Tag Archives: oil prices

GUNDLACH: If oil goes to $40 a barrel something is ‘very, very wrong with the world’

Jeffrey Gundlach

Jeff Gundlach – bond trader

West Texas Intermediate crude oil is at a 6-year low of $43 a barrel. 

And back in December 2014, “Bond King” Jeff Gundlach had a serious warning for the world if oil prices got to $40 a barrel.

“I hope it does not go to $40,” Gundlach said in a presentation, “because then something is very, very wrong with the world, not just the economy. The geopolitical consequences could be — to put it bluntly — terrifying.”

Writing in The Telegraph last week, Ambrose Evans-Pritchard noted that with Brent crude oil prices — the international benchmark — below $50 a barrel, only Norway’s government is bringing in enough revenue to balance their budget this year. 

And so in addition to the potential global instability created by low oil prices, Gundlach added that, “If oil falls to around $40 a barrel then I think the yield on ten year Treasury note is going to 1%.” The 10-year note, for its part, closed near 2.14% on Tuesday. 

On December 9, 2014, WTI was trading near $65 a barrel and Gundlach said oil looked like it was going lower, quipping that oil would find a bottom when it starts going up. 

WTI eventually bottomed at $43 in mid-March and spend most all of the spring and early summer trading near $60. 

On Tuesday, WTI hit a fresh 6-year low, plunging more than 4% and trading below $43 a barrel. 

WTI

In the last month, crude and the entire commodity complex have rolled over again as the market battles oversupply and a Chinese economy that is slowing.

And all this as the Federal Reserve makes noise about raising interest rates, having some in the market asking if these external factors — what the Fed would call “exogenous” factors — will stop the Fed from changing its interest rate policy for the first time in over almost 7 years. 

In an afternoon email, Russ Certo, a rate strategist at Brean Capital, highlighted Gundlach’s comments and said that the linkages between the run-up, and now collapse, in commodity prices since the financial crisis have made, quite simply, for an extremely complex market environment right now. 

“There is a global de-leveraging occurring in front of our eyes,” Certo wrote. “And, I suppose, the smart folks will determine the exact causes and translate what that means for FUTURE investment thesis. Today it may not matter other than accurately anticipating a myriad of global price movements in relation to each other.”

CRB commodity price index

Advertisements

Why U.S. Oil Production Remains High While Prices Tank – Bakken Update

Summary

  • US production remains high due to high-grading, well design, cost efficiencies, and lower oil service contracts.
  • High-grading from marginal to core areas can increase per well production from 200% to 500% depending on area, which means one core well can equate to several marginal producers.
  • Shorter stages, increased proppant and frac fluids increase production and flatten the depletion curve.
  • EOG’s work in Antelope field provides a framework for other operators to increase production while completing fewer wells.
  • Few operators are currently developing Mega-fracs, this provides significant upside to US shale production as others start producing more resource per foot.
by Michael Filloon, Split Rock Private Trading and Wealth Management

US Oil production remains at volumes seen when WTI was at $100/bbl. Many analysts believed operators couldn’t survive, but $60/bbl may be good enough for operators to drill economic wells. Oil prices have decreased significantly, and the US Oil ETF (NYSEARCA:USO) with it. Many were wrong about US production, and the belief $60/bbl oil would decrease US production. Although completions have been deferred, high-grading and mega-fracs have made up for fewer producing wells. When calculating US production going forward, it is important to account for the number of new completions. If more wells are completed, the higher the influx of production should be. We are finding the quality of geology and well design have a greater effect on total production than originally thought.

(click to enlarge)

(Source: Shaletrader.com)

There are several factors influencing US production. Operators have moved existing rigs to core areas. This decreases its ability getting acreage held by production. In the Bakken, rigs have moved near the Nesson Anticline.

In the Eagle Ford, Karnes seems to be the area of interest. Midland County in the Permian has also been attractive. Operators have decided to complete wells with better geology. When an operator completes wells in core acreage versus marginal leasehold, we see increased production per location. This is just part of the reason US production remains high.

The average investor does not understand the significance. Most think wells have like production, but areas are much different. When oil was at a $100/bbl, it allowed operators to get acreage held by production, although payback times were not as good. Marginal acreage was more attractive, even at lower IRRs. Operators have a significant investment in acreage, and do not want to lose it. Because of this, many would operate in the red expecting future rewards. Just because E&Ps lose money, does not mean the business isn’t economic. It is the way business is done in the short term as oil is an income stream. Wells produce for 35 to 40 years, and once well costs are paid back there are steady revenues. Changes in oil prices have changed this, as now operators will have to focus on better acreage.

Re-fracs are starting to influence production. Although most operators have not begun programs, interest is high. Re-fracs may not be a game changer, but could be an excellent way to increase production at a lower cost. This is not as significant with well designs of today, but older designs left a significant amount of resource. More importantly, when operators began, it was drilling the best acreage. Archaic well designs could leave some stages completely untouched. Current seismic can now identify this, and provide for a better re-frac. We expect to see some very good results in 2016. In conjunction with high-grading, well design continues to be the main reason production has maintained. Changes to well design have been significant, and the resulting production increases much better than anticipated.

No operator is better than EOG Resources (NYSE:EOG) at well design. From the Bakken, to the Eagle Ford and Permian it continues to outperform the competition.

The following map courtesy of ShaleMapsPro.com does a good job of illustrating EOG’s exposure in the Eagle Ford.

EagleFord.SeekingAlpha

(Source: Shalemapspro.com)

EOG’s focusing of frac jobs closer to the well bore has provided for much better source rock stimulation (fraccing). Since more fractures are created, there is a greater void in the shale. This means more producing rock has contact with the well. EOG continues to push more sand and fluids in the attempt to recover more resource per foot. To evaluate production, it must be broken into days over 6 to 12 months. To evaluate well design, locations must be close to one another and by the same operator. This consistency allows us to see advantages to well design changes. Lastly, we compare marginal acreage it is no longer working to the high-grading program. This is how operators are spending less and producing more.

EOG is working in the Antelope field of northeast McKenzie County. This is Bakken core acreage and considered excellent in both the middle Bakken and upper Three Forks.

(click to enlarge)
(Source: Welldatabase.com)

The center of the above map is the location of both its Riverview and Hawkeye wells. These six wells are located in two adjacent sections. The pad is just west of New Town in North Dakota. Riverview 100-3031H was completed in 6/12. It is an upper Three Forks well. 39 stages were used on an approximate 9000 foot lateral. 5.7 million pounds of sand were used with 85000 barrels of fluids.

(click to enlarge)
(Source: Welldatabase.com)

Date Oil (BBL) Gas ((NYSEMKT:MCF)) BOE
6/1/2012 4,384.00 3,972.00 3972
7/1/2012 27,133.00 15,337.00 15337
8/1/2012 24,465.00 17,223.00 17223
9/1/2012 21,457.00 9,190.00 9190
10/1/2012 18,040.00 12,601.00 12601
11/1/2012 19,924.00 13,366.00 13366
12/1/2012 28,134.00 22,259.00 22259
1/1/2013 15,382.00 12,661.00 12661
2/1/2013 3,429.00 2,451.00 2451
3/1/2013 15,242.00 22,774.00 22774
4/1/2013 15,761.00 8,479.00 8479
5/1/2013 13,786.00 18,372.00 18372
6/1/2013 14,485.00 18,555.00 18555
7/1/2013 15,668.00 27,250.00 27250
8/1/2013 12,084.00 23,876.00 23876
9/1/2013 13,841.00 46,815.00 46815
10/1/2013 11,388.00 45,800.00 45800
11/1/2013 2,711.00 10,533.00 10533
12/1/2013 0 0 0
1/1/2014 5,953.00 35 35
2/1/2014 11,368.00 20,851.00 20851
3/1/2014 8,784.00 11,179.00 11179
4/1/2014 5,607.00 8,479.00 8479
5/1/2014 4,727.00 5,663.00 5663
6/1/2014 8,359.00 12,726.00 12726
7/1/2014 8,799.00 22,957.00 22957
8/1/2014 7,958.00 31,621.00 31621
9/1/2014 7,218.00 44,318.00 44318
10/1/2014 3,778.00 14,058.00 14058
11/1/2014 3,701.00 9,951.00 9951
12/1/2014 6,612.00 18,435.00 18435
1/1/2015 6,181.00 24,142.00 24142
2/1/2015 3,517.00 10,722.00 10722
3/1/2015 5,218.00 24,175.00 24175
4/1/2015 4,275.00 24,233.00 24233

(Source: Welldatabase.com)

Riverview 100-3031H was a progressive well design for 2012. It produced well. To date it has produced 379 thousand bbls of crude and 615 thousand Mcf of natural gas. This equates to $24 million in revenues. Over the first 360 days (using the true number of production days) it produced 240,036 bbls of crude. The month of December 2013, this well was shut in for the completion of an adjacent well. There was a return to production but no significant jump in production from pressure generated by the new locations. This well declined 42% over 12 months. This is much lower than estimates shown through other well models. The next year we see a 35% decline. 10 months later we see an additional decline of approximately 55%. The decline curve of a well is very specific to geology and well design. Keep in mind averages are just that, and do not provide specific data. These averages should not be used to evaluation acreage and operator as there are wide average swings. Also, averages are generally over a long time frame. Production in the Bakken began in 2004 (first horizontal well completed). Wells in 2004 produce nothing like wells today. Updated averages based on year (IP 360) are more useful. Riverview 100-3031H was part of a two well pad. A middle Bakken well was also completed.

Riverview 4-3031H began producing a month after Riverview 100-3031H. It was a 38 stage 9000 foot lateral. 4.3 million lbs of sand were used and 69000 bbls of fluids.

(click to enlarge)
(Source: Welldatabase.com)

The Riverview and Hawkeye wells analyzed in this article were drilled in a southern fashion.

Date Oil Gas BOE
7/1/2012 20,529.00 12,537.00 12537
8/1/2012 16,553.00 16,903.00 16903
9/1/2012 17,096.00 10,148.00 10148
10/1/2012 23,197.00 17,914.00 17914
11/1/2012 20,122.00 14,402.00 14402
12/1/2012 27,340.00 33,217.00 33217
1/1/2013 16,044.00 24,394.00 24394
2/1/2013 4,267.00 4,946.00 4946
3/1/2013 27,516.00 26,219.00 26219
4/1/2013 20,792.00 7,940.00 7940
5/1/2013 17,516.00 35,948.00 35948
6/1/2013 15,457.00 50,500.00 50500
7/1/2013 13,480.00 50,807.00 50807
8/1/2013 11,254.00 42,300.00 42300
9/1/2013 9,319.00 40,341.00 40341
10/1/2013 8,559.00 33,116.00 33116
11/1/2013 2,190.00 40 40
12/1/2013 0 0 0
1/1/2014 1,124.00 11 11
2/1/2014 5,271.00 81 81
3/1/2014 8,931.00 9,827.00 9827
4/1/2014 5,469.00 7,940.00 7940
5/1/2014 4,807.00 5,748.00 5748
6/1/2014 8,522.00 13,819.00 13819
7/1/2014 7,982.00 17,983.00 17983
8/1/2014 7,169.00 26,755.00 26755
9/1/2014 5,750.00 22,586.00 22586
10/1/2014 1,349.00 3,194.00 3194
11/1/2014 6,495.00 15,947.00 15947
12/1/2014 6,442.00 18,806.00 18806
1/1/2015 5,840.00 22,126.00 22126
2/1/2015 4,171.00 18,682.00 18682
3/1/2015 4,221.00 18,539.00 18539
4/1/2015 3,878.00 19,725.00 19725

(Source: Welldatabase.com)

Riverview 4-3031H has produced 361 thousand bbls of crude and 657 thousand Mcf of natural gas. It under produced Riverview 100-3031H, but this is consistent with well design. 360 day production totaled 237,735 bbls of oil. We do not know if the Three Forks is a better pay zone than the middle Bakken as the well design was not consistent. Most operators have reported better results from the middle Bakken. The Three Forks well used one more stage (less feet per stage should mean better fracturing). It also used significantly more sand and fluids. Either way both wells were good results. Riverview 4-3031H only declined approximately 36% in a comparison of the first month to month 12. This was 7% better than 100-3031H. It declined another 41% in year two on a month to month comparison. This was 6% greater. 56% was seen when compared to adjusted production for 5/15. The Three Forks well declines slower in later production than 4-3031H. This may be due to well design. The well with more stages, proppant and fluids continues to out produce the Bakken well. It is possible the source rock is better. There are many other variables to look at, but this data provides why EOG continues to push ahead with more complex locations.

In September of 2012, EOG drilled its next well in this area. Hawkeye 100-2501H is a 13700 foot lateral targeting the upper Three Forks. It is a 47 stage frac. 14 million pounds of sand were used with 158000 bbls of fluids.

(click to enlarge)
(Source: Welldatabase.com)

Of the three pads, this well is located in the center. It was an interesting design, given the length of the lateral.

Date Oil Gas BOE
9/1/2012 21,959.00 444 444
10/1/2012 54,927.00 155 155
11/1/2012 47,557.00 57,300.00 57300
12/1/2012 55,367.00 92,144.00 92144
1/1/2013 33,396.00 55,877.00 55877
2/1/2013 22,100.00 32,810.00 32810
3/1/2013 36,631.00 57,544.00 57544
4/1/2013 29,075.00 32,696.00 32696
5/1/2013 22,210.00 33,351.00 33351
6/1/2013 17,544.00 25,794.00 25794
7/1/2013 15,872.00 23,600.00 23600
8/1/2013 19,647.00 28,746.00 28746
9/1/2013 15,486.00 22,352.00 22352
10/1/2013 21,325.00 31,678.00 31678
11/1/2013 6,418.00 9,214.00 9214
12/1/2013 0 0 0
1/1/2014 0 0 0
2/1/2014 0 0 0
3/1/2014 29,699.00 23,822.00 23822
4/1/2014 39,782.00 32,696.00 32696
5/1/2014 35,267.00 61,543.00 61543
6/1/2014 27,554.00 49,551.00 49551
7/1/2014 7,229.00 12,565.00 12565
8/1/2014 31,155.00 98,086.00 98086
9/1/2014 12,617.00 32,742.00 32742
10/1/2014 2 4 4
11/1/2014 7,769.00 15,996.00 15996
12/1/2014 15,487.00 49,147.00 49147
1/1/2015 4,427.00 9,918.00 9918
2/1/2015 9,344.00 20,654.00 20654
3/1/2015 8,459.00 25,171.00 25171
4/1/2015 7,235.00 24,752.00 24752

(Source: Welldatabase.com)

Hawkeye 100-2501H had some excellent early production numbers. From that perspective, it is one of the best wells to date in the Bakken. It has already produced 655,000 bbls of crude and 960,000 Mcf of natural gas. It has revenues in excess of $42 million to date. This includes roughly four non-producing or unproductive months. Crude production over the first 360 days was 389,835 bbls. Over the first 12 months, this well produced crude revenues in excess of $23 million. Decline rates were higher, as the first full month of production declined 65% over the first year. This isn’t important as early production rates were some of the highest seen in North Dakota. It is important to note, decline rates are emphasized but higher pressured wells may deplete faster depending on choke and how quickly production is propelled up and out of the wellbore. Any well that produces very well initially will have higher decline rates, but this does not lessen the value of the well. This specific well is depleting faster, but no one is complaining about payback times well under a year. Decline rates decrease significantly in year two at 11%. This well saw a marked increase in production when adjacent wells were turned to sales. The additional pressure associated with well communication increased production from 20,000 bbls/month to 35,000 bbls/month on average. This occurred over a 6 month period.

(click to enlarge)
(Source: Welldatabase.com)

Hawkeye 102-2501H was the fourth completion. This 14,000 foot 62 stage lateral targeted the upper Three Forks. It used 14.5 million pounds of sand and 164,000 bbls of fluids.

Date Oil Gas BOE
1/1/2013 18,486.00 41 41
2/1/2013 27,120.00 8,705.00 8705
3/1/2013 39,702.00 15,748.00 15748
4/1/2013 17,714.00 30,501.00 30501
5/1/2013 41,368.00 57,489.00 57489
6/1/2013 26,602.00 34,399.00 34399
7/1/2013 0 0 0
8/1/2013 133 0 0
9/1/2013 0 0 0
10/1/2013 0 0 0
11/1/2013 0 0 0
12/1/2013 0 0 0
1/1/2014 5,163.00 6,403.00 6403
2/1/2014 41,917.00 74,353.00 74353
3/1/2014 36,439.00 18,111.00 18111
4/1/2014 19,477.00 30,501.00 30501
5/1/2014 26,388.00 43,071.00 43071
6/1/2014 27,480.00 49,456.00 49456
7/1/2014 14,529.00 33,072.00 33072
8/1/2014 24,542.00 62,753.00 62753
9/1/2014 17,613.00 53,460.00 53460
10/1/2014 17,451.00 66,544.00 66544
11/1/2014 9,634.00 33,366.00 33366
12/1/2014 16,338.00 76,547.00 76547
1/1/2015 11,450.00 65,277.00 65277
2/1/2015 8,971.00 50,919.00 50919
3/1/2015 3,177.00 14,820.00 14820
4/1/2015 6,495.00 13,616.00 13616

(Source: Welldatabase.com)

It has produced 458,000 bbls of crude and 839,000 Mcf to date. This equates to roughly $30 million over well life. 360 day production was 394,673 bbls of crude. Production was interesting as initial production was outstanding. The big production numbers were hindered as many of the early months had missed production days. We don’t know if there were production problems, but do know the well was shut when adjacent wells were turned to sales. Production was over 1000 bbls/d over the first six months. It was shut in for another six months. After this production jumped, but this is misleading. Given the fewer days of production per month, there wasn’t much of an increase when the new wells were turned to sales. The decline over the first year on a monthly basis is 20%. The second year is much greater at 80%. We have seen recent production decrease significantly, and is something to watch. Lower decline rates initially are more important. This is because production rates are higher. It equates to greater total production.

Hawkeye 01-2501H was completed in January of 2013.

(click to enlarge)
(Source: Welldatabase.com)

It is a 64 stage, 15000 foot lateral targeting the middle Bakken. This well used 172,000 bbls of fluids and 15 million pounds of sand.

Date Oil Gas BOE
1/1/2013 18,792.00 43 43
2/1/2013 30,211.00 13,879.00 13879
3/1/2013 42,037.00 17,648.00 17648
4/1/2013 17,433.00 36,881.00 36881
5/1/2013 38,754.00 63,501.00 63501
6/1/2013 28,602.00 48,817.00 48817
7/1/2013 0 0 0
8/1/2013 134 1 1
9/1/2013 0 0 0
10/1/2013 0 0 0
11/1/2013 0 0 0
12/1/2013 0 0 0
1/1/2014 6,311.00 7,186.00 7186
2/1/2014 43,713.00 74,099.00 74099
3/1/2014 39,156.00 18,492.00 18492
4/1/2014 23,408.00 36,881.00 36881
5/1/2014 21,681.00 33,498.00 33498
6/1/2014 28,502.00 51,543.00 51543
7/1/2014 18,795.00 45,017.00 45017
8/1/2014 25,512.00 58,837.00 58837
9/1/2014 20,522.00 60,662.00 60662
10/1/2014 19,137.00 68,576.00 68576
11/1/2014 12,093.00 37,043.00 37043
12/1/2014 16,587.00 45,980.00 45980
1/1/2015 14,246.00 62,819.00 62819
2/1/2015 9,220.00 35,931.00 35931
3/1/2015 3,617.00 6,634.00 6634
4/1/2015 13,702.00 42,551.00 42551

(Source: Welldatabase.com)

It has produced 492,170 bbls of crude and 866,520 Mcf of natural gas. 360 day production was 412,072 bbls of oil.

(click to enlarge)
(Source: Welldatabase.com)

This is an excellent well, but the location of focus is Hawkeye 02-2501H. It was completed last in this group. This well provides the link between changes in well design to production improvements.

Date Oil Gas BOE
12/1/2013 3,022.00 6,533.00 6533
1/1/2014 37,385.00 75,940.00 75940
2/1/2014 30,066.00 58,949.00 58949
3/1/2014 22,876.00 50,690.00 50690
4/1/2014 26,703.00 43,926.00 43926
5/1/2014 31,987.00 55,124.00 55124
6/1/2014 27,777.00 47,166.00 47166
7/1/2014 31,500.00 50,279.00 50279
8/1/2014 51,709.00 99,583.00 99583
9/1/2014 43,292.00 98,069.00 98069
10/1/2014 40,143.00 98,927.00 98927
11/1/2014 24,064.00 50,495.00 50495
12/1/2014 31,488.00 99,684.00 99684
1/1/2015 27,087.00 94,621.00 94621
2/1/2015 22,207.00 94,490.00 94490
3/1/2015 22,590.00 125,634.00 125634
4/1/2015 17,707.00 94,910.00 94910

(Source: Welldatabase.com)

The production numbers are significant. In less than a year and a half, it has produced 490,000 bbls of crude and 1.25 Bcf of natural gas. Revenues to date are $33.2 million. Its 360 day crude production was 427,663 bbls. The production is impressive but the decline curve is more important. This Hawkeye well has a steady production rate with only a slight decline. This is where the analysts may be getting it wrong, as decline curves change significantly by area and well design. What EOG has done is not only increased production significantly, but also flattened the curve. Initial production is interesting as we don’t see peak production until nine months. This means our best month is August of 2014, and not the first full month. When we analyze the production after one full year of production, there is no drop off.

This 12800 foot 69 stage lateral is a very good middle Bakken design. EOG decided to pull back some of the lateral length. There are several possible reasons for this. We think it is possible EOG has discovered it was having difficulty in getting proppant to the toe of the well. But this is why operators test the length. More importantly, the increase in stages in conjunction with a shorter lateral provides for shorter stages. This means the operator will probably do a better job of stimulating the source rock. This well also used massive volumes of fluids and sand. 460,000 bbls of fluids were used with over 27 million lbs of proppant. I don’t normally break down the types of sand, as it can be trivial to some but in this case I have as the design seems somewhat unique. This well used approximately 16 million lbs of 100 mesh sand, 7 million lbs of 30/70 and 4 million 40/70. The large volumes of mesh sand are interesting. It would seem EOG is trying to push the finest sand deep into the fractures to maintain deeper shale production.

Well Date Lateral Ft. Stages Proppant Lbs. Fluids Bbls. 12 mo. Oil Production Bbls. Production/Ft.
Riverview 100-3031H 6/12 9,000 39 5.7M 85,000 240,036 26.67
Riverview 4-3031H 7/12 9,000 38 4.3M 69,000 237,735 26.42
Hawkeye 100-2501H 9/12 13,700 47 14M 158,000 389,835 28.46
Hawkeye 102-2501H 1/13 14,000 62 14.5M 164,000 394,673 28.19
Hawkeye 01-2501H 1/13 15,000 64 15M 172,000 412,072 27.47
Hawkeye 02-2501H 12/13 12,800 69 27M 460,000 427,663 33.41

I completed the above table for several reasons. The first was to show well design’s effect on one year total production. We used 360 days as a base. We didn’t use 12 months as that will skew data, as some wells don’t produce every day of every month. Wells are shut in for service or more importantly when new production from adjacent locations are turned to sales. So these are a specific number of days and not estimates. We also broke down production per foot of lateral. This may be more important than any other factor. Production per well is important, but lateral length is a key as it shows how well the source rock was stimulated. In reality, production per foot matters more at longer lateral lengths. Many operators don’t like to do laterals longer than 10,000 feet, as production per foot decreases sharply. When looking at well production data, it is obvious that production per foot suffers as the toe of the lateral gets farther from the vertical.

There are several other ETFs that focus on U.S. and world crude prices:

  • iPath S&P Crude Oil Total Return Index ETN (NYSEARCA:OIL)
  • ProShares Ultra Bloomberg Crude Oil ETF (NYSEARCA:UCO)
  • VelocityShares 3x Long Crude Oil ETN (NYSEARCA:UWTI)
  • ProShares Ultrashort Bloomberg Crude Oil ETF (NYSEARCA:SCO)
  • U.S. Brent Oil ETF (NYSEARCA:BNO)
  • PowerShares DB Oil ETF (NYSEARCA:DBO)
  • VelocityShares 3x Inverse Crude Oil ETN (NYSEARCA:DWTI)
  • PowerShares DB Crude Oil Double Short ETN (NYSEARCA:DTO)
  • U.S. 12 Month Oil ETF (NYSEARCA:USL)
  • U.S. Short Oil ETF (NYSEARCA:DNO)
  • PowerShares DB Crude Oil Long ETN (NYSEARCA:OLO)
  • PowerShares DB Crude Oil Short ETN (NYSEARCA:SZO)
  • iPath Pure Beta Crude Oil ETN (NYSEARCA:OLEM)

All six wells had fantastic results. The first two Riverview wells are still considered sand heavy fracs and produced almost a quarter of a million barrels of oil. This does not include natural gas in the estimates, but EURs for these wells are approximately 1200 MBo. We don’t put much emphasis on EURs other than an indicator of how good production is in comparison. Since locations will produce from 35 to 40 years, we are more inclined to emphasize one year production. Although the Hawkeye wells drilled on 9/12 and 1/13 didn’t show a large uptick in production per foot, it is still quite impressive considering the lateral length. Overall production uplift was exceptional, and these wells produce decent payback times at current oil price realizations.

There is no doubt this area has superior geology. It is definitely a core area, but may not be as good as Parshall field. Because of this, we know other areas would not produce as well, but still it provides a decent comparison for the upside to well design. Geology is still key and this is probably why EOG recently drilled a 15 well pad in the same general area. These wells are still in confidential status, so we do not know the outcome. Given the results in this area, these wells could be very interesting. The most important reason to focus on these Mega-Fracs is repeatability. If EOG can do this, so can other operators. Our expectations are many operators will be able to complete wells this good within the next 12 to 24 months. If this occurs we could see production maintained at much lower prices and fewer completions.

US Oil Rig Count Decline Quickened This Week

Idle rigs in Helmerich & Payne International Drilling Co.'s yard in Ector County, Texas. North Dakota has also been hit hard, forcing gains in technology.

Source: Rigzone

The fall in U.S. rigs drilling for oil quickened a bit this week, data showed on Friday, suggesting a recent slowdown in the decline in drilling was temporary, after slumping oil prices caused energy companies to idle half the country’s rigs since October.

Drillers idled 31 oil rigs this week, leaving 703 rigs active, after taking 26 and 42 rigs out of service in the previous two weeks, oil services firm Baker Hughes Inc said in its closely watched report.

With the oil rig decline this week, the number of active rigs has fallen for a record 20 weeks in a row to the lowest since 2010, according to Baker Hughes data going back to 1987.
Since the number of oil rigs peaked at 1,609 in October, energy producers have responded quickly to the steep 60 percent drop in oil prices since last summer by cutting spending, eliminating jobs and idling rigs.

After its precipitous drop since October, the U.S. oil rig count is nearing a pivotal level that experts say could dent production, bolster prices and even coax oil companies back to the well pad in the coming months.

https://jafrianews.files.wordpress.com/2015/04/shia-houthi-threatens-to-attack-saudi-arabia-it-air-strikes-continue.jpg?w=296&h=166

Pioneer Natural Resources Co, a top oil producer in the Permian Basin of West Texas, said this week it will start adding rigs in June as long as market conditions are favorable. U.S. crude futures this week climbed to over $58 a barrel, the highest level this year, as a Saudi-led coalition continued bombings in Yemen.

That was up 38 percent from a six-year low near $42 set in mid March on oversupply concerns and lackluster demand, in part on expectations the lower rig count will start reducing U.S. oil output.

After rising mostly steadily since 2009, U.S. oil production has stalled near 9.4 million barrels a day since early March, the highest level since the early 1970s, according to government data.

The Permian Basin in West Texas and eastern New Mexico, the nation’s biggest and fastest-growing shale oil basin, lost the most oil rigs, down 13 to 242, the lowest on record, according to data going back to 2011.

Texas was the state with the biggest rig decline, down 19 to 392, the least since 2009.
In Canada, active oil rigs fell by four to 16, the lowest since 2009. U.S. natural gas rigs, meanwhile, climbed by eight to 225, the same as two weeks ago.

One Third Of U.S. Companies’ Q1 Job Cuts Due To Oil Prices

https://i2.wp.com/www.jobcutnews.com/wp-content/uploads/2011/10/pink-slips.jpgby Olivia Pulsinelli

Oil prices caused one-third of the job cuts that U.S.-based companies announced in the first quarter, according to a new report. March was the fourth month in a row to record a year-over-year increase in job cuts, Chicago-based outplacement consultancy Challenger, Gray & Christmas Inc. reports. And 47,610 of the 140,214 job cuts announced between January and March were directly attributed to falling oil prices. Not surprisingly, the energy sector accounted for 37,811 of the job cuts — up a staggering 3,900 percent from the same quarter a year earlier, when 940 energy jobs were cut. However, U.S. energy firms only announced 1,279 job cuts in March, down about 92 percent from the 16,339 announced in February and down nearly 94 percent from the 20,193 announced in January. The trend held true in Houston, where several energy employers announced job cuts in January and February, while fewer cuts were announced in March. Overall job-cut announcements are declining, as well. U.S. employers announced 36,594 job cuts in March, down 27.6 percent from the 50,579 announced in February and down 31 percent from the 53,041 announced in January. In December, 32,640 job cuts were announced. “Without these oil related cuts, we could have been looking one of lowest quarters for job-cutting since the mid-90s when three-month tallies totaled fewer than 100,000. However, the drop in the price of oil has taken a significant toll on oil field services, energy providers, pipelines, and related manufacturing this year,” John Challenger, CEO of Challenger, Gray & Christmas, said in a statement.

The U.S. Oil Boom Is Moving To A Level Not Seen In 45 Years

by Myra P. Saefong

Peak U.S. oil production is a ‘moving target’

SAN FRANCISCO (MarketWatch) — U.S. oil production is on track to reach an annual all-time high by September of this year, according to Rystad Energy. If production does indeed top out, then supply levels may soon hit a peak as well. That, in turn, could lead to shrinking supplies. The oil-and-gas consulting-services firm estimates an average 2015 output of 9.65 million barrels a day will be reached in five months — topping the previous peak annual reading of 9.64 million barrels a day in 1970. Coincidentally, the nation’s crude inventories stand at a record 471.4 million barrels, based on data from U.S. Energy Information Administration, also going back to the 1970s. The staggering pace of production from shale drilling and hydraulic fracturing have been blamed for the 46% drop in crude prices CLK5, -1.08% last year. But reaching so-called peak production may translate into a return to higher oil prices as supplies begin to thin.

Rystad Energy’s estimate includes crude oil and lease condensate (liquid hydrocarbons that enter the crude-oil stream after production), and assumes an average price of $55 for West Texas Intermediate crude oil. May WTI crude settled at $49.14 a barrel on Friday. The forecast peak production level in September is also dependent on horizontal oil rig counts for Bakken, Eagle Ford and Permian shale plays stabilizing at 400 rigs, notes Per Magnus Nysveen, senior partner and head of analysis at Rystad. Of course, in this case, hitting peak production isn’t assured. “Some will be debating whether the U.S. has reached its peak production for the current boom, without addressing the question of what level will U.S. production climb to in any future booms,” said Charles Perry, head of energy consultant Perry Management. “So one might also say U.S. peak production is a moving target.” James Williams, an energy economist at WTRG Economics, said that by his calculations, peak production may have already happened or may occur this month, since the market has seen a decline in North Dakota production, with Texas expected to follow.

Permian Basin Idles Five Rigs This Week

by Trevor Hawes

Drilling rig

The number of rigs exploring for oil and natural gas in the Permian Basin decreased five this week to 285, according to the weekly rotary rig count released Thursday by Houston-based oilfield services company Baker Hughes.

The North American rig count was released a day early this week because of the Good Friday holiday, according to the Baker Hughes website.

District 8 — which includes Midland and Ector counties — shed four rigs, bringing the total to 180. The district’s rig count is down 42.68 percent on the year. The Permian Basin is down 46.23 percent.

At this time last year, the Permian Basin had 524 rigs.

TEXAS

Texas’ count fell six this week, leaving 456 rigs statewide.

In other major Texas basins, there were 137 rigs in the Eagle Ford, unchanged; 29 in the Haynesville, down three; 23 in the Granite Wash, down one; and six in the Barnett, unchanged.

Texas had 877 rigs a year ago this week.

UNITED STATES

The number of rigs in the U.S. decreased 20 this week, bringing the nationwide total to 1,028.

There were 802 oil rigs, down 11; 222 natural gas rigs, down 11; and four rigs listed as miscellaneous, up two.

By trajectory, there were 136 vertical rigs, down eight; 799 horizontal rigs, down 13; and 93 directional rigs, up one. The last time the horizontal rig count fell below 800 was the week ending June 4, 2010, when Baker Hughes reported 798 rigs.

There were 993 rigs on land, down 17; four in inland waters, unchanged; and 31 offshore, down three. There were 29 rigs in the Gulf of Mexico, down four.

The U.S. had 1,818 rigs at this time last year.

TOP 5s

The top five states by rig count this week were Texas; Oklahoma with 129, down four; North Dakota with 90, down six; Louisiana with 67, down five; and New Mexico with 51, unchanged.

The top five rig counts by basin were the Permian; the Eagle Ford; the Williston with 91, down six; the Marcellus with 70, unchanged; and the Cana Woodford and Mississippian with 40 each. The Mississippian idled three rigs, while the Cana Woodford was unchanged. The Cana Woodford shale play is located in central Oklahoma.

CANADA AND NORTH AMERICA

The number of rigs operating in Canada fell 20 this week to 100. There were 20 oil rigs, up two; 80 natural gas rigs, down 22; and zero rigs listed as miscellaneous, unchanged.

The last time Canada’s rig count dipped below 100 was the week ending May 29, 2009, when 90 rigs were reported.

Canada had 235 rigs at this time last year.

The total number of rigs in the North America region fell 40 this week to 1,128. North America had 2,083 rigs a year ago this week.

The “Revolver Raid” Arrives: A Wave Of Shale Bankruptcies Has Just Been Unleashed

by Tyler Durden

Back in early 2007, just as the first cracks of the bursting housing and credit bubble were becoming visible, one of the primary harbingers of impending doom was banks slowly but surely yanking availability (aka “dry powder”) under secured revolving credit facilities to companies across America. This also was the first snowflake in what would ultimately become the lack of liquidity avalanche that swept away Lehman and AIG and unleashed the biggest bailout of capitalism in history. Back then, analysts had a pet name for banks calling CFOs and telling them “so sorry, but your secured credit availability has been cut by 50%, 75% or worse” – revolver raids.Well, the infamous revolver raids are back. And unlike 7 years ago when they initially focused on retail companies as a result of the collapse in consumption burdened by trillions in debt, it should come as no surprise this time the sector hit first and foremost is energy, whose “borrowing availability” just went poof as a result of the very much collapse in oil prices.
As Bloomberg reports, “lenders are preparing to cut the credit lines to a group of junk-rated shale oil companies by as much as 30 percent in the coming days, dealing another blow as they struggle with a slump in crude prices, according to people familiar with the matter.

 

Sabine Oil & Gas Corp. became one of the first companies to warn investors that it faces a cash shortage from a reduced credit line, saying Tuesday that it raises “substantial doubt” about the company’s ability to continue as a going concern.

It’s going to get worse: “About 10 firms are having trouble finding backup financing, said the people familiar with the matter, who asked not to be named because the information hasn’t been announced.”

Why now? Bloomberg explains that “April is a crucial month for the industry because it’s when lenders are due to recalculate the value of properties that energy companies staked as loan collateral. With those assets in decline along with oil prices, banks are preparing to cut the amount they’re willing to lend. And that will only squeeze companies’ ability to produce more oil.

Those loans are typically reset in April and October based on the average price of oil over the previous 12 months. That measure has dropped to about $80, down from $99 when credit lines were last reset.

That represents billions of dollars in reduced funding for dozens of companies that relied on debt to fund drilling operations in U.S. shale basins, according to data compiled by Bloomberg.

“If they can’t drill, they can’t make money,” said Kristen Campana, a New York-based partner in Bracewell & Giuliani LLP’s finance and financial restructuring groups. “It’s a downward spiral.”

As warned here months ago, now that shale companies having exhausted their ZIRP reserves which are largely unsecured funding, it means that once the secured capital crunch arrives – as it now has – it is truly game over, and it is just a matter of months if not weeks before the current stakeholders hand over the keys to the building, or oil well as the case may be, over to either the secured lenders or bondholders.

The good news is that unlike almost a decade ago, this time the news of impending corporate doom will come nearly in real time: “Publicly traded firms are required to disclose such news to investors within four business days, under U.S. Securities and Exchange Commission rules. Some of the companies facing liquidity shortfalls will also disclose that they have fully drawn down their revolving credit lines like Sabine, according to one of the people.”

Speaking of Sabine, its day of reckoning has arrived

Sabine, the Houston-based exploration and production company that merged with Forest Oil Corp. last year, told investors Tuesday that it’s at risk of defaulting on $2 billion of loans and other debt if its banks don’t grant a waiver.

Another company is Samson Resource, which said in a filing on Tuesday that it might have to file for a Chapter 11 bankruptcy protection if the company is unable to refinance its debt obligations. And unless oil soars in the coming days, it won’t. 

 

Its borrowing base may be reduced due to weak oil and gas prices, requiring the company to repay a portion of its credit line, according to a regulatory filing on Tuesday. That could “result in an event of default,” Tulsa, Oklahoma-based Samson said in the filing.

Indicatively, Samson Resources, which was acquired in a $7.2-billion deal in 2011 by a team of investors led by KKR & Co, had a total debt of $3.9 billion as of Dec. 31. It is unlikely that its sponsors will agree to throw in more good money after bad in hopes of delaying the inevitable.

The revolver raids explain the surge in equity and bond issuance seen in recent weeks:

Many producers have been raising money in recent weeks in anticipation of the credit squeeze, selling shares or raising longer-term debt in the form of junk bonds or loans.

Energy companies issued more than $11 billion in stock in the first quarter, more than 10 times the amount from the first three months of last year, Bloomberg data show. That’s the fastest pace in more than a decade.

Breitburn Energy Partners LP announced a $1 billion deal with EIG Global Energy Partners earlier this week to help repay borrowings on its credit line. EIG, an energy-focused private equity investor in Washington, agreed to buy $350 million of Breitburn’s convertible preferred equity and $650 million of notes, Breitburn said in a March 29 statement.

Unfortunately, absent an increase in the all important price of oil, at this point any incremental dollar thrown at US shale companies is a dollar that will never be repaid.

Finally, speaking of Samson, its imminent bankruptcy should not come as a surprise. Back in January we laid out the shale companies which will file for bankruptcy first. The recent KKR LBO was one of them.

Many more to come as the countdown to the day of reckoning for the US shale sector has just about run out.

Junk-Rated Oil & Gas Companies in a “Liquidity Death Spiral”

by Wolf Richter

https://ashwinikumar007.files.wordpress.com/2011/06/blackmoney.jpg?w=355&h=284

On the face of it, the oil price appears to be stabilizing. What a precarious balance it is, however.

Behind the facade of stability, the re-balancing triggered by the price collapse has yet to run its course, and it might be overly optimistic to expect it to proceed smoothly. Steep drops in the US rig count have been a key driver of the price rebound. Yet US supply so far shows precious little sign of slowing down. Quite to the contrary, it continues to defy expectations.

So said the International Energy Agency in its Oil Market Report on Friday. West Texas Intermediate plunged over 4% to $45 a barrel.

The boom in US oil production will continue “to defy expectations” and wreak havoc on the price of oil until the power behind the boom dries up: money borrowed from yield-chasing investors driven to near insanity by the Fed’s interest rate repression. But that money isn’t drying up yet – except at the margins.

Companies have raked in 14% more money from high-grade bond sales so far this year than over the same period in 2014, according to LCD. And in 2014 at this time, they were 27% ahead of the same period in 2013. You get the idea.

Even energy companies got to top off their money reservoirs. Among high-grade issuers over just the last few days were BP Capital, Valero Energy, Sempra Energy, Noble, and Helmerich & Payne. They’re all furiously bringing in liquidity before it gets more expensive.

In the junk-bond market, bond-fund managers are chasing yield with gusto. Last week alone, pro-forma junk bond issuance “ballooned to $16.48 billion, the largest weekly tally in two years,” the LCD HY Weekly reported. Year-to-date, $79.2 billion in junk bonds have been sold, 36% more than in the same period last year.

But despite this drunken investor enthusiasm, the bottom of the energy sector – junk-rated smaller companies – is falling out.

Standard & Poor’s rates 170 bond issuers that are engaged in oil and gas exploration & production, oil field services, and contract drilling. Of them, 81% are junk rated – many of them deep junk. The oil bust is now picking off the smaller junk-rated companies, one after the other, three of them so far in March.

On March 3, offshore oil-and-gas contractor CalDive that in 2013 still had 1,550 employees filed for bankruptcy. It’s focused on maintaining offshore production platforms. But some projects were suspended last year, and lenders shut off the spigot.

On March 8, Dune Energy filed for bankruptcy in Austin, TX, after its merger with Eos Petro collapsed. It listed $144 million in debt. Dune said that it received $10 million Debtor in Possession financing, on the condition that the company puts itself up for auction.

On March 9, BPZ Resources traipsed to the courthouse in Houston to file for bankruptcy, four days after I’d written about its travails; it had skipped a $60 million payment to its bondholders [read… “Default Monday”: Oil & Gas Companies Face Their Creditors].

And more companies are “in the pipeline to be restructured,” LCD reported. They all face the same issues: low oil and gas prices, newly skittish bond investors, and banks that have their eyes riveted on the revolving lines of credit with which these companies fund their capital expenditures. Being forever cash-flow negative, these companies periodically issue bonds and use the proceeds to pay down their revolver when it approaches the limit. In many cases, the bank uses the value of the company’s oil and gas reserves to determine that limit.

If the prices of oil and gas are high, those reserves have a high value. It those prices plunge, the borrowing base for their revolving lines of credit plunges. S&P Capital IQ explained it this way in its report, “Waiting for the Spring… Will it Recoil”:

Typically, banks do their credit facility redeterminations in April and November with one random redetermination if needed. With oil prices plummeting, we expect banks to lower their price decks, which will then lead to lower reserves and thus, reduced borrowing-base availability.

April is coming up soon. These companies would then have to issue bonds to pay down their credit lines. But with bond fund managers losing their appetite for junk-rated oil & gas bonds, and with shares nearly worthless, these companies are blocked from the capital markets and can neither pay back the banks nor fund their cash-flow negative operations. For many companies, according to S&P Capital IQ, these redeterminations of their credit facilities could lead to a “liquidity death spiral.”

Alan Holtz, Managing Director in AlixPartners’ Turnaround and Restructuring group told LCD in an interview:

We are already starting to see companies that on the one hand are trying to work out their operational problems and are looking for financing or a way out through the capital markets, while on the other hand are preparing for the events of contingency planning or bankruptcy.

Look at BPZ Resources. It wasn’t able to raise more money and ended up filing for bankruptcy. “I think that is going to be a pattern for many other companies out there as well,” Holtz said.

When it trickled out on Tuesday that Hercules Offshore, which I last wrote about on March 3, had retained Lazard to explore options for its capital structure, its bonds plunged as low as 28 cents on the dollar. By Friday, its stock closed at $0.41 a share.

When Midstates Petroleum announced that it had hired an interim CEO and put a restructuring specialist on its board of directors, its bonds got knocked down, and its shares plummeted 33% during the week, closing at $0.77 a share on Friday.

When news emerged that Walter Energy hired legal counsel Paul Weiss to explore restructuring options, its first-lien notes – whose investors thought they’d see a reasonable recovery in case of bankruptcy – dropped to 64.5 cents on the dollar by Thursday. Its stock plunged 63% during the week to close at $0.33 a share on Friday.

Numerous other oil and gas companies are heading down that path as the oil bust is working its way from smaller more vulnerable companies to larger ones. In the process, stockholders get wiped out. Bondholders get to fight with other creditors over the scraps. But restructuring firms are licking their chops, after a Fed-induced dry spell that had lasted for years.

Investors Crushed as US Natural Gas Drillers Blow Up

by Wolf Richter

The Fed speaks, the dollar crashes. The dollar was ripe. The entire world had been bullish on it. Down nearly 3% against the euro, before recovering some. The biggest drop since March 2009. Everything else jumped. Stocks, Treasuries, gold, even oil.

West Texas Intermediate had been experiencing its biggest weekly plunge since January, trading at just above $42 a barrel, a new low in the current oil bust. When the Fed released its magic words, WTI soared to $45.34 a barrel before re-sagging some. Even natural gas rose 1.8%. Energy related bonds had been drowning in red ink; they too rose when oil roared higher. It was one heck of a party.

But it was too late for some players mired in the oil and gas bust where the series of Chapter 11 bankruptcy filings continues. Next in line was Quicksilver Resources.

It had focused on producing natural gas. Natural gas was where the fracking boom got started. Fracking has a special characteristic. After a well is fracked, it produces a terrific surge of hydrocarbons during first few months, and particularly on the first day. Many drillers used the first-day production numbers, which some of them enhanced in various ways, in their investor materials. Investors drooled and threw more money at these companies that then drilled this money into the ground.

But the impressive initial production soon declines sharply. Two years later, only a fraction is coming out of the ground. So these companies had to drill more just to cover up the decline rates, and in order to drill more, they needed to borrow more money, and it triggered a junk-rated energy boom on Wall Street.

At the time, the price of natural gas was soaring. It hit $13 per million Btu at the Henry Hub in June 2008. About 1,600 rigs were drilling for gas. It was the game in town. And Wall Street firms were greasing it with other people’s money. Production soared. And the US became the largest gas producer in the world.

https://martinhladyniuk.files.wordpress.com/2015/03/be197-deathspiral2.jpg?w=287&h=191

But then the price began to plunge. It recovered a little after the Financial Crisis but re-plunged during the gas “glut.” By April 2012, natural gas had crashed 85% from June 2008, to $1.92/mmBtu. With the exception of a few short periods, it has remained below $4/mmBtu – trading at $2.91/mmBtu today.

Throughout, gas drillers had to go back to Wall Street to borrow more money to feed the fracking orgy. They were cash-flow negative. They lost money on wells that produced mostly dry gas. Yet they kept up the charade. They aced investor presentations with fancy charts. They raved about new technologies that were performing miracles and bringing down costs. The theme was that they would make their investors rich at these gas prices.

The saving grace was that oil and natural-gas liquids, which were selling for much higher prices, also occur in many shale plays along with dry gas. So drillers began to emphasize that they were drilling for liquids, not dry gas, and they tried to switch production to liquids-rich plays. In that vein, Quicksilver ventured into the oil-rich Permian Basin in Texas. But it was too little, too late for the amount of borrowed money it had already burned through over the years by fracking for gas below cost.

During the terrible years of 2011 and 2012, drillers began reclassifying gas rigs as rigs drilling for oil. It was a judgement call, since most wells produce both. The gas rig count plummeted further, and the oil rig count skyrocketed by about the same amount. But gas production has continued to rise since, even as the gas rig count has continued to drop. On Friday, the rig count was down to 257 gas rigs, the lowest since March 1993, down 84% from its peak in 2008.

US-rig-count_1988_2015-03-13=gas

Quicksilver’s bankruptcy is a consequence of this fracking environment. It listed $2.35 billion in debts. That’s what is left from its borrowing binge that covered its negative cash flows. It listed only $1.21 billion in assets. The rest has gone up in smoke.

Its shares are worthless. Stockholders got wiped out. Creditors get to fight over the scraps.

Its leveraged loan was holding up better: the $625 million covenant-lite second-lien term loan traded at 56 cents on the dollar this morning, according to S&P Capital IQ LCD. But its junk bonds have gotten eviscerated over time. Its 9.125% senior notes due 2019 traded at 17.6 cents on the dollar; its 7.125% subordinated notes due 2016 traded at around 2 cents on the dollar.

Among its creditors, according to the Star Telegram: the Wilmington Trust National Association ($361.6 million), Delaware Trust Co. ($332.6 million), US Bank National Association ($312.7 million), and several pipeline companies, including Oasis Pipeline and Energy Transfer Fuel.

Last year, it hired restructuring advisers. On February 17, it announced that it would not make a $13.6 million interest payment on its senior notes and invoked the possibility of filing for Chapter 11. It said it would use its 30-day grace period to haggle with its creditors over the “company’s options.”

Now, those 30 days are up. But there were no other “viable options,” the company said in the statement. Its Canadian subsidiary was not included in the bankruptcy filing; it reached a forbearance agreement with its first lien secured lenders and has some breathing room until June 16.

Quicksilver isn’t alone in its travails. Samson Resources and other natural gas drillers are stuck neck-deep in the same frack mud.

A group of private equity firms, led by KKR, had acquired Samson in 2011 for $7.2 billion. Since then, Samson has lost $3 billion. It too hired restructuring advisers to deal with its $3.75 billion in debt. On March 2, Moody’s downgraded Samson to Caa3, pointing at “chronically low natural gas prices,” “suddenly weaker crude oil prices,” the “stressed liquidity position,” and delays in asset sales. It invoked the possibility of “a debt restructuring” and “a high risk of default.”

But maybe not just yet. The New York Post reported today that, according to sources, a JPMorgan-led group, which holds a $1 billion revolving line of credit, is granting Samson a waiver for an expected covenant breach. This would avert default for the moment. Under the deal, the group will reduce the size of the revolver. Last year, the same JPMorgan-led group already reduced the credit line from $1.8 billion to $1 billion and waived a covenant breach.

By curtailing access to funding, they’re driving Samson deeper into what S&P Capital IQ called the “liquidity death spiral.” According to the New York Post’s sources, in August the company has to make an interest payment to its more junior creditors, “and may run out of money later this year.”

Industry soothsayers claimed vociferously over the years that natural gas drillers can make money at these prices due to new technologies and efficiencies. They said this to attract more money. But Quicksilver along with Samson Resources and others are proof that these drillers had been drilling below the cost of production for years. And they’d been bleeding every step along the way. A business model that lasts only as long as new investors are willing to bail out old investors.

But it was the crash in the price of “liquids” that made investors finally squeamish, and they began to look beyond the hype. In doing so, they’re triggering the very bloodletting amongst each other that ever more new money had delayed for years. Only now, it’s a lot more expensive for them than it would have been three years ago. While the companies will get through it in restructured form, investors get crushed.


Oil Production Falling In Three Big Shale Plays, EIA Says

HOUSTON – It’s official: The shale oil boom is starting to waver.

And, in a way, it may have souped-up rigs and more efficient drilling technologies to thank for that.

Crude production at three major U.S. shale oil fields is projected to fall this month for the first time in six years, the U.S. Energy Information Administration said Tuesday.

It’s one of the first signs that idling hundreds of drilling rigs and billions of dollars in corporate cutbacks are starting to crimp the nation’s surging oil patch.

But it also shows that drilling technology and techniques have advanced to the point that productivity gains may be negligible in some shale plays where horizontal drilling and hydraulic fracturing have been used together for the past several years.

Because some plays are already full of souped-up horizontal rigs, oil companies don’t have as many options to become more efficient and stem production losses, as they did in the 2008-2009 downturn, the EIA said.

The EIA’s monthly drilling productivity report indicates that rapid production declines from older wells in three shale plays are starting to overtake new output, as oil companies drill fewer wells.

In the recession six years ago, the falling rig count didn’t lead to declining production because new technologies boosted how fast rigs could drill wells.

But now that oil firms have figured out how to drill much more efficiently, “it is not clear that productivity gains will offset rig count declines to the same degree as in 2008-09,” the EIA said.

Energy Information Agency

Overall, U.S. oil production is set to increase slightly from March to April to 5.6 million barrels a day in six major fields, according to the EIA.

But output is falling in the Eagle Ford Shale in South Texas, North Dakota’s Bakken Shale and the Niobrara Shale in Colorado, Wyoming, Nebraska and Kansas.

In those three fields, net production is expected to drop by a combined 24,000 barrels a day.

The losses were masked by production gains in the Permian Basin in West Texas and other regions.

Efficiency improvements are still emerging in the Permian, faster than in other oil fields because the region was largely a vertical-drilling zone as recently as December 2013, the EIA said.

Net crude output in the Bakken is expected to decline by 8,000 barrels a day from March to April. In the Eagle Ford, it’s slated to fall by 10,000 barrels a day. And in the Niobrara, production will dip by roughly 5,000 barrels a day.

But daily crude output jumped by 21,000 barrels in the Permian and by 3,000 barrels in the Utica Shale in Ohio and Pennsylvania.

Read more at MRT.com