The November supermoon rose behind Precision Drilling Rig 515 in Liberty County, Texas, situated a few dozen miles east of Houston in a patchwork of rice fields and wooded farms. The rig is drilling the Jack Rabbit prospect for Arlington, Texas-based Choice Exploration Inc. It’s a 13,500-foot conventional Upper Cook Mountain test with potential to recover up to 6 billion cubic feet of gas (Bcf) and 200,000 barrels (bbl) of oil.

Two previous offsets have tested this objective, one drilled in 1984, another in 2000. Both were on smaller fault blocks, seven and 22 acres, respectively, and tapped between 30 feet to 40 feet of net pay. Both produced, although with modest results.

The new test targets a larger 41-acre fault block, buttressed with an amplitude anomaly identified on reprocessed seismic data. Choice believes the Jack Rabbit prospect exhibits much stronger seismic attributes, which could indicate a much thicker column of pay. The dry hole cost to test the premise is $2.5 million.

“Gulf Coast conventional prospects offer excellent cash flow and on a per-project basis, the economics are good,” said Jon Martin, Choice president and CEO. “These traditional sands are high quality reservoirs.”

After a slow year, Choice has increased activity in the fourth quarter to begin four new exploration projects in southeast Texas. “As a company, we have close to 5,000 square miles of 3-D seismic in that particular area of the downdip Yegua Trend—Cook Mountain, Frio, Vicksburg, Yegua. If there are budget dollars to be spent in the Gulf Coast, we feel like we will be fairly active.”

Stretching from South Texas to the Florida Panhandle, the Gulf Coast Basin has been a playground for oil and gas explorers since the discovery of Spindletop near Beaumont, Texas, in 1901. The highly porous and permeable reservoir rocks, overprinted by complicated faulting and salt-related tectonics, have been a treasure trove for hydrocarbon explorers seeking structural and stratigraphic traps.

The basin was once dominated by majors and large independents, but deepwater exploration and resource plays ultimately beckoned these operators to more scalable hunting grounds. That left onshore conventional plays largely in the hands of smaller, private independents.

But Gulf Coast conventional operators, too, were hit hard by the downturn in oil prices over the past two years. Projects failed to find financial support, particularly in late 2015 and into 2016, as investors became skittish and working interest partners faced their own cash flow struggles. Now, the downturn is thawing, and conventional explorationists are ready to match financial partners to prospects once again.

“With the downturn in the industry, I see money coming back into the market for conventional deals,” said geologist Deborah Sacrey, principal of Auburn Energy—“if you’ve got a good story.”

A good story today is defined as a low-cost prospect with high reserve potential. As it turns out, there is still ample fruit left on the conventional tree.

Southeast Texas resurgence

Choice’s Martin said 2016 has been “obviously a little slow,” recounting the company’s activity level during the past year. The prospect generating/operating company focused on Southeast Texas did drill some development wells in Jefferson County and drilled an offset to a discovery made in late 2015, but its 2016 capital budget and thus activity was purposefully limited.

“We didn’t want to drill up a lot of our existing inventory at $1.80 gas, and being a generator, it is also difficult trying to find partners when the majority of companies are having their own budget issues.”

While a challenging period, there was a silver lining, he said. “It got us to reach out to other companies that might have a stronger balance sheet and who were looking to take advantage during the down market. In some ways, it has worked better in the long run for us because it has allowed us to expand our reach.”

Martin’s lineage begins as an engineer with Meridian Oil, followed by Belco Oil & Gas and Westport Oil & Gas, with a heavy diet of Gulf Coast exploration. He, along with his team, formed Choice in 2006 as an independent operator and prospect generating company. After many years in the Gulf Coast basins, the company has retooled its strategy to process all seismic in-house in order to keep up with changes in technology.

“To me, that has been a huge difference between success and failure,” he said. “With mature producing areas, when you get to that second, third and fourth pass through the data where there are subtle differences, some of the larger discoveries come out of the later work.

“It took time to get down that road, but now we feel we are on the upper end of the curve when it comes to Gulf Coast reservoirs.”

Martin considers Choice to be more of an exploitation than an exploration company. It focuses on mature basins with a lot of production history and available seismic data.

“It’s a matter of going into producing basins and putting on a much better pair of glasses to exploit it one more level down the technology chain. The sands aren’t new targets, but just additional optimization of an ongoing resource.”

Choice’s success stats range from 60% to 75% within the core fairway, with a return on investment (ROI) “north of 2:1 on a portfolio basis.” Dry holes are part of the business, he said, “then you have some spectacular home runs as part of the range of outcomes. We tend to look at it longer term where we have the opportunity to reinvest our cash flow back into the basin.”

With four new wells drilled in the fourth quarter targeting Cook Mountain, Yegua and Frio, “hopefully, our success will carry into 2017 with some additional activity.” A typical year results in 12 to 15 wells drilled. The company currently has two prospects ready to drill in Orange County, Texas, with committed partners.

At $50 oil and improving gas prices, “the economics work pretty well combined with the overall cost reductions in the industry,” he said. “Costs have come to a point where we feel like we’ve reached equilibrium with pricing in the current term.”

Additionally, Gulf Coast gas has high British thermal unit (Btu ) content and, because of this quality, usually receives a premium to Nymex of 10% to 15% on a volumetric basis, he said, with condensate garnering $1 to $1.50 to Nymex. “In this market, it is always helpful to get the credits for higher-quality gas in that area.”

Nonetheless, Martin considers conventional a linear model vs. a scalable unconventional model, and the company is seeking to balance Gulf Coast cash-flow projects with longer-life, more scalable Western Anadarko Basin plays going forward. But that will not be at the exclusion of conventional, with unconventional targeted to be around 25% of its business.

The upside to working the conventional Gulf Coast, he said, are great rocks, low drilling costs, good-quality product and 3-D seismic in existing basins. “For us, the economics work quite well now. It’s been a positive basin in a down market, given that the reservoirs are so good.”

Louisiana lagniappe

South Louisiana is a niche for Lafayette and Baton Rouge, La.-based The Hise Co., which has been operating in Cajun Country for some 48 years. Its current three marketed prospects are all justified at $40 to $50 oil, according to Richard Hise, president of The Hise Co. “They make great economic sense.”

The Hise Co. operates exclusively in Louisiana’s conventional strata, generating prospects for its own cadre of investors as well as for Baton Rouge-based Pennington Oil & Gas. Hise has managed the oil and gas assets for the Pennington family since the late 1990s.

The Hise Co. is a family-owned petroleum and geological engineering firm formed when Richard Hise, then a reservoir engineer with Exxon in Lafayette, joined his parents, the husband/wife duo of Bill Hise, a petroleum engineering professor at LSU, and Anne Hise, one of the first petroleum engineering graduates at the University of Oklahoma, both of whom were consultants in Baton Rouge. Richard’s son Forrest continues the family legacy of petroleum engineers.

While the company handles projects from “prospect to pipeline,” Hise prides the seasoned expertise of his technical team, all with major company experience, with the ability to find South Louisiana hydrocarbons.

“On the things our technical team has originated, I would be hard pressed to find a well where we had a dry hole that we logged then abandoned.”

The definition of what makes economic sense has evolved over recent years. Deep Tuscaloosa gas wells at 22,000 feet were the targets of choice during the 2000s. These over-pressured wells sported dry hole costs of $15 million to $20 million. The Hise Co. success-fully generated and managed the drilling of 13 of these. But the advent of shale plays flooded the market with gas, softening prices and making the Tuscaloosa wells too costly.

“We have things we’d like to do in the Tuscaloosa, but they’re not justified now economically. We backed away from that years ago.”

In 2014 and 2015, the company successfully drilled four overpressured wells, including two into the deep Wilcox Sands at 15,000-foot depths, producing between 130 bbl to 160 bbl of oil and 200,000 to 800,000 cubic feet (Mcf) of gas per day, with several different zones behind pipe that can be completed later. Hise figures he needs 300,000 to 400,000 bbl of oil reserves to justify the costs of these wells.

While the company doesn’t publish reserves, these wells were successful at prices back then, he noted. “We wouldn’t have drilled the second well at Bayou Latenache if we weren’t pleased with the first. And we have other things to do in this area.”

Yet again, the dry hole costs need to move lower still. With each well requiring a string of protective pipe, “these Wilcox wells would be less justified today.”

Today, to meet economic hurdles, The Hise Co. focuses on shallower, less costly prospects that don’t need multiple strings of pipe. It sets at a minimum of a risk-weighted 2:1 return on investment.

“We think these are more than justified.”

The company has three prospects queued up for 2017 drilling. The Quartz prospect in Morganza Field, Pointe Coupee Parish, is a 13,800-foot Wilcox test. Dry hole cost is $2 million, with potential of 1.9 million barrels of oil. Abita Springs is a multi-well project in Central Louisiana targeting Wilcox oil in two areas, with total potential of 36.5 million barrels. Stallion, with 17 primary targets across 330 feet of potential pay, has potential of more than 2.8 million bar-rels and 2.25 Bcf in Iberville Parish’s Bayou Sorrel Field.

“All three are in South Louisiana with a lot of potential. None of them require setting a string of protective pipe, which greatly reduces costs. There is still oil and gas to be found in South Louisiana on an economic basis at current prices.”

While Hise acknowledged finding drilling partners has been more difficult of late, “we have not generated a prospect where we had to eat the leases and just walk away,” he assured.

Can a South Louisiana prospect generator still make money in the current environment?

“We wouldn’t be doing this six days a week if we didn’t think we could. We live it and breathe it, and we enjoy what we do. The opportunities are there, and we’re trying to take advantage of them.

“We’re busy and we’re active.”

Prospecting the Deep South

Paul Hoffman and Jim Allen know Gulf Coast lithology. Individually, the two geologists have explored the basin for some 40 years, together for the past nine. Allen worked the Hackberry Trend in Louisiana throughout the ’90s with Mayne & Mertz, and Hoffman various Gulf Coast targets with Ladd Petroleum, Duncan Energy and with Cox & Perkins Exploration. Ladd and Cox & Perkins were well-known as two of the dominant players in the shelf-margin Yegua Trend in Texas.

In the early 2000s, Allen struck out on his own with JL Allen Exploration Ventures, backed by a group of investors, and shot the first 3-D seismic survey in the Smack-over peripheral fault trend in southern Arkansas, which turned out to be “quite interesting,” he noted. He shot a total of five 3-D surveys there.

Hoffman joined with Allen in 2008, forming Allen-Hoffman Exploration Co., a Houston-based pure exploration company. Today, the company stands on some 3,800 square miles of 3-D seismic data, about half of which is proprietary.

Soon after forming the company, gas prices softened, and the geologists expanded their focus in sweet oil objectives in the Jurassic and Cretaceous to adapt to the changing market.

“We shifted into Alabama and Mississippi fairly heavily after doing significant reconnaissance work on the Smackover Formation from northeast Texas all the way to the Florida Panhandle,” Hoffman said. “We’ve since put ourselves in the position where we've got probably 700 square miles of 3-D data over in the Mississippi and Alabama area. Those surveys are a pretty big part of our focus as things stand today.”

During the downturn the explorationists have readied 15 prospects in the two states, including targets in the Smackover and Norphlet in Alabama, and in the Cotton Valley, Hosston and younger rocks in Mississippi, while retaining some Wilcox and Midway prospects still in Texas. “The Mississippi and Alabama prospects are all clear, incontrovertible four-way closures based on recently processed 3-D seis-mic data.” Aggregate potential tops 11 million barrels of oil (MMbbl) and 15 Bcf of gas.

“These are inexpensive wells to drill, almost none over $2 million dry hole cost. The reservoir quality is good, and the production allows for payout at not more than a year. Even with today’s oil prices, it makes for a decent return on successes.”

The company sets a 3:1 return as a minimum threshold, with 5:1 a common return on investment for its prospects.

Allen-Hoffman investors retain roughly half and sell down the balance in its prospects to like-minded E&P companies, reserving a back-in working interest. By mid-2015, though, the market was all but dead as the severity of the downturn sank in, he said. “We were getting very little traction on our marketing efforts,” and prospects bottlenecked. Finally, the ice is thawing, and the company is readying two prospects to drill in the first quarter, one each in Clarke County, Ala., and Clarke County, Miss.

“If our stratigraphic prospect in Alabama works, that’s going to be for publication for sure,” Hoffman projected. “It’s quite interesting from the point of view of the seismic technology applied, and would be really a heck of a find. It’s the biggest prospect we’ve had in quite some time.”

The Mississippi prospect is a classic four-way closure at 8,000 feet with reserve potential of 2.6 MMbbl and a dry hole cost of $800,000. It’s in a cluster with three additional similar structures with aggregate potential of 4 MMbbl in close proximity.

But with the migration of independents to shale, are conventional plays playing out?

“Personally, I don’t think so,” said Allen. “They may not be big enough for the majors, but for this play we worked up in Arkansas, we found a 3-million-barrel field at 5,000 feet. That sort of thing can be very profitable to a small company like us. If we can apply the technology, we can find some real gems even scattered within places where there’s been drilling.”

Allen sees sunnier days for conventional players into the New Year. “We’re seeing improvements, but it’s still difficult times for conventional exploration,” said Allen. “We’re going to drill a lot more next year.”

Hoffman sees the upside of a down market. “For the industry being in a decidedly lousy part of the cycle, we’re sitting here with a luxury of prospect inventory and opportunity. We're looking forward to drilling again now with a little bit of a resurgence,” he said.

“Given our druthers, we’d rather have avoided the down-turn, but the silver lining is that we are as rich in prospect opportunities as we've ever been.”

Blue Moon rising

Michel Bechtel and Thomas McWhorter are long-time industry veterans also, having plied Gulf Coast conventional trends for more than 40 years, the last 20-plus together. The co-founders of Houston-based Blue Moon Exploration LLC have seen their share of commodity price highs and lows, as well as active and slow periods. But this time around is frustrating them more than ever before.

“I’ve been in exploration for 46 years, and as far as drilling new stuff, 2016 was the slowest we’ve ever had—ever,” Bechtel said. “Everybody’s saying cash flow is down, they don’t have the budget, there’s no risk money to participate.”

Mitch Polk guides a drilling tool to the ground at Choice Explorations's Bebe #1 conventional drilling operation.

Ninety percent of their work focuses on South Louisiana, and the prospectors are chomping at the bit to find partners for three particular current projects.

“The three projects we’ve got put together right now are every bit as good as the ones we’ve put together over the past 20 years that we’ve had extremely good success with,” McWhorter said. There are just no takers, yet.

The Triad project features three wells, the first being the Boudreaux Shallow prospect. It is a 10,500-foot normally pressured play in Acadia Parish targeting the Miocene-age Het and Alliance sands with potential of 200,000 bbl and 2.5 Bcf of gas. The additional two wells are in nearby fault blocks with existing shallow production, but deeper sands were never tested. These sands have potential of more than 60 Bcf of gas and 1 MMbbl.

The prospects were present at the edges of various 3-D shoots taken at different times, but were hard to image. To identify these, various shoots were merged, reprocessed, acquired and interpreted by Blue Moon.

“The output from the merged dataset gave us the ability to see things more clearly and crisply than we could see on the individual 3-D,” McWhorter said.

The next prospect emerged from the same dataset. West Ridge Extension prospect in Lafayette Parish rises from a series of sands that expand from 150 feet to 800 feet downthrown in two lobes, the Upper and Lower Marg Tex at 14,000 feet. Total potential is 31 Bcf of gas and 464,000 bbl of condensate, with a dry hole cost of $3.9 million.

The flat-spot seismic anomaly that identifies this prospect mirrors the seismic indicators of two other past success stories: A 1995 well that has produced 12 Bcf gas to date, and a 1999 well that tested at 22 MMcf and 1,100 barrels of condensate per day.

“We have a pair of those same flat-spot anomalies that we saw at both of those discoveries drilled in that original, older data set. West Ridge Extension has the potential for being better than both of those first wells.”

But the real prize package is Blue Moon’s Profit Island project in East Baton Rouge Parish. This project seeks to reactivate the Lower Tuscaloosa Trend, the playground of majors in the 1970s and ’80s, with new 3-D data. Bechtel characterizes this play as “the best I’ve ever seen. “They found some tremendous fields, and it was all done on 2-D seismic data.” With new 3-D data at hand, “we can go back into these major fields of the past and now see development opportunities that people couldn’t see before. So you end up with very large, PUD-like development plays in an onshore area with infrastructure.”

Blue Moon markets the potential at 318 Bcf of gas and 22 bbl of condensate.

The catch: The target zones are at 20,000 feet. Despite its depth, “it is development drilling, pure development drilling,” McWhorter assured. “The biggest Catch-22 is that it takes someone that’s got enough capital right now to be able to drill an $11 million dry hole.”

And the project has garnered tremendous interest thus far. “As soon as I get an operator in place with a firm commitment, I believe I can finish getting the partners in line pretty quick,” he said.

Blue Moon has eight more wells behind the first, said Bechtel, “at least. We’ve got a lot of running room.” He believes all three projects will be drilled and put on production this year. When that happens, the company will have the cash to continue leasing for future prospects that are prepared as well.

When prodded that conventional prospectors might be a dying breed, both were emphatically opposed to the thought.

“No, no, no, no,” Bechtel corrected.

“Definitely not,” McWhorter answered.

“Most people will realize that the risk-reward in conventional drilling is actually much greater than the risk-reward in unconventional drilling,” Bechtel continued. “The scientists—the geologists and geophysicists—would probably say the conventional stuff is very strong. It’s those pushing unconventional—more of the financial guys—that like the shale. They’re not scientists.” McWhorter added, “You can find more bookable reserves with unconventional drilling, but you’re going to find better producible reserves with conventional drilling.”

Spoken like hard-core prospectors, but they acknowledged fewer younger explorationists are following behind them. “That’s why you’ve got all of us old guys still doing it,” Bechtel mused.

Third time charmed

“If you follow the Gulf Coast line from the Texas/Mexico border through southern Louisiana, those are areas my team and my family have been operating in for multiple generations,” said Gregg Davis, founder of D3 Energy in Houston. “We know the Gulf Coast region very well, as well as several other sub-basins in Texas.”

Davis is the son of iconic oilman and media magnate Marvin Davis, who built Davis Oil Co. and owned movie studio 20th Century Fox, Pebble Beach and Aspen Skiing Co., among other high-profile assets. Gregg trained at Davis Oil then went on to build Davis Petroleum Corp. D3 Energy represents the third Davis oil company iteration for Gregg Davis.

D3 Energy is “focused on conventional trends with repeatable, resource-play qualities,” he said, “primarily targeting legacy trends with stacked pay benches, applying old fashioned 3-D interpretation, integrating well logs with lithology and mineralogy and employing mod-ern drilling techniques.”

Davis’ future success lies in his technical team, who has successfully worked together previously, each with 35-plus years of experience. “They’re oil and gas finders; real explorationists,” he said. “They can do the whole thing.”

The model is an extrapolation of traditional prospecting. Rather than targeting one-off prospects, D3 Energy’s strategy is instead to harvest mature fields and trends by building a comprehensive basin-wide map correlating all known information. It’s a labor-intensive endeavor that has been the company’s mission during its first two years. To build its proprietary maps, D3 Energy’s data analysts are marrying all available seismic, including fault patterns, to production history, accumulations and well logs.

“We’re building battle maps,” he said. “Every-thing we’re doing has lots of running room.”

Historically, operators focused on just one tar-get and passed over shows in other formations, or were unable to extrapolate opportunity in trends across distance. “You can uncover pat-terns, and hence drilling targets, based on the historical environment of deposition and fault-trap integrity that may have only been grazed with past drilling activity.”

Davis wouldn’t say specifically which regions his team was mapping, only that they were in Texas and Louisiana, and the targets would include Wilcox, Vicksburg, Yegua and Miocene along the Gulf Coast, “and we’ve got some new ones we’ve uncovered in traditional Permian formations.”

While Davis Petroleum was known for exploration, famous for the Eagle Bay discovery in Galveston Bay that hit 150 Bcf of gas and 15 MMbbl of oil, D3 Energy’s strategy is the oppo-site of wildcatting, he emphasized.

“This is an acquisition and exploitation program. We’re going into areas others aren’t focused in where there is lots of well control and existing 3-D, and making new correlations.” Most legacy fields were developed using the basic geological and drilling knowledge of the time, he noted. “With a comprehensive ‘look-back’ and integration of new interpretive technology and drilling techniques, we are renewing and extending trends and improving statistical success. Like an unconventional trend, we’re drilling wells in areas where there are established productive benches that we can exploit for miles using modern drilling and completion practices.”

The company is getting ready to execute on its expansive acquisition and development plan. “We’re going to start 2017 pretty aggressively,” he said, with first activity by summer or earlier. Most wells will be under $1 million. “We’re pretty certain we’re going to find hydrocarbons wherever we go; we know the fluids are there. It’s just a question of how much are we going to get?”

Most people look at a map and see thousands of well dots and say that’s an old area that’s been drained—why bother with it?, he said. “That’s what we’re looking for because, truth is, there is still a lot of opportunity there.”

But is there enough meat left on the bone in conventional?

“It’s significant,” said Davis. “If only I could show you. Texas is still chock-full of oil and gas, and there is a tremendous amount remaining in conventional trends that are overlooked.

“In some areas there are tens of millions of barrels left and several hundred Bcf of gas. It’s going to take some work, but there are still multi-million barrel fields to find. We know, because we’ve got it on our technical work.”

Detour through Kansas City

For 27 years Corpus Christi, Texas-based Suemaur Exploration & Production LLC has made its living drilling deep gas wells in deep South Texas, but those just don’t work now, said Jim Devlin, vice president of land. “There’s no way to mas-sage the numbers to make those prospects work. We’re faced with trying to find projects that are large enough that can withstand a high cost with low gas prices. There are fewer of those prospects that work at $3 gas.”

Suemaur—named after two of the founders’ wives, Carolyn Sue and Maureen, in 1968—has prospects in the chute that will make economics at $4 gas and others that won’t meet economics until gas tops $5. “That’s just reality. You just can't drill a deep gas well—we’re not there yet.”

The company is instead targeting shallower prospects that don’t require a drilling liner, but “that’s a fairly narrow window,” he admitted.

To fill the gap, Suemaur expanded its scope to include shallow, oily Lansing/Kansas City targets in northwest Kansas, where it completed seven out of 14 total wells drilled in 2016. From a dollar standpoint, the break will be about 50:50 Kansas to Gulf Coast drilling, but from an activity standpoint, the same amount of money will buy a whole lot more drilling in Kansas than in South Texas.

“It’s just a matter of balancing our portfolio,” said Devlin. “We needed a play that made economics in the current environment, and not know-ing what was going to happen in gas because of the unconventionals, we decided to get oilier.”

The company did drill three wells on Lopez Ranch in Brooks County, Texas, this past year which Suemaur president and CEO Brent Hop-kins characterized as “marginal to pretty good,” and an unsuccessful Vicksburg wildcat. “It was a rank wildcat, high potential. It just didn’t work. It happens.”

Nonetheless, Suemaur has just made a deal to acquire 700 square miles of seismic data in the Gulf Coast that will bear a significant number of prospects, “we hope. We’ve got a serious commitment to the Gulf Coast in addition to the projects we’ve got going on, with the focus on trends that don’t need to be fracked, and that don’t have as much sand risk as the Vicksburg trend.

“We’ve moved up the coast into some better rocks,” Hopkins said.

Devlin emphasized the company acquired the data with the express intent of generating prospects that it fully intends to drill. “Over the next two to three years, we hope to have a long list of Gulf Coast exploratory prospects that we will be putting together and drilling.”

Following NAPE last summer, Hopkins is optimistic for the future of conventional prospects, where he experienced “a surprising number” of people looking for deals.

“It was the best NAPE we’ve had in six to seven years,” he observed. “There’s an appetite for conventional right now, but it’s got to be the right prospect.”

Hopkins is optimistic on Gulf Coast gas long-term, pointing to the $50 billion in newbuild infrastructure that he sees going in looking out his office window in Corpus.

“A lot of the European and Asian petrochemical industry is moving here because we have cheap energy. With this amount of end users, and the amount of gas that’s going to Mexico and overseas via LNG, you’ve got to think at least the South Texas Gulf Coast is going to get a premium for its product.

“You can’t build all these plants and not turn them on. That’s a lot of gas that’s got to come from somewhere.”

Which leads us back to the investment in seismic. Much of the Suemaur executive team has been together for 35 years and is unfazed by the downturn.

“This isn’t our first rodeo,” opined Bill Maxwell, Suemaur board chairman. “We fully expect to thrive as things get better. We certainly haven’t given up on Gulf Coast conventional—we’ve just reloaded.”

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