Tag Archives: Mississippian Lime

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
puffin-balder-misslime-well

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

Miss_Revenue-by-Hyrocarbon

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)

miss-production-graph

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.

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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).

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
sandridge_Mississippian-Well-Results-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
SandRidge_Mississippian-Well-Declines
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.

The Mississippian Lime: America’s Next Big Resource Play?

There’s no doubt that shale plays are sexy in the oil and gas realm these days, but prudent investors know all that really matters is return on investment.  Valuations are high in South Texas’ Eagle Ford Shale, where private equity firm Kohlberg, Kravis, Roberts & Co (KKR) recently agreed to pay $25k per acre in a participation agreement for up to 1/3 of Comstock Resources’ (CRK) undeveloped Eagle Ford acreage.  In North Dakota’s Bakken Shale, Bakken pure-play Kodiak Oil & Gas (KOG) paid $11,800 per acre in a deal late last year with two private companies.  If investors are looking for a value play, they should turn their heads to the Mississippian Lime, where acquisition prices averaged $3,284 per acre1 during the past year.

Source: Orion Exploration Partners August, 2011 Mississippi Lime Presentation

The Mississippian Lime, located in South-central Kansas and North-central Oklahoma (see map above), is a shallow carbonate play (mostly Limestone) with depths ranging from 3,000’ to 6,000’.  The Lime is not a new play, but an old producing field with more than 30 years of production and 14k vertical wells drilled.  It’s now being redeveloped using horizontal drilling and fracking techniques, and in that respect could be compared to the Permian Basin of West Texas.  While conventional production in the play stemmed from the “Mississippian Chat,” a reservoir with high porosity and permeability above the Lime, new development is targeting the tighter Mississippian Lime that underlies the Chat (see cross-section below).

Mississippian Lime Cross-Section

Source: Range Resources Corporate Presentation

Because the Lime is shallower than the Bakken and Eagle Ford, companies use smaller drilling rigs and cheaper proppants which has led to drilling and completion costs between $3 and $3.5 million, less than half of what an operator would pay in the Bakken or Eagle Ford.  The play is estimated to span 17 million acres with oil in place estimates ranging from 5.4 to 5.9 billion barrels of oil equivalent (BBOE).  This impressive amount of oil in place has companies like Sandridge Energy (SD) drilling three wells per section, which increases the recoverable reserves in the play.  For a more complete view on the Lime’s economics, let’s take a look at its most experienced operator, the aforementioned Sandridge Energy.

An intelligent discussion on the Mississippian Lime can’t be had without talking about Sandridge, who has drilled 382 horizontal wells or 44% of the total horizontal wells drilled in the play.  The company has amassed 1.7 million net acres in the Lime, from which it expects to generate estimated ultimate recoveries (EURs) of 456 thousand barrels of oil equivalent (MBOE) per well.  These EURs are based on 30-day average IPs of 275 barrels of oil equivalent per day (BOEPD), or put another way, a well that produced at an average rate of 275 BOEPD for 30-days is expected to produce an EUR of 456 MBOE.  How does this model out on a return basis?  SD estimates that a well which produces at a 30-day average rate of 244 BOEPD will have an 80% rate of return (ROR), a solid rate for a company whose average 30-day production rate is 325 BOEPD per well (119% ROR).  The table below shows how SD’s EUR estimate in the Lime compares to those of operators in other prolific plays in the U.S.

Play Economics

1Includes liquids content which prices at a discount to oil

As you can see from the table above, the Mississippian is by far the cheapest formation to produce from with respect to the peer group.  It’s worth noting that EOG Resources (EOG) and Continental Resources (CLR) are two of the premier operators in their respective plays and  if you were to take a survey of average well costs across those plays, I would expect current costs to average between $7 and $10 million per well.  The Mississippian is a play that produces more hydrocarbons per dollar than any of the above mentioned plays, with the main negative being a lower oil cut.  Despite its lower oil cut, SD is still reporting an average rate of return of 119%, a rate that has plenty of natural gas pricing upside.  The Lime also gets oilier as you move from East-to-West, and SD has reported several wells in Alfalfa County, Oklahoma with 30-day production rates in excess of 2,000 BOEPD (90%+ oil cut).  So while it’s a gassier oil play than some would like, oil cuts vary and returns are high.

These numbers aren’t going unnoticed by the oil and gas industry, but have prompted industry titans such as Chesapeake Energy (CHK), Apache (APA), Devon Energy (DVN), Encana (ECA) and Repsol (REP) to accumulate large acreage positions in the play.  CHK has approximately two million net acres in the Lime, making the play its top liquids play by acre and a key component of its shift towards liquids production.  The company plans to run 22 rigs in the Lime versus 30 in the Eagle Ford and 10 in the Utica during 2012, meaning this struggling company has levered itself to these three plays to resurrect its share price (down 73% from its high of $69.40 in July, 2008) and pay down its high debt levels.  Acreage positions of other large caps in the Lime: APA: 580k, DVN: 545k, ECA: 360k, and REP: 363k (see map below).

Range Resources (RRC) made its excitement for the Lime obvious during its second quarter earnings call, affirming its decision to market its Ardmore Woodford acreage to help finance the acceleration of its Mississippian development.  On the call, Jeffrey Ventura, President and CEO of RRC said regarding the planned divestiture, “Although the rate of return in the Ardmore Woodford is very good, the rate of return in our horizontal Mississippian play is even better.”  RRC’s excitement stems from two gushers it recently hit in the play, one which peaked at 1,363 BOEPD and a second which peaked at 1,950 BOEPD.  The company hit these wells after modifying its drilling and completion techniques by lengthening its laterals and fracs to 3,468’ and 17 stages versus 2,197’ and 12 stages previously.  For that reason, keep in mind that this is still an emerging play in its beginning stages with upside potential as companies tweak their completions.

Who’s where in the Lime?

Source: Map data was prepared based on public data provided by companies.  Please note that this map is only meant to show the acreage location of certain operators and no precedence is given to companies based on format or color.

The above map (prepared by The Energy Harbinger) shows where certain operators own acreage by county.  Because not all operators have disclosed where they’re operating and some companies have only partially disclosed the counties they operate in, this map is incomplete.  However, it does show the extent of the play and some of the more popular counties.  Net acreage by operator: APA: 580k; Atlas: 7.25k; Chesapeake: 2,000k; Devon: 545k; Equal: 7.25k; HK: 45.28k; Range: 152k; Sandridge: 1,700k.

Now we know the big operators that are in the Mississippian; however, there’s plenty of smaller companies with large acreage positions there too, including Petro River Oil.  This private company is interesting not only because it has amassed 100k net acres in the Lime, but because of its strong leadership team.  The company boasts two CEOs, Daniel Smith and Ruben Alba, who combined have several decades of experience in the oil and gas industry.  Mr. Smith has experience growing companies to maturity, serving as the Operations Engineer at XTO Energy before it was bought by Exxon Mobil (XOM) in December, 2009.  Mr. Alba brings an extensive oil service resume to the company.  Not only has he spent the majority of his career working for Halliburton Energy Services and Superior Well Services, but he also holds several patents in completion technology.  These Co-CEOs are supported by Luis Vierma, who spent several decades at Venezuelan state-owned oil and gas company PDVSA, where he served as the VP of Exploration and Production.  Bottom line, if there’s a private company to keep an eye on in the Lime, its Petro River.

If one of the negatives on the Lime is its lower oil cut, a second would be its high water content.  Sandridge is reporting an average of 2k to 3k barrels of water per day during the first 30-days of production per well.  To efficiently dispose of this water, companies must develop a network of salt water disposal wells (SWD) which they will inject produced water into for disposal in the Arbuckle Group formation (see Mississippian cross-section above).  While SWD wells add complexity to the Lime, they are relatively cheap to drill (~$265k per well) and will service water for between six and eight producing wells.  If we divide $265k by six (low end of estimate), we find that SWD wells add roughly $44k in expenses per well.

What can we expect from the Lime moving forward?  Companies like Devon and Encana, who’ve recently added 400k and 220k net acres, respectively, will be ramping-up production to delineate and hold their acreage positions.  The core of the play, lying in South-central Kansas and North-central Oklahoma (see map above), has been delineated for the most part and has proven to be consistent.  While the extension area hasn’t been delineated with horizontal production, the area holds more than 7k producing vertical wells and is an oilier field than the core.  SD is beginning to drill wells in the extension area of West-central Kansas (see above maps), where it holds 900k net acres.  The company’s initial extension wells are located in Hodgeman, Finney, Ford, Gray and Ness Counties and the company expects to announce results from these wells later this year.  Apache’s entire acreage position (580k net) lies in the extension portion of the play (see map above), and its delineation will be important to pay attention to.  If SD’s and APA’s wells prove to be as economic as the core, the land grab currently happening in the core will quickly spread North, creating one of the biggest plays in the United States.

1 Based on the following four deals: