While the world waits to see what shape this downturn will take, countries and companies in West Africa have the opportunity and incentive to keep production up and adjust their strategies to position themselves to come out on top. Many projects offshore are due to come online in the next five years and are unlikely to be delayed since costs have already been sunk into them, and two floating LNG (FLNG) projects are moving forward, each vying to be the first FLNG project online in West Africa.

The falling oil prices are causing various energy players around the world to rethink their budgets and activities, but there are opportunities for companies and countries that make smart moves during the downturn.

Countries in West Africa—in particular the Republic of Congo, Gabon and Angola—are largely dependent on oil exports. This reliance will likely translate into potential austerity measures and budget reviews in these nations, PwC said in a report released in February, “Fit for $50 oil in Africa: Will the boom go bust?”

“We also expect an uptake in M&A [merger and acquisition] activity as players with strong balance sheets secure resources from those with less liquidity, many of which could be smaller players with a strong presence on the continent,” the report said. In addition to this type of activity, assets may be put up for sale as part of new or shifting strategies.

While prices are low, companies have the chance to reassess strategies, optimize portfolios, evaluate talent and improve access to capital, the report said. There is also opportunity for new players with strong balance sheets to get into the African market, buying assets at bargain prices.

“Oil and gas companies now need to plan for the upturn that is sure to follow to ensure that the potential boom does not go bust,” said Chris Bredenhann, PwC Africa oil and gas advisory leader. “A number of issues must, therefore, be addressed. This can be done by starting with an organizational stress test including strategic, financial, operational and commercial elements. In situations of low commodity prices, many companies respond with knee-jerk cost reduction programs. This could be more effective if they took the time to understand what specific costs are, how they compare to peers and what reductions are truly possible. Cost reduction programs need to be targeted and realistic.”

Challenges

The players in frontier areas, major gas projects, host governments and service companies are likely to be most at risk, the authors of the PwC report noted.

“[Service] companies will be hit hard globally, but Africa may be an especially vulnerable portion of their portfolios,” it said. While the service companies will likely try to cut back on spending, operators will be pressuring them to drop their prices. Some experts predict that the cost of hiring offshore rigs may fall by almost 40%.

The host governments are also players in the development of resources. Many operators have said they will be renegotiating their exploration license terms. Countries can use this time of low prices as an opportunity to sort out regulatory, legislative and fiscal policies to become more attractive to companies when the price recovers, according to the report.

The difficult logistics and lack of infrastructure in Africa as a whole may complicate matters because they make it hard to respond quickly to demand. “Those who can predict movements in the market ahead of time will perform best in this environment,” the report said.

Downward cost pressures are already hitting the overall exploration costs in Africa, specifically seismic surveying and drilling. This is likely to result in idle rigs and delayed and/or cancelled projects.

Total, for example, is reducing greenfield investment and delaying final investment decisions (FIDs) in some situations. “On some new projects, costs are simply too high, and we are not going to award contracts. We have this situation on Zinia-2 in Angola and on Bonga South West in Nigeria, and we have decided to postpone the FIDs,” said Arnaud Breuillac, president of E&P for Total, in a 2014 results presentation.

The company also is cutting some marginal brownfield projects, notably in mature areas like Congo and Gabon, Breuillac said.

Despite the downturn, progress is expected to continue on many projects in the area. Offshore Ghana, Jubilee development is unlikely to be delayed since costs are already sunk and production is underway, and the TEN project is on track for its 2016 production start. In Nigeria, additional exploration may be put on hold, but development projects are expected to go on as planned. Deepwater subsalt exploration off Congo and Angola is likely to be delayed or cancelled, according to PwC.

With the high cost of drilling offshore Angola, Douglas-Westwood has forecast a drop in deepwater completions in Angola in 2016. However, because the country’s deepwater and ultradeepwater projects are important for pushing offshore production forward during a time of reduced spending, the analyst does not expect to see projects that are past FID being cancelled. With Eni’s West Hub and Total’s CLOV projects onstream, Douglas-Westwood said the short-term outlook for the country is positive and expects Angola to meet its 2015 target production of 2 MMbbl/d.

FLNG

Plans for two floating LNG (FLNG) projects are going forward in West Africa—one from Ophir Energy and one from Golar LNG. FLNG offers a quicker route to market, a lower cost of production compared to an onshore LNG train, flexible field development with staged upstream capex and expandable vessel capacity, Ophir Energy noted in an investors presentation. The calm metocean conditions and relatively dry gas offshore Cameroon and Equatorial Guinea make the area suitable for this type of development.

Ophir Energy’s Equatorial Guinea FLNG project on Block R is progressing, with FID expected in 2016 and first gas in 2019, the company said at Africa Oil Week. The project is being developed to produce 3 million tonnes per annum (MMtpa) of FLNG at 12.5 MMcm/d (440 MMcf/d).

Block R covers 2,450 sq km (946 sq miles) with water depths ranging from 600 m to 1,950 m (1,970 ft to 6,400 ft). There have been eight technical discoveries in the block, six by Ophir. The company has four appraisal wells in the block—Fortuna East, Fortuna West, Fortuna-2 and Tonel North-1. Discovered and risked 2C resources total 96 Bcm (3.4 Tcf) with up to 198 Bcm (7 Tcf) of additional unrisked prospective resources, 56.6 Bcm (2 Tcf) of which are low-risk prospective resources. The company decided these resources are sufficient to support an FLNG train.

In November, Ophir appointed Excelerate Energy LP as its lead midstream partner for the provision of the floating liquefaction and storage facilities at the project. Excelerate will be the lead in a consortium of technology providers that is expected to include Samsung Heavy Industries and Black & Veatch. This is the final key milestone before FEED along with the successful Fortuna-2 drillstem test and an agreement on improved Block R gas fiscal terms with the Ministry of Mines, Industry and Energy (MMIE) of Equatorial Guinea.

The proposed midstream plan will involve a newbuild hull turret-moored vessel classed as floating offshore LNG liquefaction terminal with an LNG storage capacity of 230,000 cu. m (8 MMcf) and side-by-side offloading.

The Block R resources will be developed through a four-phase development starting with the Fortuna Field followed by volumes from the Silenus Complex, Tonel and other smaller discoveries, according to MMIE. The initial phase will involve up to seven production wells.

FLNG also is on the horizon offshore Cameroon with Golar LNG’s planned project. On Dec. 24, 2014, Société de Nationale de Hydrocarbures of Cameroon, Perenco Cameroon and Golar LNG entered into a heads of agreement to develop an FLNG export project 20 km (12 miles) off the coast of Cameroon.

The project will use Golar’s FLNG technology GoFLNG. The agreement dedicated 14 Bcm (500 Bcf) of natural gas reserves from offshore Kribi fields to the project; the gas will be exported to global markets from the GoFLNG facility Golar Hilli, under construction at the Keppel Shipyard in Singapore. The allocated reserves are anticipated to be produced at a rate of 1.2 MMtpa of LNG for about eight years, according to Golar LNG’s preliminary fourth-quarter and financial year 2014 results. There are additional reserves available in the field that may be allocated in the future.

The target for first LNG production in Cameroon is set for April 2017, and it is within budget and on track for the target startup date. The overall Hilli FLNG project progress at the end of January was 30.3%, 4.8% ahead of the scheduled progress.

With the progress on this project, the company reported that there is increased interest in the region for fast-track LNG solutions. Near-term effort is focusing on West African opportunities for the deployment of the Golar Gimi, a sister ship to Hilli, from 2018. Golar LNG has agreements in place for the conversion of the 125,000-cu. m (4.4-MMcf) Gimi with Keppel Shipyard, which has subcontracted Black & Veatch to provide its PRICO technology for the units.

Progressing toward startup

If all goes to plan, the next five years will be busy ones offshore West Africa, with startups scheduled up and down the coast. On deck for 2015 are Chevron’s Lianzi in the unitized offshore zone of Angola and the Republic of Congo and Exxon Mobil’s Kizomba Satellites Phase Two in Angola. The completion of Tullow’s final two Jubilee Phase 1A wells in Ghana also is planned for the first half of 2015, adding well capacity to the field. In preparation for the next phase of investment in the Jubilee Field, Tullow is discussing the approval of future long-term development activities with the government of Ghana.

In 2016 Tullow is expecting to bring the TEN project online in the Republic of Congo, Total has Moho Nord in the Republic of Congo, and Eni is starting up East Hub in Angola.

The TEN project, Tullow’s second major operated deepwater development in Ghana, is 50% complete as of Feb. 11, 2015, and is on budget and on track for first oil in mid-2016. Tullow expects to ramp up production from the project toward FPSO facility capacity of 80,000 bbl/d gross of oil around the end of 2016. The development includes the drilling and completion of up to 24 development wells that will be connected through subsea infrastructure to an FPSO vessel. All 10 of the wells expected to be onstream at startup have been drilled; completion operations were scheduled to start in first-quarter 2015. The conversion of the Centennial Jewel trading tanker into the TEN FPSO vessel is on schedule at the Jurong Shipyard in Singapore.

“The year 2014 was difficult for our industry and a challenging one for Tullow. In response to this and the fall in the oil price, we have reset our business and are focusing our capital expenditure on high-quality, low-cost oil production in West Africa,” Tullow CEO Aidan Heavey said in the year-end results. “The TEN project in Ghana, which remains on track, will increase our net West Africa oil production to more than 100,000 [bbl/d of oil] by the end of 2016, generating substantial cash flows and placing Tullow in a strong position when the sector recovers.”

Total’s Moho Nord development is made up of 28 subsea wellheads tied back to floating production units (FPUs) and 17 more wells from a tension-leg platform. By 2016, the production capacity of the project will be 140,000 boe/d, according to the Total website. The design of Moho Nord’s facilities was created with its environmental footprint in mind. Gas will not be flared under normal operating conditions, and produced water will be reinjected into the wells. Dow Water & Process Solutions and Veolia Water Technologies have designed a multi-element ultrafiltration system to be used on the Moho Nord FPU to treat seawater for reinjection. The ultrafiltration seawater treatment installation will treat 210,000 bbl/d of seawater.

Expected 2017 startups include Total’s Kaombo development offshore Angola, which is based on hybrid-loop technology for multiphase pumping and transport of fluids. Two FPSO vessels will be deployed with a capacity of 100,000 bbl/d each. The project is expected to involve production of several oil deposits among the Gindungo, Gengibre, Canela, Mostarda, Louro, Salsa and Caril fields, Total’s website said.

Eni’s Offshore Cape Three Point (OCTP) project in Ghana was officially given the green light in January. First oil is expected in 2017 and first gas in 2018. The OCTP fields will continuously supply Ghana’s thermal power system from 2018 to 2036.

Total’s Egina and Eni’s Etan, both in Nigeria, are also scheduled to come onstream in 2017.

Maersk’s Chissonga development in Angola is due for startup in 2018. The Chissonga Field is located in the western part of Angola’s Block 16 and is Maersk Oil’s first operated deepwater discovery. Maersk may be looking to reduce costs, with reports of potential re-tenders and farm-outs circulating. Danish newspaper Jyllands-Posten reported in September 2014 that Maersk had proposed the sale of a part of its 65% stake in the project citing sources familiar with the matter, but the company hasn’t confirmed the report.

"We remain committed to developing the Chissonga Field and expect a profitable project. Our ownership in Chissonga is high. We will consider reducing our interest when the project has matured further and the timing is right," Maersk told Offshore Energy Today in September.

Startup of Eni’s Zabazaba Field in Nigeria is scheduled for 2019 and Shell’s Bonga Southwest/Aparo Field in Nigeria in 2020.

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