All posts tagged farm in-farm out

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.


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.



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.



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”.



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.

Rwanda Grants Extension To Vanoil

Rwandan authorities have approved a two month extension to Vanoil Energy’s Technical Evaluation Agreement with the Rwandan Ministry of Natural Resources.

The agreement provides Vanoil with the exclusive right to negotiate a Production Sharing Contract (PSC) covering approximately 629 square miles (1,631 square kilometers) of the East Kivu Graben, located beneath Lake Kivu, Rwanda.


Brazillains Sell Some To Portuguese

Namibian authorities have approved the sale of some percentage of HRT’s stakes in each of three offshore blocks, Petroleum Exploration Licences (PEL)  to Galp Energia HRT is a Brazillian firm. Galp Energia is Portuguese. In the deal, first announced in November 2012, the two companies said that Galp had acquired a 14% stake in the three exploration blocks in return for covering a portion of drilling costs.

This assignment is related to PEL 23, located in the Walvis Basin, and PELs 24 and 28, both located in the Orange Basin. HRT will retain operatorship of these PELs. The deal helps clear the way for HRT to start drilling in what it considers “the highly prospective region” off Namibia’s coast, which geologists believe could hold an area similar to Brazil’s subsalt because the two areas were connected millions of years ago. Billions of barrels of crude oil were discovered under a thick layer of salt in the Atlantic Ocean off Brazil.

HRT holds operating stakes in 10 blocks and minority shares in two others in the Walvis, Orange and Namibe basins.


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