Regional Report: East Africa

Recovering from a six-year drilling low that was reported last May, African E&P is slowly picking up the pieces. The region has seen numerous setbacks, despite having the potential to become one of the leading oil and gas producers and exporters in the world. Much of East Africa is riddled with severe debt and economic unrest, impeding investment and the development of infrastructure.

KENYA

Industry leaders have been keeping an eye on Kenya of late, as it is being hailed as one of Africa’s chief oil provinces for new development. More economically advanced than some of its neighboring countries, Kenya has the potential to bring the region’s energy industry to life.

Last year, in March, a Tullow Oil wildcat struck oil in northern Kenya’s Block 12A, Fig. 1. The Cheptuket-1 (Fig. 2) exploration well—the first well to test the Kerio Valley basin—encountered strong oil shows after being drilled to a TD of nearly 10,115 ft. The PR Marriott Rig-46 was reportedly demobilized, and post-well analysis was getting underway to demarcate the basin’s future exploration program.

Fig. 1. More economically advanced than some of its neighboring countries, Kenya has the potential to bring the region’s energy industry to life. Discoveries in Blocks 12A, 13T and 10BB have been made of late. Source: Africa Oil Corp.

Fig. 2. Tullow Oil’s Cheptuket-1 exploration well, in northern Kenya’s Block 12A, struck oil last March. It was the fi rst well to test the region’s Kerio Valley basin. Photo: Tullow Oil.

 
Angus McCoss, exploration director, said, “This is the most significant well result, to date, in Kenya, outside the South Lokichar basin. Encountering strong oil shows across such a large interval [2,296 ft] is very encouraging, indeed. I am delighted by this wildcat well result, and the team is already working on our follow-up exploration plans for the Kerio Valley basin.”

Just north of Cheptuket-1, Tullow hit another discovery in Kenya’s Block 13T. The Erut-1 well, which was drilled about 6 mi north of Etom-2, reached a TD of approximately 4,320 ft. It encountered a gross oil interval of 180 ft with 82 ft of net oil pay, at a depth of nearly 2,297 ft. The well’s main objective was to test a structural trap in the northern part of the South Lokichar basin. It was determined that oil had migrated to the northern limit of the basin, de-risking several other prospects in the area. Tullow reported that the PR Marriott Rig-46 would be moved to the southern part of Block 10BB, where it was scheduled to spud the Amosing-6 appraisal well.

Tullow’s exploration success has allowed the company to progress in terms of development planning. Negotiation of a Joint Development Agreement (JDA) concluded in October. The JDA was established to formulate a plan for Kenya’s government, and Kenya JV partners, to progress in the development of an export pipeline. According to Tullow Oil, the JDA will allow important studies to commence, including FEED, environmental and social impact assessments, as well as studies on pipeline financing and ownership.

JV partners already have sanctioned an early oil pilot scheme, which will use existing wells and storage tanks to produce about 2,000 bopd, gross, by mid-year. It also will provide information and important insight into the region’s oil production, which will assist in planning the fields’ development.

SOUTH SUDAN

Despite the fact that it is one of the top Sub-Saharan countries in terms of reserves, South Sudan’s energy industry has been crippled by war and corruption since 2013. Last year, its output dropped to as little as 120,000 bpd, a significant decline when compared to the 350,000 bpd that was produced in 2011. The decline is largely due to the excessive damage caused to production facilities and pipelines—which the land-locked region is palpably dependent on, as all of its crude is transported via a pipeline that passes through neighboring Sudan to an export terminal at Port Sudan.

In May 2016, it was reported that only one area in the entire 10-state nation was still producing: the Paloch fields in Melut County of Upper Nile state. The drop in output, along with heavy inflation and ongoing conflict between the army and rebel forces, has caused an economic crisis within the country, making it more difficult to restore production to pre-war levels.

However, progress was made earlier this year, when security was boosted at oil facilities throughout the region, prompting employees to return after fleeing the war-torn country. Companies returning to the region include China National Petroleum Corp., Malaysia’s Petronas and Oil & Natural Gas Corp. of India. “During the July crisis last year, they left, but came back,” Petroleum Minister Ezekiel Lul Gatkuoth said. “They are ready to resume production and increase output.”

Bloomberg reported last month that South Sudan’s government is now in talks with several major oil companies, including Total and Oriental Energy Resources, regarding the start of exploration efforts in Block B—the region’s largest untapped deposit. Other major companies, including Exxon Mobil and Tullow Oil, have reportedly expressed interest in investing in the country’s energy sector.

UGANDA

While many regions around the world have been cutting output to ease the global energy glut, the Republic of Uganda has been making plans to ramp up production. In August 2016, the country’s government reported plans to begin pumping as much as 230,000 bopd, following the issuance of production licenses to major oil companies Tullow Oil and Total, Fig. 3.

Fig. 3. Uganda’s government reportedly has plans to ramp up production, to as much as 230,000 bopd. Photo: Tullow Oil.

 
Energy Minister Irene Muloni said that the companies, along with Chinese producer CNOOC, would invest approximately $8 billion in the East African nation before beginning production as early as 2020. Final investment decisions are reportedly expected to be made within 18 months, and the licenses are expected to run for 25 years, with potential to be renewed for an additional five years.

Muloni explained, “The companies are expected to invest over $8 billion in the infrastructure required for all the production licenses. This investment will be for the drilling of about 500 wells, construction of central processing facilities and feeder pipelines, among others.”

With an estimated 1.7 Bbbl of recoverable oil in Uganda’s Lake Albert basin, the region is expected to become a key exporter within the next five years. To achieve this, however, the land-locked country must overcome a lack of infrastructure required to transport crude, as well as a lack of regional financing. Once the country is exporting successfully, the government reportedly expects to receive an estimated $43 billion in revenue from Lake Albert resources over about 25 years.

Development of energy infrastructure has been slow compared to many sub-Saharan producers. Last year, for instance, there were considerable delays in Uganda’s plans to route a pipeline via Kenya. Instead, the Ugandan government made the decision to route the 870-mi pipeline via Tanzania, to the Indian Ocean port of Tanga. Construction, however, has yet to begin. “A multitude of projects that need to be completed significantly increases chances of development bottlenecks,” Jacques Nel, a senior economist at NKC African Economics’ Paarl, told Bloomberg. “The government has more to lose than oil companies, regarding the risk of delayed oil production.”

In January, Total and Tullow—two of Uganda’s most active operators—entered an agreement, which granted Total an additional 21.5% interest in the Lake Albert oil project. Following the $900-million transaction, Total will hold a 54.9% interest, leaving Tullow with an 11.76% interest. Patrick Pouyanné, Total chairman and CEO, said, “Following the agreement on the Tanzanian pipeline, this transaction gives Total a leadership position to move this project efficiently toward FID in the current attractive cost environment, while providing strong alignment and a pragmatic financing scheme for our partner, Tullow.”

TANZANIA

The United Republic of Tanzania is one of the top East African countries in terms of natural gas reserves. According to the nation’s government, estimated reserves could be as high as 55 Tcf. However, like much of sub-Saharan Africa, when a lack of energy infrastructure is paired with the region’s severe level of poverty, development and the potential for future exports are stunted.

In November, it was reported that energy giant Shell, along with JV partners Pavilion Energy and Ophir Energy, had begun its Tanzanian offshore drilling program. The $80-million drilling campaign is part of the Tanzania LNG project, focusing largely in southern Tanzania’s Mafia Deep basin—which occupies an area of about 75,000 km2.

The program saw drillship Noble Globetrotter-II drill one well (Kitatange-1) in Block 1 and another (Bunju-1) in Block 4, meeting exploration requirements set forth by the country’s Ministry of Energy and Minerals’ issued licenses. In December, however, Shell confirmed that good-quality reservoir was encountered, but no hydrocarbons were found. Following the completion of drilling Kitatange-1, a bridging license was awarded for the existing discoveries in Block 1.

Wentworth Resources and its partners have reported significant success in southeastern Tanzania of late, as production at Mnazi Bay field has averaged 44 MMscfd. Bordering the Ruvuma River and extending east into the Indian Ocean, the concession area is situated between the Ruvuma and the offshore Block 1 concessions. According to Wentworth, there are plans for new development and exploration wells in the area this year.

MOZAMBIQUE

Amidst a global energy glut, the Republic of Mozambique has been the highlight of East African E&P. Particularly for Anadarko Petroleum Corp., which made its first initial discovery off the coast of Mozambique about seven years ago, in the Rovuma basin’s Area 1, Fig. 4. The discovery has been hailed as one of the most important natural gas finds in the past 20 years. Since then, the company has discovered more than 75 Tcf of recoverable resources in Area 1.

Fig. 4. The Republic of Mozambique has been the highlight of East African E&P, particularly in Anadarko’s Rovuma basin Area 1 and Eni’s Area 4. Source: Instituto Nacional de Petroleo (INP) Mozambique.

 
Despite the company’s regional success, it has yet to make a decision regarding final investment for a $15-billion LNG project that would help supply that gas to domestic markets. According to Anadarko, the project has the potential to elevate Mozambique to the world’s third-largest gas exporter. “The key is to finish the legal and contractual framework as quickly as possible, as this is a critical element in providing project certainty and securing long-term economic value,” John Peffer, Anadarko’s manager in Mozambique, told Bloomberg.

Sasol, too, has had significant success in Mozambique’s Inhambane province. In January 2016, the company obtained approval from the Mozambique Council of Ministers for its field development plan (FDP), aiming to develop further growth in the region. The production sharing agreement (PSA) license proposed an integrated oil, LPG and gas project, contiguous to Sasol’s existing petroleum production agreement (PPA) area, which is where gas is produced from fields including Pande and Temane.

Sasol’s first well under the phased development plan reportedly was drilled in May 2016. This marked the beginning of the plan’s $1.4-billion phase one, which includes the demarcation and development of the Temane G8, Temane East, Inhassoro G6 and Inhassoro G10 reservoirs. The drilling campaign includes a total of 13 production wells. Meanwhile, installation of oil and LPG production facilities commences, as well. Additionally, the company reported a fifth gas processing train to be established at the central processing facility.

John Sichinga, senior V.P. at Sasol E&P, said, “The spud of the first well in the PSA license area reaffirms Mozambique as the heartland of Sasol’s oil and gas strategy in sub-Saharan Africa, and provides a platform from which to drive socio-economic growth.”

Sasol also announced its first-ever, onshore, 3D seismic campaign in Mozambique. In October, the company reported the acquisition of 115 km2 of data at Inhassoro field. Sichinga explained, “The acquisition of the 3D seismic data in Inhassoro field will significantly enhance our understanding of the structure of the oil accumulations through better resolution and more defined characterization of the reservoir.”

Exxon Mobil obtained assets in Mozambique last year, which was rumored to be easing the country’s expanding debt crisis through tax dividends. Rumors continued to swirl last July as Exxon, along with Qatar Petroleum, was said to be considering the purchase of stakes in fields owned by Anadarko and Eni, potentially generating capital tax gains of approximately $1.3 billion for the Mozambique government.

Eni’s Coral discovery has drawn similar attention, as the company has entered a sales and purchase agreement with BP for the LNG produced by the Coral South Floating LNG facility, planned for installation offshore Mozambique. The agreement, which was reportedly signed in early October, consists of the purchase of LNG for over 20 years.

The initial Area 4 discovery was made in May 2012, nearly 50 mi offshore in the Palma Bay, in the northern province of Cabo Delgado. It is estimated to hold around 15 Tcf of gas-in-place. Eni is the operator of Area 4 with a 70% interest, while its partners, Galp Energia, KOGAS and Empresa Nacionalde Hidrocarbonetos, each hold 10%.

Eni’s plan of development (POD), however, was not approved by the Government of Mozambique’s Council of Ministers until February 2016. It is the first POD approval granted in the Rovuma basin. Claudio Descalzi, Eni’s CEO, described the approval as a “historical milestone.” He said, “It is a fundamental step to progress toward the Final Investment Decision of our project, which envisages the installation of the first Floating LNG facility in Africa, and one of the first in the world.”

Eni did authorize investment for the first phase of the Coral South project in November, which will include the construction of six subsea wells connected to an FLNG facility, with a liquefaction capacity of about 5 Bcm.