The Haynesville Shale continued to be the go-to spot for Comstock Resources Inc. during 1Q2019, where four rigs are now running across the company’s 88,000-acre leasehold.
The Haynesville heavy’s exploration program underwent a makeover last year after a transformative deal with Dallas Cowboys owner Jerry Jones, whose family contributed an estimated $620 million in Bakken Shale properties in exchange for an 84% stake in the company.
The cash flow from the Bakken properties infused the Haynesville program. Comstock produced 38 Bcfe overall, including 33.1 Bcf of natural gas and 810,470 bbl of oil.
Gas production, primarily from the Haynesville, jumped 53% year/year and 10% sequentially to 368 MMcf/d. Oil production averaged 9,005 b/d, primarily from the Bakken, versus year-ago output of 2,110 b/d, mostly from Eagle Ford Shale properties, some of which were sold last year.
The first quarter results “reflect strong growth from our Haynesville-focused drilling program,” CEO Jay Allison said last week during a first quarter conference call.
Comstock re-entered the Haynesville in 2015 and has since completed 76 operated wells with average initial production (IP) rates of 25 MMcf/d. During 1Q2019, six wells had average IPs of 26 MMcf/d.
“Our Haynesville/Bossier production was 57% higher this quarter than a year ago and shows we are on track to have 50% growth in our natural gas production this year,” Allison told analysts.
The second quarter also is shaping up as a strong one, CFO Roland Burns said. However, he noted that well work, including pauses to do fracture work, along with third-party curtailments, required Comstock to shut in about 19.5 MMcf/d during the quarter.
“After some modifications, we believe that we'll be able to have that to 0% here in the near future,” Burns said. “Our goal is to try to get the shut-in production percent down to about 3%, and that's a work in process.”
Pricing also was a jumpy business early this year. Including hedging gains, Comstock’s average realized gas price increased 2% year/year to $2.87/Mcf, while the average realized oil price decreased by 33% to $45.78/bbl. Oil and gas sales combined were $132.3 million versus $74 million a year earlier.
“Differentials for both oil and gas prices in this quarter were wider than we normally experience,” Burns said. “On the oil price, the Bakken basis widened considerably in December, which carried over into January due to refinery issues and other issues in the basin. By March, though, our oil differential in the Bakken was back to a normal level of about $4.50/bbl…
“On natural gas, we sold more than half our production in the quarter in the daily market versus on the index market, and usually there's not a very big difference between those two. But the first quarter was unusual.”
New York Mercantile Exchange gas prices for January were $3.65/Mcf. However, “by the time we got to March, they were $2.86,” Burns said. “So if you looked at the month of January in particular, which was the high-price month, there was almost a 60-cent difference between the daily price and the index price for the month.”
Another factor driving the differential was more production into the latter part of February and March, “when gas prices were lower than the very high price of January,” Burns said. “When you get back to March, our differential was back to normal at about 20 cents.”
During the first three months of 2019, Comstock spent $92.5 million on development activities in the Haynesville/Bossier and $82.6 million to drill and complete (D&C) Haynesville wells. Comstock also spent $5.6 million drilling two Eagle Ford oil wells and an additional $4.3 million primarily on leases and other development activity.
Comstock secured lower contracted D&C rates from its oilfield services providers that began in April. On the lower costs, the D&C budget was reduced to $318 million for the Haynesville/Bossier program.
A total of 49 operated wells in the Haynesville program are set for completion this year, operations chief Daniel Harrison said. He pointed to the third generation, i.e. Gen 3 fracture designs, which use 3,800 pounds/foot of sand and lateral lengths averaging 9,646-9,913 feet.
“Our Gen I wells were predominantly drilled as 7,500-foot laterals back when we returned to the play,” Harrison said. “Our newer Gen III wells have been predominantly drilled as 10,000-foot laterals. The Gen III completions continue to outperform our earlier vintage wells.”
Comstock’s average Gen I well today is expected to recover 15 Bcf, or 2.1 Bcf/1,000 feet of lateral.
“Our current average of our Gen III wells is on track to recover 22 Bcf, or 2.4 Bcf/1,000 feet of lateral, or nearly 50% more recovery than the average Gen I well,” Harrison noted. “This change, coupled with our continually improving cost structure, is what is driving the increase in our returns…”
The fracture costs drive total well costs. However, with a softening pressure pumping market, Comstock has been able to drive down the total well costs by renegotiating oilfield services rates.
“At the $2.50 flat gas price, we're generating approximately a 37% rate of return on our 4,500-foot laterals and up to a 76% rate of return for our 10,000-foot laterals,” Harrison said. “With the gas price increasing to $3.00, the rate increases to approximately 76% for the 4,500-foot laterals and well over 100% for the 10,000-foot laterals.”
Through the rest of 2019, Comstock plans to run five rigs on average. The 49 planned wells are to have 10,000-foot laterals.
“We're continuing to push down our well costs, improve our well performance and improve our gas takeaway cost structure,” Harrison said. “All of these measures deployed together will generate strong returns and cash flow into the future.”
In addition to the Gen 3 fracture designs and lower per-well costs, Comstock has been able to reduce its transportation costs with new contracts, Allison said, “which should lower our lifting cost/Mcfe basis.”
The producer recently began drilling its 95,400 undeveloped net acres in the Eagle Ford, where it has 126 net potential drilling locations. Results from the initial wells are expected in 2Q2019 results.
Results for the first three months of 2019 reflect the Jones contribution, while results for the year-ago quarter reflect the historical results for that period.
Net income in 1Q2019 totaled $13.6 million (13 cents/share), which included the Jones contribution, compared with a year-ago net loss of almost $42 million (minus $2.78). The 1Q2019 results included an unrealized hedging loss of $13 million. Operating cash flow increased 98% year/year to $70.8 million.