GKP Gramacho 1 feb ' his views '

I posted this on the main board a few mins ago...A few posters (Chopper et al) have discusssed the potential value of Shaiken. Here is my take to add to the mix.
INTRO
Unrisked NPV
10 Values have been estimated for a number of success case development scenarios to give a feel for the potential value of the Shaiken oil discovery. The gas accumulation is poorly defined but a speculative evaluation of a range of accumulation sizes will be covered in a separate note at a later date.Cash flows were calculated using the PSC terms for cost oil and profit oil splits for Shaiken’s low risk categorisation. NPV/share was calculated assuming 488mmm shares i.e. pre this week’s SEDA.
CONCLUSIONS
1. The current share price reflects the value of Shaiken assuming the Field OIP is equal to the mean estimate provided by DGA (4200 mm bbl). This value is ~100p/share.
2. If Shaiken 2 proves that the OWC is at or close to spill and reservoir properties are similar to those found in Sh-1(i.e. no good or bad surprises) the unrisked share value is in the range 220 – 290p/share, based on Shaiken Jurassic alone. The share price will be whatever the market is comfortable with at the time, according to how risks are perceived!
3. It is vital that GKP can support the case for a decent field recovery factor as, even if the Jurassic is full to spill, NPV10/share is likely < 145p if recovery factor is as low as 15%. Evidence to support the case will need to come from core analysis including coreflood experiments, oil sample PVT analysis and the Sh-1 long term test results.

CASES AND ASSUMPTIONS
The range of cases investigated includes
a) Two OIP estimates of 4200 mmbbl (current DGA mean OIP estimate) and 13700 mm bbl (approximate OIP of Jurassic section only if it is full to spill)
b) Sensitivities of the 13700 mm bbl case to a range of well production rates (8000, 12000 and 15000 bopd)
c) Sensitivity of the 13700 mm bbl case to a reduced recovery factor of 15%.Key development assumptions common to all cases:• 1 additional oil appraisal well Sh-3 drilled in early 2011. Any gas appraisal wells will penetrate Shaikan oil reservoir en route to the gas accumulation and provide additional “free” oil appraisal wells.• Reservoir water flooded to supplement low reservoir energy and attain assumed recovery factors. Facilities designed to accommodate high volume water production and source and W.I. wells drilled.• Well spacing 400 acres ~1.6 sq km resulting in 96 producers for the higher OIP and 30 producers for the lower OIP. Nominal recovery 35mm bbl/producer when RF = 25%.• Oil export via Turkey, pipeline tariff 70c/bbl.• Big Oil Development approach and timetable: GKP buy out 1Q 2011. Concept selection 4Q 2011 (depletion plan, well design, export route, facilities capacity, processing options, power gen etc.), FEED engineering 1-3Q 2012. Dev approval 3Q 2012. Detailed Eng and Fabrication with startup 1/1/2015. • 2/3 rig drilling program commencing 2014. Deviated wells drilled from multiple well pads.• Oil Price 2015 $83/bbl Brent. Shaikan discount to Brent 8.5%. Exch Rate $1.6/£.• Oil price and cost inflation 2.5%• 30 Year production profile

DESCRIPTION, RESULTS AND COMMENTS
Case 1 4200 mm bbl OIP Description, Results and Comments• RF = 25%, Field Gross Reserves over contract life 1050 mm bbl• Well IP 12000 bopd, Peak Oil Rate 290000 bopd in 2018• Capex Drilling/Facilities/Export = $2650mm m.o.d., $2.5/bbl• Opex $1.0/bl at peak rates, $4.3/bbl over field lifeNPV10/share = 103pNPV/ W.I. bbl = £3.0This result is interesting since it falls within the current share price trading range. The market is pricing the share at the value of the drilled asset. One interpretation is that the political risks and other uncertainties are offsetting all the upside associated with Shaikan itself and the other prospects. Normally share price reflects what is foreseen in a few months time.
Because the market can’t see 6-9 months ahead with any clarity the big investors are only willing to pay what is known in Shaikan today. Case 2 13700 mm bbl OIPDescription, Results and Comments• RF = 25%, Field Gross Reserves over contract life 3270 mm bbl• Well IP 12000 bopd, Peak Oil Rate 630000 bopd in 2025• Capex Drilling/Facilities/Export = $6470mm m.o.d., $2.0/bbl• Opex $1.0/bbl at peak rates, $2.4/bbl over field lifeNPV10/share = 263pNPV/ W.I. bbl = £2.5This is a good time to talk about well rates. It is easy to get carried away with these when you hear about very high well rates at Tawke and particularly Tak-Tak Fields. However these crudes are higher API gravity i.e. significantly lower specific gravity and significantly less viscous than Shaikan. They have a higher GOR and this lightens the flowing column in the wellbore assisting high rate production. Also test rates from a single well flowing in a reservoir are not always representative of the average rate of 20, 50, 100 wells all producing from the same reservoir.The rate used in this analysis is NOT derived from the summation of the test results reported in the DGA report (Fig 11 and Fig 15) or the recent Macquerie presentation (slide 16). In fact the figures shown in these documents are misleading. Both report 5000bopd from the Butmah but this zone did NOT flow to surface due to wellbore problems that required the test string to be fished. (Bit misleading on part of GKP/DGA.)The combined rate was about 7600 bopd from DST 1 and 2. Considering the Butmah has 79m of pay it should be capable of supporting a combined rate of 12000 bopd from the entire Jurassic if it is fractured. However the reason for using 12000 bopd is related to the overall field profile that this produces.The production profiles from Giant (>500 mm bbl reserves) and Super Giant Fields (> 5Bn bbl reserves) can be characterised using a few parameters and those parameters have a range that is set by the laws of physics and other laws (such as Murphy’s!) that conspire to limit the rate that oil can be extracted.
One of the key parameters is the depletion rate in the final year of the peak/plateau production period. Depletion-at-peak rate is the % of remaining reserves produced in the final year of plateau. The 12000 bopd average well initial rate results in a depletion-at-peak rate of 12%. The mean depletion-at- peak value for the 20 non OPEC Giants entering the decline phase in the 2000’s was 13.3% and that of the 4 OPEC Giants was 10.2%.
Using significantly higher well rates will result in depletion-at- peak values well beyond historical precedents. (Note some of you may be asking why not drill fewer wells with a higher initial rate. However this would imply a much larger well spacing and I don’t have evidence to show that this would be realistic.)
Sensitivities to well rates:Case 2a Well IP = 8000 bopd • Peak Oil Rate 500000 bopd in 2025 (depletion-at-peak 9.3%)• Field Gross Reserves over contract life 2960 mm bbl• Capex Drilling/Facilities/Export = $5666mm m.o.d., $1.9/bbl• Opex $1.2/bbl at peak rates, $2.4/bbl over field lifeNPV10/share = 222pNPV/ W.I. bbl = £2.3
This case does not get as close to achieving the 25% recovery factor in the 30 year profile. More wells would need to be drilled. Note the reduction in NPV. It is important for share price that GKP show everyone that 10000+ bopd will be achievable.Case 2b Well IP = 15000 bopd• Peak Oil Rate 700000 bopd in 2025 (depletion-at-peak 14%)• Field Gross Reserves over contract life 3370 mm bbl• Capex Drilling/Facilities/Export = $6690mm m.o.d., $2.0/bbl • Opex $1.0/bbl at peak rates, $2.4/bbl over field lifeNPV10/share = 291pNPV/ W.I. bbl = £2.6
This case is considered an upside from the perspective of well and field profile performance. The % depletion- at-peak is higher than the recent historical mean for Giants. It may be achievable if water imbibes very effectively into the matrix pores and expulses the oil into the fracture network. However it is seen as a stretch due to the heavy oil viscosity.
Sensitivity to Recovery FactorCase 2c Well IP = 12000 bopd, R.F. = 15%• Peak Oil Rate 47000 bopd in 2025 (depletion-at-peak = 17.5%)• Field Gross Reserves over contract life 2060 mm bbl• Capex Drilling/Facilities/Export = $6470mm m.o.d., $3.1/bbl • Opex $1.4/bbl at peak rates, $3.8/bbl over field lifeNPV10/share = 145pNPV/ W.I. bbl = £2.2This case shows the perils of getting the RF wrong. It assumes the operator develops the field, i.e. invests assuming a 25% RF but reservoir performance has been over estimated and RF turns out to be 15%. Costs and, for simplicity, the initial well rate assumption is the same as Case 2. NPV/share drops from 263p/share to 145p/share. Note that the depletion-at- peak term is high (17.5%) indicating in reality well rates would decline more quickly than modelled hitting the NPV even harder.Sensitivity to CostsThe NPVs are very insensitive to the dev cost assumptions at the levels assumed. They would have to increase by well over 50% before the cost oil kitty becomes saturated and NPVs are hit hard.

General Comments
I have not tried to evaluate the Cretaceous Sarmond as frankly we don’t know anything about it (although it is lumped into DGAs 4200 OIP estimate). DGA report says there is 37m of pay and estimates 744 mm bbl OIP (up to 3bn if full to spill) but we have not seen test results. It could be a low flow rate interval. The reservoir temp will be about 100 F and the oil viscosity may be too high for decent production rates. If I am not mistaken this is in the range where biodegradation may be quite severe. The bugs may have left only the long chain HCs. There is also the Garagu where oil shows were encountered but logs could not be run. With favourable results Shaiken oil total PV10 may approach £3/share. The time to evaluate the Sarmond and Garagu however is after the shallow Shaikan 4 test. No attempt has been made to try to optimise NPV by the use of an early production system.

Very important point... these are NPV values to GKP. If big oil comes in to buy out GKP its NPV10 will be reduced by the amount it pays. If it pays the full NPV10 value it will make only a 10% return on the investment. Big oil might want to factor in some remaining risk on oil price, well rates/reservoir performance etc by evaluating the project at a higher discount rate. For example Case 2 drops to 196p/share on a PV12 basis and 127p/share on a PV15 basis. Similarly Case 2 NPV10 drops to 220p/share if Brent is $70/bbl in 2015.

Looking forward to the presentations tonight. May see some of you there!