The strong headwinds of 2017 in Oman’s oil and gas sector have spurred authorities to develop new sources of revenue. Despite recovering to 2015 levels of $55 a barrel, the steep fall in prices that saw Omani crude fall from $103 per barrel in 2014 to $40 in 2016 has squeezed state finances and added urgency to diversification efforts. On the back of a drop in crude output – following an agreement with the Organisation of the Petroleum Exporting Countries (OPEC) – overall economic growth in Oman was estimated to have remained flat in 2017, at roughly -0.02%, its weakest performance since 2011. However, the IMF forecast GDP growth would recover to 3.7% over the course of 2018, as gas production expands and the non-oil economy steadies.
Similarly, the National Bank of Kuwait forecast in October 2017 that the GDP of Oman’s hydrocarbons would decline 2.9% for the year, before increasing by 3.4% in 2018. The upside projection reflects the impact of the September 2017 launch of phase one of BP’s Khazzan tight gas development, one of the largest unconventional narrow reservoir projects to take place in the Middle East.
Hydrocarbons revenue in the sultanate accounted for 68.2% of total government revenue in 2016, according to the IMF, down from 84.3% in 2014. Despite achieving record production that year, total government revenue from hydrocarbons dropped by 67% from 2014 to 2016 as a result of lower oil prices. Meanwhile, oil revenue accounted for 27.4% of nominal GDP in 2016, decreasing from 34.1% in 2015 and 46.4% in 2014, according to US Energy Information Administration (EIA) statistics.
Large-scale projects, such as BP’s Khazzan gas field, have buoyed the oil and gas sector through the oil price downturn, but by the third quarter of 2017 the total number of rigs in Oman had declined by 14% year-on-year, according to the Baker Hughes rig count. With fewer wells being drilled, and operators prioritising cost containment in a low oil price environment, many contractors and oil field services (OFS) companies are finding themselves under pressure to step up efficiency and optimisation efforts to lower the cost of production.
The Ministry of Oil and Gas (MOG) oversees the sector and acts as counterparty to exploration and production-sharing agreements (EPSAs) with exploration and production (E&P) companies. These concession agreements grant firms the rights to explore, appraise, develop and exploit oil and gas. Because petroleum resources that have not been extracted are owned by the state, the right to import, export, transport, store, distribute, process or market petroleum substances is subject to a separate licence that must be granted by the MOG. The ministry therefore has the authority to negotiate individual commercial terms of EPSAs with private and public sector operators.
International oil companies (IOCs) have a prominent role in Oman’s E&P activities as well. Major players include Occidental, BP, Shell, Total, Partex and DNO. However, state-owned companies account for most of the sultanate’s hydrocarbons industry.
National oil and gas companies involved in upstream activities include Oman Oil Company (OOC), which is responsible for pursuing investments in the energy sector both inside and outside of Oman, as well as its subsidiaries like OOC Exploration and Production (OOCEP). Founded in 2009, OOCEP operates several blocks and is a minority partner in a number of joint ventures as well, including the Khazzan tight gas project operated by BP, the Mukhaizana field and Block 9, both operated by Oxy, and offshore Block 52, where Italian operator Eni holds a majority stake. Omani companies making up the downstream landscape include Oman Oil Refineries and Petroleum Industries Company (ORPIC), responsible for Oman’s refining sector, and Oman Liquefied Natural Gas (OLNG), which operates the sultanate’s three liquefaction trains near Sur.
Perhaps taking note of the restructuring of national oil companies in neighbouring Saudi Arabia and Qatar, Oman is reviewing proposals to sell shares, merge units and also cut costs in certain state companies. In particular, OOC was reportedly seeking advice from banks in 2017 over the selling of its energy assets and the issuance of public stock in certain portfolio businesses, such as Salalah Methanol Company. This approach is consistent with a coming privatisation and public-private partnership law that is expected to be introduced in 2018. As of early 2018, however, detailed information regarding the government’s potential initial public offerings had not yet been released.
In order to reduce the budget pressures caused by lower oil prices, the government has also targeted raising international finance as a means of funding national initiatives. Alternative financing arrangements employed by state companies include a $2bn loan financing deal secured by OOC in July 2017, and an export finance agreement that funded most of the 2016 and 2017 spend for Petroleum Development Oman (PDO), among others. While they still need to take steps to adapt to new market conditions, it is expected that PDO and larger IOCs will be capable of obtaining financing to maintain production levels. The impact will be felt more by medium-sized operators that have to rely on backing from IOCs, and by smaller players that may find it difficult to obtain financing in the oil price downturn.
Petroleum Development Oman
PDO, Oman’s largest hydrocarbon producer, extracts around 70% of the sultanate’s crude oil and approximately 2.5bn cu feet of natural gas per year from a concession area that spans 100,000 sq km, which is equal to roughly one-third of the country’s total geographical area. The government has a 60% share of the company, with the other 40% divided among Shell (34%), Total (4%) and Partex (2%). Gas fields and processing plants are operated exclusively by PDO on behalf of the government.
Production numbers at PDO have always been strong, backed by successful explorations that the company has been able to quickly pull on-stream. In 2016 oil exploration companies drilled a total of 53 exploration wells, and PDO alone was responsible for 29 of these. In 2017 the company was reportedly considering turnkey drilling as a substitute for day rate contracts and recently awarded a contract to Halliburton for the Lekhwair field on the premise that the wells would be drilled at a substantially cheaper cost. PDO’s rig count in Oman stood at 46 as of the end of 2017, and this count is expected to remain the same throughout 2018.
PDO aligns its strategy to government priorities and maintained a daily average oil production of 600,200 barrels per day (bpd) in 2016, up from 588,900 bpd in 2015 and well ahead of its production schedule of 600,000 bpd in 2019. “Three or four years ago our objective was 600,000 bpd flat for the next 10 years,” Amran Al Marhubi, technical director at PDO, told OBG. “We were at 550,000 bpd, and our objective was 600,000 bpd by 2018. We achieved that two years early, reaching it by 2016, so now our objective is to grow to 650,000 bpd by 2019.”
Like the vast majority of the oil and gas industry, PDO had not predicted the mid-2014 downturn in global oil prices and embarked on two major projects worth over $4bn – the Rabab Harweel Integrated Project (RHIP) and the Yibal Khuff project – the second initiated within months of the oil price decline. The RHIP has the potential to add more than 500m barrels of oil equivalent to reserves, through integrating sour gas processing facilities, associated gathering and injection systems and export pipelines. The Yibal Khuff project is another large and technically complex scheme centring on the simultaneous development of a number of sour oil and gas reservoirs. First oil is projected for 2020, with peak average production targets of 20,000 bpd and a gas plateau of 6m cu metres per day over 18 years. Despite market pressure to rein in capital expenditures, the firm and its shareholders are committed to seeing through both projects to commission on schedule in 2019 and late 2020, respectively.
To that end, another option for quick operational savings that has been rejected by PDO officials is cutting back on an organic growth drilling programme. “You may be cash flow positive in the first year from reduced activity, but you are certainly cash flow negative in the second year, and even more significantly negative by the fourth or fifth year,” Al Marhubi told OBG. The company is instead focused on saving through efficiency initiatives, working with contractors to take out unnecessary costs. In practice, this has meant considering different contracting strategies and steering clear of engineering, procurement and construction (EPC) contracts where possible. Almost $500m has been saved on the company’s two mega-projects using this strategy. According to Al Marhubi, this approach has ensured that PDO sees the benefits of procurement rather than an EPC contractor. Looking beyond 2020, the PDO project folder is set to be full, but made up of smaller initiatives that are focused on drilling and incremental growth. The company is reportedly considering rig fleet renewal as a means of integrating new technologies and automation.
Before topping 1m bpd in 2016, Oman’s annual petroleum and other liquids production had peaked at 972,000 bpd in 2000 before dropping to 715,000 bpd in 2007, according to data from the EIA. The figure began rising again with the increased adoption of enhanced oil recovery (EOR) techniques and a string of successes in exploration.
Volume output contracted again in 2017 as part of an agreement with OPEC members – though Oman is not a member – in which Oman pledged to cut production by 45,000 bpd. The deal helped reduce record high inventory levels and boost oil prices to above $55 a barrel. As a result it was extended by nine months to March 2018, with Omani officials suggesting that they would support output cuts to current levels of approximately 970,000 bpd beyond that date to help prop up oil prices.
Before the agreement was reached with OPEC, Omani operators had been preparing to increase production to offset shortages in the state budget. Any decision to extend the agreement looks set to inhibit E&P activities in Oman in 2018, though the sector is poised to ramp up production when limits imposed under the OPEC-led deal are lifted.
“We have the potential to exceed the constrained production level of 968,000 bpd, which we test on a monthly basis to ensure complete readiness in our ability to boost production when the limits are eased or removed, or in response to operational challenges in some of our fields,” Salim bin Nasser Al Aufi, undersecretary at the MOG, told local media.
Oil Reserves & Exports
According to a Thomson Reuters report, the sultanate had an estimated 5.3bn barrels of proved oil reserves in 2017. In a regional context, this makes Oman one of the less endowed Gulf countries, despite being the largest oil and natural gas producer in the region outside of OPEC. For the year ending 2016, Oman exported 912,500 bpd of crude oil and condensate, its highest level since 1999. Virtually all of the country’s crude oil exports went to Asian markets. China by far had the largest share for the year with 78% of aggregate oil exports, totalling some 251.1m barrels. Taiwan was the second largest market with imports of 18.8m barrels of Omani crude. Other major importers included Japan, the US, South Korea and India. Oman does not import any crude oil, although it does import certain refined petroleum products for use in the domestic market.
Natural gas is the primary fuel resource used in Oman, supplied to power and desalination plants by the MOG for use in power generation and associated water production. The resource is also used in heavy industry and for priority use in petroleum operations, commercial exploitation and injection for enhancing extraction rates, although alternative EOR techniques, such as solar steam EOR, are being rolled out to allow natural gas to be used and monetised elsewhere. The number of producing gas fields in Oman stood at 35 in 2016, with a total of 24 new exploration wells drilled. Provisional figures suggest an aggregate reserve of 24.8trn cu feet of natural gas, according to the Central Bank of Oman.
Total gas consumption in the country increased by 2.6% in 2016, in part driven by 4.6% growth in industrial activities. Meanwhile, daily production of natural gas rose by 5.3% in that same year, reaching an output of 106.1m cu metres per day. Demand for gas in Oman is expected to rise in the coming years, driven largely by new energy-intensive industries and organic electricity demand growth.
With the government keen to reduce Oman’s dependency on gas imports, future increases in demand are expected to be met by the new sources of domestic gas that are in the process of being brought online. Improving domestic supply will boost Oman’s contractors as well. “Connecting new power plants to the grid will create many opportunities for engineering companies in Oman,” Milan Maksimovic, general manager at Energoprojekt, a firm specialising in energy construction in Oman, told OBG.
While crude oil and condensate can generally be sold on the open market with prices benchmarked at the Dubai Mercantile Exchange, producers of natural gas are required to allocate their production output, excluding gas used for operations, for sale to the government on long-term gas or liquefied natural gas (LNG) sales contracts. Some 7.9m tonnes of LNG produced by OLNG in 2014 were exported, with the majority going to Japan and South Korea. Oman also imported 5.5m cu metres per day of natural gas in 2016 to meet rising demand, which was primarily used for re-injecting oil wells. This gas came from Qatar via the UAE using the Dolphin Pipeline.
Khazzan Gas Field
BP’s Khazzan tight gas field development in Block 61 onshore Oman will be a major new domestic gas contributor. The first gas from phase one came on-stream in the third quarter of 2017, with gas from the field flowing into the national grid some three to six months ahead of schedule, as well as hundreds of millions of dollars under the original budget. Khazzan will deliver a strong boost to the gas sector as daily production capacity is increased by 1bn cu feet, roughly 25% of current levels. BP is projecting a combined delivery of 1.5bn cu feet of gas and 25,000 barrels of condensate a day once phase two becomes operational, scheduled to take place in 2021 (see analysis).
The bulk of Khazzan’s early output is expected to be consumed within the sultanate by domestic end-users, but a substantial portion of future volumes is likely to be earmarked specifically for industries and consumers that are within the Duqm Special Economic Zone (SEZ). However, this will not commence until after 2019, when a pipeline to the SEZ is expected to be complete.
Gas from Khazzan will also be used to cover unutilised capacity at the three-train LNG complex at Qalhat, which averages almost 10.4m tonnes produced per annum, 25% of its total capacity. As feedstock, that volume was reported in September 2017 to be the equivalent of 15% of volumes being produced at Khazzan. The new gas was not expected to immediately translate into substantial increases in LNG exports, and Al Aufi has confirmed that gas imports via the Dolphin Pipeline from Qatar, which caters to demand in the Sohar area, will continue at similar volumes for the time being. “For the sultanate to fully optimise the potential of the Khazzan project, the ports and free zones will need not only financial, but political support too,” Bader Al Nadabi, executive director of Al Ha’el Ceramic Company, told OBG.
Planned Policy Changes
Government strategy in oil and gas as laid out in Oman Vision 2020 aims to reduce crude oil contribution as a percentage of GDP, while at the same time increase the contribution of natural gas. The ninth and final five-year plan of Oman Vision 2020 covers the period between 2016 and 2020 and aims to lower crude oil’s contribution to GDP to 26%, a decrease from the target of 44% as set in the eighth five-year plan. Key aspects of the federal strategy include promoting new industries outside of the oil industry sector, expanding downstream oil capabilities, such as petrochemicals, and developing new talent.
In terms of upstream investment opportunities, particularly in the context of the region, Oman is open to investment from smaller explorers as well as IOCs. Challenging exploration prospects are incentivised to ensure that risks are balanced, and the government’s fiscal framework is flexible and open to bidding and negotiation (see analysis).
To further enhance investment appeal for international E&P companies and to support the continued development of a well-regulated upstream oil and gas sector, the MOG has been making preparations to roll out high-level regulations governing all facets of upstream hydrocarbons activities in the sultanate.
The new “Oman Oil and Gas Regulations” are expected to address deficiencies in the existing Oil and Gas Law (Royal Decree 8/2011) and EPSA guidelines. Once in place, the supplementary provisions should provide greater clarity on regulatory obligations for a variety of areas, such as data acquisition, well abandonment methodologies and flaring of associated gas. The timeline drawn up by the MOG envisages a six-month pilot phase that will take place over the first half of 2018, with regulations expected to come into full effect by mid-2018.
Separately, a planned new labour law is expected to include a chapter that is specific to oil and gas workers, however, concrete details about the content and timing of promulgation have yet to be released. According to Craig Glatley, general manager at Al Sahari Oil Services, one area for improvement within the industry relates to the safety conditions of workers. “Oman’s oil and gas sector still has room for enhancement when it comes to safety and welfare in the field,” Glatley told OBG.
Concessions in the country are awarded by the MOG following well-publicised bid rounds. The latest completed round was opened in 2016, and by November 2017 the MOG had signed a total of four EPSAs with competing energy companies. The winning bidders for this round were Tethys Oil Oman for the 15,439-sq-km Block 49; ARA Petroleum for oil exploration in the 8528-sq-km Block 31; Occidental Oman and OOCEP for the 1185-sq-km Block 30; and a joint venture of Eni and OOCEP for exploration in Block 52, which is the largest concession in Oman, occupying an offshore area of approximately 90,800 sq km in the southern region of the country (see analysis).
The most recent licensing round was launched in September 2017 for four new onshore oil and gas blocks, with the round closing at the end of that year, though the winning tenders had not been announced as of January 2018. As a result of investors gaining confidence around pricing, this tender garnered more attention than other recent bid rounds. The round comprised of the 12,000-sq-km Block 43B, recently relinquished by Hungarian oil and gas company MOL; the adjoining 8520-sq-km Block 47, which was recently relinquished by Norwegian firm DNO; the 10,100-sq-km Block 51, where a total of 19 wells were drilled by previous owners; and Block 65, which covers some 1230 sq km, a concession that until recently was owned by OOCEP.
The interest in the new bidding round, which came against the globally protracted low oil price environment, underscores confidence in the strength of investor interest in Oman’s upstream sector. This uptick could also be partly attributed to updates to Oman’s business environment. “There have been a number of improvements in terms of contract awards, despite the economic conditions, due to the elevation in transparency of the tender bid process,” Said bin Saif Al Maskery, general manager of Composite Pipes Industry, told OBG.
In other recent upstream activity, the government ratified DNO’s agreement to concede 75% of its rights and obligations in Block 36 to Allied Petroleum. Masirah Oil has continued to evaluate findings from its exploration activities in Block 50 off Oman’s south-eastern seaboard, and PetroTel has pressed ahead with exploration efforts in Block 17 and 40 offshore Oman’s Musandam peninsula.
Oman operates two refineries, the oldest at Mina Al Fahal, near Muscat, has a capacity of 106,000 bpd. The second – which was launched in 2006 in Sohar and has a capacity of 116,000 bpd – recently underwent a multibillion-dollar refurbishment and expansion, coming under the Sohar Refinery Improvement Project (SRIP). Upon reaching full commercial operation in 2018, it is expected that the newly expanded Sohar refinery will be equipped to process 198,000 bpd of crude, providing a 70% boost to output, with capacity for more than 13m tonnes per year of finished products, according to ORPIC.
The SRIP is the centrepiece of a three-year expansion and modernisation programme undertaken by ORPIC at a total investment of $2.1bn. The programme was implemented in line with government diversification efforts that aim to add a slate of new refined oil and petrochemicals products at Sohar, including motor fuels and refined petroleum products. ORPIC’s $3.6bn new steam cracker and petrochemicals project in Sohar, the Liwa Plastics Industry Complex, will also enable Oman to produce polyethylene for the first time.
Oman’s existing refineries at Sohar and Mina Al Fahal are linked by the $320m, 280-km-long Muscat Sohar Product Pipeline Project (MSPP), which was completed in late 2017 and is operated by ORPIC. The MSPP began commercial operations as a two-way multi-product pipeline in October 2017, and will ultimately supply more than 50% of the sultanate’s fuel through a new oil product storage and distribution terminal in Al Jefnain. The pipeline is the first of its kind to be constructed in Oman, and meets several strategic needs, including increased safety and efficiency of fuel distribution, removing the need for ORPIC to ship refined products. The pipeline also provides a higher supply capacity of aviation fuel via direct pipeline to Muscat International Airport.
Another major pipeline locked in deliberations is the proposed joint subsea gas pipeline project, which would supply Iranian natural gas to Oman. Initial studies for construction of the pipeline have commenced, and talks are centring around the technical details of the agreement. Though internal planning is reportedly under way to launch an international tender to lay the pipeline, there are concerns that the volatility of the oil and gas market over the past two years could undermine progress.
In addition to the two existing refineries at Mina Al Fahal and Sohar, major EPC packages have been awarded to multinational companies for construction of the country’s third refinery at Duqm, 600 km south of Muscat.
A 50: 50 joint-venture deal that was signed between OOC and Kuwait Petroleum International (KPI) in April 2017 commits both parties to development of the $7bn, 230,000-bpd Duqm Refinery and Petrochemical Industries Company in the Al Wusta region. The new refinery is expected to commence commercial operations in 2021. Once working at full capacity, it will produce a number of value-added refined products, including diesel, jet fuel, naphtha and liquefied petroleum gas (LPG).
The project was first conceived in 2009 and a joint venture agreement was signed with Abu Dhabi’s International Petroleum Investment Company (IPIC) in 2012. IPIC subsequently withdrew from the agreement in 2016, when it was expanded to include petrochemicals, opening the door for KPI to step in and sign a memorandum to cooperate on development of the complex.
It is expected that the Duqm refinery will play a lynchpin role in transforming the Duqm area into an important hub for energy-related industries in the region by directly and indirectly supporting new projects in the SEZ. The area is estimated to receive up to $15bn in investments over the next 15 years, generating 12,000 new jobs.
By the end of 2017, three main EPC packages had been awarded to multinational companies for construction of the refinery’s main processing plants: Técnicas Reunidas and Daewoo Engineering and Construction won a contract at an estimated $3.3bn; a contract for the construction of utilities and offsite facilities was awarded to Petrofac International and Samsung Engineering at an estimated $2bn; construction of a product export terminal, a crude tank farm at Ras Markaz, and crude oil and natural gas pipelines was awarded to a consortium that included Saipem, worth an estimated $1.7bn; and a $400m crude oil storage terminal in Duqm is to be built by Oman Tank Terminal Company. The facility, which was due to be operational at the end of 2017, will have an initial capacity of 6m barrels, with the potential for this to be expanded to 200m barrels.
Discussions between state-owned Oman Shipping Company (OSC) and the Kuwait Oil Tanker Company regarding the supply of more medium-range tankers – which will be required to handle volumes from the new Duqm refinery – were in the preliminary stage as of early 2018. The OSC was reportedly favouring the second-hand tanker market as a means of quickly ramping up tonnage as required, but was separately considering buying between two to 10 bulkers to expand its aggregates business, as well as two container ships to replace chartered vessels.
In addition to its investment in Duqm, OOC is also enhancing existing and future downstream industries in the Governorate of Dhofar by investing in Oman’s first LPG extraction plant in the Salalah Free Zone. The strategically important Salalah LPG extraction plant is expected to commence operations in 2020, producing different types of LPG, mainly propane, butane and light condensate from natural gas flowing through Oman Gas Company’s southern grid.
Oman Oil Facilities Development Company, an OOC subsidiary, closed a $640m loan for the project in 2017, and UK-based international oil services contractor Petrofac was awarded an EPC contract to build the project in January 2017.
Once the Salalah LPG plant is operational, LPG will be shipped to markets primarily in the Indian subcontinent from a dedicated export jetty at the Port of Salalah – a task handed to OOC’s international trading arm Oman Trading International. Revenues from the export of the plant’s 300,000-tonne LPG output are projected at $200m per year.
As a result of government pressure to build up local talent, oil and gas companies across Oman are ramping up the In-Country Value (ICV) Blueprint Strategy to generate job and training opportunities, develop a robust and skilled local supply chain, and invest in the growth of Omani small and medium-sized enterprises (SMEs). The approach is in line with the 2012 ICV initiative launched by the MOG to promote the employment and training of Omanis, as well as investments in fixed assets and locally sourced goods and services.
One such company assisting in the generation of job and training opportunities in Oman is PDO, which has employed thousands of specialised workers. Under a government mandate to develop local skills for the global economy, PDO is looking at ways in which human capital can be converted to renewables or operational consultancy, particularly in areas of competitive advantage around oil field recovery methods and water injection techniques. The firm recently signed research and development agreements with Sohar University and A’Sharqiyah University in Oman to support efforts to boost ICV and fund specialisation in targeted sector areas such as enhanced oil recovery, water management, and energy sufficiency and security. PDO will assist with the establishment of technology centres at both of these universities, and will work with the institutions to encourage the development of Omani SMEs.
New services are also being developed within the oil and gas sector at a local level to meet niche market needs. The Oman Oil Marketing Company, for example, maintains a network of 184 filling stations and 105 accompanying Ahlain convenience stores spread across the country. Adding to its offerings, the company also launched mobile filling stations in 2017, which are capable of storing 50,000-100,000 litres of petrol and providing fuel services in remote areas for customers in industry, oil and gas, construction and transportation.
The ICV Blueprint Strategy has not been without its implementation challenges, however, particularly for contractors and service providers in oil tools and equipment and OFS firms. Many product lines in these industries have matured in Oman over the past four decades, and fewer competitors were entering the market in 2016-17 due to business conditions and pricing pressures.
For incumbents in the oil services market, legacy costs for Omani personnel – whereby national employees are entitled by law to a yearly salary raise of 3% – result in continually increasing staffing costs. Drilling and engineering contractors in the country have reported spending between 40-50% of total revenue on crew costs, which places them at a disadvantage vis-à-vis new market entrants that have not yet accrued such legacy costs. “The country needs to develop its local labour force with balance,” Saif Al Tobi, CEO of Oilfield Inspection Services, told OBG. “Optimising Omanisation rates should not come at the expense of productivity.”
Local contractors were also having to offer E&P operators heavily reduced rates in order to retain business. Companies like PDO and Shell have historically chosen to invest in developing long-term relationships with in-country contractors; increasingly, however, larger corporations appear to favour a value-driven approach that awards contracts to the lowest bidders in the global market.
Since 2016 this has resulted in deflationary pressure on contractor bids for major projects. Many contracts that were signed before oil prices crashed are now being retendered, and operators are receiving large discounts. Facing the likelihood of a reduced scope of business on existing contracts if they refuse renegotiation, many service providers and OFS companies are left with no option but to accept mid-contract cuts at considerable discounts.
“Contractors are reducing prices and bidding very aggressively in tenders. For us and everyone else to maintain market share we need to bid competitively. At the end of the day we have to be more efficient, reduce costs and adjust to new market conditions,” Andrey Krokhin, senior account manager at OFS provider Halliburton Worldwide, told OBG.
New market conditions in 2017 also included amendments to the income tax law, which imposed an additional 10% withholding tax on top of a planned corporate tax hike from 12% to 15%. This will have a notable impact on international companies operating in Oman, equal to up to 25% in corporate tax taken off bottom-line revenues.
Squeezed on the one hand by operators in contract negotiations, and on the other by the diminishing volume of activities stemming from cost optimisation and scrutiny, supplier margins are shrinking, making the new taxes unpopular with many sector players, while others stressed a more holistic assessment of Oman’s competitiveness.
“The increase of Oman’s corporate tax rate has had a small impact on the country’s competitiveness,” Chris Breeze, country chairman at Shell Development Oman, told OBG. “What would really impact the sultanate’s competitiveness for the better would be the simplification of administrative procedures.”
The drop in oil revenue has prompted reform in Oman’s energy sector, serving as strong motivation to increase the country’s use of renewable sources. For the time being gas is subsidised in the country and remains a cheap fuel source, with as much as 96% of the electricity produced in Oman derived from processes that use natural gas as feed stock. Keen to reduce government expenditures and commit a greater share of oil and gas resources to more profitable purposes, Oman’s official objective for renewable energy as laid out in Oman Vision 2020 is to source 10% of consumed energy from renewables by 2020. This may slip closer to 2030, but development of renewable projects has nevertheless gained a new urgency in Oman.
The sultanate’s location in the Gulf supports the pivot to alternative power. “With more than 320 sunny days per year and one of the highest levels of solar irradiance in the world, the opportunity for further developing solar energy in Oman is immense,” Ken Paton, CEO of Symtech Solar, told OBG.
PDO is acting on the momentum in renewables and reportedly is targeting to become a full-fledged energy company over the next decade, encompassing hydrocarbons and renewable energy generation as well as water management. The oil and gas company is already investing heavily in alternatives to generate steam for EOR, as at the moment it is produced by burning natural gas.
In cooperation with US-based GlassPoint Solar, PDO has made steady progress on the Miraah solar energy project at the Amal oilfield in Southern Oman. The 7-MW pilot Miraah project was successfully launched more than four years ago. Following on from this achievement, the first phase of the 1021-MW solar thermal facility reached completion in the fourth quarter of 2017, and the facility had plans to generate steam from the first greenhouse block by the end of that year.
At full capacity, the plant will be able to produce 6000 tonnes of steam for EOR purposes, saving 5.6trn British thermal units of natural gas each year, which is equivalent to the amount of gas needed to provide electricity to 209,000 Oman residents.
Separately, Oman Investment Fund and China-based Ningxia Zhongke Jiaye New Energy and Technology Management entered an agreement in May 2017 for the development of a large solar panel project at the SEZ in Duqm. When commissioned by the end of 2019, the $94m project will have an installed capacity to manufacture panels for power plants and residential buildings to generate around 1000 MW of energy per annum. The company anticipates $215m in predominantly export sales revenue per year, with 400 MW of installed capacity in the first phase of its operations.
Miraah and initiatives like the Duqm solar panel project have the potential to generate significant value for Oman, creating new opportunities for supply chain development, manufacturing capability, and employment and training, as well as helping to turn the sultanate into an international hub for solar energy research and development.
Oman’s oil and gas sector is in the process of diversifying and expanding its potential. Although overall economic growth in the country remained flat in 2017, and crude output dropped in line with OPEC supply cuts, Omani operators are well positioned to ramp up production above 1m bpd once the restrictions are lifted.
Over the interim, large upstream initiatives like BP’s Khazzan tight gas field are buoying the sector and transforming the sultanate into a swing producer of natural gas, in turn increasing feedstock supplies for the development of downstream and petrochemical industries. This supports a raft of government initiatives aimed at positioning the country as an international centre for the processing, storage and export of crude oil and its derivatives. Notable among these is the establishment of the country’s third refinery at Duqm, which is expected to play a fundamental role in transforming the area into an important hub for energy-related industries when it comes on-line in 2021.
Persisting growth constraints in the sector are tied to pricing pressures and the private sector belt tightening. With fewer wells being drilled, and operators prioritising cost containment in a low oil price environment, contractors and OFS companies are finding themselves under intense pressure to step up efficiency and optimisation efforts in a bid to lower the cost of production.
The government is also in the process of reviewing alternative funding arrangements and public offerings of state energy assets in oil and gas to reduce pressure on the state budget.
At the same time, the decline in international oil revenue in recent years has also inspired a new logic for reform in Oman’s oil and gas sector, and increased support for alternative solutions, such as the uptake of renewable energies. “The reality we have to face is that the end of oil will arrive sooner than expected, and Oman has to learn to adapt,” PDO’s Al Marhubi told OBG. “Part of this will involve embracing it and seeing it as an opportunity.”