Statoil acquires stake in Lundin Petroleum

On 14th January, Statoil announced that it had acquired 37.1 million shares in Lundin Petroleum, corresponding to 11.9% of the company. Statoil says that it paid c.SEK4.6 billion for the shares, which equates to a price of SEK120/share or a 28% premium to the share price close as of yesterday at SEK97. Statoil purchased the shares over the past few weeks and says it is supportive of Lundin management, its board of directors and strategy, but there is currently no plan to increase its shareholding in the company.

Statoil says "this is a long term shareholding. The Norwegian Continental Shelf is the backbone of Statoil's business, and this transaction indirectly strengthens our total share of the value creation from core, high value assets on the NCS". Despite the longer term strategic rationale, the move is unexpected. Lundin is one of the more expensive E&P stocks and the transaction further increases Statoil’s exposure to the giant Johan Sverdrup development. Questions are now being asked by the market on whether Statoil can continue to pay its dividend.

From an E&P sector perspective, the move is encouraging as it demonstrates industry interest in the subsector, and the news should help shore-up Lundin’s share price. Nevertheless, corporate activity is likely to remain muted until the oil price starts to recover and confidence returns to the sector.

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PTTEP may pre-empt BG Bongkot process

On 12th January, it was reported that PTTEP, Thailand’s state owned oil company, is keen to acquire BG’s stake in Bongkot. The Bongkot area is located in the Malay Basin in the Gulf of Thailand and consists of various gas accumulations. It is currently owned by PTTEP (44.45% operator), Total (33.33%) and BG (22.22%). PTTEP’s potential desire to acquire this asset is in line with the strategy of Asian NOCs’ of security of supply. For BG, the disposal represents an exit of a non-core asset which supplies gas only to a domestic market and a tidy-up of the portfolio ahead of its merger with Shell.

Southeast Asia M&A environment
The Southeast Asian M&A market has historically accounted for a small portion of global M&A activity (c.7% by deal value and volume between 2009 – 2014); this is largely due to the relative sporadicity of assets that come to market. High quality assets that become available generally garner strong interest from regional players seeking to consolidate around existing positions and competencies in a part of the world which has experienced strong energy demand growth over the last decade (c.3.5% p.a. since 2000 according to the IEA).

The region is dominated by majors, select large-cap E&Ps and regional NOCs and independents. A number of North American players have recently made divestments in the region as part of wider international retrenchment plans (e.g. Hess, ConocoPhillips) – asset sales have generally been met with strong interest. Recent international new entrants include Ophir Energy (acquired Salamander Energy, RBC acted as a joint financial advisor to Ophir) and CEPSA (acquired Coastal Energy).

In the current oil price environment, gas assets with long term gas sales agreements are viewed as particularly attractive, although may not fit the strategy of players (particularly NOCs) seeking oil-weighted production exposure and more flexible supply or off-take. Although oil-weighted assets are a clearly stated preference, assets with strong production cash flows, such as BG Bongkot are also of interest irrespective of the oil/gas weighting.

Thailand is seen as an attractive area for upstream investment, despite the high level of government take. The country is a net importer of hydrocarbons with the domestic supply shortfall expected to increase as a result of continued economic growth. Economic growth supported by government spending on large infrastructure projects and improvement in political stability, whilst gas demand growth driven by switch to gas-fired power plants. The basins are established and proven with further exploration potential and licensing rounds are held regularly.

BG Bongkot sale process
Feedback from various industry players on the BG Bongkot sale process indicates that there is select interest. It is understood that the Chinese NOCs have entered the process, however the opportunity has only attracted weak interest internally; their ability to be competitive in a time critical auction situation is also questionable given increased internal procedures now required following corruption probes. Other regional players, including local NOCs, see limited strategic rationale in acquiring a domestic supply asset and some have limited financial capacity; Indonesian focused players see more compelling opportunities in their home market which are currently live or upcoming (e.g. ConocoPhillips’ interest in South Natuna Sea Block B).

PTTEP’s pre-emption has already been flagged as a key concern by a number of potentially interested parties which is likely to have discouraged some companies from participating in the process. PTTEP’s pre-emption is a key risk given its active strategy to secure supply in the region (as demonstrated by recent acquisitions of Hess’ assets in Thailand and Indonesia) and its strong balance sheet position. PTTEP pursue an active M&A strategy with 10 acquisitions made globally since 2010 and with a total disclosed deal value of ~$6bn. The state company generally acquires acreage in Thailand through licence awards, but will consider M&A for strategic assets that come to market; in 2014, PTTEP acquired Hess’ 35% in Sinphahorm and 15% in Pailin gas fields in which PTTEP was an existing partner in both.

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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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