All articles in the In the news Section:

Lighting up Africa

By Gerard Kreeft

Royal Dutch Shell’s Sky Energy Scenario, first published in 2018, still provides energy companies a solid roadmap to develop their own Post—Parisenergy plans. A key observation in the document is that “New energy sources grow up to fifty-fold, with primary energy from renewables eclipsing fossil fuels in the 2050s”.

An important message for Africa here is simply that the continent has a window of 30 years to decide how its fossil fuels can help usher in renewables.

It’s crucial not to hastily abandon your fossil fuel resources in favour of renewables,be that wind or solar. Instead strategic fossil fuel scenarios should be developed to provide an energy roadmap. In Africa the need to speed up oil and gas exploration and production has never been greater. The oil and gas assets are the currency to finance renewable energy. Can Africa’s oil and gas assets be harvested for lighting up Africa, before they are declared ‘stranded assets’?

Defining the Need

A key message from Akinwumi A. Adesina, President of the African Development Bank, is that a New Deal on Energy for Africa must have the goal “to light up and power Africa by 2025”. Certainly this must be a key goal for the oil and gas industry.

Power conditions are to say the least terrible. Power consumption per capita is the lowest of all continents: 181 kilowatts per annum, 6500 kilowatts in Europe and 13000kilowatts in the USA.

Energy sector bottlenecks and power shortages cost Africa between 2%-4% GDP per annum. Companies in Tanzania and Ghana lose 15% of sales value as a result of power outages. It is estimated that two thirds of a million people, mostly women and children, die annually due to indoor air pollution associated with the use of fuel wood for cooking. Children under-perform at school for lack of electricity since over 900 of Africa’s primary schools have no electricity.

The goals of 2025 are increasing:

On-grid generation to add 160GW of new capacity;

On grid transmission and grid connections by 160% in order to create 130 million new connections;

Off-grid generation to add 75Million connections, an increase 29 times more than what Africa generates today;

Access to clean cooking energy for 130Mllion households.

In Search of an Energy Champion

Is it not time to enlist an energy champion to help leapfrog exploration and development hurdles? To ensure that oil and gas projects are implemented, on time and under budget. To ensure that these energy assets can be used in developing Africa’s economic needs. Without reservation TOTAL would be my nomination to fulfill such a role. A company well positioned in the Upstream, Mid-stream and Downstream sectors across a broad swath of the African Continent.Having a well-defined strategy, transparency and an ability to operate, in what may appear to outsiders as a difficult marketplace. And, finally a unique ability to deliver projects at neck-breaking speed in which technical zeal is always present!

To address climate change the company is expanding its natural gas output. i.e. LNG production; expanding in the non-regulated low carbon electricity market; and striving for carbon neutrality through carbon sinks(wetlands and forests and Carbon Capture Storage).

TOTAL has also acquired two companies- Saft, an industry leader in advanced battery technology and Eren, which promotes and invests in technological innovations in the water, basic materials and energy sectors.

For the first time TOTALs Chairman and CEO’s compensation package has quantitative criteria linked to trends in greenhouse gas emissions at operated oil  and gas facilities.

According to the company’s Rupture Energy Scenario renewables will capture 90% of the power growth between 2018-2030.

An African Pioneer Illustrated

TOTAL’s track record in fossil fuels exploration and production in Africa is awesome: The company’s field development projects in several fields in Angola’s flagship deepwater Block 17 have produced almost 3 Billion barrels of oil produced since the taps opened with Girassol in 2001. Currently producing around 440,000 barrels of oil equivalent per day, the potential of this very prolific block is still high, with more than 1 Billion barrels yet to be produced.

In 2019, operator TOTAL and its partners Equinor, ExxonMobil and BP signed an agreement with national oil, gas and biofuels agency ANPG and state-owned Sonangol of Angola, to extend their consortium’s production licenses in Block 17 to 2045.

In South Africa, TOTAL made a discovery with the Brulpadda Deepwater Prospect, a world-class find in which 57 meters of net gas condensate was found. TOTAL and its partners plan to acquire 3D seismic this year, followed by up to four exploration wells on this license. The Block 11B/12B covers an area of 19,000 square kilometers, with water depths ranging from 200 to 1,800 meters.

TOTAL acquired Anadarko’s 25% in and operatorship of Mozambique LNG project in 2019, and is currently leading other partners in the construction of a two-trains liquefaction plant with a capacity of 12.9Million tonnes per year (Mt/y). The reservoirs in deep-water Area 1 contain more than 60 Tcf of gas resources, of which 18 Tcf will be developed with the first two trains. The Final Investment Decision (FID) on Mozambique LNG was announced on June 18, 2019, and the project is expected to come into production by 2024.

Electrifying Africa

TOTAL’s challenge is to ensure it can harness it’s project management skills to ensure that Africa can be lit up.The company currently delivers 3GW of renewable energy through its affiliate Eren but it has a goal of delivering 25GW on renewable energy.The French super major develops projects in countries where renewable energy provides an economically viable response to growing power demand.

Eren in 2018 installed the world’s largest hybrid solar/thermal with a capacity of 15MW for the IAMGOLD Mine in Burkino Faso. The company also provided two photo voltaic power plants(PV) with a capacity of 126MW for the Benban Complex, Aswan Province, Egypt. Eren delivered  a 10MW facility for the Soroti Power Plant in 2016;Uganda’s first-grid connected solar plant generating clean energy for 40 000 households.

A likely partner with TOTAL could also be IRENA ‘s(International Renewable Energy Agency) Clean Energy Corrid or which aims to support the integration of cost-effective renewable power options to national systems, promote its cross-border trade and to support the creation of regional markets for renewable energy. The Clean Energy Corridor initiatives has two African regions:

The African Clean Energy Corridor (ACEC) for the member countries of the Eastern and Southern African power pools;

West African Clean Energy Corridor (WACEC) within the Economic Community of West African States.

So, why not begin a serious public-partnership involving TOTAL and the Oil and Gas Industry and  the African Development Bank together with IRENA so that Africa can be lit up by 2025?

Why not go for 100GW of electrical energy?. Translated to the oil and gas sector: 565800 barrels of oil equivalent. A language TOTAL understands, representing approximately 20% of their current oil production. Adding 20% production goes a long way in supporting your RRR (Reserve Replacement Ratio).

A final message to the African Development Bank. Ensure that your oil and gas partners understand that their energy contribution can be translated to oil of barrel equivalent. Presently the illusion continues to be fostered that renewable energy can be added to the reserve count of an oil company. The SEC, the USA watchdog of Wall street makes it abundantly clear that only fossil fuels are legitimate reserves. Africa can provide a great service to the oil and gas industry by helping them become energy companies.

Gerard Kreeft holds a BA (Calvin University) and  MA (Carleton University, Ottawa, Ontario, Canada). An Energy Transition Adviser, he 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.

Angola May Break A Four-Year Recession Jinx in 2020-IMF

Africa’s second largest oil producer may be out of recession in 2020, the IMF hopes.

If it doesn’t, then Angola would be marking the fifth year of contraction of its mono-product economy.

The IMF reported a 1.1% drop in the country’s GDP in 2019, due to a further decrease in the oil economy (-5.0%), not compensated by the largely stagnant non-oil economy (+0.6%), but the Fund is expecting a 1.2% growth of the economy in 2020, supported by a 1.3% increase in oil GDP and a 1.1% growth in non-oil GDP.

The government’s figures are more optimistic, claiming a likely 1.8% increase in GDP, due to an anticipated 1.5% growth in the oil economy.

Despite efforts to diversify the economy, GDP, exports and government income mostly rely on crude oil.

For 2020, the government forecasts oil production to rise to 1.44Million barrels per day (MMBOPD) from 1.39MMBOPD in 2019, which is contrary to projections based on the natural rate of decline in mature projects.

The Angolan budget bases its calculations on an average of $55 per barrel of oil, in line with the long-term anchor price forecasted for Brent although price for most of the last quarter of 2019 and first half of January 2020, have hovered close to $70. This means that a budget surplus of 1.2% of GDP can kick in during 2020.


South Sudan Invites Tenders for Environmental Audit of Oilfields

The Government of the Republic of South Sudan has announced a tender for a comprehensive environmental audit of all the country’s producing oilfields.

The Petroleum Act of 2012, enacted a year after independence, governs the oil sector in South Sudan. The Act is designed to better manage the environmental impact of the sector after years of neglect prior to independence, and the resulting pollution.

Civil war also prevented the proper management of the environment, based on environmentally, socially and economically sustainable principles.

South Sudan is now faced with the challenge of balancing developmental needs with the spirit of environmental protection enshrined in the Petroleum Act. The sector has in the past caused a loss of grazing land, deforestation, soil and water contamination, and health issues in and around oil-producing areas.

President Salva Kiir, writing in the South Sudan First State of Environment and Outlook Report in 2018, explained the country’s desire to become the bread basket and economic powerhouse of East Central Africa.

“The lack of environmental standards and guidelines to safeguard the exploration and exploitation in the extractive industry has led to pollution in the oilfields and in the surrounding areas. This trend needs to be checked through the formulation of environmental policies, standards and guidelines, and enforcement of these instruments.”

Ahead of any new exploration and drilling, the government has committed to conducting an environmental audit. Minister of Petroleum, Hon. Awow Daniel Chuang, explains that understanding the pollution damage will allow the country to put systems in place to prevent further damage as the country looks to ramp up production.

At a media briefing late in August 2019 in Juba, President Salva Kiir warned that his government would be taking a stronger stance against pollution in oil-producing areas. And while the government is eager to welcome new exploration and production, companies would be held to a high standard. The era of “bad business” was coming to an end.

He warned, “I will not tolerate irresponsible activities in the oil sector.”

An international independent organization will now be appointed to conduct the audit, mandated to suggest best practices for new exploration as well as ways to repair the historical damage in South Sudan.

Tender pre-qualification documents for conducting a Full Environmental Audit will be available during office hours at the Ministry of Petroleum’s headquarters in Juba, and from its website The documentation will be available between 13 and 20 January 2020.

Completed documentation needs to be submitted by 16h00, 20 January 2020 to:

1. Electronic Submissions:

2. Hardcopy Submissions to be delivered in a sealed envelope addressed to:
Environmental Audit Tender Committee Secretary
Ministry of Petroleum HQ
Ministries Road, Juba
Republic of South Sudan
PO Box 376

Distributed by APO Group on behalf of South Sudan Ministry of Petroleum.

View multimedia content

Media Contact:
Claudia Padayachy
Tel: +27 84 88 44317

South Sudan Ministry of Petroleum

MODEC Wins the Contract for Senegal’s First Oilfield FPSO Deployment

By Toyin Akinosho, Publisher

The Japanese contractor MODEC Inc., has won the nod of Woodside Energy and its Partners for the purchase of a Floating Production Storage and Offloading (FPSO) vessel to process and produce the oil in Senegal’s deepwater Sangomar Field.

The FPSO has to have an oil processing capacity of 100,000 Barrels of Oil Per Day (100,000BOPD).

  • Subsea Integration Alliance (a non-incorporated alliance between Subsea 7 and OneSubsea) wins the award for the construction and installation of the integrated subsea production systems and subsea umbilicals, risers and flowlines for the project.
  • Diamond Offshore wins the contract for two well-based contracts for the drill rigs Ocean BlackRhino and Ocean BlackHawk.

The Government of Senegal granted the Exploitation Authorisation on January 8, 2020, handing the relevant regulatory approvals, including the execution of the Host Government Agreement, to operator Woodside Energy and its partners to proceed.

Phase 1 of the development will target an estimated 231 MMbbl of oil resources from the lower, less complex reservoirs, and an initial pilot phase in the upper reservoirs.

“We look forward to progressing the project towards first oil in early 2023 and expect that our experience in offshore FPSO developments will support its delivery on cost and schedule”, Woodside CEO Peter Coleman, said in a statement.

The Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) joint venture comprises Woodside Energy (Senegal) B.V., Capricorn Senegal Limited (a subsidiary of Cairn Energy PLC), FAR Ltd and Petrosen (the Senegal National Oil Company).

Operational production costs have fallen globally, led by the United Kingdom

Operational production costs in the oil and gas industry have fallen across the globe, with the United Kingdom emerging as a cost-cutting powerhouse among global offshore regions. A Rystad Energy analysis aimed at mitigating currency effects confirms this trend, after examining regional opex reduction per barrel, measured in local currency. The results are clear – from 2014 to 2018 the UK reduced operational production costs by 31%, followed by Norway and the United States with opex reductions of 19% and 15%, respectively.

“The reduction in operating expenditure is largely the result of offshore regions – such as the United Kingdom, Brazil, Nigeria, Angola, the Gulf of Mexico and Norway – feeling the squeeze of uncertain oil prices, which in turn has driven operators and contractors to nurture operational improvements in pursuit of lower unit prices,” says Sara Sottilotta, Oilfield Service Analyst at Rystad Energy.

Secondly, with a greater focus on strategic planning, more efficient maintenance management and the increased and improved implementation of technology, opex per barrel of oil equivalent (boe) has fallen. It should be noted, however, that in times of downturn some opex reduction has historically been a consequence of maintenance deferral. This is important to bear in mind, as unplanned outages caused by equipment failure and damages have quadrupled globally since 2013.

“The UK has experienced the greatest reduction in opex per boe, falling from more than $30 per barrel in 2014 to just $16 per barrel in 2019. The drop is attributable to two main factors: the general increase in production, and the falling share of production from mature fields as new fields came on-stream and old fields were shut-in,” Sottilotta says.

Changing rotation cycles, the closing of older fields and lower salaries have also contributed to the reduced cost levels. A majority of UK offshore operators switched from two-week to three-week personnel rotations in 2015-2016, generating salary and logistics savings by reducing the number of flights required to shuttle personnel to and from offshore facilities. Still, despite this significant decrease in operational costs, the UK exhibits the highest opex per boe of all major offshore regions due to smaller field size, a fragmented operator landscape, a more mature continental shelf, and a higher number of personnel on board (POB) per produced barrel.

In absolute terms, Brazil experienced the second greatest drop in opex per boe, falling from $16 per boe in 2014 to $11 per boe in 2019. This reduction was driven primarily by a significant increase in production, especially from the giant Lula field. Across the globe, opex per boe in Norway is among the lowest, helped by the rising exchange rate between Norwegian Kroner (NOK) and the United States dollar (USD), which grew from an average of NOK 6.3 per $1 in 2014, to an average of NOK 8.3 per $1 in 2017. In contrast, Mexico’s operating cost per boe has risen since 2016, the result of decreasing production and an increasing share of production from mature fields.











As Figure 2 above illustrates, the UK has achieved the greatest decrease in operational expenditure per production unit, even when considering expenditure in local currency. Norway and the US follow close behind, with each of the three leaders primarily doing business in their respective domestic currencies. It should be noted that Angola and Nigeria typically carry out operational transactions in USD. Because of this, when considering operational expenditure in local currency these countries appear to have experienced skyrocketing opex thanks to soaring local inflation, while real change in opex is likely not as great in magnitude.


CGG Returns to Profitability

For the first time since 2012, CGG will be back to black in 2019 and anticipates a positive Net Cash Flow around $185Million, the company says in a release.

The largest Geophysical Acquisition firm in the Western Hemisphere says it anticipates year-end 2019 Net Debt to be around $584Million. The Group’s Liquidity is expected to be at $611Million at the end of December 2019.

The Multiclient market have helped CGG out of the red, more than any other segment of the business, “CGG anticipates segment Multi-client sales around $166Million for the fourth quarter of 2019 after an exceptional third quarter 2019”, the release explains. “After-sales are expected to be around $96Million.

CGG will announce its 2019 financial results on March 6 2020, before the opening of the Paris stock exchange.

Africa’s State Energy Firms Now Pay More Promptly

By Toyin Akinosho

In his insightful piece on the discovery of the giant Zohr gas field in Egypt, Marco Alfieri, the Italian journalist, wrote about the context in which ENI decided to risk taking the acreage in which the field was found.

“With the fall of the Muslim Brotherhood, the new government of President Sisi started to pay the old debts”, Alfieri wrote. “In a few months they renegotiated gas contracts. Production in the country was falling, and new hydrocarbons would have to be found from exploration”.

Zohr was discovered in mid-2015; some thirty trillion cubic feet of gas in deep-water Mediterranean Sea.

Just two years before that, the conversation around gas sales in Egypt was very much different than the environment that Alfieri painted.Egypt’s conspicuous domestic gas consumption, the largest in Africa, is fed by production by the International oil companies. The companies pump their gas output into the Egyptian national grid, operated by EGAS, the government company responsible for distributing the molecules to power plants, industries and households at a very high subsidy.

Egyptians enjoy piped gas at home, are advantaged with one of the highest per capita electricity supplies on the continent and operate more Petrochemical plants than anywhere in Africa outside South Africa. But the companies who produced the gas neither got paid on time nor (in their view) sufficently.


GAS PAYMENTS WERE AS MUCH A SOURCE of headache for E&P companies in Tanzania as they were in Egypt.By late 2015, for example, it was clear to Orca Petroleum, one of the country’s top gas producers, that debts owed by the Tanzanian Electricity Supply Company, TANESCO, were going to stifle the company and probably render it bankrupt.  Orca produced 48.5Million standard cubic feet per day (48.5MMscf/d) of gas on average in 2014, was being owed $59.8Million by the end of 2014, excluding interest (of which arrears were$52.2Million) compared with $54.0Million (including arrears of $44.3Million) as at 31 December 2013. Meaning: the debt just kept piling up!

The challenge of getting paid by the state energy company dated back over five years. There was a very pointed statement in Orca’s annual report of 2014: “TANESCO arrears and payments continue to be irregular and unpredictable. As a result, there is significant doubt about TANESCO’s ability and/or willingness to settle arrears”.In 2016, the International Monetary Fund IMF noted that the TANESCO’s financial sustainability was an issue. “TANESCO still has a large amount of arrears to gas and electricity suppliers”.

But three years after, Orca’s second quarter 2019 report told a completely different story. It said, in part: “At June 30, 2019 the current receivable from TANESCO was $ nil (December 31, 2018: $ nil).During the quarter, the amounts received from TANESCO were in excess of the revenue for gas sales to TANESCO, resulting in the reversal of the provision for doubtful account of $3.5Million in Q2 2019. Orca said that “the TANESCO long-term trade receivable at June 30, 2019 was $55.0 Million with a provision of $55Million, compared to $58.5Million (with provision of $58.5Million) at December 31, 2018. Subsequent to June 30, 2019 the Company has invoiced TANESCO $4.6Million for July 2019 gas deliveries and TANESCO had paid the Company $6.2 Million.

NIGERIA’S NNPC IS AN EXCEPTIONAL PROOF that Africa’s state energy companies can transform into effective partners with Private parties; funding their cash calls timeously, clear arrears on payments for hydrocarbon molecules they purchase, even pay their share of equity in projects far in advance of development.

For years, while Egypt’s Gas Holding Company EGAS furiously searched for solutions to its billions of dollars of payables for gas produced by international companies working in the country, the NNPC wasn’t lifting a finger.As of March 2015, five major oil companies operating in the Niger Delta claimed they were owed over $7Billion in arrears by this Nigerian bully of a state oil firm.

Fast forward to August 2019, and ExxonMobil officials are celebrating. The American major actually convened a little public gathering to acknowledge the end of payment of outstanding cash call by the NNPC with a payment of $833.57Million. Paul McGrath, Chair of the Corporation’s subsidiaries in Nigeria, expressed his delight for “the crossing of the finish line on our JV arrears repayment” on July 3, 2019.

The repayment process had commenced less than two years earlier, in August 2017, with the execution of an agreement for a repayment”. NNPC itself has a target: Pay off the entire cash-call arrears owed its International Joint Venture, JV partners, including Shell, TOTAL, ENI (known as Agip in Nigeria) and Chevron, within a period of five years, meaning that, all the $5Billion it agreed it owed them would be paid by 2021. NNPC sources told Africa Oil + Gas Report that the debt to the American giant was one of the lowest. There are much larger sums to pay Shell and Chevron each. The interpretation of that is: “Don’t get too excited”.

But symbolism is important.And there is one example in which NNPC has even performed better as a paying partner.That example is the ANOH Gas Processing Company AGPC, an incorporated Joint Venture between Seplat Petroleum and Nigerian Gas Company, NGC, a subsidiary of the NNPC. The AGPC is raising $700Million, in equity and debt, to develop three hundred million standard cubic feet of gas per day (300 MMscf/d) midstream plant on an onshore acreage in the east of Nigeria, to process future wet gas production from the upstream unit. Seplat and NGC, 50% equal partners in AGPC, have collectively paid down $300Million of the $420Million equity subscription for the IJV, meaning that they’ve each contributed $150Million. “It is very unusual for an NNPC subsidiary to make upfront payment in a partnership venture”, says Jerry Tolein, a Cairo based hydrocarbon market analyst focused on Africa. “But this really has happened”.

Not all the news about state energy firms paying their due invoices have turned positive.Nigeria is particularly a bad case for private companies selling natural gas to state electricity firms. Seven Energy, a natural gas producer and supplier, went bankrupt two years ago on account of debts owed by the Akwa Ibom State government owned Ibom Power, which received 24MMscf/d of gas and accumulated the debt. Seven Energy was also being owed by the Niger Delta Power Holding Company, which had a contract to receive over 40MMscf/d to run the Federal Government owned Calabar IPP plant.

But such cases are becoming the few exceptions on the continent and soon enough, companies like that will find themselves isolated.

The Qataris To Finance LEKOIL’s Ogo Field Appraisal, Development

AIM listed LEKOIL has secured close to $200Million loan for appraisal drilling and possible development of the Ogo field offshore Lagos, Nigeria.

The company says it has signed a binding loan agreement with the Qatar Investment Authority QIA, the sovereign wealth fund of the State of Qatar, in the amount of $184Million. The Facility will be disbursed in five (5) tranches over eleven (11) months, with the first drawdown intended to occur in February 2020.

Lekoil holds 17% in the Oil Prospecting Lease (OPL) 310 in which Ogo is located, but it is the funding and technical partner to Optimum, the rentier Nigerian company which holds 60%, has held the acreage since 1991 and will be carried in any funding arrangement.

Ogo was discovered in 2013 by Afren, working in partnership with LEKOIL which had just bought into the asset. LEKOIL’s IPO of that year was used to part fund the Ogo discovery well. The partners claimed, at the time, that the oil and gas in place could be up to 750Million barrels of oil and gas equivalent. The appraisal drilling that will be funded by the loan from Qatar will provide clarity about recoverable reserves, as the discovery well and the ensuing sidetrack were not tested.

Less than two years after that discovery, Afren ceased to be a going concern. LEKOIL paid $13Million to Afren’s owners to secure the 22.8% that Afren held on the lease, but Optimum, the licence holder, refused to recognize that payment. The Nigerian state, apparently preferring to believe Optimum’s claim over that of LEKOIL, also refused to grant official consent for LEKOIL to take the 22.8%.

What will the $184Million Loan Do?

LEKOIL says it will advise the market about the work programme for appraisal and possible development of the Ogo field, in short order, but the following is what it had said before the loan was secured:

There’s a plan to drill two wells in the next 12 months, and depending on results from the initial wells and planned extended well tests, two additional appraisal-development wells could follow.

All the wells will be designed to be compatible with an early production scheme.

The tranching of the draw down of funds under the terms of the Facility is expected to enable LEKOIL to meet the costs commitments under the envisioned work programme as and when they arise.

The Facility, which has a tenure of seven years from the date of first disbursement, is secured against, amongst other things, the shares and assets of LEKOIL 310 Limited and Mayfair Assets and Trust Limited and includes a moratorium on both the interest and principal repayments commencing from the date of the Facility until six months after the commencement of commercial sale of production from the field.

The annual interest rate payable on amounts drawn under the Facility is 3.72%, with an upfront fee of 2.75% of the amount drawn under the Facility which is payable upon drawdown of the Facility.


Re-examinating the Energy Value Chain: The Case of Saudi Aramco

By Gerard Kreeft

Saudi Aramco’s  IPO (Initial Public Offering) has raised much curiousity. A valuation of some $2Trillion. Proved liquid reserves larger than that of the five largest IOCs (International Oil Companies). And a goal  to be the largest  integrated energy and chemical company.

The Saudi Aramco announcement could set off a flurry of massive takeovers and corporate re-structuring not previously witnessed in the Oil and Gas Industry.


Size matters. To be able to compete with Saudi Aramco many of the majors will be re-thinking their next strategic moves. In a competitive E+P environment, economies of scale, lowered project costs and innovation matter.

Could this mean the wholesale takeover of one or more of the majors?

Possibly it would not stop there. Given the dominant size of Saudi Aramco the demise of the largest IOCs could be further threatened. One possible scenario is more specialization: Upstream entities merging to enhance exploration and reduce costs. Downstream specialized chemicals and other by-products.

A possible reason why Saudi Aramco’s IPOis now being implemented is because of the move away from fossil fuels by major investment and pension funds. Bill McKibben estimates that to date some $8Trillion has moved away from the oil and gas industry. Waiting longer could well  depreciate the value of Saudi Aramaco’s hydrocarbon base.

Saudi Aramco has indicated it wants to move in the direction of solar energy. A strategic movitation would be to translate Saudi Aramco’s  solar energy capacity to barrels of oil equivalent,thereby increasing the value of the company’s Reserve Replacement Ratio (RRR).

Oil companies’reserve count are, by their very definition, based on a fossil fuel basis. Their Reserve Replacement Ratio is purely based on a fossil fuel basis. Clean energy—wind,sun or hydropower—cannot be part of the mix. The US SEC stock market regulator leaves no doubt about that! A move by Saudi Aramco, given its its leadership role to move to a broader definition of RRR, could help bolster fossil fuels and serve as an incentive for taking  renewables  on board.

At present the RRR rate for the industry is 7%, a historic 20 year low. The norm is 100%. There is no evidence that if  the E+P industry were to continue its present trajectory things will drastically change. Could Saudi Aramco’s IPO set off a chain reaction in which renewables are an integral part of the RRR count? Helping to salvage the E +P sector. Or will we witness, in reaction to the Aramco IPO,takeovers  and consolidation in both the Upstream and Downstream sectors? And hiving off their renewables to separate companies?

Business as Usual?

Rystad, the Norwegian Consulting Firm, in a study of offshore projects sanctioned  between 2010 and 2012, indicated that projects were barely able to generate any value for E+P companies; and projects sanctioned between 2013 and 2014 are expected to have no value creation. Yet in the period 2015-2018, value creation was positive even with an oil price of only $40 per barrel.What has changed? Lower unit costs, rig rates and rig design and simplification of projects.

Simon Flower, Chairman and Chief Analyst of Wood Mackenze has drawn similar conclusions. Bringing fields on stream quicker, via simpler development concepts and by breaking complex projects into smaller units, have decreased development costs. Prior to 2015  Pre-FID costing was $79 per barrel and now $50 per barrel. A drop of 37%. According to Wood Mackenzie to date 155 major projects targeting over 50Million barrels of oil equivalent have been started. Combined spending of $500Billion.

In spite of the increase in oil price since 2017, the service sector has to date shown few signs of witnessing a recovery.In October 2019 it was reported that Petrobras’ Drillship Vitoria was being sold for scrap. A somewhat startling revelation for a deepwater floater only 10 years old and in 2011 having a value estimated of $653Million.

Given the revival of the deepwater market, does it not seem more logical that one of the international sector’s drilling contractors buy this rig for a hugely discounted price? Both Transocean and Valaris have pointed out with pride how young their fleets are. Certainly Vitoria should be a welcome asset by either contractor.

The scrapping of Vitoria is perhaps indicative of the state of the industry. Currently new builds, both floaters and jack-ups are on hold. Expect a long delay for the 27 floaters and 58 jack-ups that are now being built or slated to be delivered.

Certainly a snapshot of the drillers provides consternation: Transocean’s share price on November 1 was $5.14. Even in the downturn in 2016 it’s share price was $8.65 (26 February 2016). Valaris no better: on November 1it’s share price was $4.52. On October 20, 2016 it was $35.60.

Valaris at a recent Investors’ Conference indicated that it requires an average day rate of $490,000 for its floaters, and $160,000 for its jackups, if it is to achieve a 15% unlevered internal rate of return.All indications are that current day rates are far below this requirement.

Utilization rates are currently 70%; in 2016-2017 they were 60%; and in 2014, 90%.

Since 2000 the average cost for  building floaters was $665Million, and for jackups $200Million. Better to buy up cheap assets and not burn your cash.

Total debt of the top three drillers (Transocean, Seadrill, Valaris) is depressing: $23.5Billion.

The historical relationshiip between the drilling fraternity and the oil companies is not a pretty picture. In time of high oil prices the drillers saw an opportunity to have huge day rates; and in the downturn  oil companies took their revenge and demanded day rates that barely covered costs.

Yet the drillers remain in a precarious state of health. And their sub-scector requires long-term support.Drillers and oil companies must learn to develop a long-term relationship if they are to thrive. The transactional mentality must change if the offshore industry is to recover some of it lost lustre.

Finally the responsibility of the oil companies is very fragile. Not only must they mend fences with the drilling fraternity; but also butress up their RRR with renewables. Otherwise we could be writing the final chapter of the industry sooner rather than later.

Gerard Kreeft, MA (Carleton University, Ottawa, Ontario, Canada) has  30 years experience in the Oil and Gas Sector. For much of that time he has managed and implemented oil and gas  conferences, seminars and master classes in Angola, Brazil, Canada, Libya, Kazakhstan and Russia. He writes on a regular basis for Africa Oil+Gas Report.

In Africa, the Oomph Will Continue in 2020

2019 was the great year of reset for the hydrocarbon industry in Africa.

There was sharper clarity in fiscal remit for the large sized, field development projects that had been on queue since the price crash period.

The loss of momentum around the Uganda basin wide oil development was the spectacular exception.

That Oomph! will spill over into 2020, a year that will be defined by both optimism in the sector and stock taking about the future of hydrocarbons.

Nigeria’s Eight Million Tonne Per Annum (8MMTPA) NLNG Train 7 became, last week, the second large sized LNG development project to take Final Investment Decision in 2019.

With the Mozambique LNG project sanctioned last June, there will be some 20MMTPA combined onshore LNG capacity in the build phase in 2020. Which translates to some construction frenzy about African hydrocarbon projects around the world in 2020.

As country after countries in Africa is determined to run licensing rounds, the seismic data market will be busy, so will the “competent persons industry”, and the whole gamut of the subsurface investigation sector.

Rig activity will remain conservative; there’s unlikely to be very significant uptick in drilling in Angola,Gabon, Congo Brazzaville and South Sudan. Nigeria, however, is headed for at least 20% higher rig activity than it experienced in 2019, which translates to about five more rigs. Algeria and Egypt will also be busy with the drill bit.

That said we highlight, in our late December 2019/early January 2020 edition, a number of operational events that will run the course of the year. Our theme is Who Is Doing What and Where in 2020?

The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the

market leader in local contextualizing of global developments and policy issues and is the go-to

medium for decision makers, whether they be international corporations or local entrepreneurs,technical enterprises or financing institutions. Published by the Festac News Press Limited since 2001, AOGR is a paid subscription, monthly hard copy and e-copy publication delivered around the world.

Its website remains, and the contact email address is Contact telephone numbers in the West African regional

headquarters in Lagos are +2348124374087, +2348130733523, +2347062420127,

+2348036525979, +2348023902519.

We wish all our readers a prosperous new decade.

Fred Akanni, Editor in Chief

© 2020 Festac News Press Ltd..