Cameron LNG Liquefaction-Export Facility Begins Production At Train 2

Press release as follows:

Sempra LNG, a subsidiary of Sempra Energy, today announced that Cameron LNG has begun producing liquefied natural gas (LNG) from the second liquefaction train of the export facility in Hackberry, Louisiana.  

"We are pleased to reach this important milestone in the development of the liquefaction facility," said Lisa Glatch, chief operating officer of Sempra LNG and board chair for Cameron LNG.

Train 2 and Train 3 are expected to commence commercial operations under Cameron LNG's tolling agreements in the first and third quarter of 2020, respectively. The facility's first liquefaction train started commercial operations in August 2019.

Phase 1 of the Cameron LNG export project includes the first three liquefaction trains that will enable the export of approximately 12 million tonnes per annum (Mtpa) of LNG, or approximately 1.7 billion cubic feet per day.

Cameron LNG is jointly owned by affiliates of Sempra LNG, Total, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha (NYK). Sempra Energy indirectly owns 50.2% of Cameron LNG.

Sempra Energy is also developing other LNG export projects in North America, including Cameron LNG Phase 2, previously authorized by the Federal Energy Regulatory Commission, which could include up to two additional liquefaction trains and up to two additional LNG storage tanks; Port Arthur LNG in Texas; and Energía Costa Azul (ECA) LNG Phase 1 and Phase 2 in Mexico.

Development of any of these LNG export projects is contingent upon obtaining binding customer commitments, completing the required commercial agreements, securing all necessary permits, obtaining financing, other factors, and reaching final investment decisions. In addition, the ability to successfully complete construction projects, such as the Cameron LNG export project, is subject to a number of risks and uncertainties.

Sempra LNG develops and builds natural gas liquefaction facilities and is pursuing the development of five strategically located LNG projects in North America with a goal of delivering 45 Mtpa of clean natural gas to the largest world markets.

See also:
Cameron LNG Commences Commercial Operations For Train 1 Of Liquefaction-Export Project

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McDermott, Chiyoda and Zachry Group Announce First Cargo from Freeport LNG Train 2

• First cargo of liquefied natural gas shipped from Train 2 of the Freeport LNG project
• Project team maintains a continuous focus on safety and quality
• Accomplishment is a precursor to substantial completion of Train 2

Below is the full press release from McDermott

HOUSTON, Dec. 18, 2019 McDermott International, Inc. along with its partners, Chiyoda International Corporation and Zachry Group, announced today that the first commissioning cargo of liquefied natural gas (LNG) has been shipped from Train 2 of the Freeport LNG project on Quintana Island in Freeport, Texas. Production of LNG from Train 2 was announced on Dec. 6 and today's announcement of first cargo is a precursor to substantial completion of Train 2.

"The ongoing momentum of this project has accelerated us past multiple accomplishments, including Train 1's introduction of feed gas, first liquid and first cargo. And, we are well on our way toward commercial operation for Train 2," said Mark Coscio, McDermott's Senior Vice President for North, Central and South America. "I commend the project team for delivering these results and getting us closer to substantial completion."

Zachry Group, as the joint venture lead, partnered with McDermott for the Pre-FEED in 2011, followed by FEED works to support the early development stage of the project as a one-stop shop solution provider for Trains 1 and 2. Later Chiyoda joined the joint venture partnership for work related to Train 3. The project scope includes three pre-treatment trains, a liquefaction facility with three trains, a second loading berth and a 165,000 m3 full containment LNG storage tank.

Freeport LNG Trains 2 and 3 remain on schedule with Train 3 initial production of LNG scheduled for Q1 of 2020.

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Cheniere: Innovative deal structuring on Corpus Christi

This year saw one of the first innovative upstream gas supply deals for a US Gulf Coast liquefaction plant.

In June, Cheniere had signed a long term gas supply agreement with Apache for its Corpus Christi Stage III trains. The Corpus Christi Stage III project is being developed to include up to seven midscale liquefaction trains with a total expected nominal production capacity of approximately 9.5mtpa.

The supply agreement will be for gas volumes of 15mmbtu/day, delivered to Corpus Christi, and more importantly Apache will receive a gas price that will be the LNG price less a fixed liquefaction fee and certain costs incurred by Cheniere.

The LNG associated with this gas supply is c.0.85mtpa and will be marketed by Cheniere.

“This first-of-its-kind long-term agreement with Apache represents a commercial evolution in the U.S. LNG industry, as it will ensure the continued reliable delivery of natural gas to Cheniere from one of the premier producers in the Permian Basin, while enabling Apache to access global LNG pricing and receive flow assurance for its gas,” said Jack Fusco, Cheniere’s President and CEO.

“This commercial agreement, which is expected to support the Corpus Christi Stage III project, reinforces Cheniere’s track record of creating innovative, collaborative solutions to meet customers’ needs and support Cheniere’s growth.

Apache’s agreement with Cheniere is part of the company’s long-term strategy to leverage the scale of our assets in the Permian Basin and diversify our customer base and cost structure by accessing new markets for natural gas produced at Alpine High. We are pleased to partner with Cheniere in this innovative marketing agreement,” said John J. Christmann IV, Apache’s Chief Executive Officer and President.

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PGNiG confirms termination of Russian gas imports from end 2022

Poland's PGNiG has notified Gazprom of its intention to terminate imports of Russian pipeline gas from the end of 2022.


This will now increase the country's reliant on US LNG (which at this time many US Gulf Coast LNG projects still have to be sanctioned and not guaranteed to come online) and the long awaited Baltic pipeline to take Norwegian gas to Poland.


The move is not a big surprise and is completely consistent with all the messages the Poland has been giving over the past few years including aggressively signing up US LNG volumes.


Poland consumes around 17 bcm of gas annually, more than half of which comes from Gazprom under a long-term contract that expires at the end of 2022. It has used the upcoming expiry as an opportunity to diversify its gas supply ahead of time and has consistently stressed that Gazprom is charging Poland too much for the gas noting that Russia has taken advantage of the historic lack of other sources of gas which is now rapidly changing with the advent of LNG.


Related links:

• Nov 2018: PGNiG shuns Russian gas
• Nov 2018: PGNiG expands footprint in Norway
• Jun 2019: PGNiG acquires Total's 22.2% stake in King Lear
• Jun 2019: Tommeliten Alpha Project passes important decision gate towards production in 2024

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Blackrock and GIC acquires critical North Sea gas infrastructure

Blackrock and GIC have announced the acquisition of Kellas Midstream from Antin. Antin was expected to launch an auction process for Kellas Midstream at the end of the year and it appears that Blackrock and GIC moved quickly and were able to agree a deal ahead of the formal auction. No sale price was disclosed but believed to be in the range of £1.4-2.0 billion.

There will be a number of disappointed parties out there who were lining themselves up for the process including the runners-up on the NSMP sale of last year - widely reported as KKR, Macquarie, Partners Group and numerous pension funds.

Kellas owns the CATS pipeline and terminal, a majority stake in the ETS pipeline and is building the new HGS pipeline that serves Premier Oil's Tolmount Area. All of this is critical infrastructure for UK North Sea gas production, without which, the country would be crippled from a shortage of gas. Some of the key hubs that the infrastructure serves include the Cygnus Area (the largest and newest gas field in the Southern North Sea), the Culzean Area (another critical new gas field in the Central North Sea) and the up and coming Tolmount Area.

Kellas systems
Source: Kellas Midstream

CATS system
Source: Kellas Midstream

In addition, the CATS pipeline appears to be a key contender for export from the massive Glengorm field that was discovered at the beginning of this year and will become an important source of gas for the UK in the decades to come (see UK North Sea gets shot in the arm with Glengorm).

The advisers to Blackrock and GIC were listed as:

- RBC Capital Markets and Scotiabank as financial advisers

- Herbert Smith Freehills as legal advisers

- Xodus as technical advisers

The full press release below:

Antin sells Kellas Midstream to BlackRock and GIC

Antin Infrastructure Partners, a private equity firm focused on infrastructure investments, announced today that it had signed an agreement to sell Kellas Midstream to BlackRock’s Global Energy & Power Infrastructure Funds (GEPIF III) and GIC, a leading global institutional investor, in a joint venture.

Kellas Midstream owns and operates key gas infrastructure in the UK Central and Southern North Sea. Kellas Midstream comprises: (1) the Central Area Transmission System (‘CATS’): a major gas transportation and processing system which takes gas from the Central North Sea to the CATS reception and processing terminal at Teesside in the North East of England; (2) the Esmond Transportation System (“ETS”): a key subsea pipeline in the Southern North Sea connecting four producing fields to the Bacton gas terminal on the North Sea coast; and (3) the Humber Gathering System (“HGS”): a first-of-its-kind greenfield project to build the infrastructure required for the development of the large Tolmount gas field in the Southern North Sea.

Antin initially acquired a 63% stake in CATS from BG (now Shell) in 2014, later acquiring a 36% stake from BP in 2015. Having fully carved out the business and established a standalone entity, Kellas Midstream grew substantially both via organic growth with connection to new major gas fields such as Stella, Caley & Shaw, Culzean and Vorlich, and by expansion in the UK Southern North Sea with the ETS acquisition and the HGS development. Throughout Antin’s period of ownership, it focused on achieving outstanding operational performance whilst maintaining a clear focus on Health & Safety. Kellas Midstream maintained a perfect safety record with zero Lost Time Incidents for 16 consecutive years. The transaction is expected to close in early 2020.

“We are proud of the significant growth and strategic transformation accomplished during Antin’s ownership over the past five years. We are also grateful for the strong partnership and outstanding performance of Kellas Midstream’s talented management team and dedicated employees. We wish them continued success with their new owners” said Mark Crosbie, Antin’s Managing Partner.

Andy Hessell, Kellas Midstream’s Managing Director, said: “We thank Antin for their significant support over the past five years. GIC and the BlackRock GEPIF team recognise the growth potential of the business we have built and share our strategy to continue to invest, grow and build our portfolio of midstream assets and serve all our customers in the North Sea. We look forward to working with our new partners.”

Mark Florian, Group Head of the Global Energy & Power Infrastructure Funds Team at BlackRock, added: “A growing number of institutional investors are seeking exposure to energy and power investments. Within the sector, energy from gas is viewed as a necessary component of the energy transition as we move towards a lower carbon economy. This investment in Kellas Midstream reflects the focus of GEPIF III on making strong equity investments in mid-market energy and power infrastructure and partnering with outstanding management teams.”

Ang Eng Seng, Chief Investment Officer of Infrastructure at GIC, said: “We are pleased to invest in Kellas, a leading provider of high-quality midstream infrastructure with a strong track record. As a long-term investor, we look forward to partnering with BlackRock and Kellas’ management to support the future growth of the company.”

Bank of America Securities and Citi acted as financial advisers to Antin, and Weil, Gotshal & Manges acted as its legal adviser. RBC Capital Markets and Scotiabank acted as financial advisers to BlackRock Real Assets and GIC, and Herbert Smith Freehills and Xodus acted as their legal and technical advisers respectively.

Source: https://www.gic.com.sg/news-and-resources/antin-sells-kellas-midstream-to-blackrock-and-gic/

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Is Busta a bust?

Exploration well on the Busta prospect on PL782S has been drilled in 127m of water in the Jotun-Balder area of the Norwegian North Sea. It appears to be a marginal discovery with preliminary resource estimates of 6-60mmboe (vs. pre-drill 50-200mmboe).

Two separate gas/condensate and oil-bearing intervals totaling ~25m were encountered -the primary target hitting the reservoir with the secondary target water bearing.

Busta is operated by ConocoPhillips (40%) with AkerBP, Dea and Equinor each with 20%.

The Leiv Eiriksson rig which drilled the well is now scheduled to relocate to the neighbouring block, PL917, to drill the Enniberg/ Hasselbaink prospect.

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SNE partners buy FPSO

Cairn and FAR have announced a material increase in the capex for the SNE development from USD2.2 billion to USD3.7 billion (plus USD500 million contingency) for Phase 1. This has been driven by the partners' decision to buy an FPSO rather than lease it. This does however bring the opex down, estimated form c.USD14/boe to c.USD11/boe.

FID is expected to be taken at the end of 2019 with first oil forecast for late 2022. The development will be phased with Phase 1 targeting 230mmbbl and production of 100mbopd. Phase 2 will target a further 253mmbbl oil.

This is a particularly tough week for Cairn having earlier announced a dry hole in Mexico at Alom-1 and the Indian arbitration award delayed into summer 2020, while now also being exposed to larger capex on SNE.

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European gas storage is full

European gas storage is full and Equinor has highlighted three potential catalysts that could provide short term relief for the current super low European gas prices

1. A delay to Nord Stream 2 due to sanctions
2. The lack of a transit agreement with Ukraine
3. A colder than expected winter

The Nord Stream 2 project was expected to come onstream on 1 January 2020. However with ongoing concerns that the EU's reliance on Russian gas continues to grow and Trump considering sanctions on the project, it is likely to be delayed.


Russia's agreement to transit gas through Ukraine also expires in January 2020 and there is current uncertainty on whether a new agreement can be reached between the two countries.


So upside to European gas prices to exist as we head into the winter in north west Europe.

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Cameron LNG Commences Commercial Operations For Train 1 Of Liquefaction-Export Project

• Cameron LNG to Start Recognizing Revenues from Train 1
• Sempra Energy's Share of Full-Year Run-Rate Earnings from the First Three Trains are Projected to be Between $400 Million and $450 Million Annually

Press release as follows:

Sempra LNG, a Sempra Energy subsidiary, today announced that Cameron LNG's first train of the liquefaction-export project in Hackberry, Loiusiana, has begun commercial operations under Cameron LNG's tolling agreements.

"This is an exciting moment for Cameron LNG and for Sempra Energy," said Carlos Ruiz Sacristan, chairman and CEO of Sempra North American Infrastructure. "Cameron LNG is exporting liquefied natural gas (LNG) to customers in the largest world markets, helping to support economic growth in the U.S. and abroad."

Sempra Energy's share of full-year run-rate earnings from the first three trains at Cameron LNG are projected to be between $400 million and $450 million annually when all three trains achieve commercial operations under Cameron LNG's tolling agreements.

"We are proud that Cameron LNG has realized this key milestone with an excellent safety record and zero lost-time incidents," said Lisa Glatch, chief operating officer of Sempra LNG and board chair for Cameron LNG. "We remain focused on safely achieving commercial operations of Train 2 and Train 3."

Train 1 is part of Phase 1 of the Cameron LNG liquefaction-export project which includes a projected export capacity of 12 million tonnes per annum (Mtpa) of LNG, or approximately 1.7 billion cubic feet per day of natural gas.

Cameron LNG is jointly owned by affiliates of Sempra LNG, Total, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha (NYK). Sempra Energy indirectly owns 50.2% of Cameron LNG. 

Cameron LNG Phase 1 is one of five LNG export projects Sempra Energy is developing in North America: Cameron LNG Phase 2, previously authorized by FERC, encompasses up to two additional liquefaction trains and up to two additional LNG storage tanks, Port Arthur LNG in Texas and Energía Costa Azul LNG Phase 1 and Phase 2 in Mexico.

Development of Sempra Energy's LNG export projects is contingent upon obtaining binding customer commitments, completing the required commercial agreements, securing all necessary permits, obtaining financing, other factors, and reaching final investment decisions. In addition, the ability to successfully complete construction projects, such as the Cameron LNG facility, is subject to a number of risks and uncertainties.

Sempra LNG develops, builds and invests in natural gas liquefaction facilities and is pursuing the development of five strategically located LNG projects in North America with a goal of delivering 45 Mtpa of clean natural gas to the largest world markets, which would make Sempra Energy one of North America's largest developers of LNG-export facilities.

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PNG seeks to renegotiate Papua LNG

The PNG Minister for Petroleum issues the below release on re-opening the Papua LNG terms for negotiation.


PRESS RELEASE


STATE TEAM HEADING OUT TO RE-NEGOTIATE WITH TOTAL


The National Executive Council has authorized a State Negotiating Team (SNT) lead by the Minister for Petroleum, Kerenga Kua, to head off to Singapore to seek to re-negotiate the terms of the Papua LNG Gas Agreement previously signed on 19 April 2019. The SNT left today 15 August for Singapore.


The Papua Gas Agreement was signed by the previous O'Neill led Government inside the period when serious moves were afoot to remove and replace that Government.
The Marape led Government on taking office on 30 May 2019, took the firm view that the Papua Gas Agreement was disadvantageous to the State and the people in certain respects and resolved to seek a renegotiation.


Mr Kua cautions that considering what's at stake, the peoples expectations must be guarded during this period. The negotiations could work out well or even disastrously, but either way, the people must be ready to accept whatever the outcome. As a Nation we have reserved all our rights in law as we move down this path.


Success in the discussions could lead to an early progress of the project. By the same token failure could have very serious ramifications. But failure must not be ruled out and must remain within our contemplation. This is a risk we take as we try to move in the direction of taking PNG back and making it wealthy. The final outcomes will be briefed to the Prime Minister James Marape and the National Executive Council, and the final decision will be taken by the National Executive Council.


Considering our Nations economic circumstances short and long term, no stone must be left unturned at such important junctures. Mr Kua said, it would be futile and worthless to say in the future we should have done this deal differently. That question must be asked and answered now. This is the only diligent approach given how we find ourselves in this spot. The SNT expects to return early next week and report back to the National Executive Council. But Mr Kua says the Prime Minister will be kept informed daily as the negotiations progressed.

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European TTF breaks through historical boundaries

S&P has highlighted in its recent webinar that the European TTF price has historically traded within a range but that recent gas pricing dynamics has seen it break out of this range.

TTF has historically been bound by the JKM price as a ceiling (spot LNG price in Asia) and the coal switching price as a floor.

• In a tight gas market, TTF traded closer to the JKM price to incentivise LNG supplies into Europe
• In a loose gas market, TTF traded closer to the coal switching price to incentivise more take uptake of LNG by the European power sector

However in H1 2019, there was a big collapse in both the JKM and TTF price. In fact, there has been a period when JKM fell faster than TTF, making it lose its traditional role as a price ceiling and trading below TTF for a brief period.

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Warwick duster in the West of Shetlands

Hurricane Energy plc, the UK based oil and gas company focused on hydrocarbon resources in naturally fractured basement reservoirs, provides an update in relation to the 205/26b-13Z ("Warwick Deep") well.

Following completion of drill stem testing of the Warwick Deep well, the decision has been made to plug and abandon the well.

The Warwick Deep well was drilled to a total depth of 1,964m TVDSS and included a 712m horizontal section of fractured basement reservoir. Initial analysis indicates that the well intersected a poorly connected section of the fracture network within the oil column. The well did not flow at commercial rates producing a mixture of drilling brine, water, oil and gas.
The Company and its contractors are currently evaluating the drill stem test data and fluid samples with the objective of providing an update on this preliminary analysis at Hurricane's Capital Markets Day, scheduled for 11 July 2019.

The rig will now undertake work to permanently plug and abandon the Warwick Deep well and will then move to the 205/26b-B 'Lincoln Crestal' well, the second well of a three-well programme on the Greater Warwick Area. Hurricane has a 50% interest in the Greater Warwick Area following Spirit Energy's farm-in to the P1368 South and P2294 licences in September 2018.

Dr Robert Trice, Chief Executive of Hurricane, commented:

"It is disappointing that the Warwick Deep well did not flow at commercial rates. We were initially encouraged by hydrocarbon shows and gas ratio analysis indicative of light oil, however drill stem testing has clearly demonstrated that Warwick Deep cannot be considered suitable as a future production well and therefore the well will be plugged and abandoned.

"I look forward to commencing operations on the second well in the three-well programme, Lincoln Crestal. This is now the preferred candidate to be tied back to the Aoka Mizu FPSO, where Lancaster EPS production operations remain in-line with guidance."

See also: Spirit Energy farms in to Hurricane's Greater Warwick Area

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Guyana's upcoming drilling

Tullow and its partners have upcoming drilling in Guyana over the summer over two blocks.

The blocks are:

• Orinduik: Tullow (60% operator), Total (25%), Eco Atlantic (15%)
• Kanuku: Repsol (37.5% operator), Tullow (37.5%), Total (25%)

In August, the Stena Forth drill ship will arrive on Orinduik for a two well campaign to drill the Jethro and Joe prospects.

In October, Repsol is scheduled to drill the Carapa prospect on Kunuku.

Guyana remains an exciting place to watch following the success of ExxonMobil, Hess and CNOOC on the Stabroek block.

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Zama resource increase

Talos and Premier Oil have announced the successful appraisal of Zama in Block 7 offshore Mexico under the Zama-3 well. Premier has indicated a P90-P10 resource range of 670-970mmboe with P50 of 810mmboe. This further reaffirms the resource base and provides an upgrade to the previous 600mmbbl (oil) estimate.

The Zama-3 well follows:

• The initial Zama-1 discovery in 2017
• Zama-2 appraisal in January 2019
• Zama-2ST1 sidetrack well in April 2019

Zama-3 was drilled 2.4km from Zama-1 and logged 228m of gross pay. The net-to-gross was consistent with prior penetrations. The Zama-3 well was completed 9 days ahead of schedule and on budget.

The entire 3 appraisal well programme finished 39 days ahead of schedule and under budget.

The Zama field is planned to be developed from a single drill centre with drilling from the platform. Three production platforms are envisaged, each with capacity of up to 100mbopd. Produced oil is planned to be transported via a pipeline to the Dos Bocas terminal located onshore, c.70km away from the field.

The Zama partners are: Talos (35% operator), DEA (40%) and Premier Oil (25%).

Premier Oil also has a non-operated interest in Block 30 which could see Mexico transform into another important leg of its portfolio.

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Kurdistan steps up efforts to eliminate gas flaring

The Kurdistan Ministry of Natural Resources ("MNR") has asked the Shaikan field partners (Gulf Keystone and MOL) to re-submit a revised FDP for the field to address additional MNR requests on gas management.

The next well planned on the field will now be used to assess the feasibility of gas reinjection into the Jurassic formation, rather than as an originally planned Jurassic production well.

Whilst a key driver to be reservoir management and ultimate recovery rates, it is noted that the MNR is keen to eliminate flaring in Kurdistan.

Gulf Keystone has previously stated that the elimination of gas flaring is the single most complex and expensive component of the field’s development, and additional gas-handling capacity would be required to handle the gas-rich light oil in the underlying Triassic reservoir.

At nearby DNO’s Tawke field, work is scheduled to begin later this year on building the gas-gathering and processing facilities to enable reinjection of Peshkabir’s associated gas into the Tawke field, to reduce flaring and increase the latter recoverable reserves; this gas-gathering and injection system is forecast to be operational in early 2020.

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Dry well in the Barents near Korpfjell

The 7335/3-1 exploration well on Production Licence 859 has drilled a dry well.

The partners on the licence are: Equinor 65% operator, Lundin 15%, DNO 20%.

The licence lies in the Barents Sea and the 7335/3-1 well is located c.8km southeast of the Korpfjell gas discovery.

Both the primary and secondary exploration targets encountered sandy and poor reservoirs. The well was drilled by the West Hercules drilling rig to 4,268m below the sea surface and water depth was 239m The well has not been permanently plugged and abandoned.

The West Hercules rig will now move to drill a wildcat well 7324/6-1 in PL855 in the Barents Sea.

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Woodside's Pluto LNG restart delayed

Source: RBC

Woodside's restart from its planned Pluto LNG turnaround will be delayed until the end of June after initial restart efforts were unsuccessful. Vibration in the refrigerant compressor has delayed restart.

In the interim, Woodside will be purchasing cargoes from the market to fulfill its contractual obligations. However Woodside are making a healthy margin of  c.USD5/mmbtu with the current lull in Asian spot LNG prices due to subdued summer demand.

Spot LNG prices are c.USD5/mmbtu and Woodside's contractual supplies have achieved c.USD10/mmbtu.

#LNG

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PGNiG acquires Total's 22.2% stake in King Lear

Total has sold its 22.2% stake in King Lear to PGNiG. This follows AkerBP's acquisition of Equinor's 77.8% stake in the field in October 2018 for USD250 million.

In October 2018, AkerBP noted that King Lear is one of the largest undeveloped discoveries in Norway and that it planned to develope the field as a satellite to Ula. Ula is operated by AkerBP (80% with DNO as 20% partner) and the tie-back will improve capacity utilisation at the Ula facilities. Importantly, King Lear will also provide signifcant gas volumes for injection into the Ula field for increased oil recovery. Net recoverable resources at King Lear is estimated at c.100mmboe and is gas weighted.

PGNiG notes that the development of the field is planned to commence in 2021 with first production in 2025.

The King Lear development has stalled since its initial discovery as it was originally expected to be part of the Greater Ekofisk Area project which would have seen King Leat, Tommeliten Alpha and Tor tie back to Ekofisk. However gas processing capacity constraints at Ekofisk meant the project was not sanctioned.

With PGNiG entry into King Lear, and also ownership of Tommeliten Alpha (acquired from Equinor in October 2018) could see the latter now being routed to King Lear.

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Hurricane reaches first oil and Lancaster

Hurricane has reached first oil at the Lancaster field. The Aoka Mizu FPSO completed the start-up phase with a 72-hour production test and combined production from the wells reached the targeted 20mbopd, marking the contractual completion of commissioning. Hurricane now expects to ramp up production over the next six months towards the longer-term ~85% operating efficiency target.

Production guidance is:

• c.9mbopd for the next three months; followed by 
• c.13mcopd for the subsequent three months;
• before reaching a sustained target of c17mbopd

This is another step forward in demonstrating the scale and deliverability of the fractured basement play in the UK North Sea on the Lancaster licence. However fractured basement plays are risky propositions and production could be short lived with water breakthrough at risk of occuring in short order. Therefore 12-24 months of production data is now crucial in order to fully understand the scale of the reservoir and importantly, sustainability of production.

Meanwhile drilling continues on the nearby Greater Warwick Area licence with partner Spirit Energy.

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Chevron-Anadarko: the overlooked jewel

As Chevron swallows up its USD50 billion acquisition of Anadarko, OGInsights turns its focus away form the heavily covered synergies in the Permian, DJ Basin and Gulf of Mexico, and towards its LNG portfolio as Chevron strives to join the ranks of the supermajors in LNG.

Chevron has a Australasia-centric LNG business, but Anadarko's 27% operated interest in Mozambique Area 1 now broadens the former's reach. The Mozambique position is a low cost, integrated LNG project in an ideal geography with reach into the European and Asian markets.

Area 1 is close to FID with c.9.5mtpa of its 12.88mtpa capacity already signed up. The stepping in of Chevron into Anadarko's shoes adds further weight behind the project. 

In February, it was noted that Anadarko had signed a 2.6mtpa LNG SPA with Tokyo Gas/Centrica
joint agreement with implicit destination flexibility which will help broaden Chevron's LNG marketing portfolio, although it is yet to fully launch its own trading portfolio like the Shells and Totals of this world.

The Area 1 LNG joint venture in Mozambique comprises Anadarko, Mitsui, ONGC, ENH (Mozambique NOC), Bharat PetroResources, PTTEP and Oil India. In addition to the Area 1 development, the Area 4 joint venture between Exxon and Eni is on track for sanctioning later in 2019.

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Saudi oil optics

The release of the March Official Selling Prices begins to illustrate Saudi Arabia's complex and calculated moves in the global oil markets.

After years of trying to figure out the market dynamics of the brave new world with US shale and testing market responses to various signals, it knows that cutting its own production is not the only thing that matters (not to mentioned damaging to its own market share).

In fact, targeting data points that are strongly followed by the markets is more important, even if the signals they give are only superficial.

In March, Saudi Arabia increased its Official Selling Prices, pricing out its usual Asian buyers despite a market that is awash with light crude. However this is important in paving the way for more visible Atlantic Basin crudes (North Sea and West African) to be cleared,

In the first quarter, EIA data also shows that Saudi Arabia exported no barrels to its Motiva refinery in Port Arthur, USA, helping to manage storage levels in the US Gulf Coast and Caribbean, data from which drive global price sentiment.

Over the same time period, Saudi domestic inventory levels appear to have been rising.

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Further positive momentum at Zama

The Zama-2ST1 well (side-track well son Zama-2) encountered 873ft of gross oil bearing column with a net-to-gross ratio of c.70%. The well flowed at 7.9mboepd of which 94% was light 26-30 API oil. The well results indicated a prolific reservoir and potential to achieve significant plateau rates at the field. The operator estimates that a peak production of 150-175mboe/d is achievable.

This news is positive for the recoverable reserves of the field and could tighten the current estimates range of 400-800mmboe upwards.

The rig will now move to drill the Zama-3 well, the last in the 2019 campaign, and should confirm the extent of the field to the south. The drilling programme remains ahead of schedule with the Zama-2ST1 completed 9 days ahead of schedule and 16% below budget.

The Zama field is planned to be developed from a single drill centre with drilling from the platform. Three production platforms are envisaged, each with capacity of up to 100mbopd. Produced oil is planned to be transported via a pipeline to the Dos Bocas terminal located onshore, c.70km away from the field.

The Zama partners are: Talos (35% operator), DEA (40%) and Premier Oil (25%).

For Premier Oil, this development could overtake the Sea Lion development in the Falklands (another large resource optionality for the company), adding visibility to additional near-term production growth.

Premier Oil also has a non-operated interest in Block 30 which could see Mexico transform into another important leg of its portfolio.

Block 30 is operated by DEA 40% with partners Premier Oil 30% and Sapura Energy 30%.

See also Premier success at Zama on the Zama-2 result in January 2019.

Premier Oil Camarco RBC Capital Markets

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Energean success at Karish North

Energean has made a significant gas find at its high profile Karish North well. The well reached a depth of 4,880m and encountered a fantastic hydrocarbon column of c.250m

Management guidance of the estimated Gas-in-Place is 1-1.5tcf of which ~875bcf could be recoverable resource (i.e. close to 60% recovery factor).

Further evaluation will now be undertaken to determine the liquids content on the discovery.  The A, B and C sands have been drilled and Energean will now deepen the well to the D4 horizon. Following completion of D4 at Karish North, the rig (Stena DrillMAX) will return to drill the three development wells at the Karish Main development.

Karish North could be developed as a tie-back to the Energean Power FPSO which is located 5.4km from the Karish North well.

The FPSO is designed to handle 8bcm/y and Energean has so far secured 4.2bcm/y of offtake. It is expecting to finalise another 1.1bcm/y shortly, bringing contracted volumes up to 5.3bcm/y. Energean therefore has another 2.7bcm/y of capacity and Energean will look to contract this as soon as it is comfortable that it has more upstream gas volumes to underpin this.

In December 2018, Energean signed a contract with power supplier I.P.M. for 0.2tcf of gas over the life of the contract contingent on the results of the 2019 drilling programme. The result at Karish North significantly increases the chance of such potential supply being converted into firm contracted volumes.

Energean see lots of opportunity to sell more gas, led by the privatisation of Israeli power stations in the period 2019-22 which will open up 4.3bcm/y of demand.

See also: Energean targets Karish North

RBC Capital Markets, Morgan Stanley

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Mediocre week for UK exploration

This week saw a disappointing well result in Rowallan and a mediocre result in Verbier.

Rowallan
The keenly watched wildcat drilled at the Rowallan prospect "was not found to be hydrocarbon-bearing”. The 22/19c-7 well was targeting 143mmbbl in a structural fault and dip-closed trap analogous to Total’s Culzean field 20km away.

The well encountered a 182m section of sandstone and shale after being drilled to a depth of 4,641m .

The Dundonald and Sundrum prospects, which are geologically similar to Rowallan, have previously been identified as potential drilling targets in the block but will now be “re-evaluated in the light of the drilling results”, Serica said.

Serica, with a 15% interest in the block, did not incur any costs for the well as it was fully carried following an earlier farm-out. Eni operates the block with a 32% stake, with remaining partners JX Nippon (25%), Mitsui (20%) and Equinor (8%).

Verbier

Equinor (70%), Jersey Oil & Gas (18%) and CIECO (12%) completed appraisal well 20/05b-14 on the Verbier discovery last week. The well did not encounter Upper Jurassic sands as anticipated, and the contingent resources have been revised towards the lower end of initial resource estimates to 25mmboe.

Further upside potential exists in the area at deeper horizons and an additional prospect at Cortina. This will continue to be matured. At 25mmboe, Verbier is viewed to be commercial and development planning will now commence as part of a wider area development plan, which could include the Buchan Area.

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First step in reversion of LNG pricing structures

LNG has historically been priced to an oil price marker. This is because until recently, LNG has been a point-to-point business - LNG was produced in one country and shipped under a 20-30 year contract to a single destination and the LNG tanker would shuffle back-and-forth between the two end points. This underpinned the project financing for construction of liquefaction projects.

LNG prices were then linked to oil as both the LNG producing nations and importers typically had no mature domestic gas market, and hence no price discovery for the gas, but for the importing country, the LNG would have displaced oil for power generation.

Since the genesis of North American LNG, US Gulf Coast exports have been priced to Henry Hub ("HH"), with contracts being HH plus a liquefaction toll. However, buyers are starting to shift to being overweight HH contracts and the last few weeks have seen the first set of contracts away from HH linkage.

On 2^nd April, NextDecade signed a 20 year SPA to deliver LNG from its Rio Grande facility with Shell. The pricing is c.75% linked to Brent with the remainder linked to HH, on a FOB basis. First LNG is planned to be in 2023. This was the first-ever LNG contracts out of the US to be indexed to Brent and comes with full destination flexibility.

On 5^th April, Shell went one step further by agreeing to sell LNG to a Japanese utility with a linkage to coal prices and is the latest innovation to help buyers seeking to diversify risks. This contract is for 10 years and is the first ever coal-linked contract.

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Maria, you've gotta see her!

Wintershall has shut-in the Maria field since February, approximately a year after first production, following poor production performance. It is understood that reserves have been downgraded from 207mmbbl to c.60 mmbbl.

The field is now undergoing testing and monitoring to see how best to produce the remaining reserves the recover the lost reserves whilst managing the reservoir. It is understood that the NPD has to review plans and sign off on the field's restart for fear unintended reservoir damage. There is currently uncertainty on whether the field will start up again.

The cause is believed to be poor connectivity between zones. Water injection is provided to the zone below for pressure support. However analysis is now showing low connectivity between the geological layers in the reservoir, and thus the water injection is not working effectively.

Wintershall started production from the Maria oil field on Haltenbanken in the Norwegian Sea in December 2017, one year ahead of schedule and with 20% reduction in costs. Maria was Wintershall’s first own-operated field in Norway.

Wintershall chose an innovative subsea concept to develop the field. Two subsea templates were installed on the seabed above the Maria reservoir and connected via a pipeline network to the existing Kristin, Heidrun, and Åsgard B platforms.

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Waha gas pricing goes negative

Chart of the week: Waha hub gas pricing goes negative

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Azinor Catalyst portfolio

Azinor has an exciting Central North Sea portfolio which is situated close to existing fields and could act as low cost tie-backs to existing infrastructure.

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Energean targets Karish North

Energean is in the middle of drilling the Karish North prospect with results expected at the end of April 2019. The prospect is located c.5.4km from the Karish FPSO and is targeting 1.4tcfe. Assuming success and a discovery, Energean believes it would convert into 0.4bcm/y.

The FPSO is designed to handle 8bcm/y and Energean has so far secured 4.2bcm/y of offtake. It is expecting to finalise another 1.1bcm/y shortly, bringing contracted volumes up to 5.3bcm/y. Energean therefore has another 2.7bcm/y of capacity and Energean will look to contract this as soon as it is comfortable that it has more upstream gas volumes to underpin this.

Energean see lots of opportunity to sell more gas, led by the privatisation of Israeli power stations in the period 2019-22 which will open up 4.3bcm/y of demand.

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Leveraging off Leverett

As part of the 30th Licensing Round, Zennor picked up Blocks 21/2d, 21/3c-d in licence P2350. The licence contains the Leverett discovery which was appraised by CNOOCNexen.

The discovery has had four wells and may or may not require further appraisal prior to development. The field could be tied back to Zennor's Finlaggan field and extend the plateau.

Leverett has been penetrated by:

• 21/2-2 - drilled in 1975 with the West Venture rig
• 21/2-4 - drilled in 1977 by Zapata with the Norjarl rig 
• 21/2a-11 - drilled in 2015 by Nexen with the Blackford Dolphin rig
• 21/3f-8 - drilled in 2013 by Nexen with the Transocean Prospect rig

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CNOOC to drill in the West of Shetlands

CNOOC has contracted the Island Innovator rig from Island Drilling Company for the drilling of the Howick prospect in Block 206/21 in the West of Shetlands. CNOOC is 100% operator of the block

CNOOC also has Cragganmore discovery in Block 208/17A which is planned to be further appraised, potentially in 2019. CNOOC is operator of Cragganmore with 70% interest; INEOS is a 30% partner.

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Understanding Mozambique's fiscal regime (Part I)

Government take across countries in East Africa are generally below the Sub Saharan Africa average of 62%. This reflects the relative infancy of the E&P industry in the region with high exploration risk and uncertainties on the path to commericialising discovered resources. A lower fiscal take is required to attract investment.

Mozambique’s government take lies in the middle of its East African neighbours - lower than Uganda where significant oil reserves have been proved up, and Tanzania where fiscal terms are less attractive. Mozambique's fiscal take is uncompetitive relative to Kenya and Ethiopia, which are considered to be important E&P players in due course.

It is also important to note that Mozambique's resources are gas and hence deemed significantly less attractive than oil. Such large scale gas discoveries are expensive to monetise but clearly LNG is becoming an increasing focus by global IOCs and there has been enough momentum over the years to fianlly get Mozambique LNG off the ground.

Mozambique operates a standard PSC regime with an R-factor based on cumulative income/cumulative costs.

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Gran Tierra's Grand Tour (into Ecuador)

Gran Tierra has won three blocks in Ecuador covering c.140,000 acres in the highly prospective Oriente-Putumayo Basin: Charapa, Chanangue and Iguana. The blocks are contiguous with Gran Tierra’s Putumayo position in Colombia and allows the company to extend its Colombian success on the trend across the border.

Gran Tierra will have 100% interest and operatorship on each block in exchange for a 14 well, four year work programme – management plans to commence the programme in 2020, to be fully funded from internal cash flow.  The contracts work on a sliding scale for contractor share of revenues, ranging from 87.5% at USD30/bbl to 40% at USD120/bbl.

The Charpara block sets Gran Tierra off to a good start with an existing field and historical production from the B-Limestone. As Gran Tierra matures its new acreage, there is scope to construct its own gathering infrastructure and use the export infrastructure in Ecuador. In due course, this could also be an export route for its Colombian production in the same way that Amerisur has built its own OBA pipeline from its Platanillo block to Ecuador (see Bienvenido Victor Hugo and Putumayo smart crude marketing).

The other side of the border into Ecuador has always been an exciting play. Whilst geologically the same trend, the Colombian side of the border has been underexplored due to historical above ground conflict and security issues. In contrast, Ecuador has been highly successful with many fields where nearly 6bnbbl of oil has already been produced.

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