UK North Sea Oil & Gas Review

It has been a busy end-of-year period in the UK Continental Shelf. Between mid-November and the first half of December, several end-year industry reports were published, and companies both large and small announced developments, investments, stake acquisitions, and drilling plans.

Oil & Gas UK’s 2018 Decommissioning Insight Report revealed that the UK is expected to spend £15.3 billion on decommissioning over the next decade. Decommissioning spending is seen at around £1.5 billion every year over the next decade, 20 percent lower than forecast in 2017. As many as 1,465 wells are expected to be decommissioned over the next ten years, accounting for one-fifth of total UKCS well stock. According to Wood Mackenzie, the UK is the largest decommissioning maker over the next decade, with one-third of expenditure across the top 12 markets.

The 29th edition of Aberdeen & Grampian Chamber of Commerce oil and gas survey for November 2018 showed workforce recruitment is on the rise among oil and gas contractors in the UKCS as business confidence reaches its highest level since 2013.

“The industry appears to be setting its sights on growth opportunities, with 58% of firms forecasting an increase in profits in 2018 and a net balance of 50% of firms anticipating an increase in the value of production-related activities,” according to the survey.

Oil & Gas UK is encouraged by the survey results, but pointed out that continued investment is needed in the UKCS.

“However, as we continue to emerge from one of the toughest downturns in our history, industry remains focused on maintaining its attractiveness in a competitive global market,” said Deirdre Michie, Chief Executive of Oil & Gas UK.

The latest UK offshore licensing round, which closed in November, attracted 36 applications covering 164 blocks in frontier areas of the UKCS, with a strong and diverse set of applications received from 35 companies ranging from multinationals to micro-businesses, the Oil & Gas Authority (OGA) said.

“This is an encouraging set of applications, demonstrating that interest in UK offshore licensing opportunities has increased since the 29th frontier round held in 2016, with an almost 50% increase in the number of blocks applied for,"  Dr Nick Richardson, Head of Exploration and New Ventures at the OGA, said.

In projects developments and field start-ups, BP announced on 23 November first oil production from the giant Clair Ridge project in the West of Shetland. The major UK North Sea development—the sixth new upstream project to come on stream for BP in 2018—is targeting 640 million barrels of oil reserves and peak production is planned at 120,000 barrels of oil a day.

“This is a major milestone for our Upstream business and highlights BP’s continued commitment to the North Sea region,” said Bernard Looney, BP Chief Executive Upstream.

Commenting on first oil at Clair Ridge, the OGA said:

“First oil from the newly built Clair Ridge platform is a major milestone for the UKCS. The OGA continues to view the West of Shetland as strategically important with substantial remaining potential.”

Shell, together with partners Esso Exploration and Production UK Limited and Arco British Limited, LLC, (BP) announced on 10 December the final investment decision (FID) for the Shearwater gas infrastructure hub in the central North Sea—the seventh FID for Shell in the UK North Sea in 2018. Currently, dry gas produced by the Shearwater platform flows via the Shearwater Elgin Area Line (SEAL) pipeline to Bacton, on the east coast of England. In this latest investment, the Shearwater platform will be modified and a 23-mile (37-kilometre) pipeline from the Fulmar Gas Line (FGL) to Shearwater installed, enabling wet gas to flow into the Shell Esso Gas and Associated Liquids (SEGAL) pipeline.

The Shearwater gas infrastructure hub is the seventh investment decision for Shell in the UKCS this year, after the decisions to develop the Penguins fields in the northern North Sea, the BP-operated Alligin field west of Shetland, the Fram, Arran, and Gannet E fields along with the Gannet Export infrastructure investment in the central North Sea.

Chevron North Sea Limited, operator of the Captain Field, said in December that the OGA had approved the Field Development Plan (FDP) to progress its Captain Enhanced Oil Recovery (EOR) project in the UK Central North Sea.

Apache Corporation began oil production from its Garten development in the UK North Sea in late November. The discovery well, located 6 kilometres south of the Beryl Alpha Platform, was placed on production less than eight months after being drilled in March 2018.

“To have delivered a project from discovery to first oil in just eight months shows the remarkable agility of the UK Continental Shelf as it continues to become more competitive,” Oil & Gas UK Upstream Policy Director Mike Tholen said, commenting on the news of first oil on Garten.

In December, Tailwind Energy Ltd announced first oil from the 100-percent owned Gannet E redevelopment to the Triton FPSO. The subsea tieback project was completed in September 2018 with first oil delivered on budget and on schedule, the company said.

Azinor Catalyst, a Seacrest Capital Group-backed company focused on the UKCS, announced in mid-November an oil discovery on the Agar-Plantain Prospect, and believes that the discovery holds recoverable resources of between 15 and 50 million barrels of oil equivalent, in line with pre-drill estimates.

“Provisional results are very encouraging, especially given the location in an infrastructure-rich area of the UK North Sea,” the OGA said, commenting on the discovery.

Azinor Catalyst has also received a Letter of Intent (LOI) for the acquisition of material non-operated interests in three exploration wells it plans to drill in 2019 on Catalyst’s Boaz, Goose, and Hinson prospects. All three prospects are large, high-value North Sea exploration opportunities and are close to existing infrastructure and export routes.

Premier Oil said in mid-November that preparatory work was underway ahead of drilling the high-value Tolmount East appraisal well scheduled for mid-2019. Premier also plans to acquire 3D seismic across the Greater Tolmount Area in the first half of 2019 to enable maturation of the Tolmount Far East well location, the company said.

Independent Oil and Gas plc, a development and production company focused on becoming a substantial UK gas producer, is pushing back its final investment decision (FID) on a two-phase development of its 302 BCF 2P gas reserves at the Blythe Hub and the Vulcan Satellites Hub to the first quarter of 2019 from the end of this year, due to the current oil price volatility and capital market conditions. The company aims to take the FID in Q1 2019, and it is technically ready to achieve first gas within 20 months of FID.

Spirit Energy submitted in November its Environmental Statement for the Pegasus West development in the southern North Sea to the Department for Business, Energy and Industrial Strategy. Spirit Energy expects to make an FID on the field, which would be produced as a subsea tieback to the Cygnus Alpha complex, in 2019. If the environmental statement is approved and the project is sanctioned, first gas from the field would be between 2021 and 2023.

The same company said in December that it had taken over operatorship of the Babbage Gas field, where it holds a 13-percent stake. Spirit Energy has also taken on operatorship of the nearby Cobra licence, in which it owns 50 percent and plans to drill an additional well in the area to prove up reserves.

In December, Norway’s Equinor completed the sale of its 17-percent stake in the Alba oil field in the Central North Sea to Verus petroleum.

EnQuest PLC has completed the acquisition of the remaining 75-percent stake in the Magnus oil field, an additional 9-percent interest in the Sullom Voe Oil terminal and supply facility, and additional interests in associated infrastructure from BP. EnQuest expects its 2019 average Group production to rise by around 20 percent to 63,000 Boepd-70,000 Boepd, thanks to the additional equity in Magnus.

Subsea 7 was awarded in November a three-year extension of an existing Diving Support Vessel initiative frame agreement, with seven North Sea clients: Chevron North Sea Limited, Dana Petroleum (E&P) Limited, Hess Denmark APS, Nexen Petroleum U.K. Limited, Repsol Sinopec Energy UK Limited, Shell UK Limited, and TAQA Bratani Limited. Under the frame agreement, Subsea 7 will continue to provide diving support vessel services on a year-round basis, plus associated project management and engineering services for up to 50 offshore facilities in the North Sea.

We are wrapping up one of the most interesting years in oil and gas recently. We have seen oil prices taking one rollercoaster ride throughout 2018. We have seen major oil and gas projects started and sanctioned. We have seen the world’s major oil and gas companies booking their highest quarterly profits since 2014, when oil prices were above US$100 a barrel. We have seen the return of offshore projects and developments, and the US shale patch stepping up drilling and production to all-time highs.

Earlier this year, oil prices increased in 2018 compared to the 2017 levels, after OPEC and its Russia-led non-OPEC partners continued to remove oil supply from the market under an agreement which began in January 2017, aimed at wiping out the global glut and lifting prices. The partners in the output cut agreement declared victory in their undertaking this year, and so did the market. Oil prices moved up.

In the summer, the United States began to hint at more severe sanctions on Iran than during the previous period of sanctions on Iranian oil in 2012-2015. The oil market and analysts started to fear an imminent supply crunch.

Saudi Arabia, the UAE, and some other OPEC members with spare capacity, as well as non-OPEC Russia, moved in to anticipate a steep drop-off in Iranian oil exports, reversed some of the production cuts and ramped up their production. This left the oil market wondering whether the world’s spare capacity had become too thin to meet unexpected oil supply outages.

Prices moved further up, to four-year highs in early October. Fuelled by higher oil prices, oil majors were reporting Q2 and Q3 earnings above analyst estimates and at levels last seen back in 2014 when oil prices were exceeding US$100 a barrel, showing that they have become smarter in project execution and development in a lower-oil-price world.

In the summer, however, the US-China trade war heated up, and as autumn progressed the oil market and experts started to fear that a slowdown in global economy—due to the trade war, high oil prices, and emerging-market currency troubles—could lead to slower oil demand growth going forward. Many analysts began cutting their oil demand growth estimates for 2018 and 2019.

The US sanctions on Iran’s oil and shipping industries returned in early November. On the day the sanctions snapped back, the US granted waivers to eight key Iranian oil buyers—including the biggest customers China and India—to continue importing oil from Iran at reduced volumes for a 180-day period, until early May 2019.

Suddenly, the market was awash with oil, as Saudi Arabia, Russia, and the US (buoyed by shale drilling thanks to higher oil prices) were pumping crude oil at record highs. Fears of tighter supplies flipped into fears of oversupply, sending oil prices into a bear market and to one year-lows in November.

OPEC and Russia-led non-OPEC started to hint that another oil output cut would be needed to bring the market back to balance. At a meeting in early December, the so-called OPEC+ group of producers forged another deal—to cut their combined oil production by 1.2 million bpd from October levels for a six-month period, with an option to review in April 2019.

The last two months of 2018 haven’t negated the recovery of the oil industry, although prices have slumped to the levels of December 2017. The industry has reduced a lot of costs since the dizzy spending days of 2013.

According to a Wood Mackenzie report from end-November, the cost of developing new deepwater resources has declined by more than 50 percent since 2013. Project downsizing, more phasing of larger developments, better project execution, faster well completions, lower service and rig costs have all helped deepwater cost reductions.

Total annual deepwater capital expenditure is expected to grow to nearly US$60 billion by 2022, from around US$50 billion now, driven by large projects in Guyana, Brazil, and Mozambique. However, cyclical inflation in costs could return and “this epic period of deepwater cost reduction” could come to a close, according to Wood Mackenzie.  

“This is maximising economic recovery in action and shows the determination of the basin to work innovatively and collaboratively in pursuit of Vision 2035 – ultimately adding a generation of productive life to the UK Continental Shelf,” Tholen said.

The highlights of the gas industry in 2018 include the US shale gas boom, the increase in liquefied natural gas (LNG) trade, along with major LNG projects started up or sanctioned. Rising supply of LNG from the US, Australia, and Qatar continue to extend the global reach of the natural gas market.  

In the UK North Sea oil and gas industry, more projects were announced in 2018 than in the past three years combined, which shows “an improved landscape for the sector after one of the most testing and prolonged downturns in its history,” Oil & Gas UK Upstream Policy Director Mike Tholen said in October, commenting on some of the new developments announced in the North Sea.

China is set to dominate the rising gas demand globally through 2022, while the US is forecast to account for the biggest share of supply growth, according to the IEA. Europe’s dependency on gas imports is set to further increase, “leading to potential competition between traditional suppliers such as Russia and new sources of supply, mainly from LNG,” the IEA said.

“Globally, the industry sector is set to replace power generation as the main driver of growth, with natural gas being used for not only energy for processes but also feedstock for chemicals. This includes fertilisers in emerging economies and feedstock for petrochemicals in regions with abundant natural gas,” according to the IEA’s Gas 2018 report.

In LNG, Australia beat Qatar in November to become the world’s top LNG exporter, even if its place at the top may be just for one month. The start of gas exports from the Ichthys LNG offshore Western Australia in October helped Australia topple Qatar in November, but analysts expect the Gulf state to regain its top exporter status as early as in December, because Qatar’s lower November exports were also due to maintenance. Qatar has a plan to boost its LNG exports further, while for Australia, there is just one project left of the recent LNG infrastructure boom that is yet to begin operations: Shell’s Prelude floating LNG, which is expected to start production around the end of 2018.  

This year also saw the first LNG project in Canada given the green light. Shell and its partners in the LNG Canada project in Kitimat, British Columbia, announced in October the final investment decision (FID) for the project, with construction starting immediately and first LNG expected before the middle of the next decade. The cost to deliver LNG into Asia is expected to be structurally advantaged compared to a greenfield development on the US Gulf Coast, according to Shell and its partners in the LNG Canada venture—Petronas, PetroChina, Mitsubishi, and Korea Gas Corporation.