A fledgling industry: While oil is now flowing, questions about sustainability, long-term development and resource maximisation remain

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The transition from energy “nobody” to an important regional player is reaching a crucial phase in Ghana. Since the discovery of offshore oil in June 2007, the government has made a number of decisions to reach oil production in just 42 months, the quickest turnaround in the history of the modern energy sector. However, the decision-making process is far from over and since the first lift of oil was greeted with much fanfare in December 2010, production has begun to backslide, raising worrying questions about the long-term sustainability of the country’s offshore deposits and the potential costs to producers.

As such, the government is still wrestling with a number of key concerns, ranging from the future terms of engagement with international oil companies to how to best to utilise oil and gas reserves to fuel sustainable growth at home. While much of this should be answered in the next 12 months, these broad questions, as for all developing countries with hydrocarbons reserves, are likely to recur for years.

Still, the economic benefits that the newfound resource will bring to the larger economy cannot be overstated. “The oil discovery provided significant spin-off opportunities for the supporting services. Oil rigs need food, laundry, housekeeping and logistics services, and would much rather outsource these services,” Maud Lindsay-Gamrat, the general manager for the catering firm Newrest Ghana, told OBG.

ECONOMIC SHIFT: What is already clear, however, is that the discovery of oil and gas has significantly altered the prominence of energy in the Ghanaian economy in a very short space of time. The mining and quarrying sector, which includes crude oil production, increased by 207% in real terms in 2011. Indeed, crude oil output alone accounted for 6.8% of GDP in 2011, the first year of hydrocarbons production, according to the Ghana Statistical Service.

With production expected to be increased to 120,000 barrels per day (bpd) in the coming year, from a figure of 60,000-65,000 bpd in June 2012, the prospects for hydrocarbons to play an even greater role in the country’s economic growth are strong.

OIL IMPACT: A January 2012 working paper for the International Growth Centre by three Oxford academics, Rick van der Ploeg, Radoslaw Stefanski and Samuel Wills, estimates that the current oil find has the potential to generate $1.8bn per annum at the peak of production, based on field and production forecasts from Tullow Oil, the lead operator of Ghana’s Jubilee Field. Although Ghana’s reserves are minor in global terms, in absolute and per capita terms, they have the potential to represent a significant proportion of GDP. According to the paper, Ghana will rank 15th in the world by barrels of oil per dollar of GDP, approximately on par with Nigeria and Angola. At peak production, the oil find is expected to generate as much as 30% of the government’s income at an estimated price of $75 per barrel. With more finds in the appraisal stage, these forecasts are expected to grow substantially over the next five years.

While this is obviously good news for the government, it also bodes well for international operators producing from the Jubilee Field (Tullow Oil, Kosmos Energy, Anadarko Petroleum, and Sabre Oil and Gas, alongside the government-owned Ghana National Petroleum Company (GNPC). This is particularly true as more is revealed about the properties of the country’s hydrocarbons deposits and the potential pricing of Ghanaian crude in the international market.

TULLOW & KOSMOS: The oil and gas deposits now producing in commercial quantities were found in two separate exploration blocks, Deepwater West Cape Three Points and Deepwater Tano, 60 km offshore. The blocks were first operated under separate agreements by the US’s Kosmos and the UK-based Tullow Oil, respectively. However, they were later found to be in pressure communication and are considered to be in the same reservoir and it was christened the Jubilee Field in recognition that the discovery was made in the 50th year of Ghana’s independence.

SHARED SOURCE: Under a July 2009 unitisation agreement, Tullow was appointed as the unit operator, while Kosmos became the technical operator for development of Jubilee. The holders’ interests in the field broke down as Tullow (34.7%), Kosmos (23.49%), Anadarko (23.49%), GNPC (13.75%), Sabre Oil and Gas (2.81%), and EO Group (1.75%). In May 2011, EO Group was bought out by Tullow after the Ghanaian firm had failed to pay its share ($62m) of operating costs for the field, raising its stake to 36.5%. In March 2012, Kosmos agreed to buy out Sabre Oil and Gas’ interest in the Deepwater Tano Block, at an estimated purchase price of $365m, a result that would have taken its share in the Jubilee Field to 25.8%, but the agreement was subsequently terminated in May 2012. The first equity redetermination for the Jubilee unit was conducted in October 2011, bringing the shares in the field to 35.48% for Tullow and 24.08% for Kosmos.

QUALITY & QUANTITY: A 2008 appraisal of the Jubilee Field by GNPC found that it contains recoverable reserves at 90% probability of at least 800m barrels of crude, with an upside potential of 3bn barrels. In July 2012, the Ministry of Energy (MoE) told OBG that, according to its most recent estimates, the upside potential remains unchanged at 3bn barrels, but the recoverable reserves have increased to approximately 1.2bn barrels. This is a good sign for the country and tends to support the assumption of many analysts, such as Kofi-Agyeman Boakye, executive director of Emos Consultancy, a firm that has advised the government on energy-related issues, that the field and Ghana’s total offshore reserves will progress steadily upwards over the coming years. James McDougall, managing director of Baker Hughes, is also optimistic about the prospects. “There is still a lot of untapped potential in Ghana, as a couple of the licences have not yet been explored,” he told OBG.

Perhaps equally as important, studies suggest that Jubilee crude has a light and sweet quality and should price well in the international market. According to initial assessments by Tullow, it is a low-viscosity, or “thin” oil with an American Petroleum Institute (API) gravity of 37°, meaning it is lighter in weight than water, (although further assessments from the Mahogany 2 well gave an API of 39°). This is similar in gravity to Brent crude oil (API of 38°), which is a major classification of sweet light crude oil, and light enough to price well. It is also sweet, with a sulphur content of just 0.25%, much lower than Brent crude (0.45%), suggesting that it may have a price advantage over the benchmark rate when sold.

While there are suggestions on paper that in the longer term Jubilee crude is likely to sell at a margin above Brent, it may take some time for a stable fair value for the product to emerge. Responding to press reports in January 2011 that the first liftings of Jubilee crude were selling at a significant discount to the Brent benchmark (below $90 per barrel), in a joint statement Tullow Oil and Vitol Oil, the marketers of the product, vehemently denied this, stating, “It takes a while for the market, and refiners in particular, to assess the fair value of any new crude oil, since ultimately its value reflects the actual yield and quality of products that a refiner obtains as compared with its formal technical and paper yield.”

THE RIGHT PRICE: In June 2012, it was still difficult to establish the fair price of Jubilee crude, with the MoE also remaining cautious of the potential for its product in the international market. According to Edem Wordi, an adviser with the Petroleum Directorate of the MoE, “The last time GNPC sold, the price had risen to between $100 to $110 per barrel as determined by Platts. However, we are still carrying out the chemical analysis on Jubilee crude. I’m not sure when it will be complete, but we can expect a clearer idea on pricing after this.”

Nonetheless, Kosmos reported in its 2011 annual report an average realised price per barrel of $111.70 for the year in Ghana, compared to an average Brent spot price of $111.26 per barrel for the year, according to the US Energy Information Administration.

The pricing signs in the longer term are positive, a situation that should help operators’ margins, especially given the general initial optimism over the field characteristics and the cost of production. An initial appraisal of the field characteristics by Tullow Oil included porosity over 20%, permeability of 200+ millidarcys and a net oil pay of 40-100 metres in the reservoir. Initial flow rate tests were also positive, with a January 2009 test on Tullow’s Hyedua-2 well recording a stable rate of 16,750 bpd, a vast improvement on initial flow rates of 4448 bpd and 5200 bpd on the Mahogany 2 well. Tullow believe that the Hyedua-2 well, located in the Deepwater Tano block at a depth of 1246 metres, will be able to produce over 20,000 bpd in future. As the well lies on the north-west periphery of the field, flow rates could be even higher in its core, according to comments made at the time of the appraisal by Gerry Hennigan, an analyst at the Irish stock brokerage firm Goodbody.

PRODUCTION COSTS: With such output, the cost of production from the Jubilee Field is likely to be highly competitive. According to the MoE, the cost is $14 per barrel, a welcome figure for a deepwater reservoir. According to a 2009 Reuters report, production in the ultra-deepwater Nigerian fields can reach $30 per barrel. Nonetheless, Ghana’s low cost figure does not take into account the costs of exploration or other expenses associated with development.

According to the Kosmos 2011 annual report, while the operating cost of production from Ghana was $13.99 per barrel, the total cost of production, including all capitalised and expensed costs for oil and gas property acquisition, exploration and development came to just over $100 per barrel in 2011. This will undoubtedly decrease as more barrels are produced and initial exploration and development costs are absorbed. Nonetheless, it represents a significant outlay compared to a more mature African market, such as Angola, where the offshore cost of production (operating and capital expenses) was $40 per barrel in 2009, according to Reuters.

Moreover, as with all deepwater production, 1100-metre-deep Jubilee Field is technically challenging and has presented more difficulties than first anticipated. Tullow Oil has yet to reach the Phase I target of 120,000 bpd, a goal that has been pushed back and is now expected to be achieved by 2013. According to the Wordi of the MoE, in June 2012, the field was producing roughly 60,000-65,000 bpd, while the maximum daily output achieved since production began has been 90,000-95,000 bpd.

MEET THE PRESS: The local press has made much of this, suggesting that the field’s complexity and difficulty had been underestimated and that production targets – which were originally projected to reach 250,000 bpd by 2013 under Phase II of the project – may never be reached. A July 2012 report by the IMANI Centre for Policy and Education, a local think tank, argues that Ghana’s oil production is actually declining and that production may begin to fall to 45,000 bpd in 2013. The IMANI report does take note of Phase I A, in which Tullow will drill new wells in an attempt to stabilise production at 120,000 bpd, but suggests that while it may push production above 80,000 bpd in the short term, there will be further regression. The report likens the Ghana find to other offshore West African finds, such as those in Côte d’Ivoire and Cameroon, where initial production estimates failed to materialise in the long term. However, the MoE remains sanguine about these issues. Wordi told OBG, “We are currently facing technical issues with sand migrating into the well bore. These are the problems that Tullow is facing and this is the main reason we have seen production decline.” But he said that “measures are in place” to remedy this situation, and the 120,000 bpd production is anticipated by 2013.

DEVELOPMENT: Indeed, Tullow’s Phase I remedial work, including acid stimulations and recompletions of some of the underperforming wells, began to take effect in the first quarter of 2012, while the firm also began to execute the $1.1bn Phase I A development, following government approval in early January 2012. It consists of eight new wells, five producers and three new water injectors, which are due to be completed over an 18-month period. These measures should help production to move up towards the 120,000-bpd Phase I target, with Tullow expecting production to average 70,000-90,000 bpd in 2012.

While these new developments should go some way towards rectifying the production decline, they also raise questions about the costs of production at the Jubilee Field and the margins that operators are able to earn. According to IMANI, the finding costs, or how much an oil company needs to expend to explore and develop new reserves, “appear outsized in comparison with similar projects elsewhere. Both on a preliminary proven reserves and daily production basis, capital expenditure at the Jubilee Field appears to suggest a fundamental lack of competitiveness that requires additional study.”

However, IMANI has not provided data that supports this assertion and statistics from the 2011 annual report of the Public Interest and Accountability Committee, a government body established under the Petroleum Revenue Management Act 2011, suggest that Ghana is highly competitive on cost. The report shows that finding costs for the Jubilee reserves were approximately $6.92 per barrel, compared to the international average for Financial Reporting System companies of $18.31 per barrel of oil equivalent.

Perhaps the best indication that Ghana is a cost-effective place to produce is the strong level of interest in further exploratory and development drilling. In a July 2012 interview with Bloomberg, GNPC’s CEO, Nana Boakye Asafu-Adjaye, said that it would invest $20bn to develop newly discovered oilfields over the next decade in conjunction with its partners, Tullow, Kosmos, Anadarko and Sabre. Indeed, since the discovery of the Jubilee Field in 2007, a number of further finds have been made including Tweneboa (oil and gas condensates) in January 2010, Enyenra (light oil) and Ntomme (light oil), all in the Deepwater Tano Block operated by Tullow (49.95% share) and grouped together as the “TEN complex”.

OTHER FINDS: There have also been further finds in the West Cape Three Points block, operated by Kosmos, at Mahogany (2008), Teak, Akasa and Banda (2011). Appraisal is still ongoing for these fields, but a plan of development for the TEN complex should be submitted to the government of Ghana in the third quarter of 2012, according to SubseaIQ, an offshore oil information service. Production is expected 30 months after approval at a level of around 100,000 bpd. Indeed, by the end of 2012, there could well be a dramatic upward revision in both Ghana’s reserve levels and future production forecasts. According to Emos Consultancy’s Boakye, from current finds, Ghana can expect to be producing 425,000 bpd by 2015. However, the MoE remains cautious and tight-lipped.

Wordi told OBG that the ministry expects a cumulative production of 220m barrels of oil by 2015, which works out to approximately 120,000 bpd from the commencement of production in 2010. Nonetheless, Wordi does concede that the achievement of this will depend on how the exploration and appraisal work proceeds. “The assumption is that there are going to be quite a lot of oil finds out there. There are a lot of finds currently under appraisal.”

INVESTING OFFSHORE: This has led to significant interest in Ghana’s offshore potential as other investors eye the market. Since the 2007 discovery, a number of firms, including Vitol Upstream and a consortium of Eni, Afren and Mitsui in the Keta Basin, near the maritime border with Togo, have entered into new petroleum agreements for exploration in Ghanaian waters. Furthermore, the interest shows little sign of abating. For example, PetroSaudi International signed a memorandum of understanding with the GNPC for joint ventures in oil and gas exploration, development and production in August 2011. Although in the intervening year no additional details have been disclosed, it is anticipated that the market will begin to open up to other upstream players.

One such firm could be South Africa’s PetroSA, with the government-owned group stating in July 2012 that it was in talks to buy Sabre Oil’s Ghanaian assets, including its 1.7% stake in the Jubilee Field. One potential issue for new investors is the terms of engagement, with the government under increasing pressure to adjust revenue sharing agreements and taxation policy to get more direct income from oil production. With several finds in place and less exploration risk, future agreements with upstream companies may be less appealing than those enacted for the current Jubilee operators (see analysis).

LOOKING ASHORE: While the current focus is on the offshore prospects, in the longer term attention could turn onshore. Wordi said, “In the Volta Basin, we have 108,000 sq km to explore. GNPC is seeking investment for this, but it still needs to do an environmental impact assessment. It is currently not open for exploration, but an initial exploration funded by the EU has been carried out.” Although it is very early to assess the onshore resource potential of sites in Ghana, a 2008 study by Nikolay Bozhko of Moscow’s Lomonosov University, presented at a workshop funded by the EU-backed Mining Sector Support Programme under the auspices of the Ghana Geological Survey and the Water Resources Commission, noted that, “the Voltaian Basin displays favourable general preconditions for its oil potential and deserves further investigation, primarily 3D seismic exploration.”

According to Wordi, “The GNPC wants private investment and partnership to accomplish seismic exploration.” However, this is likely to be a longer-term ambition. In the short term, the government is more concerned about putting the infrastructure in place so that the country can fully benefit from the current oil and gas find. This not only includes revisiting the revenue agreements with investors in the sector (see analysis), but also improving mid-stream and downstream physical infrastructure.

NECESSARY INFRASTRUCTURE: The most pressing matter in this regard is the development of gas processing facilities. The Jubilee Field is rich in associated gas, with 1.2m standard cu ft (mmscf) of gas for every 1000 barrels of oil produced, according to Tullow. Up to this point, Tullow has been reinjecting the gas into the reservoir in order to maintain pressure for pumping the oil out, with minimal gas flaring. However, the company has said that sending gas back into the reservoir beyond December 2012 could damage the field and harm its future productivity.

As such, with the government’s commitment to a no-flaring policy, the Ghana National Gas Company (GNGC) is in a race against time to get the infrastructure in place to pipe and process the wet gas by the end of the year. “The development of our country’s gas reserves is considered extremely important, as we are aware that the current practice of re-injecting will have a limited timeframe.” Yaw Akoto, the managing director of Bulk Oil Storage and Transport (BOST), told OBG. According to Chris Chinebuah, the executive chairman of Fueltrade, a local fuel trading firm, this is a serious challenge. “The deadline for the completion of gas infrastructure is tight, however, there is no alternative. Stopping oil exploration because of the flaring or reinjection is inconceivable. One way or another, the country will have to do it,” he told OBG.

With such a quick turnaround to first oil production, the question of how to build the necessary infrastructure for the associated gas has been one of the most difficult to answer. The original outline of what is necessary was in place for some time. During Phase I of production from the Jubilee field, a pipeline would be constructed to take gas to Effasu in the Western Region, supplying 30-50 mmscf of gas to feed the Osagyefo thermal power plant, with the remainder of the gas being reinjected into the field. During Phase II, when oil production is expected to reach 250,000 bpd and gas output 250 mmscf, another pipeline is to be constructed that will take the gas to Takoradi, supplying the Aboadze power plant and other industries. However, the announcement of the infrastructure plans in November 2011 revealed changes to the strategy, with a decision to relocate the gas processing plant to Atuabo, reducing the required pipeline length by 23 km. The plant will produce lean gas, propane, butane, liquefied petroleum gas (LPG) and condensate. Under the new plan, an onshore pipeline will be constructed connecting the facility to both the Takoradi thermal power plant in Aboadze and to the mining centre of Prestea.

FINANCING OPTIONS: It would have been possible to seek private investment for the infrastructure, however, the government made a decision early in the process to retain control of the gas supply chain so that it could use the resource to drive the country’s growth strategy. According to Boakye, “There is a logic that if you want to drive an industrial application, if you want to mandate or incubate a certain industry, then you have to determine at what price this can work. And if you are going to do these things, you have to have government ownership in gas production so that you can drive decisions forward.”

Therefore, the government established the GNGC in July 2011 and, under the auspices of the company, has been looking at ways to finance the necessary gas infrastructure. The initial negotiations with the national gas company of Trinidad and Tobago broke down in 2011 and since then the government has been focusing on using a portion of a $3bn China Development Bank (CDB) loan facility, secured in August 2011, for financing the pipeline and the processing plant. This was confirmed in February 2012 when parliament approved a subsidiary agreement with the CDB for $850m to finance the Western Corridor Gas Infrastructure Development Project (WCGIDP). The WCGIDP includes the construction of a processing plant for the gas and a submarine pipeline.

BEING PREPARED: Given that this agreement came less than 10 months before the gas would need to start being transported away from the field, there has been some concern that the infrastructure will not be in place in time for the field to produce, leading to output disruptions. However, the MoE is confident that the deadline will be met. According to Wordi, “The first gas is expected by the end of 2012. About 14 km of the deep-sea pipeline has already been laid, so we now have about 50 km to lay for the shallow-water component.” The MoE told OBG that the country will be producing 150 mmscf of gas per day from the first gas in December 2012.

In many ways, this gas will be more important to the economic development of the country than the oil. Indeed, the government strategy is based around using gas to drive industrial diversification and economic growth. As Wordi told OBG, “Once the gas has been processed, some will be given to the Volta River Authority (VRA), some will be given to the petrochemicals industry and we will send some to the national refinery for reprocessing into LPG.

However, initially the gas will be going to the VRA to fire turbines for electricity.” This is expected to allow the government to comfortably meet the country’s electricity demand and potentially bring down electricity prices for end-users, as they can sell the feedstock to generators at a discount (see analysis).

POWER UP: Yet, this supply has to reach the population. “The government is quite determined to extend the reach of rural electrification,” Charles A Darku, the CEO of the transmission firm Gridco, told OBG. “This means extending the high-voltage network deeper into the country to reduce the length of distribution lines and reduce losses across the network.” To that end, Gridco is constructing a $29m-30m substation in Kintapo. Boakye estimates that the country will produce approximately 5000 MW from natural gas-fired power stations by 2015. “The priority is to facilitate gas use for electricity. Ghana gas is going to the power sector until all the needs are met here. After that, all options are possible,” he told OBG.

Until now, oil production has been directly exported for refining. While the managing director of the Tema Oil Refinery, Ato Ampia, told local press in June 2012 that Jubilee crude could soon be refined there, it is regarded as unlikely that the government will implement the ‘right-to-access’ clause it has listed under the petroleum agreement with the operators, which gives it the ability to purchase the Jubilee crude at the prevailing international price.

EXPORTING: Rather it seems more likely that most of Ghana’s oil will be sold on the international market. Kwaku Agyemang-Duah, CEO of the Association of Oil Marketing Companies, the body representing the firms selling in the local market, said, “Basically, we wish we could have [oil production] for domestic use, but it is not being processed down here.” One of the key impediments to bolstering local supply is the limited and unreliable refinery capacity. The refinery at Tema currently produces 45,000 bpd but the long-term goal is to increase this by 160,000 bpd to 205,000 bpd through private investment.

In the shorter term, however, as Agyemang-Duah said, “We are having a refinery issue, because it is not capable of responding to demand.” The country must import 46% of its refined products consumption, according to Agyemang-Duah, and in some months marketers have to rely 100% on imports because of shutdowns at the Tema Oil Refinery (see analysis).

Furthermore, while local distributors and marketers may be keen to get access to Ghana’s oil, the government is unlikely to take up much crude for domestic use, as it would rather boost revenues by selling its supplies on the international market.

According to Wordi, “It is a matter of economics. Why would you want to use a high level crude that can bring in more money to the economy when you can use a cheaper crude that our refinery is configured to crack?” The catalytic cracker at the Tema Oil Refinery is already configured to crack heavier oil with more sulphur than the Jubilee product.

In May 2012, the local press reported that Ghana had struck a 15.5-year deal with Unipec, the largest oil trading firm in China. Unipec began marketing Ghana’s share of Jubilee crude internationally during January 2012. This deal was part of the agreement for a $3bn loan facility from the CDB, and came after the GNPC decided that it would not be renewing the contracts it held with Vitol and Woodfields, which were permitted to expire in 2011.

While the government is keen to get a higher price for its crude on the international market, it is also aware of the potentially destabilising effect that price fluctuations can have both on the local economy and on economic planning. To mitigate the risks posed by volatility, the minister of finance and economic planning, Kwabena Duffuor, announced in his November 2011 budget speech that the country’s hedging programme was expanded in May 2011 to include petroleum reserves and that 100% of anticipated receipts of Ghanaian crude sales would be hedged at $107 per barrel until the end of 2011.

DISTRIBUTION: With the additional oil output, improving fuel distribution has become a more pressing priority. Traders of various oil products – crude oil, petrol, automotive gas oil, kerosene, aviation turbine kerosene, liquefied petroleum gas, and residual fuel oil – are all working to expand their storage and transport capacities. Currently, the national capacity for fuel storage is 340,000 cu metres, the equivalent of six weeks worth of consumption. FuelTrade operates two 40, 000-cu-meter gasoil tanks, one gasoline storage tank (40,000 cu metres), and two market tanks (5000 cu metres each) for gasoline. Meanwhile, Cirrus Oil operates two petroleum terminals, one in Tema and the other in Takoradi. BOST is also expanding capacity, with a tank farm under construction and a contract from the government to add 50,000 cu metres of capacity. The government intends to have three months of strategic stock for petroleum on reserve.

LOCAL INVOLVEMENT: The oil and gas sector is not a large-scale employer, but the government does work to maximise the involvement of nationals in the industry. Stephen Kermah, the managing director of Genesis Oil and Gas Services, told OBG, “We need more Ghanaians involved in the industry, particularly at the level of support services, where there are more opportunities for job creation.” The deputy minister of energy, Inusah Abdulai Fuseini, told parliament in June 2012 that of the total of 1500 jobs created in the industry, some 840, or 57%, were filled by Ghanaians, with the remainder going to expatriates.

In addition to employing more Ghanaians, the government is also working to increase the involvement of local companies in the sector. According to Christian Ibeagha, an oilfield service manager at Schlumberger, oilfield services provider, this process needs to be handled carefully. “The government wants the industry to transfer more and more activities to local companies, but the complexity of the discoveries will require a high level of technical expertise. This transfer to local enterprises and expertise needs to be managed carefully; otherwise the costs of development can become too high,” Ibeagha told OBG. He also said that there are opportunities in areas like onshore production, which is a less technically challenging segment where local players could develop their skills.

OUTLOOK: The discovery of oil and gas has completely changed the energy sector, providing opportunities for growth and development. Nevertheless, with the rapid turnaround to production, the government and the international field operators are facing a host of challenges, from technical difficulties to infrastructural roll-out. Most of these challenges are being addressed by the players in the sector and the industry is expected to have a very different appearance in the next five years, with more finds developing and natural gas fuelling growth. This suggests that the scepticism about the potential of Ghana’s hydrocarbons reserves is likely to give way to optimism on the part of both the government and investors.

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The Report: Ghana 2012

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