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Algeria Reduces Fiscal Deficit Despite Lower Oil Price

By Mohammed Jetutu, in Cairo

Overall economic activity was resilient, but IMF advises reduction in ‘costly’ energy subsidies

The International Monetary Fund (IMF) has praised Algerian authorities for achieveing a notable reduction in the fiscal deficit in 2016, despite the challenges of lower oil prices.

Algeria is the third largest crude oil producer in Africa and the continent’s largest gas exporter. But its economic indices are better than Nigeria’s and Angola’s, the two top oil producers.

In a March 21 2017 report, the IMF noted that Algerian authorities were seeking to reshape the country’s growth model, but the country “continues to face important challenges posed by lower oil prices” the World Bank institution noted.. While efforts to adjust to the oil price shock are underway, “fiscal . consolidation will need to be sustained as oil prices are expected to remain low”. 

The report is the product of an IMF staff team visitation led by Jean-François Dauphin.

Discussions focused on the appropriate mix of policies to adjust to lower oil prices. “Overall economic activity was resilient, but growth in the nonhydrocarbon sector slowed under the effects of spending cuts and is estimated at 3.4% in 2016,” Mr. Dauphin explained in the statement.

Inflation increased from 4.8% in 2015 to 6.4% in 2016 and stood at 8.1% year-on-year in January 2017. Unemployment increased to 10.5% in September 2016 and remains particularly high among the youth (26.7 percent) and women (20.1 percent). Despite some fiscal consolidation in 2016, the fiscal and current account deficits remained large, and public debt increased. International reserves, while still ample, fell by $30Billion to $113Billion (excluding SDRs).

“Efforts to adjust to the oil price shock are underway. The authorities achieved a notable reduction in the fiscal deficit in 2016 and have adopted an ambitious fiscal consolidation plan for 2017-19. They made progress improving the business environment and are working on a long-term strategy to reshape the country’s growth model to foster greater private sector activity and economic diversification. The central bank is adapting its monetary policy instruments to a tighter liquidity environment. This growing reform momentum is welcome.

“A key challenge at this juncture is choosing a policy mix that will help the economy adjust to the oil price shock in a way that is sustainable and the least costly in terms of growth and employment.

“Fiscal consolidation will need to be sustained as oil prices are expected to remain low and hydrocarbon reserves are exhaustible. At this stage, the consolidation should rely primarily on broadening the tax base, including through better tax enforcement and the rationalization of tax exemptions; containing current spending; gradually replacing costly energy subsidies, which mostly benefit the well-off, by direct support to the population most in need; and improving the efficiency of capital spending and reducing its cost. Investment in health, education, and well-targeted social safety nets should be preserved. These efforts should be supported by further strengthening the budget framework and closely monitoring growing fiscal risks.

“Too abrupt a fiscal deficit reduction, however, should be avoided to reduce the risk of a sharp slowdown in growth. In the mission’s view, given the relatively low level of public debt, Algeria could afford a somewhat more gradual fiscal consolidation than entailed in the current medium-term budget framework if it were to consider a broader range of financing options, including external borrowing and the sale of state assets.

“The mission strongly supports the authorities’ objective to decrease the economy’s dependence on hydrocarbons and unleash the potential of the private sector. This is not only needed to adjust to lower oil prices but also to ensure a sustainable source of job creation even beyond the horizon for proven oil and gas reserves. Achieving this goal will require wide-ranging structural reforms. Measures are needed to improve the business environment and access to finance, strengthen governance and transparency, make the labor market more effective, ensure that skills produced by the education system and sought by students match the needs of employers, foster greater female participation in the labor market, and further open the economy to foreign investment. The overall strategy should be designed and sequenced so that reforms reinforce each other and the burden of economic adjustment is shared equitably. Action should be timely as structural reforms take time to bear fruit.

“Exchange rate, monetary, and financial policies should support the adjustment. Further efforts to bring the dinar in line with fundamentals, combined with steps toward the elimination of the parallel foreign exchange market, would support fiscal and external adjustment. The Bank of Algeria is appropriately introducing open market operations, which should become its main monetary policy tool. The Bank of Algeria will need to stand ready to tighten monetary policy in light of growing inflationary pressures. Based on preliminary data, the banking sector as a whole remains adequately capitalized and profitable, but the oil price shock has increased liquidity, interest rate, and credit risks. It is therefore important to accelerate the transition to a risk-based supervisory framework, enhance the role of macro-prudential policy, strengthen the governance of public banks, and develop a crisis resolution framework”, the statement concluded.
 


GE Commissions Takoradi Facility

GE Oil & Gas is commissioning its new services facility in Takoradi, in Ghana’s oil rich western region, this Wednesday, March 22, 2017.

On hand will be Ghana’s top petroleum bureaucrats, led by the country’s Minister of Petroleum, and G.E’s African leadership.
The project will primarily support the ENI operated Sankofa-Gye Nyame integrated oil and gas field development, located in Offshore Cape Three Points (OCTP) block, in water depths ranging from 600 to 1,500metres.

For a duration of 15 years, the Sankofa-Gye Nyame development will drain about 400Million barrels of crude oil reserves at 50,000BOPD at peak. It will supply 180Milliion standard cubic feet of gas to the country’s burgeoning domestic market.
The crude oil phase of the development is expected to come on stream before the end of June 2017.

GE will deliver a total of 21 subsea trees (also known as Christmas Trees, or XTs) for the project –  18 for installation and three for backup. Their primary function is to control the flow – usually oil or gas – out of the wells.

The Takoradi facility received the first two XTs for the Sankofa-Gye Nyame development in the last quarter of 2016.
GE Oil & Gas will also, at this facility, support the customer’s aftermarket needs, with the facility largely responsible for site receival testing and providing support to ENI’s equipment installation campaign for the Sankofa-Gye Nyamme project. Site receival testing involves ensuring the safe arrival of equipment, flushing systems and replacing hydraulic fluids, and making sure there’s continuous, undisrupted communication between the control equipment after they have been deployed offshore.


Nigeria’s Newest Indies Produce Close to 200,000BOPD

By Toyin Akinosho, in Lagos

Three Nigerian independents Aiteo, Eroton and Newcross, collectively produced close to 200,000Barrels Per Day at peak, close to the end of 2016.

These companies, each of which emerged less than four years ago, are the newest beneficiaries of the divestment programme of the oil majors operating in the country.

Aiteo Eastern E&P, the operator of the Oil Mining Lease (OML) 29, reported gross production of 92,000BOPD in October 2016, figures in NNPC’s December 2016 report show. Eroton E&P, in OML 18, averaged 63,764BOPD gross output in the same month. There were no figures published for Newcross in October 2016 and November 2016, (the last months for which figures are officially available), but the company, operator of OML 24, delivered 30,213BOPD in September 2016.

These figures come to about 186,000BOPD, roughly 10% of the country’s average 2016 production and are less than half of what the 22 Nigerian owned producers of crude oil and gas are capable of delivering.

Indeed, the five similar Nigerian independents, including Seplat, Shoreline Natural Resources, NDWestern, Elcrest and First Hydrocarbon Nigeria, who have had up to 80% of their production shut-in for more than 12 months by the damage to the TransForcados pipeline, were collectively producing over 160,000BOPD before the bombing. Seplat and Neconde alone were averaging 115,000BOPD prior to the February 14, 2016 outage.

Analysts however say that Nigerian owned oil producing companies have not historically been consistent in maintaining, let alone increasing production. Conoil, which produced around 45,000BOPD in 2005, and now delivers less than 10,000BOPD, with four acreages, is proof of this assertion.

“Poor governance is part of the challenge”, says Sam Ojehonmo, an Africa focused energy consultant based in Cairo, “but these new breed of operators have a different challenge; they took huge loans to buy the assets; the earlier generation had the assets largely handed over to them gratis, and they were cash flush when they had to bid for another round of acquisitions”.

Aiteo, Eroton and Newcross took over their assets from the consortium of Shell, TOTAL and ENI between 2014 and 2015, paying a total of $4.1Billion for the consortium’s 45% share, with the state hydrocarbon company, NNPC holding the remaining 55%. “We are a strategically important Borrower to the Nigerian banking industry”, Chike Onyejekwe, Group Managing Director of Aiteo, told an industry summit a fortnight ago in Abuja.


Nigeria’s Senate Says Four Petroleum Laws Will Be Passed in 2017

The upper house of the country’s bicameral legislature, the Senate, will pass all the four petroleum reform bills replacing the Petroleum Industry Bill before the end of the year, a ranking legislator has said.

“We will lay down the third reading of the Petroleum Industry Governance Bill (PIGB)sometime in March and possibly pass it by April 2017”, David Alasoadura, Chairman of the Upstream Petroleum Committee in the Senate, said in response to a question by Africa Oil+Gas Report at the Nigeria Oil and Gas (NOG) conference in Abuja last week.

The PIGB is the first of four bills which replace the Petroleum Industry Bill (PIB), which has been under deliberations since 2008. “The third reading is the last of the readings; it’s the nut and bolt reading”, he said.

The house is looking forward to fast track the passage of the three other bills; including the Petroleum Fiscal Reform Bill and the Host Community Bill. “We plan to combine two of the three remaining bills so that we can pass all the bills before the end of the year,” Alasoadura said.


Our Monthly Editions For 2017

The Africa Oil+Gas Report kickstarts its monthly editions for 2017 with a package focused on deepwater opportunities around the continent.

It’s a tradition that was established in 2004, when we evaluated 10 years of active deepwater foray in Africa.

Deepwater Annual 2017 is what we christen the January 2017 issue, released on January 22, 2017 as both e-copy and print issues distributed to our growing league of paid up subscribers around the world.

The February edition is themed Stepping On The Gas, and it features keenly observed narratives, maps and charts of the continent’s growing gas market, both internally and externally, offering both financing investors and technical solutions providers the tools to navigate the opportunity landscape.

March 2017 will witness the release of The African Independent Annual, our yearly take on the emerging African Independent company. This species of the African business entity has evolved in significant ways since its earliest incarnation in the 1970s.

The African Independent, like Angola’s Somoil, Nigeria’s Seplator Ethiopia’s Southwest Energy, is not the same as an Independent focused on Africa, like Cairn or Tullow. Because we don’t want to get it twisted, we have a separate edition, coming up in May, entitled Independents’ Day, which looks at the fortunes of the Kosmos, the Anadarkos, the Tullows, the Cairns, the Perencos, all such Western and non Western independents focused on Africa, in the past year.

Our April edition is the inaugural PETROLEUM PEOPLE issue. It’s an edition we are very proud of.

Each of our 12 editions in the year contains, apart from the main feature, our increasingly fine-tuned intelligence data, that enable our subscribers stay ahead of the competition.

Click here for fuller disclosure of the year’s offerings as well as our media pack.
Editor


Nigeria is one of the Highest Cost Producers of Crude-Draft Policy

By Toyin Akinosho

..Contradicts Minister’s Statement at Davos 2016

The draft Petroleum Policy for Nigeria, which is currently being debated by stakeholders, has delivered a verdict that has been subject of whispers in the boardrooms until now.

“Nigeria is one of the highest cost of extraction oil provinces in the world, estimated at $29/bbl, “says the 115page document on its 15th page.

“Nigeria has to substantially reduce the costs of production if the country is to be competitive in the modern low oil price world, and if it is to have anything more than a bare minimum government take,” the draft advises.

According to the document, Nigeria is only less expensive, as a cost per barrel producer, than Brazil and UK, in a 12 country ranking that includes Saudi Arabia, Iran, Iraq, Russia, Indonesia, Norway, US Non Shale, US Shale, Canada and Venezuela.

The cost ranking, pulled out of a U Cube analysis by Rystad Energy, the Norwegian consulting firm, doesn’t indicate whether this was an average of a basket that includes crudes from deepwater, shallow water and onshore terrains. Which is significant, especially as it features different figures for US Shale:$23.35/bbl and US Non Shale: $20.99/bbl.

What it does, however, is that it breaks down the cost structure for Nigeria as follows: Gross taxes: $4.11, Capital Spending: $13.10; Production costs: $8.81 and Admin/transport costs: $2.97.

This statement on cost by the Petroleum Policy Team at the Ministry of Petroleum contradicts the Minister of State’s January 2016 statement that Nigeria would still make profit if crude oil prices averaged $20/bbl.

Mr. IbeKachikwu caused a stir around the oil industry in the country when, at a meeting a year ago in Davos Switzerland, he declared that cost of producing a barrel of crude oil onshore Nigeria was less than $13.

“The deep off-shore projects, obviously we are putting on hold, given the fact that the returns on those, would not match the prices today,” Kachikwu said at the World Economic Forum. “Everybody is sort of coming back on land so this is time to put a lot of investments on ground, put a lot of incentives on ground, make everybody return on ground, where in fact our average cost of production is about $13 per barrel. So we need more on that, bringing those numbers down from $13 to somewhere $10. Obviously we won’t get the Saudi figures of about $6 or $7, but we can get it much lower,” he said.

His remarks made industry analysts scramble for their fiscal modeling templates, and not a few shook their heads in horror. Now Mr. Kachikwu’s ministry is passing round a document which declares that the average cost of extraction in the country is $29/bbl.


GE Will Build Its Calabar Plant, In Spite of Delays on Bonga South West

By Fred Akanni, in Lagos

General Electric (GE) says it will go ahead and complete construction of its Calabar Manufacturing Facility despite the fact that Bonga South West-Aparo (BSWAP), the deepwater oilfield project for which it was primarily conceived, has been put on hold.

Ado Oseragbaje, President and CEO of GE Oil and Gas Subsaharan Africa, acknowledges that the non-taking of Final Investment Decision (FID) on BSWAP, has “challenged” the plans for a Manufacturing facility in Calabar.

He would not mention BSWAP by name but he says: “It is true that we had big ambitions from the oil and gas perspective but with some of the delays that some of our customers are facing, that kind of challenged the project”.

“Having said that, overall, we are an industrial company and one of the things we are already doing is ensuring that the facility will be able to support the different GE businesses”.

“Let’s say that the whole thing was initially going to be 1000sqm and if oil and gas was initially supposed to use 600sqm but if they can’t, can we redeploy some of the space to power services or to transportation. We are committed to making that huge investment and it is still ongoing. Our contractor is still working on site”.

Oseragbaje won’t disclose a timeline to the inauguration “but there is a project team that is responsible for delivering the project on time and on budget. Overall, in our long term strategy for Nigeria, the Calabar facility is part of our thinking both as GE and the oil and gas division”.


TOTAL’s Block 17 Delivers Close to 700,000BOPD In Angola

By Toyin Akinosho, Publisher

BP in vigorous challenge for the top spot.

TOTAL operated Block 17 offshore Angola produced 661,795 Barrels of oil per day between January and September 2016.

It’s the most productive oil block anywhere in Africa.

The volume is over a third of the country’s 1.766Million barrels per day in the 274 day period, figures from the Ministry of Finance show. The performance of this prolific block leaves, in the dust, ExxonMobil operated Block 15, the second place producer, which came up with 314,847BOPD.

Although Angola is largely a deepwater producer, the third largest output comes from Chevron operated shallow water Block O, which output 235,440BOPD during the period.

There are 13 producing blocks in the southwest African country, but only six of them produce higher than 100,000BOPD.
TOTAL looks set for continuous dominance of the Angolan crude oil production scene in the near term, with the 230,000BOPD Kaombo project under construction in the ultra deepwater Block 32. The company holds 30% in the block and the field is expected onstream in 2017.

BP’s Challenge, A Distant Call?

It would seem, from these figures, that TOTAL is the company with the highest headroom, in the short term, to grow in Angola, but BP comes very close in terms of equity production. In the January to September 2016 data, the British major netted 310,417BOPD, coming a close second to TOTAL’s net of 322,047BOPD. BP announced, last December, that it was working on growing its equity production in the country to 480,000BOPD by 2020.

BP, however doesn’t have any field development project in view between now and 2020, going by data published by the US Energy Information Administration (EIA). Nor does it publish anyone on its own. So the best guess would be incremental increase in Blocks 18 and 31 as well as expected top-up in volumes from its non-operated equity in Block 15 and Block 17. BP operates exploratory Blocks 19 and 24 and holds non-operated positions in Blocks 20, 24 and 25. Out of all these, only the Cobalt Energy operated Block 20 has shown any real promise of becoming a producer.

Even so, with its signature Cameia discovery not yet sanctioned it is no longer looking like Block 20 can come on stream by 2020. Block 24 has a commercial discovery which is yet unappraised. The well in Block 19 was non-commercial, the one in Block 25 was an outright duster.


Reservoir Producibility Challenges Kenya’s First Oil Ambition

By Toyin Akinosho

Tullow Oil is having challenges of producing the waxy crude in the reservoirs of its operated oil wells onshore Kenya.
There are flow assurance and producibility issues in extracting the crude from the reservoirs, with water injection process experiencing obstacles, according to oil service sources close to the project.

Faced with a government insistence on commencing crude oil export by 2017, Tullow has been working up ways of extracting the hydrocarbon at a cost that is economically feasible, given the low price environment.

The London listed explorer only made Kenya’s first commercial discovery in in April 2012, in the very year that crude oil prices started heading south, but President Uhuru Kenyatta’s government, in power since 2013, is keen on first oil to happen before the next elections in August 2017.

Plans for a joint Kenya-Uganda crude oil pipeline from oil fields in both countries to Kenya’s Indian Ocean port at Lamu or Mombassa went up in smoke when the Ugandans decided on an alternative route through Tanzania in early 2016.

Kenya has since chosen to start small, producing 2,000Barrels of oil Per Day and trucking the crude from the oil fields in Turkana county, in the north of the country to the coast in the south for export, as the country’s refinery is not designed for the sort of crude that is trapped in the geological formations. Andrew Kamau, Permanent Secretary in the Ministry of Energy, says that the Early Oil Pilot Scheme (EOPS), will specifically utilise five existing wells to produce the crude, which will be transported from Turkana to Mombasa by road in insulated tanktainers. “At current oil prices, EOPS is not expected to generate significant revenue”. Mr.Kamau says.

The crude type in East African rift system (South Sudan, Uganda and Kenya) is like a long candle in the pipeline and has to be heated along the way.

“But It’s not just the evacuation infrastructure that is constrained, crude oil extraction at the reservoir level in Kenya has had to be studied extensively”, sources explain. “There has been water injection (meant to drive up the crude into the surface) that ended up damaging the formation”, the sources, who choose not to be named, disclose. “There are issues of what chemicals to use in the stimulating the upward flow of the crude”.

“Subsurface challenges are common in field development”, says Tim O’Hanlon, Tullow’s Vice President for Africa responded when Africa Oil+Gas Report asked him about the issue. “Whatever this issue is, we are dealing with it”.

Tullow has had prior experience in Africa in getting crude out from the subsurface to the surface. Ghana’s Jubilee field didn’t deliver anywhere close to its optimum in the first 18 months because of faulty design of the well completion jobs. But the challenges in Kenya’s oil reservoirs are different from the Ghanaian experience. Before a process like water injection happens, the completion infrastructure would have been installed.

Editor’s note: an earlier version of this report, published in the October 2016 edition of the monthly issue of the Africa Oil+Gas Report, did not contain Mr. Tim O’Hanlon’s views.


Don’t Blame Shell For Everything, Spokesman Laments

Precious Okolobo, media relations manager for Shell Companies in Nigeria, has responded to the persistent fingering of the Anglo Dutch company for just about any environmental hazard in the Niger Delta region.

“SPDC should not be blamed for everything that goes wrong,” Okolobo declared in the last week of 2016, in a response to the allegations of adverse impact of the Gbaran Gas Processing Plant, located in Gbarantoru, Tombia in Nigeria’s Bayelsa State.
The latest name calling had come from a certain Alagoa Morris, described by the press as an environmentalist, requesting for a scientific study on pollution from the plant, which, at 1Billion cubic feet per day capacity, is Shell’s largest processor of natural gas in Nigeria.

The government owned News Agency of Nigeria NAN reported that Morris “made the call in Tombia, near Yenagoa, shortly after an assessment tour of the area”.

NAN said that “Morris was reacting to reports of suspected air pollution from the natural gas gathering and liquefaction facility which is causing breathing discomfort to residents”.

NAN reported that residents of Tombia were complaining of air pollution, allegedly emanating from oil and gas facilities located near the community. “We have received reports of air pollution, very high temperature caused by gas flare and poor fish catch from the Nun River, among others”, Morris reportedly observed. “Who monitors compliance with the EIA to ensure that the steps prescribed to mitigate the negative environmental impacts of the operations of the plant were ameliorated?”, Morris reportedly queried, adding that the country’s environmental law “requires periodic study to determine the environmental implications of the project and ascertain when the indices are out of tolerable limit”.

The NAN report disclosed that Shell’s spokesperson Precious Okolobo, denied that the air pollution was from the company’s gas processing and gathering facility.

“There is no air pollution from our Gbarantoru plant; the plant is running efficiently,” Okolobo reportedly said. “He said that a similar occurrence was reported in Port Harcourt where there was no gas plant”, NAN said of Okolobo.
“There is a general problem that people do not understand and SPDC should not be blamed for everything that goes wrong,” Okolobo said.

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