Oil price brave new world

Oil prices have never been easy to predict and despite the vast amount of data points out there, making sense of it all remains a big challenge. Two themes have emerged in the past decade that has changed the landscape and makes understanding the oil markets difficult: emergence of non-sophisticated traders and US exports.

Non-sophisticated traders have replaced traditional traders. These new (and now established) entrants trade off newsflow rather than fundamentals. Whilst the fundamentals have pointed to a positive supply demand picture for oil prices in the past few years, consistent bombardment of rig count and inventory data has meant fundamental trends have not surfaced to the front of mind leading to what can be viewed as depressed oil prices throughout the period 2015-17. With global inventory rebalancing now taking place and this making its way to the headlines, oil prices have begun to correct in 2018. The problem of non-sophisticated traders has been exacerbated by the financialisation of the market leading to increased volume of trade and exit by some traditional traders.

Secondly, US exports has completely redrawn the map for oil trade flows and the market is still learning what this means. Some of the characteristics that the US has exhibited which the market has never seen before is the short-cycle/ability to ramp-up and turn down production in a relatively short space of time, anti-fragile nature of production resilience, ability to store crude behind pipe (drilled uncompleted wells or DUCs) and wide range of crude blends it can produce. In particular OPEC (i.e. Saudi Arabia) has been experimenting with prices to elicit US production data points in order to study US producer behaviour.

A recent topic around US exports is the divergence of the WTI and Brent benchmarks with the widening spread. This has raised the question of the US’ ability to cater to any demand. WTI has been under pressure recently (vs. Brent) as bottlenecks in export pipeline infrastructure have depressed prices. However, there is significant capacity build-out over the near-term which will alleviate this problem and the persistent discount of c.USD10/bbl of WTI along the back-end of the curve is likely unfounded. While WTI and Brent appear to be showing signs of catering to different markets right now rather than a single global market, trends (and spreads) should converge again over time.

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Anadarko close to Mozambique Area 1 FID and raising USD12 billion debt financing

On 26^th April, Anadarko had "in principle" secured sufficient offtake to enable FID of the first phase of Mozambique LNG on Area 1 offshore Mozambique. The huge resource of 75 tcf is planned to be initially developed via two trains with capacity of 12.88 mtpa. In time, this could eventually be expanded to eight trains producing 50 mtpa.

Since the announcement, Anadarko has also made clear that it expects to debt finance ~USD12 billion of the USD20 billion Phase 1 development, mainly from export credit agencies or ECAs.

In March, Anadarko noted that it had secured 5.1 mtpa of offtake and was close to achieving the 8.5 mtpa needed for FID. It is clear that the company is now very close or has surpassed that threshold with remaining efforts on converting heads of terms and discussions into signed SPA contracts.

Offtakers include a range of Chinese, Japanese and other NOC buyers as well as utilities. It has been reported that deals include France’s EdF, Thailand’s state-run PTT and Japanese utility Tohoku Electric.

This is a good piece of news for Mozambique LNG which is finally showing signs of moving ahead and follows finalisation of development concessions with the Mozambique government last year. The Area 1 FID could potentially overtake ExxonMobil's Area 4 project, in which ExxonMobil acquired a 25% from Eni in 2017 (the deal closed in December 2017).

Area 1 ownership stakes
Source: Bloomberg, Mozambique LNG

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RockRose acquires Dyas' Netherlands portfolio for €107 million

RockRose has announced the acquisition of Dyas' Dutch portfolio for €107 million.

Press release follows:

RockRose Energy plc is pleased to announce that it has signed a Sale and Purchase Agreement to acquire the entire issued and to be issued share capital of Dyas B.V. (the "Acquisition"), which owns the non-operated, Netherlands gas and condensate producing assets of the Dyas group of companies, for a total consideration of EUR €107 million. The Dyas group of companies is wholly owned by SHV Holdings N.V., a family-owned Dutch multinational.

The Acquisition, which has an effective date of 1st January 2018, will be funded from existing cash resources with no debt or equity issuance or shareholder approval required. There will be a significant working capital adjustment at completion.

The Acquisition adds a further 13 MMboe net developed reserves (with material undeveloped and prospective resource upside) and over 5,000 boepd of production to the Group. Post completion RockRose estimates combined Group 1P reserves of approximately 23 MMboe and 2018 pro-forma production in excess of 10,000 boepd. The Group's production will be circa 60% gas and 40% oil.

Both the existing asset base and those assets to be acquired have incremental opportunities which the Board believe could add significantly to the Group's reserve base and maintain current production for at least the next five years, with Rockrose's portion of the associated capex to be funded from the Group's operating cash flow.

Andrew Austin, Executive Chairman of RockRose Energy said:
"On completion this acquisition grows our North Sea business to a level of production that is over 10,000 boepd and in addition to providing significant free cash flow diversifies the portfolio and strengthens the Company's position. Management sees significant upside in the combined portfolio and is confident RockRose can organically maintain or grow profitable production from these levels without necessitating additional funding."

Robert Baurdoux, CEO of Dyas, said:
"After a presence of over 50 years in the Netherlands, the divestment of our Dutch entities is part of a strategic refocussing of our business. RockRose Energy is well placed to take-on the stewardship of the Dutch assets, allowing Dyas to pursue new investment opportunities in the UK, Norway, Denmark and Malaysia."

Link: https://ir.euroinvestor.com/Tools/newsArticleHTML.aspx?solutionID=2446&customerKey=rockroseenergyplc&storyID=13931066&language=en

The Dyas Dutch portfolio comprises the following (offshore unless specified otherwise):

Concession	Operator	Dyas % Interest
Alkmaar Peak Gas Installation (onshore)	TAQA	12.00
Bergen-II (onshore)	TAQA	12.00
A12a,d	Petrogas	14.63
A18a,c	Petrogas	14.63
B10a,A12b	Petrogas	14.63
B10c,B 13a	Petrogas	14.63
B16a	Petrogas	14.63
F2a Hanze	Dana	20.00
F2a Pilocene	Dana	12.00
F6b	Dana	14.00
F15a,d	Total	7.50
F15a (B-Field)	Total	8.82
J3b,J6	Centrica	7.50
Markham Unit	Centrica	4.43
J3-C Unit	Total	1.73
K4b,K5a	Total	11.66
K4b,K5a-Unit	Total	6.98
K5C-EC2Unit	Total	7.67
K5-F Unit	Total	8.86
L16b	Oranje-Nassau	30.00
K18b,L16a	Wintershall	10.00
P6-D	Wintershall	30.60
P6 Main Field	Wintershall	15.00
P6-South	Wintershall	24.38
P9a,b	Wintershall	15.58
P9 A+B Unit	Wintershall	11.61
P9c	Wintershall	9.88
P12 (Part Area)	Wintershall	23.61
Q1-B Unit	Wintershall	2.59
Q4-A Field	Wintershall	10.35
Q4-B Unit	Wintershall	10.25
Q5d	Wintershall	5.62
P15a,b	TAQA	8.99
P15c	TAQA	9.71
P15 Rijnfield	TAQA	45.69
P15-9 Unit	TAQA	5.30
P18a,c Unit	TAQA	0.68
P18c	TAQA	3.75
P18-6A7 Unit	TAQA	2.82

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Kurdistan uncertainty: imposing higher export charges

All’s well in western Kurdistan

DNO export payments

Kurdistan operators received payment for January crude exports in April. The increasing oil price should feed through into the payments over the next few months as operators get paid for sales made in Q1 2018.

However just as the improving oil price is about to kick in, it appears that Kurdistan is looking to reap some of the benefits back from the operators. In April 2018, DNO disclosed that the discount to Brent on its Tawke crude had increased from USD12/bbl to USD13.15/bbl. This has been dressed up as an increase in the transportation tariff and quality discount, although this may mask the underlying reason for the increase driven by desire of the KRG to extract more money.

Despite increasing record of payments, Kurdistan remains an uncertainty for oil & gas companies with upcoming elections in Federal Iraq and ruling on the legality of crude exports from the region. Surprises of sudden increases in export tariffs do not help its case either.

We also question the ability of Kurdistan to maintain payments to operators given its accumulated debts, particularly to civil servants and Peshmerga, as well as the loss of export revenue from the disputed Kirkuk fields.

Related links:

• Kurdistan E&Ps get paid for January sales
• All’s well in western Kurdistan

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Aphrodite gas: lover's quarrel

Aphrodite is owned by Noble (35% operator), Delek Drilling (30%) and Shell (35%). The field lies in Block 12, offshore Cyprus and was discovered in 2011. BG Group farmed into 35% from Noble Energy in November 2015 for USD165 million following declaration that the field was commercial in June 2015.

As reported earlier, Shell intends to use Aphrodite gas to supply ELNG, but this has now faced a new hurdle. Cyprus and Israel are arguing over the extension of the Aphrodite structure into Israeli waters. Given the importance of the gas, the regional governments are keen to avoid the dispute delaying the commercialisation of the field.

Despite its vicinity to and significantly earlier discovery than Zohr (2015), Aphrodite remains uncommercialised. In fact, its commercialisation was previously called into question given the resource was too small to justify export infrastructure. This is a recurring theme within East Med gas with export route remaining a key issue. Egyptian gas discoveries are lucky enough to have a short gas domestic market and the option to export via LNG.

Israeli gas has taken longer to get off the ground, but has reached sufficient scale to export into the region by pipeline beyond supplying its own domestic market.

Cypriot gas, and indeed Lebanon, face the challenge of a small domestic market and lack of gas export infrastructure. Cyprus has toyed with the idea of developing its own LNG terminal but currently lacks the scale of reserves required to do so.

It makes sense for Aphrodite to supply ELNG at Idku. Shell has ownership in both Aphrodite and ELNG and a direct pipeline to the plant would allow it to bypass the Egyptian gas grid. Furthermore, a direct pipeline could galvanise further exploration and development activity along the route.

ELNG is largely supplied by the West Delta Deep fields and has been operating at minimal levels since gas was diverted to the domestic grid in 2013. In 2017, it shipped 0.78 million tonnes in cargoes (vs. capacity of 7.2 mmtpa). This has meant the plant remains operational and ready to ramp up once gas is supplied. In contrast, the Damietta LNG plant has been idled and would require significant work to restart operations.

The partners of Aphrodite are now finalising the field development plan with the Cypriot government. The plan initially involves five wells with a combined output of 800mmcf/d and developed using a floating platform. Cost estimates are estimated at USD2.5 - 3.5 billion excluding the cost of any pipeline to ELNG at Idku.

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Santos rejects Harbour and goes alone

Santos has rejected Harbour Energy's upped bid of US$5.21/share (A$6.86) - we expect Habour has given up on Santos for now having made a number of failed approaches and putting forward fairly full bids.

Harbour re-approached in April 2018 with a bid of US$4.98 (A$6.50) subject to due diligence, funding and unanimous recommendation from the Santos board. This bid was at a 28% premium to the prevailing share price and a 43% improvement to the A$4.55 bid made in August 2017.

Following engagement with Santos in April and May, Harbour returned with its "best and final" bid of US$5.21. Santos cited the following reasons for rejecting this bid:

• Increase in Brent which has lifted the share price of its peers on the ASX
• Acquisition would be highly levered and require Santos to enter into hedging prior to transaction close to support Harbour's financing efforts
• Restriction on conduct of Santos' business from time of entering the Scheme Implementation Deed
• FIRB approvals
• Offer in US$ with Santos shareholders bearing the risk of fluctuations in the A$/US$ exchange rate

Ultimately, the rejection by the board is down to price and the recent rally in Brent has supported their argument.

Santos will now have to go alone and demonstrate to shareholders that it can independently create value. The board has put out strong messages that it will be able to do so with the company now entering strong cash flow generation territory and reduction in the company's debt significantly ahead of initial targets.

Harbour Energy is a private equity vehicle backed by EIG Global Energy Partners.

ENN/Hony hold c.15% shareholding in Santos and under its shareholding agreement, is obliged to vote in agreement with the majority of the Santos' board on matters of control.

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Cameroon FLNG: Hilli Episeyo ships first FLNG cargo

The Hilli Episeyo FLNG project has exported its first LNG cargo, destined for China, and is on the way to producing its second cargo.

It is the first FLNG project to take off in Africa and could pave the way for future projects in Equatorial Guinea (Ophir's Fortuna project) and Mauritania (BP/Kosmos).

FLNG technology was been pursued by Golar after the cost of land based LNG projects soared. Golar has been converting old LNG tankers into liquefaction units and the Hilli Episeyo will be important to demonstrate the viability of FLNG as a solution to stranded gas.

All of the gas at the Cameroon Hilli Episeyo project is sold to Gazprom's trading arm for a period of 8 years. The capacity of the project is 1.2mmtpa.

#Perenco

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