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Sasol’s Delay in Report Is a Pointer to Governance Risk

Africa’s largest publicly listed hydrocarbon company is pointing fingers at itself, indicating higher governance risk, in the opinion of S&P, the global ratings firm.

“A further delay in the release of South Africa-based integrated chemicals and energy group Sasol Ltd.’s year-end results indicates higher management and governance risk, and suggests potential disclosure restatements in last year’s financial statements”, S&P says in a statement.. “We rate Sasol (BBB-/Stable/A-3) two notches above South Africa (BB/Stable/B)”, S&P declares.

The release of results for fiscal 2019 (ended June 30, 2019) was initially delayed from Aug. 19, 2019 to Sept. 19, 2019. However, this has been extended to no later than Oct. 31, 2019, which is within the respective equity and bond listing authorities’ regulatory deadlines.

“The further delay follows the Board’s decision to commission additional work and to give time for further investigation into particular points raised in the original board-commissioned independent review of recent cost and schedule changes in the Lake Charles Chemicals Project (LCCP)”, S&P says in a note to investors.

The investigation began after Sasol announced further increases to the capital cost estimate in May 2019. A preliminary report was provided to the Board on Aug. 14, 2019. The additional investigation includes assessing if any potential control weakness identified in the preliminary report, as well as the root cause for the changes in the cost and schedule estimate, were present in the previous fiscal year.

The review and subsequent additional work followed Sasol’s announcements in February and May 2019 of cost overruns, with LCCP’s capital expenditure exceeding the $11.1 billion it had communicated in September 2018 by $1.5Billion-$1.8Billion. In its Aug. 16, 2019 and Sept. 6, 2019 announcements, Sasol’s Board indicated that it expects no change to the earnings guidance in the company’s trading statement of July 25, 2019, and has also confirmed its previous LCCP capital cost guidance of $12.6Billion-$12.9Billion. The LCCP ethane cracker unit achieved beneficial operation at the end of August 2019.

S&P says it expects “that the financial results for fiscal 2019 will include information on the qualitative aspects of LCCP cost estimation/projection controls, specifically reporting and oversight, further informing our view on Sasol’s management and governance risk”.


BW Tops Up the Volume at Dussafu

Proved and probable oil reserves in BW Energy operated Dussafu Permit has increased by 89%, compared to those reported at year-end 2018.

A mid-year update of the reserves report from Netherland, Sewell & Associates Inc. (NSAI) the independent reserves auditor on certain fields located within Dussafu Production Sharing Contract (offshore Gabon, indicates that the 2P gross reserves have increased by 31.2 MMbbls, in the eight months since the last audited report by the same company.

“This mid-year reserves report from NSAI shows a 89% growth of our net 2P reserves at Dussafu and confirms the value of our Gabonese asset. We are very encouraged by the continued upward revision of reserve estimates and will continue to progress the development potential at Dussafu”, according to John Hamilton, Chief Executive Officer of Panoro, a minority partner (with 8%) in the asset.

Companies like NSAI are commissioned to generate Competent Person’s Reports (CPR), which are independent technical reports on the oil and gas assets (or mineral assets) of a company.

NSAI has revised estimates for Tortue reserves based on production to date and provided new estimates for reserves at the Ruche and Ruche NE fields. NSAI has calculated the following estimates for the total gross economically recoverable oil reserves as at June 30, 2019, derived from the assumed production from six oil wells at the Tortue field and six oil wells at the Ruche and Ruche NE fields:

  • Proved (1P) reserves of 43.5 MMbbls
  • Proved + Probable (2P) reserves of 66.3 MMbbls
  • Proved + Probable + Possible (3P) reserves of 86.4 MMbbls

The increase in reserves is firstly due to an increase in the 2P gross remaining reserves at Tortue by 5.8Million barrels, approximately 16% higher compared to year end 2018 and secondly the addition of new 2P gross reserves at Ruche and Ruche NE amounting to 25.4Million barrels.

BW Energy holds a 81.67% working interest in the Dussafu Marin Permit, while Panoro Energy holds 8.33%  and Gabon Oil Company holds 10% working interest.

Libya’s Crude Output in a Sharp Drop

By Ahmed Gafar, Editorial Assistant
Libya’s state hydrocarbon company has reported a steep decrease in revenue by 25%, month on month.
The National Oil Corporation says it received $1.7Billion in June 2019, down from $2.28Billion in May, from sales of crude oil and derived products as well as taxes and royalties from concession contracts.

The $10.3Billion received as total revenue for the first half of the year, itself is lower than the amount made in 1H 2018 by 11.25%.
NOC says it could add up to 400,000 barrels to production through critical infrastructure upgrades, advancing outstanding deals, and attracting new investment.

“But to do this we need sufficient budget and to not operate against a backdrop of ongoing conflict”, the company explains.
“Attempts to undermine our work through disinformation, attacks on facilities, or efforts to illegally export have been near-constant, including by the parallel institution. The indivisibility of the oil sector is crucial for the preservation of national unity – there is but one NOC”, says Mustafa Sanalla, the company’s chairman.

Sanalla informs that the revenues for June 2019 were adversely affected by a two-week power outage, with NOC subsidiary Arabian Gulf Oil Company (AGOCO) in the east of the country losing 70,000 barrels per day from total production.

The chairman urges the Ministry of Planning to “fast-track budget approval for key infrastructure and the development of both discovered and undeveloped projects”, as this will “allow NOC to continue to grow national oil and gas revenues and meet the critical energy supply needs of the country.”

“Despite a promising tripling of petrochemical revenues, financing remains an issue to ensure stable and sustainable production”, Sanalla explains.

Oilfield Employment Has Shifted Offshore

You are more likely, than anyone else, to find a job in the oil industry today if your skills are offshore.

A Rystad Energy report says that offshore oilfield services now have more job offerings than any other sector.

“Employment is shifting from shale to offshore”, the report headlines.

 “This is a clear effect of the increase in offshore sanctioning. We expect offshore commitments to nearly double from 2018 to 2020, and sustain high levels of spending over the next five years,” says Matthew Fitzsimmons, vice president on Rystad Energy’s oilfield services team.

Rystad, a Norwegian firm of oil industry consultants, says that increased activity in onshore shale basins such as the Permian in the US held employment in the oilfield service industry steady from 2016 to 2017. “However, the offshore industry has now taken the lead, gradually increasing the overall headcount of the top 50 oilfield service companies from 2017 to 2018”.

The company forecasts that the demand for offshore services will reach $442Billion in 2025, a 45% increase from 2018.

Companies greatly exposed to the offshore industry struggled with the financial realities of reduced activity in 2015-2017, resulting in a cumulative workforce decrease of 31%, Rystad notes in its report.

“The tides are now turning as the offshore market gains momentum. Four out of the top five oilfield service companies with the largest workforce change from 2017 to 2018 were primarily exposed to the offshore industry.

“Among the smaller players with a strong focus on offshore segments, the Norwegian shipping company Solstad has nearly doubled its workforce from 2017 to 2018 – a significant staff ramp-up which bet on the long-term improvement of market conditions.

“Similarly, the drilling contractor Seadrill saw employment grow by 15%. The company has seen some recent contract award success with Saudi Aramco and Equinor. However, their 2018 year-end headcount is only 100 people more than after massive layoffs in 2016, and remains just over half of what is was as in 2014.

 Bring Back the Experience 

“Our informal interviews with OFS company leaders across the offshore industry all echoed a common challenge: how to bring experienced personnel back into the industry amidst current growth, and how to attract new talent. History would show that to bring back experienced professionals into an industry, higher wages will be required,” Fitzsimmons remarked.

However, not all hiring trends look sunny for oilfield service companies. Bristow cut its labour force from 2017 to 2018 in an effort to decrease operational costs and address its financial insecurity. The move proved to be insufficient, and the company filed for Chapter 11 in May 2019.





Indian Company to Fund NNPC’s Acreage With $3Billion

By Prospectus Mojido, in Abuja

Sterling Oil Exploration and Energy Production Company Limited (SEEPCO) has inked a Financing and Technical Services Agreement with the Nigerian National Petroleum Corporation (NNPC) for the development of Oil Mining Lease (OML) 13.

The Indian explorer, one of only two non-indigenous, independent operators in Nigeria, will serve as funding and technical partner for the development of the acreage, pumping $3.15Billion to drain the recoverable portion of the 926Million stock tank barrels (mmstb) and 5.24Trillion cubic feet (tcf) respectively of oil and gas reserves in place, over a period of 15 years.

First oil of about 7,900BOPD is expected from the project by 1 st April, 2020, while production is expected to peak at 94,000BOPD and 542MMscf/d within four years.

The terms of the deal is that the $3.15Billion, described as the “ceiling funding”, comes with a 10-year capital investment period and five years for cost recovery.

OML 13 is 100 per cent owned by the NPDC, the operating arm of NNPC, and is located in the eastern axis of the Niger Delta covering a total area of 1987km².

NNPC spokesman,. Ndu Ughamadu, says the Nigerian treasury is expected to earn over $10.2Billion in royalties and taxes from the project over the next 15 years, while NNPC would earn over $5Billion after payment of the entire financing obligation.


AFC Bets Big on Ghana’s Fourth Deepwater Development

By Susu Nooman

Aker Energy has convinced Africa Finance Corporation to invest in its projects, as the company edges close to Final Investment Decision FID on a >100,000Barrels of Oil Per Day field development offshore Ghana.

 The Norwegian E&P operator has issued subordinated convertible bonds to the   multilateral finance development institution, of $100Million. “The bonds have a coupon of 5.5% per year and will be converted to equity in the event of an Initial Public Offering (“IPO”) of Aker Energy, at an agreed discount to an IPO offering price of 1.85% per year”, Aker Energy says in a statement. The bonds have a maturity of five years, with an option to extend with another three years. The proceeds from the bonds will be part of the financing for the development of the Deepwater Tano

“We look forward to further strengthening our collaboration in the years to come”, saysJan Arve Haugan, CEO of Aker Energy, “as we embark on development projects in Cape Three Points (“DWT/CTP”) block offshore Ghana”.

The oil field currently in development in the DWT/CTP block is the Pecan field, discovered by Hess Corp. in December 2012.

Aker Energy purchased Hess Corp.’s 50% in the DWT/CTP block in February 2018 and has moved rapidly to develop it, even though the resources are located far beneath 2,000metres of water,

Aker has indicated that the field could produce as much as 110,000Barrels of oil per day. What it hasn’t said, in public, is how long the peak production could last.  First oil can flow by 2022 if the project is sanctioned this year. Aker submitted a Plan for Development and Operations (PDO), for the Pecan field and its satellites on March 28, 2019, while the appraisal drilling campaign was still ongoing. The company is working on a revised PDO, following scheduled feedback from Ghanaian authorities.

As FIDs on field projects in Ghana usually come much less than a year after the submission of PDO to the authorities, it is expected that the financial sanction for the field will happen before the end of 2019. If it does, the Pecan field development will be the country’s fourth deepwater field development after Jubilee (first oil 2010), TEN (first oil 2016) and Sankofa Gye Nyamme, located in the OCTP block (first oil 2017).

As part of the agreement between AFC and Aker Energy, AFC has received equity warrants with the right to subscribe shares in Aker Energy in future equity offerings by the company of up to $50-100 Million. AFC also intends to take part in other capital market activities initiated by Aker Energy in the future.

“Partnerships with financially and technically strong sponsors, is a key component of our Natural Resources strategic focus. We are therefore delighted to be announcing this transaction with Aker Energy, which, through the Aker group, has an outstanding track record of executing complex offshore projects like the DWT/CTP block in Ghana,” Samaila Zubairu, President and CEO of AFC commented.


Shell Reports All Leases Were Renewed, But Omitted OML 11

Shell Nigeria has reported that the three blocks that Nigerian regulators indicated they weren’t going to renew were renewed, afterall.

In its 2018 annual report, the AngloDutch major noted: “The 20-year renewals of 16 oil mining leases (OMLs): 17, 20, 21, 22, 23, 25, 27, 28, 31, 32, 33, 35, 36, 43, 45 and 46 were achieved in December 2018. These OMLs expire in October 2038”.

This simply means that OMLs 31, 33 and 36, which were initially denied approval by the Department of Petroleum Resources, DPR, eventually got renewed after protestation by Shell.

In June 2018, Africa Oil+Gas Report had reported, based on ranking sources in the Ministry of Petroleum Resources, that renewals of those three leases were denied because regulators deemed the acreages were not optimally operated.

But the Shell annual report did not say anything about OML 11, which was among the acreages submitted for renewal.

OML 11, it is now known, was renewed, but unlike the rest, the operatorship was withdrawn from Shell and that decision, by President Buhari, was only made known in  February 2019, so it couldn’t make it to the Shell annual report.

NNPC Public Affairs officials have repeatedly argued that withdrawal of operatorship does not translate to withdrawal of licence. “Shell had prayed the government to renew OML 11”, they say. “Its prayers had been answered. But this renewal did not come with operatorship”.


NDPR Has Made Some Tidy Profit in South Sudan-Fatona

Its East African foray is turning into cash in the bank for Niger Delta Petroleum Resources NDPR, the Nigerian independent.

And the money is coming from the unlikeliest of places.

“If there was any place elsewhere in Africa where we could access opportunities and quickly develop those opportunities into the same kind of portfolios that we have had in the Niger-Delta, South Sudan was that place”, Layiwola Fatona, Chief Executive of NDPR, told Africa Oil+Gas Report in an exclusive interview.

“We have never regretted going into South Sudan”.

Asked if he wasn’t concerned about crippling security challenges in a country that has been in civil war since 2013, as a result of which its oil and gas production has plummeted, Fatona replies: “We have security challenges in Nigeria and I am here”. Then he says: “Juba (the South Sudanese capital city), is a growing town”.

Fatona contends that South Sudan produces about 160,000BOPD, “the economy is young and there is very low cost of entry. Stability is coming into the country and we have been there for over three to four years.

“For the first time last year, we actually made a little bit of a profit from our engagements there and we are very hopeful that indeed, everything that we have done in Nigeria, growing from a very small producer into a fully integrated entity can be replicated in South Sudan”.

NDPR was in Uganda before South Sudan. Indeed, it won a block in the last bidding round, “but not until we were forced to partner with another entity that we didn’t feel compatible with did we actually opt not to go further in exploring the opportunity in Uganda”.

“We have been looking at Zambia and Mozambique, not necessarily because of any big offshore gas development. We are driven essentially by low cost of entry; we will not be risking any of our shareholders capital in exploration. In other words, anything that we do will have the potential of generating cash flow at the shortest and quickest period of time”.

For the full, extended article: My Journey to Independence, by Olayiwola Fatona, please click here


Now It Is Possible to Complete a Well without Cementing

By Sully Manope, Coastal West Africa Correspondent

French major TOTAL and the Danish oil service company Welltec have jointly announced the first deployment of a cementless completion.

Building on the experience gained through the continuous deployment of the Welltec® Annular Barrier (WAB®) in the Moho North Albian field which was awarded the first quarter of 2017, TOTAL E&P Congo says it has pushed the boundaries of Metal Expandable Annular Sealing technology by deploying the world’s first cementless completion using the Welltec® Annular Isolation (WAITM) in open hole.

The job was done during the second quarter of 2019.

The Moho field is located in the Congo Coastal Basin, and the reservoirs are carbonates.

The WAITM uses multiple metal expandable packers to provide long length open hole zonal isolation to replace the functions of traditional cement, leading to significant gains in efficiency in the overall well construction process, Both companies say.

The method/process/technology significantly reduces the free annulus space between the liner/casing and the open hole which can be beneficial in highly layered reservoirs of varying permeability where selective production, stimulation or water shut off is required, Welltec explains. In addition to the efficiency gains, the simplified well completions operations enabled by the WAITM eliminated multiple operational risks associated with the cementing process in depleted and over-pressured reservoirs.

TOTAL says it plans to deploy the WAITM in subsequent wells – especially those identified as high-risk.”

“The WAITM technology will without doubt transform how future wells are constructed in the industry” explains ‘Gbenga Onadeko, Senior Vice President, Welltec Africa.



Otakikpo JV Agrees With Schlumberger and Shell, on a $170Million Deal for Five Wells, Terminal Infrastructure and Export Pipeline

In a nutshell, Shell will be funding the field development expansion of Otakikpo field. As well as a new export terminal

LEKOIL has announced a Memorandum of Understanding between the Otakikpo JV (itself and Green Energy) other one hand and Schlumberger and a subsidiary of an unnamed major international oil company on another, ‘on a comprehensive infrastructure sharing and drilling programme around a group of marginal field assets in OML 11’.

The company says that Standard Chartered Bank is to act as the lead financial advisor for the Project and perform financial advisory, security and banking services required for the Project.

Africa Oil+Gas Report believes the unnamed Major Oil Company in LEKOIL’s press release is Shell, the Anglo Dutch major, largely because it was the company that farmed out Otakikpo to Green Energy seven years ago and more, its crude oil trading subsidiary is involved in exporting Otakikpo crude.

LEKOIL says the “phased development plan of the project consists of drilling up to five new wells in Otakikpo, expanding processing infrastructure to comprise an onshore terminal to be located outside the Otakikpo field operations area, construction of an export pipeline connecting the onshore terminal to an offshore buoy to handle Otakikpo and other fields in OML11”.  It adds that “the Otakikpo Joint Venture will partake in the costs of its field development with funds provided for such participation by the development consortium Project management and associated asset management costs provided by Schlumberger will be shared between the Otakikpo Joint Venture and the operators and owners of other marginal fields participating in the Project.

“Capital expenditure to be incurred by the Otakikpo Joint Venture is expected to be approximately $170Million covering new wells and processing infrastructure, of which LEKOIL is expected to fund $68Million.   The anticipated costs consist of debt repayment to financing parties, including the Major Oil Company, in addition to a project implementation fee paid to Schlumberger. Repayment of the facilities anticipated to be provided to the Otakikpo Joint Venture pursuant to the project will be made from production revenues from Otakikpo, in priority to any existing lending facilities (subject to agreement with existing lenders), future CAPEX and returns to equity holders”.

Under the terms of the MOU, the Major Oil Company will provide funding to the Otakikpo Joint Venture alongside the other funding partners, subject to due diligence, project economics, entry into definitive documentation and final investment decision.  The Otakikpo Joint Venture will enter into an exclusive offtake agreement with the Major Oil Company for the sale of crude produced pursuant to this project. Schlumberger will act as technical and project execution partner to provide oilfield services and project management services to assist in ramping up production and long-term field management. The Consortium will also form multidisciplinary project management teams from LEKOIL and Green Energy.

Due diligence will be undertaken and the financial terms and cost of capital will be finalized following final investment decision.  The final investment decision is subject to the satisfaction of customary conditions precedents, including the credit committee approval of financing parties and the execution of definitive project agreements. Site mobilisations are tentatively scheduled for late Q3 2019.

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