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.
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.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).
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.Charlson
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.
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.