On Tuesday 24 September 2013, Goldman Sachs published upbeat comments about drilling activity in the Bakken. Amongst other things, they said:
"We came away from our trip to North Dakota last week with greater confidence in our outlook that Bakken production/completion activity will likely exceed Street expectations....during our trip producers were uniformly confident in resource expansion, efficiency gains and potential for improving well performance in the coming years.... production can continue to grow substantially."
Whilst GS's remarks, and their mention of some specific stocks, were received positively by the Street, the firm was only confirming what many followers of the shale oil drillers have known for some time - that the best oil shale drillers are set to enjoy many years of strong and increasingly profitable growth.
Indeed, Goldman's comments are not optimistic. Industry insiders would argue that Goldman Sachs and many other analysts don't typically highlight the real strength of the multi-year growth model that's driving the business. True, it is becoming generally known that efficiency and savings from pad-drilling, upgrades to completion techniques and improvements in down-spacing are all combining to propel growth over the coming years. Many analysts are now incorporating these factors into their assumptions and estimates. However, what the analyst community has yet to bring into the public domain is the fact that, on top of these various positives, there is a new game-changing fracking methodology in town. This will be looked at later.
Internal Rate of Return (IRR)
Companies with the best core acreage produce the highest rates of return whilst companies with marginal acreage may struggle to compete. For example, Continental Resources (NYSE:CLR), Kodiak Oil & Gas (NYSE:KOG), Oasis Petroleum (NYSE:OAS) and Whiting Petroleum (NYSE:WLL) all own sizable tranches of core acreage in the Bakken and achieve excellent Internal Rates of Returns. Their mid-point well models have IRRs ranging mostly from the low 40% to 70% and, in some cases, way over 100%. Contrast this with marginal producers generating IRRs of 30% or less. Investors will readily understand that the multi-year compounding effect of 50%+ IRRs is vastly superior to that of 30%.
To better understand the long-term effect of a 50% IRR, it is worth reviewing a sample from Kodiak.
Using an $85 WTI price, less $7 differential (the net effective Boe price then being $78), Lease Operating Expense (LOE) $7, Production Tax $9 and Gathering & Transport cost of $3, this produces a 56% IRR with a pay-back of 15 months according to Kodiak's sample. Backing out Selling & General (SGA) costs of $4 gives an EBITDA of $55 per barrel or about 71% of sales. This 71% EBITDA/Sales figure stacks up nicely, if conservatively, against Kodiak's Q2 2013 earnings report which showed that the company generated EBITDA of $131 million on $173 million sales i.e. EBITDA/Sales of 76%. Accordingly, it seems fair to say that Kodiak is delivering results that support the 56% IRR model.
Investors can verify the IRR and NPV numbers by running a spreadsheet for themselves. Production numbers displayed are gross - a 20% royalty has to be deducted. Net annual production from Kodiak's 750Mbo well is approximately 151Mbo in Yr #1, 57Mbo in Yr #2, 42Mbo in Yr #3, 35Mbo in Yr #4, 30Mbo in Yr #5, 27Mbo in Yr #6, 24Mbo in Yr #7, 21Mbo in Yr #8, 19Mbo in Yr #9, 17Mbo in Yr #10 and so on.
The Kodiak 750Mbo model is not an exact average for Bakken players such as Continental, Kodiak, Oasis and Whiting, but it is a useful proxy. Further examination of these four companies reveals that on average they have an 82% Oil / 18% Nat Gas product mix, they achieve average effective oil pricing of about $80-$81 per barrel, they generate EBITDA of ~70% of Sales and collectively report IRRs of ~50%.
A major point of importance for investors is that the acreage of Continental, Kodiak, Oasis and Whiting is predominantly core Bakken acreage and, therefore, these companies should repeatedly deliver IRRs of ~50% at current oil pricing. With project payouts of about 1.5 years, this is an excellent growth platform. Their growth models are further boosted by leverage - typically these Bakken players maintain borrowing levels that are 100% or more of total equity. In essence for every $10 million project payback $20 million can be reinvested in new projects within a short time frame. The multiplier effect from this leverage over just a few short years is powerful. Overall, these shale oil operators are operating with a very heady growth mixture.
But what of the oil price?
There are two elephants in the shale oil room - the future price of oil and potential drilling locations.
As for the price of oil, hedging is one solution. With oil futures now being in backwardation, the fully hedged oil price will be lower than current spot prices and, in practice, a driller typically wouldn't hedge a large chunk of future production beyond 2 years. Nonetheless, for the purposes of demonstrating how a driller can fully protect itself and still provide investors with excellent returns, I will outline what a 10-year fully hedged picture would look like.
Keeping in mind the typical 82% oil / 18% nat gas product mix by core Bakken players, the effective average spot price currently being achieved by them is about $80-$81 Boe after deducting differentials. On a fully hedged basis, and allowing for a strong ramp in production that gives a heavier weighting to the out years when the forward price is lower (refer to futures pricing here), the fully hedged effective price, net of differentials, is about $66 Boe. This is a sizable drop from the current $80-$81 level. It would lead to operating costs rising, expressed in barrel terms, and overall EBITDA falling. Assuming a $1/Bbl increase in both LOE and SGA, but maintaining a flat $5 differential, the IRR drops from ~50% to 30% and the EBITDA/Sales drops from over 70% to ~60%. It is immediately evident that producers who today have IRRs below 30%, and/or who already achieve a low Boe oil price, are likely to struggle in a lower oil price environment. However, producers who have ~50% IRRs should still deliver good multi-year growth even with $66 oil.
Under a $66 oil model, starting with 1 well in year #1, the total number of producing wells rises to about 30 wells in year #10 which would produce sales of $116 million and EBITDA of $72 million. This is truly impressive from a 1-well starting point and a lowly $66 oil price. The multi-year growth prospects that would occur with firmer oil prices - like for example today's high oil spot prices (effectively $80-$81) - are a great deal higher. Perhaps, it's best to treat this as icing on the cake if/when it occurs.
|Multi-Year Model||Yr 1||Yr 4||Yr 7||Yr 10|
|Using $66 Oil|
|Production Mbo / well||151||35||24||17|
|Total production Mbo||151||534||913||1,750|
|Equity incl NI @ 25%||22,491||44,787||83,117||154,784|
In building this model these additional assumptions were used.
- The starting point was $20 million capital in the form of one $10 million well drilled in year #0 and acreage for 10 wells @ $10k per acre using 100 acre spacing.
- No reductions in well costs, no production or operating efficiency improvement are assumed over the 10-year period.
- A well drilled in one year is only assumed to start production the following year.
- Borrowings are maintained at around 100% of Equity with funding costs included.
- Drilling inventory is kept at about 10-year equivalent throughout, including at the starting point.
Collectively, these assumptions are reasonably conservative in order to allow for other items such as infrastructure capex etc. One exception is the 100 acre well spacing. This is too aggressive by today's standards. However, given the down-spacing work being carried out in the Bakken, I suspect that 100-acre spacing may turn out to be reasonable in a few years time.
Conversely, there may be two overly conservative assumptions. First, Bakken drillers today have much more than 10-years of drilling inventory. As such, for the next couple of years, they can arguably pour 100% of cash generated into drilling and associated capex whereas, in the model, capital is constantly being peeled off to maintain drilling inventories at the 10-year level. Second, the model assumes new wells don't come online until a full year after they are drilled. In reality, wells come online after a few months and this earlier timeframe significantly boosts cash flows and the payback cycle. Both of these overly conservative assumptions relate to cash flow and, over time, the effect is compounded.
As for the oil price, I believe we will see oil prices move lower in the coming years. However, periodic flare-ups by producing countries will cause price spikes that will enable forward hedging to be done at prices that are better than the $66 mentioned here. Also, any signs of a real slowdown in tight oil production growth in the coming years will likely lead to a firmer oil price. Additionally, any significant downward price moves in the market should be short-lived because of the sharp decline curve of tight oil, especially in the early years, and thus a slowdown or pause in bringing new wells online automatically leads to a sizable production cut-back which should support higher prices.
Will operators soon run out of drilling locations?
The second elephant in the room is fear of running out of drilling spaces. The Multi-year model has embedded growth from 1 well at the outset to 30 producing wells 10 years later. That's a huge drilling increase, and that's with a modest $66 oil price assumption. The message is clear - shale drillers wishing to grow strongly over the next several years must have or must obtain a very robust drilling inventory.
The Williston Basin is buzzing with down-spacing activity and work exploring lower oil-bearing intervals. One of the best articles on this topic "Bakken - The Downspacing Bounty And Birth Of 'Array Fracking'" was penned by Richard Zeits on Seeking Alpha in May 2013. I highly recommend reading it.
For those less familiar with shale drilling, I would point out that each drilling unit of 1,280 acres is 1 mile wide by 2 miles long. Tags such as "320-acre" and "160-acre" apply to each separate drilling interval. For example, Continental is drilling a test project of 160-acres in 4 separate intervals: one x Bakken and three x Three Forks. In total, that means the 160-acre pilot has 32 wells in the 1,280 spacing unit, effectively 1 well per 40 acres. Communication (cannibalization) between wells is certainly an issue to be monitored whether it occurs through natural rock fissures, which can extend for long distances, or through induced fracs. Communication is more likely to occur when wells are drilled closely together such as in the Continental 160-acre pilot. When meaningful, it leads to lower IRRs and longer paybacks. There is a trade-off between lower IRRs / longer paybacks and maximizing overall profitability from the oil play by extracting the maximum amount of oil in situ. Comments from Continental over the next few quarters on these 320-acre and 160-acre pilots will be highly instructive both for Continental themselves and for all drillers in the Williston. Generally, positive indications are coming out of the Williston Basin with regard to the ongoing down-spacing and lower interval tests. The Goldman Sachs comments at the beginning of this article offer further validation.
Continental has 1.2 million acres in the Williston Basin and has begun presenting its inventory in terms of 320-acre spacing and 160-acre spacing. As with all shale operators, not all of Continental's acreage is prospective for each zone. Using 80-acre spacing, Continental estimates that it has almost 8,000 undrilled wells (effectively 1 well per 150 acres) and using 40-acre spacing it would have over 15,000 potential inventory (effectively 1 well per 75 acres). By end 2013, Continental will drill approximately 250 wells in the Williston Basin. Using the 8,000 inventory figure, Continental potentially has over 30 years drilling inventory, or 60 years using the 15,000 number.
Kodiak is planning to drill 100 net wells in 2013 and says it has 15 years drilling inventory, implying a total inventory figure of 1,500. Kodiak has 196,000 net acres in the Williston Basin and 1,500 drilling locations is equivalent to one well per 131 acres. Kodiak has some ongoing down-spacing pilots drilling 6 wells in the Middle Bakken and 6 wells in the Three Forks, this being 12 wells per 1,280 spacing unit or 107 acres per well. Considering that not all of Kodiak's acreage will be prospective for all intervals, it would appear that Kodiak has already incorporated its pilot test findings into its current well inventory calculations. Looking on the bright side and using Continental's best case scenario of 1 well equivalent per 75 acres, this would equate to 26 years inventory for Kodiak. This is okay, but not a great best case scenario, meaning that Kodiak may need to acquire more acreage before very long.
Oasis, following its September acquisition, has about 2,150 net drilling inventory which is 16 years equivalent. Oasis has 492,000 net acres and its drilling inventory equates to 1 well per 230 acres which appears conservative in comparison with Continental or Kodiak. There is a good deal of down-spacing and lower interval work being done by drillers offsetting Oasis' land and Oasis too are undertaking several test pilots.
Because Oasis has used a conservative inventory count, a solid increase of these numbers is on the cards. Using Continental's best case scenario of 1 well equivalent per 75 acres, and acknowledging that not all acreage is fungible, Oasis would have about 6,600 drilling locations, equivalent to 50 years inventory. Using Continental's less optimistic 150-acre denominator, Oasis would have 25 years drilling inventory.
Whiting has 714,541 net acres in the Williston Basin, including its recent acquisition. It has 1,912 net Williston drilling locations, equivalent to 11.5 years inventory using its 2013 drilling rate of 167 net wells. These figures appear to be very cautious, being just 1 well per 373 acres. Notwithstanding that acreage varies from location to location, these inventory numbers should be expected to undergo significant upward revisions during the next couple of years. For example, using Continental's lesser optimistic scenario of 150 acres per well would provide Whiting with about 30 years inventory.
A Game Changer
In March 2013, Michael Filloon published an article on Seeking Alpha titled "EOG Resources' Completion Technology is a Game Changer".
"... EOG has figured out how to better stimulate the source rock closer to the well bore. Most operators have tried to improve fractures further away. This poses a problem for proppant to travel greater distances. With more fracture surface area close by, the sand can be packed in deep providing a less restrictive zone for crude to flow. This would provide the reason for the very large amounts of sand. If this is true, even average acreage could see payback times in less than a year. If EOG can produce these results, so can other operators. This completion technology is now a proven technique. It has worked for EOG in three of the best unconventional basins in the United States. I estimate it will increase EOG production growth in the Bakken for 2013 by 50%. Companies like Kodiak Oil and Gas or Oasis could see production growth of 30% to 70% if and when they adopt this technique. This technology could change the economics of unconventional oil."
These words were prescient. Other operators are indeed beginning to develop new techniques similar to EOG's (NYSE:EOG). Whiting Petroleum, an early adopter, explained the new fracking technology at a conference on October 3, 2013 and the presentation - JP Morgan Technical Presentation - is available on their web site.
Striking aspects of the new technique, called "Cement Liner," potentially include tighter and more numerous stages and more fracs per stage, all of which combine to produce a dramatic increase in entry points i.e. 120 versus 30. My understanding, and I'd invite engineers/geologists to weigh in here, is that, because this new technique places more emphasis on improving fractures close to the bore hole with less emphasis on improving fractures further away from the bore hole, that, in addition to boosting oil production, this should allow wells to be drilled closer together with less risk of incurring significant communication.
The Whiting presentation of October 3 indicates that the cost of the new Cement Liner wells is the same as older wells. The early results from Whiting are extremely positive with 30-day production registering as much as a 100% improvement. Given the unchanged cost basis, this could potentially lead to a very big increase in IRRs.
It remains to be seen over the next reporting quarters exactly how well the new techniques compare to the existing methodologies. The indications from EOG Resources and from analysts' recent comments on the Bakken players suggest continued optimism about this latest fracking technique.
For example, on October 4, 2013 SunTrust increased its target price for Whiting from $69 to $92 saying "the company's new completion design will cause its productivity to rise significantly, whilst its inventory is deeper than previously thought". The firm identified Whiting as its Top Pick.
As a possible taster of things to come, here is a well curve from Whiting's Sanish Bakken interval taken from their October Presentation. These IRR and Payout numbers are truly amazing, even using WTI at $80. Whiting's other areas have very good data too but not quite at these nosebleed levels.
The question was asked earlier - will operators run out of drilling locations soon? The answer is heading for a very definitive no. It cannot be stated with certainty today exactly how many drilling locations each company will have in the coming years. However, on the back of ongoing work on down-spacing and lower oil bearing intervals, plus the fracking technique game-changer, the overall upside to drilling inventories and production efficiency is potentially enormous.
Daily oil production from the Bakken is expected to hit 1 million B/day around the end of 2013 or early 2014. Goldman Sachs is predicting that Bakken daily production will continue rising until it hits 2 million B/d in about 2022/2023 and then begin a long decline.
The history of "estimates of recoverable oil in the Bakken" is awash with continued upward revisions. In April 2008 the USGS estimated there were 3.65 billion barrels recoverable. In April 2013 they revised it up to 7.4 billion barrels. In October 2010 Continental Resources estimated there were 24 billion barrels recoverable. In November 2012 Continental then estimated there were 903 billion barrels total oil in place, including lower benches, and that a 5% recovery factor would amount to 45 billion barrels. A 5% recovery factor may be comfortable especially considering recent advances. As with the estimates of recoverable oil, I suspect the Goldman Sachs production estimate will experience upward revisions.
Whilst every cloud may have a silver lining, silver linings may also presage rain. Just as EOG/Whiting's "Cement Liner" fracking methods should boost production, a meaningful increase in overall US tight oil production should, after new techniques are widely adopted, cause downward pressure on oil prices. The Multi-Year Model using $66 oil suggests that continued profitability and growth is likely to remain in place for companies with high IRRs and short paybacks. I would not be optimistic for marginal players. Similarly, I would argue that whilst total Bakken daily production may only double or triple over the Goldman Sachs forecast period, companies with high IRRs are set to experience much stronger growth whilst some bread and butter drillers will come in well below the average.
Inherent within that Multi-Year Model was that the number of producing wells grew by a factor of 30 times over the 10-year period and production in year #10 was 10 times greater than in year #1. This is a big ask for any company. Rather than going all-in with grandma's savings, a more reasonable assumption for investors to adopt would be the premise that leading shale players are positioned to enjoy excellent growth for the next few years.
Best Bakken stock to buy, and when?
|Market Cap $mil||22,270||3,590||5,310||7,950|
|Economic Value $mil||26,470||5,440||7,510||11,850|
|Recent Production '000||140||36||43||100|
|EV / Production $000||189||151||175||119|
|Proved Reserves MMBoe||922||144||216||345|
|EV / Proved Reserves $||29||38||35||34|
|EBITDA 2013 estimate $000||3,300||650||1,000||2,000|
|Net Acres, 000||1,200||196||492||715|
|Wells drilled 2013||250||100||134||167|
|Yrs Drilling @ 1well/150 acres||32||13||24||29|
|2014 Analysts EPS $||7.23||1.00||3.91||4.36|
|2014 P/e ratio||16.7||13.6||14.5||15.4|
Whiting already has some of the best valuation metrics on the above table and weighing everything together, the stock appears to offer the best long-term growth prospects of this group.
All of these companies should experience annual growth of 30%-40% and, in some cases, possibly a lot more. Continental, Oasis and Whiting have strong inventories of drilling locations enabling them to pour all available liquidity into growth without needing to acquire more acreage.
In May 2013, the Williston Basin experienced severe flooding resulting from late spring melting snows. This caused general disruption and well completion delays during Q2 2013 and the adverse impact showed up painfully in Q2 earnings releases. Recent reports from North Dakota Department of Mineral Resources (DMR-ND) and from drillers such as Northern Oil and Gas (NYSEMKT:NOG) confirmed that strong sequential production growth returned to the Bakken during Q3. Northern announced on October 17 that it registered sequential Q2-Q3 growth of 19%. With this in mind, it would appear that Whiting's Sales and EPS estimates for Q3 may be a little low - they are largely flat with Q2. The Whiting estimates appear to include a low-ball figure from an analyst that's skewing the consensus numbers lower and this effect has carried into 2014. Considering the breakthroughs underway at Whiting, I would expect that the 2014 earnings estimates (and then preliminary 2015!) will be revised upwards, perhaps following the Q3'13 earnings release on October 23.
Currently, the S&P 500 Index (click on Additional Info, then Index Earnings), at 1,744, is on a 2014 p/e of 14.4 (full-year 2014 operating earnings estimate $121.46). On a full-year 2013 to 2014 period, the implied earnings growth of the S&P 500 is 13%. The above listed shale drillers are, on average, valued in line with the S&P 500 Index and offer immeasurably better earnings growth prospects. And that is why every investor should own some shale oil stocks; far superior growth, market valuations.
When to buy? Despite the recent stock price runs, there is still a lot of value and upside potential in these shale drillers. This is still a good time to buy, especially since earnings estimates are set to increase in the weeks and months ahead. I would advocate buying on pull backs. As already mentioned, the Williston Basin is prone to inclement weather; severe winter snows and late spring floods. If there are heavy winter snows look for flooding the following April/May, and buy the ensuing pull back.
Investing in the core Bakken is a repeatable process that yields strong growth and highly attractive returns, even when 100% hedged for 10 years with an effective oil price of $66. This point will become better understood as time passes. Repeatability of high returns is a key driver behind consolidation. Kodiak is a company that has often been mentioned as a possible acquisition target. One thing in its favor is that it is understood to be willing to sell itself if a buyer will offer an attractive price.
"First mover advantage" is a huge issue in fast-growing businesses. EOG and Whiting both have game-changing fracking technology. With that advantage, they can extract a lot more value from the ground than other competitors. Adjoining acreage is therefore worth more to EOG and Whiting than to others. In late August, Whiting acquired 17,282 net adjoining acres plus some production for $260 million. James Volker, Whiting Chairman & CEO commented
"This acreage expands our presence in our Western Williston Basin area where we have seen recent strong production growth primarily as a result of positive drilling results at our Hidden Bench, Tarpon and Missouri Breaks prospects."
These remarks are telling. It says that direct neighbors to EOG and/or Whiting can expect a phone call.
What's the betting there is an investment banker somewhere dreaming of putting together a merger between Whiting and Oasis? They are direct neighbors in much of their Bakken acreage. Together the combined company would have 1.2 billion acres in the Bakken as well as Whiting's valuable assets in the Permian and the Niobrara. The economic value of a merged Whiting and Oasis would be about $18 billion. Continental, in terms of total production and asset footprint, is almost identical and carries an EV of almost $26 billion i.e. over 40% higher than Whiting and Oasis combined. Plenty of scope there to give a generous $200 million in stock as a sweetener to both management groups and still release billions of dollars of value for shareholders. A possible stick in the mud is that Oasis recently swallowed a large acquisition and would need time to digest it.
That said, investors should never buy stocks in the hope of landing a fat acquisition premium. Instead, they should buy value which is available in abundance in Whiting's and Oasis's stocks.
In June 2013, Leonardo Maugeri of the Harvard Kennedy School, Belfer Center, published an outstanding report on the US and global shale industry - The Shale Boom: A US Phenomenon. This is essential reading:
Disclosure: I am long OAS, WLL. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.