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NTUA details significant progress on Navajo Nation CARES Act projects

November 18, 2020

by Paul Ciampoli
APPA News Director
November 18, 2020

In the Four-Corners region of the United States, the Navajo Tribal Utility Authority (NTUA) has been busily working towards a December 30, 2020 deadline to extend, build, connect, and provide utility services to hundreds of families funded through Coronavirus Aid, Relief, and Economic Security (CARES) Act.

In mid-August, the Navajo Nation– the recipient of CARES Act funding — announced the award of $147,116,561 to NTUA to construct utility projects eligible under the CARES Act with the goal and purpose of combatting COVID-19. The various NTUA projects are identified in the Navajo NationCARES Act legislation.  These projects must be completed by December 30, 2020.

NTUA is grateful that the Navajo Nation Council passed the Navajo Nation CARES Act legislation and that the Navajo Nation President signed the legislation authorizing the connection of over 500 homes of Navajo families to the electric grid.

NTUA further noted that in anticipation of the approval of the Navajo Nation CARES Act, it had been organizing internally to connect hundreds of homes. In an effort to connect as many families as possible NTUA’s electric construction crews started working five ten-hour days per week starting in June. 

By starting to connect families before the Navajo Nation awarded CARES Act funding to NTUA, NTUA took the risk that the Navajo Nation might not fund NTUA with CARES Act funding as was being proposed at the time.

“We did this with complete faith that Navajo leaders would approve Navajo Nation CARES Act dollars for electric construction,” NTUA General Manager Walter “Wally” Haase said. “If we waited until September to start construction, over 100 families would not have been connected this year.”

“We didn’t want to take that chance,” Haase added. “We want to help as many families as possible to help fight the spread of this devastating COVID-19.”

In June, NTUA presented a proposal to extend electricity to 510 homes, which includes 350 families that NTUA was prepared to connect during the 2020 Light Up Navajo II project (LUNII). The Light Up Navajo initiative, which was supported by a $125,000 grant from APPA’s Demonstration of Energy and Efficiency Developments (DEED) program began in Spring 2019, bringing together volunteer crews from public power utilities across the country to connect Navajo homes to the grid.

NTUA and 34 public power utilities were ready to connect the 350 homes in April 2020; however, the COVID-19 pandemic delayed plans for LUNII. Rather than having the 350 families wait until Spring of 2022, NTUA submitted their homes for funding from the Navajo Nation with CARES Act funding.  Many of the LUN II homes were shovel ready with all the necessary Rights of Way and land acquisition approval in place.

“We wouldn’t have had these LUN II projects ready if we didn’t have our sister utilities on board,” Haase said. “Even though they didn’t travel here, they made it possible for LUN II families to be connected. Their initial commitment resulted in a meaningful difference in the lives of these families.”

NTUA plans to launch another Light Up Navajo project as soon as it is safe to do so. “We want to echo NTUA’s thanks and encourage utilities to continue reaching out if they are interested in participating the next LUN event” said Alex Hofmann, Vice President, Technical and Operations Services, at APPA.

Progress Reports

In weekly progress reports for Navajo Nation leadership, NTUA provides updates on the various CARES Act projects. In Update #11 of November 12, 2020, NTUA noted that in order to help combat the spread of COVID-19, it created partnerships with the other electric service utilities that serve small regions on the Navajo Nation.

As part of the Navajo Nation CARES Act legislation, NTUA was authorized to install off-grid solar units across the Navajo Nation. NTUA initiated a public campaign inviting families without electricity to apply for a solar unit.

NTUA received more than 1,000 applications and many are from families living within close proximity to a power line. In addition, some of the families are living beyond the reach on NTUA’s electric distribution system.

NTUA therefore reached out to the electric companies that serve applicants living in these areas, including Arizona Public Service, Continental Divide Electric Cooperative, Jemez Mountain Electric Cooperative and Socorro Electric Cooperative to find ways to partner to connect these families to the electric grid. NTUA will use CARES Act funding to fund the connection of a minimum of 31 homes served by these companies.

“We used the blueprint of Light Up Navajo as a guideline. I was inspired through the generosity of our sister utilities during LUN to find and create new partnerships,” Haase said. “This is the first time NTUA has established such a partnership with these neighboring electric utility companies. We reached out because of the success of LUN and now we have another unified effort to help families get connected.”

Dual Purpose — off-grid solar units and electric grid connections

As of November 12th, NTUA crews have been working to prepare qualified homes to be connected to the 3,000-kW solar units, energy efficient refrigerators come with each unit, and have determined that:

199 homes are feasible to date; Installation of solar units is scheduled to begin the week of November 16th

NTUA continues to work with the Navajo Nation to obtain land acquisition for construction. The Navajo Nation Land Department has issued NTUA land acquisition for 117 projects, moving these projects closer to construction.

NTUA Districts and Electric Construction line crews have worked 10-hour days. Various crews are building power lines on weekends and holidays.

As a result of these efforts, 358 families are now connected to the electric grid, an increase of 36 homes from the week.

Moreover, NTUA connected 29 homes in two days following the completion of two major power lines that extended over 10 miles.

As for electric capacity projects, NTUA’s electric division has completed 27 out of the 59 planned CARES Act funded projects. There are 17 projects in construction, including Kinlichee (AZ), Kayenta (AZ), Shiprock (NM), and Mexican Water (UT).

Additional projects are set to begin construction later this month in Fort Defiance (AZ), Crystal (NM), Navajo Mountain (UT), and Chinle (AZ). The work will include substation work and pole replacements.

The complete week #11 Update is available here. To continue to follow NTUA’s progress, please look for the weekly Updates at www.ntua.com on the CARES Act – NTUA projects page. 

NYPA reports first milestone in effort to extend hydro project’s operating life through digitization

November 17, 2020

by Paul Ciampoli
APPA News Director
November 17, 2020

The New York Power Authority on Nov. 17 announced the first milestone of its 15-year modernization and digitization program to significantly extend the operating life of its Niagara Power Project.

The Niagara Power Project is New York State’s biggest electricity producer, providing up to 2.6 million kilowatts of electricity, which is generated by two facilities, the Robert Moses Niagara Power Plant and the Lewiston Pump Generating Plant, with a combined 25 turbines spun by 748,000 gallons of water per second. NYPA sells the power to state facilities, municipal and rural electric coops, and large utilities.

As part of the Robert Moses Niagara Power Plant’s life extension and modernization program, called “Next Generation Niagara,” 13 turbine units in the project’s main generating facility will be upgraded. An outage to allow for the overhaul of the first unit began recently and digitization and modernization work commenced earlier this month, NYPA said.

“The digitization of the first hydroelectric generator at the Robert Moses Power Plant is significant because it will set the course for work on the remaining twelve units,” said Gil Quiniones, NYPA president and CEO, in a statement.

Improvements under Next Generation Niagara, which was launched in July 2019, include replacing aging equipment with the latest machinery reflecting advanced digital technologies for optimizing the hydroelectric project’s performance. 

The initiative encompasses four major phases.

NYPA said that the first major outage will allow for the installation of new digital controls on the first turbine generator unit and its connections to the control room and the plant’s substations. Panels in the control room corresponding to the turbine unit also will be digitized as part of the plant’s overall control room upgrade and redesign.

The turbine unit outage aligns with another outage for work on NYPA’s transmission life extension and modernization program taking place in the plant’s switchyard. This will allow new digital controls to be installed on the transformers and circuit breakers corresponding to the upgraded turbine.

The work on this first unit is part of a design build contract NYPA trustees awarded to Burns and McDonnell earlier this year which includes subcontracts to Emerson and Ferguson Electric of Buffalo.

The first-unit outage is expected to last approximately 7 months.  

Redwood Coast Energy Authority, Valley Clean Energy sign resource adequacy agreements

November 17, 2020

by Paul Ciampoli
APPA News Director
November 17, 2020

California community choice aggregators Redwood Coast Energy Authority and Valley Clean Energy have signed resource adequacy agreements with California-based Leap, which enables real-time automated trading on energy markets.

Under the agreements, Leap will provide a total of 12.5 megawatts in flexible capacity to Redwood Coast Energy Authority and Valley Clean Energy. The new capacity will be made available for use by the CCAs starting in June 2021 over a ten-year term and will be sourced from Leap’s marketplace for grid flexibility.

The new agreements will allow the CCAs to unlock a new means of meeting energy demand in their service territories by gaining access to a statewide market of distributed energy resources, Leap said in a recent news release.

This includes delivering flexible capacity from within the CCAs’ service territories, as some of the resources in the Leap marketplace will be provided by customers of the CCAs.

According to Leap, it has been the largest participant in California’s Demand Response Auction Mechanism over the past two years.

Leap’s marketplace for grid flexibility grants energy resources — including battery energy storage, electric vehicles, smart thermostats, HVAC systems and industrial facilities — access to demand response programs, wholesale markets, and real-time pricing through a single application programming interface.

The Redwood Coast Energy Authority is a local government joint powers agency whose members include the County of Humboldt, Calif., all incorporated cities within the county, and the Humboldt Bay Municipal Water District.

Valley Clean Energy is a not-for-profit public agency formed to provide electrical generation service to customers in Woodland, Davis, Winters and the unincorporated areas of Yolo County, Calif.

Additional information about Leap is available here.

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

Chelan PUD Commissioners hear details on plan to expand conservation efforts

November 17, 2020

by Paul Ciampoli
APPA News Director
November 17, 2020

Commissioners for Washington State’s Chelan PUD on Nov. 16 heard a plan to expand energy conservation programs to focus on households that spend more than 6 percent of their income on power bills.

In Chelan County, about 2,100 households qualify as “high energy-burdened” because they spend more than 6 percent of their paychecks on electricity. About 98 percent of these households earn less than $20,000 a year.

PUD staff outlined a plan to launch a focused low-income energy assistance program in 2021. The PUD already offers rebates for energy-saving measures, including insulation, heat pumps and windows. Staff recommended greater engagement with nonprofits and landlords, as well as greater assistance to help low-income homeowners cover the up-front cost of home improvements.

PUD commissioners “expressed support to expand energy conservation, which would provide significant benefit to about two-thirds of the 2,100 high energy-burdened households,” Chelan noted in a news release.

“I believe we also have to remind ourselves that we work consistently to keep our rates lower than most of the country,” Commissioner Steve McKenna said. “That’s part of our ongoing commitment to provide rate relief.”

PUD staff will continue developing the program and report on progress in 2021.

Energy Northwest, partners bring solar-battery project online

November 17, 2020

by Ethan Howland
APPA News
November 17, 2020

Energy Northwest and its partners started operating Washington State’s first utility scale solar-plus-battery project.

The Horn Rapids Solar, Storage and Training Project, which includes 4 megawatts of solar and a 1-MW/4-megawatt-hours vanadium flow battery, came online this month.

The City of Richland, Wash., where the project is located, will buy electricity from the project.

Excess electricity from the solar panels will be stored by the battery system for later use, according to Energy Northwest, a joint action agency serving public power utilities with 1.5 million customers.

The battery storage component will help smooth the project’s solar output, support energy time shifting with peak demand reduction, offer demand side management options, and provide voltage and var support, according to the project’s developers.

Tucci Energy Services, a Seattle-based company, owns and operates the solar portion of the poject. Energy Northwest owns and operates the battery storage system.

“This project will provide clean and reliable power to families in this community while showcasing the role utility-scale solar and battery projects can play in our statewide energy strategy moving forward,” said Mary Tucci, Tucci Energy Services chief operating officer.

Pacific Northwest National Laboratory, part of the U.S. Department of Energy, and the University of Washington’s Clean Energy Institute will monitor and analyze data from the project to evaluate the financial benefits of incorporating battery energy storage, Energy Northwest said.

The information will be used to improve battery designs and develop tools for incorporating intermittent renewables onto the grid more reliably and economically, according to Energy Northwest.

The facility also houses a training program for solar and battery storage technicians. The program will be run and managed by Potelco Inc., an electric utility contracting firm based in Sumner, Wash.

Energy Northwest expects hundreds of workers from across the United States will use the training facility a year.

The roughly $6.5 million project received a $3 million grant from Washington’s Clean Energy Fund. The International Brotherhood of Electrical Workers, Local 77, which owns and leases the land where the project is located, worked with Energy Northwest and Potelco since 2015 to develop the project.

Groups urge FERC to reject objections to small utility opt-in mechanism under DER order

November 16, 2020

by Paul Ciampoli
APPA News Director
November 16, 2020

The American Public Power Association and the National Rural Electric Cooperative Association are urging the Federal Energy Regulatory Commission to reject objections to a small utility “opt in” mechanism that the Commission adopted in Order No. 2222, a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets.

In addition, APPA and NRECA said that FERC should not carve out an exception to the small utility opt-in for energy efficiency resources (EERs) in a Nov. 3 filing.

Order No. 2222, which FERC approved in September, enables DERs to participate alongside traditional resources in the regional organized wholesale markets through aggregations, opening U.S. organized wholesale markets to new sources of energy and grid services (Docket No. RM18-9-000).

In October, the Sierra Club, Sustainable FERC Project, and Natural Resources Defense Council filed a request for rehearing and clarification in response to Order No. 2222.

These groups argued challenged the final rule’s small utility opt-in on the grounds that “state authorities simply do not possess the power to directly determine whether resources are permitted to participate in RTO/ISO markets,” asserting that “such state actions directly ‘aim at’ wholesale transactions and are therefore field preempted.”

This argument “mischaracterizes the nature of the small utility opt-in, which is not a unilateral assertion of state and local authority over wholesale transactions, but rather a framework adopted by the Commission pursuant to its jurisdiction to establish the criteria for participation in wholesale markets,” APPA and NRECA said in a joint answer to the filing made by the Sierra Club, Sustainable FERC Project, and Natural Resources Defense Council.

NRECA and APPA pointed out that under the small-utility opt-in, state and local actions do not directly “aim at” FERC-regulated wholesale transactions.

“Rather, the Commission accounts for state and local preferences and concerns in determining eligibility to participate in wholesale markets.” In adopting the small-utility opt-in, the Commission “appropriately exercised its discretion to determine that, given the burdens that the final rule could impose on small utilities, retail customers of those utilities are not eligible to participate in DER aggregations under Order No. 2222” unless the relevant electric retail regulatory authority affirmatively allows such retail customer participation.

“This is an exercise of the Commission’s jurisdiction, not an intrusion upon it,” APPA and NRECA said.

APPA, NRECA also argue that FERC should not carve out an exception for EERs

Meanwhile, APPA and NRECA told FERC that it should not carve out an exception to the small utility opt-in for EERs.

That proposal was made in an Oct. 19 request for clarification, or, in the alternative, rehearing filed by Advanced Energy Economy (AEE) and Advanced Energy Management Alliance (AEMA).

“As a threshold matter, AEE and AEMA do not establish that participation of EERs in DER aggregations could have no impacts on small distribution utilities or their regulators that justify providing the opt-in,” APPA and NRECA argued.

AEE and AEMA pointed to the Commission’s assertion in a case involving AEE that, compared to demand response, EERs are not likely to present the same operational and day-to-day planning complexity that might otherwise interfere with a load-serving entity’s day-to-day operations.

But FERC “never said that EER wholesale market participation could impose no obligations on distribution utilities, nor would such an assertion be accurate,” APPA and NRECA noted.

“For example, a small distribution utility with EERs on its system participating in an aggregation might need to monitor how any capacity provided by the EERs was accounted-for in determining the utility’s resource adequacy obligations.”

Similarly, under Order No. 2222, small distribution utilities and/or their regulators might need to coordinate with RTOs and ISOs concerning whether a resource participating in a state or local energy efficiency program should be restricted from participating in a wholesale aggregation under the provisions of Order No. 2222 that are designed to avoid double compensation, APPA and NRECA said

“Indeed, just the obligation for distribution utilities and their regulators to monitor and track the complex RTO and ISO rules that will govern DER aggregation could impose a significant burden on small distribution utilities.”

Further, the fact that EERs are not subject to the Commission’s opt-in/opt-out regulations under Order Nos. 719 and 719-A is not a reason to exclude EERs from the small utility opt-in, as AEE and AEMA contend, the public power and cooperative trade groups argued. Order Nos. 719 and 719-A addressed improvements to RTO governance.

Final rule builds off recent court ruling on Order No. 841

FERC in September said that Order No. 2222 builds off a ruling earlier this year from the U.S. Court of Appeals for the District of Columbia Circuit on Order No. 841 in which the court affirmed the Commission’s exclusive jurisdiction over the regional wholesale power markets and the criteria for participation in those markets.

In July, the appeals court issued an opinion that denied an appeal filed by the American Public Power Association and several other parties that challenged certain aspects of Order Nos. 841 and 841-A, which established rules for the participation of electric storage resources in RTO and ISO markets. 

Public power utilities respond to power outages caused by ice storms

November 16, 2020

by Paul Ciampoli
APPA News Director
November 16, 2020

Oklahoma public power utilities embarked on a large-scale restoration effort after a historic ice storm caused widespread outages the week of October 26-31, the Oklahoma Municipal Power Agency (OMPA) reported on Nov. 12.

OMPA said that statewide, more than 300,000 customers lost power in the first 24 hours of the storm, due mainly to fallen trees.

Utilities in Oklahoma typically employ tree-trimming programs to avoid such disasters, but this storm came earlier in the year than normal and dumped several inches of ice onto trees that still hadn’t lost their leaves, thus impacting trees that had sustained decades worth of winters.

The state’s public power utilities deployed their mutual aid program to get customers back online, as crews from around the state answered the call for assistance, as well as crews from utilities in Arkansas, Kansas and Missouri.

Fourteen of the OMPA’s 42 members suffered outages in the first day of the storm, while another 15 experienced outages in the following days, impacting thousands of customers. One public power utility with just less than 16,000 customers had 260 different individual outages on the second day of the storm.

Several of the outages OMPA members saw lasted days, some the entire week, due to the extensive damage sustained from the fallen trees. However, all OMPA members had power restored by Monday, November 2, with a few remaining service drop issues.

OMPA offered thanks to the following crews for assisting members with outage restoration:  GRDA; Tahlequah, OK; Claremore, OK; Skiatook, OK; Pryor, OK; Collinsville, OK; Stilwell, OK; Bentonville, AR; Wellington, KS; Coffeyville, KS; Siloam Springs, AR; Monet, MO and OMPA Field Services.

NPPD helps Burt County Public Power District restore power

Meanwhile, in partnership with other public power utilities, Nebraska Public Power District assisted Nebraska’s Burt County Public Power District in making repairs after a hard-hitting ice storm earlier this month.

Along with NPPD, crews from the following utilities assisted Burt County Public Power District assisted with power restoration efforts: Elkhorn Rural Public Power District, North Central Public Power District, as well as Niobrara Valley Electric Membership Corporation.

Snohomish PUD signs deal to move forward with vehicle-to-grid charging

November 13, 2020

by Peter Maloney
APPA News
November 13, 2020

Snohomish County Public Utility District in Washington State has contracted with Mitsubishi Electric, Hitachi ABB and Doosan GridTech to install two electric vehicle-to-grid (V2G) chargers.

The V2G chargers are being sited at Snohomish PUD’s Arlington microgrid site and will be able to charge an electric vehicle and also send the stored energy back to the grid during a power outage.

Snohomish PUD began planning its Arlington microgrid project four years ago. It is now nearing completion, which is expected in January 2021. The $9 million project, which includes a $3.5 million grant from the Washington Department of Commerce, includes a 500-kilowatt (kW) solar array and a 1-megawatt (MW), 1.4-megawatt hour (MWh) battery system, as well as the two Mitsubishi two-way capable electric vehicle chargers.

Doosan’s DERO distributed energy resource management system (DERMS) will control the Arlington microgrid’s energy storage system, as well as the electric vehicle charging stations when grid connected. Doosan is also partnering with Awesense, a Canadian software company that is integrating its digital energy platform with Doosan’s DERMS to gather more granular data on the distributed energy resources, V2G devices and other assets involved in the project to provide accurate, real-time data and analytics.

The microgrid is designed to support a new local office that Snohomish PUD is building in Arlington, north of the utility’s Everett headquarters, to accommodate growth in the northern part of the county.

The microgrid will allow Snohomish PUD’s Arlington operations center to continue to operate in the case of an outage. But the microgrid will also be able to provide revenues when the system is connected to the grid in the form of ancillary services such as peak shaving, energy arbitrage, and capacity firming.

For instance, the solar-plus-storage microgrid will be able to offset charges Snohomish PUD would have to pay its wholesale power provider, Bonneville Power Administration, to provide capacity firming, also known as solar smoothing, during times when solar output drops because of conditions such as cloud cover.

In that way, the microgrid is “earning its keep,” Scott Gibson, project manager for the Arlington microgrid, said. “It is benefitting the grid daily. It is a solar powered emergency generator with a day job.”

Snohomish PUD plans to use the two-way capable electric vehicle chargers to power up utility electric vehicles. Snohomish PUD is just starting to build up its electric vehicle fleet, Gibson said.

Currently, the utility has four electric vehicles, two Nissan LEAFs and two Kia Niros. The LEAFs will be used for the V2G system.

While V2G technology has often been touted as a promising form of mobile storage for the grid, achieving that promise is more difficult. “There is a big controversy with V2G, about whether to use public vehicles or fleet vehicles,” Gibson said. “In our opinion, it is tough to find the right incentive to allow owners to let us use their vehicle.” An electric vehicle that is also feeding the grid would be charging and discharging more frequently than a vehicle that is only being used for transportation and that degrades the battery more rapidly. “Everybody is struggling with that,” Gibson said.

A utility, on the other hand, can monetize the discharge functions of an electric vehicle for the benefit of the grid. Gibson noted that if a utility were to have 16, 60-kWh Nissan LEAF electric vehicles, it would essentially have 1 MWh of storage.

“We see this as an important step in our ‘utility of the future’ vision and for SnoPUD to be one of the premier utilities in the country,” John Haarlow, the utility’s CEO and general manager, said in a statement.

While the Arlington microgrid is a pilot project, it is “an actual functioning system,” Gibson noted. There are a lot of similar demonstration projects but “this will be one of the first to truly put a functioning grid connected V2G system together,” he said.

Among the challenges that come with building a pioneering project is integrating the various pieces of the system. “Electrically the system is pretty simple,” Gibson said, but getting the different controllers to talk to each other is a challenge.

The Mitsubishi V2G chargers have their own control system, which must talk to the microgrid control system, a task made more difficult because control of the microgrid depends on how it is being used.

When the microgrid is connected to the grid, it will be controlled by Doosan’s DERMS system. When the microgrid separates from the grid during an outage and is in islanded mode, it will be controlled by the Hitachi-ABB microgrid control system. “It is really a unique system,” Gibson said.

In the initial stages, Snohomish PUD’s recovery of its investment in the microgrid project will be learning, Gibson said. “When the energy market changes, though, there will be more value and we will be able to step right in and take advantage of that.”

“We have an incredibly supportive commission and general manager, who all see this as part of our future” Gibson said. With that vision, “the more we invest, the more we can take advantage of it.”

WAPA, Municipal Energy Agency of Nebraska and others to evaluate SPP membership

November 13, 2020

by Paul Ciampoli
APPA News Director
November 13, 2020

Southwest Power Pool (SPP) on Nov. 12 reported that it has received letters from several western power entities committing to evaluate membership in the organization.

If they pursue membership, Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska (MEAN), Tri-State Generation and Transmission Association, and Western Area Power Administration (WAPA) would become the first members of SPP’s regional transmission organization to place facilities in the Western Interconnection under the terms and conditions of SPP’s open access transmission tariff.

SPP said that WAPA’s evaluation of RTO membership will consider the participation of its Upper Great Plains-West region and Loveland Area Projects. “This would extend the reach and value of SPP’s services — including day-ahead wholesale electricity market administration, transmission planning, reliability coordination, resource adequacy and more — and the synergies they provide when bundled under the RTO structure,” SPP said in a news release.

Basin Electric, MEAN, Tri-State and WAPA’s Upper Great Plains-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.

Along with Deseret, each is also a customer of at least one of SPP’s contract-based Western Energy Services, which includes reliability coordination and a real-time market scheduled to launch in February 2021.

The companies’ letters indicate they will now work with SPP to evaluate the terms, costs and benefits of putting western facilities under the RTO’s tariff.

A recent SPP Brattle study found that WEIS participants’ membership in the SPP RTO would produce approximately $49 million in savings annually for SPP’s current and new members.

The RTO said that 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 said 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, the grid operator said.

SPP launched its first real-time balancing market in 2007 then transitioned to a day-ahead market and became a single, consolidated balancing authority in 2014.

It first began serving customers in the west in December 2019 when it launched its Western Reliability Coordination service on a contract basis.

SPP is awaiting FERC approval to implement a western energy imbalance service market that it plans to launch in February 2021.

FERC in July rejected the SPP proposal for a western energy imbalance service market. At the same time, FERC offered guidance for a modified proposal should SPP choose to submit one. SPP then submitted a modified western energy imbalance service market proposal in October.

CAISO Western EIM

Earlier this year, the California Independent System Operator signed an implementation agreement with Xcel Energy-Colorado, which paves the way for its participation in the CAISO Western EIM in 2022.

The agreement also provides for participation of three other utilities: Black Hills Energy Colorado Electric Colorado Springs Utilities, and Platte River Power Authority.

The four utilities currently share resources and balance demand for electricity during peak periods through a Joint Dispatch Agreement.

These utilities launched a study in 2019 to determine which market, the WEIS proposed by SPP or CAISO’s Western EIM, would provide greater benefits to customers.

The Colorado utilities also report that the Western EIM has lower administrative costs and is exploring adding day-ahead market services, which could help participants to make wider use of renewable energy resources.

New England public power utilities sign PPAs for hydroelectric power

November 13, 2020

by Peter Maloney
APPA News
November 13, 2020

A total of 21 public power utilities in New England have signed agreements to purchase 200 million kilowatt-hours (kWh) per year of hydroelectric power produced by FirstLight Power in Western Massachusetts.

The purchase agreement, which was structured and executed by Energy New England, will take energy from the Turners Falls and Cabot generating facilities on the Connecticut River in Montague and will save the participating utilities’ ratepayers millions of dollars over the life of the contract, according to Energy New England, a wholesale risk management and energy trading organization serving public power utilities in the northeast.

“Never before have so many municipal light plants, municipal electric departments, and other public power utilities come together to buy emissions-free renewable power on this scale,’’ John Tzimorangas, president and CEO of Energy New England, said in a statement.

Power purchases by Massachusetts public power utilities served by Energy New England on average now account for 29% fewer carbon dioxide (CO2) emissions than electricity generated in the state as a whole, Energy New England said, adding that the new contracts will raise the public utilities’ average to 34% below the state average.

FirstLight and Energy New England offered an excellent opportunity for Reading Municipal Light Department “to increase its portfolio of local renewable energy at competitive rates for our customers in the four towns we serve,” Coleen O’Brien, general manager of the Reading utility, said in a statement.

The participating utilities are mostly in Massachusetts and include:

Also participating are the Block Island Utility District and Pascoag Utility District in Rhode Island and Stowe Electric Department in Vermont.

FirstLight Power is a clean power producer and energy storage company in New England with a portfolio that includes nearly 1.4 gigawatts of pumped hydro storage, battery storage, hydroelectric generation, and solar generation.