PetroBakken: Production Growth on the way

[dan_s]

May & June were very wet in Canada which really slowed down activity. Today PetroBakken has 15 rigs running and a lot of wells to be completed.

From the company's press release: "Activity levels have resumed in the second half of the year as we focus on the efficient execution of our 2012 drilling program. Production for July 2012 of 38,250 boepd, based on field estimates, did not materially increase from June as activity was ramping up through the month. However, we currently have 27 net wells waiting to be completed or brought on production and 14 drilling rigs operating within our core Bakken and Cardium areas. With approximately 75% of our wells yet to be drilled in our $875 million 2012 capital program, our production growth will gain momentum in the second half of 2012 as we bring new and existing wells on production. As previously announced, we expect 2012 exit production rates of 52,000 boepd to 56,000 boepd".

PetroBakken reported a 2nd quarter loss because they took non-cash impairment (asset writedown) on their natural gas assets in BC. The balance sheet is solid and they are going to report strong 2nd half results. The dividend is secure.

The big increase in production will come from the Cardium.

Note: One of my favorite micro-caps is Vero Energy (VRO). The partner with PetroBakken on a lot of Cardium wells.

[danross70]

So, what is the consensus on the best way to own PBN, by owning PBG (each PBG share represents roughly $1.05 cash, 75 cents in heavy oil assets, and 1.08 shares of PBN, yet sells for less than the price of a PBN share), or by owning PBN directly? The arbitrage is attractive, but there will have to be some catalyst to release the value in the PBG stock, perhaps a merger of the two or a distribution of PBN stock by PBG. Owning PBG also allow US shareholders to participate indirectly in the dividend reinvestment program. I am leaning toward converting my PBN position to PBG.

[mingya]

I wonder about that too. I am not so interested in the dividend (nice to have), but always liked the upside risk with Petrobank. The latest presentation shows that this is quite undervalued just if you sum the Petrobakken itself.

THAI is struggling with about 400 bopd from the Kerrobert project and far below the 7,000 mark touted in the presentation. For some reason I have a sliver of hope that they can get this working right. I just wonder if the time to get the deep roasting fire front moving takes too long when compared to alternatives like SAGD. I know there are being extra cautious this time, but we are getting towards the first year anniversary. I am starting to think it takes one year from drilling and set-up and 2 more years for ramp-up to full production - I am not sure if that is a viable model.

[dan_s]

Update of PetroBakken forecast is on my To Do List for today. PetroBakken is in the Sweet 16 because it is an excellent choice for those seeking high yield dividend stocks + I think it is trading at a deep discount to the value of its Cardium position. It they hit their production targets (and they seem very confident) then the share price should respond.

I really like the PetroBank management team but I'm not sure about THAI. Regardless, they hold some valuable acreage.

[dan_s]

Sweet 16 Growth Portfolio: An updated Net Income & Cash Flow Forecast model for PetroBakken Energy Ltd. (PBN.TO) has been posted under the Sweet 16 Tab.

As long as WTI crude oil stays over $80/bbl and PetroBakken hits their own production guidance, they should have now problem paying the monthly dividends. If natural gas prices push up to $3.50/mcf in 2013 the outlook for this one looks very good.

Also, I heard a "rumor" yesterday that PetroBank is getting good results on their oil sands project. Apparently, they have finally figure out how to control the sand issue in the horizontal production wells.

[prince_jake_33]

The second quarter has been interesting in the Bakken. Much of this has been better than expected as wide oil differentials were expected, but decreased costs weren't. A reoccurring positive is decreased water costs. Water pipelines are being installed at a faster rate as construction companies are not booked out for months, providing infrastructure quickly and at a reduced cost. Trucking charges are also decreasing as there seems to be enough supply for demand. More importantly pressure pumping, as the Bakken is still seeing price decreases, although other basins have had prices level off. Other companies like QEP (QEP) see these positives, and are adding acreage.

QEP's purchase was in northeast McKenzie County. This area has produced some excellent IP rates, although it has higher GORs. With Helis selling its operated acres, there are very few other opportunities in this area. Both Denbury (DNR) and Newfield (NFX) are in this general area and have had some very good completions. Some of Continental's (CLR) best wells are located here. There is little by the way of opportunities in this area with respect to core operated positions. Much of these positions are held by bigger producers, like the ones listed above. Asset sales to fund capex would more likely be in areas that are not as good.

Companies operating in northeast McKenzie County faired well in the second quarter. Realized oil price was much lower but was figured into estimates. Well costs were lower when taking into account the price of water and stages. Here are how some of the companies near QEP's new acreage faired. WPX Energy (WPX) reported a large increase in oil production, while costs trended lower. LOE decreased 6%, while gathering, processing, and transportation costs were down 10%. WPX increased capex, which has been the norm for the basin. $75 million of the $200 million was for completion and facility costs. Cap ex increases are being done in the face of lower costs, but overall spending is higher. Average completions are being done with more stages, water, and proppant. This makes each completion more expensive, but production increases more than offset this. On average, completion costs are down 20% from the first of the year.

Costs should continue to decrease. One important factor is pad drilling. WPX has been drilling all over its acreage and now has just 10 wells to do for its acreage to be held by production. All will be done by the end of the year. This coupled with other infrastructure improvements will decrease well costs by $2 million. Current well costs are $12.5 million. Its wells on the reservation cost approximately $500,000 more. A move from 100% sand to a 65% ceramic mix also adds $1 million. WPX estimates EURs of 805 to 710 MBoe in its Williston Basin acreage.

Bakken differentials have been an issue for the first six months of the year. WPX believes this will average $11 off WTI for the rest of the year. Natural gas liquids pricing has also decreased in the second quarter. Its original estimates were for $51/barrel, while the current realized price is $31.

SM Energy (SM) added a fourth rig and has started infill drilling. SM's acreage is very good, with the majority in north McKenzie County. Production was up only slightly from the first quarter, but we should see this improve in the third quarter. Costs should pull back some as well. Occidental (OXY) reported a large increase in mid-continent production. The majority of this was from the Bakken. Conoco (COP) also reported a large increase of U.S. unconventional oil plays. The bulk of this was from the Eagle Ford, Bakken, Permian and oil sands. The average Bakken production for the quarter was 25,000 Boe/d, with a total of 8 rigs in the play. COP's Bakken results were hindered by a 23% decrease in the realized price of natural gas liquids.

Hess (HES) has increased its capex spending, with the majority seen in the Bakken. 35% of its expenditures will be spent on the Bakken, compared to 11% in 2009. Hess's Bakken production was up to an average of 55,000 Boe/d in the second quarter. This was a year-over-year increase from 25,000 Boe/d. It commenced its crude by rail system and shipped 29000 Boe/d to markets with higher realized oil prices. It joins EOG Resources (EOG) in using the rails, for higher oil prices.

Hess is changing the way it completes wells in the Bakken. This is important as it seems to have found a recipe that works the best while reducing overall costs. It had been aggressive using a 38 stage frac. These wells cost on average $13.4 million. Its move to infill drilling, and reducing to 34 stage, sliding sleeve design wells reduce this cost to $11.6 million. In the fourth quarter, further cost reductions will be seen bringing the average to $10 million. Hess currently uses a controlled flowback in the Eagle Ford and Utica to increase EURs. It does not do this in the Bakken, as the nature of these plays are quite different.

In summary, northeast McKenzie County is where some of the best well results have been completed. Much of this is held by production, and many of the bigger players will be concentrating on pad drilling. We will continue to see a decrease in well costs, and increases to cap ex. The most important factor is realized prices. Oil has held up nicely, but natural gas liquids and especially natural gas have decreased significantly. Producers like Hess are able to send a large number of barrels per day to markets with better pricing. I believe these variables will continue to add value to this area. The price tag QEP was willing to pay, shows some companies are not fairly valued at today's market capitalization.