[ROCKMAN]

Pops - Remember the list I posted up top showing how many EFS wells began producing each month? I decided that could be an important metric going forward so I decided to take it further back in time to see if any trends were apparent. This metric implies nothing about when a well was drilled or frac'd...just the first month it began producing:

July 13 – 241
Aug 13 – 153
Sept 13 – 187
Oct 13 – 162
Nov 13 – 184
Dec 13 – 233
Jan 14 – 162
Feb 14 – 122
Mar 14 – 171
April 14 – 169
May 14 – 160
June 14 – 179
July 14 – 134
Aug 14 – 103
Sept 14 – 131
Oct 14 – 127
Nov 14 - 171
Dec 14 – 198
Jan 15 – 90
Feb 15 – 103
Mar 15 – 4

See what I mean about late reporting. I wouldn’t accept the March count for at least another couple of more months. There were certainly more than 4 wells that began producing that month. I'm even a bit suspicious about the Jan and Feb numbers. We'll see if they change over the next couple of months.

Still rather erratic. It will be very interesting to see how wells add on in the next 6 to 12 months. I'll keep it up to date and post every month going forward.

[Pops]

thanks ROCK

[ROCKMAN]

Pops - Here's the latest word from an EFS forum

(http://eaglefordshale.com/news/eagle-fo ... the-state/)

They keep a very close and current eye on the situation. Notice drill permits: they really aren't a very good measure of activity...they are good for 12 months and don't represent a commitment to drill the well. Also notice the number of producing well increased from April 2014 to April 2015 from 1,012 to 1,867. Which actually isn’t very good news. OTOH those wells going on line gave a very nice boost to production but they also represent a group of wells that will show the most dramatic decline. So the need to drill more wells to make up for declining new wells obviously won’t happen this year with the rig count drop. Also with regards to all the hype that operators are intentionally delaying fracs on wells already drilled: check the last paragraph: EFS oil completions in April: 222. Remember my list of the number of wells completed each month? Those 222 completions in April are the largest number of wells coming on line in any one month since December 2013. That doesn’t seem to support the big “frac log” numbers some folks are estimating.

“Texas Railroad Commission released its latest statistics showing the state’s oil and gas production continues to impress, with the Eagle Ford leading the way. Original drilling permits issued for April dropped from 1,919 last year to 848. Of the April total, 721 permits were for new oil and gas wells, 9 to re–enter existing well bores and 118 for re–completions. Broken down even further, April permits included 218 for oil, 51 gas, 530 oil and gas, 40 injection, zero service and nine other.

Texas Drilling Permits down 50% - Statewide, well completions were up in April 2015, with operators reporting 1,867 oil, 314 gas, 125 injection and one other completions. In April 2014, there were 1,012 oil, 92 gas, 21 injection and four other completions. Total well completions for the year are still down by several thousand over this time last year.

Directly from the TRRC itself: a nice update of EFS activity.

http://www.rrc.state.tx.us/media/7078/e ... perday.pdf

“Activity in the Eagle Ford continues lead the state in April with 176 permits to drill oil and gas, 222 oil completions and 94 gas completions. There were 2,521 producing oil leases on schedule in 2013; 1,262 producing oil leases on schedule in 2012; 368 producing oil leases on schedule in 2011; 72 producing oil leases in 2010; and 40 producing oil leases in 2009”

{A very impressive increase in the number of producing leases in just 5 years, eh? But notice the production chart they present: in 2014 EFS production averaged 1.016 million bopd. But for 1Q 2015 it has averaged 0.963 million bopd. That’s a 5% decline BEFORE the effect of the fallen rig count kicks in. I was already somewhat pessimistic about future production from the EFS. Now with the current numbers directly from the TRRC I’m more so. But remember we have to be careful about how Texas classifies oil vs condensate: it isn’t a function of the API. Two wells might be producing the exact same oil but one could be counted as oil and the other as condensate. Too complicated to explain. But here is the stat for EFS condensate production:

2014 avg: 273k bbls/day
1Q 2015 avg: 245k bbls/day

So even combining C+C the daily rate is still currently more than 5% lower than the average for 2014. And a reminder again: the 1Q production is from wells that were drilled long before the collapse of the rig count.

The Rockman didn’t play the EFS so he didn’t really give a sh*t about what was happening. Now, out of morbid curiosity, he’ll start paying close attention. LOL}

[ROCKMAN]

pstarr - Which is why I consul patience and avoid debates about where US oil production is heading. A model could be built but the potential ranges of the assumptions required are just too broad. But by the end of 2015, if oil prices remain at the current level, we should have a strong empirical answer to the question.

[copious.abundance]

MORE CLICK-WORTHY NEWS ON THIS TOPIC

[ROCKMAN]

pstarr - And another grim day for those trying to talk themselves into seeing a turnaround beginning:

Reuters - A slowdown in U.S. oil drilling trudged along in its seventh month as more rigs were pulled than in the previous week, denying the market a sign that producers have started ramping up production. Energy firms pulled another seven rigs from U.S. oil fields this week, the most since late May. That was the 27th straight weekly decline, bringing the total rig count down to 635, the lowest since August 2010.

I've seen turnarounds in the oil patch both big and small. And they have never happened in a few months. Declines...yes. Turnarounds...never.

[Observerbrb]

O - I would give it a try but I'm not sure what "data variability" you're referring to.

Well, I was referring to data variability such as this one:

http://www.eia.gov/petroleum/drilling/pdf/dpr-full.pdf

My assumption is that Shale Oil production has peaked (momentarily or not?) since some months ago, and that the negative trend is increasing...at least, according to EIA. But how trustworthy these data are when another report comes out the next day and shows an oil production increase?

Best Regards,

[ROCKMAN]

Observer - Thanks for that link...one of my favorites. Of anyone skipped they should go back. The best concentration of easily digestible trends.

Folks have addressed the changes in data as updates are released. If you're talking about varying numbers between different sources then it goes down to their sources. I just focus on the Eagle Ford and the data from the Texas Rail Road Commission as presented by Drilling Info. There is a lag of several months to that data so best not to draw hard conclusions on the latest 2-3 months.

Yes: looks like the lag between drilling and first production has just about run its course since the rig drop began. We may be seeing the serious production slide began. But I would still wait till this fall/winter before drawing hard conclusions.

One very important trend from that link: look at how the production per well has shot up in the EFA over the last 12 months while the rig count has stayed until the collapse. They were drilling better locations: they were drilling longer laterals and, more important IMHO, pumping a lot more frac stages per well. From when pumping 6 or 8 stages were a lot to 36 to 72. Eventually the cost of the frac exceeded the cost of drilling the well. Typically from $5 - $7 million to $10 to $12 million. If one normalized that increased production per well with the total well cost I suspect the trend wouldn't be impressive.

[dcoyne78]

Hi Rockman,

The RRC has data (in graphic form upper right corner) of its Eagle Ford page (link below).

http://www.rrc.state.tx.us/oil-gas/major-oil-gas-formations/eagle-ford-shale/

The graphic gives the number of oil wells on schedule. Using the video you can determine the number of oil wells on schedule each month back to 2011.

A question I would have is this, if a company's oil well is on schedule and it is a new well, wouldn't it usually be producing oil?

As far as using Drilling info, they rely on the data from the RRC's PDQ and the data is only about 95% complete after 12 months from the most recently reported month.

The Eagle Ford information on number of oil wells on schedule may also be incorrect, the public information available from the RRC is not very timely, we really have to use estimates from the EIA to get the best guess or wait 2 years and 2 months for complete data from the RRC.

[dcoyne78]

I present the data below for oil wells on schedule in the Eagle Ford for July 2013 to May 2015 with the data that Rockman presented for new wells producing.

Data is month, Drilling info data, RRC data

where Drilling Info data is from Rockman's comment above and RRC data is from the Eagle Ford page (video with oil wells on schedule).

July-13, 177, 241
August-13, 245 , 153
September-13, 186, 187
October-13, 214, 162
November-13, 206, 184
December-13, 125, 233
January-14, 264 , 162
February-14, 343, 122
March-14, 230, 171
April-14, 114, 169
May-14, 224, 160
June-14, 218, 179
July-14, 91, 134
August-14, 203, 103
September-14, 198, 131
October-14, 243, 127
November-14, 185, 171
December-14, 240, 198
January-15, 192 , 90
February-15, 128, 103
March-15, 132, 4
April-15, 141,
May-15, 281,

Data can be copied and pasted into Excel, then use text to columns in the Data tab with a comma separator.

[dcoyne78]

Hi Rockman,

Are your numbers from Drilling info, the number of producing wells or the number of producing leases? Most oil leases have more than one well (as you know), so that might account for the difference between the numbers. I have the well data back to April 2011 (as reported by the RRC) for oil wells on schedule, it would be interesting to see what the drilling info data says for July 2012 to June 2013 (which would include a longer period of "complete" data) to see if the numbers match up better. Some of the difference may be incomplete data and some of it may be that some wells go on the schedule prior to production or that there is a few weeks delay between completion and production.

[GoghGoner]

From the EIA report, it does appear that the monthly production numbers have begun dropping for both oil and ng. Brent and WTI appear to moving towards parity. The shale oil glut isn't increasing anymore. Start the shortage watch...

[dcoyne78]

One more comment on first quarter 2015 production from the RRC. This data is likely to be revised substantially as more data comes in. This data is pulled from the PDQ, which is very incomplete data for the first 3 months of the year, even 2014 data is not very good (it is incomplete), though the 2013 data is probably pretty good.

The best way to estimate is to take the percentage of statewide output that has been produced by the Eagle Ford (or Permian Basin if you are looking at that) as reported by the RRC.

Then assume that this percentage will not change very much as new data comes in. Also assume that the EIA estimate is likely to be much better than the incomplete RRC data and multiply the % found by using the RRC data by the EIA estimated statewide output. For February 2015(the last time I did this) Eagle Ford C+C output was about 1400 kb/d and Permian basin C+C output was about 1500 kb/d.

[dcoyne78]

The Drilling Productivity report should be ignored. The drop in output in that report is due to an overestimate of output in the Nov to April period. The best estimates from the EIA are in the Monthly Energy review(MER), these are revised monthly as they get better data, the weekly estimates are never revised and the Drilling Productivity report revises past estimates about once per year.

Bottom line the MER is the EIA's best estimate of past output, everything else is a very rough guess.

[ROCKMAN]

dc - As I understand it the TRRC uses a % correction for their reported numbers that takes into account the historic corrections. I think they currently use a multiplication factor of 1.18 these days.

But ignoring that if you look at the trend: since the reported high in Aug 2014 every month since then has posted lower Texas monthly oil production except for Dec 2014. How would you interpret that trend? The absolute values may still need more adjustments but wouldn't you think the month to month error stay fairly constant?

As far as the EIA being more accurate then the TRRC: the TRRC is the only organization that has actual state oil production reported to it. So unless the EIA is a very good guesser they are starting with the same TRRC data base as everyone else.

[Tanada]

Directly from the TRRC itself: a nice update of EFS activity.

http://www.rrc.state.tx.us/media/7078/e ... perday.pdf

“Activity in the Eagle Ford continues lead the state in April with 176 permits to drill oil and gas, 222 oil completions and 94 gas completions. There were 2,521 producing oil leases on schedule in 2013; 1,262 producing oil leases on schedule in 2012; 368 producing oil leases on schedule in 2011; 72 producing oil leases in 2010; and 40 producing oil leases in 2009”

{A very impressive increase in the number of producing leases in just 5 years, eh? But notice the production chart they present: in 2014 EFS production averaged 1.016 million bopd. But for 1Q 2015 it has averaged 0.963 million bopd. That’s a 5% decline BEFORE the effect of the fallen rig count kicks in. I was already somewhat pessimistic about future production from the EFS. Now with the current numbers directly from the TRRC I’m more so. But remember we have to be careful about how Texas classifies oil vs condensate: it isn’t a function of the API. Two wells might be producing the exact same oil but one could be counted as oil and the other as condensate. Too complicated to explain. But here is the stat for EFS condensate production:

2014 avg: 273k bbls/day
1Q 2015 avg: 245k bbls/day

So even combining C+C the daily rate is still currently more than 5% lower than the average for 2014. And a reminder again: the 1Q production is from wells that were drilled long before the collapse of the rig count.

The Rockman didn’t play the EFS so he didn’t really give a sh*t about what was happening. Now, out of morbid curiosity, he’ll start paying close attention. LOL}

ROCKMAN do you have access to say 3Q 2016 numbers yet for comparison purposes? The more current the better but as 4Q ended yesterday I presume those numbers won't be released for a while yet.

[ROCKMAN]

No hard numbers I would but much coincidence right now given the trailing corrections put out by the TRRC. But here's a site you might want to try to mine:

http://eaglefordshale.com/eagle-ford-production/

[Tanada]

Thanks for the link, didn't find exactly what I was looking for but I did find this,

OPEC announced it will reduce production and many are wondering what this means for this mean for the Eagle Ford.

Related: OPEC Decision Doesn’t Intimidate

For the first time in eight years, OPEC has agreed to reduce oil production, announcing last week that it will cut approximately 1.2 MMBOPD to 32.5 MMBOPD effective 1 January 2017.

The decision is great news for energy-producing regions in the United States including Texas and the Eagle Ford Shale Play. Texas has lost over 100,000 jobs since 2014 as crude pricing remained low, and this agreement should help create more jobs and reverse some of the stress of the last two years.

Analysts predict that this deal will remove 1.5 million barrels of oil per day from the global market, causing an increase in the price of crude oil, possibly moving closer to the $60/bbl range. Prices jumped immediately after the announcement, with Bloomberg reporting a per barrel price of $52.08 this morning.

One of the first things shale producers will likely do is to begin to attack their inventory of DUCs that have been waiting for prices to recover. There are currently 5,155 DUCs in the U.S., with one-quarter of them in the Eagle Ford, according to the Energy Information Administration.

During a press conference, OPEC responded to comments that this agreement will cause an increase in price that will benefit shale producers:

The idea is to take measures to get the market rebalanced. We are not saying the rebalance will be from just OPEC and non-OPEC key members, but producers from outside will react to the price, but we cannot see a threat from shale gas and shale oil producers, because they will look at how much it will cost them, and the affordability. They will do it without us interfering. We think this measure will help rebalance. There will be effects on expensive producers, not only shale oil, but others.

Details Include:

The OPEC deal was unanimous
The deal is initially for six-months deal, but OPEC could extend by another six months
The cuts will begin in January with cut OPEC production to 32.5 million barrels daily
Saudi Arabia is making the biggest cut, agreeing to reduce its production levels by nearly 500,000 barrels a day to about 10 million

I found the fact that there are over 5000 DUC's still in the USA inventory and a quarter of those are in the eagle Ford interesting. I have not seen any DUC numbers posted for a while around here, I thought the number had gotten much lower than that by this time.

[ROCKMAN]

T - The chart in this link shows less the half of that number (25% of 5,155)..

http://mercercapital.com/energyvaluatio ... agle-ford/

I'm always a tad dubious of any DUC #. As far as I know in Texas there is no OFFICIAL reporting category for DUC's. Wells are spudded and are either reported plugged & abandoned, completed & producing or "suspended". Why a well is suspended and what it will take to complete it is subject to interpretation. The pubcos like EOG can release numbers. But when/if such wells are completed is not given. Bear in mind every Eagle Ford well completed even when oil was $100+/bbl went thru a DUC phase. At the height of the boom some operators had to wait 6+ months for a frac crew. With that in mind how many new EFS wells that had casing run and became suspended last November (and were added to the DUC list) are anticipating a frac this month? The boom demand might be gone but many frac crews have been laid off so it might take a month or two for a ready and willing operator frac a new well.

The more curious aspect are areas where the DUC # has increassed well after the oil price collapse. A company might choose to drill a well to keep a lease about to expire. OTOH most leases require production to keep it. But there can be a provision for a "shut-in royalty" payment after the primary term passes. And every aspect is subject to renegotiations.

But for many shale players with high debt loads to service spending many $millions on new DUC's that won't generate cash flow for an indefinite amount of time would be very difficult.