nightmare, page-13

Hi vaga, agree :o) though the chance of D4 coming in dry is very small. HDGU1 is probably the highest risk well drilled to date (beside HDR1 that is) given its stepout distance and the HDR1 result.

Someone else asked about how I had arrived at a production lifespan of 7-10 years for Rayburn? Well, a bit of simple arithmetics really. Using the numbers provided by STX in upgrading their revenue to 55-60mn for the current year (including Mesquite production - which I will ignore), they had used an assumed average gas price of US10/mCF. We know their NRI is about 17.5%. So, to get 55-60mn, they would have to produce a 5.5-6BCF net to STX to get 55-60mn at US10/mCF. For this to happen, field production must be 6BCF/0.175 = 34BCF. It's actually not this high since some of the production revenue is coming from Mesquite, but if we assume all of it is coming from Rayburn, we're erring on the safe side.

So back to the numbers... depending on your recoverable reserve assumption (mine is 250-300BCF), annual production of 34BCF implies a field life of 7.35 years to 8.82 years.

Yes, the prod rate of each well will decline rather sharply after 2-3 years, but they will drill more wells progressively to access additional unrecovered reserves. We'd already been told that each well will recover between 5-10BCF. So to fully drain the field of 300BCF say, they will need to drill around 30 to 60 wells over the field life. Sounds like a lot of hardwork and CAPEX? Not really a problem when the payback for each well is 1BCF. Even if one allows for OPEX of 1BCF, that's a ROI of more than 100% for every dollar invested. There are of course operational and geological risks attached to this field, but the highly profitable margin is more than sufficient in offsetting those risks.

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