Kurdistan producers receive fourth consecutive payment from the KRG

Tawke processing facilities
Source: KRG

On 6^th January, DNO and Genel announced that partners of the DNO-operated Tawke field have received a gross payment of USD30 million from the Kurdistan Regional Government for oil exported through the Kurdistan Region of Iraq-Turkey pipeline. This represents the fourth export payment by the KRG since payments recommenced in September.

On 5^th January, Genel also confirmed that the Taq Taq field partners had received a gross payment of USD30 million from the KRG for oil exported through the Kurdistan Region of Iraq-Turkey pipeline with Genel’s share of the payment being USD16.5 million.

It is interesting to note that payments to the oil companies have remained flat (at USD75 million per month) during the past four months, despite a collapse in the oil price from c.USD50/bbl at the start of September to c.USD36/bbl at the end of December 2015. This means that the international oil companies' share of Kurdistan's oil revenues is slowly creeping up.

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Saudi Arabia: fissures within

King Salman

The lack of agreement between members at the 168^th OPEC meeting on 4^th December means that Saudi Arabia can continue to pursue its strategy of maintaining market share over price for a little longer. In fact, recent production figures show that Saudi Arabia is pumping record amounts of crude this year, a sign of its commitment to this strategy.

However, with oil prices reaching recent lows of c.USD40/bbl and little sign of a recovery anytime soon, questions are being raised on whether this was the right strategy to pursue. The country’s 2015 budget was based on an oil price of USD90/bbl, but with the ongoing war in Yemen and King Salman handing out money to stave off public discontent, the fiscal breakeven oil price is now approaching USD110/bbl, almost triple of where Brent is currently hovering.

Members of the royal family have begun questioning King Salman and his son, Prince Mohammad bin Salman’s, ability to run the kingdom, culminating with letters written by an anonymous Saudi prince calling for a coup against the King – these letters were published in The Guardian newspaper in September 2015. The letters assert that King Salman and his son are pursuing dangerous policies that will lead to the kingdom’s ruin. Apparently the call for the change in leadership has widespread support from within the royal family and wider Saudi society, although few will publicly acknowledge this given the history of harsh crackdowns on any dissenters.

Aside from scepticism over oil policy, the Saudi intervention in the Yemeni conflict has also become a serious source of unease inside and outside the palace walls. Prince Mohammed bin Salman, who is in his early 30s, and has been educated domestically with limited military training is viewed as lacking the necessary experience in running the country’s defences. His unofficial nickname, “Reckless”, reflects an increasingly held view that he rushed into Yemen without a well thought-out strategy and the war is now consuming a significant part of Saudi’s budget with no end to the conflict in sight.

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The Egyptian gas landscape

The Egyptian gas sector has historically suffered from underinvestment and the country has experienced a domestic supply shortfall since the beginning of 2015. Subsidised gas pricing encouraged strong demand growth during the 1990s and 2000s and at the same time, declining gas reserves in the onshore and the high cost of offshore gas developments have resulted in investment being diverted away from gas to onshore oil.

The state of the gas market has led to two major concerns for the government: (i) the energy subsidies have become habitual and a key contributor to the fiscal deficit which is unsustainable at current levels; and (ii) persistent energy shortages and brownouts have been a cause of public discontent in recent years at a time when the government is trying to restore stability post the Arab Spring. President Sisi and his administration are keen to entirely phase out energy subsidies in an attempt to tackle the fiscal deficit, encourage more responsible energy use and reinvigorate investment in gas development. The move, which should lead to gas pricing increasing over time, is welcomed by international investors and the E&P industry.

In 2015, Egypt became a net gas importer in the face of a domestic supply shortfall. This followed the diversion of LNG export volumes to the domestic market with the Gas Natural operated Damietta plant and BG operated ELNG plant being placed into force majeure in 2013 and 2014 respectively. During 2015, two LNG regasification facilities were installed at the Port of Sokhna and multi-year supply deals were concluded with LNG sellers; the lease of a third regasification unit is under consideration. Discussions are also ongoing to import gas from Israel by pipeline to supply industrial customers and the grid.

LNG imports are an expensive source of gas supply and the government is keen to boost domestic production and reduce dependence on imports. The government has envisaged a gas supply shortfall for a number of years and has agreed to increase the gas pricing or improve fiscal terms for a number of developments since 2008; the pace of these revisions has increased in recent years. In 2015, Dea agreed a new gas price of USD3.5/mcf, BG and Eni agreed up to USD6.06/mcf for new phases of offshore developments and Apache’s shale gas production will receive USD5.45/mcf.

In July 2015, Eni made the Zohr discovery which is estimated to hold 30tcf of gas in place. The large resource base has the scope to help Egypt regain gas self-sufficiency (potentially with a return to gas exports), although in the near term, the country remains in a gas shortage and reliant on imports. Zohr’s ability to effectively address Egypt’s future gas shortfall could potentially limit the liberalisation of gas pricing. Despite the discovery being in deepwater (~1,500m) and 200km offshore, initial estimates suggest that a gas price of USD4.5/mcf could result in a 15%+ IRR for the project due to the large volumes and low operating costs once onstream. However, with the government’s plan to remove subsidies and IOCs’ desire to maximise gas pricing for developments/production, the outlook for the Egyptian gas sector appears positive. In the near term, costlier gas developments may be delayed or their ability to achieve higher gas pricing may be impacted by more favourable Zohr economics, however domestic gas pricing has the potential to increase significantly from current levels of USD2.73/mcf.

Egypt gas supply excess / (deficit)
Source: Wood Mackenzie, BMI research, BP Statistical Review of the World, EIA, OGInsights

Egypt gas pricing for producers
Source: Wood Mackenzie

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Repsol and Statoil announce asset swap

Alfa Sentral platform in the North Sea

On 11th December, Statoil and Repsol announced that they had entered into number of asset swaps as part of a packaged deal:

• In the North Sea, Statoil farms down a 15% WI in Gudrun (Norway), whilst retaining operatorship and will acquire a 31% WI in Alfa Sentral (UK portion), a field which spans the UK-Norway border
• In the US, Statoil acquires a 13% WI in the Eagle Ford JV and becomes operator, taking its interest to 63%; Repsol’s interest reduces to 37%
• In the Brazil Campos Basin, Repsol-Sinopec will transfer operatorship of the BM-C-33 licence to Statoil

Summary of asset swaps

From Statoil's perspective, sole-operatorship on the Eagle Ford JV will allow the company to have more control of the project going forward and improve efficiency of the operations. The JV was previously jointly operated with Repsol operating one-half of the acreage and Statoil operating the other half, leading to sub-optimal development. In the North Sea, Statoil will remain the largest partner in Gudrun and will consolidate its position in Alfa Sentral. Statoil increased its interest in the Norwegian part of Alfa Sentral to 62% in October 2015 (from First Oil) and the 60mmboe gas condensate field is a priority project for Statoil and will be developed as a tie-back to the Sleipner Area. The assumption of operatorship in Brazil will further Statoil’s strategy of growing in the country and enable the company to build on its deepwater experience.

Alfa Sentral tie-back to Sleipner

For Repsol, the key swap is the reduced interest in the Eagleford, alongside acquiring a producing asset in the form of Gudrun. The transaction will support Repsol’s financial position and stretched balance sheet with cash flows expected to improve by €500m in the period 2015-17. Furthermore, the transfer of operatorship in Brazil is consistent with Repsol’s focus on three themes (onshore, shallow offshore and unconventionals) as outlined in its 2016-2020 strategic plan.

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Bienvenido Victor Hugo

Amerisur's pipeline into the Victor Hugo field

On 1 December, Amerisur provided an operational update on its interconnector pipeline from Platanillo to the Ecuadorian export pipeline. Once operational, oil export will benefit from the low cost, under-utilised Ecuadorian infrastructure bringing transportation costs to below USD5/bbl. In addition to improved netbacks, the excess export capacity will support increasing production levels at Platanillo.

The pipeline is expected to be operational at the beginning of 2016 compared to the original expectations of end 2015 due to an outstanding environmental approval, which has been delayed by personnel changes at the Ecuadorian Environment Ministry. The permit is expected to be issued imminently and will allow the drilling of the 1.4km under-river crossing from Platanillo to the Ecuadorian river bank and construction of the 3.8km pipeline from the river bank to the connection point (under construction) at the southern point of the Victor Hugo field.

Pipe laying operations have commenced from the facilities on the Victor Hugo field to the new connection point – this 14km stretch of pipeline should be fully welded and trenched by year end. At the Victor Hugo field itself, civil works to prepare for the receipt and handling of Platanillo crude are c.80% complete with tankage, piping and instrumentation largely in place.

The pipeline should be ready for operational testing and commissioning around year end with initial transportation of oil through January. Aside from the environmental approvals, certification of the LACT units (fiscal measuring points) on the Colombian and Ecuadorian sides will take around two weeks once the pipeline is operational.

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Fortnum & Mason: the true cost of Christmas

Spending became complacent when oil prices were high and now with oil prices in a lower for longer environment, oil companies are tightening the purse strings. All costs are scrutinised, projects are being sent back to the drawing board to be re-engineered and no dollar of spend is approved unless it is absolutely necessary. In the spirit of Christmas, the team at OGInsights thought we would do a little cost scrutiny of our own following stories about the cost inflation of Christmas hampers.

Fortnum & Mason's Imperial Hamper costs £5,000

We had a look at the Fortnum & Mason’s Imperial Hamper which can be purchased for the small sum of £5,000. How much would it cost if all the items were bought separately? We looked at the maths and the answer is £3,036.55 (excluding the tea caddy which isn’t available to buy standalone). This implies one of two things, both of which are extraordinary and outrageous! Either Fortnum & Mason’s are charging a mark-up of £1,963.45 on top of the profit of the individual items, simply for the service of putting everything into a hamper for you or the basket, packaging and tea caddy are worth £1,963.45! Full workings below - all credit to our guest contributor Alistair F.

What about all the trouble of going around the store picking up all the items you say? Well, you can either order online, or if you are spending £3,036.55, we are sure the personal shoppers will be more than happy to help out in store.

Actual cost of the Fortnum & Mason's Imperial Hamper

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ExxonMobil - finding a needle in a haystack

We met with ExxonMobil in the first week of December to catch up on what they have been up in 2015 on the M&A front. The low oil price has certainly prompted an internal flurry of screening for targets and the teams have been looking at “a lot of opportunities” with billions of dollars ready to be spent on acquisitions. Despite a desire to do something, finding the right opportunity is still like “finding a needle in a haystack”.

ExxonMobil’s corporate development team is split into two divisions – Upstream Ventures which look at deals up to USD20 billion and Corporate Strategic Planning which look at deals above USD20 billion. Acquisitions broadly fall into three categories which are generally independent of size:

• Bolt-ons – these are generally small acquisitions to supplement an existing position although larger acquisitions will be considered on a case-by-case basis 
• Expansions – these are to materially grow an existing position into a wider position; size is opportunity specific and considered on a case-by-case basis
• New entry – these are always sizeable acquisitions as they must have sufficient critical mass in order to establish a new position

Outside of North America, Africa and the Middle East are regions of keen interest and we discussed two themes around current market developments.

The Africa Oil farm-out to Maersk was viewed as interesting and ExxonMobil remarked that more innovative structures, such as the one adopted by Maersk, was likely needed to get deals which weren’t clear winners over the line in the current oil price environment. East Africa is an area which ExxonMobil’s technical team have evaluated before and they remain cautious on the prospectivity (noting that no-one outside of Tullow/Africa Oil has been successful in the region) and timing to first oil (given the export pipeline infrastructure is yet to be built).

On Kurdistan, ExxonMobil are comfortable with the region geologically but see very few opportunities of sufficient size to justify building up a full-scale presence. This likely limits the opportunities to a handful such as Genel and Gulf Keystone. Payments for exports by the Kurdistan Regional Government remain a key issue and ExxonMobil noted that any slippage of payments could severely depress project economics as well as delaying any development spending. The Kurdistan Regional Government have implemented payment schedule on multiple occasions in the past which subsequently collapsed and it yet remains to be seen whether the current payment plan, implemented in September 2015, can be sustained.

ExxonMobil will continue to scour the international E&P landscape for opportunities and believe that current environment is a good time to act, but finding the perfect opportunity remains a challenge.

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