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Senate confirms FERC nominees Clements and Christie

December 1, 2020

by Paul Ciampoli
APPA News Director
December 1, 2020

The U.S. Senate on Nov. 30 confirmed by voice vote the nominations of Allison Clements and Mark Christie to be members of the Federal Energy Regulatory Commission.

Clements, a Democrat, will serve a term expiring June 30, 2024, while Christie, a Republican, will serve a term expiring June 30, 2025.

The Senate Energy and Natural Resources Committee on Nov. 18 favorably reported the nomination of Clements and Christie to be members of FERC.

President Donald Trump on Nov. 5 named James Danly as Chairman of FERC. He will replace Neil Chatterjee as head of the agency.

Danly has served as a Commissioner since March 2020. Prior to that he served as general counsel to the Commission since joining FERC in 2017.

Chatterjee, who joined the Commission in 2017 and served as Chairman from August to December 2017 and since October 2018, congratulated Danly on his appointment and said the Commission will be well-served by Danly’s leadership.

Chatterjee will remain a FERC Commissioner, along with Commissioner Richard Glick.

Public power utilities earn high scores for business customer satisfaction

November 30, 2020

by Paul Ciampoli
APPA News Director
November 30, 2020

A new J.D. Power study shows that public power utilities in several parts of the U.S. are among the leading utilities to earn high marks for business customer satisfaction.

J.D. Power on Nov. 18 released its 2020 Electric Utility Business Customer Satisfaction Study.

Within each of the four U.S. geographic regions included in the study, utility providers are classified into one of two segments: large (serving 85,000 or more business customers) and midsize (serving 40,000-84,999 business customers).

The 2020 Electric Utility Business Customer Satisfaction Study, now in its 22nd year, measures satisfaction among business customers of 88 targeted U.S. electric utilities, each of which serves more than 40,000 business customers.

Overall satisfaction is examined across six factors (listed in order of importance): power quality and reliability; corporate citizenship; price; billing and payment; communications; and customer contact.

The index ranking is based on a 1,000-point scale and also included customers of investor-owned utilities.

In the midsize segment for the Midwest Region, Nebraska’s Omaha Public Power District ranked third with a score of 789.

In the South region’s midsize segment, five of the 12 listed utilities were public power utilities. Fourth place Texas public power utility Austin Energy earned a score of 808. Nashville Electric Service (ranked sixth) posted a score of 792, followed by Florida’s JEA in seventh place (score of 787) and eighth place Texas public power utility CPS Energy (score of 781).

Memphis Light, Gas and Water in Tennessee came in 12th in with a score of 736 in the region’s midsize segment.

In the West region’s large segment, Arizona public power utility Salt River Project earned second place out of 12 utilities with a score of 809.

In the West region’s midsize segment the top three utilities were public power utilities: Seattle City Light (number one spot, 822 score); California’s SMUD (number two spot, 813 score); and Los Angeles Department of Water and Power (third spot, 804 score). There were a total of six utilities ranked in the West region’s midsize segment.

The study was based on responses from 18,457 online interviews of business customers in decision-making roles related to their utility company. The study was fielded from February through October 2020.

J.D. Power reported that overall business customer satisfaction with electric utilities was 793, up 14 points from 2019, driven largely by improvements in customer contact and power quality and reliability. Nearly one-third (31%) of business customers said they received perfect power throughout 2020, up from 29% in 2019. Among those businesses that did experience an outage, 61% said they received some form of proactive communication from their utility.

Overall satisfaction among large businesses has increased eight points during the COVID-19 pandemic, while satisfaction among small and medium-sized businesses has declined during the same period. Small businesses posted the largest decline (-11 points) from the pre-pandemic period of Feb. 12-March 11 through the end of fielding in October. Small businesses in the study also cited increased financial stress during the pandemic, with 27% saying they are financially worse off now than before the pandemic.

Overall customer satisfaction was significantly higher (73 points) among the 64% of businesses that are aware of COVID-19-related relief efforts, such as late payment forgiveness, waived charges and fees and community support initiatives. However, 36% of business customers say they are unaware of these efforts.

Belmont Light rolls out program to help customers adopt air source heating systems

November 30, 2020

by Paul Ciampoli
APPA News Director
November 30, 2020

Belmont Light in Massachusetts has launched an education and marketing program aimed at providing customers with the information they need to install air-source heat pumps.

Belmont Light’s CleanComfort program, which is being administered by Adobe Energy Management, connects customers with expert research and guidance throughout the installation process, as well as available rebates.

“Our overall goal is strategic electrification,” Ben Thivierge, energy specialist at the public power utility, said. The town of Belmont adopted a climate action plan last year that calls for an 80% reduction in carbon dioxide emissions by 2050. Belmont Light was involved with that plan and as part of it, “we need to do electrification and fuel switching. A lot of customers felt that heat pumps would be a good way to do that,” Thivierge said.

“Air-source heat pumps play an integral role in our plan to help the Town of Belmont reduce its carbon emissions,” Craig Spinale, Belmont Light’s general manager, said in a statement. “The CleanComfort program gives us an incredibly useful way to move toward those goals while also being able to offer cost savings and increased comfort to our customers.”

Belmont Light offers customers rebates of between $650 and $2,000, depending on size of the heat pump system they install. Rebates of up to $1,500 are also available for homeowners who completely replace fossil fuel systems with heat pumps.

Air-source heat pumps are ducted or ductless systems – sometimes referred to as mini-splits systems – that are able to heat and cool homes more efficiently than systems that use fuel oil. According to the Northeast Energy Efficiency Partnerships, homeowners can save up to $948 per year when replacing an existing fuel oil system with an air-source heat pump.

About 75% of Belmont Light’s customers use natural gas for heating. For them, the cost of switching to an air source heat pump would save them a little bit of money or be about equal in costs, while customers who use fuel oil or propane for heating would likely see lower costs, Thivierge said. However, customer feedback indicates that about half the customers who switch to air source heating do so for environmental reasons more than monetary reasons, he said.

Through the CleanComfort program, Abode Energy Management will provide a heat pump specialist to talk directly with Belmont Light customers. “Because the systems are highly customizable, it can be difficult to compare quotes and system designs,” Travis Estes, COO of Abode, said in a statement. “The heat pump specialist will help Belmont Light customers navigate the entire process and ensure installations are completed with the utmost quality at a fair price.”

Belmont Light sees the CleanComfort program as a follow up to its HeatSmart Belmont program, a similar education campaign that resulted in the installation of over 40 air source heat pump systems in Belmont homes in 2019.

The new program is also slightly different than the previous program in that customers have the opportunity to work with an expert energy consultant to verify that air source systems are sized correctly. “It helps us make sure the money is well spent and customers will not see their electric bills skyrocket,” Thivierge said.

The HeatSmart program had support of a state grant. For the new program, Belmont Light is bearing the costs by tapping the utility’s energy efficiency funds. “We view the program as a net benefit,” Thivierge said. The education piece of the program is important because “we want to be sure customers are comfortable with the changes in the technology, and we want customers to view us as a trusted energy adviser.”

Air source heat pumps have been around for a long time, but recent changes, particularly to some control components, have made the systems more efficient and reliable and better suited for colder climates.

In setting up the CleanComfort program, Belmont Light also met with other public power utilities – knowns as municipal light plants in Massachusetts – to come up with unified branding for the program. Thivierge said he knows of four other utilities that are using the program and have rolled it out in the past month or so.

Looking forward, Belmont Light is considering expanding its heat pump program. Based on customer feedback, Thivierge said the utility is looking at setting up rebates for customers who already have installed air source heat pumps and want to expand their systems to replace their existing fossil fuel heating systems.

DOE awards $9.4 mil grant to EPRI-led advanced hydrogen production project that includes NPPD

November 25, 2020

by Paul Ciampoli
APPA News Director
November 25, 2020

A team led by the Electric Power Research Institute (EPRI) has been awarded a $9.4 million grant from the U.S. Department of Energy to support research and development related to hydrogen production from fossil assets without carbon emissions.

The team includes Nebraska Public Power District (NPPD), Bechtel, Gas Technology Institute, Hamilton Maurer International, Inc., Nexant Energy and Chemicals Advisory, and Wärtsilä North America, Inc.

The award is part of a DOE Initiative “to advance innovative power plant concepts that are capable of flexible, net-zero operations while producing hydrogen to support economy-wide decarbonization goals,” EPRI noted in a Nov. 23 news release.

The project will investigate design options for hydrogen production in a hybrid coal and biomass power plant. The integrated design study will assess multiple gasification systems that utilize the water-gas shift, a process that converts carbon monoxide and steam to hydrogen and carbon dioxide.

The system will be paired with pre-combustion carbon dioxide capture and pressure-swing adsorption, which produces high-quality hydrogen and a synfuel capable of generating flexible power using an engine or gas turbine, EPRI said.

The design study is a stepping stone to a future demonstration plant that will be strategically located at NPPD Gerald Gentleman generating station. NPPD is a sponsor of the Low-Carbon Resources Initiative, jointly led by EPRI and the Gas Technology Institute.

John Swanson, Director of Generation Strategies and Research at NPPD, noted that Nebraska is an area where opportunities for enhanced oil recovery and sequestration are being investigated for carbon dioxide storage, “and where the need for clean power and hydrogen is increasingly important to support low-carbon and long-term storage targets.”

The primary biomass to be used in the demonstration project is corn stover — stalks, leaves and cobs left over after a corn harvest. Corn stover, which is abundant in Nebraska, will be mixed with Powder River Basin coal, necessitating a flexible gasifier that can use this fuel source, among others, including waste.

The study will begin in early 2021, which complements technology assessments underway as part of the Low-Carbon Resources Initiative, EPRI said.

EPRI conducts research and development relating to the generation, delivery, and use of electricity.

Texas public power cities to buy energy from 1,310-MW solar facility

November 25, 2020

by Paul Ciampoli
APPA News Director
November 25, 2020

Three public power cities in Texas – Bryan, Denton and Garland – have entered into agreements to buy energy from a 1,310-megawatt solar energy generation facility to be built in the state.

Invenergy, the project’s developer, said that the facility will be the largest solar project in the United States upon completion. The Samson Solar Energy Center is currently under construction in northeast Texas.

Along with Bryan, Denton and Garland, the following corporations will also purchase energy from the solar facility: AT&T, Honda, McDonald’s, Google and The Home Depot.

The breakdown of energy to be purchased from the facility is:

Located in Lamar, Red River and Franklin Counties, Samson Solar is a $1.6 billion capital investment, Invenergy said.

Samson Solar will be constructed in five phases over the next three years, with each phase commencing operation upon completion.

The full project is slated to be operational in 2023.

Study finds electrification is key to decarbonization of New England

November 24, 2020

by Peter Maloney
APPA News
November 24, 2020

New England will require economy wide electrification to achieve greenhouse gas reduction targets, according to a new report by Energy + Environmental Economics (E3) and Energy Futures Initiative (EFI).

All six New England states have adopted economy wide greenhouse gas (GHG) reduction targets of at least 80% reductions by mid-century, and Massachusetts recently adopted a net-zero commitment. And every state in the region, except Vermont, has seen its gross emissions decline since 1990 aided by the power sector’s transition from coal to natural gas as a generation fuel.

The region does pose unique challenges in achieving its emission reduction goals, the authors said.

The proportion of emissions in New England attributable to the transportation sector is higher than the national average while emissions from industrial sources are lower.

Transportation accounts for 42% of carbon dioxide emissions in New England while electricity accounts for about 20%, the report, Net-Zero New England: Ensuring Electric Reliability in a Low-Carbon Future, noted.

The report was sponsored by Calpine, an independent generation company that is heavily invested in gas-fired power plants. Calpine provided “input and perspectives” regarding the scope and analysis of the study but “all decisions regarding the analysis were made by E3 and EFI.” The authors also noted that the report “solely reflects the research, analysis, and conclusions” of E3 and EFI.

The report found that New England’s unique energy profile means that the region will not “be able to attain its GHG reduction goals with an exclusive focus on electricity production; it will be necessary to implement aggressive decarbonization on an economy-wide basis.”

Another unique factor in New England’s energy profile also creates a challenge. Fossil fuels used for residential and commercial heating contribute about 25% the region’s emissions, and New England is the only region in the country where oil is the most common heating fuel, the report said.

Direct energy use for transportation and buildings makes up two-thirds of New England’s emissions, therefore, mitigating GHG emissions will require strategies that emphasize the aggressive deployment of energy efficiency; widespread electrification of buildings, transportation and the industrial sector; development of low-carbon fuels, and deep decarbonization of electricity supplies, the report found.

The study modeled two scenarios: one focused on electrification (High Electrification) and the other on low-carbon fuels (High Fuels) to achieve 95% carbon emissions reductions in the region, although the scenarios use both strategies to some degree. As New England states draw closer to their GHG reduction goals, electricity demand in the region will increase significantly over the next three decades, the report said. In the two primary scenarios studied, annual electricity demand grows by 70 terawatt-hours (TWh) to 110 (TWh) by 2050, roughly a 60% or 90% increase from current levels. And electric peak demand would rise to between 42 gigawatts (GW) and 51 (GW).

Meeting GHG reduction goals while increasing electrification will also require a greater reliance on renewable energy, the authors said. Under the two scenarios, a mix of 47 GW to 64 GW of new renewable generation capacity would be needed by 2050, including land-based solar and wind, offshore wind, and distributed solar, along with 3.5 GW of incremental Canadian hydro. The authors also noted, however, that New England’s constrained geography, “slow pace of electric transmission planning, and historical difficulty siting new infrastructure are significant challenges that the region must overcome.”

Higher levels of renewable energy would also require firm capacity to ensure cost-effective and reliable energy supplies, the report said. As much as 46 GW of firm capacity could be needed in 2050 to ensure resource adequacy. Relying on renewable energy resources backed by battery storage, would be “extremely costly,” the authors added. Firm capacity would include about 34 GW of gas-fired generation, 3.5 GW of nuclear power, 8 GW of energy imports, and 1 GW of biomass and waste energy, the report found.

New resources, such as advanced nuclear, natural gas plants with carbon capture and sequestration, long duration energy storage, or generation from carbon-neutral fuels such as hydrogen, could be used to provide firm capacity, but until any of those technologies are commercially viable, natural gas generation is the most cost-effective source of firm capacity, the report said, adding that “some reliance” on gas generation is consistent with achieving a 95% carbon-free electricity grid in 2050 as long as the gas plants operate at a “suitably low capacity factor.”

NYPA completes work on first segment of transmission line project

November 24, 2020

by Paul Ciampoli
APPA News Director
November 24, 2020

The New York Power Authority (NYPA) on Nov. 24 announced the completion of work and energization of the first segment of one of the lines for its Smart Path Transmission project, the upgrade of the Moses to Adirondack transmission lines 1 and 2.

“The Smart Path transmission project is critically important to the resiliency of New York’s north-south transmission system,” said Gil Quiniones, NYPA president and CEO, in a statement. “The benefits of this important transmission work accrue incrementally, so every time we complete a section, New York State’s transmission system becomes that much stronger, more resilient and reliable.”

 The Smart Path project involves rebuilding approximately 78 miles of the total 86-mile transmission artery that was constructed originally by the federal government in 1942 and acquired by the Power Authority in 1950.

Running north to south through St. Lawrence and Lewis counties in the North Country, the newly rebuilt lines will connect renewable energy into the statewide power system, including low-cost hydropower from NYPA’s St. Lawrence-Franklin D. Roosevelt Power Project as well as power from newly constructed renewable energy sources.

Construction involves the replacement of the original H-frame wood poles, some of which are more than 80 years old with single steel monopoles in the existing right of way. The project, which has been broken into six parts — three segments per line — includes high-voltage transmission lines from Massena to Croghan.

Work on the first 21-mile section of the Moses to Adirondack 2 line began at the beginning of the year.  A total of 104 new structures have been installed and the rebuilt section was energized earlier this month. It will provide improved resiliency to support the transmission of clean energy from Northern New York, NYPA noted.

There are five remaining transmission line segments to be rebuilt under the Smart Path project. Work will begin next month on the replacement of the Moses to Adirondack 1 line in segment 1.

The first phase of the Smart Path project is expected to be complete in 2023. The project will strengthen the state’s electric power grid, and help the state meet the goals set forth in New York Gov. Andrew Cuomo’s Climate Leadership and Community Protection Act.

The rebuilt lines will be capable of transmitting up to 345 kilovolts (kV). However, they will be operated in the near-term at the 230 kV level.

Together the lines are currently rated to carry 900 megawatts during the winter months. “This ability to increase the voltage when the demand requires it is a cost-effective way to add on more renewable power, especially from in-state renewable generation, anywhere along the transmission line, as New York continues to advance its clean energy goals,” NYPA said.

Analysis finds adequate Eastern Interconnection frequency response

November 24, 2020

by Ethan Howland
APPA News
November 24, 2020

The Eastern Interconnection should be able to maintain system frequency for at least the next five years, according to a group of transmission planning coordinators.

However, with the addition of non-synchronous generation (intermittent wind and solar) and planned power plant retirements, maintaining frequency in the Eastern Interconnection is a concern that warrants continued study, the Eastern Interconnection Planning Collaborative (EIPC) said in a report issued Nov. 11.

The Eastern Interconnection electric grid covers about two-thirds of North America from the Rocky Mountains to the East Coast.

The North American Electric Reliability Corporation asked the EIPC, a coalition of 19 transmission planning coordinators, to study how the changing resource mix could affect frequency response in the Eastern Interconnection.

Frequency response is a measure of the grid’s ability to stop and stabilize frequency changes after the sudden loss of generation or load. If unchecked, sharp frequency changes can lead to power outages.

Load along with large fossil-fueled and nuclear power plants provide inertia to help maintain the grid’s frequency, but some plants are being replaced with renewable resources, which until a 2018 decision by the Federal Energy Regulatory Commission generally didn’t provide frequency response. To help maintain the grid’s stability, FERC ordered that all new generating facilities be able to provide frequency response.

The loss of inertia from the large power plants could trigger “under-frequency load shed” events, or blackouts, according to the EIPC.

At NERC’s request, the EIPC finished an initial frequency response study in April 2019.

“As the generation resource mix continues to evolve over time to incorporate new and emerging technologies and address energy and environmental policies, it is essential to understand how the Eastern Interconnection will be poised to maintain system frequency under a wide range of operating conditions,” said Keith Daniel, senior vice president of transmission policy at Georgia Transmission Corp. and chairman of the EIPC Executive Committee.

The EIPC task force that wrote the report studied four hypothetical events, including including generation losses of 2,300 megawatts, 3,850 MW and 4,500 MW as well as a 10,000 MW event.

The EIPC’s Frequency Response Working Group will continue to update its analysis, according to Daniel.

The EIPC is conducting additional power system analysis that will provide information to help maintain grid reliability and to inform state and federal regulators and policy makers, Daniel said.

The EIPC’s frequency response analysis will supplement NERC’s 2021 Long-Term Reliability Assessment.

The EIPC members include public power entities Municipal Electric Authority of Georgia (MEAG Power) and Santee Cooper.

FERC looks to improve accuracy and transparency of transmission line ratings

November 23, 2020

by Paul Ciampoli
APPA News Director
November 23, 2020

The Federal Energy Regulatory Commission recently issued a notice of proposed rulemaking (NOPR) aimed at improving the accuracy and transparency of transmission line ratings, which represent the maximum transfer capability of each transmission line. 

FERC took the action at its monthly open meeting on Nov. 19.

At the meeting, FERC staff noted that under current typical practices, transmission line ratings are seasonal or static ratings. 

These ratings are based on conservative assumptions about the worst-case, long-term ambient conditions that equipment might face.  They are typically updated only when equipment is changed or ambient condition assumptions are revised, and therefore may not accurately reflect the near-term transfer capability of the system. 

FERC staff said that more accurate ratings include ambient-adjusted ratings (AARs) and dynamic line ratings (DLRs), both of which are the subject of the NOPR. 

Unlike seasonal or static-based ratings, ambient-adjusted ratings incorporate near-term forecasted ambient air temperatures.  Dynamic line ratings are based not only on forecasted ambient air temperature, but also on other weather conditions such as wind, cloud cover, solar irradiance intensity, precipitation, and/or on transmission line conditions such as tension or sag. 

There can be consequences to using an inaccurate representation of system transfer capability, FERC staff said. 

For example, FERC staff said that because ambient air temperatures are typically less extreme than worst case assumptions, seasonal and static transmission line ratings typically indicate that there is less transmission system transfer capability available than the transmission system can actually provide. This increases congestion costs.  At other times, however, seasonal or static transmission line ratings may overstate the near-term transfer capability of the system, creating potential reliability problems and inaccurately low congestion pricing, which may prevent occurrences of rates for scarcity pricing.  In either case, the use of seasonal and static assumptions results in transmission line ratings that do not accurately represent the transfer capability of the transmission system.

To address this concern, the NOPR proposes to require transmission providers to implement ambient-adjusted ratings and seasonal line ratings on the transmission lines over which they provide transmission service.  Transmission providers would use AARs for evaluating requests for near-term transmission service, and would use seasonal ratings for evaluating other, longer-term transmission service requests. The NOPR also proposes to revise the rules for setting seasonal ratings to make them more accurate.

In addition, the NOPR proposes to require RTOs and ISOs to establish and implement the systems and procedures necessary to allow transmission owners to electronically update transmission line ratings at least hourly. 

The NOPR recognizes that there may be instances in which transmission owners may wish to implement transmission line ratings that may be more accurate than AARs, such as dynamic-line ratings, but are unable to have such ratings reflected in RTO/ISO markets under those markets’ current capabilities.  This proposed requirement seeks to remove this barrier to adoption of these more accurate line ratings. 

The NOPR also proposes to require transmission owners to share transmission line ratings and transmission line rating methodologies with their respective transmission provider(s) and, in RTOs/ISOs, with their respective market monitor(s).  Such information sharing would increase situational awareness and improve the ability to verify the accuracy of transmission line ratings.

Finally, the NOPR seeks comment on whether to require transmission providers to use unique emergency ratings.

Comments are due 60 days after publication in the Federal Register.

The NOPR is available here.

CPS Energy signs deal to provide renewable natural gas for San Antonio’s buses

November 23, 2020

by Peter Maloney
APPA News
November 23, 2020

CPS Energy in San Antonio, Texas, has signed a deal to provide renewable natural gas (RNG) to the city’s mass transit provider.

Under the deal, the public power utility would provide the gas, which will be produced from landfill biogas, to VIA Metropolitan Transit beginning in 2021.

The transit agency will use the gas in its fleet of 502 buses, which are now powered primarily by compressed natural gas (CNG) along with some diesel-electric hybrid, electric, diesel and propane-fueled vehicles.

As the waste in a landfill decomposes, it produces methane, a powerful greenhouse gas, that, unless captured, is released into the air. Renewable natural gas can be created from captured methane and blended with natural gas. CPS Energy said it would distribute the enhanced natural gas through its existing natural gas distribution pipelines.

The gas will be captured from a landfill site in Converse, Texas, at a facility that is being designed, built and will be owned and operated by EDL of Australia, which will inject into CPS’ gas pipeline. The utilities will have to build spur lines to connect its pipeline network to the landfill facility.

CPS Energy has agreed to buy the gas EDL produces. On the other end, VIA Metropolitan Transit has agreed to take the beneficial environmental attribute of the non-fossil fuel gas, known as Renewable Identification Numbers (RINs) that are like Renewable Energy Credits (RECs) for fuel. “This is a unique opportunity for CPS,” utility spokesman John Moreno said.

VIA began converting its bus fleet to CNG in 2017 in an effort to reduce nitrogen oxide emissions by 97% from the diesel buses they replaced. As a vehicle fuel, renewable natural gas also reduces carbon dioxide emissions by 85% compared with diesel fuel vehicles.

The renewable natural gas program is “one more component of our creative Flexible Path strategy, which has been designed to leverage emerging environmental stewardship opportunities, which we keep our customers’ bills affordable and our services reliable,” Paula Gold-Williams, president and CEO of CPS Energy, said in a statement.

In 2019, as part of its Flexible Path strategy, CPS Energy made a commitment to reduces its next emissions profile by 80% by 2040. The utility is also working toward full carbon dioxide neutrality by 2050 in support of the City of San Antonio’s Climate Action & Adaptation Plan (CAAP) that was endorsed by the utility’s board of trustees in August 2019.

CPS Energy in San Antonio, Texas, has signed a deal to provide renewable natural gas (RNG) to the city’s mass transit provider.

Under the deal, the public power utility would provide the gas, which will be produced from landfill biogas, to VIA Metropolitan Transit beginning in 2021.

The transit agency will use the gas in its fleet of 502 buses, which are now powered primarily by compressed natural gas (CNG) along with some diesel-electric hybrid, electric, diesel, and propane-fueled vehicles.

As the waste in a landfill decomposes, it produces methane, a powerful greenhouse gas, that, unless captured, is released into the air. Renewable natural gas can be created from captured methane and blended with natural gas. CPS Energy said it would distribute the enhanced natural gas through its existing natural gas distribution pipelines.

The gas will be captured from a landfill site in Converse, Texas, at a facility that is being designed, built and will be owned and operated by EDL of Australia, which will inject into CPS’ gas pipeline. The utilities will have to build spur lines to connect its pipeline network to the landfill facility.

CPS Energy has agreed to buy the gas EDL produces. On the other end, VIA Metropolitan Transit has agreed to take the beneficial environmental attributes of the non-fossil fuel gas, known as Renewable Identification Numbers (RINs) that are like Renewable Energy Credits (RECs) for fuel. “This is a unique opportunity for CPS,” utility spokesman John Moreno said.

VIA began converting its bus fleet to CNG in 2017 in an effort to reduce nitrogen oxide emissions by 97% from the diesel buses they replaced. As a vehicle fuel, renewable natural gas also reduces carbon dioxide emissions by 85% compared with diesel fuel vehicles.

The renewable natural gas program is “one more component of our creative Flexible Path strategy, which has been designed to leverage emerging environmental stewardship opportunities, while we keep our customers’ bills affordable and our services reliable,” Paula Gold-Williams, president and CEO of CPS Energy, said in a statement.

In 2019, as part of its Flexible Path strategy, CPS Energy made a commitment to reduce its net emissions profile by 80% by 2040. The utility is also working toward full carbon dioxide neutrality by 2050 in support of the City of San Antonio’s Climate Action & Adaptation Plan (CAAP) plan that was endorsed by the utility’s board of trustees in August 2019.

CPS’ Flexible Path also includes initiatives such as its FlexSTEP energy efficiency program In July, as part of its FlexPOWER Bundle initiative, CPS Energy released a request for information to evaluate potential partners that can help the utility in the process of adding up to 900 MW of solar power, 50 MW of battery storage, and 500 MW of new technology solutions.