, according to the DEED report, include:

The study marks another step toward our goal of eventually being able to fire the Lodi plant entirely with hydrogen, Ledesma said. NCPA plans to present the idea to its governing commission in order to adopt it as an emerging technology to track.

“California is seriously looking at whether natural gas remains in the future configuration of the power grid.” Tomashefsky said. “This study provides more context and helps move the conversation forward on what to do with the existing natural gas infrastructure.”

The study also does double duty, Ledesma said. It not only provides NCPA with valuable input as it negotiates a future with lower carbon dioxide emissions, but it helps inform other utilities and the public as a whole, so “we look at it as a dual benefit.”

APPA will host a webinar related to the project on May 4, 2021 from 2:00 pm to 3:00 pm EDT.

Additional details about the webinar are available here and DEED members can access the full project report here.