It’s feeling like “Casablanca” all over again. Remember when Inspector Louis Renault says “Round up the usual suspects?”
Or are we more in line with Groundhog Day when Bill Murray repeats the same events over and over again?
Those of us who’ve been at this oil patch thing for a while certainly remember the heady days of the early 80’s when prices jumped to $30/barrel, buoyed by sophisticated punditry that often looked ahead to $100/barrel.
I remember sitting horizontal wells around Dilley, Tx in the early 90’s when bumper stickers were getting printed that said “God please send us another oil boom. I promise not to piss this one way away—-again.”
And God love us, optimistic bunch that we are, we all charged happily forward as the unconventional paradigm unfolded, noting the pivot from geological risk to engineering risk…but not really holding any hole cards against price risk.
Well, here we are. And maybe this time is different.
What’s different this time?
Prices tanked in the past because of demand weakness. This time around we have not only demand weakness but a marginal glut of supply.
And this weakness comes at a time when a ton of money has been invested in both acreage and drilling in the pursuit of “guaranteed” returns from unconventional plays.
Previous hard times on the oil price front took anywhere from nearly 30 years (late 1985 drop) to 2.5 years (2008-09 crash) to work back to pre-crash levels (using inflation adjusted 2014 dollars to normalize prices).
And the “recovery” post-1985 was temporary; the reality is that prices stayed depressed for nearly 16 years before beginning the steady climb that was halted by the 2008-09 financial debacle.
The present feels like uncharted territory. And, to paraphrase Charles Lyell’s dictum about Uniformitarianism, ”the present may NOT be the key to the past.”
One thing that hasn’t changed is the role of timing in developing—or destroying—oil patch fortunes.
Consider that, using type curves for the Bakken and Eagle Ford from DI Analytics, an Eagle Ford well will have produced 50% of its total recoverable volume in 14 months and a Bakken well will have reached 50% depletion after 29 months.
Which is fine, if the price environment in which that depletion occurs is consistently within your modeled price decks. But if a meaningful portion of your drilling portfolio is dedicated to drilling operations with these kinds of declines, and first production is occurring in a time of suppressed prices that historically seem to take, at minimum, a couple of years to reset, then the best image for your ROI is
Ponder this- depleting 50% of your producing Eagle Ford wells during $50 oil will cost you nearly $4,700,000/well. Or $7,400,000 if you’re producing the Bakken.
So maybe now is the time to start seriously thinking about how to hedge against depletion timing risk (DTR).
And what comes to mind is a fresh re-think on the value of conventional exploration. Perhaps modern exploration portfolios should have a greater percentage of assets dedicated to plays that deplete more slowly.
For example this lease in Gaines County, TX has enough longevity and recoverable reserves to return great cash flow no matter how long the price recovery cycle is.
In comparison, median EUR for Eagle Ford wells as calculated in DI Desktop is about 250,000 BO. Type curve predictions are more modest, with a predicted recovery of about 186,000 BO and an approximate 17 year life before depleting to stripper well status.
So, conventionals can be a great natural hedge, right? But maybe it’s not quite that easy.
Unconventional plays were/are a paradigm shift: they pivoted risk away from geology (highly variable; locked set of outcomes) to engineering (far more controllable w/sufficient cash, technology, talent, but developmentally nuanced). We replaced “will I find hydrocarbons” risk with “can I efficiently produce known hydrocarbons” risk. On the surface, unconventionals seemed to have reduced finding risk by a substantial amount. But perhaps that finding risk has been replaced by pricing risk.
The graphs below show the percentage of wells (first production from 1/1/2012) that broke even under different drilling cost assumptions at $100 and $50 oil , with beginning well costs for conventionals starting at $1MM and unconventionals starting at $6MM.
At high wellhead prices, unconventional projects are more likely than conventional projects to perform at breakeven cash flow or better.
But at times of lowered prices ($50/barrel in the scenario above), the differential in breakeven probabilities between unconventionals and conventionals narrows—a lot!
We can certainly see in DI Analytics that some operators are opting for less aggressive early flow profiles, thereby lessening their production declines and thus besting a lot of their competition in terms of EUR values.
So…is the industry ready to take on higher front end finding risk (conventionals) to hedge against depletion timing risk?FreePort McMoran is probably quite satisfied that it stayed the course during the drilling of its conventional 30,000’ Jeanerette Minerals #1 in Ascension Parish, LA. It took over 2 years to drill but finally reached TD and was flowing to sales as of 2/9/2015 from the Lower Tuscaloosa. Reported flow was 43,000 MCFD, 11,955# FTP (no liquids reported); the well is the first step in confirming nearly 1.4 TCF of reserves.
Reserves by the way, with a LONG projected producing life.
And no doubt Samson has been happy with its conventional production in the Constitution Field complex.
Samson’s Paggi-Broussard #1 produced nearly 2,500,000 BO and 59.6 BCF from the Yegua over 10 years—outperforming (on an allocated cumulative production basis) every single Eagle Ford well. It produced volumes equal to the Eagle Ford type curve cumulative volumes in 7-8 months!
One interesting thing to note is that although failure rates for conventional projects are higher than for unconventional projects, the capital bleeding on a conventional failure stops pretty quickly. You stake a wildcat, drill, run high on seismic and well control but find no reservoir rock, you’re pretty much done. The conventional trap model tells you that your chances of rescuing your drilling capital is slim to none, you refrain from setting pipe, and you move on.
You are NOT facing an undrilled prospect position of 20,000-100,000+ acres that will require–at 160 acre spacing–125-625 wells costing in the $6 MM-$12 MM range/well (all of which are still, even in late stage development, mini-experiments) and which will probably require, at a minimum, 20 wells for you to BEGIN to understand the actual value of what you’ve drilled.
One bridge to more conventional-friendly drilling portfolio opportunities would be if acreage-rich companies encouraged farm-ins. This would open large tracts of prospective acreage to a large cohort of independents, HBP a lot of at-risk acreage nearing expiration of primary lease terms, and perhaps identify new conventional exploration fairways.
What do you think? Leave a comment below.
Latest posts by Mark Nibbelink (see all)
- The Texas Cold Snap — Where Do We Go from Here? - February 26, 2021
- A Modest Proposal for Small Operators - January 13, 2021
- State of the Energy Industry Amid COVID-19, Aging Workforce, Electrification - October 6, 2020