Via Halcon Conference Call. They will participate as a WI in other operator's wells.  Current well results and costs don't work with current crude prices 


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They will be back. Recent conversation with them lead me to think that they see this drop in oil price as a catalyst to bring costs of drilling and completion way down. They were complaining about having to pay top dollar for rigs and completion services due to the high demand. This could solve one of the major problems with TMS economics. If it does they will come back in

IMO there is a problem beyond the price of crude and that is well cost.  I have been interested in data regarding cost and it's not easy to come by.  TMS horizontal wells drilled in LA are eligible for a severance tax abatement based on well cost.  A handful of early wells have received their exemption and the form entered in the database.  Here is the list I have so far that anyone capable of using SONRIS Document Access may review independently. 

ECA Weyerhaeuser 60H #2 (244934) $18,990,788

"        "                              #1 (245238) $18,619,704

GDP Weyerhaeuser 51H #1 (247041) $18,678,090

DVN Murphy 63H #1H (244560) $25,772,882

DVN Thomas 38 #1H (244870) $19,855,870

Even if we consider the DVN Murphy as an outlier the average well cost is >$19MM per each.  Granted the sample size is small and the wells are early designs.  However since these early phase wells the later wells have become more expensive, not less, owing to longer laterals and increased proppant.  Any savings in drill days are likely offset to some extent by these changes.  As completion costs rise, the ability of the operators to drive down costs diminishes.  Where once well cost was approximately 50% drilling and 50% completion, the ratio is now closer to 45% drilling and 55% completion.  Drilling is under contract for a day rate and the fewer days to drill the cheaper the well.  Completion ops (frac crews) are a completely different story.  There is no competition, the demand for completion crews is not great because there are so few rigs running and not enough work for frac crews to stay busy.  It doesn't add up to a situation favorable for driving down well costs. 

GDP claims a cost to drill a development well of $13MM.  I'm suspicious of that claim but don't have the facts to refute it.  I will however point out that the majority of wells being drilled and those that need to be drilled by all the operators are not development wells, they are exploration wells drilled in Wildcat areas where a Pilot Hole is required to determine the correct landing depth.

I currently have on my desk an AFE for a Wilkinson County well with an estimated cost of $19,288,310 - Drill Cost >$8,600,000 and Completion Cost > $9,800,000. That estimated cost is based on everything going right.  This is a very recent AFE for a well yet to be drilled.

Skip, as you pointed out most of the wells in your pool are pretty old, when would data about well cost for Goodrich's newer wells like the Blades 33H-1 & SLC 81H-1 be available?

Whenever GDP decides to file for their exemptions.  No way to know when that may be but I suspect that there is a reason for not filing in a timely fashion.  If they file forms with well costs higher than what they claim in their public announcements it would be an embarrassing situation at the least.  And potentially a problem with the SEC at the worst. 

GDP's total rigs currently drilling for the company - 4.  HK has 5.  Neither company is likely to get any major discounts from drilling contractors at their level of activity.


Keep in mind that 2 or 3 of those Weyerhaeuser wells had significant wellbore instability/sidetracking issues that led to cost overruns. That's not to say such problems are an anomaly by any means, but it is worth keeping in mind when appraising costs.

Andrew, I do.  I also watch the drill time on the wells being drilled now.  For example the Comstock CMR FOSTER CREEK 28-40 #1 was at 94 drilling days as of last Friday.  That certainly will not help the average well cost.

The mechanical issues are part of the challenge of the TMS and selected wells can not be removed from the sample set simply because of those issues.  The very recent Sanchez AFE only reinforces the fact that the wells are high cost even when things go smoothly.

Steve, totally bogus argument by HK.  The only way drilling & completion go way down is if oil stays down for a long time.  People forget that service companies also have contracts (hedges) for their services, so they will be collecting top dollar on these contracts for awhile.  For HK to want to go back into the TMS they say they need the price of oil to rise, but by the time the price reaches the necessary level for the TMS all the other lower cost oil plays will be ramping up and the cost of services will again be high.

Remember all those leases that HK bought from ECA are getting pretty old and it takes time to ramp back up after a hiatus.  HK will have had ECA acreage for over a year and will have drilled less than 10 wells, you don't HBP 300,000 net acres at that pace.


Posted on November 11, 2014 at 11:21 am by Rhiannon Meyers

(Eddie Seal/Bloomberg)

As Halcón Resources Corp. dials back drilling plans in the wake of plunging oil prices, the Tuscaloosa Marine Shale will bear the brunt of the spending cuts, the company said Tuesday.

CEO Floyd Wilson told investors in a call Tuesday morning that while he remains confident that the play in Louisiana and Mississippi has the potential to gush lots of oil, it’s too expensive to justify drilling while crude continues to fall.

“Right now, with oil prices where they are and service costs where they are, we’ve elected to slow down there,” he said.

Before oil prices plunged below $80, the Houston-based independent oil and gas company had planned to expand its 2015 drilling program in the Tuscaloosa Marine Shale from two to four rigs.

Halcón now plans to pull its two rigs out of the shale and focus solely on its two key regions — the Williston Basin in the Bakken/Three Forks shale and the El Halcón in the East Texas Eagle Ford region.

The company will pull back on the number of rigs it plans to operate next year from 11 to six, down from the eight Halcón is currently operating. Those six rigs will be divided between its two star plays, Wilson said.

The decision to pull back from the Tuscaloosa underscores the wide disparity between the economics of different shale plays. Drilling in the core acreage of older, more established plays tends to remain profitable even at very low crude prices while newly developed regions and riskier plays require higher oil prices to remain economic.

In the core of the Eagle Ford Shale in South Texas, the domestic benchmark price would have to plunge as low as $30 to $40 a barrel before companies no longer found it economically feasible to drill there, according to a recent report by Tudor Pickering Holt.

The Tuscaloosa Marine Shale was the least economic of the basins studied by Tudor Pickering Holt, requiring a West Texas Intermediate price between $70 and $90 per barrel.

Still, Wilson said Halcón remains confident about its acreage in the Tuscaloosa. The company plans to continue participating in wells in which it has a stake but doesn’t operate and will assess its drilling plans as oil prices dictate.

“We’re really in a great position to ease back, watch prices, watch costs, review data and set a course,” he said.

Halcón announced Monday that it planned to cut rigs and slash spending as the company struggles against the double punch of falling crude and high, and in some cases rising, service costs.

The company posted a $186.9 million profit in the third quarter, compared to a $860 million loss last during the same time last year, thanks in part to surging production and more efficient drilling and completions.

Halcón plans to slash its drilling and completion budget by $300 to $400 million next year, sending some of the strongest signals yet that slumping oil prices are taking their toll on small independent exploration and production companies.

The company had originally planned to spend $950 million in 2014, but a private equity firm that joined Halcón as a partner in the Tuscaloosa Marine Shale earlier this year chipped in an additional $150 million, boosting the budget to above $1.1 billion.

Halcón now says it will spend $750 or $800 million on drilling next year. Despite the spending cuts, Halcón expects to pump 15 to 20 percent more oil next year, thanks to dramatic reductions in well costs and improvements in overall results.

What will they do with all of the Acerage that they have Leased  ????


Some of that acreage under HK leases will get drilled by other operators.  That's what is meant by participating in wells drilled by others.  The leases not drilled by others and not located in a producing HK drilling unit will remain in force for the length of their term.  Some of those leases will contain an option to extend the lease for additional years beyond the primary term should HK choose to exercise their option.  HK can also assign leases to other operators who may be interested in forming TMS units. 

It is worth noting that HK has other ongoing plays where they can spend their drilling dollar on wells with better economics. ECA and CRK also. GDP does not have that option.  They have bet the farm on the TMS and will likely have to continue to drill to maintain cash flow even if they are loosing money on each well. 

Maybe GDP will Drill those Newly proposed HK units SE of the Blades ...Although they have plenty of units of there own that need drilling..There sure is a lot of surveying and well  pad prep going on around here....


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