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

The Limes inconsistency has led some companies to leave the play and some to dial back expectations. but theres 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

This data tells us that SDs early wells didnt pay out in two years based on a $3.2 million well cost. While thats an important data point, investors should be more concerned with the results from the next thousand SD wells than the first 100. So lets compare these results to what were seeing from the companys newer wells.

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

*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 wells revenue. If the 2012 wells continue to produce 20% higher than the 2011 wells, theyll 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, were not sure why SandRidges 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 theyve 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, youve 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.

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.

1 Production results during first six-months of well.

2 Natural 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.

3 Cost per barrel calculated as estimated well cost divided by first six months of production.

4 Estimated revenue generated from well during first 6-months of production. Assumed 85$ oil, $3 natural gas and 80% NRI.

5 Cletus 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.

1 Production results during first six-months of production.

2 Natural 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.

3 Cost per barrel calculated as estimated well cost divided by first six months of production.

4 Estimated 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.

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

I dont usually talk about largest wells in formations or plays because they arent representative of the productivity or economics of a play as a whole. With that said, its still good to know where the biggest wells are being drilled because that usually indicates theres 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)

Spud Date: April 15, 2008

Peak Month Rate Oil: 1,492 BOPD

Peak Month Rate Gas: 1,008 Mcfpd

Cumulative Oil: 911,627 BO

Well Name: Jendrusch Unit 1H

Operator: Plains Exploration and Production (PXP)

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

Well Name: Livestock 1-25H

Operator: SandRidge Energy (SD)

County, State: Grant, OK

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

Well Name: Federal 16-10/3FH

Operator: Helis (Private)

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

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

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

I regularly spend time digging through earnings transcripts as I research the various companies and formations I write about.  While its currently post earnings season, I thought Id post a few notes from earnings calls from several companies Ive recently looked at.  These notes arent necessarily the most important points from the call, just ones that interested me.

* 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 its testing different areas of acreage position and different intervals to see which work best.  Its confident the play will be economic.

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

*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, Nicaraguawhats 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).

*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).

*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).

*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).

*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.