Muscat's oil plans in disarray
The sultanate’s upstream development projects have taken short and longer-term hits
The Omani government is not having a good year oil-wise. The new Opec+ agreement to cut 9.7mn bl/d of production from 1 May requires the adherents, including Muscat, to reduce output by nearly a quarter. The heavily oil revenue-dependent sultanate’s original 2020 budget was based on an average price of $58/bl and more than 900,000bl/d production—which, even then, would have entailed a $6.5bn deficit.
With average prices in April being less than half of the government’s assumptions, the new requirement to also slash sales volumes rubs salt in a painful fiscal wound. The impact of both will mean deep spending cuts. And the twin tracks of the country’s upstream policy—to stanch declines at ageing production stalwarts and open up new plays with foreign help—are both under threat.
Omani output peaked at just over 1mn bl/d in 2016 before Opec+ obligations first intervened. And Oman has been among the most compliant of the pact’s non-Opec adherents.
The ministry of oil and gas last month obediently instructed the operators of the six most prolific concessions to cut a collective 200,000bl/d from production to achieve the newly agreed 682,000bl/d ceiling. Petroleum Development Oman (PDO)—the decades-old government-led operator of the vast onshore Block 6 concession that encompasses most of the state’s main fields and accounts for around two-thirds of the sultanate's output—is to absorb 135,000bl/d, bringing its crude output down to 453,000bl/d. The quota now excludes the company’s roughly 90,000-100,000bl/d of condensate production thanks to Russia’s efforts.
682,000bl/d – Omani oil output ceiling
The Opec+ constraints are due to be eased from July. But a finance ministry directive in late March that all state-owned enterprises should suspend new projects and capex budgeted for the current fiscal year could have a longer-lasting effect on PDO.
Pre-crisis, the firm aimed to raise capacity from around 630,000bl/d to 700,000bl/d by mid-decade. But even small gains come at a large cost in Oman. PDO has deployed expensive enhanced oil recovery (EOR) techniques for over two decades to maintain, and modestly augment, output from maturing fields. Oil minister Mohammed al-Ruhmy said in mid-April that spending was likely to be deferred on projects not expected to yield returns within around two years.
PDO is fortunate in that its two key ongoing projects both pass the test. The $4.7bn Rabab-Harweel integrated project started up in July last year, while the similar Yibal Khuff project is due to reach the same milestone next year—adding a combined 70,000bl/d. But work on the third phase of a polymer injection EOR project at the Marmul field, due onstream in 2023, could be paused, while the long-planned development of the ultra-heavy Habhab field will certainly return to the backburner.
Longer-term capex crunch
US independent Occidental Petroleum, the sultanate’s largest independent producer, will shoulder more than a quarter of the cuts—chiefly from the 120,000bl/d Mukhaizna field in the south-east, as well as Blocks 9 and 27 in the north. Given the company’s domestic travails, it is unlikely to shed too many tears over cutting 58,000bl/d of Omani output.
But, longer-term, Occidental’s capex cuts will have an impact on potential Omani capacity growth. The firm acquired two additional blocks in late 2018 to create a belt of contiguous licences stretched across the north of the country. And a tranche of spending this year had been earmarked for the expansion of facilities at the producing Block 62 to handle production from the newer acreage from next year—a plan now likely to be deferred.
Oman is more vulnerable than its neighbours to upstream retrenchment
Lacking the large low-cost plays for which its Middle Eastern Gulf region is famed, Oman is more vulnerable than its neighbours to upstream retrenchment. The vicious global downturn is thus likely to force a pause in the government's rolling efforts to attract new international operators to try their luck with the sultanate’s complex geology and challenging geography.
Bid rounds typically take place annually, but the results of last year’s—which focused on remote, lightly explored acreage in the far south-west—have yet to be announced more than a year after closing. A new auction will likely wait on a market recovery.
Development spending by those firms that recently acquired licences through bilateral agreements—which, hearteningly for Muscat, has included the likes of Shell and Italy’s Eni—is expected to be minimal in the near-term. The government may broadly have to chalk up 2020 as a lost year for Oman's oil sector.