With established domestic gas production and ambitious plans to scale up, Tanzania’s energy sector is in the process of moving from potential to reality. Offshore gas reserves are sufficient to have prompted a proposal for a two-train liquefied natural gas (LNG) project in Lindi, while there is ample potential onshore around the Rift Valley based on commercial-scale deposits in similar terrain as in neighbouring Uganda and Kenya.
Infrastructure is always a challenge for new producing countries, but Tanzania has constructed midstream processing plants and pipelines to leverage existing production, and has capacity to spare for new projects, although the proposed LNG development is still some way from finalisation (see analysis).
As of 2017 the country’s natural gas discoveries totalled 57trn cu feet, according to the Ministry of Energy, which estimates that around 70% of that reserve is recoverable. Tanzania’s territorial waters include the northern part of the Ruvuma Basin, which extends south into Mozambique, where large gas fields found in the late 2000s renewed global interest in the region.
Although there have not yet been any discoveries of oil in the country, onshore gas production has increased steadily. It reached 37.17bn cu feet in 2015, up 9.8% from 2014, according to a 2015 report by Tanzania’s National Bureau of Statistics. This gas is currently used in the domestic economy, primarily by the power sector but also by industrial customers around Dar es Salaam. Given the expected costs of deepwater offshore production, the government is also looking at future overseas exports to Asian markets as the only economic means of underpinning exploitation of the deepwater gas reserves.
In October 2017 President John Magufuli’s administration announced that the Ministry of Energy and Minerals was to be split into two separate ministries as part of a government reshuffle. Medard Kalemani was to become Tanzania’s minister of energy, while Angellah Kairuki was named as the new minister of minerals.
Henceforth, the Ministry of Energy and the Ministry of Minerals oversee policies for their respective sectors. Other government entities include the Petroleum Upstream Regulatory Authority (PURA), which was created in 2015 to manage upstream affairs, and the Energy and Water Utilities Regulatory Authority (EWURA), the downstream regulator. EWURA oversees midstream and downstream functions, including setting prices for fuels, electricity and natural gas, and issues licences. In the electricity sector, any generation project with capacity of 1 MW or more must obtain a licence from the agency.
The state’s national oil company, Tanzania Petroleum Development Corporation (TPDC), is responsible for upstream and downstream activities, including operating the country’s growing network of domestic pipelines and gas-processing plants. TPDC is formally designated as the sole gas aggregator in the country by the Petroleum Act of 2015.
In the electricity sector, Tanzania Electric Supply Company (TANESCO) is the state utility with a monopoly over transmission. Generation is open to private investment on a case-by-case basis, but distribution is primarily handled by TANESCO, except on Unguja and Pemba Island, where the Zanzibar Electricity Corporation distributes the power it buys from TANESCO, and in a district in the south, where Mwenga Hydro operates a 4-MW generation facility and distributes via a local network.
There are a number of other affiliated agencies that are involved in the sector as well. Important specialist bodies in the public sector include the Rural Energy Agency, the Petroleum Bulk Procurement Agency (PBPA) and the Tanzania Geothermal Development Company, along with the National Development Corporation, a state investment vehicle charged with mining coal and developing power plants, among other responsibilities.
Tanzania has introduced several new laws in recent years ahead of any large-scale ramp-up in production and activity at all points on the value chain. The Petroleum Act of 2015 is the new umbrella law for the sector, which among other key steps detached the regulatory role from TPDC to make it a standalone national oil company. It is the only entity that can be granted petroleum rights, and has the stated ambition of maintaining a minimum of 25% interest in any venture, as well as serving as the gas aggregator. Under the 2015 reforms, licences are issued by the Ministry of Energy. As of late 2017 the published contract terms are modelled as production-sharing agreements. In Tanzania these contracts cover exploration activity as well as any future production.
Published royalty rates are 12.5% for onshore and 7.5% for offshore production. The state also passed revenue-management laws and a disclosure law that mandates energy sector contracts signed with investors be made available to the public.
The above rules, however, apply only to mainland Tanzania and the offshore zones it controls. Zanzibar oversees its own resources and any revenue from them, according to the 2015 law. To explore the potential for this, in 2016 the Zanzibar Oil and Gas (Upstream) Act created the Zanzibar Petroleum Regulatory Authority and Zanzibar Petroleum Development Company. The 2015 overhaul helped to highlight the importance of the sector in the government’s economic development plans, creating the Oil and Gas Advisory Bureau in the Tanzanian president’s office to advise the Cabinet on strategic matters related to oil and gas.
The government has also taken steps to constrict activity in extractive sectors, with the passage of laws aimed at strengthening state involvement in mining. The impact of these laws on hydrocarbons production is pending clarification, although they have the potential to conflict with active production-sharing agreements (see Mining overview).
While the big discoveries have all come in the past few years, Tanzania is not technically a new play. Between 1952 and 2013 some 67 wells were drilled, with 53 in onshore basins and 14 offshore. By December 2012 the state had signed 26 production-sharing agreements with 18 companies. Finds from the 1970s and 1980s have been revisited, and three have been commercialised in recent years. Smaller companies have also been exploring along the coast in shallow and deep water.
The big finds in the Ruvuma Basin came in 2013 and 2014. The gas is roughly 100 km offshore in depths of 0.5-2.6 km of water, and the technical challenges – and resulting high cost of extracting the gas – are the main reasons why LNG production and export to international markets provides a development alternative. The domestic market is undeveloped and not large enough, and the lower, regulated domestic gas prices (see analysis) do not provide the margin to justify the capital investment required to develop Tanzania’s deepwater reserves, so liquefied natural gas production and export overseas is the only development alternative.
In Zanzibar exploration is at an earlier stage. In May 2017 Bell Geospace began conducting a survey on behalf of the government and the rights-holder to hectarage in Zanzibar, RAK Gas, of Ras Al Khaimah, one of the seven federated emirates that comprise the UAE. RAK Gas primarily sources and markets natural gas, with a portfolio of exploration in Africa.
The majority of discoveries are found in three blocks. Norway’s Statoil and ExxonMobil’s discovery was the second largest in the country, and a string of others have led to a total of 22trn cu feet of gas in place found in Block 2. Blocks 1 and 4 both delivered substantial discoveries, totalling around 25.4trn cu feet. Exploration there is being conducted by Royal Dutch Shell – after it acquired BG Group’s assets in 2016 – in partnership with UK-based Ophir Energy and Singapore’s Pavilion Energy.
The remaining discoveries, 10trn cu feet on a gas-initially-in-place basis, are found in several smaller fields onshore or in shallower water than the big finds. Of this smaller group, Mnazi Bay contains 5trn cu feet and Songo Songo Island 551bn cu feet.
In August 2011 Tanzania awarded oil and gas exploration rights for the northern side of Lake Tanganyika to a subsidiary of France’s Total, which beat eight other bids from companies including Australia’s Beach Energy, UK- and Ireland-listed Aminex, Ophir Energy and US independent ERHC Energy.
The most recent bidding round in the country took place in 2014, with eight offshore blocks available, including some adjacent to the big finds, and one onshore near Lake Tanganyika North. However, interest for the projects was somewhat muted, with four of the eight blocks failing to attract a bid. Bidders included China National Offshore Oil Corporation, Russia’s Gazprom, Abu Dhabi’s Mubadala Investment Company and RAK Gas. Statoil and ExxonMobil submitted a joint bid for one of the offshore blocks. However, no bids have yet been successful. One of the main challenges was the terms that were set out in the model production-sharing agreement, with all of the bidders failing to submit a bid that was compliant. Block rights can also be conveyed directly to TPDC by the Ministry of Energy.
The most productive field is Songo Songo, operated by PanAfrican Energy Tanzania (PAET), which has an estimated 1trn cu feet of recoverable gas and was responsible for 85% of production in 2015. The field lies in the southern offshore zone and produces approximately 90m cu feet per day, of which around 40m cu feet per day is reserved for special contracts and the rest is sold to TANESCO, industries, households, institutions and vehicles.
In 2015 much of the production growth came from the Mnazi Bay concession, which is operated by France’s Maurel & Prom, with TPDC and Wentworth Resources, a Canadian firm, as equity partners. Mnazi Bay produces roughly 60m cu feet per day. Production increased from 783m cu feet in 2014 to 5.79bn cu feet in 2015, bolstered by a new pipeline from Mtwara to Dar es Salaam. Overall production figures for 2016 are set for a small increase when announced, as the year featured first gas from a third source, the Kiliwani North field, which is operated by Aminex. The field was producing at a rate of some 15m cu feet per day in 2016. Aminex’s contract with TPDC pays it $3 per million British thermal units (Btu).
EWURA is charged with approving the mid- and downstream tariffs applications to ensure investors recover prudently incurred investment costs plus a reasonable margin. In 2016 the Ministry of Energy issued pricing regulations, which outlined clear methodologies for calculating tariffs and end-user prices. Prices for natural gas that is used for power generation are charged on a cost-plus-margin basis, while prices for other users are discounted from alternative fuels, except for strategic investors. In the first three months of 2017 the average price of gas sold to TANESCO was $3.57 per million Btu, according to PAET’s parent company, Canada’s Orca Exploration. That was up $0.02 from the first quarter of 2016. Gas sold to industrial customers averaged $7.75, down from $8.15.
The contract with TANESCO is a take-or-pay agreement. The utility has fallen behind on both payments for gas and the take-or-pay obligation, the debt becoming part of a larger arrears to suppliers estimated at $363m as of early 2017 – a trend which has affected several government-owned energy purchasers across Africa, from Egypt to Ghana.
Given the current investment climate, in which some significant private sector projects are under review by the government, PAET may be asked to renegotiate its terms. A state audit for FY 2015/16 recommended approaching the company to consider adjustments for several reasons, including the fact that the production-sharing agreement is structured so that the state’s profitability from PAET’s production falls as output increases. The auditor’s report also acknowledges that calling on the company to change its terms could lead to arbitration.
While production has so far been in small increments, Tanzania has installed the midstream infrastructure necessary to handle the expected growth in its resources. It has four operational gas-processing facilities, and a pipeline network carrying gas from two offshore spots to Dar es Salaam’s industrial zones and power plants. The major pipeline is the 548-km Mtwara-Dar es Salaam facility, which originates in Madimba, south of Mtwara. Current installed capacity is 737.39m cu feet per day, while the flow rate is 46.61m cu feet per day, meaning current utilisation stands at just 6.3% of installed capacity. The line was completed by Chinese state-owned companies for $1.23bn in 2016. The Mtwara-Dar es Salaam pipeline is operated by TPDC. A 28.5-km pipe runs from Mnazi Bay to the new pipeline, and has a capacity of 27m cu feet per day. An older 232-km pipeline links Songo Songo Island to Dar es Salaam, with a capacity of 102m cu feet per day. The pipeline is operated by Songas.
In addition, Tanzania has a 33.3% stake in the Tanzania-Zambia Mafuta Pipeline, which is not connected to the domestic system. Instead it passes through the country, carrying crude oil inland to the Indeni Refinery located in Ndola, Zambia.
The country is also collaborating with Uganda on the $3.55bn Uganda-Tanzania Crude Oil Pipeline, which will carry crude oil produced in Uganda to Tanga, on Tanzania’s northern coast, for export.
The US firm Gulf Interstate Engineering was selected to design the 1443-km pipeline in January 2017. Looking ahead, the construction of the project is scheduled to commence in early 2018, and is expected to take three years to complete. As of August 2017 Stanbic Bank Uganda and Japan’s Sumitomo Mitsui Banking Corporation, the joint financial advisers for the project, were exploring bank financing or loans from export credit agencies.
Two of Tanzania’s four gas-processing plants are on Songo Songo Island. PAET’s facility there has a capacity of 110m cu feet per day, which is mostly spoken for by the company’s own production. TPDC’s facility on the island has a capacity of 140m cu feet per day, but is using about 15m of that currently. The third site is in Mtwara, where TPDC’s facility has a capacity of 210m cu feet per day, and is processing the approximately 60m cu feet per day produced at Mnazi Bay.
While offshore gas production volumes will be of a larger magnitude than what the domestic market currently produces and consumes, Tanzania’s moves to lay pipe and build processing capacity provide certainty at an early stage about the marketability of smaller prospective discoveries.
However, the downside of this early investment is that the country is paying for the capacity before it generates sufficient revenue from it. For example, a government audit for FY 2015/16 submitted in March 2017 found that the only customer for the MtwaraDar es Salaam pipeline is TANESCO, which was using it for the transportation of 46.61m cu feet per day.
Mussa Assad, Tanzania’s controller and auditor general, noted that the pipe was built before TPDC could estimate a true figure for demand, and that repayment could be a challenge. A complicating factor is the rate charged by TPDC to sell gas, which was $1.64 higher than the rate at which PAET was selling gas to TANESCO at the time. “Any reasonable buyer will buy from a cheaper source,” Assad wrote in the March 2017 report. “This may have negative effects on TPDC sales levels.”
In FY 2015/16, running from July to June, approximately 5.5bn litres of petroleum products were imported, with 99% of them passing through the Port of Dar es Salaam, with the remainder transported overland or through the Port of Tanga, on the northern coast. Of the total, around 37% was re-exported across the region, including to Zambia, the Democratic Republic of the Congo, Rwanda, Malawi and Burundi. Most of this market is served by trucks, not unusual in a region where road transport has dominated goods distribution (see Transport chapter). The figures show a 20% rise in imports in 2015 over the previous year. However, actual sales of petroleum products rose by 7%, indicating an increase in stockpiles.
EWURA has stepped up its regulation of downstream fuel markets, as part of a broader drive by the Tanzanian government to reduce parallel pricing in the economy. For EWURA, this means a focus on eliminating unregulated suppliers and facilities in the market. Efforts include ensuring construction approvals are sought for filling stations and other facilities, boosting the level of regulation for liquid petroleum gas, ending the availability of smuggled imports and making the contracting process for importing end-user fuels more attractive.
Petrol prices are regulated by EWURA, which sets a maximum allowable charge on a monthly basis. Capped retail prices effective from October 1, 2017 in Dar es Salaam were TSh2063 ($0.94), TSh1908 ($0.87) and TSh1858 ($0.85) per litre for petrol, diesel and kerosene, respectively. This price is a hard cap but not a floor: it allows for supply-and-demand competition by encouraging marketers to sell for less if they are able to do so. As part of efforts to boost compliance, EWURA has established a code that Tanzanians can enter into a mobile phone to check the capped price before buying. The importing of petrol, diesel, kerosene and other fuels is controlled by a competitive bidding process. For FY 2015/16, 27 companies were prequalified by the PBPA, which cleared them to bid on monthly supply contracts. Qualifiers included a mix of local and international names, with foreign entrants such as Singapore’s Trafigura, Switzerland’s Glencore and Mercuria, and regional entities like Sahara Energy, a Nigerian firm involved in upstream and downstream segments.
Retailing is a competitive market, with four filling station operators holding market shares above 10%: Puma Energy, GBP Tanzania, Oryx Energies and Camel Oil. There are 14 others, including Total, which in 2016 acquired the Tanzanian assets of Gulf Africa Petroleum Corporation, part efforts to boost its downstream presence across the region. The sale included 67 filling stations and a logistics terminal.
State utility TANESCO is a vertically integrated company responsible for generation, transmission and distribution. The sector is regulated by EWURA, which provides licences, sets tariffs for electricity and for gas sold to power plants, and reviews and approves any power-purchase agreements TANESCO signs with outside generators. It is also the licensing agency for captive power plants. On the back of high economic growth, the task of meeting the country’s increasing demand for electricity has emerged as a major challenge, not only for retail use, but also to facilitate an industrial drive. The medium-term aim is to boost potential output from 1246.24 MW of installed generation capacity as of 2015 to 4915 MW by 2020. “Power demand has been growing rapidly at about 10% per year, but the country has a good range of assets and a number of resources for generation, including gas, hydroelectricity and renewables,” Patrick Rutabanzibwa, country chairman of PAET, told OBG.
In FY 2015/16 natural gas accounted for 56% of generation, hydro 31% and liquid fuel 13%, EWURA data shows, indicating a shift away from a historical reliance on hydroelectric production. The government is also pursuing additional generation capacity using domestic coal, geothermal, wind and solar power, with projects of each type at various stages of development (see analysis). A further 15 MW of power is imported from Uganda and Zambia.
Based on its Power Sector Master Plan, Tanzania will require $46.2bn in power investment by 2040 if it is to meet demand for the long term. This figure includes the cost of upgrades to the transmission grid and new substations, however, almost 80% of the total is needed for new generation capacity. The private sector is expected to play a key role in the development of the power sector by building and operating the plants, providing finance and maintenance. As of 2015 there were six independent power producers, which together accounted for 40% of power generation, with TANESCO providing the balance. However, not all of these are currently producing, and their contribution to overall generation in 2016 has fallen as a result (see analysis). The state has also been exploring other public-private partnership options, including potential models that might allow for state ownership.
One of the hurdles for TANESCO is collecting payment for all the power it provides, including from government users – an issue that is hardly unique among Tanzania’s continental peers. Another challenge is the tariff TANESCO charges, which is not reflective of costs. The June 2016 national audit found it buying power at an average of TSh544.65 ($0.25) per unit, and selling to customers at TSh279.35 ($0.13). Raising the tariff is considered unlikely in the shorter term; TANESCO proposed an 8.53% hike in late 2016, which it said was less than half of what would have been necessary to cover its losses, however, no moves have yet been taken. According to local press reports, there have also been discussions over the possibility of seeking assistance from a development finance institution.
Tanzania’s smaller fields are supplying the domestic market and have already helped to modify the generation mix and make gas available for industry. With midstream infrastructure and ample reserves in place, the challenge of attracting larger investment, such as for the Lindi LNG plant, hinges on the government’s ability to maintain a competitive commercial, fiscal, legal and regulatory framework.
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