Supply and demand: balancing production in mature offshore regions
Depressed oil prices are taking their toll on mature offshore regions such as the North Sea and the Gulf of Mexico. But with production set to plummet after 2018, what is the right E&P strategy as the market gradually starts moving back towards balance between supply and demand?
Since the sudden and sustained decline in oil prices – which saw benchmark grades such as West Texas Intermediate and Brent Crude plummet from peaks of more than $100 a barrel in the summer of 2014 to less than $30 at the outset of 2016 – has left the oil and gas sector scrambling to re-balance and adjust to a downturn that appears deeper and more enduring than the industry could have predicted.
More than half a trillion dollars has been knocked off the value of total proven reserves across the world, pushing smaller exploration and production (E&P) companies out of the market and forcing big oil to slash tens of thousands of jobs.
Royal Dutch Shell cut 7,500 jobs in 2015, while BP announced in January that it would cut 4,000 out of 24,000 E&P positions as the supermajors, along with the rest of the industry, seek to offset massive losses of revenue with extensive and far-reaching cost-cutting measures. Oilfield services companies have taken an especially hard hit as rig counts fall and contractors are expected to do more with less – Schlumberger has cut 34,000 jobs, representing more than a quarter of the company, while Halliburton and Baker Hughes have jettisoned 27,000 and 16,000 workers respectively.
“We have to make sure we have a competitive and sustainable business,” BP spokesman David Nicholas told the New York Times at the beginning of the year. “External market conditions are getting tougher.”
While a global loss of around 250,000 jobs throughout the industry is a major concern at present, there are many future implications of the current slump for oil and gas companies, resource-rich countries and the global economy as whole. Two questions are paramount: what effect is today’s low oil price environment having on offshore oil production on the macro level, and after months of oversupply, how quickly will the market be able to move back to a state of relative balance between oil supply and demand?
Mature regions increasing short-term production
In mature, highly developed regions such as the North Sea and the Gulf of Mexico, 2015 and 2016 has brought a production development that on the surface seems counterintuitive. In spite of the rock-bottom oil prices, production in these regions has risen and is expected to continue rising for at least the next couple of years.
In the Gulf of Mexico, production is expected to reach an average of just over 1.6 million barrels per day in 2016, up from around 1.52 million barrels in 2015, according to data from the US Energy Information Administration (EIA). In 2017, the administration projects that Gulf of Mexico oil production will hit a record-high average of 1.8 million barrels a day, possibly even reaching 1.9 million barrels by December of that year.
On the UK Continental Shelf of the North Sea, meanwhile, offshore producers reversed a 15-year run of consistently declining production in 2015, with around 590 million barrels of oil produced in total last year, compared with 545 million barrels in 2014.
With oil revenues massively impacted by the low oil price and some companies losing money on each barrel of oil produced – 3.4 million barrels worldwide and one in seven barrels in the North Sea are being produced at a loss, according to a February 2016 Wood Mackenzie – why are relatively high-cost mature regions such as the North Sea and the Gulf of Mexico increasing production?
Offshore investment lag
The explanation lies in the extremely long lead times for the development of offshore projects, which means the offshore sector is far less responsive to short-term oil price volatility than its onshore counterpart. Ultimately, production spikes in these regions are down to existing projects such as the coming online of Taqa’s Cladhan field off the coast of Shetland – for which investment decisions would have been made years ago, during more lucrative times – rather than new projects kicking off.
“There is a lag in offshore investment,” BMO Capital Markets senior oil and gas analyst Brendan Warn told the Telegraph newspaper in January. “Investments sanctioned today will take three to five years to start producing, so the new wells would have been approved back when oil was above $100.”
Such is the cost and time required to bring in-development wells into production that, for the vast majority of operators, it is more worthwhile to start even unprofitable production rather than mothballing a project for any length of time. This is especially true in the complex ultra-deepwater developments now taking place in the Gulf of Mexico.
“There’s a point where you pass the Rubicon,” said PRICE Futures Group senior market analyst Phil Flynn in an interview with McClatchy DC in March, discussing the investment decisions of Gulf of Mexico oil producers. “Even if prices collapse, you’ve already spent so much money that you’ve got to complete the process, even though I think a lot of these companies are remorseful that they started [offshore projects] a few years ago.”
New exploration sputters: supply set to shrink
While developing projects coming on stream has provided a temporary boost to production in many developed offshore regions, for this production growth to be sustainable there needs to be a wave of new exploration, which will make new discoveries and feed into the next generation of development projects.
Now that the oil price is so depressed and market conditions are so unfavourable, it is unsurprising that this surge of exploration hasn’t happened. In the current climate, large oil companies are heavily cutting back on exploration spending and allocating their more conservative capital expenditure budgets into efficiency improvements and buying up low-cost existing assets (Shell’s recent acquisition of BG Group is a good example of the latter).
The Gulf of Mexico has seen new deepwater drilling projects drop in half year-on-year from eight in 2014 to four in 2015 and only two expected by the EIA in 2017.
In the North Sea, exploratory drilling dropped to 12 wells in 2014, down from 44 in 2008, while between seven and ten exploration wells are in the pipeline for this year. As things stand, production is likely to peak on the UK Continental Shelf by 2018 and plummet thereafter, potentially dropping by half between 2015 and 2025.
Despite the pain that low prices and declining exploration will inflict on the offshore oil and gas industry and the oilfield services companies that rely on it, in many ways this supply cliff is necessary as the market begins the long, slow journey back towards balance between supply and demand. A drop in production, both onshore and off, will drive up prices and make more investment viable (barring unforeseen circumstances such as OPEC increasing production or US shale supply declining more slowly than expected). But long lead times for offshore projects mean that decisions on big projects need to be made years in advance, which requires boldness, with oil prices currently sitting below $50.
“Given the long lead time of offshore projects, the long-term view on oil price, not near-term, will dictate investment decisions,” wrote Deloitte analysts Lesley Mitchell and Robin Mann in a January editorial for Offshore magazine. “There are too many variables to forecast oil price with a high degree of confidence but each company will have to decide how conservative or aggressive they want to be in that medium to long-term oil price arena…to balance long-term growth, companies that intend to stay in offshore plays long term still need to explore for some new development opportunities. This means that exploration budgets cannot be eliminated completely.”
Although it’s certainly too soon to say for sure, early signs suggest that the market is slowly creeping back towards balance – after starting the year at around $25, oil prices bounced back to $48 in April as a result of supply disruptions in Iraq and Nigeria and a decline in US shale production. This prompted the World Bank to revise its 2016 crude oil price forecast from $37 to $41 – still a year-on-year drop, to be sure, but a more gradual drop than seemed likely in January and perhaps reason to hope that benchmark prices might be closer to $80 in 2020 than expected.
No company can see the future, but difficult investment decisions in a brutal market have to be taken nevertheless. What will be driving debate in the boardrooms of oil and gas companies all over the world won’t be circumstances in the present, but faith in the future.