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Thursday, November 5, 2009

ND Oil: Trends

Note: 53 wells come off the confidential list in January, 2010.
Note: 55 wells come off the confidential list in Febraury, 2010.
Note: 65 wells come off the confidential list in March, 2010.
Note: Skipping ahead -- 49 wells come off the list in June, 2010.
It has been opined that the increase in wells coming off the confidential list early in 2010 was due to number of EOG wells that would have been reported earlier, but were delayed due to delay in fracking.

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I am an eternal optimist so take the following with the proverbial grain of salt. I'm getting the feeling that 2010 could be a watershed year for the oil industry in North Dakota, the perfect storm one might say, but in this case, a very, very good storm, for these reasons:

a. Oil prices seem to be trending higher, but in an orderly fashion. Meanwhile, analysts predict demand for oil will outpace supply in 2010. More recent update from EIA, January 14, 2010.

b. The oil companies will continue to define the geology and the extent of the basin.  Particularly noteworthy is the "far east field" -- the Clear Water field bordering Ward County -- which EOG is aggressively pursuing. As of early January, 2010, EOG has 50 of 54 wells/permits in this field of 101 sections (the prolific Parshall field has 162 sections). [Note: both fields could be expanded over time. The Parshall field could be extended north and east. EOG is not the only producer interested in the Clear Water field; Hess was granted two permits in the Clear Water on December 16, 2009.

c. North Dakota had a record-breaking land lease auction, November, 2009. Producers and developers did not lease this land to watch the prairie grass grow.

d. All major producers in the Bakken have announced a) an increase in their capital expenditure program; and, b) an increase in the number of rigs they will be operating.

e. Although a lot of consolidation that resulted from slump in oil prices in 2008 seems to be ending, there are still significant deals being made. The relationship between NOG (publicly traded) seems to be growing with Slawson (not publicly traded).

f. Several major producers or exploration companies have recently concluded new share offerings: KOG, BEXP, NOG, raising cash for their 2009-2010 program. These companies are not raising cash just to invest in money market funds.

g. Current data suggests 20+ stage fracturing will become the norm in the Bakken.

h. It appears that more companies are drilling 1280-acre spacing wells.  Even EOG, historically drilling short laterals, now has applications in for long lateral wells.

i. Time to complete a well has decreased significantly, which will result in at least two things: a) more wells being drilled in a calendar year; and b) less cost to drill.

j. The US has adjusted to an unemployment rate of 10%.  The strength of the dollar has increased, and oil continues to rise in price (January, 2010).

k. Could the choke point for increasing oil production and getting oil out of the state be the pipelines? Although still lagging, the pipeline capacity to get the oil out of North Dakota has increased remarkably, and EOG's rail head to ship oil out by tanker went operational December 31,2009, about two months ahead of schedule. [Nice overview posted here, dated November 16, 2009.]

l. If an eco-pad with four wells on it actually works out, it's going to be quite a story. Can you imagine initial production (IP) numbers based on an Eco-Pad with eight (8) laterals versus a single well with a single lateral?

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I think the biggest trend in "the Bakken" right now is multi-stage fracturing. Examples abound but the history of Hess may be as good as any and better than most. It's hard to believe that only a year ago there was not a lot of talk about the number of stages of fracturing. All of a sudden, it seems, the number of stages of fracturing has become a hot topic of discussion. A few months ago, Halliburton announced a huge ($20 million) expansion in its complex east of Williston. And shortly after that, BEXP announced that 20-stage fracturing will become the standard.

This site says we will soon see 32-stage fracturing, and it will not be long before operators/drillers could see 60-stage fracturing.

It also appears that producers are studying the best time to actually accomplish the fracturing. The timing may depend more on the finances/availability of frack crews/price of oil rather than simply fracturing immediately after the well has reached total depth. There were suggestions/rumors on message boards that EOG was studying the timing of fracturing. EOG has stated it is researching the optimum number of fracturing stages.

There may be a good example of this trend line. The Charlson 44-33H came off the confidential list today. Its IP was under 300 bopd, and yet two months later, its average daily production is over 500 bopd. So, the questions: when did they do the frac; and how many stages?

The Bakken Blog posts a wonderful review of multi-stage fracturing. Posted November 6, 2009.

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This may or may not be important in the future as a trend (cost and time to drill a horizontal Bakken well), but I don't want to lose the link. If you scroll to the top of that link, Slawson reports that it has put in a horizontal well in 16 days and for less than $3 million. The rule of thumb for a horizontal well in North Dakota: 30 days (it used to be 45 days) and $4 - 6 million.  [Note: since this was posted a long time ago, NOG and Slawson have strengthened their relationship.]

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The trend in prices paid for oil leases from the state of North Dakota can be found by clicking here. North Dakota state holds an auction every three months. The November 3, 2009, auction hit a record ($71 million vs $30 million in 1980).


Original post: November 5, 2009. Updated: January 12, 2010.  Reviewed: January 23, 2010.

Bakken: Encore / Denbury


November 12, 2020: reacquires its Northeast Jackson Dome (NEJD) Pipeline System and its 860mile Free State Pipeline in eastern Mississippi after coming out of bankruptcy September 18, 2020. Link here

October 29, 2018: Right in my back yard. A Plano company -- just down the road from us -- will Houston upstream company for $1.7 billion Denbury Resources will acquire Penn Virginia Corp, an upstream company focused on the Eagle Ford shale.

June 19, 2018: appears to be the leader in North Dakota in EOR-CO2 in legacy oil fields.

September 21, 2015: Denbury suspends dividend. Shares up about 5.7%, slightly over $3/share.

January 18, 2014: Barron's on DNR.

The first 20% of an oil well's production gushes out, thanks to natural pressure. That eventually drops, and you can push out another 20% by flooding the well with water. When that's finished, you can do carbon-dioxide flooding, a highly effective technique that is Denbury's specialty. Carbon dioxide is an unusual gas. It loves oil. Denbury injects highly pressurized CO2 into a well. It finds the oil, bonds to it, and pushes it out. 
The biggest user of this oil-recovery procedure is Occidental Petroleum. The next largest, and the purest play, is Denbury, which produces 72,000 barrels of oil equivalent a day.
This quarter, the Plano, Texas-based company will pay its first-ever dividend, of 25 cents. Next year, that dividend will grow to between 50 cents and 60 cents a share, giving the stock a yield of about 3%. At a recent $16.46 a share, the stock trades at 4.5 times free cash flow, well below the industry average of 6.8. Closing the gap could push the shares up at least 20%, to $20, not including the dividend.
January 3, 2014: The Dickinson Press, for some reason, ran a story today suggesting that DNR will begin waterflooding in southwestern North Dakota around 2020, but needs to lay a CO2 pipeline first. Not sure why the story was printed at this time. Don updates DNR's plans for southwestern North Dakota:
One year ago this field was supposed to have CO2 in 2018. DNR is currently laying the pipeline for CO2 from Belle Creek, MT, to Baker, MT. I believe the injection in the Baker, Montana, field is to start in 2015. There are also fields northwest and southeast of Baker
DNR's plans were delayed somewhat because the company decided in late 2013 to transition to a "dividend company" rather than a growth company. In 2014 DRN will start paying dividends and are slowing down the growth pace. This meant that the field in North Dakota got pushed back two years (to 2020).
December 9, 2013: Denbury's management decides not to convert to a master limited partnership. Share price slumps. Motley Fool talks about that decision early in November, 2013.

October 2, 2013: Denbury presentation transcript.

January 15, 2013: Denbury buys COP's Red River field in the Williston Basin.

July 19, 2012: Denbury completion designs paying dividends.

May 1, 2012: Denbury to buy Gulf Coast Thompson oil field.  $360 million in cash; 17 million bbls conventional reserves; CO2 flood could generate antoher 30 - 60 million bbls -- flooding could require a capital cost of $8 - $10 / bbl. Currently producing 2,200 bopd; OOIP 650 million bbls in place.

August 31, 2011: Motley Fool feels DNR undervalued at $16.

July 11, 2011: Vanguard Natural acquires rest of Encore Energy Partners, LP. This should be the end of "Encore" name in the Bakken. Much of Encore net acreage acquired by Denbury Onshore last year. 

January 15, 2011: Recently completed wells, corporate presentation, December, 2010.

December 10, 2010: Investopedia update on DNR.

August 5, 2010: Did Encore Just 'UP' Their EUR By 3.5 Times?

June 10, 2010: Denbury Moving West!

April 11, 2010: Update.

April 11, 2010: Corporate Presentation, April 8, 2010

November 13, 2009: Very minor news but just to note: Encore assumed operator status for eight (8) wells previously operated by Ranch Oil Company. These are "old" wells and probably don't add much to the bottom line, but it's eight more wells. Could they be candidates for re-work? Fracturing? See Daily Activity Report dated November 13, 2009.

November 8, 2009: Encore just announced plans for a 22-stage frac of a Three Forks Sanish well. It also announced plans to add another rig to the Williston Basin before the end of 2009.  

As other producers are doing, Encore is re-fracing their wells to increase production. The economics are significant: the average development cost is $5/net bbl of reserves.

I continue to opine that re-fracing is going to be the story of the decade in the Williston Oil Basin, and the $20 million Halliburton expansion east of Williston is just the beginning.
Charlson
This is an interesting observation. The Charlson 44-33H (Encore) came off the confidential list on 5 Nov 09 and reported an IP of 283 bopd.

However, during its second full month, the well produced 15,793 barrels of oil, which works out to 509 barrels per day on average.

My guess: the IP was calculated before fracking. It is one-section (640-acre) spacing. When a WLL well comes in at 1,000 bopd "everyone" is happy, but generally a WLL well is two-section spacing. By those standards, a one-section well with 500 bopd is pretty good.

Other comments: the Charlson seems to be a mediocre field but it is dotted with lots of activity. The Charlson is directly west of the Sanish/Parshall oil fields, on the other side of the river. The few wells for which I have information, all reported around 400 bopd on initial production. But those wells were among the first drilled in the current boom (2007-2008) and probably were not frac'd or only one-stage frac'ing.

A 500-bopd * $60/barrel *365 = $11 million in the first year vs $4 - $6 million cost of the well.

CLR: outstanding 3rd quarter earnings

Continental Resources reports outstanding 3rd quarter results.

CLR announced that the company doubled its operating earnings and net income for the third quarter.

CLR will expedite its drilling program and increased its 2009 (current year) capital expenditures from $390 million to $415 million.

CLR will exit 2009 with 12 operated drilling rigs, compared with the previous target of six. That's incredible, doubling the number of its rigs from six to 12.

Average daily production the most recent quarter was 37,384 boepd vs 33,297 boepd last year, same quarter.

33,297 *$50 *365 = $608 million/year.

37,384 *$70 * 365 = $955 million/year.

Oh, by the way, CLR has 59 wells on the confidential list.