ConocoPhillips' mix of a North Sea portfolio

ConocoPhillips' is one of the largest operators in the UK North Sea, being the operator of the Britannia area, the J-Area and large swathes of the Southern North Sea. ConocoPhillips is also a non-operated partner in the giant Clair field.

Clair is one of the largest oil fields in the UK offshore and located in the West of Shetlands which is making a name for being the last frontier of the UK and is increasingly attracting further exploration activity. The Clair field was brought onstream in 2005 and is currently undergoing a second phase of development (Clair Ridge). Clair Ridge is planned to come onstream in Q4 2018 with operator BP targeting an additional 640mmbbl which will extend the life of the Clair Area beyond 2050. As soon as Clair Ridge is onstream, the partners will be planning for the Phase 3 of the development known as Clair South.

On the operated assets, Britannia is one of the largest gas fields in the UK which has acted as a hub for various tie-backs over the years. The J-Area, although now beginning to mature, has been a highly successful gas hub in the Central North Sea where more infill drilling and exploration activity is planned into 2019 and 2020.

The Southen North Sea assets are the most mature with some going into decommissioning. ConocoPhillips has widely announced the closure of the Theddlethorpe gas processing plant which is the terminus for its CMS pipeline. This will lead to early/forced decommissioning of all the fields which currently utilise the CMS pipeline as the export route including the Faroe and Tullow Schooner and Ketch fields which will cease production in August 2018.

The ConocoPhillips' UK portfolio is concentrated around a few hubs and excluding the Southern North Sea, has a good amount of life remaining with current production at c.80mboe/d.

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Saudi and Russia dominate gossip columns in run up to June OPEC meeting

As we approach the June OPEC meeting, all eyes on Saudi Arabia and Russia for any clues on the direction they will go on 22nd June. With the sanctions on Iran and imminent collapse of Venezuela, Trump has asked the two power weights to step in to avoid oil prices going any higher. This in itself is ironic as the US has been trying to wean itself off imports and attain energy independence from OPEC, yet it is now openly asking Saudi Arabia to help.

In recent days, both Saudi Arabia and Russia have hinted at wanting to increase production by 300mbopd, although the details remain to be thrashed out- i.e. will it be these two countries shouldering the increase or will it be spread amongst the OPEC members. The path this will take and desire to increase production will be dictated by whether consensus can be reached next week.

On the one hand, keeping a lid of oil prices is important for OPEC to avoid a wave of US production coming onstream with producer hedging. On the other hand, a number of OPEC nations urgently require cash flow from higher oil prices to balance precarious budgets.

If consensus can be reached to increase production, the additional barrels can be met by Saudi Arabia and Russia making up the production but will likely be criticised by other OPEC members of using the opportunity to snatch market share. An alternative would be for the members’ quotas to be renegotiated although this will open up another can of worms. In the case of the latter, it is noted that not all members are in a position to raise production (e.g. Venezuela, Nigeria, Libya which are fraught with domestic difficulties). Finally, OPEC members have been in over compliance so there remains running room to utilise the existing quotas, although this will again be shouldered by Saudi Arabia and Russia.

In the medium and longer term, fundamentals point to a supply shortfall so gradually raising production now will keep prices under control although the path ahead will remain choppy.

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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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