Wood Mackenzie estimates that 100 trillion cubic feet (tcf) of gas has been discovered in Mozambique and Tanzania to date, ranking the Rovuma Basin as one of the most prolific conventional gas plays in the world.
However, there are significant technical and commercial challenges to be overcome in order to bring the gas to market by the end of this decade. These include: addressing issues around infrastructure, government capacity, financing and reaching a positive outcome to unitisation negotiations in Mozambique.
Recent discoveries and high profile M&A activity in Mozambique and Tanzania are attracting attention and Martin Kelly, Wood Mackenzie’s Head of Sub-Sahara Upstream Research, says the interest is justified: “100 tcf of gas has been discovered to date in East Africa and we estimate yet-to-find reserves could be as much as 80 tcf in Mozambique and 15 tcf in Tanzania. There is clearly plenty of gas to supply the likely commercialisation route of LNG – theoretically enough to support up to 16 LNG trains.
“The Rovuma basin is the most prolific in the region, and one of the hottest conventional gas plays in the world, with 85 tcf discovered so far. Globally in 2011, it yielded the third most hydrocarbons, and we expect it to top the list in 2012 if the first half of the year is anything to go by,” Kelly continues.
In neighbouring Tanzania, the targets are the northern extension of the Rovuma Basin and the Mafia Basin. Kelly says: “Tanzania has enjoyed considerable exploration success as well, but hasn’t discovered the same scale of reserves. The average discovery size is much smaller at around 2 tcf, compared to Mozambique which is over 7 tcf. Discoveries in Tanzania are also more spread out, so developing them will be more expensive than those in Mozambique because additional infrastructure will be required.”
One of the most immediate challenges for Mozambique, is the unitisation discussions which Wood Mackenzie understands have already begun. Kelly explains; “Of the 85 tcf of gas discovered to date in Mozambique, around half of it is thought to be one enormous field which is in communication across the block. Under Mozambican law, a unitisation agreement between the operating parties will be required.”
Although there is a risk that unitisation discussions could delay Final Investment Decision (FID) – the crucial last step before commercial development – and therefore LNG production, there are other discoveries which are wholly contained in Area 1 and Area 4 and therefore gas could come from these first.
Giles Farrer, Senior LNG research analyst for Wood Mackenzie comments: “Many challenges will need to be overcome prior to LNG project sanction. The region’s remoteness and lack of development present serious technical obstacles. There is virtually no existing skilled workforce and both Mozambique and Tanzania will have to build and establish deepwater ports capable of servicing the needs of the petroleum sector. On the commercial side, there is the question of government capacity – whether there is sufficient impetus and capability within the governments and national oil companies to advance the huge legislative, bureaucratic, customs and financial challenges that such a development would bring.
“The major outstanding milestone for Mozambique is the conclusion of a commercial framework agreement, which is in the process of being negotiated. It will determine how the LNG facility or facilities will be structured for the purpose of taxation and whether the Joint Ventures (JVs) will co-operate in the construction of a single, mega LNG facility, or pursue individual developments. One crucial advantage that the Tanzanian projects enjoy is that they have already negotiated commercial terms, prior to the announcement of their projects.”
Farrer continues: “Lastly there is the question of finance, we estimate that a two train greenfield development in the region is going to cost at least US$25 billion, and for some of the players involved financing their share of this sort of development cost will certainly prove challenging and could delay development.”
The joint analysis by Wood Mackenzie’s upstream and LNG research teams stresses that these challenges are not insurmountable. “They have been encountered and overcome in several countries before. The risk is that delays could lengthen development schedules and add to costs,” Farrer says in closing.
Apache Corp. has found a huge amount (up to 48 trillion cubic feet) of natural gas in its Liard Basin properties in northeastern BC. All of the gas is targeted to ship to a proposed LNG plant which should be built at Kitimat, according to Refinery News.
As the company says, it is the best unconventional gas discovery in North America. They have rights to drill 430,000 acres within the region.
Because of the low gas price, it is expected that the drilling plans in the Liard region could be very slow.
- No relief for natural gas producers as Apache’s Kitimat plant delayed (mb50.wordpress.com)
- Apache discovers massive shale gas field in B.C. (business.financialpost.com)
- Apache discovers huge gas reservoir in northern B.C. (calgaryherald.com)
ATP Oil & Gas Corporation today announced an increase in its estimated year-end 2011 proved and probable pre-tax PV-10 value to $7.3 billion based on SEC pricing, up 52% from $4.8 billion at year-end 2010.
ATP also provided an update on production for full-year 2011 which averaged an estimated 24.6 thousand barrels per day (MBoe/d), an increase of 17% over 2010.
Reserves – ATP estimates year-end 2011 proved reserves of 118.9 MMBoe compared to 126.1 MMBoe at year-end 2010. ATP estimates proved and probable reserves of 194.4 MMBoe at year-end 2011, compared to 211.3 MMBoe at year-end 2010. The changes were primarily a result of production of 9.0 MMBoe in 2011 and revisions to oil and gas reserves. On a Boe basis, ATP estimates that oil and natural gas liquids (NGLs) represent 66% of its year-end 2011 proved reserves and 65% of proved and probable reserves, compared to 60% and 59%, respectively, at year-end 2010.
ATP estimates a year-end 2011 SEC pre-tax PV-10 value of $4.2 billion for its proved reserves and $7.3 billion for its proved and probable reserves, compared to $2.6 billion and $4.8 billion, respectively, at year-end 2010. This increase is primarily a result of pricing, but other factors include timing and an increase in oil and NGL reserves.
Since independent reservoir engineers are finalizing estimates of ATP’s oil and natural gas reserves for year-end 2011, ATP will issue its final reserve amounts utilizing SEC pricing and reconciliation in conjunction with filing its Form 10-K, anticipated in March 2012.
Production – ATP’s production in the fourth quarter 2011 averaged 24.8 MBoe/d compared to 24.2 MBoe/d in the third quarter 2011. The fourth quarter average benefited from a 1.4 MBoe/d recognition of royalty relief related to 2010 production. Not including this benefit, average production in the fourth quarter was 23.4 MBoe/d, of which 70% was oil, compared to 69% in the third quarter 2011. ATP intends to conduct the previously announced sleeve shift at the Mississippi Canyon (MC) 941 A-1 well in the first quarter 2012 after production is established at the MC 942 #2 well. This sleeve shift had previously been scheduled in the fourth quarter of 2011. ATP estimates that opening the sleeve in the MC 941 A-1 well will increase production by 1.5 MBoe/d.
ATP anticipates an increase in production from the completion of the MC 942 #2 well during the first quarter 2012 and an increase later in the year with the installation of the pipeline for the two Clipper wells that were completed and tested in 2011. The installation of the Clipper pipeline is scheduled to begin in the third quarter 2012 with production expected in the late third quarter/early fourth quarter 2012.
ATP Oil & Gas is an international offshore oil and gas development and production company with operations in the Gulf of Mexico, Mediterranean Sea and the North Sea. The company trades publicly as ATPG on the NASDAQ Global Select Market.
Source: ATP Oil & Gas, February 24, 2012
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