Roughly seven years after the discovery of oil, Ghana’s hydrocarbons sector has seen significant growth in terms of both production and infrastructure. Yet the industry is still very much a work in progress, with potential for investment across the value chain. The past few years have been busy ones, as the country needed to create an enabling environment for the sector from scratch, including a new regulatory framework, new agencies and new funding.
All this was done with an eye to attracting foreign expertise and capital to fast track the development of the first significant commercial discoveries and generate export earnings. Increasingly, new projects are being ramped up to develop the sector, including for the downstream segment.
Sector policies are currently undergoing a period of review, as the existing legislation is being adjusted to target indigenisation of the sector and the broadening of local job and enterprise creation. However, unlike in other producers around the Gulf of Guinea where reforms have stalled activity – such as in Nigeria, where the pending Petroleum Industry Bill has slowed inbound investment into the hydrocarbons sector – investors remain bullish about Ghana, as evidenced in the signing of new production agreements (PAs), even as the new draft of the Petroleum and Exploration Bill awaits ratification.
Coming Of Age
Ghana’s emergence as an energy player in Africa is still very much a new story, not even a decade old. The discovery of the offshore Jubilee field marked a watershed moment for the economy, bringing in significant capital and stoking growth into the double digits. The field was developed in record time, at roughly 42 months, and by 2011 the country’s oil production had risen more than tenfold to reach 78,000 barrels per day (bpd) from a meagre 7000 bpd in 2009. That same year the economy grew 14.4%, the fastest pace in Africa according to the IMF. In 2012, with hydrocarbon exports worth around $3bn, oil had overtaken cocoa as the country’s second-largest export earner after gold. According to figures from Ghana’s National Petroleum Corporation (GNPC), average oil production as of March 2014 was about 104,000 bpd, with 20% of the Jubilee field’s estimated crude reserves having been lifted to date.
Ghana has emerged as West Africa’s fourth-largest oil producer after Nigeria, Equatorial Guinea and Gabon. Although its hydrocarbons sector has come a long way and gained international attention in a short period, nearby Nigeria, which is firmly entrenched as the continent’s largest oil producer, is approaching production levels of 2.5m bpd; around 25 times Ghana’s current output. Meanwhile, its neighbour to west, Côte d'Ivoire, is boosting its production to match Ghana’s by 2019, with the country’s prime minister stating that within five years it will be producing 200,000 bpd. This is twice the volume Ghana pumps at present, but below the 250,000-bpd target the country has set for 2021.
Ghana’s proven crude oil reserves stood at 660m barrels as of January 2013, according to figures from the US Energy Information Agency (EIA). This is a quantity that could yet expand as exploration is still ongoing, with promising, albeit unconfirmed, volumes in blocks adjacent to the Jubilee field. Given anticipated rising output levels from the Jubilee field, in combination with other discovered sites set to soon begin production, the GNPC forecasts output will double by 2021, and has stated it anticipates an additional $20bn will be spent on further developments at Jubilee and other fields.
The EIA has also estimated that the country possesses 800bn cu feet of natural gas reserves, mainly in associated deposits. Although Ghana does not currently produce dry natural gas, and has historically relied on imports from Nigeria in order to meet domestic demand, this is set to change once the Atuabo gas processing plant, set for completion in late 2014, becomes operational (see analysis).
The area where most exploration and production (E&P) activity is currently taking place is within the Tano Basin, a deepwater drilling zone off of Ghana’s west coast. In 2007 the Tano Basin block saw the first major discovery of commercially viable oil deposits some 60 km offshore, near the Côte d’Ivoire border, in the Jubilee field – one of Africa’s largest offshore finds over the past decade.
Initial estimates suggested that the new field could hold as much as 1.2bn barrels of oil. The site is primarily developed and operated by a consortium led by Ireland- and UK-listed Tullow Oil, which has a 35.5% stake in the project, along with US-based Kosmos Energy (24.1%) and Anadarko Petroleum (24.1%), Ghanaian state-owned GNPC (13.6%) and South Africa’s PetroSA (2.7%).
In 2009, global oil giant ExxonMobil bid $4bn for Kosmos’ stake in the Jubilee project, which put the perceived long-term value of the field at around $17bn, although the deal eventually stalled. According to calculations made by the World Bank, also in 2009, potential government revenue from royalties and taxes over the production life of the field could amount to slightly more than $19bn.
According to Tullow Oil, the field, which covers 110 sq km, could potentially contain 1.4trn cu feet of recoverable gas, primarily in associated deposits. The gas, for the most part, is being re-injected, with an allowance for flaring, while the necessary off-take infrastructure is developed. Plans had been in place for a processing plant with 150m cu feet of capacity, supplied by pipelines from the field, to start operations in 2013, although the current expected launch date is now late 2014 (see analysis). Once the project is up and running, it will help to reduce dependence on gas from Nigeria, which has been erratic in recent months, and will limit potential demand for more costly substitute fuels.
Also located in the Tano Basin and discovered in March 2009, the Tweneboa-Enyenra-Ntomme field, commonly referred to by the acronym TEN, is located 20 km west of Jubilee and encompasses an area of 800 sq km. The field, which is jointly held by Tullow (47.18%), Kosmos (17%), Anadarko (17%), the GNPC (15%) and Sabre Oil (3.82%), is set to start producing in mid-2016. At peak production levels, according to the GNPC, it is expected to generate between 75,000 and 76,000 bpd, providing the country with its second major offshore development.
Total reserves are estimated at around 245m barrels, of which 216m are deemed recoverable, and there is also the potential for producing 85m standard cu feet per day (scfd) of gas. The field’s plan of development, which was approved in June 2013, is expected to cost around $4.5bn.
Apart from the major findings at Jubilee and TEN, there are a number of smaller wells located throughout Ghana’s western sea territory where explorations and appraisals are taking place. The Sankofa well, located in the Cape Three Points block, was identified by Italy’s Eni Group as containing commercially viable oil and gas reserves in 2011, and a consortium led by the company, including Vitol Upstream Ghana and GNPC, has submitted a plan of development to the government for review.
Early indications are that the well possesses 150m barrels of recoverable oil and that production, which is forecast at 40,000 bpd, could begin by 2017. The site is also thought to contain Ghana’s first non-associated gas find, with potential recovery expected to reach 160m scfd.
Future Offshore Development
Other areas where new exploration projects are taking place include the Deepwater Tano/Cape Three Points block, where Hess Corporation has successfully drilled seven of eight exploratory wells. Hess, as the block’s operator, holds a 90% working interest, while the GNPC controls the remaining 10%. The estimated upside potential of the development, for which plans have been submitted and the Petroleum Commission has granted a three-year period in which to complete appraisals, stands at 300m barrels, according to figures from the World Bank.
Also in the appraisal stage is a project in the Cape Three Points deepwater block spearheaded by Russia’s Lukoil with 56.66% ownership, and participation from PanAtlantic (28.34%) and the GNPC (15%). According to the Petroleum Commission, while initial appraisals were not successful and are now undergoing re-evaluation, they have received confirmation of a desire to drill around the wells in 2015. Should commercial discoveries be made during the five-year exploration licence, the development and production period is slated for 23 years with an extension possible if required. Finally, Kosmos, as the primary licensee for the West Cape Three Points block, is completing appraisal activities on the Mahogany, Teak and Akasa discoveries to the east of the Jubilee and TEN fields, with a decision expected in the first quarter of 2015.
Granting New Licences
The GNPC is also in negotiations with Royal Dutch Shell over an E&P deal in the East Keta Basin, which is situated offshore in the east of the country between the port city of Tema and the Togolese border. Alex Mould, the GNPC’s CEO, told Reuters in early April 2014 that discussions are simultaneously taking place with a number of other oil majors, including Chevron, and that new blocks could soon be awarded to UB Petroleum, A-Z Petroleum and Heritage Oil.
Efforts are under way to explore for onshore hydrocarbon deposits, and the GNPC is spending $20m to drill six holes at the Voltaian basin, a 103,600-sq-km area in central Ghana, after which seismic surveys will be conducted and the blocks divided up.
Framework & Agencies
Established in 1983, the GNPC, as the state agency responsible for the exploration, development and production of petroleum resources in Ghana, has been looking to increase its stake and active participation in projects. “In order for PAs to move forward, it is critical that the GNPC transition towards developing operator capability,” Theophilus Ahwireng, the acting CEO of Ghana’s Petroleum Commission – which acts as the upstream sector’s regulator – told OBG. The GNPC, in addition to being afforded ownership percentages, also receives a portion of state oil revenues in order to fund operations and investments in future oil developments, with the objective of ultimately evolving from a pure equity partner to a stand-alone operator capable of undertaking its own E&P activity.
The Petroleum Revenue Act, which was passed by parliament in March 2011 and is based on Norway’s model, stipulates revised conditions for collecting and distributing petroleum revenues, with a mandate that the country not only receives greater royalties, but makes the entire process more transparent by disclosing more information on the amount of money received and how that money is then allocated. The law, at a basic level, calls for 70% of receipts to be provided to the Ministry of Finance’s budget, and the remaining 30% to be set aside for future savings and deposited into the Ghana Petroleum Funds, which include the Future Generations Fund and an Oil Price Stabilisation Fund. According to the Public Interest and Accountability Committee, projected state earnings from the stream of projects should amount to $5bn by 2015.
Under new legislation passed in 2013, dubbed the Petroleum Regulation on Local Content and Participation, the government is making an effort to further boost local participation beyond the role of the national oil company. Private Ghanaian companies will be given first preference on bids for petroleum licences. There will also be a requirement that local companies other than the GNPC hold a minimum equity stake of 5% in future contracts awarded to international investors (see analysis).
Chief Kojo Aidoo, the president and CEO of Baychester Petroleum, told OBG, “In terms of developing a sustainable local content initiative, Ghanaian companies should look to agreements with adequate technology transfer and synched timelines.”
As the Gulf of Guinea sees a boom in E&P activity, Ghana has begun increasing investment into ancillary infrastructure to improve the capacity of the country’s pipelines, ports and processing plants to accommodate growing demand. The country’s two main seaports, at Takoradi and Tema, are undergoing expansion and modernisation to handle larger volumes and a greater variety of cargo. Takoradi, due to its proximity to much of the Western Region’s offshore activity, currently handles most of the oil vessel traffic.
September 2013 marked the start of the Takoradi harbour expansion project, which will include a bulk oil service terminal and an open area for an oil pipe, plant and machinery.
Plans have been proposed by the UK’s Lonhro to construct and operate a dedicated oil and gas port terminal at Atuabo which could serve as a regional oil rig servicing and repair site. Currently, vessels in the region have to spend as many as 20 days travelling to South Africa in the event of needed repairs. Lonhro has acquired 514 ha of land, and estimates indicate that 35% of the $600m project, currently in the feasibility stage, will be offered to local companies. However, there has been some resistant to the project. In August 2014 five MPs filed a legal challenge against the agreement that would establish the Atuabo port, claiming that it was illegal under existing legislation. A month later the Maritime and Dock Workers Union indicated that they may initiate their own court action to prevent the deal.
In Need Of Capacity
Although oil now constitutes Ghana’s number two export, the country is a net importer of petroleum and petroleum products due to its lack of oil refining capacity – a not uncommon scenario throughout Africa. State-owned Tema Oil Refinery (TOR) is the country’s sole facility. Full capacity at the refinery, which stands at 45,000 bpd, has rarely been reached due to underinvestment and debt, and between 2008 and 2012 the refinery ran intermittently, largely due to mounting unpaid debts of $600m. The funds needed to pay off debtors and acquire new crude were eventually mobilised in 2012 through several tranches, but capacity utilisation still hovers below 30% due to ageing equipment and operational inefficiencies.
According to the National Petroleum Association, over the course of 2013, TOR supplied just 20% of local crude consumption while the rest was procured via imports. Aidoo told OBG, “Unfortunately, proper rehabilitation of TOR has not yet happened.”
Even if TOR was running at capacity, the refinery would still only be able to supply less than half the nation’s petroleum product demand. The government has in the past stated plans to double capacity to 100,000 bpd, although no concrete decisions have been made. Recent years have seen expressions of interest from potential investors in a greenfield refinery, but no announcements have yet been made.
Exploiting Ghana’s domestic gas reserves is a more pressing concern. The Jubilee field has significant associated deposits, but re-injection is only feasible for a limited period of time before it begins to impact crude production. While some flaring has been allowed to avoid further degradation, offtaking the gas has become a priority for ensuring the field’s continued production.
Improving gas utilisation would also be of significant benefit for the broader Ghanaian economy, by diversifying inputs for the country’s power sector and reducing exposure to other exogenous pressures. Installed electricity generation capacity, as of December 2012, stood at 2296 MW, according to Ghana’s Energy Commission, with generation split nearly 50:50 between hydro plants and thermal power plants (see Utilities section).
Most thermal plants in the country run on flex-fuel technology that allows for light crude oil (LCO), diesel or natural gas, but locking in more natural gas beyond the West African Gas Pipeline (WAGP) – which has suffered erratic supply in recent months – would result in a cheaper and lower emitting alternative to costly LCO imports.
Building A Pipeline
The WAGP was first proposed in 1982, as a means of transporting gas from Nigeria through to Benin, Togo and then onto Ghana. The 678-km pipeline, which was developed at a cost of $974m, constituted Africa’s first cross-border transmission system. Although the arrangement calls for Ghana to receive 123m British thermal units (Btu) per day, recent months have seen this fall to an all-time low of 20m Btu per day, according to the local press – a result of lingering issues related to damage caused by an errant oil tanker, as well as a reduction in supplies from Nigeria, which has started re-allocating exports to its domestic market.
Walter Perez, managing director of the WAGP Company, which owns and operates the pipeline, is confident that higher volumes will be made available in the future, as “indications from the Nigeria Gas Company are that in a few years’ time there will once again be a surplus.” Perez added that supply will continue to provide a needed contribution to domestic consumption even after the Atuabo plant is up and running. “The oil and gas business is all about location, and West Africa is set to both produce and require more gas in the future. It takes years of government negotiations and huge capital to construct a pipeline, and we have already overcome this hurdle. The infrastructure is in place, and one way or another, it will be exploited,” Perez told OBG. The pipeline’s directional flows could potentially reverse, with Ghana becoming a net exporter of gas.
Arthur Hurberts, CEO at Ghanaian pipe producer Interplast, also agreed that the pipelines are very important. “In light of the fluctuating electricity supply, dedicated power plants that could be run by natural gas might make sense for energy-intensive manufacturers in Ghana,” he told OBG. “However, the remaining challenge is the transportation of natural gas to the site. Without dedicated [high-density polyethylene] HDPE low pressure gas pipelines, a manufacturer has to rely on liquefied natural gas (LNG) shipments by truck, which is unpractical, cumbersome and expensive.”
In addition to the Atuabo plant and the WAGP, Ghana’s domestic gas consumption is increasing at such a pace that further buffers may be needed to ensure continuity of supply over the short term. A recent World Bank note recommended that Ghana also invest in LNG import and re-gasification facilities. “We cannot think that once Jubilee’s gas becomes available that all of our problems will be solved,” Harriette Amissa-Arthur, executive partner at Arthur Energy Advisors, told OBG. “We need to make further provisions, one of which is having the facilities in place for the import of LNG.”
Ensuring a more diverse array of supply sources would help strengthen Ghana’s ambitions to improve manufacturing and industrial activity. Ghana’s Energy Commission predicts local gas production from Atuabo could reach 500m scfd by 2020, although power demand by that time is forecast to require at least 800m scfd, outstripping WAGP capacity.
The Volta River Authority (VRA), Ghana’s major electricity generator and distributor, has announced plans to build a $150m facility to offload LNG near Takoradi by the end of 2016. Kofi Ellis, the VRA’s director of planning, said in a newspaper interview in late 2013 that the company will lease floating vessels to store the LNG and handle the re-gasification, and that the imported gas, with capacity of 450m cu feet per day, could be used to produce up to 1500 MW of power. Should this and additional import infrastructure come to bear, it will likely also bolster the supply-side confidence of independent power producers to invest in new generation capacity, though some unresolved issues over off-take certainty remain (see Utilities section).
In less than a decade, Ghana has become a key regional upstream player. In the near term, the country has begun to shift to optimising the development of its hydrocarbons in a sustainable manner – improving local content and participation in the value chain. It also aims to finalise linkages with associated sectors, including the power industry – an objective that the planned gas processing plant, upon completion in late 2014, should start to fulfil.
While financial and technical bottlenecks have hampered the pace of refinery activity and new electricity generation, should these challenges be resolved, the country could emerge as not only an exporter of crude, but also as a downstream petroleum products manufacturer and a provider of surplus electricity to the regional power pool. For the time being, however, the impetus is on improving the regulatory structure in order to maximise benefits.
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