Eni set to sign landmark Libyan gas deal worth $8bn

Spanish Market: Condensate, Crude oil, Natural gas
25/01/23

Libya's state-owned NOC is poised to sign an 845mn ft³/d offshore gas project deal with Italy's Eni worth an estimated $8bn, representing the largest single investment in the north African country's upstream sector since the 2011 civil war.

"We have reached an agreement with Eni and the signing ceremony will take place on 28 January," NOC chairman Farhat ben Gudara told local TV channel Al Masar. Eni declined to comment.

The long-delayed deal will not only help Libya meet rising domestic gas demand but will also boost its gas exports to Italy, which slumped to the lowest level since 2011 last year. The agreement is due to be signed in Tripoli during the first visit to Libya by Italian prime minister Giorgia Meloni, who is pushing her "Mattei plan" that seeks to deepen Italy's energy and political ties to Africa. Italy has been scrambling for alternative gas supplies since Russia's invasion of Ukraine and is looking to north Africa in particular.

Central to the agreement with Eni is the Structures A&E project in Block NC-41, which will have the capacity to produce 760mn ft³/d of gas and 47,000 b/d of liquids, mostly condensate. This is equal to about 65pc of Libya's current 1.2bn ft³/d of sales gas production capacity. The agreement is also likely to include the 85mn ft³/d Bouri Gas Utilization project, which plans to capture associated gas output that is currently being flared at the 25,000 b/d Bouri oil field in Block NC-41. With its own climate goals in mind — and Libya's nascent decarbonisation ambitions — Eni has floated the possibility of incorporating a carbon capture and storage (CCS) element to its projects in the block.

The company said in October last year that it expects first gas from Structures A&E in 2024, with the project slated to reach full capacity in 2027. The relatively safe location of the two projects offshore Tripoli makes them less vulnerable to disruption than Libya's onshore fields. The country's decade-long political quagmire has not only hampered new oil and gas projects from getting off the ground but has also frequently led to existing output being shut down for political purposes.

With Libya roughly split between rival western and eastern administrations, political division still poses a threat. The head of the eastern-aligned Government of National Stability (GNS), Fathi Bashagha, has pushed back against the Eni deal, saying the western-based Government of National Unity (GNU) lacks the legitimacy to sign such an agreement.

Eni is Libya's largest foreign gas producer, overseeing most of the country's gas output via its Mellitah Oil and Gas joint venture with NOC. Mellitah's production is split between the offshore Bahr Essalam project and the Wafa wet gas project located on the border with Algeria, as well as some fields in the Sirte basin, Libya's oil heartland. Mellitah's western output feeds the 775mn ft³/d Greenstream pipeline — Libya's only gas export outlet — which has been running at well below capacity over the past few years. Exports through Greenstream hit their lowest level since the 2011 revolution last year, averaging some 250mn ft³/d.

By Aydin Calik and Bachar Halabi

Libya's gas exports to Italy

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26/12/24

Viewpoint: US tariffs may push more Canadian crude east

Singapore, 26 December (Argus) — Canada may divert crude supplies from the US to Asia-Pacific via the Trans Mountain Expansion (TMX) pipeline in 2025, should president-elect Donald Trump impose tariffs on Canadian imports. Trump has declared that he will implement a 25pc tax on all imports originating from Canada after he is sworn into office on 20 January. This will effectively add around $16/bl to the cost of sending Canadian crude to the US, based on current prices, and impel US refiners to cut their purchases. The US imported 4.57mn b/d of Canadian crude in September, according to data from the EIA. Canadian crude producers are expected to turn to Asian refiners in their search for new export outlets. This is especially after Asian refiners gained easier access to such cargoes following the start-up of the 590,000 b/d TMX pipeline in May. The new route significantly shortens the journey to ship crude from Canada to Asia. It takes about 17 days for a voyage from Vancouver to China, compared with 54 days from the US Gulf coast to the same destination. China has become the main outlet for Asia-bound shipments from Vancouver, accounting for about 87pc of the 200,000 b/d exported over June-November, according to data from oil analytics firms Vortexa and Kpler (see chart). But even if the full capacity of the TMX pipeline is utilised to export crude to Asia from Vancouver, it will still only represent a fraction of current Canadian crude exports to the US. Vancouver sent just 154,000 b/d via the TMX pipeline to US west coast refiners over June-November, Vortexa and Kpler data show. Meanwhile, latest EIA figures show more than 2.63mn b/d of Canadian crude was piped into the US midcontinent in September, while US Gulf coast refiners imported 469,000 b/d. This means Canadian crude prices will likely come under downward pressure from higher costs for its key US market, should Trump's proposed tariffs come to pass. This will further incentivise additional buying from Chinese customers, as well as other refiners based elsewhere in Asia-Pacific. India, South Korea, Japan, and Brunei have already imported small volumes of Canadian TMX crude in 2024. A question of acidity But other Asian refiners have so far been reluctant to step up their heavy sour TMX crude imports because of concerns over the high acidity content. China has been mainly taking Access Western Blend (AWB), which has a total acid number (TAN) as high as 1.6mg KOH/g. Acid from high-TAN crude collects in the residue at the bottom of refinery distillation columns where it can corrode units, which deters many refineries from processing such grades. But Chinese refiners have been able to dilute the acidity level by blending their AWB cargoes with light sweet Russian ESPO Blend, allowing them to save costs compared to buying medium sour crude from the Mideast Gulf. Cold Lake, the other grade coming out of the TMX pipeline, has a lower TAN and is currently popular with refiners on the US west coast. But higher costs from potential tariffs could prompt Cold Lake exports to be redirected from the US to buyers in South Korea, Japan, and Brunei — which had all bought the grade previously. Canadian crude appears to have so far displaced medium sour grades in Asia-Pacific, and this trend is expected to continue should TMX crude flows to the region climb higher in 2025. More Canadian crude heading to Asia may displace and free up more Mideast Gulf medium sour supplies to buyers in other regions, including US refiners looking for replacements to their Canadian crude imports. This will also limit the flows of other arbitrage grades like US medium sour Mars crude to Asia-Pacific, which has already seen exports to Asia dwindle in 2024. Opec+ is also due to begin unwinding voluntary production cuts in April 2025, which means Canadian producers will likely have to lower prices sufficiently to attract buyers from further afield. By Fabian Ng TMX exports from Vancouver (b/d) Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: California dairy fight spills into 2025

24/12/24

Viewpoint: California dairy fight spills into 2025

Houston, 24 December (Argus) — California must begin crafting dairy methane limits next year as pressure grows for regulators to change course. The California Air Resources Board (CARB) has committed to begin crafting regulations that could mandate the reduction of dairy methane as it locked in incentives for harvesting gas to fuel vehicles in the state. The combination has frustrated environmental groups and other opponents of a methane capture strategy they accuse of collateral damage. Now, tough new targets pitched to help balance the program's incentives could become the fall-out in a new lawsuit. State regulators have repeatedly said that the Low Carbon Fuel Standard (LCFS) is ill-suited to consider mostly off-road emissions from a sector that could pack up and move to another state to escape regulation. California's LCFS requires yearly reductions of transportation fuel carbon intensity. Higher-carbon fuels that exceed the annual limits incur deficits that suppliers must offset with credits generated from the distribution to the state of approved, lower-carbon alternatives. Regulators extended participation in the program to dairy methane in 2017. Dairies may register to use manure digesters to capture methane that suppliers may process into pipeline-quality natural gas. This gas may then be attributed to compressed natural gas vehicles in California, so long as participants can show a path for approved supplies between the dairy and the customer. California only issues credits for methane cuts beyond other existing requirements. Regulators began mandating methane reductions from landfills more than a decade ago and in 2016 set similar requirements for wastewater treatment plants. But while lawmakers set a goal for in-state dairies to reduce methane emissions by 40pc from 2030 levels, regulators could not even consider rulemakings mandating such reductions until 2024. CARB made no move to directly regulate those emissions at their first opportunity, as staff grappled with amendments to the agency's LCFS and cap-and-trade programs. That has meant that dairies continue to receive credit for all of the methane they capture, generating deep, carbon-reducing scores under the LCFS and outsized credit production relative to the fuel they replace. Dairy methane harvesting generated 16pc of all new credits generated in 2023, compared with biodiesel's 6pc. Dairy methane replaced just 38pc of the diesel equivalent gallons that biodiesel did over the same period. The incentive has exasperated environmental and community groups, who see LCFS credits as encouraging larger operations with more consequences for local air and water quality. Dairies warn that costly methane capture systems could not be affordable otherwise. Adding to the expense of operating in California would cause more operations to leave the state. California dairies make up about two thirds of suppliers registered under the program. Dairy supporters successfully delayed proposed legislative requirements in 2023. CARB staff in May 2024 declined a petition seeking a faster approach to dairy regulation . Staff committed to take up a rulemaking considering the best way to address dairy methane reduction in 2025. Before that, final revisions to the LCFS approved in November included guarantees for dairy methane crediting. Projects that break ground by the end of this decade would remain eligible for up to 30 years of LCFS credit generation, compared with just 10 years for projects after 2029. Limits on the scope of book-and-claim participation for out-of-state projects would wait until well into the next decade. Staff said it was necessary to ensure continued investment in methane reduction. The inclusion immediately frustrated critics of the renewable natural gas policy, including board member Diane Tarkvarian, who sought to have the changes struck and was one of two votes ultimately against the LCFS revisions. Environmental groups have now sued , invoking violations that effectively froze the LCFS for years of court review. Regulators and lawmakers working to transition the state to cleaner air and lower-emissions vehicles will have to tread carefully in 2025. By Elliott Blackburn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Crude production resumes at Karoon’s Brazil Bauna field

24/12/24

Crude production resumes at Karoon’s Brazil Bauna field

Sydney, 24 December (Argus) — Australia-listed oil producer Karoon Energy has restarted its Bauna project offshore Brazil, the firm said today. Output resumed late on 22 December local time, Karoon said. This followed the repair of one of two mooring chains tethering its floating production, storage and offloading (FPSO) vessel, which failed on 11 December , leading the company to cut its 2024 guidance to 27,600-28,100 b/d of oil equivalent (boe/d), down from an earlier 28,700-29,500 boe/d. The second mooring chain is expected to be repaired by mid-January, Karoon said. An investigation into the failure will be jointly undertaken with FPSO owner and operator Ocyan, and its joint-venture partner Altera Infrastructure. Bauna production was about 24,500 b/d before the shutdown, with Karoon expecting to reach this level again in the coming days. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US LPG cargo premiums poised to fall

23/12/24

Viewpoint: US LPG cargo premiums poised to fall

Houston, 23 December (Argus) — The booming US LPG export market has fueled record spot fees this year for terminal operators that send those cargoes abroad, but those fees are poised to fall next year as additional export capacity comes online. US propane exports surged over the past two years, hitting an all-time high of 1.85mn b/d in the first quarter of this year, according to data from the US Energy Information Administration (EIA). Terminal fees for spot propane cargoes out of the US Gulf coast hit an all-time high of Mont Belvieu +32.5¢/USG (+$169.325/t) in mid-September. US propane production is expected to grow by another 80,000 b/d in 2025 to 2.22mn b/d while the outlook for domestic consumption is fairly steady, at 820,000 b/d next year — meaning even more propane will be pushed into the waterborne market. But that is dependent on US infrastructure keeping up with the pace of production. US export terminals in Houston, Nederland and Freeport, Texas, have run at or above capacity for the last two years given the thirst for cheaper US feedstock, largely from propane dehydrogenation (PDH) plant operators in China. This demand has created bottlenecks at US docks, and midstream operators like Enterprise, Energy Transfer, and Targa have rushed to ramp up spending on both pipelines and additional refrigeration to stay ahead of the wave of additional production. US gas output spurs LPG exports As upstream producers have ramped up natural gas production ahead of new LNG projects, most producers are counting on LPG demand from international outlets in Asia to offload the ethane and propane the US cannot consume. For the past four years, Asian buyers have been more than happy to oblige. US propane exports to China rose from zero in 2019, when China imposed tariffs on US imports, to an average of 1.36mn metric tonnes (t) per month in January-November 2024, according to data from analytics firm Kpler, making China the largest offtaker of US shipments. US exports to Japan averaged 480,000t per month throughout most of 2024, and exports to Korea averaged 460,000t per month in the first 11 months of 2024. China, Korea, and Japan received 52pc of US propane exports in 2024, up from 49pc in 2020, according to data from Vortexa. Strong demand in Asia has kept delivered prices in Japan high enough to sustain an open arbitrage between the US and the Argus Far East Index (AFEI). Forward-month in-well propane prices at Mont Belvieu, Texas, have remained well below delivered propane on the AFEI. In 2020, Mont Belvieu Enterprise (EPC) propane averaged a $143/t discount to delivered AFEI — a spread that has only widened as additional PDH units in Asia have come online. During the first 11 months of 2024, the Mont Belvieu to AFEI spread averaged a hefty $219/t, leaving plenty of room for wider netbacks in the form of higher terminal fees for US sellers, especially as a wave of new VLGCs entering the global market has left shipowners with less leverage to take advantage of the wider arbitrage. The resulting wider arbitrage to Asia has kept US export terminals running full for the last two years. So when a series of weather-related events and maintenance in May-September limited the number of spot cargoes operators could sell and delayed scheduled shipments, term buyers willing to resell any of their loadings could effectively name their price. This spurred the record-high premiums for spot propane cargoes in September. New projects may narrow premium An increase in US midstream firm investments in additional dock capacity and added refrigeration in the years ahead could narrow those terminal fees, however. Announced projects from Enterprise and Energy Transfer, in particular, will add a combined 550,000 b/d of LPG export capacity out of Houston and Nederland, Texas by the end of 2026. Enterprise's new Neches River terminal project near Beaumont, Texas, will add another 360,000 b/d of either ethane or propane export capacity in the same timeframe. These additions are poised to limit premiums for spot cargoes by the end of 2025. Already, it appears the spike in spot cargo premiums to Mont Belvieu has abated for the rest of 2024. Spot terminal fees for propane sank to Mont Belvieu +14¢/USG by the end of November. The lower premiums come not only as terminals resume a more normal loading schedule, but at the same time a surplus of tons into Asia ahead of winter heating demand has narrowed the arbitrage. The spread between in-well EPC propane at Mont Belvieu fell from $214.66/t to $194.45/t during November. A backwardated market for AFEI paper into the second quarter of 2025 means US prices are poised to fall more in order to keep the spread from narrowing further. By Amy Strahan Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US tax fight next year crucial for 45Z

23/12/24

Viewpoint: US tax fight next year crucial for 45Z

New York, 23 December (Argus) — A Republican-controlled Congress will decide the fate next year of a federal incentive for low-carbon fuels, setting the stage for a lobbying battle that could make or break existing investment plans. The 45Z tax credit, which offers greater subsidies to fuels that produce fewer emissions, is poised to kick off in January. Biofuel output has boomed during President Joe Biden's term, driven in large part by west coast refiners retrofitting facilities to process lower-carbon fats and oils into renewable diesel. The 45Z tax credit, created by the 2022 Inflation Reduction Act (IRA), was designed to extend that growth. But Republicans will soon control Washington. President-elect Donald Trump has dismissed the IRA as the "Green New Scam", and Republicans on Capitol Hill, who had no role in passing Biden's signature climate legislation, are keen to cut climate spending to offset the steep cost of extending tax cuts from Trump's first term. Biofuels support is a less likely target for repeal than other climate policies, energy lobbyists say. But Republicans have already requested input on 45Z, signaling openness to changes. Republicans plan to use the reconciliation process, which enables them to avoid a Democratic filibuster in the Senate, to extend tax breaks that are scheduled to expire in 2025. "I want to place our industry in a place to make sure that the biofuels tax credit is part of reconciliation," said Kailee Tkacz Buller, president of the National Oilseed Processors Association. But lawmakers "could punt the biofuels discussion if stakeholders aren't aligned." A decade ago, biofuel policy was a simple tug-of-war between the oil and agriculture industries. Now many refiners formerly critical of the Renewable Fuel Standard produce ethanol and advanced biofuels themselves. And the increasingly diverse biofuels industry could complicate efforts to present a united front to Congress. Farm groups worry about carbon intensity scoring hurting crop demand and have lobbied to curtail record-high feedstock imports, to the chagrin of some biorefineries. Those producers are no monolith either: Biodiesel plants often rely more on local vegetable oils, while ethanol producers insist on keeping incentives that do not discriminate by fuel type and some oil majors would back subsidizing fuels co-processed with petroleum. Add airlines into the picture, which want greater incentives for aviation fuels, and marketers frustrated by 45Z shifting subsidies away from blenders — and the threat of fractious negotiations next year becomes clear. There are options for potential compromise, according to an Argus analysis of comments submitted privately to Republicans in the House of Representatives, as well as interviews with energy lobbyists and tax experts. The industry, frustrated by the Biden administration's delays in clarifying 45Z's rules, might welcome legislative changes that limit regulatory discretion regardless of what agency guidance eventually says. And lobbyists have floated various ways to appease agriculture groups without kneecapping biorefineries reliant on imports, including adding domestic content bonuses, imposing stricter requirements for Chinese-origin used cooking oil, and giving preference to close trading partners. Granted, unanimity among lobbyists is hardly a priority for Republican tax-writers. Reaching any consensus in the restive caucus, with just a handful of votes to spare in the House, will be difficult enough. "These types of bills always come to down to what's the most you can do before you start losing enough votes to pass it," said Jeff Navin, cofounder of the clean energy advocacy firm Boundary Stone Partners and a former House and Senate staffer. "Because they can only lose a couple of votes, there's not much more beyond that." And the caucus's goal of cutting spending makes an industry-wide goal — extending the 45Z credit into the 2030s — even more challenging. "It is a hard sell to get the extension right away," said Paul Winters, director of public affairs at Clean Fuels Alliance America. Climate costs Cost concerns also make less likely a simple return to the long-running blenders credit, which offered $1/USG across the board to biomass-based diesel. The US Joint Committee on Taxation in 2022 scored the two-year blenders extension at $5.5bn, while pegging three years of 45Z at less than $3bn. An inconvenient reality for Republicans skeptical of climate change is that 45Z's throttling of subsidies based on carbon intensity makes it more budget-friendly. Lawmakers have other reasons to not ignore emissions. Policies elsewhere, including California's low-carbon fuel standard and Europe's alternative jet fuel mandates, increasingly prioritize sustainability. The US deviating from that focus federally could leave producers with contradictory incentives, making it harder to turn a profit. And companies that have already sunk funds into reducing emissions — such as ethanol producers with heavy investments in carbon capture — want their reward. Incentives with bipartisan buy-in are likely more durable over the long run too. Next time Democrats control Washington, liberals may be more willing to scrap a credit they see as padding the profits of agribusiness — but less so if they see it as helping the US decarbonize. By Cole Martin Tax credit changes 40A Blenders Tax Credit 45Z Producers Tax Credit $1/USG Up to $1/USG for road fuels and up to $1.75/USG for aviation fuels depending on carbon intensity For domestic fuel blenders For domestic fuel producers Imported fuel eligible Imported fuel not eligible Exclusively for biomass-based diesel Fuels that produce no more than 50kg CO2e/mmBTU are eligible Feedstock-agnostic Carbon intensity scoring incentivizes waste over crop feedstocks Co-processed fuels ineligible Co-processed fuels ineligible Administratively simple Requires federal guidance on how to calculate carbon intensities for different feedstocks and fuel pathways Expiring after 2024 Lasts from 2025 through 2027 Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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