US majors offer up mixed fortunes on M&A
ExxonMobil's $64.5bn acquisition of shale giant Pioneer Natural Resources is already showing signs of paying off, but Chevron's $53bn takeover of US independent Hess is stuck in limbo because of a simmering dispute with its major rival over a Guyanese oil stake that is likely to drag on into 2025.
The contrasting fortunes of the two blockbuster deals that ushered in a frantic round of dealmaking in the shale patch, with billions of dollars of assets changing hands, could have far-reaching consequences for ExxonMobil and Chevron as the two US majors double down on fossil fuels and chase low-cost and lower-carbon barrels that can withstand the challenges of the energy transition. The stakes are high as both have set out ambitious plans to ramp up shareholder returns in the forthcoming years.
In a preview of its global outlook due out later this month, ExxonMobil forecasts that world energy demand will be 15pc higher in 2050, with oil demand holding firm around 100mn b/d, even as renewables and natural gas grow. "We anticipate this year will be a record, and then next year will be a record, so demand continues to be fairly healthy from an oil standpoint," chief executive Darren Woods says.
ExxonMobil looks set to extend its lead over its smaller rival Chevron after closing the Pioneer deal in record time. Woods is citing "extremely encouraging" early results from the integrated assets to hint at even greater cost savings from the Pioneer takeover than the initially estimated $2bn/yr. ExxonMobil has already started to deploy its more efficient "cube" production strategy to the Pioneer assets, which enables it to drill multiple horizontal wells in stacked intervals from a single location. Pioneer, in turn, is contributing expertise in logistics and procurement.
ExxonMobil is now producing more oil than at any other time since the Exxon and Mobil merger in 1999, after achieving record second-quarter output from the Permian and the prolific Stabroek block off Guyana. Output is set to grow further as the latest results only included two months of production from the Pioneer assets.
I drink your milkshake
The story is different over at Chevron, where chief executive Mike Wirth has had to put on a brave face after having his hopes of closing the Hess deal by the end of the year dashed. International arbitration to resolve a disagreement with ExxonMobil over its right of first refusal to a 30pc stake in the Stabroek block currently held by Hess — and the main impetus behind Chevron's proposed takeover — will now not take place until May 2025. That will likely postpone the deal's closure until late 2025, almost two years after it was first announced.
Wirth does not expect the spat to be settled outside of arbitration, saying such a strategy had been tried but "that time has now passed". With the Hess deal on hold, Wirth is talking up Chevron's robust pipeline of projects from the Permian to the Gulf of Mexico and Kazakhstan. Wirth has not ruled out further acquisitions, even as the company waits for the Hess deal to be completed. "If another opportunity were to present itself that was compelling, we're certainly in a position to consider it," he says.
But the Hess deal, with its highly prized Guyana asset, is seen as essential by some analysts for the company to answer questions over its long-term growth plans. That ExxonMobil is refusing to back down shows the extent to which the company is determined to protect its rights over one of the biggest discoveries seen in recent decades, with an estimated 11bn bl of recoverable oil.
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Opec downgrades oil demand growth forecasts
Opec downgrades oil demand growth forecasts
London, 12 August (Argus) — For the first time, Opec has downgraded its global oil demand growth forecasts for 2024 and 2025. In its latest Monthly Oil Market Report (MOMR), the group has revised down its demand growth projection for 2024 to 2.11mn b/d from 2.25mn b/d, having previously kept the forecast for this year unchanged since it was first released in July 2023. Opec put the revision primarily down to "softening expectations for China's oil demand growth" and actual data received for the first half of the year. It now sees Chinese oil demand growing by 700,000 b/d this year, down by 60,000 b/d compared with last month's report. Opec has also cut its oil demand growth forecast for next year by 60,000 b/d to 1.78mn b/d, driven by a lower than previously expected rise in Middle East consumption. The group's latest oil demand growth projections narrow the gap with other forecasters such as the IEA and EIA, but Opec's figures are still comparatively bullish. The IEA projects oil demand will increase by 970,000 b/d this year, while the EIA sees demand rising by 1.1mn b/d. Opec notes that its new growth forecast of 2.11mn b/d for this year is "well above the historical average of 1.4mn b/d seen prior to the Covid-19 pandemic". Opec puts recent oil price falls down to sentiment "driven by speculative selloffs, easing geopolitical risk premiums and mixed economic indicators". Sentiment was also affected by uncertainty surrounding high interest rates in the US, concerns about China's economy and oil demand growth, as well as a slower-than-expected onset of the driving season, it said. On the supply side, the group has kept its non-Opec+ liquids growth estimate for 2024 and 2025 unchanged at 1.23mn b/d and 1.10mn b/d, respectively. It said non-Opec+ growth for 2024 would be mostly driven by the US, Canada and Brazil. Opec+ crude production — including Mexico — rose by 117,000 b/d b/d to 40.907mn b/d in July, according to an average of secondary sources that includes Argus . This is around 2.09mn b/d below Opec's projected call on Opec+ crude for this year, which it sees at 43mn b/d. By Aydin Calik Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Oil emissions progress slows ahead of Cop 29
Oil emissions progress slows ahead of Cop 29
London, 12 August (Argus) — After a unanimous agreement to "transition away from fossil fuels" at last year's UN Cop 28 summit in Dubai, the oil industry says it stands by its net-zero goals. But its short-to-medium term focus on increasing production appears in conflict with last year's agreement, and with the ambition required from the forthcoming round of national climate plans, expected over the next year. Large Mideast Gulf national oil companies (NOCs) have mostly stuck to their net zero milestone targets, but continue to avoid making any commitments concerning the Scope 3 emissions that come from the use of their products. These account for the overwhelming majority of oil and gas company emissions. State-controlled Saudi Aramco is keeping its ambition to reduce by 15pc the carbon intensity of its upstream production by 2035, targeting 7.7kg of CO2 equivalent per barrel of oil equivalent (CO2e/boe) against the company's 2018 baseline figure of 9.1kg CO2e/boe. It intends to achieve net zero Scope 1 and 2 emissions from its operations by 2050. But last year, Aramco's upstream carbon intensity measure increased by 3.2pc, compared with 2022, to 9.6kg CO2e/boe, in part because the company increased its gas production. Aramco says gas is more energy and carbon-intensive to produce, despite being a lower-emitting fuel when it is used. Riyadh recently put the brakes on Aramco's plan to lift crude production capacity to 13mn b/d from 12mn b/d by 2027 as it ushers in an ambitious gas expansion programme, which fits the view within the industry that gas is a "transition fuel". Aramco plans to increase its gas production by more than 60pc by 2030, compared with its 2021 production. Meanwhile, lower overall hydrocarbon production helped decrease Aramco's Scope 1 emissions by 2.4pc between 2022 and 2023. Its Scope 2 emissions jumped by 26.3pc, although this was mainly because of the inclusion in Aramco's greenhouse gas (GHG) emissions inventory of the new Jazan refinery, which became fully operational in early 2023. Slower burn Riyadh is also turning to renewables, with the aim of delivering significant growth in lower-emission power to the national grid and providing an opportunity for Aramco to lower its Scope 2 GHG emissions. Domestic renewable power will free up more crude production for exports and reduce crude burn. Riyadh plans to increase the share of renewables in its oil-and-gas-heavy energy mix to 40pc by 2030. How Saudi Arabia could change its climate plans by early next year remains to be seen. All Cop parties have to reflect the outcome of Dubai, including transitioning away from fossil fuels, in their new nationally determined contributions (NDCs) — climate plans — due by February 2025. Saudi energy minister Prince Abdulaziz bin Salman said in January that the Cop 28 text was something his country "was willing to agree on because this is something we are doing". Oil and gas producers the UAE, Azerbaijan and Brazil — the so-called Cop presidencies Troika — last month encouraged parties to "step up the work" on NDCs and keep the Paris Agreement's 1.5°C target in reach. The three countries called on "early movers", including themselves, to signal their commitment as early as September, but always within "national capacities". "The ambition of keeping 1.5°C within reach in a nationally determined manner and building global resilience will be determined by our resolve to act at this critical moment," the three presidencies said. In Abu Dhabi, state-owned Adnoc is moving forward with plans to raise its crude production capacity to 5mn b/d by 2027, after bringing this to 4.85mn b/d earlier this year. It is also heavily investing in expanding its LNG business. But it has brought forward its ambition to achieve net zero across its operations by five years to 2045. By 2030, it aims to reduce its upstream GHG intensity by 25pc compared with its 2019 level. This metric stayed flat at 7.2kg CO2e/boe in 2023, although Adnoc notes its performance is in the industry's top tier. Adnoc's key advantage is that since 2022, all its onshore activities have received "clean electricity" through the grid from nuclear and solar facilities. The western majors are sticking to milestone targets that were already in place last year. Shell made a slight adjustment to its 2030 reductions goal for Scope 3 emissions coming from the use of its oil products by introducing a target range of 15-20pc, against a 20pc target previously. BP is sticking to its interim targets for 2025 and 2030, which it revised at the start of 2023, as is TotalEnergies. In the US, Chevron has kept to its target for a portfolio carbon intensity of 71g CO2e across Scopes 1, 2 and 3 by 2028 — representing a 5.2pc decrease against the company's 2016 baseline. ExxonMobil's emission-reduction plans remain the same, aiming to achieve "a 20-30pc reduction in company-wide GHG intensity" by 2030. Despite the majors making plenty of progress in nearing these 2025-30 emissions-reduction milestones in 2022 and 2023, the latest data reveal this progress began to slow last year. Shell's Scope 1 and 2 emissions fell by just one percentage point in 2023 to 31pc below their 2016 baseline, after having fallen by 12 percentage points the year before. BP's Scope 1 and 2 emissions cuts, compared with its 2019 baseline, remained steady at 41pc between 2022 and 2023. TotalEnergies was one major that improved its progress on Scope 1 and 2 last year, reducing these emissions by 24pc against its 2015 baseline. Although the progress at BP and TotalEnergies means those companies have already dipped below their Scope 1 and 2 emissions targets for 2025, the UK major noted that its "operational emissions are expected to fluctuate" as new oil and gas projects come on stream. This is an important point, especially as a key factor in the majors' impressive emissions-reduction performance from 2022 has a simple explanation — Russia. As they wrote off billions of dollars of Russian assets, production and any associated emissions took a huge hit. Collectively, the majors' production from 2021 to 2023 fell by 3.7pc to 14.44mn b/d of oil equivalent (boe/d), with Shell and TotalEnergies' output declining by 11.2pc and 11.9pc, respectively. Production speed-up Now their production is growing again, with a vengeance. Year to date, they have increased their output by 5.9pc to a combined 15.29mn boe/d. BP, which in 2020 planned to slash its production to 1.5mn boe/d by 2030, now recognises this is likely to remain above its revised target of 2mn boe/d. TotalEnergies wants to grow its energy production, including electricity generation, by 4pc/yr to 2030, but this includes room for 2-3pc/yr growth in oil and gas production too. Shell sees plenty of room to grow its gas production, if not its oil output. Chevron and ExxonMobil, which were never signed up to net zero, continue to raise oil and gas output. Last year's Cop 28 summit drew intense scrutiny from campaigners, particularly as its president, the UAE's special envoy for climate change Sultan al-Jaber, was steadfast in bringing oil and gas companies to the table. This year's summit host, Azerbaijan, is drawing similar attention. Cop 29 president-designate Mukhtar Babayev, the country's ecology minister, has responded by calling on oil producing countries and companies to contribute to a climate fund. The fund will target $1bn, a tiny drop in the climate finance ocean. The move should revitalise the conversation about polluters paying to tackle climate change, but the oil industry has remained silent so far. By Bachar Halabi, Jon Mainwaring and Caroline Varin Majors' emissions progress Scope 1 and 2 Scope 3 BP 41pc reduction in emissions by 2023 from 2019 baseline 13pc reduction in emissions by 2023 from 2019 baseline Chevron 5.07pc reduction in portfolio carbon intensity to 71g CO2e/MJ achieved by 2023 from 2016 baseline ExxonMobil 11.7pc reduction in GHG emission intensity over 2016-2023 - Shell 31pc reduction in absolute emissions over 2016-2023 6.3pc reduction by 2023 in net carbon intensity against 2016 baseline TotalEnergies 24pc reduction achieved by 2023 against 2015 baseline 35pc reduction in scope 3 emissions from oil output over 2016-2023 Majors' emissions goals Scope 1 and 2 Scope 3 Net Zero by 2050? BP* 20pc reduction by 2025, 50pc by 2030 10-15pc reduction by 2025, 20-30pc by 2030 Yes Chevron** >5pc reduction in carbon intensity across Scopes 1, 2 and 3 by 2028 No ExxonMobil† 20-30pc reduction in GHG intensity by 2030. Net zero by 2050 - No Shell‡ 50pc by 2030 9-13pc reduction by 2025, 15-20pc by 2030, 100pc by 2050 Yes TotalEnergies# >17pc reduction by 2025, >34pc reduction by 2030 40pc by 2030 (oil production only) Yes *2019 baseline. Scope 3 targets lowered in early 2023 from 20pc by 2025 and 35-40pc by 2030. **Chevron uses a portfolio carbon intensity target: 71g CO2e/MJ by 2028, from 74.9g CO2e/MJ in 2016. †2016 baseline. ‡2016 baseline. Scope 3 targets refer to net carbon intensity, rather than absolute emissions. #2015 baseline. TotalEnergies has no Scope 3 targets for gas production Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Australia’s Beach Energy cuts gas reserves estimate
Australia’s Beach Energy cuts gas reserves estimate
Sydney, 12 August (Argus) — Australian independent Beach Energy has slashed its total proven and probable (2P) gas reserves following revisions of some assets under a strategic review concluded in June. The firm revised its estimated oil and gas reserves downwards by 31.5mn bl of oil equivalent (boe) in 2023-24, of which 11.5mn boe was attributed to re-evaluation at Enterprise reservoir. This, combined with a 7pc on-year drop in output to 18.2mn boe in 2023-24, brought the firm's 2P oil and gas reserves to 205mn boe as of 30 June, down by 20pc from 255mn boe at the same date last year . Beach maintained its production guidance for 2024-25 of 17.5mn-21.5mn boe, which it said is wider than typical to account for uncertainty on the timing of Waitsia's production ramp-up. Pressures are declining faster than anticipated at Beach's Enterprise and Thylacine North fields in Victoria state's Otway basin, Beach said on 12 August when announcing the company's full-year results to 30 June. Reprocessed seismic testing at the Beharra Springs Deep field and results at the Beharra Springs Deep 2 well in Western Australia's Perth basin also led to a downgrade in estimates. "Following the Enterprise field coming on line on 12 June, which has flowed at peak rates of up to 68 TJ/d (1.8mn m³/d), early pressure data indicates a smaller resource pool than originally estimated," Beach said. Beach disclosed in June that drilling results at the Kupe South 9 well in New Zealand's Taranaki basin had shown low gas flow rates , contributing to cumulative impairments in 2023-24 of A$1.1bn ($720mn). A lack of political support for the gas sector and the designation of Kupe as a non-core asset has led the firm to canvass offers for selling the asset, Beach's chief executive officer Brett Woods said on 12 August, but no offers have yet been fielded. The significantly delayed 250 TJ/d Waitsia stage 2 project, co-owned with Japanese trading firm Mitsui, will deliver first gas in early 2025, Woods said, reiterating the most recent schedule announced in April for the A$1.2bn-A$1.3bn project. The Waitsia partners have an agreement with the North West Shelf (NWS) joint venture for processing of 7.5mn t of LNG, originally scheduled to occur between the second half of 2023 and the end of 2028, but the tone from NWS operator Woodside Energy was "supportive" for extending that timeline, Woods said. First gas from the Thylacine West 1 and 2 wells will flow to the Otway gas plant in July-December, Beach said, following the arrival of pipeline equipment in Australia. The Adelaide-based firm posted a A$475mn net loss for the 2023-24 fiscal year, down from 2022-23's net profit of A$401mn. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Can Opec+ afford to raise output?
Can Opec+ afford to raise output?
The plan to begin returning oil to the market from October might need to be rethought, write Aydin Calik and Nader Itayim London, 9 August (Argus) — Falling oil prices are casting doubt on whether Opec+ members will unwind some of their production cuts from October as planned. Oil prices have fallen by $8-10/bl over the past month, leading observers to question whether the market needs more Opec+ supply. But Opec+ delegates say it is too soon to know whether a change in production policy will be required. Eight Opec+ members are expected to unwind 2.2mn b/d of voluntary production cuts over a 12-month period starting in October — as agreed in their ministerial meeting in June. This would see the collective output target of these countries increase by a hefty 540,000 b/d by the end of this year and another 1.92mn b/d by September 2025. But it was always made clear that the return of this supply would depend on market conditions. A decision on whether to begin unwinding could come in early September, leaving several weeks for Opec+ to monitor market developments. Will markets recover by then? The recent slide in oil prices is an overreaction to weaker-than-expected jobs data in the US and a return to $80/bl is already under way, one Opec+ delegate says. The jobs data stoked fears that the world could be headed for a US-led global recession, prompting a sharp sell-off in commodities and global equities. Another delegate insists that the weakening of oil prices was neither reflective of supply and demand fundamentals nor of elevated geopolitical risks. They also say they expect prices to strengthen in the next few weeks, noting a recent rebound in financial markets. For now, there is an expectation among delegates that the eight Opec+ members will adhere to their plan to unwind supply cuts, particularly given their view that oil market physical fundamentals remain strong. But even if the expected demand surge in the second half of the year does not materialise, any move to delay the plan might still receive pushback from some members that are eager to return output. The Opec+ deal in June was a compromise between members that argued cuts had gone on too long and those that stressed the need to keep production in check. But if oil prices continue to slide, it is possible that the group of eight will alter the plan, a delegate says. This could take the shape of a pause, as ministers have previously suggested, or potentially even a slowdown of the return, meaning less oil would start to come back to the market in October than originally planned. Output at three-year low The recent slide in oil prices comes despite a series of output cuts by Opec+ that have removed 3.65mn b/d from the market since October 2022, Argus estimates. Production by members subject to cuts fell for a fourth straight month in July as serial overproducer Kazakhstan finally made good on its promise to reduce output. The group's production fell by 50,000 b/d to 33.89mn b/d, the lowest since May 2021 and exceedingly close to its 33.85mn b/d target. Within the group, the nine Opec members subject to cuts were 220,000 b/d above their target in July, while the nine non-Opec members were 180,000 b/d below. Output in July could have been lower still. Iraq's production increased by 50,000 b/d to 4.25mn b/d — 250,000 b/d above its formal output target and 320,000 b/d above its effective target under its plan to compensate for overproducing in the first half of the year. Russia — which is not due to begin its compensation cuts until October — reduced output by 30,000 b/d to 9.05mn b/d but remained 70,000 b/d above target. Moscow blames this on "problems with the supply schedule". Kazakhstan drove down production by 80,000 b/d to 1.46mn b/d, which was 10,000 b/d below its formal target but still 10,000 b/d above its effective target based on its compensation plan. Opec+ crude production mn b/d Jul Jun* Target† ± target Opec 9 21.45 21.38 21.23 0.22 Non-Opec 9 12.44 12.56 12.62 -0.18 Total Opec 18 33.89 33.94 33.85 0.04 *revised †includes additional cuts where applicable Opec wellhead production mn b/d Jul Jun Target† ± target Saudi Arabia 9.00 8.95 8.98 0.02 Iraq 4.25 4.20 4.00 0.25 Kuwait 2.38 2.40 2.41 -0.03 UAE 2.94 2.94 2.91 0.03 Algeria 0.91 0.91 0.91 0.00 Nigeria 1.46 1.44 1.50 -0.04 Congo (Brazzaville) 0.24 0.26 0.28 -0.04 Gabon 0.21 0.23 0.17 0.04 Equatorial Guinea 0.06 0.05 0.07 -0.01 Opec 9 21.45 21.38 21.23 0.22 Iran 3.35 3.31 na na Libya 1.20 1.22 na na Venezuela 0.88 0.86 na na Total Opec 12^ 26.88 26.77 na na †includes additional cuts where applicable ^Iran, Libya and Venezuela are exempt from production targets Non-Opec crude production mn b/d Jul Jun* Target† ± target Russia 9.05 9.08 8.98 0.07 Oman 0.76 0.76 0.76 0.00 Azerbaijan 0.49 0.49 0.55 -0.06 Kazakhstan 1.46 1.54 1.47 -0.01 Malaysia 0.36 0.36 0.40 -0.04 Bahrain 0.18 0.18 0.20 -0.02 Brunei 0.07 0.07 0.08 -0.01 Sudan 0.02 0.02 0.06 -0.04 South Sudan 0.05 0.06 0.12 -0.07 Total non-Opec† 12.44 12.56 12.62 -0.18 *revised †includes additional cuts where applicable Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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