Hi Bob, thanks so much for making the contact and above all, for sharing it with us. I’m going to comment in between and if you or anyone else wish to fire back, please go ahead.




Ok, I was disappointed in Q3 P&L. Missed my back of the envelope forecast of .10 to .12eps by a mile at .05. Q3 for SKO is 6/1- 8/31/12. If you look at a Brent crude price chart, you can see a big drop in price in that period, with the low about mid qtr. So avg prices dropped about $8/boe and that caused about $1million in lost profits. So if prices had been even, they might have come closer to Q2 but they still missed my production target. So what's up? Called CFO Jim Hodgson.


1. Earlier estimates of productive capacity included natural gas production, which is currently shut in. Delvina 12 is capable of producing 3mmcfpd. Stream tried selling to the local refinery but they pay slow and were up and down with maintenance so Stream is proceeding with other options. Also there was repairs to one of the jet pumps that lowered production AND the refinery closure for maintenance.



First option is to sell the gas to a Greek company that the CEO has worked with before and known for a long time. They propose to bring in ngas generators to produce power from the Delvina ngas. They already have imported one 2.5megawatt unit and are delivering it to the Delvina field. They will use the already existing Delvina 12 for ngas. Each generator uses about 400mcfpd so Delvina 12 could support 5+. The regional power line is less than a km away to hook up to and sell into. I asked what price they would get for the ngas, he said $9 to 10/mcf. So this is a near term catalyst for Stream. But it will take some time to get the first one hooked up and running properly, run the line to the power grid and generate revs. Then the Greek company proposes to bring in more generators based on producing cashflow from the first one. I asked if there was any doubt this company could finance the new generators and Hodgson said no.


I mean, this is the type of information that should go into the MD&A! How is this not material?? About the greek angle, this is a bit of Mom n’ Pop again, it will most likely not amount to much, especially if they plan to bring in more generators based on producing cashflow from the first one. I mean, what is the price on the grid in Albania? It must be at least a year or two payback time on the generator, if not more. 400 mmcf per generator is about 5% of what SKO produces today, so any major impact on cash flow will be in the medium term, at the most. Still, don’t get me wrong, this is positive development, it shows that they are not sitting on their hands and waiting for that big power plant to be built. And who know, maybe there are more takers of gas out there once they see that it’s there and it works.


I asked about the restart of the power generation plant. Apparently the government put out a bid request to restart the plant. It originally used heavy sour crude to generate electricity and was closed for environmental reasons. The proposal contained requirements that would be hard to comply with and made the proposal uneconomic so the company that was most interested did not submit a bid. However, the same group is now proposing to build a new 100megawatt plant for power generation and feel it will be more economical than trying to convert the old plant. This would be sufficient size to use all of the Delvina field production once it's developed.


This is the big pie in the sky that would really do it for SKO. With 100 MW we’re talking about 16 MMcf/d or around 4.5 kboe/d including the condensate. Question is, will they base it solely on the Delvina field, or are there other sources of gas as well? Or can they also run it on coal? The reason I bring this up is because you would not go ahead and build this plant unless you have firm contracts on the gas, and 1P reserves…so this is where the Hz well comes in, we need that (and likely a few more…) to be able to be a trustworthy supplier to a 100 MW power plant. I think this is years into the future, and the main source of income from Delvina in the mean time with be the condensate.


Stream is required to drill one horizontal to prove up the concept. Initially they will use the ngas to feed the Greek mini plants and wait for the new power plant proposal to get to the construction phase before they drill any more wells.


2. Gas re-injection compressor. Stream has purchased a gas re-injection compressor that is being shipped from New Zealand. This will allow Stream to produce from their existing gas wells, strip off the condensate and re-inject the ngas into the field or produce it for power but the key is the condensate. Delvina is very liquids heavy at 100barrels condensate for every 1 mmcf gas produced. Delvina 12 could produce 200+bpd condensate and they will get Brent pricing. The compressor will take until early 2013 to be installed and operating but this is near term high revs for Stream. The horizontal well should produce another 300-400bpd condensate. 200bpd X $100/boeX92 days = $1.8million gross revs per qtr from Delvina 12 condensate.


Ok, so it is not online, but will be installed in early 2013….how can they not put this into the MD&A?? Already in the May 2012 MD&A they said that they “acquired the gas compressor” and in my contact with Jim earlier this year he said it would be operational in Q3…not so apparently. Delays happen, but lack of information to the market is what partly holds this story down. I’m all for the concept though, it is an excellent way to monetize the condensate while waiting for higher gas demand. Did you get a feeling for the capacity of the compressor? Will it be able to handle the volumes from the Hz well? Another question is the reinjection capacity of the well, I guess they will use the other old well for this purpose.


3. Another catalyst is the installation of the 6 jet pump units in existing oil wells. The current production prior to installation is about 10-12bpd so the increase to 100bpd will add 90bpd per jet pump or 540bpd to Stream production. The first three units are ready to turn on and the next 3 will be installed and operational by the end of the year. 540bpd X $70/boeX 92days= 3.47million per qtr. First qtr of full production is likely to be qtr ending 2/28/13. Since this is new production, Stream will just have to pay a 2-4% royalty on the production.


Yes, this is the bread and butter low hanging fruit that should drive production increases going forward. I seem to remember pay packs in the order of 8-10 months, and the kicker is that the decline is very low, so it’s not like a NA shale well…

In addition to the royalty they also have to pay this 10% state royalty that they are negotiating with the government about.


4. There is another possibility for the ngas use. Bankers Petroleum has drilled a well,that is a dry hole, looking for ngas to perform Enhanced Oil Recovery on their fields in Albania. If they are not successful in finding gas, they may become a customer.


For sure, and a third option could be to use the gas ourselves for EOR.


The first question I asked was about the pricing they receive for their crude. They sell most to an Italian broker at 68% Brent. The oil is shipped to a port, stored in tanks and once a month, a small tanker takes it away. The tanker is a small size and so the operating costs are relatively high at $12.90/boe. Stream is negotiating to raise the percentage to maybe 70%. They can also sell to the local refinery for 75% brent for their lightest oil and 60% for their heavy oil field. This works out to a blend of 71% Brent but the refinery takes it's time to pay. Stream gets paid in 10 days from the broker and closer to 90 days from the refinery. So they try to sell thru the broker. Another possibility is when production increases, Stream can contract more tanks and store higher quantities of crude for a bigger tanker to take away Stream's production. This would lower operating costs/boe and allow the broker to pay Stream more, maybe into the low 70% range.


Is the operating cost for the shipping 12.9  USD/bbl, or does that include transportation also in Albania? There are clearly upsides here as production increase, the quality of SKOs crude is higher that BNK, so no other reason for larger discount than smaller volumes and less bargaining power.


I asked why Bankers was getting 81% for their production. Hodgson said they have looked closely at that situation. They found that Bankers is selling to the same refinery that Stream deals with so they are waiting 90 days for their money. Also they are responsible for transporting the oil to the refinery so their net is not as good as it looks. Bankers is also a lot bigger than Stream so they have volume to negotiate higher prices.


Hmmm…I thought that most of the BNK crude went to refineries in Italy and Spain and that is why they access better prices with their larger volumes?


I asked about the horizontal well financing. He said they are close and expect to announce a deal in a month. They hope to issue one operational update that includes the financing, drill availability, takeoff agreements and timetable.


If this comes through, there is a window of opportunity here until then, as this would be very material and should set us up for a good run into the new year. SKO NEEDS to communicate better with the market, did you get that message across to Jim?


So in summary, 200bpd in high rev condensate is coming in early 2013 and possibly ngas production for the power generators at $9-10/mcf plus 500+bpd oil from the new jet pump units. That should be done by 12/31/12.


The horizontal well is expected to be at least 4mmcfpd plus 400bpd condensate.


So I was probably a little early in calling for big increases in production but it seems like Stream has multiple catalysts coming in the next few months. I am holding. Bobwins


So am I Bob, and looking to take some more paper from weak hands. Thanks again, much appreciated.