Seplat Petroleum has formally signed off on an agreement to supply between 2,000 and 4,000 Barrels of Oil Per Day from its working-interest production fin the Ohaji South Field in Oil Mining Lease (OML) 53 to Waltersmith Petroman Limited’s just completed 5,000BOPD capacity refinery in Ibigwe, in the east of Nigeria
Seplat, a Nigerian independent listed on both the Nigerian Stock Exchange and the London Stock Exchange, has operated output of about 7,000BOPD in the field at optimum, of which 2,800BOPD is its current, optimal working interest.
Previously, Seplat’s share of Ohaji South crude was primarily evacuated to the export Terminal via a third-party Crude Handling Agreement with Waltersmith.
“This new agreement benefits Seplat by selling its crude oil directly to Waltersmith for refining, thereby eliminating crude losses and downtime experienced along the evacuation and export route. The transaction would also boost the capacity of Waltersmith in providing its products particularly to the immediate region of our operations thereby supporting Seplat’s commitment to national energy security”, Seplat says in a release.
“This Crude Purchase Agreement with Waltersmith ensures that Nigerian crude will be refined locally by a Nigerian refiner”, says Roger Brown, Seplat’s CEO. “The agreement will eliminate losses we previously experienced on the export pipeline, meaning more revenue will be booked by Seplat for the same amount of oil produced from the field. Waltersmith’s refinery will also benefit the Nigerian economy by creating local jobs to refine our oil.”
Seplat maintains its guidance of 48,000 – 52,000BOEPD for the 2020 financial year.
Sebastião Gaspar Martins, chairman of Sonangol, says that a production cost of $20 to $25 per barrel is “fairly good cost” for Angolan marginal fields, which the government is proposing to offer in a bid round. “When we say high production costs, we are looking at no more than $20-25 per barrel, which is still fairly good. If prices stabilise around $50-55 per barrel by the end of 2020, we might be well within the range to be able to secure gains from the development of marginal fields”.
Angola defines marginal fields as crude oil and gas deposits which, due to costly recovery processes, are not worth the investment under the existing legal and fiscal framework. Several of the prospects found over the years in the country’s deep offshore, were dismissed in the pursuit of more profitable opportunities. A new framework, published in May 2018, considers, as marginal fields, those discoveries with proven oil reserves of less than 300Million barrels (exceptions are considered for bigger reserves in particularly expensive working conditions), standing at or below 800 metres of water depth, that do not give returns to the State of more than $10.5 per barrel, returns for the operator of no more than $21 per barrel and that have an average return on investment after taxes of less than 15%.
“Production costs are essential in deciding whether a project moves forward or not. Deep and ultra-deep waters come with very high production costs and we know that can jeopardise upstream activity in the current industry climate”, Martins explains. “One of the ways to overcome the high costs associated with the development of offshore fields is by utilising new technologies and ensuring high rates of production.
“We currently have some marginal fields (onshore and offshore) where fiscal terms can be improved in such a way that the projects can be viable even with high production costs”.
Whisky Galore! A 1949 British comedy film based on a true event concerning a shipwreck off a fictional Scottish Island. The islanders have run out of whisky because of wartime rationing.
Then they discover the ship is carrying 50,000 cases of whisky, which they salvage. The film is a cat and mouse chase between the islanders, anxious to preserve their precious cargo, and government officials, eager to seize the contraband.
A story of islanders eager to preserve their pot of gold.
Could a similar tale be told about Guyana? This South American country has a population of only 782,000 persons but had been constantly in the news since May, 2015, when ExxonMobil and its partners Hess Corporation and CNOOC International announced the discovery of more than 90 metres of high-quality, oil-bearing sandstone reservoirs about 200 km off its coastline.
The Liza-1 well was drilled to 5,433 metres in 1,742 metres of water, and was the first well on the Stabroek block, which is 26,800 square kilometres in size.
ExxonMobil’s Stabroek Block
According to ExxonMobil the gross recoverable resource for the Stabroek Block is now estimated to be more than Eight Billion boe (barrels of oil equivalent). In total, 18 discoveries to date.
One source predicted : “This small nation is likely looking at a windfall in royalties. For a country of less than a million people, the find changes everything. Within a decade Guyana could be completely transformed by the find, going from unpaved roads and sporadic power to being a developed nation”.
The International Monetary Fund (IMF) in a recent report warned of the dangers that oil wealth could bring, noting that by 2024 oil could generate 40% of the country’s GDP. As a result the Government of Guyana has set up its Natural Resources Fund (NRF) for managing its oil wealth.
This is where the optimism stops.
In a blistering critique of Guyana’s new found oil wealth the Institute for Energy Economics and Financial Analysis based in Cleveland, Ohio (IEEFA) sketches a somber picture: “Over the next five years, revenues from Guyana’s newly discovered oil reserves will be insufficient to cover the country’s deficits, support new spending and build its wealth. New oil revenues will provide Guyana with some choices, but will not generate enough revenue to satisfy all of these needs. Longer term, the declining oil and gas sector faces challenges that will result in it becoming even smaller and an increasingly less reliable partner for Guyana.”
IEEFA argues that:
Oil revenues to Guyana will be constrained during the next five years by low global oil prices and the price of oil is likely to remain below $50/bbl.
For the next five years, oil revenues will not fully cover Guyana’s budget deficit likely leading to an aggregate shortfall of between $160Million to $482Million.
At the end of five years Guyana will carry a minimum $20Billion outstanding balance owed to its oil producer partners. This amount must be paid, along with other contractually obligated development costs, before the country can fully enjoy any long term benefits that might materialize.
Some Inconvenient Truths
On June 27, 2016 the Government of Guyana signed a Production Sharing Agreement with a consortium consisting of ExxonMobil (45% working interest), Hess Corporation (30% working interest), and CNOOC International (25% working interest). ExxonMobil is headquartered in Irvine, Texas, a suburb of Dallas. Hess Corporation is based in New York City. CNOOC International is owned by China National Offshore Oil Company (CNOOC) and is one of the largest national oil companies in China and is based in Beijing.
The agreement outlines how oil production will take place, how costs are calculated, and how ‘profit oil’ is divided among the parties. ‘Profit oil’ is the amount left over after the oil is extracted and sold and recoverable contracts have been fulfilled.
As a 50% partner the Government is expected to be a full financial and technical partner. Both in terms of exploration and development costs. According to IEEFA, up to and including 2024, total project costs are expected to be more than $39Billion, half of which must be paid by the Government of Guyana.
The size of the concession is huge: extending between Guyana’s border with Venezuela to Guyana’s border with Suriname, a total of 26,800 square km. In comparison, oil blocks located offshore USA Gulf of Mexico are approximately 214 square km, 100 times smaller than Guyana. Even offshore Angola, which has huge blocks – between 4000 to 5000 square km—are small compared to that of Guyana. The size of the concession is virtually a monopoly position.
The virtue of such a large concession also offers the following advantage: allowing the consortium to charge exploration and field development costs for new projects in the block against the cost of a revenue producing field, as in this case the Liza Field.
The contract also stipulates that the Government will fully pay the consortium’s income tax for a five-year period: $653Million, a windfall for the consortium.
IEEFA concludes that ” if the Guyanese government follows prudent fiscal planning for the use of the anticipated revenues during the next five years, the new resources will be insufficient to cover the country’s expected annual deficit. … aggregate revenues available for the budget after contributions are made to the sovereign wealth fund would be insufficient to cover budget deficits in 2020, 2021 and 2022, leading to a shortfall of $152Million over the full five years. The revenue level during the next five years indicates that new spending of any kind would have to be delayed. The choice is whether to use the revenues to balance the budget and grow Guyana’s sovereign wealth fund or to spend the money now on new budget priorities.”
According to the New York City-based Natural Resource Governance Institute (NRGI), which provides advice on economic, fiscal and public policy to resource-rich countries, the Government of Guyana collected a signing bonus of only $18Million. The NRGI categorically stated, “Guyana needs to stop collecting chicken feed in the form of signature bonuses. It must demand what it deserves…”
This amount is in sharp contrast to the $3Billion that Sonangol, the state oil company of Angola, collected in signing bonuses back in 2006 for three deep water blocks, Blocks 15/06, 17/06/ and 18/06 which were the relinquished parts of the oil producing Block 15, operated by ExxonMobil, Block 17 operated by TOTAL, and Block 18 operated by BP. True, times have changed and Angola was then the golden boy of the deepwater plays. Yet the contrast is startling to say the least.
The New Reality In 2007 ExxonMobil had a market capitalization of $528Billion and today has been reduced to less than $140Billion. Annual revenues peaked at $486Billion in 2011 and in 2019 were reduced to $265Billion.
Then there is the matter of impairment charges. In a recent filing with the US Securities and Exchange Commission, ExxonMobil indicated that it is possible it will write down its Kearl Project of proved reserves in the Canadian Oil Sands of its Canadian affiliate Imperial Oil Limited, which account for 20% of the company’s 22.4 BOE ( billion barrels oil equivalent) reported in 2019.
ExxonMobil is also expected to reduce the 1Billion BOE of proved reserves from its unconventional operations in the Permian Basin, Texas.
Proved reserves, linked to RRR (Reserve Replacement Ratio) is the Holy-of-Holies for the industry. An indicator how well a company’s reserves stand. To have them declared as impairment charges has basically destroyed the entire petroleum classification system.
The sly culprit was the major French energy company, Paris-based TOTAL. In the summer of 2020 TOTAL took the unusual step of writing off $7Billion impairment charges for two oil sands projects in Canada. Both projects at the time were listed as ‘proven reserves’.
TOTAL’s candor has unwittingly opened a Pandora’s Box of potentially explosive proportions. All of the majors are showing red ink but increasingly attention is being given to impairment charges and the loss of proven reserves. Have proven reserves become the equivalent of stranded assets?
TOTAL’s strategy is focused on the two energy scenarios developed by the International Energy Agency (IEA): Stated Policies Scenario(SPS) is geared for the short/ medium term; and Sustainable Development Scenario(SDS) for medium/long term.
Taking the “Well Below 2 Degrees Centigrade” SDS scenario on board, TOTAL has in essence taken on a new classification system for struggling oil companies seeking a green future.
This comes at a time that ExxonMobil is coming under closer scrutiny. It has announced the sacking of 14,000 employees. Capital spending is being reduced by $10Billion to $23Billion. It is feared that if oil remains under $45 per barrel ExxonMobil could face a cash crunch.
The twin folly that ExonMobil nows faces is the following:
Guyana is now being touted as ExxonMobil’s leading strategic investment. In essence that is why ExxonMobil and its consortium have frontloaded the contract costs and the reimbursements. Guyana is now viewed as ExxonMobil’s leading cash cow.
Yet because the long established hydrocarbon classification system has now been superceded by the IEA’s climate scenarios, this will downgrade considerably the value of Guyana’s deepwater oil and gas assets with the fear of being reduced to stranded assets.
The present situation could grant the Government of Guyana a position of strength perhaps leading to major contract revisions or perhaps even pushing the government to declare the present contract a basis for force majeure.
Needless to say, with the Stabroek Block held 75% by American oil companies, ExxonMobil and Hess Corporation, and 25% by one of the largest national oil companies of China, such a move could cause consternation in Washington and Beijing.
The Government of Guyana does not at the present time have the technical and financial expertise to properly act on behalf of its people or guard its public oil and gas interests.
A Final Warning
Post-Paris Climate Agreement, those companies who have developed a green scenario, a Plan B, and who use such a plan to butress up their reserve count will have the resilence to develop deepwater projects and make them bankable. This could prove to be most invaluable.
Ignoring the Paris Climate Agreement, signed in 2015, is dangerous for oil companies and their investors. The importance of the Paris Accord is reconfirmed by the latest news coming out of Washington that President-elect Joe Biden is reportedly planning to issue executive orders to quickly reverse some Trump measures, such as Trump’s exiting of the Paris Climate Accord, as soon as Biden takes office in January.
Look to players such as TOTAL, now working in deepwater Suriname, to jump into neighbouring Guyana if ExxonMobil begins to flounder.
Equinor and even Shell could also become potential partners.
Not only are these companies greener than ExxonMobil, but the investor community has green growth on their radar screens. A green perception will also aid deepwater developments. A stable share price is a guarantee that deepwater projects have the resilence to develop and grow.
Only having hydrocarbons in your portfolio has become hazardous to your health.
Additional actions should be taken:
Strengthening the Natural Resources Fund (NRF)to ensure it can fulfill its mandate.
Establishing a National Energy Agency to be responsible for the country’s concessions, and oil and gas legislation. In short the eyes and ears of the Government.
Establishing a State Energy Company to be the negotiating partner of all oil and gas activities.
Canada and Norway, both steeped in the oil and gas tradition, and seen as honest brokers could most likely provide financial, economic and technical expertise to help set up such institutions.
The country requires an energy roadmap in order to build up a diversified economy.
Fast forward 10 years and perhaps the people of Guyana will by then have found their version of Whisky Galore!
The Natural Resource Governance Insitute (NRGI) says that its objective as stated on its website is “Ensuring that countries rich in oil, gas and minerals achieve sustainably inclusive development and that people receive lasting benefits from extractives and experience reduced harms”. Amongst its distinguished Board of Directors is Dr. Paul Collier, professor at Oxford University in the UK and world renown authority on economic and public policy.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. He writes on a regular basis for Africa Oil + Gas Report.
The Board of Governors of the African Development Bank, while accepting the idea of an independent evaluation of whistleblowers’ accusations against the bank’s president, Akinwunmi Adesina, has determined that such an evaluation will be a review of the report of the Ethics committee, which had cleared the president of any wrongdoing.
The review will be entrusted “to a single person, neutral honest, of high calibre with indisputable experience and a proven international reputation”, the Board said in a release. And the review work must be carried out “within two to four weeks, taking into account the Bank’s electoral calendar”.
The election to the AfDB’s Presidency, for which Adesina is the only candidate to date, is due to take place at the end of August.
The statement says that the “review” of the report of the ethics committee was a decision taken “with the aim of reconciling the different points of view of each governor in the resolution of this case”.
The Board reiterates its confidence in the ethics committee “which has fulfilled its role in this matter”. However, the Bank’s whistle blowing and grievance handling policy “will need to be reviewed within three to six months of the review to ensure that this policy is properly applied and to review it, if necessary, to avoid situations of this nature in the future”.
Tullow Oil and its partners have formally ended the Early Oil Pilot Scheme EOPS, in Kenya, describing it as a successful project which provided critical technical data, logistical and operational experience and training.
The scheme featured extraction of up to 2,000Barrels of Oil Per Day and trucking on over more than 1,000 kilometres of road from the Ngamia and Amosi oilfields in the Turkana County, in the country’s north, to a storage depot in Mombasa in the far south. Export of the commodity from Mombasa began in August 2019, with the value of inaugural shipment of 200,000 barrels, bought by ChemChina UK Ltd, for an estimated $12Million.
Over 100 tankers were used to move 2,000 barrels per day over the 1,000 kilometres, while the scheme lasted
The partners-Tullow, TOTAL and Africa Oil, say that the experience will materially assist the National and County Governments and the Joint Venture Partners on the journey towards Full Field Development (FFD).
“It has allowed Kenya’s oil to be marketed and established on world markets. EOPS has given local entrepreneurs an opportunity to participate in crude oil transportation with key focus on industry-safe practices”, says a statement by Mark MacFarlane, Tullow Oil’s Chief Operating Officer (COO). “Critical local infrastructure, including local roads and the Kainuk bridge, have been significantly improved as part of the scheme”.
In January 2020, Tullow Oil reported it had suspended the transport of crude oil from Turkana to Mombasa due to incessant rains that caused severe damage to roads.
In November 2018, Schlumberger pulled out of the Madu /Anyala field development project offshore Nigeria.
It was 17 months after the oil service giant had inked a tripartite agreement to be financier and technical service provider on the project, with the Nigerian independent First E&P, operator of the asset, and NNPC, the state-owned partner.
Schlumberger’s decision to pull its $724Million funding for this development in Oil Mining Leases (OMLs) 83 and 85, has been kept out of public scrutiny by all the parties involved.
But as the company moves on to another Nigerian field development project, questions are being raised: Will Schlumberger prevail through the life of the Otakikpo field expansion project? Or will it, again, pull out?
These questions are grounded in some context.
Five months before Schlumberger walked out of the Madu/Anyala, it had pulled out of another planned investment in West Africa: the Fortuna NLNG project off Equatorial Guinea.
Schlumberger was involved in the Fortuna LNG project through OneLNGSM, a Schlumberger/Golar LNG joint venture partnership with which operator Ophir Energy had signed a binding Shareholders’ Agreement, to develop the 2.2Million Tonnes Per Annum Fortuna NLNG.
OneLNGSM owned 66.2% of the $2Billion project of which $1.2Billion was to be debt financed. Schlumberger did say it pulled out of OneLNGSM because the Fortuna project was unable to finalise attractive debt financing in time.
Less than a month after the mighty Schlumberger withdrew from OneLNGGSM, Gabriel Lima Obiang, the Equatoguinean Minister of Mines and Hydrocarbons (MMH), noted that the government could bring in some other investors to the project to replace Ophir. He referenced the expiration of the Block R licence at the end of 2018.
The minister did not renew the licence, effectively tossing out Ophir Energy’s five-year appraisal drilling, FEED studies, and three-year widely publicised effort to raise finance. Faced with the loss of its biggest development on the continent, Ophir has since exited its entire portfolio in Africa.
First E&P has not suffered the same fate as Ophir. It has struggled too, though, and scaled down the number of wells needed to drill to get to first oil by more than half. In its case the state has been more benevolent: the Madu/Anyala development has benefitted from ready cash call payments by NNPC.
The Otakikpo field is operated by Green Energy International Limited (GEIL), which has the London listed LEKOIL as financial and technical partner. Schlumberger, officially never responded to enquiries from Africa Oil+GasReport. But highly regarded sources who are familiar with the company’s working, say that the Schlumberger’s financial exposure in the two projects: Otakikpo and Madu/Anyala are dissimilar. And the terms are different.
Whereas the Madu/ Anyala project was to be executed under Schlumberger Production Management SPM, in which the company is an investor and recoups its money on production, the deal on Otakikpo is being consummated under the company’s Asset Performance Solutions (APS) scheme, in which case Schlumberger is not putting a single dollar on the table, but using its brand to help the partners pull in financiers. “Schlumberger’s involvement in Otakikpo is a support by way of investing sweat equity and integrity”, our sources say.
Still, there’s something unnerving about a partner who has dropped out of two hydrocarbon field developments inside of the last two years.
GEIL signed a Memorandum of Understanding (MoU) with a consortium of international financiers for a package of more than $350Million, to take forward the second phase development of Otakikpo. The consortium includes an international bank based in London, a crude oil off-taker and an EPC contractor. The Field Development Plan FDP of the project involves the drilling of seven additional wells (there are two producing wells already) and expansion of the crude processing infrastructure. The plan also includes the construction of a 1.3Million barrels onshore terminal and a 17 kilometre export pipeline to connect the terminal to an offshore loading system. GEIL director of corporate affairs Olusegun Ilori said that the company intends to increase production from 6,000 barrels per day (BOPD) to 20,000BOPD.
Anthony Adegbulugbe, chairman GEIL has been quite enthusiastic about the work programme and vocal in the media about the financial and technical partnerships he has attracted on board of this expansion project. With COVID-19, there may be delays, the cost of debt financing may go up and the project may have to be phased, but Otakikpo expansion looks likely to go on. The one other worry is, as Schlumberger is the main subsurface service vendor, and its services come at premium cost, continual benchmarking with the rest of the industry is key. After all, this is the era of bare bone cost of production.
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.
Needs cash to expand gasproduction to 390MMscf/d by 2017, crude output to 100,000BOPD..
Nigerian independent Seplat Petroleum has won a three year struggle to list on the main board of the London Stock Exchange. The company, with operated gross daily production of 60,000BOPD of crude and 90MMscf/d of natural gas, intends to use the platform to raise about $500Million, in part for debt repayment, in part for prime acreage acquisition and in large part for aggressive increase in hydrocarbon output, to 100,000BOPD by 2017 for crude and 390MMscf/d by 2017 for natural gas (gross).
Seplat, which also plans a listing on the Nigerian Stock Exchange, is the first company, incorporated in Nigeria, to make the main board of the LSE. Companies from ‘outside the west’, or from the so called emerging markets, have had a hard time listing on the LSE, since “the flotations of ENRC of Kazakhstan and Bumi of Indonesia in the 2000s tarnished the reputation of the City of London”, the Financial Times reports. “Controlled by foreign tycoons and lured to London by persuasive bankers, each was allowed to list despite a poor record in regard to corporate governance”.Since then, the newspaper explains, “the UK Listing Authority, which acts as the gatekeeper for the London Stock Exchange, has tightened rules for IPOs”. In Seplat’s case, there was also the poor perception of Nigeria as a haven of corrupt businessmen.
Seplat’s application, submitted in 2011, went through such a rigorous scrutiny that, at some point, there were whispers in elite business circles in Lagos that the deal was off. On its own, the Seplat management never contemplated the idea of failure. “A listing on the LSE, imposes the sort of corporate governance that aids our growth as a company”, company sources remark.
SEPLAT was founded in 2009 by Shebah Petroleum Development Company Limited and Platform Petroleum (Joint Ventures) Limited for the purpose of investing in Nigerian oil and gas opportunities. Maurel& Prom, a French independent oil company, subsequently acquired a 45% equity interest in SEPLAT; this interest was later spun-off to form Maurel& Prom Nigeria S.A (now Maurel& Prom International).In July 2010, SEPLAT acquired a 45% participating interest in, and was appointed operator of, a portfolio of three onshore producing oil mining leases (OMLs 4, 38 and 41) located in the Niger Delta. In June 2013, the Company entered into an agreement for the acquisition of a 40% participating interest in the Pillar Oil operatedUmuseti/Igbuku marginal field area in the western Niger Delta. Seplat also has a similar agreement with Chorus Energy which holds the Matsogo/Amoji/Igbolo fields. Seplat hopes to be able to deliver 100MMscf/d from Platform operated Egbeoma field, Pillar operated Umuseti/Igbuku and Chorus held Matsogo/Amoji/Igbolo fields combined by 2017.
Seplatalso hopes to have completed the de-bottlenecking of the Oben Gas Processing plant to 240MMscf/d capacity by the end of 2014, in order to satisfy some contractual agreements with power companies that are due by 2015. The company is thinking of looping the Sapele Gas Plant to Oben. “The offtake in Sapele has been epileptic so we may as well expand the Oben processing plant and mothball the Sapele plant”, company sources say.
Raising $500Millionis quite ambitious and if it succeeds would rank as perhaps the largest oil industry IPO in London in several years. Officially, Seplat says that the money it raises will be used as follows: (i) $ million to repay in full all outstanding amounts under its shareholder loan from MPI S.A.; and (ii) the remainder of the net proceeds to be available for acquiring and developing new acquisitions, and/or pay down any additional debt raised in connection therewith, of both onshore and shallow offshore acreages, assets or joint venture farm-ins. The main source of acquisitions is expected to come from divestitures by various international oil companies”. Seplat is in the running to acquirethe 45% stake held by Shell, TOTAL and ENI, in one of the four Oil Mining Leases (OMLs) 18, 24, 25 and 29, that the three European partners have put up for sale. Shell, which is managing the transaction, is expected to announce the winnersby April 2014.
Midwestern Oil&Gas, the Nigerian independent, has taken a decision to find an alternative to its current crude oil evacuation route. The company is about to construct a 53km pipeline to take the 13,000Barrels Of Oil per Day produced in its Umusadege field to Shell’s Eriemu manifold, where the fluid will be taken into the trunkline to Shell’s Forcados facility. “The pipes have been ordered, we’ve done the survey, we are doing the right of way acquisition”, says Adams Okoene, Midwestern’s CEO.