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.
By: Mustafa Ansari, analyst, energy research at APICORP
An economic slowdown coupled with energy reforms has adversely affected domestic fuel consumption growth across most of the GCC, and in some cases even led to negative growth. While a similar trend could be observed in most countries in the region, it was especially pronounced in Saudi Arabia. The region’s largest fuel consumer saw a 10 per cent decrease in demand for diesel in 2016, while gasoline demand flat lined. The UAE is the only GCC country where demand for both gasoline and diesel increased in the same period in the wake of the energy liberalisation plans implemented in August 2015.
Ever since January 2015, oil prices have teetered around the US$50 mark, placing huge fiscal pressures on net oil-exporting countries. Declining GDP growth rates and reduced government revenues led many countries in the region to initiate energy reforms and cut subsidies. While the new prices were still low by international standards, the reforms represented a fundamental shift in economic and social policies. The resulting effects of higher domestic energy prices and lower economic growth have in turn driven domestic demand for petroleum products down.
This development means that net energy exporters have benefitted from higher export volumes than they would have otherwise, slightly offsetting the lower revenues.
But oil prices have failed to recover, despite a collective agreement from OPEC in November 2016 to cut output. In the 16 years since the turn of the century, the MENA region added more than 4.8 million barrels per day (bpd) to global oil demand, second only to China’s 7.9m bpd and ahead of Africa, Latin America and the rest of Asia (excluding China). But demand will likely slow down further as countries in the region continue to undergo energy reforms.
Slowing GCC demand sends mixed signals
Rapidly growing demand for petroleum products has long been typical for the GCC countries. High population growth, robust economic performance until recently, and low fuel prices led to rising demand for gasoline and diesel in the transportation sector, and in the case of Saudi Arabia and Kuwait, rising demand for liquids in the power sector.
Governments therefore prioritised the expansion of the downstream sector, adding 1.2 million bpd of refining capacity in the last five years, with diesel representing more than half the additions and 350,000 bpd of gasoline. In early 2016, the GCC introduced energy price reforms that led to a hike in domestic prices, including gasoline and diesel. Whilst prices remained relatively low by global standards, the region began to experience a slowdown in demand growth and in some cases negative growth.
Annual gasoline demand growth averaged 6.2 per cent between 2010 and 2015 but shrunk to 0.4 per cent in 2016. The change in diesel demand was even more significant, going from an average of 4 per cent growth between 2010 and 2015 to a 6 per cent decline in 2016. Beyond the impact of the reform, the slowdown in economic activity also contributed to lower demand growth, and as these economies recover, some of this demand growth will gradually return.
UAE demand least affected
Despite its strong fiscal position, the UAE was one of the first countries in the GCC to liberalise its gasoline and diesel prices back in August 2015. The government still sets the domestic fuel prices on a monthly basis, but these are directly linked to international prices. The UAE has introduced electricity reforms, but the impact on the country’s nationals has been limited (especially in Abu Dhabi) with non-UAE nationals bearing the brunt of the reform. Subsidies for natural gas, which account for the bulk of the UAE’s subsidies, remain in place.
Amongst its GCC peers, the UAE was the only country where demand for both gasoline and diesel increased in 2016 compared with the year before (plus 20 per cent and 40 per cent, respectively). The trend in gasoline demand since 2010 has been upwards, having increased each year with the exception of 2014 when it slipped from 70,000 bpd to 63,000 bpd. Meanwhile, demand for diesel had been shrinking marginally from 85,000 bpd in 2010 to 71,000 bpd in 2015. But a significant increase to 99,000 bpd could be observed in
2016, when domestic retail prices dropped further in line with international prices. Liberalising prices in the UAE has received wide media attention. With the continued slump in oil prices, the initial impact on gasoline was negligible as prices were already close to international levels. But gasoline prices soon went from an average of $0.48 in 2015 to as low as $0.36 in March 2016, as international prices dipped below $30 per barrel in the beginning of 2016. For diesel, however, the situation is different: a prolonged trend of price cuts continued into 2016, with prices dropping to their lowest level in July. This contributed to an increase in demand for both products. Average demand for gasoline in 2015 jumped up from 69,000 bpd in the first half of the year to 108,000 bpd in the second half. Similarly, average demand for diesel increased from 69,000 bpd to 74,000 bpd over the same timeline. Although prices have fluctuated this year, they have remained on a relatively low level. Notably, there did not seem to be a correlation between monthly prices and demand, but an upside trend in demand could be noticed throughout the year.
VAT set to exert downward pressure on demand
Energy consumption is certainly important for growth. For decades, the provision of cheap energy has been a main pillar of GCC development strategy aimed at achieving key economic, social and political objectives. Low energy prices have enabled the GCC to achieve some of these objectives. Earlier in the year, the UAE announced that a 5 per cent value added tax (VAT) will be implemented from January 2018 as part of their efforts to diversify revenues. Whilst the tax will be exempt on products such as social services, health and education, it will be imposed on general household goods including electronics, entertainment, new vehicles and transportation fuel. In most countries, businesses can claim back VAT on commercial vehicles, but at this stage the rate in the UAE for both individual and commercial vehicles will be the same.
Although the tax is low by international standards, it will nevertheless increase domestic prices and will likely place downward pressure on demand. Certainly, for the oil industry, a slowdown in fuel consumption may lead to lower output levels, lower utilisation rates, lower demand for skilled labour and higher costs. Rapid demand growth in the past meant that the level of investment required to keep pace became unsustainable. But on the upside, lower consumption will free up more products for exports. In 2014 the UAE added 417,000 bpd of refining capacity with the start-up of Ruwais where it substantially affected trade balances, turning the country into a net exporter of both gasoline and fuel oil and substantially raising diesel exports.
With the ramp-up of the Ruwais refinery in 2015 and an additional 70,000 bpd of refining capacity expected in the next five years from the Jebel Ali condensate splitter expansion, the UAE could further benefit from higher export revenues.
What’s next for the GCC?
In its July update, the IMF predicted a considerable slowdown in growth, especially if oil prices remain low. MENA GDP growth is expected to average 2.7 per cent this year and to recover modestly to 3.3 per cent by 2020. Oil prices might remain lower over the long term, meaning that further policy reforms will be necessary to alleviate fiscal pressures. But there is a bright spot amidst the gloom. Energy consumption growth is clearly slowing down in most countries in response to energy subsidy cuts, which will help regional governments save millions whilst also freeing up more products for exports.
The UAE are well placed to take the lead in this new opportunity. Rapid demand growth in the past meant that the level of investment required to keep pace became unsustainable. Lower domestic demand levels will ensure that the region can maintain its position as a leading energy exporter, whilst simultaneously working towards economic diversification to reduce dependence on export revenues. In the absence of economic recovery, demand growth for transportation fuel products could decline further.
Whilst gasoline demand has not dropped significantly, not least due to fuel switching from premium to regular grades, governments need to invest more in public transport to reduce reliance on transportation fuel. Still, with a global oversupply of products, the GCC countries are challenged to ensure that they remain competitive. But, as the regional economies enter the recovery phase, we are set to see some of this demand growth gradually return.
Digital technologies are set to transform the global energy system in coming decades, making it more connected, reliable and sustainable. This will have a profound and lasting impact on both energy demand and supply, according to a new report by the International Energy Agency, Digitalization & Energy.
In this first comprehensive report on the interplay between digitalisation and energy, the IEA analyses how digitalisation is transforming energy systems. From the rise of connected devices at home, to automated industrial production processes and smart mobility, digital technologies are increasingly changing how, where and when energy is consumed.
More than 1 billion households and 11 billion smart appliances could participate in interconnected electricity systems by 2040, thanks to smart meters and connected devices, the report said. This would allow homes to alter when and how much they draw electricity from the grid. Demand-side responses - in building, industry and transport - could provide 185 GW of flexibility, and avoid US$ 270 billion of investment in new electricity infrastructure.
With the help of smart thermostats, the IEA report finds that smart lighting and other digital tools, buildings could reduce their energy use by 10 per cent by using real-time data to improve operational efficiency. Meanwhile, massive amounts of data, ubiquitous connectivity, and rapid progress in Artificial Intelligence and machine learning are enabling new applications and business models across the energy system, from autonomous cars and shared mobility to 3D printing and connected appliances.
The same transformation is taking place in how energy is produced - from smart oil fields to interconnected grids, and increasingly, renewable power. Digital technologies could help integrate higher shares of variable renewables into the grid by better matching energy demand to solar and wind supplies. Energy supply sectors also stand to gain from greater productivity and efficiency, as well as improved safety for workers.
"Digitalisation is blurring the lines between supply and demand," said IEA executive director Dr Fatih Birol. "The electricity sector and smart grids are at the centre of this transformation, but ultimately all sectors across both energy supply and demand - households, transport and industry - will be affected."
In parallel with these opportunities, digitalisation is raising new security and privacy risks, as well as disrupting markets, businesses and employment. While the growth of the "Internet of Things" could herald significant benefits in terms of energy efficiency to households and industries, it also increases the range of energy targets for cyber-attacks. Such attacks have had limited impact so far, but they are also becoming cheaper and easier to organise.
To help understand and deal with this fast-evolving landscape, the report concludes with 10 no-regret policy recommendations, as sound policy and market design will be critical in steering a digitally enhanced energy system along a more efficient, secure, accessible and sustainable path.
Energy suppliers will reap greater productivity and improve safety
Digitalisation can improve safety, increase productivity and reduce costs in oil and gas, coal and power. The magnitude of these potential impacts – and associated barriers – varies greatly depending on the particular application, the report said.
Oil and gas
The oil and gas sector has a relatively long history with digital technologies, notably in upstream, and significant potential remains for digitalisation to enhance operations. Further digitalisation in the upstream oil and gas industry in the future is likely to initially focus on expanding and refining the range of existing digital applications already in use, IEA said in its report.
For example, miniaturised sensors and fibre optic sensors in the production system could be used to boost production or increase the overall recovery of oil and gas from a reservoir. Other examples are the use of automated drilling rigs and robots to inspect and repair subsea infrastructure and to monitor transmission pipelines and tanks. Drones could also be used to inspect pipelines (which are often spread over extended areas) and hard-to-reach equipment such as flare stacks and remote, unmanned offshore facilities.
In the longer term, the potential exists to improve the analysis and processing speed of data, such as the large, unstructured datasets generated by seismic studies. The oil and gas industry will furthermore see more wearables, robotics, and the application of artificial intelligence in their operations.
Widespread use of digital technologies could decrease production costs between 10 per cent and 20 per cent, including through advanced processing of seismic data, the use of sensors, and enhanced reservoir modelling. Technically recoverable oil and gas resources could be boosted by around 5 per cent globally, with the greatest gains expected in shale gas.
Wood Mackenzie: Libya hits production landmark but political divisions overshadow outlook
In August 2016, blockades of key export terminals and pipelines saw production fall below 300,000 barrels per day (bpd). Output has since rebounded. Credit is due to NOC and its indefatigable boss, Mustafa Sanalla. The company has been integral to the country’s production recovery, resisting demands by militia and tribes and methodically calling out how much "spoilers" have cost the country. Campaigns to keep oil flowing have reduced and shortened the length of disruptions, and attempts by the eastern House of Representatives (HOR) administration to market crude independently have receded. NOC remains one of the last functioning institutions of the state, able to act independently of Libya's competing administrations with the goal of depoliticising oil restoring output.
Other events, including repairs to infrastructure damaged by insurgents, field restarts and blockades on major pipelines being lifted, all contributed to growing production.
But doubts remain that these increases can be sustained. Fighting and blockades continue to cause output to fluctuate, and Libya's myriad of tribes and militias continue to target infrastructure as a means to leverage their demands. NOC previously announced that it had hoped to reach 1.25 million bpd by the end of this year, ramping up to 1.5 million bpd by the end of 2018. This now looks ambitious, even by NOC's own admission.
In the near term, we consider that Libya may now be approaching its production limits. There are a number of reasons for this. Export ports are key to incremental growth. Crucially, capacity at As Sidrah, the country’s largest port, was reduced by rocket attacks in 2016. Reinstating Sidrah's capacity to its pre-war level of 450,000 bpd will take several years. It is uncertain how much of this capacity has been destroyed, but we estimate it to be operating at less than 100,000 bpd. Effective export capacity is thus estimated to be restricted to around 1.25 million bpd.
Realising available capacity will require remedial efforts upstream. Near- to medium-term incremental gains will be more modest, as the easiest gains have been made. In the east, in particular, greater investment will be required to address years of under-investment in ageing facilities and leaky pipelines.
Looting and sabotage have also taken a toll: up to 100,000 bpd of production is understood to have been lost due to attacks on facilities. Many of these projects, including Mabruk and Ghani, will require complete rebuilds. This will not occur until the security and the investment climate has improved markedly.
IOCs will be reluctant to return capital so long as insecurity and competing administrations persist.
Accessing equipment, already harder with port closures, and undertaking basic maintenance compound the challenge. The exodus of service companies and hefty risk premiums will drive up costs significantly, once companies judge the environment safe enough to resume operations.
The most readily accessible upside barrels may be in the west where El Sharara and Elephant (El Feel) could perhaps yield an additional 100,000 bpd with some investment. Infrastructure in the west is also newer and has not been subject to sabotage.
We do not see Libyan production returning to pre-war levels until well into next decade and think that, without IOC involvement, maintaining and realising modest gains on a baseline of 1 million bpd could be considered a success in itself.
Conversely, greater downside exists. Production remains highly susceptible to disruptions. A deteriorating political situation or further shut-ins of key infrastructure could limit production to offshore fields and NOC fields in the east which have remained consistent throughout.
For investors seeking steady barrels and predictable cash flows, Libya has long since lost its lustre. North American companies have demonstrated less risk tolerance than their peers. We consider further divestments from companies holding mature, non-core positions plausible. European incumbents and Asian NOCs looking for long-term barrels are the likely buyers, but would-be sellers may wait for greater stability to capture price upside, rather than selling at a discount.
For others, Libya still holds appeal. Billion-barrel brownfield developments, lifting costs below $5 per barrel and proximity to European markets make the conflict worth sitting out. European IOCs have come to view the risks as manageable; whilst a reticence to invest will continue, some are beginning to return gradually. Volumes present a large upside and, when oil flows, cash flow is good. Prolonged stability could yet see operators in the west, where an outlet for production upside exists, and recommence development drilling in 2018.
The return of Libyan oil to the market has come as other OPEC and non-OPEC parties have agreed to extend production cuts in a bid to boost oil prices. Libya was exempt from recent OPEC accords as it struggled to rebuild production lost due to internal fighting and instability. How long OPEC continues to exempt Libya from quotas will ultimately depend on how the political situation unfolds.
While gas markets are currently well supplied, the transformation of natural gas markets from regional systems to more globalised and interdependent markets is creating new security challenges, according to the International Energy Agency's latest assessment of global gas security.
The IEA's second Global Gas Security Review looked at recent gas balancing issues and risks with related policy developments linked to security of supply - including the stressed situations in natural gas and power markets experienced by several southern Europe countries in the winter of 2016-2017; the diplomatic tensions in the Gulf; and the supply risks posed by recent hurricanes on the United States energy system.
The report details how importing countries in mature and well-interconnected markets can still experience unexpected shocks that put strong pressure on the market. Even in the current low-price environment, suppliers are still exposed to low-probability but high-impact events that could have potentially serious consequences for global gas supplies.
"As recent events demonstrated, the security of natural gas supplies cannot be taken for granted even with the current low price environment and oversupplied market," said Dr Fatih Birol, the IEA's executive director. "From cold spells in southern Europe, to hurricanes in the Gulf of Mexico, to diplomatic tensions among Gulf countries, energy security is impossible to ignore."
This year's edition updates these metrics and shows a continuing improvement in supply availability and contractual flexibility, which are expected to grow in the near future, along with diversification of market participants.
LNG contract flexibility appears as an important determinant of the resiliency of the global gas system. The report's updated analysis of new signed contracts shows clear evidence of contractual structures becoming less rigid, a trend evidenced by the growing share of flexible destination contracts, as well as the decrease in contracts' average duration.
The report also looks at how contract flexibility will develop over the next five years. Looking forward, the pool of legacy export contracts with fixed destination and long duration can be expected to shrink as these expire, and be replaced by more flexible contracts. The development of US exports emerges as a major source of additional contractual flexibility. Global portfolio players would play an increasing role and provide additional flexibility from their currently open selling positions.
To improve the risk assessment of importing countries, the report also introduces a new typology of LNG buyers as a tool to measure market exposure, and related security of supply issues. This typology also suggests a way to measure future LNG market evolution.
Converging oil price expectations of investors and companies in the oil and gas sector creates a strong platform for M&A deals to flourish, according to A.T. Kearney’s 2017 Oil and Gas M&A study. The report reveals a sharp pick-up in deals announced at the end of last year, although 45 percent of the US$850 billion worth of transactions declared since January 2016 is still pending.
“The oil and gas industry has a tremendous opportunity to benefit from stabilising oil prices that can fuel deal activity in order to improve balance sheets, and raise cash for capital projects through divestitures,” said Brent Ross, principal, A.T. Kearney and co-author of the study. “In addition, many buyers need acquisitions to replenish reserves that dwindled during the challenging environment of the past two years.”
The study identified strong optimism for the year ahead, with more than two-thirds of the executives surveyed expecting M&A to rise moderately or even aggressively in the year ahead.
“In the Middle East, we expect to see an increase in M&A and partnerships in the Oil & Gas industry. National oil companies in the Gulf will continue to seek access to the key technologies and capabilities that they need to expand their domestic business and to create more value. In parallel, they will continue to explore partnership opportunities to secure access for their crude and fuel products in international markets, while capturing a larger share of the profit pool,” said Ada Perniceni, partner, A.T. Kearney and co-author of the study.
Across the world, improved market conditions have sparked several megadeals since 2016, including Sunoco’s $50 billion purchase of Energy Transfer Partners, the US$43 billion merger of Enbridge and Spectra Energy, and a $32 billion deal that combined GE’s oil and gas operation with Baker Hughes.
With signs that investment prospects are improving, the study indicates that financial investors will be more active in 2017 and are open to new deal structures. With oil prices holding steady and industry sentiment improving, investors are moving to capture acreage, secure midstream assets with reliable returns, and capitalize on opportunities in oil services.
“Long-term uncertainty as a result of energy transition, concerns of peak oil demand, and digital trends, means companies are also pursuing strategic transactions in alternative energy and new capabilities centred around digitalization to be better placed in a changing energy value chain,” said Richard Forrest, A.T. Kearney global lead partner for the Energy Practice and co-author of the study.
The fog is lifting on the oil and gas M&A landscape, but the horizon remains hazy. Companies need to retain a strong focus on cost control and leverage digitalization to improve the efficiency and effectiveness of operations and capital deployment. They will also need to prepare an uncertain future with a shift of strategies to reflect accelerating energy transition and the impact of new disruptive technologies. Mergers and acquisitions will be an important lever for oil and gas companies, both in the short and long term, to remain successful.
A new report by Wood Mackenzie, Non-OPEC Decline Rates: Lower for Longer, looks at the factors influencing this stability, how long it can be maintained and the impact future shifting decline rates may have on the oil market.
Through operational excellence programmes and smart spending, operators have managed to maximise production and improve efficiencies, bucking expectations of an increase in decline rates. In fact, non-OPEC decline rates have remained stable since 2015.
Dr Patrick Gibson, research director, Global Oil Supply, at Wood Mackenzie, said: “Decline rates are a critical factor influencing the current rebalancing of the oil market and price recovery. A 50 per cent cut in investment in non-OPEC producing oilfields and a dwindling pipeline of new projects since the price crash should have led to progressively steeper decline rates. Nonetheless, decline rates have held steady at around 5 per cent since 2015 and we expect they will remain at this level until 2020.”
Wood Mackenzie's analysis shows that, annual decline rates for conventional fields peaked at nearly 7 per cent during the last decade, or 2.4 million bpd a year. However in 2014, they reached an historical low of just 3.6 per cent, or 1.2 million bpd. The price collapse saw decline rates increase to 5.1 per cent, or 1.9 million bpd in 2015, on the back of steep spending cuts. Decline rates have stayed at around that level since.
"Stable rates of non-OPEC decline is a disappointing story for those looking for significant price support coming from declining conventional production," Dr Gibson said.
He said improved operating efficiency and focused capital expenditure (capex) have helped maintain decline rates at current levels. Operators have maximised production rates by focusing on the best-performing wells, as well as targeting processes and maintenance programmes so uptime is increased.
"Careful budgeting is also in play," Dr Gibson added. "Slashed capex now predominantly targets short-cycle opportunities with high returns potential, while development plans and service-sector cost cuts have bolstered spending efficiency."
While some shorter-term measures may relax, longer-term factors, such as increased production from 'zero decline' assets and early-life assets, will help keep decline rates steady. Wood Mackenzie's analysis shows early-life assets increasing their proportion of production from 6 per cent in 2010 to 30 per cent by 2020. The lower decline rates of these assets counter-acts the higher declines of more mature assets.
Dr Gibson said: "Canada's oil sands and Brazil's deepwater pre-salt play are adding a growing proportion of production, significant enough to offset global decline rates. The oil sands alone could reduce decline rates by as much as 0.6 per cent in 2020."
Technology will also play a role in maintaining stable decline rates, as evidenced by developments in horizontal drilling, hydraulic fracturing, enhanced oil recovery techniques and CO2 flooding in the US, Canada, and Russia.
Beyond 2020, Wood Mackenzie expects decline rates will return to the historical norm of around 6 per cent, and higher oil prices will be needed to incentivise investment in new production to meet a widening supply gap. Even moderate swings in average annual decline rates are capable of influencing the market; the rate of decline for non-OPEC fields is crucial to the global supply picture. A 1 per cent shift in annual global decline rates would have a significant effect on supply, potentially adding or removing 2 million bpd by 2021.
"Our current modelling shows stable decline rates until 2020, then a widening to 6 per cent in 2021. Although the present picture is one of resilience and smart spending, further gains remain unlikely. With investment so low, the industry is potentially storing up problems for supply that won't become apparent until after the end of the decade."
Gas will become the single biggest source of energy by 2050 even as rapid decarbonisation gives rise to renewables – DNV GL said in its inaugural Energy Transition Outlook.
“The world is approaching a watershed moment as energy demand is set to plateau from 2030, driven by greater efficiency with the wider application of electricity,” DNV said in a report that charts the world’s energy future.
“As a company, we are highly exposed to the radical changes that will come to every part of the energy value chain, and it is critical for our customers and ourselves that we understand the nature and pace of these changes,” said Remi Eriksen, group president and CEO of DNV GL.
“The profound change set out in our report has significant implications for both established and new energy companies. Ultimately, it will be a willingness to innovate and a capability to move at speed that will determine who is able to remain competitive in this dramatically altered energy landscape.”
DNV GL, a quality assurance and risk management company providing independent advisory services to the oil & gas industry, said that historically, energy demand and CO2 emissions have moved broadly in line with GDP and population growth, but that relationship will unravel.
Electrification, particularly with the uptake of renewables, will change the way in which energy is supplied and consumed. While the global economy and world population are set to grow modestly, energy demand will flatten out and CO2 emissions will drop sharply, according to the report.
DNV GL forecasts that renewables and fossil fuels will have an almost equal share of the energy mix by 2050. Wind power and solar photovoltaics (PV) will drive the continued expansion of renewable energy, whilst gas is on course to surpass oil in 2034 as the single biggest energy source. Oil is losing ground as a source of heat and power, and is set to flatten from 2020 through to 2028 and fall significantly from that point as the penetration of electric vehicles gains momentum. Coal use has already peaked.
The global energy transition will occur without a significant increase in overall annual energy expenditure and on a straight comparison, the world’s energy will cost less than 3 per cent of global GDP compared to the current level of 5 per cent, the report said.
Although the oil and gas industry has responded impressively to the present lower price environment, renewables will improve cost performance at a much faster rate, benefitting from the ‘learning curve’ effect. Electric vehicles will achieve cost parity with internal combustion vehicles in 2022 and, by 2033, half of new light vehicle sales globally will be electric.
Despite greater efficiency and reduced reliance on fossil fuels, the Energy Transition Outlook indicates that the planet is set to warm by 2.5˚C, failing to achieve the 2015 Paris Agreement target.
“Even with energy demand flattening and emissions halving, our model still points to a significant overshoot of the 2°C carbon budget. This should be a wake-up call to governments and decision-makers within the energy industry. The industry has taken bold steps before, but now needs to take even bigger strides,” said Eriksen.
The International Maritime Organization (IMO) recently confirmed that global refiners and shippers must comply with new regulations to reduce the sulfur content in marine bunker fuels by January 2020—five years earlier than many expected. As a result, both the global refining and shipping industries will experience rapid change and significant cost and operational impacts, according to new analysis from IHS Markit.
“While the IMO is taking positive action to address the environmental impacts of air pollution from ships, the rapid change creates significant disruption for both the refining and shipping industries,” said Kurt Barrow, vice president of downstream research at IHS Markit. Barrow, along with Sandeep Sayal, senior director of refining and marketing research at IHS Markit, are two authors of an IHS Markit report entitled Refining and Shipping Industries Will Scramble to Meet the 2020 IMO Bunker Fuel Rules.
“The two industries are vastly unprepared,” Sayal said. “Neither has made the necessary investments for compliance, which means that the 2020 implementation date will result in a scramble. Both industries are taking a wait-and-see approach until firm signals are in place by the IMO for compliance with the regulation."
“Shippers will face significant compliance costs by having to upgrade equipment or switch to more expensive fuels,” Barrow said. “Refiners will experience significant price impacts as they shift production to deliver more lower-sulfur fuels to the market and, at the same time, find a market for the higher-sulfur fuels they produce. Refineries, like ships, do not turn on a dime, so it takes significant investment and market demand to retool a refinery to deliver new supply.”
Shippers will have several options to meet the new IMO regulations, IHS Markit said. Low-sulfur bunker fuels (primarily for smaller vessels), and liquefied natural gas (LNG) (primarily for new builds) will be part of the solution. However, IHS Markit researchers expect that on-board ship scrubbers, devices that clear harmful pollutants from exhaust gas, will be the primary compliance path for ships, which could continue to burn higher-sulfur fuels.
“From the shipping industry point of view, IHS Markit estimates that about 20,000 ships account for around 80 percent of heavy fuel-oil bunker fuel use,” said Krispen Atkinson, senior consultant, IHS Markit Maritime & Trade research. “Currently only about 360 ships have installed scrubbers, since there is currently no economic incentive for the ships to add scrubbers. However, based on the price spreads between low-sulfur bunker fuel and high-sulfur fuel oil during the scramble period, it will be economic for many of them to install scrubbers.” The payback period for installing a scrubber on the largest vessels, Atkinson said, would be two-to-four years in 2022-2025, and less than one year based on peak-price spreads in 2020.
A key uncertainty also lies in the actual level of compliance to the IMO regulation in 2020. “Not only is it hard to enforce compliance in the open seas, but it is still uncertain if sufficient supplies of compliant bunker fuels will be broadly available in all ports,” Sayal said.
Overall, the installations of scrubbers and some level of noncompliance will not be in time to halt the disruption on refined products markets, IHS Markit said. According to the IHS Markit report, the primary challenge with the bunker fuel quality change (which requires sulfur content to be reduced from 3.50 percent by weight to 0.5 percent by weight) is the disposal of high-sulfur residual fuel—not the production of low-sulfur bunker fuel.
“When we account for all the supply and demand factors for the sour residual balance, including new conversion projects, capacity creep, scrubber and LNG capacity, as well as quality compliance, our bottom line is that a sizable portion of today’s fuel oil will be pushed into lower-price tiers, notably oil-fired power-generation plants,” Barrow said. “Refining capacity will most likely exist in 2020 to produce the low-sulfur bunker fuel, but higher overall crude runs will be required.”
The largest refinery margin disruption will be significant but fleeting, according to the IHS Markit report, with impacts felt most notably in 2020 and 2021. IHS Markit expects an unprecedented light-heavy price spread during 2020 to 2021. During these years, pricing for high-sulfur fuel oil (HSFO) will have to be near thermal parity with coal to clear into the power market—a very low price relative even to today’s fuel oil price, IHS Markit said.
As ship owners respond to the large-scrubber investment incentives, high-sulfur bunker fuel demand will rebound, although not to prior 2020 levels. Due to increasing demand and addition of debottlenecking capacity for residue conversion, IHS Markit estimates price spreads will moderate within a few years, but the timing of price recovery will be dependent upon a number of variables.
Refiners will produce more distillates (higher-value components derived from crude) as new demand arises for these products during the disrupted years, IHS Markit said. With HSFO priced at coal-thermal parity and demand for middle distillates (kerosene, jet fuel, diesel) increasing to blend to low-sulfur bunker fuel, refining margins will benefit, but in different ways.
“Refiners of sour-crude will be negatively impacted by the nearly valueless sour-crude residue, while refiners of sweet-crude conversion will experience moderately higher margins, but sweet-crude prices will reflect the low-sulfur residue value,” Barrow said. “It is the high-conversion refiners of sour crude that are expected to have extraordinary margins.”
Highly complex refineries will benefit the most from the IMO specification change, IHS Markit said. Highly complex refiners will produce the least amount of residual fuel oil and the highest amount of distillate and gasoline as compared to lower-complexity refiners.
Crude-price relationships, specifically between light-sweet and heavy-sour crude, will widen around the compliance timeframe, IHS Markit said. Assuming the specification change implements as announced on a global and instantaneous basis with no phase-in timing or quality transition allowances, the margin uplift will be acute in the compliance period from 2020 to 2021.
By: Peter Lyall, Eagle Lyon Pope and David Drew, Global Maritime
Despite oil prices remaining in the high US$40’s and a limited pickup in offshore activity worldwide, the Middle East is bucking the trend and seeing an increase in offshore activities around the oil and gas sector.
The Middle East was the only market globally to witness an increase in demand in offshore support vessel (OSV) activity in 2016 with a 2.6 per cent rise, according to industry analysts Petrodata. Furthermore, the region also seems to have been relatively unaffected by offshore drilling activity reductions with jack-up rigs remaining in high demand, according to the Global Jackup Rig Market Report 2016 by industry analysts, Research & Markets.
In addition, commercial shipping activities continue to be on the increase. Abu Dhabi’s Khalifa Port is just one example of a container port within the region that is set to expand, with plans to increase its annual container throughput to 2.5 million twenty foot equivalent units (TEUs).
Whether in the commercial shipping and ports sectors or the offshore oil and gas industry it is now as important as ever to have a consistent and comprehensive approach to marine risk.
As offshore oil and gas and commercial ports and shipping operations continue to grow within the Middle Eastern region, what is required for the successful alleviation of risk in these sectors? Specialist marine consultants, loss adjusters and engineers Eagle Lyon Pope (ELP) and its parent company Global Maritime Consultancy will attempt to address these issues in this article.
A Focus on Ports
Firstly, the focus must be on the ports and terminals themselves in order to ensure that all infrastructure is safe, functionally compliant, and conforms to industry guidance and best practices, whilst also being capable of adapting to future requirements.
Areas to consider in reducing risk in ports include effective port master planning; terminal feasibility studies for new developments; port marine safety audits; the provision of port designated persons; liability risk surveys; mooring and analysis; dredging; constructability support; and pilotage, navigation and ship manoeuvrability assessments.
Port and terminal operators are also required to have in place a contingency plan for marine pollution in order to support the decision making process, thus ensuring an adequate and timely response to such incidents. To this end, ELP can draft and deliver a pollution contingency plan bespoke to the port or terminal requirements.
We are also very conscious that the International Maritime Organisation (IMO)’s International Convention for the Control and Management of Ships’ Ballast Water and Sediments requires all international vessels to be equipped with a system to clean their ballast water before releasing it into the ocean. This prevents the transfer of alien marine species, such as bacteria and microbes.
This is another important pollution issue and it’s positive to see a global response to a global problem where incidents can be seen every day if not acted upon quickly. The IMO’s regulations will ensure standardisation in this area.
A Focus on Shipping
As vessel traffic increases and vessels become larger, safety in navigation and marine operations is of paramount importance. ELP employs an experienced team of master mariners, naval architects and marine engineers providing innovative solutions to highly technical marine issues. Using in-house operational simulation and risk management software disruption, delay, utilisation and risk can be effectively determined and managed.
Recently, ELP’s ports and shipping department conducted fast and realtime vessel simulations for berthing and unberthing Q-Flex LNG carriers at a newly developed floating storage regasification unit (FSRU) terminal within the Middle East.
The project included the facilitation of a full mission ship simulator workshop, which engaged stakeholders such as marine pilots from the region, ship’s masters, vessel operators, charterers and terminal operators.
Marine Casualty Investigation, Claims & Litigation
Marine accidents and incidents can potentially have catastrophic consequences, which inevitably result in insurance claims and potential litigation.
With this in mind, ELP’s team of marine master mariners, naval architects, marine engineers and insurance professionals can provide a global response service in investigating the cause, nature and extent of damage due to marine collisions, groundings, pollution and other incidents.
As vessels become more sophisticated, analysis of Automatic Identification System (AIS) and Voyage Event Recorder data is also becoming one of the key areas in which ELP can provide assistance to maritime lawyers and insurers.
ELP also provides loss adjusting services covering energy and marine claims, through to cargo claims, damage to ports, terminals, handling equipment, stevedore’s liability losses, personal injury and onshore work that includes power and utility losses, construction and business interruption.
ELP also carries out risk engineering for a variety of insurers and other clients in the Middle East and globally, providing underwriters with the information they need to assess the magnitude of specific risks.
Marine Warranty Services
Finally, Marine Warranty Surveys (MWS) are also an important means of managing risk for the insured and insurers. Global Maritime has more than 30 years of experience in Marine Warranty Surveying services covering transportation, construction, commissioning and decommissioning projects, assisting underwriters, brokers, oil companies, drilling contractors, offshore contractors and vessel owners.
In another Middle East example, Global Maritime provided MWS for a high-profile offshore concession, which included vessel suitability surveys, third party documentation reviews and the issuing of Certificates of Approval for marine operations and construction activities. As a leading provider of MWS, Global Maritime is constantly re-evaluating the process and procedures to ensure that the expectations of all are met.
Preparing for All Eventualities
As the Middle East offshore oil and gas and shipping markets continue to face risks, it’s vital that they are prepared for all eventualities. A consistent and process driven approach to risk, ports, shipping, marine casualties and loss adjusting is a good start.
Homayoun Falakshahi, senior research analyst for Middle East and North Africa Upstream at Wood Mackenzie speaks to Pipeline Magazine’s Nadia Saleem about Iran’s current oil and gas industry
What is the main incentive for Iran to bring in IOCs to develop its oil and gas resources?
Since the elections which resulted in President Rouhani’s win, solving the nuclear issue was the first mandate in clearing the way for reviving the oil and gas industry which has been suffering. The main incentive to bring international companies is to bring back investment rather than just knowledge. Meanwhile, some fields are hard to develop - like South Pars, so they needed to bring the technology that Iran doesn’t have.
How important are new oil and gas contract terms under Iran Petroleum Contract? The new contract terms are key to determine if Iran is able to bring back investors. Previous contract terms were known to be the world’s harshest - most of the time companies were unable to cover cost of investment under schemes which were more like service contracts.
What projects do you expect to go forward and what timelines do you see for this?
Iran has more than 50 upstream projects - these are only the discovered resources. Exploration hasn’t been a priority because the country has a lot of discovered resources, which go back nearly 50 years. So they have had other opportunities to grow. Additionally, Iran has between 14-18 exploration blocks which are on the do list for tendering. Although this been quoted to happen in two-three months, it’s more likely to be end of the year or even next year. Most of the interest from foreign companies will be on the developed resources - some of which are already producing.
What foreign investment does Iran need right now and what can attract these?
Iran has plans to develop 54 projects, which combined would need $114 billion in the next 20 years. Two-third of this is expected to come from foreign companies – that’s why it’s key for Iran to attract foreign investment. These are all new projects that didn’t exist 20 years ago. The main attraction Iran has is that most of these assets have a cost per barrel of around $15-16, which is low compared to others in the world (shale etc). Brazil is currently around $30-40, while North Sea’s operational cost alone is $20 per barrel. Iran can therefore afford to offer terms that are stricter - but they are being more pragmatic to ensure competition. In order to reach capacity targets, they need to do a lot of investment. We think this will happen over 10 years, not five. Most of the capacity building will be gas focused because of the high reserves (second highest after Russia) Iran has.
What challenges do you see in Iran being able to develop its oil and gas industry?
The first challenge will be international politics and policy of United States on the nuclear deal – so far we have yet to see something change. All the deals between certain dates can be cancelled if the snap-back clause in the sanctions deal is triggered. I would expect companies to play a cautious role although at this time this looks unlikely. Timeline is also a challenge. Iran is more optimistic that us on all the deals that will be signed. I don’t think Iran has the capacity to deal with all 50 projects at one time. It is likely that there will be series of tenders, and then every few months, some projects being awarded due to Iran’s international bureaucracy.