All posts tagged farm in-farm out


Africa Oil Makes $137.5Million in Seven Months, on Asset It Purchased for $519Million

Africa Oil Corp. concluded its acquisition – worth $519.5Million – for a 50% ownership interest in Petrobras Oil and Gas BV (POGBV) in January 2020.

Today, seven and half months later, it reports it has received  total dividends amount of $137.5Million since the closing of the Prime acquisition on 14 January 2020.

POGBV’s primary assets are an indirect 8% interest in oil mining lease (OML) 127, operated by Chevron, containing the Agbami Field, and 16% interest in OML 130, operated by TOTAL and contains the Akpo and Egina Fields, offshore Nigeria.

The Toronto listed minnow says it has received four dividends from Prime Oil and Gas B.V. (Prime) since the January 2020 purchase. Prime is a company that holds interests in deepwater Nigeria production and development assets.

On August 31, Africa Oil Corp. reported that Prime has distributed the fourth dividend, “a  $50Million dividend with a net payment to Africa Oil of $25Million related to its 50% interest”.

The Company has applied  $17.7Million of this dividend to pay down the BTG term loan, reducing the outstanding balance to  $176.9Million.

Africa Oil Corp. is a Canadian oil and gas company with producing and development assets in deepwater Nigeria; development assets in Kenya; and an exploration/appraisal portfolio in Africa and Guyana. The Company is listed on the Toronto Stock Exchange and on Nasdaq Stockholm under the symbol “AOI”.

 


Africa Energy Doubles Its Stake in South African Discovery

By Jo-Jackson Mthembu

Toronto listed minnow Africa Energy Corp., says it has signed definitive agreements to increase its effective interest in Block 11B/12B offshore South Africa from 4.9% to 10%.

Block 11B/12B is the site of the Paddavissie Fairway, on which TOTAL’s huge gas and condensate discovery was made in February 2019.

TOTAL is returning for a multi-well campaign in the block, located in the rough waters offshore Cape Agulhas, from September 2020.

“Block 11B/12B offshore South Africa contains one of the most exciting oil and gas exploration plays in the world today” Garrett Soden, the Company’s President and CEO, commented.

“In anticipation of the Luiperd-1X well results expected later this year, we have agreed with Impact Oil& Gas and Arostyle to simplify and consolidate Main Street’s 10% interest in Block 11B/12B under Africa Energy,” Soden said.

Luiperd-1, suspected to be the largest prospect in Paddavissie Fairway, will be the first on TOTAL’s drilling schedule. It will be drilled by the semisubmersible rig Deepsea Stavanger, operated by Odfjell Drilling.  Two other wells are expected to follow in short order.

Africa Energy currently holds 49% of the shares in Main Street 1549 (Proprietary) Limited, which has a 10% participating interest in Block 11B/12B. TOTAL operates the block with a 45% participating interest, while Qatar Petroleum and CNR International (have 25% and 20% participating interests, respectively.

Africa Energy says it is pursuing two transactions by which will first secure the indirect financial interest held by Impact Oil & Gas Limited and then obtain an option from Arostyle Investments (RF) (Proprietary) Limited, which holds 51% of the shares in Main Street, to acquire the entire Participating Interest after drilling the Luiperd-1X well. “Following the Impact Transaction and exercise of the Arostyle Option, subject to various consents and approvals, Africa Energy will directly hold the Participating Interest, and both Impact and Arostyle will be significant shareholders of Africa Energy”.

 


Senegal Expands its Stake in Sangomar Oilfield Project

Petrosen has decided to increase its stake in the Sangomar Exploitation Area from 10% to 18%.

Senegal’s state hydrocarbon company is now required to reimburse the other venturers in the Rufisque, Sangomar and Sangomar Deep (RSSD) acreage their pro-rata share of the 8% of expenses relating to the Sangomar Exploitation Area incurred since 8 January 2020.

“As a result, FAR’s stake in the Sangomar Exploitation Area decreases from 15% to 13.67%”, FAR says in a release.

Woodside Energy, the operator, holds 31.89%; and Cairn Energy has 36.44%. Russian giant Lukoil agreed to buy out Cairn Energy’s interest, but Woodside has invoked the right of first refusal. Woodside will now purchase Cairn’s 36.44% by paying $300Million upfront, plus working capital adjustments, including reimbursement of Cairn’s development capital expenditure incurred since 1 January 2020.

Work on the Sangomar Field Development commenced in early 2020 and first oil production is targeted in 2023.

FAR, an Australian junior, has struggled to pay its part of the cost of the project on an ongoing basis and has stated, time and again, that it is willing to sell some or its entire equity.


Conoil Wins Bid for Chevron’s Sale of Equity in OMLs 86 and 88

By Jo-Jackson Mthembu, in Yenagoa

Conoil Producing, the Nigerian E&P independent owned by the billionaire Mike Adenuga, is the winner of the bid for the 40% equity held by Chevron Corp. in Oil Mining Leases (OMLs) 86 and 88.

The Lagos based junior is currently in discussion with the California headquartered major.

It wasn’t clear, as of the time of this writing, how much Conoil is betting on the assets, which lie in contiguity with some of its own producing properties.

Chevron had been trying to dispose the shallow water acreages, located off the mouth of the current Niger Delta basin, for over five years. They are part of the five Nigerian tracts acquired in the course of the merger between Chevron and Texaco 21 years ago.

But things only revved up in the last seven months. Africa Oil+Gas Report disclosed, three months ago, that bidders were expected to make full disclosure of their financial and operating capacities by the end of April 2020.

OML 86 contains the Apoi fields; the largest being North Apoi.

It also holds Funiwa, Sengana and Okubie fields. One recent discovery: Buko, straddles Shell Nigeria operated Oil Prospecting Lease (OPL) 286 and is either on trend with, or on the same structure as the HB field in OPL 286. OML 88 holds the Pennington and the Middleton fields, as well as the undeveloped condensate discovery, Chioma field.

The conclusion of this sale means that Chevron has disposed of all the legacy shallow water assets it acquired when it purchased Texaco in 1999.

Between 2013 and 2015, Chevron sold its stakes in OMLs 83 and 85, both of them former Texaco Nigeria assets.

It’s instructive, then, that Chevron’s largest producing asset in Nigeria, the Agbami field, was “inherited” in that same turn- of –the- century merger with Texaco; this deepwater field alone produces 165,000BOPD, more than a third of Chevron’s total operated crude oil production in Nigeria.

 


High Number of Offshore Fields Increases the Risk in 2020 Marginal Field Bid Round

By Fred Akanni, Editor in Chief

There are 29 shallow water fields among the 52 fields on offer in the ongoing Nigerian marginal field bid round, which wraps up on September 2, 2020.

This represents 56% of the total.

Compared with six offshore fields (or 25%) out of the 24 marginal fields offered in 2003/2004, this current round is enormously riskier.

Offshore fields are more expensive.

An average 20Million barrel field in 30 metres of water will require in excess of $65Million to reach first oil, according to modelling by Africa Oil+Gas Report.

In the last marginal field round, offshore fields represented the highest proportion of the fields that didn’t make it to first oil.

Out of the six offshore fields (all located, incidentally, in acreages operated by Chevron) awarded in 2004, only one made it to first oil.

The fields with the fastest routes to market, in the class of 2004, are located on land. Most of those that struggled to reach first oil, are in swamp terrain.

Details on funding challenges and opportunities in the July 2020 issue of Africa Oil+Gas Report.

 


Energy Chamber Campaigns for Chevron’s “Entry” into Eq Guinea’s Gas Project

Chevron’s ongoing take- over of the US independent Noble Energy offers it the opportunity to lead a significant gas project in the Equatorial Guinea and Cameroon.

These two countries, along with Israel, make up the international portfolio on the list of properties, up for Chevron’s grab, in the $13Billion take over. As Africa Oil+Gas argues in its July 2020 issue, the California based major has prioritized the unconventional basins in the US as the raison dêtre for seeking to buy Noble Energy. Eq Guinea and Cameroon are a little below the radar in its ranking.

But the African Chamber of Energy (ACE) sees the bright side for the African opportunity. It is encouraging the authorities to facilitate Chevron’s entry into Central Africa’s “most ambitious gas project” through this take over.

Noble Energy has interests in the Alba Field (33% non-operated WI and 32% revenue interest), Block O (Alen Field 51% operated WI and 45% revenue interest) and Block I (Aseng Field, 40% operated WI and 38% revenue interest).

“While the Alba Field has been feeding gas into the country’s Punta Europa complex for decades, including the EG LNG Plant, the AMPCO methanol plant and the Alba LPG plant, its declining reserves have led to the development of the Alen and Aseng fields as alternative sources of gas”, the Chamber recalls. “In 2019, Noble Energy was at the heart of a groundbreaking agreement to launch the Alen Monetization Project, expected to ensure continued and stable gas supply to Equatorial Guinea’s LNG and downstream revenue-generating infrastructure.

ACE appeals that “transaction and projects approvals should not be unnecessarily delayed ensuring a quick and efficient takeover in the region so ongoing gas projects are not delayed.”

NJ Ayuk, the Chamber’s Executive Chairman and Kickstarter, declares: “This acquisition gives the region a very experienced and credible gas player with tried, true and tested solutions to support our gas ambitions. ‘Fast tracking approvals and driving commonsense measures around this deal will make the industry work.”

Although ACE says that “these assets in Equatorial Guinea represent 94Million barrels of oil equivalent of proved developed reserves and 38Million barrels of oil equivalent of proved undeveloped reserves”, Noble Energy, on its website, talks of three trillion cubic feet of gross natural gas resources in the Douala Basin, “which positions us well for LNG sales exposure over the coming decade”.  Three Trillion Cubic Feet translates to 500Billion BOE. So, the chamber’s figures don’t add up. Not good enough for a supposedly optimistic release. ACE adds: ”In addition, Noble Energy was also the operator Block YoYo in Cameroon and of the deepwater Block Doujou Dak (60% WI) in Gabon, where it was in the process of evaluating recently acquired 3D seismic data.

“The project is still on track for delivery in 2021 and is the first step of the development of a much broader offshore gas mega-hub in the Gulf of Guinea. This regional gas hub would ultimately include the development of the Yolanda and YoYo discoveries located in Equatorial Guinea’s Block I and Cameroon’s YoYo Block, both operated by Noble”.

Noble Energy explains on its website: A 24-inch pipeline capable of handling 950 million cubic feet of natural gas equivalent per day (MMcfe/d) will be constructed to transport all natural gas processed through the Alen platform approximately 70 kilometers to the onshore facilities.

At start-up, natural gas sales from the Alen field are anticipated to be between 200 and 300 MMcfe/d, gross (~75 to 115 MMcfe/d net to Noble Energy)

The reserves figures may look impressive, from where ACE sits, but American companies, as a rule, and Chevron is a good example, have, in the last five years tilted to E&P developments at home than abroad.

Ayuk calls for “a pragmatic commonsense approach that welcomes credible investors and see gas taking the lead in economic development and industrialisation, therefore the entry of Chevron is extremely welcomed and should be accepted by all stakeholders.”

“From its Nigerian and Angolan presence, Chevron understands the issues and opportunities of developing African content. We expect its entry to be beneficial from a local content and capacity building perspective,” said Leoncio Amada NZE, President for the CEMAC region at the African Energy Chamber. “We hope that the authorities in Cameroon and Equatorial Guinea can do an efficient and fast track the due diligence process and ensure that Noble meets all its obligations to exit and create a seamless transition for Chevron. This is an opportunity for our public authorities to demonstrate their commitment to empowering investment and move away from an era of uncertainty to give confidence to future investors and stay competitive”.

ACE is full of praise for Chevron’s leadership in African natural gas development. “Chevron is indeed a true gas player in the African market. In Nigeria, Chevron has been leading natural gas commercialization efforts for decades through its Escravos projects targeted the monetization of 18Tcf of gas. These have resulted in the Escravos Gas-to-Liquids facility and the Escravos Gas Plant, both cornerstones of Nigeria’s gas development strategy. In Angola’s Block 0 and Block 14, Chevron has demonstrated a remarkable ability to invest in cutting flaring and monetization gas. In block 0, it still operates what is the world’s largest LPG FPSO vessel, turning previously flared gas into cleaner fuels for Africans and the for the world.”

 

 

 


Oriental Proposes Sale of Equity in Nigerian Assets

Oriental Energy Resources has commenced a marketing campaign of certain interests in its existing offshore Nigeria assets to qualified prospective partners, having recently obtained Government approval for its legacy block Oil Mining Lease (OML-115) for a new twenty-year term under terms which include a zero-relinquishment provision.

OML-115 includes an oil discovery adjacent to the Okwok Field, and several large potential exploration prospects defined by a block-wide circa $40Million state of the art four-component 3D seismic survey acquired in 2012, the same seismic data set that was used to define Oriental’s recent successful exploration well Ebok-45, that has tapped a significant new pool of light oil in acreage adjacent to OML-115.

Oriental is an indigenous offshore (marginal field) operator and oil producer, and the 100% interest owner of OML-115 and the Ebok Field in OML-67, and the 88% interest owner of the Okwok Field in OML-67.   In Oriental’s nearly 30-year history, it has partnered with Conoco, Nexen, Mobil-NNPC, Addax Petroleum, Energy Equity Resources, and Afren Plc.

Oriental’s recent Ebok-45 Deep Discovery promises to deliver a potential recoverable reserve of a similar or greater scale than both Ebok and Okwok Fields.

“Oriental has been responsible from Day One to maintain all of its licenses in good standing with the Government, to acquire all permits and licenses for the circa $4Billion Ebok Development and its 45 wells drilled to date”, the company says in a note to investors.

“Since 2015 Oriental has completed the acquisition of 100% of the Ebok Field equity, and is bearing 100% of the Ebok Field production costs” Oriental explains, “as well as the recent deep exploration discovery well costs and of the future planned Ebok exploration and appraisal drilling programme”.

The Okwok Field is currently under development with a well-head and FPSO development solution that has its FDP approved and under way to deliver First Oil in mid-2021. From Oriental’s recent organic exploration successes and the conservative reserve potential Oriental anticipates achieving gross production from the combined Ebok and Okwok Fields of circa 50,000BOPD by year-end 2023 and has set a corporate goal of attaining 100,BOPD by year-end 2028.

This article was originally published in the May 2020 edition of Africa Oil+Gas Report.

 


Nigerian Bid Round: DPR Says ‘Hold on, We’d Communicate Soon’

Nigeria’s Department of Petroleum Resources (DPR) says it will communicate the next steps of the ongoing bid round of marginal fields soon.

Several of the 500+ companies who have been notified of their prequalification had fruitlessly attempted to access the portal, on Monday and Tuesday, to pay for the next step of the round.

But officials at the regulatory agency told Africa Oil+Gas Report, they were still dealing with matters arising over the pre-qualification process and that access to the portal was closed for now.

The portal itself, on the DPR website, says: “Next step of the bid round to be communicated, soon”.

For the purpose of further payments, the notice on the portal adds: GIFMIS Code for Application Fee: 1000289370 and GIFMIS Code for Bid Processing Fee: 1000289383.

The matters arising that the officials spoke about has to do with the fact that there were companies who could make the qualification, but who are owing government a tax, tariff, fee or the other. A company may have fulfilled all obligations to government, but a director on its board may be a director in another company that is delinquent in paying statutory fees. Prequalificiation of such a company is on hold until the director clears himself.

Companies so affected have to comply by close of business on Friday, July 24, 2020.

In effect, the Nigerian government has taken advantage of the bid round to reclaim some of the debts owed to it.

As an update to our last report, there are no clear schedules for the remaining steps of the bid round, now.  The best thing to do is keep visiting the website of the DPR, https://www.dpr.gov.ng/


FAR Signs New JOAs, But Struggles for Partner to Fund the Next Gambian Well

Australian minnow, FAR, has reported “efforts to find an additional partner for the drilling of the next well in The Gambia”.

FAR is still smarting from the dismal results of the Samo-1 well, drilled in offshore Block A 2 in late 2018. The first exploratory well to be drilled in the Northwest African country in  40 years, Samo-1 was a dry hole.

The company signed new Joint Operating Agreements (JOA’s) in respect of the A2 and A5 Blocks, with the Malaysian state hydrocarbon company f Petroliam Nasional Berhad, PETRONAS).

This follows the granting of new Licences for those Blocks by The Government of The Gambia effective October 1 2019, after which FAR and PETRONAS took the opportunity to update the terms of the existing JOA’s by entering into new JOA’s with effect from 1 October 2019.

FAR remains as Operator under the new JOA’s which better reflect the terms of the new Licences.

FAR says it has “run numerous data room presentations for interested parties” and it is “working to conclude a farm-out before the restart of the drilling operations”.


Foretelling Winners and Losers in Nigeria’s High-Stake  Marginal Field Bid Round

By Dimeji Bassir

The Nigerian government, obviously betting that its estimated 2.3Billion barrels of discovered but mostly unappraised crude oil reserves across 183 fields considered marginal are peculiarly coveted, launched the 2020 Marginal field bid rounds at the end of May 2020. The fee structure as published in the advertised bid guidelines suggest the exercise is a desperate move to raise capital by a government on the verge of a second recession in five years. Pundits, however, believe the timing for the bid round could not be more inauspicious given the global pandemic that has thrown the world into severe health and economic crisis. With resource ownership and production dominated by the five major International Oil Companies (IOCs) operating in the country, the government in 2003 formally transferred ownership of 24 fields to Nigerian companies following the 2003/4 marginal field bid round and between then and now have approved the transfer of $10Billion worth of assets from IOCs to a slew of homegrown independent companies, who are mostly well-positioned to benefit from the ongoing bidding exercise.

A recent Africa Oil+Gas Report newsletter article, quoting unnamed sources at the ministry of petroleum resources, reports that up to 500 companies are expected to have applied and paid the fixed registration fee of Five Hundred Thousand Naira by the new June 21 registration deadline. Six out of the seven statutory fee categories are field-specific thus variable, growing incrementally depending on how many fields a participant is bidding for. A bidder who has narrowed down to and bidding for only one field must part with approximately $125,000 to progress to the stage of signature bonus. The asking amount for signature bonuses was not disclosed in the bidding guidelines contrary to what obtained in the past. A successful bidder must confirm willingness to pay the signature bonus upon selection and before the award of the marginal field. While the process is planned to be conducted 100% electronically, how this will pan out in reality remains to be seen. In the period since the bid round was launched, some prospective bidders have complained of inability to access the registration portal. Previous bidding processes in Nigeria have been fraught with political interference and nothing in the current political climate in Nigeria suggest there will be a departure from status quo this time.

Challenges: Setting aside the widespread enthusiasm by participating stakeholders momentarily, the sub-optimal performance shown by the majority of licensees from the 2003/4 class should evoke some caution. For a number of reasons but mostly due to funding challenges, no more than 50% of the marginal fields awarded in Nigeria have produced hydrocarbon, leaving observers pondering how successful bidders hope to attract capital as sources of funding for fossil fuels thin out across the globe. On their side, local banks who have shut their purses primarily due to over-exposure to the sector, draw little inspiration to further invest in this round at a time when unprecedentedly, the credit rating of giants like ExxonMobil has been downgraded by S & P due to its anaemic cash flow position thereby impacting the company’s ability to fund its capital projects and continue to pay dividends as the industry witnesses its bleakest outlook in history.

Among the class of 2003, approximately 47% of those licensees that attained production partnered with foreign entities, at one point or the other in their development journeys with 23% funded through financing and technical services partnerships with international players. Notably, 55% of gross daily liquid production from marginal fields comes from assets initially funded by foreign entities. This fact assumedly raises a glimmer of hope that if replicated, the model of seeking avenues to partner with foreign entities under similar arrangements could bode well for current bidders.

Other areas that could pose challenges down the line to undiscerning participants in the current bid round pertains to potential issues surrounding enforceability and bankability of contracts between the licensee, who enters into a farm-out agreement with the main lease owner, effectively as a sub-lessee. The parameters of the terms of the farm-out agreement which ideally must thoroughly address obligations of parties regarding issues such as overriding royalty to the farmor, crude handling prioritization & lifting costs, how to handle pipeline losses, abandonment & decommissioning, resolution of unitization where applicable etc. could potentially become contentious. Aside from the reality of restiveness in some areas of the Niger Delta, which portends risk for those that will operate in those communities, certain fields included in the basket are potential candidates for litigation as the government had revoked licenses from previous lessees in controversial circumstances.

Potential for Upsides: Marginal fields by definition are technically and economically challenged assets that typically haven’t met the development criteria of the IOCs who discovered them. Decisions made and the strategy adopted at the bidding stage invariably predicts future outcomes post-bid and drives an asset’s overall performance as well as underpins the ability to effectively de-risk the ensuing development project to maximize commercial value from the asset. A delicate balance must be achieved to effectively manage the competing philosophical considerations that will drive the most prudent risk-balanced FDP approach; the wisdom to achieve early, albeit relatively minimal cash flow timeously and most cost-effectively versus a full-blown, costlier and seemingly more lucrative development strategy. The upsides realizable centers on taking a life-cycle view during bidding, ensuring that consideration is given to depletion beyond primary recovery. Looking at assets deemed marginal, the prudent approach is to advocate key technologies, multiple depletion strategies and the timing of implementation to be incorporated in the field’s life cycle plan and road-map. Having a life cycle plan and road-map allows for optimal facility planning to accommodate technology application geared towards maximizing economic URF. The eventual goal, of course, is to maximize the value of the full hydrocarbon stream.

The self-healing nature of crude oil cycles infers some optimism that current effort to stimulate supply deficit through agreed production cuts will yield results in short order. Pending the restoration of oil prices to pre-COVID 19 levels, the prevailing environment where demand remains relatively depressed could offer some advantages – reduced baseline costs to procure services, that typically trails oil price, should motivate operators to develop projects through this slump and be positioned to reap in the upside when the cycle adjusts in a couple of years.

Winners and Losers: The federal government has clearly placed its bet on a robust subscription in this bid round. However, there are no indications that learnings from the historical performance of previous awardees have been incorporated into the thinking in order to influence better outcomes for the program. If the only driver for launching the round, as it appears, is for the government to raise capital from signature bonuses, then the government’s outlook is at best myopic.

As stipulated in the bid guidelines and consistent with what obtained historically, pressures on successful licensees to ” develop or lose ” amidst potential government-imposed bottlenecks, fiscal uncertainties as PIB remains unpassed, as well as other challenges earlier outlined pose significant headwinds which fundamentally threatens the achievement of the marginal field program’s theoretical objectives. With minimal long-term value creation for stakeholders, the crushing legacy of serial losses underwhelms the lofty ideals behind the marginal field programme.

Bassir is Chief Executive, Ofserv, an E&P service company with expertise covering a broad range of services across the Drilling & Facilities Maintenance domains.

 

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