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U.S. Insures ‘Troubled’ Israel –Egypt Gas Pipeline

By Toyin Akinosho

The United States has committed to back Noble Energy, a US independent, with $430Million worth of insurance to restore the 90-kilometre, 26 inch, East Mediterranean Gas (EMG) Pipeline, running from the coastal city of Ashkelon, Israel and under the Mediterranean Sea to its destination in Al-Arish, Egypt.

The pipeline supplied natural gas from Egypt to Israel for four years, from 2008, under terms agreed on the back of the countries’ 1979 accord. Egypt also supplied gas to Jordan from a tie in to the same pipeline. But the facility became a main target of saboteurs in the days of the Egyptian democracy uprising and the blow ups were so frequent that Israel’s infrastructure minister said the attacks were proof the country needed an alternative to Egyptian gas.

Egypt officially stopped supplying gas to Israel in 2012. The Zionist state, by strokes of luck, discovered large volumes of the molecules under its own seabed around the same time (Leviathan, 2010, Tamar, 2012).

The physical capacity of the Arish-Ashkelon pipeline is 250Billion cubic feet of gas per year, (roughly 700Million standard cubic feet a day) although technical upgrades can increase its capacity to a total of 850MMscf/d.

Now, the deal is that Noble Energy, which operates the new gas fields discovered in Israel, will pump the gas into the pipeline in a reverse direction, onward to Europe and other global markets.

The insurance contracts were signed with the U.S. International Development Finance Corporation (DFC) after Noble Energy and its partners achieved financial close for the project.

The $430Million in insurance commits to rehabilitating the EMG pipeline and transporting natural gas from fields offshore in Israel. Under the terms of the project, the gas will be purchased by Dolphinus Holdings, a gas trading company.

“The Dolphinus gas sales contracts and the EMG acquisition underpin delivery of natural gas from the Tamar and Leviathan fields in Israel into Egypt and represent a major milestone toward Egypt’s goal of becoming a regional energy hub. Both these transactions and the support from the U.S. Government provide further confidence in the long-term export market and growing cash flow from these premier assets,” said J. Keith Elliott, Noble Energy’s Senior Vice President, Offshore.

These transactions were originally approved by the Overseas Private Investment Corporation’s (OPIC) Board of Directors in December 2018. DFC is a new U.S. Government agency that combines and modernizes OPIC and USAID’s Development Credit Authority (DCA). With a more than doubled investment cap of $60Billion and new financial tools, DFC is equipped to more effectively mobilize private sector capital to urgent development challenges and advance U.S. foreign policy.


NDWestern Trounces Seplat in Gas Output for September 2019

Production from the latter has even dropped further, in October

The NPDC-NDWestern Joint Venture raced ahead of the NPDC-Seplat JV in natural gas utilisation for the month of September 2019, field records sighted by Africa Oil+Gas Report indicate.

In a reversal of trend, Seplat trailed behind NDWestern by around 30Million Standard cubic feet of gas per day (MMscf/d).

NPDC-NDWestern Joint Venture averaged 288MMscf/d compared with Seplat’s average gas utilisation of 258MMscf/d.

In the same month, NPDC operated Oredo field gas plant utilised 94MMscf/d, which fits a pattern of the last six months. But the NPDC/Neconde JV, which has reportedly installed two 40MMscf/d gas processing plant in the last one year, utilised less than 2MMscf/d from its fields.

NPDC-NDWestern and NPDC-Seplat JVs are the largest indigenous Nigerian natural gas producers for the domestic market. But they each trail behind the NNPC/Chevron JV, the original contributor of gas to the Escravos-Lagos Gas Pipeline System (ELPS), the nereve of the country’s gas transmission system.

Seplat has gas processing capacity of 525MMscf/d in its Western Niger Delta Assets and it is planning to build 300MMscf/d capacity in the eastern Niger Delta. NPDC sources attribute the company’s declining production to fluctuating offtake by customers, mostly Nigerian power plants.

Seplat continued the low gas output trend in October, averaging even less than September output, at around 235MMscf/d.

 


S. A Fiddles While Gas Burns

By Toyin Akinosho

In late October 2019, the South African government published the long-awaited Integrated Resource Plan, or IRP, which seeks to chart the means by which the country will manage and meet its electricity needs leading up to the year 2040.

The plan provides insight into the state’s 20-year approach to SA’s energy mix.

IRP 2019 envisages, among other energy types, some 1 000 MW of Gas To Power capacity being introduced into the South African grid by 2024, with a further 2 000 MW to be added by 2027

We have been here before.

Assigning a figure for proposed electrical power expected to be generated by natural gas in the energy plan does not begin to address the possibility of gas based industrialisation in South Africa.

For a country with such an absorptive capacity, a significant flow of gas into the economy is a compelling case against the forces of de-industrialisation, banging hard at the gates.

But the business/political elite has to have the appropriate mind-set to construct a system of opportunities to allow gas to flow in.

The absence of a framework for gas intake and utilisation is a core reason for the looming shutdown of the state run Gas to Liquid (GTL) plant which, at inception, was the largest such plant in the world.

The absence of a coherent guidance on gas to industry is why Sasol’s importation of (currently about) 400Million standard cubic feet of gas a day does not come across as a leverage factor for what the country can do with gas.

What has South Africa done to pump up its economy with natural gas? What has she done?

Find out the details in this Kick-starter piece in the October 2019 edition of the Africa Oil+Gas Report

 


Chevron Signs Second Gas Sale Agreement in Seven Months

Chevron Nigeria Limited, operator of the NNPC-Chevron Nigeria Limited Joint Venture (NNPC/CNL JV), has signed a gas sale and aggregation agreement with Olorunsogo Generation Company Limited, Niger Delta Power Holding Company Limited and Gas Aggregation Company Nigeria Limited.

It is the second time the American major would be signing a Gas Sales Agreement with a company that would use the gas in the Nigerian economy.

Last March, Chevron, which operates the NNPC/Chevron Joint Venture, signed a 75MMscf/d Sales Agreement with Dangote Fertiliser. The new agreement with NDPHC, will enable the company to supply on an interruptible basis, a daily contract quantity of up to 63Million standard cubic feet a day (63MMscf/d) of natural gas to Olorunsogo Generation Company Limited.

The Olorunsogo generation plant in Ogun State is an existing NDPHC electricity generation project designed to supply power of about 750MW into the national grid. “Natural gas is the feedstock of the Olorunsogo generation plant. The GSAA for the supply of the major input needed to run the power generation plant is another demonstration of the NNPC/CNL JV’s commitment to the domestic gas market,” explains Esimaje Brikinn, Chevron Nigeria’s General Manager, Policy Government and Public Affairs.

Sanjay Narasimhalu, Director, Chevron Nigeria’s Downstream Gas claims that  NNPC/CNL JV was currently the largest and most on-spec supplier of gas to the domestic market. “The JV continues to collaborate extensively with other stakeholders in finding creative solutions to issues relating to the domestic gas market”, he says.


Frontier Oil Gives Up on Uquo Gas, Now Focuses on Liquids

Frontier Oil, the Nigerian minnow known primarily for developing a gas field and advocating a robust domestic gas market, has given up on that business for now.

The company has handed over monetization of the gas in the Uquo field in south eastern Nigeria, to Savannah Petroleum, in the ongoing process of the latter taking over the bankrupt Seven Energy Limited.

Final long-form documentation has been signed by Frontier Oil Limited, Seven Uquo Gas Limited SUGL and Accugas Limited (both now part of Savannah Petroleum) in relation to the restructuring of economic ownership interests at the Uquo marginal field and the operatorship of the Uquo gas central processing facility (Uquo CPF) .

“The Frontier Transaction will result in SUGL assuming responsibility for all operations (including production) of the gas project at the Uquo marginal field (including, inter alia, control of gas-related capital investment projects, design and implementation of operations and production plans, as well as day to day gas operations at the Uquo gas field) and will retain 100% of the revenue from gas sales”., Savannah Petroleum says in a statement

Frontier Oil’s founder and Chief Executive, Dada Thomas, is a passionate advocate for a robust Nigerian market. His passion drove him to become the President of the Nigerian Gas Association, the highest, private sector advocacy group for the country’s gas market.

But as Thomas spoke on podium after podium, his company got caught up in the liquidity crisis of the Nigerian electricity industry. Frontier struggled with getting paid for gas sold to Nigerian state energy firms, including the Akwa Ibom State owned Ibom Power and the Federal Government owned Calabar IPP plant.

In the deal signed with Savannah, Frontier will control all oil related activities in the Uquo Field and retain 100% of revenue from oil sales. Operatorship of the Uquo CPF will be transferred to Accugas. Following completion of the Frontier Transaction, the Enlarged Group will have effective operational control of the Uquo gas supply chain. The Frontier Transaction is conditional upon completion of the wider Seven Energy Transaction, and is expected to occur following Transaction completion.

“The signature of the Frontier Transaction documentation represents the achievement of one of the final remaining milestones to be reached as we move towards completion of the Seven Energy Transaction”, says Andrew Knott, CEO of Savannah Petroleum: “The Frontier Transaction is of strategic significance, affording the Enlarged Group increased operational control across the gas value chain and enabling us to maximise value from the Uquo gas field..”

 

 


Africa’s Largest Gas Field Threatens Even More Output

The giant Zohr cannot be reined in

The giant massif contained Zohr field in the Mediterranean offshore Egypt is threatening to surpass its 2.7Billion standard cubic feet per day mark, its handlers are saying.

Luca De Caro, head of the IEOC Joint Venture, ENI’s partnership with Egypt’s state hydrocarbon company, says the 13 wells currently producing at the field will be surpass 3Bscf/d by the end of October, up from 2.7Bscf/d in August.

ENI discovered Zohr in the Sharouk concession in 2015, on the same acreage which Shell had held for 10 years before relinquishment.

The discovery affected the fortunes of Egypt, changing the country from a net importer of natural gas to a self sufficient consumer of natural gas with aspirations to be an exporter of natural gas again.

The company originally estimated that production would peak at 2.7Bscf/d, but, in consultation with the Egyptian government, it was agreed that output would rise above 3Bscf/d in 2019.

 

 


With Gas Reserves Confirmed in Bauchi, Who Needs an AKK Pipeline?

By the Editorial Board of the Africa Oil+Gas Report

If there is truly far more substantial natural gas reserves encountered in Kolmani-2 than was found in Kolmani-1, then there is a clear basis for a valourisation project targeted at gas supply to the commercial city of Kano, the ultimate terminus of the Ajaokuta-Abuja-Kaduna-Kano pipeline, AKK.

The Anglo Dutch major Shell reported 33Billion cubic feet of gas in one zone for the Kolmani-1 discovery in 1999.

NNPC has not provided any volumetric figures for the Kolmani River-2, the appraisal well it just drilled, but its statement about the probe is quite upbeat and the company did indicate that hydrocarbon was found in several levels.

It also says that Kolmani 2 is the first of a multi-well drilling campaign.

Should Kolmani be found to hold even just 500Bcf of gas, NNPC should be ready to commence a natural gas supply study project to ferry those molecules from Bauchi to Kaduna and Kano and therefore discard the $2.8Billion, 614 km project.

Some have suggested that discarding the expensive AKK pipeline would be too wrongheaded, considering that the project is already on course.

But the least the company can do for Nigeria’s sake is start evaluating the modification of the AKK project, now that there is clearer line of sight to hydrocabons in Nigeria’s geographic and political north.

NNPC has reported it had completed negotiations with Chinese Financiers to loan it the money for the AKK project, which will pump gas from the Niger Delta to the North of the country. But paying for that project has been a point of debate.

“What NNPC has done is to look at the entire receivables from gas flows from the existing pipelines today and used that to pledge in terms of the tariff”, says Emeka Okwuosa, Chief Executive of Oilserv, one of the contractors for the project.

So, even though the AKK is being called contractor financed, the state hydrocarbon company is essentially funding it and that has implications for the treasury.

We do know that pumping hydrocarbon from any point to another in pipelines managed by the NNPC or its subsidiaries is always riddled with inefficiency. And no one has said that the AKK was going to be managed by any entity other than this highly unaccountable state hydrocarbon company.

The Escravos Lagos Pipeline System is frequently sabotaged. A looping of the line (running a parallel line in order to double the throughput), has been under construction for seven years. The cost overruns ensuing from this kind of poor project management and what it does to the national treasury receipts never show up even in the most detailed reports of the Nigeria Extractive Industry Transparency Initiative (NEITI).

If we find natural gas in the north, should we not simply structure a north- north gas project to feed power plants and industries in the north and do away with expensive, long distance pipelines, the payment for which we are not entirely certain?

 


The Japanese Get Rovuma LNG

Japan is not only going to consume gas produced in Mozambique but its engineers will be leading the operations to extract the gas from the Indian Ocean.

The Japanese contractor, JGC Corp. unprecedentedly won the contract to develop the Rovuma liquefied natural-gas project in Mozambique, which is set to be the biggest-ever private investment in Africa.

JGC is leading a consortium including Fluor Corp. And Technip FMC Plc to develop the Rovuma LNG project, a 15.2Million Tonnes Per Annum (MMTPA) project which is operated by ExxonMobil. The invoice for the project is around $30Billion and is the priciest hydrocarbon valourisation project on the continent in the last 10 years.

The Rovuma LNG project will develop over 60Trillion cubic feet of reserves in the deepwater Area 4 block, offshore Mozambique.

But the final investment decision, earlier planned for second quarter of 2019, has been deferred to 2020, with first gas expected on stream in 2025.

 


ENI Opens the Tap in Egypt’s Baltim South West

Italian explorer ENI has started up production of the offshore Baltim South West gas field in Egypt.

It is another fast discovery to market by the aggressive operator.

ENI discovered the field in June 2016 and took Final Investment Decision (FID) in January 2018. Baltim South West thus comes on stream 39 months after discovery and 19 months after FID.

The field is located in shallow waters 12 kilometres off the Mediterranean coast of Egypt in the Baltim South development lease. It lies within the Great Nooros area, some 10km from the Nooros field, an area in which ENI says it “first recognised great gas production potential and where it is conducting other new exploration projects”.

With the start-up of the first well, BSW1, the field is now producing with an initial rate of 100 million standard cubic feet per day (scf/d) from a new offshore platform connected to the existing onshore Abu Madi Gas Plant through a new 44 km long, 26 inch diameter pipeline.

The development programme anticipates the drilling of further five wells with the objective of achieving a production target of 500Million scf/d by the second quarter of 2020. Volumes produced by Baltim South West will further contribute to Egypt’s natural gas export capacity. The overall gas potential from the Great Nooros Area is approximately 3Trillion cubic feet (Tcf) of gas in place, of which about 2Tcf are in the Nooros field and the remainder in Baltim South West.

ENI has a 50% interest, through its subsidiary IEOC, while BP holds the remaining 50% interest of the contractor’s stake in the Baltim South development lease. The project is executed by Petrobel, the Operating Company jointly held by Eni and the state corporation Egyptian General Petroleum Corporation (EGPC) on behalf of Medgas, jointly held by contractor (ENI and BP) and EGPC.

 

 


Mixed Signals from Tanzania’s Domestic Natural Gas Market

By Sully Manope, East Africa Correspondent

Indonesian owned, Paris listed operator, M&P, reported a sizeable drop in natural gas production in Tanzania for first half 2019.

But Orca Exploration says it had a surge in Natural gas deliveries from the Songo Songo gas project in the same country.

Each of the two companies operates one of the two key natural gas projects that feed Tanzania’s industries, power plants and factories.

M&P operates the Mnazi Bay project, which pumps gas directly into the 532 kilometre National Natural Gas pipeline and connects Mtwara, where the Mnazi Bay gas field is located in the south eastern region of the country with the commercial capital Dar es Salaam.
Orca Exploration operates a natural gas processing facility on Songo Songo Island, off the coast of southern Tanzania.

M&P says its natural gas production (gross) dropped 17% to 66.2Million standard cubic feet per day in first half 2019, from 77MMscf/d averaged in first half of 2018. It cites “a result of the lower demand for gas because of the early and heavy rainy season, which led to a marked increase in hydropower generation capacity at the expense of gas demand”

But Orca Exploration reports its own supply shot up by 68% to 56.6Million standard cubic feet per day (MMscf/d), year to year in the second quarter of 2019.The same project had delivered 33.7 MMscf/d on average in second quarter 2018. Indeed, in the first six months of 2019, the production averaged 59.0 MMscf/d.

Orca says the surge in deliveries “is as a result of higher sales volume to Tanzanian Electricity Supply Company (TANESCO)”. Orca’s plant supplies natural gas to a 25 km 12″ offshore pipeline and a 207 km 16″ onshore pipeline and is used by the power sector and industrial markets in the Dar es Salaam area.

 

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