It’s tough to keep pace with the astonishing happenings in the Eagle Ford. Blink and you might miss the billions of dollars trading hands in mergers, acquisitions and joint ventures.

And at such a breakneck speed, midstream players are rushing to keep up with the play’s everevolving demands through a series of build-outs and reconfigurations. There’s good reason for the near-hysterical level of Eagle Ford activity. As production at some other U.S. plays whittles, the Eagle Ford remains hotter than ever—and it shows no signs of slowing.

“While the Eagle Ford is a great play, there are a lot of hydrocarbons left to be found and developed,” Mike Howard, chief executive of Howard Midstream Energy Partners LLC, tells Midstream Business. “While the Eagle Ford is profitable and a great play right now, I think there’s a lot more to come in South Texas because it is a stacked hydrocarbon play.

Plenty of studies lend credence to the Eagle Ford’s economic strength. A PwC US study released in August showed the Eagle Ford helped drive merger and acquisition (M&A) activity for second-quarter 2013. The Eagle Ford was the period’s most active shale play for M&As with values greater than $50 million, having been home to three transactions totaling $1.5 billion. It was followed by the Bakken shale, with two deals totaling $910 million, and the Marcellus, which had three deals totaling $416 million.

According to a Wood Mackenzie Ltd. study, oil and gas companies will spend $28 billion in the Eagle Ford this year. That’s well above the $19 billion spent on capital expenditures in 2012, according to Center for Community and Business Research’s estimates. Meanwhile, Deloitte’s mid- 2013 Oil and Gas Mergers and Acquisitions report indicates the midstream spending is likely to remain strong in the Eagle Ford and elsewhere.

“Production is still oustripping infrastructure,” Deloitte & Touche LLP partner Jim Dillavou says in the report. “There are plenty of opportunities for investment, so this continues to be an area of high interest.”

Money maker

It’s no secret that the Eagle Ford shale is generating a significant amount of cash for South Texas. The play generated more than $61 billion in revenue for South Texas in 2012 and will continue to sustain the local economy into the foreseeable future, according to a recently released report. The Economic Impact of the Eagle Ford Shale study, released in March by the University of Texas at San Antonio (UTSA), says the Eagle Ford supported about 116,000 full-time jobs last year. It was a sizable leap from the estimated 50,000 jobs being supported in 2011.

“A lot of the projects that had been announced actually started bringing people on board to work there,” Dr. Thomas Tunstall, director of the UTSA’s Center for Business and Community Research and the study’s principal investigator, tells Midstream Business.

“For example, it was known that Halliburton was building a facility in San Antonio. In 2012, they actually started bringing people on board to work there. A lot of the pipeline companies had been hesitant to build infrastructure because they, like a lot of other entities, were initially somewhat skeptical. But during the last couple of years they’ve become convinced, so they’re building infrastructure.”

The study adds that oil and gas development in the Eagle Ford will generate $89 billion and 127,000 jobs for the region in 2022. Last year alone, the play added more than $1 billion in local government revenue and about $1.2 billion in estimated state revenue, the report says.

Researchers at the UTSA compiled the study after examining the Eagle Ford’s 14 oil- and natural gas-producing counties, as well as six surrounding counties.

The Eagle Ford is also partly responsible for a large chemical manufacturing build-out along the Gulf Coast. By Tunstall’s estimates, there are between $80- and $90-billion in planned, announced or under-way projects along the Gulf.

“A lot of them have been built and are going forward, and we continue to hear about new ones,” he says. “Because of the relatively low price of natural gas, it has become very attractive for manufacturing facilities to be located in the U.S.”

Making an entrance

The Eagle Ford is continuing to draw new players into the region as well. Atlas Pipeline Partners LP made its entrance into the play last April with its $1 billion acquisition of TEAK Midstream LLC. Atlas’s second-quarter 2013 report, released in early August, provided the first glimpse into how the company has fared since entering the play. Its adjusted EBITDA was $86.3 million for the second quarter. Its distributable cash flow was $58 million for the quarter, or 78¢ per average common limited-partner unit, compared with $32.8 million during last year’s second quarter.

TEAK, a gas gathering and processing company, started up in 2009 with a $100 million investment from Natural Gas Partners. Through TEAK, Atlas inherited an enviable assortment of midstream assets, which sit on a prime piece of real estate.

“We feel we’ve probably got the best assets in the Eagle Ford shale play,” Patrick McDonie, Atlas’ chief operating officer, tells Midstream Business. “We’re excited about the opportunity, we’re excited about the capabilities of our assets and where they lay, and we’re excited about how this acquisition further diversified our overall portfolio.”

The assets include 250 miles of gas gathering and residue delivery pipeline, two high-pressure gas gathering systems and a 200 million cubic feet (MMcf) per-day cryogenic processing plant.

The larger gathering system runs through Bee, Live Oak, McMullen, La Salle, Webb and Dimmit counties and can move more than 500 MMcf per day of production to the Silver Oak gas processing plant in Bee County, Texas. Meantime, the Silver Oak processing plant near Pettus has been designed specifically to process the liquids-rich Eagle Ford gas, which will allow Atlas to maximize the amount of natural gas liquids (NGLs) that are recovered from the gas streams of producers. Atlas has started construction on a second 200 MMcf per-day cryogenic processing facility, called the Silver Oak II plant, which will sit next to the original facility. It is expected to be operational by early 2014. The facilities should give Atlas a leading edge, says the company’s head of investor relations, Matthew Skelly.

“There is a lot of other processing capacity down in the Gulf, laying back into the area,” Skelly tells Midstream Business. “From a business development opportunity, having a newer cryogenic facility that’s located right where all the activity is, with the infrastructure already there, should give us a competitive advantage against others that have less efficient plants. If you’re going to produce and you’re offering market terms on a fixed-fee basis, you would think the excess recoveries our plant can do gives us quite an advantage over the legacy assets down there.”

Commodity uncertainties

The Eagle Ford’s growth is attributed, largely, to its productiveness. Though it still trails the Bakken, it’s quickly catching up. Right now, the Bakken produces about 700,000 bbl. per day, compared to the Eagle Ford’s approximately 584,000 bbl. per day. However, it’s expected that the Eagle Ford will reach 1 million bbl. per day. Of course, it also has the advantage of containing natural gas and NGLs as well as oil.

“If this were a pure gas play, which is how a lot of activity had initially begun, there wouldn’t be nearly as much activity,” says the UTSA’s Tunstall. “A lot of the natural gas plays like the Barnett and Haynesville have really slowed down because the price of natural gas has dropped so low. There may be some rebound in activity, but the real driver for activity in the Eagle Ford is the oil.”

So what happens if the price of oil plummets, as it did in the 1980s?

While there’s little doubting the Eagle Ford’s production possibilities (estimates indicate it could boast as much as 10 billion bbl. of recoverable oil), its financial future isn’t as certain.

“The question of whether the oil and gas is there and extractable has been asked and answered,” says Tunstall. “The other question is: What are commodity prices going to do?

“We’ve already seen a real cutback in production for natural gas and condensate because of commodity prices. I think we would see the same thing if oil prices dropped. Unfortunately, nobody can predict the commodity prices with certainty, so we’re going to have to watch that.”

The break-even point for Eagle Ford oil is between $50 and $70 per bbl., producers say, and although producers are currently profitably extracting oil from the play, this could change. Since demand drives the price of oil, Tunstall says he and his team are keeping a close watch on the big buyers, such as China and India. “If their economies slow down and they buy less oil, it could put a damper on price,” he adds.

While there’s nothing to indicate the Eagle Ford will become uneconomic sometime soon, that doesn’t mean it can’t happen. But of course, industry participants aren’t expecting a commodity price crash in the near term.

“We would expect a considerably high level of activity for the next three to five years,” says Atlas’s McDonie. “The only possible barrier to that is if crude oil and liquids prices fell very low. Obviously, all bets are off then. Barring something like that, we think this is where capital will be spent. It’s going to be the best economic play in the U.S., along with the Bakken.”

Big investments, big payoffs

By year’s end, Kinder Morgan Energy Partners LP’s Midstream Natural Gas Group and its Products Pipeline Group collectively will have spent almost $2 billion on the company’s Eagle Ford midstream infrastructure build-out. Acquisitions in the play are already paying off, at least if the company’s 2013 second-quarter earnings are any indication. Kinder Morgan’s five business segments produced approximately $1.34 billion in segment earnings for the latest quarter before certain earnings and depreciation, depletion and amortization, with approximately 42% of that amount coming from the company’s Natural Gas Pipelines segment.

Kinder Morgan Energy Partners reported net income of $1.01 billion, including certain items, up from $138 million versus the 2012 second quarter. Its net gains were attributed largely to asset dropdowns from Kinder Morgan Inc., stemming from the El Paso Corp. acquisition in May 2012 and from two months of contributions from the Copano Energy acquisition in May of this year.

Kinder Morgan Energy Partners reported secondquarter distributable cash flow of $505 million, up 38% year-over-year. Quarterly cash flow distribution rose to $1.22 per unit before certain items, compared to $1.07 per unit for second-quarter 2012.

The company’s extensive collection of treating, gathering and processing assets continues to grow at a ferocious speed.

“It wasn’t too many years ago when companies were at ground zero in this play,” Kinder Morgan’s Midstream President Duane Kokinda tells Midstream Business. “It has been a pretty incredible ride.”

Kinder Morgan’s Eagle Ford assets, as well as its bottom line, were bolstered with the $5 billion acquisition of Copano. Copano served gas producers in Texas, Oklahoma and Wyoming through gas treating, processing, gathering and fractionation facilities. It owned or operated almost 7,000 miles of pipelines and boasted 2.7 billion cubic feet (Bcf) per day of gas throughput capacity, with nine processing plants that had more than 1 Bcf per day of processing capacity and 315 MMcf per day of treating capacity.

The recent Copano acquisition helped strengthen the heart of Kinder Morgan’s Eagle Ford gathering and processing system. It provides the company 1 Bcf per day of cryogenic processing capacity at its Houston Central Plant in Colorado County, Texas, once the 400 MMcf per-day train currently under construction is completed mid next year, as well as another 200-plus MMcf per day of lean oil-processing capacity. It has a 44,000 bbl. perday fractionator, too.

“We have a lot of synergies with those Copano assets,” says Kokinda. “It made a lot of sense to us to be a buyer for that specific set of assets.”

This wasn’t the first time the companies joined forces. Kinder Morgan Energy Partners and Copano had initially formed a joint venture in May of 2010 to provide gathering, transportation and processing services to natural gas producers in the Eagle Ford shale. As part of its first phase, the joint venture constructed 111 miles of 30-inch and 24-inch natural gas gathering pipeline from Duval County, Texas, into McMullen, La Salle, Dimmit and Webb counties to gather and process up to 375,000 MMBtu per day. The joint venture subsequently added another 70-plus miles of 24-inch and 20-inch pipeline to access additional processing capacity to bring its total capability to slightly more than 700,000 MMbtu per day.

On the crude side, the 300,000 bbl. per-day Kinder Morgan Crude Condensate (KMCC) pipeline transports Eagle Ford production to the Houston Ship Channel, where Kinder Morgan is building 100,000 bbl. per day of splitter capacity. And with its Copano acquisition, Kinder Morgan also acquired a 50% interest in the Double Eagle Pipeline, an Eagle Ford gathering system that delivers condensate to the Valero Three Rivers Texas refinery and the Corpus Christi Ship Channel market.

Right now, the play’s crude window is where the action’s happening, says Kokinda.

“What we see is that producers are now focused on the oily sections of the play,” he says. “I think that bodes well for more crude and condensate gathering and takeaway and handling facilities, certainly in the next few years.”

Reconfigurations

With producers focusing their attention on crude and condensate, numerous midstream companies are reconfiguring pipelines to accommodate the growing demand. Kinder Morgan’s KMCC line is comprised of 113 miles of converted gas pipeline and 65 miles of new-build construction. The $215-million pipeline went into service June 2012. Kokinda says the economics justified converting that line from gas to crude.

“The pipe that we contributed to the KMCC project— we gave it a 30-inch natural gas pipeline—when full can move about 500 MMcf of gas,” says Kokinda. “If you put a 10¢ margin on that business, that pipe could make $50,000 per day in natural gas. But if you move crude oil through that pipe, like we are now, moving 50,000 bbl. per day at a $1 tariff would make the same amount of money as that pipe would if it were full of natural gas. But that pipe can move 300,000 bbl. per day, not just 50,000 per day, so that’s a multiple of six. Plus the tariff on that pipe isn’t a dollar—it is closer to $2. So that’s a multiple of 12. So, if you can find a liquids application, and highly utilize a pipe versus natural gas, those are opportunities you will try to take advantage of.”

But, of course, commodity prices change, and companies do sometimes find themselves converting pipelines, only to convert them back to their original function.

“That might have happened over long periods of time,” says Kokinda. “We bought a crude oil line that runs from the Permian basin to Katy when it was almost empty, converted it to natural gas and more recently we have looked at converting that one back to crude oil,” he says.

Hello, Mexico

The Eagle Ford, like many other shales, has too little local demand and too much supply for its gas. Fortunately, there’s high demand close by. With its strong thirst for gas, Mexico is becoming an obvious market point for Eagle Ford production. The U.S. exported nearly 1.7 Bcf per day to Mexico in 2012, a 24% increase above 2011 figures, according to the U.S. Energy Information Administration (EIA). Gas flowing in from U.S. pipelines accounted for nearly 80% of Mexico’s overall gas imports of 2.1 Bcf per day last year, the EIA said. The bulk of gas came under the Rio Grande from Texas, which supplied about 75% of U.S. gas exports to Mexico. It shipped 1.3 Bcf per day south last year, a 34% increase from 2009’s pipeline shipments from Texas to Mexico.

“Most of the U.S. exports to Mexico departed the country from Hidalgo County in southwest Texas, where the supplies were likely coming from the Eagle Ford play,” says a March 2013 EIA report. “Several U.S. pipeline-export projects that could support additional natural gas exports to Mexico have been announced. According to company announcements, these projects are expected to be completed by the end of 2014 and, if they are all built, could add up to 3.5 Bcf per day of additional export capacity to Mexico, doubling existing capacity.”

Take, for instance, NET Midstream’s NET Mexico Pipeline LP, which is building a 124-mile natural gas pipeline from the Eagle Ford to the Texas-Mexico border. The line will transport gas from the Agua Dulce hub to the Rio Grande City, Texas, area in Starr County.

The 42-inch diameter pipeline will be anchored by a long-term, firm gas transportation agreement with MGI Supply Ltd., a subsidiary of the Mexican stateowned gas company Pemex Gas y Petroquimica Basica. The line is expected to go into service in December 2014.

“NET Mexico Pipeline will be an important source of supply to meet Mexico’s growing demand for natural gas,” Joe Gutierrez, NET’s co-president, said in a public statement. “NET Mexico is a natural next step in our pipeline system, as we connect abundant gas supply from the Eagle Ford Shale to expanding power generation and industrial markets in Mexico.”

Kinder Morgan pipes collectively transported about 80% of the gas delivered into Mexico last year, with its Texas intrastate assets accounting for about 40% of Kinder Morgan’s volumes and its interstate pipelines accounting for the rest. The Midstream Group is continuing to build on its capacity, having recently received approval to increase the volume of its border crossing into its Mier-Monterrey Pipeline. Permitted capacity on the 100-mile pipe, which delivers gas to Pemex and end users in Monterrey, Mexico, increased from 425,000 MMBtu per day to 700,000 MMBtu per day. “We have sold most of that incremental capacity and are embarking on expansion projects to bring it on line over the next two years,” says Kokinda.

Hub resurgence

As increasing volumes of Eagle Ford gas move south, Agua Dulce is becoming a popular spot for pipelines to cross through. Though the hub has existed since the first days of South Texas drilling, it is enjoying a rebirth thanks, largely, to Mexican gas demand.

Mike Howard, Howard Midstream Energy Partners LLC's chief executive, grew up in Agua Dulce and says the region was traditionally an aggregation point for product heading to places such as Chicago, the Northeast or the Houston Ship Channel. Now, he says, its resurgence in popularity is causing a disconnect between Houston Ship Channel pricing and South Texas pricing.

“Today there are multiple interstate and intrastate lines that cross through the region,” he says. “It is just a natural point where a lot of pipelines aggregate volumes. Agua Dulce is an ideal place to access gas if there is a large demand, such as from Mexico, where demand is growing.

“Whenever you have a large demand out of a hub like that, it is going to naturally disconnect from the next closest points, which are currently Katy and the Houston Ship Channel,” he adds.

Kinder Morgan’s Kokinda says “demand pull” from the Mexican market will be a strong influence on the Agua Dulce hub. However, he doesn’t feel Eagle Ford production alone will have much of an effect on the hub.

“If you look at where the new processing plants are being built in the Eagle Ford, they’re not Agua Dulce or south. They’re actually north,” he says. “I think that is more of a Katy hub impact than an Agua Dulce impact. But when the Frontera header project gets built, and there is a new 2 Bcf per-day capacity pipeline headed to the border, that will certainly increase the liquidity at the head of that pipe at the Agua Dulce area.”

Building is better?

Howard Midstream delivers lean gas into Mexico, as well as the domestic market, with its extensive gathering, processing and pipeline system. It operates more than 500 miles of pipeline in the play. As well, the company is undergoing numerous expansions in the region. This includes its new Reveille cryogenic plant and associated pipelines in Webb County, Texas, which will tie into Howard Energy’s Cuervo Creek gas gathering pipeline system. The Reveille facility is expected to start-up this coming January.

Howard Energy is also constructing an import and export logistics rail hub for various cargo including oil, condensate and natural gas liquids (NGLs). The Live Oak County, Texas, hub will access the Union Pacific Railroad and a variety of area oil and condensate pipelines. The cost of both projects—which will serve producers in the Olmos, Escondido and Eagle Ford plays—is about $100 million.

As well, the company is constructing a 10,000 bbl. per-day off-spec liquids stabilizer in Live Oak County and is planning some expansions—including bulk liquid storage —in the Port of Brownsville, Texas. Howard Energy’s new stabilizer will help the company focus on light condensates.

“The purpose of the facility is to treat high-vapor pressure condensates and find a market for them. Right now in South Texas, it’s very difficult to find a place to take a highvapor pressure condensate,” says Howard. “You have to truck it really far to find a home. That’s a problem we’re focused on and looking to fix.” Since its 2011 formation, Howard Energy has more than tripled in size. A large chunk of the company’s assets came in March 2012 when the company acquired 185 miles of south Texas pipeline from Meritage Midstream Services. In 2011, Howard Energy acquired Texas Pipeline LLC and construction company Bottom Line Services. Mike Howard says he prefers growing the company organically.

“We’re the classic model of building is better. With the Eagle Ford being viewed as one of the top—if not the top—shale plays, the acquisition multiples are relatively high, and there is quite a bit of money looking to be placed in the market. We can build organic projects on much lower multiples rather than going out and trying to finance an acquisition,” he says.

Overcoming challenges

But as build-out intensifies, challenges are emerging. More infrastructure is needed to get product to market, for example. As well, labor shortages continue to dog midstream companies eager to build out additional infrastructure.

Meanwhile, residents of Eagle Ford’s counties are facing infrastructure issues related to water, waste water and, in some cases, schools, says Tunstall. He says there is also a shortage of housing in the region, which has led to a lot of hotels, man camps and RV camps being used to house workers. Of course, this drives up temporary housing rates. It’s not uncommon to shell out hundreds of dollars a night for a basic hotel, though Tunstall says the issue is being addressed.

As the UTSA continues its studies of the Eagle Ford, Tunstall can’t help but think of the more than 250 ghost towns in Texas. Many were once booming resource towns. Tunstall hopes the same fate does not befall the Eagle Ford’s numerous communities.

“We’re working with them in a variety of ways to ensure these communities benefit in the long term,” he says. “I don’t know if you’re familiar with the resource curse, but that’s one of the things they’re trying to make sure doesn’t happen.”

Mexico Mulls Pemex Changes—Again

By Paul Hart, Editor

It's a perennial in Mexican politics: Every six years around a presidential election, there are promises that troubled, state-owned Petróleos Mexicanos, or Pemex, will be reformed. Then little changes and little is said until the next election cycle. So it has been for 75 years.

But this time, perhaps, President Enrique Peña Nieto really means it. Since assuming office in December 2012, Peña Nieto has made Pemex reforms a priority. It’s easy to see why. Bloomberg estimates the state-owned energy company provides one-third of the federal government’s income. It clearly is the largest enterprise in Mexico’s economy—and it has serious financial and operational issues.

The new Pemex reform talk has been greeted with skepticism in the energy industry. Tudor Pickering Holt & Co. observed in a recent report, “Same song, second verse?”

Mexico’s production and reserves continue to fall sharply despite billions invested in unsuccessful exploration and development. Pemex doesn’t have the in-house technology to successfully drill and produce prospective unconventional shales and deepwater Gulf of Mexico plays. But Mexican law blocks it from working freely with foreign partners who do have that technology—and the capital to finance new projects without straining the Mexico City treasury.

Estimates show Mexico has declined to the world’s 10th-largest oil producer with output dropping by one-quarter in the last decade. Its supergiant Cantarell field in the Gulf of Mexico, discovered by accident after a fisherman complained about oil seeps, continues to decline despite an ambitious nitrogen-injection program.

Earlier proposals to create broader development plans to lure foreign interests under existing law have brought yawns from the world’s energy business. In July, an auction of geologically promising tracts drew what Nasdaq OMX reported was a “dismal response” from potential partners. The Wall Street Journal observed in a recent article that even Cuba has a more open policy toward private energy investment.

Mexico’s decline in natural gas production has been particularly steep as Pemex focuses on propping up more-lucrative oil output. The U.S. exported 1.7 billion cubic feet (Bcf) per day of gas under the border at the end of 2012, much of it from the booming Eagle Ford play in Texas—even though northern Mexico’s geology is highly prospective for gas. Some industry estimates say Mexico may be importing 5 Bcf per day from the north within a few years as its economy grows and Pemex gas production dwindles further.

The Mexican congress will consider Peña Nieto’s proposal this month. The plan would allow Pemex to work with foreign, privately owned companies in a manner similar to that of many other national oil companies. But getting his plan through the senate and chamber of deputies will be a huge challenge as it literally requires a constitutional amendment to change the law governing Pemex. Peña Nieto’s plan includes new taxes to wean the federal government off Pemex revenues over time.

Midstream opening

The dominant opposition party to Peña Nieto’s socialist Partido Revolucionario Institucional has been supportive and that could give the president the two-thirds majority he needs in congress. Also, the conservative Partido Acción Nacional, has introduced a bill in the senate that would open the midstream and downstream sectors of the energy industry—as well as the electric power monopoly. A new National Hydrocarbon Commission would grant oil and gas concessions.

Change means a huge political fight. Every Mexican school student learns how then-President Lázaro Cárdenas del Rio expropriated the assets of foreign oil companies in March 1938 and turned everything over to the state enterprise that became Pemex. Nationalistic fervor continues for the company and opponents of Peña Nieto’s program used terms such as “treason” and “traitor” freely at recent street rallies.

Midstream operators and service firms do some work for Pemex now under contract, as well as the power utility, Comisión Federal de Electridad. TransCanada Corp. has done several projects and currently has additional projects in planning or construction. Two of the larger projects involving TransCanada are the Tamazunchale Pipeline, an 81-mile gas pipeline in east-central Mexico and the Guadalajara Pipeline, a 193-mile system linking a liquefied natural gas terminal under construction outside Manzanillo on Mexico’s Pacific Coast to Guadalajara, Mexico’s second-largest city.

Comments