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Global Wind And Solar Pipeline Grows, But Rich Nations Fail To Build Equal Share
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Global Energy Monitor
Feb 10, 2025

Global Wind And Solar Pipeline Grows, But Rich Nations Fail To Build Equal Share

Key points

The pipeline of prospective utility-scale solar and wind capacity grew by a fifth last year, but the world’s richest countries account for only a fraction of new construction, according to a new report from Global Energy Monitor (GEM).  

The Global Solar Power Tracker and Global Wind Power Tracker include all projects that have been announced, entered pre-construction, or are currently under construction for solar capacity over 1 megawatt (MW) and utility-scale wind capacity over 10 MW. 

During 2024, prospective utility-scale solar and wind capacity grew to 4.4 TW. Utility-scale solar and wind are largely equal in their prospective development, with 2 TW and 2.5 TW, respectively. 

China has the largest prospective capacity for both utility-scale solar and wind, with over 1.3 TW — over a quarter of all prospective capacity globally — followed by Brazil (417 gigawatts (GW)), Australia (372 GW), the U.S. (218 GW), and Spain (144 GW). 

India targets adding nearly 130 GW of prospective utility-scale solar and wind capacity in the upcoming years, and 35 GW of these additions will be connected to the grid by March 2025. In the past year, India’s prospective utility-scale solar and wind capacity grew by 50%, signaling a shift in renewables planning. 

But G7 countries, who own a 45% share of global gross domestic product, are currently building just 59 GW of utility-scale solar and wind capacity. This amount is dwarfed by China, which is responsible for more than 70% of current construction on utility-scale solar and wind globally, or over 416 GW.

Meanwhile, outside of China the amount of utility-scale solar and wind capacity under construction remains low, with just 7% of prospective capacity (226 GW) currently being built. Failing to bring renewable projects online could jeopardize the pace and scale necessary for meeting the goal of tripling renewables capacity by 2030 set at COP28.

GEM data included 185 GW of solar and wind farms that were under construction as of December 2023 and designated to become operational before the end of 2024. Globally, only 59% of these projects started producing electricity on time.

Despite their lower share of total capacity, G7 countries are more likely than China and the rest of the world to finish projects on time. About 76% of solar and wind projects in G7 countries became operational within the originally planned time frame. This figure declines to 55% in China and further drops to 52% in other non-G7 countries.

Diren Kocakuşak, Research Analyst for Global Energy Monitor, said, “The growth of wind and solar in the last year is promising, but the world needs to pick up the pace and bring these projects online much faster. Addressing barriers like limitations on the physical grid, permitting bottlenecks, and lack of financing can help bring us closer to tripling renewables capacity and limiting the worst impacts of a changing climate.”

Contact

Diren Kocakuşak

Research Analyst, Global Energy Monitor

[email protected]

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South America Estimated To Add 160 Gw Of Pv By 2034
PV Magazine
South America Estimated To Add 160 Gw Of Pv By 2034From pv magazine LatAm In its latest report on the South American solar PV market, Wood Mackenzie has revealed that the region will add 160 GW of photovoltaic (DC) capacity between 2025 and 2034, driven by diversification efforts, growing energy demand and favorable system economics. Among the key findings in the report: mature markets Brazil and Chile will account for 78% of total regional installations. However, the South American solar PV market is expected to slow as those mature markets stabilize. Regional PV installations are expected to peak in 2024 as small-scale and utility-scale solar additions slow in Brazil. Despite this, growth is expected in emerging markets, such as Colombia or Uruguay. Felix Delgado, Wood Mackenzie’s senior analyst for the power and renewables sector in the Americas, attributes this “cooling” in annual additions “to lagging transmission infrastructure, increased spills, and rising transmission rates for small-scale solar.” Small-scale projects (<5 MW DC) will account for 48% of total construction in the region, as distributed generation plans remain attractive across the continent. Transmission lag and further curtailment hamper growth in mature markets, driving hybridization of solar + storage projects, especially in Brazil and Chile. The economics of solar PV systems will continue to improve, with a projected 42% reduction in regional LCOE for single-axis trackers and fixed-tilt solar PV by 2035. Over the longer term, the report indicates that Brazil, Chile and Colombia are well positioned to capitalize on the growing demand for green hydrogen, further driving solar capacity additions and diversifying the region’s energy landscape. Brazil, the largest market in the region, is experiencing a slowdown in solar additions following recent renewables expansion driven by the expiration of incentives. Specifically, according to the consultancy's forecasts, Brazil will not reach 15 GW this year, and its installation rate will be around 10 GW until 2031, when it will grow again, but without reaching the installation rate recorded in 2024. Large-scale solar energy faces an environment of energy oversupply and delayed transmission infrastructure. Meanwhile, small-scale solar energy faces rising transmission rates, increased import taxes on solar modules, and interconnection disputes between distributors. However, capacity additions will continue to be driven by power purchase agreements (PPAs) in the free market environment and distributed generation installations. Chile, on the other hand, will remain at similar levels except for the years 2026 and 2027, when its installation level will decrease. It also faces similar challenges with curtailment and grid restrictions, pushing the solar PV project pipeline towards hybrid projects. “The transition to solar with storage projects in markets such as Brazil and Chile is a critical development,” Delgado added. “Chile is paving the way for storage adoption in the region and serves as a testing ground highlighting the challenges and solutions available for countries with already high penetration of renewable generation.” The report also highlights the role of direct commercial and industrial buyers in driving capacity growth. In Argentina, the corporate renewable PPA market is allowing buyers to sign US-linked PPAs, acting as the main market scheme driving solar capacity additions. In addition, 99% of the current solar pipeline in Brazil is planned to operate in the free market. Nevertheless, regulated auctions remain critical for emerging markets such as Colombia and Peru. This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.
powerplant
06 March 2025
India’S Solar Additions Could Double To 30 Gw In Fiscal 2025
PV Magazine
India’S Solar Additions Could Double To 30 Gw In Fiscal 2025From pv magazine India A new report by SBICAPS projects India’s annual solar capacity addition to double to 30 GW in fiscal 2025 against 15 GW in fiscal 2024. The report states the deployment pace will further improve in fiscal 2026 and fiscal 2027, leading to significant spike in module demand. It projects PV deployment for fiscal 2026 at 42 GW and for fiscal 2027 at 46 GW, with residential rooftop solar driving expansion. Annual module demand is forecast to increase from 50-55 GW in fiscal 2025 to 105 GW in fiscal 2027. [The calculation assumes DC/AC overloading of 1.2-1.4, effective utilization to nameplate capacity ratio of 55% to 65%.] The report says PV installation projections are likely to be met with moderate PPA-PSA gap reduction, PM Surya Ghar Muft Bijlee Yojana (PM-SGMBY) completion by FY28, and enhanced RPO [renewable energy purchase obligation] compliance. Timely scheme (especially PM-KUSUM) and project execution could further augment demand. On the other hand, land constraints, ALCM [Approved List of Cell Manufacturers] implementation, and restrictive state net metering policies pose as deterrents. To continue reading, please visit our pv magazine India website. The report says the integration drive needs to kick into next gear to meet ALCM and DCR goals. [DCR solar panels are panels made in India with domestically manufactured cells, meeting the domestic content requirement as stipulated for PV installations under PM Surya Ghar Muft Bijlee Yojana, PM KUSUM and CPSU Phase II Scheme.] “Despite integration factor (cell/module capacity ratio) likely improving from 32% to 65%, more than half of India’s cell requirements will continue to be imported in FY27, even if all capacities promised come on board,” states the report. DCR module prices will maintain a premium due to PM-SGMBY-driven demand exceeding cell capacity additions and escalating regulatory stringency on DCR. As cell production expands, wafer and ingot manufacturing emerge as the next strategic imperative, with the government expected to allocate $ 1 billion in incentives to foster domestic ecosystem development. This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.
powerplant
06 March 2025
China Huadian Begins Working On 19.24 Gw Wind-Solar-Coal-Storage Project
PV Magazine
China Huadian Begins Working On 19.24 Gw Wind-Solar-Coal-Storage ProjectChina Huadian Corp. has begun construction on China’s largest and highest-altitude integrated energy base in Golmud, Qinghai province. The project, with a total investment of about CNY 80 billion ($11 billion), will feature the country’s highest share of renewable capacity in a hybrid energy system designed to export power across provinces. The project will have a total installed capacity of 19.24 GW, with wind and solar making up 85% of that capacity. The wind and photovoltaic installations will cover about 3,000 square kilometers of arid, saline, and rocky terrain. While Huadian has not disclosed the exact breakdown, an industry source told pv magazine that the renewable capacity will exceed 14 GW. To balance fluctuations from intermittent renewables, the project will include a large-scale battery energy storage system (BESS), typically 10-15% of the renewable capacity, along with four 660 MW ultra-supercritical coal units approved by the Qinghai Development and Reform Commission. These plants will feature indirect air-cooling, wet flue gas desulfurization, and denitrification systems, supported by a dedicated railway line and a 750 kV substation. The thermal component is expected to cost CNY 11.5 billion. State Grid Corp. of China is developing an ±800 kV ultra-high-voltage (UHV) direct current transmission line, the “Qinghai-Guangxi UHV DC Project,” to transmit power with an 8 GW capacity. The project will annually supply 36.5 TWh of clean energy to Guangxi, alleviating regional power shortages and meeting 14% of the province's 2024 electricity needs. Huadian said it aims to complete the project by 2027, following a synchronized development approach that integrates renewable generation, dispatchable capacity, and transmission infrastructure. The energy base will also serve as a national research platform, focusing on integrated energy systems, multi-energy complementarity, and digital applications in large-scale energy hubs. Additional research will target desertification control and ecological restoration, supporting China’s sustainability and environmental goals. This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.
powerplant
05 March 2025
Brookfield Divests 1.6Gw Solar And Wind Portfolio To Gentari In India
Power Technology
Brookfield Divests 1.6Gw Solar And Wind Portfolio To Gentari In IndiaBrookfield Asset Management has announced the completion of a divesture comprising 1.6GW of Indian solar and wind assets to Gentari Renewables India. The transaction marks Brookfield’s first full-cycle portfolio monetisation in India’s renewable energy sector, as reported by the Business Standard. The gold standard of business intelligence. Find out more Gentari Renewables India is fully owned by Gentari International Renewables, a subsidiary of Malaysia’s Gentari, owned by Petroliam Nasional Berhad. The sale, structured in two phases, has already seen the completion of the first phase, involving 1GW of operating assets. The assets include 21 special purpose vehicles (SPVs) that own and operate renewable power plants, including two projects under construction, and the holding companies of some SPVs. Brookfield managing director and head of renewable power and transition for South Asia and the Middle East, Nawal Saini, stated: “Our focus is on delivering value to our stakeholders while advancing the country’s energy transition. Monetising a part of our portfolio demonstrates our ability to create and realise value. “This transaction with Gentari reinforces investor confidence and unlocks new opportunities for further capital allocation in the country.” In June 2024, the International Finance Corporation (IFC) announced an investment commitment of $105m in Brookfield’s 550MW solar power project in Bikaner, Rajasthan. The investment will be made via long-term non-convertible debentures, with funds specifically assigned to the project’s special purpose vehicles. In September, United Arab Emirates-based clean energy company Masdar announced its intention to acquire Saeta Yield from Brookfield Renewable and its institutional partners for an enterprise value of $1.4bn. The acquisition includes a portfolio of 745MW, primarily consisting of wind assets, with 538MW in Spain and 144MW in Portugal, and 63MW of solar photovoltaic assets in Spain in addition to a 1.6GW development pipeline.
powerplant
05 March 2025
Lg&E, Ku Propose $3.7B Power Buildout: 1.3 Gw Of New Gas Plants, $153M Coal Unit Upgrade
POWER NEWS
Lg&E, Ku Propose $3.7B Power Buildout: 1.3 Gw Of New Gas Plants, $153M Coal Unit UpgradePPL subsidiaries Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU) have proposed to upgrade environmental controls at a 1974-built coal unit, build two new gas-fired power plants at a combined cost of $2.8 billion, and add 400 MW of battery storage. The measures seek to significantly boost the companies’ capacity to ready the region for a dramatic surge in power demand. LG&E and KU on Feb. 28 requested approval for a certificate of public convenience and necessity (CPCN) from the Kentucky Public Service Commission (KPSC) for the additional generation capacity and battery storage. The commission is expected to rule on the regulatory permit request by November 2025.    The companies’ joint application proposes four major projects. The companies said the massive $3.7 billion capacity expansion is required to meet a sharp increase in annual energy requirements in Kentucky—from 32,808 GWh in 2025 to 48,129 GWh in 2032. Seasonal peak demand could rise from 6,230 MW (summer) and 6,146 MW (winter) in 2025 to 8,034 MW (summer) and 7,930 MW (winter) in 2032, the filing suggests. Nearly all projected load growth can be attributed to economic development from emerging industries, the companies added. While traditional load (non-economic development) will decline slightly in the short term, with only modest growth expected in the late 2030s, at least 1.8 GW of additional load could come from large-scale, high-load-factor data centers, and another 250 MW from the BlueOval SK Battery Park, which a Ford-SK joint venture is developing in Hardin County. Other economic development projects, including automotive and industrial expansion, could add another 40 MW. LG&E and KU’s estimates are partly rooted in a Kentucky General Assembly measure enacted under HB8 in 2024 that includes tax incentives to attract data centers to Jefferson County. “The General Assembly finds and declares that the authority granted in Sections 37 to 41 and the purposes accomplished are proper governmental and public purposes for which public moneys may be expended, and that the inducement of the location of data center projects within the Commonwealth is of paramount importance to the economic well-being of the Commonwealth.” the legislation declares. On Jan. 16, LG&E announced it secured its first hyperscale data center customer: A joint venture between PowerHouse Data Centers, an American Real Estate Partners (AREP) division, and Louisville-based Poe Companies will develop a 402-MW data center campus in Louisville, Jefferson County, with the first 130 MW coming online by October 2026. The site will be supported by a new LG&E switch station, scheduled for completion in September 2026, and a dedicated on-site substation to ensure reliable power delivery. In testimony filed with the CPCN request, John Bevington, senior director of Business and Economic Development for PPL Services Co., said LG&E and KU are fielding more than 8 GW of economic development load potential, based on a list of  prospective customers. “More than 6,000 MW is related to data centers,” he said. “A primary driver of data center development is the availability of power. As noted above, without certainty of available generation and transmission capacity, it will be difficult to fulfill the initiatives of the General Assembly and Governor Beshear in marketing Kentucky to data centers and other large load customers.” Bevington noted Kentucky’s location and resources, including an abundant water supply, make the state attractive to data centers. “Additionally, Kentucky is located in close proximity to major data centers in neighboring states. Based on my discussions with data center developers, I understand there are advantages in latency and redundancy to locating data centers near other data centers. Land in Kentucky is also relatively inexpensive when compared with other markets where data center development has been thriving and reaching a point of market saturation,” he said. On Friday, LG&E and KU underscored the significance of the new power projects. “This is an exciting time for Kentucky as the interest in locating new and expanding businesses continues to grow,” said John R. Crockett III, LG&E and KU president and PPL chief development officer on Friday. “These investments in our system will allow us to continue serving our customers safely and reliably while meeting our regulatory obligation and the growing economic interest in the commonwealth—all while maintaining affordability.” Mill Creek Generating Station in Louisville, Kentucky. Courtesy: GE Vernova LG&E and KU’s existing dispatchable generation resources are approximately 7,264 MW in 2025, with coal still a majority of its portfolio. To comply with environmental requirements and energy efficiency measures, as of December 2024, the companies had retired approximately 1,500 MW of coal power since 2010. At the end of 2024, the companies retired Mill Creek 1, a 300-MW coal-fired power unit. Mill Creek 2 is slated for retirement after 2027. Retirements are also planned for two simple-cycle gas-fired plants: the 47-MW Haefling 1-2 in 2026, and 47-MW Paddy’s Run 12 in 2026. However, in a pivotal decision in November 2023, the Kentucky Public Service Commission denied the companies’ proposed retirement of KU’s 486-MW Ghent Unit 2, citing a need for additional clarity regarding environmental compliance regulations. The KPSC had previously approved other major generation changes, including a 640-MW NGCC at Mill Creek, a 125-MW battery system, and multiple solar projects. In August 2024, the companies announced they would replace two aging coal generation units at Mill Creek—a combined 600 MW—with a 645-MW GE Vernova hydrogen-ready 7HA.03 gas turbine.  At the end of 2024, LG&E and KU had a combined owned generating capacity of 7,264 MW (LG&E: 2,466 MW, KU: 4,798 MW). The companies’ 2024 electricity generation by fuel source is reflected in the table above. Source: PPL (10-K, Feb. 2025) KU’s Ghent 2 is part of the larger 2-GW, four-unit Ghent Generating Station, the largest coal-fired power plant in the LG&E and KU system. The plant, which began commercial operation in 1973, uses subcritical coal combustion technology, and is already equipped with electrostatic precipitators and flue gas desulfurization (FGD) systems on all units to control emissions. A $600 million FGD installation project completed in 2009 equipped all four units with scrubbers. New 662-foot chimneys were built for Units 1 and 4, including monitoring systems to measure air quality and ensure regulatory compliance. The $152 million project to install an SCR system will ensure Ghent 2 will control its nitrogen oxide emissions and comply with the federal National Ambient Air Quality Standards (NAAQS) for ozone, the filing suggests.  As Philip Imber, director of Environmental Compliance at PPL Services, explained, Kentucky is no longer subject to the 2023 Good Neighbor Rule due to legal challenges and subsequent court rulings that invalidated the U.S. Environmental Protection Agency’s (EPA’s) disapproval of Kentucky’s State Implementation Plan (SIP). In December 2024, the U.S. Court of Appeals for the Sixth Circuit vacated the EPA’s denial of Kentucky’s SIP and remanded it to the agency, effectively blocking the application of the Good Neighbor Plan in the state. The decision has meant that Kentucky reverts to compliance under the earlier Revised Cross-State Air Pollution Rule (CSAPR) Update, rather than the more stringent requirements imposed by the 2023 Good Neighbor Plan, Imber said. However, the EPA “remains obligated to drive compliance with the 2015 Ozone NAAQS, and adding an SCR to Ghent 2 is an obvious target for such compliance efforts. Thus, adding a Ghent 2 SCR now will help ensure the ongoing year-round availability of Ghent 2, which is part of the least-cost resource plan,” he said. Beyond the Good Neighbor Plan, the EPA’s regulatory framework includes additional rules that could affect coal-fired generation. Most notable are the Greenhouse Gas (GHG) Rule and the Effluent Limitation Guidelines (ELG). The GHG Rule, finalized in May 2024 under Clean Air Act Sections 111(b) and 111(d), imposes strict emissions limitations on coal plants, requiring them to implement carbon capture by set deadlines. However, the rule’s future is uncertain owing to legal and political opposition, including directives from the Trump administration aimed at rescinding it. “President Trump’s day-one executive orders, coupled with his campaign commitment to undo the GHG Rule, cast serious doubt on the near-term need to comply with the GHG Rule,” he said. Likewise, the 2024 ELG Rule imposes stringent zero-discharge requirements for FGD wastewater, bottom ash transport water, and combustion residual leachate. Compliance deadlines extend to 2029, but facilities that cease coal operations by 2034 can qualify for exemptions. The rule builds on previous ELG standards but significantly tightens discharge limitations. “As with the GHG Rule, it is reasonably possible and perhaps likely that the Trump administration will seek to rescind the 2024 ELG standards. Importantly,  although the EPA had the legal authority to implement the 2024 ELG standards, it was not obligated to implement revised standards,” said Imber. “Indeed, I am unaware of any reason the 7 EPA could not rescind the 2024 ELG standards.” —Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).
powerplant
04 March 2025
Distributed Generation Surpasses 37 Gw In Brazil Amid Concerns Over Curtailment
PV Magazine
Distributed Generation Surpasses 37 Gw In Brazil Amid Concerns Over CurtailmentFrom pv magazine Brazil Brazil has reached 37 GW of installed capacity in distributed generation (DG). The Brazilian Association of Distributed Generation (ABGD) projects a 20% growth in installed DG capacity in 2025, which represents more than BRL 25 billion in private investments and the generation of more than 100 thousand new jobs. Most of the installed DG capacity is concentrated in residences (18.18 GW), followed by commercial establishments (10.63 GW), rural facilities (5.09 GW), industries (2.67 GW) and public institutions (0.41 GW). In the state ranking, São Paulo leads with 5.33 GW, followed by Minas Gerais (4.63 GW), Paraná (3.30 GW), Rio Grande do Sul (3.29 GW) and Mato Grosso (2.39 GW). The growth of DG, however, has been accompanied by debates about its integration into the electrical system. There are allegations about the impact on the operation of the National Interconnected System (SIN), especially in relation to curtailment – ​​generation cuts due to limitations in the transmission infrastructure. The ABGD emphasizes that DG operates in a decentralized manner and aligned with consumer demand, not depending on transmission networks to deliver energy. “DG is the only form of generation that is born tied to the real demand of the end consumer, helping to mitigate problems in the electrical system. The real reason for generation cuts in Brazil is the lack of planning and the structural limitations of the transmission networks, problems that have no relation to distributed generation,” said ABGD President Carlos Evangelista. He emphasized that attributing curtailment costs to DG masks strategic challenges faced by centralized generation. “DG does not depend on the transmission network to transport the energy it produces. On the contrary, one of the main virtues of DG is precisely that it generates electricity close to consumption, reducing the need for investments in transmission infrastructure and relieving the burden on the electrical system. DG also improves grid efficiency, reducing losses and reinforcing the quality of supply,” Evangelista added. The ONS's Medium-Term National Grid Operation Plan (PAR/PEL) indicates that, by 2029, DG capacity should reach around 50 GW, becoming the second largest source of electricity generation in the country, behind only hydroelectric power. Considering micro and mini distributed generation and Type III plants — commonly installed close to the load, connected to the distribution grid and totaling 19.8 GW — there is a total of 53 GW, which represents 22% of the installed capacity in Brazil that is not supervised in real time and cannot be controlled by the ONS. The distribution network may start to inject energy into the transmission network in some areas, in a larger-scale “flow reversal.” “Minas Gerais, Rio Grande do Sul, Mato Grosso and Piauí stand out as those that presented the largest number of substations capable of operating with the flow of active power in the direction of the distribution networks to the transmission system,” states PAR/PEL. For this reason, ONS advocates that distribution system operators, that is, energy distribution concessionaires, assume a strategic role with greater control over these distributed energy resources and greater integration with the operation of the transmission network. The operator also reinforces the need to increase investments in dynamic voltage control equipment, such as synchronous compensators. According to ONS, with the expected growth of DG in the coming years, by 2029 it may be necessary to cut up to 40 GW of centralized solar and wind generation during the times of day when the systems are generating. The ONS estimates that MMGD will generate around 18.35 GW in 2024, considering the midday period, while the forecast for this generation in 2029 is approximately 37 GW. In view of this scenario, large generators have suggested that distributed generation also share in the generation cuts. New DG projects have been receiving recommendations from concessionaires to inject energy into the grid at night. This could create opportunities for the implementation of batteries, but the high tax burden and the lack of clarity regarding the remuneration for services rendered keep the technology expensive. This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.
powerplant
04 March 2025
Texas Electric Co-Op Teams Up With Tesla For Utility-Scale Virtual Power Plant
RENEWABLE ENERGY WORLD NEWS
Texas Electric Co-Op Teams Up With Tesla For Utility-Scale Virtual Power PlantGuadalupe Valley Electric Cooperative (GVEC) announced a partnership with Tesla, making the cooperative the first in Texas to participate with Tesla as a utility-scale virtual power plant resource in the Electric Reliability Council of Texas (ERCOT) Aggregated Distributed Energy Resource (ADER) pilot program. Through the ADER program, the integration of distributed energy resources (DERs), such as battery storage systems and other controllable devices, is being explored as dispatchable generation into the Texas wholesale energy market to improve year-round grid stability and reliability. Recent updates show the ADER program has registered approximately 17 MW in generation from companies like Tesla with their residential battery customers. GVEC is a cooperative that delivers electricity, internet, AC/Heating, solar and battery, and electrician services. The cooperative currently serves over 130,000 customers covering a 3,200 square mile span of South-Central Texas. With “growing consumer interest” in alternative energy sources, GVEC expanded its offerings to become a certified installer of Tesla battery systems in 2019. “Consumer generated energy is quickly becoming an important resource for the Texas wholesale electricity market,” said GVEC board president Gary Birdwell. “Cooperation between GVEC and Tesla, two prominent market participants, uniting to utilize their strengths for the common goal of building stability and resiliency of the grid is a strategic move. Creative solutions such as this will make a real difference in meeting the constantly rising demand and maintaining affordability for all Texas utility customers.” GVEC members are incentivized to join the program through rebates provided upfront upon registration in its Peak-Time Payback (PTP) program, then an ongoing annual rebate each year of participation. Through PTP, during times of high demand or as regularly scheduled throughout the year, GVEC, in conjunction with Tesla, can access up to 70% of the total capacity of each battery system to discharge back into the home reducing the home’s reliance on the grid, or send electricity directly to the grid once local demand is met. Discharge events will not take place during extreme weather conditions or outage situations, GVEC noted. “Tesla has been a major player in the ADER pilot program since its inception,” said GVEC general manager and CEO Darren Schauer. “They are a highly visible company with the capabilities and expertise to meet the robust participation requirements. As an additional benefit, GVEC has the ability to offer ancillary services directly onto the market. This means GVEC Powerwall members can now support the needs of the Texas grid while also creating a new revenue stream to reinforce the long-term financial strength of their member-owned cooperative.” In 2023, ERCOT began the first phase of the Aggregate Distributed Energy Resource (ADER) pilot project by launching two virtual power plants (VPP). To qualify for the pilot project, an ADER had to be able to produce at least 100 kW, and each individual device in the ADER had to be less than 1 MW. The average residential battery is about 5 kW. In February 2024, ERCOT launched the second phase of the pilot project. ERCOT said the overall pilot project will likely extend for at least another two years. Texas’ energy demand is anticipated to keep growing, and if generation and transmission buildout doesn’t keep up, the state could face a capacity shortfall that threatens system reliability. A recent study released by the Texans for Local Energy Freedom Coalition, The Value of Residential Solar in Texas, argues the state is not fully taking advantage of its rooftop solar potential, and changing course could mitigate some of the capacity shortfall. The report, commissioned by the Texas Solar Energy Society (TXSES), argues that the overall value of distributed solar in ERCOT will be about 27¢/kWh, with 15¢/kWh realized in the generation, transmission, and distribution system and 12¢/kWh realized through air pollutant and emission reduction benefits. However, with “rapid” additions of solar in Electric Reliability Council of Texas (ERCOT) territory in 2023, often co-located with storage, the shape of the daily electricity supply has noticeably changed, according to recent analysis from the U.S. Energy Information Administration (EIA).
powerplant
04 March 2025