Energy News Beat
The electrification of heating is a hot topic: the idea is that heat pumps are going to save the planet, make American homes more efficient and save American households money. Plenty of people agree since heat pumps are selling like hot cakes, but does this all boil down to something worthwhile or is it just hot air?
The post Here’s what heat pumps mean for America: Free air conditioners for the poor appeared first on Energy News Beat.
Energy News Beat
Portuguese oil and gas company Galp has announced the discovery of light oil at the Mopane-1X well offshore Namibia, bringing the total number of oil and gas discoveries to six since 2022.
Namibia has reached another milestone in its exploration journey, with Portuguese multinational energy corporation Galp announcing the discovery of light oil at the Mopane-1X exploration project – located in Petroleum Exploration License (PEL) 83 in the Orange Basin. Representing Namibia’s sixth commercial oil and gas discovery – following hydrocarbon discoveries made by TotalEnergies in PEL 56 and Shell in PEL 39 – the Galp discovery further elevates Namibia’s status as a frontier oil and gas market.
Galp reports that the discovery, made in reservoir-bearing sands of high quality, prompts the company to initiate an assessment of the reserves’ commercial viability through a planned drill stem test in the coming weeks. Recognizing the immense potential of Mopane-1X and Namibia’s Orange Basin for world-class discoveries, Galp and its partners – Namibia’s national oil company (NOC) NAMCOR and Custos Energy – are extending their drilling campaign with upcoming activities in the Mopane-2X well.
The African Energy Chamber (AEC), as the voice of the African energy sector, congratulates Galp and its partners for the discovery. This achievement represents a substantial stride in positioning Namibia as a major energy player in Africa and on the global stage, aligning with recent successes in the country’s upstream sector.
The AEC believes that the discovery is a massive milestone for Namibia, Galp, NAMCOR and its partners on PEL 83. In addition to fortifying local and regional energy security, the AEC foresees Galp’s discovery and Namibia’s burgeoning oil and gas industry playing a pivotal role in enhancing the country’s economic strength and gross domestic product growth. This will be achieved through bolstering energy market resilience, creating job opportunities, and expanding export revenue. Notably, with approximately 45% of the Namibia’s population currently lacking access to electricity, discoveries like Galp’s will be instrumental in realizing the government’s objective of universal energy access by 2040 while ensuring the region has access to affordable energy.
“This is an example of an African country, the ministry and the NOC working hand-in-hand to enable explorers. These discoveries do not just happen because of the geology itself, but credit should be given to the hard work that has been put in by the Namibian government through its ministry and NOC in constantly and consistently keeping a stable environment, encouraging companies, listening to investors, and giving investors the confidence to pour in money and get massive discoveries. Namibia’s example should be a lesson to many African states when it comes to exploration,” stated NJ Ayuk, the Executive Chairman of the AEC.
The discovery of light oil at Mopane-1X further demonstrates the commercial potential of offshore oil and gas in Africa. With six discoveries made in less than two years, Namibia is a testament to the role and future oil and gas plays in Africa. The AEC is optimistic about Namibia’s hydrocarbon future and urges exploration companies and government to work together in navigating the legal, environmental and investment requirements to fast-track the development of these critical resources.
“We stand with Namibia in its endeavor to explore and exploit oil and gas resources to address energy security issues and maximize industrialization. Namibia’s oil and gas resources will be key to expanding economic growth, driving diversification and advancing socioeconomic development, both in Namibia and across the southern African region,” concluded Ayuk.
The post Galp Hits Oil at Mopane-1X: Big Win for Exploration, Jobs and More Energy Investments in Namibia appeared first on Energy News Beat.
Energy News Beat
A study of clean energy alternatives led by the Pueblo Innovative Energy Solutions Advisory Committee (PIESAC) found that only advanced nuclear could make the community “whole” from the losses it will suffer from the closure of the last unit at the Comanche coal-fired power plant in Pueblo, Colorado, while ensuring a just transition.
PIESAC, a diverse 11-member committee of Pueblo community leaders, was assembled by Xcel Energy-Colorado to evaluate and recommend future clean energy generation strategies to replace the final coal-fired unit at Comanche as the company transitions to delivering 100% carbon-free energy by 2050 to its Colorado customers and communities. The plant, some 110 miles (177 km) south of Denver, includes three coal units: unit 1 (335 MWe) retired in 2022, unit 2 (315 MWe) is due to retire by the end of 2025, and unit 3 (750 MWe) is to retire by 1 January 2031 at the latest.
The closure of Comanche 3 – which had originally been expected to operate until 2070 – will have “devastating impacts” on the economy of Pueblo unless the community, Xcel Energy and other stakeholders begin planning now for its replacement, the study says. The 2031 closure will cost Pueblo more than USD845 million in taxes which fund schools, fire districts, libraries, conservation districts as well as the operations of the city and the county. “It is urgent that we reduce climate changing emissions, but we must also provide a path forward for coal communities such as Pueblo that have relied on highly paid skilled jobs and tax payments from coal plants,” the study finds.
PIESAC’s newly released report is the culmination of ten months’ work to evaluate clean energy generation strategies to replace the existing coal units at the Comanche Generation Station while ensuring a “just transition” so that “coal communities should not only be no worse off with the closure of coal facilities but also replace the coal generation with high paying and highly skilled jobs and lost tax base so that coal communities have an opportunity to prosper, grow, and reimagine their local economies”.
The committee looked at a “large number” of generation possibilities for Pueblo that could be available by 2034, including various energy storage and battery technologies, hydrogen as a primary fuel, the construction of additional solar facilities, combined cycle gas with carbon capture, and advanced nuclear. Of these, it recommends that only the latter two – a new gas plant with carbon capture or advanced nuclear – should be considered for Pueblo.
A new gas plant with carbon capture would provide 20 to 25 jobs with a salary range of USD80,000-120,000 and tax payments of approximately USD16.5 million a year, but advanced nuclear would provide 200 to 300 jobs with a salary range of USD60,000-200,000 and tax payments of USD95.29 million a year, it notes: “Of all of the technologies that we studied, only advanced nuclear generation will make Pueblo whole and also provide a path to prosperity.”
Coal accounted for some 27% of Xcel Energy-Colorado’s 2022 generation mix, with natural gas supplying around 31% and wind 36%. The company is aiming for 81% of its generation to be carbon free by 2030 and 100% carbon free by 2050.
Xcel Energy-Colorado is part of Minneapolis-headquartered Xcel Energy, serving eight Western and Midwestern US states from a generating portfolio which includes the Monticello and Prairie Island nuclear power plants in Minnesota.
Source: World-nuclear-news.org
ENB Top News
ENB
Energy Dashboard
ENB Podcast
ENB Substack
The post Colorado study recommends nuclear to replace coal plant appeared first on Energy News Beat.
Energy News Beat
LAUNCESTON, Australia, Jan 11 (Reuters) – China’s status as the colossus of renewable energy is set to be cemented in the next five years, with the world’s second-biggest economy adding more capacity than the rest of globe combined.
The International Energy Agency said in its Renewables 2023 report, released on Thursday, that China will account for 56% of renewable energy capacity additions in the 2023-28 period.
China is expected to increase renewable capacity by 2,060 gigawatts (GW) in the forecast period, while the rest of the world will add 1,574 GW, the IEA data showed.
The European Union and the United States are the next biggest builders of renewable energy, at 429 GW and 337 GW respectively.
It’s worth noting, though, that India is forecast to add 203 GW of renewable capacity, while the 11 countries that make up the Association of Southeast Asian Nations are expected to boost capacity by a combined 63 GW.
This shows that Asia is the dominant force in renewable energy deployment, largely because of supportive policies and the availability of capital and offtake agreements for the electricity produced.
The IEA report also sheds light on just how China is coming to be the leading force in renewable energy, with supportive policies driving a huge increase in the expected capacity additions from the previous report in December 2022.
“China accounts for almost 90% of the global upward forecast revision, consisting mainly of solar photovoltaic (PV). In fact, its solar PV manufacturing capabilities have almost doubled since last year, creating a global supply glut,” the IEA said.
“This has reduced local module prices by nearly 50% from January to December 2023, increasing the economic attractiveness of both utility-scale and distributed solar PV projects,” the report said.
The IEA said the lower costs are making utility-scale solar more attractive in China than coal- and gas-fired generation.
China has also clarified the rules around its green certificates, which will provide additional revenues for solar and wind developers.
China is also expected to increase its gap over the rest of the world in deploying renewables, even as the United States and countries in Europe boost policy and financial support.
China has several advantages that sometimes aren’t available in other countries.
These include being able to approve and build transmission grids and renewable energy projects more quickly than in countries where democratic processes and the objection of local communities can constrain infrastructure development.
China can also finance projects more easily than in countries where money is lent or raised on the basis of expected returns rather than on policy priorities.
The country’s manufacturing base also allows for economies of scale in producing PV panels and wind turbines, and this is further supported by China’s efforts over the previous decades to build a leading position in the supply and processing of minerals such as copper, nickel and lithium.
There is also a caveat to China’s rapid build-out of renewable capacity because at the same time it is still adding substantial coal-fired generation.
China is the world’s biggest coal producer and importer and has more coal-fired capacity under construction than the rest of the world combined.
China is building 136.24 GW of coal-fired generation, and has another 255.5 GW at the announced, pre-permit or permitted stage, according to data compiled by the Global Energy Monitor.
This is 67% of the global coal-fired capacity currently under construction and 72% of the potential new capacity.
China already accounts for 53% of the world’s 2,095 GW of operating coal-fired generating capacity, a share likely to increase in coming years as more coal plants are retired in the developed world.
When taking China’s renewable deployment together with its ongoing coal-fired construction, a more nuanced view emerges of the country’s energy profile.
It’s clear that renewables are increasing their share of China’s power generation, but it’s equally clear coal-fired power is going to be around for decades to come, and that if China does meet its goal of net-zero emissions by 2060, it will largely be achieved in the final years prior to the deadline.
The opinions expressed here are those of the author, a columnist for Reuters.
The post China dominates renewable energy and coal power forecasts appeared first on Energy News Beat.
Energy News Beat
There is more demand of U.S. natural gas now and it is expected to growth more by 2025, said Williams Companies (WMB) CEO Alan Armstrong.
The Henry Hub Natural Gas Spot Price reached $8.81 per million Btu in August 2022, but last year prices declined about 60% and moved down below the cost of marginal production, said Armstrong during a CNBC interview.
“We’re starting to see that supply taper off now,” he said. “At the same time, we’re starting to see demand pick up pretty strongly against the fundamentals — on a weather normalized basis.”
In 2023, demand for natural gas (NYSEARCA:UNG), (NG1:COM) was up by about 6%. LNG (liquified natural gas) growth is expected to pick up “a little bit” in 2024 and there will be “a big pick-up” in 2025, as a lot of new facilities come on, he said.
According to the Energy Information Administration, 20 new natural gas power plants are expected to come online with a total capacity of 7.7 gigawatts.
“You can see quite a bit of contango in the market with prices picking up by about 25% from 2024 to 2025,” said Armstrong. “So, producers are holding their breath right now through those periods of low prices.”
The EIA’s Annual Energy Outlook 2023 report said that U.S. natural gas production is expected to increase by 15% — to 42.1T cubic feet — and LNG exports are expected to increase by 152% — to 10T cubic feet — by 2050.
“Since 2010, we’ve seen total natural gas demand pick up by 60%, but pipeline infrastructure only 30%,” said Armstrong, adding that storage to back up intermittent renewals only increased by 12%.
ENB Top News
ENB
Energy Dashboard
ENB Podcast
ENB Substack
The post Demand for natural gas will increase significantly by 2025 – Williams Co. appeared first on Energy News Beat.
Energy News Beat
The post The down side to wind power appeared first on Energy News Beat.
Energy News Beat
Russia was on pace for a second year of record oil drilling in 2023, further evidence of the nation’s resilience to Western sanctions.
The boom in activity came alongside a recovery in both the volume and value of Russia’s oil exports, a stark illustration of how the country’s fossil fuel industry has been a crucial source of funds for President Vladimir Putin’s war in Ukraine, which is about to enter its third year.
“Russia is substantially more independent in its oil-field services than generally appreciated,” said Ronald Smith, an oil and gas analyst at Moscow-based BCS Global Markets.
In the first 11 months of 2023, Russia drilled oil production wells with a total depth of 28,100 kilometers, according to industry data seen by Bloomberg. That’s on track to beat the previous year’s post-Soviet record.
The frenetic pace of drilling — amid fairly static production — also offers an indication of some long-term problems that may be building up for Russia’s oil sector as a result of Moscow’s international isolation. The industry is working harder to maintain output from its oldest wells, while new projects that would sustain production in the coming decades must adapt to the country’s changed circumstances.
For 2023 as a whole, Russia’s production drilling is set to top 30,000 kilometers, according to analysts at intelligence firm Kpler and Moscow-based consultant Yakov & Partners. The increase comes despite Western countries’ pressure on the country’s energy industry, which is a key source of funds for the Kremlin’s war in Ukraine. The sector has been the target of sanctions ranging from import bans and price caps, to prohibitions on the export of technology.
Last year, the US sanctioned dozens of companies that produce drilling equipment and develop new production techniques, aiming “to limit Russia’s future extractive capabilities.” The European Union in 2022 imposed “comprehensive exports restriction on equipment, technology and services for the energy industry in Russia.”
Two of the world’s largest oil-service providers — Halliburton Co. and Baker Hughes Co. — sold their Russian units and withdrew. Two more giants, SLB and Weatherford International Plc, have said they continue operations in the country in compliance with sanctions.
Failed Goal
The data indicate that these restrictive measures have largely failed.
“Only some 15% of the nation’s domestic drilling market depends on technologies from so-called unfriendly nations,” said Daria Melnik, vice-president for exploration and production at Oslo-based research firm Rystad Energy A/S.
The withdrawal of major Western oil-service companies from Russia had minimal impact because it largely left intact their local subsidiaries. These operations “were mostly sold to management, retaining the know-how built up over the years,” said Viktor Katona, lead crude analyst at Kpler.
Russia’s exploration drilling rates have also resumed growth after dipping in the wake of the pandemic, industry data show, although they remain below the 2019 peak.
“In crisis times, when companies have to optimize their investment budgets, high-risk projects, including exploration, are slashed,” Rystad Energy’s Melnik said.
Still, for the full-year 2023, Russia is set to drill exploration oil wells with a total depth of just over 1,000 kilometers, according to Dmitry Kasatkin, a partner at Kasatkin Consulting, formerly Deloitte’s research center in the region.
The drilling boom is a sign of Russia’s resilience to Western energy sanctions, but the pace of activity also carries a warning.
Over the years, the rise and fall of the nation’s drilling has moved largely in sync with changes in output, historic data show. Yet in 2023, the drilling boom came alongside production cuts that Moscow is implementing in tandem with the Organization of Petroleum Exporting Countries. That suggests the high level of activity is necessary simply to maintain output.
“The main reason for the growth in Russia’s drilling is the need to launch new wells,” said Gennadii Masakov, director of the research and insights center at Yakov & Partners. “New wells have to be launched as the currently producing fields are depleting.”
As of 2022, fields that had been in operation for more than five years accounted for nearly 96% of Russia’s total liquids production, according to a research paper from the Oxford Institute for Energy Studies. Many of those upstream projects are long past their peak output levels, the paper said.
“Natural decline is a routine factor” for the nation’s industry, said Sergey Vakulenko, an industry veteran who spent ten years of his 25-years career as an executive at a Russian oil producer.
Depletion has to be compensated either by new drilling at existing sites, so-called brownfields, or by new projects known as greenfields. The latter could be problematic, said Vakulenkо, who is now a scholar at the Carnegie Endowment for International Peace in Berlin.
“Pre-war planned greenfield developments were conceived with Western technologies in mind and need to go back to the drawing board to be adjusted to the available technologies,” he said. “In the meantime, Russian oil companies are trying to maintain the plateau by accelerating production in the brownfields.”
Some components from foreign suppliers are difficult to obtain and “the Russian industry might have to resort to simpler wells and fewer frack stages as a result of missing parts,” Vakulenko said. “This would make the wells less productive and more expensive per barrel of oil produced.”
The technological independence achieved by its drillers will be enough for Russia to keep output stable in the medium-term, said Yakov & Partners’ Masakov. Yet over time, the efficiency of Russia’s drilling operations will decline, potentially risking as much as 20% of the nation’s output if untapped reserves become uneconomic to develop, he estimated.
ENB Top News
ENB
Energy Dashboard
ENB Podcast
ENB Substack
The post Russia’s Oil Drilling Boom Proves Moscow’s Resilience to Western Sanctions appeared first on Energy News Beat.
Energy News Beat
BRICS members Russia and Iran have officially abandoned the SWIFT payment system for cross-border transactions. The two countries will initiate payments to settle international trade using direct bank transfers. SWIFT payment system is no longer needed for trade between Russia and Iran, as both countries have agreed to carry out transactions directly through the banks. The two BRICS members will engage in direct bank transfers in their respective local currency and not the US dollar.
The direct bank transfers with no SWIFT are between Russia and Iran only, and not the other BRICS members. Read here to know how many sectors in the US will be affected if BRICS ditches the dollar for trade.
Source: oilprice.com
Both Russia and Iran were banned from SWIFT in 2022 after the US pressed sanctions against the two countries. However, both countries were allowed to partake in SWIFT for a few transactions but have now decided to abandon it. The Central Banks of both the BRICS countries, Iran and Russia, are now working towards smoothing the direct bank transfers.
The two BRICS members are now bypassing the US sanctions by completely sidelining SWIFT and engaging in direct bank transfers. Mohsen Karimi, Deputy Head for Central Bank of Iran and International Affairs confirmed that the country no longer requires SWIFT.
“We have connected the transmission systems of messages of the two countries to each other. This means that the banks of the two countries no longer need Switzerland to communicate with each other and commercial banks of both countries can establish intermediary relations with each other. The exporter can issue an invoice in Rials to the Russian side and receive money from Russian banks in Iran,” said Karimi to Fars news agency.
The post BRICS: Russia & Iran End SWIFT, Start Bank Transfers in Local Currency appeared first on Energy News Beat.
Energy News Beat
The Biden administration is reevaluating the climate criteria it uses to approve new liquefied natural gas export facilities, threatening to stall pending projects as the 2024 election nears.
A panel of government officials convened by White House climate adviser Ali Zaidi met to develop a policy recommendation on the issue for President Joe Biden, according to two people familiar with the matter who weren’t authorized to speak publicly. The officials met Saturday, one of the people said. Biden has been briefed on the issue but has yet to make a decision, a second person said.
The issue forces Biden to balance competing geopolitical and domestic priorities. He committed to providing more gas to Europe after Russia invaded Ukraine. But as the election nears, every fossil-fuel project approval under his watch is being scrutinized by climate-minded voters key to his reelection.
The deliberations, meanwhile, come on the heels of an agreement reached by the US and nearly 200 other nations at last month’s COP28 climate summit in Dubai to transition away from fossil fuels.
The Department of Energy, which issues export permits, is checking whether it’s properly accounting for the climate impact of proposed plants, Politico earlier reported, citing an unidentified senior US administration official.
An Energy Department spokeswoman said the agency didn’t have any updates on its approval process. The White House didn’t immediately comment.
The US, which was the largest LNG exporter in the world in 2023, has five LNG export facilities under construction and several more permitted and awaiting a final investment decision. The plants chill natural gas to a liquid, allowing it to be loaded onto tankers and shipped around the globe. The US began exporting LNG from its vast shale reserves in 2016, with demand picking up sharply after Russian gas flows to Europe sputtered following the country’s invasion of Ukraine in 2022.
“Should the Biden administration decide to needlessly delay permits for additional LNG exports, it would undoubtedly send a troubling message to our allies and potentially force them to seek supply from bad actors like Russia for LNG supply,” said Charlie Riedl, executive director of the Center for LNG, a trade group.
While international buyers are eager for US LNG, environmental groups and some Democrats have pushed Biden to reject further export licenses amid climate concerns. Natural gas’s primary ingredient, methane, is a super-potent greenhouse gas.
Any push to change how export licenses are approved could effectively stall permitting in the meantime. Administration officials already warned industry representatives of potentially protracted delays for approvals to broadly export LNG during meetings at the COP28 summit, according to a person familiar with the matter.
Reviews of applications to broadly export LNG have stretched to more than 330 days under the Biden administration, up from 49 days under former President Donald Trump and 155 days under former President Barack Obama, according to the American Petroleum Institute.
“The signal that sends to our allies is very, very concerning: Is the United States going to be a source of LNG and a reliable partner into the future?” American Petroleum Institute Chief Executive Mike Sommers said in an interview. “Our allies are going to start asking that question if they make this determination.”
Environmentalist Bill McKibben, who earlier pushed to block the Keystone XL oil pipeline, has now taken up the campaign against LNG exports. He and other climate activists are planning a three-day demonstration at the Department of Energy in February. The sit-in’s website includes a sign-up form asking participants whether they are willing to risk arrest.
“So far, the DOE has refused to listen to thousands of letters and ignored petitions signed by hundreds of thousands of people. So we need to go to DC to drive home how serious this crisis is,” a letter from the activists released Tuesday reads. It specifically calls out CP2, a proposed plant from Venture Global LNG Inc. in Louisiana that’s awaiting approval by the Federal Energy Regulatory Commission.
Venture Global says its proposed project, like other US plants, will be key to the world’s push to move away from dirtier fuel sources, like coal.
“American LNG is the best weapon in our arsenal to quickly displace global coal use and combat climate change. NGOs and their paid activists have continually misled the public, making up their own facts to fit their agenda, when the data shows otherwise,” Shaylyn Hynes, a spokeswoman for Venture Global, said in an emailed statement.
Compared to the two previous presidencies, the Biden administration has taken longer to approve LNG export licenses for new projects, according to data from LNG Allies, a trade group. A longer wait means delays in getting financing and customer commitments, potentially putting projects’ viability at risk.
The proposed Commonwealth LNG project in Louisiana has been waiting more than 400 days for its so-called non-FTA export permit from the DOE.
Compared to the FERC process, “we find there is far less feedback or visibility in DOE’s deliberations for us to understand the delay,” Commonwealth LNG Founder and Executive Chairman Paul Varello said in an emailed reply to questions. “With all our other permits in hand, we’re ready to move forward with the final steps toward financing and construction once the Non-FTA permit is secured.”
The post Biden Administration Reviews Climate Criteria for LNG Projects appeared first on Energy News Beat.
Energy News Beat
The following content is sponsored by the EnergyX
Current lithium extraction and refinement methods are outdated, often harmful to the environment, and ultimately inefficient. So much so that by 2030, lithium demand will outstrip supply by a projected 1.42 million metric tons. But there is a solution: Direct lithium extraction (DLE).
For this graphic, we partnered with EnergyX to try to understand how DLE could help meet global lithium demands and change an industry that is critical to the clean energy transition.
Lithium is crucial to many renewable energy technologies because it is this element that allows EV batteries to react. In fact, it’s so important that projections show the lithium industry growing from $22.2B in 2023 to nearly $90B by 2030.
But even with this incredible growth, as you can see from the table, refined lithium production will need to increase 86.5% over and above current projections.
2022 (million metric tons)2030P (million metric tons)
Lithium Carbonate Demand0.461.21
Lithium Hydroxide Demand0.181.54
Lithium Metal Demand00.22
Lithium Mineral Demand0.070.09
Total Demand0.713.06
Total Supply0.751.64
DLE is a process that uses a combination of solvent extraction, membranes, or adsorbents to extract and then refine lithium directly from its source. LiTASTM, the proprietary DLE technology developed by EnergyX, can recover an incredible 300% more lithium per ton than existing processes, making it the perfect tool to help meet lithium demands.
Additionally, LiTASTM can refine lithium at the lowest cost per unit volume directly from brine, an essential step in meeting tomorrow’s lithium demand and manufacturing next-generation batteries, while significantly reducing the footprint left by lithium mining.
Hard Rock MiningUnderground ReservoirsDirect Lithium Extraction
Direct CO2 Emissions15,000 kg5,000 kg3.5 kg
Water Use170 m3469 m334-94 m3
Lithium Recovery Rate58%30-40%90%
Land Use464 m23124 m20.14 m2
Process TimeVariable18 months1-2 days
DLE promises to disrupt the outdated lithium industry by improving lithium recovery rates and slashing emissions, helping the world meet the energy demands of tomorrow’s electric vehicles.
EnergyX is on a mission to become a worldwide leader in the sustainable energy transition using groundbreaking direct lithium extraction technology. Don’t miss your chance to join companies like GM and invest in EnergyX to transform the future of renewable energy.
The post Will Direct Lithium Extraction Disrupt the $90B Lithium Market? appeared first on Elements by Visual Capitalist.
The post Will Direct Lithium Extraction Disrupt the $90B Lithium Market? appeared first on Energy News Beat.
Pecos Country Operating, LLC is a privately owned oil and gas exploration and production company headquartered in Fort Worth. We own and operate wells across the South Central United States with our predominant means of production coming out of West and North Texas.
There are four main ways in which the roughly 131 million American homes are heated: electricity, natural gas, propane or fuel oil. The vast majority use electricity or natural gas. While some 20 million homes already have a heat pump, a similar number still rely on inefficient electric resistance heaters which are expensive to use, and predominantly found in low and middle-income households.
Around half of US homes are heated with gas – mostly natural gas, although some 10 million homes use propane or heating oil which is stored in tanks on the property, and powers often aging furnaces. These furnaces heat up air which is then blown round the homes though ducts and vents. The use of hot water pipes and radiators, as normally seen in the UK, is comparatively unusual.
The other big difference from the UK is that around 90 percent of homes use some form of air conditioning. Two-thirds of households use central air conditioning or a central heat pump as their main AC equipment. That means that quite a lot of US homes either don’t have air conditioning, use portable AC or have a system that is powered by gas.
Against this backdrop the US Government plans to install 20 million heat pumps by 2030, with 40 percent of the benefits being directed to disadvantaged communities. Lawmakers hope that as existing heating and air conditioning systems break down with age they will be replaced by modern heat pumps.
Heat pumps run on electricity, and are hailed as key to achieving zero carbon goals by removing the use of fossil fuels for heating. Of course, that assumes that the electricity that powers the heat pumps is generated from something other than fossil fuels – unfortunately, around 60 percent of electricity in the US comes from fossil fuels.
There are other challenges with heat pumps, in particular their performance in cold weather, when their operations become less efficient. This is a fundamental feature of air-source heat pumps since they involve indoor and outdoor components – when it’s cold outside the outdoor component must be heated in order to work properly, and this means less energy is available for heating indoors. The lower temperatures fall, the worse this effect becomes, and the more expensive the system becomes to run.
Heat pump fans often point to the widespread use of the devices in cold nations such as Norway and Sweden as evidence they “work” in cold weather, but they fail to mention that many Scandinavian households have more than one heat pump or use an additional form of heating, typically a wood-burning stove. Gathering wood for heating is common across the Nordic countries. More modern models claim to “work well” at low temperatures, but they will still lose efficiency as it gets colder.
The economics of heat pumps vary greatly across the US, depending on the amount of heat needed and the price of natural gas. The installation of heat pumps is expensive, with air source heat pumps costing between $2,500 and $10,000, with the average homeowner spending $5,500. However these costs can jump to up to $30,000 in homes which don’t have existing ductwork. Ground source (or geothermal) heat pumps work much better in cold weather but they are much more expensive. They also require a lot of land so aren’t suitable for many homes.
There are tax credits in the Inflation Reduction Act that cover 30 percent of the upfront costs of buying and installing a heat pump, up to $2,000. For households with less than 80 percent of the median area income, the subsidy is higher and will cover 100 percent of the upfront costs, up to $8,000. Many states also offer rebates.
According to the International Energy Agency, heat pumps can reduce American heating bills by up to $300 per year. That’s a significant saving for those households whose installation costs are fully covered by the government, but not so great for those left funding thousands of dollars of upfront costs. People using natural gas for heating see smaller benefits since gas is pretty cheap in the US.
So are heat pumps hot or not? The boring answer to that is “it depends”. Low income households with older electrical resistance or propane heaters are likely to benefit the most from getting a heat pump as they will have most if not all of the upfront costs covered and will make significant savings on energy bills. These households are also less likely to have air conditioning, so the installation of a heat pump will give them a new capability for cooling.
Toby Schumacher and the external part of his heat pump CREDIT: Jeff Gilbert
However in colder states heat pumps could need a secondary heating source which might be difficult to afford. For higher income households the economic benefits are less clear. They will have to pay higher upfront costs which will take years to recover through lower bills. If they currently have gas heating the savings will be smaller and the capital costs take longer to repay.
The climate benefits in the short term will be marginal since the US still relies heavily on fossil fuels for electricity generation. Switching from burning gas in the home to burning gas in power stations does reduce emissions since power stations are more efficient. However electricity demand will increase, as people switch from gas to electric heating, and will rise further if the homes which don’t currently have electric air conditioning begin to use their heat pumps for cooling.
Bringing cooling to houses that don’t currently have air conditioning will be an absolute increase in energy demand, rather than a change from one form of energy to another, and it could be big. Air conditioners are the domestic appliances that generally consume the most electricity, accounting for an average of 17 percent of total US household electricity usage (compared with 15 percent for space heaters).
This higher electricity demand will strain America’s creaking power grids, which already struggle with reliability issues, and they will increase the need for more generation and grid infrastructure such as power lines and transformers, adding to the multi-billion dollar bill for electricity system upgrades. To make heat pumps really work we need reliable low carbon electricity and plenty of it otherwise there is a risk the increased demand will cause more blackouts. And if you have electric heating, a blackout means no heating either.
There are a lot of numbers in this article. And they add up to one conclusion: it’s hard to be more than lukewarm on heat pumps. They will be great for people who get them for free to replace old, expensive and inefficient heating systems – these people will also be getting free air conditioners. They will be a lot less great for everyone else, involving high upfront costs, and more grid infrastructure that will be paid for through higher bills and taxes. And as long as the majority of electricity comes from fossil fuels, their climate benefits will be marginal.