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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CNOOCNexen on the prowl

Last week, we met with the CNOOCNexen corporate team to discuss their thinking in the current low oil price environment and the possibility of using the opportunity to make acquisitions.

At the beginning of 2015, CNOOCNexen expected oil prices to settle at c.USD60/bbl and the second drop in June came as a surprise. Similar to the view held by many oil companies, the oil price is now lower for longer than originally anticipated. CNOOCNexen anticipates oil prices in 2016 to be similar to 2015 levels.

The company’s UK portfolio, which mainly comprise of its 43.21% interest in Buzzard and 36.54% interest in Golden Eagle, is in a relatively good place with operating costs of below USD20/bbl. While the UK operations are not making a fortune at current oil prices, it is keeping its head above water which is more than what can be said for many North Sea fields.

M&A remains on the radar with Beijing head office looking for opportunities in the UK, Brazil, West Africa and Southeast Asia. In fact, the UK North Sea has been cited as one of the top desired areas for further investment and growth. Corporate and farm-in opportunities at all stages of the lifecycle from exploration through to production are of interest. CNOOCNexen did not disclose their oil price assumptions for evaluating acquisitions, but noted that they are beginning to see convergence between buyers and sellers in the market. In terms of acquisition size, USD5 billion would be the top end of what could be do-able. However, CNOOCNexen are still waiting for some stability in oil prices and cost indices before they can feel comfortable with valuations internally and start to make moves.

In the UK North Sea, acquisitions would be to “keep the engine running” rather than building a new business. CNOOCNexen are looking for assets where there is scope for upside and their team could add value; in this regard, assets which have demonstrated reserves creep are of interest such as Apache’s Beryl field and Shell’s Pierce field. Upcoming disposals from the majors, whether piecemeal or as a portfolio, are opportunities coming to market that CNOOCNexen are keeping a close eye on. Development assets are not ruled out given the current North Sea portfolio is in a tax paying position and development expenditure could be used to offset against profits. CNOOCNexen are now beginning to explore heavy oil opportunities as the size of the resource and progress in developing technology to exploit heavy oil (such as by the likes of Statoil) means it can no longer be ignored as a strategy. 

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Premier Oil exits Norway

Premier Oil Norwegian operation
Source: Premier Oil

On 16 November 2015, Premier Oil announced that it had agreed to sell its Norwegian business to Det Norske for USD120 million. The Norwegian business consists of the Premier Oil Norges subsidiary and includes the Vette development, adjacent Mackerel and Herring discoveries, a non-operated stake in Froy and seven exploration licences.

The transaction is expected to close before year end and proceeds will be used pay down debt. The exit of the business will give rise to a G&A saving of c.USD20 million p.a. as well as remove capital requirements for the Vette development that was progressing towards sanction.

For Premier Oil, the sale is in line with the company’s ongoing portfolio management strategy and is an important step to managing the high debt levels.

For Det Norske, the acquired business will bolster its Norwegian portfolio and Det Norske will be able to offset its production against the tax losses in Premier Oil Norges (from spend on Vette and Froy) which stood at USD146 million as at mid-2015. Det Norske will fund the acquisition from internal cash resources.

Tony Durrant, CEO of Premier Oil commented:

“We are pleased to have reached agreement to sell our Norwegian business to Det norske, one of our long term partners in Norway. Our team in Norway has done an excellent job in bringing the Vette project close to a sanction decision in a low oil price environment. The transaction will realise immediate value from the project as part of our strategy of active management of our portfolio.”

Karl Johnny Hersvik, CEO of Det Norske commented:

“Following the recent closing of the Svenska transaction, the acquisition of Premier is another bolt-on acquisition that further underlines our firm belief in and commitment to the Norwegian Continental Shelf.”

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Petroamerica’s call for cash

A sign of the times, another independent raises funding as the low oil price environment continues to hit small producers hard. On 27th October 2015, Petroamerica became the next in line to ask for cash, raising USD20 million in debentures. The expensive cost of the debt at 13.5% reflects the high risk which investors are attributing to the sector, and also that of Petroamerica. The USD20 million will consist of two USD10 million tranches, with the first expected to close on or around 16 November 2015, and the second six months later.

This fund raise comes shortly after the acquisition of PetroNova and raises the question of whether Petroamerica acquired more than it could take on. A review of the PetroNova asset base suggests that the acquisition appears sensible – the CPO-7 and CPO-13 blocks provide existing production with commitment wells not required to be drilled until July 2016 and July 2017 respectively, the Tinigua block has attractive fiscal terms (0% X-factor) although a commitment well is also required by July 2016 and Petroamerica’s Put-2 position is consolidated to 100%.

Petroamerica - PetroNova combined portfolio
Source: Petroamerica

In hindsight, it can be seen that Petroamerica’s woes stem from pre-PetroNova. At the end of 2014, the company had seven exploration wells and seismic commitments and balance sheet cash of USD73 million, out of which the redemption of a c.USD40 million debenture would be required (essentially leaving the company with c.USD33 million to fund its activities). The exploration portfolio is clearly one for a USD100/bbl oil price environment where production cash flows would have funded drilling. However, at current low oil prices, Petroamerica has been loss making – balance sheet cash as at the end of June 2015 was USD23 million; netbacks fell to USD9.1/bbl for the six months ended 30 June 2015 compared with USD54.2/bbl for the same period last year. The company has spent minimal capex in 2015 to date, conserving precious cash and only spending what it needs to maintain or manage production at its producing assets (Los Ocarros and Sur Oriente).

Some of the exploration commitment deadlines have now passed without being met (no drilling has been reported to date), yet no licences appear to have been relinquished. It is expected that Petroamerica are negotiating hard with the ANH to extend these deadlines; most likely, other cash-strapped Colombian E&Ps are doing the same. Petroamerica should be able to keep the lights on for now with the new USD20 million funding going towards satisfying the commitments. However, unless Petroamerica makes a significant discovery which it can bring onstream quickly, it will be stuck between a rock and a hard place as it continues to battle a declining production base, dwindling cash flows and a shrinking cash balance. It would not be a surprise if the company brings in partners to help with some of its commitments or raises more financing. In the meantime, Petroamerica’s case is not unique and there remains a long line of E&Ps that need more cash.

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Petroceltic: A review of Worldview's concerns

Brian O'Cathain, CEO of Petroceltic

Over the last year, Worldview has been very public about its dissatisfaction with Petroceltic's performance and has openly criticised the board of the company. Earlier this year, it tried to remove Brian O'Cathain as CEO and replace the board with two of its own directors.

Worldview believe the assets are not being managed properly and that the Ain Tsila development in Algeria could be brought onstream at a third of the cost and much more quickly. In this post, we review the key arguments that Worldview have come out with and provide our view on each of these.

Production decline in Egypt
Worldview notes that 2015 production guidance for Egypt of 16.5 - 18.5mboepd represents a 18-27% drop vs. 2014 levels and views such significant drop to be caused by poor management of the wells. Worldview believe they could boost production by a third within months.

We say: The Egyptian assets are mature and production has been steadily declining for the past four years at a rate of c.16% p.a. from 38mboepd in 2010 to 19mboepd in 2014. Unfortunately since the production guidance given in January 2015, reservoir issues have led to a further decline in production and guidance was revised down at the July AGM to 12-13mboepd. The infill programme is now on hold to allow detailed reservoir studies to be carried out. We also agree with Petroceltic's position that attempts to significant boost production as per Worldview risks damaging the reservoir and wells.

Capex being spent in the wrong places
Worldview say that development capex of USD59mm in 2015 on the Egyptian and Bulgarian assets "do not make sense" given the assets are mature and in decline.

In Egypt, Petroceletic notes that the capex is to be used for production optimisation, whilst in Bulgaria, this is required for a tie-back well given the compartmentalisation of the reservoir leading to lack of communication between pools.

We say: Given the halt of the infill drilling programme, capex in Egypt may come in below guidance at the end of the year. Nevertheless, given declining production, the spend is necessary to maintain production levels and to halt decline through infill drilling and optimisation. Similarly for Bulgaria, this capex appears to be rather essential as opposed to nice to spend.

Unnecessary exploration spend
USD35mm has been budgeted for exploration in 2015 with the bulk going towards Egypt. The company aims to rejuvenate its Egyptian portfolio through the drill-bit and had acquired four new licences between 2013-15. Worldview notes that a better strategy might be to acquire low-risk acreage with proven and undeveloped reserves.

The exploration licences cover onshore (South Idku), deepwater (North Thekah and North Port Fouad) and Gulf of Suez (El Qa'a Plain) acreage.

• South Idku is viewed as low risk with geological similarities to Petroceltic's existing acreage with 400-1,900bcf of prospective resources
• The offshore licences are believed to be an extension of the proven Levantine play where >40tcf has been discovered although water depths reach up to 4km 
• The Gulf of Suez block is in an oil-prone area

We say: We agree with Petroceltic's view that this is an opportune timing for operations in Egypt given the country's short gas position. There are three commitment wells over the next three years with two on South Idku and one on El Qa'a Plain. The company is in active discussions with farm-in partners for carry. We note that these licences were signed historically prior to the collapse in oil prices and that spending commitments are now unavoidable. While the onshore licences are generally viewed as lower geological risk, the deepwater licences are a large gamble although there are no well commitments on them.

High opex

Worldview notes the high opex structure and makes comparisons around employees/well.

• Petroceltic: 16 employees/well
• Apache: 9.5 employees/well
• TransGlobe: 6.7 employees/well

We say: Employee/well is not a standard metric. In addition, Worldview are assuming Petroceltic headcount of 365 vs. disclosed headcount of 171 as at the end of December 2014. We note that Petroceltic has a substantial number of staff dedicated to the Ain Tsila development and should not be directly compared with TransGlobe. Apache is a top-tier player in Egypt with its substantial success since entering the country in the 1990s. In June 2015, the company noted that a staff reduction programme had been implemented with 27 reduction in headcount to 144.

Timing and high cost of Ain Tsila

Worldview believe that the development cost of USD1.5bn (gross) is unjustified.

"In our view, the current approach to Algeria is outdated with its unreasonably large budgets and long schedules, aimed to deliver a "gold-plated" custom-designed plant where one is unlikely to be required."

Worldview believe that the project could be completed at USD500mm using off-the-shelf modular gas plants which can be constructed with much shorter lead times.

We say: Significant FEED work has been completed on Ain Tsila with a wide range of options and concepts studied. "Off-the-shelf" gas plants as used in the US are unlikely to be fully compliant with Sonatrach's stringent specifications for gas and target of >95% uptime. Furthermore, the field is 1,700km from the coast with limited infrastructure and the plant has to be designed with minimal risk of breakdown/need for repairs, especially when operating in an environment of c.50 degrees Celsius in the summer. There is additional cost in transporting and constructing a plant in such a remote location and extra costs need to be factored in for security arrangements. We view Worldview's proposal as unrealistic with a lack of understanding of the timescales required when working with National Oil Companies.

Concerns on the bond issuance

Worldview has said that it will take all steps available to stop the bond issue arguing that Petroceltic’s proposed pledging of “the company’s crown jewel”, its interest in the Ain Tsila asset, “will result in squandering shareholder value”. 

Petroceltic notes that the bond has been contemplated for a long time and shareholders have been made aware of the plan for months.

We say: Petroceltic clearly needs the financing unless, as Worldview believe, that production in Egypt can be restored, costs can be cut further and Ain Tsila brought onstream more quickly and cheaply than currently planned. Concerns around pledging Ain Tsila are unjustified since it would need to be security against any future debt that is raised, regardless of whether it is bank or bond debt. In fact, Ain Tsila is already part of the security package for the USD500mm facility that the company put in place in April 2013.

Borrowing powers

Worldview wishes to limit the borrowing powers delegated to the board under its Articles and has proposed that no new debt be raised which contain any of the following provisions:

• Interest rate above Libor + 8%
• Granting of security over the company's assets or subsidiaries
• giving rights over equity securities
• including any structured elements such as contingent coupon

Petroceltic has reviewed guidance from the Investment Association which recommends that companies should limit borrowings that can be incurred without shareholder approval. In this regard, Petroceltic has proposed a resolution to amend the articles that limit the company's borrowings to USD650mm with shareholder approval required for debt in excess of this amount.

We say: The inability to pledge assets is unrealistic and would essentially mean no further debt could be raised. Petroceltic's resolution to limit borrowings to USD650mm is unlikely to appease Worldview and is seen as a token gesture.

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Why Kenyan crude will be exported and not domestically refined

Mombasa refinery
Source: http://mygov.go.ke/national-treasury-sets-aside-funds-to-buy-essar-stake-in-refinery/

Kenya currently has no crude oil production and relies solely on imports to feed the domestic refinery in Mombasa. Aside from feedstock for the refinery, there is no other demand for crude oil in Kenya.

In 2012, domestic consumption of refined products was 73mbbl/d – this was satisfied by 20mbbl/d of domestic production from the refinery and 53mbbl/d of imports. The shortfall in domestic production has been met by imports for many years and this has steadily grown from 22mbbl/d in 2005 along with the increasing demand for refined products. The shortfall suggests that there is scope to increase throughput of the refinery and reduce the level of imports.

Kenya Refined Products Production and Consumption
Source: Kenya National Bureau of Statistics, Kenya Petroleum Refineries Limited, OGInsights

The refinery has a design capacity of 80mbbl/d, but has continually operated at c.40% of capacity. This low utilisation is due to a number of reasons including regular utility supply outages, limitation on size of cargoes it can accommodate, low profitability (some batches of processing are loss making), limitation on product slate and general inefficiency of the refinery. The refinery has a reformer and a catalytic hydro-treater, but no upgrading units; the refinery’s two complexes were commissioned in 1963 and 1974 with minimal investment since. The profitability of the refinery was further hit in 2013 when the incoming government removed the price protection previously provided to the refinery, making it uncompetitive relative to refined product imports.

The refinery’s current configuration is designed to handle heavy crude grades from the Middle East. In 2012, a refinery upgrade project was considered by the then owners (50% Essar Energy, 50% Government of Kenya). The plans included changing the configuration to handle lighter crudes and would incorporate the ability to process Lokichar crude. However, the $1.5bn cost of the upgrade was deemed to be too expensive and uneconomic; as a result the upgrade was abandoned, following which, Essar Energy decided to exit the joint venture. In December 2014, Essar Energy sold its 50% interest in the refinery to the Government of Kenya.

The refinery has been mothballed since mid-2013 and now acts as a storage facility for imported refined products. All demand for refined products are now met by imports. There are currently no plans to restart the refinery, and without further investment, it is unlikely the refinery would be able to operate profitably. Until there is a plan and willing financing to upgrade the refinery, the destination for Lokichar crude is most likely to be the export market - in its current state, the refinery configuration is not designed to process Lokichar crude.

In a scenario where the refinery was upgraded and being wholly fed by Lokichar crude, then feedstock requirements could reach c.100mbbl/d by 2020 in order to fully meet forecast domestic demand for refined products (96mbbl/d estimate by Kenya Petroleum Refineries Limited). However, this scenario is deemed to be highly unlikely in the foreseeable future.

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Colombia calling: Petroamerica acquires PetroNova

Cartagena, Colombia
Source: http://www.backtrackers.nl/colombia/

The Colombian E&P landscape is characterised by a few IOCs with 100mmbbl+ of reserves (e.g. Repsol, Chevron, Occidental) and a large number of independent E&Ps. The smaller end of the scale is dominated by many small players with more than 25 companies with less than 2.5mmboe of reserves.

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The Apache Egypt treasure map

Source: Houston Geological Society, HGS

Apache is a significant acreage holder onshore Egypt with an extensive infrastructure network which allows new discoveries to be brought onstream quickly and at relatively low cost. Its acreage can be broadly split into four areas, the most significant of these is the Western Desert Gas area which underpins the portfolio’s gas reserves and is a key supplier of gas to the domestic market.

Source: OGInsights

 The highlights from each area are below.

Western Desert Gas

This area has been a key source of growth in recent years and accounts for 80% of Apache’s Egyptian 2P reserves (Wood Mackenzie). The area comprises three sub-areas with the Khalda Area, which has been producing since the 1970s, being the most established. The Fahgur, Sushan and Matruh Areas all commenced production post 2005 and have all been a target area for exploration. Production in the Western Desert is currently constrained by lack of gas processing capacity (currently 900mmcf/d) and further investment to debottleneck the facilities is dependent on increase in gas prices.

Apache Merged Area

The blocks in this area were acquired from BP in 2010 with production underpinned by two fields: Abu Gharadig and Razzak. Both of these fields are mature and in terminal decline, although horizontal drilling and water flooding efforts have been successful in arresting declines. The area is considered as underexplored and exploration success will be important to maintain production levels in the longer term. A seismic programme in 2010/11 and subsequent simulation studies has helped Apache identify new targets for future exploration and development.

East Bahariya Area

Apache aggressively explored the East Bahariya block between 2000-2005 bringing on-stream a number of discoveries. Since 2005, Apache has implemented water flooding on all the fields in the block which has boosted production. In 2008, the Heba Ridge cluster of fields were discovered which is now a key growth area on the block. Apache acquired the nearby El Diyur and North El Diyur blocks after recognising the

extension of one of the East Bahariya reservoirs into these blocks.

Qarun

The fields on the Qarun block are mature and in decline with production expected to cease in the next few years. The East Beni Suef block is also in decline, although Apache has been able to sustain production through water flooding. Exploration success on East Beni Suef has also helped to maintain production, although discoveries have been small in size (1-5mmbbl).

Apache exports its production via an extensive network of oil and gas pipelines and facilities. A schematic of the network is shown below.

Source: OGInsights

Source: Apache Egypt EIA
https://www.miga.org/documents/Apache_Egypt_2004_Egyptian_Oil_and_Gas_Activities_EIA.pdf

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Apache exits LNG business through sale to Woodside

Source: OGInsights

On 15 December 2014, Apache announced the sale of its interests in the Wheatstone and Kitimat LNG projects to Woodside for USD2.75bn. The move was widely anticipated with Apache announcing in its Q2 2014 results its intention to completely exit LNG; this message was reinforced in the company’s Q3 results on 7 November 2014.

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Lundin stops funding Africa Oil

Africa Oil’s history dates back to 1983, when it was founded as Canmex Minerals with funding from the Lundin family. The company was officially renamed to Africa Oil in June 2009 to reflect its strategic and geographic focus. Since 2009, the company went through a series of acquisitions to consolidate its position in Kenya and Ethiopia.

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Vetra: A Colombian story

Vetra Energia is a private Colombian based E&P with a sole focus on Colombia.

Its main asset is a 69.5% operated interest in the Sur Oriente block; Petroamerica is the partner on the block with 30.5% WI which it acquired through the merger with Suroco in 2014. Vetra Energia also has a 100% WI in the La Punta block and a 60% operated interest in VMM2 (40% Canacol) which contains the Mono Araña field.

In July 2013, Vetra Energia was acquired by a consortium led by ACON Investments and Capital International. The Vetra management team, along with private investors including oil & gas veteran Atul Gupta also participated in the acquisition. The Vetra management team and private investors participated through a vehicle called New VEG.

Vetra Holdings SARL was incorporated for the acquisition of Vetra Energia and is owned by the consortium members. Based on the company’s filings, the acquisition consideration is estimated to be c.USD440mm. This has largely been funded through pseudo-debt with USD265mm of Preferred Equity Certificates (“PECs”) issued to the consortium members and USD187mm of promissory notes issued to Vetra’s selling shareholders. The PECs carry no interest whereas the promissory notes carry a rate of 10% per annum.

In 2013, Vetra produced 5.6mmbbl or 15.4mbbl/d. However, latest filings with the ANH show that production had plummeted to 6mbbl/d in2014 suggesting that the consortium may have significantly overpaid for the acquisition. This view is supported by the valuation of the assets from public sources:

• Broker consensus read-through valuations of $92mm for Sur Oriente and <$1mm for the other assets
• Wood Mackenzie valuation of $63mm for Sur Oriente and <$1mm for the other assets
• Furthermore, Petroamerica recorded a write-down of $30.4mm on Sur Oriente in 2014

Sur Oriente is Vetra’s main asset and is located in the Putumayo Basin. It is owned through Consorcio Colombia Energy (“CCE”) in which Vetra holds a 69.5% interest and Petroamerica 30.5% interest. CCE holds a Crude Incremental Production Contract with Ecopetrol on Sur Oriente which entitles Ecopetrol a share of the block’s production which is determined by an R-factor. Petroamerica’s disclosure notes that Ecopetrol is entitled to 52% of production; the remaining 48% of production is shared between Vetra and Petroamerica per their interests in CCE. The block produces from three fields (Pinuna-Quillacinga, Cohembi and Quinde) and in 2014, gross production was c.14.3mbbl/d from six wells.

Production from Sur Oriente was historically trucked to the nearby Orito facilities and then exported via the Trans-Andean Pipeline (“OTA”) to the port of Tumaco on the Pacific coast where it is sold as the Colombian South Blend. In November 2014, a new export route was established for the Cohembi and Quinde fields with crude trucked to the Amazonas Station in Ecuador and transported through the Oleoducto de Crudos Pesados (“OCP”) pipeline which is expected to result in $8-10/bbl improvement in netbacks over time.

Pipeline export routes from Putumayo
Source: Petroamerica January 2015 corporate presentation

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Apache's Egyptian Jewel

Apache entered Egypt in 1994 and has since built up a dominant onshore position through a series of acquisitions and an aggressive exploration campaign. It is the largest acreage holder in the Western Desert and operates 24 licences. In 2010, Apache expanded its position through the acquisition of BP’s entire Western Desert portfolio as part of a wider transaction involving BP’s North American assets. In 2013, Apache divested 33.3% of its Egyptian portfolio to Sinopec for USD3.1bn in an effort to refocus on its North American business.

Apache’s Egyptian portfolio contains c.594mmboe of 2P reserves (Wood Mackenzie) as at the end of 2014 with about half of these reserves being gas. Gas production is an important part of Apache’s business, which is a material supplier of gas to the domestic market with a 12% market share (excluding Sinopec’s interest in the portfolio). All gas is sold to EGPC.

One of the biggest concerns for Egyptian operators over the past couple of years is the receivables balance due from the EGPC. To date, EGPC have not defaulted (to Apache or any other operator); in fact, EGPC have been aggressively paying down the balance since the beginning of 2015. To manage payment default risk, Apache has insurance with USD300mm of cover from the Overseas Private Investment Corporation  and this is in place until 2024.

Egypt has been one of Apache’s success stories, where production and cash flow have grown strongly with each USD1mm of investment generating USD2mm. This has be driven by strong and consistent exploration success – success rate has averaged above 80%. The company holds a large acreage position with 72% still undeveloped which will provide significant opportunities for the future.

Historical production

Cash flow growth

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Pricing Kenyan crude

The price a crude fetches is typically against a benchmark such as Brent, WTI or Urals and the underlying crude marketing agreement will detail the calculation of the premium or discount to such a benchmark as well as other adjustments. As Kenyan crude has never been marketed before, there is no established pricing for Lokichar crude – however, a hypothetical value can be calculated. One of the key determinants of crude pricing is crude quality with the heaviness (API gravity) and sourness (sulphur content) often being a point of focus.

The heaviness of a crude is measured in °API and is a measurement of how heavy or light a crude is compared to water. Crude with an above 10°API is lighter than and will therefore float on water (i.e. is less dense). Heavier crude oils have longer hydrocarbon chain lengths and are generally less desirable as it is more difficult to convert them into more useful petroleum products. Light crude oil is defined as having an API gravity of greater than 31.1° API and a heavy crude oil has an API gravity of below 22.3° API.

The sourness of a crude is a measure of the level of sulphur by weight. Crude with less than 0.5% sulphur is considered sweet and above this level is sour. Sour crude is less desirable as the sulphur is a corrosive material and requires more processing; there are also increasingly strict limits on the sulphur content of gasoline and other petroleum products.

Amosing well testshave flowed oil between 31° to 38° API and is therefore considered a light oil; sulphur content is generally less than 0.1%. Based on test results to date, Lokichar crude is relatively high quality and should fetch pricing broadly in line with Brent (see bubble chart).

Other determinants of crude oil pricing are:

• Location - the total cost to a buyer is the wellhead price plus the cost of transportation and freight which will be benchmarked against other sources of supply
• Logistics – for long haul crudes, larger parcels tend to command a premium as per unit freight costs are lower; this also requires the loading and destination ports to be able handle larger vessels as well as having sufficient storage facilities
• Destination – refineries have different configurations in that they are setup to process different kinds of crudes. Not all refineries require light, sweet crudes and some are built to handle heavier crudes and will desire certain crude blends over others 

Refiners pay particular attention to the crude assay, or the chemical composition of the crude – this goes beyond looking at the API gravity and sulphur content mentioned above. For example, the pour point, wax content, level of other impurities are important considerations and depending on the refinery product slate, the refinery yields are also key (this refers to the relative proportion of the different hydrocarbon chain lengths in the oil). BP’s assay for Brent is shown below.

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Battle of the routes

Significant resources have been discovered in East Africa with 1.7bnbbl lying in Uganda and 600mmbbl in Kenya. The key barrier to monetising the vast amounts of oil is an export pipeline. In 2010, when Tullow acquired Heritage’s acreage, first oil was envisaged for 2016. Over the last five years, this timing has slowly crept back with estimates now pushed back to late-2019 despite government PR continuing to promote first oil in 2016-17.

There remains a significant risk that the timeline will be delayed further as the regional governments have yet to decide on a route. There are currently two routes under consideration, a Northern Route and a Southern Route. The governments’ preference is for a Northern Route which aligns with a wider regional plan for the development of a trade corridor from South Sudan through to the Port of Lamu in Kenya. In 2010, the LAPSSET (Lamu-South Sudan-Ethiopia) study was commissioned to explore a road and railway path as part of this plan, which also considered a concurrent pipeline as part of the development. In 2014, the Northern Route for a pipeline was further advanced with the governments engaging Toyota to select the actual path for the Northern Route and to carry out pre-FEED – this work is expected to be completed in May 2015.

The upstream partners have commissioned their own study into a Southern Route, which is to run parallel to the existing Mombasa-Eldoret products pipeline. Whilst this will utilise existing rights of way and road networks which will aid accessibility and construction, the higher population density along this route vs. the Northern Route could pose its own challenges.

To date, the governments’ focus remains on the Northern Route and they have given little consideration to the alternative Southern Route. The upstream partners continue to lobby the governments on the Southern Route which is seen as logistically less challenging. However, political impetus may override any economic and logistical considerations in choosing the final route, and until one is chosen, Uganda and Kenya’s discovered resources remain stranded.

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Gran Tierra's little pain

Gran Tierra is a TSX and NYSE listed E&P with a focus on Colombia. Its main assets are the Costayaco and Moqueta fields in the Putumayo Basin which accounted for 88% of the company’s Colombian NAR production of 18.4mboe/d in 2014. The company also has an exploration portfolio in Brazil (supported by minimal production of 900bbl/d NAR in 2014) and Peru. In March 2015, Gran Tierra announced that it was suspending development operations on the Bretana field in Peru following disappointing drilling results at the end of 2015; all reserves related to the development have now been re-categorised as contingent resources. Exploration activities are expected to continue in the Peru with outstanding commitments of USD160mm over the next three years.

Although the company’s flagship assets are performing strongly, there are two unwelcome pieces of information buried in the company’s 10-K filing – there is an overriding royalty on the Putumayo blocks and a legal claim filed by the ANH against Gran Tierra over royalties.

Gran Tierra entered Colombia in 2006 through the acquisition of Argosy Energy’s assets in the country (Santana, Guayuyaco, Chaza and Azar blocks). Gran Tierra increased its interests in certain assets through the subsequent acquisition of Solana Resources, most importantly, taking the interest in the Chaza block from 50% to 100% in 2008. The original interests in 2006 are subject to a third party overriding royalty under an agreement entered into between Gran Tierra and Crosby Capital in June 2006. The agreement also allows for Crosby Capital to convert its royalty into a net profit interest (“NPI”) in certain circumstances. As at the end of 2014, the following arrangements were in place with Crosby Capital:

·         10% NPI on the originally acquired 50% WI in the Costayaco and Moqueta fields which lie in the Chaza block

·         35% NPI on the 35% WI in the Juanambu field in the Guayuyaco block

·         Various overriding royalty on production in the Santana block and Guayuyaco field in the Guayuyaco block

The ANH has also filed a claim against Gran Tierra in relation to the HPR royalty. This is a royalty which is paid on top of normal royalties and is triggered when the oil sale price exceeds c.USD37/bbl and cumulative production from an exploitation area exceeds 5mmbbl. The HPR royalty affects Gran Tierra’s Costayaco and Moqueta fields which are separate exploitation areas, but lie within the same block (Chaza).

Given the two fields, Costayaco and Moqueta, are separate exploitation areas (with the company further emphasising that they are separate hydrocarbon accumulations), Gran Tierra is currently only paying the HPR royalty on the Moqueta field which has recovered in excess of 5mmbbl to date. As at the end of 2014, recovery on Costayaco had reached 4.2mmbbl and therefore Gran Tierra has not yet commenced the payment of HPR royalty on this field.

The ANH have taken a different interpretation of the Chaza contract and view that the 5mmbbl threshold should be applied to aggregate cumulative production across all exploitation contracts within the Chaza block, meaning that Costayaco would also be subject to the HPR royalty. The ANH has challenged Gran Tierra’s position with a claim of USD64mm in respect of Costayaco HPR royalties. Gran Tierra and its legal advisers do not view that the ANH claim will be successful and the company has not made a provision in its accounts for this potential liability.

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Oil price contingent payment: Bridging the valuation gap in an uncertain oil price environment

In the current oil price environment, buyer-seller alignment on valuation is likely to be an issue with differences driven by view on the oil price outlook. A number of transactions have stalled or been pulled over the last year. One possible way to bridge this gap is to have a contingent consideration element that is contingent on the recovery of the oil price; the seller benefits from recovery in the oil price if it believes a recovery is forthcoming and the buyer can base upfront payment on a lower price deck and avoid overpaying in the event oil prices do not recover.

Contingent consideration based on the oil price has not been common given Brent has been relatively stable in the ~$100/bbl range in the past few years. Seplat, in its acquisition of Chevron’s assets in Nigeria, is the only recent example of a buyer which has adopted such a payment structure. When structuring such a mechanism, close attention should be paid to a number of key elements:

• Amount: Based on the valuation difference under the two oil price decks, subject to negotiation
• Trigger: Trigger needs to be defined clearly (e.g. oil price refers to realised price or Brent) and responsibilities for monitoring the trigger and notification of the counterparty needs to be set out. In the case of the Seplat transaction, the trigger was oil prices averaging USD90/bbl or above for 12 consecutive months
• Long stop date: Period needs to be sufficiently long and in a timeframe where oil price could realistically recover. A longer period is generally more favourable for the seller and less favourable for the buyer as it gives more time for the trigger to be satisfied. Seplat and Chevron agreed a period of five years in the recent transaction

Seplat / Chevron Transaction Overview

On 5 February 2015, Seplat announced the completion of the acquisition of a 40% WI in OML 53 and 22.5% WI in OML 55 onshore Nigeria from Chevron. Seplat paid USD387mm upfront with a USD39mm (9% of the total potential consideration) contingent payment on oil prices averaging USD90/bbl or above for 12 consecutive months over the next five years.

OML 53 contains the Jisike oil field which produces at 2,000bbl/d (gross). The block also contains the undeveloped Ohaji South gas and condensate field which could utilise the existing facilities which have capacity of 12,000bbl/d and 8mmcf/d; total net resources of 151mmboe.

OML 55 is located in the swamp to shallow water areas of the Niger Delta and contains five producing fields; current gross production of 8,000bbl/d; total net resources of 46mmboe with further oil and gas potential identified on the block.

The transaction fits with Seplat’s strategy of securing, commercialising and monetising natural gas in the Niger Delta with a view to supplying the rapidly growing domestic market. For Chevron, it reduces exposure to the Nigerian onshore which has been affected by bunkering in recent years and further refocuses its portfolio towards North America and the Gulf of Mexico.

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Iran interim agreement: the Minotaur's labyrinth

In the story of the Minotaur, Daedalus was tasked with building a labyrinth under the order of King Minos of Crete to imprison the dreaded creature. The Minotaur, part man part bull, was an unnatural being. He was created when Pasiphae, King Minos’ wife mated with the bull sent by Poseidon; this was made possible by the wooden cow crafted by Daedalus into which Pasiphae climbed into. The Iran framework agreement, is in some respects like the labyrinth – an artificial solution to a man-made problem. As the tale goes, only a great Athenian hero (Theseus) is needed to finally slay the Minotaur.

On 2 April 2015, the P5+1 and Iran had agreed to the framework agreement against all odds. The details of the agreement were also more granular than had been expected by the international community. Initial expectations were that high level terms would be agreed by the end of March deadline, with the finer details to be thrashed out over the following months ahead of the ultimate 30 June deadline. Reaching a nuclear deal with Iran has been a desire for the US for decades, and following lengthy negotiations, it appears that things are now moving in the right direction. Iran has also been more willing to come to the table following years of sanctions which have crippled its economy.

The main elements of this interim deal are:

• Centrifuges: Reduce the number of centrifuges from 19,000 to around 6,000
• Enrichment: To no more than 3.37% for at least 15 years
• Stockpile: 10,000kg stockpile to be reduced to 300kg
• Facilities:
• Fordow to be converted for research purposes with no enrichment
• Enrichment only allowed at Natanz which will house 5,060 first generation centrifuges
• Arak to be redesigned as a heavy water research facility with no plutonium production capabilities
• Monitoring: IAEA to monitor supply, usage and sale of nuclear technology with inspections to last for up to 25 years

In return, sanctions on Iran will be suspended upon IAEA certification of compliance with the final terms of the deal. Any breach of the terms will result in immediate reinstatement of sanctions. However, cracks are already in sight with Iran declaring that there will be no deal unless sanctions are lifted immediately upon conclusion of the deal. Also, in the latest twist of events, the US Senate Foreign Relations Committee voted unanimously (19-0) on 15 April in support of legislations that would give Congress authority to approve any final deal thus undermining the President’s authority to conduct foreign policy with Iran.

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