Some Operator Notes: ECA, GMXR, QEP
Here are some E&P notes from the 2Q Earnings reports that may be helpful to some of you guys. I noticed many Haynesville operators discussing that they have not been feeling drilling and completion cost pressures in the Haynesville lately. Dry gas is not exactly in favor, especially not $9.5MM per well dry gas such as the Haynesville. The name of the game has been program ramp-downs and drilling efficiences.
EnCana Corporation (ECA)
-Averaged 487 MMcf/D in 2Q 2011, up 89% from the 2Q 2010. ECA plans to average 505 MMcf/D at YE 2011 and > 1 Bcf/D at YE 2015.
-ECA drilled 23 wells in the 2Q and 45 wells in the first half of 2011. ECA will drill 86 net wells in 2011.
-Plans to drill a total of 85 net wells by year end, holds 350k net acres.
-Operating 11 rigs and participating in 9 non-operated rigs. Significant JV with Shell.
-Drilling cycle times are down over 20% year-over-year, in large part due to hub development.
-Hub design can reach efficiencies of 40 days spud to rig release, 50% gains in frac stages per crew per month
-ECA obtained regulatory approval for first Louisiana cross-unit alternate unit wells which allows for the drilling of 7,500’ laterals spanning blocks of 3 sections. Future plans call for 10,000’ laterals.
-Guidance set at 505 MMcfe/D at YE 2011
-ECA will continue to delineate Bossier Shale, holds 150k-200k acres.
-Haynesville NGIP: 175-225 Bcf / section. Mid Bossier Shale NGIP: 100-200 Bcf / section
QEP Resources (QEP)
-16 completed wells from 1Q2011 earnings call to 2Q2011 earnings call
-Not affected by rising well costs
-D&C $9.1MM/well in 2011, down from $9.3 MM last year
-Lacks one section until Haynesville is HBP, company estimates that 6 rigs will be an appropriate level thereafter
-Strong proponent of restricted rates, the practice helps maintain reservoir integrity and curtails sale of cheap gas
GMX Resources (GMXR)
-25,224 net core HA/BS acres
-During the 2Q 2011, GMXR completed 3 long lateral Haynesville / Bossier wells (~6,500’)
-The long laterals fall in line with previous EUR guidance of 6.5 Bcf / well
-GMXR will suspend Haynesville drilling due to depressed gas prices and lack of significant service cost reduction. The company’s 8th and final well of 2011 will be completed in the 3Q.
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Last year I blogged a few times on the first Petrohawk-operated, restricted rate well in the Haynesville. How did I know it was the first? Petrohawk said so in one of their conference calls. It has been a while so I feel the need to post an update. This will be short and sweet.
First, let’s set the scene. The border of Red River and De Soto Parish. Below is the map highlighting the 17H, as well as a number of offset wells (all HK operated). I used the nifty Drillinginfo label feature to identify the first prod date, the peak gas production, and the cumulative gas produced thus far.
Next I used a different tool in the Drillinginfo arsenal, HPDI. For those unfamiliar with HPDI, it is widely regarded as the best data set for US oil and gas production (ask the EIA among others). I exported the monthly production data and dropped it into an application called spotfire. I used spotfire to make the charts look pretty but you could use Excel to deliver the same results.
Of the 7 wells depicted, I believe only two were produced at non-restricted rates. This is based on the significantly higher IPs and initial declines. I say “restricted rate” in reference to the reservoir optimization technique as I am aware all wells are produced with some amount of choke control. These two non-restricted rate wells appear to have been choked back around month 3, as there are about 4 months of relatively flat production following the steep initial decline.
Can conclusions be made here? Sure, it took the Matthews 17H 5 months to catch up to the Matthews Trust 7 despite having an initial production rate 30% less. This data shows that reservoir optimization by restricting rates does in fact help the production in the first year. DI-ESP includes a very detailed study of restricted rates in our Unconventional Play Studies which includes the Haynesville. This quick blog does not go too deep into the details, but it does show how DI subscribers could go about performing these analytics themselves. Let me know any thoughts.
I am going to make this post short and sweet, basically a compilation of a few slides I was working on for internal use.
Here are some recent Haynesville producers.
Using data straight out of Drillinginfo, I made a chart of peak monthly gas rates and 3-month declines through time. I chose EOG and EXCO because they are two top operators. Clients of DI-ESP have access to not only this Drillinginfo data set, but also the coveted DI-ESP data set. The ESP data set is a combination of all the Drillinginfo and HPDI data, plus all other DI products. This forms one, all inclusive, set that seeks to provide the BEST answer possible.
It can be tough to model the effects of restricted rate production in less mature plays. Some of the trends you see are simply due to science stage testing or lack of infrastructure. We look to mature plays like the Haynesville, Barnett, and Bakken to identify trends that may have serious impacts on other emerging plays.
Speaking of emerging vs developed plays, here is a neat chart of EnCana’s learning curve. I always like these charts, the learning curve is real and should be taken into account when passing judgement on operator performance and economics. If an operator quotes a 50% ROR in a play, you should do some due diligence to determine if that number reflects producing wells or future wells. Take note Mr. Berman.
I know I haven’t blogged on the Haynesville in a while, I am working hard to find the time to continue blogging on all the plays DI-ESP covers. This is a challenge, but well worth it for the feedback we receive from readers and clients.
The Drillinginfo suite of tools includes Drillinginfo, HPDI Production Tools, DI-ESP Unconventional Research Platform, Earth Model (which includes isopach maps of unconventional plays, structure maps, log interpretation, sequence stratigraphy, etc) and DI-International (DII). All these tools are delivered in user-friendly platforms designed for quick and easy analysis as well as for in-depth studies of particular areas.
This blog is an example of a 5 minute, quick snapshot of a particular county. I chose San Augustine because it is part of what has developed into a second Haynesville core (the SW Extension) and we recently released DI Landtrac data for this county.
Here are the maps. First, a map of 2010 operator activity. I also used the export data functionality to put the data into an Excel pivot table. Second, a map of San Augustine 2010 wells colored by cumulative production and bubbled by Max monthly gas prod. The larger cums are to the SE as well as the larger monthly gas prods.
Finally, I turned on the new Drillinginfo Landtracs. We use Drillinginfo Landtracs internally to understand what companies have exposure to what areas, sweet spots in unconventionals etc.
Clients of DI-ESP have access to our aggregation of gross lease positions based on Landtracs and DI leases. It is a great time saver and utilizes our expertise of the Drillinginfo products and unconventional reservoirs.
The hardest part of this blog was using wordpress to compile it. The maps, data export and Landtrac took under 5 minutes…
TX Haynesville Snapshot
Operators are drilling up the Haynesville despite the increase in well costs and commodity spread. Has activity decreased? Of course. With the deepest wells costing around $10MM per, only the best wells will be attractive.
This entry looks at TX Haynesville activity. Specifically, a quick snapshot of permitting and production. Ill just post the slides below.
The total depth graph shows the depths increase as you venture south in the SW extension. The permit chart shows the peak of Haynesville activity in early 2010. Although the wells permits fall off during 2010, the SW extension wells stay relatively constant using the “eye test”. The North wells however, drop off significantly.
EnCana and others are experimenting with ways to cut costs. EnCana has saved over %15 using drilling pads at their “Gas Factory” locations. EOG said they will try to transfer the Hiway fracs to the Haynesville, they are apparently cheaper than hybrid. Even though the Haynesville is expensive, the gas is not going anywhere. Operators are interested in shoring up this proved gas in place, its just a matter of the price.
Encana just had their 4Q2010 conference call this Thursday and gave some detailed info on how their Haynesville assets have performed in 2010 along with new directions the Company is heading for the current year.
Over the last quarter, Encana has added 1.3 Tcfe of reserves in the Haynesville Shale. The per well costs are said to be approximately $1 million but may go over that, specifically in this play. Overall production rates were averaged to be 410 MMcfpd as the Company closed out the year with 10 rigs in their multi well drilling pad. Drilling costs were lowered by 18% from the previous year.
During the call, members of Encana’s team stated that permits for 12,500 acres in the Haynesville expired prior to any work being done in the area. This is because the Company has come into better knowledge of the geology of the play and therefore decreased drilling projections that were made after the first half of the year. Below you can see a map I created in DrillingInfo of Encana’s production wells histogrammed by gas production in the past month and bubbled by cumulative gas production.
The main direction Encana is hoping to go with the Haynesville Shale is to transition the field from a land retention strategy play to a gas factory (multi-pad drilling) play. The Company plans to drill in higher quality areas of the reservoir and stay away from more complex areas (zones with high clay content) until better geological data has been accumulated. The complex areas are mainly in the eastern part of the basin where there is much faulting taking place and also high pressure and temperatures in the reservoir. Encana is very sure that their long term production of the Haynesville will be over 1 Bcfpd.
Keep up to date with all Haynesville activity in the DNA section of the DrillingInfo site.
2010 was a busy year for EXCO Resources, Inc. (XCO). In April of 2010, they partnered with BG Group to acquire Common Resources Haynesville/Bossier assets, including more than 39 MMCf/d of gross production and 29.2K net acres, all acreage in the Shelby Trough, a Haynesville sweet spot.
Two months later, EXCO announced it would be acquiring Southwestern Energy’s Haynesville/Bossier assets, which were also situated in the Shelby Trough area. In their 4th quarter operating results report, they announced their fourth-quarter oil and gas production increased 70% from a year earlier thanks to drilling in the Haynesville shale region and acquisitions. The natural-gas producer said production reached 350 million cubic feet equivalent per day and predicted that 2011 production would average between 520 and 580 Mmcfe per day. 59% of the company’s total production is a direct result of their Haynesville shale drilling program, which was up from 23% just one year earlier (Tess Stynes, Dow Jones Newswires).
According to this report, EXCO is using 80-acre spacing in a manufacturing mode while utilizing multi-pad development in the De Soto Parish core area. In 2010 they completed their first four well, 80-acre spacing test across 320 acres, and their first eight well, 80-acre spacing test across a full 640 acre unit. At year end 2010, they had 12 units in progress for full 80-acre development. In late 2010 they commissioned a water distribution line utilizing waste water from a local paper mill to support their frac fleets, which they successfully used to simultaneously feed three frac fleets.
By year end 2010 EXCO had six drilling rigs running in the area and a total of 19 horizontal wells flowing to sales with a total gross production rate of approximately 100 Mmcf per day (34 Mmcf per day net). Fourth quarter highlights included completing and turning to sales two wells with initial rates of 23 and 28 Mmcf per day with flowing pressures of 8,979 and 9,520 psi, respectively. They also achieved their best drilling time performance to date with an impressive 28 days from spud to rig release.
Exco has also recently completed 168 square miles of 3-D seismic in DeSoto Parish and acquired another 126 square miles in the Shelby Trough area. In 2010, they used micro-seismic to monitor five wells and another 19 wells with our buried array monitoring system. They also drilled a dedicated vertical pressure monitoring well and installed permanent down hole gauges to measure and monitor the reservoir pressure in the Haynesville shale.
As of January 13 2011, the LDNR (Louisiana Department of Natural Resources) reported 86 active-producing wells for EXCO Resources, 22 drilling in progress, 30 in testing phase, and 47 with initial permitting reports, 5 wells being recompleted and 3 waiting on rigs. Analysis of the completion data for these wells produced some interesting statistics. Their average completion choke size for these wells is 20/64, ranging from 6/64 to 26/64. The average perf interval for these wells has increased steadily, but averages around 4000 feet. Average TD was around 16,000 in the fourth quarter of 2010. The average Prac IP in the fourth quarter was ~9000 mcf/d.
Chart of Exco’s position relative to other Haynesville operators, based on average daily production (includes both Texas and Louisiana)
Histogram of Cumulative Production - Exco's LA Haynesville Leases
Actually it is not really a question anymore, it’s a theme. Unfortunatley for operators, rising completion costs (and I mean really rising) and low gas prices have moved this once prized asset towards the back of their portfolio. I should clarify “once prized”, it isn’t like the gas is going anywhere it will still be in the ground so when operators figure out more ways to cut costs and see some kind of rebound in the price, it will come back in favor. At at least $9MM a pop, it is just really expensive right now.
That being said, I put together a chart showing how some of the bigger operators have compared against one another this year in terms of maximum monthly production. Choking back wells has certainly affected rates, however from this chart it is only evident in the Petrohawk program. Of course, when 2009 is compared against these 2010 values, more trends become evident. But this entry is only dealing with 2010, so here are the 2010 new leases on a map and in chart form.
A few clarifications, the data is current through August 2010 however I did not include that month since those wells still need time to clean up. Also, older leases with new wells on them are not included. Keep checking back, send me comments or quips or concerns.
One more thing, Jason Simmons (Unconventional Analyst Extraordinaire) put together a really nice article for the December 2010 American Oil and Gas Reporter issue regarding Haynesville Trends. I will see about publishing his article on the blog, not sure about legal issues, which is silly because he wrote it, oh well.
2010 has brought with it a few distinct trends in the Haynesville Shale. 2009 was a year of massive IPs, in 2010 these IPs have been restricted. 2009 was a year of intense Haynesville drilling, in 2010 companies are drilling the bare minimum to hold acreage. 2009 saw the steepest declines of all unconventional plays in the Haynesville, 1 year declines of about 80%. In 2010 companies really begin to choke back wells to combat a few pressing issues. I’ll use Drillinginfo to quantify some of these trends, easily and quickly.
Here are some maps, first 2009-2010 3-Month declines. 2009 3-Month declines were pushing 50%. They dropped to under 40% in 2010.
Now 2009-2010 Maximum Monthly Gas. Restricted rates have brought the IPs down.
I believe the initial driving issue for the drop in IPs and drop in 3-Month declines was the idea of reservoir optimization. The Haynesville rock is distinct from the Barnett and Eagle Ford and other unconventionals. Companies one by one began to disclose test results indicating that pressure drawdown and fracture integrity and ultimately EURs are positively affected by restricting the rate at which wells are intially produced. This trend started towards the end of 2009.
Fast forward to now, there is another more pressing issue. Gas Prices. Company reports indicate much of the play is uneconomical at current prices. However, wells still have to be drilled to hold the acreage and meet certain contracts. Restricting the rate now can make even more sense on an NPV basis, assuming you think prices can recover, at least some, going forward. In essence, save the production for a slightly better pricing environment.
LA gas data is reported at the lease level, therefore I filtered out some of the leases that showed large gas production from multiple wells on the same lease. A more detailed review of these issues, using HPDI allocated data to include all wells, is available to subscribers of the Unconventional Research Platform.
Be sure to mark your calendars! On Thursday November 18, 2010 at 10:00 am, we will be holding our November monthly webinar between our DI-ESP analyst team and our Unconventional Resources Platform members. Topics to be discussed will include the following:
1) EURs and B Factors for the Eagle Ford and the Haynesville
2) GOR Maps and Trends in the Eagle Ford
3) Examination of evidence of retrograde condensate based on GORs in the Eagle Ford
There will also be a Q&A and feedback session at the end.
Please email Lisa Remington at lremington@drillinginfo.com if you plan to attend. This event is reserved for Unconventional Research Platform members only.