Even amid the low global oil price environment, Ghana’s energy sector continues to evolve in a positive fashion, with deregulation implemented in the downstream sector and two new oil and gas fields coming on-line. The long-awaited benefits of the country’s oil and gas reserves are also beginning to be felt by the power sector, with the government looking to boost capacity of electricity generation across the country to 5000 MW. This goal will take time but has driven policymakers to expand facilities and operating capacity, tapping both offshore gas and renewable energy sources.
Oil exploration in Ghana dates back over 120 years to when the West Africa Oil and Fuel Company made the first discovery. However, it was not until the late 1960s that exploration shifted from onshore to offshore, and in 1978 Ghana’s first commercial offshore production occurred in the Saltpond field. In 1983-84 the country passed its first petroleum laws, establishing Ghana National Petroleum Corporation (GNPC) and providing a regulatory framework to expedite exploration and production (E&P).
For the next couple of decades small oil and gas deposits were discovered, but none were significant or sustainable until 2007, when Kosmos Energy discovered large quantities of commercially viable oil in the West Cape Three Points Block, now known as the Jubilee field. Development and operations at Jubilee were granted to one of Africa’s leading oil companies, Tullow Oil, and production began at the end of 2010. Production did have to clear additional hurdles, including slow progress on downstream gas infrastructure and technical problems that limited oil output.
Against some of Africa’s larger exporters, Ghana is a comparatively modest-sized oil and gas producer, with an estimated 898m barrels of oil and 2.02trn standard cu feet (scf) of gas reserves, primarily in deepwater fields, according to figures from the Public Interest and Accountability Committee (PIAC) 2015 annual report. The Jubilee field produced a total of 37.4m barrels of oil and 52.5bn scf of associated gas in 2015 and Saltpond saw an overall output of 41,113 barrels for the same year, according to data complied by the PIAC. More than 10 companies are currently investing in the development of the country’s hydrocarbons fields, and in July 2016, on the sidelines of the Maritime Week Conference in Accra, Michael Aryeetey, the COO of a subsidiary of GNPC, EXPLORCO, told local news media that there were approximately 17 licences that are active offshore in the country.
As the oil sector has continued to expand, so has its overall share of GDP. The value of the country’s oil exports has declined sharply in the past two years, with earnings dropping 42.3% to $6.9bn between January and October of 2015, compared to the same period in 2014.
From the start of commercial production in 2011 until 2015, Ghana’s oil revenue totalled $3.2bn, according to the PIAC. However, the drop in oil prices globally has been a major shock to revenues. The price of oil fell around 50% between mid-2014 and early 2015, drastically reducing Ghana’s derived revenue. According to the PIAC, petroleum receipts in 2015 totalled $396.2m, roughly 46% below the revised projected revenue and around 60% lower than 2014 earnings. None of the country’s downstream petroleum products met the stated revenue projections either.
The Ministry of Finance and Economic Planning (MoFEP) is expecting an estimated $502.1m in revenue from the petroleum sector in 2016, a reduction of more than 50% from the 2015 projection of $1.24bn. Not only has revenue declined sharply, but actual payment has been stifled as well. According to the PIAC, just 0.7% of the $79.06m earned in gas export revenue and 39% of surface rentals, or $466,000, were paid by the end of December 2015. While oil prices have recovered occasionally over the past few years, few experts believe prices of $90 to $100 per barrel will return any time soon (see analysis).
Oversight & Regulation
A number of entities are responsible for managing Ghana’s oil industry. The Ministry of Petroleum (MoPET) is charged for formulating and evaluating Ghana’s overall energy sector policies, while the Petroleum Commission (PC) regulates and manages upstream projects. Closer to operations, GNPC explores oil and gas fields independently, and then partners with other companies for E&P works. The Ghana National Gas Company (Ghana Gas) builds, owns and operates the government’s infrastructure for gathering, processing, transporting and marketing natural gas. In 2014 the government announced that GNPC would become the sole shareholder of Ghana Gas in order to develop a more streamlined management structure for the county’s resources.
For over 20 years the petroleum sector in Ghana was governed by two laws: GNPC Law 64, which allowed for exploration, and the Petroleum E&P Law, which provided the legal basis for petroleum contracts. When oil was discovered in 2007, the laws were updated to strengthen revenue allocations, introduce health and safety regulations, improve data collection, encourage private participation and add local content rules.
The end result was the 2011 Petroleum Revenue Management Act (PRMA). This law ensures transparent and accountable management of Ghana’s petroleum revenues and requires the MoFEP to present a report on updates in the sector to Parliament each year. The PIAC was also established under the PRMA to ensure compliance. It is a 12-member body representing a variety of industry stakeholders, ranging from the Ghana Academy of Arts and Sciences and Ghana Bar Association to the Trades Union Congress, among others.
In August 2016 the Petroleum E&P Law was updated to improve oversight of the upstream sector, attract additional investors and continue expanding the sector. Transparency is one key focal point: the new regulations require the minister of petroleum to publish invitations to tender or enter negotiations through a number of public communication systems, and oblige the PC to publish a Petroleum Register of licences and agreements in the public domain.
Ghana has three sedimentary offshore basins and one inland basin. The TanoCape Three Point/Western Basin is an eastern extension of a basin in Côte d’Ivoire and where the Jubilee field was discovered in 2007. Most of Ghana’s current extraction activity takes place in this area. To its east lies the Saltpond/Central Basin, covering roughly 12,000 sq km and home to the country’s first commercial field. However, the site offers only limited amounts of commercial production; the field produced around 3.5m barrels at its peak in 1978, dropping to 41,113 barrels by 2015. GNPC, which operates the Saltpond field, has made plans for its decommissioning. The third offshore area is the Accra-Keta/ Eastern Basin, covering around 33,000 sq km, 1900 sq km of which are onshore. This area encompasses the western portion of a basin that runs along the coast of Togo, Benin and Nigeria. Ghana’s deepwater environment is made up of mainly stratigraphic play system with hard and interbedded formations. As a result, there are higher operating costs due to the difficulty of exploration, increased risk and a lack of deepwater drilling rigs. “Drilling in deepwater is substantially more expensive. You can drill a well onshore for hundreds of thousands of dollars, but offshore needs millions,” Sam Eshun, corporate affairs manager at oilfield services firm Schlumberger, told OBG. However, Ghana’s geology also yields high-demand, light sweet crude, which means it can sell at a premium. Jubilee field produces a lighter oil than standard Brent crude, and therefore typically fetches a higher price. In 2015 Jubilee oil received, on average, $52.36 per barrel, although as of 19 December, Brent crude was selling at $54.93 per barrel.
Inland lies the Voltaian Basin, which covers approximately 40% of Ghana’s landmass and stretches into Togo and Benin. Historical surveys identified potential deposits in the northern region of the basin. In June 2016 the online news portal Ghana Business News reported that Daniel Amlalo, executive director of the country’s Environmental Protection Agency, announced at a meeting for various stakeholders for the basin’s northern region that the government would intensify exploration projects in the onshore basin.
The focus on deepwater fields makes offshore E&P in Ghana more difficult and costly than in a number of other oil-producing countries, a concern that has been exacerbated by the fall in prices. Outside of the country’s two actively producing fields, Jubilee and Tweneboa, Enyenra and Ntomme (TEN), and the Sankofa field, which should begin production by the second half of 2017, large-scale activity is limited to preliminary studies and test wells.
A number of companies have stakes in existing blocks. Hess, in partnership with Statoil, is currently putting together a plan of development for a block in the Tano/Western Basin, while ExxonMobil has expressed interest in purchasing a share in an unnamed field off Ghana’s coast. However, few firms have yet to begin activity in earnest. Richard Badger, deputy chief executive of engineering and operations for the country’s main utility Volta River Authority, told OBG that he believes companies will hold off on investing resources in discovery until oil prices exceed $80 per barrel.
Ghana’s first major oil field, Jubilee, was discovered in 2007 and has been producing oil since December 2010, following an impressively short turnaround period. It is located in the Tano Basin, which is off Ghana’s coast between the West Cape Three Points and deepwater Tano fields. In 2015 Jubilee produced approximately 37.4m barrels of oil and 52.55trn scf of associated gas. According to the PC, between January 2015 and March 2016 Jubilee’s output averaged around 102,000 barrels per day (bpd).
Cost of production at Jubilee was roughly $410.45m in 2015, a reduction of 4.5% from 2014. Equity partners of the Jubilee unit area include Tullow Oil (35.5%), Kosmos Energy (24.1%), Anadarko Petroleum (24.1%), GNPC (13.6%) and PetroSA (2.7%), and Tullow Oil serves as the primary operator. The Ghanaian government is also entitled to a 5% royalty on the Jubilee field.
In February 2016 damage to the turret bearing of the Jubilee floating production, storage and offloading (FPSO) vessel Kwame Nkrumah shut down production between April and May of that year. Following the resolution of this incident, operating and offtaking procedures have been reviewed and adjusted, and production at the FPSO vessel is now up and running. The insurance and reinsurance industry lost an estimated $1.2bn-1.25bn while the vessel was out of commission.
The Jubilee partners are in negotiations with the government on a development strategy for the Greater Jubilee field. The Greater Jubilee Full Field Development Plan incorporates the Mahogany and Teak discoveries in the West Cape Three Points block and is intended to expand field production and increase commercial output.
The plan was initially submitted in December 2015, but has been delayed in discussions between the PC and the MoPET. The government’s decision was originally expected in 2016, but given the issue with the FPSO turret this integration programme is not likely to come any time soon.
TEN: Development of the TEN project began in 2013 and is being led by Tullow Oil (47.2%), Anadarko (17%), Kosmos Energy (17%), GNPC (15%) and PetroSA (3.88%). The field has an estimated 239m barrels of oil and 360bn scf of gas reserves, according to the PIAC. Speaking to the BBC’s Focus on Africa in August 2016, Seth Terkper, then-minister of finance and economic planning, said oil production was originally expected to begin by the end of 2017, but the early arrival of the FPSO vessel expedited development and the field’s first oil, which was in August of 2016. TEN is expected to increase production to 80,000 bpd at peak capacity. Terkper told the BBC the output from TEN will enable Ghana to recover from low oil prices. Additionally, TEN is also expected to contribute significant amounts of natural gas that could help fuel the country’s thermal power plants. TEN is going to produce between 63m and 70m scf per day (scfd) of associated gas, according to the April 2016 energy outlook from Ghana’s Energy Commission. For the first year of oil production, TEN’s gas will be reinjected into the Ntomme reservoir gas cap. In 2018 gas from TEN will be commingled with Jubilee gas and processed onshore at the Atuabo Gas Processing Plant before being distributed. Atuabo is the county’s only gas processing plant, and in 2015 it received less than 120m scfd from Jubilee’s FPSO. Additional drilling at TEN has been suspended until maritime boundary disagreements with neighbouring Côte d’Ivoire are resolved.
Indeed, the ongoing dispute with Côte d’Ivoire has dampened activity over the past several months. In 2014 Ghana brought its neighbour to the International Tribunal for the Law of the Sea to contest its claim to an offshore area being developed by Tullow that would have affected the TEN project and future exploration. Côte d’Ivoire argues that some of Ghana’s oil concessions extend beyond their conceptualised boundary line between the two countries – a line that Ghana contests. Official presentations to the tribunal were ongoing in 2016 and a final decision is expected shortly, with both countries repeatedly stating that the outcome will be respected.
Most of Ghana’s major oil and gas discoveries have been made in the Western Basin, and significant development has yet to be conducted in the area, meaning that a series of projects and investors could be affected by the outcome of the tribunal decision. In April 2015 the international tribunal gave Ghana the green light to continue developing the $4bn-plus TEN project while the case is being considered. The court is expected to make its decision by the mid-2017.
While the oil segment is slowing down, natural gas production in Ghana is rapidly increasing. In 2015 production reached 46.9trn scf, nearly twice as much as 23.6trn scf seen in 2014, coming primarily from associated deposits in the Jubilee field, according to the Energy Commission. This is welcome news given Ghana’s ongoing energy crisis and the need for additional gas to fuel the country’s thermal power plants. This is likely to be further boosted by new discoveries.
Large commercial reserves were discovered in Sankofa, a deepwater non-associated gas reservoir located 60 km offshore in the Cape Three Points area. The Sankofa-Gye Nyame field, found by Italy’s Eni in 2009, has expected reserves of 162m barrels of oil and 1.07trn scf of non-associated gas. This field, which is expected to produce first oil in late 2017 and first gas in 2018, is particularly exciting for gas production in Ghana, Philip Liverpool, commercial director of Kosmos Energy, told OBG. “Since gas from Sankofa is non-associated, it will be more extensively processed offshore before being stabilised onshore and sent on for distribution. The onshore receiving facility will likely be completed in early 2018,” he said.
The field, which is being developed by Eni, Dutch firm Vitol Group and GNPC, is projected to be able to provide up to 1000 MW of domestic power – which is equivalent to 40% of current installed capacity – and greatly improve the reliability of power in the country. This project is receiving the largest injection of foreign direct investment in Ghana’s history at $7.9bn. It is expected to bring in $2.3bn in revenues for the government.
The World Bank announced it will be helping finance this project through a $500m International Development Association guarantee facility that covers the risk of non-payment by GNPC, as well as an International Bank for Reconstruction and Development enclave loan guarantee of $200m to cover any possible debt service defaults.
Furthermore, the supply of gas that will become available at the completion of this project should enable Ghana to reduce oil imports by 12m barrels and CO emissions by around 8m tonnes over five years. However, achieving these ambitions will be dependent on having adequate gas processing capabilities, an area in which the country continues to face challenges. Despite a number of promising projects and improvements, technical issues with the Atuabo gas plant meant that 9% of gas from Jubilee had to be flared and 39% re-injected in 2015, according to the PIAC.
To address this, the government is developing the Western Corridor Gas Infrastructure Development Project, which is being designed to transfer and process gas from Jubilee and other offshore projects without the need for flaring or reinjection. In order for Ghana to reap maximum benefit from its gas reserves, all of its infrastructure, including Atuabo, will need to be operating at full capacity as new fields come on-line (see analysis).
As a result of several years of high headline growth, along with industrialisation and urbanisation, consumption of oil and gas derivatives has increased over the past few years. According to the Energy Commission, domestic energy demand is growing by 10% to 15% annually (see Utilities overview). There has also been a specific increase in demand for diesel due to the increased use of private generators to help bridge the shortfall in grid production.
Consumption far exceeds domestic production, which means that Ghana is reliant on imports for both oil and gas products. The country currently imports natural gas from Nigeria via the West African Gas Pipeline, which is used to fuel the country’s thermal plants. However, in 2014 supply only reached 30m-50m scfd, which was far less than the anticipated 123m scfd (see analysis).
Crude oil imports for domestic consumption totalled 310,000 tonnes in 2015, a 55% decrease from 693,000 tonnes in 2014 and an even more significant reduction compared to the 1.3m tonnes imported in 2013, according to the Energy Commission. Bunmi Omole, group general manager for Ghana, Côte d’Ivoire and Remote Operations at Schlumberger, told OBG, “Over the past two years, Ghana has been highly dependent on the import of petroleum products, including crude, for power production and fuel, but this calculus should change in the future.”
In total, Ghana spent $3bn on approximately 3.7m tonnes of imported petroleum products in 2015 nearly 30,000 tonnes less than imported in 2014, according to the National Petroleum Authority (NPA). These imports included crude oil, diesel, petrol, liquefied petroleum products and aviation turbine kerosene. Around 80% of crude oil consumption was dedicated to fuelling the production of electricity, while 20% was allocated for refinery operations.
Downstream Storage & Distribution
undefined Ghana’s downstream oil subsector is overseen and evaluated by the NPA and includes the processing, marketing and distribution of petroleum products. The downstream gas sector, however, is also overseen by the Energy Commission (see analysis). Ghana currently has one refinery, the Tema Oil Refinery (TOR). TOR has a capacity of 45,000 bpd and has been owned by the MoPET since 1977. It is situated in Tema, about 24 km east of Accra, and refines crude oil, most of which has historically been imported from Nigeria. The refinery has faced a number of challenges in meeting its planned output, and a shortfall of capital has led to an inability to secure crude oil inputs.
However, in August 2016 Bloomberg reported that Alexander Mould, acting CEO of GNPC, said that if TOR could provide a financial guarantee, GNPC would be willing to begin supplying the recently refurbished refinery with crude oil. The refinery would then convert bank loans into a 10-year bond held by its lenders, as the state-owned firm owes as much as GHS950m ($245.1m).
Storage and distribution of Ghana’s oil is managed by bulk oil distribution companies (BDCs). Originally, the state-owned Bulk Oil Storage and Transportation Company (BOST) was the only player in the industry; however, as part of a series of downstream liberalisation policies, the government has opened the sector to private competition. BOST is also licensed by the Energy Commission to transport natural gas throughout Ghana and between ECOWAS states.
Since the sector opened up to private sector participation the number of investors has ballooned, with the roster of BDCs jumping from an initial group of four to 30. According to research by the Association of Oil Marketing Companies, the market is now fragmented with market leaders capturing a share of between 11% and 13%.
Since liberalisation of the sector Singapore-headquartered midstream and downstream company Puma Energy announced its direct entry into the Ghanaian market, adding 10,000 cu metres of storage capacity at Kotoka International Airport. Emmanuel Buah, then-minister of petroleum, addressing the private sector at an industry event in April 2016, said, “This certainly provides golden opportunities for industry players,” GhanaWeb reported. The former minister stated that he was happy to see the competition.
In an effort to further liberalise the downstream sector, in June 2015 the government began deregulating the price of petroleum products including petrol, kerosene, diesel oil, heating oil and lubricants, among others. This new policy allows BDCs and oil marketing companies (OMCs) to assert more control over their own prices, rather than following the fixed price set by the NPA. While this significant step towards deregulation was widely welcomed, some believe it did not go far enough. Vincent Richter, head of external affairs and customer service for Shell’s Ghana licensee Vivo Energy, told OBG, “Higher-quality fuels are regulated, which is becoming more of a problem as the country continues to develop. More people are purchasing or leasing cars, and those cars require higher-quality fuels.” The system as it was previously designed intended to regulate prices to ensure affordable fuels for consumers, as well as full cost recovery plus a profit for the commercial side, with the government subsidising a portion if necessary. The NPA was unable to completely eliminate an element of government intervention due to the steady drop in the value of the Ghanaian cedi.
However, under the new system the government will no longer set prices for consumer fuels every two weeks, instead leaving BDCs and OMCs to do so, albeit according to the existing formula that the NPA had used. The two-week window will also be preserved, meaning that BDCs and OMCs will submit their rates to the NPA ahead of those periods for approval and are free to charge less than the formula implies if they wish. The first two-week window under the system, beginning on June 16, 2015, was a transition period during which the NPA, BDCs and OMCs agreed on a partial adjustment that brought prices up by 4%, but still short of full market rates, which would have necessitated a 14% jump.
In order to ensure domestic employment in the power and energy sector, the government has implemented local content and participation requirements, which are outlined in two pieces of legislation. The first piece of legislation, which was passed in 2011, is the Petroleum Commission Act 821, which established the PC and charged them with promoting the use of local staff and materials in the segment.
The second, passed in 2013, is called the Petroleum (Local Content and Local Participation) Regulations. This piece of legislation has shifted responsibility for incorporating local workers from the PC to contractors and companies operating in Ghana, and works to further ensure Ghanaians benefit from oil discoveries. It requires that at least 5% equity be given to a Ghanaian company on top of the shares held by GNPC.
The government is hoping that this legislation will help them reach a target level of 90% local participation throughout the oil sector by 2020. “Within the power sector more semi-skilled and skilled jobs should be given to Ghanaians rather than foreign workers and expats,” Omane Frimpong, CEO of local firm Wilkins Engineering, told OBG. “Local know-how for imported technology remains key for sectoral growth,” he added. For foreign investors hoping to enter the Ghanaian market, Harriette Amissah-Arthur, executive partner at Arthur Energy Advisors, which focuses on energy projects in West Africa, told OBG that its critical for “foreign investors to work with someone who is local and understands timelines, costs and hurdles, but can also see potential and reward”. However, some in the industry believe that these local content laws might actually be discouraging private sector investment. For example, Richter told OBG, “It is difficult because we are not pushing local participation, we are pushing local ownership. Most companies hire locals, but extending equity is when it becomes challenging for foreign investors.” Foreign companies have also, at times, struggled to find properly qualified local technical staff who meet international standards, and some believe the 5% local ownership rule is keeping a number of the large players out of Ghana. Yet despite these reservations, then-President John Dramani Mahama has confirmed the importance of local content laws, and reiterated his support. At the August 2016 commissioning of the new TEN fields, he said the government would continue working to increase the use of local resources in the country’s oil activities.
With two new fields scheduled to come on-line in the next two years and improved regulation through updated E&P laws making interactions more transparent for investors, prospects for oil and gas are trending positively.
Additionally, given Ghana’s current energy crisis and its immediate need for gas to fuel its thermal power plants, there is a ready market for its reserves. Given the limited prospects for an increase in the global price of oil, which will continue to cost Ghana much-needed revenue and limit the prospects for the oil and gas sector, it is expected the current situation will continue.