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    Deal Frenzy Swells with Diamondback's $8.4 billion Shale Buyout (Friday, 17 August 2018)

    17 Aug 2018, 10:00 pm

    Diamondback Energy’s agreement to buy Energen in an $8.4 billion all-stock deal makes it official: The long-awaited Permian basin buying spree has arrived, promising to shake up the U.S. shale industry.

    Some $30 billion in transactions this year center on the Permian, where pipeline shortages and other hurdles have boosted costs, adding fresh momentum to the push for consolidation. In March, Concho Resources Inc. paid $9.5 billion including debt for RSP Permian Inc. In July, BP Plc said it would spend $10.5 billion across three U.S. shale plays, including the Permian.


    “There will be further consolidation over time for sure,” said Leo Mariani, an Austin-based analyst at NatAlliance Securities. “There are a lot of players in the Permian and a lot of economies of scale can be achieved such as lower-cost debt and reducing competition for services.”

    At the end of last year, Energen owned drilling rights for about 150,000 acres across the Permian, which stretches across West Texas and New Mexico. The driller was “undervalued” with “three different activist investors,” Mariani said in a telephone interview. “They were seeing some pressure.”

    Stock Premium

    The $84.95 per-share price represents a 16% premium to Energen’s closing price Tuesday. Diamondback will also assume $830 million in Energen debt in a deal approved by both boards, Midland, Texas-based company said in a statement Tuesday.

    Diamondback shares fell 5.2% to $126.85 in New York; Energen jumped 9.7% to $80.26.

    The move comes a week after Diamondback announced it was buying closely held Ajax Resources for $1.2 billion in cash and stock, the holder of 25,000 Permian acres. The two deals are set to make Diamondback the third biggest producer in the Permian among companies focused on the region, the company said.

    Analysts had long predicted a wave of consolidation in the Permian, a remote region where the drilling renaissance was pioneered by dozens of independent wildcatters. Output in the basin is expected to rise to 3.42 MMbpd in September, according to Energy Information Administration forecasts, more than double the production five years ago.

    In July, PricewaterhouseCoopers predicted that the second half of 2018 would see a boom in oil and natural gas mergers and acquisitions, given that deal making conversations already were “at a fever pitch” following a slow down in M&A earlier in the year.

    Activists including Carl Icahn, Paul Singer’s Elliott Management Corp. and Keith Meister’s Corvex Management had pressed Energen to seek a buyer, arguing its management had failed to wring full value from its acreage in the heart of the Permian. Corvex last year moved to call a special meeting of shareholders to remake Energen’s board, prompting a lawsuit from the company.

    The two sides announced a settlement in March, with Energen agreeing to expand its board and conduct its review.

    Meister praised the deal on Tuesday, saying it delivers “significant" gains for Energen shareholders. The new Diamondback “should be poised for many years of growth at an industry-leading cost structure," he said in an interview.

    Travis Stice, CEO of Diamondback, said in a statement that Energen’s leaders have “done an outstanding job assembling a portfolio of Tier One acreage in both the Midland and Delaware basins.”

    Energen started life as an Alabama natural gas utility but shifted its main focus to exploration and production after acquiring drilling rights in the Permian. It agreed to sell Alabama Gas to the Laclede Group for $1.28 billion in cash in 2014 to raise money to accelerate drilling.

    “Over the past five years, Energen has strategically divested noncore assets and transformed into a low-cost Permian basin pure-play with what we view as a firm foundation for growth,” Bloomberg Intelligence analyst Michael Kay said in a note to clients in May.

    Citigroup Global Markets, acted as Diamondback’s financial adviser and Akin Gump Strauss Hauer & Feld LLP as legal adviser, according to the statement. J.P. Morgan Securities and Tudor, Pickering, Holt & Co. were financial advisers to Energen and Wachtell, Lipton, Rosen & Katz was its legal adviser.


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    Drones Poised to Reduce Operating Costs for Energy Industry (Friday, 17 August 2018)

    17 Aug 2018, 10:00 pm

    Cheap drones are poised to boost output and cut operating expenses for the energy industry.

    The unmanned aerial vehicles are generally faster and less expensive than people, and can go places that may not be safe for workers. As costs fall, and their capabilities increase, drones are spotting leaks in natural gas pipelines, helping utilities inspect transmission and distribution lines and evaluating thermal power plants, according to a Bloomberg NEF report Mo

    @medicalInsuranceWidget@ nday. While they’re limited by factors including battery life and the systems that help them avoid obstacles in flight, researchers are working to make them more useful.

    Utilities can also use them to inspect transmission and distribution lines, and they aided in repairing Puerto Rico’s electrical grid after Hurricane Maria slammed into the island last year. Drones can also aid mining companies, find leaks in gas pipelines, provide security at power plants and inspect the interior of oil tankers.


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    New Decom Hotspots Opening Up (Friday, 17 August 2018)

    17 Aug 2018, 8:00 pm

    The offshore support industry faces a busy few decades as numerous decommissioning opportunities present themselves around the world

    In April, Ocean Installer’s construction support vessel, the Normand Vision, took up station in the Chinquetti field, 80 km off the coast of Mauritania in West Africa, as it began one of the region’s main new decommissioning projects.

    The contract, which was awarded by Malaysia’s state-owned Petronas, highlights one of the latest “decom” hotspots that will keep the offshore supply industry on its toes for the next 20-30 years.

    A new wave of decomissioning activity is emerging as time runs out for dated infrastructure in offshore exploration areas other than the North Sea and Mexico, the busiest areas until now. According to a report entitled Preparing for the next wave of offshore decommissioning released in April by Boston Consulting Group (BCG), three of the busiest regions will be Southeast Asia, Latin America and West Africa, where about half of the fixed platforms and wells are due to become uneconomical in the next 20 years.


    Other, newer fields are also approaching abandonment. According to BCG, Egypt, India and Italy each have about 150-200 structures and 700 to 1,000 wells that will have to be dismantled by 2038. China, which has some of the oldest fields in the world, will also have to start decommissioning up to 200 platforms and 2,000 wells in coming years. Further south, Australia has about 50 structures and 700 wells of a similar age.

    The Arabian Gulf is also shaping up as a future decommissioning hot spot. Within the next 20 years, more than 1,000 structures and 3,000 wells there will be more than 30 years old and become due for dismantling.

    And in the Northern Hemisphere, besides the usual action in the North Sea, 40-year-old infrastructure in the Celtic Sea off southern Ireland is approaching its use-by date. In July two companies – PSE Kinsale Energy and PSE Seven Heads -- applied for permission to decommission a range of production facilities lying up to 70 km off the coast of County Cork.

    Hive of activity

    For the foreseeable future, the North Sea will remain a hive of plug and abandonment activity. According to the Oil and Gas Authority, the all-in decommissioning costs could reach US$150Bn, a sum that covers the cost of taking down more than 600 fixed installations and plugging and abandoning more than 7,000 wells.

    One of the more immediate projects is the dismantling of Equinor’s 36-year-old Huldra Field facility in the Norwegian North Sea that stopped production in 2014. Norwegian regulator, the Petroleum Safety Authority, signed off decommissioning approval in July.

    As such, most of the infrastructure built in the 1970s is coming down and creating a new era of work for the offshore support industry. “Decommissioning is a costly challenge and for many countries, the value at stake in handling these projects properly could be worth several billion dollars,” noted BCG.

    The potential opportunities have led to the establishment of new kinds of specialists, such as Maersk Decom, which was established in April to offer “bundled decommissioning solutions”. To begin with, the group will cover up to 80% of the entire decommissioning operation and use outside contractors for the rest, but eventually it intends to pull all of it under the Maersk Decom umbrella. That comprises project management, well plug and abandonment, removal of subsea infrastructure and towage.

    The removal of offshore infrastructure presents special challenges. While age is obviously a determining factor, so is the period of disuse. For platforms that have been left to the elements for several years, the difficulty of the job goes up several notches, and so do the costs; the helipad may no longer be useable; walkways and handrails have often become unsafe; original lifting equipment such as cranes may have rusted; and in certain cases the infrastructure has deteriorated so badly that it has to be partially rebuilt before it can be brought down.

    “We have seen instances in which decommissioning took nearly twice as long as planned because contractors needed to make repairs before the project could proceed, leading to significantly higher costs,” reported BCG.

    Another recurring problem is a dearth of information on which to base the project. Sometimes, say contractors, there is no documentation at all and even if information is available, it may be outdated, for instance because pipelines may have moved from their original location on the seabed.

    Red tape

    Regulatory scrutiny is intensifying just about everywhere. In the UK Continental Shelf, contractors must deal with more than a dozen different governmental and non-governmental organisations before projects get the green light.

    The Netherlands has recently updated its decommissioning regulations. With about 150 offshore platforms and 1,800 still active wells, the country has come up with a 20-year blueprint known as the Netherlands master plan for decommissioning and re-use. The stakes are high – the North Sea nation estimates it will cost around US$9Bn to retire its offshore infrastructure.

    The programme is billed as the world’s first national platform for decommissioning. As in the UK, the Netherlands’ plan is based on collaboration between operators, contractors, government bodies and other interested parties.

    Other nations are also pursuing aggressive decommissioning goals, albeit with varying degrees of success. By early 2018, Brazil had only overseen the removal of six fixed platforms and five floating ones, equivalent to less than 5% of its total offshore platforms. As a result, the government is now fine-tuning its decom system.

    Similarly, Thailand has only just established a legal framework for decommissioning under the Petroleum Act, while an initiative known as Decommissioning 2.0 is designed to streamline the process with a one-stop service for obtaining approvals.

    It appears that the realisation is now dawning that state agencies need to get organised. “A country with decommissioning liabilities of US$14Bn, the median level among the top 30 countries by total liability, could generate savings of more than US$1Bn by improving its decommissioning performance,” noted BCG. This would be based on a 25% reduction in the average cost per well, or a 30% saving per tonne in the removal of topside infrastructure.

    With these kinds of savings on offer, it makes a great deal of sense for governments and regulators to take a close look at the processes they currently have in place.

    The need for speed

    In decommissioning projects speed of execution is everything, as Scotland-based James Fisher Offshore (JFO) can vouch. Among a variety of recent work, in Thailand the company was contracted to dismantle pipelines from the seabed and cut them into sections for transportation to shore. In Australia, JFO’s offshore technicians undertook a rapid-response assignment at 24-hours’ notice to fix faulty pipelines and in Malaysia, using subsea equipment, they assisted in the decommissioning of a floating storage and offloading vessel.

    In the Middle East, JFO has repeatedly deployed a formidable array of equipment, including four large demolition shears for pipeline demolition and recovery projects, sometimes undertaking several projects at once.

    “JSO has been busy on many projects,” explained chief executive Jack Davidson. “Customers appreciate the way we bring complete methodologies and cost-effective solutions for what are often highly complex offshore projects. And we like to work fast.”

    Decommissioning vessels are becoming more specialised all the time, as Ocean Installer’s Normand Vision illustrates. A type VARD 3 06, the ship is built for the kind of heavy construction (or de-construction) work required by large dismantling projects offshore. Among other equipment, the vessel boasts a 400-tonne capacity active heave-compensated crane and a launch system for remotely-operated vehicles that do much of the subsea inspection.

    In China, construction will start later this year on two new 96 m multi-activity jack-up units (MAUs), one of the workhorses of decommissioning projects. Ordered by Netherlands-based Overdulve Offshore Services International and classified by DNV GL, the four-legged, self-elevating vessels are designed to work fast, with two cranes that have a combined lifting capacity of 2,400 tonnes when hoisting in tandem. Self-propelled by four steerable thrusters, the MAUs will also have the latest advanced dynamic-positioning systems.

    “The MAUs will be equipped for light drilling operations to close wells,” explained DNV GL Maritime’s business development manager for Benelux Bas Veerman. “In addition, they can deconstruct the topside of an oil rig’s structure and remove the jacket structure.”

    In deconstruction work, speed is essential, especially in hostile waters. Early last year, Antwerp-based Scaldis Salvage and Marine was able to dismantle Tullow Oil’s Horne and Wren field in the North Sea in just three days with the aid of the Rambiz, a heavy-lift vessel. In that time Scaldis completed an in-and-out seabed survey, removed the topside and fastened it on board the Rambiz, dredged and cut the jacket piles, installed internal lifting tools and hoisted the jacket off the seafloor.

    With the jacket suspended from a crane and the topside on deck, the Rambiz was then towed back to Flushing in the Netherlands.


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    Equinor Completes Successful Appraisal of Sigrun Discovery in PL 025 (Friday, 17 August 2018)

    17 Aug 2018, 6:00 pm

    Equinor Energy AS, operator of production licence 025, has concluded the drilling of appraisal well 15/3-11 on the 15/3-4 (Sigrun) oil and gas discovery.

    The well was drilled about 10 km southeast of the Gudrun field in the North Sea, and about 225 km west of Stavanger.

    The objective of the well was to delineate the 15/3-4 discovery in three reservoir zones in the Middle Jurassic (the Hugin formation).


    The discovery was proven in reservoir rocks from the Middle Jurassic in the Brent group in 1982. Before well 15/3-11 was drilled, the operator’s resource estimate for the discovery was between 0.3 – 1.4 million Sm3 of recoverable oil equivalents.

    The well encountered a total oil column of about 35 metres in the Hugin formation, of which about a 15-metre thick sandstone layer with poor to moderate reservoir quality. The oil/water contact was not encountered. Preliminary estimates of the size of the discovery after the delineation well are between 1.1 and 2 million standard cubic metres (Sm3) of recoverable oil equivalents.

    The well was not formation-tested, but extensive data acquisition and sampling have been carried out.

    The licensees in production licence 025 will assess the profitability of the discovery with regard to a potential development over the Gudrun field.

    This is the 9th exploration well in production licence 025. The licence was awarded in licensing round 2-A in 1969.

    Appraisal well 15/3-11 was drilled to a vertical depth of 3991 metres below the sea surface, and was terminated in the Sleipner formation in the Middle Jurassic. Water depth at the site is 109 metres. The well has been permanently plugged and abandoned.

    The well was drilled by the Deepsea Bergen which will now drill wildcat well 35/10-4 S in production licence 630 in the northern part of the North Sea, where Equinor Energy AS is the operator.

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    ‘At the Heart’ – Shell UK Boss says Bacton Gas Terminal will be Pivotal in Future Plans (Friday, 17 August 2018)

    17 Aug 2018, 12:00 pm

    As the group marks 50 years of drilling for oil and gas off the East Anglian coast it reaffirmed its allegiance to Bacton gas terminal, which itself celebrated its 50th anniversary last month.

    Shell’s energy production in the southern North Sea began with the Leman field, 43 miles north-east of Lowestoft, in 1968.

    Its operations now include the Bacton terminal, where it employs around 150 people, and the Clipper installation, 46 miles north-east of Bacton.


    The group has four strategic hubs in the UK, including Bacton, which has had £300m worth of investment ploughed into it in recent years.

    Sinead Lynch, Shell UK country chairman, said the north Norfolk facility would continue to be pivotal as the group explores new development opportunities in the southern North Sea.

    “We are focused on operational efficiency, generating competitive resources, maximising recovery of the resources we already have and looking forward to where the next opportunity for development will be in the basin,” she said.

    “We will make sure we put the investment [into Bacton] to make sure it can be used to its full potential for many years to come.”

    She added: “It is quite an exciting time for oil and gas in the UK, especially with 50 years of Bacton and we look forward to it continuing its contribution to the sector.”

    Like many energy companies Shell is starting to explore opportunities with tight gas – a notoriously difficult resource to access. Supported by new technologies, it has drilled a number of development wells into tight gas reservoirs including in the southern North Sea.

    It is also exploring opportunities in third party gas, bringing resources tapped by other providers through its pipelines.

    Ms Lynch said the Bacton terminal would play a key part in these growth areas, particularly third party gas.

    “That is part of the economic recovery plan, access to other people’s infrastructure so we can be sure that other smaller platforms can be operated economically,” she said.

    “We have spent money rejuvenating Bacton terminal over the last number of years so we are open and ready for third party businesses.

    “The fact that the discoveries are getting smaller will put a focus among operators and players in the North Sea on collaboration.”

    Reflecting on 50 years of energy generation

    Ms Lynch said Shell’s 50th anniversary in the UK was “a moment of quite some size”.

    “Shell as a company has been in the UK since the 1890s and has been an explorer in the North Sea since the beginning,” she said.

    “There is a huge amount of passion, hard work and dedication from everyone in order to develop an industry around the UK because I don’t think anybody anticipated it would grow to the level it has.”

    Since drilling began in the North Sea, Ms Lynch said the area has attracted some $300bn of capital investment from the oil and gas industry, including Shell.

    “None of that would be possible without our amazing people, whether it is engineers, geologists, geophysicists, accountants or lawyers.

    “It is sometimes good to take a step back and look at what we have achieved. At the heart of that has been doing things safely and keeping the environment in mind,” she said.

    A year with Shell in the North Sea

    Shells has thousands of staff working around the North Sea – and managing its offshore operations is a massive logistical challenge. Each year involves, on average:

    – 1,680 helicopter flights

    – 70,000 passengers moved

    – 5,000 cups used per day offshore in the North Sea, meaning 1,798,638 per year

    – 2,661 meals served per day, meaning 971,265 per year

    – 1,666 Christmas lunches served

    – 2,823 ice cream tubs used

    – 290,809 bread rolls baked offshore

    – 150,000 tonnes shipped


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    Norwegian Companies Join Forces for Expansion of AI Initiative (Friday, 17 August 2018)

    17 Aug 2018, 10:00 am

    Norway has a huge potential to be a pioneer in Artificial Intelligence (AI), but it needs resources and collaboration in order not to lag behind. To strengthen national efforts on artificial intelligence, Telenor, NTNU and SINTEF are inviting Norwegian businesses to partner on the new Norwegian Open AI Lab. Additional partners will include DNB, DNV GL, Equinor, and the Kongsberg Group.


    While the Norwegian Open AI Lab will develop solutions specific to the partners’ industries, it will also consider opportunities where Norway can take positions internationally. Norway benefits from a competitive advantage thanks to its advanced ICT infrastructure, purchasing power, competence and a population with above-average technological literacy. Having a strong position on artificial intelligence is central to ensuring that Norway is able and prepared to compete in the global market. A strengthened AI lab like this ensures that Norway can continue the tradition of collaboration between business and academia in the country.

    Expanding the AI Lab

    The Norwegian Open AI Lab is an expansion of the Telenor-NTNU AI-Lab in Trondheim. This initiative builds further on the work already carried out there in the areas of innovation within artificial intelligence/machine learning and big data. It was during Arendalsuka in 2016 that Telenor, NTNU and SINTEF announced the launch of this common initiative to support entrepreneurship and the development of Norwegian competence in the field of artificial intelligence. Together with central research institutions nationally and globally, the centre will work to develop itself to become recognised laboratory for AI research and development.

    In addition to supporting world-class research on artificial intelligence and big data, the Norwegian Open AI Lab will develop new technologies and services within these fields. Partners in the lab will contribute with funding, competence and data, and will therefore strengthen cooperation across industry sectors. Common to all of the current partnering companies is their established contribution of resources to NTNU to support the university’s AI and big data research.


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    Total Takes New Approach In North Sea (Friday, 17 August 2018)

    17 Aug 2018, 8:00 am

    Operating in the North Sea comes with challenges, particularly high costs, for the oil and gas sector. But Total has grown its assets in the region with the acquisition of Maersk Oil.

    From the perspective of Martin Rune Pedersen, vice president of Total’s operations in Norway, Denmark and the Netherlands, the industry is pretty good at finding hydrocarbons, but when it comes to turning discoveries into developments they could do better.

    “To improve that we need to utilize technology to turn these discoveries into profitable, value-creating operations for us and our host countries,” Pedersen said. “Some of it is around data management; how we can use our data much better?”


    Despite high costs, Europe and the North Sea region are still valuable parts of Total’s portfolio for the stability they provide.

    “The stable geopolitical environment around the North Sea is attractive in the uncertain times that we see globally,” Pedersen added. “The allowances and incentives are also essential in the North Sea and ensure that we can remain competitive and attract the investments. This strong future requires continued tripartite collaboration between the industry, the regulators and the governments in the areas that we work in.”

    Two-pronged Approach

    With the acquisition of Maersk, which made Total the second largest operator in the North Sea, Total remains fully committed to the North Sea with at least three decades of production horizons. The Maersk acquisition deal closed in March. Pedersen explained that there are two sides of the company’s strategy for the region: new greenfield projects and smaller discoveries that can piggy-back onto existing infrastructure.

    “For greenfield projects, the challenge is how to revitalize and reinvent ourselves to think differently,” he explained, pointing out work at the Johan Sverdrup development as a good example of doing that. “We came at that with new ideas—new concepts of how to address a very mature basin. As an operator, another good example is the upcoming Jasper well we are going to drill in the Norwegian North Sea.

    “When it comes to smaller discoveries near current assets it is about how we can use the exploration and appraisal work already undertaken to unlock smaller fields and ensure that we have extended lifetime and value for the existing infrastructure and facilities,” Pedersen said. “The well we are drilling right now in the Laggan-Tormore offshore fields, west of Shetland, is an excellent example of this.”

    Collaborative Future

    Some digital technologies are still in their early stages of development when it comes to oil and gas. Pedersen said that it is still very early days, so it is difficult to put a specific number on the value such technologies offer. But he believes it will have a significant impact as Total moves forward.

    “We know there’s a huge prize in the subsurface data and the subsurface domain, and that is one of the drivers for Total to set up a partnership with Google Cloud. With that, we will jointly develop artificial intelligence solutions specifically tailored to subsurface data analysis both for the exploration and production areas.”

    The agreement focuses on the development of artificial intelligence (AI) programs that will make it possible to interpret subsurface images, notably from seismic studies, using computer vision technology and automate analysis of technical documents with natural language processing technology. These programs allow Total’s geologists, geophysicists, reservoir and geo-information engineers to explore and assess oil and gas fields faster and more effectively.

    “We believe that if we can speed up the adoption of AI in the field of geosciences, we can build new systems, new tools that can make us even more efficient,” Pedersen added. “The objective is to accelerate workflows. If we can become faster at analytics, we can make faster decisions.”

    Total began applying AI to characterize oil and gas fields using machine learning algorithms in the 1990s. “Today we are exploring machine learning and deep learning applications, and there are many other areas we can use it in such as forecasting,” Pedersen said. “We are working at improving satellite imaging and rock sampling analytics. Digital development plays a huge role in this, and I believe we have only really started exploring the potential we see in that.”

    Facility of the Future

    Although a crucial part of unlocking new volumes is new technology, there’s more than digitization to Total’s approach.

    Pedersen spoke about a concept he called “Facilities of the Future.” He described it as a way in which the company tries to marry digital technology with traditional oilfield technology development to help generate transformational change.

    “Some of it is unmanned facilities, no accommodation or control rooms; the control would come from onshore. We are eliminating a lot of these areas already in the design stage for future new developments, which is going to make the area significantly more competitive,” Pedersen said.

    “If we do this right, we believe that this can help to develop both major fields but also certainly the smaller satellites fields, the small discoveries, and translate them into developments and value creation for the infrastructure we already have in place,” he added.


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    Offshore Discoveries in the Mediterranean to Increase Egypt’s Gas Output (Friday, 17 August 2018)

    17 Aug 2018, 6:00 am

    Natural gas production in Egypt has been in decline, falling from a 2009 peak of 5.8 Bcfd to 3.9 Bcfd in 2016, based on estimates in BP’s Statistical Review of World Energy. The startup of a number of natural gas development projects located offshore in the eastern Mediterranean Sea near Egypt’s northern coast has significantly altered the outlook for the region’s natural gas markets. Production from these projects could offset the growing need for natural gas imports to meet domestic demand, according to the Egyptian government.


    The West Nile Delta, Nooros, Atoll, and Zohr fields were fast-tracked for development by the Egyptian government and have begun production, providing a substantial increase to Egypt’s natural gas supply. Zohr field’s estimated recoverable natural gas reserves of up to 22 Tcf would make it the largest natural gas field in the Mediterranean, based on company reports gathered by IHS Markit. The Zohr field is currently producing 1.1 Bcfd and is expected to increase to 2.7 Bcfd by the end of 2019.

    Natural gas production in Egypt has declined largely as a result of relatively low investment, according to Business Monitor International research. Meanwhile, domestic demand for energy has grown, driven by economic growth, increased natural gas use for power generation, and energy subsidies. With the exception of small declines in 2013 and 2014, natural gas consumption has increased every year since at least 1990, and it is up 19% from 2009, when domestic production peaked.

    Faced with growing demand and declining supply, Egypt had to close its liquefied natural gas (LNG) export terminals to divert supply to domestic consumption. Egypt became a net natural gas importer in 2015, and although LNG exports resumed in 2016, Egypt’s net imports of natural gas continued to increase.The Middle East Economic Survey (MEES) indicated that Egypt will still need to import small volumes of natural gas in the coming years, particularly for the power sector. MEES reported that the state-owned Egyptian Electricity Holding Company (EEHC) awarded contracts that would add 25 gigawatts (GW) to total generation capacity, 70% of which would come from natural gas-fired projects. Three combined-cycle natural gas turbine power plants with a total capacity of 14.4 GW will collectively require as much as 2.0 Bcfd of natural gas when they become fully operational in 2020.


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