The story of the US domestic oil patch over the past 14 years has been squarely focused on unconventionals—Barnett Shale, Fayetteville, Woodford, Haynesville, Bakken, Eagle Ford, Mississippian Lime, Niobrara. As we all know, drilling results from these plays have catapulted the US into the position of being the largest gas producer in the world and the largest oil producer in the world (if we included NGLs).It has been a breathtaking pivot away from finding risk, ie “will I make a well?” to engineering risk, ie “how do I efficiently drill and frac while managing high cost operations?” The results speak for themselves, but have, in great part, ironically depressed the revenue model on which these unconventional plays were built.
This sea change in risk definition has, unsurprisingly, come at the cost of conventional exploration. The graph below (source: Texas RRC) shows how the number of new field discoveries (NFD) has nosedived in tandem with the increased flow of capital into unconventional operations.
Should anyone care? I mean, we have this unconventional wealth – the gift that can keep on giving – that is not yet thoroughly exploited. Joe Q Public can be forgiven that believing that we have what we need.
But Joe Q does not sit in a C-level suite answerable to Wall Street, stock holders, private equity stakeholders, and large workforces. Joe Q does not have to show improving business results, but everyone in the oil patch does.
So let’s get this on the table — conventional exploration needs to be a larger part of company exploration portfolios.
They’re less costly — in obvious, and not so obvious ways
- A 10,000’ vertical well to test a conventional trap will cost a whole lot less than an unconventional 16,000’ MD well with 10-40 frac stages
- Acreage costs are lower—fewer acres are needed to lock down a conventional prospect
- Risk capital in conventional exploration is exposed with brutal clarity. Drill high and dry on a conventional trap, you’ve condemned it and you walk away with no additional speculative economic exposure. If you make a discovery, log signatures defining oil column and contacts, pressure tests and supporting 3D provide good visibility in how many wells you need to drill and where to drill next.
Take 50,000 acres in an unconventional play and each well you drill in early development is an experiment that slowly, over time increases your knowledge store, but delays your visibility into how good – or mediocre – your operations are. The graph below of the EUR values of an Eagle Ford operator attempts to illustrate the point.
They provide more clarity about reserve base and therefore valuations
Initial test wells provide open hole logging data that help define the porosity and permeability of the reservoir. Seismic data and subsurface well mapping do a good job of defining the extent and thickness of the reservoir, and therefore the volume of oil in place. Confirmation wells will either moderately increase or moderately decrease prospect EURs, but EUR values converge to a realistic estimate reasonably quickly. This means operators can book their prospect NAV more quickly, have quicker clarity with regard to potential cash flow, and therefore better strategic planning inputs.
I would rather be making decisions about my strategic directions on this behavior (first three wells drilled in Covenant Field, UT)
than on this behavior (recognized operator in Eagle Ford wells completed 1/1/2012-12/31/2012).
How do you quickly converge on a producing model that you can attach valuations to? Overestimate and the shorts will kill you in the public markets, underestimate and The Street will be slow to reward your shareholders.
Good conventional fields have longer producing lives which help offset depletion timing risk – depleting your reserve base during times of low prices.
Conventionals can provide a much higher rate of return
Some napkin numbers are illustrative. Again, looking at a major player in the Eagle Ford and totaling up the number of wells drilled, assumed spacing per well to estimate acreage costs, and a cost to drill and complete of $7 MM/well, I estimated that this operator had exposed nearly $12.4 B in the Eagle Ford.
Using DI Desktop median EURs, a generous $70/bbl average price/bbl, and uniform 75% NRI, I estimate that this $12.4 B would generate nearly $18 B in revenues over project life.
Now let’s compare what it would cost to define , acquire, and drill 50 conventional prospects.
Assume: 4,000 acres/prospect @$500/ac, 13,000‘ average TD @ $2.5 MM/well, 80% of prospects are dry holes or not commercial. So our risk exposure is
Acreage + Seismic + 50 test wells=100,000,000+ 10,000,000 + 125,000,000=$235,000,000
Remember, 80% are dry holes so we’re left with 10 commercially viable prospects that could have about 24 development wells per 4000 acre prospect. Assuming all those wells are drilled, the development cost (to target primary pay) is $60,000,000/prospect, or a total of $835,000,000 to drill, discover, and develop the 10 viable prospects in the inventory of 50 prospects. So what reserves might we find?
DI Desktop EUR estimates for:
- Wolverine’s Covenant field in the Utah hinge line : 94,000,000Bbl
- Constitution/Constitution South Yegua production in Jefferson Co. TX: 26,654,000 Bbl/401 BCF
Here are the napkin numbers on revenues (assume$60/bbl,$2.25/MCF,75* NRI, 5%severance)
So even if the kinds of results shown above represented 95% of the discovered reserve base, our exploration portfolio expenditure on conventionals yielded about 1/3 of the reserve base of an unconventional portfolio, for about 1/16th the cost. And even if unconventional EUR’s are artificially depressed due to choked back production, and/or shut in status, the cost/benefit for conventionals is still compelling.
It’s a great thing to be able to say – with confidence – that the wells you drill will find oil and gas. It’s one of the powerful drivers in the unconventional space, and as mentioned avoids the perceived risks of traditional exploration.
As we’ve seen, however, great advances in engineering and seismic acquisition/processing capabilities have propelled the unconventional model forward. And I would argue that these advances in seismic processing and attribute extraction greatly minimize dry hole risks going forward.
The two maps below show wildcat permits (left image) and wildcat permits which were completed as producers (from1/1/2010-7/17/2015)
Source: DI Desktop
The left hand map below shows Texas wells which made (on an allocated basis) 500,000+ BOPW. Median EUR of 774,000 BO implies that there is a good reserve base to explore and develop. The right hand map shows partial seismic coverage of just Texas. Given the constantly improving production and well log database in the US there’s ample reason to believe that targeted conventional exploration can provide excellent rates of return.
A Way Forward
An astounding amount of acreage has been put under lease to support unconventional drilling, a large number of wells have been drilled that have added to the knowledge base about uphole reservoirs, and unknown petabytes of seismic data have been acquired to support analysis of below pay objectives. Operators with large positions should seriously entertain the option of checker-boarding their acreage to stimulate conventional farm in activity and or actively begin to develop their conventional portfolio because it will probably deliver better margins.
What do you think? Leave a comment below.
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