All posts tagged farm in-farm out


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.

 


Widespread Interest expressed in Nigeria’s Marginal Field Bid Round

Over 300 companies have applied to be prequalified for the Nigerian Marginal Field Bid Round, with many others unable to gain access to the portal, in the three weeks since the round was launched.

The Department of Petroleum Resources, the industry regulator, meanwhile, postponed the terminal date of registration of Bids to June 21.

Nigerian Ministry of Petroleum sources say it is likely that over 500 companies would have applied by that date.

The ongoing exercise is the first government supervised oil and gas asset sale since the acreage bid round in 2007.

Marginal fields are undeveloped discoveries that have lain fallow in acreages operated by International Oil Companies for at least 10 years.

It would take around $150,000 for a qualified application to get all the way to signature bonus and a number of Nigerian businessmen. “Once you get to the point of being qualified and all you have to pay is the signature bonus, you’re there”, says a retired reservoir engineer who spent over 25 years with a super major in Nigeria. “There is the impression that a marginal field licence has conferred on you some entitlement”.

The entire exercise, up to the submission of technical/commercial bid, ends on August 16, 2020. In between, from June 21 to August 16, the following will happen: (1) Evaluation of submission and preparation of report, June 22 to July 5; (2) Announcement of Pre-Qualified Applicants and Issuance of Field Teasers, July 5; (3) Data Prying, Leasing, Purchase of Reports, July 6 to August 16; (4) Payment of Application and Bid Processing Fee and Submission of Technical and Commercial Bid; July 6 to August 16. The schedule means that the heavy lifting will happen between July 6 and August 16.

 


TOTAL Won’t Go into Ghana’s Upstream Yet

French major TOTAL has taken the decision not to proceed with consummating the purchase of Occidental Petroleum’s stakes in Ghana.

Occidental had acquired Anadarko in early 2019 and subsequently entered into a Purchase and Sale Agreement (PSA) in order for TOTAL to acquire Anadarko’s assets in Africa. Under this agreement, TOTAL and Occidental have since completed the sale and purchase of the Mozambique and South Africa assets.

The PSA provided that the sale of the Ghana assets was conditional upon the completion of the Algeria assets’ sale. Occidental has informed TOTAL that, as part of an understanding with the Algerian authorities on the transfer of Anadarko’s interests to Occidental, Occidental would not be in a position to sell its interests in Algeria.

“Given the extraordinary market environment and the lack of visibility that the Group faces, and in light of the non-operated nature of the interests of Anadarko in Ghana”, says a company press release, “TOTAL has decided not to pursue the completion of the purchase of the Ghana assets and, as a consequence, to preserve the Group’s financial flexibility”.

 


Geophysical Contractors Seek Fiscal Relief from African Governments

The International Association of Geophysical Contractors IAGC, is asking for financial relief from regulatory authorities and banking institutions in hydrocarbon prospecting and producing countries in Africa.

Such relief is being sought in order to mitigate the negative effects of the global crisis

In collaboration with the Johannesburg based African Energy Chamber, the contractors are making several demands on governments, including waiving taxes on service companies for six months; waivng withholding taxes, especially for non-resident companies, for six months.

“These measures are intended to mitigate the expected loss of jobs and abandonment of erstwhile viable projects in the African oil and gas sector in the face of a global recession”, the IAGC says in a joint statement with the AEC.

The two organisations are urging banks to provide no interest loans and loan guarantees for local service companies with ongoing projects with operating E&P companies. They are asking governments to grant extensions on all exploration projects for 24 months; extend the non-exclusive geophysical data confidentiality periods to a minimum of 15 years where such is not already in place; waive part of the work project commitments for exploration companies.

They are also praying for setting up and implementing government and private sector discussions on revising some of the fiscal terms in the Production Sharing Contracts “that make it difficult for explorers to meet commitments in today’s market environment and aid capital fundraising”, and they want a 50% reduction in fees due to the state like training funds, surface rental, social projects et.

Nikki Martin, President of the IAGC highlighted the importance of the geophysical and exploration (G&E) industries in maintaining a stable energy industry. “National Authorities should be working to maintain expected timelines for licensing rounds, including all review periods and award announcements which contribute to business certainty and a stable pipeline for future oil production. Energy security for the continent will only be ensured with continued exploration,” she said. “The G&E industry provides the key to unlocking energy resources that will allow for rebuilding economies when the COVID-19 virus has run its course, however, in order to rebuild, there must be a viable energy industry when that time comes.”

 


The State is Aware that Shell Will Sell Nigerian Acreages Upon Renewal

Officials in the Nigerian Ministry of Petroleum Resources are aware that the Anglo Dutch major Shell is inclined to divest from several of the 17 onshore acreages it asked the government to renew.

But they have gone ahead to renew most of the licences anyway, because they think it is unlawful not to do so.  The extant licences on the acreages were due to expire in 2019.

“By the regulations we are working with, all these assets we have renewed deserve to be renewed”, Ministry sources categorically tell Africa Oil+Gas Report.

“Shell can take us to court if we don’t renew”, say ranking government officials in the Ministry, who also argue that, with state sponsored bid rounds not having happened in the country in the last 11 years, the frequent Shell lease divestments since 2008 “have benefited Nigerian companies”, who have purchased the stakes belonging to Shell and other international companies in these assets.

As it is, even during the process of renewal between late 2017 and mid-2018, Shell was actively negotiating on the side, with several parties, its divestment from three of the acreages in the renewal basket: Oil Mining Leases (OMLs) 11, 17 and 25.

Shell was asked to pay $820Million for renewal of 14 of the 17 acreages it sought to renew, including OML 25, an acreage that Shell had put in a divestment round in 2014, but failed to sell because of a last minute NNPC invocation of its right of first refusal. Shell, NNPC and several parties have been involved in closing that transaction since that time.

Regarding OML 11 and 17, Shell has, for a while, been negotiating with buyers and has put a $1.2Billion invoice on the table.

It would seem that such asset should not have been renewed, since Shell had demonstrated that it was going to sell them. It would, ordinarily appear intriguing, that the state would renew the licence of an acreage to a company that had clearly shown it no longer wanted it.

Why don’t you put it in a bid basket so that the state gets the benefit of the licencing?, we asked.

But MoPR officials say that Shell has paid all it needed to pay on every asset in the 30 years since they were last renewed and had extensive work programme on each of the acreages, so it would have been illegal to say no to renewal.

Out of the 17 onshore acreages Shell submitted for renewal in late 2017, only three were revoked, at the provisional conclusion of the process in February 2018, “for lack of enough work done over the last 10 years”.

Shell requested for renewal of OMLs 11, 17, 20, 21, 22, 23, 25, 27, 28, 31, 32, 35, 36, 43, 45, and 46. It succeeded in getting everything renewed, but for four acreages.

OMLs 31, 33 and 36 were denied approval, while the government decided to cut OML 11 into three because it was too large. But Shell has contested the decision on OML 11, arguing that “the proposal would unduly punish” the company, which had conducted operations in the asset “legally and in full compliance with the law”.


BP’s Gas Success in Egypt Makes Oil Look Uncool.

By Toyin Akinosho

Britain’s top hydrocarbon company is aiming to dump its oilfields in Egypt, as its recent string of successes in natural gas, aided by the country’s competitive local prices, makes oil properties relatively uncool.

Competitors have been invited to scrutinise BP’s data, a prelude to purchasing the major’s stake in Gulf of Suez Oil Company (GUPCO), the company’s 50+ year old joint venture with the Egyptian General Petroleum Corporation (EGPC).

Egypt is paying at least $5 for every thousand cubic feet –in new projects-to E&P companies who pump gas into its national grid, the largest domestic gas market in Africa.

While payments had been a struggle in the past, the government has recently been in haste to clear the backlog.

BP has found itself right in the centre of Egypt’s gas boom, even though its oil output is 15% of the country’s total production.

BP holds 10% of ENI operated Shorouk concession offshore Egypt, which includes the giant Zohr gas field. The company itself operates the Atoll field, of which it announced the start of gas production from the project’s Phase One last February. Both Zohr (which came on line December 2017) and Atoll collectively produce 700MMscf/d.

BP’s Net production in Nile Delta increases sixfold from 50,000BOEPD in 2016 to over 300,000BOEPD in 2020; 90% of that is natural gas.


The Big Asset Grab

Atlantic Energy AndThe NPDC Operatorship: Follow The Money

There wasmore than a bit of misplacement of emphasis of issues by the Nigerian oil producing Communities protesting the relationship between the state hydrocarbon company Nigerian Petroleum Development Company(NPDC) and Atlantic Energy, its funding partner.

The complaint, aired at the National Assembly, thecountry’s bicameral house of legislature, in late April 2013, was largely about Petroleum Rights. The Communities accused Diezanni Allison- Madueke, the Minister of Petroleum of having secretly transferred production rights in four large oil blocks (OMLs 26, 30, 34, and 42) to Atlantic Energy Drilling Concept Limited.

This claim is not true in the literal sense, but there’s a lot more in the transaction between Atlantic Energy and NPDC, the operators of those blocks, that the public ought to know about, and doesn’t.

“The role of Atlantic Energy in the divestment issue is just the provision of funding, which both NNPC and NPDC have explained”, says Atlantic Energy chief, Jide Omokore. “The Strategic Alliance Agreement entered into between Nigerian Petroleum Development Company Limited and Atlantic Energy Drilling Concept Limited was not a divestment of Assets nor transfer of Operatorship but simply an alternative funding agreement in order to meet the Nigerian Petroleum Development Company Limited’s cash call obligations in the affected OMLs”.

This is all very true, so why are so many people worried?

The answer is thatthe details of the transaction hint at a hand over of free money, from the Nigerian National Treasury, to a company to play with.

Is this some slush fund? A lot of people think that this is what the National Assembly should be investigating.

Prior to Shell’s decision to divest from OMLs 26, 30, 34, and 42, NNPC, as the government’s “eye” in these operations, had always had the 55% equity.  Since they were not operators, they didn’t need upfront money. They paid their share of the expenses and received 55% of the volume of the crude produced.

Then, suddenly, the Nigerian National Petroleum Corporation (NNPC) said it wanted to operate those assets,fine. As of right it could.

The corporation said that the operatorship would be done on its behalf by NPDC, its operating arm, fine.

Now that it was going to operate(be the primary managers of the assets), it required funding.

Couldn’t it find a way of raising the money on the back of the assets?  Nigerian banks would rush to fund NPDC’s operatorship. These assets are producing crude oil, at $90+ a barrel at the time and they generate cash flow from Day 1!!!!!.

No, NPDC suddenly and dramatically signs a funding agreement with Atlantic Energy, which ensures that, as its “fees” for funding NPDC, it is entitled to collecting crude oil, for the life of these assets.

What this means is that the volume of crude oil, for which there will be money in the country’s coffers, falls short by a size equal to what Atlantic Energy collects.

Don’t take our word for it. Just take a look at the part of the Strategic Alliance Agreement, below. This is what the Conversation in Abuja should be about, and not whether the minister has secretly transferred production rights to Atlantic Energy.

NPDC/ATLANTIC ENERGY  STRATEGIC ALLIANCE AGREEMENT(OML 34) –EXCERPTS FUND1NG OF PETROLEUM OPERATIONS

8.1 ATLANTIC shall provide all the funds required for NPDC’s 55% share of Petroleum Operation Costs, subject to Article 8,2 and in accordance with approved Work Programme and Budget. A review of the Work Programme shall be concluded by Project Management Team subject to approval of the Management Committee within fifty (50) days from the Effective Date to estimate the capital investments for the Development and the required initial Working Capital. Based on this review the Management Committee shall within seven (7) days approve the amount for the capital investments, which shall be covered by the parent company guarantee.

8.2 The costs incurred by the Parties in carrying out Petroleum Operations shall be recovered by the Parties through Cost Oil or Cost Gas, in accordance with Article 10 and the Accounting Procedure as set out in Annex ‘C’.

8.3 All bank transactions shall be made through bank accounts opened and maintained by ATLANTIC exclusively for the Petroleum Operations.

8.4 ATLANTIC shall open and maintain project bank account(s) exclusively for funding Petroleum Operations and shall procure that NPDC shall have unlimited inquiry and audit mandate and a right to copies of all information and transactional documents including all accounts records and balances as they occur from bank accounts and project bank accounts referred to in Articles 8.3 and 84.

8.5 If additional Development Costs are required to add facilities not included in the development Programme, including but not limited to in-fill well, secondary recovery facilities, additional processing facilities, deeper wells and artificial lilt, ATLANTIC shall provide NPDC’s share of Petroleum Operations Costs required to carry out such additional development activities.

8.6 The additional capital investments referred to in Article 8.5 hereof shall be recovered by ATLANTIC through Cost Oil and Cost Gas in accordance with Article 10 and the Accounting Procedure, and ATLANTIC shall be entitled to receive a share of Profit Oil and Profit Gas over the additional production as provided for in Article 10.2 hereof.

8.7 ATLANTIC shall bear all losses associated with funding NPDCs 55% share of Petroleum Operations under this Agreement.

ARTICLE 9.

DEVELOPMENT PROGRAMME AND BUDGETS

9.1 ATLANTIC shall submit to the Management Committee for approval within

60 days of the Effective Date, the development plan which shall include the Development Programme and relevant Budget appropriately apportioned into yearly phases.

9.2 At the meetings of the Management Committee to consider and approve the Work Programme and Budget for each year, ATLANTIC shall submit a report on organizational structure to be utilized for conduct at Petroleum Operations in accordance with Annex B. During such meetings, ATLANTIC shall report on the actual performance of the organizational structure for the previous year.

9.3 The Development plan shall include the Work Programme and Budget, apportioned into quarterly phases, to be carried out under the Development plan during the remainder of the financial year. In respect of subsequent financial years, the Work Programme and Budget shall be submitted not later than 31’ August of the preceding financial year. Such Work Programme and Budget shall comprise all requisite services including, but not limited to. environmental studies, drilling and completion programmes, construction and assembling of field installations and equipment, as may be necessary to permit the production, storage, transportation and delivery of Crude Oil and Natural Gas from the Contract Area. The Development Programme and Budget shall be detailed as necessary.

9.4 ATLANTIC shall submit to Management Committee any revision of the Annual Development Programme and Budget. Any such revision of the approved Development Budget shall be made by agreement of the PMT, In the event of emergency or extraordinary circumstances that require immediate action, ATLANTIC may take actions it deems necessary to protect life and property and the interest of Parties and shall promptly notify Parties in writing within forty-eight (48) hours notwithstanding the provisions of this Article 9.4 any cost so incurred shall be recoverable.

ARTICLE 10

RECOVERY OF PETROLEUM OPERATIONS COSTS AND OIL AND NATURAL GAS ALLOCATION

10.1 Crude Oil and Natural Gas Allocation

The allocation of Available Crude Oil and Available Natural Gas shall be in accordance with Annex “C”. Annex “D” and this Article 10, as follows:

(a) Royalty Oil and Royalty Gas shall be allocated to NPDC in such quantum as will generate an amount of proceeds equal to NPDC’s Royalty applicable to the Contract Area.

(b) Cost Oil and Cost Gas shall be allocated to the Parties in such quantum as will generate an amount of proceeds sufficient to recover the following:

1. Un-depreciated costs associated to Capital Costs as defined in the Accounting Procedures incurred prior to execution of this Agreement shall be allocated to NPDC:

1. Development Costs and Production Costs related to the Production of P1 Developed reserves as agreed in the production profile attached hereto as Annex H shall be allocated to ATLANTIC;

Ill. Incremental Investment (Development Costs and Production Costs), made by ATLANTIC shall be recovered from incremental volumes (i.e. the monthly production from 2P reserves less the P1 Developed reserves as indicated in the production profile attached hereto as Annex 1-1) shall be allocated to ATLANTIC.

NPDC Forty per cent (40%) ATLANTIC – Sixty per cent (60%)

Thereafter, Profit Oil shall  beallocated in the following ratio:

NPDC — Seventy per cent (70%)

ATLANTIC – Thirty per cent (30%)

iv. Up to the full recovery of Development Costs regarding non associated gas by ATLANTIC.

Profit Gas shall be allocated in the following ratio:

NPDC – Thirty per cent (30%)

ATLANTIC Seventy per cent (70%)

Thereafter, Profit Gas shall be allocated in the following ratio:

NPDC — Seventy per cent (70%)

ATLANTIC – Thirty per cent (30%)

v. Up to the full recovery of the Development Costs for the development of contingent resources, Profit Gas shall be allocated in the following ratio:

NPDC – Thirty per cent (30%)

ATLANTIC Seventy per cent (70%)

Thereafter, Profit Gas shall be allocated in the following ratio:

NPDC — Seventy per cent (70%)

ATLANTIC – Thirty per cent (30%)

10.3 Each Party shall take in kind, lift and dispose of its allocation of Cost Oil and Profit Oil in accordance with the Lifting Procedure (Annex D).

The PPT and Tax Gas payable under this Agreement represents the NPDC’s tax obligations as Concessionaire. ATLANTIC’s tax obligations which shall be paid under CITA shall be paid by ATLANTIC from its profit.

10.4 Either Party may at the request of the other, lift the other Party’s Cost Oil and Profit Oil pursuant to Article 10.1 and the lifting Party shall within thirty(30) days transfer to the account of the non-lifting Party the proceeds of the sale to which The non-lifting Party is entitled. Overdue payments shall bear interest at the annual rate of three (3) months LIBOR.

10.5 Either Party may, with the consent of the other Party, purchase any portion of the other Party’s respective allocation of Cost Oil and Profit Oil from the Contract Area.

10.6 Parties shall meet on a monthly basis as may be agreed to reconcile all Crude Oil allocated and lifted during the period as per Annex “E”.

ARTICLE 11

VALUATION OF AVAILABLE CRUDE OIL

11.1 Available Crude Oil shall be valued in accordance with the following procedures:

(a) On the commencement of production from new reservoirs, ATLANTIC shall engage the services of an independent Laboratory of good repute to determine the assay of the new Crude Oil.

(b) When a new Crude Oil stream is produced, liftings shall be made for a trial marketing period of three (3) calendar months or the period required to lift the first three (3) cargoes, whichever is shorter, During the trial marketing period ATLANTIC shall:

(i) collect samples of the new Crude Oil upon which the assay shall be performed as provided in Article 11.1(a) above;

(ii) determine quality and yield pattern of the new Crude Oil;

(iii) share in the marketing such that each Party markets approximately their proportionate share of the new Crude Oil, notwithstanding the fact That a Party’s share of Available Crude Oil may be lifted in the process; payments Thereafter shall be made in accordance with Article 0.5;

(iv) exchange information regarding the marketing of the new Crude Oil including documents which verify the sales price and terms of each lifting;

(v) Apply the actual F,O,B. sales price to determine the price of each lifting. Such F.O.B. sales pricing for each lifting shall continue after the trial marketing period until a valuation of the new Crude Oil has been completed but in no event shall it be longer than ninety (90) days after conclusion of the trial marketing period.

C) As soon as practicable but in any event not later Than sixty (60) days after the end of the trial marketing period, ATLANTIC shall review the assay, yield, and actual sales data. ATLANTIC shall present a proposal for the valuation of the new Crude Oil. A valuation method either spot related or any other method acceptable to both Parties shall be established for determining the price for each lifting of Available Crude Oil. Such valuation method shall be in accordance with the Official Selling Price published by NNPC or relevant government authority. It is the intention of the Parties that such prices shall reflect the true market value of the new Crude Oil. The valuation method determined hereunder (including the product yield values) shall be mutually agreed within thirty (30) days from the aforementioned meeting failing which; determination of such valuation shall be referred to an independent consultant.

 

 

 


Eco Signs Three JoAsFor Walvis Bay Basin

Eco (Atlantic) Oil & Gas has signed three joint operating agreements with NAMCOR, the National Petroleum Corporation of Namibia, and Azimuth Ltd., an exploration and production company backed by majority-ownerSeacrest Capital Ltd. and Petroleum Geo-Services ASA (PGS).

The agreements were signed with respect to the Guy, Sharon and Cooper license blocks located in the prospective Walvis Basin offshore Namibia.

Colin Kinley, chief operating officer of Eco Atlantic, says that the three partners collectively, “bring extensive oil and gas experience to the Walvis Basin. We understand this oil play and the significant potential it has and look forward to working collaboratively with both companies to continue our exploration work in the Walvis basin, where significant drilling activities are scheduled for 2013 commencing this quarter.” ObethKandjoze, managing director of NAMCOR, commented that the agreements “signify the international support and interest in the development of Namibia’s oil and gas resources.”

 


AOC Executes Rift Basin PSA, ETHIOPIA

Africa Oil Corp has announced the formal execution of a new Ethiopian Production Sharing Agreement.  The agreement covers the 42,519 square kilometer “Rift Basin Area”, previously held by the Company under a Joint Study Agreement and referred to then as the “Rift Valley Block”.     The Rift Basin Area is located north of the Company’s South Omo Block and includes the extension of the Tertiary-age East Africa Rift Trend in Ethiopia.  The new license is on trend with highly prospective blocks in the Tertiary rift valley including the South Omo Block, and Kenyan Blocks 10BA, 10BB, 13T, and 12A.  During the joint study period, the Company completed an airborne high resolution gravity and magnetic survey over the block. In addition, satellite-imaged natural oil slicks were ground truthed, which indicate the presence of an active petroleum system in parts of the block. The Company plans to complete a Full Tensor Gravity Gradiometry survey and exhaustive environmental/social impact assessment over the block during 2013.

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