Tag Archives: Sandridge Energy

SandRidge’s Mississippian Wells are Improving

The Mississippian Lime has put companies and investors alike on a roller coaster ride during the last couple of years. When SandRidge Energy (SD) and Range Resources (RRC) started hitting big wells such as the Puffingbarger 1-28H and Balder 1-30N (see below), EUR and IRR projections ballooned to 600MBOE and more than 100%, respectively. Subsequent drilling has shown that these wells are more the exception than the rule, leading companies to slash their expectations considerably.

Big Wells in the Mississippian Lime

Source: The Well Map.

The Lime’s inconsistency has led some companies to leave the play and some to dial back expectations, but there’s reason to believe companies are finally starting to figure out its eccentricities. SandRidge saw production results improve approximately 20% from 2011 to 2012. These results coupled with a decrease in wells costs have increased the economics of the play.

SandRidge began drilling in the Lime in late 2010, meaning their oldest wells have produced for about three years. The company is currently estimating that its wells pay out in two years, so we took a look at their oldest producers to see if those estimations are accurate.

The average well the company turned to production prior to 2012 has produced 26 MBO (thousand barrels of oil), 197 MMcf (million cubic feet of natural gas) and 4 MBNGL (thuosand barrels of natural gas liquids). Assuming $88 oil, $4 natural gas, $40 natural gas liquids and an NRI of 80%, these wells have grossed $2.5 million in two years.

Revenue by Hydrocarbon


Source: The Energy Harbinger / Oklahoma Tax Commission.

This data tells us that SD’s early wells didn’t pay out in two years based on a $3.2 million well cost. While that’s an important data point, investors should be more concerned with the results from the next thousand SD wells than the first 100. So let’s compare these results to what we’re seeing from the company’s newer wells.

Average Production by Well During First Year (2011 to 2012)


Source: The Energy Harbinger / Oklahoma Tax Commission.
*Natural gas production converted to barrels based on 6:1 energy equivalency.
**Assumes 12% of natural gas stream is NGLs.

While natural gas production has remained flat, oil production by well increased approximately 20% from 2011 to 2012. This is important because oil is responsible for roughly 73% of a well’s revenue. If the 2012 wells continue to produce 20% higher than the 2011 wells, they’ll gross $3 million by their second year. SD is currently modeling sub $3 million well costs for the Lime wells, which means their newer wells are paying back in two years. A two year payback period is on par with most major oil plays in the United States.

At this point, we’re not sure why SandRidge’s newer wells are producing more oil. It could be that the company is able to focus on its better areas after it delineated it acreage or the new frac designs they’ve cited in their earnings transcripts are paying off. Either way, the production improvements make it a stock to watch for the future. To that end, Range is also tweaking its frac designs and has reported strong results in the few wells it has used to test the design.

If you track the Lime, you’ve probably heard of Petro River Oil (PTRC) who held its IPO earlier this year. The company has 85k net acres in the Mississippian and 32k net acres in a heavy oil play in Missouri. It recently attracted outside capital when Petrol Lakes (Chinese investment group) purchased $6.5 million in stock from Petro River. If you like micro-cap stories, these guys have an impressive management team which makes it a stock to watch.


Verticals could be Key to Mississippi Lime Development

Most people probably associate the present and future of the oil and gas industry with horizontal wells and monster frack jobs in deep formations. That concept is driven by the idea that most of the shallow oil that’s easy to get to has been exploited, leaving deep plays in tight rock as oil’s last frontier. I’d respond to that argument with Lee Corso’s famous line, “not so fast my friend.”

The industry’s technological advances haven’t just improved horizontal drilling, they’ve improved vertical drilling as well. For instance, it’s now possible to drill a vertical well into a targeted zone and fracture the rock similar to a horizontal. This is an effective way to delineate acreage in formations that are characterized by multiple producing strata with “trapped” hydrocarbons like the Mississippian Lime, versus a resource play like the Bakken.

To illustrate this, SandRidge’s (SD) well results on the Western side of the Mississippian are all over the board. They’ve drilled wells like the Puffinbarger 2-28H which produced 51 thousand barrels of oil (MBO) in its peak month alongside a plethora of wells which never topped 1 MBO in a month. Out East it’s a similar story with Range (RRC) whose landmark Balder well produced 19 MBO in its peak month, but it has also drilled a number of wells which won’t top 19 MBO in their first year of production. The results are indicative of a play with high concentrations of oil in small areas “trapped” by faults, synclines, etc. versus widespread oil across a large area.

These companies will tell you it’s a numbers game and the good wells more than make up for the bad ones. Even if this is true and companies are earning an acceptable IRR from their drilling program, is it really the best use of investor capital to be drilling a large number of expensive, uneconomic wells or is there a better way?

Austex (AOK) is a company that’s taking a different approach to the Lime. While the big companies are using data from the Lime’s old vertical wells to “delineate” acreage (the formation has a lot of historical production), it’s drilling new vertical wells with new technology to find oil. Once a high producing area is found, clusters of verticals can be drilled at 20 to 40 acre spacing. It’s early on, but the results of the program (see below) are looking solid.

Austex’ Vertical Well Results
Source: The Energy Harbinger / Oklahoma Corporation Commission.
1Production results during first six-months of well.
2Natural gas production isn’t publicly available. This number was calculated based on assumption of a 30% natural gas cut during the first 6-months of production.
3Cost per barrel calculated as estimated well cost divided by first six months of production.
4Estimated revenue generated from well during first 6-months of production. Assumed 85$ oil, $3 natural gas and 80% NRI.
5Cletus 20-5, Blubaugh 20-4 and Blubaugh 20-1 all share tank batteries with a second well making actual production from the individual wells difficult to determine. The production numbers shown are averages.

The above table shows Austex’ vertical wells aren’t only consistent but they’re also nearly paying for themselves in six-months. These wells were all drilled in Township 25 North, Range 1 East, Section 20, so it’s obviously a strong section for the company and may not be indicative of results across the play. Austex is a small company and doesn’t have the capital to drill a large number of wells at this point, but it will be interesting to measure consistency on the wells as the program develops. The company has 5,500 acres in this area, known as its Snake River Project, and plans to develop it at 40-acre spacing.

When we contrast Austex’ results with those of Range’s horizontal program in the same area, we see they lack the consistency of the verticals.

Range’s Horizontal Well Results
Source: The Energy Harbinger / Oklahoma Corporation Commission.
1Production results during first six-months of production.
2Natural gas production isn’t publicly available. This number was calculated based on assumption of a 30% natural gas cut during the first 6-months of production.
3Cost per barrel calculated as estimated well cost divided by first six months of production.
4Estimated revenue generated from well during first 6-months of production. Assumed 85$ oil, $3 natural gas and 80% NRI.

Range’s horizontal program boasts results which include the Balder 1-30N which is a best in class well (vertical or horizontal) and the Dark Horse 26-6N which might never recover its original cost. The company is probably drilling these wells to hold its Mississippian leasehold which consists of 160k net acres, so it’s not necessarily targeting its best acreage. With that said, why not drill more verticals whose cost per barrel of $61 per BOE (see footnotes above) is much less than the $243 per BOE it’s paying for horizontals?

PetroRiver Oil (PTRC) is a micro-cap E&P whose acreage, located along the Nemaha Ridge in Southeast Kansas, is in the same geological area as Austex. The company’s team is made up of some of the key engineers and executives who designed Austex’ vertical program. Due to Austex’ success, it’s likely they’ll take a similar approach. Petro is definitely a company to keep an eye on in the Lime as they’re well positioned in a play with a lot of upside.

The Mississippian has gotten some bad press from companies like SandRidge and Range, as both have pumped the markets on the play’s economics and probably taken the wrong approach to development. While it’s not prudent to make decisions based on a few solid well results, I believe the geological characteristics of the Lime make vertical wells (at least initially), the best method to develop the play.

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).

An Early Look at Range’s Mississippian Results in Kay County

After looking at Range Resources’ (RRC) early production results in the Mississippi Lime, it’s hard for me to understand why the company thinks estimated ultimate recoveries (EUR) from its wells will be 600 thousand barrels of oil equivalent (MBOE).  I read that in their presentation, look at their estimated well cost of $3.4 million and wonder how many investors lick their chops and buy the stock.

When production results for the company’s Balder #1-30N well were released, some believed RRC had found the “sweet spot” in the Lime.  Its acreage is positioned along the Nemaha Uplift in Noble, Kay and Cowley Counties, East of where SandRidge Energy (SD) and Chesapeake Energy (CHK) have been drilling.  While the Nemaha area is shallower and oilier than Alfalfa and Grant counties, there’s also less pressure which appears to be effecting production results as shown by the graph below.

30-Day Production Rates in the Mississippian (Barrels of Oil per Day/BOPD)
Source: Production Reports / The Energy Harbinger.
*Based on 13 RRC wells

The above graph shows RRC’s limited results from Kay County compared to SD’s results across the Mississippian.  Of the company’s 13 wells which have been on production for more than a couple months, their average 30-day IP rate is 149 barrels of oil (BO) with an implied 534 Mcfpd (238 BOEPD) based on a 63% oil cut (see bottom for more on the implied rate).  These results are mediocre for the Lime and will need to improve for the company to reach its EUR goal for its program.

Now to be fair, Range is still drilling to hold its acreage, meaning the company isn’t drilling in its best areas but in a broad range of areas which it believes holds the most potential for its acreage block.  Still, when I see verbage like “17 well average EUR is 600 MBOE” on the type curve in its presentation, I’m a little concerned as to its validity.  Even if the company has a handful of wells I haven’t seen, you can look to the performance of the heralded Balder #1-30N well to see the steep oil declines associated with drilling in a low pressure formation.

Production Results from Balder 1-30N (Kay County)
RRC_Balder 1-30N
Source: Production Reports / The Energy Harbinger.
*Natural gas production data is not available to the public for wells designated as “oil wells” in the State of Oklahoma.  These natural gas production results are not the actual figures produced from the well but based on an implied rate calculated from the oil/natural gas rates in the well’s completion report.

The graph above shows the steep decline for oil which is indicative of the larger wells drilled to date in the Mississippian (see my article on SD’s wells).  While natural gas appears to decline in lock-step with oil, these are not actual natural gas figures as shown by the footnote above, but implied figures to give us a better understanding of the economics of these wells.

Regarding economics, the Balder well has produced more than 57 MBO and 134 MMcf of natural gas as of November, 2012.  This well paid for itself in its first six months of production based on a $3.4 million drilling and completion cost (includes SWD well cost).  While the Balder well is a good result, it’s the exception so far in Range’s Miss Lime drilling program which puts its economics/type curve in question.

When you look at the Mississippian as a whole, there’s big wells being drilled from Alfalfa to Kay Counties in Oklahoma in addition to Harper County across the border in Kansas.  We know there’s a lot of oil there, but it appears the industry hasn’t quite discovered the secret to producing oil from low pressure systems.  Once it does, we could have a lot of cheap oil on our hands.

A Close Look at SandRidge’s Results in the Mississippian

When Sandridge (SD) talks about its Mississippian acreage, it makes it sounds like there’s no “sweet spot” in the formation which implies that each of its counties are as good as the next.  There’s an advantage for SD to speak of its acreage like that, because with 1.85 million acres scattered across the Mississippian, the company is banking its future on the play (assuming it follows through with its plan to sell its Permian Basin assets).  Based on 160-acre spacing, SD estimates it has 11,000 net well locations of which it will have drilled a program total of 589 wells by year-end with 581 planned for 2013.  As shown by the graph below, the company’s early results in the Mississippian have me skeptical that all of its 11,000 well locations will be prospective for drilling at current commodity price levels.

SandRidge’s 30-Day Oil Production Rates in the Mississippian by County
Source: Oklahoma Corporation Commission / Kansas Geological Survey; The Energy Harbinger.
1The Oklahoma Corporation Commission (OCC) doesn’t provide natural gas production for wells designated as “oil wells”.  Oil cut based on initial production rates provided by the company in completion reports.
Note: 30-day production rates may differ from reported figures as the state doesn’t report the amount of days a well produced in a month.  For this reason, production may be understated.
Sample size: Alfalfa (46), Harper (13), Grant (43), Barber (7), Woods (13), Comanche (16), Total (138).

In Oklahoma, Alfalfa and Grant are its top producing counties although it has drilled a couple dozen wells in Eastern Woods County.  While production from Alfalfa looks to be much stronger than Grant, I don’t see much difference between these counties and expect them to perform similarly moving forward.  Alfalfa’s advantage over Grant can be attributed to two monster wells drilled by SD in the county, Puffinbarger 1-28H and 2-28H, both of which achieved 30-day production rates of more than 1,800 barrels of oil per day (BOPD).  The Woods County wells are gassier and less impressive overall, so I wouldn’t expect the company to do much there other than drill to hold.

In Kansas, results have been strong in Harper and Barber which are located across the border from the aforementioned Alfalfa and Grant Counties.  Production from Comanche, which is North of Woods, has been similar to Woods, thus less impressive than Harper and Barber.  All of this evidence leads me to believe that Woods and Comanche will be less economic than the counties to the east.  To that end, expect SandRidge to delineate its acreage in Sumner and Cowley (North of Grant and Kay Counties, Oklahoma) over the near-term.

A lot of people are wondering why SD’s impressive production numbers aren’t translating into bigger production “beats” with coinciding stock price appreciation.  One answer is steeper than expected declines in the Mississippian:

SandRidge Declines by Well
Source: Oklahoma Corporation Commission / Kansas Geological Survey; The Energy Harbinger.

The above wells are average to above average performing wells across SD’s acreage.  The company has to be disappointed by its Puffinbarger 1-28H well which has declined at a high rate since its impressive 120-day run when it produced at an average of 1,110 BOPD.  Despite recovering more than 150 MBO during its first six-months, the well has since fallen off the map and produced at a rate below 100 BOPD during September, 2012.  This is a disappointing result and one that undoubtedly contributed to the company’s decision to lower estimated ultimate recoveries (EUR) of oil to 155 MBO per Miss well.

Of the rest of these “average to above average performers”, 5 of 11 are producing at a rate below 100 BOPD as of August, 2012.  Does this mean SD was wrong when it claimed a 119% rate-of-return (ROR) for its Mississippian program earlier this year?  Yes it does and I would argue this has as much to do with its recent stock price struggles as anything else.  The company’s expectations came back down to earth in its Q3 2012 conference call when it adjusted its ROR target to 50% (still robust) on its Miss drilling program.

So what changed? The 30-day average IP of 181 BOPD that I computed (see graph above) on the 138 wells I looked at implies a rate of 324 BOEPD (56% oil/see footnote below).  This is very similar to the company’s reported program production rate.  Instead, steeper than expected declines in oil production combined with the realization that their acreage produces a lot of gas has caused the company to modify its expectations.  SD now expects its oil EURs to be 40% of total production (down from 45%) which is more in-line with what Range (RRC) has predicted.  Economically, I expect these wells to pay for themselves in approximately 2.5 years, longer than what you’ll find in the Bakken or Eagle Ford but still plenty economic.

I don’t see SandRidge having trouble achieving its (new) target Miss EUR of 155 MBO and 1.6 Bcf  (422 BOE) per well in its core acreage, but I’m skeptical of its assumption that economics will be similar in the extension.  Investor skepticism over this claim is probably another reason for recent stock price struggles.  To that end, the company would be wise to hang on to the Permian until it proves its theory on the extension Miss.

Note: The Oklahoma Corporation Commission (OCC) doesn’t provide natural gas production for wells designated as “oil wells”, so I inferred the total production rate based on initial production rates provided by the company in the completion report.

The Bakken and the Mississippian Lime: A Comparison

Were you one of the smart people who rolled their eyes at the comparisons of Adam Morrison to Larry Bird? Michael Jordan certainly wasn’t.  Is Lebron James the next MJ?  Probably not, but he might rival his value as an individual player.  While it may be trite, we’re constantly comparing what we know to what we don’t know in order to predict future performance.  The Mississippian Lime is a popular play in the oil and gas industry these days and has been compared to the Bakken due to its size and high projected returns, but not everyone agrees with the comparison.

Tom Ward, CEO of SandRidge Energy (SD), compared the Mississippian to the Bakken favorably in an interview with Seeking Alpha on April 20, 2012 saying, “Well, half of the production is gas, so I think there are people who believe that’s a negative where I look at (it) as upside, because the rate of return in our opinion is superior to the Bakken.”  Mark Papa, Chairman and CEO of EOG Resources (EOG), offered a sharp divergence from Ward’s opinion on the Lime at the Barclays Energy Conference in September, 2012 saying, “There’s been a lot of sell-side news and specific company news about plays like the Woodford, the Mississippian, the Niobrara, and so on and so forth but they barely make a spec on this chart.”  (The chart Papa was referring to is a chart of oil play growth from 2005 to 2012 which highlighted the Bakken and the Eagle Ford as the two biggest horizontal plays in the United States.)

These two CEO’s are publicly backing the plays the companies they run have chosen to bank their future growth on.  While this shouldn’t be surprising, the question remains: Is the Lime going to turn out to be Lebron James as Ward thinks or Adam Morrison?  Somewhere in between?  The best way to start a comparison of these resource plays would be to talk reserve numbers (see table below), but note these are both relatively new plays so the available reserve data ranges and is not widely agreed upon.

Recoverable Reserve Comparison (Billion Barrels of Oil)

My increase of Bakken reserve totals of 12% or 1.8 BBOE to account for natural gas and NGLs is consistent with oil/natural gas/NGL reserve cuts in the USGS’ 2008 Bakken reserve report.  Unfortunately, there’s not a lot of data on recoverable reserves in the Lime, so for now my analysis is limited to the IHS report on the Mississippian Lime.  Nevertheless, this data shows that the Lime contains approximately 49% of the recoverable reserves the Bakken contains, meaning the formation could yield about half as much hydrocarbons.  I would guess there’s upside to both of these numbers, as future downspacing and enhanced recovery should increase recovery factors.  The Lime may have the advantage here, as downspacing using vertical wells (see analysis below on vertical well economics) could be done using small spacing units and be an effective way to increase the recovery factor of the play.  To get a deeper understanding of the “why” for these two plays, I took a look at what separates them from a geological standpoint.

The reservoir rock in both the Mississippian Lime and the Bakken is Mississippian aged carbonate rock.  The rock in the shallower Mississippian Lime is (you guessed it) limestone while the rock in the Bakken is mostly dolomite.  The Bakken’s reservoir rock originated as limestome, but transformed to dolomite by undergoing diagenesis due to increased pressures and temperatures from layering.  As a result, the Bakken formation has higher pressures because it’s deeper than the Lime but lower porosities meaning it’s a tighter formation.  What does this mean for the oil and gas industry?

The lower pressure in the Lime translates to lower EURs per well, but said wells will also cost less as lower horsepower rigs can be used to drill the shallower wells. Fracking the Lime will also be cheaper than in the Bakken, as higher porosities allow operators to frack at lower pumping pressures and lower closure stress permits the use of cheaper proppants to “prop” the rock while hydrocarbons flow out of the reservoir.

The structure of the formations is another way in which they differ.  One of the features that makes the Bakken so prolific is its “bowl shape” (see cross-section below), which acts as a hydrocarbon trap and leads to consistent well results.  The Lime is considered a “stratigraphic trap,” meaning hydrocarbons are trapped by changes in the shape of rocks, often by thinning or thickening of the limestone as it presses up against a rock with low permeability.  What this essentially translates to is the Bakken being a steady producer across the formation with consistent oil counts, while EURs and oil cuts vary across the Lime.

The Bakken’s Bowl Shape

Source: Continental Resources’ Presentation at NAPE.

For instance, the Mississippi Lime gets shallower as you move from South to North and produces more oil the further North you go.  The map below shows that the Mississippian also gets oilier as you move from East to West.  So why are Alfalfa and Grant Counties the current hotspots versus oilier counties such as Osage or Pawnee?  Well, the oilier regions also tend to be shallower and this makes sense because oil requires lower temperatures to form than gas; however, shallow formations are also less pressurized which will lead to lower EURs.  In the end, the decision to drill in a less oily county will come down to the operator determining who wins in the trade-off between higher oil cuts and higher resource volumes.  This doesn’t mean Osage and Pawnee wells won’t offer great returns, they just might not be quite as good as those in Alfalfa and Grant.

Mississippian’s Oil Cut Increases from West to East

Source: Range Resources Corporate Presentation.

While the Bakken has an advantage in shape, the Lime is thicker.  When an operator drills into the Bakken, its target is the Middle Bakken which is approximately 50 feet thick and/or the Three Forks which is 35 feet below the Middle Bakken and approximately 100 feet thick (see stratigraphic maps below).  Thickness in the Mississippian ranges from 200 to 300 feet, meaning companies have more margin for error thus more options when drilling wells compared to the Bakken.  Because of tight carbonate rock, both plays must be fracked, but the structurally thin Bakken forces operators to complete wells with horizontal legs up to two miles long, whereas Mississippian operators can drill either vertically or horizontally (but with shorter laterals) depending upon the economics of the well.

Stratigraphic Maps: Mississippian on the left, Bakken on the right

Source: Devon Energy                                                                      Source: Kodiak Oil and Gas

While you can see from the map below that horizontal production is in ramp-up mode in the Mississippian, an interesting feature of the play is that verticals work well there too.  AusTex Oil (ATXDF) is a micro-cap company with 23,000 net acres in the Lime.  The company is completing wells in the play using multiple stage fracks in both vertical and horizontal wells. In Kay County, Oklahoma the company estimates a vertical well with a two-stage frack will cost $600k per well and produce EURs of 80 MBOE which translates to an IRR of 65%.  How will these results translate to the Northern portion of the play?

In its second quarter 2011 earnings transcript, SandRidge revealed that it has studied over 16,000 vertical wells in the play and believes the EURs in the Northern portion will be very similar to the South.  Verification of this assessment would go a long way towards proving the magnitude of this play, because this would imply economics would be even stronger in the extension area where oil cuts are higher and the formation is shallower.  SD has drilled 364 wells in the core of the play with 30-day average rates of 335 BOEPD (see graph below), implying an IRR greater than 82% using the company’s type curve.  46 of these wells were drilled in the Kansas portion of the play (still core Mississippian), with 30-day average IPs of 317 BOEPD, which imply an IRR of more than 82% as well.  The company will release results on its 2012 drilling program in the extension area later this year.

Source: SandRidge Energy Corporate Presentation

Horizontal Wells on the Kansas Portion of the Mississippian Lime

Source: Kansas Geological Survey

Most companies with large acreage positions will need to use horizontal production (at least initially) to hold their acreage before their leases expire.  Completion techniques vary, but two companies have recently altered methods and seen higher resource cuts as a result.  Range Resources (RRC) recently boosted its EURs on its Mississippian type curve to 600 MBOE from 485 MBOE after increasing its laterals to 3,468’ with a 17 stage frack from 2,197’ with a 12 stage frack, while only increasing well costs 10% to $3.2 million.  Petroquest Energy (PQ) announced 30-day IP rates for its first two Mississippian wells, PQML #1 and PQML #2, in Pawnee County, Oklahoma during its Q2’12 earnings call.  PQ’s wells were completed with 4,100’ laterals and 12-stage fracks and flowed back at 200 BOEPD and 525 BOEPD, respectively.  While this is a small sample size, frack methods may explain the performance gap between these two wells, as the second well used an acid-slick water mix in all stages versus white sand in the first seven stages in #1 and acid-slick water mix on the other five stages.

Economic Comparison

The table above shows well costs in the Mississippian are about half as expensive as its Bakken counterpart.  While Range’s EURs rival those in the Bakken, the company is basing the number off of a small sample size of six horizontal wells, so I would hesitate to use that number even as an upper bound of reserves per well.  A conservative EUR for the Lime would be in the 300 to 400 MBOE range (that’s the range Devon Energy (DVN) sites), just know that they will fluctuate and while RRC’s wells in Kay County may be large, they will be balanced out by lower EURs as you move to the Northern/extension portion of the play.  IRRs powered by prolific wells at low cost are where this play looks to be better than the Bakken.  There are issues with margins in parts of the Bakken, where high well costs combined with a WTI discount and high transportation costs can eat into a company’s returns, whereas the Lime’s proximity to Cushing will keep differentials under control.  A risk factor for the Lime is that it lies in natural gas country, and while a gas price recovery will help economics for the play, costs could go up coincidentally due to competition for frack crews and other services.

Circling back to the comments made by Ward and Papa, both seem to be right at least to some extent: Ward’s comment that the Lime has better returns than the Bakken is proving to be accurate and Papa’s claim that the Bakken makes the Lime look like a spec is accurate, at least for the time being.  The Bakken has seen production grow 550% since 2008 to 713 MBOEPD, which is not a number to shrug at.  IHS forecasts the Lime could produce 200 MBOEPD by 2020, which is less than a third of what the Bakken produces today.  Of course, the Lime doesn’t need to be bigger or better than the Bakken to be one of the best land resource plays in North America.  SD has proven that while the play isn’t as consistent as the Bakken (the graph above shows it has drilled 64 wells with 30-day average IP rates of 55 BOEPD), good wells more than make up for lackluster ones and have powered the company’s program IRR to over 80%.  The next step for the play will be to prove its extension area is as economic as the core, a feat that will be a major catalyst for most operators in this play.  The Lime may not be the next Bakken (or Michael Jordan if you prefer), but it’s proving to be a big, economic play and I’d put my money on it surpassing 200 MBOEPD well before 2020.