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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, 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.

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.

No Transit Tax to Tanzania on the East Africa Crude Oil Pipeline

Ugandan president, Yoweri Museveni, expressed gratitude to “the Tanzanian government and people” for the generous concessions the latter have granted his country on the 1,445 Hoima (Uganda) to Tanga (Tanzania) crude oil pipeline.

“There will be no pay transit tax, no Value Added Tax, no corporate income tax, they gave us 20 years depreciation tax holiday, granted us a free corridor where the pipeline passes and promised to buy shares in the pipeline”, President Museveni said on Saturday, August 5, 2017.

He was speaking at the inauguration of the construction of the pipeline, named the East African Crude Oil Pipeline. With him at the stone laying, in Tanga, was Tanzanian President Joseph Pombe Magufuli, and ranking ministers from both countries, as well as a crowd of cheering Tanzanians.
Because of those concessions, Museveni explained, “the cost of delivering a barrel of oil from Hoima to the Tanga on the edge of the Indian ocean will be $12.2, making Uganda’s crude profitable even at today’s cost of about $50 per barrel.

Cost has been the core issue in the choice of route for the evacuation of crude from landlocked Uganda to the nearest coastal town from which to export the hydrocarbon.

French major TOTAL pushed the Ugandan government into jettisoning the Hoima (Uganda) to Mombassa or Lamu (Kenya) route for the Hoima (Uganda) to Tanga (Tanzania) route by stating repeatedly that the Tanzanian route was “the least cost” route.

The idea that Ugandan crude would pass through Kenya had seemed settled for several years, and been accepted by the (then) main player Tullow Oil, until TOTAL showed up in the scheme.

One of TOTAL’s key argument was that the Kenyan route was mountainous and as such expensive, compared with the rather flat land route from Hoima to Tanga. There were also security concerns.

But the generous concessions by Tanzania, announced last Saturday had also helped.

Museveni asked other East African countries (Rwanda, Congo DRC, South Sudan) to look at the East African Crude Oil Pipeline as an East African community asset and argued that new discoveries in the region would find ready evacuation to the sea through the pipeline.

The heated crude oil pipe line, reportedly the longest of its kind in the world, will cost $3.5Billion and is expected to be completed by 2020. The pipeline works will be undertaken by Total E&P, CNOOC and Tullow Oil together with the two governments of Uganda and Tanzania. At peak, the line will pump 216,000 barrels of crude oil for export daily.

Three important oil trade chokepoints are located around the Arabian Peninsula

By the US Energy Information Administration

Nearly 59Million barrels per day (b/d) of global petroleum and other liquids production moved on maritime routes in 2015, or almost 61% of the world total. Many of these products transited the Suez Canal and SUMED Pipeline, the Bab el-Mandeb Strait, and the Strait of Hormuz chokepoints around the Arabian Peninsula.

Chokepoints are narrow channels along widely used global sea routes, and they are critical to global energy security. The inability of oil to transit a major chokepoint, even temporarily, can lead to substantial supply delays and higher shipping costs, resulting in higher world energy prices. Although most chokepoints can be circumvented through the use of other routes that add significantly to transit time, there are no practical alternatives in some cases.

The Strait of Hormuz is the world’s most important chokepoint, with an oil flow of 18.5 million b/d in 2016. The Strait of Hormuz connects the Persian Gulf with the Gulf of Oman and the Arabian Sea, and in 2015 its daily flow of oil accounted for 30% of all seaborne-traded crude oil and other liquids. More than 30% of global liquefied natural gas trade also transited the Strait of Hormuz in 2016. At its narrowest point, the Strait of Hormuz is 21 miles wide, but the width of the shipping lane in either direction is only two miles wide, separated by a two-mile buffer zone.
There are limited options to bypass the Strait of Hormuz.

Only Saudi Arabia and the United Arab Emirates have pipelines that can ship crude oil outside of the Persian Gulf and have additional pipeline capacity to circumvent the Strait of Hormuz. At the end of 2016, the total available crude oil pipeline capacity from the two countries combined was estimated at 6.6 million b/d, while the two countries combined had roughly 3.9 million b/d of unused bypass capacity.

The Suez Canal and the SUMED Pipeline are strategic routes for Persian Gulf oil and natural gas shipments to Europe and North America. Located in Egypt, the Suez Canal connects the Red Sea and the Gulf of Suez with the Mediterranean Sea. In 2016, 3.9 million b/d of crude oil and refined products transited the Suez Canal in both directions, according to data published by the Suez Canal Authority. Northbound flows rose by about 300,000 b/d in 2016, largely because of increased crude oil exports from Iraq and Saudi Arabia to Europe. Southbound shipments decreased for the first time since at least 2009, largely because of lower exports of petroleum products from Russia to Asia.

The 200-mile long SUMED Pipeline transports crude oil through Egypt from the Red Sea to the Mediterranean Sea. Crude oil flows through two parallel 42-inch pipelines that have a total capacity of 2.34 million b/d. The SUMED Pipeline is the only alternate route to transport crude oil from the Red Sea to the Mediterranean Sea if ships cannot navigate through the Suez Canal.

Closure of the Suez Canal and the SUMED Pipeline would require oil tankers to divert around the Cape of Good Hope near the southern tip of Africa, which would add approximately 2,700 miles to the transit from Saudi Arabia to the United States. In 2016, 1.6 million b/d of crude oil was transported through the SUMED Pipeline to the Mediterranean Sea and then loaded onto tankers for seaborne trade.

The Bab el-Mandeb Strait is a chokepoint between the Horn of Africa and the Middle East and is a strategic link between the Mediterranean Sea and the Indian Ocean. Located between Yemen, Djibouti, and Eritrea, it connects the Red Sea with the Gulf of Aden and the Arabian Sea. Most exports from the Persian Gulf that transit the Suez Canal and the SUMED Pipeline also pass through Bab el-Mandeb.

An estimated 4.8 million b/d of crude oil and refined petroleum products flowed through this waterway in 2016 toward Europe, the United States, and Asia, an increase from 3.3 million b/d in 2011. The Bab el-Mandeb Strait is 18 miles wide at its narrowest point, limiting tanker traffic to two 2-mile-wide channels for inbound and outbound shipments. Closure of the Bab el-Mandeb could keep tankers originating in the Persian Gulf from reaching the Suez Canal or the SUMED Pipeline.

Entire article and illustration by the US Energy Information Administration (EIA)
Principal contributors:
Lejla Villar, Mason Hamilton

M&P’s Production Drops in Gabon

By Njoroge Karoo

French junior Maurel & Prom says that its First Half (1H) 2017 oil production in Gabon stood at 24,705BOPDgross, operated, or 19,764BOPD(net) for M&P’s80% share.

This level was below the fields’ production capacity, which had been impacted by a strike that disrupted operations in Q1 2017. “The consequences of the strike continued into Q2 2017”, the company says.

All the fields concerned are in the Ezanga permit.

M&P is listed on Euronext and headquartered in Paris, but has more operations in Africa than anywhere else in the world. It has oil production assets in Nigeria as well as both exploration permits and production rights in Gabon.In Tanzania, the company has gas producing assets. In Nigeria it holds, for instance, roughly 22% of the shares of Seplat, a dual Nigeria and London listed junior.

South Sudanese Oilfield Engineers Complete Training in Ogbele

The first set of South Sudanese well production, oil and gas processing “Technical Assistance Training Programe” at Ogbele Production Facilities has ended.

The training lasted six months.
The four Engineers have returned home and the Niger Delta Exploration and Development (NDEP), the Nigerian company leading the assistance, expects the second batch of four Engineers to be in the country by mid-August 2017.

The programme is part implementation of the agreement between NDEP and Nile Petroleum Corporation (Nilepet), the South Sudanese state Hydrocarbon Company, to support the latter to monetize and commercialize all the gas resources in South Sudan as well as support it in production optimization and improved production in existing brown fields.

“We have exposed our business in Nigeria to human content development of South Sudanese”, declares Layiwola Fatona, NDEP’s Managing Director. “The next batch of engineers will participate in a more robust programe, as our 2017 Drilling campaign would have started with the mobilization of a rig in 2 weeks”.

Seplat Remains in the Red but Its Debt Portfolio Is …

Loss making Seplat Petroleum Development says it has successfully concluded a one year extension of its revolving credit facility (“RCF”) until 31 December 2018.

The company reported a loss after tax of $19.1Million for the first quarter of 2017, but its lenders have a positive appraisal of its possibilities.

Africa’s top homegrown E&P Firm says the current three year RCF was due to expire at the end of 2017. The facility now expires on 31 December 2018 and has been successfully amended to amortise the remaining outstanding principal balance of US$150 million in equal instalments over five quarters commencing Q4 2017. Overall, Seplat’s aggregate indebtedness under its Term Loan and RCF has reduced by US$365 million from its peak in Q1 2015 of US$1 billion to the current balance at the end of June 2017 of US$635 million, which is a significant deleveraging of the balance sheet particularly in exceptionally difficult trading conditions over the past 18 months.

The amended facility has been provided by Citibank N.A. London Branch, Citibank Nigeria Limited, The Mauritius Commercial Bank Plc, Natixis, Nedbank Limited London Branch, Nomura International Plc, FirstRand Bank Limited acting through its Rand Merchant Bank Division, Stanbic IBTC Bank Plc, The Standard Bank of South Africa Limited and Standard Chartered Bank.

Roger Brown, Seplat’s Chief Financial Officer, explains that the approval to extend “and strong demand within our core lending group, which saw around 30% over subscription, demonstrates Seplat’s strong underlying business fundamentals and is further testament to the strength of our relationship with our continuing and new lenders”.

The amended facility, and recent resumption of exports via the Forcados terminal, “will enable the business to rebuild cash on its balance sheet as we seek to strengthen our capital structure to ensure a strong platform for future growth”, Brown adds.

Three More Marginal Field Operators Reaching First Oil

By John Sanussi, in Warri

Century Energy E&P is on course of putting the Atala Marginal Field on stream; Excel E&P has now formally started to inject about 800Barrels of crude oil per day crude oil from Eremor field into the TransForcados system and sources at Millenium Oil and Gas say it has “less than” 60days to go to complete all the remaining hook up and commissioning facilities for the startup of the Oza field.

The licences to these fields were awarded by the Nigerian Government in 2003.

The Atala field is actually held by the Bayelsa Oil and Gas Company (one of the three state companies which won an asset in the 2003 marginal field round). Century is only a technical and financing partner, but its economic interest is higher than 50%. The field development project is funded by Eunisell Solutions, a service company which will realize its investment from the proceeds of the crude output.

“What remains are minor permitting issues and installation of sales line metres for evacuation purposes”, say sources familiar with the Atala field production procedures. 2,000 BOPD from two reservoirs, will be delivered into barges and ferried into an FSO for export. Offtaker is Monaco. Part of the cash flow from Atala-1 production is expected to fund the drilling of Atala-2.

Millenium’s partners on Oza field are Hardy Oil and Emerald Resources. The field’s Early Production Facility (EPF) and tie-in at SPDC’s Isimiri flowstation, Pipe laying of 27.5km of 3” inter well flowlines and 3” and 6” test and crude delivery pipelines from the Oza manifold to Isimiri flow station are all done. Well test on Oza-2 Short and Long strings gave results suggesting productions of as high as 1,500BOPD on Choke 22 (short-string) from the L9.0 sand and 10,000BOPD on Choke 20 (long-string) from the M2.1 sand. Production on both strings had low GOR (between 250scf/Bbl and 1,000scf/Bbl). Oza field’s production is the least certain of the three.

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