All posts tagged in-the-news


Massive Production Drop in Nigeria’s Western Onshore

Crude Oil output crashed to significant lows in five acreages held by Nigerian independents in the western onshore Niger Delta, in August 2021, according to field data seen by Africa Oil+Gas Report.

These acreages, operated as Joint Ventures with state oil firm NPDC, produce the bulk of the hydrocarbons in Nigeria’s western onshore as well as most of the natural gas for the country’s electricity supply.

NPDC/Neconde’s OML 42 output fell to 23,000 Barrels of Oil Per Day (BOPD), from 38,669BOPD averaged in July 2021.

NPDC/NDWestern JV grossed…Read more

 

 

 


NIGERIA: The Big Asset Sale Season

Nigeria is back in a big asset sale season.

This is like mid- 2013 all over again, a half-year after RoyalDutch Shell completed a significant asset sale and was about to conduct another. But this time, the scale is humongous, and the above headline is closer to the narrative than it was when we ran it in 2013.

Our latest edition, just released to our global pool of paying subscribers, covers the asset sale with full disclosure.

Shell is about to sell acreages. ExxonMobil is in the midst of selling and Chevron has almost concluded a sale.

But again, the really big disposer is RoyalDutch Shell.

When the European major concludes the imminent sale of its equity in 18 joint venture assets in Nigeria, it will be left with just one operated acreage and two non-operated assets, all of them in deepwater. Midstream, it will still hold the largest non-state share in the NLNG plant, but it will no longer be in direct control of the feedstock.  The company whose name was, for most of the last 65 years, synonymous with the phrase ‘Nigerian Oil industry’, will have retreated into the background.

In our last monthly edition, released in mid-July, 2021, we explored the likely beneficiaries of these sales. We have updated the analysis in this edition.  In that issue, we worried about the impairment to the state coffers and debated whether the overall divestment picture was a good or bad sign, on balance to the fiscus. In this edition, we ask, why is the state company deeply concerned about this sale?

Elsewhere in the magazine, our regulars are of course included: who is getting to first oil; who is drilling what and where? Where in Africa is gas being commercialized and how can our subscribers benefit from such opportunity? Where else is opening up and what are the new technologies?

The Africa Oil+Gas Report  is the primer of the hydrocarbon and the growing new energy 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, for useful analyses of Africa’s oil and gas industry. Published by the Festac News Press Limited since November 2001, AOGR is a monthly, publication delivered to subscribers around the world. Its website remains www.africaoilgasreport.com and the contact email address is info@africaoilgasreport.com. Contact telephone numbers in our West African regional headquarters in Lagos are +2348038882629, +2348036525979, +2347062420127, +2348023902519.

 

 


South Africa Sprouts New Shoots

In the last five years, several E&P companies, primarily owned by South Africans, have left the upstream market, such that it is tempting to declare the end of the growth of South African E&Pindependents. 

JSE listed SacOil, badly burned by its dealings in Nigeria with local partners Transcorp and NigDel, has turned into a downstream company and changed its name to Efora. 

Thombo Petroleum, owned by Trevor Ridley, former Petroleum Advisor at BHP Billiton, disappeared into the folds of Canadian owned Africa Energy Corp.

But apart from Sasol Exploration and Production International, which is the most visible and best resourced South African bornE&P company, there are a number of companies to consider:

JSE and ASX listed Renergen describes itself as an integrated alternative and renewable energy business that invests in early-tage alternative energy projects.

But it started its project life six years ago by acquiring an onshore natural gas acreage from Molopo South Africa Exploration and Production. Renergen holds the first, and currently only, onshore petroleum production right in South Africa. 

Several homegrown independent South African companies, including Tshipise Energy (Pty) and Sungu Sungu Petroleum, are exploring for natural gas, in coal beds, in the Karoo and offshore Orange Basin, but their distance to development is, at best, far off. 

Renergen is the only one pumping natural gas from subsurface reservoirs into the local market. It has been supplying compressed natural gas to transportation companies since May 2016.

South African National Petroleum Company (formerly PetroSA), the only other natural gas producer in the country, is a state-owned enterprise.

Renergen is working on ramping up production from its acreage, which holds an estimated 142Billion standard cubic feet of proven and probable reserves, near Virginia, about 300km southwest of Johannesburg. It has moved intoliquefied natural gas (LNG) production, “primarily serving the growing domestic heavy duty truck market across Africa and emerging markets”, it says. Renergen has signed an offtake agreement with South African Breweries (SAB) for the supply of liquefied natural gas to power its delivery trucks. For this project, it initially rolled out compressed natural gas to a small fleet of SAB trucks in Gauteng, the country’s major commercial province.

A POTENTIAL STAR IN THE SOUTH AFRICAN E&PFIRMAMENT is Sunbird, a gas explorer and developer which owns a 76% interest in the Ibhubesi Gas Project, Block 2A, offshore of the west coast of South Africa and is the operator of the block. The company was originally owned by Australians, and was sold to South Africans in 2016. The Ibhubesi Gas Project is the country’s largest, undeveloped gas discovery, in the opinion of Sunbird and the local media. Theindependently certified gas reserves are 540 Bcf (2P) with “best estimate” prospectivity of close to 8 Tcf of gas, according to the company. The immediate focus of the project is provision of gas to the Ankerlig Power Station, an 11 year old, 1,338MW capacity thermal plant, designed to be fired by natural gas, but instead, utilizing expensive diesel fuel.Sunbird’s JV partner PetroSA, holds the remaining 24% in Ibhubesi.

Sunbird, for now, remains no more than a potential.

Five years after the Department of Environmental Affairs (DEA) issued an Environmental Authorisation (EA) for the project, the company is not anywhere close to concluding the gas sales negotiations with Eskom, the South African state power utility which owns the Ankerlig power plant. Nor is Sunbird seen to be progressing any deal to sell gas for industrial uses like Renergen is doing.  


TOTAL Boosts Gross Angolan Output With a 40,000BOPD Development

French major TOTAL, has announced the start of production from Zinia Phase 2 short-cycle project, in its prolific Block 17, in deepwater off Angola.

The field is hooked up to the existing Pazflor’s FPSO (Floating Production, Storage and Offloading unit). 

The project includes the drilling of nine wells and is expected to reach a production of 40,000 barrels of oil per day by mid-2022. 

TOTAL operates Block 17 with 38%. Partners include Equinor 22.16%, ExxonMobil 19% and BP 15.84% and Sonangol P&P (5%). The contractor group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor. 

Gross crude oil volume exported from Block 17 in March 2021 was 10, 455,209 barrels, amounting to 337, 265BOPD, according to Angolan government statistics.

Located in water depths from 600 to 1,200 metres and about 150 kilometres from the Angolan coast, Zinia Phase 2 resources are estimated at 65Million barrels of oil. 

 

 

TOTAL said that the project’s entire development “was carried out according to schedule and for a CAPEX more than 10% below budget, representing a saving of $150Million. 

“It involved more than 3Million manhours of work, of which 2 million were performed in Angola, without any incident”.

The Block 17 production license was recently extended until 2045.


Oza Field Poised to Flow More Than the Trickle it Currently Does

By Sully Manope, in Port Harcourt

London listed minnow, San Leon Energy, has moved much closer to injecting the funds it says it plans to use to ramp up output from the Oza field, onshore Niger Delta, which has produced a trickle of crude oil: about 400Barrels of Oil Per Day, in the last one year.

San Leon will invest in Oza field, by way of both granting a loan to and taking equity interest in Decklar Resources Limited. San Leon will grant Decklar a loan of $7.5Million, and subscribe for a 15% equity interest in Decklar, with another $7.5Million.

Decklar, a Canadian player listed on the Toronto Stock Exchange, will re-enter Oza 1, perform a work over and drill a new well, to start with.

Oza field is held by and operated by Millenium Oil and Gas Company Limited, a Nigerian owned independent which won the field from the government in the 2003 marginal field bid round. Decklar is the holder of a Risk Service Agreement (RSA) with Millenium on the field. Translation: Millenium had been unable to properly optimize production from the field. Decklar is investing in the field, both technically and financially and the Risk Service Agreement is legal instrument to ensure that it makes back its investment and take some profit.

Decklar is raising money elsewhere for the ramp up, apart from the $15Million it has agreed it will receive from San Leon. It is trying to raise funds from private placement financing and secure a facility from a crude trading company, which is a subsidiary of an E&P major (most likely Shell Trading, but Decklar doesn’t say).

Decklar, indeed has announced it was completing a private placement financing for a total of just over CAD $4Million, (or $31.75Million) which will enable it to immediately advance operational activities to re-enter the Oza-1 well. Closing of this private placement is expected to provide sufficient funds to re-enter the Oza-1 well and to re-establish oil production at the Oza Oil Field.

“The previously announced debt funding plans, including the arrangements of which San Leon is part, are in the final stages of being concluded which will provide additional development funding for further operations and development drilling for the full development of the Oza Oil Field”, San Leon says in a statement  “The current private placement, which will allow Decklar Petroleum to begin the Oza-1 well re-entry and production operations on an expedited basis, is expected to close by the end of February 2021.

Civil works required for the Oza-1 wellsite are complete, according to Decklar, including rebuilding of the access road, construction of a concrete drilling pad, a concrete mud pit, buildings and other facilities required for well re-entry and drilling operations and management. A drilling rig located near the field has been contracted and will be moved to the Oza-1 wellsite in the near term, and operations to perform the planned re-entry of the Oza-1 well will begin shortly thereafter. The recently completed drilling pad will be used for both the Oza-1 well re-entry and the first horizontal development well on the Oza Oil Field.

The funds proposed to be used from San Leon on Oza are now expected to be used on the drilling of the new well on the Oza structure.


NNPC Records 54% Increase in Trading Surplus for November 2020

By Kish Onwunali, in Abuja

The Nigerian National Petroleum Corporation (NNPC) has announced a trading surplus of ₦13.43Billion (or $35.4Million) for the month of November 2020, up by 54% when compared to the ₦8.71Billion ($22.9Million) surplus recorded in October 2020.

The November 2020 edition of the NNPC Monthly Financial and Operations Report (MFOR) indicates that export sales of crude oil and gas for the month stood at $108.84Million, a 70.33% increase over the value of sales for the previous month. Crude oil export sales contributed $73.09Million (67.15%) of the dollar transactions compared with $12.38Million contribution in the previous month; while the export gas sales amounted to $35.75Million in the month.

The total crude oil and gas export for the period of November 2019 to November 2020 stood at $2.89Billion.

The trading surplus or trading deficit is derived by the deduction of the expenditure profile from the revenue in the period under review.

The MFOR November 2020 report notes that NNPC Group’s operating revenue, compared with October 2020 earnings, decreased slightly by 0.02% or ₦0.09Billion ($236, 842) to stand at ₦423.08Billion ($1.113Billion).

Expenditure for the month decreased by 1.16% or N4.81Billion (12.6Million) to stand at N409.65Billion ($1.07Billion), leading to the ₦13.43Billion ($35.4Million) trading surplus.

Overall, expenditure as a proportion of revenue was 0.97 in November 2020 as against 0.98 in October 2020.

The 54% increase in trading surplus in the November 2020 MFOR is primarily ascribed to the substantial decrease in expenditure from the Nigeria Gas Company (NGC) due to cost reduction in overheads, coupled with 38% reduction in NNPC Corporate Headquarters deficit. In addition, the NNPC Group’s surplus was bolstered by the noticeable improved profits for additional engineering services rendered by the Nigerian Engineering and Technical Company (NETCO) and increased revenue from import activities posted by Duke Oil Incorporated. “These healthy performances dominated the positions of all other NNPC subsidiaries to record the Group surplus”, says the press release.

 


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”.


Waltersmith Formally Gets Seplat’s Nod as a Supplier of Refinery Feedstock

Seplat Petroleum has formally signed off on an agreement to supply between 2,000 and 4,000 Barrels of Oil Per Day from its working-interest production fin the Ohaji South Field in Oil Mining Lease (OML) 53 to Waltersmith Petroman Limited’s just completed 5,000BOPD capacity refinery in Ibigwe, in the east of Nigeria

Seplat, a Nigerian independent listed on both the Nigerian Stock Exchange and the London Stock Exchange, has operated output of about 7,000BOPD in the field at optimum, of which 2,800BOPD is its current, optimal working interest.

Previously, Seplat’s share of Ohaji South crude was primarily evacuated to the export Terminal via a third-party Crude Handling Agreement with Waltersmith.

“This new agreement benefits Seplat by selling its crude oil directly to Waltersmith for refining, thereby eliminating crude losses and downtime experienced along the evacuation and export route. The transaction would also boost the capacity of Waltersmith in providing its products particularly to the immediate region of our operations thereby supporting Seplat’s commitment to national energy security”, Seplat says in a release.

“This Crude Purchase Agreement with Waltersmith ensures that Nigerian crude will be refined locally by a Nigerian refiner”, says Roger Brown, Seplat’s CEO. “The agreement will eliminate losses we previously experienced on the export pipeline, meaning more revenue will be booked by Seplat for the same amount of oil produced from the field. Waltersmith’s refinery will also benefit the Nigerian economy by creating local jobs to refine our oil.”

Seplat maintains its guidance of 48,000 – 52,000BOEPD for the 2020 financial year.


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

 


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.

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