All posts tagged gas


Africa E&P Virtual Summit: Africa’s Online Oil, Gas & Energy Event

Don’t miss Africa’s only real online oil, gas & energy event of the year! A real conference & expo, with real networking – the Africa E&P Virtual Summit will deliver the best opportunity of 2020 to connect with Africa’s oil and gas leaders, governments & decision makers. Namibia, Liberia and Ghana are set to share their latest and most exciting oil and gas developments in a series of dedicated roundtable discussions, showcasing hydrocarbon potentials and investment opportunities. You will also hear from 50 industry leaders who will deliver quality content on Africa’s petroleum sector through sessions and main-stage keynotes. Day 1 will end with an interactive wine tasting event, live from Cape Town, where you can make the most of the platform’s networking functions. The closing ceremony of the Africa E&P Virtual Summit will end with Frontier’s renown Big Five Board Awards, which will be presented by the winner of last year’s Africa Oil Legend Award, Patrick Pouyanné, CEO & Chairman of Total.

Africa E&P Virtual Summit delivers…
• 7 Governments and 50 Speakers Now Confirmed
• Liberia Harper Basin License Round Update
• Face-to-Face Networking within Africa’s oil and gas community
• One-to-One Business Meetings
• Africa Oil and Gas License Round Promotions
• Access to Virtual Exhibition
• Interactions with Clients
• Access to Private Meeting Rooms
• Round Table Discussions

See the full agenda and book tickets >> https://www.frontierenergy.network/africa-ep-virtual-summit-2020-overview
(Governments & NOC’s can use discount code ** 50gOvUp ** at checkout)


Petroci in League with Sahara for a $43Million LPG Project

Sahara Energy Logistics Holding Limited (A Sahara Group company) and  Société Nationale d’Opérations Pétrolières de la Cote d’Ivoire (The National Oil Company of Cote d’ivoire, Petroci Holding), have entered into a Joint Venture Agreement (JVA) to facilitate the construction of a 12,000 Metric Tonnes Liquefied Petroleum Gas (LPG) storage facility to guarantee LPG supply security in the nation.

The cost of the project is estimated at $43Million and will be executed in two phases, with commissioning scheduled for November 2021 and October 2022 respectively.

Incorporated as SAPET Energy S.A., the joint venture company will handle the construction, operation, and maintenance of the ultra-modern LPG storage terminal. “Upon completion, the facility will become the largest of its kind is Sub-Saharan Africa”, Sahara’s spokesman, Bethel Obioma, claims in a release, “and more importantly, support the government’s efforts to meet Cote d’Ivoire’s growing LPG demand”.

The challenge with Obioma’s claim is that there are facilities with similar size in Nigeria currently and a raft of construction of larger sized LPG terminals in the country, is on course for commencement before the end of 2021.

However, Ibrahima Diaby, Director General, Petroci, said of the SAPET project: “this joint venture project is the first of its kind in Cote d’Ivoire and will serve as a model for other projects in the energy sector. It is a historic event that will pave the way for a robust and seamless storage, distribution, and supply of LPG. This translates to more clean energy, growth, and productivity in Cote d’Ivoire. We are delighted and look forward to more collaboration with Sahara Energy.”

“We are excited about the project and the huge opportunity it will confer on Cote d’ Ivoire as the leading LPG hub in the sub-region”, commented Olayemi Odutola, Country Manager, Sahara Energy.

 


Agreement Signed: Construction of East Africa Crude Oil Pipeline to Start in 2021

The Uganda government and TOTAL E&P, the French oil supermajor, have moved rapidly towards common ground on the country’s oilfield project, with both inking an agreement that paves the way for a final investment decision (FID) on the 230,000Barrels of Oil Per Day (BOPD) development.

Yoweri Museveni, President of Uganda and Patrick Pouyanné, chairman and CEO of TOTAL, signed the Host Government Agreement (HGA) for the East Africa Crude Oil Pipeline (EACOP) project. The meeting was held at the Ugandan State House, in Entebbe last Friday, September 11, 2020.

The two parties agreed on the participation of the Uganda National Oil Company (UNOC) in the EACOP as well as on governance issues around the benefits, to Host Governments from the export pipeline in Uganda. The project is expected to cost the consortium $3.5Billion, with construction expected to start early next year, a government statement declared.

The Host Government Agreement aims to ensure that both countries (Uganda and Tanzania) fully benefit from the project in the course of transportation of the crude to the international market. The Host Government Agreement will govern the construction and operation of the crude oil pipeline from Hoima, the Ugandan oil rich district, to Tanja, the Tanzanian port town from which the crude will be exported.

“We now look forward to concluding a similar agreement with the Government of Tanzania and to completing the tendering process for all major engineering, procurement and construction contracts,” said Pierre Jessua, managing director of TOTAL E&P Uganda.

Jessua said the conditions are set for the ramp-up of project activities and in particular, the land acquisition activities in Uganda.

TOTAL E&P Uganda is leading the development activities towards production in the Tilenga project area – Exploration Area1 (EA-1) and Exploration Area2 North(EA-2N) within the Albertine Region.

 

 


Renergen’s Gas Well Fails at a Prime Position

A gas well being drilled by South African independent, Renergen, has collapsed at the very position the company considers most efficient and cost effective.

The well had been on a horizontal course, but Renergen had moved the trajectory on inclined drilling through the sandstone sequence to intersect the underlying faults in the underlying volcanic rock.

But the base assembly was lost before breaking through the base of the Karoo sedimentary rock and the company decided it best to abandon the well. Renergen has thus, again, revised the drilling programme and has also secured a directional drilling rig.

The dual listed Renergen (JSE, ASX) is the only active South African independent in exploration and production of hydrocarbon. Its Virginia Gas Project covers 187,000 hectares of gas fields across Welkom, Virginia and Theunissen, in the country’s Free State.

The asset holds both natural gas and helium. Renergen currently sells compressed natural gas (CNG) from the hub, but following a plant expansion planned for completion in 2021, Renergen will instead produce liquified natural gas (LNG).

Earlier in the course of the drilling, the company reported “strong gas flows with high (up to 12%) helium”, and announced that technical issues had necessitated significant changes from the original horizontal well design. It also said that the sections penetrated by several side-tracks had provided valuable encouraging data for future development drilling. The company noted, then, that the key learnings from the drilling were as follows:

  • The gas is migrating up through two major fault structures, named 2089 and 2057, which have a combined known strike length of approximately 31 kilometres
  • The gas emanating from the faults contains helium of up to 12%, and not the anticipated lower concentration (~3%). It was previously postulated that high helium (11%) in an earlier well at this site was a result of helium dissociation in the overlying sandstone reservoir
  • The sandstone is stratified with siltstone, and some coal, such that the zones of high porosity and permeability cannot be accessed efficiently with horizontal drilling.

It was the inclined trajectory chosen after these “key learnings” that has now been compromised by the failure of the rig.

“It is unfortunate that the drilling rod broke”, commented Renergen ‘s CEO Stefano Morani, “but unfortunately accidents happen beyond anyone’s control. The silver lining is that it resulted in us gaining access to a fit-for-purpose directional drilling rig, which means we will be able to drill with far greater confidence and speed.”

“Where we were drilling one before, now we have multiple targets being drilled concurrently, and in some highly prospective areas where indications of gas are strong, and no exploration drilling has been undertaken to date,” he explained.

 


The Namibian Government Would Neither Guarantee, Nor Invest A Cent in Kudu Gas Development

By Toyin Akinosho, Publisher

The Namibian government insists it does not want to ether invest, or give any form of guarantee for the Kudu gas field development.

Not even when it is meant to generate power for the country.

It is official.

This point was reiterated several times over at a recent webinar on the country’s energy strategy.

Tom Alweendo, Namibia’s minister of Mines and Energy, told the webinar, organized by Africa Energy Chamber: “the government was required to put in as either capital or certain physical concession, but unfortunately, given our situation, we are not able to do that. And what we have agreed to do is to say, can we find another way to actually develop that field using another business model in such a way that the government is not necessarily involved in that”?

The comment, versions of which Mr. Alweendo has made on other platforms over the last two years, keeps being surprising, considering that natural gas inflow into an economy, more than anything else, energises it, as industrial clusters, as a rule, generally grow around processed gas.

The current business model the Minister referred to is the plan to process a fraction of the 1.3Trillion standard cubic feet of gas in the field, use it to generate 475 MW per day of electricity, supply some power to Namibia and export some.

The Namibian government has prioritized renewables over Kudu Gas to power and NAMPOWER, the power utility, does not include the project in its Five-Year Strategic Plan. It’s okay to do renewables, but what is the planned growth of electricity to be injected in the Namibian economy? Around 1 Million Namibians lack access to electricity, which means that almost half of the country is without access at all (~53% has access & ~47% has no access). These are World Bank 2019 figures. You have a meagre population of a 2.4 Million people and you can’t even provide them electricity.

Why? A lack of industrial mindset of considerable scale.

The state is saying that it doesn’t need the electricity from Kudu, but countries that have experienced significant degree of industrialization are known to have favoured availing their citizens far more electricity power than the economy demanded. Eskom of South Africa was one such example, long before it lost its way in the profligate corruption of the Jacob Zuma years.

In Namibia, no new investment has been made on sizeable generation of electricity in the last 30 years.

THE NORWEGIAN COMPANY BW Offshore concluded its farm in into the Kudu field acreage in February 2017, taking a 56% stake, with the state hydrocarbon company NAMCOR holding a 44% stake in the upstream and midstream segments of the project. The state power utility NAMPOWER, with its partners, will install the power plant, offtake the gas and convert it to electricity. But neither state owned enterprise has been able to get hold of their share of financing the project because the government is not keen.

NAMCOR was hoping that BW Offshore would carry it by paying its 44%, after the ministerial consent had been granted. But that did not happen. Further downstream, NAMPOWER is challenged in raising finance for its 51% share of the power generation side of the project.

The invoice for the Kudu Power Station in 2016, was about $749Million of which 75% would be raised as debt (limited recourse). The gas field development was expected to cost $1.15illion (70:30 debt/equity). The entire funding to get the project started was slightly less than $2Billion, although it’s not clear now what the cost will be, in the light of the current Pandemic induced crisis which has forced down the cost of EPC contracts.

Again, Kudu is not only about electricity. Access to natural gas has been known to benefit economies.

Mr. Alweendo is not interested. And the Namibian government is not prepared to do any thinking on its own around the development. “We haven’t had a formal engagement (with BW) as yet since last year(2019)  to see how far did we get to see if we can take if off the ground”, he told the webinar. “But certainly, I still think it is a potential development that can be carried out and the economic potential and the economic benefit coming from that is so immense and therefore, as a government, we will still want to see that happening but we just need to come up with a different business model than the one which was actually grafted earlier”.

This story was originally published in the June 2020 edition of the monthly, Africa Oil+Gas Report


Jet Fuel Demand Will Be Harder Hit Than Other Premium Fuels

The economic crisis caused by COVID-19 is hitting Jet Fuels far much more than it does Road Fuels.

Total global demand for road fuels will fall by 10.1% in 2020, or by 4.8MillionBPD year-on-year. The Rystad estimates Road fuel demand in 2019 to have been 47.4MillionBPD. It now sees this number dropping to about 42.6MillionBPD in 2020.

But the Norwegian conslutancy expects jet fuel will be hit the hardest. We expect global commercial air traffic will fall by at least 51% this year versus the levels seen in 2019, which we estimate stood at around 99,700 flights per day. For 2021, we expect around 76,800 flights per day. These numbers will be revised as operators continue to cut routes.

Many distressed airlines are facing heavy cost cuts and are laying off unprecedented numbers of employees as many non-essential routes are closed.

As a base case we now assume that the common summer air travel peak will not occur at all this year. We see global jet fuel demand falling by almost 41.4% year-on-year, or by at least 3MillionBPD. Last year’s demand for jet fuel was about 7.2MillionBPD.

Jet fuel demand in April was as low as 2.9 MillionBPD, and shrank further to 2.8Million BPD in May 2020.

In 2021, jet fuel demand is expected to average 6.1MillionBPD


Recovery of US Gasoline Demand Stalls..Will Affect Crude Prices – IHS Markit

Demand fell back during last full week of August resulting in volumes for the month down 18% compared to last year

The recovery in U.S. gasoline consumption has plateaued as the summer driving season comes to an end and the school year begins for wide swaths of the country.

Latest data by OPIS, an IHS Markit (NYSE: INFO) company shows that demand actually fell 1.9% during the last full week of August from the previous week. The four-week rolling average for the period ending August 29th now shows demand resting at 18.2% below prior year levels.

U.S. gasoline sales had improved rapidly from May to early July following the collapse in early April that came with the national shutdown, when sales were 50% below prior year levels. But the recovery had begun to sputter even before demand slipped backwards in that final week of August.

“The plateauing in demand is a symptom of the continuing aggressiveness of the coronavirus and is telling us that it will take longer to get back to normal,” said Daniel Yergin, vice chairman, IHS Markit and author of The New Map.

The most recent OPIS survey now suggests that the post-COVID peak for U.S. volumes occurred during the week ending August 15th at 7.844 million barrels per day—15.4% below prior year levels.

The coming months typically bring a seasonal reduction in demand from the high points of the summer driving season. For the years 2017-2019 the average drop in U.S. gasoline demand from August to October has been on the order of 5 to 10%.

“Aside from the potential for a short-lived bump in demand from the Labor Day weekend, history suggests that the end of the U.S. driving season inevitably brings lower demand for gasoline thanks to shorter days, less vacations and more inclement weather,” said Fred Rozell, president of OPIS. “Now that those prime driving days are behind us, we are likely to settle into a prolonged pause in the demand recovery.”

OPIS DemandPro tracks actual weekly same-store gasoline consumption volumes at over 15,000 stations, aggregated on a national, regional and state level. This allows users to track and benchmark industry trends for overall retail gasoline sales.

The OPIS survey—tracking actual gallons out of retail stations—shows greater demand losses than recent figures reported by the Energy Information Administration (EIA) on account of different methodology, that EIA measures movement of gasoline from primary stocks rather than actual consumption at stations.

The latest OPIS report for the week of August 29th shows demand losses in every portion of the country over the prior year period.

  • The Mid-Continent region posted the most moderate decline, down 17.44%
  • The Southeast registered the sharpest declines, down 27.1%, but that was due to big volumes last year due to pre-hurricane buying. Florida showed an even larger year-on-year differential of 35% for the same reason.
  • The Pacific Coast was off 24.4%. Year-on-year through-puts in the region never got better than 20% off from 2019 levels.
  • The Northeast had seen its year-on-year consumption differential whittle down to within 16% of 2019 levels, but the past two weeks were weaker, and the gap widened back to 20% this past week.

“The data points to a challenging environment for refiners and marketers in the remainder of 2020,” Rozell said. “Cheap gas prices relative to the past 16 years will help curb some of the demand destruction, but retailers will have to adjust to shifting habits as consumers likely make fewer visits to traditional stations for fill-ups in favor of more ‘aggregated trips’ to supermarkets and big boxes chains that also sell fuel.”

OPIS DemandPro updates gasoline retail sales every week.

 


Kenya Reduces Electricity Outages by 50% in Four Years

Kenya’s Ministry of Energy says that the average time customers are shut out of power supply per month has reduced from four hours per month in 2016 to one hour, 40 minutes in 2020.

Response time to outages has also improved, the data says. Over the same period, the number of hours, on average, that customers are cut off supply to fix power lines has dropped from seven to four.

These numbers concern the segment of the population that are connected to publicly generated electricity.

Kenya has a population of 48 Million people, according to 2019 data from the country’s National Bureau of Statistics. A 2019 International Energy Agency (IEA) report says that 75% of Kenyans have access to electricity.  It also says that over 95% of urban dwelling Kenyans have access, but 66% of rural Kenyans have access.

Kenya’s current effective installed (grid connected) electricity capacity is 2,651 MW, with peak demand of 1,912 MW, as of November 2019. At that time, demand was rising at a calculated rate of 3.6% annually, given that peak demand was 1,770 MW, at the beginning of 2018.

It’s curious how 75% of 48 Million people, which is 36Million, could find less than 2,000MW of electricity generation adequate.

But just five years ago, only 41% of the Kenyan population had access to electricity, according to the IEA report.

Charles Keter, Kenya’s Energy Cabinet Secretary, says the country has invested in measures to reduce power outages and is looking to have a utility that assures its customers of reliable power in the next few years.

The Energy ministry claims that Kenya Power has invested some $645Million improving its distribution infrastructure by constructing new substations and undergrounding of power lines to reduce interferences that cause outages.

 

 


Tullow Reports $1.3Billion Half Year Loss, Talks Up Ghanaian Asset

London listed Tullow Oil has reported a post-tax loss of $1.3Billion in the Half Year, between January 1 and June 30, 2020.

The company’s revenue was $731Million during the period, with gross profit of $164Million.

Tullow said that the loss after tax was driven by exploration write-offs and impairments totalling $1.4Billion pre-tax. Net debt as of June 30 2020 was $3illion; Gearing of 3.0x net debt/EBITDAX; liquidity headroom and free cash of $0.5Billion.

The best performing asset in Tullow’s portfolio remains Ghana’s Jubilee field and TEN cluster of fields. Tullow talks of “strong operational performance”, of those assets in 1H 2020, with “both FPSOs delivering in excess of 95 per cent uptime.”

The Ntomme-09 production well came on stream in August and is incrementally adding c.5,000BOPD gross to TEN oil production.

Tullow’s report talks of maximizing gas offtake nominations from both Jubilee and TEN, in order to “focus on continuous improvement to maintain FPSO uptime in excess of 95%”.

The company has been working on restructuring its business since the sharp plunge in its stock rice in December 2019 led to significant leadership changes.

The current CEO, Rahul Dhir who took charge in July 2020, has commissioned a comprehensive review of Tullow’s portfolio, growth prospects and capital structure. “Once this review is complete, and its conclusions have been fully validated, the Group will hold a Capital Markets Day (CMD) before the end of the year. At this CMD, Rahul Dhir and other senior leaders will lay out their plans for Tullow’s business and assets and demonstrate how they will unlock material value from the portfolio”.

 

 

 


Kosmos Farms Down in Namibia and South Africa

Kosmos Energy has agreed to sell its interests to Shell in Namibia, Sao Tome and South Africa

These African positions are part of a portfolio of frontier exploration assets that the Dallas based minnow agreed to sell to the AngloDutch major for approximately $100Million, plus future contingent payments of up to $100Million.

Kosmos’ asset in Suriname is the only non-African property on the list.

Under the terms of the agreement, Shell will acquire Kosmos’ participating interest in blocks offshore São Tomé & Príncipe, Suriname, Namibia, and South Africa , Kosmos says in a release. The consideration consists of an upfront cash payment of approximately $100Million, plus contingent payments of $50Million payable upon each commercial discovery from the first four exploration wells drilled across the Assets, capped at $100Million in aggregate. Three of the four wells are currently planned for 2021.

Kosmos plans to use up to one-third of the initial proceeds to test two high-quality infrastructure-led exploration prospects in the Gulf of Mexico, each offering hub scale potential with a low-cost, lower-carbon development scheme. The company expects to use the remainder of the proceeds to reduce borrowings outstanding under its credit facilities.

Post completion of the transaction, Kosmos retains a focused exploration portfolio with over six billion barrels of gross resource potential in the Gulf of Mexico and West Africa.  Kosmos also expects to realize approximately $125Million in total savings across capital expenditures and general and administrative expenses over the next two years as a result of the transaction.

 

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