APPA Warns of Spike In Transmission Costs If FERC Incentive Proposals Are Adopted
July 1, 2020
by Paul Ciampoli
APPA News Director
Posted July 1, 2020
If adopted, transmission incentive changes proposed by the Federal Energy Regulatory Commission in a Notice of Proposed Rulemaking (NOPR) are likely to hike transmission costs without any assurance of commensurate benefits for consumers, the American Public Power Association said on July 1.
Moreover, given that transmission development in the U.S. has been strong in recent years, FERC has fallen short in justifying the need for significant reforms to its transmission incentive policies, APPA said in response to the NOPR (Docket No. RM20-10).
In the NOPR, which was issued in March, FERC proposed substantial changes to its regulations and policies governing the award of transmission incentives under section 219 of the Federal Power Act (FPA).
As a threshold matter, APPA noted that it supports prudent investment in the country’s transmission infrastructure for the benefit of consumers. “Prudently planned and constructed transmission facilities can increase supply options, reduce congestion-related costs, integrate renewable resources, and promote grid reliability. APPA supports reasonable Commission policies that promote such beneficial transmission investment.”
No compelling reason to change existing approach
APPA said that FERC’s existing approach to evaluating project-specific incentive applications is generally sound and argued that the NOPR identifies no compelling reason to change. The current incentive framework was established in Order No. 679 and subsequent orders.
In the years since the Commission issued Order 679, and particularly since a 2012 Policy Statement was released, transmission investment has grown significantly, “and the NOPR provides no evidence that investment is being withheld for lack of incentives under FERC’s current policies,” APPA said.
“It is important to note, moreover, that the increase in transmission investment in recent years has resulted in substantial increases in transmission rates in some regions, and this trend is expected to continue.”
APPA pointed out that the Energy Information Administration’s 2020 Annual Energy Outlook projects that rising transmission and distribution costs will offset much of the projected decrease in generation costs through 2050.
“These transmission cost increases impose a significant burden on public power utilities and the customers they serve. In considering proposed changes to its transmission incentives, the likelihood of increased cost burden on transmission customers should be a principal consideration, consistent with FPA section 219,” APPA told FERC. “Unfortunately, most, if not all, of the new incentives proposed in the NOPR fail to adequately ensure that the additional costs that would be imposed on consumers would be justified by commensurate consumer benefits.”
NOPR has a number of significant flaws
APPA said that the NOPR suffers from a number of significant flaws that should prompt the Commission to reconsider most of the proposed policy changes.
As a threshold matter, the NOPR does not justify the need for significant reforms to its incentive policies, APPA argued.
“The Commission specifically acknowledges that transmission development has been ‘robust’ in recent years. There is no empirical evidence cited in the NOPR demonstrating that the current incentive framework is ineffective in promoting transmission investment in accordance with the dictates of FPA section 219, and, in fact, the Commission acknowledges that it is has insufficient information to gauge the effectiveness of its current policies.”
While FERC asserts that the types of transmission projects and the incentives needed to promote them must evolve in response to industry changes, “the NOPR never draws a rational connection between the proposed incentives and the new types of projects the Commission claims are needed.”
Even if the Commission is correct that new “types” of transmission are needed, the proposed incentives are largely aimed at “low-hanging fruit” projects that are – or should be – identified in the regional planning processes already, APPA went on to say.
APPA questions proposal to shift to a “benefits-based” system
APPA also took issue with the Commission’s proposal to eliminate the nexus requirement and shift to a “benefits-based” system.
Such a move “runs afoul of the requirements of FPA section 219,” APPA said. It pointed out that Section 219 of the FPA requires FERC to adopt certain transmission incentives for the purpose of benefitting consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion.
But this obligation is coupled with the overarching requirement that incentive rates under FPA section 219 must be just and reasonable and not unduly discriminatory or preferential.
Project benefits are necessary, but not sufficient, to satisfy the requirements of FPA section 219 for granting transmission investment incentives, the public power group said.
The current “risks and challenges” framework for project-specific incentives was designed to ensure that there is a nexus between the total package of incentives sought and the demonstrable risks or challenges faced by the applicant in undertaking the project, APPA pointed out.
Joint ownership of transmission facilities
Of particular concern to APPA and its public power utility members, the NOPR makes no reference to promoting joint ownership of transmission facilities by non-public utilities, even though the issue was squarely raised in a prior notice of inquiry and addressed by APPA and other parties.
The Commission has consistently recognized the benefits of joint ownership of transmission facilities, and, in particular, has encouraged the participation of non-public utilities in jointly owned projects, including through the 2012 Policy Statement.
“If the Commission proceeds with a final rule based on the NOPR, it should continue to promote joint ownership of transmission facilities by, at a minimum, applying heightened scrutiny to incentive requests for any project for which joint ownership arrangements may have been feasible but were not pursued,” APPA argued.
FERC should not double the RTO Adder
APPA was harshly critical of FERC’s proposal to “double down” on the current equity return bonus that transmission owners get for participating in regional transmission organizations and independent system operators. The proposed rule would double the return on equity adder from 50 to 100 basis points, and would award the adder even if a utility is required to participate in an RTO/ISO by state authorities or other legal requirement.
The “NOPR offers no reasonable basis for simply doubling the current standard RTO participation adder,” APPA said, arguing that the proposed rule failed to establish that the substantial increase in costs that doubling the RTO/ISO participation bonus would be justified by any increased customer benefits. “The NOPR cites no evidence that an increase to the adder is necessary to encourage new, let alone continued, RTO/ISO participation,” APPA added.
APPA also contended that awarding the adder for non-voluntary participation in RTOs/ISOs would be “a departure from the bedrock principle for granting incentives (i.e., of inducing action that is not otherwise required).”
APPA outlines recommendations to FERC if it proceeds with NOPR incentive proposals
If the Commission chooses to proceed with the incentive proposals in the NOPR, APPA offered a number of recommendations including, among other things:
* Transmission incentives should be restricted to projects evaluated and approved in a full Commission-approved regional transmission planning process under Order No. 1000;
* An entity seeking a project-specific transmission incentive should be required to demonstrate that there is at least a rational relationship between each incentive sought and the decision to invest in the transmission project;
* The Commission should require a clear demonstration through a cost-benefit analysis that the quantifiable benefits to consumers from a project materially exceed the incremental costs of the requested incentives; and
* Parties to proceedings in which project-specific incentives are proposed must have full access to all information and analysis on which the claims of benefit are based, including analyses conducted by RTOs and ISOs, and an opportunity to evaluate and challenge benefit claims. The risk of being unable to substantiate a claimed benefit-cost outcome must be on the applicant.
APPA also makes several recommendations related to return on equity (ROE) adders.
It said that project-specific ROE adders should sunset after no more than 15 years. A shorter time frame could be applied in particular circumstances if, prior to the sunset date, the Commission makes a determination that the adder is no longer needed or effective.
APPA also argued that project-specific ROE adders should be limited to the cost of the project used in the application to demonstrate project benefits.
Also, any basis point cap on ROE adders should be set at 150 basis points, and total ROE adders should be limited to the lower of this basis point cap or the top end of the zone of reasonableness, it said.
As Much As $125 Billion Needed By 2030 To Support EV Growth: Brattle Report
June 30, 2020
by Peter Maloney
APPA News
Posted June 30, 2020
An investment of between $75 billion and $125 billion in the electric power system will be needed by 2030 to serve 20 million electric vehicles, according to a report by The Brattle Group.
There will be 10 to 35 million electric vehicles in the United States by 2030, a steep rise from the 1.5 million electric vehicles on U.S. roads in 2020, Brattle economists estimate. Factors driving the proliferation of electric vehicles include decreasing vehicle and battery costs, an expanding variety of electric vehicle models, more widespread charging infrastructure, as well as favorable federal and state policies and incentives, they say.
The investments needed to support the expected spread of electric vehicles includes $30 billion to $50 billion for generation and storage, $15 billion to $25 billion for transmission and distribution upgrades, and $30 billion to $50 billion for electric vehicle chargers and other customer-side infrastructure, the report, Getting to 20 Million EVs by 2030: Opportunities for the Electricity Industry in Preparing for an EV Future, says.
“While EVs and chargers are becoming more common in our everyday lives, the industry is really just seeing the tip of the iceberg when it comes to the impact that EVs will have on the grid,” Michael Hagerty, Brattle senior associate and study coauthor, said in a statement.
Among the challenges Brattle sees as electric vehicles become more prevalent is an increase in charging demand of between 60,000 gigawatt hours (GWh) and 95,000 GWh per year, including a 10 gigawatt (GW) to 20 GW rise in peak load from electric vehicle charging. Those increases in electricity use and load will require the addition of between 12 GW and 18 GW of renewable resources to maintain compliance with state mandates, such as renewable portfolio standards, that require minimum levels of renewable energy.
Deeper penetration of electric vehicles will also necessitate the expansion of charging infrastructure. So far, less than $2 billion has been approved for utilities to build charging infrastructure, but only 159 public charging stations are utility owned, representing about 0.6% of all public charging stations.
In all, the country will need about 1.25 million public chargers to fuel 20 million electric vehicles by 2030, representing a 20-fold increase in Level 2 chargers, a fivefold increase in direct current (DC) fast chargers, as well as 6 million to 10 million of residential Level 2 chargers installed at single family homes, Brattle estimates.
Meanwhile, Tesla has spent about $220 million building out its Supercharger network of over 800 stations. ChargePoint network has 38,000 chargers and plans to add 2.5 million globally by 2025. And Electrify America is investing $2 billion in Zero Emission Vehicle infrastructure by 2027.
Electrify America recently announced the completion of the first charging network that would enable an electric vehicle to travel cross country.
One of the challenges system planners will face is finding reliable, regional forecasts for electric vehicles sales, the report says. Most forecasts provide “limited insight” into local adoption rates as they are based on “black-box” models that can be challenging to understand
According to Brattle’s analysis, states with zero emission vehicle mandates have 26% higher electric vehicles sales, a $1,000 increase in electric vehicle incentives increases sales by 7.5%, a $10/kWh decrease in battery prices leads to a 4% increase in sales, and for every 10 additional electric vehicle models introduced sales increase by 8%.
Brattle recommends that industry planners and policy makers should develop plans, or roadmaps, that include detailed electric vehicle adoption forecasts, craft policies that articulate societal benefits of electric vehicle adoption, and facilitate collaboration across the electric vehicles supply chain to reduce market barriers, such as targeting under-served markets that are not prioritized by private investment.
More specifically, Brattle says the tension between private and utility investment needs to be resolved. Regulators often try to balance the need to provide sufficient charging infrastructure with the desire to keep the market open to competitive suppliers.
The Brattle report says there should be a “Win-Win-Win” approach among utilities, regulators and the private sector that recognizes that private investment will lead to increased product demand and sales and that increased electric vehicle utilization will lead to higher electricity sales and improved asset utilization for utilities.
Electrify America Completes First Route Across US With EV Charging Stations
June 29, 2020
by Peter Maloney
APPA News
Posted June 29, 2020
Electrify America says it has completed its first string of cross-country fast charging, direct current (DC) electric vehicle charging stations.
The route, spanning 11 states and over 2,700 miles, travels along interstates 15 and 70 from Los Angeles to Washington, DC, providing the first cross-country route with charging stations available the entire way, the company, a subsidiary of Volkswagen of America, said. The charging stations provide speeds up to 350 kilowatts.
“Range anxiety” and the fear of not being able to find an electric vehicle charging station is often cited as a key barrier to the wider adoption of electric vehicles.
“Electrify America’s primary goal has always been to advance electric vehicle adoption in the U.S., and that starts by instilling feelings of confidence and freedom in consumers when it comes to EV ownership,” Anthony Lambkin, director of operations at Electrify America, said in a statement.
By end of the summer, Electrify American says it will complete a second cross-country electric vehicle charging route, from Jacksonville, Fla., to San Diego, Calif., on interstate highways starting near I-10 and finishing along I-8. The company says its charging stations are on average about 70 miles apart, in metro areas and near highway routes near stores and restaurants.
Electrify America already has a series of charging stations on the East Coast along Interstate 95 from Portland, Maine, to Miami, Fla., and on the West Coast along Interstate 5 from Seattle, Wash., to San Diego.
A group of utilities, including several public power utilities, recently released a report recommending adding electric vehicle charging stations for freight haulers and delivery trucks along the I-5 corridor running from Canada to Mexico.
To date, Electrify America has more than 435 charging stations in operation with over 1,900 DC fast chargers and has more than 100 charging sites in development. Electrify America says it has located more than 300 of its completed stations near major highways to facilitate regional and cross-country travel.
Early on, Electrify America installed Level 2 chargers, but the majority of its work is focused on DC fast charger, spokesman Mike Moran said.
In 2019, Electrify America says it opened DC fast-charging stations at an accelerated pace of about 1.2 per business day. By the end of 2021, the company plans to install or have under development approximately 800 charging stations with about 3,500 DC fast chargers.
Electrify America, which says it has the largest open DC fast charging network in the US, was formed in 2017 to manage $2 billion in investments in zero emission vehicle infrastructure. The funds come from its parent company and are mandated under a 2016 settlement of the Volkswagen emissions-cheating scandal. The settlement will cost the car manufacturer $14.7 billion over 10 years.
The settlement also includes $2.7 billion over three years for an environmental trust to remediate the illegal levels of nitrogen oxides emitted by the VW vehicles.
Electrify America solicits input for investment plans
Electrify America is soliciting input for its Cycle 3 Investment Plans through July 31, 2020.
The American Public Power Association plans to submit comments encouraging Electrify America to consider investments in public power communities.
Organizations interested in providing comments, information, data and/or recommendations should click on this link for further details and submit input.
Updated ESCC COVID-19 Resource Guide Addresses Contact Tracing
June 29, 2020
by Paul Ciampoli
APPA News Director
Posted June 29, 2020
The Electricity Subsector Coordinating Council (ESCC) has updated a resource guide it has developed in response to the COVID-19 pandemic to add new sections that address planning considerations for contact tracing during mutual assistance and the use of contact tracing for workplace reentry.
The guide was updated with the input of the American Public Power Association and public power utilities. This is version 9 of the guide, which was released on June 26.
The guide is a living document developed under the direction of the ESCC. It has been updated and distributed regularly by the ESCC Secretariat, based on input from several “Tiger Teams” of industry leaders who are tracking key issues related to this global health emergency.
Planning considerations for contact tracing during mutual assistance
In the new section of the guide that discusses planning considerations for contact tracing during mutual assistance, the ESCC says that investor-owned electric and/or natural gas companies, electric cooperatives, and public power utilities should implement and utilize contact tracing programs to identify and assist employees who may have been exposed to the virus.
“Organizations should consider how those tracing programs would be utilized during a mutual assistance deployment that includes non-native employees/contractors from other organizations,” the guide goes on to say.
Prior to the mobilization of crews, a requesting organization should provide responding organizations, including contractors, with an overview of how it will conduct contact tracing for any mutual assistance crew member who tests positive, or has been exposed to the virus, while deployed.
These contact tracing plans for mutual assistance deployments should consider addressing the following:
Reporting: What process should a mutual assistance crew member use to report a positive test result, symptoms, or possible exposure to the virus? Will the requesting/responding organization provide access to testing and access to medical care for mutual assistance crew members with symptoms?
Mitigate: How will the requesting/responding organization support the isolation of the impacted crew member? Will that crew member(s) be released and required to return home immediately? Will the entire crew be required to isolate, or will they be released from the mission?
Investigate: Will the impacted mutual assistance crew member be included as part of the requesting organization’s internal contact tracing efforts? Will mutual assistance crews be required to complete additional documentation, such as detailed logs and summaries of locations visited, to facilitate contact tracing investigations? If so, how will this be facilitated, and what is the retention policy for that documentation?
Inform: Will the requesting organization be required to inform local health authorities when a mutual assistance crew member reports positive test result to the virus?
In addition, the guide suggests addressing the question of how other native and non-native crews, base camp support teams, other housing support staging site staff, food service staff, and customers will be informed of the potential exposure.
Reentering the workplace and contact tracing
The latest version of the guide also said that as organizations begin to consider when and how to transition employees from working remotely to reentering the workplace, they also should consider contact tracing programs as a tool to identify and to assist employees who potentially are exposed to COVID-19.
These programs are designed to protect workers, their families, and their communities by slowing or stopping the transmission of the virus.
Along with listing typical steps for contact tracing (report, mitigate, investigate, inform and track and follow up), the guide also offers a detailed set of approaches for contact tracing.
The latest version of the guide is available here.
House Bill Supported By APPA Makes Energy Tax Credits Available To Public Power
June 26, 2020
by Paul Ciampoli
APPA News Director
Posted June 26, 2020
House Subcommittee on Select Revenues Chairman Mike Thompson, D-Calif., on June 25 introduced legislation that will allow public power utilities to directly benefit from energy tax incentives.
The American Public Power Association is one of more than 20 organizations that have voiced support for Thompson’s bill, the Growing Renewable Energy and Efficiency Now (GREEN) Act (H.R. 7330).
“APPA applauds Representative Thompson’s leadership in helping to level the energy tax incentive playing field by ensuring that all utilities can benefit from incentives intended to encourage critical energy investments,” said Joy Ditto, President and CEO of APPA, on June 26.
In a June 19 letter to Thompson, Ditto noted that the GREEN Act “would mean that all – not just some – utilities can directly benefit from energy tax incentives. This will make these incentives fairer and more effective.”
Federal tax expenditures are the primary tool Congress uses to incentivize energy-related investments. However, such incentives do not work for tax-exempt entities — including public power utilities, Ditto pointed out in the letter.
“That means public power utilities are effectively locked out of owning such facilities – and explains why 80 percent of the nation’s (non-hydropower) renewable energy generating capacity is owned by merchant generators,” Ditto said in the letter.
The GREEN Act “addresses this inequity by allowing for the direct payment of energy production and investment tax credits and carbon capture tax credits to any entity that owns the project. This would remove the financial disincentive for public power utilities to own such facilities and would allow the full value of these credits to pay for additional investment or be passed on to our 49 million customers,” she said.
A summary of the bill is available here.
APPA Encourages Members To Reach Out To Lawmakers In Support Of Financial Aid Bill
June 26, 2020
by Paul Ciampoli
APPA News Director
Posted June 26, 2020
The American Public Power Association is urging its member utilities to reach out to their congressional delegation in support of legislation that would provide direct COVID-19 pandemic-related aid for public power utilities.
Past legislation has provided aid that will help public power at the margins, such as Low Income Home Energy Assistance Program (LIHEAP) funding increases to help customers pay their bills, Coronavirus Relief Funds to state and local governments, and assistance in paying unemployment benefits for laid off workers.
But APPA now estimates that public power utilities will lose up to $5 billion in revenue due to pandemic-related declines in load and customer arrearages.
APPA recently urged its member utilities to take steps to educate lawmakers on the issue and to ask the lawmakers to join in signing a letter in support of public power being circulated by House Energy and Commerce Committee member Doris Matsui, D-Calif.
The due date for signing onto the letter has been extended to July 2.
Board of Colorado Springs Utilities OKs Plan That Will Close Coal Plants, Expand Renewables
June 26, 2020
by Paul Ciampoli
APPA News Director
Posted June 26, 2020
The board of Colorado Springs Utilities on June 26 signed off on a plan under which the public power utility will decommission its coal plants by 2030, expand renewable energy and storage and reduce its carbon emissions by 80% by 2030.
The plan calls for grid modernization, integration of more cost-effective renewable energy and incorporation of new technologies like energy storage. Noncarbon resources such as wind and energy storage will replace the generation from the utility’s last coal-fired plant, the Ray Nixon Power Plant, which will be decommissioned no later than 2030.
To enable the decommissioning of the Martin Drake Power Plant no later than 2023, temporary natural gas generators will be placed at the site to ensure system reliability, Colorado Springs Utilities said. Once new transmission projects are complete in the coming years, generation will no longer be needed in downtown Colorado Springs and these units will be relocated.
The plan is aligned with the utility’s Energy Vision, Colorado Springs Utilities noted.
“My goal from this planning process was to develop an energy future that provides the most value to our customers; one that is resilient, reliable, cost-effective and environmentally sustainable,” said Colorado Springs Utilities CEO Aram Benyamin. “Today’s decision sets the stage for a brighter, sustainable future for generations to come.”
Colorado Springs Utilities said that through the utility’s sustainable energy plan, it will:
* Commit to its community with industry-leading reliability and resiliency and support the economic growth of the region;
* Benefit customers by maintaining competitive and affordable rates and advance energy efficiency;
* Reduce carbon emissions at least 80% by 2030 and 90% by 2050;
* Increase renewable energy and incorporate storage resources;
* Decommission all coal generation by 2030 and reduce reliance on fossil fuels; and
* Integrate new technologies responsibly by modernizing its grid and partner with its customers to create distributed energy resources throughout the community.
Benyamin said that the growth of the utility’s energy efficiency programs will be key to success. The utility’s customers are motivated to change the way they use energy in their homes and businesses as determined through public input and surveys, Colorado Springs Utilities noted.
A skilled workforce will be required for this energy transformation, Benyamin said. “As we look to the future, training opportunities will be available and transition plans will provide employees new and exciting opportunities. That is a benefit of a four-service, community-owned utility,” he said.
Colorado Springs Utilities said that the plan was largely delivered by utility employees who built comprehensive financial and technical analyses and took into consideration public input, growth forecasts for the city and future environmental regulations.
Commercial And Industrial Companies Purchase Record Amount of U.S. Wind Power
June 25, 2020
by Taelor Bentley
APPA News
Posted June 25, 2020
Commercial and industrial companies bought 4,447 megawatts (MW) of U.S. wind capacity last year, setting a new record for annual procurements and bringing total corporate agreements for wind power to 16,857 MW, according to the first Wind Powers American Business report from the American Wind Energy Association (AWEA).
More than 140 companies have purchased U.S. wind energy. Google is the top corporate wind energy purchaser in the U.S., having contracted for 2,397 MW. Facebook is the second largest purchaser with 1,459 MW, followed by Walmart, AT&T, and Microsoft.
Walmart also purchased the most wind energy of any company in 2019, signing contracts for three wind projects totaling 541 MW. AT&T was the second largest corporate buyer of wind for the year, contracting 460 MW from two projects. Facebook followed after AT&T with 440 MW.
Eighteen first-time buyers of wind entered the market last year. McDonald’s, Sprint, Ford Motor Company, Crown Holdings, and Gap were the leading first-time buyers of wind in 2019. McDonald’s became the first quick service restaurant company to buy wind energy, having purchased 220 MW. This led McDonald’s to land sixth in wind purchases for the year and into the top 20 for overall contracted capacity.
Before 2015, technology and retail companies made up nearly 80 percent of corporate wind energy purchases. Now the types of companies buying wind are diversifying. Today, technology and retail account for 53 percent of purchases. Wind energy purchases in the retail, food and beverage, and telecommunications sectors have increased significantly in the past few years.
The past six years have seen a large amount of growth for corporate wind purchases, with total contracts rising from fewer than 800 MW at the end of 2013 to over 16,800 MW at the end of 2019. Economics has been a major factor for this growth, AWEA said.
Wind is now the lowest-cost source of electricity generation in many parts of the country, thanks to costs declining more than 70 percent since 2009, AWEA said.
AWEA said that while corporate wind purchases have grown significantly in recent years, it is still a fairly new market and represents a large opportunity for future growth. Today, Fortune 1000 companies only source 5 percent of their electricity needs from renewables, it noted.
Utilities, individuals and businesses looking to reduce their respective carbon footprints buy renewable energy certificates. This is a green power procurement strategy used by electricity consumers to decrease the cost of their renewable electricity use, while also substantiating renewable electricity use and carbon footprint reduction claims.
The AWEA report is available for download here.
Austin Energy Shifts To Virtual Inspections For Green Building Program
June 25, 2020
by Peter Maloney
APPA News
Posted June 25, 2020
The onset of COVID-19 quarantine restrictions prompted Austin Energy to use virtual inspections for its green building program.
“We have rated 170 homes in May and 152 in April,” Catherine Lee Doar, utility strategist at Austin Energy, said. “That is almost one-third of our typical annual production in just two months.”
The ratings are based on sustainability criteria that include items such as energy-, water-, and materials conservation as well as occupant and environmental health.
Texas did not impose restrictions on construction activity during the COVID-19 lockdown, so “our customers have been going full speed,” Doar said.
“I am sure we will continue to do virtual inspections” after COVID-19 restrictions are eased, she said. People will likely be working from home more often, and virtual tours save time and reduce pollution because inspectors do not have to drive in Austin’s heavy traffic, she said.
While the rating measures can be applied during the design and building of new or major remodeling projects, the vast majority of the work the Austin Energy Green Building team does is with contractors and developers engaged in new construction. The virtual tours are essential for residential ratings, Doar said.
The Austin Energy Green Building program evaluates the sustainability of buildings and awards a rating, on a scale of one to five stars, based on a point system of required and voluntary sustainability measures. The program groups buildings into one of three categories: commercial, multifamily and residential.
In a typical year, the Austin Energy Green Building program rates about 25% of permitted houses in the City of Austin. The program rates buildings in Austin as well as in the surrounding counties, but the developers hire contractors to conduct inspections in areas not served by Austin Energy.
“A large part of the ratings we do result from developer agreements with the City of Austin,” Doar said. Many of the people applying for ratings are doing so to fulfill a requirement for a minimum standard qualification as an affordable housing development or as a tradeoff for a zoning variance, she explained.
Since the green building program began in 1991, Austin Energy has rated 16,771 single family homes, 182 multi-family properties with a total of 29,900 dwelling units, and 331 commercial projects including 10,582 dwelling units.
Between the utility’s 2007 fiscal year, when Austin Energy first started measuring impact toward the newly adopted City of Austin Climate Protection Plan, and FY 2019, the program has realized rating savings of 58.7 MW and 156,739 MWh.
The rules and criteria Austin Energy develops for the green building program also find their way into other aspects of the municipal government. When the city revised its rules to require that 50% of construction waste is recycled, they used information on the green building rated projects’ success to develop the new rules. The utility also worked with the city’s fire department when they were drawing up a new Wildland Urban Interface ordinance.
In 1991, Austin Energy, with the help of a grant from the Department of Energy, developed the first residential rating system in the United States. In 1995, a checklist for commercial buildings was added and in 1998 multi-family ratings were added.
Many cities have since followed suit. Austin Energy also advised on the standards set by the more widely known LEED (Leadership in Energy and Environmental Design) program.
Austin Energy updates its green building program criteria every three years generally in conjunction with the release of new building codes.
“We spent the last 18 months developing the new 2020 ratings, which were released in May, and now we are adding innovation guides,” Doar said. The innovation guides encourage customers to come up with solutions that are not in our ratings, she explained.
Alameda Municipal Power’s Budget Is Approved With No Rate Changes
June 23, 2020
by Taelor Bentley
APPA News
Posted June 23, 2020
The city of Alameda, California’s Public Utilities Board (PUB) recently approved Alameda Municipal Power’s (AMP) budget of approximately $65 million with no rate increases for customers.
Throughout the 2021 fiscal year, which begins July 1, 2020, customers will see no change in the electric rates they pay.
AMP noted that its budget reflects the priorities set by the board through its adopted strategic plan and the annual budget workshop held in April 2020
Due to the utility’s strong financial outlook, the board decided not to raise electric rates during a time when AMP customers are facing economic hardships caused by COVID-19.
AMP is projecting an increase in purchased power costs, transmission costs, and other operating expenses such as labor and strategic plan initiatives. As presented at the Board’s annual budget workshop in April, the increased costs will be paid out of AMP’s existing reserves.
Major initiatives for the 2021 fiscal year include powering new construction projects at Alameda Point, replacing substation breakers, and moving forward with the undergrounding program to bury overhead utility lines.
Since AMP is a community-owned and locally operated electric system, the utility does not make a profit on rates. The revenue from electric sales goes toward operation of the system and then to the community through annual transfers of $5.5 million to the city’s general fund for valuable community services.
AMP rates average 20% less than those of neighboring communities, saving Alamedans a total of $15.5 million. On January 1, 2020, AMP began providing 100% clean energy to all customers.
AMP’s 2021 fiscal year begins on July 1, 2020 and will end June 30, 2021.