Tag Archives: Range Resources

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.

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.

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: