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FERC rejects ISO New England energy security proposal

November 4, 2020

by Paul Ciampoli
APPA News Director
November 4, 2020

The Federal Energy Regulatory Commission on Oct. 30 issued an order finding that ISO New England’s Energy Security Improvements (ESI) proposal “is unjust and unreasonable because it would impose substantial costs on consumers without meaningfully improving fuel security.”

Background

On April 15, ISO-NE submitted to FERC proposed ESI tariff changes, which the ISO described as “necessary to address the fuel security challenges facing the New England region.”

The proposal came in response to a July 2018 order in which FERC denied the ISO’s request for a tariff waiver to allow for reliability-must-run (RMR) agreements with Units 8 and 9 at the Mystic Generation Station for fuel security purposes.

FERC instead directed ISO-NE to submit interim tariff revisions providing for the filing of short-term, cost-of-service agreements to address demonstrated fuel security concerns, and “to submit by July 1, 2019 permanent Tariff revisions reflecting improvements to its market design to better address regional fuel security concerns.”

The ESI proposal responded to this second requirement, the deadline of which was extended twice since the July 2018 order.

The proposal called for the creation of new day-ahead ancillary service products that would allow market participants to voluntarily offer to sell options to the ISO to ensure the availability of energy in real time.

Details of FERC order

The Commission’s decision centered on three findings:

The New England Power Pool (NEPOOL) Participants Committee did not support the ESI proposal, so NEPOOL submitted an alternative ESI proposal along with ISO-NE’s proposal.

FERC determined that while the alternative “would result in lower costs to consumers than ISO-NE’s ESI proposal, we also reject the NEPOOL alternative as unjust and unreasonable because it contains the same deficiencies that render ISO-NE’s proposal unjust and unreasonable.” 

The Commission did not make a finding on whether ISO-NE faces a fuel security or energy security issue, but acknowledged the concerns leading to the proposal and stated that if ISO-NE “decides to pursue a solution to address these concerns, we encourage it to explore a market-based reserve product that provides resources sufficient lead time and ability to acquire fuel or take other steps necessary to be able to deliver energy when needed.”

FERC said it expects that such a market solution would be designed to:

“We are not, however, directing ISO-NE to pursue any particular approach.  We further note that nothing in this order prohibits ISO-NE from proposing a day-ahead reserves market independent of any proposal to address the concerns at issue here,” FERC said.

The Commission also rejected ISO-NE’s associated proposal to sunset interim fuel security programs one year earlier than currently provided for in the tariff, stating that “ISO-NE may propose to the Commission other steps it believes are warranted to address fuel security, such as submitting a revised long-term fuel security proposal or seeking to extend one or more of the interim programs.” 

MMWEC, others protested ISO proposal in May

The Massachusetts Municipal Wholesale Electric Company (MMWEC), New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative protested the ISO-NE proposal in a May 15 filing at FERC.

While the ISO’s proposal “is presumably intended to bring operational enhancements to bear, it is at best an incomplete solution to the region’s fuel security issues,” MMWEC, New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative said in their protest.

The ISO has acknowledged that its proposed solution was incomplete for lack of a market mitigation plan and a seasonal forward market, they noted. “Each of the missing elements is critical, and their omission should be fatal,” MMWEC and the others said.

Without a seasonal forward market, the ISO’s filing “fails to address the root cause of the region’s fuel-security problems: that generators must make fuel-procurement decisions long before they know whether they will clear in the day-ahead or real-time markets and be able to recoup those costs,” they went on to argue.

“And without a market mitigation plan, the proposal not only fails to solve the key problem; it potentially exposes consumers to the exercise of unmitigated market power in the newly created markets.”

MMWEC, the New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative said that in the absence of these essential components, “neither the Commission nor stakeholders should be forced to draw conclusions now about whether this one piece of a larger program is just or reasonable—particularly where these other components of the ISO’s comprehensive solution would also require this Commission’s approval in another proceeding.”

Therefore, they argued that FERC should reject the ISO’s compliance filing, without prejudice to the day-ahead ancillary services proposal being re-filed when the ISO has completed work on the totality of its response, at which time the Commission and stakeholders can conduct a comprehensive review of the total package of reforms.

Alternatively, MMWEC, the New Hampshire Electric Cooperative and Connecticut Municipal Electric Energy Cooperative said that if the Commission does not reject the filing, it should:

“But, to be clear, acceptance of the NEPOOL Alternative — while an improvement over the ISO’s proposal — will not solve New England’s fuel security problem. Like the ISO proposal, the NEPOOL Alternative does not include a seasonal forward market nor a mitigation plan,” they noted in their filing.

In a news release, MMWEC said that under ESI, New England electric customers would have paid the region’s generators up to an additional $257 million dollars a year, “based on the hope that doing so would encourage them to procure fuel supplies under tight operating conditions.”

MMWEC, the New Hampshire Electric Cooperative and the Connecticut Municipal Electric Energy Cooperative argued that the ESI proposal did not allow sufficient time for the generators to purchase fuel supplies.

They also pointed out that the proposal was voluntary, meaning that generators could choose not to participate in providing fuel security when the system needed them the most.

In a separate filing in the proceeding made on May 15, a group of New England consumer-owned systems and Energy New England (ENE) argued that ISO-NE’s ESI Proposal was unjust and unreasonable in three substantial respects, and incomplete in a fourth respect.

Among other things, they said that ISO-NE’s ESI proposal sought to impose on load-serving entities a year-round obligation to procure “Demand Quantities” of Day Ahead options for energy to supply Replacement Energy Reserves, “which produce no benefit during the months of March through November, when the New England gas pipeline system is not subject to constraint during periods of low temperatures and high heating demand.”

ISO-NE’s ESI proposal was incomplete in its lack of an appropriately designed market power mitigation strategy, the New England consumer-owned systems and ENE said.

“In substance, this case represents a replay of the ‘jump ball’ over ISO-NE’s 2015-2018 Winter Reliability Program,” they said.

“Here, as in the earlier case, ISO-NE has pursued a theoretical market design construct without regard to its cost or efficacy. Here, as in the earlier case, NEPOOL has proposed an alternative rate design that achieves the objectives outlined in the Commission’s July 2 Order without imposing irrational and unjustifiable cost burdens on consumers.”

As in the earlier case, the New England consumer-owned systems and ENE argued that the Commission should accept the NEPOOL Alternative, and should require a number of modifications to the ISO-NE ESI proposal.

Public power green pricing programs make NREL top 10 lists

November 4, 2020

by Paul Ciampoli
APPA News Director
November 4, 2020

A number of public power utilities are included on top 10 lists compiled by the National Renewable Energy Laboratory (NREL) for utility green pricing programs. The recently released rankings are for 2019.

Utility green pricing programs allow homes and businesses to procure green power through their electric utility.

Since 2000, NREL has compiled data on these utility green pricing programs and released annual “Top 10” lists to recognize outstanding programs.

In terms of the top green power sales (as of December 2019), the following public power utilities were on the Top 10 list compiled by NREL:

With respect to green power customer counts, three public power utilities made the top 10 list: SMUD (71,867 customers); Austin Energy (23,720 customers); and Seattle City Light (10,964 customers).

Turning to green power sales rates, the following public power utilities were represented on the top 10 list:

In terms of green power participation rates, public power utilities represented seven of the top 10 utilities listed:

The full report is available here.

Platte River Power Authority’s board approves integrated resource plan

November 3, 2020

by Paul Ciampoli
APPA News Director
November 3, 2020

The Platte River Power Authority’s Board of Directors on Oct. 29 approved the utility’s 2020 integrated resource plan (IRP).

The approval of the IRP follows two years of public discussions and surveys, numerous studies and reports, and energy mix modeling on multiple levels, Platte River noted in a news release.

The Western Area Power Administration (WAPA) requires IRPs from its members every five years to maintain long-term hydropower contracts with the federal government.

The plan, to be submitted by Platte River to WAPA in November, will also serve as its baseline for future energy planning and resource acquisition in pursuit of the objectives within the resource diversification policy approved by the board in December 2018.

The 2020 IRP places Platte River on the path to achieve a minimum of 90% carbon emissions reduction from 2005 levels, based on current technology as well as anticipated advancements, it noted.

The plan will allow Platte River “to reduce emissions further should improvements in renewable and energy storage technologies enable a 100% noncarbon energy mix while maintaining strong system reliability and low cost.”

Platte River said that its IRP earned support from the Colorado Energy Office and Department of Public Health and Environment whose leaders acknowledged the plan is consistent with state goals, which call for an 80% carbon reduction by 2030 for participating utilities.

The leadership team of Platte River initiated the 2020 IRP following the board’s adoption of a resource diversification policy that recognizes several milestones must be achieved before the noncarbon goal can be met.

The milestones include participation in an energy market, the strategic integration of distributed energy resources (DER), improved integration of the transmission and distribution grids, and greater overall investment in energy delivery systems and technologies.

While developing the 2020 IRP, Platte River initiated actions to address the key marks identified in the policy.

In late 2019, Platte River and partner utilities announced joint participation in the Western Energy Imbalance Market.

Meanwhile, Platte River and its owner communities recently announced the formation of the DER strategy committee, which will formulate policies and plans to effectively integrate such tactics and technologies as distributed generation and energy storage (e.g., rooftop solar and batteries), more energy efficiency and demand response programs, electric vehicle adoption and delivery systems integration. The committee plans to complete its work on a strategy by the end of 2021.

Although system planning remains an ongoing effort, Jason Frisbie, General manager and CEO at Platte River, noted that two additional IRP processes will be conducted before 2030, which Platte River said will provide greater clarity concerning the attainment of a 100% noncarbon energy mix. He said each process will again seek involvement by stakeholders and the public.

More information about the 2020 IRP can be found at the project microsite.

Platte River Power Authority is a not-for-profit wholesale electricity generation and transmission provider that delivers energy and services to its owner communities of Estes Park, Fort Collins, Longmont and Loveland, Colorado for delivery to their utility customers.

GHG reduction goals in PJM states best met with an RTO-wide carbon price

November 2, 2020

by Peter Maloney
APPA News
November 2, 2020

The PJM Interconnection, the largest wholesale power market in the nation, could create “substantial opportunities for low cost decarbonization” by pursuing policies such as establishing a charge on carbon dioxide (CO2) emissions, consulting firm Energy and Environmental Economics (E3) said in a new report.

A CO2, or “carbon,” price that would apply across the board in PJM’s marketplace, which operates in 13 states and the District of Columbia, would be a better option than “continuing to rely on fragmented and restrictive clean energy policies and subsidies,” the report, Least Cost Carbon Reduction Policies in PJM, argued. The report was commissioned by the Electric Power Supply Association.

Several states within the footprint of the regional transmission operator (RTO) have set up a variety of policies aimed at encouraging renewable energy resources or curbing greenhouse gas emissions, creating a patchwork of regulations

RTO specific policies establishing a carbon price recently gained a glimmer of support when the Federal Energy Regulatory Commission (FERC) on Oct. 15 issued a proposed policy statement, affirming that it has jurisdiction over organized wholesale electric market rules that incorporate a state-determined CO2 price in those markets. FERC’s proposal encouraged operators of organized markets to consider the benefits of establishing a price on CO2.

“Our study of decarbonization policies in the PJM region finds that the most effective policies are ones that maximize market participants’ choices and leverage diversity across the PJM footprint,” Arne Olson, senior partner at E3, said in a statement.

From a near-term policy perspective, current policies aimed at reducing greenhouse gas emissions by subsidizing specific technologies or in-state resources, such as renewable portfolio standards, are inefficient and will become less and less cost-effective as policy targets reach higher levels, the E3 report found.

The report put the cost of existing state policies at more than $3 billion per year by 2030, or $50 per person each year across the 65 million customers served by the PJM system, for a 12% reduction in net GHG emissions.

Instead, E3 said its analysis shows that technology-neutral policies that enable the broadest array of potential solutions will generally be “the most cost-effective by incentivizing coal-to-gas switching, retaining the most competitive zero-emission nuclear generators, and developing the lowest-cost renewables that harness the diversity benefits of PJM’s geography.”

Some current state policies are “well intentioned” but may not have the intended effect, the report said, citing the Regional Greenhouse Gas Initiative (RGGI) as an example of how a partial carbon pricing approach can undercut emission reduction goals.

RGGI, which includes New England and four adjacent Eastern Seaboard states, has limited or negative impact on emissions because of leakage across state lines where compliance costs within RGGI incentivize a shift in energy production to less efficient resources outside of the RGGI region, the report said.

E3 recommended improvements to RGGI to mitigate leakage by expanding the program to encompass more PJM states. Only three PJM states, Delaware, Maryland and New Jersey, are currently in RGGI and such an expansion could drive “significantly deeper emissions reductions.”

E3 also found that that current resource specific mandates for offshore wind and battery storage in PJM “appear premature if immediate GHG reductions or cost savings are the intended goals” and may not be needed to achieve decarbonization goals until after 2030. Such technology-specific policies could cost over $1 billion per year compared with more readily available GHG savings opportunities. Instead, E3 said, targeting cheaper onshore resources would reduce emissions at “significantly lower cost over the next decade.”

Beyond 2030, efficient policy design and resource usage will become increasingly important if GHG reduction goals are going to be met at a reasonable cost, the report said.

While there are sufficient renewable resources to meet 2030 goals, the report identified the availability of land, potential transmission constraints and flexible generation capacity to backstop those resources as key to achieving long-term decarbonization goals.

E3 said there is a “deep pool of flexible gas capacity in PJM” that will allow it to integrate renewables at low cost, though the authors noted that gas plant operations will look significantly different in the future. They will see increased levels of cycling and more seasonal operation.

By 2050, E3 sees at least 35 gigawatts (GW) and likely 50 GW to 80 GW of existing gas capacity remaining valuable for grid reliability. The price of that reliability, though, will likely be more volatile energy prices in certain hours or higher capacity prices may be required to keep these plants online, the report said.

The report also noted that there are limitations to the ability of existing technologies to reach a 100% reduction in GHG emissions by 2050 at a reasonable cost whether those goals are met by renewable resources or clean energy resources.

Moving from an 80% target to a 100% target “would lead to exponential increases in costs,” the report said. Moving from 80% GHG reductions to 100% reductions in 2050 would drive additional costs of over $20 billion per year, moving from an 80% to a 100% renewable portfolio standard policy would increase costs by over $30 billion per year, E3 said.

In conclusion, E3 said the diversity of the PJM system’s loads and resources offers significant cost savings for meeting the collective climate goals of the region and recommended that policy makers should “see the regional marketplace as a critical tool for enabling long-term decarbonization. Efficient policy will be key to meeting climate goals at manageable costs.”

Report highlights benefits of public power utility in Boulder, Colo.

November 2, 2020

by Paul Ciampoli
APPA News Director
November 2, 2020

A local power financial analysis finds that lower renewable electricity prices, lower bond rates and increasing electrification of transportation and buildings means that citizens of Boulder, Colo., can expect that a locally owned utility would at least breakeven financially within five to 10 years of startup.

The analysis was released on Oct. 14 by a coalition called Empower Our Future, a group that opposes approval of a ballot initiative (City Initiative 2C) that is on the Nov. 3 ballot in Boulder. Boulder ballot initiative 2C is opposed by Empower Our Future in part based on the Local Power Financial Analysis, the coalition noted.

If passed, the ballot initiative calls for the city to enter into a new, 20-year franchise with Xcel Energy and end the city’s efforts to create a local, city-run electric utility.

The franchise agreement is a part of a comprehensive settlement agreement with Xcel Energy. The comprehensive settlement agreement would only go into effect if the franchise is approved by voters in the Nov. 3 election.

Empower Our Future “believes that we are experiencing a paradigm shift in world energy markets, largely driven by the imperative to stop and reverse climate change,” the coalition said in the financial analysis.

“Further, we believe that remaining flexible relative to options for sourcing 100% renewable electricity and open to new technologies and policies that make it possible to share electricity more equitably, reliably, and affordably, is critical,” the coalition said.

“We offer this analysis of one option-that of implementing a locally owned electric utility-to demonstrate that we have at least one viable option at our disposal today. All indications are that even more options will be available in the near future, which strengthens our conclusion that entering into a twenty-year franchise agreement with Xcel is both ill-conceived and poorly timed.”

Empower our Future said the report independently evaluates several alternative scenarios using the City of Boulder’s Financial Forecasting Tool, current data, and reasoned projections for the near future to independently determine the financial viability of a locally owned electric utility.

The combination of lower renewable electricity prices, lower bond rates, and increasing electrification of transportation and buildings “has resulted in a situation in which Boulder citizens can, with confidence, expect that a locally owned utility would at least breakeven financially within 5 to 10 years of startup, relative to continuing to source more carbon-intensive electricity from Xcel,” the analysis found.

In addition, the financial scenarios included in the analysis predict that enough savings and cash flow would be created to offer Boulder customers lower electric rates for 100% renewable electricity, and to make investments in the modernization of Boulder’s electric system for the benefit of all.

The analysis also found that the switch to 100% renewable electricity by 2030 would nearly eliminate the City of Boulder’s greenhouse gas emissions from electricity production in contrast to the 80% reduction mandated by the state of Colorado for Xcel.

The report shows that entering into a franchise agreement with Xcel Energy “at this critical time, with the currently proposed terms, is not in the best financial interest of Boulder or its citizens,” the coalition said.

“Rather, Boulder should stay the course, keep our options open, and take the lead in establishing an equitable, clean, modern electricity system for now and generations to come. In our estimation, Boulder can accelerate the electrification of our buildings and transportation systems and enjoy the full environmental benefits of 100% renewably-sourced electricity while capturing the financial benefits of a locally owned electric utility for the welfare of our community.”

East Bay Community Energy seeks offers for renewable energy, storage resources

October 30, 2020

by Paul Ciampoli
APPA News Director
October 30, 2020

California community choice aggregator East Bay Community Energy (EBCE) on Oct. 29 issued a request for offers to procure long-term renewable energy and storage resources.

The RFO also seeks to provide long-term clean energy hedges and resource adequacy and to contribute to EBCE’s Renewable Portfolio Standard (RPS) and Integrated Resource Plan (IRP) obligations under state laws.

EBCE is seeking offers for the sales of RPS-eligible energy for a contract term of 10, 15, or 20 years, with a preference for offers with terms less than 20 years.

EBCE will also evaluate offers for long-term clean energy hedges from large hydro resources and other eligible resources for a duration minimum of five years.

Eligible offers may be for: (1) as-Available RPS product; (2) As-available RPS Product plus energy storage; (3) indexed energy plus RPS attributes; (4) shaped RPS energy product; (5) stand-alone energy storage toll; or (6) shaped clean energy hedge.

Respondents may submit offers for as many or as few products as they wish, relative to their capabilities and expertise.

EBCE seeks energy and related products from both existing and new construction resources.

Projects must begin deliveries no later than December 31, 2024 to qualify for the RFO. EBCE has a preference for deliveries beginning in 2021 or 2022.

Offers are due by Dec. 1 and additional details on the RFO are available here.

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

Generation backed by utilities accounted for half of new capacity in 2018-19

October 30, 2020

by Peter Maloney
APPA News
October 30, 2020

Power generation projects financially backed by utility ownership or by a utility contract accounted for about half of the new capacity built in 2018 and 2019, according to a new report by the American Public Power Association.

Utility owned new generation also resulted in a greater diversity of resources than merchant generation. In 2018, about half of the utility sponsored new capacity was natural gas, one-fourth was solar, and one-fifth was wind, according to the report.

In 2019, those three technologies each accounted for about one-third of utility capacity additions.

In contrast, new merchant capacity additions, plants that receive revenue solely from wholesale power markets, consisted almost entirely of natural gas-fired generation — 92% in 2018 and 99% in 2019.

Merchant generation itself accounted for about 38% of the new capacity that began service in 2018 – a total of 11,800 megawatts (MW) – and 16% of the capacity that began service in 2019 or 3,700 MW.

“The capacity constructed or contracted by utilities is far more diverse than merchant generation capacity and includes hydropower and geothermal projects, which are not present in new merchant generation,” Elise Caplan, director of electric markets analysis at APPA and author of the report, said.

New merchant generation capacity has fluctuated over the past seven years, from a low of 2.4% in 2013, climbing to a peak of 29.1% in 2017 and then 37.9% in 2018 before settling back to 16.3% in 2019. That trend has not been “a positive development for resource diversity, environmental goals, and risks to consumers,” the report noted.

The downside of the expansion of merchant power plants includes concerns about fuel security as natural gas plants continue to dominate new generation. For example, ISO New England, which represented 30% of the new merchant natural gas generation last year, has said it has an “energy security problem” because it “relies most on gas delivered through its constrained pipeline system.”

Merchant generation also creates a pool of resources with a continued interest in propping up their earnings by administratively increasing energy and capacity prices, the report said, such as the Federal Energy Regulatory Commission’s (FERC) December 2019 order expanding the Minimum Offer Price Rule (MOPR) in the PJM Interconnection’s capacity market.

At the time, FERC said the administratively determined offer floor would “enable PJM’s capacity market to send price signals on which investors and consumers can rely to guide the orderly entry and exit of economically efficient capacity resources.”

Such administrative interventions “pose impediments to state and utility efforts to develop particular types of resources and increase costs to consumers,” the report said.

Overall, 31,200 MW of new capacity came online in 2018, exceeding the 18,750 MW of capacity that retired even though electricity consumption has been relatively flat. In 2019, about 22,700 MW of capacity came online, exceeding the 18,760 MW of capacity that retired.

The fact that the amount of new merchant generation in 2018 and 2019, 11,800 MW and 3,700 MW, respectively, came close to the amount by which new capacity exceeded the retirements – 11,800 MW in 2018 and 3,700 MW in 2019 – indicates that “new merchant generation could have been a contributing factor to the surplus of new capacity compared to retirements,” the report said.

The report also included data that show that public power utilities accounted for almost 20% of new capacity and 17% of all renewable energy and storage installations in 2018 and 11% of all capacity and 15% of renewables and storage in 2019.

Overall, the “data show that resource diversity, technology innovation, and emissions reductions can be best achieved by financial arrangements that consider utility, consumer and state policy goals rather than projects constructed to maximize earnings from wholesale markets,” the report said.

The report used the list of new generating units from the Energy Information Administration and combined it with information on financial arrangements behind the new capacity primarily from utility and developer websites and from news articles, as well as data from the Federal Energy Regulatory Commission and the American Wind Energy Association.

Austin Energy ADMS upgrade advances with COVID-19 safety protocols

October 29, 2020

by Peter Maloney
APPA News
October 29, 2020

Deploying an Advanced Distribution Management System (ADMS) is challenging in the best of times. Deploying an ADMS upgrade during COVID-19 only adds to the challenges.

Texas public power utility Austin Energy had “robust policies” in place to guard against the spread of COVID-19 before its ADMS upgrade, but for the in-person portion of the system operator training sessions related to the software upgrade, they decided to take “a lot of extra precautions,” Danny Ee, Austin Energy’s Director of System Operations and Advanced Grid Technologies, said.

“It was one of the most difficult decisions in my career to elect for a remote go-live during the pandemic,” Ee said. “However, we were determined to deliver the upgraded functionality despite the additional challenges and had the support of senior management and dedicated employees that were well prepared to make it a seamless upgrade.”

ADMS software monitors and optimizes a wide array of utility functions, including integration with outage maps, tie-ins with GIS mapping tools, notifications for utility field workers, distribution grid optimization, as well as providing analytical planning tools.

“ADMS is similar to Emergency Room triage for the healthcare industry,” Ee said. “It helps assess severity of issues, prioritize, and dispatch the appropriate staff to keep Austin’s power going. Without it, we would not have visibility to our grid and the ability to remotely control field equipment.”

Austin Energy deployed its first ADMS system in June 2014.

By 2020, it was time to upgrade to a newer version of the software. The upgrade, which went live in September, was the culmination of more than two years of preparation and was so extensive, “it was almost like installing a brand new system including all new servers and network infrastructure and extended the ADMS system user base by over 600 employees,” Ee said.

The ADMS Upgrade Project was focused on making a good thing better, Ee said. A good portion of the upgrade delivered improvements to usability, situational awareness, visualization and functionality that will improve monitoring, decision-making, optimization, reliability and security assessment of the electric grid and its components.

The ADMS Upgrade delivered expanded and enhanced functionality to existing system users and added applications for mobility/field crews and call centers. The new groups of users will have direct access to more information, which will help resolve customer outages more efficiently.

“The grid is changing, utilities are changing, and we have to be prepared,” Ee said. ADMS is an important tool in the transformation from a utility with one-way power flows to a smart utility that is continually responding to real time inputs and integrating multi-directional power flows, he said.

Austin Energy began implementing safety protocols related to COVID-19 early on. The City of Austin declared a local disaster in early March, allowing the utility to offer aid to customers having trouble paying their bills.

And, through a mix of new protocols and processes, Austin Energy has kept its employees safe and its operations running smoothly throughout the pandemic. About 1,400 of the utility’s 2,000 employees are now working from home.

Ee said the ADMS Upgrade deployment was supported completely remotely and was “intimidating” because the project teams were depending on on-site presence for several weeks leading up to the event, as well as on-site stabilization support after go live. Despite the change in plans due to COVID-19 restrictions, Ee said he is proud how the team worked through the implementation.

To keep employees safe through the pre-deployment system operator training, Ee and his team drew up an eight-page document of protocols. The training plan allows for only one trainer from the vendor, Mosaic, to be onsite. The trainer drove from Tulsa, Okla., to Austin, instead of flying, and quarantined for about one week before training began. The trainer also agreed to an initial COVID-19 test and restrict his movements to his hotel and Austin Energy facilities for the duration of the training.

The trainer and the employees participating in the training, in addition to following regular COVID-19 safety protocols, such as wearing face masks and washing hands frequently, also agreed to regular temperature checks.

Austin Energy marked off six-foot perimeters around the work stations that will be used during the training, provided daily cleaning and has limited the areas of the utility’s facilities that can be accessed by the trainer and trainees.

The utility is also providing boxed breakfasts and lunches and bottled water to the participants. The pre-deployment system operator training course lasted four days and was limited to three or four trainees within the same shift per course to prevent cross-contamination. Six weeks of courses were scheduled.

Post-deployment in-person field crew training is ongoing – it will last until December – and sessions that are underway currently are focused on situational awareness and efficiencies that are now available to the Field crews.

“ADMS will bring us to the future,” Ee said. He credits the utility’s robust safety and health protocols with winning the support of management and employees alike. “I am pleased to report that the employees that were offered in-person training are a dedicated bunch of individuals that chose to participate in training despite these uncertain times. I’m honored by the commitment that is continually demonstrated. The high buy-in is what made it successful.”

Authority overseeing new Calif. municipal utility executes agreement tied to microgrid

October 28, 2020

by Paul Ciampoli
APPA News Director
October 28, 2020

Concentric Power Inc. and Gonzales Electric Authority (GEA), which was established by the City of Gonzales, Calif., to oversee its new municipal electric utility, have executed an energy services agreement to deliver wholesale electric power via a community-scale microgrid.

The microgrid will initially have 35 megawatts of capacity to provide power to the Gonzales Agricultural Industrial Business Park, which houses processing facilities for fresh vegetable and wine producers. It will also meet the clean energy requirements of the city’s climate action plan.

Concentric Power said in an Oct. 7 news release that it designed the microgrid to integrate a mix of 14.5-MW-AC of solar energy, 10-MW/27.5 MWh of battery energy storage and 10-MW of flexible thermal generation, all of which will be managed by the company’s Advanced Microgrid Controller.

The system will allow the park to island from the wider energy grid, “ensuring that end users have reliable, high-quality power 24 hours a day, 365 days a year, even when facing planned or unplanned grid outages,” Concentric Power said.

The microgrid will also include a privately owned substation that will allow energy and capacity services to be sold into the California electricity grid.

The City of Gonzales, which is located California’s Salinas Valley, formed GEA to help attract and retain a strong agriculture and industrial base as well as to protect companies doing business there from unplanned power outages and poor power quality, Concentric Power noted.

The project will support continued economic development and job creation to further build the city’s tax base. With the Agricultural Industrial Park currently one-third occupied, the ESA allows for the power infrastructure to expand and meet growing demand.

The $70 million project will be funded primarily by Concentric Power, with supplemental funding from GEA and the Gonzales Municipal Electric Utility towards ownership of the distribution infrastructure.

Concentric Power will develop, design, build, operate and maintain the microgrid assets, including both generation and distribution. The distribution assets will be transferred to Gonzales Municipal Electric Utility.

The initial term of the energy services agreement is 30 years and the project is expected to break ground in mid-2021 and be ready for service in 2022.

Power sector keeps close eye on physical, cybersecurity in lead up to elections

October 28, 2020

by Paul Ciampoli
APPA News Director
October 28, 2020

The power sector is keeping a close watch on potential threats to physical security and cybersecurity from international and domestic actors in the lead up to next week’s elections in the U.S.

A number of electric utilities including public power utilities recently participated in an Electricity Subsector Coordinating Council call related briefing from the Federal Bureau of Investigation, two peer utilities, as well as the E-ISAC. The FBI has set up a command center to monitor potential civil unrest related to the elections.

Meanwhile, the North American Electric Reliability Corporation’s Electricity Information Sharing and Analysis Center (E-ISAC) on Oct. 27 released an All-Points Bulletin (APB) on Electricity Industry Preparedness for 2020 U.S. Election.

The E-ISAC routinely monitors all threats to the grid and provides alerts to industry as needed when new or continuing threats emerge.

In its bulletin, the E-ISAC noted that the power industry has undertaken weeks of preparation and analysis and collaboration with federal, state and local partners to ensure continuity of operations during the U.S. election cycle.

“At this time, the E-ISAC is not aware of any known specific or credible threats to the North American electric grid in conjunction with the election,” the E-ISAC said, noting that the bulletin is being shared to raise awareness and promote preparedness during the election.

Also, the E-ISAC has coordinated with the Elections Infrastructure-ISAC and the Department of Homeland Security’s Cybersecurity Infrastructure and Security Agency over the last two months to provide awareness and produced a 2020 Election Threat Awareness and Preparedness White Paper and Executive Summary, which offers an overview of the industry-specific threat and mitigation measures. Additionally, CISA has created a Rumor Control webpage, that will be constantly updated to help the general public understand what is fact and fiction with regards to misinformation efforts by foreign or domestic groups.

In terms of relevant resources provided by the American Public Power Association, APPA’s All-Hazards Guidebook helps public power utilities, joint action agencies, state associations, and other industry representatives in the development or continuous improvement of emergency preparedness programs and all-hazards planning efforts. As utilities prepare for potential civil unrest, the guidance in this resource may be helpful.

APPA encourages its members to coordinate with local, state and federal law enforcement, before any potential physical or cybersecurity incident, to ensure a rapid and coordinated response. For information on how to connect with your local FBI or CISA representatives, please email Cybersecurity@PublicPower.org.