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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Victoria Oil & Gas: Cameroon's emerging integrated utility

Victoria Oil & Gas is an AIM listed E&P with a 60% WI in the Logbaba field, Cameroon and an associated infrastructure network that supplies gas to the local market. The company acquired its interest in the Logbaba field in 2008 and drilled its first appraisal well (La-105) on the block in 2009, the first onshore well since the 1950s. First production commenced in 2012 with the roll-out of a distribution pipeline network in 2013 Victoria Oil & Gas is now transitioning away from a pure-play E&P to an integrated energy supplier in Cameroon. The next stage of the company’s strategy is to grow its gas-to-power business which supplies gas for power generation by industrial customers and also to the gas grid which feeds into regional power plants. The company also has a 100% WI in the West Medvezhye field in Russia with 2C resources of c.14.4mmboe; this asset is non-core and the company continues to seek options around a partial or full exit.

The Logbaba gas field is located in the Douala Basin, in the eastern suburb of Douala, Cameroon’s largest city. Victoria Oil & Gas has a 60% WI with the remaining 40% held by Grynberg Petroleum. Gross 2P reserves are estimated at 210bcf of gas plus 3.4mmbbl of condensates. Seismic data suggests there may be a larger reservoir c.4km north of Logbaba that could provide future upside. Production is currently from two wells La-105 and -106 which were drilled between 2009 and 2010, and is tied back to 40mmcf/d gas processing facilities that include a gas and condensate separator. These facilities are currently c.20% utilised. The gas is supplied through the company’s pipeline network to customers in the nearby Magzi industrial area and condensates are trucked to other parts of the country.

Victoria Oil & Gas operates its utility business in Cameroon through a wholly owned subsidiary, Gaz du Cameroun (“GDC”), which supplies gas and condensates to the local market. GDC commenced construction of a gas pipeline network in 2013 in Douala to enable the supply of gas to the region’s industrial customers. In 2014, GDC extended the pipeline across the Wouri River, opening up a new market; the pipeline network now extends over 25km. Gas is supplied for industrial processes and power generation. Gas for thermal use is sold at $16/mmbtu for the first 5 years of a 20 year supply contract with the price renegotiated at the end of the 5th year. Gas for power generation is sold at c.$12/mmbtu under a 10 year take-or-pay contract. In December 2014, GDC agreed the initial supply of gas to the domestic grid for power generation at $9/mmbtu. The company is currently evaluating the feasibility of supplying compressed natural gas which would allow the sale of gas outside of Douala by road; this could remove the capital requirements of establishing a pipeline distribution network.

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