Encana's (ECA) Q4 earnings call on February 14 stirred an animated reaction among E&P-focused investors and analysts. Surprisingly, the most notable news came not from the company's emerging oil and liquids-rich plays (the update on that front was uneventful and cautious, likely contributing to the stock's 6.6% decline on the day of the release), but from its Haynesville dry gas operation. At the time when many competitors and investors seem to have written the Haynesville off as economically uncompetitive in today's low natural gas price environment, Encana announced a plan to re-enter the play and gave a very bold forecast regarding its economics:
Encana is resuming activity in the Haynesville play. Because of the low supply costs in this play, Encana expects that the Haynesville will be able to produce solid returns at current natural gas prices. The company currently has two rigs running in the play with plans to increase to five rigs through 2013. (Encana's February 14 press release)
The company now estimates that its cost of supply in the Haynesville (minimum Nymex price needed to earn the company's 9% hurdle rate of return on incremental drilling) will be "in the $2.50/MMBtu range."
Encana believes it will be able to achieve rates of return at the project level of approximately 30% using a flat $3.50/MMBtu Nymex price and approximately 40% using $4/MMBtu. I should note that the $4/MMBtu scenario is by no means in disconnect from what the futures market is currently indicating. Encana is re-entering the play with pad drilling (4-6 wells per pad) and 7,500 laterals, which means that peak production from new drilling will not be seen for at least another six months (I assume 40-45 days spud-to-spud drill time and, once the drilling rig is off the pad, another four-eight weeks to complete the wells and achieve peak production). With the rig count increasing from two rigs currently to five rigs later in the year, the majority of production volumes will ramp up in 2014 and will come in lumpy increments. The Nymex futures show Calendar 2014 and Calendar 2015 currently trading at $3.93/MMBtu and $4.19/MMBtu, respectively (Encana has been layering in hedges at above $4/MMBtu level).
Based on Encana's comments, two major factors are behind the company's confidence in the viability of the play even in a low-price environment. With several hundred Haynesville wells drilled to date, Encana has been continuously improving its frac designs: completions are bigger, denser and more effective (this has been the trend reported by several operators in the Haynesville - an illustration is provided further in this note). Based on the performance from shorter laterals, Encana believes that "the new modern design in the core areas of the Haynesville…will be able to achieve 2.5 Bcf per 1,000 feet of completed interval, which would equate for a 7,500-foot well to approximately 18 Bcf." On the cost side, Encana projects it can drill and complete a 7,500-foot horizontal in the $13-$14 million range, although cost may vary depending on the well's depth and rig specification required. The second, and most crucial, factor is that Encana will be drilling in "the best of the best sweet spots in the play" that has been thoroughly delineated by the dense HBP-driven drilling (at least one well per section).
For Encana watchers, the company's comments during the call should not come as a surprise. From my notes at an industry conference six months ago, Encana's USA Division President commented that the company is seeing its cost of supply from the Haynesville at below $3.00/MMBtu Nymex, based on the performance of the company's six-well long-lateral pilot pad. Last Thursday's announcement and commentary are nonetheless important as they indicate a high degree of confidence that Encana has obviously gained from monitoring the performance of its 14 cross-unit laterals drilled to date and evaluating inter-well communication between the larger completions.
We drilled six wells that…extended outwards to reach 7,500 feet. Over the last year, we've been able to look at those wells and carefully understand across their performance, and what we found was that they were highly efficient, and it has changed our belief in what kind of supply cost we can drive in the best part of the play.
Encana has allocated about $270 million to the Haynesville for the year - which is a modest amount for the 3 Bcf/d gas producer - and is targeting to prove up its new well designs and demonstrate development economics and well cost efficiencies.
Encana's newly formulated metrics for the Haynesville should probably be interpreted as an operating target yet to be demonstrated. Clearly, the bar is set very high. The 18 Bcf EUR needs to be achieved on an average basis, not just for select best wells, - a very high goal. Well cost may also be a challenge in the Haynesville - which is deep, hot and overpressured - as all wells, including those with drilling-related issues and mechanical problems that are not infrequent, must be accommodated within the average realized D&C cost.
How Big Is The Haynesville's Sweet Spot?
Clayton Woitas, Encana's interim CEO, commented during the call:
I feel that Encana is fortunate to have the sweet spot of the Haynesville play and so that puts us in somewhat unique position.
There is no doubt that Encana has captured a sizeable acreage position within the Haynesville's most productive area on the Louisiana side. However, it is not the only operator with a significant sweet spot exposure. In fact, the biggest holders of prime quality acreage in Northwest Louisiana are BHP Billiton (BHP) and Chesapeake Energy (CHK) (with Freeport McMoRan [FCX] as a ~20% non-op partner). Other operators include Royal Dutch Shell (RDS.A, RDS.B) (Encana's AMI partner), J-W Operating (private), EXCO Resources (XCO) (with BG Group [BRGYY.PK] as a JV partner), QEP Resources (QEP) and El Paso (private). The fact that there is no monopoly in the Haynesville on the most productive geology has important consequences:
- drilling activity in the field will reflect the play's economics (and will not be captive to a single operator's budget/other priorities);
- best operating practices and technologies will have quick adoption across the board;
- rig count and production will build up rapidly once natural gas price provides sufficient incentive.
There is some divergence of opinion among operators and consultants regarding the size and areal extent of the Haynesville's most productive areas. Petrohawk Energy, one of the largest operators in the play, provided the following EUR map in one of its investor presentations dating back to 2010:
BHP Billiton's recent presentation validates Petrohawk's initial assessments and is in line with Encana's estimates:
Defining the Haynesville's "sweet spot" as the area with 10+ Bcf/well EUR potential (for ~4,500-foot laterals) and using Petrohawk's and some other EUR maps from the same period, the sweet spot in Northwest Louisiana appears to be as big as ~250,000 acres. The contour of the sweet spot may have evolved as production history has been accumulating and operators have improved their completion techniques and advanced towards unlocking the potential of the play's geology.
If one were to think of the sweet spot as the area with 8+ Bcf EUR potential (again based on ~4,500-foot laterals), its size would likely be 300,000-400,000 acres, based on Petrohawk's maps.
While the area in Northwest Louisiana circled on Petrohawk's map above is the play's most economic location, the Shelby Trough area appears to come reasonably close in terms of EUR per well potential. However, D&C costs and gas treating requirements in this part of the play tend to be higher, which impacts the returns.
While Encana's 18 Bcf per well EUR target still needs to be validated by at least few years (and better, several years) of production history from wells with the company's latest completion designs, the figure is not inconsistent with some earlier industry EUR estimates for this specific area. It is important to note that longer laterals result in approximately 10% gain in the length of usable horizontal wellbore due to reduced "dead" setback zone. (While Encana's current operating plan calls for 7,500-foot laterals, the company will also test 10,000-foot laterals. Clearly, the risk of drilling-related issues in an overpressured, high-temperature formation such as the Haynesville increases with the length of the lateral.)
Also, it is hard to overemphasize the importance of the improved completion designs. A recent presentation by GMX Resources (GMXR) provides an illustration of how the size and density of frac jobs in the Haynesville have increased over time, leading to improved recoveries:
With these factors in mind, Encana's 18 Bcf/well EUR estimate correlates with the 10 Bcf/well industry estimates seen in some older (2010-2011) presentations (Encana's estimate is "scaled-up" to reflect longer laterals and larger, more advanced completions).
How Long Will The Sweet Spot Last?
Assuming that the size of the sweet spot is approximately 250,000 acres, it should support close to a thousand future 7,500-foot well locations on 100-acre spacing (I assume that 1.5 wells per section have already been drilled, on average, and 15% of all acreage is not usable due to faulting and other limitations). This also translates into close to 20 Tcf of highly economic dry gas resource, assuming model decline curves live up to the expectation. Using a 40-45 day spud-to-spud drill time assumption in the development mode, this inventory would translate in ~6 years of drilling based on a total of 20 rigs working in the area (~160-180 wells per year).
While 20 rigs may, at first glance, strike as a low number (particularly in the context of the 180+ peak rig count in the play during the summer of 2010), a closer examination shows that 20 rigs would be an adequate level of drilling activity for this specific area in the full development mode. This is in fact a highly important conclusion that I will discuss in full detail in a follow-up note.
Who Is Drilling In The Haynesville's Sweet Spot Currently?
Based on Baker Hughes rig survey as of February 8, 2013, there are 13 rigs currently drilling in or around the play's Northwest Louisiana sweet spot (Red River Parish and vicinity).
(Source: Baker Hughes)
The operators are:
- BHP Billiton: 4 rigs
- EXCO: 3 rigs
- Encana: 2 rigs
- J-W Operating: 2 rigs
- Chesapeake: 1 rig
- Royal Dutch Shell: 1 rig
Notably, Exxon Mobil (XOM) is running three rigs in the southern part of the play in the Shelby Trough area.
The total Baker Hughes gas-directed rig count in the Haynesville area as of February 8 stood at 36 horizontal and directional rigs. This includes 7 rigs targeting the liquids-rich part of the play - both the Haynesville and Cotton Valley - in Panola County, Texas (six operated by Anadarko (APC) and one by EOG Resources (EOG)).
Sweet Spot's Drilling Economics
The 18 Bcf EUR assumption and $13-$14 million D&C cost translate in an impressively low ~$1.00/Mcf development cost. Still, this puts the Haynesville behind the Marcellus (where development costs can be as low as $0.60/Mcf in the "best of the best" areas and $0.70-$0.80 in Tier I) and the Fayetteville (where Southwestern Energy (SWN) is targeting ~$0.80 development cost for its 2013 drilling program).
However, several factors enhance the Haynesville competitiveness and bring its sweet spot effectively at par with high-graded Fayetteville and Marcellus locations:
- Due to the overpressuring, well decline profile in the Haynesville tends to be much steeper than in other shales: 50% of the EUR is produced in less than 2 first years on production, according to QEP's type curve which I view as conservative (0.3 b-factor); Petrohawk's type curve used to show 50% of the EUR produced in about 3 years. Quick payback results in substantially higher NPVs for the same EUR - a key difference relative to many other shale and tight gas plays.
- Many wells in the Haynesville's sweet spot have demonstrated excellent sustainability of bottomhole pressure in a "slow back" production regime. As a result, no compression is required until several years into the life of the well - a substantial operating cost advantage versus other shales. (Using QEP's comment during their Q2 2012 results discussion: "Four QEP wells - with almost 3.8 Bcf of cumulative production - were flowing at about 5,000 pounds of pressure…So, at what is effectively the half life of the well, you still have flowing pressures of five times our gathering system…").
- Ample pipeline access to several liquid pricing points should help to avoid "basis explosions" (such as the one seen in the pipeline-constrained Marcellus in 2012, for example, which destroyed the economics of interruptible volumes).
Another very important factor that needs to be taken into consideration (which I also discussed in significant detail in my last week's note "Fayetteville Shale: Operating Analysis, Infrastructure, Economics, Outlook" is the existence of transportation and gathering costs that are subject to take-or-pay agreements and are effectively "sunk." These two cost components may have a very material impact on the way operators see incremental drilling economics.
The Haynesville has traditionally been perceived as a field with a 3+ million acre areal extent and 250+ Tcf of potentially commercial resources. In the context of the new natural gas competitive landscape (which is continuing to evolve), it may be appropriate to look at the field through the filter of economic competitiveness. Economically, the Haynesville is effectively reduced to just a few compact sweet spots including, for the time being, one in Northwest Louisiana surrounding Red River Parish, discussed above; the high-return liquids-rich Haynesville/Cotton Valley play in Panola County; and, possibly, the Shelby Trough area in the south of the play. Each of the areas also has its fine structure in terms of expected EURs. While these sweet spots represent less than 20% of the field's total size, they have sufficient resource to sustain the Haynesville's production volumes at their current level for more than a decade.
The Haynesville is also emerging as a very different field operationally. Pad drilling, long laterals, super-sized and very dense completions in surgically selected locations will likely be the path to the field's re-invented competitiveness in the next few years (as percentage of the total well cost, drilling-related expenses will decline and cost of completing the well will grow).
- The Haynesville's inventory of "the best of the best" locations may prove extensive and remarkably prolific, putting the field (or rather its sweet spot) within the "baseload" category of natural gas supply for at least several years.
- Using Encana's new average EUR forecast, the play's economics in its best area indeed promise to be very solid, although not overwhelming, based on my analysis.
- However, even if operators in the Haynesville's sweet spot are able to reach the very impressive operating targets highlighted in Encana's presentation (clearly, a tall order), the field will still be facing very tough competition in terms of cost of supply from other dry gas shales such as the Marcellus and Fayetteville.
- Similar to the Barnett and Fayetteville, firm transportation and gathering commitments (in many cases with 10-15 year terms) likely play a very important role in providing stability to the field's volumes.
- The expectation of a significant decline in production volumes from the Haynesville that has been suggested in the past by some sell side analysts and industry executives likely misses several important factors: substantial fixed component in the cost structure; highly differentiated well productivity within the sweet spot; and rapid evolution of the completion designs. The field's base decline rate is also often overstated.
- Despite a modest decline in its aggregate production during the first half of 2013 (based on my analysis of drilling and completion activity), the Haynesville will likely demonstrate stability of future volumes and may show a recovery to at least its peak production level registered in November 2011 should natural gas prices improve above a $4/MMBtu level.
- Due to pad drilling and likely adoption of longer laterals, the impact of any re-acceleration of drilling activity in the play may not be visible in production volumes for as long as six to nine months.
The above discussion is fundamentally relevant for natural gas (UNG) and the natural gas producer stocks. My natural gas producer index includes:
- Chesapeake Energy
- Encana Corporation
- Devon Energy (DVN)
- Southwestern Energy
- Ultra Petroleum (UPL)
- EXCO Resources
- WPX Energy (WPX)
- Cabot Oil & Gas (COG)
- Range Resources (RRC)
- QEP Resources
- Quicksilver Resources (KWK)
- Forest Oil (FST)
- Bill Barrett (BBG)
Disclaimer: This article is not an investment recommendation. Any analysis presented in this article is illustrative in nature, is based on an incomplete set of information and has limitations to its accuracy, and is not meant to be relied upon for investment decisions. Please consult a qualified investment advisor. The information upon which this material is based was obtained from sources believed to be reliable, but has not been independently verified. Therefore, the author cannot guarantee its accuracy. Any opinions or estimates constitute the author's best judgment as of the date of publication, and are subject to change without notice.
Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.