Tag Archives: DJ Basin

The Well Map Update (12-3-13)

Testing is finished with The Well Map and we’re going to go live next week. Here’s what you need to know:

*There’s roughly 13k wells on the map and we’ll be adding more each week.
*The 13k wells include areas such as the Bakken, Eagle Ford, Miss Lime, Powder River Basin, DJ Basin, Piceance Basin, Permian Basin, Granite Wash, Marcelllus and Utica.
*We’ll be updating existing data and adding new data all the time. Wells from the San Juan Basin, SCOOP and Marmaton are coming soon.
*For quick analysis of the data we’ve installed several filters including operator, well name, formation, wellbore, spud date, state/county and production ranges.
*Once data is filtered, the filter summary averages the data filtered which allows the user to pull data points such as average production by operator, formation or state quickly.
*The map will be free, all you have to do is sign-up.
*If you want to stay up to date on the new wells we add each week and crunch raw data, we’ll be offering several newsletters containing just that, these start at $50/month.
*To stay up to date on new features and launch information, like us on Facebook and follow us on Twitter.

Thanks for your support,

The Well Map Team



Largest Oil and Gas Wells by Formation

Note: Added Powder River Basin well on June 10, 2013

I don’t usually talk about “largest wells” in formations or plays because they aren’t representative of the productivity or economics of a play as a whole. With that said, it’s still good to know where the biggest wells are being drilled because that usually indicates there’s a lot of oil in the area (whether it can be extracted consistently and economically is another matter).

Note: Peak month rate oil/gas is the amount produced in a given month divided by 30 days.

Well Name: Behr 11-34
Operator: Whiting (WLL)
County, State: Mountrail, ND
Formation: Bakken
Spud Date: April 15, 2008
Peak Month Rate Oil: 1,492 BOPD
Peak Month Rate Gas: 1,008 Mcfpd
Cumulative Oil: 911,627 BO
Cumulative Gas: 558,996 Mcf
Latest Monthly Rate Oil: 273 BOPD
Latest Monthly Rate Gas: 242 Mcfpd
Source: North Dakota Oil & Gas Commission/The Energy Harbinger.

Well Name: Jendrusch Unit 1H
Operator: Plains Exploration and Production (PXP)
County, State: Karnes, TX
Formation: Eagle Ford
Spud Date: April 21, 2012
Peak Month Rate Oil: 2,551 BOPD
Peak Month Rate Gas: 3,917 Mcfpd
Cumulative Oil: 341,352 BO
Cumulative Gas: 629,981 Mcf
Latest Monthly Rate Oil: 681 BOPD
Latest Monthly Rate Gas: 1,825 Mcfpd
Source: Texas Railroad Commission/The Energy Harbinger.

Well Name: Frye Ranch 2012H
Operator: Forest Oil (FST)
County, State: Wheeler, TX
Formation: Granite Wash/Hogshooter
Spud Date: March 23, 2010
Peak Month Rate Oil: 2,149 BOPD
Peak Month Rate Gas: 20,630 Mcfpd
Cumulative Oil: 327,782 BO
Cumulative Gas: 6,081,260 Mcf
Latest Monthly Rate Oil: 70 BOPD
Latest Monthly Rate Gas: 1,444 Mcfpd
Source: Texas Railroad Commission/The Energy Harbinger.

Well Name: Livestock 1-25H
Operator: SandRidge Energy (SD)
County, State: Grant, OK
Formation: Mississippian Lime
Spud Date: March 18, 2012
Peak Month Rate Oil: 1,595 BOPD
Peak Month Rate Gas: 3,909 Mcfpd*
Cumulative Oil: 170,398 BO
Cumulative Gas: NA
Latest Monthly Rate Oil: 214 BOPD
Latest Monthly Rate Gas: NA
Source: Oklahoma County Commission/The Energy Harbinger.
*Natural gas data is not publicly available for this well. Rate was computed using IP rates in the completion report.

Well Name: Dolph 27-1HZX
Operator: Anadarko Petroleum (APC)
County, State: Weld, CO
Formation: Niobrara
Spud Date: January 9, 2011
Peak Month Rate Oil: 730 BOPD
Peak Month Rate Gas: 1,595 Mcfpd
Cumulative Oil: 154,287 BO
Cumulative Gas: 568,554 Mcf
Latest Monthly Rate Oil: 71 BOPD
Latest Monthly Rate Gas: 331 Mcfpd
Source: Colorado Oil and Gas Commission/The Energy Harbinger.

Well Name: Anderson 18H-1
Operator: Encana (ECA)
County, State: Amite, MS
Formation: Tuscaloosa Marine Shale
Spud Date: January 15, 2012
Peak Month Rate Oil: 840 BOPD
Peak Month Rate Gas: 267 Mcfpd
Cumulative Oil: 115,991 BO
Cumulative Gas: 35,075 Mcf
Latest Monthly Rate Oil: 169 BOPD
Latest Monthly Rate Gas: 54 Mcfpd
Source: Mississippi Oil & Gas Board/The Energy Harbinger.

Well Name: Federal 16-10/3FH
Operator: Helis (Private)
County, State: Converse, WY
Formation: Frontier
Spud Date: July 16, 2011
Peak Month Rate Oil: 1,198 BOPD
Peak Month Rate Gas: 1,461 Mcfpd
Cumulative Oil: 270,530 BO
Cumulative Gas: 272,705 Mcf
Latest Monthly Rate Oil: 281 BOPD
Latest Monthly Rate Gas: 258 Mcfpd
Source: Wyoming Oil and Gas Conservation Commission/The Energy Harbinger.

For those of you who use the prototype version of the The Well Map, this is the type of data you’ll be able to access using the full version which will launch this summer.

Disclaimer: These are the largest wells in the above formation that I’m aware of. If you know of larger ones, feel free to disclose.

Excerpts from Earnings Transcripts (DVN, NBL, SD, CRZO, MRO, AREX)

I regularly spend time digging through earnings transcripts as I research the various companies and formations I write about.  While it’s currently post earnings season, I thought I’d post a few notes from earnings calls from several companies I’ve recently looked at.  These notes aren’t necessarily the most important points from the call, just ones that interested me.

Devon Energy (DVN)
* D&C six wells in the Cline Shale with “highly variable results.”  Plans to drill 30 more exploration wells in the formation testing various intervals.
* Regarding variability of the Cline results, the company mentioned it’s testing different areas of acreage position and different intervals to see which work best.  It’s confident the play will be economic.

Source: Q4 Earnings transcript (Click here for transcript).

Noble Energy (NBL)
*Plans to test 350k net acreage position in NE Nevada with vertical wells.
*Plans to test 1.8 MM net acreage position in offshore Nicaragua.  (Noble, Niobrara, Nevada, Nicaragua…what’s with that?)
*Will spud exploration well at Karish (follow up from Leviathan 4) in the Eastern Mediterranean.
*Plans to drill 5 to 10 wells in Northern Colorado (North of Wattenberg) where company has 230k net acres (versus 290k net in Wattenberg).
*2013 Drill plan for DJ Basin is to spud 300 wells.

Source: Q4 Earnings transcript (Click here for transcript).

SandRidge Energy (SD)
*90% of rate-of-return (ROR) of a Mississippian Lime well is recovered in its first five years.
*Lowered EUR estimate in Miss Lime to 369 MBOE from 433 MBOE.
*Company projects to move well cost in Miss Lime below $3 million (not including SWD) by end of 2013.
*In 2012, the company produced 10.1 MMBOE (45% oil), a 163% increase compared to 2011.
*2013 plans include D&C 581 horizontal wells and 74 SWD wells in the Lime.
*Agreement with Atlas Pipeline Partners allows for capture of NGLs from Lime.

Source: Q4 Earnings transcript (Click here for transcript).

Carrizo Oil & Gas (CRZO)
*In the Niobrara the company is producing 800 net BOPD on 33 gross wells with five more gross (2.4 net) awaiting completion.
*Plans to test Niobrara down to 80-acre spacing .
*Niobrara wells are 80% oil.
*In Guernsey, Ohio (Utica Shale), CRZO expects 50% to 75% oil cuts with the remainder wet gas (Antero, PDC and Gulfport wells cited).
*50% of the company’s NGL production in the Eagle Ford is ethane; company also makes point that 90% of revenues from Eagle Ford are from oil.

Source: Q4 Earnings transcript (Click here for transcript).

Marathon Oil (MRO)
*70% of Eagle Ford wells will be drilled on pads in 2013.
*D&C costs in the Eagle Ford are now averaging $8.5 million but company expects this to drop to $8.1 million over the near term.
*Bakken wells are being completed at $8.5 to $8.8 million.

Source: Q4 Earnings transcript (Click here for transcript).

Approach Resources (AREX)
*Estimated 2,000 gross drilling locations in the horizontal Wolfcamp play (includes A, B and C benches).
*Average well should be in the 450 MBOE range with D&C costs $5.5 to $6.0 million.
*Expects to recover 85 to 90 MBOE in first year of average well.

Source: Q4 Earnings transcript (Click here for transcript).

Anadarko’s Horizontal Wattenberg Wells are Moneymakers

There’s an old saying in the oil and gas industry that goes something like this, “the best place to find oil is an oil field.”  While it’s exciting to to see what the future holds for newer fields like the Utica and the Tuscaloosa Marine Shale, the Wattenberg field in the DJ Basin (Colorado) is showing us that these old oil fields that have been peppered with vertical wells still contain a lot of recoverable oil and natural gas.  For proof, look no further than Anadarko Petroleum (APC) whose horizontal wells have been delivering fantastic results.

These wells are fairly cheap at $4.5 million a pop and are consistent (see graphs below).  The average well produces 49 thousand barrels of oil (MBO) and 198 million cubic feet of natural gas (MMcf) during its first ten months of production.  Assuming $85 oil, $3 natural gas and a company reported 88% net revenue interest (NRI), these wells are netting more than $4.1 million in their first ten months.

Oil Produced to Date
Source: Colorado Oil and Gas Commission/The Energy Harbinger.
Sample Size: 72 wells.

The scatter-plot above shows oil recoveries from 72 of APC’s horizontal wells in the Wattenberg oil field.  Most of these wells are between 5 and 15 months old and have produced between 20 and 60 MBO to date (COGCC’s latest production month reported is December, 2012).  What’s really interesting about this data is that while there’s a few bigger wells and a few smaller wells, nearly every well should be economic and 75% of the wells produced more than 30 MBO in their first ten months.

I’ve calculated a break-even oil production of 60MBO (assuming no natural gas production) at a $4.5 million well cost.  While these wells are still young (notice none in my sample size have produced for more than 25 months) and no long-term data is available, these economics are competitive with any oil play I’ve seen.

Natural Gas Produced to Date
Anadarko_Niobrara-Natural Gas-EUR
Source: Colorado Oil and Gas Commission/The Energy Harbinger.
Sample Size: 72 wells.

I think you have to put Anadarko’s horizontal Wattenberg play in the upper echelon of oil and gas plays.  Not only is it producing a lot of hydrocarbons, but the wells are cheaper than in the Bakken or Eagle Ford and the company is netting a whopping 88% NRI from its wells.  It doesn’t hurt that its working interest averages 96% in each well and the company estimates it has ~4k drill sites with ~300 wells planned for 2013.

I plan to take a look at Noble’s (NBL) Wattenberg wells in fairly short order as they’re the other major player in this field, but I expect the company’s results to be a little shy of APC’s but still strong.

As far as APC’s stock goes, I wouldn’t necessarily recommend buying it as it has skyrocketed over the past year (you could probably do much worse), but maybe start thinking about some of the smaller players in the field like Bill Barrett, Bonanza Creek and PDC.

DJ Basin Update (CRZO gets $4,558 per acre in JV)

EOG Resources’ (EOG) Jake 2-01H well on its Hereford prospect (Northern Weld County) put the horizontal Niobrara on the map with an average 30-day production rate of 645 BOEPD.  This well gave the industry hope that the formation could be produced economically outside of the prolific Wattenberg field.  Up until recently, results in the DJ Basin (Niobrara) had been inconsistent, with several operators drilling a number of uneconomic wells.  Chesapeake Energy’s (CHK) CEO Aubrey McClendon has called CHK’s acreage in the area “disappointing” and has since put it up for sale.  EOG’s CEO Mark Papa said the following regarding the Niobrara, “I mean it’s no secret that the Niobrara is proven to be one of the more complex horizontal oil plays that both we and the industry have dealt with.”

Why is it so hard to drill in the Niobrara?

For starters, when people talk about the Niobrara they’re probably referring to the DJ Basin but know that the formation spans several states and several basins (see map below), including the Green River Basin (NW Colorado), North Park Basin (North-Central Colorado), DJ Basin (NE Colorado) and Powder River Basin (Eastern Wyoming).  While producing intervals will vary across these basins, I’m going to focus on the geology of the DJ because most of the Niobrara’s development has emanated from this basin to date.

Sources: Colorado School of Mines; Colorado Geological Survey

As you can see from the stratigraphic column above, the DJ Basin is characterized by three benches (A, B and C) which are primarily composed of chalk that have been compressed over time, thus having low permeability.  These benches are separated by three marl/shale zones that contain high clay volumes (virtually no permeability) making it very difficult/expensive to frack a well through all three zones as the clay blocks commingling.

Drilling into the benches separately is no easy task either as they are relatively thin.  The “B” bench is the thickest, ranging from 20’-40’, making it difficult for operators to stay in zone.  Complicating matters is faulting throughout the Basin which thins the intervals in certain areas.  Imagine fracking into a zone 7,000′ deep  that may be no wider than 10′.  The FT Hays Limestone, Codell Sand, D-Sand and J-Sand are also prospective for hydrocarbons throughout the DJ Basin, creating a series of stacked pay zones for operators to explore.

What the DJ Basin does have a lot of is oil and natural gas.  Nearly two billion barrels of oil equivalent (BBOE) has been produced from the Wattenberg field alone and sell-side investment bank Tudor, Pickering and Holt (no relation) estimate the basin holds an additional 4-10 billion barrels of recoverable oil and gas.  This isn’t just a Niobrara story either, as the D and J-Sands alone have produced approximately 1 BBOE to date.  The basin also gets oilier as you move North too, with 90% oil cuts in EOG’s Hereford prospect.  The big question is how to get to it economically.

(See TPH’s Niobrara Primer here, it’s a great resource which I relied on for this report)

One of the keys to producing from the Niobrara is to find areas where it’s naturally fractured, which increases the operators margin for error when drilling the chalk, but could also fracture the marls/shale, allowing for commingled production from the Niobrara benches.

The Wattenberg field has been economic for decades, in part because natural fracturing exists throughout the field.  What companies must do outside of the Wattenberg is either find areas with natural fracturing or induce fracturing themselves.  This is not only expensive (well costs are $1.0 to $2.0 million more outside of the Wattenberg), but well production outside of the field has been no more prolific and much less consistent, leaving operators like Chesapeake and GMX Resources (GMXR) to abandon the play.

So where are we at in the DJ Basin today?

EOG Resources

EOG has ramped-up production in the play since 2010, drilling more than 50 wells and producing more than 3.0 MMBbls of oil and 4.0 Bcf of natural gas.  The bulk of the company’s production has come from its Hereford ranch prospect, lying in Northern Weld County, where it holds approximately 80,000 net acres.  After evaluating its well results, EOG decided the DJ Basin would be an ancillary project for the company as its economics didn’t rival those of its other plays.  Consequentially, the company hasn’t done much in the basin since 2011 and has quit talking about it in its presentations.  Who could blame them really? EOG has the best acreage in the two best unconventional oil plays on the planet.

Just how economic were EOG’s wells in the DJ?  I took a look at ten different wells in its Hereford prospect and found an average 30-day IP rate of 348 BOEPD.  I then selected six wells from different quartiles of this sample size and looked at 80-90 day rates from these wells (see table below).  While I included gas production in the table, EOG flared nearly all of its gas from these wells, so I didn’t include it in the economics.

Source: Colorado Oil & Gas Commission

These wells were all drilled by EOG between 2010 and 2011.  This data shows us that after 86 days, EOG’s average well will produce approximately $2.3 million in revenue (at $90 oil) or 42% of the overall cost of a well (again this doesn’t include gas production).  These Hereford ranch wells show low decline rates during the first year, making them economic; however, not nearly as economic as the wells the company is drilling in the Bakken and the Eagle Ford.  One would think an experienced Niobrara operator like Noble Energy (NBL) would be interested in this acreage.

So Chesapeake and GMXR have thrown in the towel and EOG is largely on the sidelines, who else is trying to figure out the Northern DJ Basin?  The aforementioned Noble Energy.

Noble Energy

Noble’s onshore U.S. legacy assets are in the Wattenberg field, so the company is familiar with the complexities of drilling in the Niobrara.  NBL currently holds 410k net acres in the Wattenberg and 230k net in the Northern DJ.  Its decision to divest non-core assets in the Permian, mid-continent and North Sea earlier this year to focus more on the Niobrara and various international plays certainly gives the play a boost of confidence.  To combat the Niobrara’s various complexities, the company has been experimenting with spacing units down to 40-acres on its horizontal program, in addition to an extended reach lateral program where it’s drilling 9,000 foot laterals.

Noble is seeing better results on its 40-acre spacing program, with the theory that smaller spacing units are breaking up more rock which is increasing permeability.  Its first extended reach lateral (unclear where this was drilled) cost $7.5 million and averaged 400 BOEPD during its first year of production.  NBL expects it to produce 750 MBOE, a success that has the company testing more of these wells moving forward.  The company has already spud more than 190 horizontal wells (40 in Northern Colorado) this year using seven rigs and will add three more rigs by year end.  It’s experimenting with pad drilling as well, which should lead to decreased well costs, providing a boost to the economics of the play.

In the horizontal Wattenberg, the company expects EURs to range from 337 to 350 MBOE based on 30-day average IP rates of 497 to 567 BOEPD (60-80% liquids).  What’s more encouraging for the Niobrara itself is that NBL is seeing improved production results on its last eight Northern Colorado wells with 30-day average IPs of 550 BOEPD (85% liquids) which track an EUR of 310 MBOE.  Don’t hold your breath on these results just yet, as the Northern Niobrara is proving to be about as hard to tame as Afghanistan, but there’s a lot of oil there so they’re worth keeping an eye on.

Anadarko Petroleum

Anadarko (APC) recently pledged to spend $1.0 billion annually during the next several years developing its Niobrara acreage.  In the DJ, the company currently holds 350k net acres in the Wattenberg and 550k net acres to the North.  The company plans to drill 170 Wattenberg wells in 2012, 270 in 2013 and 300 in 2014.  Based on its type-curve, a well that has a 24-hour IP rate of 800 BOEPD will produce an EUR of 350 MBOE and return 100%.  To date, Anadarko’s production has averaged right around its type-curve, and judging from its expected ramp-up, the company seems excited about the play.

Outside of the Wattenberg, Anadarko plans to evaluate its acreage by drilling 30 wells during 2012.  As of November, 2011, APC had drilled 15 wells in the area which produced at an average 24-hour rate of 350 BOEPD.  It’s difficult to read too much into those IP rates, as wells outside the Niobrara have been known to either decline slow or fall off the map.  It’s worth noting that the company has stopped highlighting this acreage in its presentations, which leads me to believe it hasn’t been all that happy with the results.

Carrizo Oil & Gas

Carrizo Oil & Gas (CRZO) just sold 18k net acres Northeast of the Wattenberg for $4,558 an acre, a great value for an area that has struggled to produce consistently.  Pro-forma to the acquisition, the company has 43,400 net acres remaining in the DJ Basin.  To be honest, I wasn’t even planning on looking at CRZO’s production data for this report, but the valuation they received intrigued me.     The company hasn’t hit any big wells on its acreage, but its 30-day average production rate of 289 BOPD (353 BOEPD) is comparable to EOG’s Hereford prospect.  Flaring has decreased on its wells, leading me to believe the company is getting gas pipeline infrastructure in the field as well, which will help the economics.  With a target well cost of only $3.6 million per well, this acreage looks to be more economic than EOG’s.

Source: Colorado Oil & Gas Commission


There’s several other companies, including Bonanza Creek (BCEI) and PDC Energy (PDCE), who are achieving solid results in the horizontal Wattenberg play, but by now you get the point: companies are excited about the Wattenberg, while the Northern portion of the play seems more prospective; however NBL and CRZO’s results in the Northern portion of the play are encouraging. The Niobrara probably won’t blow your socks off, but if you know how to work this sometimes perplexing play you can find economic oil.

How is the Market Valuing Different Oil and Gas Plays?

When I analyze stocks I look for two things: an industry that I believe will thrive over the long-term and value.  I don’t have models to predict the future prices of oil and natural gas, and even if I did, I doubt they would be very accurate; however, I do believe in the long-term viability of the industry or I wouldn’t have bothered starting this blog nearly three months ago.  When looking for value in oil and gas stocks, I first look at how investors are valuing each play.  The easiest way to do this is to look at reserve and production multiples.

The trouble with valuing an individual play is that there aren’t a lot of “pure-play” companies in the oil & gas industry.   Most companies have operations in various plays across the U.S. and abroad, so their reserves and production valuations have several different plays factored in.  Companies like Kodiak (KOG) in the Bakken and Concho (CXO) in the Permian are great examples of pure-plays that make analysis easy.  A play like the Eagle Ford is more difficult to value, not only because it’s so new, but because it has attracted companies from all over the globe, most of which had existing production and were looking for oil and liquids rich assets.

At first glance, Sanchez Energy (SN) is the perfect Eagle Ford comparable.  It’s an Eagle Ford pure-play, but it’s an early stage company that the market is expecting significant reserve and production growth from over the next several years.  Because of these expectations, its multiples are high which throws off my Eagle Ford valuation.  I did consider throwing SN out of the analysis, but I had a tough time justifying this because their core acreage is in Gonzales County where two Bakken companies, EOG Resources (EOG) and Magnum Hunter (MHR), have been drilling gushers and I want to get a sense for the valuation of that acreage.

While SN may bloat my Eagle Ford valuations some, keep in mind that Marathon (MRO) spent $3.5 billion purchasing 141k net acres (~25k/acre) from Hilcorp a little over a year ago.  By year-end 2011, the acreage was expected to have 46 wells on it producing 12,000 net BOEPD (80% oil and liquids) giving us a valuation of $291,667 per flowing BOEPD, 22% less than the $355,234 per flowing I calculated based on my peer group.

See valuations by basin/play below to get sense for how the market is valuing each play:

The first point to make here is the “well duh” observation: the gassier the basin, the lower the valuation.  It should be no surprise that the North Dakota Bakken is receiving the industry’s best reserve valuations, because the play is in more advanced stages (thus less risky) than the Eagle Ford, DJ and Permian, and more oily than the Marcellus.  While the Eagle Ford is more gassy than the Bakken, it’s downspacing potential has led EOG to nearly double its reserve estimates.  In addition, the play has several resource windows and the potential for stacked pay zones which is undoubtedly driving up valuations.  The DJ and Permian Basins also have stacked pay zones, which has led to a revival of both Basins in recent years.

Companies are now going back into these Basins using updated completion techniques (horizontal drilling, fracking, etc) to exploit the previously unrecoverable resources.  Large cap E&Ps Noble Energy (NBL) and Anadarko (APC) aren’t spending billions in the Niobrara over the next several years for no reason.  With valuations in the Bakken and Eagle Ford extremely high, I think it’s worth looking at these other plays for value.  Below are the peer groups I used in my valuations by play above.

1: SYRG reserves based on 8/31/2011 year-end

The companies used in the analysis above are either pure-plays in a specific basin/play or have current operations focused in a certain play.  Aside from SN, KOG is another company whose valuations are outliers.  KOG is an early stage company that has several years on SN.  KOG’s production has done what SN’s investors are hoping its production will do: explode.  And when I say explode, I mean increase nearly 5-fold from May 31, 2011 to May 31, 2012.

SM is an established operator, producing in a premier shale play, but with a low production valuation.  Why might this be?  Its reserve life (reserves divided by annual production) is only 5.5 years versus the peer group average of 17.39.  The market isn’t buying that SM will be able to replace its reserves quickly enough to maintain production.  The company is in the process of shifting assets from the Cotton Valley and Wyoming gas Basins to invest nearly a billion dollars in 2012 drilling in the Eagle Ford and Bakken-Three Forks.   The company has over 200k net acres in each of these plays, so if you believe in the acreage, the present could represent an opportunity to buy SM on the cheap.

Based on pure value, we should all be buying Marcellus companies right?  EQT’s stock price has increased 20% from its lows this spring when natural gas prices dropped below $2 per Mcf.  EQT has the largest reserve base in this analysis, located in one of the most economic plays on the planet.  The economics of the Marcellus are so good that the company boasts 25% IRRs at $3.00 gas and 50% at $4.00 gas.  On an energy equivalent basis, those numbers blow the Bakken out of the water.