Bakken Update: U.S. Small-Cap Oil Producers May Be Responsible For Balancing World Supply And Demand

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Includes: BNO, CLR, COP, CVX, DBO, DNO, DTO, DWTI, EOG, EOX, OIL, OLEM, OLO, SCO, SZO, TPLM, UCO, USL, USO, UWTI, WLL, XOM
by: Michael Filloon

Summary

US oil production continues to decrease approximately 20K bbl/d each week although Gulf production continues to increase.

Producers had planned to increase production significantly from 2014 to 2015 but low oil prices pulled barrels from the market.

2016 oil production from shale could see a much larger decrease year over year as increases may be seen from Iran, Saudi Arabia, Iraq, Russia, Kuwait, etc.

U.S. small cap unconventional oil producers could shoulder the majority of the 2016 production cut if 2015 numbers were a preview.

2016 US oil production has started to roll over in the wake of low prices. It is difficult to know the volumes and timeframe, but weekly declines of approximately 20K bbls/d have occurred. Although we have seen production declines, shale has accounted for the bulk of barrels. The re-emergence of Gulf production has offset this. Shale estimates are already approximately 600K bbls/d, and we expect those declines to continue. Most operators are not decreasing production year over year. If this is the case, why are numbers heading lower. During oil gluts, the weakest fall while the strong take over. We continue to speak about highly levered marginal operators and the upcoming defaults. When this occurs, new well completions decrease and natural production declines become the new reality. Bigger names wait and continue to produce. These operators will grow by swallowing assets after these defaults. The majority of production declines should come from the smaller names having difficulty in making interest payments. This is true in the Permian, Eagle Ford, Bakken and all US plays.

Much of the industry thought production decreases would be larger. There are many reasons to consider, as to why declines having taken this long. The first is hedges. Many operators had a significant number of barrels hedged at higher prices, and this allowed production to continue. Banks have also been lenient, as it does not want to own these assets. The most important issue are decline rates. Better well design has decreased decline, and to a significant degree. This is more impressive when considering the difference. Operators have needed to move rigs and increase activity in core areas. The best acreage, as a general rule, is higher pressured. This could be due to depth of source rock, increased natural gas percentages, or other variables. Declines in higher pressured areas are generally greater because more resource is produced in the first month. So measured declines are greater as those higher pressures decrease during early well life. First year production numbers are much higher but initial well pressures decline more because it is also greater.

There is no doubt lower oil prices in 2015 affected how producers navigated. Improved well production also allowed this. This produces an interesting conundrum. Operators produce more with fewer wells. It also decreases breakevens, and provides E&Ps with better economics at lower oil prices. The effects on operators are quite different. Much of this depends on quality of geology and oil service costs by area. The Permian seems to have the best of both worlds, as wells are producing very well at a low cost. This is focused around Midland, but the Permian core covers a significant area. Due to the large number of intervals per section, operators can drill a significant number of horizontals. This provides a decent inventory to develop at low prices. It gets interesting in marginal and poorer quality areas. Producers with core leaseholds will continue to work those areas, while others see less traffic. Bankruptcies could also help to decrease US production, and should be expected.

Lower oil prices in 2015 were just a precursor to worse economics. In 2014, the US Oil ETF (NYSEARCA:USO), declined from $34.23 to $19.89. 2015 was worse, as it declined to $11.00.

(Source: Yahoo Finance)

There are several other ETFs that focus on U.S. and world crude prices which have also been effected:

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

It is possible declines in activity from last year may provide some insight into changes occurring today. The Bakken may see the greatest changes during this transition. The Permian and Eagle Ford are better positioned due to refiner proximity. The shorter the distance to end users, the smaller the differentials. Differentials are basically the cost of transport. Bakken light is a better grade than oil from the Eagle Ford and Permian, but still sells at a discount. Newer pipeline projects may aid in this, but the current situation is more difficult in North Dakota.

(Source: Continental)

The above map provides a great representation of the Bakken core. The area marked MB, TF1, TF2 & TF3 is generally perceived as core. It has better production from both the middle Bakken and upper Three Forks. If an operator has acreage in southeast Williams, northeast McKenzie, southwest Mountrail, and northwest Dunn counties it will see better economics.

There are many operators with excellent core acreage including EOG Resources (NYSE:EOG) and Whiting (NYSE:WLL), while others have little to none like Emerald (NYSEMKT:EOX). Well costs can differ from one area to the next, but production rates have a high degree of variance. An example is western Williams County where the middle Bakken is shallow. An operator can drill and complete a well for approximately $1 million less when compared to northeast McKenzie. Operators still focus on the latter, as the increased production provides better economics than the lower costs associated with other areas. We have been looking at data from specific operators to see which names are effected the most. This should aid in identifying how overall production and those players will change in a low oil price environment.

Triangle Petroleum (NYSEMKT:TPLM) is having a difficult time with its western ND focused leasehold. It is unable to move rigs to core acreage because it possesses none. In 2014, Triangle was busy. Its completions totaled 52.

(Source: Welldatabase.com)

2014 locations produced 2.7 million bbls of crude. On a per well basis, these totals are not exceptional. Some of Triangle acreage is ok, but all is below average. Triangle is a good operator and has made some interesting technological advances with respect to its Rockpile oil service division. It is also vertically integrated, which decreases costs. This may not be enough, as it needs higher oil prices.

Date

Oil

Gas

Water

Wells

1/31/2014

37,926.00

50,733.00

109,861.00

5

2/28/2014

71,789.00

76,041.00

85,104.00

7

3/31/2014

105,017.00

114,966.00

127,723.00

10

4/30/2014

144,717.00

189,593.00

173,378.00

14

5/31/2014

180,790.00

255,022.00

210,239.00

18

6/30/2014

248,427.00

289,306.00

269,052.00

24

7/31/2014

263,872.00

317,882.00

290,898.00

29

8/31/2014

282,942.00

297,499.00

348,923.00

34

9/30/2014

303,447.00

316,583.00

417,725.00

40

10/31/2014

336,524.00

348,751.00

473,779.00

46

11/30/2014

334,606.00

358,412.00

475,939.00

50

12/31/2014

423,032.00

451,629.00

512,384.00

52

Total

2,733,089.00

3,066,417.00

3,495,005.00

52

Production Increase

60.3%

(Source: Welldatabase.com)

It managed to increase oil production by 60.3% in 2014. Oil prices allowed many operators to not only increase production but also improve logistics. TPLM did a great job, but the current oil glut may be too much to persevere. It turned five wells to sales in January of 2014. It added completions relatively quickly.

(Source: Welldatabase.com)

Oil: Green

Gas: Red

Water: Blue

Grey: BOE

Black: Well Number

The chart above provides the production of 2014 locations. There is a steady move in production. There is no decline as new locations more than cover decline. This chart provides a good impression of the Bakken as a whole. North Dakota was ramping up and increasing locations at a rapid rate. Wells were being drilled all over the Basin, as operators focused on getting acreage held by production. This is a stark contrast to the current situation, as operators are now doing large pad projects to decrease costs. The drilling rig is able to stay on the pad, and the wells zipper frac'ed. Pad projects are more economic as all work is done at that location. Work can be done on more than one well at the same time.

Things changed in 2015. It completed just 10 wells. These are focused around Rawson and Alexander in northwest McKenzie County. All of its wells are south of Williston.

(Source: Welldatabase.com)

It completed 2 wells in January, but the largest increase in production comes from locations in April and May.

Date

Oil

Gas

Water

Wells

1/31/2015

16,548.00

16,650.00

16,976.00

2

2/28/2015

13,786.00

7,233.00

16,521.00

2

3/31/2015

27,541.00

10,962.00

32,415.00

2

4/30/2015

43,305.00

46,931.00

98,241.00

7

5/31/2015

85,491.00

106,122.00

240,493.00

10

6/30/2015

99,288.00

86,240.00

176,423.00

10

7/31/2015

107,338.00

127,254.00

196,917.00

10

8/31/2015

96,585.00

129,150.00

154,331.00

10

9/30/2015

69,707.00

98,478.00

124,538.00

10

10/31/2015

62,884.00

89,342.00

114,831.00

10

Totals

622,473.00

718,362.00

1,171,686.00

-41.4%

(Source: Welldatabase.com)

Production peaked in July which is not strange given the pad projects that were recently turned to sales.

(Source: Welldatabase.com)

The above chart tracks TPLM production from just wells completed in 2015. It does not include locations already online before January first of that year. The chart is much different than 2014, as new wells cannot keep up with earlier production declines. Overall production from new wells in a marginal producer decreases significantly, and probably much more than an operator with core leasehold.

Continental Resources (NYSE:CLR) completed a large number of locations in 2014. Its 253 wells are spread throughout North Dakota.

(Source: Welldatabase.com)

2014 Continental wells were located in seven counties.

(Source: Welldatabase.com)

Continental was focused on getting acreage held by production. Early in the year, oil prices were high enough to support much of the development. Hedging was important as many operators were able to set prices for the following year. This allowed development to continue through early low prices. The importance of hedging cannot be stressed enough. This was seen when CLR recently sold its hedge book.

Name

Wells

CUM Gas

CUM Oil

CUM Water

WILLIAMS

97

15,777,209

10,119,012

12,426,360

MC KENZIE

78

14,152,867

9,258,993

7,608,641

MOUNTRAIL

28

4,195,033

3,142,316

2,332,779

DIVIDE

19

2,163,328

1,586,919

2,287,631

DUNN

13

1,369,765

1,498,941

1,882,052

BILLINGS

10

453,804

499,102

764,935

BURKE

7

587,179

504,389

885,342

BOWMAN

1

47,254

194,988

1,338,300

(Source: Welldatabase.com)

Williams and McKenzie saw a large number of completions. This would be expected as the eastern portion sits next to the Nesson Anticline. Continental's acreage isn't perfect as a large majority is in marginal areas, but has a large core footprint.

Date

Oil

Gas

Water

Wells

1/31/2014

3,693.00

7,574.00

49,352.00

5

2/28/2014

66,995.00

95,245.00

224,445.00

37

3/31/2014

378,359.00

412,224.00

487,754.00

57

4/30/2014

527,580.00

633,213.00

680,711.00

70

5/31/2014

790,719.00

980,787.00

856,645.00

104

6/30/2014

1,031,972.00

1,317,572.00

1,235,769.00

124

7/31/2014

1,259,384.00

1,617,591.00

1,447,475.00

135

8/31/2014

1,084,604.00

1,416,205.00

1,213,810.00

162

9/30/2014

1,276,217.00

1,745,622.00

1,640,509.00

187

10/31/2014

1,516,137.00

2,126,259.00

1,940,225.00

210

11/30/2014

1,633,390.00

2,302,063.00

1,847,577.00

226

12/31/2014

1,832,024.00

2,567,799.00

1,991,901.00

254

Total

11,401,074.00

15,222,154.00

13,616,173.00

(Source: Welldatabase.com)

Continental saw production increase throughout the entire year. Its least active month was January, but if you have even been through a North Dakota winter you know why. Continental saw a steady ramp up of locations too, and this is much like Triangle.

(Source: Welldatabase.com)

The above chart shows a consistent large ramp up. Many operators were doing this with no expectation of oil prices heading lower.

In 2015, Continental decreased its completion number to 145. Still a considerable number for a low oil price environment.

(Source: Welldatabase.com)

Continental continued to complete in several counties. It has tightened up this area. The well in southwestern North Dakota is out of place. This is not a horizontal well, but a vertical. It does not target the Bakken/Three Forks.

(Source: Welldatabase.com)

It didn't complete any wells in Billings over this period, and a large number of its wells were turned to sales near the river where better results have been seen. Locations near New Town are considered core, but the wells to the east and southeast of Williston have still shown decent results. It has lessened exposure to central Williams and southern Divide counties.

Name

Wells

CUM Gas

CUM Oil

CUM Water

WILLIAMS

53

5,383,508

3,714,690

3,714,877

MC KENZIE

50

3,554,818

2,484,020

2,098,097

DUNN

19

999,077

1,083,007

777,865

MOUNTRAIL

13

401,270

371,822

308,823

DIVIDE

5

360,158

279,274

585,526

STARK

3

160,009

160,069

117,173

(Source: Welldatabase.com)

In 2015, Continental's decreased activity still translated to a production increase. This is important, as smaller operators with poor acreage cannot do the same. This production increase was muted compared to 2014. Operators must keep increasing the number of new wells to counter natural production declines.

Date

Oil

Gas

Water

Wells

1/31/2015

33,903.00

54,187.00

27,294.00

21

2/28/2015

220,378.00

300,522.00

290,279.00

49

3/31/2015

397,059.00

515,970.00

566,373.00

81

4/30/2015

328,766.00

384,711.00

434,702.00

93

5/31/2015

929,103.00

1,212,268.00

932,969.00

101

6/30/2015

936,874.00

1,209,550.00

936,590.00

107

7/31/2015

1,020,279.00

1,331,186.00

937,650.00

118

8/31/2015

910,476.00

1,194,055.00

806,079.00

128

9/30/2015

1,034,352.00

1,407,100.00

886,008.00

142

10/31/2015

1,067,896.00

1,504,164.00

909,557.00

142

11/30/2015

1,243,565.00

1,754,605.00

932,537.00

142

Total

8,122,651.00

10,868,318.00

7,660,038.00

21.9%

(Source: Welldatabase.com)

Well development slowed significantly but this decrease was seen towards year's end. 81 wells were completed in the first 3 months, but just 61 after. This would be the opposite of the norm. Since January and February are very cold, completions work is more expensive. So most operators focus on the best weather. This chart does not include December's production data. This 11-month period produced 8.1 million BO. This was done with 142 wells. In 2014, it took 254 wells to produce 11.4 million BO in 12 months. The well results were 28.1% better when accounting for the one less month of data. Continental did see better results. This attributed to the decrease in production, as CLR was able to drill fewer wells to get the same number of barrels.

The two previous operators highlighted are Bakken focused (although CLR looks to be much more active in the SCOOP). TPLM and CLR have accumulated significant debt. The situation changes when we look at larger operators. Companies like Exxon (NYSE:XOM), Conoco (NYSE:COP) and Chevron (NYSE:CVX) have a different outlook. Bigger names are more focused down the road, so to speak. Just like some of the projects currently being completed by OPEC. It may not be cost effective now, but OPEC is more concerned with 40 years from now. At least that is what Qatar is saying. Projects still get cancelled, but a new focus has emerged. Distressed assets are hitting the market and the big names are acquiring. It will be interesting to see if OPEC countries try to get into the US shale market.

Exxon currently operates in North Dakota as XTO Energy. It completed 139 wells in 2014.

Date

Oil

Gas

Water

Wells

1/31/2014

22,896.00

28,623.00

14,091.00

4

2/28/2014

127,500.00

179,077.00

60,009.00

9

3/31/2014

252,402.00

440,963.00

127,391.00

25

4/30/2014

305,341.00

450,674.00

214,231.00

35

5/31/2014

429,597.00

643,493.00

348,937.00

47

6/30/2014

528,467.00

818,075.00

328,726.00

60

7/31/2014

843,011.00

1,248,695.00

500,151.00

76

8/31/2014

908,369.00

1,352,086.00

548,156.00

88

9/30/2014

984,967.00

1,322,480.00

614,852.00

101

10/31/2014

1,064,687.00

1,458,220.00

712,236.00

113

11/30/2014

1,015,068.00

1,302,930.00

624,901.00

127

12/31/2014

1,203,853.00

1,671,796.00

647,868.00

139

Total

7,686,158.00

10,917,112.00

4,741,549.00

42.8%

(Source: Welldatabase.com)

It worked three counties. Most of its work was done in McKenzie (it has good acreage in the northeast). Production from 2014 wells continued to increase through the year.

(Source: Welldatabase.com)

Some of its acreage is in the northern part of Williams isn't really productive, but the majority is near the Nesson Anticline. This geology is in the best part of the play. McKenzie was the home of the majority of its wells (75).

In 2015, it increased the number of locations completed year over year to 148. Oil production in 2014 was 7.6 million BO versus 2015's 6.07 million. We only had 10 months of production data.

Date

Oil

Gas

Water

Wells

1/31/2015

69,242.00

97,822.00

96,576.00

15

2/28/2015

135,885.00

207,428.00

154,561.00

23

3/31/2015

321,392.00

528,557.00

344,325.00

42

4/30/2015

463,941.00

819,524.00

397,904.00

61

5/31/2015

695,063.00

1,227,604.00

529,296.00

75

6/30/2015

726,373.00

1,307,514.00

580,810.00

96

7/31/2015

854,536.00

1,522,781.00

621,916.00

113

8/31/2015

906,728.00

1,531,016.00

616,126.00

132

9/30/2015

947,245.00

1,555,715.00

588,478.00

141

10/31/2015

959,442.00

1,561,940.00

539,093.00

148

Total

6,079,847.00

10,359,901.00

4,469,085.00

12.3%

(Source: Welldatabase.com)

One may expect oil production to remain constant year over year, but more locations were completed. This question can be answered by a basic flaw in data compilation by state agencies. There are many months where wells are shut in and do not produce any resource. Adjacent wells must stop producing while others are being completed. This tends to skew data with respect to production models.

(Source: Welldatabase.com)

Twelve of the 148 Exxon 2015 wells were shut in as of 10/2015. This does not mean well performance has suffered. It is also the reason company presentations may provide well performance that does not match state data. A well could be a top performer, but if it is shut in for four months, a quarter of its production would not be accounted for.

In summary, production from 2015 wells declined significantly year over year. These numbers do not include production from existing wells, as the lower decline rates of those wells cover the effects of depressed oil prices. Expectations are for a much larger decline this year than last.

Operator

2014 Production

2015 Decline

TPLM

60.3%

(41.4%)

CLR

45.5%

21.9%

XOM

42.8%

12.3%

When using just the wells completed for the year, there is generally an increase in production from January when compared to December. As an operator adds wells, total production increases. Since there is no natural decline from wells already producing, production numbers increase more quickly. Using this data, we can compare two years and see if the operator remains aggressive when oil prices change. In the table above, I took the operator's production from July and compared it to the last month of the year. By doing this, we can see if there is a decline or increase. Every operator saw a decline over this period, but Triangle was hit the hardest. Its wells have a higher breakeven price, so it shut down much of its development program. As a smaller operator, it will be hit harder than larger companies. Both CLR and XOM saw smaller decreases of 23.6% and 30.5%. But production still increased in the second half of the year. It can be assumed the same is occurring throughout all plays. It will continue until the world oil markets balance. This could happen in 3Q16, but if OPEC becomes more aggressive it could push this forward into 2017. The Bakken impact is just beginning, and no one knows with certainty when it will stop.

Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

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