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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