| 2015 | 2016 | ||||||
| Price: | 18.32 | EPS | (0.67) | 0.77 | |||
| Shares Out. (in M): | 146 | P/E | na | 23.8 | |||
| Market Cap (in $M): | 2,667 | P/FCF | na | na | |||
| Net Debt (in $M): | 942 | EBIT | 0 | 0 | |||
| TEV (in $M): | 3,609 | TEV/EBIT | na | na | |||
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I am long PTEN. The stock is at $18, or I don’t think there’s a lot of downside on the fundamentals alone. There might be $4-5/sh of downside on a trading basis because this stock is a hedge fund whipping boy that gets yanked around whenever oil moves. But that’s the opportunity – the stock trades almost like it’s the same company that went through the 2009 downturn with a tired fleet of undifferentiated mechanical rigs and almost zero backlog, but the reality is their asset mix and organization has been radically transformed and they have a meaningful backlog now. It’s not the best business in the world, but it’s better than people give it credit for and the stock has been cut in half. I think it could go up at least 2x over the next 2-3 years, so you’ve got 18 points of upside compared with 5 points of downside. In the mean time it’s paying a 2.2% dividend that is secure and they are only levered 25% total debt/capital (cash flow interest coverage is >10x in my Low Case). There is little doubt they will be around for the next upswing.
Patterson-UTI has three business segments (1) contract land drilling – they drilled ~10% of all U.S. land wells in 2014 (2) pressure pumping and (3) a small E&P operation. Contract land drilling is their best source of earnings power and I am going to spend the most time on that segment. Its value alone is almost enough to support the entire market cap in my Low Case.
My Low Case valuation is $21. My High Case valuation is $37 – 41. If we have an epic meltdown I think it could touch $12 for a moment in time.
Land drilling primer: Land drilling used to be a pure commodity service. There was very little basis for contractors to differentiate themselves from the competition. Drilling contractors provided rigs to oil and gas producers (also known as “operators”), along with the men to crew the rigs, and the contractor would drill wells according to the operators’ instructions. The rigs were primitive mechanical contraptions run by guys who might otherwise be in motorcycle gangs or rodeos. Drilling contractors had no pricing power. It was very much a feast or famine business given the cyclicality of the oil patch.
Drilling is still quite cyclical, but other dynamics about the industry have changed as a result of the shale revolution. The land drilling industry has bifurcated into two groups; mom and pops who still own low-tech rigs crewed by unsavory dudes that drill simple vertical wells in conventional oil and gas formations, and the “Big 4” contractors who own fairly uniform fleets of high tech rigs crewed by professional staff that are backed by substantial organizational and technological support.
The Big 4 are Helmerich & Payne (NYSE: HP), Nabors Industries (NYSE: NBR), Precision Drilling (NYSE: PDS) and Patterson.
The game changed for a few reasons. The rise of shale drilling meant a growing need for contractors who could drill wells that didn’t just penetrate vertically into the earth for a mile or two; operators needed drillers who could drill down vertically first mile or two and then change directions and continue drilling horizontally for another mile or two through geological horizons that were only 100-200 feet thick. It’s kind of like drilling into a layer cake until you get to the cherry layer, and then drilling sideways through the cherry filling because you want to get as much of it as you can. Horizontal drilling requires equipment that can steer through the earth with a very high level of precision. When you’re trying to stay within the cherry filling the last thing you want is for the drill bit to accidentally veer up or down into the other layers of cake that are less tasty. Shale production is all about maximizing your contact with the source rock. Drilling with that kind of precision requires the assistance of computers to guide the drill bit; humans can’t do it alone. Operating more sophisticated equipment naturally required more sophisticated crews.
In the late 1990s, Helmerich & Payne (aka H&P), the industry’s largest and best run company, designed a rig with a top drive that was powered by alternating current electricity (as opposed to diesel fuel). It happened to be an ideal fit for shale when the revolution started gaining traction in the early 2000s. AC-powered rigs can do a lot of things that mechanical diesel-powered rigs can’t do. They steer the drill bit through the earth with smooth power and greater precision, and the accuracy of their penetration is greater. They damage fewer drill bits, which saves time and money. They generate reams of telemetry data that can be analyzed back at the company’s operational nerve center almost in real time to identify opportunities for improved drilling efficiencies. These learnings can be disseminated almost immediately to all the AC rigs in the entire fleet. The rig’s communications link with the operations center allows a second set of eyes to watch the rig to make sure operations stay on course in case the crew misses something. H&P can tell you at any given moment exactly what every single one of its rigs is doing anywhere in the country.
The difference between mechanical rigs and AC rigs is like the difference between a 1988 NASCAR Ford Thunderbird and a 2014 Mercedes Formula 1 car. With the Thunderbird you just strap the driver in and say “good luck”. You send him out on the track and the team basically can’t get any data off the car until he comes back into the pits. Their only contact with the car is through the driver via radio. In contrast, when a Mercedes F1 car hits the track, there is a team of computer engineers in the pits monitoring its performance, and there is also a team of engineers back at the factory monitoring additional parameters and supplying the driver with feedback he can use to drive better/faster/more efficiently. They can take the constantly optimized settings from the first driver’s car and apply them to his teammate’s car in real time. They can also tell if a combination of settings on one car is leading to conditions that may do damage to the car, and make adjustments to the second car based on that knowledge in order to preemptively avoid things like an engine meltdown that cost a lot of time and money.
The organization behind the Ford Thunderbird would be unable to run the Mercedes team because it would require a lot of sophisticated training they don’t already have. The same goes for drilling: the crews on a mechanical rig are generally unable step onto an AC rig and run it right away.
Shale introduced another dynamic to the drilling industry. Producers who drilled wells in conventional formations 20-30 years ago might have had 50-60% success rates, meaning that 40-50% of their wells were dry. The nature of shale is such that producers often have drilling success rates of 95-100%. The homogeneity of these formations is (relatively) high within a field, so when you’re drilling the same kind of well over and over across a swatch of acreage you have the opportunity to refine your approach to drilling a well and become more efficient with every well you drill. Given that operators pay drilling contractors by the day, time is literally money. Contractors who save their customers money by taking learnings from one rig in a field and applying them to others in the same field in order to drive down well cycle times will be rewarded with a steadier stream of work. In other words, drilling wells fast and drilling them consistently is a valuable service.
H&P usually has a slide in their presentations that illustrates the benefits of having superior efficiency – if one of their competitors is charging $25,000/day and takes 22.4 days to drill a horizontal well in the Eagle Ford, the operator pays $560,000 to the driller.
If it only takes H&P 18.1 days to drill the same well the operator would only have to pay $452,500 to the driller, for savings of $107,500. Since H&P is creating those savings they should be entitled to keep some it for themselves. They typically get about 1/3 of the savings. In this example, keeping 1/3 of the savings would result in them earning a premium of $2,000/day for a total dayrate of $27,000. The drilling bill, in spite of the premium dayrate, would be $488,700 (18.1 days * $27,000/day).
The operator has other intangible spread costs during the drilling process in this example of ~$45,000/day. When you factor 4.3 days of saved time, the operator will avoid an additional $193,500 worth of costs. Because H&P was able to drill faster than their competitor, they were able to save the customer $301,000 assuming equal dayrates. When you take H&P’s $2,000 dayrate premium into account they are capturing just over 10% of the operator’s total savings.
Shale introduced a dynamic that takes * some * of the pricing pressure off drillers during a cyclical downturn. When a downturn hits and operators seek to reduce their costs, the biggest opportunity for them to target is pressure pumping. It used to be drilling but not any more.
Total costs incurred by the operator during the drilling phase of well construction (including the intangible spread costs) used to account for ~2/3 of the cost of a conventional well. With shale wells it only accounts for ~1/3 of the total cost because a much larger portion of the cost goes towards fracking services. Speaking very generically, if the total well cost was $6 million, drilling phase of the well might cost $2 million and the completion phase might cost $4 million.
Much more money has to be spent on fracking shale wells than on drilling them because the porosity of shale formations is so low, and therefore more effort needs to be spent on forcing the rocks open in order in order to allow the hydrocarbons to flow to the surface.
(Porosity is the measure of how much of a rock’s surface area is open space. Higher porosity is better because it means more space for hydrocarbons to flow through. To draw an extreme contrast, the Ghawar field in Saudia Arabia, which is the largest field in the world at ~5 million bbl/d of production, and arguably the greatest material prize in human history, has porosity of up to 35%. Rosetta’s Gates Ranch field in the Lower Eagle Ford is one of the best shale assets and it has porosity of 12-13%.)
Also, reputational risk has become a key issue for the largest producers over the years. It’s simply not acceptable for them to end up in the news because of well blowouts or fatalities. Their operations are under immense scrutiny, and it’s just not worth it for them to save time by cutting corners. If you’re a drilling contractor and you can’t meet Anadarko’s health, safety and environmental protocols you’re not going to get the job no matter how cheap you bid.
Producers like Anadarko are generally going to be the ones with the deepest inventories of high quality acreage with the lowest finding costs, as well as the strongest balance sheets. In other words, they are the most desirable customers because they are the least likely to be affected by falling commodity prices.
At peak industry activity levels in Sep-2014 there were nearly 1,900 land rigs operating in the United States. Companies outside the Big 4 owned more than half of those rigs. However, only 850 of the 1,900 were AC rigs, and within the category of AC rigs the industry is much more concentrated; the Big 4 control approximately 80%.
850 AC rigs by company:
Investors have recently become concerned that the Big 4 are saturating the market with new AC rigs. H&P used to be the only player with an AC rig fleet of any size. They pretty much had the market to themselves. They were the only ones who could assemble their own rigs with off the shelf components instead of having to buy their rigs from NOV. The other big players developed the ability to make their own rigs, and at this point the Big 4 have the capacity to manufacture 160 rigs per year. Even startups like Independence Contract Drilling (NYSE: ICD) can make their own rigs. Total industry newbuild capacity might be 200 AC rigs per year. Assuming 100% manufacturing utilization they could probably double the fleet in 4 years.
Overcapacity will eventually become a legitimate concern, but I don’t think we got there this cycle. There were >1,300 rigs drilling horizontal wells at the peak in Sep-2014, meaning there were >500 non-AC rigs drilling wells that AC rigs can almost always drill faster. Some AC newbuilds will still enter the market in the next year but only because they were commissioned with multi-year take or pay term contracts before oil prices crashed. At this point in the cycle nobody is going to build rigs on spec.
Moreover, just having an AC rig doesn’t entitle you earn the same returns the big boys get. It’s not good enough to simply have the rig. You have to be able to maximize its performance.
ICD has good AC rigs just like H&P does, but there is a reason why H&P gets paid >$28k/day and ICD gets paid <$24k/day. H&P has a better organization which leads to faster well cycle times and less downtime, which leads to cost savings for the customer. Based on everything I’ve seen PTEN has the second best organization behind H&P. They only get paid ~$1k/day less than H&P for their AC rigs. PTEN’s average reported dayrate for their drilling segment was just $24,220/day for the MRQ, but that is because the overall rate is diluted by the presence of older legacy rigs that earn much lower rates. They don’t break out their dayrates by asset type.
Corporate history: PTEN was formed in 2001 through the merger of Patterson Energy (founded in 1978) and UTI (formed in 1986). Patterson and UTI rolled up hundreds of old drilling rigs during the lean years of the 1980s and 1990s when a lot of rigs were sitting idle. The U.S. land rig count was ~2,000 in 1979 when the second oil shock hit. The escalation in oil prices drove a frenzy of drilling activity that sent the rig count up to ~4,500 just two years later! A lot of those rigs were newly built to satisfy the demand, but after the collapse in 1982 the rig count fell to ~2,500 within a handful of months and never recovered. By the early 1990s barely 600 rigs were still working. Nabors rolled up a bunch of rigs and even made money by scrapping some of them and getting more money out of the steel than they paid for the machines. Mechanical rigs were a dime a dozen, so operators rarely signed long-term contracts for them, knowing that plenty were available.
When Patterson and UTI joined forces their combined fleet was a Noah’s Ark of different rig models that were old and tired. By the end of 2005 they owned 403 rigs in total, 361 of which were mechanical rigs and 42 of which were SCR rigs (a type of rig that was an intermediate step between mechanical and AC rigs). The combined company didn’t own any AC rigs. That didn’t matter because shale hadn’t taken off yet and oil prices were rising. Operators became motivated by rising oil prices to hire rigs and drill more wells. By that time a lot of rigs had been taken out of the industry’s fleet so the survivors did very well during the upswing. PTEN’s drilling segment EBITDA rose from $704 million in 2005 to $1,160 million in 2006.
Then the financial crisis hit. The absence of any backlog hit Patterson hard. PTEN’s drilling segment utilization fell from 73% in 2008 to just 27% in 2009. Since mechanical rigs generally work on a spot market basis they tend to get laid down before AC rigs that are more likely to be working under term contracts. Drilling segment EBITDA fell 70%, from $760 million in 2008 to $237 million in 2009. The stock fell 80%, from a high of $37.45 in Q3’08 to a low of $7.49 in Q1’09. The company wasn’t even levered – they had zero debt going into the downturn.
In contrast to PTEN, H&P did quite well. Thanks to their first mover advantage with AC rigs they had a substantial backlog of take or pay contracts. As a result, the utilization of their U.S. land fleet only fell from 96% in 2008 to 68% in 2009, and their EBITDA only fell 20% from peak to trough.
I think investor perception that PTEN and H&P sit at opposite ends of the quality spectrum was cemented during the crisis. The reputation was deserved back then, but PTEN’s drilling segment has since closed the gap because they were a fast follower and undertook an aggressive transformation. Their experience during the financial crisis made them very motivated to evolve. Around that time they bought their own AC rig design from a former H&P engineer who had developed the design and was shopping it around. Patterson branded it the Apex rig. The first Apex rigs were introduced in 2008. The company stopped doing stock buybacks and basically plowed all their capital into ramping up the AC rig fleet and developing the organizational support structure, building an average of 21 per year over the next three years. They outspent their operating cash flow and had to take on some debt in order to build the fleet. It was the right move and now the fleet is large enough to be FCF positive.
At YE2014 they had 145 Apex rigs. They are going to build 16 rigs during 2015 even though oil prices crashed because those newbuilds were previously ordered with multi-year take or pay term contracts behind them. At ~$23 million per rig the 16 newbuilds will cost $368 million. By YE2015 they will have 161 Apex rigs.
The company has also been aggressive about getting rid of their mechanical rigs. They wrote off, sold, or scrapped over 300 of them and in doing so reduced their exposure to 44 mechanical rigs at YE2014 from 361 rigs at YE2005.
PTEN significantly high graded their drilling segment’s customer base over the last few years. It’s still not as blue chip as H&P’s, but it is light years ahead of where it was heading into the last downturn. Importantly, whereas PTEN’s drilling segment had basically zero backlog in 2008, they now have a firm backlog equal to 1x LTM segment revenues (although it will be spread out over more than one year), and H&P is only slightly better with 1.2 year’s worth of current run rate revenues in their backlog.
In fact, the backlog is so substantial relative to the market value of the enterprise that I think the EBITDA from the backlog alone is almost enough to support the current share price for a year.
Drilling backlog EBITDA Low Case ($15/sh): The company will average 93 rigs under contract during 2015. Since PTEN doesn’t disclose their Apex rig economics we can use H&P’s results as a good proxy. H&P is currently earning rig-level drilling margins of ~$15,000/day ($28,000 dayrates minus $13,000 daily opex). Patterson’s executive chairman confirmed to us that H&P generally gets a ~$1,000 premium on their dayrates, so let’s haircut H&P’s daily rig margin by that much to get a ~$14,000 daily rig margin for Patterson’s contracts. I think it’s safe to stick with $14k/day economics for the backlog through 2015 and beyond even though we’ve entered a downturn because the contracts were signed back in a more robust market environment and the dayrates are generally fixed for the life of the contracts. If anything, $14,000 might be conservative because it assumes no cost relief as a result of the slowing environment.
(Side note: those assumptions result in an ROIC of 11% on newbuilds when you run them with a construction cost of $23 million, a useful life of 15 years, and a 35% tax rate.)
93 contracted rigs * $14,000 daily margin * 365 days = $475 million of contracted rig margin. Let’s burden that figure with the drilling segment’s allocated SG&A of $6 million and the full corporate SG&A of $54 million. Now we’re at $415 million of EBITDA.
H&P has traded at ~6.5x through the cycle. We should use an expanded multiple on these earnings because if it’s all they get from their rig segment it would represent a 45% decline from segment EBITDA of $768 million in 2014. Even if I only add 1 turn for a 7.5x multiple, the implied enterprise value would be $3.1 billion. Subtract $942 million of net debt and divide the resulting $2.2 billion equity value by 145.6 million shares = $15 per share.
Spot market drilling EBITDA Low Case ($1.70/sh): What about the other 52 Apex rigs that aren’t under contract? In my Low Case I assume they only achieve 35% utilization for the year at dayrates of $18,000. When netted against daily opex of $13,000 you’ve got $5,000 of daily rig margin and $33 million of additional EBITDA. Since I’ve already netted out segment and corporate SG&A from the contracted rig earnings along with deducting all the net debt from the EV, this incremental earnings accrues 100% to the equity. A 7.5x multiple means you’ve got an extra $249 million of market cap to spread over 145.6 million shares, or $1.70 per share. Add it to the $15 of value from contracted drilling EBITDA and you’ve got total value of $16.70.
I should note that land rigs generally don’t incur a material amount of costs while they sit in the yard.
Between the contracted earnings and spot market earnings, total segment EBITDA would be $453 million, for a decline of 41% vs. 2014.
Legacy rig Low Case ($0.65/sh): That still doesn’t account for the other 94 legacy rigs (44 mechanical + 50 SCR rigs). Those 44 mechanical rigs alone generated LTM EBITDA of $85 million as of Sep-30-2014, but assume the EBITDA from those rigs goes to zero, along with whatever the SCR rigs were earning, and assume that the 94 rigs only have scrap value of $1 million per rig, for a total of $94 million. This would also fall straight to the equity line and add another $0.65 per share. Add it to the $16.70 and you’ve got $17.35 of value.
Pressure pumping Low Case ($3.85/sh): Don’t forget Patterson has a pressure pumping segment. Sometimes I would like to forget they have it. This is a frustrating business with weak economics for almost all the participants. Barriers to entry are low and pricing power is non-existent. The industry used to be okay (I suppose) 5-10 years ago when Schlumberger (SLB), Baker Hughes (BHI) and Halliburton (HAL) controlled 75% of the market in North America. I suspect it was so concentrated in spite of the low barriers because the market wasn’t growing enough to attract many new entrants. That changed with the rise of shale gas. Demand for pressure pumping took off because horizontal shale wells are so much more frac-intensive than conventional vertical wells for the reasons described earlier. In 2005 there were only 2 million hydraulic horsepower (HHP) of fracking capacity in the U.S. By 2009 there were ~7 million HHP as horizontal gas drilling took off. Capacity additions exploded after the energy industry recovered from the financial crisis, and now there are ~19 million HHP. SLB, BHI and HAL only control ~1/3 of the industry’s capacity at this point. Even when the market was throbbing last year pressure pumpers were barely getting enough price increases to cover the rising costs of their materials (e.g. frac sand and chemicals).
I don’t know what PTEN wants to do with this business in the long run. The CEO and IR have separately told us that the company would be willing to get rid of it when it has enough critical mass to stand on its own. There aren’t any meaningful synergies with the drilling segment. I don’t know what management thinks is the threshold for having sufficient critical mass. If I had to guess last summer I would have said ~1 million HHP. At this point in the cycle I’d probably say it’s a bigger number because the market is weaker. Five years ago the company only had a couple hundred thousand HHP. Now they have 1,029,000 HHP with another 100k on the way (that was ordered before the downturn). However, the executive chairman told us he is intrigued by the potential of this business because the customer’s job tickets are so large. Recall the example of the generic shale well that costs $6 million, with roughly $2 million of the cost coming from the drilling phase and $4 million coming from the completion phase that pressure pumping is involved in. It’s a bigger pool of revenue. The flip side to that as I mentioned earlier is that it’s also a bigger target for customer price reductions when a downturn hits.
Nevertheless, with the drilling segment alone being able to almost support the company’s entire valuation, we don’t have to be very accurate in our appraisal of the pressure pumping segment’s value. We just have to get comfortable that at least it won’t destroy value.
I’m pretty sure the business won’t burn much cash at the bottom of the cycle. The way to model the earnings power of this business is in terms of dollars of EBITDA per HHP of capacity. PTEN’s pressure pumping segment generated $224 EBITDA/HHP at the trough in 2009 and averaged $298/HHP over the five years ending 2013. There aren’t many pure comps. FTS International only did $82 in 2009 and they averaged $338/HHP over those five calendar years. RPC, Inc. generated $118 at the trough and averaged $451. So let’s say PTEN earns $125/HHP in my Low Case. That would mean segment EBITDA of ~$125 million, slightly more than maintenance capex.
Maintenance capex is probably ~$150 million if you assume they need to spend in line with depreciation in order to maintain the equipment. Q4’14 segment depreciation expense was $37.4 million, or $149.7 million annualized.
I’m biased against putting a healthy multiple on pressure pumping earnings even if they are trough earnings. Small cap services peers trade at 4.5 – 5.5x through the cycle. Let’s use the lower end of that range at 4.5x even though these are trough earnings and might reasonably deserve an expanded multiple. That’s $563 million of enterprise value or ~$3.85 per share. Add it to the $17.35 of value from the drilling segment and we’re at $21.20 of total value.
E&P Segment ($0/sh): Patterson also has a small E&P business in West Texas. In Q4’14 it generated $7.7 million of EBITDA, or $31 million annualized. It was earning more than that before oil prices fell. The segment is a collection of properties Cloyce Tabott invested in. He was a founder of Patterson and still sits on the board. The company invested alongside him, but they decided in 2006 it was a non-core business and divested all the operated acreage. They still have to write some checks for non-operated wells that get workovers, but IR tells me that at least so far it has been free cash flow positive. That may change with the decline in oil prices. I assume it will be FCF negative by a few million dollars. The company doesn’t publish enough data (like production volumes or realizations) to do granular analysis on this segment. For example, I don’t know if the $7.7 million of EBITDA in Q4’14 benefitted from hedges that were in place, or if it represents a true mark to market rate of earnings. The business can’t really be sold in an efficient manner because its properties are spread out all over the place. If the MRQ EBITDA of $7.7 million was annualized and you put a 3x multiple on it, it would be worth <$1/share. I’d just as soon assign zero value to the segment and forget about it.
Macro: Let’s talk about the macro picture, which will finish off the discussion about the downside and lead us into a discussion about the upside. WTI spot prices already fell by over 50%. What if oil keeps falling and goes to $30? I don’t see that happening, but if it trades with a 3 handle it won’t be for more than a short while unless there’s an exogenous shock from outside the industry like another Great Recession. We are at the point where large amounts of global supply will go cash negative if prices fall further.
Just to frame the magnitude of the cash cost data shown below, total global liquids demand is >90 million barrels of oil equivalent per day (of which ~80 million is black oil and the rest is natural gas liquids like butane, propane, etc.).
At this point we’re looking at North American E&P capex being down 30-35% in 2015. We’re even looking at a situation where international E&P capex will fall at least 10-15%. To put those declines in perspective, total global upstream capex only fell by 16% in 2009 and that year was an outlier in the long-term trend. Upstream capex has grown at a 13% CAGR since 1999. From 1999-2014 it only fell twice. The other time was in 2002 when it fell 5%.
In spite of all that investment, the world has only added 6-7 million bbl/d of production over the last 10 years, and >4 million bbl/d came from U.S. shale.
A key difference between the current oversupply situation and past oversupply situations is that marginal barrels are coming from shale wells, and their decline rates are much steeper than conventional wells. The current problem can be corrected more quickly by laying down rigs than in the past. Core Labs assumes 70% first year decline rates, 40% second year decline rates, and 20% third year decline rates for shale wells. U.S. shale production has grown by ~1 million bbl/d pear year for the last few years. If you apply the Core Labs decline rates to those three tranches of annual production additions, the market will lose ~1 million bbl/d of shale production in the next year if no new shale wells are drilled.
I mentioned earlier that the peak U.S. land rig count was nearly 1,900 back in September, of which >1,500 were drilling primarily for oil. Current estimates are for a decline of 800 rigs peak to trough. We have lost 517 oil-directed rigs since OPEC had their meeting on Thanksgiving, or roughly 1/3 from the peak. The pace of rig releases has been accelerating. 7% of all U.S. land rigs drilling for oil were laid down last week alone. What is becoming clear is that even if U.S. average daily production in 2015 ends up being higher than 2014, the exit rate will actually be lower. If these activity levels hold into 2016, the declines will accelerate. The market can come back into balance faster than you might think.
Hans Helmerich (H&P’s 3rd generation CEO) told us a couple years ago that a big thing that has changed in his 30 years in the business is operators have become a lot less willing to drill through downturns, and he was right – we are seeing a meaningful and rapid supply response by even the lowest cost producers. Cimarex’s acreage in Culberson County, Texas and EOG’s acreage in the Eagle Ford is some of the lowest cost stuff in the industry and even those two companies are cutting capex by at least 40% in 2015.
I’d like to address a few bearish concerns I have been reading about in the media. The first is the idea that shale producers are going to do to the oil market what they did to the natural gas market. I would agree there is a parallel in the sense that the best acreage will keep getting better as producers and service companies work together to lower costs and increase recoveries. I would also agree that the mindset of E&P management teams is to produce until prices fall so far they are forced to stop drilling, regardless of whether they are producing oil or gas. However, the scale of the oil market means it is much harder to have an impact on the total supply picture.
Again, the global liquids market is ~90 million bbl/d. Shale producers are only contributing ~4 million bbl/d, or 4.5% of global supply after four years of aggressive drilling. In contrast, shale gas went from a standing start to contributing 40-50% of domestic supply in less than 10 years with most of that growth since 2008.
The second bearish concern I want to address is the idea that shale production will keep growing even though the rig count is falling because they will simply high grade. In other words, producers are going to stop messing around with high cost acreage and get serious about focusing on low cost acreage. The implication being that there is enough shale that is economic at $50, and that the high-graded wells are so prolific, that operators can continue growing production with much fewer rigs. I would agree that producers are high grading. No question. It’s also true that the average daily rate of production for these companies in 2015 will be higher than the average daily rate of production in 2014.
But, but, but. It’s the exit rates that matter, and very few producers will exit 2015 at a higher run rate of production than they exited 2014. Even EOG and Cimarex are guiding to potentially lower exit rates. While producers are definitely high grading out of necessity, and a few companies like those two have acreage that works at $50 oil, hardly anybody has an entire portfolio that works at $50, especially after you layer in the costs of centralized facilities, corporate overhead, financing costs, etc. Moreover, the Bakken, which currently accounts for >1 million bbl/d of shale production, has a locational disadvantage that is amplified in the current price environment. It is so far away from benchmark pricing hubs that they have to take substantial discounts on their price realizations. When oil was at $100, taking a $9 haircut on their realizations was manageable. When oil is at $50, taking a $9 haircut is devastating to their economics.
The third bearish concern I want to address is the argument that this will be like the 1980s. I believe that comparison is false for a number of reasons. Oil prices in the first couple years of the 1980s were being artificially held well above the true marginal cost of supply because OPEC pulled almost 10 million bbl/d of low cost supply out of a market that was barely 60 million bbl/d. When the industry entered that downturn it was falling from a much higher and unsustainable starting point. Heading into this downturn there were almost no wells anywhere in the world that were being shut-in, except in Saudi Arabia, which only has ~2 million bbl/d of spare capacity. When I look around at different independent producers I see many that truly needed $90-100 prices to make their economics work and to incentivize them to supply the marginal barrel they were providing. In other words, prices in the 1980s were artificially high. Heading into 2014 they were not artificially high.
Another reason why it’s a false comparison is that back in the 1980s there were significant new sources of low-cost supply from a variety of regions such as the North Sea and Mexico that entered the market at the lower end of the cost curve. The supply that wants to enter the market these days is much higher cost and generally sits at the end of the cost curve.
Even if the entire U.S. shale complex were economic at $50 it wouldn’t necessarily mean prices would need to stay capped at $50. There is plenty of supply the world still needs that requires higher prices. 30-40% of the world’s new source barrels over the coming years will come from deepwater, which needs >$70 pricing in order to work.
Another dynamic I would point out is that the high decline nature of shale means it would be very hard to continue growing at a rate of 1 million bbl/d per year for several more years. We shouldn’t be dismissive of the industry’s ability to innovate and surprise to the upside, but the logistics involved in continuing to grow production at that pace are staggering; it would involve consuming huge quantities of water and sand, substantial demands on rail and truck transportation for materials, lots of people, additional water disposal capabilities, and so on. The scale is similar to that of large armies mobilizing for war.
The mismatch between global oil supply and demand is actually not as great as the 50% decline in prices would lead you to believe. Schlumberger’s CEO has a useful framework for thinking about why oil prices have fallen so much. In the last year global demand has grown by roughly 1 million barrels per day, matching global capacity additions that were also ~1 million barrels per day, mostly from U.S. shale. What tipped the market into imbalance was an increase in marketed supply from OPEC - Saudi has putting the pedal to the metal to pressure high cost producers who have been taking market share - combined with U.S. shale momentum that continued even as prices started dropping.
The coincidental end of QE3 and the rising value of the dollar put further pressure on oil prices at the worst possible moment for the industry. The USD:EUR exchange rate fell all the way from 1.35:1 to 1.15:1 in just six months.
U.S. shale producers kept drilling and completing wells in Q4 even though prices were falling because if they had the capital dollars in the calendar budget they spent it, and because the industry’s near-term hedge protection was generally pretty good. They could afford to keep dumping oil into a declining market because their price realizations had already been locked in at higher prices.
The drilling momentum is slowing dramatically now. The market will eventually balance and prices will go back up to a level that more closely resembles the fully loaded marginal cost of supply. Whether $90 was the true normal or if $70 is the new normal I think an investment in PTEN can be a win-win.
With investments in new production capacity being reduced, there is an outside chance prices will overshoot and go back to >$90. If that case Patterson would go back to having results like they did in 2014 when they generated $1 billion of EBITDA. If prices only go back to $70 it will likely be because their customers have achieved enough production efficiencies to make shale work at those prices, and in that scenario their customers will resume drilling as fast as they can and continue displacing other high cost sources of oil on the supply curve. In a $70 world, shale activity levels won’t initially rebound back to their prior highs because producer cash flows and credit facility borrowing bases are key constraints (producers generally spend all their cash flow plus a little bit more), and they will have been temporarily impaired due to lower commodity prices but they will eventually re-expand.
Pioneer Natural Resources (PXD) is an independent producer with a large acreage position in the Permian Basin, which is PTEN’s main market. They used to have a slide in their investor presentations that ranked the world’s largest oilfields by size. Most of those fields are in the Middle East, but the slide showed that if the Wolfcamp and Spraberry trends in the Permian Basin were considered as a single field it would be the second largest in the world behind Ghawar. A key difference between the two fields is that a lot more wells would have to be drilled in the Permian than in Ghawar to produce the same amount of oil (bullish for PTEN).
Horizontal development of the Permian is several years behind the Eagle Ford in terms of operators cracking the code, but certain operators already have cost structures that can breakeven at the wellhead with $50 oil. For example, Cimarex can generate 74% wellhead IRRs at $50 oil/$3.50 gas on 10,000 foot lateral Wolfcamp D wells in Culberson County. You can be sure threshold breakeven prices will come down further. Don’t forget the Permian is located much closer to benchmark pricing hubs than the Bakken, so it is structurally advantaged vs. one of their major sources of competition with respect to transportation costs.
Consider the implications of that. Saudi Arabia has held the world’s only major source of spare capacity for years. What if we live in a world now where there are two swing producers? The scale of the Permian and the high decline nature of shale wells would make it an ideal swing producer, able to switch production on and off as needed to stabilize the market. The Permian is Patterson’s biggest market. Now, it’s not hard to move rigs and pumping equipment between markets, but it’s somewhat challenging to break into the Permian if you don’t already have a presence there.
High Case valuation ($37 – 41): The type of world I just described would support a very bullish outlook for Patterson. In my High Case I assume the company will complete the 16 Apex newbuilds in the queue to get to at least 161 Apex rigs in total (they could probably grow the fleet even more, but let’s not get carried away), and I assume they fund the $368 million capital expenditure (16 rigs x $23 million per rig) with debt that gets added to their existing net debt. I assume $29,000 dayrates, in line with H&P’s leading edge dayrates in the prior cycle of $30,000 less a $1,000 discount because Patterson isn’t H&P. I assume Patterson’s 94 legacy rigs can get to $15,000 dayrates with 60% utilization.
I assume the company takes delivery of the 100,000 HHP that is currently on order, and that they have taken on $100 million of debt to fund the expenditure ($1,000 per HHP). The pro forma fleet size of 1,129,000 HHP can generate EBITDA of $350/HHP compared with a trailing five-year average of $353. Keep in mind the merger between Baker Hughes and Halliburton should be good for the smaller services companies because operators will want to allocate more of their budgets away from the merged company in order to maintain viable alternatives. My $350 High Case figure might be conservative.
The rest of the key assumptions including drilling segment daily opex, segment and corporate SG&A are held constant at LTM levels. I include a small contribution from the E&P segment. This gets me to consolidated EBITDA of $1.35 billion and $2.85 of EPS, compared with $1.0 billion and $1.61 in 2014.
Put just a 5x multiple on that EBITDA estimate and you get an EV of $6.8 billion. Net out the $1.4 billion of pro forma net debt ($943 million at YE2014 + $368 million newbuild rig capex + $100 million newbuild HHP capex = $1.4 billion) and divide the $5.4 billion equity value over 145.6 million shares out to get $37. A 5.5x multiple would put the stock at $41.
A $37 share price would imply a P/E of 13.0x on the $2.85 of EPS, and a P/B multiple of 2.0x on YE2014 tangible book of $18.33. A $41 share price would imply a P/E of 14.4x and a P/B multiple of 2.2x.
Capital allocation: Patterson is one of the few companies I’ve seen that has brought down their share count through repurchases in a sustained and meaningful way, and they have shown good price discipline in doing so.
At YE2005 the company had 173.8 million fully diluted shares out. Since then they have bought back 37.2 million shares back at an average price of $22, which is about in line with the stock’s average trading price over that time frame. That doesn’t indicate any special prowess in buying back stock, but they have been particularly good since the financial crisis. They returned to the market in a major way in 2012 after taking a few years off to invest heavily in transforming the rig fleet. Since the beginning of 2012 they have repurchased 13.8 million shares at an average price of $17, compared with an average market price of $23 over that time frame.
The last time they bought back a meaningful amount of stock was in Q3’13 when they bought 3 million shares at ~$20. The stock ran up to a high of $38 after that but they didn’t chase it. A cynic might argue they didn’t chase the stock because they had capex obligations associated with growing their business. There’s some truth to that, but they had plenty of liquidity.
They have $187 million remaining under the current authorization (7% of the market cap).
Incentives: I’m not wild about management’s compensation incentives. Annual bonuses are based on a percentage of consolidated EBITDA for the year. The bonus pool was 0.55 – 0.81% of EBITDA in 2013, with the condition that for any bonus to be paid, EBITDA had to be at least $400 million, and they did $942 million. The minimum threshold was raised to $500 million for 2014 and they did $1.0 billion. For perspective, my Low Case has them doing $573 million of EBITDA in 2015. Nobody can earn a bonus bigger than $5 million, and nobody is entitled to a bonus.
The LTIP is slightly better. The general criteria for making equity-based awards are total shareholder return vs. their peer group and ROA/ROE vs. their peer group.
Risks: Implicit in my Low Case is the assumption that 2015 is the trough year. By my math they have 40% of consensus revenue estimates already fixed under contract. That ratio falls to 16% in 2016. In a dire scenario where the downturn continues into 2016 (and possibly beyond) these companies won’t be valued on earnings any more. Valuation will be based on asset values. At the absolute trough in Q1’09, PTEN traded down to 56% of tangible book value. At YE2014 tangible book value per share was $18.33. At 56% of $18.33 the stock would theoretically have a floor of $10.25. I would just remind the reader that the company is much higher quality than it was in Q1’09. Let’s call the downside $12, or 2/3 of tangible book.
BAS, KEG and NBR are lower quality companies than PTEN.
Iran is a risk. Their production peaked at 6 million bbl/d in the 1970s before the Shah was overthrown. They’re only producing ~3.5 million bbl/d these days. What if the sanctions are lifted and Iran’s oil returns to the market in full force? I don’t have an edge on that issue. I would just say that as long as the world needs oil there will probably be turmoil somewhere in the Middle East.
The E&P industry’s growing queue of drilled but uncompleted wells might pose a temporary delay to a full oil price recovery. Many operators have decided to continue drilling as many wells as possible while they still have rigs under term contracts, but they are choosing not to complete the wells until prices are higher. If oil rises to $60-70, it may unleash a wave of new completions. It’s hard to know how it would balance out against other market forces when the time comes but it would just be a temporary phenomenon.
The oil market clears and goes back into balance.
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