Monthly Archives: December 2012

EOG Bakken Production Summary

Below is a graph of EOG Resources’ production results from North Dakota’s Bakken Shale by County.  The graph contains data on 414 Bakken wells drilled between 2008 and 2012, with 29 in McKenzie, 4 in Dunn, 344 in Mountrail, 26 in Williams and 11 in Burke.  Based on the data I collected, EOG’s average 30-day IP rate in the Bakken is 619 barrels of oil per day (BOPD) and 310 thousand cubic feet of natural gas per day (Mcfpd) or 671 barrels of oil equivalent per day (BOEPD) with an oil cut of 92%.

EOG’s Bakken Results by County
EOG_Bakken-results-by-county
Source: North Dakota Oil & Gas Division / The Energy Harbinger.

Most people think of EOG as a Parshall Field (Mountrail County) company and that’s certainly its core acreage; however, it has achieved solid results in both McKenzie and Dunn Counties.  I have data on 33 wells in McKenzie and Dunn, and these wells should all be considered part of the same play despite encompassing two separate counties as they lie where the Southeastern corner of McKenzie and Northwestern corner of Dunn County meet.  I’m not sure how much acreage the company has in this area, but the results have been strong to date.

EOG’s Mountrail County wells are the cornerstone of the company as it has drilled 344 wells there with an average 30-day IP rate of 632 BOPD.  Approximately 60 or 17% of the total wells it has drilled in the County have achieved 30-day production rates of more than 1,000 BOPD.  These results have helped put EOG in the upper echelon of independent oil and gas companies and contributed to its stock price more than doubling to $121.55 as of market close December 26, 2012 from $58.47 on market close January 3, 2007.

It doesn’t hurt that the company is also well positioned in the Eagle Ford where it has 644k net acres prospective for 65-90 acre spacing units or more than 8,000 well locations.  While it’s unlikely all of these well locations will be drilled, the inventory is impressive to say the least.

EOG is also building a position in the Tuscaloosa Marine Shale (TMS), where it recently completed its first well in Avoyelles Parish in 23 days, much faster than other TMS operators.  This is an important result, because production results have been strong in the play but costs have been high.

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I hope to do more posts like this moving forward so you guys can see more in-depth production data for companies you’ve invested in or are interested in.  As always, ask questions if any of the data/analysis seems odd.

-TEH

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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 Emerging TMS: Vast Oil Potential for Several Natural Gas Weighted Companies

Horizontal drilling and fracturing have been the keys which have unlocked vast oil reserves in North Dakota’s Bakken Shale and Texas’s Eagle Ford Shale.  The success companies have achieved while developing those two formations has led to the search for other shale formations with similar geological characteristics.  Enter stage left: the Tuscaloosa Marine Shale (TMS) which is a similar geological age to the Eagle Ford Shale.  The formation is deep, with depths ranging from 11,000’ to 15,000’, but contains plus 90% oil cuts and is prospective for economic quantities of oil in Louisiana and Mississippi (see map below).  Depths combined with low permeability in the TMS had previously dissuaded companies from developing the formation, but new technologies have led companies like Encana (ECA), Devon (DVN) and Goodrich (GDP) to explore the area with 21st century drilling techniques in their toolboxes.

Tuscaloosa Marine Shale Map
Tuscaloosa-Marine-Shale_Map
Source: LSU-Basin Research Institute.

The LSU-Basin Research Institute estimates the TMS contains seven billion barrels of oil reserves (unclear whether this is recoverable or oil-in-place) and spans eight million acres as shown by the highlighted band above.  Oil generation over-pressurized the formation in this band which has led to natural fracturing and increased permeability in certain zones.  The TMS refers to three different zones, the Upper Tuscaloosa (sand and shale), the Marine Shale and the Lower Tuscaloosa (sand and shale).  Until recently, the only well in the TMS was the Winfred Blades #1 well completed by Texas Pacific Oil Company in 1978.  This well was drilled in Tangipahoa Parish in Louisiana (Parish=County in Louisiana) and has recovered 20 thousand barrels of oil to date.

TMS Stratigraphic Map
Tuscaloosa Marine Shale_Stratigraphic-Map
Source: Louisiana DNR.

The Tuscaloosa Marine Shale has several advantages over other shale plays, including no severance tax on hydrocarbons recovered using horizontal wells in Louisiana for two years or until cost of well has been recovered and close proximity to the St. James terminal located on the Gulf Coast of Louisiana.  Crude oil sold to the St. James terminal has received a premium to WTI ranging from $10 to $20 during 2012 because the U.S. crude that reaches this terminal (most is currently sold at other terminals due to transportation costs) competes with higher priced Brent crude which is imported at St. James.  While this premium is currently an advantage for the play, expect it to decline as more U.S. oil from the Eagle Ford and the TMS is sold at St. James.

Disadvantages for the TMS are that it’s a high-cost, unproven play.  The high costs stem not only from its depth (deeper than both the Bakken and the Eagle Ford) and low permeability, but from complexities due to the thin layer from which natural fracturing (thus increased permeability) exists.  GDP is a micro-cap that is currently delineating its acreage in the TMS with four to five wells scheduled to be completed during the remainder of 2013.  In its third quarter earnings transcript, Goodrich revealed that the TMS zone which has natural fracturing is only ten feet thick.  This thin layer has led to issues with wellbore stability and resulted in well costs ranging from $14 to $16 million.  The company believes it’s making progress with this issue and expects well costs to decrease to around $12 million per well for wells completed with a 7,500’ lateral and 25 stage frac.

High resistivity in the TMS encouraged ECA and DVN to explore the play, with ECA drilling the first modern well in Amite County, Mississippi in 2007.  While this well has only recovered 35 thousand barrels of oil (MBbls) to date, the company has been more successful with its recent wells by tweaking its completion techniques to add more frac stages.

Its Weyerhaeuser 73H-1, spudded in August, 2011 in Saint Helena Parish, was completed with 17-frac stages and produced at a 30-day IP rate of 770 BOEPD (94% oil).  The company has achieved similar success with three wells in Southern Mississippi (North of the shoelaces on Louisiana’s boot), Horseshoe Hill 10H-1, Anderson 17H-1 and Anderson 18H-1 which achieved average 30-day IP rates of 695, 933 and 1,072 BOEPD, respectively.  The company will maintain its focus in Southern Mississippi, where it has 11 wells either drilling or permitted according to the Mississippi State Oil & Gas Board.

Encana’s TMS Results
Encana_Tuscaloosa-Marine-Shale-Results
Note: The above results were calculated by The Energy Harbinger using data provided by the States of Louisiana and Mississippi.  Data may differ from company reported figures, specifically in Louisiana where monthly production was assumed to be 30 days as the state doesn’t report the amount of days a well produced in a month.  For this reason, production may be understated.

Devon’s activity is focused across the boarder in Louisiana where its Weyerhaeuser 14H-1 in Saint Helena Parish produced at an average 30-day rate of 695 BOEPD (93% oil).  DVA’s other TMS wells include two drilled in the Tangipahoa Parish, the Soterra 6H-1 (completed in October, 2011) and the Thomas 38H-1 (completed during Q3’12), which produced at average 30-day IP rates of 176 BOEPD and 470 BOEPD, respectively.  The company completed four wells in the East Feliciana Parish during 2011 and 2012 with average 30-day IP rates ranging from 1 BOEPD to 285 BOEPD.

Devon’s TMS Results
Devon_Tuscaloosa-Marine-Shale-Results
Note: The above results were calculated by The Energy Harbinger using data provided by the States of Louisiana and Mississippi.  Data may differ from company reported figures, specifically in Louisiana where monthly production was assumed to be 30 days as the state doesn’t report the amount of days a well produced in a month.  For this reason, production may be understated.

While I would hesitate to put too much stock into these early results, ECA’s results in Amite County Mississippi are the largest and most consistent of the early wells drilled in the TMS.  Its Anderson 18H-1 well, mentioned above, has produced a Bakken like 85,454 barrels of oil durings its first 141 days of production.  At $95 oil (LLS currently in $105 range), this well would have grossed $5.8 million during this time period.  Now these wells are running expensive (ECA’s target wells cost is ~$14 million), but the early production results look robust.  If ECA can get its costs down, it may have a lot of oil on its hands.  Production from Louisiana’s Saint Helena Parish also looks strong, with both companies completing wells averaging more than 600 Bbls per day during their peak 30 days.

At a $12 million well cost, GDP believes EURs will need to be in the 350 MBOE range for the play to be economic.  It’s worth noting that DVN is targeting EURs at 400-600 MBOE (90% oil) which corresponds to an average 30-day IP rate of 700 to 900 BOEPD, whereas ECA revealed on its investor day that it has drilled several wells which it expects to recover hydrocarbons near  its target EUR of 730 MBOE (see table below).  While these target EURs are more than what GDP believes it will take to make the TMS economic, I caution that neither company has drilled many wells in the formation which makes it difficult to determine how large the play could be.  To that end, Halcon Resources (HK) is currently drilling a well in the Western part of the play in Rapides Parish, LA which should provide some intuition on play size.

Results over the near-term of this play will be important to pay attention to as they will be a catalyst for the companies involved.  The company-wide production cuts for its first movers, Encana, Devon and Goodrich, contained 6%, 37% and 23% oil, respectively, during the three months ended September 30, 2012.  One thing we do know about the TMS is that it’s oily meaning that it could provide all three of these companies a significant amount of oil reserves which will improve cash flows, reserve quality and valuations for each.  Below is a table describing each company’s position in the play.

TMS Position by Operator
Tuscaloosa-Marine-Shale_Operator Data

The Well Map (12-3-12)

Regular viewers of The Well Map know that I’ve recently added the Oklahoma side of the Mississippian Lime play to the map.  The Oklahoma production numbers come with several caveats discussed as follows:

1) Natural gas production information isn’t provided for wells the state designates as “oil wells”, so you will see an “NA” in the gas column for those wells.
2) Because I didn’t have natural gas production to determine an oil cut, the “oil cut” column was obtained from the initial production reported by the company in the completion report.
3) Oil production is compiled monthly and days producing of a particular well is not logged, so I assumed each well produced for 30 days per month in the “IP Days” column (just like Texas).  Because some wells undoubtedly produced for less than 30 days, production rate may be understated.

What additions/changes to the well map will be made moving forward?

1) By the end of December I’m hoping to have a redesign of the website which will include a filter to make navigation of the site easier.
2) I will continue to add wells in existing plays on the map with expansions into others coming soon.  If there’s a play you would like to see added sooner than later, let me know.

-The Energy Harbinger