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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