The oil and gas sector is responsible for much of Oman’s economic growth and government revenue, thus changes in the industry tend to reflect greatly on the sultanate’s overall development. Although recent years have seen progress towards diversification goals, hydrocarbons activity still attracts a large share of domestic and foreign investment, with this pattern likely to continue for some time.
While the recent prolonged downturn in global oil and gas prices, coupled with the steady depletion of domestic resources, has given Oman some cause for concern, there are signs that the industry has turned a corner. This is not just because of more buoyant international energy prices, either: the sultanate’s astute use of enhanced oil recovery (EOR) techniques, combined with a concerted push to develop refining capacity, is breeding new optimism among industry stakeholders. Furthermore, some significant new discoveries have been made of late, revitalising the gas segment. Global majors are now ramping up their activities and re-entering fields they had previously moved out of, while Oman as a nation is building a strong reputation for EOR and the use of new seismic technologies. Challenges remain, however. Securing financing for new initiatives after several years of low prices on the global market is one, while human resources is another. Oman wishes to boost the presence of local businesses and the share of nationals employed in the sector, while international corporates seek to minimise costs, which are sometimes conflicting objectives. Still, the strong, long-standing relationships between international oil companies (IOCs) and their Omani partners put the sector on a good footing for further development.
According to the June 2018 “BP Statistical Review of World Energy” report, Oman had proven oil reserves of 5.4bn barrels, or 700m tonnes, at the end of 2017. This was around 0.3% of the global total, and roughly the same as in 2016 and 20 years earlier in 1997. The report also assessed average oil production to be 971,000 barrels per day (bpd) in 2017, or 1% of global output. This was down 3.3% from 2016, when just over 1m bpd were pumped, but higher than the average production of 868,000 bpd during the 2007-15 period. Oman’s oil reserves-to-production ratio was 15.2 years in 2017.
Meanwhile, domestic oil consumption that year averaged some 189,000 bpd, demonstrating the importance of refined exports to the sector. Indeed, figures from the National Centre for Statistics and Information (NCSI) for the first nine months of 2018 show that of the 265.5m barrels produced in the sultanate – including both crude and condensates – 222.6m barrels were sent abroad. Exports therefore represented around 84% of all output (see analysis). Similar to production, BP’s 2017 consumption figure was down 1.3% on 2016, yet higher than it had been at any other time since 2007.
Oman’s exported crude is the basis of a major trading classification, DME Oman, which is listed on the Dubai Mercantile Exchange. Over the course of 2017 this instrument posted an average price of $53.13 per barrel, showing some recovery from the $41.19 average recorded in 2016. That was the lowest it had been since 2004, and represented merely two-fifths of the $109.08 peak attained in 2012. By comparison, Brent crude averaged $54.19 in 2017 and West Texas Intermediate $50.79. Oil has continued its resurgence in 2018, with DME Oman hitting $88.96 per barrel in September – its highest point since October 2014. The price drifted down in October 2018, however, with factors such as the imposition of US sanctions on Iran and the US-China trade war continuing to create some uncertainty in global spot prices (see analysis).
In addition to exporting crude, Oman processes oil at the Mina Al Fahal refinery in Muscat and at another facility in the Sohar Port Industrial Complex. In 2017 the two plants had a production capacity of 222,000 bpd split between 106,000 bpd at Muscat and 116,000 at Sohar, according to the Oman Refineries and Petroleum Industries Company (ORPIC), which operates the plants. BP statistics show throughput standing at 204,000 bpd that year, up from 178,000 bpd in 2016 and representing 0.2% of the global total. In April 2018 a new refinery project at Duqm got under way, with the plant set to significantly increase refining capacity when it comes on-line in 2022, while an expansion was completed at Sohar in May 2018 (see analysis).
In terms of natural gas, BP states that Oman had total proven reserves of 700bn cu metres (23.5trn cu feet) in 2017. As with oil, this represents approximately 0.3% of the global total, but with a higher reserves-to-production ratio of 20.6 years. Proven deposits were the same for the end of 2016 and higher than what was known in 1997, although less than the 900bn cu metres of reserves identified in 2007. Production, meanwhile, stood at 32.3bn cu metres, up 2.9% on the 2016 total. Indeed, this was the highest output level since 2007 and accounted for 0.9% of global natural gas production.
Consumption of natural gas in 2017 stood at 23.3bn cu metres, which is demonstrative of how important the resource is to the domestic economy. Oman uses much of its upstream production for petrochemicals and liquefied natural gas (LNG), as well as for electricity generation, which was 100% powered by natural gas in mid-2018. This consumption has been growing steadily, too, with the 2017 figure up 2.2% on the previous year and around twice as much as the 12.2bn cu metres used in 2007.
Dealing with growing domestic gas needs is thus one of the key challenges facing local policymakers, as the economy and population continues to expand. This has led to projects aimed at both boosting local production and importing gas from abroad, with Oman taking natural gas from Qatar via Dolphin Energy’s subsea pipeline to meet shortfalls in recent years. This squeeze has also led to consideration of another import project, the $1.2bn Iran-Oman gas pipeline. The initiative outlines a 28m-cu-metre-per-day link that would run outside the Strait of Hormuz between the Iranian port of Kuhmobarak and Sohar. However, with the re-imposition of US sanctions against Iran and new domestic gas finds in 2018, prospects for the project were in some doubt late in the year. The gas issue is likely to be debated into 2019, though, with the Oman Power and Water Procurement Company – the sultanate’s sole purchaser of power and water services – commissioning a study on gas import requirements in October 2018.
At the same time, natural gas and LNG prices have declined since the heights reached in 2014 due to the global economic slowdown and increases in upstream and downstream supply in other countries, such as the discovery of shale gas in the US. Global benchmarks such as the Japan/Korea Marker for LNG averaged $7.12 per million British thermal units (Btu) in 2017, while prices on the UK Heren NBP Index averaged $5.80 and those at the US’ Henry Hub were $2.96. Prices crept up in 2018, though, with early June Japan/ Korea Marker prices for LNG sitting around $11.40 per million Btu – an unusually high figure given that it was summer in the northern hemisphere, when prices typically slump. However, the high prices drifted down as the year drew to a close, with the LNG index listed on the Japan/Korea Marker for November delivery falling to $9.93 per million Btu.
Predictions of weakening demand in several Asian economies were a major driver of this price reduction, with some 72% of all global LNG demand stemming from the Asia-Pacific region, according to industry media. Indeed, Oman LNG, a limited liability, joint-venture company established in 1994, lists three Asian companies with which it has long-running contracts. These are Korea Gas Corporation, which agreed to buy 4.1m tonnes of LNG per annum between 2000 and 2024, Osaka Gas of Japan, purchasing 700,000 tonnes per year over the same time period, and Itochu Corporation, also from Japan, buying 700,000 tonnes per year between 2006 and 2025.
Higher oil prices were also witnessed in 2018, which, together with an uptick in exports, provided a welcome boost to the country’s balance of payments (BOP). The 222.6m barrels of oil exported during the first nine months of 2018 represented a marginal but significant increase over the 219.8m barrels sold in the first three quarters of 2017, largely owing to the fact the average price of a barrel was $67.20 in 2017 – a considerable jump from $50.60 average between January and September a year prior.
This shift in the BOP illustrates the crucial role that the hydrocarbons segment continues to play in the Omani economy. NCSI data for the first half of 2018 shows that of a total GDP of OR14.7bn ($38.2bn) at market prices – up 15% year-on-year (y-o-y) – crude petroleum accounted for OR4.2bn ($10.8bn) and natural gas OR1.3bn ($3.3bn). This made a combined oil and gas total of OR5.5bn ($14.1bn), which accounts for more than one-third of overall GDP. These figures exclude the value of associated industries such as petrochemicals, which, if taken into consideration, would magnify the importance of petroleum and its derivatives to the economy at-large.
NCSI figures also show that of total government revenue of OR6.7bn ($17.4bn) earned from January to August 2018, net oil revenue made up OR4bn ($10.4bn) and gas revenue OR1.2bn ($3.1bn). This OR5.2bn ($13.5bn) total equated to 77.6% of all government income. The corresponding figures for the same period of 2017 were OR3bn ($7.8bn) in net oil revenue and OR958.5m ($2.5bn) in gas revenue, for 73.3% of total government revenue of OR5.4bn ($14bn). The 31.4% y-o-y jump in oil and gas revenue gives further indication of the myriad benefits that Oman derives from the rebound in global hydrocarbons prices and increased output. According to the local consultancy Ubhar Capital’s weekly report for October 7-11, 2018, the Ministry of Oil and Gas (MOG) stated that Oman has the capacity to increase the volume of its oil production by 40,000 bpd to fill the supply gap that is expected to result from the imminent cessation of Iranian oil exports, which stem from the imposition of US sanctions. Oman had reduced output in 2016, however, as part of a joint deal between the Organisation of the Petroleum Exporting Countries (OPEC) and non-OPEC members to try to support oil prices, so this would be more of a restoration of previous norms than the entry of new resources.
The main government institution responsible for overseeing the sector and planning for its development is indeed the MOG, led by minister Mohammed bin Hamad Al Rumhi since 1997. The current undersecretary of the ministry is Salim bin Nasser Al Aufi. The MOG is responsible for the development and implementation of government policy in the energy sector, and is composed of six general directorates. Each directorate is responsible for a different area of work: planning and studies, exploration and production, petroleum industries, petroleum investment management, marketing, and administrative and financial affairs.
Environmental aspects of the sector’s activities are handled by the Ministry of Environment and Climate Affairs. In late 2018 there was some discussion between the MOG and the Authority for Electricity Regulation – Oman regarding the future incorporation of the electricity sector into the ministry itself. It is expected that such an integration would help to streamline administration, and enable more unified policy development and implementation.
Work at the MOG also forms part of the government’s long-term development programme, Oman Vision 2020. This roadmap aims to boost the value of non-hydrocarbons economic sectors as a share of overall GDP through a converted process of economic diversification. The oil and gas downstream segment, in particular, is poised to be shaped by this, with petrochemicals and associated industries highly favoured for growth. One goal of Oman Vision 2020 is to reduce crude oil’s contribution to GDP to less than 10% by the end of that year, and to raise that of natural gas to 10% and industry to 20%. In 2017 the respective shares of GDP were 24.1%, 4.9% and 15.9% (for mining, quarrying, manufacturing and “other manufacturing industries”), according to the NCSI. However, despite the sultanate’s efforts to mitigate its long-standing dependence on oil, the industry will certainly continue to play an important role in the economy. “The seeming recovery of oil prices will play a pivotal role in financing the government’s diversification efforts, with market fundamentals pointing towards more buoyant prices in the medium term” Chris Breeze, country chairman of Shell Oman, told OBG.
Oman is currently in the final stage of Oman Vision 2020 with its ninth five-year plan, which runs from 2016 to 2020. This phase established the National Plan for Enhancing Economic Diversification, or Tanfeedh. Tanfeedh is focused on a handful of sectors that are key for economic growth – manufacturing, tourism, transport and logistics, mining and fisheries – and coordinates strategies for their development. One facet of this is to boost the in-country value (ICV) of all undertakings by increasing the share of project budgets and spin-offs that accrue directly to Omani suppliers. This measure is intended to address a long-standing concern that resources that could be used domestically for economic diversification are instead leaving the country.
The MOG has thus drawn up a strategy for boosting ICV in the oil and gas sector, including setting quotas for local sourcing in a given project. Companies that can demonstrate a high level of ICV in their bids are given an advantage, while those that do not meet required levels face denial. Associated with this is the longer running policy of Omanisation, which aims to address issues of employment in the sultanate by outlining rules and targets for the hiring of local and foreign nationals. These vary according to the type of job and the sector, recognising that sometimes highly specialised staff may not be available locally.
The Ministry of Manpower is responsible for implementing the Omanisation policy across the economy, with the Tanfeedh’s Implementation Support and Follow-up Unit playing a monitoring role. The latter organisation studies how various sector players are coping with the demands of working towards the Omanisation targets and, in cases of difficulty, suggests changes and solutions. According to the MOG, roughly 81% of all employees in the oil and gas sector were Omani nationals in 2017, making it one of the top areas for local employment. A total of 170,301 people were working in the sector across concession area companies, refineries, petrochemical factories, LNG activities and gas. This is close to the sector’s overall Omanisation target of 86%, although the level varies from company to company and from segment to segment. Operators, for example, are assigned a rate of 90%. The target – and the policy overall – is not without its critics, however. Some companies regard the onus on local recruitment as pushing up production costs, given that Omani employees generally command higher salaries than expatriate peers. Furthermore, for IOCs with global personnel structures, Omanisation can pose an obstacle to the circulation of highly qualified international staff.
Nonetheless, MOG officials point out that many challenges can be overcome with planning and a strategic attitude towards training and appointment. The policy is intended to function as a conduit for skills and knowledge transfer, and will thus have the result of firms investing a great deal of time and resources to bring on board new staff, but this is hoped to create a pool of domestic talent that will sustain the industry for decades to come. The refinery project at Duqm, for example, is seeing project managers train 600 Omanis for employment at the facility when it becomes operational in 2022. The total workforce is forecast to be around 800 (see analysis). Petroleum Development Oman (PDO) also delivered a record 14,146 training, redeployment, transfer and scholarship opportunities in 2017, including placing 2000 students in training-for-employment schemes.
In addition to the MOG, a handful of state companies and joint ventures play important roles in the sector. PDO is one of these, pumping the bulk of the sultanate’s crude oil. The firm also has exclusive rights to operate the country’s gas fields and processing plants. The government owns a 60% stake in the company, with the remaining shares divided between foreign interests Shell (34%), Total (4%) and Partex (2%). As the country’s main exploration and production outfit, PDO dates back to the early days of the industry, with its pioneers discovering some of the first fields in the 1950s and 1960s. At present, it operates 178 oil fields, 14 gas fields, 21 production stations, more than 10,000 active wells, 18,500 km of pipelines and flowlines, and 154 operating units, including 35 hoists and 46 rigs. In light of the size of such operations, service providers in other industries are moving to support and streamline daily tasks. “Big data analytics will greatly help the oil and gas sector to process the huge volume of information that companies deal with,” Maqbool Al Wahaibi, CEO of Oman Data Park, told OBG.
The refining sector, meanwhile, is the province of ORPIC, which runs both the Sohar and Mina Al Fahal complexes (see analysis). The Duqm refinery project, however, is being spearheaded by a 50:50 joint venture between the Oman Oil Company (OOC) and Kuwait Petroleum International, which created the Duqm Refinery and Petrochemical Industries Company. The OOC itself is the government’s main oil and gas investment arm, working both inside the sultanate and abroad, and in both upstream and downstream operations. Its upstream branch is OOC Exploration and Production (OOCEP). Oman LNG, for its part, operates the country’s three liquefaction plants outside Sur. The company is 51% government owned, with a 30% stake held by Shell, 5.54% by Total and the rest by a variety of other private investors. The facilities are planning to expand capacity by 10% by 2022 as an integral step in a “debottlenecking” programme, which will eventually see output reach a collective 11.4m tonnes per year to serve rising global energy demand.
Lastly, the Oman Gas Company (OGC) is in charge of the country’s natural gas transmission and distribution systems. The firm has also become involved in a variety of power and petrochemical projects, including partnering with Thailand’s Gulf Energy Development on establishing an independent power and water project for Duqm, and taking on operation and maintenance of ORPIC’s natural gas liquids extraction plant at the Fahud oil field. As shareholders in PDO and other government outfits, Shell, Total and Partex have long maintained influential presences in the sultanate. BP and Occidental Petroleum are also major IOCs with significant footprints in Oman, and ENI entered the country with an offshore block in 2017. In addition, there is a large family of exploration, survey and drilling companies present, including the UK’s KCA Deutag, the Schlumberger from the US, and local firms Hydrocarbon Finder, MB Petroleum, Gulf Petrochemical Services and Trading, and Abraj Energy Services.
A MOG mandate requires all oilfield service suppliers in Oman to register in the Joint Supplier Registration System (JSRS), a centralized repository. The JSRS ensures certain pre-requisites are met: it is a validation and not an audit system. Every operator carries out their own due diligence with regard to companies, and it is entirely at their discretion to decide whether a company fits with their criteria. Business Gateways International, the developer of the software, plans to integrate supplier performance, and JSRS is also going to go further into the operational side of the hydrocarbons sector, with the registration of contracts as well as companies. The tendering system will also be incorporated, with lower-level tenders going through eAuction and eTendering.
Geologically, Oman is divided into several distinct regions and is home to a collection of complex ecological features. The principal gas fields are located in a north-central region known as the Ghaba salt basin, while discoveries of exploitable petroleum deposits have been made throughout the interior of the country.
In addition to this, there is the Lekhwair oil field in the north-west, part of the Fahud salt basin, while the South Oman salt basin contains a number of oil fields as well. The first finds made by PDO were at Yibal in the Fahud region in 1962, in what is now the giant 90,874-sq-km Block 6 concession. Block 61 lies in the middle of this, home to the major Khazzan gas field that is currently under development by BP and OOCEP.
Other primary sites include the Mukhaizna oil field, which contributes around 13% to the sultanate’s entire oil output. There are a number of onshore and offshore blocks available around the country, and officials are keen to bring in new concessionaires to explore and exploit them. Indeed, the MOG is working to attract new entrants, with Asian outfits and traditional Western sources being encouraged to participate in bidding for contracts. “We need to accelerate the monetisation process of Oman’s hydrocarbon resources by expanding the horizons of operations on blocks,” Mohammed Al Jahwari, managing director of local firm Hydrocarbon Finder, told OBG. “This can be done by attracting investment from several companies, thereby increasing the number of producers and reducing the size of concessions.”
Recent evidence that suggests that this strategy is working, as the Indian Oil Company picked up a 17% stake in Mukhaizna from Shell in April 2018 for $329m, and in late October 2018 OOCEP was in the process of selling a 10% stake in Block 61 to Malaysia’s Petronas. Under the 2011 Oil and Gas Law, concessionaires typically sign an exploration and production sharing agreement (EPSA) with the MOG. This does not apply to PDO, which is a cost company making cash calls to its shareholders. The Block 6 Concession Agreement runs until 2044. An EPSA usually begins with a three-year exploration period, followed by a renewable production term of 15 years. The agreement typically covers cost recovery and production-sharing schedules, with separate versions in place for crude oil, natural gas and condensates. Under the terms of gas agreements, all production must be sold directly to the government, while oil and condensate may be sold on the open market. Concessionaires are also subject to taxes. In February 2017 a royal decree raised the standard corporation tax rate from 12% to 15%, while income tax on oil and gas companies’ Omani operations remained at 55%. In addition, the minimum tax threshold of OR30,000 ($77,900) was scrapped.
Oman’s unconventional geology and often difficult terrain have, in the past, sometimes served as deterrents to the engagement of potential concessionaires. Indeed, certain blocks have seen some churn, particularly during times of low oil and gas prices. Recently, however, activity in awarding new concessions has ramped up, as higher prices have returned and interest has grown. Four concessions were offered in November 2017, including the onshore 15,449-sq-km Block 49 awarded to Tethys Oil of Sweden. The others were offshore Block 52, awarded to Italy’s Eni and OOCEP, covering 90,760 sq km; onshore 1185-sq-km Block 30 for OOCEP and Occidental Petroleum; and onshore 8528-sq-km Block 31 for local ARA Petroleum. In January 2018 Lebanon’s Petroleb won the concession for onshore Block 57, which spans 2262 sq km.
EOR: In addition to experiencing heightened award activity, Oman’s upstream industry is perfecting EOR techniques as a method of extracting all possible product from maturing reservoirs. The large quantity of heavy oil in the sultanate – some 40% of known reserves are comprised of this high viscosity variety – is also making EOR an increasingly vital technology, as light oil, which is typically easier and less costly to pump with conventional means, becomes increasingly scarce. PDO in particular has pioneered EOR, and industry experts believe that the company’s investment in such techniques will increase EOR production as a share of its overall output to at least 23% by 2025, a significant increase on 10% in 2018. In addition to this, the company has invested in miscible gas injection, thermal recovery and chemical thickening agents as methods to optimise trapped residue.
In 2017 PDO injected some 3.3m tonnes of steam into the Shuaiba formation to extract 6.8m barrels of oil. New technologies are aiding other steam-powered pumps: California’s Glasspoint developed the 1000-MW, solar-powered Miraah project that is now operating in PDO’s Amal oil field. Polymer injection at Marmul, for its part, has released 14.6m barrels since the method was implemented in 2010.
Other outfits are also venturing into EOR in Oman. The UK’s Petrofac, for example, secured a $265m EOR deal in March 2018 for the development of the Marmul Polymer Phase 3 project, which has some 500 producing and 75 injector wells within its scope.
Meanwhile, one of the most exciting greenfield initiatives getting under way began with the decision by the government in 2017 to open the northern part of Block 6 to IOCs. This time the exploration and production deal involved a commitment to downstream projects and, in line with this, the concession needed to be awarded to companies capable of undertaking an initiative spanning the entire supply line. It was agreed through a memorandum of understanding in May 2018 that Shell and Total will partake in drilling at the block, with Shell committing to a gas-to-liquids (GTL) plant at Duqm and Total to an LNG bunkering project in Sohar as the downstream components. This will meet ICV requirements and in addition promises to increase Oman’s natural gas reserves. In March 2018 estimated recoverable reserves of more than 4trn cu feet and 112m barrels of condensate were reported in the Mabrouk North East area under review. Natural gas production is also receiving a boost from BP and OOCEP’s involvement at the Khazzan field. Work on the project began ahead of schedule in September 2017 and output quickly reached 1bn standard cu feet per day (scfd), along with 35,000 bpd of condensate. In April 2018 the second phase of this resource – called Ghazeer – also came under development, with production to start in 2021. Ghazeer is forecast to add an extra 500m scfd and 15,000 bpd of condensate to Khazzan’s output.
At the same time, improvements in seismic technologies have led many exploration and production outfits to make fresh assessments of existing prospects, with some sites that seemed less promising revealing more potential than initially expected. For example, in March 2018 Hydrocarbon Finder announced promising oil discoveries from the past year in the Hazirah formation of its Block 7 concession and in the Natih formation of Block 15. Output from the former lot subsequently rose more than three-fold between 2017 and 2018, from 600 bpd to 2000 bpd, with Japan’s Itochu signing an offtake agreement in early 2018. Gas operations shared the spotlight in this regard. “The really big one is where we drilled beneath an existing field to discover a potentially huge gas deposit,” Andrew Sutherland, HCF’s technical director, told OBG. “The landscape in gas is changing very rapidly in Oman.” While the company has experience of drilling to 3700 metres at Hazirah, these new gas deposits were discovered at 4800 metres. At present, the firm is making plans to drill a number of appraisal wells in order to tap an area that could potentially hold up to 3trn cu feet of gas, alongside its efforts to raising finance sufficient to fund the capital-intensive project.
More gas will certainly be required in the future, too, as the sultanate’s new port and industrial area of Duqm takes off. The OOC has outlined some $15bn in investment for this project, with recent moves including the ground-breaking for a $7bn integrated refinery complex in April 2018. The OOC is running the facility as a 50:50 joint venture with Kuwait Petroleum Corporation (see analysis).
At the same time, Oman Tank Terminal Company is building a $400m crude oil storage terminal at Duqm, with a 10m-barrel capacity for its first phase. The port is seeing the construction of a OR200m ($519.4m) bulk liquid terminal, which will facilitate the export of the petroleum, petrochemicals and chemicals that are produced in the industrial and refining areas of the Duqm Special Economic Zone (SEZ). The principal contractor for this work is the local subsidiary of the Netherlands’ Boskalis Westminster, which is set to dredge a massive 35.5m cu metres of seabed to prepare for the terminal’s construction.
Duqm will also function as the receiving end of a new gas pipeline, with OGC scheduled to add 500-600 km of conveying equipment to its network over the next few years, according to a statement from Sultan Bin Hamad Al Burtmani, acting executive managing director of OGC, made to industry media in October 2018. Some 350 km will connect the Saih Nihayda field to the Duqm SEZ, while roughly 250 km will run between the Fahud field and the existing refining complex at Sohar. These extensions will together extend OGC’s total pipeline network to in excess of 3000 km.
Some of the gas moving south to the SEZ at Duqm will be directed towards Shell’s GTL plant. While full details of the plant were not yet publicly announced at the time of press, it is envisioned that it will also produce electricity and pure water as by-products, with these then available for feeding into other petrochemical and industrial processes in the zone.
Sohar, meanwhile, has become a recent beneficiary of ORPIC expansion plans, with a $6.7bn steam cracker and petrochemicals project called the Liwa Plastics Industry Complex. By September 2018 it was reported 67% complete and on track to be delivered for operation sometime in 2020. When it begins operations, the complex is expected to boost plastics production in Oman by some 1.8m tonnes per year. Liwa has already added greatly to ICV, with 350 small and medium-sized enterprises awarded some $20m worth of contracts during construction through to September 2018. In other works, ORPIC and Spain’s Compañía Logistica de Hidrocarburos inaugurated the $336m, two-way Muscat Sohar Product Pipeline and Al Jefnain fuel terminal in March 2018. This pipeline now delivers about half of the country’s entire fuel needs via the terminal, which has a 170,000-cu-metre capacity.
Furthermore, the Port of Sohar was recently proposed as the future site of Total’s LNG bunkering terminal, which will become part of the downstream ICV add-on to its participation in Block 6 non-associated gas development. Total intends to use the equity gas entitlement from development of gas in Block 6 as feedstock for the LNG project, supplying the gas as bunker fuel for ships. A small liquefaction plant will be built at Sohar, with a capacity of around 1m tonnes per year. The use of LNG for shipping is likely to rise in the future as a result of new rules from the International Maritime Organisation that entail using low-sulphur bunker fuel from 2020 onwards. In the south, construction of the $826m Salalah Liquefied Petroleum Gas project is now under way in the Salalah Free Zone. Petrofac won the contract to build a $600m LPG extraction plant within the area, which will process 8.8m cu metres per day. The foundation stone was laid by OOC officials in April 2018, and the goal is to make Salalah a major global LPG and condensate export hub after the project is completed in 2020.
When it comes to local end consumers, the energy prices they pay have historically been reduced by generous public subsidies. In recent years, however, the government has moved to phase out these schemes. In January 2016 a previous fixed-price policy on a variety of petroleum products expired, and prices have been adjusted every month since to reflect international costs, although the margins the marketing companies earn per litre remain fixed by the government. As of October 2018 the National Subsidy System set fuel prices at OR0.222 ($0.58) per litre for M91 (regular grade), OR0.233 ($0.61) per litre for M95 (super grade) and OR0.258 ($0.67) per litre for diesel, all of which represented increases over what they were at the previous month. Indeed, in the two-year period between the end of the fixed-price policy and February 2018 the cost of both M91 and M95 increased by 81%. To offset some of the resultant strain on pocketbooks, a new subsidy scheme was introduced in December 2017, under which those with an income of less than OR600 ($1558) per month would become entitled to purchase 200 litres of M91 at OR0.180 ($0.47) per litre.
Petroleum retail in the sultanate is dominated by Al Maha Petroleum Products Marketing Company, which owns and operates 216 filling stations; Oman Oil Marketing Company, which runs 206 such facilities; and Shell Oman Marketing Company, with 187.
Oman’s energy sector has undergone a remarkable transformation in just a few short years, as public and private stakeholders have worked to transition the country from a gas-short to a gas-long position. Recent discoveries in the north of Block 6 and elsewhere may even give the country enough of a surplus for it to become a more significant LNG exporter, while increasing the domestic petrochemical sector’s share of the global petrochemical market. At the same time, the new refinery at Duqm is expected to provide crucial support for the oil segment. Kuwait’s involvement likely means that the facility will retain a bias towards the processing of that country’s heavy crude, while Duqm will also be well situated to harness Oman’s inland fields, which also mostly produce heavy oil. Much depends on global prices, however, which wobbled at the end of 2018 after growth earlier in the year. Some of the sultanate’s newest discoveries and most expansive projects may require a higher selling price if they are to become viable, but there is still plenty of lucrative work to be done at November 2018 levels of $70-80 per barrel.
Meanwhile, IOCs and local outfits will continue to follow ICV and Omanisation policies, while also pressing for these to be as flexible as possible, given industry constraints. The pursuit of ICV in particular will mean a much greater tie-in between upstream and downstream operations, with Oman seeking to end a period when much of the benefit from its oil and gas went overseas. Follow-through of sector plans will therefore be crucial in the years ahead. If the sultanate can fortify a position where, for example, the significant government revenue from LNG exports can be channelled directly into diversification, the country’s long-term development vision is likely to take shape.