Notes on Yemen - Summary

Summary

• Oil production dominated by 2 blocks:
• Masila (Bloack 14)
• Licence expired in 2011
• Operations taken over by newly formed government op co
• May impact production levels and future development
• Marib-Jawf (Block 18)
• Production peaked in 2002 at 160mbopd
• Absent further discoveries, reserves will be depleted over next decade
• A number of licences are due to expire in coming years, if not renewed, could exacerbate declining reserves problem
• Small discoveries in basement formation by Total and OMV may help reduce decline in the immediate future
• Deteriorating security situation
• Attacks on Marib export pipeline means pipeline regularly non-operational
• Ongoing tensions between gov and local tribesmen
• Unrest will impact future production as troops previously assigned to guarding oil infra are relocated to cities
• In recent years, government has addressed declining revenue from oil by monetising gas
• Yemen LNG commissioned in 2009
• Fed by Total-led East Shabwa gas project
• Government also keen on moving away from heavily subsidised diesel power gen by incentivising gas on commercial terms
• Due to maturity, Yemen of interest to small/med cos
• Despite security concerns, attractive fiscal terms and rel low capex/opex mean attractive returns on investments can be made for those willing to accept risk

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Yemen - Key Companies and Licensing

Key companies

• Total is largest resource holder due to interest in Yemen LNG
• Partners are: Hunt Oil and SK Energy
• Occidental is most significant IOC not in Yemen LNG
• Acreage, reserves and production reduced following expiry of Masila block in 2011
• Its East Shabwa (Block 10) is due to expire in 2015 - extension unlikely to be granted
• Nexen was also a key player in Yemen until expiry of Masila block (Block 14)
• Low capex in 2013 reflects maturity as an oil producer
• Spending likely curtailed until licence extensions are negotiated

Licensing

• In 1990s, PSC terms became less favourable following spate of discoveries and developments
• Led to many relinquishments in mid-1990s
• Yemen subsequently improved the terms on offer and 14 PSCs were signed in 1997-98
• Four rounds held between 2004-7
• However, work programmes were held up by delays to the award ratification process
• 2006 licences were only ratified in 2009
• For the 2007 bid round for offshore blocks, no bids were received and bid round was abandoned
• Deepwater blocks are far from infra, in insecure areas and prospectivity unknown - unlikely to attract much interest

Yemen LNG

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Apache divesting international assets? A hard one!

On 31 July 2014, Apache announced its Q2 2014 results

• Apache said it was looking to exit its Canadian LNG positions and was considering options around its international assets
• This comes amidst Jana Partners, a hedge fund which recently picked up c.USD1bn of shares in Apache, wrote to investors arguing that Apache should focus its efforts on the North American onshore
• Reasoning behind this is that over the last few years, a number of North American onshore pure plays have outperformed Apache
• Apache's international assets, it is argued, are diluting its North American onshore story
• However, analysts do not necessarily agree
• Apache's international assets, especially those in Egypt and the North Sea, generate significant free cash flow for the group
• These are areas of existing production and are low risk operations
• The cash flows are important for the funding of the North American portfolio
• It is further noted that given the number of North Sea assets on the market, the geopolitic issues plaguing North Africa and the relative maturity (though strong cash flow generation) of these assets, it is unlikely that Apache will fund a buyer willing to pay full value
• Its other main operations are in Australia, including the Wheatstone LNG project

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Notes on Oman

Executive summary

• After years of declining production, crude output has increased y-o-y since 2008 due to:
• Oman's EOR project at the Mukhaizna field; and
• Stabilisation of production at PDO's Block 6 (Oman's main producing area)
• PDO has also implemented a number of EOR initiatives to maintain its own production of c.550mbopd over the next 5 to 8 years
• The success of these EOR projects will largely dictate the level to which Oman can maintain liquids production over the medium term
• Increasing focus on gas production in response to projected shortfalls
• Encourage the appraisal and development of tight gas reserves
• Large part of these volumes will depend on success of BP-operated Khazzan Makarem project
• Oman viewed as a stable operating environments
• Has collaborative government offering PSCs with relatively favourable terms relative to regional peers

Key companies

• Petroleum Development Oman ("PDO") is dominant player: Government of Oman 60%, Shell 34%, Total 4%, Partex 2%
• PDO produces over 75% of Oman's hydrocarbons from over 100 fields
• BP's reserves come solely from its Khazzan-Makarem project
• Occidental, Mubadala and Oman Oil Company reserves largely from the redevelopment of Mukhaizna

Licensing

• Majority of licensing activity is onshore, accounting for 95% of active licences
• 5 active offshore licences
• New licensing opportunities for IOCs constrained by fact that PDO has operated a vast concessino area covering much of the country
• much of the acreage outside of PDO's concession area has been licensed, relinquished and re-licensed several times
• Licensing activity has increased significantly over the last 10 years
• re-licensing of PDO relinquished acreage
• response to falling oil production and rising gas demand

Reserves

• Main oil fields now mature
• remaining reserves depend on how successful PDO and Occidental's EOR is
• Remaining gas reserves estimated at 30-35tcf
• vast majority held in PDO areas; 85% of Oman's remaining gas reserves are contained in 10 fields operated by PDO, most of which are in Qarn Alam area of Block 6
• Gas reserves will increase significantly if BP's Khazzan-Makarem field and Oman Oil Comapny's Abu Butabul field are successful appraised

Production

• Between 2000 and 2008, Oman experienced production decline - PDO ageing fields
• In response, PDO shifted focus on EOR from existing fields
• Since 1999, PDO has increased sales gas significantly as the giant Qarn Alam fields were brought onstream to supply Oman's new LNG plants
• Demand for gas expected to grow to support growing industrial and domestic gas markets

Infrastructure

• Highly developed network, almost exclusively owned and operated by PDO; c.2,200km of pipeline
• Oman's main terminal is located near Muscat - all crude is either exported or processed at the refinery for domestic use
• Gas pipeline network owned by Oman Gas Company ("OGC"): Government of Oman 80%, Oman Oil Company 20%
• Network of c.2,500km
• Gas supplies Qalhat LNG terminal or domestic use

Key issues

• Largest non-OPEC producer in the Middle East
• Crude production has increased since 2008, following previous declines
• Relatively attractive fiscal regime has drawn international investors
• Leading proponent for EOR developments in the Middle East
• Challenging geology has resulted in relatively high cost developments
• PDO carries out 3 types of EOR in its contract area: Polymer, Steam and gas injection
• Other operators developing small scale, cost effective EOR techniques designed for small to medium sized fields
• Reduced availability of gas has led to innovative use of solar panels to produce steam required to mobilise heavier crudes in the south of Oman
• Gas supply remains an issue
• Khazzan-Makarem needs to realise a higher gas price to proceed

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Tullow exits Liberia and Sierra Leone

On 30 July, Tullow published in H1 2014 results.

Within the results, Tullow stated:

"After evaluating potential options in Liberia and Sierra Leone, Tullow made the decision not to renew its licence interests and will exit its position. Tullow’s interest in LB-15 in Liberia expired in June 2014 and its interest in SL-07B-11 in Sierra Leone will expire in August 2014, following which Tullow will have no licence interests in either country"

Acreage map taken from Simba Energy for Liberia shows Tullow's acreage position in that country:

Acreage map for Sierra Leone from Tullow and the Petroleum Directorate respectively:

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Afren - CEO and COO suspended re unauthorised payments

• On 31 July 2014, Afren has temporarily suspended its CEO, Osman Shahenshah and the COO, Shahid Ullah
• During an independent review by Willkie Farr & Gallagher, evidence had been uncovered showing the CEO and COO were in receipt of unauthorised payments
• These payments were not made by Afren
• The investigation continues, no conclusive findings to date
• No evidence found that any other directors involved
• Egbert Imomoh (Non-Executive Chairman) has been appointed as Executive Chairman
• Toby Hayward (NED) has been appointed as interim CEO
• Afren's H1 2014 results, originally scheduled for 4 August 2014, will now be postponed to no later than the end of August

SUPPLEMENTARY

OML113 and OPL 310

Aje and Ogo

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Sebuku PSC

Overview

• Contains 2 discoveries: Ruby gas field and the small Pangkat oil deposit
• Plan of development for Ruby approved in July 2008
• incorporates two bridge-linked platforms and initially four development wells
• 312km pipeline to transport gas to new onshore receiving terminal for processing
• Gas sold to the local Kaltim fertiliser plants
• Ruby currently contracted to supply 85mmcfpd
• Production capacity of 115mmcfpd, so scope to provide more gas

Participation

• Mubadala (70%*), INPEX (15%), Total (15%)

Exploration

• 11 wells drilled to date
• Latest activity: Mubadala returned to drilling on the PSC in March 2010 - drilled NW Ruby-1 wildcat to test satellite prospect - unsuccessful
• Further exploration planned
• In March 2013, Mubadala awarded exploration block for the acreage surrounding Sebuku PSC, the West Sebuku block; 3D scheduled in 2014 with view to identifying future exploration prospects

Reserves, production and sales

• Commercial WM: 215mmcfd (gross at 1/1/2014)
• Production began in 2013 at 14mmcfpd, ramping up to 75mmcfpd in 2014
• GSA signed in June 2011 for the supply of gas for 10 years to PT Pupuk Kaltim at c.80mmcfpd
• Ruby gas to be predominantly used for fertiliser plant operations of the Kaltim V plant; however, as field declines, gas from other PSCs will be required to fulfil GSA
• Price formula reflects local pricing and international ammonia and urea costs
• Estimated USD/mcf: 2013 (7.7), 2014 (7.1), 2015 (7.0), 2016 (6.7)

Development

• Currently produces from 4 wells, with additional drilling in future depending on reservoir performance
• Installation/construction of onshore facilities finished at end 2012, offshore platforms in June 2013
• First gas in October 2013

Fiscal and NPV

• First Tranche Petroleum at 20%
• Post-tax profit gas split is 65:35 in the government's favour; 80:20 for oil
• Corporate tax of 40%
• DMO applied at 6.7% after 60-month holiday, reimbursed at 15% of export price

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