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Shell Plots A Return To Angola

By Moses Aremu, Editor

Anglo Dutch major Shell is keen on purchasing the operator stake in Angola’s Blocks 21/09 and 20/11, two very prospective acreages in the deepwater Kwanza Basin. These are the assets that Cobalt Energy, the US minnow, operated in the country until 2015, when it sought to sell its 40% stake in them to Sonangol, the state hydrocarbon company, for $1.75Billion.

That transaction fell apart in 2016, and Cobalt took Sonangol to international arbitration over its failure to extend the licence deadlines. The two companies reached a settlement-Sonangol reported in December 2017- which called for Sonangol paying $150Million by February 23, 2018 and a further $350Million by July 1, 2018.  

Sonangol has now put up, for auction, Cobalt’s 40% stake and operatorship of these assets.

Observers see Shell’s interest in the blocks as a way of re-entering the country. Cobalt’s 2016 annual report indicated that it made seven discoveries in the blocks with a total of 750Million gross barrels of oil equivalent. A significant part of the volume is natural gas, the hydrocarbon fluid type that Shell is most interested in trading with.

Shell went to Sonangol’s data showroom in Houston on early June 2018, with a delegation of about a dozen officials and the company was widely speculated as the leading contender for the assets.

Shell was one of the earliest entrants into the deepwater activity in Angola between the early and late 1990s. Its Bengo-1 well, drilled in Block 16, tested 1,780BOPD in one reservoir, the first discovery in deepwater Angola. The company’s initial enthusiasm about the structure was restrained by the well’s high gas cap and pancake thin reservoirs, but Shell was willing to risk an early production. The enthusiasm waned when Bengo-2 turned out to miss even the thin bed that was of such fascinating interest in Bengo-1. Then the more it drilled, the less fortunate the company got.  Whereas other operators: TOTAL, Chevron, ExxonMobil, even BP, went on to make discovery after giant discovery, Shell got trapped in a run of ill luck, drilling nine wells in Block 16, most with marginal results. This is curious, because Block 16 is located between the two most successful leases in the country: ExxonMobil’s Block 15 to the north and TOTAL’s Block 17 to the south. The last well Shell drilled in Block 16 was Chiluango-1 which was abandoned in early November 1998 as a dry well. In 1999, the company packed out of Angola and shifted its gaze to Nigeria where, by 1996, it had become sure of the deliverability of its huge Bonga structure, located in the upper slope of the deepwater Niger Delta.


Austin Avuru: Three Hard Knocks in The School of Life

By Toyin Akinosho

Austin Avuru, Chief Executive of Seplat, Africa’s largest homegrown E&P firm, most vividly remembers the day the company lost the bid for Oil Mining Lease (OML) 29 in eastern Nigeria.

“That was one of our lowest points in this company because the acreage was going to be a company changing asset for us: it was going to give us the size that we seek”, Avuru reflected, in his office in Lagos, Nigeria, recently, as he prepared to celebrate a milestone that ties his own personal growth with Nigeria’s 60 year trajectory as an oil producing nation.

OML 29 is a sprawling, highly valuable property, spanning an area of 983 square kilometres (or 242,550 acres) onshore and holding some 2.2Billion barrels of oil equivalent, in proved and probable (P1+P2) reserves, in nine fields, according to a 2013 Competent Persons Report by NNS .

To put some context to the figures: Seplat, today, produces, on a gross basis, slightly higher than 60,000Barrels of crude oil and condensates and 400Million standard cubic feet of gas from five acreages, whereas OML 29 alone produces over 80,000BOPD, when there is no vandalism of evacuation pipeline.

“We had the cash on the table but we did not win OML 29. We were only a hundred million dollars away from Aiteo’s bid (to Shell, which was leading a divestment of itself, TOTAL and ENI from the tract). It was insignificant because we were talking about a $2.4Billion bid and $100Miilion was less than 5% of that, so it was insignificant”.

Avuru wonders whether the inability of Seplat to clinch OML 29 wasn’t due to “the politics of who Shell figured would more easily get the approval for the purchase” from the Nigerian government. “Otherwise they” (the company which won the asset) “couldn’t pay for one year after they got it, while we were going to write our cheque immediately because we had our money ready”.

It was the loss of OML29 that made such acreages as OMLs 25 and OML 55 important to Seplat, Avuru noted. “All these issues about OML 25 and OML 55 came because we lost the big fish”.

His disappointment about OML 29, Avuru explained, pales in comparison with a particular challenge he had faced when he was building Platform Petroleum, a marginal field operator. This was before he helped bring Platform, Shebah Exploration and M&P together to create Seplat.

“The biggest setback was the day I woke up and found out that cellar of the appraisal development well that we were drilling in Umutu had collapsed. We borrowed $10Miilion to drill that well and supplemented with our cash and in the end, the well cost us $19Million. We borrowed $20Million for the gas processing plant and our production was declining and we couldn’t borrow more. We were almost in the throes of death. This was in 2009 and that was when I scratched my head and thought ‘this is it’. The only thing that came to our aid eventually was the pipeline network that we had built all by ourselves to the cluster”, he recalled, referring to  a cluster of four oil fields in the Western Niger Delta, which evacuate their crudes into Platform’s facility. “The Ase River Pipeline was generating about $2Miilion in gross revenue in tariff every year. So that revenue stream was enough to negotiate a revolving credit facility with Skye Bank for $5Million. It was that money that we eventually used to work our way back to life”.

Not all of the huge regrets of Avuru’s life in the last 15 years were business related.

“One of the biggest potholes I have had was the day I lost my wife in 2005 after the two of us had inspected the site where we (Platform Petroleum) were building our flow station in Umutu and so on”.

Avuru remarried, several years later, and then this:

“And then the day I had to open my kitchen door to inform my wife that her 57-year-old father, who had been accidentally shot by a police man and was in the hospital, had died.

“I think those were probably my lowest points in the past 15 years”.

Otherwise, much of the path Avuru had travelled, since he left the NNPC in 1992, had been strewn with gold.

At least, so it seems.

Since he left NNPC as a star geoscientist (by his own account), Avuru had worked for Kase Lawal’s Allied Energy (which became Erin Energy, and has since ceased to be a going concern) and moved on to set up Platform Petroleum, from which platform he became the Chief Executive of Seplat, the only African indigenous E&P Company to be listed on the main board of the London Stock Exchange.

In the last 12 years he had been nominated by two successive Nigerian Ministers of Petroleum for the position of the Director of Petroleum Resources and had come terribly close to being appointed to the position of Group Managing Director of the NNPC, the hugely influential state hydrocarbon company. “I had a one-on-one interview with (President) Yar’Adua”.

To mark his 60th birthday on Friday, August 17, 2018, Seplat Petroleum’s management wove a theme around the fact that Avuru was born in the year that Nigeria first exported crude oil. An industry stakeholders lecture, at a princely venue overlooking the Atlantic, entitled 60 Years After: Preparing For A Nigeria Without Oil, was attended by over 300 people, a glittering gathering featuring the country’s top business brass, C-Suite level petroleum executives, energy bureaucrats and ranking politicians.

Full details of Austin Avuru’s career trajectory, his misses and hits, as well as blinding insights into how the world of petroleum E&P works in Africa’s largest hydrocarbon producer, is published in the August 2018 edition of the Africa Oil+Gas Report. Please click here…

This publication wishes him many more fruitful years in the service of his country.

 


Oil Prices Push up East African Retailer’s Growth

East Africa’s third leading petroleum products retailer had its profit shooting up on account of increased crude oil prices as well as growth in sales volume

 

KenolKobil’s net profit in the six months ended June 2018  rose 16.07% compared to a year earlier after sales revenue grew by a quarter and costs nearly halved, the company reports.

The Nairobi headquartered company, which operates in Uganda, Rwanda, Ethiopia, Burundi, Mozambique and Zambia, declares in a second half 2018 statement that the 24.17% increase in earnings to $890Million (Sh90.19Billion), was a result of by increased international oil prices and an 8% growth in sales volume.

Profit after taxation increased to $16.41Million (Sh1.65Billion) from $14.15Million (Sh1.422 Billion), the Nairobi Securities Exchange-listed firm said in a financial statement.

KenolKobil trails the Shell-led Vivo Energy and the French retailer TOTAL in distribution capacity and market share in the region.

Not yet out of the hole

KENOLKOBIL, HOWEVER, SPENT NEARLY $1.32Million (SH132.83Million) on servicing loans, a 61.96% per cent surge compared with $815,051 (Sh82.01Million) a year ago, “due to volume growth and increased international oil prices”.

“Along with a significant increase in LIBOR rates, this increased our local borrowing levels and cost of our dollar denominated loans during the period,” Mr Ohana said.

But we’ve done well…

Still, David Ohana, the managing director, said the company cut operating costs by 46.44% to $8.89Million (Sh893.94Million), compared with the same period in 2017, as a result of streamlined procurement processes, efficient cost management and absence of a $2.98Million (Sh300Million) debt provision a year earlier owed to the defunct Kenya Petroleum Refineries Ltd (KPRL).

The firm’s net earnings were also helped by a $270,580(Sh27.22Million) foreign exchange gain, a turnaround from $254, 570 (Sh25.61Million) loss last year, the company claims, “on stringent management of forex transactions”.


South Africa To Release Long Overdue Energy Plan

Natural volumes expected to be lowest in the mix

 

By Sully Manope, Southern African correspondent, in Windhoek

The South African Government says it will release the Integrated Resource Plan IRP latest by Friday, August 24, 2018.

The document determines the country’s long-term electricity demand and details how the demand should be met in terms of generating capacity, type, timing and cost. 

The extant edition of the IRP, finalised in 2010, was promulgated in March 2011. Although it sets out the blueprint for likely demand and supply of energy and the type to be delivered between 2010-30, there has been expectations of its revision since 2014. The government itself has fuelled the expectation by repeatedly stating that the electricity demand outlook has changed from that expected in 2010.

That expectation, that the IRP would be significantly revised, has been part of the cause of uncertainty in the country’s energy sector.

That said, the new IRP will show how much gas is expected to be introduced for electricity in South Africa and that itself is a pointer for any investor seeking to play in the proposed South African gas market.

Early revisions of the 2010 plan bumped up the target set for gas from 2,370MW to 3,550MW. Compared with renewables (+9,0000MW) and Nuclear, (being under heavy debate, but expected to be higher than 5,000MW), this is still a minuscule contribution in the proposed total generation of 60,000MW by 2030.

Evidence that the South African government isn’t keen on pumping natural gas into Africa’s largest economy is it lackadaisical attitude to developing the Gas Utilisation Master Plan (GUMP), which has been under development for over five years. GUMP is meant to establish a framework for the investment in gas infrastructure, provide clarity about the role of gas in the South African market, set out the regulatory environment, government commitments and economic prediction for the use of gas and outline  demand, supply, market structure, industry organisation, environmental risks, financing and social impacts.

The country’s Gas to Power IPP Programme, which was announced with aplomb in 2016, has also faced headwinds.


Savannah Makes The Fourth Oil Discovery in A Row

Savannah Petroleum has announced the fourth consecutive crude oil discovery in the Agadem Rift Basin (ARB) in the Republic of Niger.

 

The Eridal-1 well is the latest reported successful probe in the British operator’s four well campaign, which started with Bushiya-1 and continued with Amdigh-1 and Kunama-1.

 

None of the wells have been tested, so their deliverability is not entirely clear.

 

“Production tests are expected to be performed on at least two of the four wells as a precursor to the Company’s plans to implement our Niger Early Production Scheme (“EPS”)”, the company has explained.

 

All the wells were drilled in the R3 portion of the R3/R4 PSC Area in the ARB, South East Niger.

 

Preliminary results of Eridal-1, based on the interpretation of the available data set (which includes wireline logs, fluid sampling and pressure data) indicate that the well has encountered a total estimated 13.6m of net oil bearing reservoir sandstones in the E1 reservoir unit within the primary Eocene Sokor Alternances objective. Wireline logs indicate the reservoir properties to be good quality and the available data indicates light oil consistent with Savannah’s discoveries to date, and in line with offset wells and the depth/API trend observed across the basin. Oil samples from the E1 reservoir unit have been taken and returned to surface using wireline testing equipment.

 

The well was drilled by the GW 215 Rig to a total measured depth of 2,542m, and encountered the main objective targets at, or near, their prognosed depths. The well took a total of 14 days to reach target depth, and all operations are expected to be completed within 23 days of spud. This compares with a pre-drill expectation of 22 days to reach target depth and 30 – 35 days to complete all drilling operations. No significant geological or drilling hazards were encountered.

 

Eridal-1 is currently being suspended for future re-entry.

 

Testing is expected to require standard production completion equipment to be installed in the wells, enabling them to be connected to the proposed EPS. This well testing programme is currently being planned for later in the year and the Company intends to provide further details in due course. The Company does not expect to provide a discovered resource and volumes report until the well test programme has been completed and evaluated.


Seplat Signs Commercial Agreements on 300MMscf/d ANOH Project

Seplat has cleared one major hurdle toward Final Investment Decision  regarding the Assa North/Ohaji South (ANOH) gas project, located in Rivers State, Nigeria’s largest natural gas holding state.

The London listed company signed, together with the Nigerian National Petroleum Corporation (NNPC) and other related companies, the Shareholder Agreement and other Commercial Agreements for ANOH Gas Processing Company (AGPC) project on  Monday, 13th August 2018, at the NNPC Towers, in Abuja, the country’s Federal Capital.

The signed Shareholder Agreement will govern SEPLAT and Nigerian Gas Processing and Transportation Company (NGPTC) respective interests in the AGPC incorporated Joint Venture.

The AGPC incorporated joint venture, in which Seplat and NGPTC hold 35% each, is the midstream company that Seplat has always talked about. Patterned after the NLNG, in which NNPC, Shell, TOTAL and ENI hold equity, AGPC will buy natural gas from the upstream JV: the NNPC/Seplat JV in Oil Mining Lease (OML) 53, and process and deliver both dry gas and several products to customers in the domestic market.

“The execution of these Agreements is an important precursor to the Final Investment Decision (FID) for the ANOH project”, Seplat says in a release.

There are other conditions precedent to the FID, of course, and the timeliness of the completion of plant and inauguration project all of the depend on these conditions, but the agreements signed on Monday, especially the completion of incorporation of the AGPC incorporated Joint Venture, have been collectively close to 12 months in the making.

AGPC is being promoted by the NNPC and Seplat to develop, build, operate and maintain the Company “as a world class Organization delivering on its objectives”, the NNPC said at the event. Seplat, on its part, explained that the ANOH Gas Processing Plant is a milestone project which aligns with the gas infrastructure development initiative of the Federal Government of Nigeria.

The company assures that the AGPC would deliver the project on schedule within the next eighteen months and achieve its objective of being a major gas supplier to the domestic market.

 

The Agreements signed were:

  • AGPC Shareholders Agreement between AGPC, NGPTC and SEPLAT;
  • AGPC Share Subscription Agreement between AGPC, NGPTC and SEPLAT;
  • Wet Gas Sales and Purchase Agreement between NNPC, SEPLAT and AGPC;
  • Gas Sale and Purchase Agreement between AGPC and Nigerian Gas Marketing Company (NGMC);
  • Gas Marketing Agreement between AGPC and NGMC.


Seplat Output Drops Quarter on Quarter

Seplat Petroleum’s oil and gas production experienced a slight reduction from first quarter to second quarter 2018, largely on account of shut ins caused by leakages in the Trans Forcados Pipeline.

Gross liquid output dropped from 61,150BOPD in 1Q 2018 to 52,262BOPD in the 2Q.

Gross daily Gas Production was 351MMscf/d in 1Q, declining to 337MMscf/d in 2Q 2018.

In equity terms, Seplat produced 27,306BOPD of hydrocarbon liquids and 158MMscf/d of natural gas in 1Q , but these had declined to 23,266BOPD and 152MMscf/d in the 2nd Quarter.

The reason was the disparity in the length of time that actual production took place.

Production in Q1 stood at 82% with average reconciliation losses of 7.3%; but by the end of the first half, the company reported production uptime in the period was 76% while reconciliation losses were around 8%.

There was, in an instance, two weeks of production shut in during the second quarter, whereas the highest number of days of shut in during the first quarter was four days.

Seplat has concluded plans to move into alternative evacuation facility whenever the TransForcados line is shut in, but could not execute those plans in the period under review.

Although 1H 2018 equity production averages at 25,286BOPD (Liquids) and 155MMscf/d, the company needs to keep an eye on its “working interest production guidance (before reconciliation losses) for FY 2018”, which is 24,000 to 29,000BOPD and 148 to 158MMscf/d.

This “equates to 48,000 to 55,000 BOEPD and is predicated on there being no further prolonged force majeure event”, Seplat itself says.
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Energy Transition of Various Speeds

By Gerard Kreeft
In September 2015 the rig count in Angola was a robust 22; by June of 2018 this decreased to 4 rigs!

Is this the new reality?

Will $80 per barrel of oil help move the rig activity to new levels? The rig count is a vibrant sign how well the oil and gas industry is faring…at least that was the thinking before the Paris Climate Agreement of 2015. Lower oil prices have not helped buttress the case for the oil and gas community. Instead there is a growing public perception that all oil and gas assets should be viewed as ‘Stranded Assets”.

In Europe there are concrete plans to shut down natural gas operations. Witness Europe’s oldest gas field – Groningen-which within the next decade will be shut down. While scares of further earthquakes was a main driver to making this decision for the Government of the Netherlands, it is also a wake-up call for Exxon-Mobil and Shell the co-owners of this historic field. Once a cash cow it has become a stranded asset.

Yet in a country like Angola the gas age is now beginning: new exploration is being done to ensure that natural gas can be used as a fuel of choice to help expand the country’s industrial base. Putting together such a roadmap will require time, effort, strategy and implementation. Perhaps for the next 20-25 years. And perhaps the use of natural gas is also symbolic for more African countries.

Certainly it is chauvinism of the worst sort to believe that Africa should be following the route that Europe is taking. What to do? A simple proposition. An Energy Transition of Various Speeds. This requires an explanation.

The Good Old Days!

In the good old days when everyone accepted that RRR(Reserve Replacement Ratio) was a parameter to reflect the upstream status of an oil company…it also was assumed that mid-stream and downstream were in capable hands. An essential tool to define the concept of the ‘Integrated Oil Company‘.

RRR was a sign that Upstream reflected a robust industry and reflected well upon the mid-stream and downstream assets: 100% replacement on an annual basis was seen as the norm (see Figure). Yet because reserves are calculated in fossil units, any attempt for the majors to engage in renewable energy, be that solar or wind would be a complete waste of shareholder value given that these reserves cannot be added to the reserve total. It is little wonder that any RRR calculation is hard to find in the financial reporting of the majors.

Post-Paris this has changed and therefore the concept of an ‘integrated oil company’ has vanished…With the oil and gas sector unwilling to think about converting  their ‘fossil –based reserves to energy units’ the oil companies have missed a big opportunity to be an active player in the Energy Transition…for example if an oil company had participated in the North Sea Offshore Wind Consortium, this could have created the equivalent of 500,000BOE reserves (100GW energy) …Nonetheless time has passed on and the oil and gas sector has chosen to ignore such an opportunity.

The result is that in spite of the higher oil prices, the oil majors will, in the coming period, face a crisis of their own making: a splitting up of their upstream/mid-stream/downstream assets and seek consolidation to maintain some sense of value. Upstream will remain in place but will have fewer and bigger players. The same with mid-stream and downstream. Throwing RRR overboard is the most visible sign that the majors will be consolidating their entire energy value chain. This could become very ugly!

For example it would not be surprising if Shell were to rid itself of its upstream assets and becoming a gas player(mid-stream) a business they understand and do well…and given the necessity of having natural gas in an energy transition they are well positioned to do this…downstream perhaps also a merger of like-minded company units.

And swirling in the background the independents will continue to have a key role in exploration and in the mid-stream and downstream sectors…to feed the majors …then we come back to the service industry…if the above consolidation does take place…this will also have its toll on the drillers and service providers.

Back to the Future
What would the Energy Transition look like in Europe?

In 2007 Europe consumed 408 BCM of natural gas (McKinsey). In the period 2005-2014 gas consumption in the EU-28 had decreased by a quarter or 124 BCM.

Various factors have contributed to this: the economic and financial crisis; the impact of policy measures around energy efficiency and renewable energy; and competition with coal. For the future various demand forecasts exist: from a low of 425 to a high of 550 BCM in 2024 .

Yet the overarching new development will be the development of the Hydrogen economy. Two examples:


The H21 Leeds City Gate Project

The H21 Leeds City Gate Project provides the world, for the first time, a concrete example of how a Hydrogen Economy could work, both in technical and financial terms and be feasible..

The UK gas industry is over 200 years old and for its first 150 years, gas used was locally manufactured town gas which contained circa 50% hydrogen with smaller amounts of carbon monoxide and methane. With the ascent of natural gas the UK underwent a nationwide gas conversion programme in the 1960’s and 1970’s, converting 40Million appliances. Over 80% of UK households now use this gas network.

A hydrogen conversion programme would follow a similar process to the original town gas to natural gas conversion, so successfully undertaken then. The process will involve minimal disruption for the customer and require no large modifications to their property.

The H21 project has shown:
⦁Gas network has the right capacity for such a conversion;
⦁Can be converted incrementally with minimum disruption to customers;
⦁Minimum new energy infrastructure will be required compared to alternatives;
⦁Existing heat demands for Leeds can be met with ‘steam methane reforming’ and salt cavern storage;

Availability of low-cost bulk hydrogen in a gas network could revolutionize the potential for hydrogen vehicles, and via fuel cells, support a decentralised model of combined heat and power and localised power generation.

North Sea Wind Power Hub
In 2017, four transmission system operators (TenneT Netherlands, TenneT Germany, Energinet and Gasunie) formed the North Sea Wind Power Hub. The hub partners are to study and investigate the possible development of a large-scale, sustainable European energy supply system in the North Sea.
The collaboration is a key step towards the realization of a North Sea Wind Power Hub which will make a major contribution towards achieving the objectives of the Paris climate agreement (COP21). In order to achieve the climate targets for Europe alone, approx. 230 gigawatts (GW) of offshore wind energy capacity needs to be developed, of which 180 GW in the North Sea. 

What are the lessons that can be learned for the Energy Transition for Africa?
⦁Renewables both wind and solar should continue to be part of the energy mix;
⦁Natural gas can continue to be an important transit fuel for residential and industry purposes;
⦁With the anticipated tsunami in the various part of the Energy Value Chain countries could face increased competition because of scarce resources, i.e. fewer oil and gas companies in the upstream/midstream/downstream sectors.
⦁Likewise in the service sector: for example the state of the drilling industry. The sector’s players are in various states of bankruptcy, chapter 11, or re-organization. Will there be any drillers left to drill the wells?
⦁How should National Oil Companies prepare for the Energy Transition?

Gerard Kreeft is CEO of Energywise, a Knowledge production company which organizes conferences and consults in the Gulf of Guinea and the North Sea


Onosode in the NLNG Creation Story

Dateline: Lagos Nigeria, February 1985….
Gamaliel Onosode, first-class technocrat, administrator and Baptist minister, was persuaded to lead Nigeria’s LNG revival campaign by President Ibrahim Babangida.

Former Chairman, Cadbury Nigeria Plc; former Chairman, Dunlop Nigeria Plc; and former Chairman, Nigeria Stock Brokers Limited, Onosode was approached by Tam David-West, then Minister of Petroleum Resources.

In the course of an evening of banter at Onosode’s residence, David- West had informed him that the government was about to establish an LNG Working Committee and wanted him to serve on the committee. “I was a bit surprised because I was not an oil and gas man. I was a banker and a manager; so I was really surprised,” Onosode recalled.

But the minister persisted: “Look, those are the skills we want represented in the working committee.” Eventually, Onosode gave in: “if the government says it wants me to serve in the committee and you came all the way to my house to tell me, I will not say no.

On the day of the inauguration of the LNG Working Committee in March 1985, the minister sprang another surprise. “When we gathered for the inauguration, then the minister sent for me. I went to his office and sat down. And he said ‘well I am sorry I didn’t tell you before, but I deliberately didn’t want you to know before now because I fear that you might turn down the request. We want you to be the chairman of NLNG working committee.’ I was stunned. When I recovered from my shock, I said ‘well, since the government said that this is the right person for the job, I will do my best, but I feel I am not a technical man, not being an oil and gas man; I am a banker and a manager.’
‘I believe that is what we needed’, David West replied.

“One more thing”, the minister continued, “the terms of reference that you will get will ask you to look into the feasibility of the project. That gives you the liberty to advise the government that under present circumstances or whatever, the project is not feasible. However, I want to say very bluntly that the government is not asking you to advise it on whether LNG project is feasible. We want you to tell us how to make it feasible.”

Onosode faced the same dilemma that every administrator who grappled with building LNG project in Nigeria had to contend with. How do you convince the international financial market to lend you billions of dollars when your country has no credit history? How do you convince partners and buyers alike to take you seriously when your country turned past efforts into a circus?

In the three decades before Onosode’s appointment, Nigeria made several unsuccessful attempts at building a LNG plant. Too many false starts; too many missed chances. The struggle to realise the LNG project was an epic story of wasted opportunities and tragic miscalculations, featuring an extraordinary cast of larger-than-life characters, many of them eminence grise of Nigerian politics and public service.

Opportunities to sell Nigeria’s gas in Europe were lost in 1966, 1976 and 1980. Nigeria’s market shares were taken by Algeria, the Soviet Union and Norway. New openings in Europe and USA in mid 1990s might be Nigeria’s last opportunities to get into the international gas business. To realise the LNG project in Nigeria, Onosode and his team needed to find solution to almost unsolvable puzzles of how to keep the government engaged, but not meddling.

Wavering government attention had been the Achilles heels of previous efforts. The committee needed to convince partners, lenders and buyers that Nigeria was committed to realising the project; that the project would be completed, not abandoned. This was not easy in a country where politicians do not speak and act with one voice. In a country where passionate rhetoric and strutting led to ruin, Onosode’s analytical detachment, sure-footed leadership and years of boardroom experience were major strengths. His integrity and unwavering morals served him extremely well in his new role. He shouldered an enormous responsibility on behalf of the state.

At the inaugural meeting, the Chairman did something unusual. To everyone’s surprise, he proposed, without explaining why it was desirable, the modification of the government’s terms of reference. Onosode recalled that event years later: “I was not happy with the logical sequence of the issues set out. We reorganised the terms of reference so that we would not incorporate the Company until we were satisfied that the project was viable. So, incorporation of the Company was one of the very last things to be done by the LNG working committee. So having challenged the unorthodoxy of the approach, we all agreed and re-drafted the terms of reference and sent it back to the minister. This ensured that the terms of reference fully reflected what the government had in mind. Thereafter, the LNG working committee began the task of engineering and re-engineering the environment to make it conducive towards the LNG project.

Participants were potential investors so the committee negotiated the terms of the partnership and investment. This was captured in the shareholders agreement. It took a lot of time and delicate negotiations to arrive at terms and conditions acceptable to all. ‘After that stage, we had to satisfy ourselves that we had a market for the product – liquefied natural gas’.

Having reshuffled the cards, Onosode reminded the committee that its main duty was setting up the vehicle for the realisation of the LNG project. He said the early registration of the Joint venture would boost the confidence of buyers who would prefer to deal with a corporate entity as opposed to individual companies. He then requested Shell, Elf (now TOTAL) and Agip (ENI’s subsidiary in Nigeria) to state conditions under which they would go ahead with the registration of a joint venture company. This needed to be agreed upfront to avoid ambiguities and surprises. Brian Anthony Lavers, Shell’s highly influential Managing Director in Nigeria, gave three conditions for his company’s participation – market availability, execution of the shareholders’ contract and an agreeable fiscal regime. Agip and Elf supported Shell’s position.

Onosode responded that he did not see the connection between the items enumerated by Shell and the proposed incorporation, adding that he had always thought that the incorporation of the Company would depend only on market availability. “It had never been anyone’s understanding that a fiscal package and service agreements needed to be in place before JVC incorporation. These should not be made pre-conditions for JVC incorporation”, he said.

The lOCs stuck to their guns, insisting that they were not prepared to accept the uncertainty of not having an agreed fiscal package prior to the incorporation of the JVC. It was the responsibility of the committee to formulate and make recommendations to the government and shareholders on the fiscal regime that would govern the project, they insisted.

Onosode argued that it was not the intention of government, nor did indications from first contacts with the market show that ii was desirable that the viability of the project should be dependent on government concessions. The buyers only wanted a stable source of supply. The project would have seeds of instability if the benefits and rewards accruing from it were not seen to have been fairly shared, said Onosode.

He urged the oil companies to appreciate the several roles the government would play in the project- a sovereign, majority shareholder (through NNPC) saying that in both capacities the government had both ultimate responsibilities to all Nigerians.

Excerpted from The Story of Nigeria LNG Ltd., by Ifeanyi Mbanefo. Published by Bookcraft, Ibadan. Funded by NLNG Ltd.


Savannah Inks Early Crude Production Deal with the Republic of Niger

British explorer bound to submit a pre-feasibility study to the authorities

Savannah Petroleum has signed “a legally binding Memorandum of Understanding” with the Government of the Republic of Niger.

The MOU affirms both Parties’ commitment to the realisation of a proposed early production scheme (“EPS”) utilising crude oil resources associated with Savannah’s recent discoveries in the R3 portion of the R3/R4 Production Sharing Contract area in the Agadem Rift Basin (“ARB”) of South East Niger. The MOU further binds both parties to work together towards the realisation of the EPS and contains specific provisions relating to the actions each Party undertakes to conduct as well as setting out the key timelines associated with the project.

The EPS is intended to be domestic focused, with oil produced from Savannah Niger’s R3 area discoveries expected to be sold at the Société de Raffinage de Zinder (“SORAZ”) refinery, which is connected to the ARB via the third party owned 463km Agadem-Zinder crude oil transportation pipeline.

As part of the MOU, the Republic of Niger has confirmed its intention to, inter alia:

• Facilitate the conclusion of a crude oil marketing agreement between Savannah Niger, the local subsidiary of Savannah Petroleum and SORAZ.
• Facilitate the conclusion of an infrastructure access agreement between Savannah Niger and the owner of third party crude oil processing and transportation infrastructure, subject to confirmation of the compatibility of the proposed crude oil Savannah Niger intends to include in the EPS and those crude oils currently being processed and transported though this infrastructure (to be confirmed following Savannah’s planned well testing programme).

As part of the MOU, Savannah has undertaken to, inter alia:
• Submit a pre-feasibility study to the Republic of Niger within 90 days of the signature of the MOU in relation to the discovered crude oil resources in the R3 area anticipated to be included in the EPS;
• Submit an application to the Republic of Niger for the issuance of an Exclusive Exploitation Authorisation within 90 days of finalisation of commercial documentation between Savannah Niger, SORAZ and the third-party infrastructure owner.

Savannah intends to announce further details in relation to the EPS and the Company’s planned well testing campaign in due course.

Foumakoye Gado, Niger Minister of Energy and Petroleum, said:
“We are very pleased with the success Savannah has achieved in its exploration drilling campaign to date, with three discoveries from its first three wells. As a Government, we are keen to see that these and future discoveries commence production as soon as possible, given the positive contribution to economic growth, tax revenues and our local communities that they have the potential to deliver. We are committed to provide Savannah with all reasonable assistance to enable this to happen. We continue to hope that Savannah’s experiences will serve as a positive advertisement for our Government’s pro-FDI approach and would strongly encourage others to come and invest in Niger, both in oil and gas and other sectors.”

Andrew Knott, CEO of Savannah Petroleum, said:
“Our Niger project team is highly focused around the delivery of: (1) near-term production and cashflows from existing and future discoveries in the R3 area; and (2) further material reserve adds through our ongoing exploration and appraisal drilling program. The signature of the MOU provides a clear pathway in relation to our first objective and is a major milestone. In relation to the second objective, Savannah benefits from the large bank of drill-ready exploration prospects that our technical team has mapped within our PSC areas.

We believe the vast majority of these prospects have similar risk profiles to the ones we have already successfully drilled, and we therefore look forward with confidence to the results of the wells still to come in the campaign. It is an exciting period for Savannah and our stakeholders and I look forward to providing further updates as our Niger project progresses over the course of the coming months.

I would like to again thank the Government of Niger for their continued support of our project. We look forward to working with them and our other project stakeholders to making the EPS a reality and starting production and sales from our R3 licence in Niger.

I also look forward with confidence to the completion of the Seven Energy transaction this quarter, and expect to provide further announcements in relation to this shortly.”

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