Reduced capex, project delays and cancellations
The offshore oil and gas industry began 2020 on a cautiously optimistic note. For those that survived the 2014-2016 downturn, it appeared that there was light at the end of the tunnel.
That optimism was quickly shattered with the onset of the novel COVID-19 (coronavirus) pandemic and the equally rapid collapse in crude oil prices. The lockdowns and quarantines that followed have taken a huge bite out of oil demand; this has further eroded oil prices. The result is an unprecedented level of uncertainty in the market.
The industry is having to contend with three fundamental challenges, says Wood Mackenzie. The first is substantial reduction in demand for equipment and services. Stricter capital discipline from operators will reduce demand substantially this year both onshore and offshore, which means that only a handful of major projects will go forward this year. The second challenge will be a test of financial resilience. Companies across the supply chain had already cut back significantly in the past few years. It will be difficult for many to identify further savings without drastic measures such as refinancing or the restructuring of business models. Staff cuts and bankruptcies appear inevitable.
The third challenge will be excess capacity. Companies holding onto idle assets “just in case” will have to think again. The prospect of sub-$40/bbl oil will force profound change and pain in the short term, Wood Mackenzie said, but could ultimately create a more sustainable business for those that survive.
Reduced capital spending plans
Global capex for exploration and production companies is expected to drop by up to $100 billion this year, under Rystad Energy’s updated base case scenario of $34/bbl in 2020 and $44/bbl in 2021. According to the analyst’s data, the expected decline this year will make 2020’s capex volumes, estimated at about $450 billion, the lowest in 13 years. Its estimates before the coronavirus pandemic had indicated E&P would remain flat year-on-year.
In a low case scenario, where Brent averages $25/bbl in 2020, global investments may plunge to around $380 billion this year, falling to almost $300 billion in 2021, a 14-year and a 15-year low respectively.
The estimated cost cuts will be mainly achieved by lower activity within US shale, delays to projects that are yet to reach the final investment decision (FID) stage, deferred exploration activity, and cost cuts within development and production for conventional assets.
By the end of March, GlobalData reported that E&P companies had cut more than $50 billion in capex.
Daniel Rogers, Oil and Gas Analyst at GlobalData, said: “Of the announced $50 billion in cuts to date, approximately 20% of that is coming solely from Saudi Aramco, which could have implications for its ongoing expansion projects in the country. Elsewhere, across the supermajors, the investment cuts are within the 20-25% range, resulting in multi-billion-dollar pull backs in new projects and non-critical investments.”
At that time, the analyst found that the the average announced capex cut for 2020 is 29% from original forecasts. On the higher end of the spectrum, US operators with significant shale acreage and Australian operators with imminent large-scale LNG projects have taken the most drastic reduction measures.
“The types and severity of the cuts seen will differ depending on stakeholder requirements. National oil companies will strive to protect obligated payments to the government, whilst maintaining production volumes, whereas independent oil companies will focus on strengthening balance sheets and continuing to generate returns for investors in a challenging environment,” Rogers concluded.
In early April, ExxonMobil and BP cut capex spending by 30% and 25%, respectively.
Of the 50-plus projects Wood Mackenzie had identified as potentially going ahead this year, only 10 now look to have a chance of proceeding. According to Rob Morris of Wood Mackenzie’s upstream research team, “only those with the strongest balance sheets will even contemplate major project FIDs. The majors and certain NOCs will take the lead, while projects with financially stretched partners and at the higher end of the cost curve will struggle.”
Projects least at risk of deferrals are thought to include large deepwater oilfield developments off Guyana and Brazil, and ‘niche LNG’, including low-cost greenfield and feedgas backfill at legacy liquefaction projects.
“Two-thirds of all greenfield projects, representing $110 billion of total future investment, face almost certain deferral,” Morris said. “Some project sanctions will be delayed to 2021 and beyond. Some will be completely reworked or even put on hold permanently. These include projects with weaker strategic drivers, high breakevens, and/or financially distressed operators.
“Africa, the North Sea, Southeast Asia, and Australian LNG face mass project deferrals. Australian LNG is perhaps the most high-profile casualty. As we predicted, both Woodside Petroleum and Santos have already announced delays at Scarborough and Barossa until market conditions improve.”
At the time of writing, many offshore projects have been delayed.
Woodside has pushed back the FID for the Scarborough gas project and Pluto Train 2 on the North West Shelf to 2021. The Browse gas project has also been deferred.
Jadestone Energy has delayed development of the Nam Du and U Minh gas fields offshore Vietnam. The company had assumed receipt of government approvals by 1Q 2020, and now envisages start-up of the two fields no earlier than late 2022.
Equinor and Husky Energy have reportedly postponed the Bay du Nord project offshore eastern Canada.
Husky also has deferred by a year development of the block 15/33 oil field offshore China and put the brakes on developing the MDA-MBH gas field offshore Indonesia. In addition, the company has suspended major construction activities related to the platform-based West White Rose development offshore Newfoundland and Labrador.
Aker BP has put on hold the non-sanctioned Hod redevelopment in the Valhall area of the southern Norwegian North Sea.
Siccar Point Energy E&P Ltd. and joint venture partner Shell UK have deferred the planned sanction date for the deepwater Cambo project west of Shetland from 3Q 2020 to the second half of 2021.
INEOS FPS delayed this summer’s planned shutdown of the Forties Pipeline System in the UK central North Sea to spring 2021.
Aker Energy has postponed the Pecan project in the Deepwater Tano Cape Three Points block off Ghana.
The BW Energy-led Dussafu joint venture has temporarily postponed the start of the Ruche Phase 1 development offshore Gabon.
FAR Ltd. is working with Woodside and other partners in the Sangomar project offshore Senegal to examine how costs can be reduced, expenditure delayed or both and any impact on the timeline to first oil.
ExxonMobil has delayed the green-light on Mozambique’s multi-billion-dollar Rovuma LNG project. The company said it is collaborating with the partners and the government to optimize development plans through improved synergies and assessing opportunities related to the current lower-cost environment. BP and Kosmos Energy are working to defer the 2020 Tortue Phase 1 capital spending for their multi-billion-dollar Greater Tortue Ahmeyim gas-condensate project off Mauritania and Senegal. The Phase 1 timeline is expected to be delayed by 12 months.
Shell’s Bonga Southwest, ExxonMobil’s Bosi, Owowo West and Uge-Orso, and Chevron’s Nsiko projects offshore Nigeria are likely to be delayed.
INPEX’s Abadi project offshore Indonesia, the Limbayong project in Malaysia, Shwe Yee Htun in block A6 off Myanmar, and the Kelidang Cluster in Brunei, are potentially at risk.
ExxonMobil said that developing the numerous deepwater discoveries in the Stabroek block offshore Guyana remains an integral part of its long-term growth plans. Operations onboard the FPSO Liza Destiny are unaffected, and the second phase of the Liza field development remains on target for start-up in 2022, with the FPSO Liza Unity currently under construction in Singapore. However, as the company waits for government approval to proceed with a third production vessel for the Payara development, some planned 2020 activities are in the process of being deferred, and this could potentially delay the start of production by between six and 12 months.
The consensus among drilling rig owners and operators is that things will likely get worse before they get better, according to a recent analysis offered by Westwood Global Energy Group’s RigLogix service. This will be especially true if current conditions persist, the report said.
Operators are typically cutting planned 2020 capex by 20-30%, and the coronavirus is impacting movements of personnel and equipment/services to and from rigs. This all means the number of idle rigs will soon increase substantially. For rig owners, some of which were slowly inching their way back to profitability, the road to recovery will be longer, and some will be impacted more than others.
Terry Childs, head of RigLogix, pointed out many companies are having to face up to debt payments due in 2021. One major rig owner believes nearly every public driller will be in Chapter 11 this year or next.
Currently, rig operations in most parts of the world continue to be supported by rig owners, but with strict protocols in place concerning crews, equipment and supplies. But a growing number of drilling rig contractors are saying that they expect to cease drilling soon and warm-stack their rigs, with the impact caused by COVID-19 on logistics cited as the main problem. And should more countries end up adopting no-travel bans or lockdowns, this will only extend the number of idle rigs.
RigLogix’s data shows that Africa, Southeast Asia, and the Middle East have the highest dollar amounts at stake, and collectively comprise 50% of the total rig options value. In Southeast Asia and the Middle East, the options are entirely related to jackup contracts, whereas the $136.1 million in the US Gulf of Mexico is mainly for floating rig options.
Valaris ($331 million) and Transocean ($195 million) are said to have the highest dollar amounts of options to be exercised and are therefore the most exposed.
Most of the nearly 300 drilling programs that currently have 2020 start dates will be delayed, Childs claimed. The planning process for certain drilling programs is continuing, but at a much slower pace.
Some contract awards should continue, particularly where drilling is not planned until 2021 or beyond, but it seems probable that the number of contracts finalized over the next few months will be minimal.
As of this writing, Valaris has received early termination notices for two rigs offshore Angola. Total is expected to terminate the contract for the drillship VALARIS DS-8, which was expected to end this November. Chevron has terminated the contract for the VALARIS JU-109, which was scheduled to operate until July 2021. As a result, the rig’s contract was expected to end last month. Valaris said it expects to receive additional notices of contract terminations and requests to renegotiate contract day rates and terms considering increased market uncertainty.
Tullow Oil has notified Maersk Drilling of the early contract termination for the drillship Maersk Venturer offshore Ghana. The drillship will now likely finish its campaign in June, 20 months ahead of the anticipated termination date.
Shelf Drilling and Dubai Petroleum have agreed to amend the contract end dates for the jackups Shelf Drilling Tenacious and Shelf Drilling Mentor from January 2022 to September 2020 and January 2022 to October 2020, respectively.
ExxonMobil has notified Shelf Drilling of the early contract termination for the jackup Trident XIV offshore Nigeria. The contract end date has changed from February 2021 to July 2020.
ExxonMobil has also notified Borr Drilling Ltd. of the early termination for the jackups Gerd and Groa offshore Nigeria. The rigs were under contracts originally committed until April 2021 and May 2021, respectively.
Noble Corp. has warm-stacked the jackups Noble Sam Hartley, Noble Sam Turner, and Noble Hans Deul; cold-stacked the drillship Noble Bully II and the semisubmersible Noble Paul Romano; and will retire the jackup Noble Joe Beall. Saudi Aramco has requested a reduction to the operating day rates for the jackups Noble Scott Marks, Noble Roger Lewis, Noble Joe Knight, and Noble Johnny Whitstine.
Drilling contractors could be facing a combined loss of revenue of around $3 billion in 2020 and 2021, according to Rystad Energy. It estimated the total value of agreed contracts over the two years at $30 billion. So far, in the present crisis, six rig years of contracts have been canceled, amounting to around $400 million in value, and more look set to be called off as operators cut capex budgets and delay projects.
“More than $22 billion in contract value was wiped off the books as a result of contracts being canceled between 2014 and 2017,” said Rystad head of Offshore Rig Market Services Oddmund Føre. “Now, in the infancy of a new downturn, a market that was only beginning to return to a healthy level of contracting activity, contract volumes and day rates has seen its hopes crushed.”
This year was slated to be another good year for exploration with about 45 countries launching at least 52 lease rounds, about 60% of them in offshore areas, according to Rystad Energy. However, more than half of the world’s planned licensing rounds are likely to be canceled this year due to the combined effect of the COVID-19 pandemic and low oil prices. New licensed offshore acreage is likely to fall by about 60% compared with 2019 levels.
Aatisha Mahajan, Rystad Energy’s senior upstream analyst, said: “The unlikely upcoming lease rounds represent around 54% – a worrisome sign for global exploration. A number of factors together make these rounds unlikely to go ahead, including the oil price drop, a global cut in investments by almost 20%, a lack of skilled manpower due to the COVID-19 pandemic, fiscal regimes that are proving unattractive in the current environment, and a lack of interest among potential participating companies.”
According to the analyst, licensing rounds are unlikely to take place in the UK, Ukraine, Romania, Germany, Colombia, Brazil, Ecuador, the Dominican Republic, Thailand, Uzbekistan, Myanmar, the UAE, New Zealand, Ivory Coast, Algeria, Tanzania, Senegal, Somalia, Liberia, Ghana, Equatorial Guinea, Angola, South Sudan, and Nigeria.
Licensing rounds in the US, Suriname, Egypt, Russia, and China hang in the balance and are marked as tentative. However, licensing rounds in Malaysia, Trinidad and Tobago, Norway, India, Lebanon, and Canada are likely to go ahead. These countries look well on track to continue their lease rounds as scheduled, although the current industry volatility could cause slight delays.
As for seismic survey contractors, Polarcus has received two project cancellations. One was for an XArray marine seismic acquisition project in the Asia/Pacific region that was due to start in 2Q 2020. The other was a 3D marine seismic acquisition project offshore West Africa.
EMGS canceled a controlled source electromagnetic seismic survey offshore Mauritania and Senegal after BP postponed the project. The company has also decided to cold-stack the Atlantic Guardian.
PGS has decided to cold-stack two of its eight currently operated 3D acquisition vessels during the current quarter and warm-stack a third in 3Q.
Shearwater GeoServices has received two project cancellations. The first includes a short project for Woodside offshore Western Australia that was part of an award announced last November. Reliance Industries canceled a 1,500-sq km (579-sq mi) survey over block KG-UDWHP-2018/1 in the Krishna-Godavari basin offshore India, awarded in January. The Polar Duchess had been due to start the program in the current quarter.
The current market will bring many challenges for exploration drilling. Rystad has identified at least nine planned exploration wells in Norway, Brazil, the Bahamas, Guyana, the US, Gambia, and Namibia that would target a combined 7 Bboe are at risk of suspension.
Senior upstream analyst Palzor Shenga, said: “Given the prevailing global situation we now foresee that the cumulative discovered volumes by the end of the year could go even below the 2016 level of 8.9 Bboe, which was the decade’s lowest. This will solely depend upon how many key wildcat wells will still see a spinning drill bit in the coming months, as some of them could be either suspended or postponed.”
Bahamas Petroleum Co. has re-scheduled drilling of its first exploration well (Perseverance #1) off The Bahamas to mid-October onwards.
Oryx Petroleum and FAR Ltd. have postponed exploration wells in the AGC Central license area offshore northwest Africa and The Gambia, respectively.
Even as it scales back its E&P campaigns, the industry has been making its expertise and technologies available to help stop the spread of the coronavirus.
BP will provide access to its Center for High-Performance Computing (CHPC) in Houston to advance coronavirus research. It houses what the company claims is one of the world’s largest supercomputers for commercial research and processes enormous amounts of data. It has 16.3 petaflops of computing capability, allowing it to process more than 16 million billion calculations per second and complete a problem in an hour that would take a laptop nine years.
Petrobras will direct part of its supercomputer processing capacity to helping researchers fight the virus. The Santos Dumont, said to be Latin America’s largest supercomputer, is in the Laboratório Nacional de Computação Científica in Petrópolis, Rio de Janeiro. The other supercomputer is in Salvador, northeast Brazil. The company plans to allocate 60% and 50% of the two supercomputers’ capacity, totalling 3 petaflops. This will be used to accelerate the simulation time so that researchers can achieve results faster.
Eni has made its HPC5 supercomputer and molecular modeling capability available for research. Unveiled in February, the HPC5 hybrid architecture is said to make the algorithms for molecular simulation particularly efficient.
ExxonMobil and the Global Center for Medical Innovation (GCMI) are collaborating to swiftly re-design and manufacture reusable personal protection equipment for health care workers. The company said it is applying its experience with and know-how in polymer-based technologies, in combination with GCMI, to facilitate development and expedite third-party production of innovative safety equipment.
Shell is part of a consortium that has been developing new face protectors for doctors, made of snorkel masks. These adjusted masks are said to cover the face fully and are connected to a medical filter by a part produced using 3D printers at the Shell Technology Centre Amsterdam. •