Abu Dhabi boosting upstream while further developing downstream

In common with other major energy companies, lower hydrocarbons prices have prompted authorities to carry out streamlining and efficiencies in Abu Dhabi’s energy sector. Against a backdrop of reorganisation and reform, production from the emirate’s oil and gas fields reached record levels in 2016. Currently, Abu Dhabi National Oil Company (ADNOC) produces some 3m barrels of oil and 9.8bn standard cu feet per day (scfd) of raw gas.

Looking ahead, ADNOC’s strategy is to improve profitability and sustainability upstream while increasing value downstream. It also plans to triple the emirate’s output of petrochemicals by 2025. In the broader energy sphere, Abu Dhabi remains committed to making long-term investments in innovation and development of renewable energy and carbon capture technologies.

Oil & Gas Wealth

Oil and gas have played a dominant role in the economy of Abu Dhabi for almost 60 years, with the initial discovery made in 1958, the first well completed in 1960 and the first exports of crude in July 1962. The UAE was formed nine years later on December 2, 1971, with Abu Dhabi, Dubai, Sharjah, Umm Al Quwain, Fujairah and Ajman creating a union that was joined by Ras Al Khaimah the following year. ADNOC was established in 1971. Of the 97.8bn barrels of proved oil reserves in the UAE, 95% are located in Abu Dhabi, with Dubai’s 4bn barrels constituting the second most significant reserves base in the country. According to the “BP Statistical Review of World Energy June 2016”, the UAE’s reserves of crude oil constitute 5.8% of the world’s total, while its reserves of natural gas, at 6.1trn cu metres, represents around 3.3% of the world’s proven reserves. The UAE has the seventh-highest reserves of natural gas and the eighth-largest proven reserves of crude oil in the world. ADNOC manages 95% of the UAE’s proven oil reserves and 92% of the country’s gas reserves.

Supreme Petroleum Council

In 1988 the Supreme Petroleum Council (SPC) was created to oversee petroleum policy and activities in Abu Dhabi. The SPC functions as ADNOC’s Board of Directors and is chaired by Sheikh Khalifa bin Zayed Al Nahyan, president of the UAE and ruler of Abu Dhabi. The deputy chairman is Sheikh Mohamed bin Zayed Al Nahyan, crown prince of Abu Dhabi and deputy supreme commander of the UAE armed forces.

ADNOC’s CEO is also a member of the SPC alongside other prominent figures, including Suhail Mohamed Faraj Al Mazrouei, the UAE’s minister of energy. Al Mazrouei, a graduate in petroleum engineering, was employed by ADNOC for 10 years and spent two years on secondment to Royal Dutch Shell, where he worked on projects in Nigeria, the North Sea, Brunei and the Netherlands.

Reform & Reorganise

In 2016 UAE officials took steps to advance the country’s economic diversification strategy through the development of a roadmap for growth beyond oil. Called the UAE Post-Oil Strategy, its central aims – to advance human capital, knowledge and innovation – are consistent with the goals of the UAE Vision 2021 and the Abu Dhabi Economic Vision 2030.

The advancement of the UAE’s diversification plans took on added significance in 2016 in light of the sustained slowdown in global oil prices, which saw the price of Brent Crude reach a low of $28 in January of that year. In February large-scale reforms rolled out at ADNOC following the announcement by Abu Dhabi’s Executive Council of the appointment of a new CEO of the company – Sultan Al Jaber, UAE minister of state and chairman of Masdar, Abu Dhabi’s renewable energy and clean technology firm. The ADNOC reforms, which were geared towards improving performance, increasing profitability and optimising efficiency, involved the reorganisation of its operations, which at the time included 20 group companies, three academic and training institutes and four research and innovation centres. New chiefs were appointed to six out of the 18 operating companies and investments were made in the company’s workforce.

According to ADNOC’s “Sustainability Report 2015”, as of that year it had 65,000 employees and 165,000 contractors. In 2014, when the company reported that it employed 60,000 people and 97,500 contractors, its annual bill for wages and benefits came to Dh17bn ($4.6bn).

Restructuring

Among the separate companies under the ADNOC umbrella, there are three businesses running production on its major onshore and offshore fields. The Abu Dhabi Company for Onshore Petroleum Operations (ADCO) operates 11 onshore fields and two export terminals at Jebel Al Dhanna and Fujairah. Its oil production capacity is some 1.6m barrels per day (bpd), and the company plans to increase this to 1.8m bpd by 2018, according to ADNOC’s “Sustainability Report 2015”.

International oil companies (IOCs) had concessions collectively worth 40% of ADCO until they expired at the end of 2013 and were subsequently put up for renewal. Total was the first to rejoin the company, when it signed an agreement for a 10% stake in ADCO and its concessions in January 2015, and the company was appointed asset leader of the Bu Hasa and South East fields.

Total was followed by Japan’s Inpex and GS Energy in April and May of the same year, respectively, with the companies acquiring respective shares of 5% and 3%. Over a year later BP was also granted a 10% share in the company following a period of prolonged negotiations, which resulted in the firm becoming manager of the Bab field.

Finally, in February 2017 the remaining 12% of the 40% of foreign shareholding options available to investors was awarded to two companies from China, namely, China National Petroleum Corporation (8%) and CEFC China Energy (4%).

Historically, Abu Dhabi’s offshore fields were operated by two companies that are currently in the process of merging – Abu Dhabi Marine Operating Company (ADMA-OPCO) and Zakum Development Company (ZADCO). The companies operate as joint ventures (JVs) with IOCs. ADMA-OPCO operates two offshore fields with a total production capacity totalling 650,000 bpd in 2015: Umm Shaif, which encompasses 500 sq km, and Lower Zakum, which at 1270 sq km is the second-largest offshore field in the Gulf and the fourth largest in the world.

Apart from these fields, ADMA-OPCO started producing from the newly developed Umm Lulu and Nasr fields from 2014 and 2015, respectively. ADMA-OPCO is also developing Satah Al Razboot (SARB) Field on behalf of ADNOC, which is expected to produce first oil in early 2018. With development of these fields, ADMA-OPCO has embarked on a major growth agenda which targets oil production of 1m bpd by 2020. ADMA-OPCO also processes about 3bn scf/d which is used for injection into its reservoirs and export to ADGAS and GASCO.

ADMA-OPCO operates around 200 wellhead towers, 700 wells, 1200-km pipelines, four manned complexes offshore and Das Island processing and export facilities, encompassing oil and gas operations which will be further expanded in line with production growth. ZADCO, the other offshore company, operates three fields with a total production of 635,714 bpd in 2015: the 1269-sq-km Upper Zakum (UZ), the 150-sq-km Umm Al Dalkh and the 35-sq-km Satah field. The UZ field is expanding, with the construction of four man-made islands.

Production Aims

These islands will allow long horizontal wells to be drilled, with the aim of boosting the field’s production to 750,000 bpd by 2018. In October 2016 ADNOC announced its intention to integrate the operations of ADMA-OPCO and ZADCO into one offshore company – ADMA – by 2018, with Yasser AlMazrouei, the current CEO of ADMA-OPCO, appointed CEO of the new company. ADNOC has a 60% share in ADMA-OPCO, with the remaining shares held by BP, Total and the Japan Oil Development Company (JODCO). JODCO and ExxonMobil share 40% of ZADCO, with ADNOC holding the remaining 60%. Concessions are up for renewal for the joint entity in 2018, with the exception of the Upper Zakum concession agreement, which will expire on December 31, 2041.

Marketing & Distribution Consolidation

Undefined Shortly after unveiling the consolidation of its offshore exploration activities, ADNOC announced the consolidation of three of the companies in its marketing and distribution division: the Abu Dhabi National Tanker Company (ADNATCO), Petroleum Services Company (ESNAAD) and Abu Dhabi Petroleum Ports Operating Company (IRSHAD). Commenting on the move, Sultan Al Jaber said: “By leveraging the experience and assets across the three companies we aim to deliver an improved and cost-effective service to meet the needs of the ADNOC Group. The consolidation will capture synergies, generate savings and ensure value creation.” A steering committee was appointed by ADNOC to oversee the consolidation, which was due to be completed by the end of 2017.

The consolidated marine and services company, which had not yet been named as of April 2017, will be one of the biggest shipping companies in the region, with a fleet of over 165 ships. The fleet will include liquefied natural gas (LNG) vessels, bulk carriers, chemical and products tankers, container and container-feeder vessels, and support ships. ADNOC also announced that the National Gas and Shipping Company (NGSCO), in which it owns a 70% stake, would remain separate, although its share would be transferred to the new merged company.

NGSCO and ADNATCO merged in 2009 and share support services. ADNATCO was formed in 1975 as a wholly owned subsidiary of ADNOC to transport the UAE’s petroleum products to energy markets around the world, while NGSCO was formed in 1993 to ship LNG for the Abu Dhabi Gas Liquefaction Company (ADGAS), and in 2015 it had eight LNG vessels serving the ADGAS liquefaction plant at Das Island. NGSCO’s international shareholders are Mitsui & Co of Japan (15%), BP (10%) and Total (5%).

Adnoc 2030 Strategy Targets

In November 2016 the SPC agreed to ADNOC’s five-year business plan and budget, as part of the company’s 2030 Strategy, which is designed to further strengthen ADNOC’s role as a key contributor to the diversification of the UAE’s economy by generating sustained growth in its upstream, midstream and downstream operations. The 2030 strategy will see ADNOC evolve into a more commercially minded and performance-driven company.

To achieve this ADNOC will focus on optimising both performance and profitability, while strengthening human resources and efficiency. It has committed to raising oil production by a total of 400,000 bpd over time, and has set a production target of 3.5m bpd by 2018.

At the Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC), ADNOC announced it was working on new projects to increase its refining capability and expand its petrochemicals business. The company said gasoline production would increase to 10.2m tonnes per year by 2022 while petrochemical production would grow from 4.5m tonnes per year in 2016 to 11.4m tonnes by 2025.

Investment Funds Merged

While ADNOC focuses on consolidating the management of Abu Dhabi’s domestic oil and gas sector, consolidation is also taking place in the two entities managing many of the emirate’s key investments in energy and other sectors in Abu Dhabi and overseas.

On June 29, 2016 Sheikh Mohamed bin Zayed announced the merger of the International Petroleum Investment Company (IPIC) and Mubadala Development Company. The move will create one of the world’s largest state-owned investment funds, controlling combined assets totalling Dh460bn ($125.2bn) and maintaining partnerships with companies in some 30 countries.

IPIC, which was established in 1984 to invest in energy and related sectors around the world, has interests in a total of 18 companies. Mubadala, which is named after the Arabic word for exchange, was created in the year 2002 with a mission to generate profits for Abu Dhabi but also to help in the diversification of the emirate’s economy. It has a diverse portfolio of investments, with the largest revenues in 2015 generated by its semiconductor business at 54%, aerospace and engineering at 17%, and oil and gas at 13.2%, according to the company’s most recent annual review. The new company is called Mubadala Investment Company.

Collaborate & Integrate

There are considerable potential synergies between the hydrocarbons interests in Mubadla’s portfolio and those owned by IPIC. In an interview with local media in November 2016 Suhail Mohamed Faraj Al Mazrouei, minister of energy and then-managing director of IPIC, suggested that post-merger investment decisions could be devolved to the operator companies rather than being taken by the joint holding company.

According to local press reports, the merged companies will have combined oil and gas production outside of Abu Dhabi of more than 850,000 barrels of oil equivalent per day, with refining capacity totalling approximately 1.5m bpd.

In early 2017 the newly formed Mubadala Investment Company completed internal restructuring to create four main investment platforms. The first, the Petroleum and Petrochemicals division, which incorporates IPIC’s assets, is now the company’s largest business, accounting for 31.1% of total assets. This division is further separated into three distinct business units: exploration and production, midstream and refining, and petrochemicals.

The Alternative Investments and Infrastructure division, with an overall total of 31% of assets, is the second-largest area of operation and encompasses the company’s investments in a number of emerging sectors. This is followed by the Technology, Manufacturing and Mining division (21.6%), and Aerospace, ICT and Renewables (10.6%). The remaining 5.7% is listed as other corporate assets.

Oil Revenues

Although there is a delay in the publishing of detailed figures on oil revenues in Abu Dhabi, the latest data released from Statistics Centre - Abu Dhabi (SCAD) in its “Statistical Yearbook of Abu Dhabi 2016” did include figures from 2014. In that year Abu Dhabi’s GDP at current prices stood at a total of Dh960.1bn ($261.4bn), with oil accounting for Dh489bn ($133.1bn) of this total.

The slowdown in the price of oil in the second half of 2014 and its subsequent impact on revenues meant that this figure was 4.3% down on 2013, when oil GDP stood at Dh511.1bn ($139.2bn). Oil’s share of overall GDP fell from 57% in 2012 to 54.85% in 2013 and 50.9% in 2014.

SCAD does publish trade data from 2015, although the figures for oil, gas and oil products exported in that year do not include exports of LNG. The figures from 2012 to 2015 show that the value of oil, gas and oil product exports increased from approximately Dh451.5bn ($122.9bn) in 2012 to Dh490.5bn ($133.5bn) in 2013, but then declined to Dh328.5bn ($89.4bn) and Dh185.3bn ($50.5bn) in 2014 and 2015, respectively. Those exports as a percentage of total trade in goods expanded from 75.2% to 78.7% in 2012 and 2013 before falling to 68.3% in 2014 and 52.3% in 2015.

Trading Partners

According to SCAD, Abu Dhabi exported 661m barrels of crude oil in 2015, with Japan receiving 34.1% of the total, at 225m barrels, making it the number one importer of UAE crude, although its volume of imports decreased from 231m barrels in 2014.

Overall, the volume of crude oil exports declined by approximately 9% in 2015, from 729m barrels in 2014 to a total of 661m. The most significant falls in exports by volume were to South Korea, down 28.5m barrels; India, 23.6m barrels; Singapore, 17m barrels; and Japan, 6.3m barrels. However, Thailand bucked this trend, its imports from Abu Dhabi rising from 79m barrels to a total of 91m, which meant that – at around 13.8% of the total – it had the second-highest share of Abu Dhabi’s crude oil exports in 2015, up from 10.9% the year before.

In early 2017 ADNOC signed an agreement with Indian Strategic Petroleum Reserves (ISPR), a government-owned entity, to store crude oil at an underground facility in Mangalore. Up to 5.86m barrels of crude from Abu Dhabi will be stored at the facility under the agreement, with the objective of enhancing India’s energy security.

Exports of refined petroleum products fell by 40% in 2015, from 30.8m tonnes in 2014 to 18.3m. The biggest slowdown was in exports to the Netherlands, which fell from 9.21m tonnes in 2014 – 29.9% of total exports – to 2.23m in 2015 or 12.2% of total exports. Exports to France, meanwhile, dropped by 3.7m tonnes, and India took 1.7m tonnes less in 2015 than it had done the previous year.

Conversely, exports of refined petroleum products to Japan, Singapore, South Korea, China, Taiwan and Malaysia all increased in that year, with Japan constituting the biggest single market – at 18.8% of the total – followed by Singapore at 12.3%.

SCAD noted that overall LNG exports declined by Dh3.1bn ($844m) in 2014 to reach Dh16.9bn. Japan was the biggest recipient in 2014, importing 97.8% of the total, and importing 7.7bn cu metres of LNG from the UAE in 2014. At this time, the average price of Japanese imports, including cost, insurance and freight, stood at $16.33 per million British thermal units (Btu), a price that had only ever been beaten by the $16.75 paid in 2012.

In 2015 Japan’s LNG imports dropped slightly to 7.4bn cu metres, when the average price had fallen to $10.31 per million Btu, the lowest price since 2009. In 2016 the average price of Japan’s LNG imports was $6.85 per million Btu, cheaper than at any time since 2005. In 2015 SCAD reported that Abu Dhabi imported 21.76bn cu metres of natural gas, which comes through the Dolphin Energy pipeline from Qatar’s North Field.

Estimates & Projections

Although ADNOC does not publish financial statements, the IMF, at the end of its Article IV visit to the UAE in July 2016, gave estimates of the country’s earnings and projected earnings from hydrocarbons based on its economists’ examination of profit transfers from ADNOC to the country’s sovereign wealth funds, including the Abu Dhabi Investment Authority, and the returns of sovereign wealth funds.

The IMF estimates that the country’s hydrocarbons exports declined from a total of $129.4bn to $101.9bn in 2013-14 and $61.5bn in 2015. The fund predicted a further drop in 2016 to reach $54.5bn, before improving to $64.8bn in 2017. These projections were based on an average crude oil price of $52.40 in 2015, $45.30 in 2016 and $52.60 in 2017, with crude oil production increasing from around 3m bpd in 2016 to 3.1m bpd in 2017.

Based on these figures, the IMF assumed real hydrocarbons GDP growth of 0.8% in 2014, 4.6% in 2015, and 2% in 2016 and 2017. The fund also estimated that with fiscal consolidation in Abu Dhabi the break-even oil price declined from $79 in 2014 to $60 in 2015. Looking further ahead, the IMF predicts oil will stay below $60 a barrel until 2021.

Oil Production

In contrast to fluctuations in the global price of crude oil, production at ADNOC’s oil fields has been growing steadily over recent years, with the exception of the two years that followed the decision by OPEC in 2008 to cut production in the wake of the global financial crisis. According to BP’s “Statistical Review of World Energy 2016”, production in the UAE reached 3.9m bpd in 2015. This was a 5.3% increase on the total for 2014 at 3.69m bpd. Average production in 2011, 2012 and 2013 was 3.3m, 3.4m and 3.64m bpd, respectively.

The UAE’s average daily crude oil production was the eighth highest in the world in 2015, according to BP, after the US (12.7m bpd), Saudi Arabia (12m bpd), Russia (11m bpd), Canada (4.4m bpd), China (4.3m bpd), Iraq (4m bpd) and Iran (3.9m bpd). Of those eight leading producers, the UAE’s production increase, in percentage terms, was the third-highest after Iraq, which boosted production by 22.9%, and the US, where output surged by 8.5%. There are a number of differences in the way oil production is recorded and reported by BP, the International Energy Agency, the US Energy Information Agency (EIA) and the Joint Organisations Data Initiative (JODI). For instance, some include crude oil and lease condensate (C+C), while others do not, and Canadian tar sands are not included in the JODI C+C data. JODI is given monthly data by national governments, although there are occasional omissions.

A Record Year

The latest available data published by JODI, which for the UAE covers the first nine months of 2016, shows crude oil production increased by 2% compared to the same period in 2015, with average production up from 3.218m bpd to 3.283m bpd. The pace of production accelerated in the third quarter, with average output from July to September 4% higher than in the same period the year before, and average daily output rising from 3.276m to a total of 3.410m bpd.

In December 2016 ADNOC reported that its own production in Abu Dhabi was at the 3.15m bpd mark. According to JODI, of the eight leading crude oil producers the US and China were the only two to reduce average daily production in 2016, by 5.67% and 6.9%, respectively, over the full 12 months. Russia’s output increased by 2.9%, from 10.1m bpd to 10.4m bpd, while Saudi Arabia’s production rose by 2.9% from 10.2m bpd to 10.5m bpd. Canada boosted production by 8.1%, according to JODI, but the two most significant increases were in Iran, where the removal of sanctions saw oil output increase by 14.1%, from 3.1m bpd to 3.5m bpd during the first nine months of the year compared to the same period in 2015, and in Iraq, where crude production surged by 32.8%, from 3.5m bpd to 4.6m bpd for the full year.

Production Cuts

However, it was to be the level of production achieved in October 2016 that would be used as the benchmark for the historic production cuts agreed by the meeting of OPEC countries in Vienna at the end of November 2016. As part of this agreement, the UAE agreed to a reduction in output of 139,000 bpd based on its average October output of 3.013m bpd, leaving it with a production target from January 2017 of 2.874m bpd. Saudi Arabia, which accounts for some 31% of OPEC production, offered to make 41% of the 1.2m bpd in cuts agreed by 11 OPEC member states.

The OPEC cut was the first in eight years, and the deal saw Brent Crude immediately climb above $50. On December 10, 11 non-OPEC countries, including Russia, agreed to trim output by an additional 558,000 bpd collectively in what was described as the first global oil cut since 2001.

The same month, Reuters reported that ADNOC had announced it would cut crude supplies by between 3% and 5% from January 2017. The 5% reduction would be applied to Murban from ADCO’s onshore fields and the Upper Zakum grade produced offshore while the 3% reduction would apply to Das, the high quality blend from the offshore fields of Umm Shaif and Lower Zakum, which has an American Petroleum Institute (API) gravity of 38.79 degrees and a sulphur content of 1.14%. ADNOC’s production capacity of Murban, a light sour crude with an API of 40.31 degrees and sulphur content of 0.778%, is 1.6m bpd. Upper Zakum is a medium grade crude with an API of 33.9 degrees and a sulphur content of 1.84%. As of March 2017 Murban, Das and Upper Zakum were valued at around $56.10, $55.45 and $54.00 respectively, according to ADNOC.

Pumping Up Prices

The purpose of the agreed production cut is to control inventories in the hope that the price of oil will start to rise. The last time OPEC agreed to production cuts was in December 2008 at the height of the global financial crisis. On July 3, 2008 a barrel of Brent Crude was fetching $143.95, but by December 19 that same year, just after OPEC met in Oran, the price had dropped to $39.52. During that meeting, OPEC countries led by the swing producer Saudi Arabia agreed to cut production by 4m bpd. A year after the cut had been agreed Brent crude was selling for as much as $77.

However, many industry experts believe there are significant differences between 2008 and 2016. On the demand side, China may not have the appetite for oil it had in 2009-10. Between those two years China’s oil consumption grew by 14%, according to BP figures, while the UAE’s production was held back to 2.7m bpd in 2009 and 2.9m bpd 2010, years in which Saudi Arabia curbed supply to 9.7m bpd and 10m bpd. However, in 2016 BP noted that China’s energy consumption had grown at its slowest rate for 20 years in 2015, at just 1.5%. Another contrast with 2008 relates to the size of the production cut. In 2008 the scale of the supply reduction was more than twice that of the cut agreed in 2016.

However, the most profound change since 2008 has been on the supply side, due to the shale revolution in the US. In 2008 it could take three to six years for a new oil field to be developed and brought into production, but in 2016 and 2017 hydraulic fracture companies have the ability to increase production in a matter of months. In December 2016 the investment bank Goldman Sachs revised its outlook for oil prices for the second quarter of 2017, assuming all the countries that had offered to reduce production complied with the agreement.

Its revised forecast was that by the second quarter West Texas Intermediate would be selling for $57.50, up from its previous estimate of $55, while it expected a price of $59 a barrel for Brent crude, up from $56.50. Although a price of $59 would be very close to the $60 a year fiscal break-even calculated by the IMF for the UAE, it does not suggest a huge surplus, nor for that matter a return to the peak prices seen in 2008 and 2014. Goldman Sachs estimated the impact of the production cuts would not be felt from the start of January. Oil prices were averaging $51 as of May 2017.

Climate Change & Innovation

When the UAE’s leaders debate the future, they also acknowledge the impact international efforts to reduce global warming and environmental sentiment may have on future demand for fossil fuels, and crude oil in particular. The UAE was one of the first Arab countries to sign onto the agreement made at the COP21 UN Conference on Climate Change in Paris in 2015, and in November 2016 Sheikh Mansour bin Zayed Al Nahyan, deputy prime minister of the UAE, led the country’s delegation to the COP22 conference in Morocco. The UAE’s national statement to the international climate change conference focused on its instrumental role in working on innovative solutions in sustainability, while striving with other world leaders to advance action on global warming.

There were also signs of a global change in consumer sentiment in 2016. In February Bloomberg suggested sales of electric vehicles were showing signs of reaching a tipping point that could result in a 2m bpd fall in demand for crude oil by 2023. Two months later the US entrepreneur Elon Musk began taking $1000 deposits for his new Tesla Model 3 electric car. Within a week Musk announced $325m paid in pre-orders, representing eventual sales of $14bn for a car that was due to launch in late 2017. Comparisons with the impact Henry Ford’s Model T made on gasoline demand in the early 20th century were soon made. But there was more to come. In October 2016 Musk announced Tesla’s $2.2bn acquisition of SolarCity, the largest rooftop installation company in the US. Musk predicted that the company’s revolutionary new solar roof tiles would create a paradigm shift in home energy use.

Long-Term Forecasts

While these kinds of innovations may suggest there will be a reduction in demand for fossil fuels for some uses, global energy consumption continues to rise, albeit it modestly in 2014-16, and industry forecasters see crude oil playing a leading role for decades to come.

The “International Energy Outlook 2016” report published by the EIA predicts the share of petroleum and liquid fuels used in the global energy mix should fall from 33% in 2010 to 30% by 2040, but this will still represent the largest share. It sees the share of natural gas growing from 23% of the total to 26% over the same period, and it anticipates gas will surpass coal by 2030, with coal’s share sliding from 28% to 22%. Renewables, meanwhile, are expected to increase from 12% to 16%.

The EIA sees rising incomes in China, India and other parts of Asia as the main driver of growth in global energy consumption, which it expects to increase from 549,000trn Btu in 2010 to 815,000trn Btu in 2040. BP’s 2016 Energy Outlook sees the Middle East’s energy consumption rising by 60% by 2035, with fossil fuels accounting for 96% of the total, and it predicts the region’s share of global oil production will rise from 32% in 2016 to 33% in 2035. It also predicts the region will remain the world’s biggest oil exporter. Volumes are expected to increase from 20m bpd in 2014 to 23m bpd in 2035, with industry remaining the biggest user of energy globally. However, the report also sees gas growing faster than oil in the Middle East, with production up 49% and consumption up 67%.

2050 Strategy

In response to these long-term projections, in early 2017 the UAE launched its Energy Plan for 2050, which aims to achieve a balance between energy production and consumption by 2050, significantly expanding the role of clean energy and nuclear in the energy mix, and improving energy efficiency by 40%. Under this plan, the UAE envisages clean energy supplying 44% of the country’s overall energy needs, followed by gas (38%), clean coal (12%) and nuclear energy (6%). The plan earmarks Dh600bn ($163.4bn) in investment to meet energy demand and expects the strategy will result in savings of Dh700bn ($190.6bn).

Initiatives carried out under the strategy will focus on three main themes. The first involves the quick transition of power consumption efficiency, diversifying energy sources and ensuring the security of its supply. The second seeks to find new solutions that complement power and transport systems, and the third targets research, development and innovation to ensure the sustainability of energy.

Renewables

The launch of the new 2050 energy strategy coupled with the rapidly falling costs of renewable energy has seen renewables significantly expand their role in Abu Dhabi’s energy mix. This has opened the door for new projects, with Abu Dhabi Water and Electricity Authority receiving a world record-breaking lowest bid for a solar power generation project in 2016 (see analysis).

Also during that year, Masdar signed a power purchase agreement with Dubai Electricity and Water Authority to construct the 800-MW third phase of the Mohammed bin Rashid Al Maktoum Solar Park. The consortium was awarded the project in June 2016, after submitting a bid with the lowest cost of electricity at that time, at 2.99 cents per KWh. To date, Masdar has invested in renewables projects with a combined total value of $8.5bn.

Gas Production

Natural gas is an integral and growing part of the ADNOC conglomerate, with production divided between three companies. In 1973 the Abu Dhabi Gas Liquefaction Company (ADGAS) became the first LNG company in the MENA region. ADNOC owns 70% of the company, with the remaining shares divided between Matsui & Co, BP and Total, with the three international firms owning 15%, 10% and 5%, respectively.

The company’s LNG plant on Das Island, which is located some 180 km north-west of Abu Dhabi, processes both associated gas – the by-product of offshore oil production – and non-associated gas, produced from natural gas reservoirs. ADGAS signed its first 20-year agreement with Tokyo Electric Power Company (TEPCO) in 1972, and is still supplying TEPCO with LNG under an agreement that runs until 2019. It has an average annual production of 8m tonnes of LNG, Liquefied Petroleum Gas, paraffinic naphtha and liquid sulphur.

ADGAS’s two strategic projects – Integrated Gas Development (IGD) and Offshore Associated Gas – sees Das Island process 1bn scfd. Going forwards, the plan is to increase this by 400m scfd, which will be transferred to another of ADNOC’s gas companies, Abu Dhabi Gas Industries (GASCO). The IGD-E project comprises the construction of a new offshore and onshore pipeline, as well as additional facilities within the Habshan-5 Complex and the modification of existing facilities. The project is being monitored by ADGAS and GASCO to ensure its completion by second quarter 2018. Established in 1978 GASCO is engaged in the extraction of natural gas liquids (NGL) from associated and non-associated gas taken from both offshore and onshore fields. It operates a total of five gas processing plants and one fractionation plant.

Gas Facilities

The Habshan-Bab Gas Complex produces network gas that is supplied directly to end users, as well as NGL, condensate and liquid sulphur. The NGL is sent to the nearby Ruwais plant for fractionation, while the condensate is piped to Abu Dhabi Oil Refining Company (Takreer), which is an ADNOC subsidiary responsible for refined petroleum products. The sulphur is granulated and exported.

Saif Al Nasseri, CEO of GASCO, told OBG, “In the last couple of years, we have increased the natural gas processing capacity and have successfully achieved the historical milestone of unloading the first train of granulated sulphur with the inauguration of our Ruwais Sulphur Handling Terminal, which also handles the Al Hosn Gas sulphur granules.”

The Ruwais NGL fractionation plant creates four products: ethane, propane, butane and paraffinic naphtha. Another of GASCO’s facilities, Habshan 5, receives offshore gas from ADMA-OPCO via ADGAS for the production of sales gas, NGL and liquid sulphur. The Asab 1 plant processes condensate-rich gas with the condensate subsequently transferred to Takreer and the remaining gas transferred to Asab 2, where the sulphur and NGL are removed.

The third Asab facility – Asab 0 – is an NGL extraction plant serviced by associated gas from ADCO’s oil fields, with its product being sent for fractionation in Ruwais. Buhasa NGL plant also receives associated gas from ADCO. Of these facilities, Asab 1 and 2, the Habshan complex the Ruwais operation and the pipeline network are solely owned by ADNOC. However, the Asab 0, Bab and Buhasa facilities are JV assets, with ADNOC holding a total of 68%, Shell and Total 15% each and Partex 2%. “Cost optimisation is a major priority for GASCO,” Al Nasseri told OBG. “Over the next five years we are looking to optimise the total expenditure at both our ADNOC sole risk and JV assets, without compromising on either safety or asset integrity.”

Floating Regasification

In 2016 GASCO marked a new technological milestone when it took delivery of a floating storage and regasification unit that will help the company boost its input into the grid. The ship, which is supplied by Excelerate Energy, is capable of vaporising LNG, and it will have the capacity to add 500m scfd to the emirate’s supply, enough to power a city the size of Fujairah for a day.

Sour Gas Developments

ADNOC’s third and newest gas business is Abu Dhabi Gas Development Company, known widely as Al Hosn Gas, which has been operated as a JV with Houston-based Occidental Petroleum (Oxy) since 2011. Oxy holds a 40% stake in the company, which operates what it describes as the world’s largest sour gas development project – the Shah gas field. The project is being developed in three phases and by 2014 all 32 wells in phase one had been drilled, so that by 2015 the plant, which represents an investment of $10bn, was receiving 1bn scfd of raw gas and producing 500m scfd of sales gas for distribution to the network, as well as 4400 tonnes of NGL per day, 33,000 bpd of petroleum condensates and 9000 tonnes of granulated sulphur per day from four sulphur recovery units.

The gas in the Shah field is in a 60-km-by-11-km reservoir, which lies 8500 feet below the surface of the Empty Quarter near Liwa Oasis. It was first discovered in 1966, but the gas – which has a 23% hydrogen sulphide content – is highly toxic and was considered too dangerous to extract at that time. However, with advances in technology the project was deemed feasible in 2010.

In November 2016 ADNOC announced it would press ahead with an expansion of the facility that would increase capacity by 50%. This would make the company one of the world’s largest producers of sulphur. The statement gave a boost to ADNOC’s gas strategy following Shell’s announcement, in January 2016, that it planned to exit Abu Dhabi’s Bab sour gas reservoir project, citing the prevailing economic conditions in the energy industry. Shell had taken a 40% stake in the $10bn project for a 30-year period in 2013. According to BP’s “Statistical Review of World Energy 2016”, the UAE produced a total of 55.8bn cu metres of gas per day in 2015, a 2.8% increase on the previous year. Al Hosn Gas only reached full capacity in July 2015. Based on estimates by BP, this equalled 50.2 tonnes of oil equivalent per day, compared to UAE production of 175.5 tonnes of crude oil per day, giving the country a daily production of 225.7 tonnes of oil and gas.

Refining Boost

A key focus of ADNOC’s overall strategy is to improve the efficiency and profitability of its downstream activities and take advantage of the 2015 expansion of the Ruwais refinery’s capacity from 400,000 bpd to 817,000 bpd. Ruwais, located in the Al Dhafra Region, and a smaller 85,000 bpd refinery at Sas Al Nakhl, are run by Takreer, which accounts for 80% of the refining capacity of the UAE. The expansion boosted the country’s capacity by 61% from 2014 to 2015. Over the same period, the UAE increased its output of petroleum products by 34.6%, from 625,600 bpd in 2014 to 842,100 bpd in 2015, according to OPEC data. Although it took some time for the Ruwais expansion to take effect, with Reuters reporting in July 2015 that it was operating at 80% of capacity, as of March 2017 it was running at full capacity. “Ruwais West was designed for adaptability,” Jasem Al Sayegh, CEO of Takreer, told OBG. “The residual fluid catalytic cracking unit converts residue into lighter fractions like propylene, naphtha, LPG, and diesel, with an ability to make significant adjustment depending on the market.”

OPEC figures show that in 2015 the UAE produced 102,500 bpd of gasoline, 256,900 bpd of kerosene, 176,900 bpd of distillates and 26,100 bpd of residuals, with significant increases in production of petrol, kerosene and distillates of 17.6%, 42.3% and 43.5%, respectively, compared to 2014. Takreer’s eventual commissioning of its heavy oil conversion carbon black and delayed coker project will also help it respond to environmental pressures globally, including the compliance with IMO regulation for low sulphur bunker oil, which is targeted for implementation in the year 2020.

There are three other downstream businesses in the ADNOC portfolio: Borouge, which operates three ethane crackers, five polyethylene and four polypropylene plants and one low-density polyethylene plant; FERTIL, which operates two ammonia plants and two urea plants in the Ruwais complex; Elixier, which operates the Ruwais air separation unit providing gaseous and liquefied nitrogen to Borouge and liquefied nitrogen to ADNOC subsidiaries by tanker and the Mirfa nitrogen plant.

Speaking at ADIPEC in late 2016, Abdulaziz Abdulla Alhajri, director of refining and petrochemicals at ADNOC, said: “ADNOC’s ultimate goal is unlocking the full potential of all our assets. So, we are pursuing profitable and integrated growth in refining and petrochemicals. We are also diversifying our product portfolio to make us more resilient to economic cycles and crude oil price fluctuations.”

Outlook

In 2017 those oil price fluctuations would appear to be following an upward trajectory after a year in which historic deals were struck by OPEC and other producers to reduce output. However, industry forecasters are cautious about how high prices will increase, and some believe the shale revolution in the US may have helped create a new ceiling that could prevent the industry from returning to the boom prices of 2008 and 2014 that proved so profitable for Abu Dhabi.

Outlined in its 2030 Strategy, ADNOC envisages greater integration of its business units and a shift in emphasis to suit changing global markets for its products. After a year of consolidation and streamlining across the energy sector, the emphasis is not so much on considering the future post-oil, but on ensuring the emirate makes the most of its oil.