Union Ministry of Petroleum and Natural Gas on September 19 informed the “contractor parties (Vedanta, ONGC and Tata Petrodyne) of CB-OS/2 PSC Block that [the] application for extension of PSC filed by contractor has not been accepted. Further, in a separate communication, ONGC has been directed to take control of all data, assets, operations and responsibilities associated with the block in the capacity of government nominee. Accordingly, ONGC is taking over the control of the block,” the State-owned company informed the stock exchanges on Monday.

The directions given to ONGC to continue petroleum operations is a “purely interim measure taken by the government of India to maintain continuity of petroleum operations in public interest and safeguard petroleum reserve until the block is awarded to other party,” the company said.

An offshore block in the west coast, CB-OS/2 block consisting of Lakshmi and Gauri fields is currently producing 3,400 barrels of oil per day and 340000 SCMD of gas. The block was awarded to Cairn Energy India in pre new exploration licensing policy (NELP) PSC in 1998. Subsequent to commercial discovery of oil and gas, PML was granted in 2002. Cairn Energy in which the Vedanta Group acquired a majority stake in 2011 was subsequently merged with the Group.

Vedanta, through Cairn Energy, had a 40 stake in the block, while ONGC holds 50% interest in the asset, with the remaining 10% with Tata Petrodyne, a company that has been acquired by Invenire Energy.

https://www.thehindu.com/business/ongc-takes-control-of-cambay-basin-block/article70081754.ece/amp/

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The new pipeline, made from a proprietary composite, has the potential to reduce the carbon footprint of infrastructure projects compared to traditional materials, with its enhanced durability and efficiency expected to lead to long-term operational improvements. 

Initial off-grid testing is underway at Gas Networks Ireland’s Network Innovation Centre in Dublin, in partnership with Murphy International.

The controlled environment allows engineers to rigorously evaluate the pipeline’s safety, integrity, and performance. 

With the results from the first phase of the pilot project expected in late 2026, this initial phase will help determine if the technology is suitable for broader deployment across the national network.

According to Bobby Gleeson, chief operations officer at Gas Networks Ireland, the trial is part of the company’s commitment to innovation and future-proofing the network.

“By working with international partners like Purapipe, we can explore new technologies that could enhance the resilience of our network, reduce emissions, and ensure Ireland is ready to safely transport renewable gases such as hydrogen,” Gleeson said in a statement.

Jesper Steen, CEO of Purapipe International, added that the project highlights the potential of the company’s technology to create more efficient and environmentally friendly infrastructure.

The initiative is part of Gas Networks Ireland’s larger innovation program, which includes connecting biomethane producers and conducting hydrogen blending trials, all aimed at supporting Ireland’s transition to a low-carbon economy.

https://www.pipeline-journal.net/news/gas-networks-ireland-tests-new-pipeline-future-hydrogen-transition

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Prakob Phiencharoen, Krungsri Head of Corporate and Investment Banking Group, said: “Krungsri is honoured to support PE LNG, the operator of LMPT-2, a strategic energy infrastructure project which not only enhances Thailand’s energy security but also aligns with the government’s policy to drive the energy transition toward a cleaner and more sustainable energy. As a strategic transition fuel, natural gas plays a key role in the shift from fossil fuels to renewable energy, enabling Thailand to move forward with a stable and sustainable energy transition while maintaining energy security and economic stability. This financial support reinforces Krungsri’s long-term partnership with PTT Group and EGAT Group and reaffirms our commitment to becoming a leading bank for sustainability.”

Somchai Ramart, Managing Director, PE LNG Co. Ltd, added: “On behalf of PE LNG, I would like to express our gratitude to Krungsri for providing long-term loan support. This collaboration reflects the strong relationship among PTT Group, EGAT Group, and Krungsri, in supporting energy security and sustainable growth for Thailand.”

Pattaralada Sa-ngasang, Chief Financial Officer, PTT Public Co. Ltd, commented: “The long-term loan facility secured from Krungsri reaffirmed the unwavering confidence and steadfast support to PTT Group’s business. PE LNG will use this funding to repay its existing loan from PTT, enabling PTT to reinvest in strategic initiatives. This move reinforces PTT Group’s commitment to energy security in alignment with PTT vision, while promoting sustainable growth in harmony with Thai society.”

Somchit Dansriprasert, Assistant Governor – Finance, Electricity Generating Authority of Thailand, concluded: “EGAT is delighted and honoured to participate in today’s loan agreement signing ceremony, which reflects strong relationship and close collaboration between our organisations. This partnership is instrumental in advancing business development and strengthening the nation’s energy capabilities.”

https://www.lngindustry.com/liquid-natural-gas/30092025/krungsri-supports-long-term-financing-for-pe-lng/

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The integration of gas produced from the Aseng field represents the third phase of Equatorial Guinea’s Gas Mega Hub (GMH) initiative – a bold strategy that leverages Equatorial Guinea’s existing infrastructure to monetize regional gas resources.

 “The Aseng Gas Project will provide a reliable supply of LNG to global markets while serving as a catalyst for advancing strategic developments such as the Punta Europa complex,” said Antonio Oburu Ondo, Minister of Hydrocarbons and Mining Development of Equatorial Guinea. “In addition, it will enhance national and regional energy security, support clean cooking initiatives and drive economic growth through a sustainable energy supply.”

Equatorial Guinea’s GMH has been a focal point of regional cooperation since its inception. The initiative seeks to aggregate stranded or associated gas resources from domestic fields and neighboring countries, processing them through existing infrastructure at Punta Europa. By doing so, the country is transforming potential flared or underutilized resources into export revenue, domestic power and industrial growth. In recent years, the government has signed a series of agreements aimed at expanding the scope of the hub. Partnerships with international operators have allowed Equatorial Guinea to process gas from the Alen Field and other regional assets. The Aseng Gas Project adds further momentum, with Chevron consolidating its position as a strategic partner committed to the long-term success of the initiative.

Chevron’s agreement follows key milestones in Equatorial Guinea’s gas market. Notably, ConocoPhillips exports its first cargo from the Punta Europe facility in June 2025, representing a critical step towards advancing the GMH initiative. The Aseng Gas Project represents a cornerstone for the next phase of the country’s energy development. By combining strategic partnerships, progressive reforms and visionary infrastructure planning, Equatorial Guinea is demonstrating how gas can serve as both an export revenue generator and a catalyst for broad-based economic transformation. As the GMH advances, the country is solidifying its reputation as a model for African energy development – one where resource monetization, investor confidence, and sustainable growth converge.

Building on this momentum and to reinforce its attractiveness as an investment destination, the government is undertaking comprehensive regulatory reforms. The Hydrocarbons Law, Tax Law, Labor Law and the Special Economic Zones framework are all under review, reflecting a deliberate effort to create a modern, transparent, and competitive environment for investors. These reforms will not only strengthen Equatorial Guinea’s credibility as a reliable partner but also lay the foundation for sustained project development across the oil and gas value chain. The reforms complement a drive by the Ministry of Hydrocarbons and Mining Development to attract new investment across the market. The country is preparing to launch its 2026 licensing round, featuring key assets that will support the country’s production goals. By working closely with foreign operators, introducing new investment prospects and revisiting its regulatory environment, Equatorial Guinea is positioning itself for long-term growth.

https://www.worldoil.com/news/2025/9/30/equatorial-guinea-boosts-lng-production-with-chevron-aseng-agreement/

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Following the submission of the readiness letter on 2 September 2025, and FERC’s subsequent confirmation, this milestone accelerates Argent LNG’s path toward construction and operation, positioning the project to deliver reliable US energy to global markets by 2030.

The FERC pre-filing process, under Docket No. PF25-11, initiates formal collaboration with FERC, federal and state agencies, local regulators, and community stakeholders. This phase enables early environmental reviews, engineering advancements, permitting coordination, and transparent engagement to ensure the project upholds the highest standards of safety, efficiency, and environmental responsibility.

 “Our acceptance into the FERC pre-filing process under Docket No. PF25-11 is a pivotal step toward realising Argent LNG’s vision as a premier global LNG supplier,” said Jonathan Bass, Chairman and CEO of Argent LNG. “Designed for speed, efficiency, and performance, this project leverages modular technology and partnerships with industry leaders like Baker Hughes, Honeywell UOP, ABB, and GTT to strengthen US energy security while creating significant economic opportunities for Louisiana.”

Located on a 900-acre site under a 90-year lease at Port Fourchon, the terminal benefits from uncongested deepwater access, proximity to low-nitrogen feed-gas pipelines, and the port’s resilient energy infrastructure. Once operational, Argent LNG will be among North America’s largest and most competitive LNG ex-port facilities, supplying cost-effective American natural gas to key markets in Europe, Africa, South Asia, and South America.

 “Port Fourchon is the heart of America’s offshore energy industry, and Argent LNG’s project under Docket No. PF25-11 marks a transformative step forward,” added Chett Chiasson, Executive Director of Port Fourchon. “With our deepwater access, robust infrastructure, and skilled workforce, this project will position Fourchon as a global LNG export hub, driving economic growth and innovation in our region.”

https://www.lngindustry.com/liquid-natural-gas/30092025/argent-lng-accepted-into-ferc-pre-filing-process/

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If its backers decide to proceed with investment, Ksi Lisims LNG will have a capacity of 12 million metric tons a year. That would make it the second-largest export facility in Canada, after the first phase of LNG Canada — a mega-project backed by Shell Plc that started shipping gas to Asia in June.

“Ksi Lisims LNG is exactly the kind of development Canada’s new government is championing, advancing and approving,” Energy Minister Tim Hodgson said in a statement on X. “This approval sends a clear signal: Canada is open for business, and committed to the long-term strength of our responsible, low-carbon export and natural gas sectors.”

Earlier in September, Carney launched a Major Projects Office designed to expedite developments deemed to be in the national interest. The second phase of LNG Canada — which would double its capacity — was on the list of its first five projects.

Read More: Shell LNG Plant Wins Place on Carney’s Favored Projects List

Houston-based Western LNG has received financial backing from asset management giant Blackstone. Alberta-based Rockies LNG is a group of Western Canadian energy companies including Birchcliff Energy Ltd, Tourmaline Oil Corp. and Whitecap Resources Inc.

Representatives for the Nisga’a Nation, Rockies LNG and Western LNG didn’t respond to requests for comment outside of ordinary business hours.

https://www.bloomberg.com/news/articles/2025-09-16/canada-approves-blackstone-backed-west-coast-lng-export-project

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The agreement will also include initial terms for a 20-year heads of agreement (HoA) for 1 million metric tons per annum (mtpa) of LNG offtake on a free-on-board basis, which will be the first announced HoA for Alaska LNG, Glenfarne said.

The agreement will also include initial terms for POSCO to supply a significant portion of the steel required for Alaska LNG’s 807-mile, 42-inch pressurized natural gas pipeline. The Alaska LNG pipeline will connect Southcentral Alaska and the Alaska LNG export terminal with Alaska’s vast, stranded natural gas resources on the North Slope, the company said.

Alaska LNG is a joint venture between Glenfarne, majority owner and lead developer of Alaska LNG, and the state-owned Alaska Gasline Development Corporation. POSCO is the largest sales representative of Korea’s largest steel producer POSCO Group and a major Korean LNG importer, according to the release.

The Alaska LNG project consists of a pipeline capable of transporting enough natural gas to meet both Alaska’s domestic needs and supply the full 20-mtpa Alaska LNG export terminal in Nikiski, Alaska, Glenfarne stated.

The pipeline will be built in two independent, financially viable phases. Phase one will deliver natural gas approximately 765 miles from the North Slope to the Anchorage region, and phase two includes the Alaska LNG facility, approximately 42 miles of pipeline under Cook Inlet, and pipeline compression equipment.

The company said it is working with Worley to complete the final engineering for the domestic portion of the Alaska LNG pipeline and targeting a year-end final investment decision.

Glenfarne CEO Brendan Duval said, “POSCO’s participation in Alaska LNG adds tremendous momentum as we drive this signature North American LNG project forward at a rapid tempo. This agreement includes critical project components and demonstrates global support for unlocking some of the most strategically located LNG in the world. Korea is a valued target market for Alaska LNG and we greatly appreciate POSCO’s engagement as we advance Alaska LNG”.

Glenfarne Alaska LNG President Adam Prestidge said, “POSCO is one of the world’s foremost steel companies, a leading LNG importer in one of Alaska LNG’s most important markets, and now a significant partner in Alaska LNG. POSCO’s involvement underscores the project’s strategic, geographic, and economic competitive advantages as we rapidly progress toward a final investment decision on the Alaska LNG pipeline”.

Glenfarne said its permitted North American LNG portfolio totals 32.8 mtpa of capacity under development in Alaska, Texas and Louisiana.

Last week, Japan’s JERA Co Inc signed a letter of intent with Glenfarne for the offtake of 1 million mtpa of liquefied natural gas (LNG) from the Alaska LNG project. The potential purchase will be for 20 years on a free-on-board basis, according to a joint statement.

https://www.rigzone.com/news/glenfarne_to_partner_with_koreas_posco_for_alaska_lng-15-sep-2025-181800-article/

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But energy experts speaking to RFE/RL expressed doubts about the project’s future, pointing out that key details—such as the price of gas, export volumes, and who will bear the construction costs—remain unresolved.

Erica Downs, a senior researcher at Columbia University’s Center on Global Energy Policy, said: “The legally binding memorandum is not a supply contract, and therefore does not mean the project has received the green light. It creates the impression of progress, but it is not a done deal yet.”

The latest agreement in Beijing seemed to be just one step in ongoing negotiations over the ambitious pipeline, which aims to carry gas from Russia’s Yamal Peninsula to northern China via eastern Mongolia.

Since Russia’s full-scale invasion of Ukraine in 2022 and the loss of its key European energy market, Beijing’s leverage in these talks has only grown. China appears to be biding its time to see whether the Kremlin will offer attractive concessions on prices and volumes, as well as how the project fits into its complex rivalry with the United States.

Downs added: “China is simply postponing a decision until later, to see whether it will actually need this pipeline. If Beijing secures low prices and flexibility on supply volumes, the project could be appealing as an insurance policy. If not, it has alternatives.”

Does China Need “Power of Siberia-2”?

For Moscow, the need is clear: the 2,600-kilometer pipeline would offset part of the European market it lost after the war. For China, however, the options are abundant.

With negotiations dragging on for years, Beijing pursued a diversification strategy in gas imports to avoid reliance on a single supplier. Russia is already China’s largest pipeline gas supplier through the “Power of Siberia-1” line, which went online in 2019 under a $400 billion, 30-year deal. Russia has also become China’s third-largest supplier of liquefied natural gas (LNG) after Australia and Qatar.

At the same time, Beijing has reduced import dependency by boosting domestic oil and gas production and massively expanding renewables, with Chinese companies becoming global leaders in solar power and electric vehicles.

As a result, demand for imported gas has fallen and is expected to keep declining over the next decade, reducing the need for “Power of Siberia-2,” which could transport 50 billion cubic meters annually. Beijing could instead rely on modest capacity increases in existing pipelines with Russia—something Miller also announced in Beijing—rather than build a new line.

Joseph Webster, a senior fellow at the Atlantic Council, told RFE/RL: “Even in the best-case scenario, the project won’t start before 2030. That means five more years of technological progress in renewables and batteries, which will further reduce the need for the pipeline.”

Adding to the uncertainty, Beijing has yet to confirm Miller’s announcement, with Chinese state media remaining largely silent, merely echoing Russian and international reports. After Xi met Russian President Vladimir Putin and Mongolian President Ukhnaagiin Khurelsukh in Beijing, Chinese media only quoted Xi calling for a focus on “physical connectivity” among the three countries.

What Could Make the Project a Reality?

Benjamin Schmitt, a researcher at the University of Pennsylvania and fellow at the Center for European Policy Analysis (CEPA), argued that the project’s commercial logic is weak, calling Miller’s remarks mere “theater” from the Kremlin to showcase close cooperation with Beijing.

 “Beijing doesn’t need this pipeline, but it also doesn’t see a reason to oppose it publicly,” Schmitt said.

Two factors, however, could shift the equation: significant Russian concessions on pricing and volumes, or changing geopolitical conditions for China.

On pricing, Miller said gas would be cheaper than Gazprom charges European buyers due to the pipeline’s route and distance, but offered no details. Reports suggest China has demanded prices close to Russia’s heavily subsidized domestic levels and wants to commit to buying only half of the pipeline’s capacity (25 billion cubic meters annually) rather than the usual 80% for such projects.

With low prices and flexible commitments, the pipeline could become appealing as an energy-security measure—especially amid renewed tensions in the Strait of Hormuz, a vital chokepoint for Chinese LNG shipments, and a deepening trade war with the United States, the world’s largest LNG supplier.

China has already halted U.S. LNG imports since February, and access to cheap Russian gas strengthens its hand in renegotiating LNG contracts, many of which expire in the 2030s.

For now, however, Beijing and Moscow must first overcome the long-standing deadlock that has stalled “Power of Siberia-2.”

 “All we’ve seen so far is political messaging, not a real project,” Schmitt concluded.

https://www.economies.com/commodities/natural-gas-news/what-does-the-%E2%80%9Cpower-of-siberia-2%E2%80%9D-gas-pipeline-project-between-russia-and-china-mean%20-47332

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The entire hydrogen supply chain will operate wholly within Hong Kong. This includes hydrogen extraction from gas produced at Towngas’s Tai Po Gas Production Plant, green hydrogen converted from biogas collected at the Tseung Kwan O landfill, through to local gas compression, storage and transport, culminating in local consumption.

Two tonnes of hydrogen will be supplied daily in the initial phase. This will be enough for the basic needs of 14 local construction sites.

https://asian-power.com/news/towngas-and-linde-hko-ink-hydrogen-supply-chain-deal

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Germany will eliminate the strict EU definition of green hydrogen in favour of a more flexible, technology-neutral approach, as part of a sweeping energy policy reset unveiled by the Ministry for Economic Affairs and Energy. In a ten-point plan released this week, the government announced that the current RFNBO (Renewable Fuels of Non-Biological Origin) classification—used to determine eligibility for hydrogen subsidies under EU rules—will no longer be used in domestic support schemes. “Overly complex requirements — such as the strict definition of ‘green hydrogen’ at the EU level — will be eliminated and replaced with pragmatic criteria,” the policy states. “Low-carbon hydrogen will be treated equally.”

Energy Minister Katherina Reiche underscored the need for “pragmatism and realism” as Germany adjusts its climate and energy targets to balance affordability, industrial competitiveness, and grid reliability. While the country still aims for 80% renewable electricity by 2030 and climate neutrality by 2045, the report concedes that its goal of 10GW domestic hydrogen electrolyser capacity by 2030 will not be met. Instead, Berlin will pursue a “technology-open” framework that includes low-carbon hydrogen from sources like nuclear power or fossil fuels with carbon capture. Grid transmission expansion alone is projected to cost €440 billion [$470bn] by 2045, with an additional €235 billion [$251bn] needed for distribution networks.

Alongside the hydrogen shift, Germany will also phase out fixed feed-in tariffs for new renewable projects, transitioning instead to market-based mechanisms such as Contracts for Difference (CfDs). The feed-in scheme, which costs taxpayers €16 billion [$17.2bn] annually, is viewed as unsustainable. Capacity-based grid charges, regional bonuses, and pooling of cable infrastructure were also proposed to manage surpluses and grid bottlenecks. Industry groups including BDI, VCI, and VKU broadly welcomed the plans, with the VKU calling for “political will and speed” in implementing the changes. The BEE renewable power association warned, however, that while targets remain achievable, support must not be withdrawn abruptly.

https://fuelcellsworks.com/2025/09/15/energy-policy/germany-to-ditch-rfnbo-label-in-hydrogen-policy-overhaul-pledges-equal-support-for-low-carbon-h

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The project spans some 4,000 dunams (1,000 acres or 400 hectares) in the al-Hur desert area of Karbala, southwest of Baghdad. Tens of thousands of solar panels have been installed in rows across the site.

Nasser Karim al-Sudani, head of the national team for solar energy projects in the Iraqi prime minister’s office, said another plant under construction in Babil province will add 225 megawatts, while a 1,000-megawatt project is also set to begin in the southern province of Basra.

“These projects are part of a larger vision to account for a portion of Iraq’s electricity needs using large-scale solar power plants that could help ease the electricity crisis while also reducing the negative environmental impact of gas emissions,” Al Jazeera reported.

Deputy Minister of Electricity Adel Karim said Iraq has solar projects with a combined capacity of 12,500 megawatts either being implemented, in the approval stage, or under negotiation. Excluding the semi-autonomous northern Kurdistan region, the projects could supply up to 20 percent of Iraq’s overall electricity demand, according to the official.

Despite being rich in oil and gas resources, Iraq has struggled with electricity shortages for decades, largely due to war, corruption, and mismanagement. According to Al Jazeera, nationwide power consumption peaked at nearly 55,000 megawatts this summer, with temperatures soaring above 50 degrees Celsius (122 degrees Fahrenheit) in parts of the country.

By contrast, Karim said Iraq currently produces about 28,000 megawatts, including nearly 8,000 megawatts from natural gas imported from Iran and channelled to Iraqi power plants.

However, those imports have faced recurring disruptions, particularly due to unilateral US sanctions imposed on Tehran. In March, Washington ended a sanctions waiver that had allowed Iraq to directly purchase electricity from Iran, though another waiver remains in place permitting the purchase of Iranian natural gas for Iraqi power stations.

Iran itself has been grappling with severe energy shortages, further affecting its export capacity to Iraq, Al Jazeera reported.

https://www.awazthevoice.in/world-news/iraq-to-inaugurate-first-industrial-scale-solar-plant-in-karbala-41745.html

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“We don’t view renewables as direct replacements for oil and gas, but as strategic complements within a broader, multi-source energy ecosystem”, Al Aufi said. “Our vision is not to abandon oil and gas, but to diversify energy sources”.

The minister emphasised that while fossil fuels remain central to the global economy, Oman is pursuing a dual track: deploying advanced technologies to ensure efficiency and sustainability in hydrocarbons, while accelerating green hydrogen and renewable energy projects.

Oman has taken concrete steps to advance green hydrogen, establishing Hydrom as the national coordinating body and earmarking strategic land blocks for production and export. Multiple agreements have been signed with global companies and investors; and policy frameworks are being aligned with international market standards.

“Our focus now is on building the transport and export infrastructure, ensuring we have qualified national talent and adjusting regulations to meet global demands”, Al Aufi said. “Naturally, projects of this scale face challenges, but we see them as opportunities”.

Al Aufi stressed the role of Sultan Qaboos University (SQU) as a strategic partner in advancing the sector. A joint committee between the ministry and SQU has been formed to explore research integration, support graduation projects and establish specialised laboratories for energy transition and rare earth mineral studies.

“Reaching net-zero will require sustained R&D investment, particularly in hydrogen, clean gas technologies, carbon capture and storage; and industrial waste recycling”, he said.

This year, the ministry identified promising copper and chromium reserves in Al Sharqiyah North Governorate under new concession agreements, while Petroleum Development Oman continues to assess the commercial viability of fresh oil and gas finds in Block 6. In renewables, high-potential wind sites have been evaluated for development with local and international partners.

Al Aufi urged stronger cooperation between academics and industry professionals, highlighting the complementary role of theory and practice. “Knowledge that isn’t applied stays trapped on paper; exploration that lacks scientific grounding risks wasting resources”, he said. “The greatest discoveries always start with an idea, followed by study — and end in achievement”.

https://www.omanobserver.om/ampArticle/1176884

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However, an analysis conducted by Always On Energy Research (AOER) found Ascend Analytics’ preferred zero-emissions by 2040 scenario, the “Optimized 100” scenario, hereafter referred to as the “OT100” scenario, would lead to higher costs than using natural gas or nuclear power to meet Colorado’s energy needs and cause massive rolling blackouts.

AOER found that the true cost of the OT100 scenario is an additional $114.3 billion through 2040 compared to operating the current grid. If these costs are discounted at a six percent discount rate, as was the case in the Ascend analysis, the costs would be $56.6 billion, which is $5 billion higher than the costs reported in the Pathways to Deep Decarbonization Report conducted by Ascend Analytics.

These higher cost estimates are due to several factors, including the fact that AOER estimated additional transmission line expenses, while Ascend did not, and AOER used current capital costs assumptions for new electricity generation facilities, rather than future projections, and more realistic costs for green hydrogen.

OT100 scenario costs explode after 2040, costing an additional $214.6 billion through 2050, due to the high cost of using capital-intensive 12-hour battery storage and green hydrogen as a fuel for power plants to generate electricity during periods of low wind and solar generation.

The OT100 scenario would result in rolling blackouts in 2040 during periods of low wind and solar output when there is not enough electricity stored at battery storage facilities to keep the lights on.

From 2045 through 2049, the blackouts would be massive, with the longest blackout lasting 66 hours and the largest causing 59 percent of the state to suffer from power outages at its peak. These blackouts occur because the state would run out of stored hydrogen needed to generate electricity during low wind and solar output periods and charge the batteries on the system.

These blackouts would be costly to Colorado’s economy. AOER identified a hypothetical nine-day period in 2047 where Colorado would experience 136 hours of blackouts, which would cost Colorado’s economy more than $5.2 billion in lost economic activity.

Using natural gas to replace all but one of Colorado’s coal plants (Comanche 3) and meet the growing demand for power would only cost an additional $9.5 billion through 2040 and $15.3 billion through 2050, compared to operating the current grid. This makes the 2050 cost of using natural gas far less than the $214.6 billion in the OT100 scenario. This Natural Gas scenario would have zero blackouts and cost a fraction of the price of the OT100 scenario.

Colorado could build 15,500 megawatts (MW) of new nuclear power, batteries, and combustion turbine natural gas plants for an additional $73 billion through 2040 and $145.9 billion through 2050, compared to operating the current grid. This means using nuclear power, natural gas, and battery storage will cost $41.3 billion and $68.7 billion less than the cost of the OT100 scenario, respectively, while achieving emissions reductions of 90 percent with zero blackouts.

This plan balances costs and emissions reductions while taking advantage of recent legislation allowing nuclear power to qualify as a “clean” resource for meeting the Centennial State’s decarbonization mandates.

All energy decisions have trade-offs. Using natural gas power plants to meet growing demand will provide the lowest-cost electricity for Colorado families and businesses, but achieve the fewest emissions reductions on a per megawatt hour (MWh) basis. Nuclear can achieve reliable electricity with large reductions in emissions, but at a higher price tag than natural gas. The OT100 scenario is the worst of all worlds, subjecting Coloradans to high prices and rolling blackouts, but it would reduce emissions the most.

https://i2i.org/colorados-green-hydrogen-boondoggle/

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