Massachusetts Taps Offshore Wind Project That Will Supply Energy to Public Power Utilities
January 4, 2022
by Paul Ciampoli
APPA News Director
January 4, 2022
Massachusetts officials recently announced the selection of an offshore wind project that includes a partnership between Vineyard Wind, the developer, and Energy New England (ENE), which is representing 20 participating Massachusetts Municipal Light Plants (MLPs) including Reading Municipal Light Department (RMLD).
The partnership will allow MLPs to purchase offshore wind power for the first time, an opportunity that will green the portfolios of MLPs across the state, RMLD said.
Under the agreement, MLPs will be able to purchase up to 32 megawatts (MW) or approximately 146,000 megawatt hours (adjusting for capacity availability for offshore wind) per year, plus the associated non-carbon certificates — specifically, renewable energy credits (RECs).
Announced in October, Commonwealth Wind is a first of its kind partnership between Vineyard Wind and ENE, which is representing 20 participating Massachusetts MLPs, including RMLD. It is the first time MLPs were allowed to bid for Massachusetts offshore wind power.
The Vineyard Wind project is one of two offshore wind projects that will now move forward to contract negotiations.
The selected projects include a 400 MW proposal from Mayflower Wind and a 1,200 MW proposal from Vineyard Wind. The Mayflower Wind and Vineyard Wind bids were selected for contract negotiations based on criteria established under a Request for Proposal (RFP) released in May 2021.
Established in 1894, RMLD is a Massachusetts public power utility serving over 70,000 residents in the towns of Reading, North Reading, Wilmington, and Lynnfield Center. RMLD has more than 30,000-meter connections within its service territory.
ENE is a wholesale risk management and energy trading organization serving the needs of public power utilities in New England.
Santee Cooper Solar Farm Becomes South Carolina’s First Gold Certified Solar Habitat
January 4, 2022
by Vanessa Nikolic
APPA News
January 4, 2022
South Carolina public power utility Santee Cooper’s Jamison Solar Site, a 1.2-megawatt facility located on over 5 acres in Orangeburg, has become South Carolina’s first Gold Certified Solar Habitat Site.
To become a Gold Certified Solar Habitat, Santee Cooper had to commit to planting a variety of native flowering plants underneath and around the site’s 4,482 solar panels.
The plantings of native pollinator plants provide added ecological benefits to solar arrays. It aids in reducing soil erosion, protecting water quality and enhances the aesthetic of a solar site.
South Carolina governor Henry McMaster signed the Solar Habitat Act into law in 2018. Under the authority of the law, the South Carolina Department of Natural Resources (SCDNR) established “Technical Guidance for the Development of Wildlife and Pollinator Habitat at Solar Farms” and worked with Clemson University’s Department of Fertilizer Regulation and Certification Services to develop the S.C. Certified Solar Habitat Program.
The South Carolina Solar Habitat Act provides a framework to encourage owners of commercial solar energy generation sites to follow voluntary site management practices that provide native perennial vegetation beneficial to songbirds and pollinators, and reduce stormwater runoff and erosion at the solar generation site.
“We are pleased that Jamison Solar Farm is the first Gold Certified Solar Habitat in the state and even more pleased to help lead the way to more certified solar habitats across South Carolina,” Santee Cooper Chief Power Supply Officer Marty Watson said.
Watson said creating the habitat for pollinators is a way the public power utility puts its environmental stewardship into action. He also recognizes the guidance of the team at SCDNR.
For more information about the S.C. Solar Habitat Program, visit www.dnr.sc.gov/solar.
ERCOT Says Generation Fleet Ready for Winter Weather Following Winterization Inspections
January 4, 2022
by Paul Ciampoli
APPA News Director
January 4, 2022
The Electric Reliability Council of Texas (ERCOT) has completed on-site inspections of mandatory winterization efforts, and inspection results show the independently owned electric generation fleet and electric transmission companies serving the ERCOT region are ready for winter weather.
Inspections were completed at more than 300 electric generation units, representing 85 percent of the megawatt hours lost during 2021’s Winter Storm Uri due to outages and 22 transmission station facilities, ERCOT said on Dec. 30.
ERCOT has filed a preliminary summary inspection report with the Public Utility Commission of Texas and will submit its final inspection report on January 18, 2022 for review and any potential enforcement action. In 2021, the Legislature increased the maximum penalties for violating weatherization rules to $1,000,000 per day per violation.
Of 302 generation resources inspected, some generators had exceeded PUC winterization requirements. Only ten generation resources inspected had items identified on the day of inspection requiring correction. For example, a generation unit may have needed a windscreen to be compliant, but it was not yet installed on the day of inspection. Many items like this have now been completed since the inspection occurred and all ten units are still operational. The ten generation units have a total capacity of 2,129 megawatts, representing about 1.7 percent of the total ERCOT generation fleet.
Of the 22 transmission station facilities inspected, ERCOT found that six had potential identified deficiencies, most of which have already been corrected. These were generally minor items, such as cabinet heaters out of service or missing weather stripping on cabinet doors on the day of inspection. Most of these items have already been corrected.
ERCOT will conduct follow-up inspections on the generation and transmission facilities with potential identified issues.
ERCOT and its contractors have spent more than 3,600 hours on these inspection-related activities to date. Additionally, ERCOT and PUC staff are actively monitoring the compliance plans of the generation resources that requested additional time to finalize compliance with the new winterization regulations.
Court Advances South San Joaquin Irrigation District Bid To Replace PG&E As Local Power Provider
January 3, 2022
by Paul Ciampoli
APPA News Director
January 3, 2022
California’s South San Joaquin Irrigation District (SSJID) was recently handed a key victory by an appeals court in SSJID’s ongoing bid to replace investor-owned Pacific Gas & Electric (PG&E) as the local retail electric service provider.
The December decision issued by the Third District Court of Appeal validated the Local Agency Formation Commission’s approval of SSJID’s ability and authority to provide retail electric utility service to its customers. The decision also allows the district to move forward with the ability to provide those services by purchasing PG&E’s facilities through the process of eminent domain.
Since 2004, SSJID has been actively working to replace PG&E as the electric utility for customers in Manteca, Escalon, Ripon and surrounding areas.
As part of that process, SSJID was required to obtain approval from a San Joaquin County agency called the Local Agency Formation Commission.
In 2014, after five independent studies and a public workshop before the Local Agency Formation Commission, it found that SSJID’s business plan was sound and that SSJID has the ability to carry out its service commitments.
PG&E filed a lawsuit to have the decision overturned in San Joaquin County Superior Court. After continued litigation and some favorable court decisions for SSJID, SSJID offered to purchase local electric distribution assets from PG&E in 2016.
After PG&E indicated its assets were not for sale, the District filed a lawsuit to gain the right to purchase the assets from PG&E, through a process called eminent domain
On March 25, 2020, SSJID and PG&E stipulated to a “relief from stay” in a hearing in a PG&E bankruptcy proceeding that would allow ongoing litigation between the two parties to continue. This stipulation allowed for final briefs to be filed and for the appellate court to take the appeals under consideration.
SSJID has offered to pay PG&E $116 million for the power lines, substations and transmission infrastructure required to deliver electricity to the region.
SSJID was established in 1909 and is headquartered in Manteca, Calif.
SSJID provides agricultural irrigation water to about 56,000 acres surrounding Escalon, Ripon and Manteca, and wholesale drinking water to the cities of Manteca, Lathrop, Tracy, indirectly serving over 193,000 residents, and in the future, the city of Escalon.
SSJID, along with Oakdale Irrigation District, owns and operates the Tri-Dam Project, a series of storage reservoirs and electric generation facilities that produce zero-carbon hydropower in the Stanislaus Riverwater shed.
New Mexico Lawmakers Ask Utility Regulators To Consider Public Power Option
January 3, 2022
by Paul Ciampoli
APPA News Director
January 3, 2022
A group of New Mexico lawmakers is asking state utility regulators to launch a study that would evaluate shifting the state’s electric sector to public power.
The lawmakers said in their petition filed at the New Mexico Public Regulatory Commission (PRC) that they “believe that it is probable that public ownership of the electrical utilities that serve New Mexico would benefit New Mexico’s ratepayers, New Mexico’s businesses, and New Mexico’s state, local and tribal governments.”
The lawmakers said that the PRC should oversee a comprehensive study that would address questions that would include, among others:
- Would the pursuit of a publicly controlled utility authority at the state level advance the public interest, in both a “traditional” public utility perspective and an expansive 2021 and beyond regulatory framework that breaks up utility monopolies and supports tribal community and state energy rights, and its interactions with other disruptions that will be occurring simultaneously in the transportation, health, and building sectors during the 2020s and comprehends climate emergency needs?
- What are the benefits, costs, and risks associated with such a transition?
- What are the high-level cost reductions or increases of replacing private investor-owned utilities with public power?
- What is the revenue potential of exporting excess renewable energy and job creation opportunities?
- What is the technical, financial, and legal feasibility of pursuing public power for New Mexico?
- What would be the best design for such a transition? The study should compare and contrast the costs and benefits of the status quo versus a publicly owned power authority and Community Choice Aggregation.
The lawmakers said that within the next decade trillions of dollars will be invested in energy infrastructure across the United States. “From federal policies to market forces to the inevitable replacement of retiring fossil fuel plants, the transition to renewable energy sources will necessitate a massive restructuring of not only the power grid and generation sources, but energy markets, ownership and control,” the petition said.
“With some of the highest solar and wind capacity of any state in the nation and the ability to deliver terawatts of energy to our neighbors and beyond, New Mexico will be presented with numerous opportunities and important decisions as this transition unfolds.”
But the lawmakers argued that the transition is not being facilitated effectively by the state’s current IOU structure. “Despite New Mexico’s abundant natural resources, second in the country for solar potential and 11th in the country for wind potential, and the sun Zia on our flag, each of the state’s investor-owned-utilities have relatively small percentages of renewables in their energy portfolios.”
They said that under the current energy model, investor-owned-utilities’ plant ownership and energy investments “require a return on equity that creates a perverse incentive NOT to invest in energy sources with fixed capital costs and no fuel costs.”
The lawmakers said that under the IOU model, returns on investments and profits — at least in the case of Public Service Company of New Mexico, with a return that is 9.575% annually, are exported to Wall Street.
Lakeland Electric’s Joel Ivy Accepts Position To Lead Lubbock Power & Light
January 2, 2022
by Paul Ciampoli
APPA News Director
January 2, 2022
Joel Ivy, general manager of Florida public power utility Lakeland Electric, has accepted a position with Lubbock Power & Light (LP&L).
Ivy will oversee the Texas municipal utility after their current Director, David McCalla, announced his retirement earlier in 2021.
A final vote on the offer of employment for Ivy is scheduled for December 29th in front of the Lubbock City Council. After the formal approval by the Lubbock City Council, Ivy is expected to report to LP&L in early May 2022 with his last day at Lakeland Electric taking place in April 2022.
Ivy was hired as the General Manager for Lakeland Electric on July 30, 2012. He has currently served in that position for over nine years.
During his tenure at Lakeland Electric, Ivy concentrated efforts to strengthen the utility’s financial position, improve credit ratings and enhance the customer experience. He also worked to increase renewable solar facilities into the energy mix at Lakeland Electric.
Lakeland Electric said that Ivy and his team have been instrumental in developing a robust outage notification system, taking Lakeland Electric forward with the decommissioning of Unit 3, the aging coal fire generator, and securing future generation for the utility.
Chelan PUD Re-Energizes Fire-Hardened Transmission Line
January 2, 2022
by Paul Ciampoli
APPA News Director
January 2, 2022
Washington State’s Chelan PUD has re-energized a high-voltage transmission line rebuilt in fire-resistant steel for better reliability in the Chelan Valley.
The months-long upgrade is part of a comprehensive plan to protect customer-owners and the electrical grid in Chelan County from the growing threat of wildfire.
The transmission line powers the Chelan and Union Valley substations, which serve about 3,500 homes. The line burned down in a 2015 wildfire that blackened the shrub-steppe area. The Chelan Valley went without power for 36 hours while crews worked around the clock to rebuild the line.
As crews replaced 34 structures along the four-mile line from July to December 2021, Chelan PUD re-routed power to maintain reliable electrical service for customers in the area. The $2.7 million project was finished on time, under budget and with no outages.
The fire-hardening project is one of several by Chelan PUD to reduce fire risk and improve reliability. The utility’s wildfire risk mitigation plan calls for more frequent line inspections, hazard tree removal and fire-resistant paint.
In 2021, Chelan PUD increased its vegetation management budget from $1.5 million to $3.5 million to accomplish the work required by a more-frequent inspection and pruning cycle. By the end of 2021, Chelan PUD planned to remove about 8,000 hazard trees — a seven-fold increase compared to five years ago.
Chelan PUD is also working with the Washington State Department of Natural Resources, Cascadia Conservation District and other agencies to coordinate fuel reduction efforts and secure grant funding for projects that will lower wildfire risk in the county’s most vulnerable areas.
NERC Report Sees Potential Reliability Issues Tied To Weather, Renewables
January 2, 2022
by Peter Maloney
APPA News
January 2, 2022
Reserve margins could fall below recommended levels sooner than previously expected, the North American Electric Reliability Corp. (NERC) reported in its 2021 Long-Term Reliability Assessment (LTRA).
In the Midcontinent Independent System Operator (MISO) region, anticipated reserves fall below the Reference Margin Level (RML) beginning in 2024 instead of 2025 as previously estimated. MISO could be facing the retirement of over 13 gigawatts (GW) between 2021 and 2024 based on its annual survey of members.
The potential retirements include 10.5 GW of coal-fired capacity and 2.4 GW of natural gas-fired capacity. Those projected retirements are not confirmed, NERC noted, but if they were to take place without new generation beyond the 8 GW already in development coming online MISO could be short over 560 megawatts (MW) in 2024, NERC said.
The NERC report also singled out California, specifically the California-Mexico (CA/MX) part of the Western Electricity Coordinating Council (WECC) where the planned retirement of the 2,200-MW Diablo Canyon nuclear plant in 2024 and 2025 could contribute to a capacity shortfall beginning in 2026.
“However, energy risks are present today as electricity resources are insufficient to manage the risk of load loss when wide-area heat events occur,” the NERC report warned. The risk is most acute in late afternoon when solar photovoltaic resource output diminishes, creating a sharp rise in demand. Analysis shows up to 10 hours of potential in-day load loss beginning in 2022 and as much as 75,000 megawatt hours (MWh) of unserved energy in extreme conditions in 2024, NERC said.
Furthermore, the amount of flexible generation sources needed to meet demand have fallen in California, as well as in Texas and the Northwest to the point that projected peak demand cannot be met without some combination of weather-dependent wind and solar generation along with external imports.
“Changes in climate that drive extreme weather conditions raise the likelihood for one or more of these resources to fall short of forecasts, leaving other resources to make up the gap, or load will need to be shed,” NERC said.
The increasing amounts of variable generating resources in the Northwest and Southwest are raising the risk of energy shortfalls, according to the LTRA. There were 23 load-loss hours in the Northwest in 2022, and the Southwest faces potential load-loss hours beginning in 2024, NERC said.
“As resource planners in parts of the Western Interconnection turn increasingly to external transfers for sufficient capacity and energy to meet demand, the need for regional coordination and resource adequacy planning is growing,” NERC said.
The LTRA also identified the vulnerabilities created by the shortcoming of natural gas delivery infrastructure. Many generators in New England, California, and the Southwest rely on gas, making them vulnerable to gas supply disruptions that could affect winter reliability, NERC said.
Extreme cold weather in areas not accustomed to it, such as parts of MISO, the Southwest Power Pool (SPP) and Texas, also presents “significant” risks to winter reliability until new winterization requirements highlighted in NERC’s February 2021 Cold Weather Outages Report are in effect, NERC said.
The threat of extreme cold weather is exacerbated by the “increasing volatility and uncertainty” of electricity demand that makes “accurate load forecasting a challenge,” NERC said.
“Extreme weather is a core condition to consider in resource planning,” NERC said, advocating for a “comprehensive resource planning construct” that focuses attention on “energy sufficiency with the understanding that capacity alone does not provide for reliability unless the fuel behind it is assured even in extreme weather.”
Variable energy resources, meanwhile, continue to grow, NERC said, noting that since its 2020 LTRA, the capacity of solar projects in all stages of development has increased from 390 GW to 504 GW for the next 10 years and wind power capacity is projected to total 360 GW over the next 10 years, up from 250 GW since the 2020 LTRA projection. Battery energy storage installations have also grown with 113 GW in development through 2024, a sharp rise from the 47 GW reported in the 2020 LTRA.
Solar photovoltaic distributed energy resources (DER) also continue to grow and are expected to reach 60 GW over the next 10 years, with some regions doubling their solar DER footprint by 2031, NERC said.
The growth of DERs underscores the need for generation operators to have “flexibleresources, including adequate dispatchable, fuel-assured, and weatherized generation, at their disposal,” NERC said.
Until storage technology is fully developed and deployed at scale, which NERC sees as beyond the 10-year scope of the 2021 LTRA, gas-fired generation will remain a necessary balancing resource to provide increasing flexibility needs, NERC said.
With increasing reliance on gas-fired generation will come the need to “deeply understand natural gas and electric system interdependencies,” and to improve the coordination between natural gas and electricity.
The natural gas system was not built or operated with electric reliability as the first concern,” NERC asserted. The lack of coordination between the two industries was a “major contributor to the devastation” in the Electric Reliability Council of Texas (ERCOT) during winter storm Uri in 2021, NERC said. “
The “regulatory structure and oversight of natural gas supply for electric generation needs to be rethought to assure reliable fuel supply for electric generation to support the reliable operation” of the bulk power system, NERC said.
NERC also recommended that further work is necessary to improve the modeling needed to reliably integrate interconnecting inverter-based resources (IBRs), such as wind and solar power and batteries, into the bulk power system.
Industry planners also should update interconnection agreements to address the performance specifications for IBRs, NERC said, adding that the Federal Energy Regulatory Commission should update its pro forma interconnection agreement for large and small generators to include IBR performance specifications.
NYPA Launches Challenge For Innovative Heat Pump
December 21, 2021
by Paul Ciampoli
APPA News Director
December 21, 2021
The New York City Housing Authority (NYCHA), New York Power Authority (NYPA) and New York State Energy Research and Development Authority (NYSERDA) on Dec. 20 launched an industry competition directed at heating and cooling equipment manufacturers to develop a new electrification product that can better serve the needs of existing multifamily buildings.
“By leveraging NYCHA’s building portfolio, the Clean Heat for All Challenge is designed to spur innovation by positioning the Authority as an early adopter of this technology, providing public housing residents with access to clean sources of energy through engagement with service providers and manufacturers of heat pump technologies,” NYPA said.
The challenge calls upon manufacturers to develop a packaged cold climate heat pump that can be installed through an existing window opening to provide heating and cooling on a room-by-room basis.
The envisioned product would enable rapid, low-cost electrification of multifamily buildings by reducing or eliminating many of the cost drivers inherent to existing heat pump technologies when used in resident occupied apartments. These include costly electrical upgrades, long refrigerant pipe runs, drilling through walls and floors and other construction aspects which result in high project costs, and significant disruption to residents.
NYCHA, NYPA, and NYSERDA have also engaged with the Consortium of Energy Efficiency to engage manufacturers and encourage broad industry participation in the Clean Heat for All Challenge.
The request for proposals issued by NYPA identifies a list of product specifications that manufacturers will be challenged to meet.
To incentivize participation, NYCHA will commit to purchasing the first 24,000 units from the awarded vendor or vendors that will be installed at six developments currently slated for heating plant replacement over the next five years.
NYSERDA is supporting the effort by providing additional funding from the Regional Greenhouse Gas Initiative operating plan, which calls for the electrification of heating in New York City public housing to improve energy performance, decrease emissions, and improve resident comfort. NYSERDA will provide assistance drafting the product specifications and performing commissioning as well as measurement and verification for the demonstration units.
NYCHA will invest $250 million, in addition to the NYSERDA grant, to purchase and install the new equipment as well as provide additional improvements to the building envelopes and hot water systems.
The initiative is based on a similar product challenge that NYCHA and NYPA partnered on in the 1990s and which produced some of the first Energy Star rated refrigerators, reducing the energy use of refrigerators by over 50 percent.
If the technology developed from the Clean Heat for All Challenge is successful, NYCHA will deploy at more than 50,000 apartments over the next 10 years, to meet space heating and cooling needs with zero on-site emissions.
The type of solutions this initiative is seeking will be broadly applicable to the multifamily sector across the Northeast, NYPA said.
The New York City Department of Housing Preservation and Development and New York State Homes and Community Renewal have already confirmed their strong interest in utilizing this new type of product for their preservation and new construction pipelines.
In addition, NYCHA and NYSERDA are working together with other large public housing authorities and housing agencies in the U.S. and Canada to aggregate a larger potential demand.
These new type of heat pumps will also be applicable for net zero carbon retrofits under NYSERDA’s RetrofitNY initiative. Through the RetrofitNY Pledge, building owners have already pledged to install cost effective net-zero carbon retrofit solutions in over 400,000 dwelling units when they become available.
NYCHA and NYPA are also partnering to replace the aging gas-and-oil-fueled heating and hot water systems at a 20-story high-rise in Manhattan, with a high-efficient electric Variable Flow Refrigerant (VRF) heat pump system.
The $28 million design-build electrification project will eliminate the use of on-site fossil fuel for heating and hot water while also providing central heating and cooling to 100 percent of apartments, replacing the old, inefficient window air conditioning units that have come to define many New York City-based facades. Once complete, residents will be able to individually control the temperature in each room of their apartment.
NYCHA has been an energy customer of NYPA since 1996, partnering to complete $211 million in energy efficiency projects, saving $23 million annually and reducing greenhouse gas emissions by 75,000 tons a year.
Texas Utility Regulators Approve Reforms To Wholesale Electricity Market
December 20, 2021
by Paul Ciampoli
APPA News Director
December 20, 2021
The Public Utility Commission of Texas (PUCT) on Dec. 16 voted to enact major reforms to the state’s wholesale electricity market.
Some changes will take effect very quickly to be in place this winter, the PUCT said, while other changes “will provide long-term incentives for investment in reliable power generation infrastructure to ensure Texas will have the power the state needs for decades.”
Key Changes
The changes approved by the PUCT will provide earlier price signals to bring additional generation online and for large consumers to adjust their demand, it said.
The PUCT said its approved reforms increase the market incentives for large consumers to decrease electricity usage in response to prices and grid conditions. This includes virtual power plants where groups of customers can come together into a single resource for the grid.
Emergency Response Service (ERS) is an existing program for large customers to register with ERCOT to decrease their electricity demand when the grid needs additional power. Previously, this tool was only available during an emergency. Now ERS can be used to avoid emergency conditions.
The commission also approved new or revamped ancillary services that include paying generators for having onsite fuel storage, for the ability to respond quickly to changes in the frequency of the grid, and for the capacity to react to abrupt swings in electricity supply and demand.
These improvements are part of Phase 1 of the Commission’s work to improve grid reliability and the wholesale electricity market. Phase 2 will include a review of a backstop reliability service and a load-side reliability mechanism.
These will provide further market signals for reliable generation, the PUCT said.
PUCT staff and Electric Reliability Council of Texas staff will develop phase 2 policies over the coming weeks and report back to the commissioners.