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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