Thinking ahead: Ensuring flexibility with careful planning, partnerships, and long-term upstream and downstream investments

Having gone from being a minor actor on the world energy stage to a pivotal player in less than a decade as part of an expansive strategy, Qatar has tapped its vast gas reserves by engaging international oil companies (IOCs) and building a comprehensive infrastructure network. This approach, which has allowed it to become the largest liquefied natural gas (LNG) exporter in the world, has coincided with the steady rise of natural gas, and LNG in particular, as a viable and critical alternative source of energy globally. These trends have facilitated the emergence of Qatar as the wealthiest country in the world by GDP per capita, and have ensured that the hydrocarbons sector remains at the heart of the country’s economic success.

There is a moratorium in place on further development of Qatar’s vast North Field, part of the world’s largest non-associated natural gas field, suggesting that the rapid increase in hydrocarbons revenues seen in the past three years may be arrested.

However, the government still has plenty of plans for the sector, putting great emphasis on the need to diversify energy revenue streams. Its focus is set to shift from LNG, the country’s potential in liquids is likely to be maximised and future capital investment will focus on downstream petrochemicals initiatives.

STATE OF PLAY: Qatar has adopted a bold strategy to capitalise on its substantial hydrocarbons reserves. The country has 896trn cu feet of natural gas reserves – 14% of the world’s total – and the third-largest reserves globally, according to the Oil and Gas required an upstream investment of $1.2bn and downstream costs of $2.8bn for three LNG trains, was designed to produce 830m cu feet per day of natural gas and 50,000 barrels per day (bpd) of liquids upstream, and 6m tpa of LNG downstream.

Under the agreement, raw gas sales to the liquefaction plant were owned by the government, while the division of proceeds from the sale of liquids was determined by a production-sharing agreement. Gas was sold to the downstream sector at a fixed price of $0.50 per MB tu. The sale of liquids was subject to a 12% royalty, while the Qatargas partners would receive 77% of production of liquids during the first seven years, falling to 65% and eventually 55%. The foreign partners had the option to defer royalties and the payments for gas bought from the government at the beginning of the project to protect cash flows.

This agreement took more than eight years to realise but, once in place, it provided the industry with much-needed confidence to grow and a template for future operations. Indeed, a second agreement in 1999 was signed by Ras Laffan LNG (RasGas) with the Korea Gas Company for 4.8m tpa on a 25-year basis.

RasGas trains one and two became operational in 1999, delivering 6.6m tpa to South Korea. Between February 2004 and November 2006, RasGas added three additional trains, each with an annual capacity of 4.7m tonnes, and supply destined for India, Europe and Asia. Trains six and seven followed in 2009 and 2010, with supply meant for Europe, Asia and North America. This brought operating capacity to 36.3m tpa. Qatargas began adding additional capacity to its first three trains in 2009. By the end of 2010 it had built a further four trains, bringing the total to seven.

MORE ON THE WAY: Qatar has also rolled out this format to other projects, the latest of which is the Barzan gas project, confirmed in a signing ceremony between Qatar Petroleum and ExxonMobil in January 2011. The project, which will see the construction of two trains supplying 1.4bn cu feet of gas to the domestic market by 2015, will be built and operated by RasGas, making it the largest gas producer in Qatar, with offshore production of around 11bn cu feet per day, according to RasGas. The Barzan project will complement the Al Khaleej Gas project inaugurated in 2006, also operated by RasGas. The two plants (AKG1 and AKG2) have a production capacity of 2bn cu feet per day and pipe gas to domestic customers, including Ras Laffan Power Company, the Qatar Power Company, Ras Laffan Olefins Company and Oryx GTL.

The steady and rapid development of the LNG and pipeline gas industry has largely been built on the principles established in Qatargas’ first deal. The government maintains stewardship of the country’s resources and oversight of the operations through Qatar Petroleum’s majority stake in all ventures.

Upstream development and infrastructure expansion has largely been funded by external financing, commercial loans and foreign partner equity, with investment costs for IOCs recouped through the sale of liquids. Each operator has also looked to long-term contracts and a guaranteed level of demand before expanding. Most of these deals, however, have given the companies a significant amount of flexibility and a strong pricing model linked to the crude import price in a given export market.

The one exception is the project run by Dolphin Energy, a joint venture between Abu Dhabi’s Mubadala Investment Company (51%), Total (24.5%) and Occidental Petroleum (24.5%). The company transports gas from the North Field to customers in the UAE and Oman at a maximum throughput capacity of 2bn cu feet per day. Dolphin Energy buys the gas from Qatar Petroleum and funded its infrastructure investment through a revenue-sharing agreement with Qatar Petroleum on the sale of liquids from their production, a format similar to the market’s Qatari operators.

REAPING THE REWARDS: The agreements between Qatar Petroleum, the operating companies and IOC stakeholders have resulted in the industry’s rapid success. The country’s burgeoning hydrocarbons sector has brought significant opportunities for multinationals and plenty of work for services companies. Firms such as ExxonMobil secure a valuable share of their revenue from activity in Qatar. The level of foreign direct investment (FDI) into the sector has been substantial over the past decade. According to Qatar Statistics Authority, the hydrocarbons sector accounted for 51% of inward FDI, or $13.1bn, in 2009.

The government has also seen revenues swell, largely due to the success of its LNG strategy. According to the IMF, real GDP growth hit 19% in 2011, up from 17% in 2010, as a result of a 36% increase in LNG production. Between 2005 and 2009, Qatar’s nominal GDP grew at an average rate of 27%, according to Qatar National Bank (QNB). This was largely the result of expansion in the hydrocarbons sector and high commodity prices. Real hydrocarbons GDP grew at a double-digit rate in each of the five years up to 2010, with the exception of 2009, according to the IMF. In 2010 hydrocarbons GDP growth reached 28.8%. Additionally, gas revenue has played an increasingly substantial role in this growth, surpassing oil revenues for the first time in 2009, according to QNB. Hydrocarbons accounted for 62.1% of government revenues in the fiscal year 2010/11, while LNG revenues and royalties accounted for some 24.5%.

For the moment, though, the government has decided to pause for breath, sending out a clear signal that no new LNG projects are scheduled in the near term. It continues to renew a moratorium, first put in place in 2005, on further production and expansion of the North Field. As such, real GDP growth is expected to slow to 6%, with hydrocarbons growth coming in at less than 3%, as a result of the plateau in LNG production. The moratorium is currently in place until 2014 but could be extended, with the National Development Strategy 2011-16 alluding to this.

ASSESSING THE FIELD: While this is generally seen as sensible housekeeping, there are some concerns over the uncertainty this is creating and what it means for the field’s long-term health. Foreign operators have an isolated vision of the field, with QP being the only authority with a full picture of what is going on. Operators have expressed frustration that they do not know the reservoir levels, although they are well aware that it is an extremely mobile field and it is difficult to gauge what impact other producers’ wells are having on production. There is some concern that at the end of their production contracts, there may be some need for compression, raising question marks over the ability to extract over a long period of time.

The North Field – which shares the honour of being the world’s largest non-associated gas field with Iran’s South Pars – has long been considered one of the world’s most productive and cost-effective places to extract. “It’s easy to produce and cheap. This is one of the best fields in the world,” said Sawan. The 6000-sq-km field has a reservoir depth of up to 3553 metres, with an approximate thickness of 457 metres. The North Field is part of the Khuff Formation, which is composed of four zones – K1 to K4. Of these, K4 is thought the most productive and holds 60% of the gas reserves, according to RasGas. To date, this is where most of the activity in the sector has taken place.

However, the government is keen to assess the impact that rapid expansion is having on productivity to ensure it meets its target of 100 years of production. In 2006 Simmons & Company International estimated that all current gas LNG and gas-to-liquid (GTL) projects totalled 25bn cu feet of gas equivalent per day, giving the reservoir a reserve life of 97 years. The company also suggested that a murky picture is beginning to emerge of a more complex field that is non-homogenous and lacks full delineation. “It is generally assumed that developments to date have favoured the highly productive and liquids-rich zone 4 from the Khuff formation. This leaves a higher degree of uncertainty with regard to production capabilities from the shallower three zones,” the report said.

The field is also expected to become more sour, requiring further investment in cleaning the end product. However, this is relative and the North Field will remain significantly sweeter than other regional fields such as Abu Dhabi’s Shah Field, which has a sulphur content of 25%, compared to 2% in the North Field.

PRODUCTION POTENTIAL: Nonetheless, the general sentiment among operators is one of optimism for both the current productivity of the field and its future potential. There is also a sense that the moratorium is a reasonable step to ensure the field’s long-term health. If firms can increase the recoverable reserves by a modest amount with small enhancements and improvements, it would still make a big difference, and one that sector authorities are keen to see.

Qatar now has the infrastructure in place and the positioning in the market to rapidly bolster its production capacity should the government decide to lift the moratorium. Even when the moratorium is lifted, however, there is unlikely to be a rush of agreements for new projects. The government has been hinting that any expansion in natural gas production is likely to be absorbed by incremental improvements to current capacity. According to Saad Al Kaabi, the director of oil and gas ventures at Qatar Petroleum, “If we go for grassroots projects, we will have to set up new operating projects, meaning we will have new costs.” Rather, he said, upgrading existing facilities would be the “cheapest and most efficient way to expand”.

MARKET FOR GAS: In the shorter term, the focus seems to be largely on the domestic requirements for gas. According to the National Development Strategy 2011-16, QR130bn ($36bn) has been allocated for state-led construction development, including stadium and infrastructure projects for the 2022 FIFA World Cup, associated real estate developments, as well as other projects to support the country’s ongoing economic growth and diversification.

As such, Qatar’s power requirements are likely to remain strong over the coming years. According to Bart Cahir, the president and general manager of ExxonMobil Qatar, “This growth, and the desire of growing economies to continually advance living standards, requires more energy. To help meet this demand we are partnering with Qatar Petroleum to develop the Barzan gas project, which will play a key role in meeting future domestic gas needs and is crucial for the sustainable development of Qatar and the well-being of its citizens. The gas will be used for the additional power generation needed for a new airport and sea port, infrastructure projects in transport, health and education, not to mention the World Cup.”

Much of the 1.4bn cu feet produced by the Barzan project is expected to go to a power generation industry that was growing at a rate of 17% as of 2010, according to Qatar General Electricity and Water Corporation. As Qatar has one of the world’s highest rates of per capita electricity consumption, the demand for more generation capacity is unlikely to abate in the medium term. While some of the added capacity is expected to be generated by renewables, natural gas – which fuels all of Qatar’s power plants – is likely to remain the principal source of generation.

Exports also look likely to remain strong in the long term. For example, there is major potential for further expansion of the regional gas market. The UAE has such a high demand for gas – for both reinjection into its oilfields and for domestic energy generation – that it has been developing the Shah gas field, which is considered sour and technically difficult. Production costs have reached $5.50 per MB tu, compared to a pipeline price of $1.30 per MB tu from the Dolphin project, according to Oil Review Middle East.

This suggests Qatar will remain competitive and in high demand in the regional gas market. While there has been some decoupling in pricing between crude oil and LNG in the spot market over the past few years, global supply is currently tight and prices are high. With all of Qatargas’ capacity now on-line, it is looking to change the mix of the markets it sells to, and to sell LNG where it is needed most. This scenario may change in the longer term, with Australia expecting to push its LNG capacity up to Qatari levels by the end of the decade and the US considering its export options with the expansion of shale gas operations.

LOOKING TO LIQUIDS: Qatar is also trying to ensure it does not become overly dependent on LNG, with efforts being made to preserve revenues and diversify its hydrocarbons base. While it gets significantly less attention than the country’s natural gas production, Qatar has a substantial and important oil sector.

Indeed, in 2010-11, the government received 60.5% of its hydrocarbons revenue from oil, according to the IMF. This is largely the result of high oil prices, fuelled by tight supply and regional security issues. An average LNG price of $17 per MB tu in Japan, which is a price leader in the market, translates into a barrels of oil equivalent (boe) price of around $100.

With the Qatari crude oil price averaging $119 per barrel in the first quarter of 2012, and $125 per barrel for March, according to QNB, Qatar’s 25.4bn barrels of reserves will remain an important component of the hydrocarbons mix for some time to come.

However, the government is remaining cautious on the crude market’s prospects, with suggestions in November 2011 that Qatar may hedge some of its crude production in anticipation of falling prices. Mohammed Al Sada, the minister of industry and energy, told Reuters that the country is considering the move, which would see it follow Mexico in taking out insurance against falling prices precipitated by a sluggish global economy, the Eurozone crisis and rising Libyan supply. However, the crude price is likely to remain buoyant and provide substantial revenues to Qatar over the coming years.

PRODUCTION LINE: The country has been bolstering its production in recent years, climbing to 1.72m bpd in 2011 (including natural gas liquids), an 8.2% increase on 2010, according to BP’s “Statistical Review of World Energy 2012”. Qatar accounted for 1.8% of world production in 2011. However, with a reserves-to-production ratio of 45.2 years in 2010, the country has to fight increasingly hard, at significant cost, to push its production levels upwards. Indeed, its crude production has shown little movement, with a production level of 742,000 bpd in January 2012, up from 732,000 bpd a year earlier, according to the Joint Data Initiative. While there are other exploration licences going out, they are unlikely to translate into a significant change in production. Indeed, the North Field is likely to remain the runaway leader in both gas and liquid production for the foreseeable future.

INNOVATION: As such, Qatar has focused on maximising the potential of current reserves by introducing technological innovations from several international companies. A good example has been the exploitation of the Al Shaheen oilfield. Qatar’s largest offshore oil deposit, from which over 1.2bn barrels of oil have now been extracted, Al Shaheen was considered a commercial dead end for several decades.

However, after signing an exploration and production-sharing agreement (EPSA) in 1992, Maersk Oil has used high-precision horizontal drilling to access the reserves, drilling the longest well ever in 2008. Maersk Oil partnered with Qatar Petroleum and invested $6bn in its latest field development plan, which included the construction of 15 new platforms and drilling of over 160 new wells. The Al Shaheen field now produces one-third of Qatar’s total output.

In September 2011 Maersk Oil opened its new research facility at Qatar Science and Technology Park, into which it will invest up to $100m over the next 10 years. Applied research focus areas include increased oil recovery and enhanced oil recovery techniques. Such investments will undoubtedly support recovery from Qatar’s fields, but the difficulty and expense of these fields will remain a challenge, as the prospects for boosting production levels of crude on a long-term basis are somewhat limited. According to Stephane Michel, the managing director of Total Qatar, “In terms of oil, increasing production is going to be challenging, as the fields are declining at a rate of 3-5% per year. Qatar Petroleum has made it clear that they will not be giving any production lines to anybody else, so for IOCs it is just about helping Qatar Petroleum, while future opportunities are going to be in partnerships.”

CONDENSATES & GTL: The best opportunity for boosting production potential in liquids may come from natural gas liquids. According to Qatar Petroleum, the North Field has 30bn barrels of condensate, with at least 10bn barrels of recoverable condensate. The gas field is particularly rich in liquids and highly productive. According to the Pars Oil and Gas Company, the wider North Dome/South Pars field yields approximately 40 barrels of condensate for every 1m cu feet of gas. Given the current state of the crude market and the prices for natural gas liquids, these liquids are worth substantially more than the gas.

Due to the light nature of such liquids and their ability to be sold in the high-value downstream segment of the market, these condensates should be considered a substantial component of the country’s hydrocarbons potential. As with the global trend, in which condensate production increased from 7.4m boe per day in 2000 to 9.4m boe per day in 2009 – accounting for 11% of global oil production, according to Wood Mackenzie, an energy consulting firm – Qatar has been looking to exploit its condensate potential.

A recent report by Reuters stated that Qatar expects to increase its exports of liquefied petroleum gas (LPG), one of the major condensate products, to 11m tonnes in 2012, up from 10m tonnes in 2011, and by 2013, the country is expected to export 12m tonnes. Qatar has also made significant efforts to boost sales from condensates by expanding refining capacity.

For example, the Laffan Refinery, Qatar’s first condensate refinery, began production in 2009. The project is majority owned by Qatar Petroleum (51%), with the minority stakes taken by Total (10%), ExxonMobil (10%), Idemitsu (10%), Cosmo (10%), Mitsui (4.5%) and Marubeni (4.5%). The processing capacity is currently 146,000 barrels per stream day (bpsd), including naphtha (61,000 bpsd), kerojet (52,000 bpsd), gasoil (24,000 bpsd) and LPG (9000 bpsd). Qatargas, the operator of the refinery, has plans to double its capacity by 2016, with the engineering, procurement and construction contract expected to be awarded in 2012. In August 2011 Technip won the contract for the front-end engineering design for the expansion.

The government has also invested specifically to increase its liquid sales and diversify its hydrocarbons exports. The main project in this regard was the Pearl GTL plant, a $22bn joint venture investment between Qatar Petroleum and Royal Dutch Shell.

The project, which began operations in 2011, is the largest plant of its kind in the world, with per day production of 140,000 kg boe of GTL products and 120 kg boe of natural gas liquids. The plant will take approximately 3bn boe of natural gas from the North Field over the life of the project and turn it into high-grade diesel, kerosene, naphtha and lubricant oils. This follows on the heels of the Oryx GTL project, a joint venture between Qatar Petroleum and South Africa’s Sasol, which has a capacity of 34,000 bpd.

While energy is also lost in the liquefaction process of LNG, it is at a much lower level than GTL. However, with the current oil price, and the premium that can be charged for this high-grade diesel, often called white oil, the project is likely to be lucrative. Indeed, the payback period on the Pearl GTL plant could be as little as 2-2.5 years at current oil prices. Shell seems confident that this is a wise move by the government. Sawan told OBG, “What we are trying to do in GTL is capture the maximum value with our product and sell it at a premium. It takes time to get the depots and the contracts, but there is huge potential.”

RENEWABLES: These innovative moves to squeeze the largest returns from the country’s hydrocarbons reserves will be supported by a strategy laid out in the Qatar Vision 2030 to turn to renewable energy and solar power in particular. The government has not put any firm targets on renewable usage, but has made it a key priority over the coming decade.

While a number of companies, including Chevron, are working on the commercial viability of different solar technologies, there are other considerations. According to Omran Hamad Al Kuwari, the CEO of Green Gulf, “It’s not just an economic issue, but also a strategic one.” The government is looking to the long-term future of energy security on the peninsula as well as the short-term economics, with a strong opportunity cost associated with solar energy providing savings on natural gas usage in the domestic market, thus bolstering export revenue gains.

OUTLOOK: This development is an indicator of the growing confidence and maturity of the sector and how the government is developing a considered stewardship of Qatar’s hydrocarbons resources. Emerging as the largest producer of LNG in the world has put money in the government coffers and a spring in its step. Through its partnerships with IOCs, the government has invested strategically in both the upstream and downstream sectors. A framework that has brought substantial levels of FDI and the best technologies has served the country well. The LNG market, which Qatar pioneered to a large extent, should provide strong revenues in the medium term, while in the longer term, the country has the flexibility and resources to react to any adverse market conditions.

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