IOCs, contractors urge PdV to pay debts

Spanish Market: Crude oil, Natural gas
28/05/21

Foreign oil companies and local contractors are urging the Venezuelan government and state-owned PdV to pay debts and reform oil legislation to give the private sector control over joint ventures.

A letter addressed to National Assembly oil and energy commission head Angel Rodriguez by the foreign oil companies association (AVHI), the oil services chamber (CPV) and gas processors chamber (AVPG) calls for "a permanent dialogue" between the oil ministry, PdV, the legislature and the industry chambers to address contract compliance with "existing joint ventures and natural gas licenses; timely payment of financial, commercial and dividend debts; and the optimization of autonomous operational, financial, labor, security and environmental management of the joint ventures."

The letter signed by AVHI president Luis Xavier Grisanti, CPV president Reinaldo Quintero and AVPG president Miguel Rivero coincides with a government-led effort to reform Venezuela's oil law to pave the way for execution of new services contracts.

Among AVHI's members are US major Chevron; China's state-owned CNPC; Russia's state-controlled Rosneft; European firms Eni, Shell, Total, Equinor, Galp and Perenco; India's ONGC Videsh; and Argentina's Pluspetrol.

"The current situation is critical because of the drop in production and financial and operational disinvestment caused by internal and external factors such as, for example, US sanctions," the letter says.

PdV finance and oil ministry officials tell Argus that PdV's accumulated debt and dividend arrears with foreign oil companies and contractors totals up to $25bn.

In recent years, the company has paid some of this debt with crude and products exports mainly benefitting some of its foreign partners.

Foreign joint venture shareholders will not commit to significant new investments until an effective mechanism is in place to accelerate payment of legacy debts, and the oil and gas laws are amended to improve terms and conditions to allow foreign companies to acquire majority stakes in upstream projects, guarantee operational autonomy of the joint ventures and services contracts, and allow partners to independently market their share of offtake, the officials added.

Institutional communications between the Maduro government and the country's private oil and gas sectors including PdV's foreign joint venture partners have been sporadic at best since 2017 as PdV's crude production decline accelerated and its local refineries mostly shut down.

Currently Venezuela produces about 500,000 b/d of crude and its operational refining capacity is about 230,000 b/d out of 1.3mn b/d of installed capacity.

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31/12/24

US crude output at record 13.46mn b/d in Oct: EIA

Calgary, 31 December (Argus) — US crude production in October rose to a record high 13.46mn b/d on sustained strength in Texas and New Mexico, the Energy Information Administration (EIA) said today in its Petroleum Supply Monthly report. Output rose from 13.2mn b/d in September and from 13.15mn b/d in October 2023. The prior record of 13.36mn b/d was set in August. Texas, home to 44pc of the country's crude production, pumped out a record 5.86mn b/d in October, up from 5.8mn b/d in September and up from 5.57mn b/d in October 2023. New Mexico, which shares the prolific Permian basin with Texas, produced 2.08mn b/d in October, ticking down by 5,000 b/d from record highs set in August and September but up from 1.8mn b/d in October 2023. US offshore crude output in the Gulf of Mexico rebounded to 1.85mn b/d in October after hurricane activity in September cut production to 1.57mn b/d. Still, US Gulf of Mexico output was down from 1.94mn b/d in October 2023. Monthly production changes inland were mixed, with North Dakota falling to 1.16mn b/d in October from 1.21mn b/d in the month prior. Bakken shale basin producers had to contend with wildfires during the month and effects are still lingering for some, state officials said earlier this month. Colorado output rose in October to the highest in more than four years at 499,000 b/d. This was up from 476,000 b/d in September and the highest level for the state since March 2020. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: 2025 Hardisty heavy diffs may remain strong

31/12/24

Viewpoint: 2025 Hardisty heavy diffs may remain strong

Calgary, 31 December (Argus) — Heavy crude spot differentials in Alberta are expected to remain strong into next year, even with growing oil sands production and possible US import tariffs. After years of cost-overruns and construction delays, the 590,000 b/d Trans Mountain Expansion (TMX) commenced on 1 May, nearly tripling the capacity of crude able to reach Canada's Pacific coast and providing Alberta oil sands producers with increased access to buyers on the US west coast and Asia-Pacific. Extra egress capacity for Alberta crude westward has pulled previously apportioned volumes away from Enbridge's 3mn b/d Mainline system — Canada's main method of export to ship crude south to US refiners in the midcontinent and Gulf coast. In the fourth quarter, apportionment averaged just over 1pc for both light and heavy crude on the Mainline, significantly lower than the average apportionment of 21pc for lights and heavies in the fourth quarter last year. While president-elect Donald Trump's looming blanket tariff on all Canadian imports would re-direct more Albertan crude westward via TMX to Asia- Pacific buyers, many believe the tariff would be too harmful to US midcontinent refiners for Trump to actually carry out his threat. Prior to TMX's commencement, high apportionment combined with rising crude production heading into the winter months forced more crude onto railcars, which typically requires a $15/bl to $20/bl spread between Western Canadian Select (WCS) at Hardisty Alberta, and Houston, Texas, for uncommitted shippers to profit. With the redirection of apportioned volumes to buyers in the west, Canadian heavy spot differentials in Alberta have strengthened in a quarter when discounts have generally widened in recent years. Argus's WCS Hardisty assessment averaged a $12.08/bl discount to the CMA Nymex WTI during fourth quarter Canadian trade cycle dates, $11.52/bl stronger than the $23.61/bl discount averaged in the fourth quarter a year prior. Yet, crude output in Alberta's key oil sands is expected to rise heading into 2025, with production levels reaching record-high levels this year. Alberta crude output was 4.2mn b/d in October, according to the latest Alberta Energy Regulator (AER) data, up by 9.4pc year from a year earlier and the second highest monthly production on record. Alberta oil sands producers, meanwhile, have increased their crude production guidance for next year. Suncor expects to pump out 810,000-840,000 b/d across its upstream sector in 2025, up by 5pc from 2024. Cenovus expects to increase production next year by 4pc to between 805,000-845,000 b/d of oil equivalent (boe/d), and Imperial Oil plans to boost upstream production by 2pc to 433,000-456,000 boe/d. Egress capacity remains ample despite rising production heading into 2025. Total crude pipeline egress capacity out of Alberta is expected to be over 4.6mn b/d in 2025, with shippers still yet to utilize uncommitted space on the 890,000 b/d Trans Mountain pipeline. About 712,000 b/d or 80pc of the system is reserved for contracted shippers, with the remaining 20pc available for uncontracted shipments. With unconstrained egress capacity expected to persist, Suncor and Cenovus have both assumed WCS at Hardisty will average a strong $14/bl discount to WTI in 2025. In the near term, Trump's plans to impose a blanket 25pc tariff on all Canadian imports would threaten some US demand for Canadian crude. Yet, while some traders are pricing in the reality of US tariffs, most market participants are skeptical of whether Trump's tariff plans would extend to Canadian crude due to the co-dependency between Albertan producers and some US refiners. US midcontinent refiners, many of whom were financial backers of Trump's 2024 presidential campaign, are dependent on Canadian crude given a lack of access to alternative heavy sour crudes suited for their refineries. Canadian grades represent approximately 70pc of the US midcontinent refinery feedstock, with the remainder largely sourced in the US. US importers may take more crude from countries including Saudi Arabia, given the country has plenty of spare capacity to increase the production of heavy sour crude favored by US midcontinent refiners. However, replacing Canadian crude with waterborne supplies would result in a substantial increase in tanker demand. In August, only around 370,000 b/d of the 3.8mn b/d of Canadian crude imported by US refiners moved on tankers, Vortexa data show. Even if US refiners can replace Canadian and Mexican heavy crude, they are expected to face higher landed costs and, potentially, less reliable supplies. By Kyle Tsang Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US Supreme Court tees up more energy cases

31/12/24

Viewpoint: US Supreme Court tees up more energy cases

Washington, 31 December (Argus) — The US Supreme Court is on track for another term that could significantly affect the energy sector, with rulings anticipated in the new year that could narrow environmental reviews and challenge California's authority to set its own tailpipe standards. The Supreme Court earlier this month held arguments in Seven County Infrastructure Coalition v Eagle County, Colorado , a case in which the justices are being asked to decide whether federal rail regulators adequately studied the environmental effects of a proposed 88-mile railway that would transport 80,000 b/d of crude. A lower court last year found the review, prepared under the National Environmental Policy Act (NEPA), should have analyzed how building the project would affect drilling and refining. Business groups want the Supreme Court to issue an expansive ruling that would limit NEPA reviews only to "proximate" effects, such as how rail traffic could affect nearby wildlife, rather than reviewing distance effects. The court recently agreed to hear a separate case that could restrict California's unique authority under the Clean Air Act to issue its own greenhouse gas regulations for newly sold cars and pickup trucks that are more stringent than federal standards. Oil refiners and biofuel producers in that case, Diamond Alternative Energy v EPA , say they should have "standing" to advance a lawsuit challenging those standards — even though they could now show prevailing in the case would change fuel demand — based on the alleged "coercive and predictable effects of regulation on third parties". These two cases, likely to be decided by the end of June, follow on the heels of the court's blockbuster decision in June overturning the decades-old "Chevron deference", a foundation for administration law that had given federal agencies greater flexibility when writing regulations. Last term, the court also limited agency enforcement powers and halted a rule targeting cross-state air pollution sources. This term's cases are unlikely to have as far-reaching consequences for the energy sector as overturning Chevron. But industry officials hope the two pending cases will provide clarity on issues that have been problematic for developers, including the scope of federal environmental reviews and the ability of industry to win legal "standing" to bring lawsuits. Two other cases could have significant effects for the oil sector, if the court agrees to consider them at a conference set for 10 January. Utah has a pending complaint before the court designed to force the US to dispose of 18.5mn acres of "unappropriated" federal land in the state, including oil-producing acreage. Utah argues that indefinitely retaining the land — which covers about a third of Utah — is unconstitutional. In another pending case, Sunoco and other oil companies have asked for a ruling that could halt a series of lawsuits filed against them in state courts for alleged damages from greenhouse gas emissions. President-elect Donald Trump's re-election could create complications for cases pending before the Supreme Court, if the incoming administration adopts new legal positions. Trump plans to nominate John Sauer, who successfully represented Trump in his presidential immunity case, as his solicitor general before the Supreme Court. By Chris Knight Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Permian waiting on new gas lines

30/12/24

Viewpoint: Permian waiting on new gas lines

Houston, 30 December (Argus) — Natural gas prices in the Permian basin of west Texas and southeast New Mexico fell to historic lows in 2024, with increased takeaway out of the region likely not picking up before 2026. Gas in the Permian basin is fundamentally tied to crude economics, with associated gas being a byproduct of crude-directed drilling. US benchmark WTI values continued to boost crude output in 2024, with month-ahead Nymex WTI futures for delivery in 2024 averaging $76.20/bl, down from $78/bl in 2023, but still much higher than in previous years since 2014. As of the week ended 20 December, the Permian basin rig count stood at 304 rigs, down by only five rigs from the same time a year prior , according to oilfield service provider Baker Hughes. The vast majority of those rigs were crude-directed. Strong associated gas output has frequently pushed spot prices at the Waha hub in west Texas into negative territory since 2019. Waha prices held positive through 2021, helped in part by increased takeaway capacity, before turning negative in four trading sessions in 2022 and seven sessions in 2023. Negative Waha prices were a much more regular feature in 2024, with sellers needing to pay buyers to take Permian gas for about 47pc of the trading sessions throughout January-November. The Waha index fell to -$7.085/mmBtu on 29 August, a historic low. But prices averaged above $2/mmBtu from the middle of November into the first half of December , buoyed by seasonally stronger demand and the end of planned and unplanned maintenance on several Permian pipelines. Spot prices at the Waha hub returned below $1/mmBtu in the final full week of December, as unseasonably mild weather crimped demand. The January-March block for Waha was $2.235/mmBtu as of 27 December, according to Argus forward curves. Spot prices often have been negative despite growing export demand from the LNG sector and for pipeline flows to Mexico. Even excluding potential flows through the most recently commissioned 1.7 Bcf/d (17.6bn m³/yr) ADCC pipeline in south Texas, aggregate feedgas flows to US liquefaction facilities edged higher to 12.9 Bcf/d in January-November from 12.75 Bcf/d a year earlier. Pipeline exports to Mexico rose to 6.06 Bcf/d in January-September from 5.7 Bcf/d a year earlier, US Energy Information Administration (EIA) data show. Pipelines out of the Permian have typically taken little time to reach capacity, as was the case when US firm Kinder Morgan's Gulf Coast Express and Permian Highway pipelines opened in 2019 and 2020, respectively, and more recently in 2021 with the Whistler pipeline. Similarly, flows on the 2.5 Bcf/d Matterhorn Express Pipeline quickly ramped up in October after the line began taking on gas in September. Takeaway capacity out of the Permian is not planned to rise much further before 2026. Several large new pipelines remain under construction or in the planning stage, including the 2 Bcf/d Apex and 2.5 Bcf/d Blackcomb pipelines, both due to enter service in 2026. Oneok's 2.8 Bcf/d Saguaro Connector pipeline is not expected before 2027. Targa's proposed Apex Pipeline, which would link the Permian to the Port Arthur LNG project, remains under consideration. Oversupply led to output cuts in more gas-directed fields in the US in 2024, but Permian gas production has been immune to the low price environment. Low or negative prices at Waha may eventually spur output cuts in the oil-oriented Permian, but that would require WTI prices falling closer to breakeven. Permian producers need WTI to be at a minimum of $62/bl to profitably drill a new well, while the breakeven price for an existing well was $38/bl, according to an April survey by consumer data platform Statista. Producers such as Chevron do plan to curb spending in the region by as much as 10pc in 2025. Chief executive Mike Wirth noted in the company's third quarter 2024 earnings call that Permian "growth will become less the driver and free cash flow will become more of the driver". Yet Permian gas, which accounts for roughly a fifth of US output, is still set to rise to 26.1 Bcf/d in 2025 from a projected 24.8 Bcf/d in 2024, according to the US EIA's December Short-Term Energy Outlook . By David Haydon Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Trump tariffs may shift crude flows to USWC

30/12/24

Viewpoint: Trump tariffs may shift crude flows to USWC

Houston, 30 December (Argus) — President-elect Donald Trump's proposed 25pc tariff on Canadian and Mexican imports could redirect key imported oil grades from the US west coast, opening avenues for displaced Latin American crudes to reappear. The tariffs, which Trump announced on 25 November, could displace about 9pc of the crude US west coast refiners import. Canadian crude flows from the newly expanded 890,000 b/d Trans Mountain pipeline system, which recently have drawn purchases in the US west coast, would force barrels to Asia-Pacific . Mexican crude sellers would divert crude to other outlets as well, like Europe or Asia-Pacific. Refiners on the US west coast increased purchases of Canadian grades after the May startup of the Trans Mountain Expansion (TMX). Cheaper prices and closer proximity to Vancouver, British Columbia, where TMX crude loads, allowed the heavy sour crudes to find favor along the US west coast. But the proposed tariffs could raise landed TMX prices, no longer making it the cheapest heavy sour option. US west coast buyers would pay a 25pc import tariff to US Customs and Border Protection on TMX crude once it has entered port. US west coast refiners received around 169,000 b/d of crude from the Vancouver area since the pipeline came on line in May, up from less than 40,000 b/d a year earlier, data analytics firm Vortexa shows. Around 60pc of Mexico's crude exports in 2024 went to the US, mostly to the US Gulf coast, according to Vortexa data. Tariffs could lead to a drop in prices to adjust to a tariffed American market or for Mexican crude going more often to other destinations such as Europe or Asia-Pacific. Spain, South Korea and India, were the second, third and fourth most common destinations for Mexican crude exports in 2024, respectively. Mexico's crude production and export infrastructure is concentrated on the country's east coast, making exports to Asia-Pacific difficult. Mexico would need to invest in building exporting infrastructure from the west coast to improve trade routes to Asia, market participants say. But Mexico's state-owned oil company Pemex plans to continue cost-cutting measures, led by recently elected President Claudia Sheinbaum, so infrastructure expansion is unlikely. Other Latin crudes could also experience a rise after being displaced by the commencement of TMX in May. Since then, heavier crudes from countries such as Colombia, Ecuador and Argentina have found more frequent routes to the US Gulf coast and Asia-Pacific. Market participants believe lighter Brazilian grades could find routes to the US west coast as TMX supply increases in China. China imported 683,000 b/d of Brazilian crudes in 2024, c ompared with 180,000 b/d of imports to the US west coast from Brazil, according to Vortexa. Sources say the tariffs are a bargaining chip by the incoming administration, and participants are skeptical they will be implemented by the Trump administration. Instead, the tariffs could exclude crude and other commodities. More than $3.3bn of goods and services cross the US-Canada border each day, according to Canada's Fall Economic Statement (FES), which notes Canada is the largest market for 36 US states. Market participants are vocally against the proposed tariffs. Tariffs on crude and refined products "will not help our industry compete, nor will they support US energy dominance and affordability for consumers," the American Fuel and Petrochemical Manufactures said on 27 November . Cenovus is also trying to explain to policy makers in the incoming Trump administration how tariffs on Canada could impact the energy system in North America. But the incoming administration shows no sign of backing off the tariffs for 2025. By Rachel McGuire and João Scheller Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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