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Reservoir Producibility Challenges Kenya’s First Oil Ambition

By Toyin Akinosho

Tullow Oil is having challenges of producing the waxy crude in the reservoirs of its operated oil wells onshore Kenya.
There are flow assurance and producibility issues in extracting the crude from the reservoirs, with water injection process experiencing obstacles, according to oil service sources close to the project.

Faced with a government insistence on commencing crude oil export by 2017, Tullow has been working up ways of extracting the hydrocarbon at a cost that is economically feasible, given the low price environment.

The London listed explorer only made Kenya’s first commercial discovery in in April 2012, in the very year that crude oil prices started heading south, but President Uhuru Kenyatta’s government, in power since 2013, is keen on first oil to happen before the next elections in August 2017.

Plans for a joint Kenya-Uganda crude oil pipeline from oil fields in both countries to Kenya’s Indian Ocean port at Lamu or Mombassa went up in smoke when the Ugandans decided on an alternative route through Tanzania in early 2016.

Kenya has since chosen to start small, producing 2,000Barrels of oil Per Day and trucking the crude from the oil fields in Turkana county, in the north of the country to the coast in the south for export, as the country’s refinery is not designed for the sort of crude that is trapped in the geological formations. Andrew Kamau, Permanent Secretary in the Ministry of Energy, says that the Early Oil Pilot Scheme (EOPS), will specifically utilise five existing wells to produce the crude, which will be transported from Turkana to Mombasa by road in insulated tanktainers. “At current oil prices, EOPS is not expected to generate significant revenue”. Mr.Kamau says.

The crude type in East African rift system (South Sudan, Uganda and Kenya) is like a long candle in the pipeline and has to be heated along the way.

“But It’s not just the evacuation infrastructure that is constrained, crude oil extraction at the reservoir level in Kenya has had to be studied extensively”, sources explain. “There has been water injection (meant to drive up the crude into the surface) that ended up damaging the formation”, the sources, who choose not to be named, disclose. “There are issues of what chemicals to use in the stimulating the upward flow of the crude”.

“Subsurface challenges are common in field development”, says Tim O’Hanlon, Tullow’s Vice President for Africa responded when Africa Oil+Gas Report asked him about the issue. “Whatever this issue is, we are dealing with it”.

Tullow has had prior experience in Africa in getting crude out from the subsurface to the surface. Ghana’s Jubilee field didn’t deliver anywhere close to its optimum in the first 18 months because of faulty design of the well completion jobs. But the challenges in Kenya’s oil reservoirs are different from the Ghanaian experience. Before a process like water injection happens, the completion infrastructure would have been installed.

Editor’s note: an earlier version of this report, published in the October 2016 edition of the monthly issue of the Africa Oil+Gas Report, did not contain Mr. Tim O’Hanlon’s views.

Don’t Blame Shell For Everything, Spokesman Laments

Precious Okolobo, media relations manager for Shell Companies in Nigeria, has responded to the persistent fingering of the Anglo Dutch company for just about any environmental hazard in the Niger Delta region.

“SPDC should not be blamed for everything that goes wrong,” Okolobo declared in the last week of 2016, in a response to the allegations of adverse impact of the Gbaran Gas Processing Plant, located in Gbarantoru, Tombia in Nigeria’s Bayelsa State.
The latest name calling had come from a certain Alagoa Morris, described by the press as an environmentalist, requesting for a scientific study on pollution from the plant, which, at 1Billion cubic feet per day capacity, is Shell’s largest processor of natural gas in Nigeria.

The government owned News Agency of Nigeria NAN reported that Morris “made the call in Tombia, near Yenagoa, shortly after an assessment tour of the area”.

NAN said that “Morris was reacting to reports of suspected air pollution from the natural gas gathering and liquefaction facility which is causing breathing discomfort to residents”.

NAN reported that residents of Tombia were complaining of air pollution, allegedly emanating from oil and gas facilities located near the community. “We have received reports of air pollution, very high temperature caused by gas flare and poor fish catch from the Nun River, among others”, Morris reportedly observed. “Who monitors compliance with the EIA to ensure that the steps prescribed to mitigate the negative environmental impacts of the operations of the plant were ameliorated?”, Morris reportedly queried, adding that the country’s environmental law “requires periodic study to determine the environmental implications of the project and ascertain when the indices are out of tolerable limit”.

The NAN report disclosed that Shell’s spokesperson Precious Okolobo, denied that the air pollution was from the company’s gas processing and gathering facility.

“There is no air pollution from our Gbarantoru plant; the plant is running efficiently,” Okolobo reportedly said. “He said that a similar occurrence was reported in Port Harcourt where there was no gas plant”, NAN said of Okolobo.
“There is a general problem that people do not understand and SPDC should not be blamed for everything that goes wrong,” Okolobo said.

Woodmac Was Wrong About Ohaji South, But Right about The Avengers

By ToyinAkinosho, Publisher

In the event, Wood Mackenzie, the oil and gas scout and hydrocarbon industry analyst, was wrong about the volume of natural gas reserves in the Ohaji South field in Seplat operated Oil Mining Lease (OML) 53.

The New Jersey based, Verisk Analytics owned company was, however right about what would happen in the Niger Delta region if (Nigeria’s current President) Muhammadu Buhari beat (then incumbent) Goodluck Jonathan, of the PDP, in the country’s polls in March 2015.

Seplat acquired the 40% equity belonging to Chevron in OML 53 in 2014 and finalized the deal after ministerial consent in early 2015. The Ohaji South field was pivotal to that acquisition.

Whereas Woodmac declared, in early 2015, that Ohaji South, as a gas tank, was “non-commercial”, with “611 Bcf of gas which is at the upper end of potentially recoverable resources”, Seplat has indicated, more than a year later, that it is carrying more than 4Trillion cubic feet in the field. The London listed operator has gone on a road show to raise about$1.3Billion for the midstream to downstream components of the development of the unitized Shell-operated Assa North and the Ohaji South (Full story in the current issue of Africa Oil+Gas Report). Planned capacity is 600MMscf/d.

Meanwhile, Woodmac’s negative assessment of the above ground challenges in the Niger Delta region has proven to be on point.

In a widely distributed “intelligence report on the prospect of the 2015 Presidential and National Assembly elections on the Oil Industry”, Woodmac observed that a win by Goodluck Jonathan would be the least disruptive for the oil sector. The status quo would mean business as usual, although a reduced mandate for the PDP would increase challenges for the passage of legislation, including the controversial Petroleum Industry Bill (PIB).

“A victory by the opposition APC would be the most uncertain scenario for the oil sector, both from a security and legislative perspective”, the analyst warned. “The militant group Movement for the Emancipation of the Niger Delta (MEND) has stated that it would resume attacks in the Delta, if Delta-native Jonathan is not returned to power.”

Since February 2016, a new group, named Niger Delta Avengers, has done even more than MEND had ever done to disrupt Nigeria’s oil production: the entire TransForcardos system, delivering about a fifth of the country’s output, has been shut in for 10 months of 2016.

The Projects of 2017

2017 will pull in more petrodollars into Africa than 2016. More of the proposed‘transformational projects’ will leave the drawing board and take Final Investment Decision in the new year.

The Seplat operated $1.3Billion Assa North –Ohaji South (ANOS), gas development project is on course for FID (See story on Page 11).

Commercial sanction for oil production in Uganda and Kenya, which looked so uncertain this time last year, is so sure now. The decision, if not made in 2017, will be made very early in 2018.

The most stubborn of the dark clouds surrounding the Ophir operated, 2.2MMTPA Fortuna Floating LNG off Equatorial Guinea have been lifted. The road is clearer for FID to happen in 2017, with the first gas pushed forward to 2020. Unlike the ENI operated CORAL Floating LNG (3MTPA capacity) to be sited off the coast of Mozambique, Fortuna hasn’t sold its entire supplies. And the way it’s going, CORAL is likely to come on stream before Fortuna.

As we predicted last year, ENI has been aggressively developing Zohr, the mammoth gas find it made in the deep waters of the Mediterranean in August 2015. It is on course to deliver first gas from this 30Trillion cubic feet property by the first quarter of 2018.

There’s pressure on both Anadarko and ENI to take FID on the largest single LNG trains ever to be installed on the continent; the onshore 6MMTPA projects (apiece) in Mozambique. The LNG market is so murky now that neither side wants to nail down a date. Still it’s tougher for Anadarko to take that decision than ENI, who seems to have found a formula for getting ahead with projects.

We asked you not to expect much exploration activity in Angola and Nigeria in 2016; and we predicted an uptick in infill drilling in the latter and lower rig count in the former. In the event, the two countries were disappointing. The resurgence in rig activity expected in Nigeria didn’t happen in 2016, but watch out for Nigeria in 2017. For Angola, the adventure will continue to be on hold.

Kosmos is keen on finding oil outboard of the gas discoveries in the Mauritania-Senegal area, so it will be doing a targeted three well campaign. The American minnow wants to be like Cairn, which has been the only independent to have discovered commercial quantities of crude oil offshore Africa in the current low price regime.

Congo continues its bid round, as does Equatorial Guinea. Egypt too, the perennial bid round holder, has announced its umpteen lease sale. The deal flow market was lack lustre in 2016, and we don’t expect significant shift in the coming year.

This full bodied Who is doing what and where in 2017 edition is yours for the taking.
The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions.

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Lekoil Opts Out of “Pipeline to Terminal” System

Lekoil will not evacuate the crude from Otakikpo field, in Nigeria’s eastern Niger Delta, through the traditional pipeline to terminal route favoured by most Nigerian Independents operating in the region.

The company has commenced production from the field into tanks, starting with around 5,000Barrels Per Day. Lekoil is finalising the construction of a six kilometre pipeline to transport the crude to the tanker offloading manifold.

Anglo Dutch major Shell, which used to operate the field, had offered to rebuild the Eastern Creek Trunk Line (ECTL), which is severely vandalised, to evacuate the Otakikpo crude to the Bonny Terminal. But Lekoil turned down the offer because it felt that there was a high chance that the pipeline would be damaged again.

“I have often thought we should avoid that path to market”, Lekan Akinyanmi, the company’s CEO told Africa Oil+Gas Report.

Four such pipeline to terminal routes in the country: The TransForcados System, The Nembe Creek Trunk Line, The Trans Niger Pipeline, The Line to Qua Ibue Terminal and The Kwale To Brass Line, have been shut down by militants at various times in 2016, with the TransForcados System out for all of 10 months.

“Our field is located on the shoreline”, Akinyanmi explains. “Shuttle tanker picks up the crude from our line to the FSO”.

Floating Production Unit Sails Close to Congo for Moho Nord Start Up

French major TOTAL sys that the arrival of a Floating Production Unit in the Atlantic waters offshore Congo Brazzaville is “imminent”.
The European giant is looking forward to start up production in Moho Nord in the first quarter of 2017.
The project will deliver 100,000BOPD at peak.

“Development drilling started October 2016”, says Guy Maurice, TOTAL’s Vice President E&P Africa. The Tension Leg Platform (TLP) is already on location.

→   Read the rest of this entry

Cote d’Ivoire Gets Close to $700MM Loan From IMF

“builds on the solid performance under the previous Fund-supported programme”

The Executive Board of the International Monetary Fund (IMF) has approved two three-year arrangements under the Extended Credit Facility (ECF)[1] and the Extended Fund Facility (EFF)[2] for Côte d’Ivoire for a combined total of SDR 487.8Million (about US$658.9Million, or 75% of Côte d’Ivoire’s quota) to support the country’s economic and financial reform programme.

“Côte d’Ivoire’s economy has made an impressive turnaround since 2012 and its outlook remains favourable”, the IMF says in a release. “Nevertheless, reducing poverty and closing human capital and infrastructure gaps will take time, and structural bottlenecks pose challenges. Against this backdrop, the authorities’ new economic programme under the Extended Credit Facility and Extended Fund Facility appropriately focuses on inclusive, sustainable growth; structural transformation of the economy; and poverty reduction. The programme builds on the solid performance under the previous Fund-supported programme in 2011–15 and is expected to catalyze official and private financing”.

The IMF Executive Board’s decision will enable an immediate disbursement of total amount of SDR 69.686Million (about $94.1Million). The remaining amount will be phased over the duration of the programme, subject to semi-annual reviews.

The Fund says that the new programme will aim to achieve a sustainable balance of payments position, inclusive growth, and poverty reduction by investing in infrastructure and priority social projects. It will also focus on containing current spending, catalyzing official and private financing, and building resilience to future economic shocks.

Côte d’Ivoire’s economy has achieved an impressive turnaround since 2012. Political normalization, supportive fiscal policy facilitated by extensive debt relief, reforms to improve the business climate, and rising world cocoa prices have enabled a strong rebound in economic activity. Real GDP grew by 9% per year on average during 2012–15, driven by investment and consumption, partly reversing a decade-long fall in per capita income.

The robust economic performance since 2012 has not fully shed the socio-economic legacies of decades of sluggish growth compounded by conflict. Significant disparities remain across the country, and in the areas of education attainment, employment and income. As such, the authorities’ 2016-20 National Development Plan (NDP) appropriately prioritizes inclusive and sustainable growth, focusing on structural transformation and improving living standards.

“The authorities’ goal is to maintain fiscal discipline and strengthen buffers for future shocks, while creating fiscal space for infrastructure and social spending. To this end, improving tax administration and adopting new tax policy measures will help increase revenue mobilization. Containing current spending will be also critical, while prudent public financial and debt management will help ensure debt sustainability. Enhancing surveillance of public enterprises and extending budget coverage to extra-budgetary entities would strengthen control over all government’s activities and improve transparency. Reinforcing the framework for public-private partnerships and pressing ahead with the reform of public enterprises will mitigate fiscal risks.

Solid macroeconomic performance continued in the first half of 2016 notwithstanding the impact of a drought on agriculture, and real GDP growth is projected at around 8% for the entire year. The budget deficit is projected at 4% of GDP in 2016, reflecting higher spending, including for security, health and education. Economic growth is forecast to remain strong over the medium term, averaging 7.7% per year during 2017-19, reflecting buoyant domestic demand. Inflation is projected to remain below 3%. Reflecting investment-driven imports, the external current account deficit would widen to about 2.5% of GDP.

Programme Summary

Building on progress made under the 2012-15 programme, the new three-year programme will support the broad objectives of the NDP and help implement a sustainable balance of payments position, inclusive growth, and poverty reduction.

The authorities’ aim to create fiscal space for infrastructure investment and social spending, and strengthen policy buffers; maintain public debt on a sustainable path; facilitate debt restructuring of the national oil refinery and enhance monitoring of the debts of state-owned enterprises; address vulnerabilities in the public banks; improve the business climate; enhance the quality of economic data; and increase Côte d’Ivoire’s contribution to the regional foreign exchange reserves pool.

Under the programme’s planned policies, the government’s budget deficit would converge to the West African Economic and Monetary Union norm of 3% of GDP by 2019 in order to preserve public debt sustainability and support the regional international reserves pool. Prudent public financial and debt management practices along with public enterprise reform would ensure fiscal sustainability and mitigate fiscal risks. Financial sector polices would focus on reducing vulnerabilities, including in the public banks, and fostering financial inclusion. Structural reforms will improve the business environment. Measures to improve the quality and dissemination of economic statistics will support policy making and investment.


Côte d’Ivoire, which became a member of the IMF on March 11, 1963, has an IMF quota of SDR 650.40Million.

For additional information on the IMF and Côte d’Ivoire, see:


Nigeria Oil Industry, The Decline, 2006 to 2016

TOYIN AKINOSHO examines how a culture of rent has reduced the potentials of what could have been the largest hydrocarbon industry in Africa

At an industry conference in early August 2011, Austen Oniwon-CEO of NNPC, the Nigerian state hydrocarbon company-made a 23 -slide presentation to a roomful of ranking Nigerian petroleum engineers,
Mr Oniwon took his gaze back from the screen to the 200+ delegates attending the main roundtable session of the Society of Petroleum Engineers’ conference, in the Banquet Hall of the Hilton in Abuja.
“Everybody talks about the Petroleum Industry Bill (PIB)”, Oniwon declared. “I think we should agree that the PIB would be passed and when the PIB comes, all of us would just have to re-adjust to whatever the new PIB comes out with. “Therefore, we should stop procrastinating and saying we are not going to take decisions because the PIB has not been passed”.
Oniwon knew he had just the right audience. Flanking him, on the panel, were chief executives of the country’s two largest oil producing companies. Mutiu Sumonu, chairof the Shell Companies in Nigeria (2010 average operated production~l,000,000BOPD)and Mark Ward, chairof ExxonMobil companies in Nigeria (2010 average operated production~750,000BOPD). Together, Shell and ExxonMobil, in joint venture with NNPC, delivered around two thirds of Nigeria’s output.
The NNPC chieftain dangled some carrot: ” I can tell from what I know from the PIB, that the fiscal regime that will emerge is not going to be any worse than what operates in the West African sub- region. I believe if you can do business under these regimes, then, those that would do business under the regime, would be very happy to business in Nigeria, under the new PIB when it emerges.
Then he brought out the stick: “Opportunities available in the industry would not wait for the joint- venture partners and their colleagues, as others would come and fill the gap, if they failed to act promptly.”
To rephrase the last statement: ‘Nigeria was a great opportunity that everybody was keen to get into. If those who held its assets today did not appreciate what they had, there were others waiting to grab these opportunities’.

Coming from the CEO of the state hydrocarbon company, such utterance requires close examination. The immediate question is that: is Nigeria what it’s cut out to be? “The three leading indices of a healthy oil and gas landscape are: rig count, production growth and foreign direct investment”, says Jerry Tolkien an E&P analyst based in Cairo. “These are not at this point happening in Nigeria”.
Nigeria produced an average of 2.42MMBOPD in 2010, with capacity for far less than 3.5MMBOPD. The figures are a significant shortfall of its 2010 target, which envisaged capacity for production of at least 4MM- BOPD, but things could have been worse, as the ensuing story shows, and government officials, in public, have been recently expressing the view that the country is at least producing more crude oil per day than Angola. Such views are suggestive of a low water mark in Nigeria’s expectations of its main industry. What exactly happened?
The Boom Years: 1995 To 2005 The state of Nigeria’s E&P industry today is the result of several actions of state and non state actors in the last 15 years. But in the 10 years leading to 2006, the country experienced a sort of hydrocarbon boom.
• Bouyed by very generous incentives, including close to zero % royalty, lOCs plucked a series of deepwater discoveries between 1996 and 1999, putting Nigeria squarely on the global deepwater radar. By 2002, there were confirmed six billion barrels of new oil, in water depths between 200metres and 1,500 metres. Whenever the energy press reported that the Gulf Of Guinea was racing ahead of Brazil and the Gulf of Mexico as the deepwater exploration hot spot, they were largely referring to Nigeria and Angola.
• As the country returned to democracy in 1999, it was also commissioning a $3.8Billion Liquefied Natural Gas plant.
• Nigeria held an open transparent bid round in 2000, a widely subscribed lease sale, which featured such distinguished newcomers as Devon Energy, the large American midsized independent and Petrobras, the Brazilian giant.
• The same year, the government set up an Oil and Gas Reform Implementation Committee (OGIC), to carry out a comprehensive reform of the oil industry. This, in effect, led to the Petroleum Industry Bill.
• A rigorous, comprehensive bid round for marginal fields was conducted between 2002 and 2003, for the purpose of awarding undeveloped discoveries, located in the acreages of oil majors, to Nigerian entrepreneurs, in order to build indigenous capacity in wholesale E&P operations and in effect, boost the percentage of oil production that’s attributable to homegrown firms.
• Three deepwater fields came on stream, at a total of around 450,000BOPD on average, between 2003 and 2006. The country recorded its highest crude oil production in history in 2005, at roughly2.5MMBOPD.
• An ambitious local content programme, launched in 2002, picked up speed between 2005 and 2007, with the state enforcing, and operators committing, to “utilization of Nigerian human and material resources”. A key plank of the programme was domiciliation of goods and services supply. One deepwater project committed to the fabrication of approximately 6000 tonnes of equipment and structural modules at fabrication yards in Nigeria, a landmark development. Engineering design services continued to increase; one engineering contractor completed over 50,000 man-hours of engineering design in Nigeria between 2006 and 2007. One major operator commenced a redevelopment project of a cluster of fields which outlined a very aggressive Nigerian Content plan, including the design and construction of whole new flowstations and integration of substantial module in Nigeria, a marked departure from the token structural fabrication that had been done in the past.

The Decline: 2006 To-?

• The Emergence of MEND and the semi-official Resistance. It was in the midst of this tempo, in February 2006, that the Movement For The Emancipation of Niger Delta announced its emergence, with bomb blasts of strategic installations, especially the Escravos River part of the pipeline that delivers natural gas to the country’s largest power plant as well as the major industries in Lagos, the coastal city that is the country’s financial hub. The attack heightened the sense of urgency about what has always been termed “the Niger Delta crisis”. The damage on the gas pipeline, part of Nigeria’s domestic gas artery, took out Chevron’s daily supply of 150Mil- lion standard cubic feet (MMscf) to the Escravos-Lagos Pipeline System (ELPS), which feeds all the Thermal Power Plants in the southwest and midwest of the country, including Egbin, Papaianto, Omotosho and Delta Power stations, with combined nameplate capacity of about 2,000Megawatts (MW) of electricity.
But it also initiated a significant wind down on crude oil production on the shelf, as well as any meaningful progress that the national content programme was beginning to make. As attacks on facilities were launched after more severe attacks, with kidnappings of international oil workers and slaughtering of Nigerian soldiers, crude oil output fell to as low as 2.06MMBOPD in 2009; a figure that would have been far less, had two new deepwater fields not come on stream between 2008 and 2009.
In spite of the low intensity war on the production field, which curbed even the willingness to do exploration work, a new government, elected into power in 2007, sought as policy, a revision of ongoing hydrocarbon projects. A raft of gas to power projects were stopped on suspicion that too much money had been spent without any visible activity on ground. Two proposed Greenfield LNG projects, totaling 30Million Tonnes Per Year in scope and expected to be delivered latest 2013, were held up for scrutiny as government’s body language signaled increased commitment to domestic gas production, in favour of export projects, even without clear fiscal consensus between government and producers for domestic gas output.

Several deepwater projects have fallen victims of extended negotiations and back-and forth between officials of the National Petroleum Investment Management Services (NAPIMS), the subsidiary of the Nigerian state hydrocarbon Company (NNPC), which interfaces with Joint Venture partners.
It is known that the so-called “NAPIMS approval process” is one of the most drawn out in the global oil patch.
Between January 2010 and August 2011, NAPIMS muscled in on small gas -flare- out projects that were to be awarded to small contractors by oil majors who consider them quite uneconomic to be incorporated into large scale gas processing facilities.
• Bid Round Quality Deteriorated: Meanwhile, the quality of acreage bid round has declined since 2004, such that, even the Department Of Petroleum Resources, the industry regulator, declared the 2007 lease sale as largely a failure.
• The trickster God of Geology heralds Exploration Fatigue: One other culprit has been geology. While Nigeria’s deepwater exploration profile had been on to a good start in the mid 90s, there has been a series of disappointing dry holes, especially in the western and southern flanks of the basin, the so -called outer toe thrust belt. Chevron’s Iroko- 1(OPL 250)ENI’s Dou-1 and Emein-l(OPL 244), Devon Energy’s Pina 1 and Tari 1, (OPL 256), Petrobras’s Erinmi 1(OPL 324), Phillips’ Onigun 1(OPL318), all were either dry holes or have encountered marginal gas or little oil shows between 2001 and 2006, setting the stage for some sort of exploration fatigue in Nigeria’s deepwater, at a time when deepwater exploration success was about to break out in the marginal basins of the Gulf Of Guinea, including the Cape Three Points Sub Basin (Ghana) and the Sierra Leone-Liberian Basin.
Still, the difficult challenges of geology can be managed by host government, with the right politics. BG’s two dry holes in deepwater Nigeria (between 2008 and 2009) cost the company around $200Million, a vast sinkhole, but the UK independent’s enthusiasm about the country was already suffering reverses with the lack of progress of OK LNG and Brass LNG. Suddenly, its portfolio looked extremely lean. With these grim prospects, BG left Nigeria, some would say, in haste.Devon Energy, Pioneer and Occidental, three significant American independents, who showed up with the promise offered by Nigeria’s return to democracy at the turn of the 21st century, have largely left on this basis.
• Cash Call Debacle Fouls Up Things Add to this potent mix mounting cash calls: the continuous inability of the NNPC to fund its share of approved budgets, for projects by its JV partners. And yet government bureaucrats, blissfully ignorant that this was a cake that was not growing, kept coming up with statements like Oniwon’s: “If you can’t do it, get out: others are waiting”. Centrica, the UK gas company, took the cue. It sold its assets to Newcross, a Nigerian company.
• PIB Became the Scapegoat..As debate over the PIB was fought in the media, perception of Nigeria as an investment destination for oil and gas is what has suffered the most. But, as is obvious from above, PIB is only a part of the story. Nigeria was having all the challenges of a third world hydrocarbon economy that it could have. The uncertainty in the passing of the PIB merely added to these challenges and became the calling card.
• Shell Divestment: How NNPC Arrested the Revolution. Then came the decision by Shell to divest from a number of assets in Nigeria. In 2008, the company sold its participating interest in two non- operated interests in the deepwater terrain. In 2010, Shell announced that it had started selling acreages on the shelf (land, swamp and shallow water) too. It sold its 30% stake in OMLs 4, 38 and 41, three acreages on land and in swamp of the Midwest part of the country along with partners ENI and TOTAL, who had agreed to also sell their combined 15% stakes to a local company named Seplat(an incorporated joint venture of two indigenous companies Platform and Shebah and French minnow Mauriel et Prom). Shell & Co came out less than a year later to sell their interests in another lease, OML 26, to First Hydrocarbon Company, a local subsidiary of Afren, the UK listed producer. While these divestments, led by the largest operator in the land, may indicate a surge of uncertainty in the Nigerian petroleum sector, the underlining message has been that it is an opportunity for Nigerian private sector companies to weigh in as E&P operatives.
Shell then went on to call for a bid, by Nigerian companies, for four more of its acreages, including Oil Mining Leases (OMLs) 30, 34, 40 and 42.
A close look at what has transpired since that bid process came to conclusion, clarifies the notion that the Nigerian government, through its ranking officials at both the Ministry Of Petroleum and the NNPC, have been active participants, all along, in sending the signals that the Nigerian space was not friendly to investors.
The insistence of NPDC, the operating arm of NNPC, to step in and claim operatorship of four acreages sold to Nigerian companies by Shell, ENI and TOTAL is a clear statement that Nigerian government, as an incorporated entity, is competing aggressively against those to which it should otherwise be opening its doors.
A noteworthy trend of the years of the locust(2006-2011) for Nigeria’s hydrocarbon industry has been the strengthening of the spirit of local content, even if it means, an increasing sense of self entitlement(sometimes worrisome) among the country’s bourgeoning business class.
Although Conoil, the country’s first truly independent, growth-conscious, indigenous E&P company, emerged after a discretionary lease award to local businessmen in 1991, it wasn’t until after the Marginal field exercise of 2003, that a class of homegrown E&P companies started to take shape. By January 2010, there existed, in the country, at least five companies, producing anything from 1,000 to 20,000BOPD each. They were generally small, but had gradually amassed significant experience in upstream operatorship of hydrocarbon property -acquired in the process of raising fund to drill wells, running oil field operations, evacuating oil to export facility, building gas processing facilities, even constructing topping plants all with money invested by Nigerians. There is nowhere else in Africa that this is happening.
Shell had made it clear, with the example of Seplat, that there were local companies that could be relied on to run with the torch as local champions.
When, around mid 2010, Shell invited a number of similar companies to purchase the same percentage stake in four other acreages, out of its remaining 35 operated leases, industry analysts began to predict the emergence of Nigerian midsized independents, with capacity to produce as much as 40,000BOPD each on average in the medium term to 2015. Companies in this class were coming in with money sourced from abroad and this time they partnered in incorporated joint ventures, not as passive venturers who collect rent and leave the foreigners to maximize experience and build capacity while Nigerians remain on the margins as was the case in the earliest period of the indigenous ownership policy (1975 to 1998). In effect, what the sale of Shell’s assets to Nigerian companies was meant to do was to get on the next stage of the ladder from where the marginal field exercise had reached.
With Seplat’s operated production zooming off to 35,000BOPD by 2012, about doubling the volume itinherited from Shell in August 2010 and the company targeting 135,000BOPD in the medium term, an elaborate example had been set.
It seemed, by commonsense, that government would be all out to encourage this kind of company: a class of nifty, midsized independents operating a number of oil fields in Nigeria and writing an alternative story about Africa’s private sector capability to venture into E&P investment not as contractors, but as producers. For once, it doesn’t have to be one huge, all-powerful National Company driving everything. It would be an enlarged space, a mix of majors and minors and the mandatory national company, all co-existing. But the Nigerian government didn’t see it that way. The NNPC saw the Shell divestment as an opportunity to increase NNPC’s operated production, in effect choking off the burgeoning, private Nigerian E&P enterprise.
On Tuesday May 24, 2011, NNPC took out full page adverts in newspapers warning investors to beware of buying interests in certain hydrocarbon assets in the country. The statement, headlined “Nigerian National Petroleum Corporation CAVEAT EMPTOR”, was published in at least three widely circulating Nigerian dailies.
What has been most instructive is how far NPDC was prepared to go to show it could “operate”. As a rule, the NNPC, which is NPDC’s parent company, had struggled in the previous 10 years to pay its share of the cost of projects with its partners. So it is understandable that the NPDC would have issues funding its own share of field development and ongoing production in the leases sold by Shell and Co.
But the divestment itself was an opportunity for NPDC to work with Nigerian companies to find a way out of the funding dilemma. It was an opportunity for NPDC to build its own technical capacity, through working with Nigerian companies who had bought and were keen on operating these acreages within the ambit of the incorporated joint ventures that they had formed with European lOCs.

Instead, NPDC signed a strategic agreement with Atlantic Energy Drilling Concept, which had never featured in E&P activities either in Nigeria or elsewhere, “to provide funds for carrying out Petroleum operations arc support NPDC with technical expertise”. The terms of agreement were executed in an unethical patronage manner.
But what’s important in the context of this article is how the state hydrocarbon company considers it so crucial to undermine the enthusiasm of a collection of Nigerian companies to build Nigerian E&P capacity outside of the purview of the state.
In the event, what could have been the exception to the rule of failed initiatives and projects in the Nigerian oil industry from 2005 to date, was disrupted by the state.
As the NPDC took over, none of the four companies which bought into the Shell assets after Seplat could increase their production the way Seplat did.
Next week, we should continue the discussion about the inherent contradictions and deliberate options for failure by state actors, in running the Nigerian hydrocarbon industry, from 2006 to 2016.

IMF Not Impressed By Mozambique’s Performance

The International Monetary Fund (IMF) is not very excited by the economic outlook in Mozambique, a country which looks forward to be Africa’s next oil producer and perhaps its largest gas hub in the medium term.

“The outlook remains challenging. Growth has declined in 2016 and is now projected at 3.4% (down from 6.6% in 2015)”, reports the IMF staff team which visited the southeast African country from December 1-12, 2016.

“Inflation, which is expected to peak soon, is still high. Increased spending on wages and salaries is putting pressure on fiscal policy, although the 2016 budget deficit is still expected to narrow to about 6% of GDP, in line with the revised budget law adopted by Parliament in July 2016.

The team does not discountenance the loan that the country’s last government, which gave up power in 2015, had kept hidden. “Total public debt, mostly denominated in foreign currency, increased to distressed levels in 2016 owing to the addition of the previously undisclosed loans worth $1.4 billion (10.7% of GDP) combined with the impact of the exchange rate depreciation.

Mozambique looks forward to its first crude oil production: Sasol the South African synfuel giant is developing some small crude oil reservoirs in an essentially gas prone field onshore. (Fuller details here)The country also expects commissioning, by Italian giant ENI, of a 3.3Million Tons Per Annum (3.3MMTPA) floating LNG by 2020.

But the IMF team, headed by Michel Lazare, were focused on the current economic term sheets.

“There have been several positive economic developments over the last few months”, the report concedes .“The monetary policy tightening since October 2016 has resulted in a rebalancing of the foreign exchange market, with the metical appreciating by about 8% vis-à-vis the US dollar since end-September, following a 40% depreciation over the first nine months of the year.

Moreover, the current account deficit of the balance of payments has been narrowing rapidly, helped by a marked drop in imports and somewhat more stable exports, which are supported by higher global coal prices. As a result, despite limited foreign direct investment flows and donor financing, the stock of international reserves has recently started to increase and is expected to cover about 3.5 months of non-mega project imports at end-2016”.

The report notes that“additional policy adjustments are required to further consolidate macroeconomic and financial stability, and pave the way for a Fund-supported programme.

“Notably, further fiscal consolidation is needed in 2017. Special attention should be given to containing the expansion of the wage bill and gradually eliminating general price subsidies. Protecting critical social programs and reinforcing the social safety net should cushion the impact of these measures on the most vulnerable segments of the population. Preserving fiscal sustainability also requires limiting the fiscal risks presented by some large public enterprises. Mobilizing additional revenue by curtailing tax exemptions and strengthening revenue administration is also essential. In addition, the staff team stressed that a strong commitment to fiscal adjustment is an essential element to facilitate ongoing debt restructuring discussions with creditors.

“On the monetary side, the mission welcomed the central bank’s commitment to reduce inflation while safeguarding financial stability. To address financial sector vulnerabilities, the mission urged the central bank to remain vigilant to risks, ensure adequate liquidity provision to the economy, and continue to step up supervision and enforcement of prudential regulations.

“The mission welcomed the agreement reached with the General Prosecutor’s Office and the Embassy of Sweden on the detailed terms of reference and the selection of an international company to conduct the ongoing independent audit of EMATUM, Proindicus and MAM. In due course, it will be important to consider strong governance reforms to address findings and recommendations from the audit report.

“Discussions on a new IMF-supported program will continue in the first part of 2017. The mission thanks the authorities for their continued hospitality and close cooperation.”

Aveon Offshore delivers the Foundation Support Structures (FSS) For Egina Subsea

Aveon Offshore, the Nigerian engineering and fabrication services company, says it has successfully completed fabrication of six Foundation Support Structures and loaded out these components in respect of the Egina Subsea Production System (Egina SPS) project. The load out and sail away of these structures occurred at the end of November 2016.

The Egina oil field is being developed by TOTAL Upstream Nigeria (24%) in partnership with CNOOC (45%), Sapetro (15%) and Petrobras (16%). Egina is the French major’s third deep offshore development in the West African country. Production is scheduled to begin in 2018.

Aveon Offshore, who was awarded part of the subsea contract by the American oil service company FMC Technologies, says it has already delivered some of the project scope including sixteen Umbilical Termination Boxes and subsea tree fabrications (Frames, Permanent Guide Base and Gasmats) throughout 2015 and 2016 and assures that “the fabrication of remaining subsea tree fabrications will be completed for delivery by the end of the 1st Quarter of 2017.

The fabrication of six Manifolds is also close to completion which will allow delivery during the first half of 2017 together with five completed Subsea Distribution Modules. Twenty one multibore production well jumpers will be delivered throughout 2017 and 2018”.

Aveon Offshore’s contract, awarded in 2013, was for the fabrication and load-out of approximately 5,000 tons of subsea structures including six manifolds with associated Suction piles, various subsea tree frame elements, jumpers and control systems for the Egina Project.

The project is being executed at Aveon Offshore’s 300,000 Sqm fabrication yard in Rumuolumeni near Port Harcourt.

In order to accommodate the workload generated by the project, capex investment was made by FMC Technologies and TOTAL, to upgrade Aveons’ site in Rumuolumeni. As a result a dedicated Carbon Steel workshop, Duplex welding facilities and Painting workshops of over 8,000 sqm, Electrical power and distribution and more were added to the yard’s existing infrastructure and existing premises such as Quayside were completely reinforced. The project has generated more than 3,000,000 productive man-hours in the last three years.

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