On July 31, Plant Vogtle Unit 3 entered commercial service, adding 250 MW of emissions-free generation capacity to MEAG Power’s portfolio, an equivalent amount to power an estimated 113,500 homes and businesses. Vogtle Unit 3 is the first newly constructed nuclear unit to enter service in the U.S. in more than 30 years.

“Vogtle Unit 3 entering commercial service is a monumental achievement that reflects the tremendous hard work, dedication and perseverance of thousands of workers on-site, as well as all the current and past employees of MEAG Power and the Unit’s other co-owners, MEAG Power Board members and the countless utility and city government employees of the 49 Participant communities we serve across Georgia,” said MEAG Power President & CEO Jim Fuller.

“Bringing Vogtle Unit 3 to commercial operation – and continuing the work on Unit 4 toward an in-service date later this year or early next year – highlights MEAG Power’s commitment to serving the needs of our Participant communities,” Fuller continued. “Vogtle Units 3 & 4 will provide up to 500 MW of clean energy to our Participant communities for the next 60 to 80 years – providing critical non-emitting power to present and future generations.”

Vogtle Unit 3 passed its final testing July 27 and was declared available for reliable dispatch by Southern Nuclear, which will operate the new units for the Vogtle co-owners: MEAG Power, Georgia Power, Oglethorpe Power and Dalton Utilities. The co-owners then agreed to declare Unit 3 in commercial operation on July 31.

To mark the momentous occasion, the Vogtle co-owners each sent a small delegation to the site for a celebration event the morning of the 31st that included members of the Georgia Public Service Commission. A much larger event is being planned that will include larger delegations from each co-owner and off-taker, along with numerous state and national government officials. MEAG Power will provide further information to Participants when details of the larger event become available.

On July 28, Vogtle Unit 4 received the 103(g) finding from the Nuclear Regulatory Commission (NRC), signifying that the unit has been constructed and will be operated in conformance with the Combined License and NRC regulations. No further NRC findings are necessary in order for Southern Nuclear to load fuel or begin the startup sequence for Unit 4, which is expected to enter commercial operation late this year or early in 2024.

The MEAG Power Annual Meeting is a unique once-a-year opportunity to gather a broad spectrum of Participant elected officials and staff, our business partners and industry expert speakers to discuss the most important areas of our business and the industry. Topics included proposed legislation and the political policy environment that could affect our Participant communities, industry changes, trends and challenges – and strategies for meeting them.

This year’s Annual Meeting offered detailed insight into all of these areas and more, as well as the chance for Participants and MEAG Power staff to renew relationships and share knowledge, and for Participants to perform the vital duty of electing the MEAG Power Board members.

Before the general session on Tuesday, Participant voting delegates elected Albany, Ga., Mayor Pro Tem Chad E. Warbington to fill the Board vacancy resulting from Newnan Mayor L. Keith Brady’s stepping down from the Board after 21 years of service. In addition, Acworth Alderman L. Timothy Houston, Sr., and Monroe businessman Gregory P. Thompson were re-elected to new terms on the Board.

The full program included a detailed update on MEAG Power’s operations and Plant Vogtle from President and CEO Jim Fuller. (See the Plant Vogtle Unit 3 Enters Service article in this issue.) Dr. Roger Pielke, professor of Environmental Studies at the University of Colorado, provided a fascinating look at the Evolving Energy Landscape.

Florida Municipal Power Agency General Manager and CEO Jacob Williams spoke about Florida’s Public Power Outlook and provided a cautionary tale of a lack of diversity in generation portfolios. Andrew Busch, an economic futurist and the former Chief Market Intelligence Officer for the U.S. government, offered a look into what the future may hold for the U.S. economy.

Breakout sessions included a deep dive into Regulatory Challenges in Power Supply, featuring Rob Talley, President, Talley & Associates, Inc., along with MEAG Power Senior Vice President and COO Steve Jackson and Director of Power Generation Michele Jackson.

In addition, Daryl Ingram, ECG Senior Vice President and Chief External Officer, presented a session on economic development. And Samantha Hart and Brynne Gallahue from Milepost led a session on Communicating the Value of Public Power: Educating Kids & Families, featuring Milepost’s Monster Detective Collective program.

After the general session and breakouts on Tuesday, at the evening event both Mark Tanner, Generation Asset Manager at Plant Vogtle, and Tim Turner, Principal Financial Analyst, were presented the President’s Award from Jim Fuller in recognition of their service and dedication to MEAG Power and our Participant communities

The Environmental Protection Agency (EPA) published proposed rules for addressing greenhouse gas (GHG) emissions from fossil fuel-fired electric generating units on May 23, 2023. The rules address existing coal-fired and oil/gas-fired steam power plants, existing large gas-fired combustion turbine power plants and new combustion turbine power plants.

The rules propose sweeping changes to the electricity generation industry within the next 6.5 years, and rely heavily on significant and rapid development of new clean energy infrastructure within the same time frame, supported by trillions of dollars of tax-credit incentives under the Biden Administration’s Inflation Reduction Act. The rules are expected to be finalized in March 2024 and will likely be subject to court challenge.

MEAG Power has worked with our industry trade organizations APPA, LPPC and AFFORD to prepare and submit comments to the EPA on these rules. Also, we’ve prepared our own comments to EPA on how these rules impact our ability to continue to supply low-cost, reliable power to our Participants: click MEAG EPA GHG Comments to view. We have also met with the Georgia Environmental Protection Division (GAEPD) to address our concerns and will continue to meet with other stakeholders to provide our input and concerns.

In addition, MEAG Power is being proactive and evaluating the future options related to Scherer Units 1 and 2. Through the integrated resource plan (IRP) effort, we are evaluating key issues such as what is the likely retirement date, what resources are available to maintain reliability, and are there ways to add certainty into the process. As we wrap up the IRP process later this year, the Participants will be receiving more details on this evaluation.

If finalized as proposed, the rules could have a direct impact on MEAG Power’s ownership share of Plant Scherer Units 1 and 2, as well as a direct impact on new combustion turbine power plants that MEAG may invest in for future power generation needs. And while the Wansley CC combustion turbine units are not considered large gas-fired combustion turbines by EPA under these rules, EPA asserts that they will be addressing the need for GHG rules for all other gas-fired combustion turbine power plants, which will implicate the Wansley CC.

The rules propose essentially four “Best System of Emission Reduction (BSERs)” for reducing GHG emissions from coal-fired power plants: 1) retire prior to Jan. 1, 2032; 2) starting by Jan. 1, 2030, operate at no more than a 20% capacity factor and retire by Jan. 1, 2035; 3) starting by Jan. 1, 2030, co-fire with natural gas at the 40% level and retire by Jan. 1, 2040; and 4) starting by Jan. 1, 2030, capture 90% of the CO₂ in the flue gas, transport it and store it in a certified storage facility.

This fourth BSER – called Carbon Capture and Sequestration, or CCS – is currently operating on only one small coal-fired power plant in Canada, and was subsidized by the Canadian government. Based on this experience and other Department of Energy (DOE)-funded engineering and design studies in the U.S., MEAG Power estimates that an investment of upwards of $2.5 billion per Scherer unit could be required to achieve carbon capture. However, capture technology has yet to be demonstrated or proven on units as large as the Scherer units.

In addition to investment in carbon capture, pipelines would need to be built to transport the compressed CO₂ gas to a storage facility. These storage facilities are envisioned by EPA and DOE to be underground geological formations such as seams of a former mine. As with carbon capture, such storage facilities are still unproven and undeveloped.

Scherer Units 1 and 2 will be 50 years old by 2032 and 2034, respectively, and ready for either life extension work or retirement. Retrofitting these units with GHG-emissions technologies by 2030 (for either natural gas co-firing or CCS) will result in stranded investment if MEAG Power decides to retire after 50 years of operation.

For existing large combustion turbine power plants, the rules propose two BSERs: either 1) co-fire with low-GHG hydrogen at the 30% level by Jan. 1, 2032, then increasing to 96% by Jan. 1, 2038, or 2) capture 90% of the CO₂ in the flue gas, transport it and store it in a certified storage facility.

Currently, there are very limited supplies of low-GHG hydrogen, so new electrolysis production facilities powered by renewable energy sources will need to be developed, along with a network of pipes and storage facilities to transport large quantities of hydrogen needed by power generation facilities.

EPA’s assessment of the impact on the cost of generation with low-GHG hydrogen co-firing appears to be based on ideal conditions and is somewhat refuted by data provided in Technical Support Documents that accompanied the proposed rule. Based on data provided, we’ve assessed that the cost of 30% and 96% hydrogen blended fuels could be 3 times and 10 times as much as burning natural gas alone, respectively.

And while the cost of technology for capture of CO₂ gas is less for combustion turbine power plants than for coal-fired power plants, the required investment is still significant and, again, investment would be needed for transport pipelines and storage facilities.

Finally, for new combustion turbine power plants, the rules propose BSERs depending on how the combustion turbine is to be operated. For peaking operation (less than 20% capacity factor), BSER is the combustion of low GHG fuels such as natural gas; for intermediate operation (greater than 20% capacity factor and less than the design efficiency of the turbine (approximately 50% capacity factor), BSER is co-firing low-GHG hydrogen at the 30% level by Jan. 1, 2032; and for base load units (capacity factor greater than design efficiency (approximately 50% capacity factor), BSER is either 1) co-fire with low-GHG hydrogen at the 30% level by Jan. 1, 2032, then increasing to 96% by Jan. 1, 2038, or 2) capture 90% of the CO₂ in the flue gas, transport it and store it in a certified storage facility.

It’s difficult to imagine that the infrastructure required for natural gas co-firing at coal-fired power plants, low-GHG hydrogen co-firing at gas plants, and CCS–even though heavily incentivized through the IRA and thus largely supported by US taxpayers–can be in place to meet the proposed rules’ compliance deadlines, as early as 6.5 years out.

During the 5-year period from 2018 through 2022, 66% of the energy supplied by MEAG Power to its communities was emissions-free, resulting in a 5-year average energy supply emission rate of 412 lb. CO₂/MWH. MEAG Power’s significant investment in forthcoming emissions-free energy from Plant Vogtle Units 3 and 4, and planned transition away from fossil-fueled resources to renewable resources, show the potential for an economic path for MEAG Power to be nearly 90% emissions-free by 2045.

These proposed rules ignore the huge investment our Participants have already made in environmental control systems for Scherer Units 1 and 2, as well as in new emission-free energy from Vogtle Units 3 and 4.

The wild price fluctuations were driven by numerous unprecedented disruptions, including the war in Ukraine and an increased reliance on natural gas to fill the generation deficit as more coal plants are decommissioned and not enough replacement power has yet been added to the grid. In addition, gas pipeline capacity is lagging, coal delivery constraints limited inventories at the remaining coal plants, and severe weather events played a role in the price spikes seen during the year.

The average monthly market price for natural gas was remarkably stable for the period from February 2018 through June 2021, when it starting rising before normalizing again at year-end 2021, as shown in the chart below. In 2022, the market price was as low as about $45 per MWh and as high as about $145 per MWh.

More information about the contributing factors to this instability is helpful in understanding what an atypical year it was. And while 2023 followed that same trend line early on, there may be some relief in sight, according to research by Moody’s Investors Services, a world-renowned analytical and risk management company. However, volatility and risk of extreme pricing events are here to stay.

Non-Weather Factors

After Russia invaded Ukraine, much of Europe came to an abrupt realization that it had become overly dependent on Russian natural gas as its primary fuel source for electricity generation and heating. Some major Western European countries, led by Germany, had forsaken nuclear energy while also moving away from coal in favor of gas and renewable energy. Suddenly, much of Europe was looking for new sources of gas as Russia threatened to cut the supply entirely to countries that opposed its invasion.

Among the markets those countries tapped was the U.S. market, as shipments of liquefied natural gas (LNG) from the U.S. to Europe increased throughout the year. Commodities trading follows market pricing trends, and with European demand skyrocketing, pricing for natural gas in the U.S. market also rose.

At the same time, the demand for natural gas in the U.S. stayed strong, because of the need to fill the generation void left in the wake of ongoing coal plant retirements and limitations on coal deliveries. Despite record additions of solar and wind to the U.S. grid over the past 3-4 years, it’s not sufficient to replace the reduction in coal-fired generation being removed, and the intermittent nature and low capacity factors of solar and wind generation alone aren’t an equitable replacement for the baseload nature of coal facilities. That domestic demand likewise put upward pressure on natural gas prices.

Winter Storm Elliot

Adding to the mix at the end of an already chaotic year were unexpected pipeline distribution issues and yet another unprecedented weather event, Winter Storm Elliot, which wreaked havoc in the market in late December.

With temperatures plummeting over much of the U.S., demand for natural gas greatly increased from both home heating and electricity generation requirements. On Dec. 23, natural gas demand surged to 160 billion cubic feet (Bcf)/day with power demand 45% higher than average and residential/commercial demand 55% higher than average. The massive increase in natural gas demand required the market to utilize over 200 Bcf of natural gas storage during event. Several pipelines issued Force Majeures, limiting capacity deliverability for power generation.

The Southern Balancing Authority (SBA) enacted the Energy Emergency Alert system and issued alerts, escalating to an Energy Emergency Alert Level 2 before returning to normal operations on Dec. 26. MEAG Power enacted our emergency procedure and notified the Participants to take electric load conservation measures. Although not required in the SBA, other utilities did implement load management due to their system conditions.

All resources were available on the MEAG Power peak load hour, which occurred on Dec. 24: 1,786.3 MW. Only one generation resource was not being utilized on the peak hour: One of the Gas Turbines at Wansley 9 was not utilized due to a lack of available pipeline capacity. Plant Addison was dispatched on Fuel Oil for 41 consecutive hours — from the Friday evening peak (Dec. 23) through Sunday morning peak (Christmas day).

The only “silver lining” was the timing of this event. Load requirements were dampened by an estimated 7% compared to a non-holiday weekday, as more people were off work, lessening commercial and industrial demand. In addition, the event lasted about 2 days, which limited the impact.

Natural gas spot pricing averaged $8.49/MMBtu during the peak 5 days (Dec. 23-27), with pipeline capacity pricing averaging $47.17/MMBtu during the same period. Plant Addison was the highest priced unit dispatched, at an estimated price of $285/MWh.

Moody’s Predicts Relief

According to a recent Moody’s Investors Services research note, lower natural gas prices in 2023 will lead to a 35-45% dip in the price of on-peak power in most markets across the United States.

“Natural gas and power price expectations for 2023 have dropped steeply,” the firm said. The unusually warm winter has moderated heating demand and left gas storage facilities with inventories about 21.5% above their historical five-year averages.

“Expected 2023 natural gas prices are around 44% lower than forward market expectations in December,” Moody’s said. That has resulted in 2023 expected power prices more than 40% lower than 2022 in some regions, according to the research note, which cited S&P Global Market Intelligence data.

MEAG Power’s Projections

Although 2023 natural gas and energy market prices are lower, all of the factors contributing to December’s extreme pricing event remain. The energy market is changing from a long market — with excess generation and gas capacity — to a short market as a result of the coal plant retirements and the increased use of gas for energy demands and export.

Being short creates the environment for volatility in the markets whenever extreme weather occurs, or unexpected unit or gas pipeline outages occur. Ensuring that our resource portfolio is diverse and covers the majority of our needs can reduce risk and provide stability in cost during these extreme conditions.

On March 6, Vogtle Unit 3 safely reached initial criticality, a key step during the startup testing sequence in which operators have safely started the nuclear reaction inside the reactor.

A reactor achieves criticality when the nuclear fission reaction becomes self-sustaining. Achieving initial criticality is necessary to continue the startup of the unit in order to generate sufficient heat to produce the steam needed for the production of electricity.

Operators then continued to raise power to support synchronizing the generator to the electric grid and begin producing electricity. This step was achieved on April 1.

Next, operators will continue increasing power through multiple steps, over several weeks, ultimately raising power to 100 percent. Vogtle Unit 3 is projected to be placed in service in the May or June.

Testing has progressed through a series of “modes,” from Mode 6 to Mode 1. Unit 3 has now reached Mode 1. Unit 4 will go through the same testing modes later this year or early in 2024.

Unit 4 Progress Update

Hot functional testing started in late March and marks the last series of major tests for the new nuclear unit ahead of fuel load. Hot functional testing is conducted to verify the successful operation of reactor components and systems together and confirm the reactor is ready for fuel load. As part of the testing, the site team runs Unit 4 plant systems at normal operating pressure and temperature without nuclear fuel.

Nuclear operators are using the heat generated by the unit’s four reactor coolant pumps to sustain the temperature and pressure of plant systems at normal operating levels, and the unit’s main turbine will be raised to normal operating speed using steam from the plant. Operators are also able to exercise and validate procedures as required ahead of fuel load.

Unit 4 is focused on the remaining construction work — primarily electrical — and completions of Inspection, Test, Analyses, Acceptance Criteria (ITAAC) to support the 103g filing – the request to the Nuclear Regulatory Commission (NRC) for permission to load fuel, fuel load and commercial operation.

Another recent milestone for Vogtle Unit 4:

• Cold hydro testing – In early December, Unit 4 completed cold hydro testing, which is required to support the last major test remaining for Unit 4, hot functional testing. Hot functional testing is projected to commence by the end of the first quarter of 2023. Unit 4 is slated to enter commercial operation in the 1st quarter of 2024.Cold hydro testing on Unit 4 confirmed the reactor’s coolant system functions as designed and verified the welds, joints, pipes and other components of the coolant system and associated high-pressure systems do not leak when under pressure. As part of the testing, the reactor coolant system was filled with water and pressurized above-normal operating conditions, then lowered to normal design pressure while comprehensive inspections were conducted to verify the systems meet design standards.

At some point in early 2023, the new nuclear power Unit 3, at Plant Vogtle in Burke County, near Augusta, is expected to come fully online, after years of construction and cost delays. Unit 3, and Unit 4 right behind it, are expected to generate sufficient baseload power generation to power 500,000 homes across Georgia, out of Georgia Power’s 2.7 million customers statewide.

However, due to the growing energy demands of this state, and the massive costs of designing and constructing a nuclear power plant, and then clearing all regulatory hurdles, even an energy giant like Southern Co. has operating and financing partners in a venture this big.

The Vogtle Electric Generating Plant is jointly owned by Georgia Power (45.7%), Oglethorpe Power Corp. (30%), the Municipal Electric Authority of Georgia (MEAG Power – 22.7%), and Dalton Utilities (1.6%). MEAG Power, created in 1975 by an act of the Georgia General Assembly, provides affordable, reliable and competitively priced wholesale electricity generation for 49 communities across Georgia.

The city of Lawrenceville owns and operates both a natural gas and an electric utility, the latter of which is a member of MEAG Power. The service area for our electric utility is 13 square miles, with more than 13,000 metered homes and business customers, and a transmission grid co-owned and maintained by Georgia Power, Jackson EMC, Walton EMC and MEAG Power. On the natural gas side of the ledger, we began service in 1950 after the installation of our first natural gas supply line and head end, and we now have 51,000 customers and 1,500 miles of pipeline reaching across Gwinnett and into Walton and Rockdale counties.

Our utilities are customer- and community-owned, and as a result, invest back heavily in our communities. That payback also comes in quicker customer service response to power outages, and with no shareholders or quarterly dividends (as with a publicly traded utility), our rates have remained stable and well below the national average.

Like most utilities, a decade ago, our primary fuel source was coal. As the industry shifted toward natural gas, so did our consumption. For the past 18 months, as the utility industry has been moving rapidly toward renewable energy sources like wind and solar (both in limited supply in Georgia), we began to focus on the critical need of system resilience and for baseload energy supply which does not create additional carbon emissions.

We made the prudent and obvious choice, several years ago, to make a major investment in new nuclear energy sources. These new AP 1000 reactors, coming online soon [Unit 3 recently reached initial criticality, a key step during the startup testing sequence in which operators have safely started the nuclear reaction inside the reactor], utilize several changes in obvious physical design, such as placing massive water tanks above the reactors, which automatically release hundreds of thousands of gallons of cooling water to flood the reactor chamber and reduce temperatures in the reactor core, if needed.

Georgia is the only state in the nation with new nuclear capacity coming online, although China has several AP 1000 reactors in operation now. And once Vogtle units 3 and 4 are fully operational, the fuel mix for the city of Lawrenceville will be coming 85% from sustainable and non-carbon emission-based sources.

Our climate and planet are warming, and whether or not we believe human behavior and energy consumption are driving all of that shift and increase in global average temperatures, we are doing our part to calm the weather, flatten out those temperature spikes and reduce carbon emissions across metro Atlanta and north Georgia, as well as the neighboring Blue Ridge and Smoky mountains, where a lot of existing weather patterns eventually move our air.

Lawrenceville residents and utility customers will receive clean, green and largely carbon-free electricity. And after construction costs have been covered, ongoing nuclear energy is also the least expensive to generate per kilowatt. Plant Vogtle units 1 and 2 have been safely and affordably generating power since 1987 and 1989, respectively, and are expected to continue operation for potentially decades more to come.

As Georgia appears poised to become a center for the manufacturing and innovation of electric vehicles and battery technology, Plant Vogtle will generate the bulk of both baseload and expanded generation capacity, allowing for further development and population growth in all regions of Georgia. We are proud to play a small part in bringing this green energy source to our customers, while also improving air quality across the state and simultaneously placing Georgia at the forefront of new nuclear energy production.

Editor’s Note: On April 1, Plant Vogtle Unit 3 successfully synchronized and connected to the electric grid, and generated electricity for the first time. Operators will continue to raise reactor power for electricity generation while performing tests at various power levels. The in-service date for Unit 3 is projected during May or June 2023. Additional information on the progress of Vogtle Units 3 & 4 can be found in the Vogtle News article in this issue.

Previous Participant Visionary City winners include Acworth, Covington, Lawrenceville and Moultrie in 2022, Douglas and Griffin in 2021, and Adel, Hogansville, Marietta and Thomasville in 2020.

“GMA is thrilled to once again partner with Georgia Trend to recognize this dynamic group of elected officials, city staff and community leaders responsible for their unique and visionary approaches to bettering their communities,” said GMA Executive Director Larry Hanson. “These cities illustrate how serving and connecting their residents through innovative developments and programming can create positive change throughout Georgia.”

The Visionary Cities are grouped by population: Large (more than 25,000), Medium (5,000 to 24,999) and Small (fewer than 4,999). LaGrange represents the Large category among Visionary Cities, while Camilla and Norcross earned their designations in the Medium category.

Following are details of the civic projects and initiatives that helped each Participant earn the Visionary City designation. Reprinted with permission from Georgia Trend.

Camilla

As it emerged from the COVID pandemic, Camilla’s elected leadership saw a need to invest in the economic future and leadership development of the city’s youth. The result was the Camilla Youth Initiative (CYI), a three-pronged program that offers high school students paying jobs at nonprofit agencies, internships in city offices and a chance to learn first-hand how municipal government functions.

All of this might have been a good idea that the city could not afford, if it were not for ARPA’s federal COVID relief funding. Camilla Mayor Kelvin Owens said the city combined part of its ARPA grant with economic development funds from its own coffers to finance CYI, which has an estimated cost of $200,000 a year.

The Camilla Youth Council forms one element of the program. Elected officials, educators and a school resource officer appoint students to this advisory board, which observes the Camilla City Council and provides feedback on issues of special interest to young people.

Another program element provides meaningful work experience – and $10 to $11 an hour – to participants ages 14 to 19 by funding part-time jobs at nonprofits that partner with the CYI. The Mitchell County School System and the Mitchell County Boys and Girls Club pitched in on this aspect. “The program is designed for these teenagers to work for nonprofits only, so they are not only getting a paycheck, but they are serving the community,” says Owens. The goal for the program launched last fall is to provide a rotation of six months of employment to 16 to 20 students at a time.

Rounding out the CYI is a program that rotates students into internships in various city departments, including the city manager’s office, human resources and public works, to provide experience directly linked to workforce needs.

Norcross

Bees and other pollinators are finding Norcross to be a friendlier place these days, thanks to the Pollinate Norcross campaign. City parks, schoolyards, power easements, even the grounds of Norcross City Hall are being planted with native plants, flowers and shrubs designed to attract pollinators.

Every schoolchild and all adults who follow the news know that pollinators are in trouble, their numbers declining due to development, pesticides and other factors. The city of Norcross decided to do something about the problem in a program that turned out to be low-cost and appealing to a wide swath of the citizenry. The city was designated a Bee City in 2018, part of a national program to promote bee-friendly practices, and Pollinate Norcross grew from there.

“Sustainability and environmental stewardship are cornerstones to the City of Norcross and our continued prosperity. Our goal is to help embed sustainability into the routine practices and procedures of the city as a driver for economic development, cost efficiencies and community health and engagement,” says Norcross Mayor Craig Newton.

In 2021-2022, the program reached nearly 800 residents through school garden groups, after-school programs, community workshops, employee education and community volunteer events. Costs have been modest: approximately $7,000 from the city’s budget and an additional $1,000 in sponsored plants and materials.

The Bee City Committee, the champion of the project, was able to build a relationship with Norcross Elementary and Summerour Middle schools since its goals meshed with the curriculum. Workshops that involved local businesses upped the awareness of the program and created a snowball effect. Master gardeners and garden clubs volunteer time and expertise, as well.

LaGrange

LaGrange is one of those cities that fully grasps the potential public parks hold for community-building, civic engagement and branding. Commitment to its parks was part of the rationale behind the city’s decision to take back capital funding and maintenance of the park system from Troup County in 2021.

“The city felt it was time to take those parks back, breathe new life into them, do renovation projects and potentially some new capital projects,” says Meg Kelsey, LaGrange city manager. “Parks are quality-of-life amenities that attract people to come and live in LaGrange, and for current residents. We want them to have products to enjoy.”

In 2021, the city hired a new parks director and additional staff to help maintain the city’s 15 parks (just over 119 acres combined). That’s important to park-rich LaGrange, where the goal is to link every city park to The Thread, a linear park master-planned to encompass more than 29 miles when completed.

“We want to bring all the parks together and tie our community together so all the neighborhoods in the city can be linked by this amenity,” Kelsey says.

LaGrange uses multiple revenue streams to finance its parks, including the general fund and a dedicated line item in the budget. Many capital improvements are funded by a special-purpose local-option sales tax (SPLOST). The city leveraged American Rescue Plan Act (ARPA) funds to build newly opened Moss and Wood Park, and Kelsey recently submitted a grant application seeking funds for a bike playground the city hopes to build across from a city elementary school.

The next big park project, Ridley Lake, will combine $3 million from a Georgia Outdoor Stewardship Grant and $3 million in city funding. “We think it will be a regional draw for people from other areas to fish, kayak, paddleboard and just enjoy the outdoors,” Kelsey says.

Welcome back to the Ritz-Carlton, Amelia Island!

MEAG Power has hosted at this venue for a number of years, as it allows us to tour the trading floor at The Energy Authority (TEA)—a popular event to learn more about TEA, which plays an important role in MEAG Power’s wholesale service to Participants.

Meeting attire–Business Casual; Evening activities–Dressy Casual