The East will rise again—East Texas oil and gas, that is. As to when the heavily forested region can expect its next hydrocarbon renaissance, the consensus is: not yet.
“It seems like a lot of development in East Texas has been on an extended vacation,” Greg Haas, Houston-based director of Stratas Advisors, a Hart Energy company, told Midstream Business. “The hydrocarbons in that area are mostly gas, and we’re looking at low gas prices for the recent past and even into the near future. Even though the resources are wonderful in East Texas for producing gas, the gas prices and the relatively low gas demand in this area are not conducive to new midstream infrastructure.”
That said, there may be hope on the horizon, especially if the horizon looks out over LNG export facilities under construction on the Gulf Coast of Texas and Louisiana.
“I think LNG’s going to be a big savior for a lot of plays,” Jessica Garrison, Stratas’ manager for upstream research, told Midstream Business. “I’ve seen that trend in a couple of other areas as well, where people are vocalizing that it’s slowing down until LNG picks up again.”
Slowing for the most part, but not everywhere, that is. Midcoast Energy Partners LP, an Enbridge subsidiary, responded to the uptick in horizontal gas production in Louisiana’s Cotton Valley Formation (below the Haynesville Shale) with the opening of its Beckville Cryogenic Processing Plant in Panola County, Texas.
“We had a significant amount of lower [gallons per minute] gas flowing but not being processed due to full utilization of our facilities in the region,” Michael Barnes, senior manager for operations and project communications at Enbridge, told Midstream Business. “In addition, due to our extensive footprint, we will be able to deliver gas from the Eaglebine play to our East Texas processing complex with the completion of the Ghost Chili lateral later this year, which will bring existing volumes to our system currently moving on a competitor’s pipeline.”
Midcoast’s 40-acre Beckville plant is designed to handle 150 million cubic feet per day (MMcf/d) of natural gas and 6,900 barrels per day (bbl/d) of NGL. The company’s total processing capacity for Haynesville and Cotton Valley totals about 820 MMcf/d. Midcoast’s East Texas system is comprised of 4,100 miles of gathering and transmission pipelines, six natural gas processing plants and seven active treating plants.
That’s plenty to keep Midcoast busy without reacting to a demand surge from LNG plants, but it is prepared.
“While not built into our forecast, we have indications that there is a lot of interest to move gas to the Gulf Coast,” Barnes said. “The [Midcoast] Double D 36-inch and Clarity 36-inch pipelines are well positioned to capitalize on these opportunities if they develop.”
Midcoast is not the only player on the move in the area. MarkWest Energy Partners LP is engaged in a 67% expansion of its Carthage East gas processing plant in Panola County from 120 MMcf/d to 200 MMcf/d. The project was expected to be completed in the third quarter.
John Mollenkopf, MarkWest’s executive vice president and COO, told analysts earlier in the year that the plant would likely return to a utilization of around 90% by as soon as first-quarter 2016. He noted that Carthage East was built in 2012 with the capability of handling 200 MMcf/d but installed residue compression only totaled 120 MMcf/d.
“This expansion is very economic,” he said, “and just involves adding the additional compression to the back end of the plant to bring it up to that 200 million a day capacity. It’s a really efficient expansion.”
“The increased drilling programs in East Texas and in western Oklahoma will increase utilization,” Frank Semple, MarkWest chairman, president and CEO, told analysts. “And in fact, we’re currently planning for additional plant expansions in western Oklahoma and in East Texas to be able to accommodate what we see as the future growth.”
Across the border, PennTex Midstream Partners LP expects its 200 MMcf/d design-capacity cryogenic natural gas processing plant near Ruston, La., to begin operations in October. The facility will have onsite liquids handling facilities for inlet gas and is already booked with 15-year fixed-fee contracts.
The PennTex plant could serve East Texas plays, as well, Haas said, noting that the expansion of capacity among the players could satisfy growth in the region for several years.
“So it’s not completely flatlined,” he said of expansion projects. “But it certainly is not something like the Utica or the Marcellus or even the Eagle Ford or the Permian.”
But why not?
The region’s plays are not minor actors in the gas reserves arena. The latest U.S. Energy Information Administration estimates put the Haynesville-Bossier at 16.1 trillion cubic feet (Tcf), just shy of Eagle Ford’s 17.4 Tcf. To the north, Arkansas’ Fayetteville Shale boasts 12.2 Tcf. Clearly, Marcellus possesses a huge advantage in the pure volume of its reserves, but it’s not just how much—it’s how accessible.
“Haynesville was huge, and it just did not go anywhere when they discovered the Marcellus,” Garrison said. “Completions are a little bit harder in the Haynesville. It’s just very easy to get to in the Marcellus, whereas Haynesville’s a lot deeper. I definitely think that the Haynesville has a chance to come back, and I think LNG will be the push because of its geographic location.”
And it’s not only how accessible, but who wants it. The Haynesville produces very dry gas with little associated NGL.
“The Marcellus is very nicely situated for a number of demand markets, including Canada,” Haas said. “Very populous regions of Canada are looking to import more Marcellus and Utica natural gas, and there are a number of pipeline operators working to make that happen.”
In spite of the attention granted to Cheniere Energy Inc.’s Sabine Pass and Corpus Christi facilities, there are LNG export plants in development on the East Coast, including Dominion Resources Inc.’s Cove Point in Maryland, and Kinder Morgan Inc.’s Elba Island in Georgia. Haas expects those plants to absorb material volumes of excess gas production. Furthermore, a host of U.S.-based pipeline projects are positioned to deliver billions of cubic feet from the Marcellus-Utica to New England all the way down the Eastern seaboard to the Carolinas and Florida.
Those plays’ unbeatable location has placed the “beast in the east” in the cat-bird seat.
“The Gulf Coast, as paradoxical as it may seem in terms of gas, has been there, done that,” Haas said. “We’re not a big heating market, so if there’s a big new source of gas in between us and the Gulf Coast and that existing demand center on the East Coast, well, that source of gas—Utica or Marcellus—is going to have the leg up in terms of lower-cost supply. In a way, it’s gas-on-gas competition. The East Coast production is a better fit and more economically served if it can expand its pipelines to reach the northeast markets than is the production here in Texas.”
Stubbornly low commodity prices have hobbled the East Texas region, rendering much of its hydrocarbon wealth off-limits until better fortunes favor the industry.
“We definitely see the plays continuing to increase year-over-year production but at a much slower rate than previously anticipated,” Garrison said. “Stratas, in general, feels that prices are going to rebound at some point, and we’ll see an overall production increase again, probably toward the end of 2016 into 2017. That’s a theme that we’re seeing in some of the plays.”
Hanging on until 2016 is critical, she said. The Stratas experts anticipate a rising rig count; more wells being drilled and increased capital expenditures within the next two years.
“When you’re talking about the gas plays right now, operators are still expecting to increase production but not running many rigs at all,” she said.
“I’ve heard a couple of operators anticipate a 30% production increase this year. Another operator has projected a 20% increase in production because they’re going back and tying in wells that were already drilled and completed, rather than waste capital on new wells this year when prices aren’t good.”
Enbridge’s Barnes is cautiously optimistic.
“Outlook for the region is potential growth with the prolific nature of the horizontal Cotton Valley and also for the Eaglebine,” he said, noting that a lot of horizontal drilling and hydraulic fracturing calculations need to be figured out. Oh, and one more thing, Barnes said: “A crude oil price above $60 per bbl would be beneficial.”
Eagle Ford Jr.? Probably Not, But Then Again …
The rumors, floating hopefully through the coffee shops and diners of Crockett, Madison and Walker counties in East Texas, describe massive reserves of crude oil and natural gas awaiting producers in the Buda formation. Pipelines capable of moving 5 billion cubic feet per day and 1.7 million barrels of oil, or roughly the output of OPEC member Angola, are in various stages of construction.
Has Texas, already laden with the embarrassing riches of the Eagle Ford Shale, Permian Basin and Barnett Shale, done it again?
“It is very early to call the Buda the next big thing in East Texas,” Michael Barnes, senior manager for operations and project communications at Enbridge, told Midstream Business.
But it’s not too early to connect the dots and devise a theory. Here is what a team of Credit Suisse analysts came up with in a report released earlier this year:
EOG Resources Inc. completed a well in December 2013 called Vick “B” Unit #1H. The well tested at 1,765 barrels of oil equivalent per day (boe/d), including 850 bbl/d oil. “Interestingly,” the analysts wrote, “despite the fact that the well was completed on 12/14/13, there was a meaningful lag to the state in terms of reporting (the completion report was filed five months later).”
• The well produced 250,000 boe in its initial 150 days, far above the initial rate of 120,000+ boe from a typical Eagle Ford well.
• Listing several wells completed, the analysts declared that “we believe EOG has established a ‘zone of certainty’ in southeast Madison County.”
• The analysts noted Knight Warrior LLC’s decision to move ahead on its$300 million, 160-mile pipeline that is expandable to 200,000 bbl/d, and plans to build a $90 million gas processing plant in Houston County, Texas, by Lone Star NGL LLC, which is 70% owned by Energy Transfer.
• Conclusion by Credit Suisse analysts: “Many of the inputs to our first-cut analysis are based on assumptions that could prove incorrect. That said, we doubt ‘the Harvard of Shale’ would be spending significant time and energy on a play that wasn’t a potential needle mover. Our first cut analysis suggests$5 to $10 per share of risked upside assuming success.”
Credit Suisse is not alone. J.P. Morgan analysts noted that EOG had amassed more than 700,000 acres in East Texas and North Louisiana, not counting its legacy Haynesville and Bossier acreage.
“Until it acquires its target acreage, EOG likely is trying to conceal, for competitive reasons, its testing program as much as possible,” the analysts wrote in a second-quarter report.
Because the activities are under wraps, J.P. Morgan was reluctant to speculate on what a major discovery could mean for the company, but offered that “announced success on the large acreage position that EOG has amassed could cause the stock to rise at least 10%.”
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