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PennWest


Zorrofan
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I wanted to get the boards feedback on PennWest. The company has been undergoing a number of changes over the past few years, leading up to it's converting from an income trust to an E & P company on January 1, 2011.

 

Here are some of the highlights, as I see them

 

GOOD

 

- brought in Murray Nunns a couple of years ago and he has been working hard at tightning things up operation wise

- reduced debt by over $1 billion

- increased land holdings in key production areas through acquistions and direct land purchases & swaps

- sold off non core assets

- joint venture to develop Peace River oil sands

- joint venture to develop northern BC gas holdings

- has over 7 million acres to explore & develop

- still pays a $1.08 dividend, so you get paid to wait

 

The BAD

 

- production has not increased even though company has a significant capital budget

and has in fact dropped by 25,000 BOPD over the last two years, although some of that is due to land sales

- the pricing in the oilsands joint venture seemed a bit weak 

 

 

In the interest of full disclosure I both hold the company and do like it as an investment, but I strongly believe Munger's credo to invert! I am trying to decide if it would be better to switch to SD instead. Comments?

 

cheers

Zorro

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I used to own PennWest a few years back and sold due to a lack of direction. I made a bit of money because I bought right after the trust tax announcement

 

I like Nunns, and like how they are refocusing. I am however not a big fan of the CEO. While I owned it the company had no vision and kept selling shares to pay the dividends. They also kept talking about Peace River but had no real plans to develop it. The swift towards a Corporation, and away from a dividend and towards growth should do well for them. With that said, I prefer ATPG and SD because they have great near term catalysts and are dirt cheap from an asset perspective. I will have to relook at PWE though. It has popped up a bit on Gurufocus and now here.

 

 

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Me too I used to own PWE and sold when they made the big merger in 2007 if I remember well. It seemed to me that they had diluted original value in the merger. I haven't followed in the last 2 years because there are better values out there like you seem to have concluded also. I am a peak oil believer and have been for a while. But this economic crisis could very well have a very negative influence on prices over the next few years and cause higher cost projects to be put on hold for a while (magnifying the problem down the road). I would look for cheaper to exploit resources at this point.

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  • 3 years later...

Absolutely!

 

Net asset value is well into the teens.

 

You have a leader that will do what it takes to make this company succeed unlike previous leaders. Also, was COO of Marathon or a company 5 times PWT size.

 

Don't forget that Rick George is Chairman and probably has zero intention to get his reputation tarnished by this company. Also, Allan Markin was on the board for a little while and bought $20 million worth of shares. He apparently visited all operations and made recommendations. The reason for the departure was unclear, but he kept all his shares and left in good terms. There is speculation that it might have something to do with his previous job at CNQ.

 

The strategy is actually pretty simple: focus on your most profitable assets and where you can have some scale. The rest which earns little is to be divested to pay off debt. They already have sold $485 million worth of assets and plan for $1.5 billion in 2014. Debt to cash flow ratio already looks quite a bit better and I like their strategy of not entertaining fire sales. The Street is disappointed because it was expecting a much quicker exit and somehow thought that boe/day would stay flat while disposing of assets???

 

Eventually, the company will have very little debt and produce 80% oil and natural gas liquids at high netbacks. I doubt it will be around that long especially if it keeps trading at these prices.

 

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I think I used to hold Pennwest when it was a trust. 

 

It is certainly messy right now.  Rick George has bought around 7-8 million dollars in shares so far.  Now, I am sure this is not all of his net worth by any means, but if anyone knows what this company's assets are worth he would be that person. 

 

About half price of its supposed NAV.  Financials and production seems to have stabilized for now. 

 

Now, if I am right there should be alot of tax loss selling, starting i. a couple of weeks, especially in a year when everyone wants to offset gains made elsewhere.  It is certainly on my watch list.

 

 

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"are you guys worry about widening differential?"

 

That is a big problem, however I think that the market at the moment is more than discounting this issue. There is also a lot of focus on "spot" discount by investors vs longer term contracts.

 

It is pretty clear that the U.S. has benefited tremendously from the increase in oil & gas activity over the past several years. Without it, I don't know where would be the unemployment rate but, I would hazard to guess that it would be appreciably higher. Just think how much this has helped GE, even Buffett with Burlington. Demand for housing, steel, motors, pumps and all kinds of industrial outfits.

 

The other benefit, especially recently, is a large decline in WTI and gasoline prices. This is another big help for U.S. consumers. There is more oil produced locally and this helps. However, if WTI keeps getting lower then the pressure that you are seeing on Canadian oil producers to cut costs, spending and rationalize will also apply to U.S. producers. This will mean less employment created by oil & gas which has to be one of the few "new" and bright spots in the U.S. over the past 5 or 6 years. So there is some balance in there. 

 

Now, the approach that has been taken by Obama to block the XL pipeline so far will likely backfire. Not only is this creating issues for Canadian producers but, also for U.S. producers in northern states which are forced to sell their product at a discount and to ship it by rail. The longer this goes on, the higher the pressure will get on the Canadian government to build the TransCanada East project and the Western one from Enbridge. Canada cannot afford to sell its product forever at the lowest worldwide price and being also one of its largest industry.

 

Once approvals are in place and this is progressing, the discount will narrow and especially on longer term contracts. Eventually, it will mean higher gasoline prices for U.S. consumers than now and I suspect that some U.S. oil in the Bakken and other plays will ship out globally from Canada. I also envision a future push from U.S. producers to build more pipelines to get the additional oil out. They won't accept either to be "trapped" and to sell their oil for a pittance while it could be sold well north of $100 on the international market.

 

Cardboard

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Delayed restart of this refinery in Indiana is also playing a very large impact on spot differentials that we are seeing now:

 

http://www.reuters.com/article/2013/10/29/bp-results-whiting-idUSL5N0IJ37920131029

 

CNQ mentioned recently that differentials to WTI will come down dramatically once it comes back on line.

 

To give you an idea about the craziness in spot prices in Alberta, WCS (Western Canadian Select or heavy oil) went up by $6.68 yesterday and the SCO (Synthetic Crude Oil or light) went up by $2.98.

 

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I have a full position Longlake95. I have added close to the lows.

 

I still can't believe that acquisitions are not occurring in this sector. It is not like the entire sector is down, it is more smaller, lighter oil oriented firms that are trading cheaply. Even growing firms like LEG are very cheap. If you look at the charts of majors, CNQ, SU and others they are close to 52 week highs. Something is way out whack. But, again most executives seem to buy at the tops or just like average Joe investors.

 

While I agree that PWT still has too much debt and that most cash flow is reinvested into capex, eventually lower decline rates will mean free cash flow. The assets are good and netbacks are high and will be higher under the new direction.

 

I found this today under Stockhouse and I think it is well worth thinking about. Sorry for the format:

 

"Toil for oil means industry sums do not add up By Mark Lewis Rising costs are being met only by ever smaller increases in supply. The most interesting message in this year’s World Energy Outlook from the International Energy Agency is also its most disturbing. Over the past decade, the oil and gas industry’s upstream investments have registered an astronomical increase, but these ever higher levels of capital expenditure have yielded ever smaller increases in the global oil supply. Even these have only been made possible by record high oil prices. This should be a reality check for those now hyping a new age of global oil abundance. According to the 2013 WEO, the total world oil supply in 2012 was 87.1m barrels a day, an increase of 11.9mbd over the 75.2mbd produced in 2000. However, less than one-third of this increase was in the form of conventional crude oil, and more than two-thirds was therefore either what the IEA calls unconventional crude (light-tight oil, oil sands, and deep/ultra-deepwater oil) or natural-gas liquids (NGLs). This distinction matters because unconventional crude has a higher cost than conventional crude, while NGLs have a lower energy density. The IEA’s long-run cost curve has conventional crude in a range of $10-$70 a barrel, whereas for unconventional crude the ranges are higher: $50-$90 a barrel for oil sands, $50-$100 for light-tight oil, and $70-$90 for ultra-deep water. Meanwhile, in terms of energy content, a barrel of crude oil is worth 1.4 barrels of NGLs. Threefold rise The much higher cost of developing unconventional crude resources and the lower energy density of NGLs explain why, as these sources have increased their share of supply, the industry’s upstream capex has increased. But the sheer scale of the increase is staggering: upstream outlays have risen more than threefold in real terms over the past 12 years, reaching nearly $700bn in 2012 compared with only $250bn in 2000 (both figures in constant 2012 dollars). Coinciding with the rise in US tight-oil production, most of this increase in upstream capex has occurred since 2005, as investments have effectively doubled from $350bn in that year to nearly $700bn in 2012 (again in 2012 dollars). All of which means the 2013 WEO has the oil industry’s upstream capex rising by nearly 180 per cent since 2000, but the global oil supply (adjusted for energy content) by only 14 per cent. The most straightforward interpretation of this data is that the economics of oil have become completely dislocated from historic norms since 2000 (and especially since 2005), with the industry investing at exponentially higher rates for increasingly small incremental yields of energy. The industry has been able and willing to finance such a dramatic increase in its capital investment since 2000 owing to the similarly dramatic increase in prices. BP data show that the average price of Brent crude in real terms increased from $38 a barrel in 2000 to $112 in 2012 (in constant 2011 dollars), which represents a 195 per cent increase, slightly greater in fact than the increase in industry capex over the same period. However, looking only at the period since 2005, capital outlays have risen faster than prices (90 per cent and 75 per cent respectively), while in the past two years capex has risen by a further 20 per cent (the IEA estimates 2013 upstream capex at $710bn versus $590bn in 2011), while Brent prices have actually averaged about $5 a barrel less this year than in 2011. Iran not a game changer That prices have fallen slightly since 2011 while capex has risen by a further 20 per cent is a flashing light on the industry’s dashboard indicating that its upstream growth engine may finally be overheating. Without a significant technological breakthrough reversing the geological forces that have driven the unprecedented increase in upstream investment over the past decade, prices will have to rise further in real terms from here or else capex – and with it future oil production – will fall. It should also be emphasized that this vast increase in capex has occurred during a prolonged period of record-low interest rates. Once interest rates start rising again, this will put further pressure on the industry’s ability to make the massive capital outlays required to keep supply growing. Of course, the diplomatic breakthrough achieved with Iran over the weekend could provide some much needed short-term relief to the market, as Iran’s exports could ultimately increase by up to 1.5m barrels a day if and when western sanctions were to be fully lifted. But this would not change the dynamics of the industry’s capex treadmill in any fundamental sense. Even if global oil demand only grows at 1 per cent a cent a year, those extra barrels would be would be fully absorbed by the market within about 18 months. And that is probably how long it would take for Iran’s production and exports to return to pre-sanctions levels in any case. Alternatively, if we take the IEA’s estimate that global production of conventional crude oil from all currently producing fields will decline by 41m barrels a day by 2035 (that is, by an average of 1.9m barrels a day per year), then Iran’s potential increase of 1.5m barrels a day would compensate for just 10 months of natural decline in global conventional-crude output. In short, behind the hubbub of market hype about a new age of oil abundance, the toil for oil is in fact now more arduous and back-breaking than ever. This should worry everybody, because with the evidence suggesting that consumers are reluctant to pay much above $110 a barrel, it is an open question what happens next to the industry’s investment plans and hence, over time, to the supply of oil. Mark Lewis is an independent energy analyst and former head of energy research in commodities at Deutsche Bank; Daniel L Davis, a lieutenant colonel in the US Army, is co-author" 

 

I have also seen a chart that shows U.S. oil production peaking in 2016. Despite the best efforts from the industry, I would tend to believe that they have cherry picked best locations for horizontal drilling and unconventional techniques and that once the Bakken and Eagle Ford mature that it will be difficult to find new fields with such high initial payouts to replace the high decline rates from these large productive plays. We also hear little about Saudi Arabia and their Ghawar field lately, but eventually this will run out or at least become more expensive to milk.

 

Cardboard       

 

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So basically the long term dynamics of NG and crude oil is quite different

Basically the high price will persist for crude oil

 

I have a full position Longlake95. I have added close to the lows.

 

I still can't believe that acquisitions are not occurring in this sector. It is not like the entire sector is down, it is more smaller, lighter oil oriented firms that are trading cheaply. Even growing firms like LEG are very cheap. If you look at the charts of majors, CNQ, SU and others they are close to 52 week highs. Something is way out whack. But, again most executives seem to buy at the tops or just like average Joe investors.

 

While I agree that PWT still has too much debt and that most cash flow is reinvested into capex, eventually lower decline rates will mean free cash flow. The assets are good and netbacks are high and will be higher under the new direction.

 

I found this today under Stockhouse and I think it is well worth thinking about. Sorry for the format:

 

"Toil for oil means industry sums do not add up By Mark Lewis Rising costs are being met only by ever smaller increases in supply. The most interesting message in this year’s World Energy Outlook from the International Energy Agency is also its most disturbing. Over the past decade, the oil and gas industry’s upstream investments have registered an astronomical increase, but these ever higher levels of capital expenditure have yielded ever smaller increases in the global oil supply. Even these have only been made possible by record high oil prices. This should be a reality check for those now hyping a new age of global oil abundance. According to the 2013 WEO, the total world oil supply in 2012 was 87.1m barrels a day, an increase of 11.9mbd over the 75.2mbd produced in 2000. However, less than one-third of this increase was in the form of conventional crude oil, and more than two-thirds was therefore either what the IEA calls unconventional crude (light-tight oil, oil sands, and deep/ultra-deepwater oil) or natural-gas liquids (NGLs). This distinction matters because unconventional crude has a higher cost than conventional crude, while NGLs have a lower energy density. The IEA’s long-run cost curve has conventional crude in a range of $10-$70 a barrel, whereas for unconventional crude the ranges are higher: $50-$90 a barrel for oil sands, $50-$100 for light-tight oil, and $70-$90 for ultra-deep water. Meanwhile, in terms of energy content, a barrel of crude oil is worth 1.4 barrels of NGLs. Threefold rise The much higher cost of developing unconventional crude resources and the lower energy density of NGLs explain why, as these sources have increased their share of supply, the industry’s upstream capex has increased. But the sheer scale of the increase is staggering: upstream outlays have risen more than threefold in real terms over the past 12 years, reaching nearly $700bn in 2012 compared with only $250bn in 2000 (both figures in constant 2012 dollars). Coinciding with the rise in US tight-oil production, most of this increase in upstream capex has occurred since 2005, as investments have effectively doubled from $350bn in that year to nearly $700bn in 2012 (again in 2012 dollars). All of which means the 2013 WEO has the oil industry’s upstream capex rising by nearly 180 per cent since 2000, but the global oil supply (adjusted for energy content) by only 14 per cent. The most straightforward interpretation of this data is that the economics of oil have become completely dislocated from historic norms since 2000 (and especially since 2005), with the industry investing at exponentially higher rates for increasingly small incremental yields of energy. The industry has been able and willing to finance such a dramatic increase in its capital investment since 2000 owing to the similarly dramatic increase in prices. BP data show that the average price of Brent crude in real terms increased from $38 a barrel in 2000 to $112 in 2012 (in constant 2011 dollars), which represents a 195 per cent increase, slightly greater in fact than the increase in industry capex over the same period. However, looking only at the period since 2005, capital outlays have risen faster than prices (90 per cent and 75 per cent respectively), while in the past two years capex has risen by a further 20 per cent (the IEA estimates 2013 upstream capex at $710bn versus $590bn in 2011), while Brent prices have actually averaged about $5 a barrel less this year than in 2011. Iran not a game changer That prices have fallen slightly since 2011 while capex has risen by a further 20 per cent is a flashing light on the industry’s dashboard indicating that its upstream growth engine may finally be overheating. Without a significant technological breakthrough reversing the geological forces that have driven the unprecedented increase in upstream investment over the past decade, prices will have to rise further in real terms from here or else capex – and with it future oil production – will fall. It should also be emphasized that this vast increase in capex has occurred during a prolonged period of record-low interest rates. Once interest rates start rising again, this will put further pressure on the industry’s ability to make the massive capital outlays required to keep supply growing. Of course, the diplomatic breakthrough achieved with Iran over the weekend could provide some much needed short-term relief to the market, as Iran’s exports could ultimately increase by up to 1.5m barrels a day if and when western sanctions were to be fully lifted. But this would not change the dynamics of the industry’s capex treadmill in any fundamental sense. Even if global oil demand only grows at 1 per cent a cent a year, those extra barrels would be would be fully absorbed by the market within about 18 months. And that is probably how long it would take for Iran’s production and exports to return to pre-sanctions levels in any case. Alternatively, if we take the IEA’s estimate that global production of conventional crude oil from all currently producing fields will decline by 41m barrels a day by 2035 (that is, by an average of 1.9m barrels a day per year), then Iran’s potential increase of 1.5m barrels a day would compensate for just 10 months of natural decline in global conventional-crude output. In short, behind the hubbub of market hype about a new age of oil abundance, the toil for oil is in fact now more arduous and back-breaking than ever. This should worry everybody, because with the evidence suggesting that consumers are reluctant to pay much above $110 a barrel, it is an open question what happens next to the industry’s investment plans and hence, over time, to the supply of oil. Mark Lewis is an independent energy analyst and former head of energy research in commodities at Deutsche Bank; Daniel L Davis, a lieutenant colonel in the US Army, is co-author" 

 

I have also seen a chart that shows U.S. oil production peaking in 2016. Despite the best efforts from the industry, I would tend to believe that they have cherry picked best locations for horizontal drilling and unconventional techniques and that once the Bakken and Eagle Ford mature that it will be difficult to find new fields with such high initial payouts to replace the high decline rates from these large productive plays. We also hear little about Saudi Arabia and their Ghawar field lately, but eventually this will run out or at least become more expensive to milk.

 

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Probably, as the cheap oil gone. Unconventional oil is simply more $$$ to explore and develop. Go forward ( next several decades) the efficient companies are going to rise to the top, as opposed to anybody with a drill bit, making money in oil.

Bigger will likely be better.

 

LL

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  • 1 month later...

I was impressed with Roberts. He seems to say all the right things (i.e focusing on free cash flow, investing capital in projects with highest IRR, not worried about just growing unprofitable daily volume to satisfy some folks in the market.) Don t know his track record,  I hope he can execute what he says

 

I have recently bought a small starter position

 

Plan to add more if I see Roberts, or Rick George buying. It seems that the sell off in last couple days related to projected decrease in daily volume-volume decrease is as per there plan just coming a little sooner.

 

Personally I have not done well in cyclicals or resource sector. Probably because I don't know what I'm doing. Have been enlightened by posters here and other threads

 

Myth, Cardboard or others I would appreciate what you think of the following:

 

Projecting 5 years down the road.

 

They are projecting  125,000 barrels per day with $45 net back---that works out to netback of  $2.05 B => $4.21 per share.

 

If you subtract Finding and development cost of $15-20/barrel, does that give you a reasonable estimate of FCF ---is this right?

 

I am getting a FCF/S=$2.34-$2.80 in 2018

 

If you give it a multiple of 10--> $23-28 share price + ~7% dividend while you wait at current price which works out to 30-35% per year return.

 

It seems like a decent bet

 

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I would say this guess is better than anything I could give you, page 27 has the cash flow forecast.

I am hoping it will get better as the operational and SG&A changes continue to drop to the bottom line.

 

http://www.pennwest.com/upload/media_element/media_file/15

 

You are approximately right, cash flow per share is $2.80 in 2018 per their calcs. The issue is a large chunk of that cash flow will be reinvested. Decline rates are probably around 30% and you will have to replace that production. You also want to grow production. The vast majority of the cash flow will be pumped back into producing / maintaining / and hopefully growing cash flow. They will not likely have any free cash flow outside of the dividend in 2018, the balance will be split between growth and sustaining / maintenance capex. This is why O&G companies trade for at or below 5X funds flow generally. 

 

I tend to trust him that the prior sales are accretive. They still have the strategic stuff to sale - Gas JV, Peace River, and Duvernay.

I would say there are better O&G companies available at cheaper multiples, but the leaps and fast movement of management really help sweeten the deal.

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Thanks Myth for reply

 

If you take a net back of $45 per barrel then subtract $20 per barrel to replace the barrel you sold for net back of $45, would what is left or $25 per barrel be FCF or cash available for dividends ,growth , debt payments or share buy backs?

 

Otherwise No FCF = bad business and perhaps would be better off elsewhere

 

 

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