Aker Energy is looking to sell part of its 50% participating interest in the Deepwater Tano Cape Three Points (DWT/CTP) block in Ghana, which includes the Pecan development project.
After the COVID-19 wreckage, the Norwegian operator has struggled to come up with the funding for the Pecan development,which it sounded so passionate about just 18 months ago.
Aker Energy’s demonstrated passion to fast track the development project led to the Ghanaian government’s amendment of Petroleum Agreements concerning the DWT/CTP and the South Deep Water Tano (SDWT), an amendment which significantly reduced the state’s share of the partnership and snuffed out the involvement of GNPC Explorco, a company that was set up to build operating capacity of the state hydrocarbon company GNPC.
But Aker Energy appeared to walk the talk. As far back as February 2020, the operator had entered into a Letter of Intent (LOI) with Yinson Holdings Berhad to award a bare-boat charter and an operations and maintenance contract for a floating, production, storage and offloading (FPSO) vessel at the Pecan field, following a competitive tender. The plan was that the contracts would have a firm duration of ten years followed by five yearly extension options exercisable by Aker Energy as operator on behalf of the license partners. Once developed and installed, the FPSO will be located over and connect to the state-of-the-art subsea production system located at approximately 2,400 metres below sea level.
Now, all of that enthusiasm has been considerably challenged by the economic downturn of the last one year.
Aker Energy’s other partners in the DWT/CTP block are Lukoil (38%), Fueltrade (2%) and Ghana National Petroleum Corporation (10%).
AIM listed minnow, Tower Resources, has now received formal confirmation from Cameroonian authorities, extending the First Exploration Period on the Thali PS Licence.
The formal “arrête” from the Minister of Mines, Industry and Technological Development (MINMIDT) MINMIDT extends the First Exploration Period to 11 May 2022.
“This formal extension allows the Company to proceed with finalising a schedule for drilling and testing the NJOM-3 well”, Tower claims. “We are looking forward to seeing the NJOM-3 well drilled as soon as possible, and we will have more news for investors about the schedule in due course.”
Tower Resources had declared Force Majeure in March 2020 in respect of the First Exploration Period of the PSC, in light of the restrictions required to combat the COVID-19 pandemic, and on 31 March 2021 the Company announced that the President of the Republic had also approved a formal extension of the First Exploration Period.
But this announcement is about the formal grant of the extension.
“We are once again grateful to the Republic of Cameroon and to the Minister of Mines, Industry and Technological Development and his staff for their continued support of the Thali project, and also to the President of the Republic, the Secretary General of the Office of the Presidency, and the Prime Minister for taking a direct interest in our activity, as well as all the staff at the Societé Nationale de Hydrocarbures who have supported us during this First Exploration Period”, Tower Resources says.
Norwegian explorer Equinor, which saw its output drop by 25% in Algeria in 2020, has inked a forward looking, cooperation agreement with that country’s state hydrocarbon firm.
The memorandum of understanding (MoU) between Sonatrach (the Algerian state company) and Equinor, is looking beyond hydrocarbon exploration and production in the country.
“The signing of the MoU strengthens the existing partnership between Equinor and Sonatrach”, Equinor says in a release.
Equinor has been in Algeria for 17 years, with positions in two developments and one rank exploratory tract, including stakes in the In Salahonshore gas development, the In Amenasonshore gas development and a partnership on exploration in the Timissit licence.
The company’s equity production in the two producing projects crashed from 55,000BOEPD in 2019 to 41,000BOPD in 2020.
Equinor’s release says that the MoU “includes cooperation within greenhouse gas emissions and carbon management, industrial safety management, implementation of technology to increase hydrocarbon recovery and development of a model for driving high-performance oil operations”.
…Dismisses the rumour that the company was awarded stakes in several fields.
The Nigerian government’s expectation of raising half a billion dollars from signature bonuses, has imposed significant financial pressure on participants in the about-to-be-concluded bid round of marginal fields, in the opinion of the chief executive of a homegrown E&P independent.
“By our own assessment, I think it is overpriced”, contends Osa Owieadolor, the Managing Director and Chief Executive Officer of Platform Petroleum, itself a marginal field operator. “In (the last marginal field bid round exercise) in 2003, $150,000 was paid as signature bonus, but now it is ranging from $5,000,000 to as high as twenty-something million dollars. That’s a lot of money!”
Owieadolor, 51, who retires from the job at the end of this month, says he is not canvassing for a signature bonus as low as $150,000, “but $5Million for a marginal field is too high” and this is one of the lowest figures.
The government, apparently, is targeting early revenues from the process into the national treasury. Sarki Auwalu, the CEO of the Department of Petroleum Resources DPR, the industry regulator, set out the agency’s expectations in a televised interview with the local TV channel Arise News last February. “We estimate [signature bonuses] will be not less than $500Million, which is on the conservative side,” Auwalu said.
Owieadolor argues that field development activity should take the primacy of place. “For marginal fields, you need to look beyond the signature bonus. You want to come up with a low figure that is an incentive to encourage people to focus on the development costs. Because that is really the key thing. The idea is not to have these assets, you pay for signature bonus, at the end of the day, you’re not able to develop it. The awardee should not feel much pressure when it comes to the signing into the asset, that s/he loses clear line of sight to first oil. I think the signature bonus was overpriced”.
Asked if the stellar performance of some of the fields awarded in the last bid round exercise could have encouraged the government to raise the tariff this time, Owieadolor responds in the affirmative. “I think that is one of the factors that DPRused”, he says. “Some assets that were reported as having very low reserves have, over time, produced way above what was booked as the reserves”, he testifies. “But you have to look at the capacity to fund. It’s not about owning the asset. You own the asset, you pay government so much upfront and then you cannot fund the development; after five years, the lease expires on you. When you have a situation where a lot of these awardees and co-awardees are first and foremost going to be struggling, some people are even trying to get debt facility for signature bonus, you’ll run into problems. For signature bonus, you should be able to secure some bit of equity funding for that. Then when you now get to your real development, a mix of debt and equity can see you through all of that”
Platform Petroleum has produced the Egbaoma field, in northwestern Niger Delta basin, for 14 years, with current oil production of around 3,000Barrels of per day and natural gas output of 22Million standard cubic feet per day, pumped into the Nigerian Natural Gas Grid system.
“Difficult access to financing even played a huge role in the activities of the 32 companies who were assigned 24 marginal fields in 2003/2004. Today, only about 40% of that group that achieved full development of their assets. Those that were able to achieve first oil within the first five years were actually less than 30%. A number of them had to seek extension and all that”.
Owieadolor dismisses the rumour that Platform was awarded stakes in several fields in the ongoing round. “We were awarded just a quarter of the equity in one field”, he clarifies. “For us, that again surprisingly is one of the disappointments we’re seeing in this bid round. We had thought that companies like ours that were part of the 2003 Bid Round, we’ve clearly demonstrated capacity, we’ve grown experience over the past almost two decades and we felt that companies like us, would have been given some special considerations in this process. But for some reasons, we were treated like any other applicant. But that is what it is”.
In the current round, no single field is assigned to a single company; all fields are awarded to multiple companies and the would-be partners” are expected to form a Special Purpose Vehicle per field. Owieadolor considers it bit premature to write off the SPV idea. “The flip side of that arrangement is now you have different entities coming together. There’s a bit of collaboration. You expect that the equity funding would be improved. When you have four entities in an asset, so it’s going to be easier for the four entities to contribute their share of whatever the signature bonus will be. You’re going to be funding based on that Pro-Rated obligation. But getting the right synergy is really where the question is. But I think that can be worked out. We’re already seeing it playing out, a lot of engagements are going on, there’re all kinds alliances here and there. You have 161 companies that were awarded about fifty-something assets. Perhaps you have about 70% of this number struggling to pay their signature bonus. Then maybe out of that, you have another 20-30% in the next two-three years are able to achieve first oil. If that happens, the pattern is not different from what we had previously. For me overall, you can say that is some success.”
Shareholders of FAR Limited, the Australian hydrocarbon property broker, have agreed to sell the company’s stakes in Senegal to Woodside Energy.
The deal is that Woodside will pay FAR, $45Million, then reimburse FAR’s share of working capital, including any cash calls, from January 1, 2020 to completion of the sale, with entitlement to certain contingent payments capped at $55Million.
Woodside moved, last December, to exercise its right of first refusal to preempt the sale of FAR’s interest in the Rufisque offshore, Sangomar offshore and Sangomar deep offshore (RSSD) contract area to the Indian player ONGC Videsh Vankorneft. FAR’s interest in the RSSD Joint Venture comprises 13.67% of the Sangomar exploration area and 15% of the remaining RSSD evaluation area.
By the time the transactions are concluded, Australia’s largest E&P firm would have bought up all the stakes belonging to its partners Cairn Energy and FAR in Senegal. It will then hold 82% working stake in the Sangomar exploitation area with the state owned Petrosen holding 18%. Its working interest in the remaining Rufisque, Sangomar and Sangomar Deep (RSSD) evaluation area (including the FAN and SNE North oil discoveries) will be 90%, while Petrosen holds 10%.
In January 2020, Woodside took Final Investment Decision to develop the Sangomar field, located in 800 metres of water. It will be Senegal’s first offshore oil project and the floating production storage and offloading (FPSO) vessel will have a production capacity of approximately 100,000 barrels of oil per day. The execute phase of the Sangomar Field Development includes the drilling of 23 wells, construction and installation of the subsea network and the construction and installation of the FPSO. The company targets first oil in 2023.
In December 2020, Woodside concluded the completed the acquisition of Cairn’s interest with the purchase price of $300Million plus a working capital adjustment of approximately $225Million, which included a reimbursement of Cairn’s development capital expenditure incurred since 1 January 2020. Additional payments of up to $100Mllion are contingent on commodity prices and timing of first oil.
After all these buys, Woodside will, in its own view, have“simplified the structure of the joint venture ahead of our planned equity sell-down in 2021”.
The company is convinced that the Sangomar development “is an attractive, de-risked asset that offers near-term production to potential buyers.”
Dana Gas, the Abu Dhabi listed independent, is still looking for buyers for its Egyptian onshore oil and gas assets, after it failed to consummate a sales and purchase agreement with IPR Energy Group, another middle eastern minnow.
The two had signed a tentative agreement on the transaction, worth $260Million in October 2020. But some of the conditions precedent for the sale to go through were not met by the agreed time-frame on April 14, 2021, Dana said. “A number of conditions precedent to the transaction could not be completed to the satisfaction of both parties,” the company, which describes itself as the ‘Middle East’s largest private sector natural gas company’, declares in a briefing. “The Board has therefore decided to retain and operate the assets in Egypt alongside the highly prospective exploration acreage offshore Block 6”. Patrick Allman-Ward, Dana Gas’ Chief Executive Officer, commented.
The sale was previously due to close in 1H2021.
What Dana Gas Wants to Sell
Dana Gas is a 100% operator in four concessions and 50% non-operator of one concession, all located in onshore Niger Delta. The concessions include: El Manzala, West El Manzala andWest El Qantaraall covering 796 square kilometres, with an estimated 89Million Barrels of Oil Equivalent (BOE) of reserves(Gaffney Cline and Associates). The four concessions include 15 development leases with gas and condensate production from 15 fields. Gas production is about 155 MMscf/day 5,300Bbls/Dcondensate plus 235 tons/day of LPG, totaling 33,000BOEPD in 2020, an 8% decline from 30,300BOEPD in 2019, as a result of natural field declines. Dana Gas has been looking to offload these assets since July 2019, when it declared that a sale would allow it to double down on its more promising operations in Iraqi Kurdistan.
What Dana Gas Wants to Keep, in Egypt
Dana Gas is 100% operator of one offshore concession in the Eastern Mediterranean, a growing natural gas hub.
Angola’s hydrocarbon regulatory agency Angolan National Oil, Gas and Biofuels Agency (ANPG) has scheduled, for Tuesday April 6, 2021, a hybrid online and physical roadshow for the country’s next acreage licencing-round, at the Talatona Convention Centre in Luanda.
This will kickstart a series of both digital and in-person roadshows and technical presentations to promote the blocks to be awarded in key international markets. This event will also provide the opportunity for investors to engage with the agency regarding the blocks on offer, the data packages and the accessibility studies, as well as touch upon environmental, logistical and local content issues. The contest proper starts on April 30, 2021. The deadline for the submission of proposals runs until June9, 2021, in compliance with the 40 days provided for by law, and the opening ceremony for proposals will take place on June 10, 2021.
In line with the provisions of Presidential Decree No. 86/18, of 2 April 2019, which establishes the rules for the organisation of bid rounds, the bid round will unfold as follows:
The opening of offers from potential suitors in a public setting
The evaluation and qualification of proposals
The submission of the evaluation report to the Ministry of Mineral Resources and Petroleum and Gas
Contract negotiation with the winners of the bid-round
Data available includes 2D seismic coverage of the LowerCongo Basin, a recently updated Geological Map and Database of the Onshore Kwanza Basin and a compilation of recent aeromagnetic data covering the Transition Zone and Shallow Waters of the Lower Congo and Kwanza Basins.
Nine blocks are on offer, in the Lower Congo and Kwanza Basins: they include:
Three blocks of the lower Congo onshore Basin CON1, CON5 and CON6
Six of the Kwanza onshore Basin (KON5, KON6, KON8, KON9, KON17 and KON20)
The country’s International Competitive Bid Round for oil gas licenses, announced in 2019, is a scheduled offering for onshore and offshore, in the period 2019-2025.
ANPG), awarded three blocks: 27, 28, and 29, offshore in the deepwater Namibe Basin in 2019.
In 2020, the bidding plans were disrupted by COVID-19 complications.
The country’s least transparent bid round in 20 years inches towards some closure
The Department of Petroleum Resources (DPR), Nigeria’s regulatory agency for the hydrocarbon industry, has distributed the third letter in the series of correspondences it has been sending to, apparently, the 161 companies selected as winners of interests in the 57 marginal fields on offer in the country’s second marginal field bid round.
The third letter specifies the percentage awarded to the recipient and the signature bonus expected of it by government. The letters were emailed on March 2, 2021 and the authorities expect the signature bonus to be paid in 45 days, and it could be paid in either the local currency Naira or in US Dollars.
The total signature bonus per field ranges from $5Million to $20Million, but since no single field is assigned to a single company, the signature bonus demanded from each company correlates with the percentage interest in the field offered to the company. If the entire signature bonus charged to Field A is $5Million, a company assigned 20% equity in that field is asked to pay a signature bonus of $1Million.
Names of those who have been granted the awards remain largely in the realm of speculation, as the authorities have not published the list. This latest correspondence to awardees still doesn’t specify who your partners are and doesn’t tell who operates the field, but the partners on each field are expected to jointly create a Special Purpose Vehicle to operate the asset.
The lack of knowledge of who your partners are raises the risk involved in the funding of the signature bonus. So does the instruction to awardees attached to every field to create a Special Purpose Vehicle (SPV) to act as operator.
Africa Oil+Gas Report learns that winners of this round include at least three marginal field operating companies. There are also at least three companies, run by members of PETAN, the umbrella grouping of oilfield engineering contractors. Other companies that have reportedly received letters include those promoted by retired technical staff of some of the oil majors operating in Nigeria. But there is a lot of talk about wheeling and dealing in Abuja and names of companies that have been awarded fields who didn’t even apply. The only way to dissuade anyone from believing false conspiracy theories is to know who got what at every stage of the process.
The first of the three letters emailed to “winners” indicated that the addressee was qualified for a certain field. The second letter then merely asked the awardee to specify which currency they want to pay the signature bonus in. This third letter, then, which specifies the percentage that the awardee has on the field and requests for payment of signature bonus by a certain date, is the first firm commitment the authorities are making to an awardee. But questions around who other partners are and who to operate the field indicate that there will either be a fourth letter, or the DPR will publish a list on which the fields, the awardees to each field, the signature bonus and the operator will be. It’s quite exhausting.
The ongoing bid round has been the least open of all the non-discretionary awards organized by the Nigerian authorities since the country’s first competitive lease sale was announced in 2000. Prior to 2000, the year after Nigeria’s return to democratic governance, the country’s sole process of granting awards of acreages was discretionary. The 2003/2004 Marginal field bid round was a high-water mark in the annals of licencing rounds in Nigeria. 120 companies were shortlisted from a bidders’ list of less than 200 companies that applied for 24 fields, with their names all published. For each of the 24 fields, five companies were then asked to appear before a jury, and give technical and financial presentations on their proposed paths to first oil. The jurors at those presentations included DPR representative, who chaired the jury; a ranking technical staff of the IOC on which the marginal field lies (who is the farmor) and a representative from the NNPC. What that jury composition suggested was that the key stakeholders on a marginal field were all involved in determining who was going to develop it. The signature bonus was a flat $150,000. Companies were granted fields on the basis of convincing the jury with technical and financing argument on field development. In spite of all that rigour, 11 fields still did not achieve production 16 years after the farm out agreements were signed. Compared with the 2003/2004 process, the current round is a long walk in the dark.
Nigerian bid rounds have deteriorated in the quality of transparency since the 2003/2004 marginal field bid round, but the ongoing round surpasses all in its high level of opacity.
Angola’s National Agency of Petroleum, Gas and Biofuels says it has made available for free consultation the data packages related to the concessions that will be put out to tender starting in April.
“However, the geophysical data (seismic and magnetometric) do not integrate any of these packages, being obligatory to pay a fee for their acquisition”.
According to ANPG, the available packages contain the compilation of existing data, duly selected, related to the concessions to tender. The aim is to assist potential interested parties in the evaluation they are going to carry out and support them in decision making.
The agency, however stresses that companies will still have to buy the data if they want to interprete.
“The geophysical data (seismic and magnetometric) do not include any of these packages, being obligatory to pay a fee for their acquisition”.
For this tender, which started in late 2020, two data packages were prepared, taking into account the two terrestrial basins to be tendered – the Lower Congo and the Kwanza.
The Lower Congo Terrestrial Basin Data Package , relating to three blocks (CON 1, 5 and 6) consists of geological information on the 24 wells of the three blocks to bid and the remaining 33 wells of the adjacent blocks, as well as 14 reports studies that detail the stratigraphy, structural component and prospective; accessibility study (Atlas); georeferenced information (maps); and legal / legal information.
The Kwanza Land Basin Data Package , relating to six blocks (KON5, 6, 8, 9, 17 and 20) is also composed of geological information (reports and diagrams) from 47 wells, 36 of which belong to the blocks to be bid and 11 wells belonging to the neighboring blocks; 13 reports of abandonment of the main producing fields in the basin; seismic data (vintage seismic); accessibility study (atlas); georeferenced information (maps); and legal / legal information.
For both packages, ANPG stresses that geophysical data (seismic and magnetometric) are not part of these packages, so interested parties should purchase them from their partners Delta Development Management (Lower Congo) and GEOTEC and ION / GXT (Kwanza ).
“The disclosure of these packages, in a free session – which can be done in person or online – contributes to making the bidding process moretransparent, allowing interested parties to know the data available before they acquire them for more accurate and accurate study and analysis “
Interested companies should contact the National Oil, Gas and Biofuels Agency through its website ( www.anpg.co.ao ), e-mail or even by letter, requesting an appointment for a data consultation session. These sessions will be free and can be virtual or in person, depending on the possibilities of the interested parties, but always carried out according to the rules in force in the context of the pandemic still in force.
Malaysian driller Sapura Energy Berhad has declared that its joint venture with Seadrill, namely Sapura Navegacao Maritima SA (SNM), is not impacted by the recent Chapter 11 cases filed by several Seadrill subsidiaries operating in Asia.
In a clarification to Bursa Malaysia, the country’s Stock Exchange, Sapura states the Chapter 11 filing by Seadrill, which is an internationally renown Scandinavian drilling company, does not involve Sapura or entities related to the corporate structure of the joint venture, stressing that the filing has no financial impact on Sapura Energy’s business plans and financial strength.
Sapura Navegacao Maritima SA (SNM) is the only joint venture between Sapura Energy and Seadrill.
Headquartered in Rio de Janeiro, SNM is one of the leading subsea services operators in the Brazilian market, with a fleet of submarine service vessels providing support, installation and flexible pipe laying expertise to clients in the region.
The company has a workforce of more than a thousand professionals, from 21 different nationalities. SEB’s clarification was in response to a media report linking Seadrill’s Chapter 11 filing of its Asian units, to the Brazil-based SNM. In the clarification, SEB also explained that the filing has no effect on its contracts with Petrobras, which forms the main revenue for SNM; and does not trigger any cross default for the joint venture’s business financing.