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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.


Is Nigeria Finally Within Reach of a New Oil Law?

By NJ Ayuk, Executive Chairman, African Energy Chamber  

This week, the African Energy Chamber will publish a report outlining its short-term predictions for the continent. That report, Africa Energy Outlook 2021, identifies Nigeria as the country with the most potential for increasing hydrocarbon production. But it also points out that Nigeria faced certain challenges with respect to realizing this potential.

Of course, some of the challenges have their roots in the events of 2020 — the coronavirus (COVID-19) pandemic, the dramatic fall in global energy demand, and the oil price war between Russia and Saudi Arabia that briefly sent crude prices into negative territory. However, the country is also facing a number of ongoing challenges.

One of these is the need for a new oil and gas regulatory regime.

‘Africa Energy Outlook 2021’ notes that Nigeria’s government has been working for years to meet this need. So far, all of its attempts have failed. In 2018, for example, members of the Senate voted to approve legislation known as the Petroleum Industry Governance Bill (PIGB), only to have President Muhammadu Buhari veto its version of the bill and send it back to the floor.

Buhari’s administration has not given up, though. Earlier this year, the president declared that his administration was determined to draft a new version of the oil and gas law and secure its passage through both houses of the National Assembly before the end of 2020.

Signs of Progress … But How Much?

The AEC’s report expresses some doubt about Buhari’s ability to get that far with the new Petroleum Industry Bill (PIB). I see this skepticism as understandable, given that Nigeria has been trying — and failing — for nearly two decades to effect change on this front. But I also want to point out that Abuja has made some genuine progress this year.

First, the government completed the draft version of the PIB and submitted it to the National Assembly in August.

Second, the government secured pledges from both houses of the legislature to expedite discussions on the PIB so that it can be passed before the end of the year.

Third, the bill passed its first reading in the House of Representatives and the Senate on Sept. 30.

Fourth, the bill passed its second reading in the House of Representatives and the Senate on Oct. 20.

Fifth … well, is it reasonable to list a fifth sign of progress? Perhaps not. Almost immediately after the PIB passed its second reading, Nigeria’s Senate suspended plenary sessions until Nov. 24 so that it could focus exclusively on drawing up the federal budget for next year. Additionally, it gave the relevant Senate committees eight weeks to make the required legislative inputs into the bill.

Short on Time

Because of these developments, the timeline for securing passage for the bill has shifted.

As I mentioned previously, President Buhari has said he wants to sign the PIB into law before the end of this year. But if the Senate continues to focus exclusively on the budget until Nov. 24, it will have just over a month to meet that deadline — or even less, if the committees take the full eight weeks allotted to them for making legislative inputs. Either way, it will have a great deal to do in a short time. It will have to wrap up committee discussions, pass the new oil and gas law in its third reading, secure the assent of both the House of Representatives and the Senate to the final version of the legislation, and then send it to the president for signature within just a few weeks.

In theory, the PIB could lose momentum during any of these stages. If the committee discussions run for the full eight weeks, they will end on Dec. 15, leaving very little time before the end of the year. If legislators propose amendments during the third reading, they may need extra time to debate and vote on their proposals. If the House of Representatives and the Senate turn out different versions of the PIB and are unable to come to terms quickly, the initiative could stall. If President Buhari takes exception to any changes made during earlier steps in the legislative process, he could veto the bill.

If any of these things happen, the government may find itself ending 2020 without a new oil and gas law in place.

But would that really be such a bad thing?

More than Money

Yes, I think it would.

For years now, uncertainty about the legal regime has been discouraging companies from making commitments to the West African state’s oil and gas industry. According to Nigeria’s Department of Petroleum Resources (DPR), the repeated failure of attempts to adopt a new oil and gas law costs the country about $15Billion each year in lost investments. It’s therefore reasonable for Buhari and his government to seek passage for the PIB as soon as possible. After all, Nigeria can ill afford to keep losing so much money — especially at a time when its oil and gas industry is under extra strain because of the extraordinary events of 2020.

But it’s not just about the money. I believe there is an objective need for reform — and that the PIB can meet that need.

Nigeria’s oil and gas sector has earned the reputation of being corrupt, non-transparent, and inefficient. This reputation drives potential investors away, thereby depriving the country of money — and, what’s more, depriving it of jobs (in both the industry itself and in related sectors such as construction and transportation) and also of opportunities for partnerships, training, technology transfer, and other things that help support and amplify economic growth.

In other words, without the PIB, Nigeria can’t use its vast oil and gas reserves to optimal effect!

Needed Reforms

The PIB does try to address the deficiencies of the current system.

For example, it calls for dismantling state-run Nigerian National Petroleum Corp. (NNPC) and dividing its functions up among three separate entities. It provides for NNPC’s regulatory and administrative functions to be transferred to two new government agencies: one to supervise upstream operations and another to supervise midstream and downstream operations, including domestic gasification programs. At the same time, it assigns the company’s commercial functions to a new entity that will be known as NNPC Corp.

This one change has the potential to make a big difference. With respect to transparency and efficiency, the bill draws a clear line between Nigeria’s need to monitor and regulate the companies that work in the oil and gas sector and its need to have the capacity to develop its own resources. It also calls for NNPC Corp. to be audited annually by an independent company — rather unlike the current version of NNPC, which has come under fire in the past for its less-than-transparent accounting practices. And with respect to corruption, it establishes NNPC Corp. as a purely commercial entity with no access to the federal budget — and, therefore, fewer opportunities to function either as an instrument of state policy or as a shady space in which government officials can move money around for their own purposes.

Of course, these aren’t the only good things the PIB could do. For example, the bill also contains provisions that might settle investors’ questions about the Deep Offshore and Inland Basin Production Sharing Contract Act, a controversial piece of legislation that some energy companies have described as little more than a revenue grab. Additionally, it eliminates two state bodies that haven’t been doing the best job at monitoring the downstream fuel sector: the Petroleum Products Pricing Regulatory Agency (PPPRA), which oversees fuel pricing, supplies, and distribution, and the Petroleum Equalisation Fund (PEF), which distributes cash with the aim of making motor fuel prices uniform throughout the country. Moreover, it puts a single agency — the new midstream and downstream agency mentioned above — in charge of domestic gasification initiatives. This makes sense, given that gasification depends on the construction and expansion of transportation and distribution networks. It could also help coordinate the process by putting all activities under a single umbrella.

Don’t Stop Pushing

There are other attractive features to the PIB, but I don’t have the time or space to list them all here.

I do want to emphasize, though, that I think Nigeria needs this new law, both in general and with the particular details included in the government’s draft version. Buhari is therefore right to push the National Assembly to pass it as quickly as possible — and he should keep pushing, even if legislators miss his Dec. 31 deadline.

In other words, the president should hold members of the National Assembly to the commitment they made earlier this year to accelerate this process! If he does, he should see the PIB pass soon — and once it takes effect, it can lay the foundation for a more efficient, less corrupt, and more transparent oil and gas sector in Nigeria. And, equally important, Nigeria can start capitalizing fully on its oil and gas resources.

(https://EnergyChamber.org)

 


Moza’s Floating LNG Facility Nears Completion

By Fred Akanni

Construction of the Coral-Sul FLNG facility, Mozambique’s first Liquefied Natural Gas facility is almost completed. The floating plant will sail-away to the south east African country in 2021 to begin natural gas extraction in the vast offshore Rovuma Basin.

The lifting and installation of the last of the 13 topside modules, “configuring the entire gas treatment and liquefaction plant”, was announced by ENI, the Italian energy company which will operate the facility.

With this milestone, first gas from Coral-Sul FLNG is on course for 2022. “The massive 70 thousand tons topside was lifted onto the hull one module at a time and is now complete. However, construction continues with integration and commissioning activities” declares Roberto Dall’Omo, ENI’s General Manager on the Rovuma Basin project.

ENI discovered the Coral field in Area 4 licence Mozambique in 2012, a year after it encountered the Mamba field in the same basin: Rovuma. It estimates 16Trillion cubic feet estimated recoverable reserves of gas in the former.

The Coral Sul FLNG (meaning Coral South) is one of two projects on the field; farther down the line, the company expects to also develop the reserves in the north of the field under a project christened Coral North. ENI’s partners in Area 4 include ExxonMobil and CNP), Galp, KOGAS and the Mozambican state hydrocarbon company Empresa Nacional de Hidrocarbonetos (ENH) E.P.

These same partners are also involved in another project: the 15MMTPA Rovuma LNG facility, a much bigger, onshore plant which will be operated by ExxonMobil. The Final Investment Decision for that project has stalled.

ENI claims that the Coral-Sul FLNG, with a capacity of 3.4Million tons of liquefied gas per year (MMTPA) is the world’s first newly-built deepwater floating liquefaction plant.

It is based on six ultra-deepwater wells in the Coral Field, at a water depth of around 2,000 metres, feeding via a full flexible system the Coral-Sul FLNG.

 

 


Indians to Take over FAR’s High Profile Assets in Senegal

By Toyin Akinosho

FAR has finally found a buyer for its high profile oil and gas asset offshore Senegal.

ONGC, the Indian state hydrocarbon company, has agreed to buy the property, which includes FAR’s entire interest in the Production Sharing Contract for the Rufisque, Sangomar, and Sangomar Deep Offshore Blocks offshore Senegal and the relevant Joint Operating Agreement (the RSSD Project).

The Sangomar exploitation project, located in these blocks, is the largest offshore crude oil development currently under construction in Africa. Phase 1 development of the project, which will develop some 250Million barrels of oil, remains on track for targeted delivery of first oil in 2023. Production from this phase is expected to be around 100,000 barrels of oil per day (BOPD).

The Australia listed minnow, which has struggled as a going concern-and has defaulted on paying cash calls on the project- in the last two quarters, says it has entered into a Sale and Purchase Agreement with ONGC (full name ONGC Videsh Vankorneft Pte Ltd), the largest E&P company of India, which has agreed to pay FAR $45Million at completion. In addition, ONGC has agreed to reimburse FAR’s share of working capital for the RSSD Project from 1 January 2020 totalling $66.58Million, payable on completion. The reimbursement is comprised of cash calls paid by FAR, including $29.60Million paid to cure FAR’s default to the Joint Venture. The Transaction also includes an entitlement to certain contingent payments capped at $55Million.

The Transaction is subject to conditions precedent, including the following:

  • The written approval of the Minister of Petroleum and Energies for the Republic of Senegal to the transfer of the Transferring Interest to the Purchaser being obtained. FAR hopes that such approval would be obtained in January 2021.
  • RSSD Project Pre-Emptive Rights – The Transaction is conditional on the waiver or non-exercise of preemption rights available to FAR’s co-venturers in the RSSD Project. FAR is issuing the pre-emption notices between November 11 and November 12, 2020, and the co-venturers have 30 days to advise if they wish to exercise their right to preempt the Transaction on the same terms and conditions as ONGC. In the event of pre-emption, FAR will receive the same consideration as from ONGC.
  • FAR Shareholder Approval – ASX Listing Rule 11 requires that FAR obtains shareholder approval in relation to the Transaction. FAR intends to convene a general meeting of FAR shareholders as soon as practicable to be held in December 2020 to consider approving the Transaction (including if the sale is the subject of pre-emption).
  • Third Party Agreement Termination – The Transaction is subject to the termination or satisfactory resolution of an agreement between FAR and a third party, details of which are currently commercial in confidence. ONGC has the discretion to waive this condition.

Cath Norman, FAR’s Managing Director, describes the offer from ONGC as representing “the best option available at this time and we trust that our shareholders will vote for this transaction”. She reinstates the well-known fact that “the market for financing and selling assets has been weak since the impact of COVID was felt in March of this year”.

If the Transaction completes, the company anticipates, “FAR will be in a strong financial position and will be relieved of its future development obligations in relation to the RSSD Project, which in the absence of a sale, FAR cannot currently meet beyond December 2020”.

FAR expects to have approximately $130Million in cash at the close of this Transaction that, Ms. Norman says,” will be used to rebuild the Company and further our other West African prospects offshore the Gambia and Guinea-Bissau”.

Having been in the RSSD project for 14 years, “it’s a bittersweet moment to be selling our stake. FAR is committed to our projects in The Gambia and Guinea-Bissau and using our deep knowledge of the MSGBC Basin to potentially explore offshore Senegal again,” Norman declares.


Court Restores Marginal Fields Revoked by Nigerian President

A Federal High Court in Abuja, Nigeria’s capital city, has set aside the purported reversal of the consent given by the Government for the farm-out agreement between Chevron and Transnational Energy Limited (TEL) on the Abigborodo and Hely Creeks marginal fields in the Oil Mining Lease (OML) 49.

Justice Taiwo Taiwo held that the defendants failed to supply counter evidence and arguments to disprove the plaintiffs’ claims. The judge noted: “One thing that is very clear and undeniably so, is that the averments of the plaintiffs, from the inception of the meetings and correspondences between the plaintiffs, Chevron Nig Ltd, the third defendant,  Department of Petroleum Resources, (DPR), Nigerian National Petroleum Corporation (NNPC) and National Petroleum Investment and Management Services (NAPIMS) on the farming out by Chevron Nigeria of the Hely Creek and Abigborodo marginal fields within OML 49 were not denied’.

The court, upheld the plaintiffs’ claims and granted all the reliefs sought, including an award of $20Million in damages against the defendants, who are all Federal Government’s agents. The suit was filed by Transnational Energy Limited (TEL) and Bresson A. S. Nigeria Limited. Defendants were Minister of Petroleum Resources, Minister of State, Petroleum Resources, DPR, NAPIMS, and the Attorney General of the Federation. Sijuade Kayode, lawyer to the plaintiffs, claimed that a farm-out agreement over the two marginal fields was concluded between TEL and the joint venture operators, Chevron Nigeria Limited in 2017 for amongst other purposes, to provide feedstock to a gas-to-power project developed by TEL and its partners, which started in 2012. The DPR, in a letter dated 20th February 2017, conveyed a letter of ministerial consent by the Minister of Petroleum Resources approving the farm-out and its terms, the lawyer stated. The DPR, in its said letter, equally directed TEL to pay a prescribed premium to Federal Government, after which the farm-out will become effective, a directive TEL complied with by paying the prescribed fee of $639,820.65, the plaintiffs added.

Rather than allow the plaintiffs enjoy the benefits of the agreement after the government acknowledged receiving TEL’s payment, the then Chief of Staff to President Muhammadu Buhari, the late Abba Kyari, wrote a memo, purporting to revoke the earlier ministerial consent, claiming to have acted on the instruction of the President. They added that the DPR, without any notice to the farmee (TEL) put the two fields in the 2020 marginal fields basket, even though the fields were not part of the original 57 fields approved for the bid round, a decision TEL and its sister company in the power business (Bresson A.S. Nigeria Limited) challenged by filing the suit.

The plaintiffs exhibited their audited accounts, business plan and financial model which showed that both plaintiffs had jointly expended $22,718,000.00 (twenty-two million, seven hundred and eighteen thousand United States dollars) on the development of the gas and power side of the project. They also exhibited their financial models in arguing that they have lost over $164Mllion due to the actions of the defendants, while Federal Government may have equally lost over $68Million in royalty and taxes not earned as a result of the actions of the defendants.

The plaintiffs asserted that their gas-to-power project elicited a massive international cooperation spanning over 15 countries and involving over 100 international experts. “As a matter of fact, the Hungarian Exim Bank went to parliament to amend its legislation in order to raise her scope of participation in the power side of the projects,” they said. Justice Taiwo, in the judgment delivered on October 18, 2020, a copy of which was made available on Friday, held that the defendants failed to supply counter evidence and arguments to disprove the plaintiffs’ claims.


Mozambique Issues New Regulations on Petroleum Infrastructure

With three Liquefied Natural Gas (LNG) plants underway and a number of local gas valourization facilities in view, Mozambique has reviewed its laws on Petroleum infrastructure.

Decree No. 84/2020, just approved by the government, is a clear and unambigouous statement that

petroleum infrastructure and petroleum operations can be set-up and executed, respectively, both on onshore and offshore.

That clarity is not available in the extant law, the Regulations on Licensing of Petroleum Installations and Activities (Ministerial Order No. 272/2009), which it grandfathers, but does not revoke.

The new regulation clarifies the responsibility of the regulator Instituto Nacional de Petroleo (INP) and strengthens its powers of inspection and sanction over petroleum infrastructure and operations;

Decree No 84/2020 updates and expands the types of infrastructures used in petroleum operations and includes a schedule for fees to be paid for the issuance of each license, as well as the statement of the need of paying an annual fee by entities which operate petroleum infrastructures and carry out petroleum operations.

It also, and language is important, replaces the terms “installations and petroleum activities” with “infrastructures and petroleum operations”.

The new Regulation states the rules and procedures for the licensing of the construction, installation, modification, replacement, operation and demobilization of petroleum infrastructures, including the storage and transportation by road, sea, river or railway of petroleum products, as well as the relevant permits and authorizations.

The Decree applies to all petroleum infrastructures to be installed by petroleum concessionaires, operators, their contractors and subcontractors and other legal entities engaged in the carrying-out of petroleum operations within the territory of Mozambique.
The construction, installation, modification, operation, demobilization of any infrastructure used for the carrying-out of petroleum operations either offshore or onshore, as well as those related to development wells, drilling rigs, production, storage and transportation by vehicles, are now subject to mandatory licensing by the National Petroleum Institute (INP).The installation of petroleum infrastructures during the prospecting phase, installation and operation of petroleum infrastructures for a period below 180 days, replacement of parts or components of a petroleum infrastructure, as well as the transportation of petroleum by road, sea, river or railway, is now subject to INP’s authorization. Additionally, the installation of petroleum infrastructures during the prospecting phase and the installation and operation of petroleum infrastructures for a period below 180 days, is also subject to registration with the INP.
Thus, the new Regulation has expanded the authority of the INP in terms of licensing and authorization in the Oil and Gas sector.

 

 


DPR Waits on President Buhari’s Nod, to Announce Winners of Marginal Fields Bid Round

By Macson Obojemie, in Lagos

The Department of Petroleum Resources (DPR), Nigeria’s regulatory agency, is awaiting the approval of the Minister of Petroleum, to announce the results of the Marginal Fields bid round.

DPR concluded the analysis of the bids in the last two weeks and it has sent the results to the Minister of State for Petroleum, Timipre Sylva, who is to deliver it to President Muhammadu Buhari, the country’s defacto Minister of Petroleum.

The three and half month-long bid round exercise featured 52 fields and was concluded on September 15, 2020.

It was heavily subscribed; the largest number of bid applications in any hydrocarbon licencing sale in Africa in close to 10 years.

While the round started with over 500 applications, it closed with at least 100 applications making it all the way, each delivering at least $115,000 to the Nigerian treasury in the process.

And there will be more money heading to those coffers; when the results are announced, wining bidders have to pay signature bonus before the final awards. Analysts expect some highly contested fields, like Egbolom, to attract north of $5Million as signature bonus.

Nigerian marginal fields bid round is restricted only to locals.

Most applicants in this round, the second such formal round of its type in 17 years, were Nigerian independents who already produce crude oil and gas and are seeking to expand their portfolios. Others were Nigerian oil service contractors who now feel they should take positions in hydrocarbon acreages. Fuller story on the Bid Round is published in the monthly Africa Oil+Gas Report.


TOTAL in A Second Big Discovery in South Africa

With the second major discovery in less than two years, South Africa is shaping to become a major gas/condensate heartland for the French major TOTAL.

The company has announced that its drilling of the Luiperd prospect, which follows up the play opening 2019Brulpadda discovery, has yielded another “significant gas condensate discovery” on the Block 11B/12B in the Outeniqua Basin, 175 kilometers off the country’s southern coast.

The Luiperd well was drilled to a total depth of about 3,400 meters and encountered 73 meters of net gas condensate pay in well-developed good quality Lower Cretaceous reservoirs. Following a comprehensive coring and logging program the well will be tested to assess the dynamic reservoir characteristics and deliverability.

We are very pleased with this second discovery and its very encouraging results, which prove the world-class nature of this offshore gas play,” said Arnaud Breuillac, President Exploration & Production at TOTAL. ‘’With this discovery and the successful seismic acquisitions, Total and its partners have acquired important data on the Paddavissie fairway, which will help to progress development studies and engage with South African authorities regarding the possible conditions of the gas commercialization.”

The Block 11B/12B covers an area of 19,000 square kilometres, with water depths ranging from 200 to 1,800 metres. It is operated by TOTALwith a 45% working interest, alongside Qatar Petroleum (25%), CNR international (20%) and Main Street, a South African consortium (10%).

 


Two Percent Is Too High for Operators to Pay Now, NCDMB Pleads

The Nigerian Content Development and Monitoring Board (NCDMB) and key organisations in the country’s oil and gas industry – the Petroleum Technology Association of Nigeria (PETAN), Petroleum Contractors Trade Section (PCTS), Oil Producers Trade Section (OPTS) and the Nigeria LNG Ltd have advised against increasing the percentage of the Nigerian Content Development Fund (NCDF) from the current 1% to 2% as proposed in the amendment of the Nigerian Oil and Gas Industry Content Development (NOGIDC) Act.

The NCDF is deducted from the value of contracts awarded in the oil and gas industry and was pegged at 1%  by the NOGICD Act of 2010.

The organisations canvassed this position in separate presentations they made last Monday in Abuja at the two-day public hearing organised by the Joint Senate Committee and House of Representatives Committee on Nigerian Content Development and Monitoring.

The NCDMB argued that the 1% NCDF deduction should be maintained, “given the pressure that the global oil and gas companies are facing with cost escalations and price reductions in the industry. With prudent management of the NCDF and the full cooperation of the operating companies, we believe Local Content shall continue to operate efficiently and grow.”

The public hearing is focused on three proposed legislations, namely the Bill for an Act to amend Nigerian Oil and Gas Industry Content Development Act, Cap 2, 2010 and other maters connected thereto and  the Bill for an Act to enact Nigerian Local Content Act for the development, regulation and enforcement of Nigerian Content in all sectors of the Nigerian economy except Oil and Gas Industry Sector and for related matters. The third legislation seeks to repeal the NOGICD Act and enact Nigerian Local Content Development and Enforcement Commission Act and establish the Nigerian Local Content Development and Enforcement Commission.

The NCDMB also responded to the proposed new provision to earmark 0.5%  of gross revenue of oil and gas companies for research and development, saying that the Board welcomes it on the condition that the money would be for the operator’s own utilization. The Board also supported the proposal by the amendment to add Naira to the Benchmark Currency for Local Contracts “This means a paradigm shift from the dollar-denominated provision to a bi-currency model,” the Executive Secretary explained.

 

 


Kaduna Electric Disco (KAEDCO) is Granted a 2MW Renewable Energy Sub-Franchise

Konexa, a renewable energy developer with funding from Climate Fund Managers (CFM), has partnered with Kaduna Electric Distribution Company (KAEDCO), to co-develop a private renewable energy generation and distribution sub-franchise project in the Kaduna state, Nigeria.

The project will consist of the development and construction of a 2.5MW solar PV plant with the potential to include a storage component:

  • Construction of eight solar mini-grids and associated distribution works;
  • Roll out of solar home systems, deployment of smart metering infrastructure;
  • an integrated cutting edge information and operations technology platform, grid network upgrades, as well as securing energy supply from nearby existing renewable generation assets.

The project, requiring an investment of approximately $50Million, will enable Konexa to serve the entire range of customers in its sub-franchise area – from large commercial and industrial customers that currently cannot rely on KAEDCO due to supply reliability and quality issues, to small rural customers that are not viable to be reached by the grid.

The project’s promoters are taking advantage of the Nigerian government’s eligible customer regulation, ratified in 2017, which states that customers with energy demand of more than 2MWh/h per month can directly buy power from a grid connected Genco at a mutually agreed price.

The promoters say that this is an opportunity to contribute towards Nigeria’s grid stability, accelerate the country’s sector reforms and demonstrate the private sub-franchise model.

Donors to the project include donors include Shell and Rockefeller Foundation, the UK’s Foreign, Commonwealth and Development Office and Power Africa and the CFM.

The Nigerian energy sector is notable for its significant energy deficit which has hindered economic growth for many years. Lack of access to grid power has resulted in around 55% of the population resorting to self-generation and has created a $15Billion off-grid market that is primarily fossil-fuel based, Konexa says in a statement.

 

 

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