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Iraq eyes control of KRG crude marketing as row endures

  • : Crude oil
  • 23/03/28

A dispute keeping around 400,000 b/d of Iraqi Kurdistan crude from reaching international markets will only be resolved if Erbil hands over the rights to market its oil to the federal Baghdad government, according to a source.

Iraq and the Kurdistan Regional Government (KRG) have been locked in talks to try to settle the dispute, which was triggered by a ruling last week by the Paris-based International Chamber of Commerce's (ICC) court of arbitration. It found that Turkey, in allowing the export of KRG crude, had breached a 1973 bilateral agreement with Iraq. The ruling prompted Ankara to ask its state-owned pipeline operator Botas on 25 March to suspend all flows of KRG Kirkuk blend crude to the Mediterranean port of Ceyhan — the only viable outlet for the KRG to export its crude.

A first round of talks took place in Baghdad on 26 March, but broke up that same day after failing to make real headway. A second round began today, again in the Iraqi capital, and have yet to conclude.

The source said the talks hinge on a demand by Baghdad that state-owned oil Somo takes full control of marketing KRG Kirkuk from Erbil's ministry of natural resources. Baghdad is also asking to have access to the account into which the revenues from these exports are deposited, but only in an observation capacity.

Exports of Kirkuk Blend were 452,000 b/d in 2022, according to Argus tracking. More than 380,000 b/d of this was marketed by the KRG. Somo accounted for the rest, all of which went to Turkish refiner Tupras.

Between a rock and a hard place

That the two sides have been proactive in trying to resolve the impasse is positive. But anything other than a quick resolution to the dispute could put most, if not all, of the Kurdistan region's production in jeopardy. Several foreign oil companies operating in the semiautonomous region have begun diverting their production into storage, and at least one, Forza Energy, said it had shut in its production after running out of storage capacity.

Norwegian independent DNO said on 27 March its facilities could accommodate just "several days' production" from the Tawke and Peshkabir fields which, together, produced around 107,000 b/d in 2022. London-listed Genel Energy, which partners DNO at those fields and holds a stake in the 4,700 b/d Sarta and 4,500 b/d Taq Taq fields, told Argus the fields have "several days" and "three weeks" of storage capacity. Gulf Keystone Petroleum (GKP) said it was already producing at lower rates and could soon be forced to suspend production.

A fifth KRG-based operator, HKN Energy, said its storage facilities were approaching capacity and that it would have to shut down production within a week, unless the pipeline resumes operations.


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24/09/18

TMX is a fossil fuel subsidy of at least C$8.7bn: IISD

TMX is a fossil fuel subsidy of at least C$8.7bn: IISD

Calgary, 18 September (Argus) — Canada's newest crude pipeline to the country's west coast amounts to a fossil fuel subsidy of at least C$8.7bn ($6.4bn), a research and policy think-tank said. The federal government is unlikely to recover its C$34bn investment to construct the 590,000 b/d Trans Mountain Expansion (TMX) connecting oil producers in Alberta to the Pacific coast, qualifying the project as a major subsidy for the fossil fuel industry, according to the International Institute for Sustainable Development (IISD) on Wednesday. This runs contrary to the government's policy to eliminate direct support for the oil and gas sector , a goal Justin Trudeau's Liberals said was achieved in 2023. The government was the first G20 country to hit this milestone, following a 2009 commitment by the group to reach the goal by 2025. The subsidy as it relates to TMX could be as high as C$18.7bn, the Canadian non-profit said, but noted the entire amount could still be recovered by increasing tolls and/or implementing a levy. This levy could be against either all producers, or all shippers, of crude in the Western Canadian Sedimentary Basin (WCSB), whether they use TMX or not, the IISD suggested. About 90pc of Canada's crude production comes from western Canada, with much of that derived from Alberta's oil sands region. "A levy in the range of C$1-2/bl . . . over a 10-year period would be sufficient to recover the entire cost of the subsidy and the loss to the Canadian taxpayer," according to the IISD. Alternatively, fixed tolls on TMX would need to be more than doubled to C$24.53/bl from C$11.37/bl to recover all capital costs for the line that went into service on 1 May this year, according to IISD's figures. Variable tolls would be added to this. The terms in the original contracts signed between shippers and then-owner Kinder Morgan were no longer appropriate as they did not reflect the rising risks of the project, said the IISD. Kinder Morgan suspended the project in 2018, which led to the Canadian government buying both the expansion project and the original 300,000 b/d Trans Mountain line from US midstream company that same year. The federal government has maintained its plan to sell the pipeline once operational, but the final tolls are yet to be determined. Whether the operator or shippers will bear the brunt of the massive cost overruns is also still unknown. Tolls, representing cash flows for any prospective buyer, will help dictate the price that the expanded Trans Mountain system will fetch. The IISD suggests a sale price is likely to be between C$17.6bn-26.6bn, resulting in a net loss to the government of between C$8.9bn-18bn assuming its cost of investment climbs to nearly C$36bn before a sale is reached. But despite warnings by opponents it would go underused, TMX has been as advertised, opening a new frontier for oil sands operators and disrupting trade flows throughout the Pacific Rim. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Indian windfall tax on domestic crude output at zero


24/09/18
24/09/18

Indian windfall tax on domestic crude output at zero

Mumbai, 18 September (Argus) — India has reduced the windfall tax on domestic crude production to zero from a previous 1,850 rupees/t ($3/bl), in line with a fall in global oil prices. The new rate is effective from 18 September. The rate was last revised on 31 August when it was cut by 12pc . The rate is revised every two weeks. Global crude prices fell nearly 9pc during 1-18 September. The windfall tax was cut to zero during 4-19 April and 16 May-15 July 2023. The Indian government first imposed the windfall tax in July 2022 because of a sharp increase in crude prices that led to domestic crude producers making windfall gains. Indian producers sell crude to domestic refineries at international parity prices. India's crude production in August fell by 4pc from a year earlier to 520,000 b/d, oil ministry data show. Crude imports in August fell by 8pc from July and by nearly 1pc against a year earlier to 4.22m b/d in August, Vortexa data show. India has again extended a deadline to 21 September for submitting bids for the ninth bidding round under the Hydrocarbon Exploration and Licensing Policy's Open Acreage Licensing Programme, as it attempts to boost investment to lift domestic upstream output. By Roshni Devi Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Indonesia issues regulation to build energy reserves


24/09/17
24/09/17

Indonesia issues regulation to build energy reserves

A strategic energy reserve comprising stocks of LPG, oil and gasoline could be ready by 2035 under a presidential decree, writes Prethika Nair Singapore, 17 September (Argus) — Indonesia's government has issued a presidential decree outlining plans to build strategic energy reserves, including LPG, by 2035. The decree sets out the goal of establishing stockpiles amounting to 9.64mn bl of gasoline, 10.17mn bl of oil and 525,800t of LPG within the next 11 years. "The government is aware of the importance of having sufficient energy reserves to handle risks such as global oil price fluctuations, natural disasters, or supply disruptions," Indonesian agency the National Energy Council's (NEC) secretary general, Djoko Siswanto, said on 6 September. "The provision of the [reserves] will be carried out in stages until 2035, according to the country's financial capabilities." Funds for establishing the reserves will come from the state budget and other legitimate resources, he said. The NEC will oversee the regulations while the energy ministry and companies with permits in the energy sector will manage the reserves, according to Djoko. Management includes procurement of supplies from domestic production or imports, as well as investment in infrastructure and maintenance, and the use and recovery of the reserves. The location of the reserves will be based on local geology, ease of distribution, spatial planning, supporting infrastructure and the potential for crises or emergencies, and where infrastructure is not sufficient, new facilities will be built, Djoko said. Indonesia aims to reach 1mn b/d of oil production and 12bn ft³/d (124bn m³/yr) of gas production by 2030. But its oil output fell to 606,000 b/d in 2023 from 612,000 b/d in 2022, energy ministry data show. The country's LPG imports amounted to about 6mn t in 2023, energy minister Bahlil Lahadalia says. This contrasts with imports of just over 7mn t, relatively unchanged from a year earlier, Kpler data show. The country imported around 369,000 b/d of gasoline and 29,000 b/d of crude. The energy ministry in August announced plans to boost oil and gas output by reactivating up to 1,500 idle wells, drilling more than 1,000 new wells a year and increasing recovery rates at existing wells to 50pc from 30pc. Indonesia gas production Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

South Sudan eyes restart of Dar Blend crude exports


24/09/17
24/09/17

South Sudan eyes restart of Dar Blend crude exports

London, 17 September (Argus) — South Sudan is aiming to restart exports of its heavy sweet Dar Blend crude through Sudan within weeks, the country's presidency said. Around 100,000 b/d of Dar Blend has been shut in since February because of ruptures and blockages along the Petrodar pipeline which links oil fields in South Sudan to war-torn Sudan's Red Sea export terminal at Bashayer. "Sudanese engineers have accomplished the necessary technical preparations for the resumption of oil production," South Sudan said following a visit by the head of Sudan's army, Abdel Fattah Al Burhan. South Sudan said its engineers are expected to visit Sudan in the coming weeks to "familiarise themselves with the readiness of the facilities so as to jump-start production". Previous attempts to repair and restart pipeline flows have been hampered by the civil war in Sudan, which pits the army against the paramilitary Rapid Support Forces. International efforts to forge a ceasefire have been unsuccessful, with the war now in its 18th month. Production of South Sudan's medium sweet Nile Blend crude grade has not been impacted, as it is transported to Bashayer through the Greater Nile pipeline. Nile Blend now accounts for all of South Sudan's production, which stood at 60,000 b/d in August compared with around 150,000 b/d before the closure of the Petrodar pipeline, according to Argus estimates. The closure of the pipeline has put immense economic strain on South Sudan, which depends on oil sales for more than 90pc of government revenues. Meanwhile, South Sudan has postponed long-delayed national elections scheduled for December by two years. The move is seen by many as a bid by the country's leadership to cling onto power. By Aydin Calik Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

NGL pipeline burning in La Porte, Texas: Update


24/09/16
24/09/16

NGL pipeline burning in La Porte, Texas: Update

Houston, 16 September (Argus) — A natural gas liquids (NGL) pipeline operated by Energy Transfer Partners caught fire in La Porte, Texas, this morning, sending a bright orange plume of flame hundreds of feet into the air and leading to evacuations of nearby homes and businesses. The fire started at a valve station for a 20-inch NGL line, Energy Transfer said, located in a right-of-way shared with a number of other pipelines and high voltage power lines about 17 miles southeast of downtown Houston. Energy Transfer said the line has been isolated so that the residual product in the line can safely burn itself out. "We have no timeline at this point on how long that process will take, but we are working closely with local authorities," the company said. In a broadcast press conference today La Porte officials said it would likely be many hours until the fire burns out. Energy Transfer said it was aware of reports indicating that an unknown passenger car entered the right-of-way and struck the valve location. A vehicle could be seen very close to the flaring pipeline in video broadcasts of the fire this morning. The fire was first reported at 11:24am ET by the La Porte Office of Emergency Management via the X social media platform. The fire is near the intersection of Somerton Drive and Spencer Highway. First responders, including Harris County hazardous materials officials, were on the scene at the time of the post. The right-of-way includes a refined products pipeline system, various petrochemical pipelines, a Shell butadiene line, a Chevron ethylene line and an Enbridge Energy natural gas pipeline. Chevron said its pipeline was not affected by the fire. A shelter-in-place order has been issued for the nearby San Jacinto College campus and La Porte is recommending an evacuation of all homes and businesses between Luella and Canada roads. By Michael Camarda and Gordon Pollock Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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