Haynesville Benefits Spur Private-Equity-Backed Renaissance and Operator Improvements Despite Limited Long Lateral Prospects, Lower-for-Longer Gas Prices

Independent producers’ and private-equity-backed E&Ps’ activity level has tripled in the past year in the Haynesville Shale - a gas-rich Jurassic-era rock formation that lies some 10,000 feet below northwest Louisiana, East Texas and southwest Arkansas. The pace, however, as measured by rig counts, has recently slowed amid higher costs, low pricing and a decreasing inventory of sites for the long lateral wells that characterize unconventional plays in North America.

Over the last couple of years, new operators backed by private equity have come into the Haynesville, attracted by its well-developed pipeline infrastructure, proximity to LNG export terminals along the Gulf Coast and the potential for high initial production (IP) from 7,500- to 10,000-foot lateral wells using technological advances perfected in other basins.

This positive environment is threatened by a decline in prospects for long laterals, persistently low pricing in terms of spot and forward term structure and creeping service costs. Several operators are reporting double-digit increases in materials and service costs, resulting in significant increases in per-well cost.

Many operators are choosing to refrac wells, which carry lower upfront costs, rather than drilling new wells, suggesting increasing cost consciousness. BHP Billiton Ltd, which acquired about 300,000 net acres in the Haynesville through its $12 billion purchase of Petrohawk in 2011, recently said that “the commissioning of additional [northeastern] infrastructure, higher associated gas production and Haynesville drilling are expected to result in unprecedented supply growth in calendar 2018, which points to clear downside risks for price.”

These competing outcomes have created a dynamic between new and legacy operators. Since 2014, a resurgence in M&A has taken place in the Haynesville, albeit at depressed valuations. Buyers have largely been private-equity-backed operators, and they have been increasingly building acreage positions, buying from the legacy operators.
 
All operators, new and legacy, benefit from the low tax regime, large pay zone and attractive demand characteristics of the location. However, newer entrants are also able to take advantage of abundant existing infrastructure at current costs, and that translates into lower transportation costs than those of legacy operators that are burdened by high transportation costs under previous delivery commitments.

Additionally, over-drilled acreage limits the number of longer laterals that legacy operators such as EXCO Resources can drill. Refrac opportunities and higher production from offset wells could counter some of these disadvantages.

EXCO recently hired PJT Advisors to address liquidity concerns. Options could include bankruptcy whereby EXCO could seek to reject legacy contracts and right-size operations.

History

Haynesville was put on the map by the legendary Aubrey McClendon in the spring of 2008, when Chesapeake Energy announced a major new natural gas discovery in the play.  “Chesapeake believes the Haynesville Shale play could potentially have a larger impact on the company than any other play in which it has participated to date,” the Oklahoma-based company said at the time. It became the industry’s hottest play in 2008 and 2009, amid high natural gas prices that provided the cash flow to experiment with new well designs and completion techniques, only to lose its crown in late 2010 as a decline in gas prices drove activity to the lower-cost Marcellus and Utica shales. The number of rigs drilling for natural gas, after topping in February 2011 at 160 rigs, bottomed in April 2016 at 11 rigs, according to Baker Hughes data. Natural gas prices - on a Nymex futures expiry basis - fell from $4.036/MMBtu in February 2011 to $2.014/MMBtu in April 2016.
 
The map below shows acreage positions of major Haynesville operators.
 
Current Activity

According to data from Baker Hughes, the rig count in the Haynesville has risen to 45 as of Sept. 8 amid a rebound in commodity prices that began last March; Nymex expiry prices moved from $1.812/MMBtu in March 2016 to just below $3/MMBtu today.

Also supportive of a positive outlook for the basin: new and more favorable operating lease terms as participants turn over, a 2011 Louisiana Office of Conservation rule allowing cross-unit horizontal drilling and drilling efficiencies gained through heavier proppant use, longer laterals and multi-well pad drilling, and the advent of re-fracing. Haynesville is somewhat unusual relative to other U.S. shale plays in that the several-year pause in drilling put it behind in terms of technological advancement through operator trial and error. By comparison, all other North American major shale plays - aside from the Eagle Ford, where longer lateral use is also in its infancy -  are seeing developments such as lower sand use per well through the use of chemical diverters or tighter fracture spacing. The steady influx of cross-unit horizontal-well-drilling applications suggests that the preference for longer lateral drilling is only increasing.

Todd Keating of the Louisiana Department of Natural Resources (DNR) engineering administrative division said that although the DNR does not compile permit application data sorted by different drilling requests, “the vast majority” of the recent applications are for cross-unit drilling - owing to the persistence of 640-acre square units that have not been changed since the 1950s and the preference for longer laterals. Keating also noted that the DNR had recently received its first cross-state drilling application.

The most recent round of earnings releases and associated commentary by Haynesville operators suggest that factors including operational gains, transport capacity availability and rising LNG exports would support near-term activity levels and capex through 2018, regardless of any near-term margin pressure.

BHP, which also holds acreage in the Permian Basin and the Eagle Ford, is currently engaged in a “rethink” of its North American shale operations.

Haynesville Participant Views

Activity in the Haynesville is focused largely on eight parishes in North Louisiana and eight counties in East Texas, with the heaviest activity in Louisiana’s DeSoto Parish. Of the nearly 40 current leaseholders/producers active in the Haynesville/Bossier play, more than half are either privately held or private-equity-backed.

While the PE-backed E&Ps currently hold a significant percentage of Louisiana wells awaiting completion, wells with drilling in progress and permitted wells not yet drilled, Chesapeake Energy Corp. is still the biggest operator in the play by most measures.
 
The publicly traded participants’ commentary on the basin is, not surprisingly, generally bullish on the play, though with some cost-related caveats that were not as prevalent last year, or in some cases last quarter, when services cost inflation had not yet taken hold.

On conference calls, management teams were eager to highlight enhanced completion designs and increased well lengths. EXCO Resources COO Harold Jameson, on the company’s May 10 earnings call, said the company’s Haynesville acreage had been “re-energized” by “higher levels of proppant, higher volumes of fluid and tighter cluster spacing to deliver higher fracture intensity,” and he discussed plans to enhance the completion design, including 30% more proppant and tighter clusters. About 50% of the wells EXCO plans to drill in 2017 will be 10,000 feet or longer, Jameson said.

Comstock Resources, on its second-quarter earnings call, was similarly positive. The company’s Haynesville wells were performing above their type curve, according to CEO Miles Allison, with one setting a new IP record at over 37 MMcf/day. CFO Roland Burns, highlighting the “very low finding costs” of the company’s Haynesville wells, noted that Comstock’s operations in the basin were benefiting from a “substantial regional natural gas price advantage” to the Marcellus, with a basis differential to the Henry Hub of 11 cents compared with an average of over $1/Mcf for the Northeast over the last year.

Comstock also laid out economics per well based on lateral length, highlighting the benefit of the longer laterals. The following table comes from Comstock’s latest corporate presentation.
 
As seen above, Comstock claims that longer laterals yield higher EURs per total well cost and have lower initial decline rates. However, offsetting the potential benefit, companies cite the limited ability to drill longer lateral wells across entire portfolio. As an example, in the same presentation, Comstock says that just 18% of its current Haynesville well inventory can be drilled to 10,000 feet.

Comstock currently has 121 producing wells in the Louisiana Haynesville, with three wells awaiting completion, two wells with drilling in progress and 21 permitted wells not yet drilling, according to the Louisiana Department of Natural Resources, while Exco has 408 producing wells, 27 awaiting completion and two permitted wells not yet drilled. Chesapeake said it expects to place up to 23 wells on production in the second half of 2017, compared with 17 in the first half. During the second quarter, the company sold 119,500 Haynesville net acres and interests in 576 wells that were producing roughly 80 mmcf of gas per day, for $915 million, according to its second-quarter 2017 report.

However, these are huge fracture stimulation jobs that require millions of pounds of sand, increased hydraulic horsepower and rigs designed to operate in the deeper, tighter-spaced acreage, and this has also put a premium on well stimulation providers in the region. Comstock’s Allison noted that his company had reconfigured a drilling program in order to keep rigs busy - “these [Helmerich & Payne Inc. (HP)] rigs and Nabors [Industries Inc.] rigs that we have, they’re hard to find.”

EXCO’s Jameson also discussed the increased demand for services and what effect this increased demand is having on price for services. Increased costs, Jameson said, “will drive our overall well cost up by about 10% to 13% or an additional $750,000 to $1.5 million per well depending on lateral length. This is compared to the wells completed in the first half of 2017.” Indeed, Jameson said, the company declined to accept an option for a second frac stimulation fleet on the basis of higher cost, and it plans “to run one dedicated frac fleet for the remainder of the year, unless we can secure a more reasonable service cost option for a second fleet” in order to “preserve[] value that would have otherwise been eroded with the higher service costs.”

Exco includes specific well economics in its quarterly presentations. Because of the increased drilling costs, certain wells became less economic to drill, given the current natural gas price.
 
Jameson, who said the company had updated its type curves to reflect the higher costs, also discussed other measures to offset the cost increases, including a “continuous focus on efficiency gains across our operations.”

Walter Goodrich, chairman and CEO of Goodrich Petroleum, lowered the capex range for the year by $5 million, to a range of approximately $35 million to $45 million, and noted a change in drilling plans to two 7,500-foot laterals from a common pad, compared with previous plans for two individual 10,000-foot laterals. Goodrich’s comments echoed an underlying theme for the quarter, which suggests that operators are seeking out cost savings or are finding more opportunities for relatively shorter laterals because of operational logistics or geologic limitations.

Goodrich held about 50,000 producing and prospective Haynesville gross acres as of June 30. During the second quarter, the company, which emerged from chapter 11 in October 2016 and used $20 million of funds provided by Shenkman Capital, J.P. Morgan, Franklin and CVC for Haynesville development, completed five gross wells in the second quarter of 2017 and is focusing all of its 2017 drilling efforts in the Haynesville shale trend. The company’s second-quarter 2017 results announcement notes that per-unit lease operating expenses continue to fall as new Haynesville wells are added, because those wells “carry very low operating costs per unit of production.”

Operational economics are clearly the primary delineator over the longer term, especially in a basin so closely tied to Henry Hub pricing. The three variables that determine well production results are the IP rate (in this context the production rate during the first month), the decline rate (meaning the rate at which production declines over time) and the estimated ultimate recovery (EUR - meaning the total well lifetime production). Trends also emerge operationally on the basis of geography and experience.

Operators in the basin have reported that more focused use of proppant within longer laterals has raised IP rates and EURs from newly drilled and fracked wells while holding per-well costs relatively flat with five or six years ago, meaning increasing rates of return for each of those wells. Both EXCO and Comstock reported that each has numerous prospects where type curves suggest internal rates of return of higher than 50% at $3/MMBtu gas.

EXCO said that many of its DeSoto and Caddo Parish prospects have breakeven price levels with 25% internal rates of return of $2.52/MMBtu and $2.42/MMBtu, respectively. Comstock reported higher initial decline rates at some of its North Louisiana wells compared with EXCO, but with higher EURs and IPs, leading to overall higher rates of return.

Refracing Contributing to Increased Activity

The slower pace of drilling in the Haynesville since 2010 combined with advances in stimulation and completion techniques tested in more active basins have afforded operators an opportunity to boost IPs and EURs on the cheap through refracing - the reworking of existing wells rather than the drilling of new ones.

The math for operators is relatively straightforward. Generally, the development costs of a horizontal shale well breaks down to one-third drilling and two-thirds completion, so operators must consider whether the uptick in EUR per refraced well covers the reduced costs versus an all-in new well. The availability and/or cost of rig crews arguably favors refracing over new wells, all other things being equal.

Operator comments have highlighted the benefits of refracing to both the cost and production sides. Chesapeake president and CEO Robert Lawler, during a May conference call, noted that while the cost to refrac an older well will range about 30% to 40% of the original well, refracing has in some cases boosted well production from 1 MMcf/day to 6 to 7 Mmcf/day. Richard Doleshek, QEP Resources EVP and CFO, said on a recent conference call that his firm has increased the midpoint of its forward production guidance base case as a result of the performance of the Haynesville refracs and added a second rig in the basin to boost the number of refracs in the second half of this year.

Ultimate recoveries will be almost double the original forecasted recovery because of this refracing, QEP Chairman, President and CEO Charles Stanley said on another recent call, “That’s quite remarkable when you think about accessing a wellbore and accessing a rock that you thought was nearly depleted from the first-generation completion.”

Stanley noted that QEP had focused on refracing wells that were initially completed using relatively low proppant volumes relative to the 2,000-5,000 pounds/foot used in the refrac. The company provided this chart showing how production has benefited from refracs.
 
According to QEP’s second-quarter earning release, the average cost for its eight refracs was $4.9 million, and these “eight new refracs deliver[ed] an average gross production rate increase of 16.0 [Mmcfe/day] per well.” By way of comparison, in a June presentation, Comstock puts a price tag of $6.5 million on 4,500-foot lateral wells with initial production of 17 MMcf/day. It also stated that for a total refrac cost of $2 million, the company was able to increase production by 3.5 MMcf/day to 4 MMcf/day, while Chesapeake quoted $3 million in capex per well for a 6.5 MMcf/day uplift.

As Goodrich Petroleum COO Robert Turnham noted recently, operators have yet to determine whether the additional production from a refrac is truly incremental over the life of a well or simply a production pull-forward.

Assuming the production is incremental, and the additional production displays similar decline characteristics as new wells, refracs are marginally less productive than new wells. According to Comstock’s latest presentation, its core 4,500-foot lateral well costs $6.5 million and has an EUR of 11.2 Bcf of gas. Assuming a 20% royalty rate implies development costs of $0.73/Mcf. Applying the same assumptions as above, Comstock’s $2 million refrac implies a cost of $1.08/Mcf.

Gas Pricing, Pipeline Capacity and Upstream Haynesville Activity

The initial rush into the Haynesville following Chesapeake’s 2008 discovery was accompanied by a buildout of takeaway capacity in anticipation of that activity continuing. In addition to already-existing Haynesville-interconnected pipes such as NGPL, Tennessee Gas Pipeline and Texas Gas Transmission, Chesapeake Energy and Energy Transfer Partners LP in 2009 built the 1.25 Bcf/day Tiger Pipeline; Enterprise Products Partners LP built the 1.8 Bcf/day Acadian Haynesville Extension pipeline; and Boardwalk Pipeline Partners LP built its East Texas to Mississippi Expansion and Southeast Expansion.

And even as Haynesville rig counts followed gas prices lower as the commodity collapsed from $13/MMBtu in the summer of 2008 to levels materially less than $4/MMBtu over the past two years, operational efficiencies raised the new-well production per rig by region, absolute production level and number of drilled but uncompleted wells in the basin. According to the EIA’s August Drilling Productivity Report, new-well production per rig in the basin has increased to 7.578 MMcf/day, production is up to more than 6.3 Bcf/day, and the drilled but uncompleted (DUC) well count has risen to 194 wells. The new-well production per rig and DUC total equate to 1.47 Bcf/day of production that can be brought on line, and this - unlike in Appalachia, where pipeline capacity out of the basin is a bottlenecking factor - can easily be handled by the basin’s existing pipeline capacity.

The Haynesville has direct or indirect connections to Cheniere Energy Inc.’s Sabine Pass LNG export facility (currently operating and expanding); Sempra Energy’s Cameron LNG export facility (under construction); Freeport LNG Development’s Freeport LNG export facility (under construction); and Cheniere’s Corpus Christi LNG export facility (under construction and suffering only cosmetic damage from the recent impact of Hurricane Harvey). That said, a supportive basis and overall export demand story is necessarily predicated on robust and steady global demand for U.S. LNG, which cannot be taken for granted, given loose global balances and a growing number of new upstream supply alternatives from Australia, Qatar and elsewhere.

The current slack in the supply/demand balance has not slowed U.S. LNG export development, and one of the developers, Tellurian Inc., on Sept. 6 announced an agreement with a private seller to acquire Haynesville production and assets for $85.1 million. Tellurian owns the proposed Driftwood LNG project, and its board is chaired by former Cheniere CEO Charif Souki.

Tellurian said that the assets are held by production and 92% operated, allowing the firm to control the pace of development. The company’s CEO Meg Gentle said that she expects full-cycle costs of production and transport to be approximately $2.25/MMBtu, “which represents a significant savings to natural gas we will purchase at Henry Hub and other regional liquidity points.”

The new round of operators in the Haynesville and surviving legacy names have been touting the excess pipeline capacity which supports basis pricing - the Perryville Hub or any of the Henry-area Louisiana points are often used as Haynesville proxies - and also the ongoing expansion of Mexican pipeline and LNG exports. And just this week, Empire Petroleum Corp. announced that it will sign a purchase and sale agreement within the next few weeks to acquire producing assets in the East Haynesville and Oaks Fields in Claiborne Parish, La.; the company’s president noted the momentum building in the North Louisiana in “re-stimulating oil wells with higher proppant completions.”

These competing outcomes have created a dynamic between new and legacy operators. Since 2014, the Haynesville has seen a resurgence in M&A, albeit at valuations far below that of 2008-2012, with much of the activity since 2014 driven by newly created operators backed by private equity.

All operators, new and legacy, benefit from the low tax regime, large pay zone and attractive demand characteristics based on location. But newer entrants are also able to reach transport contracts that reflect the basin’s abundant infrastructure, and that translates into lower overall gathering, processing and transportation costs.

Legacy operators, on the other hand, are burdened by long-term delivery contracts signed when gas was two or three times higher than it is today and will be for the foreseeable future. Additionally, over-drilled acreage limits the number of locations for longer laterals available to these operators, but refrac opportunities and higher production from offset wells could counter some of these disadvantages.

Overall, companies must be extremely careful with cash flow management. One legacy operator, EXCO Resources, hired PJT Advisors to address liquidity concerns. Options could include bankruptcy whereny EXCO could seek to reject legacy contracts and right-size operations.

Conclusion

Despite the margin compression driven by rising costs for services in the Haynesville Shale and potential price pressure due to a robust natural gas supply outlook for 2018, there are several reasons to expect activity levels to remain steady in the near term. Among those are the optionality offered by refracing opportunities and offsets, the promising results on acreage where longer lateral wells are being drilled, and the tendency for private-equity concerns to kick up activity levels ahead of any asset monetization efforts.

Operator economics differ greatly across varying geography, lease costs, transportation contractual terms and drilling efficiency. Several operators appear to be counting on market conditions to improve because of demand-side growth - primarily in terms of exports - and favorable hedges to get them through both the cost structure changes and expected production increases from associated plays and inexpensive northeastern shales. The backwardated forward curve currently reflects the imbalance toward deferred sellers in the general natural gas marketplace, so any plateauing in efficiencies through the drillbit would be increasingly deleterious for Haynesville margins.