All posts tagged farm in-farm out

South Sudan Launches First Oil and Gas Bid Round

By Foluso Ogunsan, Upstream Correspondent

South Sudan has announced the launch of its first Oil Licensing Round, aiming “to welcome back experienced partners and operators following significant progress in returning to peace and stability”, the country’s Ministry of Petroleum says in a release.

With new data, analysis, and government mechanisms, the Ministry seeks to attract high-quality investors and partners.

“Potential investors are now able to request all relevant information from the Ministry of Petroleum until August 23rd 2021, by expressing their interest and providing contact details online at”, the statement explains.

“Once the expression of interest process is concluded, the Ministry of Petroleum will host a virtual series of data presentations, followed by an international roadshow”.

There are thirteen open acreages, in the country, out of a total of 21, but this particular round is offering five (5) tracts, namely A2, A5, B1, B4 and D2, with areal sizes ranging between 4,000 and 25,000km2, and most comprising between 15,000 and 20,000 km2. This means there eight (8) “free” acreages, but the Ministry doesn’t say whether these could be negotiated for, even if they are not in the round.

“This bidding round is for a number of selected blocks, which will be facilitated and evaluated based on set criteria by the MoP”, the Ministry says.

South Sudan’s upstream hydrocarbon activity has been dominated by Asian companies, notably China National Petroleum Corporation and Petronas, respectively from China and Malaysia. They produced, in partnership with South Sudan’s government owned Nile Petroleum, about 139,000Barrels of Oil Per Day in 2019, according to the BP Review of Statistics, the industry bible for country-level oil and gas production figures. As these firms themselves are state hydrocarbon companies, South Sudan can certainly do with private and publicly listed companies from the West and the Middle East.

Below are further details from the South Sudan’s Ministry of Petroleum regarding the bid round:

Currently there are three consortiums operating producing blocks in South Sudan, with another four oil exploration companies having acquired production sharing contracts.

1. Producing Blocks:

• Block 3 and 7 – DAR Petroleum Operating Company: China National Petroleum Corporation, Petronas, Nile Petroleum Corporation (8% equity)

• Block 1, 2 & 4 – Greater Pioneer Operating Company: China National Petroleum Corporation, Petronas, Nile Petroleum Corporation (5% equity)

• Block 5A – Sudd Petroleum Operating Company: Petronas, Nile Petroleum Corporation (8% equity)

2. Awarded Exploration Blocks:

• Block B3 – Oranto Petroleum, Nile Petroleum Corporation (10% equity) 

• Block 5B – Ascom, Nile Petroleum Corporation (10% equity) 

• Block B2- Strategic Fuel Fund, Nile Petroleum Corporation (10% equity)

3. Free Blocks:

• Blocks: A1, A2, A3, A4, A5, A6

• Blocks: B1, B4• Blocks: C1, C2

• Blocks: D1, D2• Blocks: E1, E24. 

First Licensing Round:• Blocks A2, A5, B1, B4, D2

Potential investors are now able to request all relevant information from the Ministry of Petroleum until August 23rd 2021, by expressing their interest and providing contact details online at

They can also contact directly:
For information about data access and purchase:
Pawel Ulatowski
Director, ZDS

For information about geoscience:
Dr. Omar B. Abu-elbashar
MD, Petro-Tec

“After years of instability and conflict, lasting peace is finally gaining a foothold in the country following the establishment of the Transitional Government of National Unity (TGNU) in February 2020, and the follow-up agreement over governance of the country’s states. South Sudan is now firmly back on a positive developmental path and is expected to continue as one of Africa’s fastest-growing countries in the foreseeable future”.

Sonangol Starts to Sell Some of its Equity in Angolan Blocks

By Toyin Akinosho, in Lagos

State hydrocarbon company Sonangol, has commenced partial divestment from eight acreages offshore Angola.

The sale process, which started June 14 and is scheduled to end on August 6, 2021, involves over 40,000Barrels of Oil Per Day production.

Sonangol is selling part of the equity assigned to Sonangol P&P, its operating arm, Blocks  03/05, 4/05, 5/06, 15/06, 18, 23, 27 and 31, all in the country’s deepwater.

The most prolific block in the sale is 15/06, in which Sonangol P&P has held around 37% equity since TOTALEnergies exited the acreage in 2014. Over 92,000BOPD was exported from Block 15/06 by the three partners on the asset in March 2021, according to the May 2021 edition of the Africa Oil+Gas Report.

Dimantino Azevedo, Angola’s Minister of Mining Resources, Oil and Gas, says that the sale is part of Sonangol’s production and exploration strategy for its repositioning as the national oil operator, in some of Angola’s offshore and onshore oil concessions.

“The opening of this process of partial alienation of the participative interests in some of Sonangol’s oil concessions emerges from actions aimed at repositioning and sustainability of Sonangol’s investment portfolio, to take on its financial commitments,” the minister declared at the launch of the sale process.

Sonangol needed to reduce its financial exposure as representative of the state in oil and gas concessions, Azevedo explained. The state company needs a step back from direct intervention in the oil acreages as an investor, and unburden itself from some financial obligations, in order to free up capital and “support the expenses associated with the acquisition of refined products”.

Azevedo concluded that partial sale of Sonangol’s stakes “would promote better allocation of capital, greater business efficiency, creation of cost synergies and greater focus on the “oil and gas” value chain”.


Angola Reduces Entry Fee, Extends the Deadline for Bid Round

Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG), the Angolan hydrocarbon regulatory agency, has announced that the delivery of bids for tenders for the Lower Congo and Kwanza onshore basins, which initially should be done by June 9th, has just been extended until July 9th, 2021.

Simultaneously, “ANPG decided to revise the entrance fee for these bids”, the agency says in a statement

“The decision of the national concessionaire is linked to the fact that many of the companies interested in the process have asked for a longer period to better understand the file, the data it contains and also to clarify doubts with ANPG technicians”.

ANPG did not give the percentage reduction of the entry(participation) fee, which was set at $1Million,  but declared that the data package for both basins still has to be acquired by interested companies. This decision is justified by the fact that it deals with onshore exploration, to which, historically, smaller companies and national companies converge, which are interested in participating in the prospecting, exploration, development and production of hydrocarbons in Angola.

“COVID-19, which continues to affect the world economy, has also destabilized the hydrocarbons market, and ANPG, which since its creation has been the driving force behind the oil activity in Angola, chose to listen to suggestions from the national business community and the foreign investors on the revision of the value of the entrance fee to facilitate entry into the sector for new entrants.

“It should be remembered that the launch of the Public Tender for the 2020 Tender for Blocks CON1, CON5 and CON6 ( Low Congo Onshore Basin ) and for Blocks KON5, KON6, KON8, KON9, KON17 and KON20 ( Kwanza Onshore Basin ) was carried out in the April 30th. This launch included the publication of the terms of reference, public tender rules, application and proposal submission models”.

ANPG concludes that interested parties can find this and other information in ANPG´s website (, and/or by contacting ANPG’s Negotiations Department through e-mail:, for any further clarify any and all questions related to this bidding process”.



OML 118: NNPC, SNEPCo, Others Sign Multibillion Dollar Deep-Water Agreement

Deal to Yield Over $780Million in Immediate Revenues to Government.

The Nigerian National Petroleum Corporation (NNPC) and its Production Sharing Contract (PSC) partners -Shell Nigeria Exploration and Production Company (SNEPCo), Total Exploration and Production Nigeria Limited (TEPNG), Esso Exploration and Production Nigeria Limited (EEPNL) and Nigerian Agip Exploration (NAE) – have executed agreements to renew Oil Mining Lease (OML) 118 for another 20 years.

The five agreements signed include: Dispute Settlement Agreement, Settlement Agreement, Historical Gas Agreement, Escrow Agreement and Renewed PSC Agreement.

The NNPC, in a statement, says that over $10Billion of investment would be unlocked as a result of the agreements, which, it argues “signaled the end of the long-standing disputes over the interpretation of the fiscal terms of the Production Sharing Contracts (PSC) and the emplacement of a clear and fair framework for the development of the huge deep-water assets in Nigeria”.  

Mele Kyari, the corporation’s Group Managing Director, estimates that “the deal would yield over $780Million in immediate revenues to the Federal Government while it would also free the parties from over $9Billion in contingent liabilities”.

Bayo Ojulari, the Managing Director of SNEPCo, contends that the agreements marked the end of a twelve-year dispute that had marred business relationship and affected trust and investment. “Today, we have signed agreements that define the future of deep-water for Nigeria. This is the first deep-water block that was developed in Nigeria and it is also the first one that we are resolving all the disputes that will lay the foundation for the resolution of other PSCs,” the SNEPCo helmsman stated.

Dana Gas Needs Financing Partner to Drill “Thuraya”, Offshore Egypt


Dana Gas the UAE based minnow, is hoping to drill a “key” prospect in its operated Block 6, offshore Egypt, in 2023.

But the operator, strapped for cash, needs a well-heeled partner to co-finance the probe.

The subject is the Thuraya prospect in the block, which is also known as North El Arish Concession.

Dana Gas is offering a material interest in Block 6 to a company willing to fund the planned Thuraya well, recently estimated likely to cost $95Million (dry hole). “A $90Million cost recovery pool, which is fully recoverable under Egypt’s profit-sharing fiscal regime, can also be shared with an incoming party. Operatorship is available to suitably qualified companies”, says a statement by marketing agents for the prospect..

Dana Gas is in the process of securing an extension to the current 2nd Exploration Period after unavoidable delays incurred during the seismic data acquisition and the COVID pandemic. Together with the optional 3rd Exploration Period of two years, this will secure the license area for three years enabling the well obligation to be drilled by mid-2023.

Envoi, the British acquisition and divestment advisor which the company hired to recruit suitable farminees, frames the situation as an “opportunity to participate in drilling of dual (stacked Oligocene & Cretaceous) play in ‘Thuraya prospect’, testable with one well”.

Envoi says that Thuraya is close to proven play analogues (including cretaceous reef in Zohr Field to the north andOligocene clastics in Ameeq and Nour discoveries to the west).

Envoi says the Thuraya prospect holds estimated combined ‘Mean’ Potential of 17+ Trillion cubic feet (Tcf) of Gas Initially In Place (GIIP) and  37 Tcf Upside (‘Mean’ 11+ Tcf and 24Tcf Upside recoverable resources) “where a discovery of only 2+ Tcf would be commercial”.

“Although large carbonate reef prospects are recognised where local basement highs occur in the region (now also including Block 6), the Oligocene sand potential, proven in the Nile Cone by the Salamat and Atoll fields since 2013, has only recently been recognised as a primary play target in the eastern part of Egypt’s offshore nearer to Block 6”, Envoi notes in its briefing.

“Its potential here has been unlocked by the Nour and Ameeq discoveries made in 2019 and 2020 just 20km to the west of Block 6. This Tertiary play fairway is, however, defined by regional seismic amplitude mapping, which clearly show that extensive basin floor fans originated from the Nile Delta. These have prograded through time to the north and east. These delta floor and prodelta complexes progressed into the Levant Basin and through the Block 6 area during Oligo-Miocene times. 

“Today the Miocene is also a proven reservoir in the very large (22Tcf) Leviathan and Tamar Fields to the north east which are interpreted as the younger more distal extension of the same sediment system that passed through Block 6 with similar resource potential, and where it remains undrilled”. Envoi’s briefing contends.

“The majority of the mapped Cretaceous and two distinct Oligocene closures that overlie it in the Thuraya prospect are now confirmed to lie mostly within Block 6 by the new Broadband 3D survey completed in 2020. 3D seismic as well as shipborne gravity and magnetic data was acquired right up to the maritime boundary to define the edge of the Thuraya prospect after the earlier block-wide 2015 3D survey was not permitted to cover the border area.

“Combined, these two plays in the Thuraya prospect are now estimated to be capable of an un-risked ‘mean’ in-place potential of 17Tcf GIIP (and P10 upside of over 37Tcf GIIP) with a ‘mean’ recoverable resource potential of over 11Tcf (and P10 upside of 24 Tcf recoverable), based on conservative volumetric inputs. The commercial threshold for a development in the area is calculated to be around only 2Tcf recoverable, hence a discovery in either the clastic or reef plays would be highly attractive commercially. The full combined mean resource potential in the Thuraya field of over 11Tcf is calculated to have an NPV10 value of $2,2Billion with an EMV of $1Billion. Block 6 also has material follow-on prospectivity, including the same stacked Oligo-Miocene play in three undrilled prospects which combined could add around 7 Tcf to the Block 6 recoverable resources. The potential value of this opportunity and the Thuraya prospect on its own should not be underestimated. Egypt’s self-sufficiency, with declining domestic gas production, is only expected to be able to fully support demand until around 2025”.

Aker Energy Looks to Farm Down in DWT/CTP

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%).

Cameroon Formally Grants an Extension for the Thali Licence

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. 

Equinor’s Algerian Output Drops, Company Inks Agreement with Sonatrach

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 Salah onshore gas development, the In Amenas onshore 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”. 

Nigeria’s Bid Round Signature Bonuses are Overpriced, says Platform’s Outgoing CEO

…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.”

FAR Finally Agrees to Sell to Woodside in Senegal

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.”

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