All articles in the In the news Section:


First E&P Exports First Anyala Cargo

First oil has been exported from Yinson Holding’s Abigail-Joseph floating production, storage and offloading (FPSO) vessel, which is moored on the Anyala and Madu fields, in OMLs 83 and 85, in shallow offshore Nigeria.

Yinson Holding says that exports began on January 10, 2021, praising its operations team for making this possible.

The FPSO is the company’s fourth facility offshore Nigeria and its first integrated greenfield oil and gas project, the company says.

The vessel left Singapore on February 26, 2020, and achieved first oil in Nigeria on October 28, 2020, marking the start of a firm charter for the vessel, which will run for seven years, with options for another eight.

Production began from the Anyala West field, on OML 83, with five development wells. Yinson has noted the speed with which it accomplished its work. It reached first oil within 20 months of signing the contract with local company First Exploration and Petroleum. Nigerian National Petroleum Corp. (NNPC) is in a joint venture with First E&P, which operates the OMLs.

The Abigail-Joseph was previously in service in Gabon. It was deployed on the Olowi field as the Allan FPSO.

 


Savannah May Get A Trickle of Crude Oil to Zinder Refinery In Niger Republic

Savannah Petroleum intends to commence installation of an Early Production System by the end of financial year (FY) 2021, market conditions and financing permitting, and intends to deliver its initial production of 1,500Barrels Per Day from the R3 East development, to the Zinder refinery in Niger Republic.

“Subsurface work has been progressing well following the completion of our Pre-Stack Depth Migration (PSDM) processing of the R3 East seismic in 2019”, Savannah explains in a release. Savannah has now completed the seismic interpretation of the R3 East area. The PSDM dataset shows an overall improvement in the interpretation of faults and horizons, supported by attributes analysis which has also improved our structural, stratigraphic and sedimentological interpretations. Based on the newly interpreted PSDM, 3D geocellular models have been built for the Amdigh and Eridal discoveries. The resulting oil in place volumes are in line with previously reported estimated figures from the Niger CPR dated April 2020.

Significant further potential on the Savannah PSC areas remains, with 146 further potential exploration targets having been identified for future drilling consideration as Savannah looks to follow up on its highly successful R3 East drilling campaign in 2018, which saw five exploration discoveries from five exploration wells. The R3 East portfolio is currently being re-evaluated based on the newly interpreted PSDM seismic dataset with a focus on the deeper Cretaceous plays.

 


TOTAL Averages 377,000Barrels A Day in Angola’s Block 17

By Toyin Akinosho

French major TOTAL produced 377,673.9Barrels of Oil Per Day (BOPD) on average (operated, gross) in Block 17 in November 2020.

The French major was also active with the drill bit in the country, utilizing Maersk Drilling’s Maersk Voyager, on Block 17.

Chevron’s operated shallow water Block O produced 195,453BOPD.

BP’s operated deepwater Block 32 averaged 188,617BOPD in the month whereas ExxonMobil ‘s Block 15 averaged 129,763BOPD, according to figures from Angola’s Ministry of Finance.

The British player was the most active with the drillbit, utilizing Enso’s DS12 on Block 18 and Transocean’s Skyros on Block 32, reports.

Angola’s oil production in November 2020 was 36,559,945 barrels and corresponds to an average of 1,218,665Barrels of Oil Per Day (BOPD), reports the Angolan Oil, Gas and Biofuels Energy Agency (ANPG), the country’s hydrocarbon regulator.


LEKOIL Asks Shareholders to Rebuff Metallon’s “Attempt to Take Control”

By Macson Obojemuenmoin

LEKOIL has told its shareholders that the requisition by Metallon Corporation, proposing three names to act as directors of LEKOIL, is “no more than an ill-disguised attempt by Metallon to gain control of your Company without paying a price to all shareholders that reflects the intrinsic value of the business and assets of the Company”.

It argues, in the letter, that Metallon is a poorly run gold mining firm with no idea about how to manage the affairs of a hydrocarbon, E&P business.

LEKOIL’s briefing suggests that it has clearly scrutinized Metallon’s financials, and determined that “Metallon has identified LEKOIL’s assets as an opportunity to address its own financial challenges”. If all of Metallon’s Requisitioned Resolutions are passed, LEKOIL’s Board contends, “Metallon’s appointees would represent 50% of the directors on the Board and, if Michael Ajukwu is elected Chairman, they will also have the casting vote. The Board does not believe that it would be appropriate for a c.15% shareholder, to enjoy that level of Board representation and control over the Company”.

Background: On 15 November 2020, LEKOIL received notice from Strand Hanson of its resignation as the Company’s nominated adviser, with effect from close of business on 20 November 2020 (resulting in trading in the Company’s shares being suspended from 23 November 2020). On the same date that Strand Hanson’s resignation took effect, the Company received Metallon’s requisition notice (together with the consent of the three proposed directors to act as directors of the Company).

LEKOIL’s letter is a blistering response to Metallon’s charges, in its requisition, that “a lack of accountability of management by the Board has led to shareholder value being destroyed.”

Metallon had raised the following concerns:

  • LEKOIL has raised over $264Million of equity from shareholders since listing in 2013. The Company’s shares were suspended on 23 November 2020 with a market cap of $13Million.
  • During this period LEKOIL has spent $129Million on General and Administrative (G&A) Expenditure and invested $210Million into Oil & Gas activities but delivered no production growth at Otakikpo (marginal field) since first oil in 2017.
  • The Board has continually missed the market expectations it sets, with production levels at Otakikpo averaging 5,676 barrels of oil per day (BOPD) (gross) in H1 2020, despite setting targets of 10,000 BOPD by 2017 year-end and 20,000 BOPD in 2020.
  • Otakikpo, its only asset generating returns, has been starved of investment whilst G&A and other costs remain at extremely elevated levels.
  • Since its listing, the Board has awarded the CEO a total remuneration of over $10Million, close to the current market capitalisation of LEKOIL. It also recently entered into a related party transaction to extend a material part of the longstanding $1.8Million Directors loan to the CEO at a time when the Company is short of cash.

LEKOIL describes Metallon’s assertion that close to half of the equity raised has been spent on G&A as incorrect. “In fact, of the $275.5Million equity raised since listing in 2013, $166.2Million was invested in capital expenditure for the development of Oil Prospecting Lease (OPL) 310, OPL 325 and Otakikpo, with only $73.3Million (which represents, 27%) going towards G&A expenditure. To date, taking into account all sources of funding for the Company (including debt and proceeds from production), G&A expenditure would represent 28% of total funds raised or generated. Further, the Company would like to clarify that the cash component of the Chief Executive Officer’s total remuneration is $7.9Million over a period of seven years, with the balance in the form of share awards and stock options. The Chief Executive’s total remuneration since Admission of $10.6Million is included in the total G&A expenditure referred to above”.

Metallon became LEKOIL’s largest shareholder after it acquired a 15.10% interest in LEKOIL’s shares between 16 June 2020 and end August 2020. LEKOL’s share price between 1 June and 3 August 2020 ranged between 2.6p and 2.75p. The Company’s share price on the last day before suspension of trading on 20th November 2020 was 1.75p.

“Metallon has been a shareholder for less than six months”, LEKOIL notes. “Shareholders are urged to undertake their own due diligence on Metallon”.

The major areas of significant concern to LEKOIL’s board, “centre on the violation of foreign exchange control regulations in Zimbabwe; winding-up petitions from several creditors leading to a winding up order of the High Court; the distressed state of Metallon’s gold mines in Zimbabwe; and the failure to remunerate employees – all of which are a matter of public record”.

Noting that Metallon has no expertise or track record in oil and gas development, LEKOIL’s board testifies that “Metallon’s gold mining operations have fared poorly over the years and contracted from at least four mines in 2002 to just one operating mine at present”.  The board also charges that “whilst Metallon claims to be a natural resources and infrastructure investment company, it is not apparent from its most recently filed 2018 financial statements that it has interests in infrastructure.

“Prior to its investment in LEKOIL, its only asset was its interest in its Zimbabwe gold mines”.

LEKOIL points to Metallon’s payables as being almost two times its 2018 revenues, going by its annual revenues of $79Million, as; “operating cash flow of $3.9Million would be negative if $51.9Million of overdue payables had been settled. If overdue payables had been settled, Metallon’s operating cash flow would be negative $48Million;  one of the only reasons the company is now considered a going concern given its negative equity, is that it has sales of two subsidiary goldfields in December 2020 (possibly explaining the reason for the very late filing of the 2018 accounts

Metallon says it is categorically not seeking to take control of LEKOIL and is not working in concert with any other shareholders. “We believe LEKOIL’s assets, specifically Otakikpo, are being substantially undervalued by the market and that the value of these assets could be realised if the proposed changes are made to the LEKOIL Board. Since notice of the requisition was given on 19 November, we are aware that a significant number of shareholders have the same concerns regarding the Board’s lack of governance and oversight of management”.


Japanese Contractor Wins the O&M Contract for Sangomar FPSO

MODEC, Inc. the supplier of the Floating Production Storage and Offloading (FPSO) vessel for the Sangomar (formerly SNE) Field Development Phase 1 offshore Senegal, has also won the contract to operate and maintain the facility.

Woodside Energy, operator of the project, has  inked a contract with the Japanese company for the operations and maintenance of the FPSO vessel for the Sangomar Field Development Phase 1 (project in the Sangomar Offshore and Sangomar Offshore Deep oil blocks, located offshore Senegal, MODEC reports.

Following the FPSO purchase contract which was signed between Woodside and MODEC on January 10, 2020, with respect to the supply of the FPSO, MODEC will be responsible for the operations and maintenance of the FPSO. The operations and maintenance contract will cover all in-country installation and commissioning activities following which an initial 10 year operations and maintenance term will commence. Extension options are allowed for every year thereafter up to 10 additional years.

The FPSO will be deployed at the Sangomar field located approximately 100 kilometers south of Dakar, Senegal. The Sangomar Field Development is expected to be Senegal’s first offshore oil development.

Scheduled for delivery in 2023, the FPSO vessel will be permanently moored at a water depth of approximately 780 metres by an External Turret mooring system to be supplied by SOFEC, Inc. a MODEC group company.

The FPSO will be capable of processing 100,000 barrels of crude oil per day, 130 million standard cubic feet of gas per day, 145,000 barrels of water injection per day and will have minimum storage capacity of 1,300,000 barrels of crude oil.


Neconde, Shoreline, Lose > 50% of Crude Oil Output to Workers’ Protest

Local contractors and staff working for the NPDC/Neconde Joint Venture in Oil Mining Lease

(OML) 42 and NPDC/Shoreline’s OML 30, in Nigeria’s Delta State, have caused disruption in crude oil output on the assets, ensuring drastic drop by over 50% in each of the OMLs.

They were protesting unpaid salaries and emoluments.

In November 2020, the NPDC/Neconde Joint Venture averaged around 18,000BOPD, a drop of more than half of the JV’s optimal output of 38-42,000BOPD. The same month, the NPDC/Shoreline Joint Venture plunged in output from around 50,000BOPD, to 18,000BOPD, according to field data available to Africa Oil+Gas Report.

OML 30 recorded no production between November 8 and 15, 2020, as a result of the protest, according to the report.

In OML 42, output stoppage occurred from November 22 to 28, record shows.

Reports say that the protesters on OML 42 numbering over 200, escalated things to above-surface level on Tuesday December 8, converging at the main gate of Neconde Energy Limited, located at the Berger

Yard, Warri, in Delta State in the mid-west of the country, vowing not to leave the premises until they were paid. They accused Nestoil and Neconde oil firms of owing them salary arrears and emoluments spanning between 2007 and 2020.

The protesters asserted that “communities, contractors and community staff have been working for Naconde and NNPC, yet they have decided to ignore us”.

Some of the protesters displayed placards with inscriptions such as “We want our total payment today”; “Nestoil pay all our money, stop being wicked to us”; “Stop intimidating us with your security agencies,” among others.

 

 

 


In Angola, Production Cost of $20-25 Per Barrel is “Fairly Good”

By Macson Obojemuinmen

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”.

First published in the September/October 2020 issue of Africa Oil+Gas Report

 


DPR’s Abuja Move Will Be Expensive and It Comes at a Bad Time

By the Editorial Board of Africa Oil+Gas Report

The relocation of the Department of Petroleum Resources, Nigeria’s hydrocarbon regulatory agency, from Lagos to Abuja, will cost about 900Million Naira (about $2.4Million). That is for a start.

The first phase of the move is anticipated to end at the end of the year, although there has been no official word from the agency itself.

Nigeria’s oil industry is largely based in Lagos. The headquarters of the major oil companies as well as the independents are located in Nigeria’s top commercial city.

As security challenges have heightened in the Niger Delta region in the last 15 years, the main offices of the service companies have moved to Lagos, with the vast equipment yards left in Port Harcourt and Warri, for ease of logistics. The Lekki Suburb, a growing commercial and residential area in the east of Lagos, is shaping to become ‘the new Trans Amadi‘, a phrase which references the name of the industrial layout in Port Harcourt, where the leading oil service firms have their facility and do their stock control.

“We are relocating our headquarters to Abuja and will be communicating the details to all stakeholders shortly”, declares Paul Osu, the DPR’s spokesman.

There has been push for the relocation, time and again, in the past three years.

But it’s a wonder why such an expensive undertaking, at odds with the trends and realities in the industry, is considered so urgent at this time.

It is expected that 300 staff will leave the Lagos headquarters in the first phase of the move. The average relocation allowance per head is ₦3Million Naira (~$8,000), Africa Oil+Gas Report can confirm.

Mr. Osu, a personable public relations professional, did not respond to follow up questions about when exactly the decision came. There was also no response to whether the cost of the relocation is in the agency’s 2020 budget. The 2020 budget for the entire Ministry of Petroleum Resources is ₦75,548,699,111 (₦75.5Billion, or $198Million) for Recurrent Non-debt expenditure and ₦2,930,776,820 (₦2.98Billion (or $8Million) for capital expenditure).

The Nigerian state is struggling with revenue management, the government has repeatedly lamented, over the past one year. It is certainly is not the best time to spend money on such an item.

Fuller details on the relocation will be published on this platform, on an ongoing basis.

 


Wintershall Transfers Operatorship of Libyan Field

The German independent Wintershall Aktiengesellschaft (WIAG) has transferred operatorship of Contract Areas 91 (former Concession 96) and 107 (former Concession 97) in the onshore Sirte Basin to Sarir Oil Operations (SOO), a newly established joint operating company with the National Oil Corporation (NOC).

WIAG had operated the fields for close to a year after the signing of two Exploration and Production Sharing Agreements (EPSAs) in December 2019, while SOO was being established and prepared to assume operational responsibility. Now, the vast majority of WIAG’s Libyan personnel has been transferred to SOO and will continue to work in their previous roles.

Oil production in the fields located in Contract Areas 91 and 107 has been suspended since mid-January 2020 due to blockades of the export infrastructure.

Things however are looking up in Libya now; as a peace process goes vigorously underway, oilfield taps are being opened and hydrocarbon production has increased.

“Although the coronavirus pandemic and the conflict in Libya have posed additional significant challenges during the past months”, the company explains in a briefing, “NOC and WIAG are nonetheless convinced that as a result of a comprehensive and diligent transitional process, SOO has successfully been enabled to operate the fields in a reliable manner and in accordance with good oilfield practices”.

 

 


Whisky Galore: Developing an Energy Roadmap for Guyana

By Gerard Kreeft

 

 

 

 

 

 

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.”

Signature Bonuses

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.

Conclusions

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:

  1. Strengthening the Natural Resources Fund (NRF)to ensure it can fulfill its mandate.
  2. 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.
  3. Establishing a State Energy Company to be the negotiating partner of all oil and gas activities.
  4. 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.
  5. 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!

Note:

The following is from the website of the Institute for Energy Economics and Financial Analysis (IEEFA):  The IEFFA examines issues related to energy markets, trends and policies. The Institute’s mission is to accelerate the transition to a diverse, sustainable and profitable energy economy.  IEEFA receives its funding from global philanthropic organizations and individuals. IEEFA gratefully acknowledge our funders, including the Rockefeller Family Fund,  Energy FoundationMertz-Gilmore FoundationMoxie FoundationRockefeller Brothers Fund,  KR Foundation and Wallace Global Fund, and some who choose to remain anonymous.

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.

© 2021 Festac News Press Ltd..