Gas output from the Permian Basin is expected to rebound relatively quickly in the second half of 2020 and will remain robust for years to come, Rystad Energy projects.
However, the low-investment environment created by COVID-19 will likely postpone approvals for important key pipelines which may necessitate increased flaring from 2023 onwards.
In the second half of the year, and into 2021-2023, Rystad Energy expects Permian gas production will see a rapid boost assuming a US$45-$50 WTI environment, which is our base case. In the short-term, the reactivation of curtailments is expected to push basin-wide gas output back to 11.4 billion cubic feet per day (cfd) in September, although further growth might be delayed until mid-2021 when activity is expected to recover substantially.
Regardless, gas output in the Permian is expected to return to record levels by late-2021, reaching 16 billion cfd by the end of 2023. This represents a downward revision of 2 billion cfd compared to our 2023 year-end view prior to the COVID-19 pandemic.
There has been limited news flow on the development of new gas pipelines in recent months, but we remain confident that both the Permian Highway Pipeline (PHP), which originally announced an in-service date of 1Q21, and the Whistler project, which announced an in-service date of 3Q21, are both moving ahead.
Earlier this year, Kinder Morgan faced some regulatory obstacles which have delayed the originally planned in-service date for the PHP. Additionally, in the current environment, the regional supply-demand balance does not require the immediate completion of the pipeline. Even if modest delays occur, Permian’s dry gas production potential will be able to wait for the pipeline to be completed until late-2021. Meanwhile, the Whistler pipeline has recently received new funding, which confirms that project-related work on the pipeline is occurring.
For other pipelines, however, serious concerns about feasibility remain and many projects have been delayed or put on hold. According to an April announcement the Pecos Trail evaluation is now on hold, and the Permian to Katy (P2K) pipeline also appears to be inactive. Tellurian has continued to advertise its future global gas market hub around Driftwood LNG, the Permian Global Access pipeline, but the likelihood of any investment decisions in the short-term remains low from our perspective.
On paper, the nameplate outbound capacity of all takeaway pipelines with local consumption (assuming the completion of the Whistler and PHP) will reach 17.5 billion cfd in 2022, enough to accommodate the increasing gas production in the basin through the mid-2020s. However, the future of utilization rates on the Permian-Mexico pipelines (Roadrunner, Comanche Trail and Trans-Pecos) remains uncertain.
While the Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline was finally completed and started service in June 2020, providing better connectivity between northern Mexico and Guadalajara, it might take several quarters (if not years) to see a significant increase in West Texas-Mexico gas exports, relative to the total capacity of outbound pipelines.
In May 2019 through April 2020, West Texas-Mexico gas exports fluctuated in the very narrow range of 0.58 billion to 0.67 billion cfd. The Trans-Pecos pipeline, specifically, flowed at around 170 million cfd in the first four months of 2020; only in the last few days have we recorded a jump in daily flows towards El Encino, with throughput surpassing 300 million cfd.
In the most optimistic scenario, we consider an increase in West Texas-Mexico exports to 1.5 billion cfd throughout 2H20-2021. However, in our lower case, exports remain flat at 0.7 billion cfd. Finally, in 2H19-1Q20 we frequently observed that pipelines flowed at rates exceeding nameplate capacity by up to 10 per cent. This is considered to be unsustainable in the long-term.
“Regardless of the state of West Texas-Mexico exports, we conclude that in a $45-$50 WTI world, there will be a need for new gas takeaway projects from the Permian as early as 2023-2024. If these projects are not approved early enough, the basin might end up with another period of degradation in local differentials and potentially increased gas flaring,” says Rystad Energy’s Head of Shale Research, Artem Abramov.
Given the conservative investment philosophy of midstream companies and the WTI strip remaining around $40 for the year, it is highly possible that any new pipelines will be approved too late, resulting again in a situation with insufficient infrastructure.
According to a new report by Wood Mackenzie, oil products demand in Asia Pacific is expected to fall by 1.8 million bpd year-on-year in 2020. But oil demand growth in Asia has still a long way to run. By 2040, the region’s oil demand is expected to rise by 25 per cent (9 million bpd) to 44.8 million bpd compared to 2019.
COVID-19 and a pessimistic economic outlook will have a near-term impact on oil demand and the refining sector in Asia Pacific. But in the long-run, demand continues to be robust driven by a future demand for mobility and petrochemicals. The region will account for over half of global oil demand growth by 2040.
Wood Mackenzie research director Sushant Gupta said: “Although demand continues to grow, the rate of growth in the next 20 years is less than half that of the past 20 years, primarily because of higher fuel efficiency, penetration of electric vehicles and displacement of oil in the transport sector.
“Oil demand growth is also increasingly reliant on petrochemical feedstocks, which could grow by over 5 million b/d from 2019 to 2040. China accounts for the bulk of this growth, because of an expansion in steam cracking and growth in propane dehydrogenation (PDH) and aromatics production capacities.
“So, the big challenge for refiners in Asia is to meet the growing deficit in petrochemical feedstocks. This year we will see close to 3 million b/d of feedstock shortage, but by 2027 this deficit could grow to 3.8 million b/d. Middle-East, which is a traditional exporter of petrochemical feedstocks to Asia, will not be able to meet the shortages in Asia fully, and we expect a growing reliance on imports from long-haul markets such as US and Europe.”
With a growing shortage of petrochemical feedstock and a growing demand for gasoline, Asia could also see a structural shortage of gasoline in the long run. Gasoline demand rises by close to 2 million bpd between 2019 and 2040. Unless additional refinery capacity and appropriate refinery configurations are built to focus on light-products, both petrochemical feedstocks and gasoline will continue to be short.
In contrast, as diesel/gasoil demand growth in China slows down, the region is expected to see a large surplus of diesel/gasoil, reaching 1.5 million bpd by 2027.
Gupta added: “Asia faces a dual challenge of meeting its shortages of light-products and finding export markets for its surplus middle-distillates. This imbalance means refiners need to rethink on their export markets, future refinery capacity and configurations, and the future types of petrochemical feedstocks.
“Overall, Asia’s product balances are opposite to Europe – light-distillate importer and middle-distillate exporter - so there is a natural synergy, with the challenge being their geographical separation. But, deficits in Asia present opportunities for West to East trade to grow further and meet part of Asia’s growing demand.”
To align with a shift towards petrochemicals, many refiners in Asia are moving towards a deeper integration with chemicals. Gupta added that a successful integrated site should find an optimal zone where the site is competitive for feedstock generation and for converting feedstock into chemicals.
In the long run, Asia Pacific needs more refining capacity to meet demand, but the required rate of capacity additions is expected to be half that of the past 20 years. Wood Mackenzie expects refining margins to recover in the longer term to support refinery capacity investments in Asia, but an over-build in Asia will mean more rationalisation in Europe.
Finally, as the demand growth centres in Asia shift from China to India and Southeast Asia, these regions will be required to take the lead in building new refining capacity.
Hit by the COVID-19 downturn, the oilfield service market is not likely to rebound to last year’s activity level until 2023 according to a Rystad Energy analysis. However, suppliers could diversify some oil and gas capabilities and replace up to 40 per cent of 2019’s revenue by servicing the renewable markets.
Rystad Energy analysed the activity of the top 50 oil and gas suppliers, which together earned $220 billion in upstream revenue in 2019, $100 billion of which originated from well services and commodities.
Many services provided by well-focused suppliers will be challenging to deploy in the context of energy transition operations, especially fracking services, OCTG and drilling services and tools. However, the top contractors providing engineering, procurement, construction and installation (EPCI) services – which earned around $55 billion in 2019 from the oil and gas industry – will find it easier to apply their competencies towards the green shift.
“Around $90 billion, or 40 per cent of the revenue from the top 50 players in the global service market, could potentially be replaced by energy transition projects, such as clean energy infrastructure and renewable energy production development services. However, the supply chain industry must also look to avenues outside of the energy transition to stay afloat,” says Rystad Energy’s Head of Energy Services Research Audun Martinsen.
Market opportunities abound
In terms of market opportunities, most traditional oilfield service suppliers are looking to expand into low carbon segments, meaning technologies or services aiming to reduce or prevent emissions from oil and gas extraction and production. This can be done by offering more efficient operations and digital solutions. This is a space where most suppliers, regardless of current exposure in the service market, have a role to play.
Another emerging market within the energy transition is clean energy infrastructure, where suppliers can provide services to support blue and green hydrogen infrastructure, carbon capture and storage, or energy storage in general. This is a market where engineering houses, fabricators and equipment manufacturers will find big opportunities for growth and for synergies.
A third option within the energy transition is to supply the end-to-end development and operations of renewable power generation itself, for example by developing solar power plants, wind parks offshore and onshore, and geothermal energy. The solar energy supply chain is highly fragmented and has become essentially out-of-box, yet the wind market offers great potential for offshore contractors to support the development of offshore wind.
However, the risk and investment required for expanding into other energy markets beyond oil and gas will not be feasible for all oilfield service providers.
In terms of growth opportunities, the clean energy market represents a fast-growing industry. The installed capacity of all utility-scale global renewable energy assets has doubled every fifth year since 2010, and will total 1000 gigawatts (GWAC) in 2020, comprised of 600 GWAC of onshore wind capacity, 284 GWAC of utility PV capacity and 34 GWAC of offshore capacity. By 2025, we expect this number grow by at least 50 per cent to 1500 GWAC, potentially reaching 1800 GWAC of global capacity in our high case.
Due to economies of scale and cost deflation, operator’s investment towards asset development will grow slower than capacity, but still much faster than the oil and gas market. In Europe for instance, investments in offshore wind will exceed offshore oil and gas investment as soon as 2022. Geothermal energy is also getting broader attention in the market, especially in Europe.
Mapping service relevancy
Rystad Energy has mapped out the relevance of existing oilfield service business offerings in the context of emerging energy transition markets. Within the scope of our analysis, we see that those oil and gas segments which will return to 2019 market levels by 2023 are those that are most agile – those that are able to support both the diversification of O&G offerings towards the energy transition, and at the same time, those that will continue to see high growth from traditional O&G operations.
The SURF, and the maintenance, construction and installation segments rise to the top in this regard, emerging as the most nimble service segments.
SURF represents the market for subsea cables and pipelines, and the installation of these mechanisms. As a key segment for the development of deepwater oil and gas operations, particularly the high growth markets of Brazil and Guyana, Rystad Energy believes the SURF segment will be on track to surpass 2019 market levels in 2023. In addition, SURF services will be in demand for both floating and grounded offshore wind – the fastest growing renewable energy segment.
Similarly, the skillset of the maintenance, construction and installation segment is applicable to the emerging energy infrastructure market and to renewable energy production in general. This segment is also expected to win big in as the oil and gas market recovers, as the segment has a major focus on LNG development, which many E&Ps have favoured in recent years.
The energy transition is likely to be more challenging for well-related services, such as rigs and well services, even though geothermal energy – a potential consumer of these services – is gaining momentum around the world. Geothermal projects typically are comprised of two to six wells per project. However, the 1,000 geothermal wells which might be drilled every year going forward will not be sufficient to compensate for falling oil and gas well services demand, which we anticipate will only decline from a high of the 70,000 oil and gas wells drilled last year.
Therefore, the sectors that are, by nature, less agile in shifting towards the green revolution would be wise to focus on reducing emissions by way of digitalisation and by developing automation and emissions control technologies.
By: Vinodkumar Raghothamarao, Director Consulting, Energy Wide Perspectives & Strategy, IHS Markit EMEA
Energy companies operate in dynamic and complex environments, where they face constant challenges especially in terms of supply and demand. Energy companies have been adopting digital technologies for years, helping to increase the recovery of fossil resources, improve production processes, reduce costs and improve safety. Within the offshore energy sector, the need for digitalisation and advanced communication systems is greater given the platforms’ remoteness and isolation, harsh sea conditions, strong and unpredictable winds, water, extreme temperatures, and distance from the shore The energy industry is known to be a heavy user of reliable, secure, and resilient networks for providing seamless communications for their daily operations. Routine operations alone require transmission of an insuperable volume of data and reports on logistics, supply, production etc.
Technology and innovation are at the heart of many of these efforts and in certain “pockets of excellence” are helping to reduce facility costs by 5–15 per cent, lower operating costs by 10–70 per cent, and raise production efficiencies by 5–20 per cent. Now with the oil prices low, the time has come to evaluate, adapt and embrace new technological initiatives. 5G is one of the leading communication technology initiative driving the tectonic shift within the energy industry. To date, mobile technology has progressed from a predominantly people-to-people platform (3G) toward people- to-information connectivity on a global scale (4G). 5G can leverage and extend the research and development (R&D) and capital investments made in prior mobile technologies to advance mobile to a platform that delivers the much-needed ubiquity, low latency, and adaptability required for future uses. 5G will make possible new classes of advanced applications, foster business innovation, and spur economic growth.
5G mobile networks represent the next major phase of mobile telecommunications standards beyond the current 4G Long Term Evolution (LTE) standards. 5G technology will do far more than usher in new service opportunities for mobile network operators (MNOs). Indeed, IHS Markit expects 5G will act as a catalyst that turns mobile into a robust and pervasive platform that fosters the emergence of new business models and transforms industries and economies around the globe.
Initially, 5G deployments are centering on enhanced Mobile Broadband (eMBB) and fixed wireless access applications. eMBB addresses the human-centric use cases for access to multi-media content, services, and data. In addition to eMBB, 5G builds upon earlier investments in Machine to Machine(M2M) and traditional IoT applications to enable significant increases in economies of scale that drive adoption and utilization across all sectors. Improved low-power requirements, the ability to operate in licensed and unlicensed spectrum, and improved coverage will all drive significantly lower costs within the MIoT. This will, in turn, enable the scale of MIoT and will drive much greater uptake of mobile technologies to address MIoT applications such as
Mission Critical Services (MCS) represents a new market opportunity for mobile technology. This significant growth area for 5G will support applications that require high reliability, ultra-low latency connectivity with strong security, and availability. This will allow wireless technology to provide an ultra-reliable connection that is indistinguishable from wireless to support applications such as autonomous vehicles and remote operation of complex automation equipment where failure is not an option.
MCS represents a potentially huge growth area for 5G to support applications that require high reliability, ultra- low latency connectivity with strong security, and availability, including:
5G will drive improvements across the entire oil and gas lifecycle, from upstream developments to refining operations to transportation, to real-time monitoring of assets such as drill rigs and pipelines, to remote operations and surveillance.
For instance, Houston-based Infrastructure Networks has been installing gear and building 5G capabilities as part of an effort to create the first 5G-enabled oil drilling site in the Permian Basin. Big carriers such as Verizon, Sprint, T-Mobile and AT&T are also taking measures to improve oilfield connectivity, deploying 5G to key spots in the Permian Basin and the Gulf of Mexico.
Edge computing technology can be used for remote pumping and distribution sites, connected through 5G networks to a main automation system. This helps with the monitoring and communication of pipelines to identify irregularities and discrepancies in data in real-time. Thus allowing automation control systems to respond immediately to take action against problems. While many of these sites currently have limited forms of connectivity, such as cellular or satellite, this type of infrastructure would need to be updated to handle the data volumes required for 5G.
In addition, 5G has the potential to serve several IoT use cases for the oil and gas industry like asset tracking and monitoring, gas detection and prevention, predictive and preventive maintenance, etc
Utilities can benefit from the MIoT and MCS capabilities of 5G for smart metering and smart grid automation. Currently, smart metering deployments are enabled by a range of different cellular, mesh, and wired technologies. 5G’s ability to support private networks, use licensed and unlicensed spectrum, and radio hopping/mesh renders it a flexible, multi-purpose technology for both greenfield and replacement deployments. Alongside the general economies of scale, the deep coverage and low power characteristics of 5G will enable utilities to benefit from automated meter reading (reducing the need for manual readings or inspector visits), more accurate customer billing, and fraud prevention.
There is an ongoing trend for renewable energy, such as solar or wind, to be integrated onto the grid; however, the fragmented and irregular nature of this supply makes integration complex. 5G, alongside analytics that can identify the optimal time for different sources of energy to come on to the grid (i.e., managing supply and demand), can enable automated real-time grid switching.
Using deep learning and IoT, new predicting and monitoring technologies for the oil and gas industries have emerged that could completely transform them. Being able to predict what’s coming and see beyond what’s currently seen allows companies to deal with potential problems before they happen, saving them time, money, and bad publicity. A future where we’re surrounded by artificial intelligence incorporating deep learning and IoT is imminent. Going forward, the impact of ML and AI has already been realised in the industry. Early adopters are taking advantage with a head-start in the competition to protect their assets. Tightening research and development budgets are prompting oil and gas firms and their suppliers to think differently about both how they source new technologies and where they direct scarce resources. These evolving technology approaches are likely to outlast the current downturn and could lead to real changes in companies’ overall business strategies.
This column first appeared in the July issue of Pipeline Magazine
DNV GL has launched an international industry consortium in collaboration with Dutch glass production expert company Celsian to develop the technology required for a gradual transition from natural gas to hydrogen as a fuel in energy-intensive industrial production processes.
A major challenge for energy-intensive industrial production processes, for example in the glass, food and ceramic sectors, is to make existing heating processes carbon-free. As electrification is often not an option, a fast and sustainable route to reduce the carbon intensity for industrial heating processes is to substitute natural gas by hydrogen.
“Existing burner and burner control technology to decarbonise industrial production processes are not yet market-ready, despite great interest and the advantages of hydrogen as a low carbon fuel in high-temperature industries. Our programme aims to have new burner concepts available within two years,” said Sander Gersen, project leader, DNV GL – Oil & Gas.
The two-year programme is a unique collaboration in the introduction of hydrogen as a fuel for industrial use, aiming to contribute fundamental improvements to existing industrial heating processes to make the gradual transition from natural gas to hydrogen fast and cost-efficiently.
The industry consortium comprises more than 30 private and public partners throughout the hydrogen value chain, including industrial end users, technology suppliers, fuel suppliers and traders, gas transport companies, knowledge institutes and the Dutch government.
“Together with our partners, we are looking at how we can best integrate new technology in industrial processes and hydrogen value chains. At the same time, we are gathering data and practical experience by conducting field demonstrations in various industrial environments. Right now, we are laying the foundation at DNV GL’s laboratories in Groningen. Subsequently, we will prepare for a field demonstration where the new technology is integrated into the industrial production processes of participating companies” said Johan Knijp, country manager DNV GL - O&G Netherlands.
The transition from natural gas to hydrogen
Three important principles must be considered when switching from natural gas to hydrogen. Firstly, it is crucial that product quality is not affected. Therefore, in the first phase of the research strong emphasis is on understanding heat transfer from the hydrogen flame to the product. Secondly, security of supply during the transition is important - in other words, an end-user always wants to be able to switch back (temporarily) to natural gas. Finally, the solution should be relatively easy and cost-effective to integrate into existing installations.
The programme's proposed solution to reduce the carbon intensity of industrial energy consumption builds on the fuel adaptive burner concept recently developed by DNV GL and burner system manufacturer Zantingh. Where a traditional burner is only suitable for 100% natural gas, the fuel transition adaptive burner can handle any mix of natural gas and hydrogen. An installation equipped with this new burner concept is prepared for any change in the natural gas/hydrogen mix that will be offered in the coming years while maintaining safety, reliability and low emissions.
From ambition to reality
Nationally and internationally, there is a lot of attention on hydrogen and its role in the energy transition. Both governments and private companies are investing significantly in this technology. In a recent survey of more than 1,000 senior oil and gas professionals conducted by DNV GL, one in five (21 per cent) of the respondents revealed that their organisation is already actively entering the hydrogen market, and more than half (52 per cent) expect the gas to form a significant part of the energy mix within a decade.
“Hydrogen is in the spotlight while the energy transition is moving at pace - and rightly so. But to realize its potential, both government and industry will have to make bold decisions. The challenge now is not in the ambition, but in changing the timeline: from hydrogen on the horizon to hydrogen in our homes, businesses and transport systems,” said Liv A. Hovem, CEO, DNV GL - Oil & Gas.
"To reach the level where societies and industry can reap the benefits of hydrogen on a large scale, all stakeholders will need to pay immediate attention to demonstrating safety, enabling infrastructure, scaling up technology and stimulating the development of value chains through policy,” Hovem added.
The first field demonstration is planned at Nedmag in Veendam (Netherlands), where magnesium salt is processed using high-temperature processes. Preparations for this test have already started. By the end of 2020, an oil stove at the plant will be to run on hydrogen obtained from the nearby Gasunie Hystock hydrogen production plant in Zuidwending.
COVID-19 has dealt a massive blow to the energy industry, and national energy companies in the Middle East must pursue bold structural cost-reduction measures to mitigate the impacts and emerge stronger from the crisis, according to a new report by Boston Consulting Group (BCG).
The report, titled ‘Procurement post COVID-19: A new reality for national energy companies’ explains how companies must act now to balance near-term supply chain management urgencies and redesign the supply footprint and supply capabilities.
BCG conducted the 2020 National Energy Operator Survey in April and May 2020 to understand the COVID-19 related supply chain challenges encountered by these companies. According to BCG findings, 75 per cent of participants have encountered supply disruptions that have impacted operations and national energy companies have taken several prudent measures to safeguard the supply chain during this time of crisis. First and foremost, many have focused primarily on supply chain de-risking – 92 percent of BCG’s survey respondents have set up COVID-19 response teams, more than 75 percent of these are already engaging with key suppliers, and close to 70 per cent have identified alternative suppliers for critical materials and increased inventory and monitoring. Secondly, most teams have initiated quick-win cash and control measures – 90 per cent of respondents are actively negotiating down prices of metal-based items as commodity metal prices fall, while 70 per cent are either considering or already working on reducing discretionary spend and repurposing existing wherever possible to defer future purchases.
“National energy companies need to consider structural cost reduction exercises. The majority of companies we surveyed have not yet initiated those changes; only less than 30 per cent of respondents are working with their functional counterparts to identify alternative materials, reduce demand, and cancel non-critical procurement,” said Arun Bruce, managing director and partner, BCG.
BCG analysis indicates that most service providers to the energy industry will likely experience cost deflations in the range of 20-30 percent over the next 12 months. This will be driven by declining demand due to steep CAPEX cuts, commodity price drop, salary/wage reductions, and financial distress within the supplier ecosystem which leads to reduced overheads and profit margins. CAPEX-related services and materials such as drilling and OCTG would see prices fall by 20 per cent to 30 per cent in the next 12 months. OPEX-related services will see marginal price declines while savings on OPEX materials including piping valves and fittings could be in the 5 per cent to 15 per cent range. However, there is an underlying need for caution since excessive bargain hunting could permanently damage the supply chain by forcing financially distressed suppliers out of business
Furthermore, as per the BCG study and analysis, the future of supply chains will be centered on three major objectives: supply security, cost efficiency and supplier innovation. To rebound and move forward, BCG has proposed five key levers that companies should adopt while pursuing these three objectives:
“Although crises are known to cause significant economic strain, they also provide opportunities for growth and companies that flourish during downturns share common traits of preparation, preemption, growth orientation, and lasting transformation,” said Cristiano Rizzi, Managing Director and Partner, BCG. “Based on the 2020 National Energy Operator Survey and our independent analysis, we are confident that the supply chains of national energy companies will recover and rebound. But in order to achieve objectives in this regard, several key levers must be utilised to ensure they act in earnest, starting right now.”
By: Paul Carthy, Managing Director – Energy Industry Group, Accenture in the Middle East
The oil and gas (O&G) industry is no stranger to supply and demand shocks and has weathered more than a dozen such jolts over the past four decades.
In the run-up to the COVID-19 pandemic, the oil and gas industry was already amid considerable disruption. Sector returns were under pressure, the capital was flowing away from the industry, and decarbonization headwinds were strengthening to capital increases. Most of the supply-side shocks, excluding 2014’s bump, were the result of sudden supply pullbacks as a reaction to geopolitical unrest. On average, the impact of these market-tightening tremors lasted anywhere between one and six months. Fluctuating demand was primarily due to macroeconomic contraction and was closely connected to more astronomical volatile economic cycles - in terms of size and duration.
However, despite the turbulences the industry has endured over the years, two uncharted global events took set to shape a new and perhaps, even more, disruptive market:
The confluence of these two shocks creates an unprecedented situation and is, therefore, difficult to anticipate. However, if we piece together the various elements of supply and demand in light of these events, it appears that their impact could last well into 2021, with a disproportionate influence on US oil production. Overall, it is likely that we are in for a turbulent 2020, and a lukewarm 2021 in which commodity markets will be under considerable pressure. Given the imminent worldwide recession, it’s hard to see any winners in this scenario, with producer nations, investors, O&G companies, and green/new energy businesses all set to lose.
Simultaneous demand contraction and a concurrent ramp-up in supply are unprecedented. We are in uncharted waters, and it isn’t clear who will win this game of brinkmanship. In this context, we can expect current low prices to prevail and quite possibly drop even further if OPEC+ continues to pursue the flood-the-market approach. This will destroy demand and result in oversupply.
Furthermore, in this scenario, resources became more abundant, the market more competitive, and alternative energy sources more prevalent, lowering the bar for alternatives to specific sources of O&G supply. The downstream sector that served as a cushion in 2014/15 for the industry at large, and specifically, for pure-play refiners and international oil companies (IOCs) as a result of improved margins, cannot be a savior in this cycle. The potential for higher margins will be blunted by reduced volumes as a result of the economic contraction that is set to occur.
As for natural gas, the onset of a global recession will affect demand, though not as much as for oil. However, supply adjustment will be limited, and even associated gas reduction is set to take time, resulting in the continued risk of lower prices. Regardless, this price risk will be more subdued than oil as the gas market was already fending off a market glut before the pandemic hit.
Still, once the global economy stabilises and growth returns, we need oil and gas to sustain development and drive prosperity in the developing world, and to meet the needs of more than two billion people, who will join the global population.
Also, while the logistics involved in oil and gas extraction have improved considerably since the last supply shock in 2014 - by up to US$10-US$20 per barrel – ultimately, the full-cycle breakeven economics of the marginal barrel will set the equilibrium price. And, that breakeven price is still in the high US$50s to low US$60s per barrel. Markets can stay irrational temporarily, but in the long run, fundamentals will prevail.
Challenging times call for intelligent measures - both traditional and non-traditional. The industry has pulled itself out of many shocks and proven skeptics wrong in the past (think peak oil that preceded the 2014 supply renaissance and disruption). However, it is now faced with concurrent disruption at an existential, system-wide, and best-in-class player level – these are risks that will truly test its tenacity and durability. While little can be done to counter the inevitable, making difficult but informed decisions and following a strategic roadmap will help oil companies to endure the downturn and anticipate the next peak.
This column first appeared in the July issue of Pipeline Magazine
Westwood Global Energy Group has released research estimating FPS contract awards will rebound to $13bn annually from 2021-24, underpinned by an anticipated average oil price of $60/bbl from 2022.
In the short-term, Westwood expects FPS engineering, procurement and construction (EPC) contract awards to reach a total of just over $5 billion 2020 – a 59 per cent decline from 2019’s ~$13 billion– assuming a base oil price of $37/bbl in 2020. The new research is a 73 per cent reduction compared to Westwood’s pre-COVID outlook.
1Q 2020 saw two key FPS EPC contract awards (Sangomar FPSO and Anna Nery FPSO [LOI in 2019]), accounting for approximately $2 billion of FPS EPC value and 170 kbpd of additional liquids production capacity. Other key FPS EPC contracts still expected to be awarded in 2020, include Equinor’s Bacalhau unit and Petrobras’ Mero 3, accounting for over $3bn in EPC spend and 400 kbpd of additional liquid production capacity.
Mark Adeosun, senior analyst, Offshore at Westwood Global Energy Group commented: “While the impact of the pandemic has hit FPS EPC contract awards significantly this year, the industry is in a much better place than the downturn of 2016 based on order intake so far, as well as the healthy backlogs of FPS contractors stemming from 2017-2019 activity. Despite this, the overall impact of COVID-19 on the FPS market represents a step backward for an industry which had expected 2020 to be a bumper year in 4Q2019”.
Longer-term, over the 2020-24 period, probable FPS EPC contract awards are estimated at $56 billion – including 40 FPSOs, 9 FPSS and 7 FLNG systems. The outlook for the latter, however, looks increasingly difficult, as low spot prices and looming overcapacity threatens the attractiveness of potential future investments.
Adeosun adds: “Over the next five years, Latin America will account for nearly 42 per cent of probable FPS awards – totalling an estimated $24 billion. Brazil is expected to dominate investment, as international oil companies ramp up activity and Petrobras commits to the development of its pre-salt discoveries. Outside Brazil, Guyana will contribute two additional orders to the forecast in addition to the Liza Unity and the Prosperity FPSO that are currently being built in Singapore (Topsides) and China (Hull).”
The research has been developed using its PlatformLogix solution, which covers global fixed and floating production facilities with data on more than 13,000 units.
The COVID-19 pandemic has stymied oil and gas activity, a phenomena which has now affected the drilling market both in terms of wells drilled and in terms of related demand for drilling equipment.
A Rystad Energy analysis shows the number of drilled wells globally is expected to reach around 55,350 this year, the lowest since at least the beginning of the century.
The decline is a staggering 23 per cent fall from 2019’s number of 71,946 wells. Our forecast, which extends to 2025, does not find it likely that last year’s number will be met or exceeded within the considered time frame. Drilled wells are expected to partly recover to just above 61,000 in 2021, as governments ease travel restrictions, boosting oil demand and prices. Then numbers will rise further to just above 65,000 in 2022 and remain just below 69,000 until the end of 2025.
North America is likely to be most affected, with the country’s rig count already down to historic lows just a few months into the downturn. Although modest recovery is possible in 2H20, drilling activity will remain more than 50 per cent below the levels seen at the same time last year.
From the 55,350 wells to be drilled in 2020, 2,238 are offshore and 53,112 onshore. Before Covid-19 struck, Rystad Energy had expected total wells to rise year-over-year to 74,575, of which 2,896 would be offshore wells and 71,679 onshore wells.
“Both new wells and drilling lengths will be pared down as E&P’s scale down investments, affecting the entire supply chain associated with these services. This includes drilling tools, which will decline by 35 per cent in 2020 compared to 2019,” says Reza Hassan Kazmi, energy services analyst at Rystad Energy.
When looking at drilling tools, we include blowout preventers (BOPs), downhole drilling tools, drill bits, drill pipe, jars, drill collars and other drilling tools except downhole pumps used for artificial lift, under the generic service segment.
Drilling length, another key driver for drilling tools, especially for drill pipes, drill collars, heavy-weight drill pipes and drill bits, is also estimated to drop by 25 per cent this year before improving in 2021. At a more granular level, such as the regional or country level, the percentage decrease in wells will not always result in a proportional reduction in total drilling lengths, as drilling depths per well could greatly vary between different regions and countries.
From the demand standpoint, we expect that onshore and offshore purchases for drilling tools will drop from $16 billion in 2019 to $10 billion in 2020. Besides North America, Africa and Russia will be the biggest contributors to this loss, where purchases will drop by 36 per cent and 27 per cent respectively this year.
Russian operators are likely to delay the drilling of new wells on mature assets to ensure compliance with agreed production cuts, while Sonatrach will cut back most of its spending on projects such as Hassi Messaoud and Tin Fouye-Tabankort. In the medium term however, as major E&Ps resume developing their lineup of offshore projects in Africa, we expect the demand for drilling tools (especially for drilling risers) to increase.
Overall, onshore markets are expected to recover as early as 2021 and grow at a rate of 7 per cen annually towards 2025, while offshore markets will see some highs and lows and will maintain an overall flattish level towards 2025.
Despite the overall stagnant growth, Brazil, Australia and China will continue to offer exciting opportunities in the short term with 20 per cent to 40 per cent growth prospects for offshore drilling in these countries while the United Kingdom, Guyana and Mexico look promising in the medium to long term. The United States remains the hotspot for spending on drilling tools onshore, while Norway is expected to top the list for offshore drilling tools spending.
In the onshore market in the U.S., more than 80% of spending on drilling tools will be spent on shale drilling. The Permian and the Appalachian basins will drive 60% of total shale spend on drilling tools followed by some conventional activity in other basins. Off the coast of Norway, Troll, Balder/Ringhorne and Johan Sverdrup will drive the demand for drilling tools.
By: Joko Priatmoko, Technical Support Consultant, Aramco Chemicals Company
Oil and chemicals markets have been severely impacted by COVID-19, but the pandemic has caused a spike in demand for some petrochemical products. While there can be few winners in the fight against coronavirus, polymers in particular have proven their resiliency, worth and value in confronting the infection. This has led to rising demand for healthcare products, flexible packaging for food and e-commerce goods, as well as Personal Protective Equipment (PPE). The two key polymers to have an impact in this area are polypropylene (PP) spunbond and polymethyl methacrylate (PMMA).
In the hygiene and healthcare sectors, the global need for items such as PPE, syringes, vials, wipes, medical cartridges, surgical masks and gowns has led to a surge in demand for products like PP spunbond non-woven fabric. One forecast predicts the spunbond non-wovens market will grow from $12.7 billion in 2018 to $18.3 billion by 2023, a Compound Annual Growth Rate (CAGR) of 7.6%. PP is likely to be the largest and fastest-growing segment in the global spunbond market, with personal care and hygiene forecast to be the biggest and fastest-growing end use segment.
There has also been significant interest in PMMA, otherwise known as acrylic, for new types of applications. This coincides with rising demand for protective shields to restrict the spread of the virus in public transport, offices, commercial stores, hospitals and pharmacies. PMMA lends itself to this purpose because it can be sterilized without impacting appearance or transparency, creating an ideal barrier between supermarket cashiers and shoppers, or between taxi drivers and passengers.
This signals a new use for PMMA sheets, for which higher COVID-19 demand is offsetting weaker consumption in the main automotive and construction sectors. In fact, PMMA has emerged as the most sought-after polymer in 2020, ahead of polycarbonate (PC) or polyethylene terephthalate-glycol (PET-G). Shields made from PMMA may well be a common sight moving forward: literally becoming part of the furniture in the post-COVID-19 new normal. This would in turn support further long-term growth potential.
Single-use plastic bags and disposable plastic bags, criticized for their environmental impact, also have a role to play with coronavirus-conscious retailers and consumers. Before the COVID-19 outbreak, sustainable packaging was on every Fast-Moving Consumer Goods (FMCG) company’s agenda. However, a shift towards more plastic packaging to help manage infection has altered the landscape - at least for the near future.
That is supported by higher demand for plastic packaging in general. The pandemic has shut down restaurants and food-service outlets, sparking a shift to grocery purchases. There is also a preference for online shopping over visiting public malls and high-street shops, increasing parcel shipments. Health precautions also demand more stringent protection for medical supplies. Such changes in behavior will not disappear overnight. As a result, the global packaging market is projected to grow from $909.2 million in 2019 to $1.0126bn by 2021, at a CAGR of 5.5%. The most optimistic forecasts suggest a CAGR of up to 9.2% over that period, while the least optimistic predict a CAGR of 2.2%.
However, plastics manufacturers face lower demand for engineering plastics in particular due to reduced production of vehicles and equipment. This is particularly the case in the automotive, construction, electrical and electronics sectors. PMMA producers have been able to offset this due to rising demand for shields, but sales of other products such as Nylon 6 - the waterproof material used to make machine parts, airbags, carpets, ropes and hoses – have suffered.
Yet despite temporary disruption, conventional demand for products is expected to return as businesses resume production with the easing of global COVID-19 restrictions. The new normal therefore presents a new opportunity for the petrochemicals sector, which has already been singled out by the International Energy Agency as the main driver of oil demand over the next decade and beyond.
That is why, at Aramco, we remain committed to expanding our petrochemicals business as part of a long-term goal to increase our downstream portfolio and capture more value from the integration and diversification of our operations, in particular in Asia. It is a strategy which inspired Aramco’s recent purchase of a majority interest in SABIC - a deal that ushers in a new era of innovation and value creation across the hydrocarbon chain and will propel Saudi Aramco as a leading global petrochemical supplier for decades to come.
By: Sverre Alvik, Energy Transition Program Director, DNV GL
The coronavirus pandemic will have a dramatic impact on energy supply and demand in the short term and will have lasting impacts once the pandemic dissipates. However, that will in itself do little to advance the world’s progress towards the Paris climate ambitions.
Energy use is strongly linked to economic activity, which has, and will continue to be, significantly impacted by the novel coronavirus pandemic: Our energy forecast is predicated on IMF’s longer outbreak scenario, where World GDP will shrink 6 per cent in 2020. The lingering effects of the pandemic will take the wind out of the sails of the world economy for many years – reducing World GDP in 2050 by 9 per cent, relative to pre-pandemic forecasts. Even with slower growth, however, by mid-century the world economy will still be twice its size today. In contrast, energy demand will not grow. In 2050, it will be about the same as it is today, in spite of a larger population and world economy. This is largely due to significant improvements in energy intensity, but also due to the effects of COVID-19.
An 8% drop in energy use
Before the pandemic, we predicted total global energy demand in 2050 at 456 exajoules (EJ), (Global energy demand using the latest historical figures was at 424 EJ in 2018.) Our modelling now shows that the pandemic will reduce energy demand through to 2050 by 8 per cent, resulting in energy demand in 2050 at almost exactly the level it was in 2018.
Improvements in energy intensity will remain the most important factor in reducing energy demand in the coming decades, and the contraction due to COVID-19 comes on top of this. That is as a result of the brakes applied to economic activity generally by the pandemic, as well as some specific sectoral impacts. Lasting changes linked to COVID-19 are mainly behavioural in nature and include the impact of the pandemic on the transport sector, especially aviation, but also on less office work and changed commuting habits, which will result in transport energy use never again reaching 2019 levels. Demand for manufactured goods globally will need almost four years to recover to 2019 levels, and the energy-intensive iron and steel industry, impacted inter alia by lower demand for new office space, may never reach its pre-pandemic heights.
On the face of it, this appears to be good news for decarbonisation – transport remains heavily oil dependent and iron and steel is one of the key so-called ‘hard to abate’ sectors, relying as it does to a large degree on hydrocarbons to supply high-heat processes. Declining demand in these sectors is one of the main reasons for the price weakness in hydrocarbons, with widespread write-downs in oil and gas assets. It appears likely that oil has already reached a supply plateau that we forecast to occur in 2022, prior to factoring in the effects of the pandemic.
It is certainly not game over for hydrocarbons, and especially not so for natural gas, which we forecast to take over from oil as the largest energy source in this decade. However, the reduced return on capital and the increased volatility in fossil fuel prices is making many investors look at these assets in the post-COVID world with a greater degree of caution; they may also now regard renewables assets more favourably, even though the pandemic is placing a temporary check on the expansion of renewable sources of energy. Renewables have first place in the merit order of the power mix due to their very low operating costs, and short design and construction times. These assets are therefore more robust, and we predict a slightly faster recovery of the non-fossil capital expenditure in the next couple of years than will be the case for fossil energy.
Limited long-term effects on the climate
With the earlier than anticipated plateauing of oil and the continued rapid decline of coal use, our forecast shows that CO2 emissions most likely have already peaked (in 2019).
Again, this appears to be good news from a climate goals perspective – but the longer-term decline in emissions is not significantly accelerated by the pandemic. Even with peak emissions behind us, and flat energy demand through to 2050, the energy transition we forecast is still nowhere near fast enough to deliver the Paris ambition of keeping global warming well below 2°C above pre-industrial levels. To reach 1.5-degree target, we would need to repeat the decline we’re experiencing in 2020 every year from now on.
To put this in perspective, the COVID-19 impact on energy demand only buys humanity another year of ‘allowable’ emissions before the 1.5°C target is exhausted (in 2029) and a couple of years before the 2°C warming carbon budget is exhausted (in the year 2050).
It should also be acknowledged that emissions have been declining in the first half of this year for the wrong reasons. The coronavirus pandemic is exacting a heavy and tragic toll on lives and livelihoods, increasing poverty and hunger and reducing growth prospects for those that need it most. There is a potential for a much more just and sound energy transition that does not cause the harm and disruption associated with the COVID crisis.
In our forthcoming Energy Transition Outlook (2020), which we will release in early September, we explore many of the technology solutions that can help to close the gap between our forecast global warming outcome and the Paris ambitions. Our view remains firmly that humanity already possesses the technology and knowhow to deliver on Paris. We also have the capacity to modify our behaviours and habits, and in this year’s Outlook we take a renewed look at energy-related behavioural change, and explore where and how COVID-19 may permanently change our habits.
However, the key to reaching the Paris goals remains policy: the political choices and policy delivered around the world that encourages the correct behavioural changes and enables the right technical solutions to scale.
Policy also represents the main uncertainty as to whether the pandemic will speed up or slow down the energy transition. It is unclear whether the enormous COVID-19 economic stimulus packages being lined up by governments will be spent wisely on renewable energy sources, or expeditiously on fossil sources in the hope of bringing larger numbers of people back to employment more rapidly. There are signs now of both directions being pursued, with strong regional variations. Our assumption is, therefore, that globally, the sum of the stimulus packages will not significantly impact the energy mix – but that remains an assumption. Time will tell.
Global discoveries of conventional resource volumes reached just 4.9 billion barrels of oil equivalent (boe) in the first half of 2020, Rystad Energy estimates, the weakest-performing first half of the 21st century. The resource volumes were 42 per cent lower and the number of discoveries was down by 31 per cent compared to the same period in 2019.
The average monthly discovered volumes so far this year are estimated at 810 million boe, a 34 per cent drop from the same period last year. This year could be on track to repeat the 2019 predominance of gas discoveries, with 55 per cent of the volumes discovered so far being categorised as gas. The top five largest discoveries account for about 68 per cent of the total discovered volumes.
The monthly average was pulled down primarily by June, which only saw three small onshore discoveries, adding around 16 million boe in discovered volumes. January and May were the most successful months in 1H20 due to significant discoveries such as Jebel Ali in the United Arab Emirates, Maka Central in Suriname, Uaru in Guyana and 75 Let Pobedy in Russia.
“Last year we saw the highest volumes of discovered resources since the last downturn. Based on the large number of high-impact exploration wells planned for this year, 2020 was meant to follow the same path. But then Covid-19 struck and the oil market crashed in 1Q20, resulting in delays and cancellations as operators cut budgets,“ says Rystad Energy’s upstream analyst Taiyab Zain Shariff.
Russia, South America and the Middle East account for about 73 per cent of the total discovered resources so far in 2020. Africa and Australia seem to have taken a back seat this time, with less than 1 per cent of the total discovered resources. It is also interesting to note that close to 70 per cent of the resources were discovered offshore.
There were a total of 49 conventional oil and gas discoveries during the first half of 2020, of which 27 were announced during the global lockdown and travel restriction period. While these travel bans and the associated logistical issues didn’t have much of an effect on projects in the testing and completion phase, they did cause delays for projects in the initial and ongoing drilling phase that required crew changes. This could be one of the reasons for the lower number of discoveries in May and June.
A total of 14 high-impact wells (HIWs) have been completed so far this year. Of these, three have resulted in medium-sized to large discoveries, nine were dry or had uncommercial hydrocarbon shows, while results are still pending for the remaining two. It is estimated that the wells that have come up dry targeted cumulative estimated pre-drill resources of more than 2.5 billion boe.
Drilling was in progress on an additional four high-impact wells as we passed the half-year mark, though the SAX01 well on BP’s Shafag-Asiman block in Azerbaijan has been temporarily suspended due to the COVID-19 travel bans. Another 11 high-impact wells are expected to be drilled before the end of 2020, including key wells in the Suriname-Guyana basin, Southern Africa, Timor-Leste, Norway and the frontier areas of Russia.
“Although we look forward to these wells being spudded before the end of this year, a few delays may still arise because of Covid-19-related logistical issues that may come up as a result of the expected second wave of the pandemic,“ adds Shariff.
The in-progress and planned high-impact wells have the potential to add up to 5.0 billion boe to the global tally. But with the unpredictable oil markets, and operators’ budget cuts on top of the COVID-19-related logistical issues, oil and gas exploration faces major challenges. It is estimated that the global offshore exploration activity this year might reach its lowest point in 20 years, with discovered volumes falling even lower than they were in 2016.
Without a major acceleration in clean energy innovation, countries and companies around the world will be unable to fulfil their pledges to bring their carbon emissions down to net-zero in the coming decades, according to a special report released today by the International Energy Agency
The report assesses the ways in which clean energy innovation can be significantly accelerated to achieve net-zero emissions while enhancing energy security in a timeframe compatible with international climate and sustainable energy goals. The Special Report on Clean Energy Innovation is the first publication in the IEA’s revamped Energy Technology Perspectives (ETP) series and includes a comprehensive new tool analysing the market readiness of more than 400 clean energy technologies.
“There is a stark disconnect today between the climate goals that governments and companies have set for themselves and the current state of affordable and reliable energy technologies that can realise these goals,” said Dr Fatih Birol, the IEA Executive Director. “This report examines how quickly energy innovation would have to move forward to bring all parts of the economy – including challenging sectors like long-distance transport and heavy industry – to net-zero emissions by 2050 without drastic changes to how we go about our lives. This analysis shows that getting there would hinge on technologies that have not yet even reached the market today. The message is very clear: in the absence of much faster clean energy innovation, achieving net-zero goals in 2050 will be all but impossible.”
A significant part of the challenge comes from major sectors where there are currently few technologies available for reducing emissions to zero, such as shipping, trucking, aviation and heavy industries like steel, cement and chemicals. Decarbonising these sectors will largely require the development of new technologies that are not currently in commercial use. However, the innovation process that takes a product from the research lab to the mass market can be long, and success is not guaranteed. It took decades for solar panels and batteries to reach the stage they are at now. Time is in even shorter supply now.
Notably, the report highlights the importance of making sure crucial clean energy solutions are ready in time for the start of multi-decade investment cycles in key industries. Doing so could create huge markets for new technologies and avoid locking in vast amounts of emissions for decades to come. If key technologies become available by 2030 to take advantage of the next round of plant refurbishments in heavy industry, nearly 60 gigatonnes of carbon emissions could be avoided.
Another issue is that many of the clean energy technologies that are available today – such as offshore wind turbines, electric vehicles and certain applications of carbon capture, utilisation and storage – need a continued push on innovation to bring down costs and accelerate deployment.
Around three-quarters of the cumulative reductions in carbon emissions that would be needed to move the world onto a sustainable path would come from technologies that have not yet reached full maturity, according to the IEA report. For example, it would require rapid progress in new battery designs that are still at the prototype stage now to shift long-distance transport from fossil fuels to electricity.
But the public and private sectors are currently falling short of delivering the innovation efforts to back up their net-zero ambitions – and the Covid-19 crisis is threatening to further undermine projects around the world focused on developing vital new energy technologies.
“A recent IEA survey revealed that companies that are developing net-zero emissions technologies consider it likely that their research and development budgets will be reduced, a clear sign of the damage that the Covid-19 crisis could do to clean energy innovation,” Dr Birol said. “Now is not the time to weaken support for this essential work. If anything, it is time to strengthen it.”
To help guide policy makers at this challenging time, the IEA report offers five key innovation principles for governments that aim to deliver net-zero emissions while enhancing energy security:
In particular, the report highlights issues requiring immediate attention in the context of the Covid-19 crisis, such as the importance of governments maintaining research and development funding at planned levels through 2025 and considering raising it in strategic areas. It stresses that market-based policies and funding can help scale up value chains for small, modular technologies with overlapping innovation needs like new types of batteries and electrolysers, significantly advancing their progress.
“Together with the Sustainable Recovery Plan that the IEA presented last month, this innovation report will provide the foundation for the IEA Clean Energy Transitions Summit on 9 July,” Dr Birol said. “The Summit will be the most important global event on energy and climate issues of 2020, bringing together more than 40 government ministers, industry CEOs and other energy leaders from countries representing 80% of global energy use and emissions. The aim is to build a grand coalition to help drive economic development and job creation by accelerating transitions towards clean, resilient and inclusive energy systems.”
The dual crisis engendered by the conflict over production levels within OPEC + and the reduced demand caused by the COVID-19 pandemic have prompted a global, sector-wide downturn in the Oil and Gas (O&G) industry that has left the oil-dependent economies vulnerable in terms of fiscal revenue.
Demand for oil has fallen by over 18 percent since the beginning of the year, leading to a steep decline of more than 70 per cent in the price of oil. Deloitte has just released its new report, Impact of oil industry crisis on the GCC and potential responses, which explores different potential responses GCC countries can take to address the impact of the oil industry crisis on their economies.
“The oil industry is facing its gravest crisis in 100 years, leading to a steep decline in fiscal revenues for many countries in the GCC. With the global economic downturn signaling lasting reduced oil prices, we looked at whether some countries in the region, particularly Saudi Arabia, would benefit from re-calibrating their visions by prioritising the most resilient transformation programs to stimulate their future economies,” explains Bart Cornelissen, Monitor Deloitte Partner, and Energy, Resources & Industrials Leader at Deloitte Middle East.
The Deloitte report finds that GCC economies have different options with regards to their development programs aimed at diversifying their economies. These options include among others accelerate the process of change, slow down the journey or scale back the vision.
The Deloitte report identifies four key dimensions with key questions to be considered in order to properly assess the various options and respond with resiliency. The first dimension focuses on crafting the strategic direction of the transformation, the second dimension focuses on understanding the future fiscal position, the third focuses on navigating the required investment and policy enablers and the fourth focuses on layout out the future blueprint for governance and socio-economic effects.
“Governments and leadership worldwide are being faced with the most difficult choices, each subject to multi-dimensional challenges and associated risk. The manner in which leadership responds in the next few months will be critical in maintaining, as well as boosting trust among all stakeholders involved,” says Cornelissen. “At the same time, any response will shape the foundation for future relationships, both in the internal and external ecosystem of any country.”
“In choosing the strategic direction and its underlying measures to address the longer-term crisis, leaders have the opportunity to not only tackle today’s challenges but also preempt and address future ones by undertaking the right approach today,” concludes Neal Beevers, Government & Public Sector Partner, Monitor Deloitte Middle East.
By: Marcin Jedrzejewski, managing director & partner at Boston Consulting Group (BCG)
The competitive position of the Gulf petrochemical sector is linked to the ethane vs. naphtha cracking economies. In the current low oil price environment, naphtha cracking becomes competitive vs. ethane cracking. The global oversupply on naphtha, observed in the last few years, is further contributing here.
We will still have to see how U.S. olefin prices will react to the drop in oil prices. Typically, there is a negative correlation of U.S. ethane (and consequently ethylene, key olefin) to oil prices. However, bearing in mind significant oversupply on natural gas and natural gas liquids already apparent before the oil price collapse in March 2020, we expect ethylene price in the U.S. to remain low, adding to the intensity of competition and further challenging the position of the Gulf petrochemical sector.
The competitive situation is now definitely more challenging than last year. What may give some respite is that the Gulf producers overall maintained production throughout 2020 while China, due to COVID-19, was forced to shut down most of their petrochemical capacity. This will offer a short term demand opportunity as the Chinese industry is coming back from COVID-19 – although this will differ by application industry.
Outlook for the continuity of Gulf projects
There is definitely space for competitive projects in the region. What is critical is to identify sustainable sources of competitive advantage – typically coming from feedstock pricing and a logistics premium. Propane is a good example – as it is typically provided to Gulf producers at a formula with a 20 per cent discount and without logistics cost in comparison to, for example, the North-East-Asian producers.
Together with the premium on the energy cost, this can make projects still very attractive. Where we expect players to be more careful are projects where there is limited or no structural feedstock advantage – while the global markets have been oversupplied. Commodity liquid derivatives generally fall into this category.
However, in a low margin environment as we face it now, other sources of competitive advantage are critically important – operational excellence, efficient logistics, robust go-to-market models without margin leakage.
Competitive advantage of the region
Historically, the advantage of the Gulf petrochemical sector came from feedstock and energy cost advantage. Additionally, the creation of chemical clusters and value parks where Gulf petrochemical players can share services and infrastructure is also a plus. The low oil price environment may have affected some elements of this– but it is still important and relevant. It is also essential is to be aware that this cannot be the only source of advantage. What still remains is, for example, the importance of market access and an advanced go-to-market model.
In the past, only a few players invested in the go-to-market model – but definitely, they now face a different opportunistic situation. Some players have been investing systematically in go-to-market capabilities, increasing target market presence, and focusing on superior delivery. These investments can make a real difference. Having a direct relationship with the final users of petrochemical material, efficient and controlled logistics, quick feedback from the market is critical to ensure your market position is resilient and that you can respond quickly (e.g., adjusting your polymer grade selection to demand changes). Such players are definitely in a completely different situation than players just relying on the global trader and bulk off-takers.
Energy and emission cost also needs specific attention. Most of the European players have put in place strategies to become carbon-neutral within the next decade or two. If successful, strengthen their place from a production cash cost position.
This column first appeared in the June issue of Pipeline Magazine
The European Union is strengthening its efforts to make its energy systems cleaner and more resilient, reinforcing its global leadership in reducing greenhouse gas emissions, according to a new energy policy review by the International Energy Agency.
EU greenhouse gas emissions in 2019 were 23 per cent lower than in 1990, meaning the bloc had already met its target of a 20 per cent decline by 2020, according to the new IEA report. Cleaner electricity was the main driver behind the reduction, with the carbon intensity of European power generation now well below most other parts of the world. The EU is a leader in renewable energy technologies, notably offshore wind, and many of its Member States have policies in placed to phase out coal. However, greenhouse gas emissions in the EU transport sector are still rising, and the use of energy in buildings remains fossil-fuel intensive.
The new IEA report sets out recommendations to help the EU meet its 2030 targets for greenhouse gas emissions, renewables and energy efficiency as well as its longer-term decarbonisation goals. It finds that stronger policies than those currently in place will be needed to deliver on these ambitions and that the energy sector needs to be at the heart of those efforts, as it accounts for 75 per cent of EU greenhouse gas emissions.
In December, the new European Commission led by President Ursula von der Leyen launched the European Green Deal in a bid to make the EU climate neutral by 2050. This plan quickly faced the added challenge of Covid-19, which has pushed the world into a sharp economic downturn. This crisis is a test of energy sector resilience and policy makers’ commitment to clean energy transitions. The EU energy sector has so far stood up well to the pressures it has been under, but the economic downturn continues to weigh on company and government balance sheets. Last month, the European Commission presented a massive recovery plan to counter the economic damage from COVID-19. The plan aims to achieve a resilient, inclusive and green recovery in Europe while laying the foundations for a low-carbon future.
“With its recovery plans, the EU has a real opportunity to boost economic activity, create jobs and support the long-term transformation of its energy sector,” said Dr Fatih Birol, IEA Executive Director, as he launched the new report with Kadri Simson, the European Commissioner for Energy. “The Sustainable Recovery Plan described in the IEA’s recent World Energy Outlook Special Report shows how to achieve these three objectives simultaneously. The IEA is working with the European Commission and EU Member States to design policies to repair the economic damage of the crisis while making their energy systems cleaner and more resilient.”
“The IEA’s review of EU energy policy comes at a crucial moment, as we debate the investment priorities for our economic recovery and the future EU budget,” said Commissioner Simson. “The review supports the Commission’s firm commitment to a green recovery, which is at the heart of our proposal for a €750 billion recovery plan. We will continue to work closely with the IEA as we design European policies to transform our energy sector and at the same time provide jobs, growth and better quality of life.”
As EU Member States have different energy policies and approaches to decarbonisation, the IEA report concludes that strong cooperation will be needed under the framework of the National Energy and Climate Plans. It also recommends that the EU build on the bloc’s integrated energy market and cross-border trade and develop stronger carbon price signals.
“The European Green Deal represents an opportunity to strengthen economies across the continent by pooling investments in energy technologies that are likely to play a crucial role in the future,” Dr Birol said. “Hydrogen electrolysers and lithium-ion batteries could potentially be game-changers both for the EU and globally. I welcome the efforts by the European Commission to accelerate innovation and commercialisation in these key areas.”
The IEA report also underscores that maintaining EU energy security remains critical, as the energy sector is vital for the health of citizens and economies. In particular, EU electricity systems and markets will need to accommodate growing shares of variable renewable energy. At the same time, risks such as extreme weather and cybersecurity threats are intensifying the challenges for designing and operating electricity systems.
The EU is facing the retirement of half its nuclear power generation capacity over the next five years unless decisions are taken to extend the lifetimes of the plants, which currently provide a major part of the continent’s low-carbon electricity. To support the phase-out of coal, natural gas is becoming essential to ensure the flexibility of electricity systems in Europe, but the region’s supply of gas will be largely dependent on imports. In this context, the IEA report finds that the EU cannot afford to reduce its energy diversity and needs to invest in electricity sector resilience.
The IEA report also points out that as the EU accounts for a relatively small share of global greenhouse gas emissions (8 per cent), global climate action and global partnerships will be essential to amplify its climate ambitions. The IEA stands ready to continue to support EU efforts to strengthen clean energy transitions worldwide by sharing lessons and insights from European experiences across the globe.
Rystad Energy forecasts natural gas output, which was previously set to grow, to decline by 2.6 per cent this year as a result of the COVID-19 pandemic.
Production of associated gas from oil fields will be hit most, losing some 5.5 per cent compared to 2019 levels.
Before COVID-19 forced a new reality upon the energy world, Rystad Energy expected total natural gas production to rise to 4,233 billion cubic meters (Bcm) in 2020, from 4,069 Bcm last year. Now this estimate is revised down to 3,962 Bcm for this year, rising to 4,015 Bcm in 2021 and to 4,094 in 2022.
Production from natural gas fields, which was initially expected to rise to 3,687 Bcm this year from 3,521 Bcm in 2019, is expected to reach 3,445 Bcm instead, recovering to 3,485 Bcm in 2021 and further to 3,551 Bcm in 2022.
The most affected output in percentage terms is the one of associated gas, which was initially forecast to stay largely flat year-over-year from the 2019 level of 547 Bcm. It is now expected to fall to 517 Bcm instead in 2020, rising to 530 Bcm in 2021 and 542 Bcm in 2022. Associated gas will likely only again exceed 2019 levels from 2023 onwards.
“Part of the recovery will be driven by optimism in future oil prices, which could gradually drive output from associated gas fields to near 600 Bcm by 2025. But how future oil prices really evolve will actually define the total natural gas output,” says Rystad Energy’s Head of Gas and Power Markets Carlos Torres-Diaz.
The biggest drop in associated gas production will be felt in North America, which accounts for about half of the global output. From a level of 259 Bcm in 2019, associated gas output will fall to 246 Bcm in 2020 and remain flat in 2021. Only later will it start recovering, to 256 Bcm in 2022 and 269 Bcm in 2023.
The second-largest associated gas producing region, the Middle East, appears a bit more resilient. Output will fall from 95 Bcm in 2019 to 91 Bcm in 2020, quickly recovering to 94 Bcm in 2021 and 99 Bcm in 2022.
Russia will see its associated gas production falling from the 2019 level of 52 Bcm to 46 Bcm in 2020, recovering to 50 Bcm in 2021, just marginally declining in years after that.
Europe’s output however, will keep its 2019’s 38 Bcm levels flat into 2020, seeing an increase to 39 Bcm in 2021 and 2022, before peaking at 40 Bcm in 2023.
Rystad Energy forecasts that oil Brent prices will stabilize at around US$60 per barrel in 2025, leading to our base case associated gas production forecast of 596 Bcm in 2025. However, if prices were to remain at the current level of $40 per barrel, then there is a risk of seeing associated production drop below 500 Bcm. On the other hand, if Brent prices were to increase towards $120 per barrel, production from associated fields would see a fast recovery and have the potential to reach 800 Bcm by 2025.
While global gas demand for 2020 has been revised down to 3,883 Bcm due to the impact of Covid-19, a jump in consumption during 2021 as a result of continued low prices and recovering economic performance could lead to a tighter balance. Currently, the production forecast for 2021 is 4,015 Bcm, meaning that if demand grows more than 3 per cent, the balance could tighten significantly. This would subsequently lead to higher prices, which could trigger a supply response.
Rystad Energy said that its current price forecast for 2021 suggests Henry Hub prices will average $2.7 per MMBtu and TTF prices $3.6 per MMBtu. The upside risk for global gas prices has increased as investments for projects are delayed.
By: Ann-Louise Hittle, Vice President, Macro Oils, Wood Mackenzie
Are we now deep in the abyss? Up to our necks in it, if the oil price is any guide. Brent has now tested sub-U.S.$20 a barrel in this downturn and WTI sub-zero, albeit briefly and in somewhat freakish circumstances. Where are the signs of stress across the oil value chain? And what are the prospects of finding an exit route to recovery?
First, oil demand, which we think may be close to bottoming out. Decline has been sharp and deep as COVID-19 takes its toll on global economic activity. Much of the world is currently in lockdown, with more than 65 per cent of the world’s population under travel restrictions. Global air travel and car use have nosedived in many countries. The big hit has been on jet fuel demand (down 50 per cent year-on-year) and gasoline (down 25 per cent). Diesel and fuel oil – used to transport goods by truck, ship and rail – have held relatively steady.
The net effect will be April’s demand falling by an average of 15 million to 18 million barrels per day (bpd) year on year, based on the early April forecast from our Macro Oils Service. It’s a big number but may be bigger still on certain days or weeks in April and May. Some estimates have suggested declines of 20 million bpd or more.
A key question is when the global economic recovery that’s needed to kick start oil demand growth again will begin. Right now, we appear to be in limbo. India, France and the UK, among other big economies, have extended lockdowns into May. Italy, Spain, Austria and others have started to ease restrictions while several US states are considering re-opening in May. There are early signs of U.S. gasoline demand stabilising.
China is the model to watch as it emerges from lockdown. It has already started ratcheting up crude purchases in April to supply a reviving economy.
Second, inventory is building at superfast rates globally. Cushing, Oklahoma, is a microcosm of the wider picture. Oil prices in Texas have incentivized producers to send crude to the Cushing hub; weak demand from refineries in the Mid-West and Gulf Coast have kept it there. Storage tanks are filling up rapidly – the three largest weekly builds on record were in consecutive weeks from late March, based on Genscape’s proprietary twice-weekly tank monitoring.
Cushing’s tightening storage capacity played a central role in WTI’s ignominious dive into negative prices on 20 April, ahead of the May contract expiry. Traders and financial players were effectively ambushed – having to pay counterparties up to U.S.$37/bbl to roll out of their expiring May contracts and into June.
Storage globally will stay tight so long as oversupply persists. Genscape estimates Cushing‘s spare capacity of up to 15 million b/d will be full within weeks, and other landlocked hubs – the Caspian for one – are in a similar position. But in reality, producers everywhere are worried their crude won’t be able to find a home.
Third, the world is still awash with supply, which unlike demand is still close to pre-crisis levels. Low prices have killed off new investment but have not yet had much impact on production. So far, we estimate barely 1 million bpd of onstream non-OPEC production has been shut in.
These are sizeable volumes but, given the scale of the market oversupply, insignificant. We estimate over 15 million bpd of production generates negative operating cash flow, now that prices have lurched lower. As storage fills up, more wells and fields will be shut-in during the coming weeks. Curtailed volumes will quickly mount up.
What must happen for the oil market to start rebalancing and prices to recover? May is important for supply, with OPEC+ cuts taking effect and removing up to 7 million bpd from the market by the end of the month. We expect a slow return to “normal” life in H2 2020 to help demand recover, though most likely staying below pre-crisis levels.
A strong bounce in demand as the world emerges from recession will be needed to soak up the overhang of inventory, which threatens to reach record levels by summer. Nothing, however, can be taken for granted while coronavirus still poses a threat to economic – and social – activity.
By: Brooke Azem, product marketer, Structural Analysis, Bentley Systems
Bilfinger Tebodin Middle East conducted various structural analyses for offshore oil field platforms. SACS helped save the team 1,200 resource hours to better meet the six-month timeline.
Located off the coast of Abu Dhabi in the Persian Gulf, Bilfinger Tebodin Middle East conducted a requalification study of an oil field. The facility includes 25 platforms and an extensive network of subsea lines. For this US$500,000 project, Bilfinger needed to perform detailed structural analyses of all existing platforms, many of which had surpassed their design life.
The project team would need to conduct data collection and review, as well as site visits to verify the as-is structural arrangement of the platforms with respect to their respective structural as-built drawings. The team also needed to prepare an updated weight control report with clear documentation, review the owner’s existing design criteria, review latest sub-sea inspection report anomalies, and recommend design changes and improvements in compliance with latest API RP 2SIMS and international guidelines.
As one of the leading service providers of engineering and consultancy services, maintenance, and lifecycle services, Bilfinger was familiar with the challenges of this scope and complexity. However, the organization had the added challenge of needing to keep within an extremely tight schedule. The project needed to be completed in just six months, which included the immense engineering work required. The multidiscipline engineering firm realized that it would need to integrate more digital workflows to meet the project objectives.
Modelling Platforms for Improved Analysis
Bilfinger used Bentley’s structural analysis software to requalify three process platforms and three wellhead towers, as well as perform pushover and fatigue analyses for six additional platforms. Six of platforms had not been modeled before, so the team would have to create them from scratch. To generate the SACS models, the team began by collecting data from site visit observations and most recent inspections including structural thickness measurements, and then generating the models.
The team then used SACS to model the platforms and perform in-service analysis, incorporating the structure’s dynamic behaviors. This analysis allowed the team to establish the current stress levels with the latest design standards for current in-place conditions. Bilfinger also used the application to perform pushover analysis to establish the reserve strength ratio (RSR) of the structures, cathodic protection design to establish the number of required anodes, and spectral fatigue analysis on all the platforms to assess the remaining life of the joints. These analyses optimised the structural strengthening and mitigation measures.
Extending the Life of the Platforms
By reviewing the model and establishing stress levels and structural strengthening modifications, the project team was able to create mitigation plans to extend the life of the structures for 20 years. The goal was to extend the structures’ operating life up to 2038 while still being structurally sound.
The team was better able to review the model and make the mitigation plans by eliminating the usual strict license restrictions. With SACS and Bentley’s cloud service subscription, Bilfinger team members could review the model at every stage of the process, whenever and wherever they were, without worrying about license usage. This process allowed everyone who needed to review the model to have access, saving time by catching any mistakes or inconsistencies early on. Bilfinger stated that the licensing model alone saved it about US$60,000 while still having all the required software modules, such as for the collapse and fatigue analysis that were pivotal for the successful completion of the project.
The most challenging part of this project was the extremely tight schedule and budget, as the project was scheduled to be completed in just six months. Having a centralized software solution with high-level interoperability for all the analyses was a huge advantage. Bentley’s SACS served a pivotal role in successful completion of this project.
Satya Medapureddi, Manager-Offshore Structural, Bilfinger Tebodin Middle East Ltd
Improving Client Satisfaction by Saving Significant Time and Cost
Bilfinger’s design was completed in March 2019. By using Bentley’s interoperable, centralised software, the organization was able to keep the project on budget and within the strict six-month schedule. As there were no existing models for six of the platforms, the team used SACS to generate the jacket structures with grid numbers, saving 50 hours per platform, resulting in about 300 resource hours. Additionally, using SACS to calculate the jackets’ surface area for cathodic protection design saved about 360 resource hours.
Taking into account all the other ways that SACS streamlined workflows, Bilfinger saved about 1,200 total resource hours throughout the project, leading to significant cost savings. The final design showed that there was no need to add new platforms, which will save the oil field operator US$90 million. Bilfinger was able to deliver a cost-saving design within the timeframe to the client’s satisfaction.
Bilfinger Tebodin Middle East Ltd.
Mining and Offshore Engineering
Abu Dhabi, United Arab Emirates
By: Paul Carthy, Managing Director, Energy Industry Group, Accenture in the Middle East
The supply chain has always been an essential lifeline for people, getting goods and services to all types of customers everywhere quickly, safely, and securely. Never has this been truer than in the current unprecedented times of global restrictions due to the COVID-19 pandemic. Companies worldwide have a shared responsibility to safeguard and ensure a smooth and reliable supply chain in all its forms, primarily via e-commerce.
Even as millions are still quarantined or self-isolated, a significant increase in online purchases left businesses scrambling to ensure the resilience of their supply chains. Unfortunately, the reality is that most companies were unprepared for a global pandemic of this nature. With labour shortages and reduced productivity challenges cropping up across the entire value chain, the supply chain’s ability to deliver has taken a severe hit across the world, specifically across the following touchpoints:
We have identified seven priorities for companies as they repurpose their supply chains to increase both resilience and responsibility:
This is a time of unprecedented supply chain disruption. By stepping up and building purpose and responsibility into supply chains, companies will strengthen the business over the long term, and build the greater resilience and customer-centricity that will be vital to growth as economies rebound.
This column first appeared in the June issue of Pipeline Magazine