After over 60 years of operating in the frigid but productive wilderness of Alaska, oil supermajor BP has decided to call it quits. The entirety of its Alaskan assets and operations have been sold to Hilcorp Energy for US$5.6 billion. Why Alaska and why now? Well, that’s just a natural consequence of looking for the next big thing. Once home to the largest crude oil field in America, BP’s departure from Alaska is not a surprise but a trend of things to come.
What Hilcorp purchases from BP includes the Prudhoe Bay oil field, which produced 1.5 mmb/d per day in the late 1980s as well as BP’s stake in the Trans-Alaskan Pipeline, which moves oil from the North Slope to the Port of Valdez for export. These were once crown jewels of American upstream, but are now tarnished after years of consistent production have dwindled resources. From peak production of over 2 mmb/d in the late 1980s, Alaskan crude output is now under 500,000 b/d. What oil is left is getting harder to extract, and what new oil is being found isn’t nearly enough to justify long-term investment. Particularly when cheaper alternatives that bring quicker returns – ie. shale
BP isn’t the only firm to exit Alaska, but it certainly is the largest so far. In fact, it had already halted exploration in Alaska years ago, maintaining its portfolio of existing assets only. Marathon Oil and Anadarko have already fled southwards to the shale fields in Texas and Mexico. But BP’s history with Alaska is deep, and therefore its departure is a psychological blow. Following the news, there is now already talk that ExxonMobil might be the next to leave. If it did, it would be a disappointment to the state but certainly not a surprise; oil production in the Last Frontier is projected to hit a 42-year low this year. What is BP’s loss is Houston-based Hilcorp’s gain – Hilcorp’s Alaskan operation will double in size after the deal, placing it just behind ConocoPhillips as the largest operators in the state.
Of course, this phenomenon isn’t just limited to Alaska. The North Sea, once crucial to the global crude supply chain has seen similar declines. And, consequently, the departure of once major players. Taking their place are smaller, more nimble players with a bigger risk appetite, seeking to eke out the last few drops of oil available in these maturing areas.
So where does BP and the other majors considering moving out go? The answer is predictable: shale. BP already has a toehold in US shale, purchasing BHP’s shale operations in July 2018 for US$10.5 billion its largest deal in 19 years. With assets in the Permian through the deal, BP returns once again to the US shale frontier, after being forced to leave the then-promising Permian in 2010 in the wake of the Deepwater Horizon disaster. BP CEO Bob Dudley called the Alaska deal a move to ‘steadily reshaping BP with opportunities that are more closely aligned with our long-term strategy and more competitive for our investment.’ In other words, once precious strongholds like Alaska, the North Sea and even Alberta oil sands are old hat. The cool new kid on the block is shale and, despite the challenges it faces in long term sustainability of production, all the majors and supermajors want to get into club. Well, maybe except Total and (to a lesser extent) Shell.
For all the talk of individual strategies and characteristics, the industry is still governed by a herd mentality. And the herds are migrating away from drying old pastures in search for fresh new grass elsewhere. Where they will go once the new grass dries up will be anyone’s guess.
BP’s main upstream assets in Alaska
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Many of Indonesia’s oil and gas fields, both on and offshore, are coming to the end of their commercially viable operational lifespan. More than 60% of Indonesia’s oil and more than 30% of gas production comes from late-life-cycle resources spread across the world's largest island country. Despite investment and use of enhanced oil field recovery measures, as well as increasing automation to extend the economic lifespan of these assets, decommissioning will soon become necessary.
However Indonesia, like many countries new to the prospect of decommissioning energy infrastructure, face many key technological, fiscal, environmental, regulatory and industrial capacity issues, which need to be addressed by both government and industry decision makers.
This report, commissioned by the consulting and advisory arm of London and Aberdeen based Precision Media & Communications, aims to take a look at many of the issues Indonesia and other South East Asian oil producing nations are likely to face with the prospect of decommissioning the region's oil and gas aging energy infrastructure both onshore and offshore... To find out more Click here
The signs going into OPEC’s bi-annual meeting in Vienna were broadly positive. On one hand, you had some key members – including Iraq, surprisingly – stating the need for the broader OPEC+ club to make further cuts to its supply deal. On the other hand, there was Saudi Arabia, which needed a win to support Saudi Aramco’s upcoming IPO. What emerged was a little something for everyone, that was still broadly positive but scant on the details.
The headlines spinning out of the December 5 meeting was that the OPEC+ alliance agreed to slash a further 500,000 b/d, with Saudi Arabia pledging an additional voluntary cut of 400,000 b/d. Collectively, this would raise the club’s total supply reduction to 2.1 mmb/d – or over 2% of global oil demand – up from the previous 1.2 mmb/d target. Beneath those headlines, however, the details of the new adjustment to the deal were murkier. The 500,000 b/d cut is, in fact, more of a formalisation of the current production levels within OPEC. It won’t remove additional barrels from the market, but it won’t add them back into global supply either.
Saudi Arabia is, once again, key to this equation. Even with the attacks on the heart of its crude processing facilities in September, Saudi Arabia has been shouldering the extra burden within the deal, making up for errant members that have consistently overshot their quotas. These include Nigeria and Iraq, and crucially Russia. The caveat that the new targets – especially Saudi Arabia’s voluntary portion – will only come into force if all members of the OPEC+ club implement 100% of their pledged cuts underscores the Kingdom’s new, more hardline stance that full compliance is required before it makes additional concessions. Because even with the declines in Venezuela and Iran, Saudi Arabia has trimmed its output to below 10 mmb/d in an attempt to show leadership through example. But its patience is now wearing thin.
But it is those details that are sketchy right now. OPEC states that the new deal formalises current production levels and will make up for Saudi overcompliance by ‘redistributing’ those volumes across other OPEC+ members. But no specifics on that split were given – a worrying sign that more arguments were coming – with the group preferring to meet compliance first before moving on to the fresh cuts.
Full adherence to the targets is tough. But it might get easier. Russia – which has only met its quota 3 months this year, when the Druzhba oil pipeline crisis hit – won a significant concession. Its argument that the only reason it was not hitting its target was due to condensate production, a by-product of its increasing natural gas output, was accepted; the quotas will exclude condensate, and Russian Energy Minister Alexander Novak was optimistic that it could meet its quota of a 300,000 b/d reduction for the first quarter of 2020. And the first quarter of 2020 is crucial, as that is the remaining length of the supply deal. Ahead of the March 31 expiry in 2020, OPEC has agreed to hold an extraordinary general meeting to assess the situation – the point which the deal either ends or is extended.
Underpinning this bet is some sentiment-based optimism from OPEC. The rise and rise of US shale has diluted OPEC’s impact over the past five years, requiring it to make deeper and deeper cuts that were muted by increasing amounts of American crude. But OPEC is betting that the wind will go out of US shale sails next year, hoping that it will allow output within OPEC+ to rise again. But low growth in US shale does not mean no growth. And perhaps for this reason, the price impact on the new OPEC decision has been muted. Despite the club’s attempt to prove that it is still effective, the market simply doesn’t believe the new cut will do much. Crude prices reflect that. Call it cynicism, but the market might have more faith if full compliance was reached and that is exactly what OPEC is striving towards.
The OPEC+ supply deal: