The Wet Cotton Valley

On a July road trip through northeastern Texas, Houston-based research analysts found undeniable indicators of the faltering demand for oilfield services in the dry Haynesville shale-gas play. “The first observation from the road and our facility drive-by’s was the significant amount of equipment parked in most of the companies’ yards...,” they report.

“In addition, our trip entailed nearly 500 miles on the highway and we didn’t see a single drilling rig operating.”

Just south of their stops in Waskom, Tyler and Longview, Texas, though, drilling action is rigging up in Panola and Rusk counties and due east in Caddo and DeSoto parishes, Louisiana. There, Anadarko Petroleum Corp. is still targeting the Haynesville and the shallower, long-familiar Cotton Valley formation.

But, hang on; don’t yawn—what has captured its and other operators’ interest here is a capex-worthy distinction from the dry-gas Haynesville of northwestern Louisiana: This rock is wet.

“It probably hasn’t received much attention from the investment community because, for some of us, it’s only been wet—that is, the liquids processed from the gas stream—since April 1,” says Bill Pritchard, chairman and chief executive officer of privately held Indigo Minerals LLC. This spring, Indigo’s Cotton Valley production in Caddo and DeSoto parishes as well as that of several others was newly connected to processing by DCP Midstream Partners LP via a 20-mile extension to its plant near Carthage, Texas, in Panola County.

The Cotton Valley horizontal liquids play is focused on Rusk and Panola counties, Texas, and DeSoto and Caddo parishes, Louisiana.

Publicly held Goodrich Petroleum Corp., which has been working the Cotton Valley for nearly a decade, is newly connected to processing as well. Rob Turnham, president and chief operating officer, explains that dry gas in the area gets roughly 25 cents below Nymex and natural gas liquids (NGLs) are priced at between 35% and 45% of West Texas Intermediate (WTI) or $35 to $40 per barrel at $90 WTI.

When putting 1 million cubic feet of wet Cotton Valley gas into the processing plant, out the back end comes some 800,000 cubic feet of dry, residue gas, he says. At $3 gas, that’s worth $2,400. On the NGL side, out comes roughly 50 barrels. Times $35 per barrel at $90 WTI, that’s an extra $1,800.

“You’re now receiving $4,200 per million cubic feet of gas that went into that plant. That’s a big difference versus $3,000 per million of dry-gas equivalent. That’s 40% uplift on your price by being able to process that gas,” Turnham explains.

Anadarko called investors’ attention to the wet Haynesville and Cotton Valley this spring in its “analyst day” presentation. A super-independent with operations extending to Africa and China and in high-profile U.S. plays such as the Eagle Ford and Marcellus, it devoted several slides to its East Texas portfolio.

There, it finds more than 35% liquids per well and a rate of return (ROR) of between 50% and 95% based on $100 oil and $3.25 gas. Its 2011 net production from the two formations was just under 30,000 barrels of oil equivalent (BOE) per day. During the second quarter, sales were 36,200 BOE per day, ramping toward estimates of 40,000 for the year, the company reports in an update. For 2013, it forecasts making some 55,000 a day. Estimated ultimate recovery (EUR) per well is 1 million BOE.

For its 116,000 net acres, which is all held by production (HBP), it expects to drill 75 wells this year: roughly 60 of those with laterals in the Haynesville formation and the balance in Cotton Valley. Drillsites total some 450 and it has nine rigs at work.

It also notes that, of the roughly 35% liquids content from production in Panola County, about a fifth is oil.

Goodrich has found oil there too. Its Travis Crow GU 1H in South Henderson Field had initial potential (IP) of 9.9 million cubic feet per day including some 600 barrels of NGLs, plus 380 barrels of oil. Turnham says, “So, almost 1,000 barrels per day of liquids come out of that in addition to the gas. Not all of the wells are as good as that, but that’s why those wells are attractive from an economic standpoint.”

GPM

A tight sandstone, the Cotton Valley is an approximately 1,000-foot column down to about 10,000 feet with porosity ranging from 6% to 12% and permeability of 0.01 to 0.08 millidarcy. Producers’ primary landing zone is at the bottom of the formation in the Taylor sand or equivalent. Water saturation is 30% to 40%. Generally, the Cotton Valley gives up between 1.8 and 4.5 gallons of liquids per Mcf or thousand cubic feet of gas (GPM) across Indigo’s acreage, says Fred Bakun, Indigo senior vice president, engineering.

“We have wells where we’ve tested 2.0 GPM in the Vaughn sand, then drilled in the Rose-berry horizon 300 feet deeper and tested nearly 3.0 to 4.5 GPM. Then, even within one horizon over several miles, gas quality can vary; for example, in our Vaughn position in DeSoto Parish, it changes from 1.8 GPM to more than 4.0 GPM over about eight miles.”

Indigo is working to delineate its 120,000-net-acre leasehold over Cotton Valley, which is almost entirely HBP, converting its reserves to proved, developed, producing (PDP) with four rigs running toward a plan to monetize its position by year-end. In a 2009 deal, the company bought rights to formations above the Haynesville from Chesapeake Energy Corp. and has since completed 24 Cotton Valley horizontals with several testing more than 1,500 BOE per day and one of these more than 3,300 BOE.

Its latest well, Berry 25H No. 1 in Caspiana Field in Caddo Parish, flowed 3,019 BOE per day—65% gas; 35% NGLs and condensate—during a 24-hour test period. Lateral length is 3,700 feet and the company applied 12 frac stages.

Indigo is backed by private equity from Yorktown Partners, The Martin Cos., Ridgemont Equity Partners and management. Pritchard says, “By year-end, we will be about 14% PDP relative to total proved. What we’re trying to do is prove each of our sands, so we’re not trying to optimize the highest GPM at this point.”

Bakun adds, “We have more than 1,800 horizontal Cotton Valley locations. Net to Indigo is approximately 4.2 trillion cubic feet equivalent of reserves.”

East Texas platform

For privately held NFR Energy LLC, the Cotton Valley has been the cash-flow platform. The producer was formed in 2006 by oilfieldservice firm Nabors Industries Inc. and private-equity firm First Reserve Corp. with an initial commitment of $1 billion. David Sambrooks, chief executive, joined the company in 2007 from running Devon Energy Corp.’s southern division, including East Texas.

This year, NFR is divesting some Rockies assets it picked up along its way to focus entirely on its Cotton Valley prospects, a start-up position in the Eagle Ford and 75,000 net acres in a play it’s hoping to prove in Navarro County, Texas, south of Dallas. “We’re calling it the DK play for now—DK for Donkey Kong. Some of the kids here named it. We’re completing our first well in it right now, but it’s going to take a few wells to know what we have.”

NFR has some 175,000 net acres in East Texas with about 84,000 of these over Cotton Valley and roughly 80% HBP or, when factoring in where it wants to continue to drill, about 95% HBP, Sambrooks says. In 2007, it began consolidating smaller players in the area that didn’t have the capital, operational and technical wherewithal to take Cotton Valley horizontal. It drilled some vertical wells at first to identify the fringes of the play and has since drilled 68 horizontals in East Texas: 27 of those Cotton Valley; the rest, Haynesville.

“It’s been a prolific producing area for decades,” Sambrooks notes. Old production in the area has been from the shallower Rodessa, Pettit and Travis Peak/Hosston formations. NFR’s gas stream has been in processing since it entered the play. “One of the benefits of this area is there is historical infrastructure. It’s a great place to find hydrocarbons and get them to sales.”

NFR’s well costs in Cotton Valley may run between $6- and $10 million as the producer pushes laterals out to 6,500 feet with as many as 26 frac stages. “We’re very strong advocates of as long a lateral as you can get. And, we can see a pretty predictable recovery per 1,000 feet.” The average is an EUR of about 1.5 billion cubic feet (Bcf) per 1,000 feet.

“It’s not unusual for us to see an 8- to 10-Bcf-EUR well, which I think is surprising to a lot of people. They haven’t normally attached that kind of EUR to Cotton Valley wells, but with the longer laterals we’re drilling and new versions of completion design, it’s getting us those EURs, which yield a pretty economic outcome,” says Sambrooks.

“Not a lot of people are currently focused on the Cotton Valley but, with the increased lateral lengths, bigger and better completion designs and, of course, the solid-liquids component, it can be a very robust play; there’s no doubt.”

In 2011, NFR took advantage of down-market dynamics to do a second round of consolidation in the play, picking up five property sets, including from SandRidge Energy Inc. “Our wells can be some of the more expensive wells in the play due to pushing lateral length and completion design, but our bottom-line economics are among the best, which is what we focus on. In these times of challenging product prices, that makes all the difference in the world.”

Cost benefits

Turnham says the Cotton Valley is a conventional reservoir but it has unconventional characteristics in that it is mostly ubiquitous in the area, long-lived and repeatable. “You are going to make wells over a fairly large area.” Another economic benefit is a Texas tight-gas-sand tax credit.

Goodrich has about 45,000 net acres over Cotton Valley in three fields in Panola and Rusk counties—all of it HBP by some 200 wells it has drilled over the years. Proved reserves are some 205 Bcf equivalent. Its last Cotton Valley horizontals proved some 7 Bcf of EUR for about $7- to $8 million each. EUR varies from 25% liquids from its wells in Beckville and Minden fields, Turnham says, and 38% from South Henderson Field. “A game-changer for this area was clearly being able to process the gas and sell the liquids. That’s been a big improvement in the economics associated with these properties.”

It isn’t drilling Cotton Valley currently, though, as it works on its Eagle Ford liquids exposure with 39,000 net acres there and on efforts to prove the Tuscaloosa Marine shale play economic in eastern Louisiana where it has 132,000 net acres.

“We’re opportunity rich and capital constrained,” Turnham says. “We’re holding our Cotton Valley acreage back because it’s HBP. If we had unlimited capital, you would continue to see us develop our East Texas fields, but we’re trying to keep capex to within cash flow at a reasonable level.”

Meanwhile, well costs have declined remarkably in the play as operators’ rush to HBP their Haynesville acreage has been completed, with rigs and frac crews being let loose. Anadarko noted this spring that its East Texas wells that cost roughly $11 million each in 2010 now cost between $5- and $8 million. Completion costs that were some two-thirds of the total bill are now about a third. EUR per well has, meanwhile, improved from 785,000 BOE in 2010 to 1.1 million today.

Indigo’s Bakun says a frac salesman dropped by the office in Houston recently. “I can’t tell you how long it’s been since we’ve had a frac salesman in the office. It was refreshing.”

NFR’s Sambrooks says, “The supply and demand for services is in the favor of the producer right now. It’s a huge help. If you can see $1 million off your completion costs, that’s going straight to the bottom line, significantly enhancing economics.”

New-generation wells

Others operators in the Cotton Valley include PetroQuest Energy Inc., GMX Resources Inc., Exco Resources Inc., Bonanza Creek Energy Inc. and Forest Oil Corp., which reported a horizontal this spring with an IP of 10.3 million cubic feet equivalent per day, 39% liquids. It has added a second rig.

Still, an inbox search of analyst reports for “Cotton” produces results mostly for cotton—the agricultural commodity.

Turnham says it may not have made many headlines because it’s an old play. “Everyone likes a new one and, foremost, oil. Until Anadarko talked about it in their analyst day, the Cotton Valley had been viewed as dry gas and, frankly, until you were able to process it, it wasn’t clear how much liquids would drop out of the gas stream.”

Bakun adds that older Cotton Valley horizontals’ economics were less attractive. “The first generation of horizontal Cotton Valley wells tended to have shorter laterals of maybe 2,500 feet with eight frac stages. These wells tended to have an average EUR of approximately 3 to 3.5 Bcf. The perception that still permeates the industry and analyst community is that a Cotton Valley horizontal is about two to three times the cost of a vertical for two to three times the reserves—that it is basically a break-even proposition.”

Newer horizontals in the rock, however, have laterals of some 4,000 feet with 15 frac stages and cost some $6 million to produce an average EUR of 6.25 Bcf. Plus, processing and higher NGL prices—as a result of higher oil prices—provide 30% to 75% or more price uplift, he says. “The problem has been that most folks are looking at the older well sets with lower IPs and not factoring in processing.”

Indigo’s Pritchard finds that the Cotton Valley’s ROR exceeds that of the celebrated multi-pay Granite Wash play in western Oklahoma. Apache Corp., a leading operator in the latter, reports its Granite Wash wells cost $8.9 million for an EUR of 793,000 BOE (48% liquids) and an ROR of 44% based on the May 2012 strip. Pritchard says Indigo’s Cotton Valley wells—at a cost of $5.6 million each for an EUR of 1.3 million BOE (55% liquids)—have an ROR of 84%.

“Our wells are less expensive to drill, our EURs are greater and our IPs are higher,” Pritchard says. “The last five wells we’ve flowed back have IP’ed at more than 10 million cubic feet equivalent a day, which is a little less than more than 3,000 BOE per day.