Everyone, it seems, wants a piece of one of the shale plays that are spread across North America — majors, independents, privately owned producers, master limited partnerships (MLP) and even some of the neighborhoods that sit on top of them.
Natixis Bleichroeder tracked the progress of exploration and production (E&P) in North American oil and natural gas shale plays in its fifth edition of “The Shale Shaker.” Led by energy analyst John White, Natixis team of energy analysts reviewed economic models for what are considered some of the most advanced shale plays on the continent, including the gas-rich Barnett, Fayetteville and Woodford-Arkoma regions, as well as the emerging oil-weighted Bakken play in Montana and North Dakota.
“Need we say, the list keeps growing,” White said. Along with the usual players, that include a mix of public and private operators, E&P MLPs are entering shale plays “both from a grassroots lease and drill approach and from the acquisition angle.” The “sheer magnitude” of activity and lack of data from producers that buy and hold leases in third-party names to maintain secrecy has resulted in an overview that White said is not definitive for every leasehold and every player. However, his team detailed the efforts by many of the largest players in some of the most name-grabbing fields.
Still leading all others on every level is Barnett Shale in Texas, which “continues to be remarkable,” said White. “Data from the Texas Railroad Commission has recent production at about 2.2 Bcfe/d, a 22% increase over the year ago figure. The industry estimates that about 1,200 new wells have been completed in last 12 months.” Now some companies are “working to push the eastern limits of the play, including Range Resources Inc., Forest Oil and Westside Energy.
There are problems facing Barnett operators, which could face some of its emerging peers: “the tight water supply situation that affected drilling and frac’ing operations during the later portion of 2006 and into the early portion of 2007 has abated to a large degree” mostly because of increased rainfall. But Barnett operators also are facing increasing pressure from the neighborhoods that sit in the middle of some of the most abundant gas reserves.
“Due to the benefits of drilling multiple horizontal wells from pad locations, operators are going after whatever is within reach of a lateral wellbore,” said White. “This is bringing development activity within the city limits of Fort Worth and other nearby municipalities.” The producers are using “various terms…including urban acreage, rooftop leases, halo acreage, neighborhood leases, but it is all the same: leasing of commercial and residential tracts.”
Now, he noted, “many residential subdivisions are organizing through neighborhood civic associations to negotiate on behalf of residents. These groups are retaining lawyers to negotiate oil and gas leases with provisions specific for the subdivision.” And some producers are offering lease signing bonuses “in the $5,000 per acre range with a 25% royalty to neighborhood groups.
“Terms may go higher,” said White. “The Fairmount Historic Southside district [in Fort Worth, TX] is currently considering an offer from XTO [Energy Corp.] of a $15,000 per acre signing bonus and 25% royalty. It is our view that neighborhood leases will continue to sell at a premium due to the amount of collaboration needed to get community buy-in plus their strategic location advantage.”
There’s a reason producers want to negotiate: “Chesapeake recently reported production of 30 MMcfe from 11 wells at its DFW [Dallas/Fort Worth] airport lease. Chesapeake has 18,000 acres covered by its airport lease and is targeting a peak production level of 250 MMcfe by year-end 2007,” White said.
The University of Texas at Arlington is partnering with Carrizo Oil & Gas to explore and develop Barnett acreage on the Tarrant County campus. University officials have only committed to one drill site on the southeast edge of campus and will not commit to additional drill sites until further review, said White, but already, “Carrizo has identified five potential drilling sites in the campus area and has compensated the university with a $391,000 payment for the right to explore, a donation of $400,000, and a 27% royalty.” Initial drilling is expected early next year.
Another triumph for the Barnett leaseholders is the higher reserves per well, said White.
“In our research on the economics of the Barnett, we found companies are disclosing higher reserves for wells in each of the core, tier 1, and noncore areas compared to approximately one year ago.” (The core is in Fort Worth, with tier 1 production immediately surrounding the city and its adjacent counties.) “This is due to continued refinement of drilling, completion, and frac techniques. Based on company reports and our estimates, we are now using 4.2 Bcfe of reserves for the core versus our previous 3.5 Bcfe. Similarly, we are now employing 2.8 Bcfe of reserves for tier 1 versus our previous 2.2 Bcfe and 1.6 Bcfe for noncore versus our previous 1.1 Bcfe.”
As other analysts have discovered, Natixis reported that Barnett’s costs are falling. In the core and tier 1 areas, Natixis reported that completed well costs are between 10% lower to flat from the same period a year ago. In general, White credited lower rig rates that were “partially offset by longer laterals, more extensive frac jobs and more expensive flex-rigs.”
Natixis base-case pricing in 2008 is $70/bbl for oil and $7.30/MMBtu for gas — which would offer operators a “robust” return. However, even if gas were to fall into the $4.50/MMBtu range, the Barnett core and tier 1 properties still would offer the “highest returns” of any other major gas shale play in the country. The Fayetteville, Barnett noncore and Woodford shales, among others, “would all probably experience significant slowdowns in activity” if gas were to fall to the $4.50 level.
“The repeatability of these plays and the desire to keep costs low through economies of scale adds an interesting element to the equation should a period of lower oil and gas prices materialize,” White said. “The repeatability and predictability of the established shale plays is much higher than conventional plays. In many of the conventional plays, operators will drill and complete a well and then observe the production and integrate the new well data into the subsurface analysis before commencing the next well.”
When gas prices fall, “these economies of scale and plans for multiple wells planned several quarters in advance will be an additional consideration in the decision to curtail drilling,” said White. “Curtailment of drilling would not only bring about lower production growth rates but also severely jeopardize the economies of scale and have a negative impact on planning and timing of the drilling effort.”
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