Eagle is Not Landing

It's easy to draw comparisons between the Eagle Ford shale and its namesake bird. After all, the play is soaring, becoming a national symbol for energy independence, and helping midstream players make bold, innovative moves. To keep the metaphor rolling for just a little longer, many analysts predict the play will be flying high for years. In fact, its landing isn't even in sight. It's all pretty astonishing considering the uncertainty the Eagle Ford hatched from.

For decades, the golden egg has been sitting stagnant in South Texas, waiting to be tapped into. Experts have known about the oil and gas riches lying beneath the Eagle Ford shale since the 1970s. At the time, the extraction of those resources was thought impossible since the necessary drilling technology did not yet exist. While the Barnett and Bakken shales were the first to test the horizontal drilling waters, it was the wealth uncovered at the Eagle Ford that blew the industry away.

Today, the Eagle Ford is ranked among the country's finest tight oil plays, according to a recently released IHS report. In fact, the play's peak-month production and typical well performance exceed the Bakken Shale, says the IHS Herold Eagle Ford Regional Play Assessment. Its success is attributed to strong drilling results, alongside enormous resource potential. "The favorable outlook for the Eagle Ford is reflected in a highly competitive merger and acquisition environment, with implied deal values averaging $14,000 per acre for Eagle Ford acreage in 2011 and top prices approaching $25,000 per acre," says the report.

The IHS is currently analyzing the play's decline curve, though no figures are currently available. Decline curves vary from play to play. According to most recent well results, the Eagle Ford is producing between 300 to 600 barrels (bbl.) per day for a median individual well, compared to the Bakken's average of between 150 and 300 bbl. per day for a median individual well.

Besting the Bakken

"Our analysis at IHS indicates that Eagle Ford drilling results to date appear to be superior to those of the Bakken," says Andrew Byrne, study author and IHS director of equity research, in a public statement. "Although the well counts aren't nearly as high at this point in development of the Eagle Ford, the peak of the well-distribution curve compares favorably with the Bakken."

Encompassing three windows—oil, liquids-rich gas and dry gas—the Eagle Ford's central area includes several counties. It runs through Gonzales, western Lavaca, DeWitt, Wilson, Karnes, Bee, Live Oak, Atascosa, Dimmit and eastern Mullen. The liquids-rich window has produced the highest production rates on a barrel of oil equivalent (BOE) basis, according to the report.

"The central area of the play has outperformed other areas and has been the focus of most of the drilling to date," adds Byrne. "The western area is the next best, with the eastern area having the least activity and performance lagging in the other two areas."

Comparing the Bakken with the Eagle Ford can be tough for a number of reasons, Byrne tells Midstream Business. First, they're measured in different ways, since they contain different resources. The Bakken oil shale is measured in bbl. of oil, while Eagle Ford production is tracked in BOE, since it contains oil, gas and natural gas liquids. Even the Eagle Ford's oil window has a gas component, which makes it difficult to compare oil-to-oil, since the gas aids in flow rates. Meantime, high oil contents in the Bakken tend to sway comparison economics, since oil is considerably more valuable than gas. As well, the Bakken has existed longer than the Eagle Ford, and its maturity has helped it move further ahead with well distribution.

"There are nuances that can be significant, even when you're just talking about comparing the well distribution," says Byrne.

Taking all of the above factors into account, Byrne and his team were surprised to see the Eagle Ford surpass the Bakken. The latter play has traditionally set the standard, he says, since it was the first U.S. unconventional oil play to emerge alongside the gas prone Barnett shale. The Bakken's strong well results, coupled with its size, allowed it to become a game changer that has impacted U.S. oil volumes.

"Prior to the Bakken and Barnett, the industry did not believe these tight oil or unconventional oil plays were possible," says Byrne. "The Bakken is really what blew it all open. The Bakken is the play we should compare all unconventional oil plays against."

Yet, as interesting as the Bakken is, with its size and oil reserves, it's not keeping up with the Eagle Ford's impressive drilling results and even larger ultimate resource potential. The Eagle Ford's wells are strong and contain good liquids content, which should translate into hefty returns. Comparisons over whether the Bakken oil well or the liquids-rich Eagle Ford well is most valuable are under way. Ultimately, however, any economic analysis starts with well productivity, says Byrne.

In the report, liquids-rich gas prospects are noted as being the most popular target in the Eagle Ford. While gas helps create higher volumes, oil is actually sitting in the higher part of the value stream. Oil can appear even more valuable when the highly volatile nature of natural gas liquids (NGL) prices are taken into account. Yet, as the Eagle Ford continues to soar, analysts like Byrnes don't foresee a plunge in drilling activity in the near future.

Right now, IHS is working on a study that will reveal the Eagle Ford's total estimated productive capacity. Much of this research will be released in a tight-oil, multi-client study. This study will examine records from 1997 to early 2012. The IHS team will explore the 27 key tight oil plays in the U.S., as well as the country's sub-plays. Byrnes researched the recently released study using IHS databases to compare well production results from various plays.

In the interim, midstream companies are continuing to reveal how high productivity in the play is helping boost their balance sheets. Chesapeake Energy Corp.'s Eagle Ford activities, for example, produced exceptionally strong results for second quarter 2012. It yielded net production of 36,300 BOE per day, or 75,400 gross BOE per day, resulting in a year-over-year increases of 615% and 58% respectively. Those figures included an increase in liquids production of 745% year-over-year and 71% sequentially. During that time frame, about 66% of Chesapeake's production was oil. NGLs accounted for 17%, while an equal amount of natural gas was produced.

The company is continuing to grow its production through the construction of new compression facilities, pipelines and extra short-term truck transportation for oil. Once its new oil gathering pipelines and associated infrastructure are completed this month, Chesapeake expects its Eagle Ford price realizations to improve by about $5 per bbl.

Chesapeake's well count as of June 30 sat at 337 in the Eagle Ford. Of those wells, 121 reached first production in second-quarter 2012, compared to 62 in first-quarter 2012 and 27 in second-quarter 2011. As of June 30, 2012, Chesapeake had about 220 Eagle Ford wells drilled that had not had not yet begun producing. The wells were either in various stages of completion, or awaiting pipeline connections. And of the 121 wells that began producing in second-quarter 2012, nearly all—or 110 wells—had peak production of more than 500 BOE per day. That figure includes 37 wells that had peak production of more than 1,000 BOE per day.

Growing up fast

Data from the Railroad Commission of Texas paints a picture of just how fast the Eagle Ford has grown. In 2008, the commission issued 34 drilling permits. That number grew to 94 in 2009. The following year, in 2010, more than 1,000 permits were issued. In 2011, 2,800 permits were handed out. And in the first five months of 2012, more than 2,000 drilling permits were issued.

"Drilling activity is growing exponentially," says Danny Oliver, senior vice president of business and corporate development with NuStar Energy LP. "Of course, production then does, too."

As mentioned, production is heating up largely thanks to relatively new technologies such as horizontal drilling and fracking. Upstream companies are consistently improving their fracking skills and are finding the wells they have hydraulically fractured have higher initial production rates.

The struggle to accommodate that growth is intensifying as companies like NuStar work to keep up. Many companies have been forced to move liquids by truck while awaiting improvements to pipeline capacity. Some existing pipelines that were previously underutilized or idled are now being utilized and servicing different needs.

Meantime, upstream folks are drilling as fast as they can.

The clock isn't just ticking on pipeline construction. Companies are also being slowed by a host of legal issues. "It's just a race to get your permits done, your right-of-way bought and then your project constructed in time to receive the barrels from our customers," says Oliver.

He doesn't see things slowing down anytime soon, and he expects companies to remain in the active drilling mode for the next decade, before the Eagle Ford enters the production phase of its life.

Transforming a company

Right now, NuStar is shipping exclusively crude and condensate, though it is mulling entry into the gas or NGL side of things. It's even working on a 12-inch pipeline from Corpus Christi to Houston that will be in Y-grade (mixed NGLs) service.

The Eagle Ford has helped the company grow.

"It's been a transformative play for our company," says Oliver. "It's provided a significant amount of EBITDA for us. I think with what we have going on with the Eagle Ford—just with our current assets—I think from this year to next year it could easily increase our earnings by 50% or more."

NuStar currently has several pipeline-delivery systems in the shale play. Its first pipeline to go into service was the previously idled South Pettus line, which runs from Pettus, Texas, to Corpus Christi. The now reactivated 60-mile line is capable of moving about 35,000 bbl. per day as part of a long-term lease agreement between NuStar and Koch Pipeline Co. NuStar operates the pipeline, while Koch leases the capacity and has combined it with existing gathering systems to move product from the Eagle Ford to Corpus Christi refineries terminals. The line went into service in June 2011.

NuStar next entered into an agreement with Valero Energy Corp. in a move to improve its transportation of crude and condensate to supply its refineries in Three Rivers and Corpus Christi. The partnership resulted in NuStar modifying existing sections of its South Texas pipeline system, which now runs from Three Rivers to Corpus Christi, to better accommodate Eagle Ford production. The eight-inch refined products pipeline initially ran in the opposite direction, but was reversed and converted to service crude oil. That line went into service in September 2011.

NuStar also built 55 miles of new 12-inch pipeline, which connects to existing pipeline segments, to move crude from Corpus Christi to Valero's 100,000 bbl. per day Three Rivers refinery.

As well, NuStar boasts a 16-inch system that was recently reversed. The line today runs from Corpus Christi, where NuStar has an existing crude oil marine facility. It was reversed after NuStar built some tankage in the Three Rivers area, where it is a partner with Texstar Midstream Services LP. Meantime, Texstar has built a gathering system in Frio and La Salle counties and into the Three Rivers area. Its system can take in as much as 100,000 bbl. per day. Texstar also built origin tankage near Three Rivers, where it gathers barrels and pumps them into NuStar's 16-inch pipeline.

The pipeline became operational in July. Although it's not yet running at full capacity, NuStar is currently moving 165,000 bbl. per day on all three of its pipeline systems running from the Eagle Ford to Corpus Christi.

As well, NuStar is developing other pipeline assets that reach into Karnes County. Once that development is complete, NuStar will be capable of bringing an extra 100,000 bbl. per day from Karnes County into its Oakville storage hub in Three Rivers. NuStar's capacity could go from its current 165,000 bbl. per day to nearly 300,000 bbl. per day.

NuStar's pipeline systems were among the first to go into service in the Eagle Ford. The system it has in place right now gathers crude from La Salle and Frio counties.

"Two years ago, really, there was nothing—absolutely nothing—out there," Oliver says.

"This has been an exceptionally lucrative deal for us, just because we had existing assets in the ground when they started developing the Eagle Ford."

Today, with the new volume in crude that's being extracted thanks to new technology, the game has changed. This could ultimately mean good things for the U.S., says Oliver.

"I think on a larger scale for America, with all of the shale plays in total, it's a significant amount of domestic supply that just wasn't available a few years ago."

A promising future

Some master limited partnerships (MLPs) are turning to the Eagle Ford for an opportunity to grow. Magellan Midstream Partners LP anticipates doing just that in the area, with many reports forecasting a promising future for the play. About 600,000 bbl. per day is currently being extracted from the Eagle Ford. According to a Bentek Energy report, that number could swell to 1.3 million bbl. per day by 2017. With such optimistic figures on the horizon, Magellan is seeking additional growth opportunities in the area, both organically and by acquisition.

"We see a lot of positives in the Eagle Ford play. We're committed to it," says Robb Barnes, Magellan's vice president of marine terminals and crude oil. "It's a very efficient and productive play by all means. It seems the Eagle Ford has many positive benefits that are going to allow a lot of barrels to be produced out of there."

The company has established a presence in the area. Magellan and Copano Energy LLC formed a joint venture in late 2011 to deliver Eagle Ford chemical-grade condensate to Corpus Christi. Called Double Eagle Pipeline LLC, the partnership will result in the construction of a 140-mile pipeline, which will connect to an existing 50-mile Copano pipeline. That line will link to Live Oak, McMullen and La Salle counties, which will allow condensate to be delivered from the Eagle Ford to Magellan's Corpus Christi terminal. The pipeline will have an initial capacity of 100,000 bbl. per day. Double Eagle is also constructing a new truck-unloading facility near Three Rivers to accommodate condensate deliveries destined for Corpus Christi. The overall project, which will cost about $150 million, is expected to be in service by mid-2013.

In connection with the joint venture, Copano is converting its existing, aforementioned pipeline from natural gas to condensate service, while Magellan will make the necessary changes to its Corpus Christi terminal. It's also constructing 500,000 bbl. of new condensate storage as well as a dock-delivery pipeline.

Magellan already has a large and well-connected terminal in the Corpus Christi area, which is connected to local refineries. The facility currently handles the truck unloading of condensate and crude barrels coming from Eagle Ford. It disperses those liquids to appropriate destinations, based on customer needs.

As well, Magellan handles plenty of Eagle Ford barrels arriving into the Houston market via an Enterprise Products Partners LP pipeline. Magellan itself owns the largest crude/condensate pipeline distribution system in Houston and is connected to all of the area refineries. It started offloading condensate at its Corpus Christi terminal at the end of 2011 and has been handling Eagle Ford barrels in Houston since the start-up of Enterprise's pipeline.

While Magellan's midstream presence in the Eagle Ford is young, the company has already been witness to incredible growth. Its condensate barrel volumes are increasing drastically each month as more Eagle Ford liquids head toward the Gulf Coast.

"Our assets are fairly new," says Barnes. "We're adapting and being creative and flexible to meet the demands of shippers and producers. The Eagle Ford play itself has been very dynamic and productive. With that comes a lot of barrels being produced up there that are finding a home at the end destination. We're trying to meet those needs."

Many of Double Eagle's customers are transporting crude and condensate by truck into Magellan's terminal for offloading to refineries. Trucks are being used as an interim solution as pipeline capacity is continuing to grow. Plenty of new pipeline announcements have been made, though the actual lines are still in the construction phase. That is the case for Magellan's 140-mile line.

"The growth has surpassed a lot of people's forecasts," says Barnes. "With that comes the need to take those barrels to the end market. The biggest factor you can look at is the volume that's coming out of the ground. It's surpassed all the expectations."

Barnes attributes the production rise, in part, to the Eagle Ford's location near two refinery hubs. It is less than 100 miles from Corpus Christi and just 175 miles from Houston. Also, the wells are producing high volumes at a relatively low cost. Its location and ability to release product at a reasonable price work to the play's advantage.

Risk and reward

In a play as diverse and expansive as the Eagle Ford, some companies are finding themselves taking chances. This was the case for Newfield Exploration Co., which in early 2010 purchased 250,000 acres in a previously untested region of the Eagle Ford. It paid $217 million for the acreage in Maverick and Dimmitt counties from TXCO Resources Inc., which was shedding its assets after filing for bankruptcy. TXCO filed for Chapter 11 in May 2009 after getting slammed by poor energy prices. Newfield snapped up the land on a hunch the same Eagle Ford type of formations that were thriving in the Gulf Coast basin would exist in the Maverick basin.

Since Newfield was taking a chance on the property, it paid just $400 an acre (excluding the value of production) for the land in a time when Eagle Ford land was typically selling for between $4,000 and $8,000 per acre. The company's low-entry fee, however, came with geologic risk. The trade-off was a low-entry price.

"It was a very significant transaction for us because of the scale. However, it had some exploration risks to it," says Steve Campbell, Newfield's vice president of investor relations. The company has so far deemed approximately 50,000 acres as commercially developable. "We are methodically attacking the challenges we face today and hope to expand the economic footprint of the acreage. As we move to the north, that number could go higher."

Newfield is currently assessing its remaining 200,000 acres and hopes to eventually move them into the commercial window.

The purchase has paid off for Newfield with respect to the land it has already tapped into. When it bought the assets from TXCO, net production was approximately 1,000 bbl. per day and consisted largely of black oil. Its production has since swelled to approximately 5,000 bbl. per day in the region. Its recent growth is being attributed to the drilling of super extended lateral wells, which have led to higher production. Newfield also uses controlled flow-back techniques to limit pressure drawdown in the reservoir. Ultimately, this technique helps lead to higher cumulative production over the long term, which translates to higher returns for Newfield.

Now, the company is working to replicate the success it's seen in those wells in the remaining parts of its acreage. Specifically, it's working on an expansion from its West Asherton area, where it is drilling to the north with hopes of expanding its economic footprint. This is a lofty task, since the Eagle Ford formation becomes progressively shallow further north, causing producers to lose reservoir energy and pressure.

"We have a tremendous amount of oil under our acreage. The challenge is how to get it out and make it commercial," says Campbell. "Because of its high black-oil content, it has some unique challenges in getting oil out of the ground, as opposed to oil and gas mixed together."

Of course, oil prices are helping Newfield's returns. By its own estimates, it's seen at least a 35% rate of return at its super extended lateral plays. Newfield expects its return to rise even more as it lowers drilling costs in the development phase.

"It's certainly because of the economics," he says. "In the Gulf Coast Basin, the Eagle Ford is a play with high flow rates, an attractive oil cut and a high natural gas liquids cut. In today's market where oil is trading at $100 per bbl. and gas is trading at approximately $2.50 per MMbtu, any of those plays that have a high oil or NGL yield are far superior in economics to any dry natural gas play."

However, NGLs aren't as valuable as they once were, leaving many focusing their efforts on crude oil. As the amount of NGLs being pulled from the Eagle Ford rises, their values are decreasing in tandem. While NGL prices were once worth upward of 70% of the price of a barrel of oil, they've slid down to 40% due to oversupply.

Innovative moves

TEAK Midstream LLC recently completed a $295 million construction project that includes about 250 miles of gas gathering and residue delivery pipeline, as well as a 200 million cubic feet per day (MMcf/d) cryogenic processing plant in South Texas. The undertaking is part of long-term firm gathering and processing agreements with Talisman Energy USA Inc. and Statoil Natural Gas LLC.

The project includes two high-pressure gas gathering systems. The larger includes over 130 miles of 24-inch and 45 miles of 16-inch pipeline. This system will run through Bee, Live Oak, McMullen, La Salle, Webb and Dimmit counties and will be able to move over 500 MMcf/d of production to TEAK's Silver Oak gas processing plant in Bee County, Texas. TEAK will own this segment jointly with TexStar Midstream Services LLC. The smaller, 20-mile pipeline system will move rich gas from Karnes County to the new plant. That 20-inch-diameter pipeline will be owned by TEAK and will originate on acreage owned by Talisman and Statoil.

Newfield purchased Maverick County land on a hunch the same Eagle Ford type of formations that were thriving in the Gulf Coast basin would exist in the Maverick basin. Source: Newfield Exploration Co.

The Silver Oak plant near Pettus has been designed specifically to process the liquids-rich Eagle Ford gas, which will allow TEAK to maximize the amount of NGLs that are recovered from the gas streams of producers.

"We have taken technology that's been around for a long time and customized and designed a cryogenic processing plant exclusively for the gas quality that's being produced out of the Eagle Ford shale," says Chris Aulds, co-chief executive of TEAK. "You may drill a gas well in the Haynesville or Barnett or Eagle Ford shale and the component of each one of those gas streams will look different. We have designed a processing plant specifically for the quality specs of gas we're seeing in the Eagle Ford."

TEAK took the original design of the plant a step further by having its vice president of engineering and operations, Gary Conway, make a few minor adjustments during fabrication to improve the overall efficiencies even more. The plant will help TEAK see over a 90% ethane recovery when its plant is in full cryogenic processing mode.

The plant's ability to maximize the recovery of such liquids is especially pressing in today's economy, where dry gas can be worth significantly less than NGLs. More money can be made separating the liquids out at the cryogenic plant and selling them in a liquid form, as opposed to merely leaving them in the dry natural gas and selling it as such.

Coming out of the Silver Oak plant will be a dry-gas line that will be connected to several downstream intrastate and interstate pipelines. There will also be a NGL line that will deliver liquids to Mont Belvieu, Texas, fractionation facilities. TEAK is also in discussions with another NGL pipeline to possibly move a portion of the NGLs to other fractionators along the Gulf Coast from Corpus Christi to Houston.

"It's a fairly extensive gathering system in the heart of the Eagle Ford shale, gathering a lot of the rich natural gas that's being produced that needs to be processed," says Aulds.

TEAK initially entered the area through the acquisition of the Texana Pipeline Co. in July 2010. Texana had been operating in the area since 2007, when the Eagle Ford

wasn't yet in full swing. At that time, most producers were still drilling for conventional oil and gas formations, and the Eagle Ford had yet to prove itself as a shale play.

Initially, TEAK's exposure to the area was focused mostly on low-pressure gas gathering, and the company had less processing capabilities. After all, the gas that was being drilled in the area about five years ago was leaner and contained less NGLs. At the time, just 2.5 gallons per thousand cubic feet (Mcf) of NGLs were contained in the gas being processed. Today, Eagle Ford wells contain between five and six gallons per Mcf, with some wells sitting in the eight to nine gallons per Mcf range. It all goes to show that there are more gas liquids coming from the Eagle Ford shale than from other conventional plays.

"The rate of return oil and gas producers are seeing in the Eagle Ford shale are still some of the best in the country, compared to the other shale plays," says Aulds. "I do expect a lot of the oil and gas producers who are able to do so to focus on the Eagle Ford shale: That would be the premium shale play for them to focus their drilling efforts. The majority of producers would put the Eagle Ford at the top of the list."

Some reports show Eagle Ford shale wells to be generating more than a 60% rate of return, when oil is at $100/bbl., and natural gas is worth $3/Mcf. At $85/bbl. crude oil prices and $3/Mcf gas prices, the rate of return is better than 40%. And with $70/bbl. oil and $3/Mcf gas prices, producers are still seeing 20% rates of return.

"There are some shale plays in the U.S. that contain mostly dry natural gas. These plays are yielding 0% rates of return with natural gas prices as low as they are," says Aulds. "Rates of return are still very attractive for oil and gas companies to be drilling and developing the Eagle Ford shale compared to some of the other opportunities that may be out there in the U.S. that are not as profitable."

One factor slowing progress down in the play is the challenge of bringing in additional equipment. Previously, it would have taken about three to six months to receive pipeline or processing equipment. Today, it can take between 12 and 18 months.

"The timing to get equipment today is much slower than it was a couple of years ago," says Aulds. "The midstream and production companies are developing all the infrastructure needed. It's just not happening as fast as in the past since there's a big demand on equipment in all the energy plays in the country."

He doesn't expect to see a slowdown anytime soon. In fact, Aulds anticipates seeing just the opposite in the Eagle Ford. He expects upstream companies to continue pumping money into the play and for drilling to remain constant in the area.

"I sense that over the next three to five years, the Eagle Ford shale will continue to be one of the most prolific plays in the U.S.," he says. "I'm very bullish it will be a prominent and very active shale play in coming years.