Decarbonisation, the energy transition and digitalisation emerged as key themes in Wood Mackenzie’s recently released second annual State of the Upstream Industry survey.
Respondents told Wood Mackenzie that addressing decarbonisation and adapting to the energy transition were priorities. Almost 70 per cent of respondents proposed investing in renewables of reducing carbon footprints as the right way to adapt to the energy transition.
Over the past year, the European Majors have emerged as leaders in renewables investment – a strategy highlighted by 15 per cent of the survey’s respondents as a priority.
“But companies can’t ignore their roots. While there has been an increase in investment in renewables, it is from a low base. Oil and gas projects still pay the bills,” Wood Mackenzie said.
Compared with last year’s survey, companies are optimistic about oil prices: more than 75 per cent think it will be above US$75/bbl in 2021. And in a period of higher oil prices, it looks like growth options are being brought back to the table. Asset M&A and frontier exploration are more attractive options this year than last year, the survey showed.
Martin Kelly, Wood Mackenzie’s head of corporate analysis, said: “The industry’s growing confidence is evident in spending expectations too. More will be spent globally and in each region this year compared to last year. Capital investment, exploration investment and M&A spending will all increase by at least 10 per cent year-on-year.
He added: “With more of a focus on growth and investment than this time last year, companies are still disciplined in how they sanction projects using hurdle rates. But hurdle rates have dropped slightly this year, particularly at the riskier end of the investment spectrum. Both deepwater and exploration investments have a lower average hurdle rate compared to last year, moving from close to 16 per cent last year to below 15 per cent in the 2018 survey. This may be statistically insignificant, but it’s a trend worth keeping an eye on.”
Speaking about digitalisation, the other key theme highlighted by the survey, Kelly said: “More than 60 per cent of survey respondents said digitalisation of the industry will have a ‘major’ or ‘transformational’ impact. This is likely to be felt most at the operational end of the industry - production optimisation, equipment reliability and internal process efficiency. Digitalisation is expected to result in faster and better decisions, more production and fewer outages. It will also help reduce costs,” he said. “If we translate the 10 per cent saved by operators in the L48 with edge analytics, the industry is looking at US$20 billion saved on drilling globally. That's a big piece of the pie.”
Supplies of Canadian oil sands heavy crude are increasingly being refined on the U.S. Gulf Coast (USGC) and could top 1.2 million barrels per day (mbd)—a full one-third of the region’s heavy oil refining market—by 2020, says a new report by business information provider IHS Markit.
Current runs of Canadian crude in the USGC market are estimated to already be in excess of 800,000 barrels per day (bpd), the report says.
Entitled Looking South: A Canadian Perspective on the U.S. Gulf Coast Heavy Oil Market, the Oil Sands Dialogue report says that the increasing volumes into the USGC refining market is coming at an opportune time for both nations. Imports from Canada have exceeded demand in their traditional import market—the U.S. Midwest—where they have joined renewed U.S. domestic light oil to collectively displace nearly all other imports.
The U.S. Gulf Coast is home to the world’s highest concentration of heavy oil refineries and more than 90 percent of the heavy oil supplied to them comes from imports. But supplies from some traditional sources of these imports are waning. Over the past five years, production from Mexico and Venezuela—two key oil sands competitors—has declined by nearly 1 mbd. This is increasing the need for Canadian heavy crude oil of similar quality, the report says.
The 800,000 bpd estimate for current runs of Canadian crude in the USGC is already significantly higher than many other estimates. IHS Markit believes that Canadian heavy oil imports may be simply “stopping off” at Cushing, OK in the U.S. Midwest—where they have already exceeded demand in that market—before being rerouted to the Gulf coast. Due to the way imports are often tracked, these imports would be counted as having been delivered into Cushing rather than to their final destination.
“The U.S. Gulf Coast is the most logistically approximate and technically suited to receive increasing volumes of heavy oil from Canada,” said Kevin Birn, executive director - IHS Markit, who heads the Oil Sands Dialogue. “With supply overtaking demand in the U.S. Midwest and traditional sources of offshore heavy supply to the Gulf Coast in decline, Canadian supply has become an obvious and attractive alternative.”
Increased volume in the USGC market would raise Canada’s already sizeable reliance on the U.S. oil market, however. And while the United States provides security of demand for Canada, there are risks to overreliance, the report says.
The IHS Markit forecast assumes the completion of all the country’s remaining long-distance export pipelines. If those projects were delayed or Canadian or other heavy oil supply is more prolific than anticipated, Canada may have to compete more aggressively for market share in the United States—something it has not yet had to do.
“Although Canadian imports are of similar quality as Latin American crudes, they are not identical. There is a point when more extensive modifications will be required to better tailor facilities to accommodate greater volumes of the Canadian heavy crude,” said Birn. “In a situation where the level of competition is high, Canadian crude may have to adjust price to incentivize refiners to make additional modifications and/or displace greater quantities of offshore imports.”
Alternative diversification strategies—such as customizing oil sands blends or developing upstream partial processing technologies that would result in the marketing of a greater range of crude oil qualities—can help mitigate the risks. However, given the scale of Canadian heavy oil supply today and anticipated growth, these solutions would not remove the risk and would still take considerable investment and time, the report concludes.
“The reality is that Canada—the 5th largest oil producer in the world—maintains an almost singular reliance on one market,” Birn said. “Such a situation is unique in the world and will always carry associated concerns.”
Global energy demand grew by 2.1 per cent in 2017, according to IEA preliminary estimates, more than twice the growth rate in 2016, with oil and natural gas both seeing growth.
Global energy demand in 2017 reached an estimated 14 050 million tonnes of oil equivalent (Mtoe), compared with 10 035 Mtoe in 2000, International Energy Agency said in its new report Global Energy and CO2 Status Report, 2017.
Fossil-fuels met over 70 per cent of the growth in energy demand around the world. Natural gas demand increased the most, reaching a record share of 22 per cent in total energy demand. Renewables also grew strongly, making up around a quarter of global energy demand growth, while nuclear use accounted for the remainder of the growth. The overall share of fossil fuels in global energy demand in 2017 remained at 81 per cent, a level that has remained stable for more than three decades despite strong growth in renewables, IEA said.
“Improvements in global energy efficiency slowed down. The rate of decline in global energy intensity, defined as the energy consumed per unit of economic output, slowed to only 1.6 per cent in 2017, much lower than the 2.0 per cent improvement seen in 2016,” it said.
The growth in global energy demand was concentrated in Asia, with China and India together representing more than 40 per cent of the increase. Energy demand in all advanced economies contributed more than 20 per cent of global energy demand growth, although their share in total energy use continued to fall. Notable growth was also registered in Southeast Asia (which accounted for 8 per cent of global energy demand growth) and Africa (6 per cent), although per capita energy use in these regions still remains well below the global average.
Meanwhile, world oil demand rose by 1.6 per cent (1.5 million barrels a day) in 2017, a rate that was more than twice the annual average seen over the last decade.
An increasing share of SUVs and light trucks in major economies and demand from the petrochemicals sector bolstered this growth.
Global oil demand rose by 1.5 million barrels a day (mb/d) in 2017, continuing a trend of strong growth since prices fell in 2014. The rate of growth of 1.6 per cent was more than twice the average annual growth rate seen over the past decade, the report said.
One of the main drivers of growth was the transport sector, IEA said. Vehicle ownership levels increased in 2017, as did the share of Sport Utility Vehicles (SUVs) and other large vehicles.
This was particularly visible in the United States, where the share of SUVs and light trucks increased from 47 per cent in 2011 to around 60 per cent of total sales in 2017, bringing up the share of these vehicles in the total passenger car fleet to almost half. It is also a factor in the European Union, where oil demand increased by 2 per cent, the highest rate of growth since 2001.
The trend towards larger vehicles has also slowed the pace of decline in average vehicle fuel use, partly offsetting energy efficiency policy efforts. Electric cars are making rapid inroads in many markets, particularly in China, which is leading global sales. For now, however, the strong growth in electric-car sales remains too small to make a dent in oil demand growth.
Another reason behind robust demand growth is oil used as a petrochemicals feedstock. Petrochemicals are the fastest-growing source of oil demand, notably in the United States, where the shale revolution has created very cost-competitive domestic supplies, as well as in China and in other emerging economies, where demand for plastics and other petrochemical products is growing rapidly. It should be noted, however, that the oil use in the petrochemicals sector has only very little impacts on emissions trends as most of the oil is not combusted but transformed into other products, such as plastics.
Around 60 per cent of the growth in oil demand came from Asia, the report said. Although China is the leading global market for the sales of electric cars, it was also the top contributor to oil demand growth, followed by India.
Meanwhile, oil demand in the Middle East, a recent source of demand growth, was flat due to oil-to-gas switching in the power sector and efforts to reform oil product prices and phase out subsidies.
“While a slowdown in oil demand growth may be likely in coming years, there are no signs of a peak in demand anytime soon. As noted in the IEA’s recent World Energy Outlook 2018 and Oil 2018 reports, it is too soon to write the obituary for oil,” the report said.
Global natural gas demand grew by 3 per cent, thanks in large part to abundant and relatively low-cost supplies. China alone accounted for almost 30 per cent of global growth. In the past decade, half of global gas demand growth came from the power sector; last year, however, over 80 per cent of the rise came from industry and buildings.
The report said that natural gas demand grew by 3 per cent in 2017 thanks to abundant and relatively low-cost supplies, as well as fuel switching in key economies, significantly above the average growth of 1.5 per cent of the last five years. China alone accounted for nearly 30 per cent of global growth – with more than 30 bcm out of a total of nearly 120 bcm. This signals a structural shift in the Chinese economy away from energy-intensive industrial sectors as well as a move towards cleaner energy sources, with both trends benefiting natural gas.
IEA said that as part of the official policy drive to “make China’s skies blue again,” there has been a strong push to phase out the practice of burning coal in industrial boilers (especially those in and around major cities) as well as reduce coal use for residential heating. China’s surging gas demand means that it absorbed much of the slack in LNG markets, pushing up international spot prices for gas in the latter part of the year.
Meanwhile, the European Union also saw strong growth in gas demand (continuing the trend from 2016), with consumption up around 16 bcm in 2017. Some of this increase was weather-related, for instance due to a poor year for hydropower. Demand from industry also reportedly picked up on the back of stronger economic activity. Gas consumption in the European Union is still more than 10 per cent below the peak seen in 2010. Gas imports were near historical highs as domestic production tapered off, notably in The Netherlands.
In the United States, gas-fired generation in 2017 fell by 8 per cent, or 110 TWh, offsetting half of the increase in gas demand for electricity generation elsewhere. The case of the United States last year highlights the importance of relative prices in determining emissions intensity trends in the power sector: a slight rise in the natural gas price in 2017 saw gas-fired generation squeezed by both renewables and coal.
“The composition of gas demand growth is changing. In the past decade, half of global gas demand growth came from the power sector. In 2017, over 80 per cent of the growth came instead from industry and buildings. The power sector remains the largest single component of global demand, but this share is likely to decline gradually,” IEA said in its report.
The Arab Petroleum Investments Corporation (APICORP) said almost US$ 1 trillion worth of energy projects will be pushed through in the Middle East in the next five years despite an uncertain geopolitical backdrop.
In its annual MENA Energy Investment outlook, APICORP said around $345 billion has been committed to projects under execution while an additional $574 billion worth of development is planned.
The overall economic outlook remains similar to the forecasts estimated this time last year, with growth of around 3.2 per cent forecast for both 2018 and 2019, it said.
“We expect the MENA region to continue investing heavily as major energy-exporting countries expand the size of their energy sector and strengthen their positions in global markets,” said Dr Ahmed Ali Attiga, Chief Executive Officer of APICORP.
Global investment in the industry is expected to pick up and parts of the MENA region are expected to see a corresponding improvement in investment. Saudi Arabia is expected to lead the way, but the uncertainty over the possible re-imposition of sanctions on Iran mean that it may struggle to attract the foreign investment it needs to develop its industry. Iraq is also facing challenges, despite the improving security situation.
“We see three important trends materialising in our outlook: the first is a transition towards the power sector, which now accounts for the bulk of planned investments as demand for the energy continues to increase,” said Mustafa Ansari, senior economist at APICORP. “The second is the increase in committed investments, reflecting an improving investment climate and a healthy transition of projects from the planning phase towards execution. And third, the private sector has an increasing role to play in financing energy projects in the Middle-East that will help ease fiscal pressures on governments,” he added.
Saudi Arabia and the UAE represent 38 per cent of planned investments, with $149 billion and $72 billion respectively, over the outlook period, as both countries look to boost their upstream oil and gas sectors. For Egypt, the main focus is the ramp-up of gas production and rising power demand. Planned investments in the country are $72 billion, with the power sector making up over 50 per cent of the total.
Elsewhere planned projects in Kuwait stand at $59 billion over the same period, with over 50 per cent in the oil sector. More specifically, the country intends to increase oil output to 4 million barrels per day (bpd) within the next few years. Similarly, in Algeria planned projects stand at around $58 billion with the Hassi Messaoud Peripheral Field Development accounting for a significant portion of investments in upstream oil. The country will seek to invest in upstream oil and gas to meet its target of increasing production by 20 per cent.
Other major investment in the oil and gas sector will be made in Iran, with an estimated $67 billion in planned projects in the coming period, and Iraq, at $47 billion. Oil investments account for $27 billion with the ENI-led Zubair and the PetroChina-led Halfaya, two of the largest upstream development projects in the country. However, the outlook for those countries is much less certain, with a significantly higher degree of political risk.
There are three main challenges that could potentially hinder the growth of investment in the region. The first is that the global investment in the oil and gas sector are closely interlinked with oil prices, and though the situation as a whole is improving, prices are not expected to return to the high levels seen prior to the sharp drop in 2014.
Another challenge to growth is the rising cost of capital, as some governments will find it harder to attract foreign investment. However, supported by its high reserves, and low debt to GDP ratios, the GCC was successful in issuing record debt of over $50 billion in 2017, surpassing the previous year’s record of $37 billion. Saudi Arabia represents the bulk of this, with over $21 billion of debt raised, followed by Abu Dhabi and Kuwait with $10 billion and $8 billion respectively. Oman ($8 billion) and Bahrain ($3 billion) also tapped the international market.
Meanwhile, the regional geopolitical environment remains fragile, and persistent conflicts in the region are creating instability that deters investors and causes them to become cautious in investing in the entire region.
2017 certainly saw improvements and rebalance in the region. The period of weakest economic growth and oil prices seems to have passed, but the recovery phase will take longer and is not without its challenges. GCC governments have announced expansionary budgets following a few years of tightening expenditures because of lower oil revenues, and will prioritise critical investments in their energy sectors.
Cyber security breaches in the Middle East are widespread and frequently undetected, with 30 percent of the region’s attacks targeting operational technology (OT), finds a new study by Siemens and Ponemon Institute.
The study, which examines the region’s oil and gas sector, reveals that while firms have begun to invest in protecting their assets from cyber threats, more needs to be done to increase awareness and the deployment rate of technology if they are to secure their operating environments.
Launched in Dubai today, the study highlights that until recently, cyber-attacks have generally targeted Information Technology (IT) environments such as PCs and workstations. With the acceleration of digitalisation and the convergence of IT and Operational Technology (OT), the region is now seeing a rising amount of attacks aimed at the OT environment, the report said.
The report investigates the readiness of the Middle East’s oil and gas sector to identify and protect against cyber threats. It also assesses what measures need to be taken to close the gaps, surveying around 200 individuals in the Middle East who are responsible for overseeing cyber security risk within their organizations.
“The convergence of IT and OT has become a key opportunity for attackers to infiltrate an organization’s critical infrastructure, disrupting physical devices or operational processes,” said Leo Simonovich, vice president and global head of Industrial Cyber at Siemens Energy. “We know that attacks are becoming more frequent and increasingly sophisticated, and firms quickly need to assign dedicated ownership of OT cyber, gain visibility into their assets, demand purpose-built solutions and partner with experts who have real domain expertise.”
The report found some 60 percent of respondents believe the cyber risk to OT to be greater than IT, and in 75 percent of cases those questioned had experienced at least one security compromise resulting in confidential information loss or operational disruption in the OT environment in the last 12 months.
Another important take away from the study was that despite awareness of rising OT cyber risk, budgets for OT cyber services and solutions have not kept up with the threat. At present, oil and gas organizations in the Middle East dedicate only a third, on average, of their total cyber security budget to securing the OT environment. This suggests that organisations are not aligning their cyber investments with where they are most vulnerable and highlights the urgency to address OT cyber security.
The report outlines six key principles which underlie the most effective OT cyber programs, beginning with assigning and empowering dedicated ownership for OT cyber security. Organisations must overcome the fear of connectivity and gain continuous visibility into their OT assets, and the operating environment needs to be secured all the way to the edge.
Analytics should be leveraged in order to make smarter, faster decisions, and organizations should demand purpose-built OT cyber solutions. Lastly, it’s crucial to partner with OT cyber security experts with real domain expertise.
The surge in tight oil production from the US over the last few years disrupted the oil market, forcing companies in conventional plays to revise, review, and optimise operations to compete with the relatively low-cost barrels being pumped from Lower 48 shale plays.
Today, new research from global natural resources consultancy Wood Mackenzie indicates that while the price crash was painful for conventional producers, they have made gains: many conventional pre-Final Investment Decision (FID) projects are now competitive with Lower 48 breakevens.
Harry Paton, Senior Analyst, Global Oil Supply, at Wood Mackenzie, said: “We have seen encouraging signs of improvement in conventional project breakevens. Costs have come down significantly since 2015. And the number of deepwater FIDs taken at the end of 2017 indicates a mood of quiet optimism in the upstream sector.”
He added: “Some conventional projects already compete with US tight oil. World-class discoveries in Brazil and Guyana, for example, which have giant reserves and high-quality reservoirs, have project breakevens lower even than most tight-oil plays. In other, more mature sectors, such as the US Gulf of Mexico or the North Sea, operators have made great progress in bringing costs down and lowering breakevens.”
However, this new competitiveness has come at the expense of volumes. In 2014, Wood Mackenzie forecast that the new production supply mix would be split 50:50 between conventional projects and US Lower 48 tight oil. These days, US Lower 48 is dominant, making up nearer 70% of new volumes.
Mr Paton said: “Production from conventional pre-FID projects today will be considerably lower than Wood Mackenzie’s pre-price crash forecasts. The key driver is the large number of projects which have fallen completely out of the picture because they are uneconomic and have been delayed or cancelled.”
He added: “Many projects now in the mix have been changed in scope. Operator mentality has shifted to ‘value over volume’. This brings significant cost savings, but takes a chunk out of production for many assets.”
This raises two key issues: rising cost of supply and a potential supply gap, caused by both declining legacy field production and a projected growth in demand.
Wood Mackenzie believes the cost of supply is set to increase as future production will be sustained by higher-cost (>$60/bbl), non-OPEC sources.
The analysis suggests that low-cost OPEC capacity growth will not be able to meet the gap created by declines in higher-cost, non-OPEC volumes. This higher-cost production is set to increase from 1.7 million b/d in 2017 to 5.3 million b/d in 2027. By 2035, these volumes should reach 9.2 million b/d.
Paton said: “Wood Mackenzie calculates that non-OPEC conventional onstream declines stabilised at around 5% in 2016. Our analysis suggests they will stay at this level through to 2020 before increasing to historic norms of 6% per annum.
“Combine this with demand growth of around 8 million b/d and the resultant supply gap is around 23 million b/d in 2027.”
Key to filling this gap are volumes produced via US Lower 48 future drilling and pre-FID projects. These are the future marginal cost barrels which will play an important role in setting the price over the next decade. The Lower 48, in particular, will emerge as an important marginal barrel producer.
“When you look at the numbers in terms of total production, our research suggests the US Lower 48 will be one of the most expensive sources of supply in 2027,” Mr Paton said. “The cost of tight oil will rise as higher-cost new drilling is required to offset declines as core, sweet-spot acreage is drilled out. This contrasts with conventional resource themes which benefit from longer-life assets providing a relatively cheap, stable base of production.”
By: David Manuel, OSV market analyst at IHS Markit
The region’s requirements for anchor handling tugs (AHT), anchor handling tug and supply (AHTS), and platform supply vessels (PSV) have seen steady growth in 2017. The year marked the most improvements in terms of demand and utilisation since offshore activity slowed down post-2014 oil price crash. According to data from MarineBase by IHS Markit, vessel term charters or contract fixtures lasting more than 30 days had increased to around 322 vessels in 2017 compared to an average of 285 vessels from the previous year. Offshore supply vessels (OSV) utilisation rose from the lows of 48 per cent to 55 per cent during the year, but slowed down to 46 per cent before the end of the year due to seasonal factors when most charters conclude and work schedules completed.
Construction support buoys marine activity
The surge in the Middle East offshore activity last year was prompted by a high demand in marine support for offshore construction. Many field development campaigns went on-stream as national oil companies took advantage of the low-cost environment. Since the downturn, a stream of offshore EPCI (engineering, procurement, construction and installation) projects was rolled out by NOCs, supporting OSV demand.
Saudi Aramco has been leading the way in the tendering and contracting activities, creating a firm pipeline of activity for field development projects. Aramco awarded a total of 18 offshore EPCI projects from 2015 to November 2017, as part of its Maintain Production Potential (MPP) and fast track projects, most of which are focused on developing and maintaining Marjan, Zuluf, and Safaniyah fields.
In Abu Dhabi, ADNOC awarded seven major EPCI contracts from 2014 until 2016. Several marine terminal projects were also awarded in Kuwait, Bahrain, Egypt and Saudi Red Sea, mainly to South Korean contractors.
Despite weaker drilling activity during the period, OSV demand on the other hand, remained firm in the offshore construction segment. The AHT and AHTS classes are core fixtures in a marine spread dedicated to support pipelaying, platform installations, and subsea support work scopes. Based on MarineBase, a total of 71 OSVs were chartered for construction support last year, an increase from 50 vessels fixed in the previous year.
Another busy year ahead for OSVs
Demand for OSVs in the Middle East is expected to see a similarly robust year ahead. In the coming months, short-term activity will be driven mainly by marine construction support charters, many of which are anticipated to begin by the end of the first quarter of 2018. Saudi Aramco has more than 100 offshore platforms under construction, projects set for installation from 2018-2020. These projects were awarded to: Dynamic Industries, Larsen & Toubro and its partner EMAS Chiyoda Subsea, McDermott International, Abu Dhabi’s NPCC, and Saipem.
McDermott alone is scheduled to mobilise four of its derrick pipelay barges to Saudi this year. The barges would each need a dedicated marine support spread of about five vessels comprising AHT, AHTS and PSVs among others. Younger, powerful and versatile AHT and AHTS classes will be in demand while DP-2 PSVs will be a basic requirement.
Moreover, the start-up of newly awarded five-year contracts from Aramco for six PSVs and nine AHTS recontracts are expected to further contribute to utilisation rates in the coming months.
Improving sentiment but overcapacity lingers
But while OSV demand continues to improve, marketed supply has exceedingly outpaced available demand. Daily charter rates remain poor since bottoming out to current breakeven levels. Oversupply continues to build up to record highs, placing the Middle East with the second largest OSV tonnage. MarineBase by IHS Markit shows a total of 640 vessels currently working in the region as of end-January. The increasing capacity is exacerbated by newbuild acquisitions and ongoing vessel relocations from Southeast Asia to the Middle East.
Day rates will remain under pressure over the long term, unless a concerted, realistic, and effective approach to removing excess tonnage is achieved by the sector.
MarineBase by IHS Markit is an online service, providing data, market intelligence and analysis about the global offshore supply vessel fleet. It tracks over 3,500 PSVs and AHTS vessels worldwide.
Bahrain plans to spend US$6 billion on oil and gas projects this year to meet increasing local demand and to boost government revenues. The three main projects that the country is pressing onwards with includes an LNG import terminal, expansion of Sitra refinery and an oil pipeline with Saudi Arabia. It also includes Bahrain National Gas Expansion Company’s third gas plant and an aromatics facility joint venture between Bapco and Kuwait’s Petrochemical Industries Corporation.
The expansion of the capacity of the existing Sitra oil refinery from 267,000 bpd up to almost 400,000 bpd is part of the Bapco Modernisation Programme, which is on track for completion in 2022.
“The expansion of the country’s refinery would increase refined fuels production by 30 per cent, providing a crucial boost to export revenues,” Richard Bailey, senior vice president at DNV GL - Oil & Gas said to Pipeline Magazine. “The refinery expansion will also inevitably play a role in meeting the increasing but relatively modest local demand.”
In recent years, refined fuels exports were increasingly insufficient to support the country’s social expenditure programmes. At the same time, energy subsidies have resulted in strong power consumption growth resulting in less refined products available for export, Bailey said.
Bahrain in December 2017 awarded a $4.2 billion engineering, procurement, construction and commissioning turnkey contract to a consortium led by TechnipFMC with Samsung Engineering and Spain’s Tecnicas Reunidas. The signing of the contract was expected for January-end, Bahrain’s oil minister Sheikh Mohammed bin Khalifa al-Khalifa said.
The project is located on Bahrain’s Eastern coast and entails the expansion of the capacity of the existing Sitra oil refinery, improving energy efficiency, valoristion of the heavy part of the crude oil barrel (bottom of the barrel), enhancing products slate and meeting environmental compliance. With estimates putting the cost of the expansion as high as $9 billion, it will be the largest project ever financed in the kingdom.
Sitra currently refines oil from Saudi Arabia’s Abqaiq processing facility, which is fed by the Arabia-Bahrain (AB) pipeline. This pipeline is being replaced with a new one that will expand capacity from 230,000 bpd to 350,000 bpd. The new oil pipeline will be completed in 2018 to serve the planned expansion of Bahrain’s refinery capacity. The pipeline will be ready to run by the end of 2018 with more than 50 per cent of the work already completed, Sheikh Mohammed said in a statement on Bahrain News Agency (BNA). The pipeline is being laid underground in the south of Bahrain. Bahrain currently produces 200,000 bpd of oil including output from the offshore Abu Safa, its major source of government revenues. Authorities are looking to increase output from Bahrain’s own oilfield by tapping pre-khuff gas, which is gas located in deep deposits.
For the Sitra refi nery however, the country will continue to rely on crude imports, particularly from Saudi, because of its small and depleting resource base, Bailey said. “The recent enhanced and improved oil recovery work slowed the decline of recoverable reserves, but not enough to reverse the trend,” he added.
LNG import terminal
Additionally, the refinery expansion will push up demand for gas, adding to the pressure on the commodity that is expected to hit a deficit in coming years despite plans for improving power stations to save gas use.
“Industry accounts for the majority of Bahrain’s gas needs - it represented 41 per cent of demand in 2015, with Aluminium Bahrain (Alba) accounting for nearly half,” Mustafa Ansari, analyst, energy research at APICORP said to Pipeline Magazine.
“The Bapco refinery, whilst not on the same scale as Alba, is also a large consumer of gas, and demand for natural gas is expected to more than double within the medium term horizon following the refinery expansion.”
Gas output in Bahrain was around 19.5 bcma in mid-2017, primarily sourced from the Khuff gas reservoirs – accounting for nearly 80 per cent of gas supplies. The remaining 2.6 bcma comes from residue gas production from the Bahrain National Gas company (Banagas).
Supplies are expected to increase marginally over the next five years due to the Deep Gas resource from the Bahrain onshore field, only to plateau to a little under 23 bcm by 2024, according to APICORP.
Although current demand is adequately met by existing levels of output, natural gas demand is expected to continue rising where by 2019 the country will experience a gas deficit of around 1.9 bcm.
Bahrain’s offshore LNG import terminal will have an initial capacity of 4.1 billion cubic meters (bcma) with the potential to expand to 8.2 bcma. This would present the kingdom with adequate capacity to cover the deficit up to 2027 at the very least, APICORP forecast.
“Given the number of liquefaction plants in recent years, competition for LNG imports has gone down and with it the price of imports. Nevertheless, Bahrain’s LNG terminal will consist of a floating storage unit (FSU), offering the kingdom the flexibility to cater to seasonal demand and the option to re-export to regional demand centres,” APICORP’s Ansari said. “The configuration will include an LNG vessel serving as an FSU, with on jetty regasification. This will enable the kingdom to optimise the utilisation of the FSU, by redeploying it to trade as an LNG carrier when imports are not required.”
Bahrain’s gas terminal project is jointly owned by Bahrain’s Oil and Gas Holding Co (Nogaholding) and a consortium of Teekay LNG Partners, Gulf Investment Corp and Samsung C&T.
Bahrain’s oil minister has said that Saudi Aramco could potentially use the terminal as part of a wider scheme to connect Gulf Arab countries with a gas pipeline.
Bahrain has set its budget based on oil price of $55 per barrel. The kingdom is taking part in an OPEC-led pact to scale back production, which will remove a stock overhang and prop up oil prices. Sheikh Mohammed recently said he expects average 2018 prices to go beyond $70 per barrel.
The global liquefied natural gas (LNG) market has continued to defy expectations of many market observers, with demand growing by 29 million tonnes to 293 million tonnes in 2017, according to Shell’s annual LNG Outlook.
Based on current demand projections, Shell sees potential for a supply shortage developing in mid-2020’s, unless new LNG production project commitments are made soon.
Japan remained the world’s largest LNG importer in 2017, while China moved into second place as Chinese imports surged past South Korea’s. Total demand for LNG in China reached 38 million tonnes, a result of continued economic growth and policies to reduce local air pollution through coal-to-gas switching.
“We are still seeing significant demand from traditional importers in Asia and Europe, but we are also seeing LNG provide flexible, reliable and cleaner energy supply for other countries around the world,” said Maarten Wetselaar, Integrated Gas and New Energies Director at Shell. “In Asia alone, demand rose by 17 million tonnes. That’s nearly as much as Indonesia, the world’s fifth-largest LNG exporter, produced in 2017.”
LNG has played an increasing role in the global energy system over the last few decades. Since 2000, the number of countries importing LNG has quadrupled and the number of countries supplying it has almost doubled. LNG trade increased from 100 million tonnes in 2000 to nearly 300 million tonnes in 2017. That’s enough gas to generate power for around 575 million homes.
LNG buyers continued to sign shorter and smaller contracts. In 2017, the number of LNG spot cargoes sold reached 1,100 for the first time, equivalent to three cargoes delivered every day. This growth mostly came from new supply from Australia and the USA.
The mismatch in requirements between buyers and suppliers is growing. Most suppliers still seek long-term LNG sales to secure financing. But LNG buyers increasingly want shorter, smaller and more flexible contracts so they can better compete in their own downstream power and gas markets.
This mismatch needs to be resolved to enable LNG project developers to make final investment decisions that are needed to ensure there is enough future supply of this cleaner-burning fuel for the world economy.
Oil and gas will grow to account for half of the world’s energy in 22 years, as natural gas overtakes coal as the second largest sources, BP said in its latest outlook.
The global energy mix will be the most diverse the world has ever seen by 2040, with oil, gas, coal and non-fossil fuels each contributing around a quarter, according to BP’s Energy Outlook 2018 which forecasts energy needs over the next two decades.
“We are seeing growing competition between different energy sources, driven by abundant energy supplies, and continued improvements in energy efficiency,” said BP’s group chief economist Spencer Dale. “As the world learns to do more with less, demand for energy will be met by the most diverse fuels mix we have ever seen.”
Oil demand is expected to grow during the next few years before plateauing towards to end of the outlook period.
Most of the oil demand growth in will come from emerging economies. The growth in supply is driven by US tight oil in the early part of the Outlook, with OPEC taking over from the late 2020s as Middle East producers adopt a strategy of growing market share, BP said.
The transport sector will continue to dominate global oil demand, accounting for more than half of the overall growth. Most of the growth in energy demand from transport, which flattens off towards the end of the Outlook, comes from non-road (largely air, marine, and rail) and trucks, with small increases from cars and motorbikes.
After 2030, the main source of growth in the demand for oil is from non-combusted uses, particularly as a feedstock for petrochemicals.
Natural gas, BP expects, will grow strongly over the period – supported by increasing levels of industrialisation and power demand in fast-growing emerging economies, continued coal-to-gas switching, and the increasing availability of low-cost supplies in North America and the Middle East.
By 2040, the US will account for almost one quarter of global gas production, and global LNG supplies will more than double. The sustained growth in LNG supplies is likely to greatly increase the availability of gas around the world, with LNG volumes overtaking inter-regional pipeline shipments in the early 2020s.
Meanwhile, renewable energy will increasingly meet global energy demand. “More than 40 per cent of the overall increase in energy demand is met by renewable energy,” said Dale.
It will grow by over 400 per cent and account for 50 per cent of the increase in global power generation over the next two decades.
All the growth in energy consumption will come from fast-growing developing economies: China and India account for half of the growth in global energy demand to 2040, BP said.
It expects China’s energy growth to slow in the next 22 years as it transitions to a more sustainable pattern of economic growth. However, India’s slowing in demand growth will be less pronounced and by the early 2030s it is seen to overtake China as the world’s fastest growing market for energy. In the latter stages of the Outlook, Africa also plays an increasingly important role in driving energy demand, contributing more to global demand growth from 2035 to 2040 than China, the report said.
Oil rich nations have a window of opportunity to transform and be well positioned to benefit from this shifting global energy landscape, according to recent report “The Great Energy Shift”, produced by global strategic management consultants, A.T. Kearney.
Growing global diversification of the energy mix and an increased share of natural gas, renewables and electrification, is challenging conventional approaches and business models in the energy value chain.
Eduard Gracia, principal at A.T. Kearney said: “Market trends along the energy value chain are dramatically changing the landscape. We expect an energy market characterized by increased demand in addition to increased electrification, supply fragmentation and consumer power. This will over time lead to stabilization of energy prices and a convergence of energy markets”.
According the report, three recommendations which will support oil-rich nations and national oil companies in the region to effectively address the global disruptive changes of the energy sector – embrace renewables; leverage gas reserves and expand down the value chain.
Sean Wheeler, partner, A.T. Kearney said, “Our industry is rapidly changing. Global energy transition will lead to a broader mix of energy sources and a more fragmented supply, also in this region.”
Many of the regional oil players have already initiated projects to prepare for the great energy shift ranging from investments, into solar energy and gas, to increasing downstream oil and gas investments.
Commenting on this strategy, Rudolph Lohmeyer, vice president A.T. Kearney Global Business Policy Council said, “The Middle East enjoys an important advantage due to both its comparatively cheap hydrocarbon reserves and its geographic location. At these times of change, it is key that nations and national oil companies manage uncertainty by applying the disciplines of strategic foresight to their decision-making. This is particularly critical for a sector in which the returns on capital investment unfold over decades.”
The report concludes that oil rich nations must focus their investments on opportunities that leverage their competitive advantages, an educated workforce and the ideal geographic location.
“In a world of accelerating energy transition and cost effective new technologies, gas and renewables will become increasingly important in the global energy mix. This region is strongly positioned to tap into the gas market as well solar opportunities,” said Kurt Oswald, partner A.T. Kearney and board member of the A.T. Kearney Energy Transition Institute.
“In these times, it is critical that governments work together with their national oil companies, energy players and downstream companies to define the best path ahead,” said Bob Willen, managing director, A. T. Kearney Middle East and Global Lead Partner Government and Economic Development Practice, A.T. Kearney.
By Anne-Marie Walters, Bentley Systems
While the low price of oil is providing relief to consumers at the gas pump, pressure is being put on offshore oil producers in this current economic environment to get more life out of the platforms they have rather than building new. Determining how to get more out of existing assets and extend their life in the offshore environment is a pressing problem for owners and the engineering companies that support them. As a result, many owner-operators are looking to optimize their resources and take a risk-based approach to monitoring their assets. A recent survey of producers conducted by Oil and Gas IQ (OGIQ) and Bentley Systems shows the extent of this trend.
Many offshore platforms in the Gulf of Mexico and the North Sea are 40 years old or more, and they have gone well beyond their expected life of 25 years. In these challenging times, though, owners cannot afford to install new platforms. So, they are leaning on analytic software technologies to analyze structural integrity and determine risks, and explore options to prolong asset life. A surprising result of the survey, though, is that even producers with assets that are less than 10 years old are looking at how to extend asset life –working out options to get more from their existing assets rather than build new. When asked what the most important drivers for reassessment are, 97 percent of those surveyed said field life extension, making it the most important business driver. Other just as important drivers for reassessment include new production equipment that puts more weight on platforms, subsea tiebacks, and changing meteorological data. But, life extension is clearly the main focus of producers.
Adhering to inspection standards is another challenge facing oil producers. When asked what compliance codes producers were using, more than half responded they were using ISO 19902, and another half used HSE in the North Sea. But the most interesting number is the 19 percent that are using RP2SIM, a relatively new standard that came into being in 2014. This standard is defined as an ongoing process for ensuring the continuing fitness-for-purpose of an offshore structure or fleet of structures. While this standard is in the early adoption phase, it is expected to lead to the next stage of adoption – the risk-based approach. The fact that this new code is at nearly 20 percent adoption shows that producers are constantly monitoring the assets and thinking about life extension.
The OGIQ survey backs up this opinion with 34 percent of producers adopting a risk-based approach to maintenance, clearly putting them beyond the early adoption phase. Producers have discovered that a risk-based inspection approach can cut costs if it’s implemented properly, and they can actually use it to optimize inspection schedules.
When asked if producers perform the engineering analysis in-house, 39 percent said they do while 59 percent responded that they conduct both in-house and contracted-out analysis, which shows that, with owners comprising 70 percent of IGQC readers, owners are addressing the problem. While it would seem that structural integrity management would be easy to outsource, the survey shows that it is too important for them to outsource. It is critical to their business, for managing their assets and for productivity improvement.
Moving to what kind of technology producers are using, the vast majority, at nearly 80 percent, are still carrying out inspections manually. This figure presents a huge opportunity for using mobile technologies to support manual data collection. Although the industry is a conservative one, it is not averse to using new technologies to streamline costs. Essentially, four out of five respondents need to physically see what is in front of them, but they are using technology to support the manual capture of as-built information, not replace it. Then, the question becomes, how do producers hold this data – in spreadsheets, with a good document management system, or by using a formalized process for storing and retrieving information used by all inspectors.
The survey results show that nearly 50 percent of respondents have a document management system, not a formalized process, which means there is potential for owners to perform inspections more efficiently. It also means that the 39 percent of those surveyed that are using a more formalized approach to their inspections can navigate the risk-based route much more easily. They are able to store and retrieve information used by all inspectors. The purpose of a formalized process, essentially, is to ensure that appropriate notifications are delivered across the organization, which enables an organization to function effectively. The respondents also said poor communication across departmental silos (41 percent) is another major challenge.
Lastly, the survey tackles alternative ways to conduct inspections that include mobile devices, unmanned aerial vehicles, cloud technology and laser scanning. With regard to using mobile devices to conduct the inspection process, only 32 percent of respondents said they were using them, which means there is great potential for adopting more of this technology. According to Phil Christensen, VP of analytical modeling with Bentley Systems, those with paper-based workflows are hesitant to adopt mobile devices fearing they could drop them in the water or not know how to back up the device when out on the platform. But with 32% adopting this technology, clearly some have overcome these challenges.
Interestingly, the adoption of UAVs is rapidly making inroads in the industry with more than a quarter already using them. Christensen says he is encouraged by this number, as he guessed that the percentage of users would only be around 10 percent. Christensen is also surprised by the number of respondents using cloud technology. With a quarter of the audience adopting it, Christensen says we are just beyond the early adopter stage with users becoming more relaxed about issues of security. He adds that some Bentley users are asking for cloud-only solutions of the products it offers. These unsolicited requests specifically demand a solution to their data needs that is not on premise, validating that the thinking among oil producers has changed.
Some Examples from the Field
The takeaway from the survey is that producers are seeking alternative ways to inspect, maintain, and extend the life of their assets. It is no different from an individual taking their car into the mechanic for general maintenance and tune ups. Let’s examine how three owner-operators are implementing analysis software to maintain their offshore platforms and assets.
Oil and Natural Gas Corporation currently operates more than 265 offshore fixed jacket platforms in waters off the coast of India that have outlived their 25-year design life. Installing new platforms would cost the company USD 25 million per platform. Instead, ONGC saw the value of asset life extension and invested USD 150 million to assess its jacketed platforms for extended fit for user and strengthen the platforms as required to meet industry safety standards.
ONGC deployed Bentley’s SACS for design-level analysis to carry out detailed structural analyses and SACS collapse for ultimate strength analysis. The analyses included dent modeling, member/joint component strengthening, additional pile modeling, and soil convergence, as well as extensive load modeling to recommend equipment removal if necessary. The technology became part of ONGC’s methodology for platform life extension/requalification, which added 10-15 years to the average life of each structure.
In the Chenqdoa oilfield in Bohai Bay, a number of offshore platforms have reached the end of their design life, and needed to be reassessed for extended life and to ensure safe operation. China-based oil producer Sinopec performed underwater inspection of the platforms to evaluate their structural security and determine their maintenance feasibility. It relied on analytical software to evaluate the structural integrity of the platforms and consider the maintenance alternatives based on the analytical data required for safe operation of the marine platform.
Using SACS, Sinopec evaluated the structural integrity of the existing platforms to determine whether repairs were necessary, economically feasible, and could be completed effectively. Sinopec’s reliance on comprehensive analysis to perform a risk-based approach to life extension of its platforms kept it from building new ones, saving millions of dollars.
Zakum Development Company (ZADCO) had to evaluate and reinstate the structural integrity of the platform that was struck by a 1,600-ton marine vessel in the Upper Zakum oil field, the fourth largest in the world. For each day that production was halted meant lost revenue for the joint-venture stakeholders, so ZADCO used analytical software to carry out the ship impact analysis in-house, which reduced project time and costs. SACS software helped ZADCO resume production sooner, and the technical documentation-generated SACS simulations allowed the company to substantiate the insurance claim resulting from the accident saving the operator considerable costs.
These three excellent examples of producers extending the life of their assets illustrate how software technology is becoming an integral part of risk-based analysis. And new technologies, such as cloud computing, mobile devices, and UAVs are already here to help continue the productive life of existing platforms. It is now a matter of getting producers to be comfortable with using them and implementing them in their daily monitoring routines.
By: David Carter Shinn, Partner, Head of Data Services for Bassoe Offshore
If you’re not ARO Drilling, you’re on the periphery of the Saudi jackup market. Rig owners can expect tough competition for fewer opportunities, but also an improving outlook for the rest of the Middle East
The company is real. Their 20-rig newbuild program is real. And their exclusive relationship with Saudi Aramco means that ARO Drilling now owns the jackup market in Saudi Arabia.
When we wrote about the Saudi Aramco-Rowan joint drilling company venture (now called ARO Drilling) a year ago, we said it wouldn’t immediately close off Saudi Arabia to all rig owners except for Rowan. That still holds true, but over time, it’s going to become harder and harder for outsiders to remain in the most important offshore market in the Middle East.
As ARO gets bigger, the Saudi Market gets smaller
Currently, 45 jackups are on contract in Saudi Arabia. ARO now has 12 rigs operating under the ARO name (seven are or will soon be owned by the joint venture), while 33 rigs are managed by other contractors like Shelf, Seadrill, Ensco, ADES, Noble, and Saipem.
But starting in 2021, the first of ARO’s 20 newbuild rigs (to be constructed at the new shipyard complex in Saudi Arabia) will roll into the market.
Assuming Saudi Aramco demand holds at 45–50 jackups on contract at any time, the 33 rigs owned by other contractors today will reduce to around 13 toward the end of the next decade. And during those years, rig contractors will have to fight to keep their place in the Saudi market.
ARO’s newbuild program will dictate opportunity flow to other rig owners
ARO’s plan to build 20 jackups over ten years has sort of been an issue the market chose to forget about. It’s an enormous undertaking. A new shipyard, a new rig design (which hasn’t been formally announced yet), a lot of moving parts, and a ten-year timeline makes the project something that the rest of market can sort of deal with later.
But these plans have matured. The design is nearly set, the shipyard has partnered with Lamprell – the number one jackup builder in the Middle East – and construction of the facilities is underway.
It’s (very probably) going to happen.
Still, there are risks for delays and cost overruns, and the actual rate of these rigs’ flow into the market will determine how the demand situation plays out for other rig owners in Saudi Arabia.
Newbuild rigs get 16-year contracts, but dayrates still unknown
As Rowan has reported, each of these rigs has a guaranteed 16-year contract where dayrates for the first eight years are governed by a formula which equals the cost of each newbuild divided by an undisclosed number of contract days plus daily OPEX, overhead costs, and a “moderate” cost escalation.
The second eight years will have dayrates set by a “Pricing Mechanism” which will likely force dayrates to be more competitive.
What’s interesting about ARO’s newbuild plans is that they give some insight into Aramco’s idea of dayrates in the future. Although it’s anyone’s guess, if we make some very rough assumptions, we can try to predict the rates these rigs will be working at and which rates, therefore, will set the market in Saudi.
We take $220 million as the build cost (including shipyard cost, supervision, and operating equipment) for each rig and amortize this over 16 years with the first eight years weighted more than the second eight years. Then we estimate daily OPEX at $65,000, daily overhead at $5,000, and apply a 3 per cent cost escalation on OPEX and overhead starting with year two.
This gives us a dayrate of $110,000 starting in year 2021 and moving up to $137,000 at the end of the contract period. And these are break-even rates only, so real rates are likely to be higher.
For reference, average dayrates in Saudi Arabia are now around $104,000.
There are two implications of this exercise. One, rates in Saudi Arabia will likely stay at the top end of the market. Rig owners who have low financing costs will be able to be competitive. Two, when ARO dayrates become subject to the Pricing Mechanism, they could get squeezed further on operating margins.
It’ll be interesting to see how this ends up working.
Look to other markets
Although Saudi Arabia is the place everyone wants to be, the effect of ARO Drilling’s growth will be offset, at least partially, by growth in other markets like the UAE (where ADNOC currently has a six-rig, four-year tender out) and Qatar, which is also expected to increase their rig count over the next few years.
Added to that, the real effects of ARO Drilling’s emergence won’t hit hard until after 2021 at the earliest, and by that time, scrapping of old rigs across the Middle East should balance out the increase in supply from the arrival of other (non-ARO) newbuild jackups into the region.
The situation isn’t dire yet, but rig owners will stay busy planning their Middle Eastern strategy and managing their efforts to stay in Saudi Arabia with their efforts to find opportunities elsewhere. And they’ll have to decide how they’ll operate in a new environment where Saudi Arabia isn’t the largest jackup market anymore (for everyone except ARO).
Oil sands production growth will continue through the next decade but a slowdown is anticipated with investment expected to remain lower than historical levels, says a new major research initiative by IHS Markit.
“Oil sands production is akin to base-load power generation, but for the oil market,” said Kevin Birn, executive director - IHS Markit, who heads the Oil Sands Dialogue. “Once operational, oil sands facilities are largely unresponsive to the oil price—with production neither ramping up nor ramping down materially. And since oil sands do not have to overcome production declines, every incremental investment in new capacity—no matter how small—can result in growth.”
Entitled Scenarios for Future Growth, the Oil Sands Dialogue report forecasts the outlook for oil sands investment and production growth across different prices outlooks in the IHS Markit global energy scenarios.
Upstream investment in new oil sands production capacity has fallen by two-thirds since the 2014 collapse of oil prices—from more than $30 billion to just over $10 billion estimated for 2017—and may fall further in 2018 before beginning to recover. Yet, oil sands production is still expected to grow in each of the IHS Markit scenarios.
In 2017, Canadian oil sands production is expected to have topped 2.6 million barrels per day (mbd). Depending on the IHS Markit scenario and corresponding global oil price trajectory, oil sands production could rise between 700,000 bpd to 1.4 mbd by 2030—with nearly 400,000 bpd of growth in all cases coming from projects in construction today or projects recently completed and ramping up.”
The report says that although costs have fallen significantly in the oil sands and more oil will come for less, it is the unique nature of oil sands production that makes a future without oil sands growth difficult to envision over the coming decade. It cites the lack of production declines—if existing oil sands facilities are maintained, their production levels do not decline—which is unique compared to other types of oil production globally.
While the collapse of oil prices has slowed investment, projects under development at the onset have continue to be completed and production growth has continued. However, the reduced investment will impact the rate of future growth, the report says. In all IHS Markit scenarios, the level and pace of future investment and growth in the oil sands is lower compared with the decade preceding the oil price collapse.
“Growth in the Canadian oil sands will ultimately be a function of the future price of oil and the challenges that face the industry,” Birn said, “but growth will also be different, driven forward through the optimisation and expansion of existing facilities because they are lower cost and quicker to oil. A more consolidated industry has also emerged in the last few years which means that even in much higher price scenarios overall investment is likely to remain lower than in the past.”
Senior oil and gas professionals in MENA expect a positive step change in the industry’s capex, opex, headcount and R&D spending levels in 2018, according to a new DNV GL research report.
Confidence and Control: The outlook for the oil and gas industry in 2018 is DNV GL’s eighth annual report providing a snapshot of industry confidence, priorities and concerns for the year ahead. It reveals an imminent turnaround in spending on R&D and innovation after three years of cuts and freezes. More than a third (36 per cent) of 813 senior sector players surveyed, expect to increase spending on R&D and innovation in 2018: the highest level recorded in four years and six percentage points higher in MENA (42 per cent), the report said.
After three tough years, overall confidence levels have nearly doubled from 34 per cent in 2017 to 64 per cent for the year ahead and are now in line with the global figure of 63 per cent, DNV GL said.
Plans to maintain or increase capital spending in 2018 is significantly higher in MENA, 80 per cent versus 66 per cent, and is a two-fold increase on last year’s intentions (40 per cent), the research added.
MENA confidence around hitting revenue targets is also higher than global counterparts (73 per cent versus 61 per cent), it said.
“The outlook for the oil and gas industry in MENA is one of confidence and control,” Ben Oudman, regional manager, Middle East and North Africa, DNV GL – Oil & Gas.
“Though the oil price is lower, it is at an acceptable level to run a profitable business, if spending is managed effectively and efficiently. In the Middle East, we are now seeing a much longed for focus on investment and plans to bring in new technology and extra skills which suffered severe cuts during the downturn,” he said.
Industry leaders and technical experts questioned in the survey cite R&D as the main area for increased spending. “This is an area which has suffered the most in the past three years, so it is very encouraging to see a positive turnaround to allow those companies to realize improved profits and performance,” Oudman added.
Barriers to growth related to increase in operating costs and a weak global economy are all expected to subside in the coming year, while geographical instability in key markets, lack of investment in innovation, and a shortage of skills are growing. The greatest challenge cited by MENA respondents is uneconomic oil price, though notably, this has fallen significantly as a key concern from 66 per cent in 2017 to 42 per cent.
Concerns regarding low oil price may explain a greater focus on cost efficiency among MENA respondents compared to their global counterparts. More than two-fifths (42 per cent) believe efforts to manage spending will be a top priority in the next twelve months, a figure that has relatively unchanged from 2017 (43 per cent), but is 11 percentage points higher than global opinion.
Meanwhile, the DNV GL research stated that rising confidence is also evident in other regions - the US. North America is up from 49 per cent to 57 per cent.
Europe has the most improved outlook for the oil and gas sector (up from 25 per cent last year to 64 per cent), with Latin America at 77 per cent (46 per cent in 2017) and Asia Pacific at 57 per cent (30 per cent in 2017).
It also said that nearly two-thirds (62 per cent) of respondents globally expect their organisation to maintain or increase headcount in 2018, compared to 66 per cent in MENA. This compares to 43 per cent globally in 2017 and 43 per cent in MENA.
The exploration sector has emerged from the downturn confident that it has put its house in order, but Wood Mackenzie does not expect to see a surge in activity in 2018.
Dr Andrew Latham, Wood Mackenzie’s vice president, Research, Global Exploration, said: “We expect most companies will maintain a highly cautious approach to exploration for a while yet. Competition for the best opportunities will be fierce. Industry investment and well counts will remain stubbornly low in 2018.”
He added: “We’ve identified five issues that stand out this year, but two are key. Firstly, the number of committed explorers has dwindled and corporate diversity will remain unusually low. Secondly, much of the industry is chasing rather similar opportunities. Play and basin diversity will also be unusually narrow. This raises the spectre of sharper competition eroding margins – a threat not seen since 2014.”
The five key themes Wood Mackenzie expects to affect the exploration sector in 2018 are:
Industry consolidation, the price downturn and the attractions of unconventional alternatives have reduced the number of wildcatters operating in the sector. With few newcomers, the narrow corporate landscape will persist. Operatorship will be more concentrated than ever, with only the Majors, a handful of NOCs and the top few independents leading high-impact drilling programmes.
Dr Latham said: “Once again, the Majors will be the explorers to watch. Too large to match the retrenchment to US shale of the US independents, they know that conventional exploration will be needed for long-term renewal. The Majors sense a bottom-of-the-cycle opportunity to build acreage at low cost. Their exploration cuts have been less deep and their overall market share will continue to grow.”
While Asian NOCs could be set to increase exploration in 2018 as part of a sustainable resource renewal strategy to address structural production declines, Wood Mackenzie believes the outlook is mixed for the independents.
The most-favoured plays will be deepwater sweet spots promising high resource density, rapid commercialisation and breakeven prices below US$50/bbl. Most of the best of these are around the Atlantic margins. Basins are a mix of the proven – such as Guyana, Mauritania, and the US Gulf of Mexico - and unproven frontiers, including Nova Scotia, South Africa, and Namibia.
Deepwater exploration will boost exposure to gas, a core strategic objective for most larger companies. Whether the plays are proven or not, the critical factor will be scope for straightforward development in the event of a discovery.
However, Wood Mackenzie expects exploration budgets to remain tight despite an improving price outlook. Exploration’s share of upstream investment has slipped to below 10% since 2016 and is not about to recover.
Dr Latham said: “Global investment in conventional exploration and appraisal will be around US$37 billion in 2018. This will be 7% less than 2017 spend of US$40 billion, and over 60% below its 2014 peak. The Majors’ investment will be cut back relatively less, trimmed by around 4% versus 2017. As some of the last outstanding pre-crash high-rate rig contracts roll over, average well costs should trend lower. Wildcat counts may creep above this year’s numbers.”
As in 2017, much of the industry’s focus will be on acreage capture and re-loading for the longer-term. For some, the priority will be to reposition their portfolios for a lower breakeven future. For others, it is simply portfolio renewal after a long period of inventory depletion.
Around 40 licensing rounds will run through 2018. Competition for quality acreage will become more intense as the Majors and other big explorers chase the same opportunities. The highest-profile licensing rounds will, once again, be those scheduled in Brazil and Mexico.
Dr Latham added that there are early signs that the exploration sector may soon return to profit. Returns in 2015 and 2016 were down in low single digits. Early signs are that 2017 will prove rather better.
He said: “Based on the volumes that we can already measure, resource discovery costs are close to US$2/boe. If these volumes have average development values of around US$2/boe, then the year’s discoveries will indeed be worth more than they cost to find.”
The industry should achieve double-digit returns in 2018. Reset portfolios and lower costs are already paying off. Many exploration costs have halved versus their 2014 peak, helped by quicker drilling of most wells. Most of the upcoming wells will avoid the expensive rig contracts from the boom years. Deflation, standardisation and project re-design are all helping reduce development costs.
One area of concern is the rising price of access to quality acreage. Can explorers hold their discipline to avoid value erosion as competition intensifies in hot plays? Conventional explorers will be keeping a watchful eye on US tight oil, a sector on probation in 2018 as investors look for evidence of surplus cash flow. Any setbacks here could further intensify competition in deepwater.
“Looking to 2018, the industry will drill fewer, better wells focused on plays that are commercially attractive,” Dr Latham said. “After a few difficult years, the economic outlook is at last looking brighter for explorers.”
This year witnessed another record low year for discovered conventional volumes globally of less than seven billion barrels of oil equivalent, Rystad Energy said in a new report.
“We haven’t seen anything like this since the 1940s,” said Sonia Mladá Passos, senior analyst at Rystad Energy. “The discovered volumes averaged at approximately 550 million barrels of oil equivalent per month. The most worrisome is the fact that the reserve replacement ratio in the current year reached only 11 per cent (for oil and gas combined) - compared to over 50 per cent in 2012.”
According to Rystad’s analysis, 2006 was the last year when reserve replacement ratio reached 100 per cent; largely thanks to the giant onshore gas field Galkynysh in Turkmenistan.
Not only did the total volume of discovered resources decrease – so did the resources per discovered field, the report said.
An average offshore discovery in 2017 held approximately 100 million barrels of oil equivalent, compared to 150 million boe in 2012. “Low resources per discovered field can influence its commerciality. Under our current base case price scenario, we estimate that over 1 billion boe discovered during 2017 might never be developed,” said Passos.
The top three countries in terms of discovered volumes in 2017 were Senegal, Mexico and Guyana.
In Senegal, Kosmos Energy continued with its exploration success story by discovering the Yakaar gas field. Coupled with the 2016 discovery of Teranga, this could represent a large LNG development in the future.
2017 was also a promising year for Mexico. Zama and Ixachi discoveries, together with some other smaller finds, added around 1 billion boe of recoverable resources for the country. Zama was of particular importance for Mexico. It was the first discovery in the country by a private company – Talos Energy – in the past 80 years.
In Guyana, ExxonMobil achieved a new milestone by adding another 1 billion boe of recoverable resources through its 2017 large discoveries like Payara, Turbot and Snoek.
“While there have been some notable successes this year, we have to face the fact that the low discovered volumes on global level represent a serious threat to the supply levels some ten years down the road,” said Passos. “Global exploration expenditures have decreased year-over-year for three consecutive years now, falling by over 60 per cent from 2014 to 2017. We need to see a turnaround in this trend if a significant supply deficit is to be avoided in the future.”
Rystad Energy does not expect the final volume of 2017 discovered resources to be significantly impacted by the results of exploration wells being drilled currently. The results of the ultra-deepwater well Lamantin in Mauritania, operated by Kosmos Energy, were reported on December 12th. Even though large prospective resources were expected from the well, the results were disappointing and the well has been plugged and abandoned. Another high-impact well is currently being drilled offshore Nigeria – Oyo Northwest – operated by Erin Energy. Rystad Energy expects the well results to be announced at the beginning of 2018. The most recent pre-drill estimate indicates resources of over 1 billion boe, which would mean a very positive start for the year.
The costs, causes, and repercussions of unplanned downtime are triggering investment in digital tools and field service management, according to a new study commissioned by ServiceMax from GE Digital, a provider of field service management solutions. The research was conducted by leading technology consultancy firm Vanson Bourne, and targeted IT and field service leaders across the Middle East and Turkey.
The study found:
● Unplanned downtime happens a lot: 82 per cent of companies have experienced at least one unplanned outage over the past three years (the average being two). These outages lasted an average of four hours.
● Unplanned downtime is expensive: Based on Aberdeen’s calculations, downtime costs $260,000 an hour across all businesses – two episodes of downtime lasting four hours each equates to more than $2 million.
● Awareness is low: More than 65 per cent of companies lack full awareness of when their equipment is due for maintenance, upgrade, or replacement.
The new study, “After The Fall: Cost, Causes and Consequences of Unplanned Downtime,” surveyed 150 field service and IT decision makers in Turkey, Saudi Arabia and the UAE across the manufacturing, medical, oil and gas, energy and utilities, telecoms, distribution, logistics, and transport sectors, among others.
The study finds that production and productivity, IT, and customer service are hit hardest by unplanned downtime, with damaging repercussions for businesses as a whole.
The study further reveals the extent to which businesses are investing in digital tools and field service management solutions:
● More than 8 in 10 companies recognise that digital tools can eliminate unplanned downtime, and zero unplanned downtime is now the number one or high priority for 62 per cent of organizations surveyed.
● 51 per cent of organizations confirm that digital transformation is a high or number one board level priority, and 40 per centreport the same for innovation.
Forty-five percent of respondents say that a digital twin, which is a digital representation of a physical asset, and predictive maintenance analytics would help prevent major failures. Fifty-seven percent say they are planning to invest in a digital twin by 2020. Likewise, field service management is expected to become a primary revenue driver within the next two and a half years, on average.
“As digital solutions have become increasingly prevalent, we’ve seen a widening gap in asset efficiency awareness that’s historically gone largely unnoticed,” said Ali Saleh, SVP and chief commercial officer, GE Digital Middle East, Africa & Turkey.
“Lack of data is unnecessarily lengthening recovery time, but the research hints at a tipping point in recognition of the problem and planned investment to address it. In the same way field service management solutions moved from being reactive to proactive to preventative, we are seeing a similar shift in attitudes to unplanned downtime from recovery to protection to pre-emptive. Over time, zero unplanned downtime will become the norm as companies develop and invest in their industrial digital strategies.”
Despite market changes, including some to the benefit of heavy oil processing in recent years, challenges still remain for investing in new heavy oil processing capacity in North America, says a new study by IHS Markit.
Entitled A New Look: Extracting Value from the Canadian Oil Sands, the Oil Sands Dialogue report presents a post-oil price collapse update to a 2013 analysis on the economics of processing heavy oil in Alberta and other select jurisdictions. The oil market has experienced major past and potential pending changes, most notably cost deflation since the 2014 oil price collapse and a pending shift in marine fuel specifications that has the potential to improve the economics of processing heavy oil. The IHS Markit report says that despite these changes, the abundance of light, tight oil continues to challenge investments in heavy oil processing in Western Canada.
The report concludes that, with growth expected to continue (albeit at a slower pace), the preferred option may continue to be exporting bitumen, rather than investing in heavy oil processing.
The study examines three investment options to process heavy oil—upgraders, refinery conversions and constructing entirely new refineries:
Under the first option, upgrading facilities convert oil sands bitumen into light, synthetic crude oil (known as SCO) that competes for refinery space with light sweet crude from growing U.S. tight oil supply. The other two options—refinery conversions and new refineries—involve either adapting an existing refinery to process heavier crude oil or building an entirely new heavy oil refinery.
“Public interest remains for heavy oil refining and processing capacity in Western Canada. Though the economic outlook has improved, upgrading continues to look challenged. New refineries could work under the right circumstances, but are not without risk,” said Kevin Birn, an IHS Markit executive director who heads the Oil Sands Dialogue.
The prospects for upgrading facilities remain the most challenged, the study says. The other two options—refinery conversions and new refineries—have benefited from recent and anticipated changes in the oil market, which could improve the return in heavy oil processing. Of those two options, refinery conversions remain the most attractive—by far—due to lower capital cost. Yet the abundance of so much light, tight oil will also weigh on any new significant investment in heavy oil processing in North America, the study says.
“In order to convert a refinery you need a suitable facility available to be converted, as well as a cost advantage source of heavy crude supply,” Birn said. “The economics for refinery conversions are the most favorable of the three options reviewed in our study. But the abundance of light, tight oil diminishes the incentive for facilities to make that switch.”
Adding to the challenge, refined product demand in North America is expected to gradually decline. Any new investments in refining capacity in western Canada would likely have to displace incumbents or, more likely, be exported offshore. Finding a party willing to commit to a mutually-agreeable, long-term contract—likely a necessity for obtaining financing for a new export-oriented refining project—may be a stumbling block, the study says.
“The most attractive option for growing oil sands production continues to look like the export of heavy sour bitumen blends to U.S. Gulf Coast region which imported over 1.8 million b/d of crude oil of similar quality to the oil sands from offshore places like Venezuela, Mexico and others in 2016,” said Patrick Smith, the study’s co-author and research associate at IHS Markit. “But present conditions have oil sands producers searching for new options as well. A key area of interest is what is being call partial upgrading which seeks to improve the mobility of bitumen—reducing the need for diluent used in the creation of bitumen blends—a significant cost for the industry today.”
By: Arash Dara, Middle East Lead, Accenture Trading Investments Optimization Strategy (ATIOS) Group
The oil market will continue to be an uncertain and increasingly challenging environment for both corporate and government players to navigate. Whilst China imported 8.55 million barrels per day in the first half 2017, up 13.8 per cent from the same period in 2016, making it the world’s biggest crude importer (EIA STEO Repot), and despite the extension of the production cuts agreement by OPEC and non-OPEC exporters in a bid to boost the price, the market is having difficultly picking up.
According to the IEA, the market could stay oversupplied for longer than expected due to rising production and limited output cuts by some OPEC members, notably Libya and Nigeria, who were exempt from the production cuts.
Compounded with resurgent US shale operations, the global fuel glut is taking longer than anticipated for exporters. Oil inventories in industrialised nations remain substantial. OECD stocks are 170 million barrels above the five-year average. Analyst expectations believe the price environment will not significantly improve, continuing to apply pressure and squeeze margins on many upstream focused NOCs.
The macro-environment is out of their hands, but what they can control is their operations. As stewards of national resources, NOCs need to harness the maximum potential of the hydrocarbons they have access to. At the same time, they must look beyond those resources to remain competitive, improve margins and reduce costs. To succeed in this new world of lower for longer, NOCs will need to be both agile and adaptable, connected and collaborative. This means reshaping their companies across four dimensions:
NOCs need to utilise enhanced digital technologies to help them manage through the low oil price environment. An example of this is advanced analytics, which are enabling upstream oil and gas companies to reduce costs, better manage operations and mitigate risks. In a recent Accenture O&G survey, Analytics was identified as one of the largest opportunity areas where digital can help transform oil and gas companies, yet most respondents felt their company did not have sufficiently mature analytics capabilities to realise the full value.
International assets, if any, to pursue
NOCs could also look to international assets for economic reasons, that is, if the NOC has an undisputed production advantage that makes the return on international assets exceed whatever handicap the NOC faces at home. If NOCs have the liquidity and foresight, the purchase of international assets that others may be looking to sell as noncore properties to generate cash, or the acquisition of distressed competitors that have strategic value, could pay off in the long run in this buyers’ market.
Saudi Aramco has been diversifying their portfolio for years and continue to do in the lower oil price environment. Aramco recently invested US$7 billion into a Petronas oil refinery and petrochemical project in Malaysia’s southern state of Johor, and has signed US$50 billion worth of deals with U.S. companies during U.S. President Donald Trump’s visit to Saudi Arabia.
Diversification from upstream further into the oil and gas value chain
NOCs have a far greater exposure to the upstream business than IOCs, which leaves them more vulnerable during commodity price down cycles. In the latest downturn, refining and midstream businesses posted healthy margins. Most NOCs currently don’t take advantage of this opportunity as much as the majors. A balanced portfolio provides stability and helps mitigate risk in a volatile price environment.
Abu Dhabi is balancing growth and cashflow. It is more than tripling its domestic petrochemical output by 2025 and ADNOC have recently been turning their attention to the issue, stating better infrastructure requirements to link producer to end user. They’ve also signed an exclusive agreement with Penthol, a global organisation in the supply and distribution of oil products and petrochemicals, to be the exclusive seller of ADNOC’s Group III base oil in US.
Potential participation in the new energy system
With alternative energy types and business models poised to assume a greater role in the overall energy sector, NOCs will need to at least consider the question of whether they should play beyond hydrocarbons. The shift may also be driven by national policies focused on reducing the host country’s carbon emissions, but a move from black to green will also offer opportunities to build on a growing market, and provide a long-term buffer for the slowing demand for oil.
Saudi Aramco is also making great strides in this area, currently mulling roughly $5 billion in renewable energy investments and has recently signed partnerships with ADNOC and Masdar to collaborate on sustainable development and renewable energy to yield advancements in clean electricity generation and carbon management. Some NOCs may feel powerless to the price of oil and its impact on profitably, but they have an opportunity to take control of their operations, and push through innovative technologies and processes, increasing profit margins in this uncertain environment and positioning them at ever greater advantages for upturns.