[ROCKMAN]

CHK has been paying down their debt by liquidating assets. Last time I counted they had sold over $26 billion in assets and some of those at bargain basement prices. And last time (been a while) I saw a statement from their bankers they were only going to allow a $4 -$6 billion credit line towards their $20+ billion budget. Debt/revenue doesn't mean much if you lack enough the capital to conduct business properly.

[rockdoc123]

$this->bbcode_second_pass_quote('', 'C')HK has been paying down their debt by liquidating assets. Last time I counted they had sold over $26 billion in assets and some of those at bargain basement prices. And last time (been a while) I saw a statement from their bankers they were only going to allow a $4 -$6 billion credit line towards their $20+ billion budget. Debt/revenue doesn't mean much if you lack enough the capital to conduct business properly.

[Scrub Puller]

Yair . . . Rocdoc123.......

$this->bbcode_second_pass_quote('', 'T')here will come a point at which all of their fields are on the long flat production where they will convert the whole thing to a trust model and sit back paying opex, G&A and nothing more .....it becomes a nice cash machine.

[rockdoc123]

$this->bbcode_second_pass_quote('', ' ')I thought a characteristic of their operation was (relatively) fast depletion wells.

[dcoyne78]

Several scenarios for the North Dakota Bakken/Three Forks, only TRR is considered in this chart and the middle three scenarios (TRR from 6.5 to 11.5 Gb) roughly match the April 2013 USGS TRR estimates (mean 8.5 Gb, F95 6 Gb, F5 11 Gb) for the North Dakota portion of the Bakken Three Forks play. The average new well EUR from April 2008 to Dec 2013 is 331 kb for 30 years. All scenarios in the chart assume 175 wells/month are added for 250 months for a total of 49,900 wells.

In the Chart legend the second number is the # of months from June 30, 2013 to the start of the decrease of the average new well EUR, the third number is the # of months from the start of the decrease of EUR to reaching the maximum monthly rate of decrease, and the last number is the maximum annual rate of decrease of EUR.



The chart above shows the middle (8.4 Gb) scenario from Jan 2008 to Dec 2017, the match between model and data is fairly close, though the most recent two months the data is higher than model predictions, the average new well EUR does not remain fixed but fluctuates month to month so this is expected (no model matches reality perfectly).

In a new post at my blog I present more charts and a link to some of the data in the charts and to an interactive spreadsheet that enables the user to create their own scenarios.

http://oilpeakclimate.blogspot.com/2013/10/exploring-future-bakken-decrease-in.html

Dennis

[ROCKMAN]

More ridiculous hype about another shale with “huge potential”. Even the numbers they present blow up in their face. From http://www.rigzone.com/news/oil_gas/a/1 ... s/?all=HG2

“Goodrich Touts Tuscaloosa Marine Success Despite Soft Shale Worries”

Bits and pieces –

First: “In fact, the company is doubling down on the Tuscaloosa after issuing 6 million shares of stock Oct. 15 to fund the accelerated drilling program in the Tuscaloosa Marine, according to a press statement”. IOW they have neither the capital nor credit capable to fund the effort. They’ve had to sell off a portion of the company to raise the capex.

Second: “Devon Energy sold its two-thirds share of 277,000 leased acres to Goodrich for $26.7 million in July, according to the companies. The price was a fraction of what equivalent acreage in the Eagle Ford formation in South Texas would go for.” The math: that’s about $145/ac. I was at Devon when they first began their Tuscaloosa run. They sold the acreage for less than 5 cents on dollar that they paid for it. And how well does Devon understand the MTS? They were one of the first players in the trend with several rigs running at the same time. Probably in excess of $100 million spent drilling.

Third: “As for the cost of acreage in the Tuscaloosa Marine, it is substantially higher than what Goodrich paid for when it bought Devon’s land, but it is substantially lower than acreage in established formations like the Eagle Ford formation, where acreage can be north of $20,000 per acre.” So Devon sold their acreage to Goodrich for substantially less than folks are paying for the rest of the acreage:”Turnham put the current market rate for acreage in the Tuscaloosa Marine Shale at close to $3,000 per acre.” So Devon sold acreage that is worth $550 million at “current market rate” for $27 million. And why did Devon give away free money??? And EFS acres going for $20,000/ac. Maybe some of it is. But one can acquire the rights to drill on 100,000 acs Shell Oil paid $1 billion for by just committing to drill a well on it. Shell has already written down $2 billion on their shale assets.

Forth: “Within the first five months of production, the Crosby well produced 100,000 barrels of oil equivalent. The total was comprised of about 1,200 barrels of oil and 600 million cubic feet of gas per day over 5 months, Turnham told Rigzone.” He can’t even see the absurdity of his own numbers. First, 1,200 bopd over 5 months is 180,000 bo. Counting NG he says it produced 100,000 boe. Which is it? Second, 600 million cu ft per day is 600,000 mcf per day. Using a price of $3.50/mcf this well, according to Mr. Turnham, the well produced over $300 million in NG alone in the first 5 months. Perhaps we should all run out and buy Goodrich stock. According to his numbers, the well paid out in several days and has in the first 5 months made about 50X the original investment.

I don’t know if Mr. Turnham is just that bad at basic arithmetic or he’s just counting on other folks not checking his numbers. The MTS may eventually prove to be viable to some degree. But I think I’ll restrain my enthusiasm until a few more wells are drilled by Goodrich beyond the first one. And then I think I’ll want to see the numbers from an outside auditor and not Mr. Turnham.

BTW I was presented with a prospect to horizontally drill and frac the MTS about 20 years ago. IOW not a new idea. Just took $100 oil to get folks to start poking holes in it.

[rockdoc123]

$this->bbcode_second_pass_quote('', 'F')irst: “In fact, the company is doubling down on the Tuscaloosa after issuing 6 million shares of stock Oct. 15 to fund the accelerated drilling program in the Tuscaloosa Marine, according to a press statement”. IOW they have neither the capital nor credit capable to fund the effort. They’ve had to sell off a portion of the company to raise the capex.

[ROCKMAN]

“How do you think small publicly traded independents finance their projects?” I’ve worked or consulted for at least two dozen independent companies over the last 38 years and not one of them raised capex by issuing stock. They all used a combination of project investors, their own cash flow and credit lines. But some public companies, when their assets have little or no value to generate cash flow or don't have sufficient proved value to borrow against, have no choice but to dilute themselves by selling to folks who believe the hype about future “potential”. If the Goodrich banker believed the acreage had even a small proven potential the company is touting he would have lent them all the capex they need at a very reasonable rate.

I've had mezzanine bankers (investment companies, in reality) loan my company $120 million on less than gold plated reserves for just LIBOR +4%. Much better trade then giving up a piece of the company. Unless the company isn't worth much. Last IPO I watched first hand was Denbury Resources swapping some pretty pieces of paper to new shareholders for $260 million. And coincidentally it was to fund an EOR project in a Tuscaloosa field. Used the monies to buy the field, drilled a few wells that proved their idea wasn't worth a crap and then took a $240 million write down. The good news for Denbury management: that they didn't owe the bank one penny. In fact, they used the residual value of the field to borrow money from the bank to drill some good wells in other trends. Of course, the folks that bought the IPO shares were burned to death but, hey, you pays your money and you takes your chances. Sometimes you win big...sometimes you lose big.

600 million cu ft/day: check your decimal places. That’s 600,000 mcf/day. For folks who aren’t familiar with the oil patch a well producing 30 million cu ft of NG per day is considered outstanding. Using a 6 mcf = 1 boe conversion he’s saying the well flowed 100,000 boepd. You probably did as I did at first: read 600 mcfpd and not 600 mmcfpd. Net-back smeck-back: 600,000 mcfpd would generate $2.1 million per day gross. Do you really believe this well paid out in just a few days from the NG production alone? This has to be an absurd typo. But a typo no one involved caught because, I’ll guess, they don’t really understand the business.

[rockdoc123]

$this->bbcode_second_pass_quote('', '�')��How do you think small publicly traded independents finance their projects?” I’ve worked or consulted for at least two dozen independent companies over the last 38 years and not one of them raised capex by issuing stock. They all used a combination of project investors, their own cash flow and credit lines. But some public companies, when their assets have little or no value to generate cash flow or don't have sufficient proved value to borrow against, have no choice but to dilute themselves by selling to folks who believe the hype about future “potential”. If the Goodrich banker believed the acreage had even a small proven potential the company is touting he would have lent them all the capex they need at a very reasonable rate.

[ROCKMAN]

An opinion from Seeking Alpha: The Permian Basin is all the rage on Wall Street, but oil prices need to stay high enough to support the current rate of exploratory drilling - and prices for West Texas crude have dropped below $100/bbl for a third straight weekly decline. The Permian remains the largest U.S. oil producer, with output averaging ~1.3M bbl/day and rising, but it's also the most expensive U.S. shale formation in which to drill - meaning the boom could become a bust if crude moves near $70/bbl, as some analysts predict. If oil drops to $80, wells in some parts of the Permian will become money-losers; wells drilled in the Cline Shale and Northern Mississippian Lime layers of the Permian need $96 oil to break even

But they don't tell us how they got to those numbers.

[ROCKMAN]

Another view of why Chesapeake isn't a likely acquisition target. Not because they are doing so good but because they re not in very good shape. Sounds like folks jumping into the stock based upon such rumors may be getting the butts handed to them soon especially if the company stays on it's self-liquidating course.

http://seekingalpha.com/article/1777022 ... e_readmore

[dcoyne78]

Tight Oil from Bakken, Eagle Ford, and Niobrara plays might result in 8.3 MMb/d of US C+C in 2016 with rapid decline to follow.

The EIA DPR (Drilling Productivity Report) suggests that the Permian may already be near its peak,
(see http://www.eia.gov/petroleum/drilling/pdf/permian.pdf )

Maugeri suggests the Niobrara may reach about 0.5 MMb/d by 2017 which is only about 0.25 MMb/d above present levels. In the chart that follows I present some preliminary modeling on the Eagle Ford along with a Bakken scenario using fairly optimistic drilling and economic assumptions to get an ERR(economically recoverable resource) of about 13 Gb for the Bakken and Eagle Ford combined from 1953 to 2073. Peak is reached in 2016 at 3 MMb/d and decline is rapid falling below present output by 2019.



So we may see a Bakken + Eagle Ford increase of as much as 1.2 MMb/d by 2016, but 3 years later output from the EF and Bakken combined has fallen back to 1.6 MMb/d. We might also see an increase of 0.2 MMb/d by 2016 from the Niobrara play so we could see as much as a 1.4 MMb/d increase in tight oil output by 2016 (from the Bakken, Eagle Ford, and Niobrara.)

When all of the US is considered we will have the underlying decline of older wells (say about 5 MMb/d declining at 4 % per year) which amounts to 600 kb/d by 2016 and 1.1 MMb/d by 2019. So accounting for this, US output only increases by about 800 kb/d by 2016 and falls from there by 1.4 MMb/d due to the Bakken and EF decline and another 0.5 MMb/d from other US field decline to a level 1.3 MMb/d below current levels. Some of this might be offset by other tight oil plays (Granite Wash and Mississippian), but I think it is unlikely that we will be above 7.5 MMb/d of C+C output beyond 2019.

A nice discussion of the EIA's DPR can be found at http://peakoilbarrel.com/

Dennis

[ROCKMAN]

Several different ways to read this story IMHO. First, they could just be taking advantage of a seller’s market. Second, the plugging liability offshore ($370 million) plus the added risk of catastrophic loss due to hurricanes makes for valid exit motivation. Third, they see better potential for their onshore shale plays but those projects don’t provide enough loan basis to self-fund and thus the need to liquidate cash flow assets. And, in all likelihood IMHO, probably a combination of all three:

Reuters – Oil and gas producer SandRidge Energy Inc said it would sell its Gulf of Mexico operations to an affiliate of private equity firm Riverstone Holdings LLC for $750 million to focus on drilling onshore. Riverstone affiliate Fieldwood Energy LLC will also assume abandonment liabilities of $370 million. Most. SandRidge is the latest company to dispose its Gulf of Mexico assets, following Apache, Devon Energy Corp and Callon Petroleum Co. SandRidge said it would redeploy capital allocated to develop Gulf of Mexico into its mid-continent properties, including the Mississippian Oil Play of northern Oklahoma and western Kansas.

[ROCKMAN]

pstarr - Good points and I'll throw in one more: all the public oil companies in the US (and especially that home in Texas) that are desperate to find bookable reserves.

That picture brings back a bad memory: About 20 years ago I knew a guy that lost his right arm up to the elbow doing something similar. If I were running that location he wouldn’t be doing that. More often the little things are more likely to kill you on a drill site than a blowout. About two years ago a hand probably would have taken a swing at me if I hadn’t been standing there on my “polio” crutches. He was helping to off load casing from a truck. The fork lift operator would lift it and he didn’t move away from the drop zone. I told him he needed to move back a few yards every time. He did not care for my advice. So I asked him if he had heard what happened to another hand doing exactly what he was doing just a few weeks early and about 40 miles away. That hand was crushed to death when a joint of csg rolled off the fork lift on to him. The other hand working with him knew about that accident and told him it was true. The I looked at the second hand said “So you knew about that accident and didn’t say a f*cking thing?” Now I had two roustabouts pissed off at me. But don’t bother me none. LOL.

BTW: he didn’t say thanks but he did do as I told him. Everyone hears about the big blow outs like Macondo. Almost no one outside of the oil patch hears about all the other deaths and cripplings. Also FYI: the majority of oil patch hands killed on the job die in helicopter crashes.

[TheAntiDoomer]

wow, this new EIA graph speaks for itself!! Doomers will have a major sad!



Paging Mr. Berman, Paging Mr. Arty Berman.

[ROCKMAN]

The Utica Shale is showing some promise but more for NG than oil. The 245 wells mentioned below average 1,500 mcf/day and 60 bopd. Technically that makes it a gas well. But from a revenue stand point it represents a gross income of about $6,000/day for the NG and about the same for the oil. The Eagle Ford has an oil rich area but also a more NG prone area that produces similar to the Utica. Perhaps the Utica may develop a more significant oil prone section…time will tell.

Not sure if this is representative of the play but from one player: "The wells cost about $8.5 million each, although officials hope to reduce that by $2 million per well. The average lateral length was 5,800 feet. Those three Utica wells are out-producing the company’s first Marcellus wells, said spokesman Steven Schlotterbeck. The company has 14,000 net acres in the Utica shale." At $12,000/day gross and $8,500/day net it would take 2.6 years to pay out but only if the wells show zero decline which we know they won’t. So just like the Eagle Ford some wells (especially with higher oil yields) will be very profitable and some will be money losers. Difficult now to tell how those numbers will be split. It would also appear the Utica play is having the same problems the EFS and Bakken suffered early on: lack of NG processing infrastructure. But they continue to work on it.

Reuters - Natural gas output continued to outrun oil in Ohio's Utica shale in the third quarter of 2013, according to state data released last week from the nascent energy play. The first ever quarterly report from the Ohio Department of Natural Resources showed that 245 wells produced on average 14,500 barrels of oil per day and 370 million cubic feet of gas per day from July through September, much higher than the last recorded output from 2012. Then, oil output averaged 1,742 barrels per day and gas output was just 35 million cubic feet per day. The results are the first statewide indication of the Utica's progress since May last year when the 2012 data was released, and give an insight into an emerging boom region for gas development.

[FrY10cK]

$this->bbcode_second_pass_quote('TheAntiDoomer', 'w')ow, this new EIA graph speaks for itself!!

[ROCKMAN]

FrY10cK - I think a more pertinent question is what does a chart denoting NG production have to do with peak OIL? And why is it posted on a thread discussing OIL production? It even begs the question as to why NG production would even be brought into a discussion about its historic production rate. NG has been producing on a plateau between 20 and 25 TCF per year for the last 40 year with no sense of a peak in sight. And in fact for the last few years has risen to new historic heights. What does a non-existent peak in one commodity have to do with the potential peak of a completely different commodity?

I don't recall anyone here or elsewhere referring to PNG so I'm a tad confused why NG production would be used as a response to any discussion about PO. Am I wrong and oes anyone here feel we're at PNG? Just seems like a pointless distraction to mix apples with zebras..