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Shell Divestment Transformed NPDC into A “Major”

By Toyin Akinosho

The divestment from four western Niger Delta acreages by the AngloDutch major Shell and its European partners transformed the Nigerian Petroleum Development Company NPDC, into “a major company”, in the opinion of NPDC managers.

“Huge hydrocarbon resources became available to us”, Kareem Folorunso, the NPDC Manager in charge of the Oil Mining Lease (OML) 26, told a technical session of the Nigerian Association of Petroleum Explorationists (NAPE) in Lagos recently.

Shell, with 30% operatorship of OMLs 26, 30, 34, and 42, led its two partners, TOTAL (10%) and ENI (5%), out of the acreages by selling the combined 45% equity to Nigerian companies between 2011 and 2012. NPDC’s involvement in those assets was triggered by NNPC assignment of her 55% equity to her wholly owned subsidiary.

The NAPE lunch hour presentation was part of a series of attempts by the company to counter charges that its takeover of operatorship of acreages divested by Shell & Co was not a value-destroying enterprise. There are widespread misgivings that the acreages would have delivered much more in terms of output and value to the Nigerian treasury if they had been operated by the private companies who purchased the Majors’ 45% share.
Mr. Folorunso’s paper presented NPDC as a technically honed, well-resourced entity, which just happens to be hampered by bureaucratic challenges normally faced by state owned enterprises.

NPDC’s crude oil in place increased tenfold from 313Million stock tank barrels before the divestment to 3.17Billion stock tank barrels (STB) post-divestment; the company’s stock tank barrels of condensate in place increased more than fivefold from 60MMSTB to 330MMSTB, while the gas resources in place jumped nine times from two trillion cubic feet (2Tscf) to 18Tscf, Folorunso said.

“NPDC is the third largest oil company in Nigeria in terms of oil reserves and has the 4th largest gas reserves in Nigeria”, Folorunso told the meeting, a monthly lunch hour talk designed for knowledge sharing among petroleum geoscientists. “Countless opportunities for partnership and collaboration with other business entities also became available as a result of the divestment”, he testified.

The word ‘Major’ was rather loosely used by Mr. Folorunso. In the oil industry lexicon, only six oil and gas companies –Shell, ExxonMobil, Chevron, BP, TOTAL and ENI are described as Majors. None of them produces less than 1.75Million Barrels of Oil Equivalent per day (1.7MMBOEPD) on a net basis.
The highest producer, ExxonMobil, produced 4.053MMBOEPD in 2016, of which liquid hydrocarbons, mostly crude oil, was 2.365MMBOPD, much higher than Nigeria’s gross total production. Even ENI, the smallest of the group, is only described as a Major because of its unique place in the European industry. In the strictest sense of the term, ENI is really considered “a large independent”, in the same class as ConocoPhillips, Apache, Anadarko and Woodside Petroleum.

What’s more, the smallest of these majors has 7.7BillionBOE, as proven reserves and not Stock Tank Barrel (STB) in Place.
So it is a clear misnomer for Mr. Folorunsho to say that NPDC had transformed into major company. But the Nigerian state hydrocarbon company can be forgiven for being excited by its good fortune.


Ghana Wins

Cote d’Ivoire’s Claim on Oil Discoveries in the Cape Three Points Has No Merit

By Sully Manope

Ghana’s 4-1 beating of Nigeria in the West Africa Football Union (WAFU) Final last Monday (September 25, 2017) was an icing on a cake baked with a huge victory on the economic front.

The country had won a decisive win over Côte d’Ivoire at the Special Chamber of the International Tribunal of the Law of the Sea(ITLOS) two days before the WAFU Cup final match in Cape Coast, capital of Ghana’s Central Region.

It’s worth noting that Côte d’Ivoire and Nigeria are Ghana’s two most important economic and political rivals on the mid-African edge of the Atlantic Ocean.

Ghana had taken Côte d’Ivoire to ITLOS in September 2014, after negotiations with the latter broke down over who had rights to explore and exploit the resources in the Cape Three Points acreages as well as the surrounding fields.

In April 2015, ITLOS forced Ghana to suspend the drilling of new oil and gas wells in the disputed territory by ordering a number of provisional measures, pending the outcome of the litigation. That decision caused Ghana’s Twenaboa, Enyenra and Ntomme (TEN) cluster of fields to begin production with 11 of the planned 24 wells, as no new wells could be drilled until the dispute was settled.

Three years after ITLOS was approached by Ghana to arbitrate, the Tribunal ruled as follows in favour of the country: 1) That there had not been any violation on the part of Ghana on Côte d’Ivoire’s maritime boundary; 2) Determined a new boundary for the two countries (3) Dismissed Côte d’Ivoire’s legal argument that Ghana’s coastal lines were unstable and 4) Declared that Ghana’s oil and gas exploration activities in the disputed basin did not violate any other country’s sovereign rights.


NLNG Commits $200Milion for Bodo-Bonny Highway Construction

By Foluso Ogunsan, in Port Harcourt

The Nigeria Liquefied Natural Gas (NLNG) Limited has agreed to provide 50% counterpart funding, amounting to N60.3Billion(or $197Million) for the construction of Bonny Island-Bodo road, a project billed to cost N120.6Billion ($394Million).

The gas company signed an agreement with the federal government and Julius Berger, according to a Press release.

The road is expected to be transformative in that it would open up vast swathes of the Niger Delta basin, which is largely inaccessible.

“The 34 kilometre road will help address the twin challenges of poverty and unemployment as well as improve the lives of people of the region, especially those from Bonny, Ogoni, Okrika, Eleme, Andoni, and other communities in the Niger Delta”, the NLNG said.

The Bodo Bonny road will have to include at least four bridges, laid over significant bodies of water.

“The federal government’s efforts to build the road had been hampered for decades, largely by funding and contractor issues, causing NLNG to intervene especially because of the criticality of the road to residents of Bonny Island, who daily brave the vagaries of the sea to travel to the mainland, ” the NLNG statement said.

Tony Attah, NLNG’s managing director, Babatunde Fashola, minister of works, power and housing, and Wolfgang Goesh, Julius Berger’s managing director, signed the agreement.

“This for Nigeria LNG is part of our effort to contribute to the advancement of the Niger Delta. More importantly for us as a company, our contribution to the project will lead to the accomplishment of the dream of connecting Bonny Island to the rest of Rivers State by road and not only by sea,” Attah said.


South Africa’s Planned Gas To Power IPP Bid Round Is On Hold

By Boniswa Umtata, in Cape Town

And the proposed exploration in the Karoo won’t happen for a while

South Africa’s plans to roll out an Independent Power programme(IPP) for gas to power projects will be on hold for the time being.

The country’s Minister of Energy was to inaugurate the bid this year.

But the entire programme is going to be delayed around political succession (with implications for energy policy) and the general need to close the outstanding renewables deals before South Africa moves on to importing gas, according to ranking sources in the Ministry of Energy.

The LNG to Power IPP Programme aimed to identify and select successful bidders and enable them to develop, finance, construct and operate a gas-fired power generation plant at each of two ports, Ngqura and Richards Bay in South Africa.

The successful bidder would also be required to put in place the gas supply chain to fuel the plant with gas from imported LNG.

The LNG to Power IPP Programme will provide the anchor gas demand on which LNG import and regasification facilities can be established at the Ports of Ngqura and Richards Bay. This will provide the basis for LNG import, storage and regasification facilities to be put in place that can be available for use by other parties for LNG import and gas utilisation development.

Therefore, Third Party Access will be a fundamental aspect of the LNG to Power IPP Programme. This will enable the development of gas demand by third parties and the associated economic development.

Full story in Africa Oil+Gas Report Vol 18, No 7, Southern Africa 2017 issue; September 2017 edition. Will be distributed to paying subscribers as well as delegates at the Africa Oil Week in Cape Town in October. It can also be accessed here…


Why the “Digital Oil Company” Mantra Is Overrated

By Toyin Akinosho

There were hardly any computers on anyone’s desk when I arrived at Chevron Corporation as a trainee geologist in mid-1988.

The entire computing power in the company resided in an offsite location, seven kilometres from the main office.

A geoscientist’s desk was typically filled with several paper prints of two and three dimensional (2D and 3D) seismic reflection profiles. The table also hosted a printed base map or two. In a rack next to the seat were rolls of sepia and paper copies of more seismic reflection profiles, a handful of basemaps and several other maps.

Earth scientists painstakingly interpreted the profiles and transferred their “opinions” on the basemaps, usually of 1: 12,500 scale. What came out of the venture was mainly a structural map, a plan view of the top of a reservoir sand or seismic event several kilometres deep in the subsurface, which every interpreter pinned on a wall above his head.

The pinup was proof that he had completed the interpretation of a prospective sand reservoir or seismic “event”. Such a map prefigured the determination of the location of an oil well.

Full story of the earliest computerisation of oil and gas exploration and why the current advances are less a revolution than part of an ongoing evolution, is here..


Gabfest Galore: Nigerian Government to Start an Oil Conference in 2018

The Nigerian ministry of petroleum has concluded plans to add to the teeming market of oil and gas conferences in the country.

It has even picked a date which puts it in competition with one of the newest of such conferences and a venue that indicates a challenge to one of the oldest such shows.

The Nigeria International Petroleum Summit (NIPS), tagged the “First Federal Government of Nigeria’s official oil and gas industry trade show”will be held in Abuja in February 2018.
So there.

This trade show will happen in Abuja in the same month that the West Africa International Petroleum Conference (WAIPEC), has been scheduled to hold in Lagos. NIPS will be inaugurated in the same month as WAIPEC’s second annual outing.

It will take place at the International Conference Centre, the same venue that the Nigerian Oil and Gas Conference (NOG) has held court for most of its 18 years. NOG is also scheduled to run in February 2018!!

The question is: Is a government conference so necessary to crowd out the space for private initiatives?

There is an answer in the press release.

The organisers advertise what seems like targeting the continent: “This event will undoubtedly be the Africa’s largest and most important industry platform and linkage to the world where engineering and technological breakthroughs, bid rounds, bid sign-off, major contract signing and sites conferences would meet other developmental and economic diversification initiatives of the country”.

Indeed, Yemi Osinbajo, the Nigerian Vice President,“unveiled the official launch of Nigeria International Petroleum Summit 2018 in the presence of 19 African Ministers of Petroleum and delegates who attended the African Petroleum Producers Organisation (APPO) meeting in Abuja, Nigeria recently”, notes the release.

But then the same statement, two paragraphs later, pulls back the curtain and limits itself to Nigeria: The NIPS, it says “will be held annually as a platform to highlight Nigeria’s long history of oil and gas production, substantial reserves and status as a leading global player in the sector”.

Which is what NOG does, What WAIPEC did this year, What the various panels of the Society of Petroleum Engineers (SPE) do, and what the annual conference of the Nigerian Association of Petroleum Explorationsists (NAPE) does.

Indeed, there have been concerns that the SPE and NAPE conferences, organised by associations of technical personnel, have been focusing much more on the business and politics of hydrocarbon exploration and extraction, than on the technical programme that is their core remit.

They all want “key Nigerian political decision makers, government officials and industry’s specialists from the National Oil Company(NOC) and other relevant government bodies on the one part and Chief Executive Officers (CEOs) of National and international oil companies, multinationals and multilateral organizations, the academia and other relevant stakeholders et cetera”, as the NIPS statement says.

They all cite Nigeria’s petroleum industry as “the largest in Africa with proven Oil and Gas reserves of 37 billion barrels (bbl) and 192 trillion cubic feet respectively. The sector contributes about 10% to the country’s Gross Domestic Product and accounts for 95% of all exports”, as the NIPS press release notes.

Then again, “given that Nigeria’s Gas reserves have remained largely untapped, the country is expected to make a shift towards becoming a major producer and exporter of Gas which the summit provide with an excellent business environment to interact, cross-pollinate ideas and to make deals happen”.

Ha. What the country needs are subject specific conferences, even in the hydrocarbon sector. That way, you deepen the search for solutions to specific areas and participants not only network, but go away from summits with information they can translate immediately to business success.


Lekoil in OPL 310: One Down, One More to Go

LEKOILis expecting the second of the two consents of Nigerian authorities on the Oil Prospecting Lease (OPL) 310.

The current lease expiry date is February 2019. Lekoil has an understanding with Baker Hughes, a GE company, for technical partnership and investment in appraisal of the discovery, possibly leading to first oil. But it can’t proceed without ministerial consent. Optimum, which is the licence holder and Lekoil’s partner, is not a technically resourced company, so a work programme will not happen before expiry date if Lekoil doesn’t get the government’s nod.

But no one seems to be in a hurry at the Department of Petroleum Resources (DPR), the industry regulatory agency, to respond to Lekoil’s challenges.

The consent to complete the transfer of the original 17.14% participating interest that Lekoil acquired on the lease in February 2013 was granted by the Minister of state for Petroleum Resources in June 2017. This means it has taken four years and three months after it acquired the interest in the block to achieve this very important regulatory approval.

What now remains is the authorities’ consent for a second acquisition that the company made on the same block. In November 2015, Lekoil acquired Afren’s remaining 22.86% participating interest in the block. That acquisition remains conditional upon receiving Ministerial Consent.

The key challenge here is that Optimum feels it ought to have been consulted when Lekoil acquired the equity from Afren. Some of the regulatory officials at the DPR, who are in charge of preparing the documents for the Minister of state to sign on, want Optimum to give them a go ahead before doing the required Due Diligence and processing the consent documents. Lekoil, a listed company, argues that the law does not require Optimum’s nod before the Minister can give a consent. Indeed, Optimum is pushing for a renegotiation of terms and Lekoil is pushing back.

“We are trying to working through the process”, once lawyer close to both parties says, “although it’s not always clear what the process is”. This is clearly an issue highlighting how difficult it is to do business in Nigeria.

The delay in regulatory consent for Lekoil on this block stands in the way of the company’s plans for the development of a work programme for the Ogo field (the only discovery on the block) for which it has signed a Memorandum of Understanding with GE Oil & Gas, now Baker Hughes, a GE Company.

Lekoil says it is also in discussions with other potential partners for the financing of the appraisal programme, following which, and subject to the fulfilment of a number of conditions including a positive well result, Baker Hughes, through a consortium SPV, and Lekoil through its funding partners, intend to invest funds towards the full field development capital of the project. Lekoil estimates this cost to be US$400MM for full field oil development and US$600MM for subsequent upstream gas field development.

“When all the issues have been resolved” Lekan Akinyanmi, Lekoil’s Chief Executive Officer told Africa Oil+Gas Report’s Akpelu Paul Kelechi back in April 2017, “we hope to spud before the end of the year”.

In the first week of September 2017, Mr.Akinyanmi’s timeline is not looking very good.


Baru Underestimates the Output of Nigerian Independents

By McJohn Akobata, in Warri

Maikanti Baru, Group Managing Director and Chief Executive Officer of the Nigerian state hydrocarbon company NNPC, has claimed that Nigerian Independent E&P companies were producing around 10% of the national output.

He made the claim when he met with their representatives in his office in Abuja a week ago.

But 10%, which means 250,000BOPD at the most, and more realistically, 220,00BOPD, is erroneous. On a good day, Nigerian independents produce over 400,000BOPD gross, which is at least 16% of national output, and this is extremely conservative, Africa Oil+Gas Report can authoritatively report.

Mr.Baru, PhD, had apparently not consulted his company’s own generated statistics.

Of course, on a bad day (when key pipelines are shut down), everyone is affected, and that includes IOCs, which then means less production from Nigerian independents correlates with less production from IOCs.

In the month of July 2017, six Nigerian Independents, in Joint Venture with NNPC itself, pumped some one hundred and sixty nine thousand barrels of crude oil a day (169,000BOPD) gross through the TransForcados system in the Western Niger Delta.
Three other such indigenous companies, also JVs with government, collectively delivered on average 182,000BOPD(gross) through the Nembe Creek Trunkline in the Eastern Niger Delta.

That means that Nine Nigerian companies grossed 351,000BOPD in July 2017. These companies include Aiteo/NNPC Joint Venture, Seplat /NPDC Joint Venture, Eroton/NNPC Joint Venture Shoreline /NPDC Joint Venture, NecondeNPDC JV, Newcross/NNPC Joint Venture as well as NDWestern/NPDC, Elcrest/NPDC and FHN/NPDC Joint Ventures, On top of these, four non JVs, including Conoil, Amni, Midwesternand Oriental, produced over 60,000BOPD collectively. Details are available here.


The Oil Market Has Become Unruly-ENI

Italian major says the world’s top energy commodity is hostage of hedge funders
Claudio Descalzi, Chief Executive of ENI, Italy’s largest company, is not optimistic about the direction of the oil market, at least in the short term.

“The oil commodity has entered a difficult crisis. There is less confidence also among institutional investors, who normally have long positions and today they have become shorters”, Descalzi said in an interview published in ENI.com, the company website. “In this way space has been given to hedge funds and speculators. Probably they do not believe that OPEC is capable of taking radical initiatives. And today several sub-Saharan African countries are in serious difficulties”

ENI’s CEO told the interviewer, Roberto Bongiorni, that the geopolitical situation around the oil commodity “is explosive”. The situation, he said,“involves several OPEC countries, there is the shadow of U.S. shale gas which still today is facing over-production, and markets increasingly at the mercy of speculation are preventing low oil prices from emerging from a three-year crisis”.

The result, for one of Europe’s top oilmen, is dramatic.“ The moment is difficult, and speculation is strong. There are speculators that are making maybe billions of dollars. It is a market without rules, which is destroying the primary industry and in the energy sector it has burned 470,000 jobs in three years.

Millions of people are affected. Africa is exploding: the lack of diversification of the economies and the absence of wealth distribution is contributing to poverty and to migration flows”.


West Africa Lags Behind In Response to the Oil Price Downturn

By Henrik Poulsen and Bimbola Kolawole, Rystad Energy

The fall in crude oil price has foisted a significant challenge on the E&P industry.

Things have eased since January 2016, but crude oil price has stabilized at a much lower level than expected. In order to survive and deliver healthy economic results, companies have initiated a string of methods to improving operations. The hydrocarbon industry is about to develop a new standard on how we collectively look upon cost levels, development concepts and efficiency.

By comparing operating cost levels, investments and robustness of future production to low prices in four different regions, we at Rystad have discerned a pattern of how the industry is evolving globally. We have scrutinized how operating costs per barrel and investments (Capex) have changed since the oil price crash in four regions, including West Africa, South East Asia, South America and Western Europe. We have also looked at the impact on how the latter changes have influenced the breakeven price distribution of the production. In other words, how robust future production will effect low oil prices. A region is a coarse geographical entity and may not reflect differences at a country level. However, a region comprises so many projects and fields that the statistics becomes significant and reliable.

Has the industry been able to improve their efficiency – Operating expenses per barrel (Opex/Bbl)
Opex/Bbl is a measurement on how cost efficient the actual oil production is. Until 2014, such expenses were by far the highest in Western Europe (among the four regions compared). The price downturn has made operators in Western Europe work more efficiently, and the cost level has lowered by more than 30% to come down to the same level as in the three other regions in this review. In the same period, South America lowered their Opex/Bbl by about 20%, while West Africa and South East Asia have only been able to lower their Opex/Bbl by 10% each. South East Asia has a declining production, which explains much of the low reduction, while West Africa is falling behind in terms of reducing their operating costs.
Investments (Capex)

The oil price crash has of course had a great impact on the investment level. Previous projects with a robust economy at US$100/Bbl are not sustainable at US$50/Bbl. Many projects have been deferred, re-designed or simply abandoned, which has caused a dramatic drop in investment levels since 2014. Regions that have been able to re-design their projects have seen a lower drop in investment levels. Among the peers, the drop have been most dramatic in West Africa and South East Asia, with an almost 60% decline in investments from 2014 to 2017. The drop in Western Europe and South America has respectively been 45 and 30%. South America stands out as positive in this respect due to the development of its many great discoveries done some years before the oil price crash. Future production will be harmed most where projects have been deferred or abandoned, while re-design will have less impact on future production, apart from the fact that redesign also cause a delay, but only by some few years.
Future robustness to low oil prices

There is no doubt that how the E&P industry is handling the current uncertain market conditions will greatly impact future performance. Decisions and achievements completed in recent years will influence how the different regions will be able to attract and develop the industry into the future. As we have seen, has the efficiency in operations and investment levels developed significantly different from region to region? The issues discussed can also help us to understand how robust the future production in the different regions will be if low oil prices remain for a longer period. Rystad Energy believes the prices to be positioned upwards of US$60/Bbl when we reach the 2020’s. However, oil prices have never been precisely predictable. Therefore we have looked at how much of a portion of future production (in 2020 and in 2025) will need a breakeven price higher than US$60/Bbl.

Production with breakeven prices higher than US$60/Bbl might be at risk, if the world remains as oversupplied as it is today. Among the four regions, West Africa has the second highest portion of vulnerable production if prices remain lower than US$60/Bbl. Only South East Asia has a higher portion of production at risk. 13% of West Africa’s predicted production in 2020 is at risk, while this increases to 27% in 2025. This shows the importance of constant work on cost reductions and efficiency gains in order to remain competitive and economically sound. However, we still forecast a small increase in oil (Crude & Condensate) production from West Africa from 2020 to 2025, while South East Asia is expected to continue its decline.

Summary
As shown, the West African E&P industry has room for improvement on how they run their daily operations. What has been achieved in other parts of the world should be possible, to a certain degree, for West Africa to copy. Efficiency gains will often require a collaborative and open environment between the E&P and OFS industry together with the authorities. We assume there is room for improvement for at least another 10% on the operating costs in West Africa.

Low oil prices have made the industry even more cautious to invest in high politically at-risk and unstable countries and there is no doubt that some regions are hurt more than others by this fact. It is important to understand that doing investments, which will pay off the next two or three decades, requires a stable and predictable investment climate.

In a high-risk environment with low oil prices, we would expect that West Africa is one of the regions in the world that would be harmed most – close to 60% drop in investments the last 3 years. This is partly due increasing maturity, deeper water, more complex reservoirs, but also difficult political conditions in some countries. We would encourage the industry, together with the authorities, to uncover simpler development concepts instead of deferring or abandoning projects to make future production more robust to accommodate lower prices. We see room for improvements on the latter.
Lower operating costs per barrel and increased focus on improved and more efficient development concepts may arrest our prognosis, that West Africa may face a doubling of their production at risk with oil prices lower than 60 USD/bbl.

Whatever the future oil price will be is it evident that both Governments and the industry would profit by working smarter and more cost efficient in a joint collaborative environment.

About Rystad Energy
Rystad Energy is an independent oil and gas consulting services and business intelligence data firm offering global databases, strategy consulting and research products.

Rystad Energy’s headquarters are located in Oslo, Norway. Further presence has been established in Norway (Stavanger), the UK (London), USA (New York & Houston), Russia (Moscow), Brazil (Rio de Janeiro), as well as Singapore and Dubai.

Author: Henrik Poulsen
Henrik holds an MSc. in Petroleum Geology from the Norwegian University of Science and Technology and is currently Senior Vice President – Government Relations at Rystad Energy. He has more than 25 years of experience in the E&P and oilfield service industry and has worked as a consultant for 15 years in the E&P industry, assessing geological and economic uncertainties. Since 2005, Henrik has held several senior management positions at different companies such as Roxar (Emerson), Schlumberger and Rystad Energy.

Author: Bimbola Kolawole
Bim (Bimbola) is Business Development Manager –Africa at Rystad Energy. She is also responsible for account management, training and support for clients in the Region. Her area of expertise includes business strategy, general management, business development, training and support as well as project coordination. Previously, Bim worked at IHS Energy where she was responsible for managing selected clients across the Oil & Gas space value chain in the EMEA region. She holds a BSc. in Economics from Ilorin University, MSc. in Energy Finance from Dundee University and an MBA from Leicester University.

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