One day in November: A Colombian visit to the UK

At the beginning of November, President Manuel Santos and his delegation from Colombia were in the UK on an official state visit. The Wednesday of that week was dedicated to showcasing Colombia’s oil & gas industry with senior members from the industry presenting in London. The next day, the delegation continued their tour in Aberdeen to build ties with the historic oil & gas city.

OGInsights attended the event and had an opportunity to speak with Germán Arce, the Minister of Energy and Mines, and Orlando Velandia, President of the ANH. They shared their views on the current state of and the outlook for the Colombian oil & gas industry.

The delegation was clearly excited to be in London and Aberdeen and keen to talk about the future of Colombian offshore oil & gas. The offshore is very early stage, but critical to sustaining the country’s longer term production levels. Before the offshore can make material progress, it was recognised that a whole supporting industry together with offshore expertise would need to be established (its offshore experience is minimal with Colombia being an onshore producer to date). For example, this would include support for offshore drilling, rig servicing, helicopter services, vessels among a much longer list of things. Forming strong ties with Aberdeen, which is seen as a “centre of excellence” in the offshore and where the North Sea industry was born, is therefore a priority for Colombia.

Barranquilla, a coastal city in northern Colombia, has been appropriately chosen and aspires to be the “Aberdeen of Colombia”. The ties between the two cities are set to strengthen and Barranquilla will call on Aberdeen’s expertise, learnings and experience as it sets to build up the city to support the emerging offshore industry in Colombia. Academics, service companies and oil & gas companies were all present at the event with the mayor of Barranquilla, the charismatic Alejandro Char, emphasising the importance of knowledge transfer and desire to “learn everything”.

To date, 22 offshore areas have been licensed: 9 TEAs which are for technical evaluation only (not drilling), and 13 exploration contracts. In total, 45 areas have been drawn up with 33 in the Caribbean and 12 in the Pacific. The infancy of the offshore, together with the lack of a supporting industry translates into high risk; however the size of the prize is large enough to attract major international players including ExxonMobil, Anadarko, Shell and Repsol.

Despite the excitement around the offshore, the importance of the onshore was not forgotten. Managing surface risk is still very much top of mind. Minister Arce elaborated on the situation - the onshore has seen a reduction in the level of attacks but an increase in social activity. He therefore encourages E&Ps to evolve their corporate social strategy away from employing on-the-ground protection to negotiation and dialogue, which is a very different skill set. In the south of the country, the ANH believes there is vast potential, underexplored in part due to militant activity and sees the continuation of peace as critical to maximising hydrocarbon recovery in the onshore.

The Colombian oil & gas industry is at a turning point, with attracting international investment very much key to advancing the industry. The government has made significant effort in opening up the country and building a business friendly environment. With the offshore on the brink of being the next frontier, the world will be keeping a close eye on Colombia and how it will use its potential new found hydrocarbon wealth.

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BP: Adapting to the times - Where were they then? (Part 1)

The OGInsights team recently met with the BP corporate strategy department to discuss how the strategic direction of the company has changed since the collapse in oil prices. In this two part entry, we look at where BP were a year ago and where they are now in terms of strategic thinking.

Part 1: Where were they then?
At the beginning of 2015, BP already began planning for a "lower for longer" scenario, however growth was still very much top of mind. Reserve replacement was a key challenge to the company's longer term existence and the USD2 billion annual exploration programme at the time, assuming a USD5/boe finding cost, would only yield 400mmboe of new reserves compared to BP's annual production of c.750mmboe. BP wanted to maintain a quality exploration programme, but it was increasingly recognised that M&A would be needed to meet the necessary level of reserve replacement.

In terms of M&A, BP were looking for "scale and materiality" and needed to be in a position where it would be relevant to a country. They shared a few key themes of their strategic thinking back in 2015, with a focus on their African portfolio:

1. Existing portfolio sufficient

• They were satisfied with their positions in Africa (Angola, Egypt, Algeria) and did not see other opportunities in the region of sufficient scale to justify a new country entry.

2. Brazil over West Africa

• Although the West African Transform Margin was an attractive play, BP's position in the conjugate Brazil offshore was seen as an easier play on the geology without the need to deal with multiple countries/governments along the West African coast.

3. Angolan monetisation

• Angolan geology was clearly a coveted part of the African portfolio, and in 2015, BP were reaching a critical phase of exploration testing with a series of wells in the year (which were technical successes).
• However, the Angolan position was littered with a lot of stranded discoveries and could not be developed on the current cost base.
• Options to monetisation being considered were sharing of costs, or acquiring to build critical mass there.
• Acquiring Cobalt was clearly something being considered.

4. Rebalancing to the onshore

• The company's portfolio was viewed as over exposed to deepwater and not the balance BP would like to be in a low oil price environment.
• They were glad to have missed out on East African gas story which has been plagued by delays and upcoming expensive developments.
• Tullow and Africa Oil continue to be monitored in the background, as an opportunity to rebalance the onshore portfolio, and NewAge's Congo position and Savannah Petroleum in Niger were added to the company's M&A screening hopper as emerging candidates.

In Part 2, we look at how BP's strategic direction has changed since 2015.

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Downgrade coming at Taq Taq?

Genel released a disappointing production update this morning with Q3 2016 working interest production of 53.1mbopd. For the quarter, Taq Taq and Tawke gross production averaged 58.6mbopd and 109.2mbopd respectively. Taq Taq’s production compares with 130mbopd a year ago.

A workover campaign on Taq Taq is ongoing with TT-27x and TT-07z completed in Q3 2016; a third side track, TT-16y, is currently underway.

As a result of the recent performance, FY16 production is expected to be at the bottom end of the 53-60mbopd guidance range and revenue will also be at the lower end of USD90-110 million guidance. There is increasing concern around a further reserves downgrade at Taq Taq and DNO’s Tawke field is the more prudent investment for now.

Separately, management continues to talk positively about the gas resources, but the development of Miran and Bina Bawi to look challenging in the current environment.

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Kenya First Oil

On 9th October, a government spokesperson said that President Kenyatta had held meetings with the Lokichar Basin oil companies (Tullow, Africa Oil, Maersk) on the Early Oil Pilot Scheme (“EOPS”). The EOPS has already received FID and will produce 2,000bbl/d, starting in June 2017. The oil will be trucked from the Lokichar Basin to Mombasa. The EOPS will allow the partners to establish a production history, providing valuable dynamic reservoir data. This implementation experience will assist in the planning of the full field development.

In the run up to the launch of the EOPS, the operator commissioned two trucks for the transport of a trial batch of crude from Block 10BB to Kenya Refineries. This trial is currently in progress and will help the partners to understand how the oil behaves under different operating conditions while on transit, and will help in determining the design, cost and type of equipment needed for the EOPS.

The Government expects to sign additional agreements in due course, including the Joint Partnership Agreement (“JPA”) that deals with the work related to the transportation of the crude oil to Lamu by pipeline.

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Support for the Danish DUC

On Wednesday 21st September Lars Christian Lilleholt, the Danish energy minister said that the government is determined to find an economically viable solution that will allow the Trya complex to continue production. This follows Maersk Oil’s announcement in April that it would cease production at the Tyra complex if no solution to extend its economic life during 2016.

The Tyra complex is operated by Maersk Oil on behalf of the DUC, a partnership between A.P. Moller Maersk (31.2%), Shell (36.8%), Nordsøfonden (20%) and Chevron (12%). Tyra is Denmark’s largest gas accumulation and the facilities are the processing and export centre for all gas produced by the Danish Underground Consortium (“DUC”). More than 90% of Denmark’s gas production is processed through the facilities, including production from Norway’s Trym field.

The government’s announcement is potentially positive for the Trym partners (Bayerngas 50%, Faroe 50% operator). Trym was acquired by Faroe from DONG E&P in July 2016 as part of a wider package; the transaction is expected to close in the coming months. Faroe’s acquisition case assumed Trym would cease production in 2018, so any extension of the Tyra complex could allow Faroe to book additional reserves.

Danish North Sea - DUC Network (Northern Segment)
Source: Maersk Oil

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Canacol doesn’t lose sleep over oil prices

Canacol is distinct from its Colombian E&P peers‎, being a gas-weighted producer with operations focussed in the Lower Magdalena Basin. Its gas operations and gas offtake contracts mean that the company has a much lower exposure to oil prices. In the company's recent investor update, it noted that it would generate EBITDA of USD107 million if the oil price was zero! Given this special situation within the Colombian and wider international E&P universe, we look to dedicate a few articles looking at Canacol in more detail.

Canacol: Sensitivity to WTI
Source: Investor presentation

Canacol was initially established as a Latin American focussed E&P and listed on the Toronto stock exchange in 2009 through a reverse takeover. The company has somewhat haphazardly experimented with different strategies and now appears to have settled on one that works: gas production supplying the growing domestic market. As a result of its past, the company has now amassed a position of 23 blocks in the Magdalena, Llanos and Putumayo Basins as well as a service contract in Ecuador, through a series of acquisitions and licensing rounds. It also previously held assets in Brazil and Guyana which have now been sold off.

Key acquisitions in the company’s history include:

• Carrao Energy (November 2011) which came with LLA-23 and Middle Madalena blocks Santa Isabel, VMM-2 and VMM-3
• Shona Energy (December 2012) which had a 100% interest in Esperanza and production in four blocks across Colombia
• 100% interest in VIM-5 and VIM-9, acquired from OGX in December 2014

Esperanza and VIM-5 are now the key assets in the company’s portfolio.

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Shell Gulf of Mexico divestment

On 29^th August, Shell announced that it had agreed to sell 100% of its interests in the Gulf of Mexico Green Canyon Blocks 114, 158, 202 and 248 (the Brutus/Glider assets), to EnVen Energy Corporation for USD425 million in cash. These assets do not appear to form part of Shell's core strategy in the region, with recent activity focusing on the Mars/Vito/Na Kika areas to the east.

The Brutus/Glider assets include the Brutus Tension Leg Platform, and the Glider subsea production system, as well as the pipelines used to evacuate production from the platform. The assets have a combined current production of 25mboepd, although the Brutus platform has capacity to produce 130mboepd.

Given investors' key concern is around the company's debt levels (Shell has over USD75 billion in net debt following the acquisition of BG), and negative free cash flow at current oil price levels, the divestment is welcome and is a step towards the USD30 billion divestment programme mentioned last year.



Source: Shell

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