Ash,Apologies for the delayed reply - I'm a kiwi in London.  I...

Ash,

Apologies for the delayed reply - I'm a kiwi in London.  I usually enjoy your pragmatic and straight to the point posts, but this instance you're in defence mode when there is no need to be.  I am a holder, have bought at 10 cents, 9 cents, 11 cents, 16 cents, 14 cents and 13 cents and therefore aligned with the longs.  

You refer me to your recent post whereby you state:

"There are Macquarie and PWC liabilities to be satisfied from gas production which will soak up funds for a while - I struggle to correctly identify their timing and scale. While this delays the $$$ inflow, it strengthens the balance sheet and brings forward the option of refinancing if desired." 

Let me help you out with your struggle and identify the approx scale and timing of these cashflows over the 3 years (as implied per the announcement and RC's commentary).  The impact could be c$33m AUD over the next 3 years using the unwind rate experienced between Jun-16 and Jun-17.  I've presented this simply below using a linear payment profile - in practice it will most likely be lower in year 1 and higher in year 3.  It will also adjust depending on the ex-field price:

What does this mean for our production financials and cashflow?  Below I have modelled, rather quickly, the 12 months of NGP using known assumptions (I'm aware of) for the two scenarios:

Scenario 1. Mac takes gas or we pay Mac the financial settlement and find a buyer for our gas.  In the interests of presentation, i haven't grossed up cash receipts/Mac cost if we did find a buyer for the gas as it is the same result net in cash terms. 

Scenario 2. Mac doesn't take the gas and we don't find a buyer for the gas.  

Assumptions listed below table. 

Assumptions

1. Current receipts from LTM to Jun-18. Mereenie gas price > Dingo due to oil product mix.

2. First year NGP sales at $5.13 ex-field

3. NGP production costs calculated at incremental 50% rate to account for scalability, reduced transport as sold on ex-field basis.

4. NGP other costs for scaling management, advisors etc at 20% of current cost base for LTM Jun-18.

5. Interest and principal repayments consistent at same rate as LTM Jun-18.

6. Capex from cashflow assumed proxy depreciation in costs.

It doesn't look pretty on a cash basis if Mac doesn't take the gas and we don't find a buyer for the gas.  Happy to hear constructive thoughts.