Putumayo smart crude marketing

Putumayo producers are blessed with having multiple export routes and the flexibility that affords in maximising sales netbacks.

The most direct route is the OTA pipeline to Tumaco. However this route has historically been plagued by attacks leading to downtime and the South Blend crude at Tumaco also fetches one of the biggest discounts to benchmarks vs. other region blends.

This has led to producers accessing Ecuadorian export routes through either the OCP or SOTE pipeline to Esmeraldes. At the port of Esmeraldes, the two key blends are Napo (19° API) and Oriente (24° API). Oriente being the lighter crude fetches a higher price.

Another option that has been employed is the trucking or part truck/part pipe of crude to Coveñas. At this port, the Vasconia blend fetches a good price and sells into the Caribbean market.

At the end of 2016, Amerisur completed its OBA pipeline linking its Platanillo field directly to Ecuadorian export infrastructure. Previously, Amerisur had to truck crude to a pipeline entry point to the OSO or OTA pipeline. The OBA link allowed Amerisur to reduce average transportation costs from c.USD14/bbl to below USD4/bbl. The link, despite taking many years to complete, cost USD18 million and in February 2018 Amerisur announced that the pipeline had been paid by within 15 months with cost savings achieved to that date of USD20 million.

Related link: Bienvenido Victor Hugo

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Shamaran acquires more of Atrush

Shamaran has acquired an additional 15% interest in the Atrush field for USD60 million. This takes its share from 20.1% to 35.1%. The remaining owners are TAQA 39.9% and KRG 25%).

The field began producing in July 2017 and currently has capacity to produce at 30mbopd. There are longer term plans to debottleneck and add future phases, potentially taking production beyond 100mbopd.

The field’s potential is underpinned by its 102.7mmbbl 2P reserves and c.300mmbbl 2C resources.

The Atrush partners continue to receive regular payments from the KRG and Shamaran has taken the opportunity to refinance and upsize its bond to USD240 million.

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Majors pick up acreage in Brazil

Equinor press release:

Equinor, ExxonMobil and Petrogal Brasil presented the winning bid (75.49% profit oil) for the Uirapuru production sharing contract in the Santos basin. Petrobras exercised its right to enter the consortium and will be the operator with 30% equity.
The final equity distribution is Petrobras (30% operator), Equinor (28%), ExxonMobil (28%) and Petrogal Brasil (14%). The pre-determined signature bonus to be paid by the bidding consortium is BRL 2,65 billion (approximately USD 682** million). The Uirapuru exploration block is located in the Santos basin, north of the BM-S-8 (Carcará discovery) and North Carcará blocks, both operated by Equinor.

A consortium comprising Equinor (25%), Petrobras (45%, operator) and BP (30%) were the high bidders (16.43% profit oil) for the Dois Irmãos producing sharing contract in the Campos basin. The pre-determined signature bonus to be paid by the bidding consortium is BRL 400 million (approximately USD 103**million). The Dois Irmãos block sits adjacent to an area where Equinor with partners were awarded four high potential blocks in the 15th licensing round in March.

“We are very pleased with the opportunities secured in the 4th PSA round,” says Tim Dodson, Equinor’s executive vice president for exploration.

“The prolific basins offshore Brazil represents world class exploration acreage. The results from this and previous bid rounds have added highly prospective acreage to Equinor’s exploration portfolio, allowing us to maintain a significant activity and pursue high value prospects in Brazil in the years ahead,” says Dodson.

“The outcome of this round further strengthens our position in Brazil, considered as a core area for Equinor. We are looking forward to working with our partners, the Brazilian authorities and Pré-sal Petróleo S.A. on the development of these new blocks. We have been increasing our investments in the country in the last two years and our expectation is that this will represent more jobs, taxes and, in the future, royalties that will benefit local communities,” says Anders Opedal, Brazil’s country manager.

This adds to Equinor’s existing portfolio in the Brazilian pre-salt area, which includes BM-S-8 and Carcará North, both in Santos basin, and the BM-C-33 in the Campos basin, containing the Pão de Açúcar discovery.

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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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