[Pops]

Drilling Deeper: A Reality Check On U.S. Government Forecasts For a Lasting Tight Oil & Shale Gas Boom
by David Hughes, Post Carbon Institute

Over the short term, U.S. production of both shale gas and tight oil is projected to be robust-but a thorough review of production data from the major plays indicates that this will not be sustainable in the long term. These findings have clear implications for medium and long term supply, and hence current domestic and foreign policy discussions, which generally assume decades of U.S. oil and gas abundance.

http://www.postcarbon.org/publications/drillingdeeper/

[Paulo1]

I just wish that statement came from Bloomberg or Forbes. When it does we will know the jig is admittedly up. Post Carbon is our choir.

Paulo

[ROCKMAN]

Short term vs long term. Of course there would be a disconnect. Short term only requires companies to develop areas identified as potentially commercial which are the leases they've taken. The short cut there is to just take the results of recent drilling activity and project it forward...but not too far forward. Long term requires posting future locations on a map where the geology and reserve value are relatively unknown...perhaps even being zero. And that's a very difficult task for the actual shale players to do. And virtually impossible for folks who don't drill wells for a living.

Which is why you'll see some folks post X millions of bbls of long term reserves but will never see them put a circle on a map showing where those wells will be drilled. And that's because they don't know where those wells will be drilled...they just assume they will.

[coffeeguyzz]

Wow! Just wow. I downloaded the report and started to quickly scan the executive summary. If this is the type of info you guys rely upon to form your collective viewpoint, it is no wonder you will still be seeking the Red Queen long after Diogenes has found his one honest man.
Does omitting - right off the bat - the Utica play, a formation that is shaping up to be more prolific than the Mighty Marcellus, referencing a phantom EIA report downsizing the Monterey, referring to the Permian and Niobrara as having a 40 to 60 year drilling history when the relevant horizontal development barely started 2 to 3 years ago call into question this man's analytical skills if not his outright competency?
Don't have the time this moment, but I WILL double check his predictions of two years ago for the Bak and EF as I am certain they were WAY off not long after he made them ... and yet Mr. Hughes starts off this report denigrating the EIA's predictive record. Sheesh.

[shallow sand]

The thing I wonder about re Bakken and EF is that close to 90% of Bakken oil is in 4 ND counties and EF oil window is also of limited area. Question how those grow production for years. However, also note other areas are just starting to ramp up. Do think will need oil price higher than present to get those going as they seem to be more expensive/less prolific.

Still a lot of unknowns out there.

[coffeeguyzz]

Regarding the four main producing North Dakota counties, Mountrail, Dunn, McKenzie and Williams, they are - at over 9,000 combined square miles - larger than the state of New Jersey. In addition, there is a fair amount of successful drilling of both the Bakken and Three Forks formations right across the border in Canada. (The TF is called the Torquay in Canada).
A quick glance at the North Dakota oil/gas website (dmr.nd.gov/oilgas) enables one to actually see every well drilled in the state going back to the fifties by clicking on the Gis button - left side on main page.
By zooming in on the most prolific fields, such as the Parshall, it should be immediately obvious how this quintessential sweet spot is yet to be developed. Every one of the 'paired rectangles' equals one Drilling Spacing Unit (DSU) of 1,280 sq. acres - 2 sq. miles. Each DSU will eventually have 8/12/16 or more wells in the coming years.

[MD]

I have been listening to ads on Sirius/XM selling oil wells to "qualified investors". The US fossil fuel industry is booming indeed.

A lot of capex has been swallowed up by shale plays. The flows have been nice, and welcome; yet concerns over diminishing returns remain.

Big concerns.

[ROCKMAN]

coffee - "...it should be immediately obvious how this quintessential sweet spot is yet to be developed." I'm curious: how is that area known to be a sweet spot if it hasn't been developed? And if it is so sweet why wasn't it drilled up by now? And if there were valid reasons for it not being developed what will eliminate those reasons in the future to allow development?

[coffeeguyzz]

rockman, great questions all, and while I am far from an authority in answering you, I will do my best.
The furious 'land grab' in the Bakken in the years 2008-2012 overlapped with the similar rush in the Eagle Ford. EOG - described as 'owning' the Parshall - was heavily involved in both areas. The upfront outlay of capital to the mineral rights owners was substantial, although the $300/acre cost in 2009 in EF pales with the current market valuation of well over $20,000/acre.
EOG, like all the other operators, had 36 months, essentially, to produce hydrocarbons of go bye bye. Thus the massive amount of drilling in what often times were less than optimal long-range (productivity/EUR-wise) conditions. (And these were frequently the wells used by predictive analysts to forecast long range, field-wide ultimate recovery numbers.)
When the Parshall was protected by the HBP leases, they turned their main attention and resources to the EF where they say they will not develop any well/area with less than a 60%/yr return. I am sure you realize how preposterously high that number is historically in this industry, but that is their stated intent.
So, back to the sweet spot, Parshall field. I just checked the ND dmr site and it looks like there are about 4 rigs currently drilling. (The nearby Sanish field, also a mega sweet spot, has double that number.)
No one but the suits at EOG can definitively say why they are holding off further production/development there, but my educated guess is that there is still a fair amount of evaluation/uncertainty as how to best proceed. The pace of technological advance has been truly stunning these past few years ... 93 stage frac job (on one run, no less) with a CT rig, inter-well spacing of 500 feet or less, increasing amounts of varying and evolving types of proppant, and on and on.
EOG doesn't have to develop this sweet spot, rock, and I guess they won't until they feel confident that they have the best way of proceeding.

[shallow sand]

Coffee. In your opinion do you think the HBP acreage may see a slowdown in drilling activity as a result of lower oil prices, or are costs now low enough that companies will keep going at the same pace. I'm referring primarily to Bakken Eagle Ford and Permian.

[shallow sand]

I just looked at most recent ND production figures. McKenzie and Mountrail counties continued their upward trend, Dunn was flat and Williams was down quite a bit. I don't know a lot about sweet spots etc in Bakken. What is reason for growth in 2 counties but not in other 2.

Also, what is long term productivity of Bakken and Eagle Ford wells. I'm referring to 5+ years out? Are they still making about 100 bbl per day or do they hit stripper well level. I understand each well is different, but what do you see when they are aggregated.

I agree the shale boom has been a big deal regarding both oil and gas. Gas has been in a long bear market IMO and I'm glad I don't own gas production. I do own an interest in oil production and am concerned it is headed to a long term bear market also, which I would define as below 60 WTI. Would like opinions on whether shale oil will drive WTI below 60 for a several year period

[rockdoc123]

I agree the shale boom has been a big deal regarding both oil and gas. Gas has been in a long bear market IMO and I'm glad I don't own gas production. I do own an interest in oil production and am concerned it is headed to a long term bear market also, which I would define as below 60 WTI. Would like opinions on whether shale oil will drive WTI below 60 for a several year period

I personally don't think this is likely for a few reasons:

1. much of increased production from shales is from a flurry of new drilling and the attendant flush high production rates. At lower prices new wells will not get drilled and it only takes about a year for the new wells production to flatten out at a low rate. To some extent I think it is self-regulating
2. OPEC is not going to live with Brent at much below $90 for very long, certainly not years of it. KSA is still in charge but they aren't going to risk having OPEC fall apart completely and the lower prices really hurt Venezuela and Iran who will be vocal. A huge discount between Brent and WTI also won't last too long simply because oil companies vote with their feet....they will start moving capital to invest where they can get higher returns.
3. having lived in the industry through more than my fair share of price collapses one thing I have noticed is that although a lower price has a positive impact on costs for steel and consumables the one thing that does not seem to see impacted is manpower costs. Certainly there will be some downsizing but the cost for individual labor seems to just keep rising. As a consequence I think there is less chance for prices to stay low for any length of time given the economics of production are such that companies will just stop drilling sooner (inability to cut costs much more than they already have).

But then again I may be wrong

[coffeeguyzz]

Shallow, I am typing on my droid with bandaged fingers ... lotta ground to cover in response ...
I am primarily an operations oriented guy, not financial. (Way too many factors to juggle like how big a ring a buxom, bleach-headed blonde covets - ask Harold Hamm 'bout that - to some berobed sheik struggling to preserve a dynasty).
That being said, the simply unbelievable amount of natgas heading our way is certain to have huge impact.
Little is said about the recent results from the UTICA dry gas areas like Rice Energy's 41 million cubic foot IP (700million cu ft produced in two months) well in Ohio, Shell's 26 million cu ft IP well in NE PA, and - 400 miles south in WVa, MRH's monster 46 million cu ft IP that they expect to produce over 5 bcf in one year.
That is a mega Kardashian-sized ass ton of natgas. To be clear, these wells are NOT from the Marcellus, but from the underlying, much larger Utica.
Yesterday's national retail average for diesel was just under $4/gal. Retail CNG was just over $2/GGE (gal. gas equivalent).
Transportation/powers generating companies will need to quickly adapt or perish.

[coffeeguyzz]

Shallow, I just now twice erased continuation responses to you and that's my limit.
Suggest you look into the current 600 well Bakken backlog of drilled, yet not frac'd wells ... the big future enchilada in ALL the shales will be EOR. Frantic-paced, deep-pocketed research shows off the chart potential. Good luck.

[shallow sand]

Thanks for the responses! You don't see low WTI long term but it seems like the facts you cite argue for that except for the high decline rates. Will be interesting.

[shallow sand]

Rockdoc I am pretty naive about shale. Are costs really going down or is this just spin. Your point about labor costs seems to argue against this assertion by those who state shale drilling in most areas is still very profitable at 80 or even 70.

The effects of 1986-1998 seem to still apply where I am located. A lot of people working in the field in their 50s and 60s. Younger people tend to shy away, not liking the long hours and hard work. Getting workers to show up consistently continues to be a challenge, even with wages rising considerably in the last ten years.

I have also wondered if the drillers would be more conservative this time around. So many lost everything before, would think there would be memories of this. However, assume a lot are using other peoples' $$ so maybe not. Also, 1998 is now 16 years ago, assume a lot of people not in the industry then.

I started to have somethIng at risk in 1997 and 1998 just about took the wind out of my sails. But then price shot up in 1999. Just don't want to revisit below LOE prices again. Happened in 2008-2009 briefly and was not enjoyable. However, that was brief and OPEC stepped in. This time looks like they can't and maybe won't be able to do anything if US continues to explode.

[ROCKMAN]

Shallow – Some interesting thoughts from some folks who probably have a better handle on reality then many who try preaching about that which they have little direct knowledge of:

“Much of the ongoing U.S. unconventional oil activity should continue if the Brent crude oil price remains in the low to mid-$80 per barrel range, but companies operating outside of unconventional ”sweet spots” could be pinched if oil prices continue to fall, according to a recent article by Gaffney, Cline & Associates (GCA). In the Oct. 28 article, the oil and gas technical, commercial and strategic advisory firm explored whether current drilling activity and production growth in U.S. unconventional oil could continue, given the recent slide in the Brent crude price by over $20/bbl towards the $80/bbl mark and over half of the 9 million barrels per day of hydrocarbon liquids produced last month coming from unconventional plays.

The firm examined publicly-available data from around 3,000 wells drilled from 2011 to 2013 in the Eagle Ford play in South Texas. After examining the possible impacts of weakening oil prices on the liquids-rich portion of the Eagle Ford, GCA concluded that, while the “sweet spot areas” of these plays are still viable at current prices, the rock’s heterogeneity means this outcome can’t be extrapolated to the entire play. Operators working in areas with favorable geology and reservoir properties would likely be able to continue current operations and remain above the economic threshold even if Brent crude falls as low as $70/bbl. However, companies operating outside of these sweet spots, where production performance and/or the netback value of oil is much lower, will likely feel pinched, leading to marginal or negative economics for wells drilled at $80/bbl oil and up to $100/bbl.

According to GCA, the analysis of Eagle Ford activity levels and production output can be extrapolated to other U.S. onshore unconventional basins. “Over several years, many small to mid-sized operators have shifted their portfolios to an essentially pure play unconventional focus,” according to the GCA article. These projects require large amounts of capital expenditures to keep production constant, let alone increase it, as initial production declines associated with unconventional wells varies from 80 to 90 percent in the first year. A large number of these projects have been based on an assumption of the oil price of $100/bbl or higher. “Given the large variability in individual well performance, internal rates of return can vary significantly from negative to over 100 percent,” according to the GCA article. “On a consolidated program/play, operators have been able to average internal rates of return of 15 to 30 percent at this pricing point.” This variability makes operators who are not well-hedged or are over-leveraged exposed to changes in oil prices.

[shallow sand]

ROCKMAN Thanks for the information. I sometimes do my own non-scientific analysis by going to Texas RRC PDQ. It does seem this is true, some really good areas and others which aren't so hot. As discussed on here, it is difficult sometimes as there are multi-well leases, so therefore difficult to tell how many wells per report. Karnes seems to be by and far the best county in the Eagle Ford. I have found several leases in other counties that drop to 10-20 bbl day range in a couple of years. Also read something recently hyping Eaglebine concerning Anadarko and KKR, but when I looked those up they didn't look so great, unless they are much cheaper to drill and complete. Permian is so much harder to tell. However, doesn't look like there is anything as prolific in Permian as Eagle Ford wells in Karnes. Looks like Shell bought a lot of horizontal production from Chesapeake in Western Permian. A lot of those Bone Spring wells don't look so great if they cost $7 million + each. Wish I had time to plot all this out, but feel I may already be taking up too much of my life reading about this stuff.

[ROCKMAN]

shallow - "but feel I may already be taking up too much of my life reading about this stuff." I know that feeling. I have the data base to mine but to do it properly would take way too much time. But I know folks who are getting paid to do just that. And they aren't going to share.

[shallow sand]

Just read that Continental Resources cashed in all its hedges through 10/16 and reduced its CAPEX budget by $600 million for 2015. Netted $433 million on liquidation of hedges. Any comments on what this signifies or is Hamm on outlier given his age, marital situation and therefore ability to have high risk tolerance? Wish I knew how to link stories, need to learn.