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‘Government Licence Revocation to Blame for Rig Fire Incident’, Company Laments

By Toyin Akinosho, Publisher

The Nigerian minnow, Guarantee Petroleum, has argued that the revocation order, sent to the company in early April 2020, right in the middle of a well re-entry process, encouraged a sense of pandemonium which resulted in the fire incident on the Grace-1 HWU, the hydraulic workover rig that was performing re-entry operations on Ororo field, in shallow water Oil Mining Lease (OML) 95.

“Service providers became jittery when the announcement came”, Tunde Giwa, the company’s Managing Director, lamented to Africa Oil+Gas Report.

“We had almost finalised operations”, Giwa explained, “We were at the bottom of the well (circa 10,000feet) we had opened four hydrocarbon zones, and taken all the plugs out. Baker Hughes was on site to put the tubings, (and complete the well). That was when the problem started. The service providers who could have intervened in the various well pressure amelioration work, were refusing to do their job”.

Nigerian regulatory authorities were well aware that there was an operation going on, there were safety issues involved and yet they revoked the licence of the operator with immediate effect.

The well re-entry commenced in October 2019 and officials of the Department of Petroleum Resources (DPR) were aware of the work, which they sanctioned, according to documents sighted by Africa Oil+Gas Report. Well control challenges started in April and when the revocation order came, “the service companies started reducing their work scope”. Giwa claims that as of Sunday, May 17, 2020, the DPR had not responded to letters and email messages on the fire incident.

Asked why the company had deployed a hydraulic workover rig to re-enter and work over a well that had prior record of overpesssured zones, Giwa said that the issue was not the rig competency. “The Blowout Preventer (BOP) stack and drilling mud pumps (designed to circulate drilling fluid under high pressure) were the same as a regular rig”.

Guarantee Petroleum, with its partner, Owena Oil, won the Ororo field in the 2002/2003 Marginal field round.

DPR is right to be concerned that the two companies had sat” on the licence for 17 years without applying a sense of urgency to bring the asset to production.

It is in the DPR’s remit to revoke the licence.

But it is wrong for officials, themselves geoscientists and engineers, to approve technical operations of this nature and financial magnitude (in excess of $20Million), with a high safety quotient, and revoke the licence right in the middle of the operations.


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”.

 


Nigerian Companies Are the Biggest Defaulters on Ghana’s Concession Rentals

Sahara Energy Fields, Brittania U and Erin Energy, all founded by Nigerian businessmen, are among the the eight Exploration and Production Companies, that were in default of one payment or another to Ghanaian Tax authorities as of February 2019, the latest date for which data are available.

With $587671.23 behind in both arrears and 2019 outstanding, Swiss African Oil owed the most, according to  Public Interest Accountability Committee, Ghana’s equivalent of NEITI. SAO was followed by Brittania U and Sahara Energy Fields, both Nigerian owned companies, indebted to the tune of $456, 879.26 and $409,315.07 respectively. The fourth most indebted to the Ghanaian state was Gosco/Heritage, with $334,850.00 in both arrears and 2019 outstanding.

Erin Energy, also a Nigerian founded company, owed $151,200. The least indebted companies were Medea $78,050; UB Resources, $37,050 and Springfield, $33,650.


LEKOIL Gets A Breather on $7.6Million It Has to Pay to Optimum

By Foluso Ogunsan

AIM Listed LEKOIL says it reached an agreement with Optimum Petroleum Development Company, the Operator of the Oil Prospecting Lease (OPL 310), on deferring the final tranche of payment of $7.6Million due on or before 2 May 2020.

The companies had earlier jointly decided that final payment of $9.6Million, in aggregate, would be made to Optimum to cover sunk costs and consent fees for LEKOIL’s 17% farmed in interest. This final payment was to be made in two tranches with the first payment of $2Million completed as announced on 3 April 2020.

Now Optimum and LEKOIL have agreed on a deferred payment schedule as follows: the sum of $1.0Million to be paid on or before 15 July 2020; the sum of $2Million to be paid on or before 2 September 2020, and the sum of $4.6Million to be paid on or before 2 November 2020.

OPL 310, located in 100 to 200metre water depth in the Benin Basin, offshore Lagos, Nigeria, contains the Ogo field.

The field was discovered in 2013, with LEKOIL and (then partner) Afren, now defunct, describing it a significant discovery and claiming estimates of P50 recoverable resources of 774 Million Barrels of Oil Equivalent (MMBBOE) a figure which far exceeds the expected pre-drill estimate of 202MMBOE.

 

 

 


Equatorial Guinea Grants Two Year Extension for All Oil & Gas Licences

One month after it announced the waiving of its fees for oil service companies in the country, Equatorial Guinea has granted E&P companies a two-year extension on their exploration programmes.

The grant, the country says, “will also ensure flexibility on the work programmes of producing companies to ensure growth and stability in the market”.
In late March, the Ministry of Mines and Hydrocarbons MMH said it took the unanimous decision to waive its fees for service companies for a duration of three months, adding that it recognised the fact that the oil sector continues to be the largest private sector employer in the country and “we want to give our local services companies the means to weather the storm and avoid any jobs being lost”. It said it was “the first action to be taken to support oil & gas services companies in the wake of the oil price drop caused by the coronavirus pandemic”.

Oil prices have headed farther south in the four weeks since that first announcement, with the horizon even cloudier. Yesterday’s press release announcing the grant of extension of tenor of acreage licences came less than a week after the Petroleum minister, Gabriel Mbaga Lima Obiang, suggested at a webinar that countries should be granting extensions for E&P licences at this time, as companies would be unable to carry out work programmes with any clarity until 2021.

“The Ministry of Mines and Hydrocarbons remains concerned about the resounding impact of the drop in oil prices, COVID-19 and its dramatic consequences on our hydrocarbons industry”, says the release.

“At a time of great uncertainty, we have an obligation to make bold, decisive, and pragmatic policy decisions to get the industry moving again,” the statement explains, adding  that the government is fully committed to safeguard local oil & gas industry, its companies and its employees.

“The granting of these extensions has been deemed suitable to create an enabling environment for international and African companies to keep investing in Equatorial Guinea and ensure a quick recovery of our industry.

“The MMH will continue working with oil companies benefitting from such incentives to make sure that the recovery of Equatorial Guinea’s oil sector is made on the back of local content promotion, increased technology transfers, and procurement of additional local goods and services. A particular emphasis will be put on educating, training and promoting local workforce to help further reduce operational costs for international companies while maximising the creation of local value and revenue”.

With these proposals, the Equatoguinean authorities say they guarantee existing investments into Equatorial Guinea, while empowering local companies to assist their foreign partners in safeguarding and increasing their operations in the country.

“Some of these companies operating in Equatorial Guinea notably include ExxonMobil, EGLNG, Marathon Oil Corp, Atlas Petroleum, Kosmos Energy, Noble Energy, Glencore, Royal Gate Energy, Gunvor, Trident Energy, etc.

“Such historic measures are being rolled out as Equatorial Guinea implements a series of landmark projects across its upstream, midstream and downstream industries. The backfill project is already ongoing to pool supply from stranded gas in the Gulf of Guinea and replace declining output from the Alba Field. Meanwhile, the ongoing Year of Investment has generated strong interest from various existing and new players in Equatorial Guinea to build and expand midstream and downstream infrastructure and maximise local processing and transformation of domestic crude oil and natural gas.”


Sonangol Begins Second Round of Sale of Equity

Angola’s state hydrocarbon copay Sonangol has launched the second round of its widely anticipated international pubic bid for the sale of its stakes in 52 companies.

Nine companies are up for grabs in this tranche, three more than the six that were involved in the tender launched in January 2020.

The companies include Petromar, where it is divesting 30%; Sonatide Marine Limited, and Sonatde Marine Angola Limitada, 51%; Sonamet Industrial S. A and Sonacergy Services and Oil Construction Limited, 40%.

Sonangol will divest 33% from each of Paenal-Porto Amboim Shipyard and SBM Shpyard. It will sell 30% of Sonadiets Limitad and Sonadiets Services SA.

The companies for sale this time are all involved in oil and gas operations, whereas those in the January 2020 tender are enterprises in non-oil and gas functions

Bidders are expected to submit qualification documents to the Negotiation Committee for the Process of Disposal of Sonangol’s Quota in Mineral Resources and Petroleum Segment.

They are required to present a provisional bond and a value raging from $7000 to $15,000  or equivalent in Kwanzas, based on the existing foreign exchange rate.

The tender is being conducted under the terms of the country’s Public Procurement Law and applications will start to be received in mid May 2020.

 

 


TOTAL Swallows Tullow A whole in Uganda

The drawn-out deal is concluded at $2 per barrel

French major TOTAL and Irish independent Tullow have entered into an Agreement, through which TOTAL shall acquire Tullow’s entire interests in the Uganda Lake Albert development project, including the East African Crude Oil Pipeline.

The overall consideration paid by TOTAL to Tullow will be $575Million, with an initial payment of $500Million at closing and $75Million when the partners take the Final Investment Decision to launch the project. In addition, conditional payments will be made to Tullow linked to production and oil price, which will be triggered when Brent prices are above $62/bbl. The terms of the transaction have been discussed with the relevant Ugandan Government and Tax Authorities and agreement in principle has been reached on the tax treatment of the transaction.

Under the terms of the deal, TOTAL will acquire all of Tullow’s existing 33.3334% stake in each of the Lake Albert project licenses EA1, EA1A, EA2 and EA3A and the proposed East African Crude Oil Pipeline (EACOP) System.

The transaction is subject to the approval of Tullow’s shareholders, to customary regulatory and government approvals and to CNOOC’s right to exercise pre-emption on 50% of the transaction. “We are pleased to announce that a new agreement has been reached with Tullow to acquire their entire interests in the Lake Albert development project for less than 2$/bbl in line with our strategy of acquiring long-term resources at low cost, and that we have an agreement with the Uganda government on the fiscal framework,” said Patrick Pouyanné, TOTAL’s Chairman and CEO. “This acquisition will enable us, together with our partner CNOOC, to now move the project forward toward FID, driving costs down to deliver a robust long-term project.”


Nigeria’s Marginal Field Bid Round Approved, May Launch in Two Weeks

By Toyin Akinosho

Timipre Sylva, Nigeria’s minister of state for Petroleum Resources, has received approval from President Muhammadu Buhari to schedule a bid round for marginal fields.

There are strong indications he may call for the bid as close as two weeks from now.

45 fields were already in the basket at the Department of Petroleum Resources (DPR), the industry regulatory agency. Add to these the 11 fields that were recently revoked and bidders will have 56 fields located on land, swamp and shallow water terrains to choose from.

Marginal fields in Nigeria refer to discoveries made by oil majors which were undeveloped either because of distance from existing production facility, low reserves (in view of the majors) or likely low production volumes as a result of flow assurance issues.

The last marginal field bid round took place in 2002. 24 fields were awarded to 32 companies, some of them two to a field, in 2003.

Impeccable sources at the Ministry of Petroleum in Abuja and Lagos say the whole exercise could be concluded in as short as six weeks.

“The data prying and other items can take place within that time”, sources say, “and they can happen digitally”.

Nigeria has been preparing for a marginal field bid round for over 10 years.

The closest to getting it done was in 2013.

Even so, this feels surreal.

The nation, like the rest of the world, is in the middle of a health crisis. Her key commercial and political hub cities are in a lockdown, but sources insist the bid round can still happen in that time frame.

As this will certainly ‘disenfranchise’ many putative participants, it makes sense to say that if it so happens then there is a smell of political corruption around it.

One thing that will differentiate any marginal bid round in Nigeria now or in the future, from past bid rounds is the Signature Bonus.

The signature bonus for each field will vary as wide as the economics of extraction. The DPR had, in the last three years, been working with a Consulting Company to evaluate all the fields and allot commercial values. “We don’t want to repeat the situation in which holders of Assaramatoru field, which can barely produce 1,000BOPD, have paid the same bonus as licensees of Umusadege, which has gushed around 20,000BOPD consistently for over five years”, says one engineer at the Ministry in Abuja.

There is the lingering suspicion that there will be a secondary market of sorts after the round has taken place, whenever it does. This suspicion springs from the assumption that the politicians will hand out the fields to themselves. “These guys won’t know what to do with the fields”, says the CEO of a producing company, “they will come to us”.

The same kind of misgivings were expressed in 2007, when the Nigerian government opened a bid round, smack in the middle of the process leading to general elections.

Marginal fields are awarded only to Nigerian companies, as a tool for boosting the “Nigerian content”, the government’s much vaunted policy of domiciliation.

 


Investors unlikely to commit to licensing rounds says GlobalData

Licencing rounds will fall away from priority lists of E& P companies, as the global crisis of demand for crude oil escalates.

“Investors have not faced both a decrease in global oil demand and a significant and potentially prolonged increase in oil supply at the same time before, which has created unparalleled uncertainty”, notes Global Data.

To manage their exposure, many exploration and production (E&P) companies, including major operators, have pledged to reduce capital expenditure (CAPEX) budgets for 2020 by around 20%. This includes sharp reductions to exploration capital, which will significantly limit the amount of exploration budget available for licensing round acquisitions, at least in the short term, GlobalData argues.

The company’s report, ‘Impact of COVID-19 on Global Licensing Round Opportunities’, states that throughout this period of uncertainty, licensing rounds are likely to be extended or deferred as governments prioritise managing the domestic impact of the virus or wait for investment conditions to improve. Several countries including Bangladesh, Brazil, India, Liberia, South Sudan, and Thailand have already announced changes to licensing round activities and it is likely that others will follow.

Toya Latham, Upstream Fiscal Analyst at GlobalData comments: “The number of deepwater licenses awarded as part of bid rounds is also likely to be subdued in the short term. With the largest discoveries of last year located mostly in deepwater settings, deepwater acreage offers potentially lucrative opportunities for E&P companies. However, deepwater projects often require more capital and have longer payback periods compared to onshore and shallow water projects, and therefore deepwater acreage is likely to be less attractive in the current investment climate.”

Following the stabilisation of the oil price, there is likely to be a period of lag before the number of new awards secured through licensing rounds increase.

Latham continues: “Companies with less exposure to the oil price through limited or hedged production, which have available capital in the current environment, are likely to be well positioned for rounds held following the oil price stabilisation and may be in an advantageous situation to capitalize on reduced service costs for exploration activities.”

 


NPDC Hands over Three OMLs Under Nine Months

For the third time in the space of nine months, the Nigerian Petroleum Development Company NPDC is about to grant a contractor the opportunity to fund and manage an Oil Mining Licence on its behalf.

It is what is called funding and technical services agreement FTSA.

State owned NPDC accepted bids from 14 companies for OML 119, an offshore acreage which hosts two producing fields collectively outputting about 20,000Barrels of Oil Per Day.

Whoever wins the FTSA will take over day to day running of the OML.

Last July, the company signed an FTSA with the Indian owned independent, Sterling Energy Exploration and Production Company (SEEPCO) for the development of OML 13.

And in late September 2019, it awarded another FTSA to a Nigerian entity named CMES-OMS Petroleum Development Company

Funding and Technical services indicate operatorship by other means.

What these transactions suggest is that the NPDC, itself set up as the operating subsidiary of the Nigerian National Petroleum Corporation NNPC, the state hydrocarbon company, is unable or unwilling to directly secure funding from financial institutions and deploy its own internal technical and managerial personnel to work up those assets. In the event, it fails to build the managerial and technical capacity of its workforce, as it outsources core technical services to contractors.

But again, going by the historic mandate of the NPDC and the histories of these OMLs, these awards could do with a bit of scrutiny.

The NPDC was created in 1988, out of the Exploration and Production division of the parent company, to build technical and managerial capacity of the Nigerian workforce to operate upstream oil and gas assets. As of the time, 32 years ago, there were just a handful of Nigerian owned E&P companies, and even the few, struggled. Only one of them was producing hydrocarbons, And it wasn’t ding up to 500Barrels of oil per day!!!

NPDC was going to be the exemplar; the model of what a homegrwn E&P company should be.

In 2016, NPDC already had a hundred percent ownership in five (5) blocks: OMLs 64, 65, 66, 111 & 119; 60% participatory interest in (4) blocks: OMLs 60, 61, 62 & 63 and 55% equity in nine (9) blocks: OMLs 4, 26, 30, 34, 38, 40, 41, 42 & 55. All these were prior to its grabbing of OML 13 from three companies which rightfully held them.

In early 2017, it was awarded the OML 13 through an instruction signed by President Muhammadu Buhari, after a request by Maikanti Baru, then Group Managing Director of the NNPC.

The 1,923 sq km block used to be operated by Shell, but was revoked along with a number of other blocks in 2005. Shell went to court, but ultimately gave up the asset.

In the 2007 bid round, the block was cut into three acreages: Oil Prospecting Leases (OPLs) 2001, 2002 and 2003, each of which was awarded to three different companies; Jacon, Hi-Ref and Industrial Oil, respectively. Two of them, Jacon (OPL 2001) and Industrial Oil (OPL 2003) had paid 50% of the signature bonus they were expected to pay to government and were waiting to get to the stage of signing the Production Sharing Contract (PSC) and pay the remaining 50%, when the President decided to merge the three acreages again into OML 13 and award it to NPDC. So, at the time that President Buhari granted the block to NPDC, it was being held by other companies!

Indeed, in the 2007 bid round, NPDC bid for OPL 2001. That It lost the bid and then turned around to ask the Presidency for the entire OML 13, was a back door way to get an asset it failed to win in a competitive bidding.

In any case, as the President had singularly awarded the OML 13 to NPDC, it would be expected that the spirit behind the award was in line with the creation of the NPDC: to build technical and managerial capacity of the Nigerian workforce, within the NPDC. But almost as soon as the licence was finalised, the NPDC turned around to sign a funding and technical services agreement with SEEPCO.

It isn’t altogether helpful, then, for the reputation of the Nigerian state hydrocarbon company, that SEEPCO is a subsidiary of an entity- the Sandesara group of companies- whose promoters, Chetan Sandesara and Nitin Sandesara, are fugitives from the law in their own country.

India’s anti-graft agency, the Enforcement Directorate (ED) had registered a case under the Prevention of Money Laundering Act PMLA against Sterling Biotech, a subsidiary of the Sandesara group, in 2017 on the basis of a CBI case of bank loan fraud of $834Million or  Rs 53.83Billion. The ED attached oil rigs and other oil installations outside India after issuing a provisional attachment order against Sandesara group of companies in June 2019. The agency attached the group’s assets worth over $1.375Billion or Rs97Billion in Nigeria, including four oil rigs, an oil field, ships and aircraft. With this order, the total attachment against Sandesara group has exceeded $2Billion, or Rs 145Billion . Last year, the ED had attached over $666Million, or Rs 47Billion in Nigeria, including four oil rigs, an oil field, ships and aircraft. “The promoters have not only siphoned off bank loans to finance their Nigerian oil business but also for their personal purposes,” the ED claimed. The probe found that the group was engaged in round tripping of standby letters of credit (SBLCs) funds worth $638Million or Rs 45Billion

UNLIKE OML 13, NPDC HAS ALWAYS OWNED OML 65, an asset it has produced for 41 years, from a single field, Abura, now doing about 900Barrels of oil per day. There had always been upside prospects to this field, but NPDC is a poor investor if it was one at all. Now, to drain the recoverable reserves of 244Million barrels of oil equivalent that NPDC’s reserves consultants believe are in this asset, the company closed a Funding and Technical Services agreement with a company that has never been known to engage in drilling a well, let alone produce a field. The parent companies of CMES-OMS JV are engaged in EPC and oil field security solutions. They are neither proven explorers nor experienced oilfield producers. The explanation that CMES-OMS would source money (based on the asset pool) and hire technical workforce to do the job throws up the question: Why will a 31 year old state funded E&P company, which boasts of managing several assets over the years, hand over an asset to an inexperienced company to manage on its behalf?

The third asset that NPDC is handing out to a technical operator is OML 119. This is the best performing acreage of all the assets wholly owned by  NPDC (without a JV partner). And that’s because the asset was put in production for the company by Agip Energy and Natural Resources (AENR), a Nigerian subsidiary of the Italian giant ENI and handed back to NPDC after a specified period of time.

Here is the story. OML 119 is a shallow water asset which hosts two producing fields, Okpoho and Okono, discovered by NPDC in 1978 and 1983 respectively.

With no capacity to develop either of the two fields 18 -23 years after discovery, NPDC, in 2001, signed a modified service contract with AENR, to technically operate the two fields for five years, after which it would hand over the operatorship back to NPDC. The idea was that AENR would, in the course of those five years, help to high-grade NPDC’s technical ability to operate the fields.

AENR put the fields on production in record time; by 2002, it had installed a floating production, storage, and offloading vessels on the Okono field. The Okono field produces oil from subsea wells tied-back to the leased vessel Mystras FPSO located at the field. Oil from Okpoho is produced via a platform linked to the FPSO by pipeline. Oil is exported from the FPSO by shuttle tanker. Operatorship of the two fields reverted fully to NPDC in 2006, and as of 2009 the fields were delivering 65,000 Barrels of Oil Per Day (BOPD). In 2008, six years after first oil, the partners purchased the FPSO Mystras.

Ten years after the handover of operatorship to NPDC, the production has plunged to a third of what it was at the time of the handover, despite the fact that NPDC geoscientists have encountered new oil at much deeper levels than AENR.

The call for bids for Financial and Technical services is an admission by NPDC that it cannot, on its own operate these assets.

So much for NNPC’s claim, since 2015, that a key corporate project was to re-kit the NPDC and make it bloom in terms of technical and personnel resources.

 

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