Motley outlook amid new highs in gas production, prices
Despite both production and seasonal gas prices at multi-year highs, asset-holders in the Haynesville and Bossier shales are sending mixed messages as to the breadth of the supposedly percolating recovery.
“For us, the internal rates of return (IRR) being generated in the Haynesville are too high for us to think about allocating anywhere else at this point in time,” Goodrich Petroleum Corp. CEO Gail Goodrich told analysts on Nov. 8. The company also holds acreage in the Eagle Ford and Tuscaloosa Marine shales.
Then, there are established players like QEP Resources Inc., which, as part of its transition to a pure play Permian-basin operator, sold its 48,900-net-acre Louisiana Haynesville-Cotton Valley leasehold and producing wells on Nov. 19, to an affiliate of Dallas investment house Aethon Energy Management LLC for $735 million. Even first-mover Chesapeake Energy Corp. plans to significantly reduce drilling activity next year, in the wake of its $3.977-billion deal to acquire Eagle Ford operator WildHorse Resource Development Corp. The deal was announced on Oct. 30 and is expected to close in the first half of 2019.
Nevertheless, the year-over-year rig count jumped 12 units in the Haynesville, and the often- linked Bossier shale that overlies it. An average 51 rigs were at work in November, in the dry gas play that stretches from the North Louisiana core into East Texas, compared to 39 rigs active in November 2017, according to Baker Hughes.
Once considered a prohibitively costly unconventional play, the deep Haynesville was one of the earliest and hardest-hit casualties of the downtime, dropping to a low of 12 active rigs in April 2016. Now, operators report wellhead break-even costs as low as $2.00/Mcf, just as natural gas prices, for December delivery, spiked to $4.4929/MMbtu, the highest seasonal gain since February 2014, when much of the U.S. was in the grip of an arctic blast.
Significant contributors to the lower well costs can be traced to a more competitive pressure pumping environment (Fig. 1) and the growth of in-field sand proppant mines. “During the course of 2018, we have actually seen (frac) spread weights come down, mainly driven by increased capacity into Haynesville,” says the Goodrich Petroleum namesake.
Correspondingly, Gen6 Proppants, on Sept. 25, became the latest frac sand provider in the Haynesville, with the acquisition of roughly 1,000 acres in Red River Parish, where a new mine is expected to begin delivering 40/70 and 100-mesh proppant by mid-2019. The site holds an estimated 75 million tons (Mt) of frac sand, and once fully commissioned, is expected to produce 1.5 Mtpa. Elsewhere, Shale Support LLC, in June, snapped up two natural sand mines in Kinder and Baywood, La., increasing its annual capacity from 3 Mtpa to 5 Mtpa.
These providers join Performance Proppants LLC, which has been providing in-field frac sand from its Hat Creek complex in Bossier City, since October 2017.
“3 IS THE NEW 35”
The U.S. Energy Information Administration (EIA) estimates that gas production in the Haynesville region will hit a nearly six-year high of 9,667 MMcfd in December, up from 7,530 MMcfd in December 2017, Fig. 2. Much of that production is being absorbed by a growing Gulf Coast petrochemical network and liquefied natural gas (LNG) exports, kick-started by Cheniere Energy in February 2016, with the first cargo shipped from its Sabine Pass terminal. Cheniere’s global customer base expanded on Nov. 8, with the signing of a 24-year sale-and-purchase agreement with Polish Oil & Gas Co., which will take delivery of approximately 1.45 Mtpa.
While Haynesville drilling activity will likely never approach the 161 active rigs in February 2011, a combination of efficiency-driven maturity, juiced-up completions and progressively longer laterals is helping to make each rig responsible for 8,650 Mcfd of new gas, according to the EIA. Of the seven EIA-monitored U.S. shale plays, the December Haynesville rig productivity estimate, which is up from 7,998 Mcfd/rig in December 2017, trails only the Marcellus-Utica region in gas production/rig.
“The new motto in the Haynesville is ‘3 is the new 35.’ Using longer laterals and more proppants, drillers in this play can get out of three wells what used to take 35 wells, back when the play was first being developed,” Loren Scott, Louisiana State University (LSU) professor emeritus in economics, wrote in “The Louisiana Economic Outlook: 2018 and 2019,” released in October 2017.
Chesapeake raised the regional horizontal bar a year ago this month with the drilling of the 15,000-ft lateral, GEPH 1HC Haynesville well, which was put online in May. The well has produced at a 170-day rate of about 24.9 MMcfgd, with cumulative production of 5.8 Bcf, as of Oct. 30. At that time, the company was drilling two additional Louisiana Haynesville wells, with 15,000-ft reaches, with “the potential” of five more 15,000-ft wells next year, despite a pending re-allocation of resources.
Chesapeake is running four rigs and one frac crew on its commanding 339,000-net-acre leasehold, 90% of which is held by production (HBP). However, in 2019, more than 80% of the drilling and completions budget will be diverted to the oily Eagle Ford and Powder River basin (PBR) assets, leaving one to two rigs active in the Haynesville. “In the Haynesville, well performance continues to improve, and we see completion costs dropping. But, we currently plan to reduce our rig count, moving forward in 2019, as we focus our capital spend on higher-margin opportunities,” says Frank J. Patterson, executive V.P., exploration and production.
At average BEP of $2.00 to $2.25/Mcf, third-quarter production came in at 769 MMcfd, compared to 804 MMcfd in the same 2017 period. After putting four wells on production in the third quarter, Chesapeake plans to connect seven wells to sales in the fourth quarter.
Among the more active players, Comstock Energy Inc. plans to add a fifth rig in early 2019, and drill 57 gross wells, compared to 48 Haynesville-Bossier wells expected to be drilled this year. Some 70% of the wells on tap for next year will be constructed with 10,000-ft laterals, at average total costs estimated at $11.9 million/well. The company also plans to average 2019 gas production between 370 MMcfd and 470 MMcfd, representing a 50% increase over targeted 2018 output.
Complementing longer laterals, Comstock continues the transition to Gen 3 completions, featuring cluster spacing halved from 30 to 15 ft, with 5 to 10 clusters/stage. Stage length and proppant loading remain unchanged at 150 ft and 3,800 lb/ft, respectively.
Comstock bolstered its now 81,000-net-acre Haynesville and mid-Bossier leasehold on July 31, with the bolt-on acquisition of 12,000 net (23,000 gross) acres in Caddo and DeSoto parishes. Acquired in the bankruptcy auction of Enduro Resources Partners for $39.3 million, the properties include 14.7 net (49 gross) Haynesville wells, which together with other producing wells, add 19 MMcfd to 2018 production.
Goodrich Petroleum, likewise, is testing beefed-up completions with 4,000-to-5,000 lb/ft proppant concentrations, spread across 10,000-ft laterals, at 100-to-200-ft frac intervals and 10-to-30-ft cluster spacing. Now in full-scale development mode on a 22,400-net-acre leasehold, concentrated mainly in the Louisiana core, Goodrich says depending on the lateral lengths, Haynesville wells generate returns from 36% to 76% at current gas prices.
Costs are expected to remain stable going into the new year, “As we look at 2019, we don’t see anything on the horizon today that looks like there is whole lot of inflation. We have obviously seen some increase in pipe prices with the steel tariffs. Although we now have what looks like a fairly stable environment, if anything it (inflation) would be kind of in the 5% to 10% range,” said CEO Goodrich.
Owing to an asset swap, Goodrich said it was likely to put a second rig to work. Of the 19,100 net (38,100 gross) acres that Goodrich controls in the core DeSoto and Caddo parishes, 27% is operated in a joint venture with Chesapeake.
BP expanded its Haynesville leasehold by 193,000 net acres with the Oct. 31 closing of the blockbuster $10.5-billion acquisition of BHP Billiton’s U.S. shale holdings. Operated under rebranded BPX Energy (formerly BP America), the Haynesville properties included in the sweeping deal were producing around 60,000 boed of gas at closing. No information was made available on current activity in the newly acquired acreage.
During a pre-closing investor call on July 27, BP said the transaction was valued at a Henry Hub benchmark price of $2.75/Mcf, while CFO Brian Gilvary said it was economically feasible at $2.25/Mcf.
The acquisition augments BP’s commanding position in the Texas segment of the Haynesville-Bossier, where the company was running seven rigs in the second quarter with a year-end production target of around 90,000 boed. “We custom-created stimulation designs for the deep Haynesville. Those are some of the most prolific wells in the United States at this point,” David Lawler, CEO of BP’s Lower 48 Onshore business, told analysts.
The Haynesville also is home to a large contingent of private, tightly controlled operators, such as Indigo Natural Resources LLC, which is the latest to apply for publicly traded status. The Houston company controls 133,164 net acres in North Louisiana, where it averaged five rigs and two frac crews in 2018, completing wells with average lateral lengths of 7,227 ft.
Indigo submitted a federal draft registration on Jan. 29 for a proposed initial public offering (IPO), joining Covey Park Energy LLC, which holds an estimated 218,000 net acres, and Vine Resources Inc, with a 175,000- net-acre position, which filed separate applications in late April 2017. Neither Covey Park or Vine responded to requests for comment on their current trading status or activity level.
Earlier this year, Vine Oil & Gas LP and GEP Haynesville LLC decided to unwind the go-forward portion of their two-year old Haynesville joint venture covering acreage in Red River, DeSoto and Sabine parishes of northwestern Louisiana.
Meanwhile, one of the key drivers for increasing production is the growing need to feed firm Southwest Louisiana LNG export demand that is set to triple between 2017 and 2024, Fig. 3.
MEETING LNG DEMAND
As of Nov. 8, Cheniere Energy’s soon-to-be five-train Sabine Pass terminal has exported more than 1,700 TBtu of LNG in 475 cargoes, delivered to 29 countries. In the third quarter, Cheniere exports amounted to 228 TBtu, up 43% from the prior quarter. If all goes as planned, Cheniere will have company over the next four years, as two closely concentrated LNG facilities are well along in development.
Tellurian Inc., for one, plans to begin construction of its Driftwood LNG terminal, south of Lake Charles, La., in the first half of 2019, with exports of up to 27.6 Mtpa scheduled to commence in 2023. Tellurian was co-founded in February 2016 by ousted Cheniere founder and CEO Charif Souki and Martin Houston, former chairman of the Global Energy Group of investment banker Moelis & Co.
To provide feedstock for the estimated $28-billion project, which includes 1,000 mi of associated pipelines, Tellurian amassed a 10,797-acre Haynesville leasehold across Red River, DeSoto and Natchitoches parishes, in a series of transactions between 2017-2018. The acquired acreage includes 20 producing wells, delivering net production averaging 3.3 MMcfd. After receiving a $60-million equity infusion in September, Tellurian’s production entity intended to “commence drilling certain operated locations on our properties in fourth-quarter 2018,” a spokesperson said.
Elsewhere, the first two trains of the Cameron LNG export terminal in nearby Hackberry, La., are expected to begin service early next year, with a third train slated for start-up in late 2019, or early 2020. The one-time import facility is being re-designed with export capacity of more than 12 Mtpa. On Nov. 5, Sempra Energy and Total S.A. signed a memorandum of understanding (MOU), clearing the way for a planned expansion of the terminal.
In a related development, the U.S.-China tariff tiff is being blamed for a delay in the final investment decision (FID) on the proposed Magnolia LNG export terminal near Lake Charles. Australian developer LNG Ltd. had planned to announce a decision by year-end 2018, but on Oct. 30 put the FID on hold, citing difficulty lining up Chinese buyers amid trade tensions, “which have caused headwinds for LNG transactions.”
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