[ROCKMAN]

zoid - Fair enough for the D's to pay the same game the R's do when it fits their agenda. It's no wonder so many of our citizens don't really have a clear picture of many of the problems we're facing as both sides of political fence go out their way to keep the public under-informed if not outright ignorant.

[Tanada]

Just thought I would share. Wrote this in another thread:

Previously fractured uncompleted wells can be measured as "spare capacity," as the area around the borehole has measured potential to produce hydrocarbons (at a given appropriate market price level.) In the strict sense of the word each and every shale borehole is it's own unique reservoir (note*), drawing from a unique portion of a larger trend --- the constrained region around the borehole previously fractured by the liquid injection. So yes, some shale LTO is space capacity.

Of course the unfractured regions are not part of any reservoir, can not be measured or booked as a reserve so of course can not be "space capacity". Because until fracturing there is no reservoir.

note*: It truly meets the definition of a reservoir. ("defined as a subsurface pool of hydrocarbons contained in porous or fractured rock "). However the rest of the trend which is neither porous or previously fractured (by the operators or nature) can not be considered a reservoir. The rest of Bakken is not spare capacity.

I don't buy it, a fractured well has already had all the money invested in it needed for extraction and revenue. Why would any company in this low price regime sit on a well that could be producing some sort of income stream during this time of desperation?

[ROCKMAN]

"Why would any company in this low price regime sit on a well that could be producing some sort of income stream during this time of desperation?" Perhaps there’s a misinterpretation of what's being said. While some companies might delay frac'ng a well BEYOND THE NORMAL WAIT TIME for a frac crew I still haven’t seen any specific numbers indicating how common an occurrence this might be. And I mean numbers coming from the companies that are intentionally delaying frac’ng. Normally 3 to 6 months pass between when a well finishes drilling (and that rig is no longer part of the active rig count) and it is frac'd, production equipment installed AND begins producing.

But that’s a very different situation then a drilled and frac’d well with production equipment in place that isn’t being produced. We have a very specific category for such wells: it is a shut in producer. A producer whether it’s producing 1,000, 100, 10 or 0 bopd. It can happen but very rarely does an operator shut in a producing well or even cut back production in hopes of higher prices down the road. It’s actually much more common for companies to do whatever they can to increase production in the face of falling oil prices.

There’s been a lot of talk about companies delaying frac’ng while waiting for higher prices. I’ve yet to see one company state that they are doing this. Did I miss one? I know there have been a lot of folks saying it’s been happening but none of them are in the oil patch. So the Rockman thinks it’s time for some nut cutting: someone who believes there are a lot of potentially good wells DRILLED that are sitting idle waiting on higher oil prices before they are frac’d let’s see some DOCUMENTED PROOF. That’s PROOF…not speculation or theories…PROOF.

[kublikhan]

Rockman, here's some data on the backlog. Looks like North Dakota's drilled but not fracked backlog is approaching 1,000. They are lobbying for a rule change that lets them idle the wells for longer than a year.

North Dakota's oil regulators said on Monday they may allow more wells to be temporarily abandoned, a step that would permit producers to delay fracking beyond the typical one-year window and prevent even more crude from flooding onto global markets.

The change would fuel massive savings for oil producers in the state who have amassed a backlog of almost 1,000 wells that have been drilled but not completed with processes needed to get the oil flowing. The delays are designed solely to ride out the roughly 50 percent drop in crude prices since last year.

The number of North Dakota wells waiting to be completed rose by 70 to 914 in July, and most of them have one-year windows that expire in December.

The one-year window has loomed over corporate budget planning, with many producers hoping to wait as long as possible to bring new wells online. For example, EOG Resources Inc, which has one of the largest number of North Dakota wells waiting to be fracked, told investors last week it would spend most of its capital budget in early 2016 on fracking new wells. The rule change could abrogate the need for EOG and peers to start fracking come January.

North Dakota may let more oil wells be temporarily idled

At the briefing, Helms said operators he’s spoken to indicate that a backlog of wells waiting to be completed by fracking would be tackled once oil prices pass $65 per barrel and rigs would begin to return at $70 oil. In March, the backlog of wells waiting on completion was at 880.

Declining rig count leveling off

[kublikhan]

If you wanted to see data at the company level, here's some comments from EOG:

Summary
* EOG Resources plans on leaving many of its wells uncompleted this year.
* By deferring its completions, EOG Resources could substantially bolster its margins.

EOG Resources (NYSE:EOG) is putting its growth story on hold as management waits for oil prices to rise. One part of EOG Resources' plan to preserve its prime drilling inventory is delaying the completion of its wells. This means that while EOG Resources will continue to drill new wells, it plans to wait several months before complete those wells. An excerpt from EOG's Q4 2014 conference call;

"First, we will reduce average rigs 50% down to 27 for 2015 and intentionally delay any of our completions, building a significant inventory of approximately 350 uncompleted wells."

EOG started off 2015 with roughly 200 uncompleted wells, and that will grow by 75% this year as management camps on its drilling inventory.

Why EOG Resources Is Delaying Well Completions

If you wanted to see individual wells, check out the links below.

North Dakota Abandoned Well Law: Bakken Fracklog Killer?

Daily Activity Report Index

[Sixstrings]

News story out, about oil boom bust in North Dakota, and subdivision and apartment complex construction being halted, half built:

After struggling to house thousands of migrant roughnecks during the boom, the state faces a new real-estate crisis: The frenzied drilling that made it No. 1 in personal-income growth and job creation for five consecutive years hasn’t lasted long enough to support the oil-fueled building explosion.

...

Civic leaders and developers say many new units were already in the pipeline, and they anticipate another influx of workers when oil prices rise again. But for now, hundreds of dwellings approved during the heady days are rising, skeletons of wood and cement surrounded by rolling grasslands, with too few residents who can afford them.

"We are overbuilt,” said Dan Kalil, a commissioner in Williams County in the heart of the Bakken, a 360-million-year-old shale bed, during a break from cutting flax on his farm. “I am concerned about having hundreds of $200-a-month apartments in the future.”

...

Civic leaders across the Bakken charged into overdrive, processing hundreds of permits and borrowing tens of millions of dollars to pay for new water and sewer systems. Williston has issued $226 million of debt since January 2011; about $144 million is outstanding. Watford City issued $2.34 million of debt; about $2.1 million is outstanding.

Construction companies and investors went along for the ride.

...

Another Glut

Fracking’s success has created another glut, and crude prices have fallen more than 50 percent in the past year. Now North Dakota’s white-hot economy is slowing. More than 4,000 workers lost their jobs in the first quarter, according to the state’s Labor Market Information Center. Taxable sales in counties at the center of the nation’s second-largest oil region dropped as much as 10 percent in the first quarter from a year earlier

...

Vacancy Rates

With the region’s drilling-rig count at a six-year low of 74 and roughnecks coping with cuts in overtime and per-diem pay, the vacancy rates in Williams County man camps are as high as 70 percent. Meanwhile the average occupancy rate of new units in Williston was 65 percent in August, even as 1,347 apartments are under construction or have been approved there.
http://www.bloomberg.com/news/articles/2015-09-29/man-camp-exodus-spurs-real-estate-crisis-across-u-s-shale-towns

[Pops]

No you just won't admit you are wrong. LoL

Spare capacity comes online within 30 days and continues for 90

If Muslims took over some backwards oil producing region today, say Texas for example, and cut off the oil supply, Bakken wells would not come online at the drop of a hat to make up the shortfall. That would be spare capacity.

I'm pretty sure the drilling goes fast but it is the completion that takes a while, last year and for a while before the backlog was 500-600 wells, I remember pointing that out. In the best of times, with full crews, full supply lines, and full schedules, there were only a couple hundred coming on per month. And IIRC, it takes somewhere around 120-140 new wells every month just to keep production flat.

None of which is to say the Bakken is cooked. I'm pretty sure there are still spots to drill with a higher price, increases will likely resume and depending on how long the price stays down may make another record, I don't know.

But I'm pretty sure it isn't spare capacity in the sense of emergency supply.

[ROCKMAN]

k - Good info on ND...thanks. The problem with the TRRC is that they don't even track when drilled wells in Texas are frac'd or not. And the TRRC has no say in extending leases: if the primary term of a lease expires it expires whether there's a well on it waiting for a frac crew or not: only a commercially producing well can hold a lease beyond expiration. Trust me: Texas mineral owners would love to see an unfrac'd well on their expired leases: such wells become 100% owned by the mineral owner with the company that drilled it retaining $zero value from the $5+ million well they drilled and didn't frac.

And here's the problem with such statements: "This means that while EOG Resources will continue to drill new wells, it plans to wait several months before complete those wells." It takes 3 to 6 months to frac a well and install production equipment before it can begin producing. So saying they'll wait several months falls into the category of BAU. More important: did they say exactly how many wells they are INTENTIONALLY delaying? And even more important: why are the fracs being delayed?

Remember that fracs have started costing more than the drilling of the well thanks to very high frac stages, In fact, EOG has been one of the leaders in doing very high frac stages: 50+. They might be delaying fracs on some wells because they don't reach the economic bar to justify finishing. Remember the story about a company that's paying $300 million in cancellation penalties for two offshore rigs? It makes more economic sense for them to pay all that money then to actually drill wells. So a company not spending $5 or $6 million to finish a shale well because the economics don't justify it can actually happen. That doesn't mean they are voluntarily delaying the frac but that they can’t justify the additional investment at current oil prices. Not exactly something a pubco would want to announce to Wall Street.

So a more important question: why are drilled wells (however many there really are) not being frac'd? A drilled but not frac'd well will never be frac'd (and thus isn't "spare capacity" if it's never frac'd and produced. Just like all those wells that won't be drilled by those two offshore rigs that were cancelled for $300 million.

I'm not saying it hasn't happened at all. But remember one of the goals of press release from pubcos is to keep the stock price stable. By not quantifying how much "new and cheap" production EOG is intentionally holding off the market one can't really estimate the future impact. Also remember for many companies finishing projects might not be voluntary from an economic value standpoint: I'm looking at 3 different situations with viable upside drilling/recompletion potential because the current operators don't have the capex to go forward. They aren't delaying production because they've chosen to: they can't afford to go ahead with those efforts. As I said elsewhere: the Golden Rule applies very heavily during times like this. I have $250 million cash ready to spend: companies trade with the Rockman on his terms or there's no trade.

Nothing personal...just good business. LOL.

[Tanada]

Rockman, here's some data on the backlog. Looks like North Dakota's drilled but not fracked backlog is approaching 1,000. They are lobbying for a rule change that lets them idle the wells for longer than a year.

North Dakota's oil regulators said on Monday they may allow more wells to be temporarily abandoned, a step that would permit producers to delay fracking beyond the typical one-year window and prevent even more crude from flooding onto global markets.

The change would fuel massive savings for oil producers in the state who have amassed a backlog of almost 1,000 wells that have been drilled but not completed with processes needed to get the oil flowing. The delays are designed solely to ride out the roughly 50 percent drop in crude prices since last year.

The number of North Dakota wells waiting to be completed rose by 70 to 914 in July, and most of them have one-year windows that expire in December.

The one-year window has loomed over corporate budget planning, with many producers hoping to wait as long as possible to bring new wells online. For example, EOG Resources Inc, which has one of the largest number of North Dakota wells waiting to be fracked, told investors last week it would spend most of its capital budget in early 2016 on fracking new wells. The rule change could abrogate the need for EOG and peers to start fracking come January.

North Dakota may let more oil wells be temporarily idled

At the briefing, Helms said operators he’s spoken to indicate that a backlog of wells waiting to be completed by fracking would be tackled once oil prices pass $65 per barrel and rigs would begin to return at $70 oil. In March, the backlog of wells waiting on completion was at 880.

Declining rig count leveling off

The problem is, if Regulators bend the rules to make the industry happy then what is the point in having rules in the first place? Either pass all new rules, or enforce the ones already on the books because anything else smells of corruption and influence peddling. They drilled these wells with borrowed money in a risky environment, if the regulators just let them slide this time for economic reasons what about next time when the economics are tight and it is environmental protection regs that are causing problems?

[kublikhan]

So saying they'll wait several months falls into the category of BAU. More important: did they say exactly how many wells they are INTENTIONALLY delaying? And even more important: why are the fracs being delayed?

They said the reason they are delaying well completions is because the WTI price is too low. They want to hold out for $65 WTI before fracking them. As for the number of wells that are intentionally delay, EOG said 85 out of 285 delayed wells were intentionally delayed this year. I am not sure how much of that 200 is intentionally delayed from last year vs BAU. But they later upped the total delayed number to 320. I would interpret this as 120 "intentionally delayed" wells this year, plus 200 delayed ambiguously.

The largest U.S. shale producer to fracklog is EOG Resources (EOG). It started 2015 with 200 uncompleted wells and announced it would “intentionally delay” about 85 more wells this year.

Fracklog Threatens to Put a Lid on Oil Prices

William Thomas (EOG Chairman; CEO): We have also stated that we have no interest in accelerating oil production at the bottom of the commodity price cycle. Instead, we are drilling but deferring completions on a significant number of wells known as DUCs until oil prices improve. It is the right business decision to drill the wells and defer completions instead of buying out drilling contracts or growing oil in a low price environment. By deferring completions and accelerating oil growth in a better price environment, we maximize 2015 return on capital invested, and build momentum as we head into 2016. We plan to enter 2016 with approximately 285 DUCs. If oil prices recover and stabilize around $65 WTI, EOG can resume strong double-digit growth with a balanced CapEx to discretionary cash flow program.

Douglas Leggate: Bill, I wonder if I could touch on your completion strategy? What would you need to see in order to re-up the dates of completions to match your drilling pace? On a related question, the backlog you've talked about coming out of 2015, what kind of pace would you expect to move those toward production?

William Thomas: Yes, Doug, thank you for the question. The reason we have deferred the completions is to really substantially increase the rate of return. So as we go forward this year, it is really important for us to be patient and allow the process to continue to firm up. As I have said, the first $10 in oil price increase with a six-month deferral is a $300,000 net PV add to a typical well. So we want to make sure that we allow prices to firm up and that the prices will continue to be firm and not short term.
And then as you see, we are getting significant cost reduction as we go forward. We are gaining on that every day, and we are gaining on well productivity as we go forward. We do not want to get in a hurry. We want to stay disciplined. We certainly don't want to jump start completions and the price maybe fall back. So if the forward curve continues to stay firm, then our plan, as we've said, is to begin completing wells in the third quarter. We will really look at what the outlook on 2016 prices are. That is what we are targeting, and that is what we are really focusing on. So we will just continue to watch the fundamentals. And certainly we want to be convinced that they are strong going forward. And we will really make the call for the third-quarter activity probably in July or so, after we get a little more data.

Douglas Leggate: So just to be clear on the pace. I mean you can obviously bring those completions back very quickly and turbocharge your growth.
I just don't know how EOG has defined the pace. But would you plan to have the backlog reduced to a level that was equivalent to your current drilling rate within a period of time? Can you walk us through how you might think about that? Just trying to see what the upside is to the growth outlook when you go back to completing those wells.

William Thomas: Yes. I guess the answer to that, Doug, is we are going to be really patient and disciplined about it, and kind of gradually increase the activity as we go forward making sure that the price is going to hold up. And we really do, as a Company -- you know EOG. We are very, very focused on returns. So every time that price increases a little bit, and every time we get the productivity of wells up and get the cost down, we're making higher returns. So there is no use pushing that too quickly.
The ramp-up will be, as we talked about, the production shape is going to be U-shaped this year; and the second and third quarters will be the low point. But the fourth quarter, with the current plan, is to ramp up production growth and be heading into 2016 on a very strong note.

Paul Sankey: Sorry to press on the drill down completed. But I guess a follow-up is trying to get a sense of the pace at which the 285 would come back relative to how much drilling you would do simultaneously. I think what you're saying is at a $65 plus price, you would be ramping up the DUCs or the drilling, both simultaneously? Can you just go into that again? Thank you.

William Thomas: Yes, Paul, that is a good question. And as we head into the last half of this year and think about 2016, we will be on a pretty good uptick. So what we want to do is get the equipment and the people in place and get the process started, certainly very strongly in the second half of the year. Then when we hit 2016, if oil prices continue to hold up, we will continue to increase activity accordingly.

Of course the goal is, and the plan is, to continue to remain CapEx to discretionary cash flow balanced. So that will really govern our activity. The stronger the price of oil is, the more, obviously, capital we'll have to work with; and the more we will continue to increase our activity.

As we look at the second part of this year, part of the process we'll be evaluating is how many drilling rigs to continue to have drilling wells versus releasing rigs. And that certainly will be a function of what the oil price is. We won't get too far out in front on the drilling side. The 285 DUCs that we start the year with, most likely over the first half of the year we'll reduce significantly as we go forward. We will exit the year next year with considerably less DUCs than we are exiting this year with.

Paul Sankey: Yes, I think I understand. To reinterpret, the closer you are to $65, the more DUCs will be used to generate the double-digit growth. But what you are essentially saying is if you're $65 or above, you will be delivering double-digit growth next year.

William Thomas:Yes, I think that's correct. Yes.

William Thomas:The reason that our guidance on the second quarter is down is because we have had a significant reduction in the amount of wells we complete. That is really the driver. We were down 39% in completions in the first quarter. And then in the second quarter, we are down an additional 36%. And that is really just the process of deferring the wells and not completing the wells, and just really taking off the spin rate as we move into the second quarter. So that is just driving it.

EOG Resources (EOG) Earnings Report: Q1 2015 Conference Call

William Thomas: our projected year-end uncompleted well inventory has increased from 285 to 320. Many of you are asking, when will EOG grow oil again? We have said all along that we do not want to grow production until we see the oil market is firmly rebalancing. We will be watching the supply-demand fundamentals in the second half of this year closely as we determine our plan for 2016. Currently, we intend to spend within cash flow. The capital efficiency gains we have made this year, along with our large high-quality inventory of uncompleted wells, positions us for an excellent 2016.

The second thing is that, as we've talked about, we have a very large, now 320 -- estimated 320 uncompleted well inventory that will be very high quality. I think it will be the highest quality inventory of any operator in the US, and that inventory is ready to complete -- to begin completion early in the year next year. We have infrastructure in place for all of that uncompleted inventory. So that won't slow us down.

Gary Thomas (COO): Would we just grow production? We're not inclined to grow production just in the continued low-price environment. But like Bill is saying, we're very well-positioned with all of our high-quality ducts, wells not completed. In order to go ahead and lease maintain, possibly grow production depending on what the prices are, we will start with quite a number of completion units. That allows us to bring production on rapidly.

EOG Resources (EOG) Earnings Report: Q2 2015 Conference Call Transcript

[Subjectivist]

A while back somebody posted a projection of Bakken peak in I think 2019 based on the number of drilling locations and the rate of new wells being drilled.

Even though drilling in 2015 fell by about 50 percent basic math says every year at half the rate extends the limit by one year. By that logic we will start running out of drillable locations in 2020, and if the rate stays low for another year to 2021, but even so we will run out of drilling locations long before we switch to an alternate fuel system.

Does that seem correct to those in the oil biz, or am I missing something?

[ROCKMAN]

Sub – “By that logic we will start running out of drillable locations in 2020”. Actually logic tells you that the Bakken wells with better potential are drilled first. So wells drilled prior to 2016 should be yielding better production then wells drilled post 2016. But an addition chunk of logic would also require the high oil prices used to justify the same pre -2016 drilling to even yield those poorer results. IOW if prices had stayed around $100/bbl post 2015 Bakken wells would likely not have been as productive (and there wouldn’t be as many drilled). But we don’t have high priced oil today. IOW would we expect to have seen as many 2014 POORER Bakken wells drilling had oil been $38/bbl that year? Easy answer, eh? lol. Thus given we have less productive Bakken wells to left to drill and oil at less than half the price as during the Bakken “boom” should we really have expectations of Bakken results in the next 5 years based upon the history of the last 5 years? I mean, strictly from a logical point of view wouldn’t we be comparing water melons to apples? lol.

And I forgot: the new no flaring rules for NG will also likely reduce the number of future economical Bakken locations left to drill.

[Outcast_Searcher]

Sub – “By that logic we will start running out of drillable locations in 2020”. Actually logic tells you that the Bakken wells with better potential are drilled first. So wells drilled prior to 2016 should be yielding better production then wells drilled post 2016. But an addition chunk of logic would also require the high oil prices used to justify the same pre -2016 drilling to even yield those poorer results. IOW if prices had stayed around $100/bbl post 2015 Bakken wells would likely not have been as productive (and there wouldn’t be as many drilled). But we don’t have high priced oil today. IOW would we expect to have seen as many 2014 POORER Bakken wells drilling had oil been $38/bbl that year? Easy answer, eh? lol. Thus given we have less productive Bakken wells to left to drill and oil at less than half the price as during the Bakken “boom” should we really have expectations of Bakken results in the next 5 years based upon the history of the last 5 years? I mean, strictly from a logical point of view wouldn’t we be comparing water melons to apples? lol.

And I forgot: the new no flaring rules for NG will also likely reduce the number of future economical Bakken locations left to drill.

So in other words, it all depends on the price of oil.

If oil is perceived as scarce, it will get more expensive, and thus more profitable to drill for.

Since no one has a clue what oil prices will be in one, much less five years, why speculate?

And if oil gets expensive enough, then capturing even very cheap natural gas to meet the "no flaring" rules becomes just a cost of drilling for the oil. (It's not like, say, deep water drilling under massive salt flats will likely be "cheap" for the likes of Chevron any time soon).

[Tanada]

The latest drilling report from EIA says the Bakken is going to lose 24,000 bbl/d of production by the end of this month and that the shale plays all together will lose 116,000 bbl/d. So long as prices stay low the salad days are over, and the longer this goes on the more sweet spots that will have been tapped out when drilling goes back into higher rates. IMO of course.

http://www.eia.gov/petroleum/drilling/#tabs-summary-2

Oil production
thousand barrels/day Gas production
million cubic feet/day
Region January 2016 February 2016 change
Bakken_______1,122_________1,098________(24)
Eagle Ford____1,217_________1,145________(72)
Haynesville______52____________51_________(1)
Marcellus_______50____________48_________(2)
Niobrara_______394___________371________(23)
Permian______2,035_________2,040__________5
Utica___________78____________79__________1

Total________4,948_________4,832_______(116)

[copious.abundance]

In spite of oil prices that have been in crash mode for well over a year now, oil production in ND is holding up pretty well. It's flat-lined since the end of last year, but it seems to be holding steady over 1 million barrels/day.

North Dakota oil output defies calls for a decline

North Dakota's oil production once again defied expectations for a decline in November, even seeing a slight uptick for the second consecutive month, as unusually warm weather helped offset the deepening decline in fracking activity.

Production in the second-largest U.S. oil producing state rose by 5,000 barrels per day (bpd) to 1.18 million barrels, monthly data from the Department of Mineral Resources showed. Last month, it also rose 5,000 bpd.

Output in North Dakota's Bakken shale fields has generally outpaced expectations even as oil prices have plunged to about $30 a barrel this week from over $100 in mid-2014. Despite repeated forecasts for a decline, even from the U.S. government itself, output has remained surprisingly resilient.

[GHung]

http://www.bloomberg.com/news/articles/ ... an-nothing

>Flint Hills values North Dakota Sour crude at -$0.50 a barrel
>Crude prices based on sulfur content and transport costs

Oil is so plentiful and cheap in the U.S. that at least one buyer says it would need to be paid to take a certain type of low-quality crude.

Flint Hills Resources LLC, the refining arm of billionaire brothers Charles and David Koch’s industrial empire, said it would pay -$0.50 a barrel Friday for North Dakota Sour, a high-sulfur grade of crude, according to a list price posted on its website. That’s down from $13.50 a barrel a year ago and $47.60 in January 2014.

While the negative price is due to the lack of pipeline capacity for a particular variety of ultra low quality crude, it underscores how dire things are in the U.S. oil patch. U.S. benchmark oil prices have collapsed more than 70 percent in the past 18 months and West Texas Intermediate for February delivery fell as low as $28.36 a barrel on the New York Mercantile Exchange on Monday, the least in intraday trade since October 2003.

So what's the point of producing oil that no one wants?

[onlooker]

This is type of low grade oil that may never be produced as the energy return on energy invested appears so poor especially as we head down Hubberts oil depletion curve and economic effects from PO manifest themselves ever more severely.