Blog Archives
Emerging Shale Oil Plays
By Peter Staas 8/11/2011
As the shale oil and gas revolution has picked up steam over the past several years, several important trends have emerged that will separate the winners from the losers.
The combination of depressed natural gas prices in North America and robust oil prices has prompted independent producers to ramp up drilling activity in fields rich in oil, condensate and natural gas liquids (NGL) while reining in operations in Louisiana’s Haynesville Shale and other dry-gas plays. By many accounts, natural gas production has become incidental to these higher-value hydrocarbons.
Besides focusing on a company’s production mix, investors must also evaluate the economics and quality of a producer’s acreage. first movers in oil- and liquids-rich plays have the opportunity to snap up the best acreage at a fraction of the costs incurred by late entrants.
For example, Marathon Oil Corp (NYSE: MRO) recently paid $3.5 billion for 141,000 acres (about $21,000 per acre) in the Eagle Ford Shale from Hilcorp Resources Holdings LP. The deal surpassed the $16,000 per acre that Korea National Oil Corp paid to Anadarko Petroleum Corp (NYSE: APC) to establish a foothold in this liquids-rich shale play.
The elevated prices that latecomers have paid for acreage illustrate the importance of being an early mover in these plays. This strategy has paid off for EOG Resources (NYSE: EOG), the leading oil producer in North Dakota, the Eagle Ford Shale and the Niobrara Shale. Lower entry prices translate into more financial flexibility and superior margins for producers that snap up the best acreage at pre-boom prices.
Readers of The Energy Strategist can attest to the importance of focusing on early movers that have acquired the best acreage.
My colleague Elliott Gue added Petrohawk Energy Corp (NYSE: HK) to the publication’s model Portfolio on May 10, 2010, citing the company’s acreage in the Eagle Ford Shale, a liquids-rich field in South Texas that the firm discovered in 2008. The stock represented a compelling value at the time; investors had overlooked this asset and the potential for the firm to grow its liquids output, focusing instead on its leasehold in the Haynesville Shale and exposure to natural gas prices. Elliott also highlighted the stock as one of his top takeover targets of 2010.
A year later, Elliott’s investment thesis panned out: Australian mining giant BHP Billiton (NYSE: BHP) announced that it would acquire Petrohawk Energy in an all-cash deal worth $12.1 billion. Readers who followed Elliott’s call booked a 92 percent gain.
With these advantages in mind, producers are constantly on the lookout for the next liquids-rich shale play that offers attractive margins. Here’s a brief rundown of some of the emerging shale plays in which North American producers have accumulated acreage.
1. Tuscaloosa Marine Shale
In recent quarters, a handful of independent exploration and production (E&P) outfits have touted their acreage in the Tuscaloosa Marine Shale (TMS), a formation that stretches from Texas to Louisiana and Mississippi. The field is far from a new discovery; famed Mississippi wildcatter Alfred Moore spearheaded drilling in the TMS in the 1960s.
The play’s proximity to the Haynesville Shale should make it easier for producers to redirect drilling rigs from the out-of-favor dry-gas play and limits bottlenecks associated with a lack of midstream infrastructure. Despite boasting similar geologic characteristics to the Eagle Ford, the TMS is far from a slam dunk, which explains the low prices that early movers have paid to build an acreage position.
Goodrich Petroleum Corp (NYSE: GDP), for example, amassed about 74,000 acres, paying an average of $175 per acre. Meanwhile, Devon Energy Corp (NYSE: DVN) has accumulated 250,000 acres on the Louisiana-Mississippi border at an average cost of $180 per acre.
Thus far, early movers in the TSM have yet to report drilling results, though management teams have indicated that these tests have been encouraging. Devon Energy recently completed drilling, coring and logging its first vertical well in the play and plans to sink its first horizontal well later this year. Denbury Resources (NYSE: DNR) and its partner EnCana Corp (TSX: ECA, NYSE: ECA) are at a similar stage in their drilling program and plan to sink a horizontal well in September.
During EnCana’s conference call to discuss second-quarter results, Executive Vice-President Jeff Wojahn described its TMS assets as “a promising liquids-rich opportunity” based on “how the rock breaks, the hydrocarbon content and gas in place, and the like.” Management also pegged the drilling costs for its first horizontal well–a 12,000-feet deep vertical shaft with a 7,500-foot lateral segment–at about $8 million.
Meanwhile, Goodrich Petroleum’s CEO provided a bit more color on his outlook for the TSM during the Q-and-A portion of the firm’s Aug. 4 conference call:
We’re very comfortable today with what we see from a geologic standpoint of going ahead and drilling wells. In fact we don’t really even see much need, at least in most of our acreage, for pilot holes. There [are] sufficient amounts of historical vertical wells that have been drilled through the Tuscaloosa Marine Shale that we’re comfortable going out and drilling today. I would characterize at least in our view that the sole or the largest single risk to the play is just one of the economic performance versus well costs. We know the Tuscaloosa is present, sufficiently thick, thoroughly oil saturated. It’s just a little unproven in that no one has drilled yet a well that’s demonstrated in the EUR horizontally that would match up to costs. And that’s just [be]cause there haven’t been really many or any of them out there that have done that.
Drilling results in this frontier play could provide a meaningful upside catalyst for these E&P operators. At the same time, if the play proves uneconomic to produce or drilling results disappoint, the low cost of acreage provides a degree of downside protection.
2. Utica Shale
Management teams from several E&P firms also touted the potential of the Utica Shale, a formation that lies beneath the Marcellus Shale but extends from Tennessee into Canada. Thus far, the Marcellus has attracted the most attention from investors and producers, though interest has picked up in the Utica–particularly the shallow portion in Ohio and Western Pennsylvania.
For example, Devon Energy has assembled an 110,000-acre leasehold in the play’s oil window and recently noted that a vertical test well indicated that the formation features excellent permeability. During Devon Energy’s conference call to discuss second-quarter results, the head of its exploration and production operations noted that the play’s oil window “could offer some of the best economics in the play.”
CEO Aubrey McClendon and his team at Chesapeake Energy (NYSE: CHK) likewise highlighted the firm’s position in the Ohio portion of the Utica during the company’s July 29 conference call. One of the first movers in the play, Chesapeake quietly amassed 1.25 million net acres–by far the largest position in the field–and drilled some of the first test wells, including nine verticals and six horizontals. Over this period, the company has also analyzed 3,200 feet of core samples and more than 2,000 well logs.
McClendon compared this portion of the Utica Shale to the Eagle Ford in South Texas, noting that the field includes three phases: a dry-gas zone in the east; a wet-gas window in the middle; and an oil-rich phase on the western side.
The outspoken CEO boldly suggested that the emerging field would generate better returns than the red-hot Eagle Ford: “[W]e believe the Utica will be economically superior to the Eagle Ford because of the quality of the rock and location of the asset.”
Not only is much of the company’s acreage already held by production, but the relative shallowness of these oil and gas reserves should limit drilling costs. Although management demurred from sharing well results, McClendon did indicate that his team was sufficiently encouraged to ramp up the rig count from one at the beginning of 2011 to eight units by year-end. At the same time, the play will require a substantial investment in midstream infrastructure to process and transport the oil, NGLs and natural gas to market.
3. Neuquen Basin
In The Future of Shale Gas is International, we opined that major international oil and natural gas companies were investing heavily in US shale plays to gain experience that would translate to fields outside the US. Argentina’s Neuquen Basin is home to one of the most-promising international shale oil plays.
Spanish energy giant Repsol (Madrid: REP, OTC: REPYY) in July announced that its Bajada de Anelo X-2 exploration well had yielded 250 barrels of oil per day from the Vaca Muerte shale formation.
US operator EOG Resources added 100,000 acres in the Neuquen Basin to its exploration portfolio in the second quarter and plans to sink two wells in this acreage in early 2012. During a recent conference call, CEO Mark Papa noted that he expected results from the play to help operators overcome a lack of hydraulic fracturing and other equipment in the country:
[T]he major service companies are in a process of shifting additional frac [hydraulic fracturing] equipment down there, and for the first couple wells, it’s going to be kind of one-off deals that we’ll have to schedule months and months in advance to get the fracs done. But our logic is if this shale turns out to be something that is commercial and productive, that you’ll see, particularly the major service companies, just move equipment in there in a 2013 through 2015 time frame. We’re pretty optimistic about the quality of that shale. We charged our people with the only way we’d go outside North America is if we could find a shale–an oil shale that we thought looked superior to the Eagle Ford, and we believe we’ve found one there. So time will tell.
Eagle Ford Shale: Information
Updated: April 14, 2011
What is the Eagle Ford Shale?
The Eagle Ford Shale is a hydrocarbon producing formation of significant importance due to its capability of producing both gas and more oil than other traditional shale plays. It contains a much higher carbonate shale percentage, upwards to 70% in south Texas, and becomes shallower and the shale content increases as it moves to the northwest. The high percentage of carbonate makes it more brittle and “fracable”. The shale play trends across Texas from the Mexican border up into East Texas, roughly 50 miles wide and 400 miles long with an average thickness of 250 feet. It is Cretaceous in age resting between the Austin Chalk and the Buda Lime at a depth of approximately 4,000 to 12,000 feet. It is the source rock for the Austin Chalk and the giant East Texas Field. The name has often been misspelled as “Eagleford”. A great picture can be found at the Energy Information Administration (EIA) http://www.eia.gov/oil_gas/rpd/shaleusa9.pdf which shows the structural contours and windows for the oil, wet gas/condensate and dry gas.
History of the Eagle Ford
It is named for the town of Eagle Ford, Texas where it can be seen on the surface as clay soil. Eagle Ford, Texas is approximately 6 miles west of Dallas, Texas. An outcrop of the Eagle Ford Shale can be seen in the Dallas-Fort Worth Metroplex. Wikipedia shows a nice picture of the outcrop of the Austin Chalk and Eagle Ford shale at the following link http://en.wikipedia.org/wiki/File:Austin_Chalk_-Eagle_Ford_Contact.JPG
Petrohawk drilled the first of the Eagle Ford wells in 2008, discovering in the process the Hawkville (Eagle Ford) Field in La Salle County (District 1). The discovery well flowed at a rate of 7.6 million cubic feet of gas per day from a 3,200-foot lateral (first perforation 11,141 feet total vertical depth) with 10 frac stages. Originally, there were 30 plus fields, however, due to field consolidations, the number of fields has been reduced to currently 16 fields
located within the Railroad Commission Districts 1 thru 6 and the fields cover 22 counties
Continents of the World
Mb50's "Liquid Mud" Rant 
