Tag Archives: Tuscaloosa Marine Shale

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.

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
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
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
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

Value Stock Search in the Eagle Ford

Comstock Resources (CRK), Goodrich Petroleum (GDP) and Penn Virginia (PVA) are three former Haynesville/Cotton Valley operators who’ve been buying up acreage in the Eagle Ford to compensate for low natural gas prices.  All three of these companies have market caps below one billion and have the potential to be a small/micro-cap growth story for your portfolio.  These companies also have debt-to-market caps North of 150% and are trading well off their 52-week highs, meaning they hold potential value if they can navigate their debt issues in the wake of low gas prices.  A common strategy among this segment of oil and gas companies has been to roll back their debt maturities to later this decade due to the expectation that natural gas prices will recover.  The graph below shows why these companies have been loathe to finance their respective transitions to oil with equity.

Source: Yahoo Finance.

As of market close November 13, 2012, Comstock was trading at $16.19 per share or 81% lower than when it peaked at $86.70 in July, 2008.  The company rolled the dice in December, 2011, when it spent $332 million or $7,543 per acre on a 44,000 net acre position in the Southern Delaware Basin.  This acquisition certainly made the company oilier by augmenting its 28,000 net acre position in the Eagle Ford (it has subsequently added an additional 13k net in the Delaware); but it also forced the company to issue more debt and CRK more than doubled its debt load to $1.2 billion from $0.5 billion at year-end 2010.  Comstock doesn’t like to issue equity and hasn’t in more than eight years, so the debt issuances show the company is sticking to its guns which is bold given its weight to natural gas (16% of Q3’12 production was natural gas/NGLs).

The company is probably done with any major acquisitions/divestitures and is now in full on execution mode.  To that end, it has been successful with 30-day IP rates in the Eagle Ford averaging 517 BOEPD (80% oil) and declining at a shallow rate over a 90-day period to 448 BOEPD.  Its acreage is primarily in Atascosa, McMullen and La Salle Counties, with McMullen primarily responsible for its results to date.  The Atascosa results aren’t as strong to date but the acreage is good, just not as consistent as McMullen.  The Atascosa block to the East is offset by EOG whose 30-day rates in the area are above 450 BOEPD.

Comstock is still working on its efficiency in the Delaware Basin where well costs have run higher than offset operators.  The company is confident that the costs will come down as it continues to delineate its acreage.  CRK will develop this acreage primarily with vertical wells (company believes 20% is prospective for horizontals) on small spacing units which will give the company more than 900 net well locations.  This will be a good oily cash flow piece for Comstock that should provide consistent results and diversification from the Eagle Ford.  Moving forward, it plans to spend within cash flow for 2013 with nearly all of its capex devoted to the Eagle Ford and the Delaware Basin.

As of market close November 13, 2012, Goodrich was trading at $8.94 per share or 89% lower than when it peaked at $82.92 in June, 2008.  With 38,200 net acres in the Eagle Ford, the company has a larger position than CRK (28,000 net), but the acreage is primarily in Frio and Northern La Salle which hasn’t been developed as much as other areas in the Eagle Ford, thus holds more risk.  The company’s early Frio wells have been mediocre to date, but its Burns Ranch lease in La Salle County has already produced 1.7 million barrels of oil on 22 wells.

While GDP has the lowest grade Eagle Ford acreage of these three companies, its 134,000 net acre asset in the Tuscaloosa Marine Shale (TMS) could be a game changer.  It’s still very early in the TMS, but it’s a good sign for GDP that the big boys are already in the play, with Devon (DVN), Encana (ECA), EOG (EOG) and Sinopec all having substantial acreage positions.  The TMS is deeper than the Eagle Ford which implies higher well costs, so GDP expects to find a JV partner for its acreage to help with financing and take some risk off its plate.  The company hopes to get well costs down to the $10 to $12 million range in the play and the thinking is EURs could be in the 500 to 600 MBOE range.  Goodrich is optimistic that the play will be economic, particularly when LLS pricing is considered.

As of market close November 13, 2012, Penn Virginia was trading at $4.61 per share or 94% lower than when it peaked at $71.63 in July, 2008.  PVA has the best acreage position in the Eagle Ford of the three companies, with 30,000 net acres in Gonzales and Lavaca Counties.  The company has shut-down its East Texas drilling until gas prices recover and will now exclusively develop its Eagle Ford acreage.  The early returns look promising as the company’s 30-day IP rates are averaging 525 BOEPD (85% oil) per well, results that have grown its oil cut to 38% of total production during Q3’12.  PVA believes it will be able to grow its Eagle Ford position in small chunks as it develops its acreage.  For 2013, the company plans to drill 22 wells and 18 wells in Gonzales and Lavaca Counties, respectively.

Financial Metrics

After looking at the stock price graph above, it’s easy to see how all of these companies look over-levered on a debt-to-market cap basis, as each has lost more than 80% of its market cap during the last few years.  If we look at Interest expense per BOE, which may be a more applicable metric to these companies, GDP and PVA still look over-levered as they’re paying $1.58 and $1.47 per Mcfe, respectively, which is high considering realized prices for natural gas.  CRK is paying $0.60 per Mcfe, much lower than the other companies in the peer group and certainly looks like the superior company from a metrics standpoint.

Based on acreage and metrics, I would have expected Comstock to be valued much higher than both GDP and PVA.  It’s my opinion that CRK is clearly the best value of this group and a solid small cap for your portfolio.  The company plans to spend within cash flow for 2013 (generated $226 million during the first nine-months of 2012) and has $200 million available in its revolver to plug any funding gaps.  PVA would be my second choice from this group as its reserves and production are significantly undervalued with respect to GDP despite its ability to generate $190 million in cash flow during the first nine-months of 2012 while GDP only generated $98 million.  Cash flow will be important for all of these companies as they don’t have much room to run debt wise and fear the consequences of an equity sale which would be very dilutive at current stock prices.

If you’re an investor in one of these companies the strategy is clear: transition to oil over the near-term to stabilize the company until natural gas prices recover.  In the meantime, roll back debt to later this decade at which point natural gas prices have (hopefully) recovered which will imply significant market cap growth.  At higher share prices levels, the companies can then issue equity to pay off their debt maturities.  I’ve said CRK is my number one pick from this group and probably the only one I’m buying at current valuations.  The other two have potential, but I think they’re too risky to add until they get production up to a point where their interest is more manageable.