Building Up In The Delaware Basin

MIDLAND, Texas—As the pace of drilling continues to gather speed in the Delaware Basin, attendees of the recent Midstream Texas conference hosted by Hart Energy heard three private equity-backed midstream players discuss their plans to expand capacity and work around potential bottlenecks.

Brazos Midstream was formed in March of 2015 with backing from Old Ironsides Energy LLC, based in Boston. The company serves customers in the southern Delaware Basin mainly around the intersection of Ward, Reeves and Pecos counties. Although it also operates crude gathering assets, “a lot of what we focus on today is on the gas side of the equation,” according to CEO Brad Iles.

Brazos has a 60 million cubic feet per day (MMcf/d) plant currently in operation and is constructing a 200 Mmcf/d plant that is scheduled to be operational in first-quarter 2018. A second 200 MMcf/d plant is expected to come online in first-quarter 2019, based on customer development plans.

Iles pointed to an “unprecedented acquisition spree” that has taken place over the last 12 to 18 months in the basin. During this time there has been some $25 billion in upstream A&D, with about $15 billion taking place on the Texas side of the basin, he said, as well as roughly $7 billion of midstream deals, of which about $5 billion were in Texas.

Iles attributed the “feeding frenzy” occurring in the Delaware Basin—where producers and midstream companies alike are looking to establish a presence—to the basin’s remarkably strong economics even at its “very early stages” of development along with the “sheer size” of the basin’s areal extent.

Looking at just five key counties—Culberson, Loving, Pecos, Reeves and Ward—Iles noted that the area was currently running north of 100 horizontal rigs, back to its level prior to the late-2014-early-2015 oil price collapse. This augured a surge in development capital, which he estimated at a rate of about $9 billion per year, based on 110 rigs and drilling and completion capex of $7 million per rig per month.

Coupled with continued drilling efficiency gains, this should lead to “exponential volume growth going forward,” Iles predicted. “But we all know that those drilling efficiencies don’t stop. The acreage is now in the hands of well-capitalized operators that will apply their expertise in what they do. We would expect that one rig tomorrow does not equal one rig today.”

Looking at the gas side of the Permian basin, the question is then: “Where does all the gas go?”

Iles said current nameplate capacity to take residue gas out of the Permian Basin is around 12 billion cubic feet per day (Bcf/d), but in practice “operational takeaway” out of the basin is limited to about 9 Bcf/d. This compares to about 6 Bcf/d of current production, “so there appears to be sufficient takeaway for current demand.”

Moreover, with a number of projects announced to take gas from Waha to the Gulf Coast, the residue gas takeaway is expected to grow to 14 Bcf/d by year-end 2019. With gas production estimated to grow to 9 Bcf/d, this means “at least over the long term there should be sufficient takeaway capacity.”

A period of potential concern, however, relates to the next 18 to 24 months, with a focus on which of the alternative takeaway routes represent the most economic way out of the basin, said Iles. These would normally be to the Houston Ship Channel and the Gulf Coast, he noted.

“From about now to the next 18 to 24 months, while there’s sufficient takeaway capacity, it’s not necessarily to the optimal markets,” Iles said. “You’re really relying on the northern corridor to get out of the basin as well as the western corridor, and that presents its challenges. In the northern corridor, you’re competing with Midcontinent gas, you’re competing with Marcellus gas. To the west, you’re competing with a declining demand in California due to some of the regulations they’ve put in place.”

In terms of its effect on pricing, this has resulted in Waha differentials continuing to trade down to around 40 cents off Henry Hub, according to the Brazos CEO. And with projects to add capacity to the Gulf Coast needing 45 cents to 50 cents to make the economics work, “it will be interesting to see how Waha trades in light of that. There may be some further weakening there.”

“In our opinion,” said Iles, “it’s not necessarily as much a question of operational takeaway as it is what the netback price is and how does that impact producers in the Delaware Basin in particular.”

Brazos, located in the eastern oil window of the Delaware, where oil cuts are 60% to 80%, expects to be largely immune to movements in gas prices at the Waha hub, according to Iles.

“We don’t necessarily get the benefit of the higher IP gas wells that you see in the west,” he observed. “But as we look out to future development, we’re excited to see that producers’ drill plans in the oil window are really indifferent to what level gas prices are. It’s really an oil-driven part of the basin; they’re indifferent as to how Waha trades going forward.”

‘Do It Ourselves’

For Matador Resources Corp., much has changed in the Delaware basin since it sought a joint venture partner in the midstream space in 2014, according to Matt Spicer, vice president and general manager, midstream. Spicer joined the firm with the task of evaluating a joint venture, and he reached out to a dozen or more midstream player with zero success.

“We could not give away a JV in 2014,” recalled Spicer. “So our only choice was to do it ourselves.”

As a result, Matador built its Loving County plant and gathering systems in 2015 and, later that year, divested itself of the assets in a $143 million transaction with EnLink Midstream Partners LP.

Matador subsequently moved up into the northern Delaware basin, where it built its Rustler Breaks plant and gathering systems, and “decided that a monetization event was prudent,” said Spicer.

Recalling Matador received “a lot of offers on our plant,” Spicer cited several factors. One was that the Wolfcamp B oil wells in the area were “phenomenal” producers, but also “happened to produce 8 to 10 MMcf/d initial production on gas. And when that gas is rich, that’s a good place to have a plant.”

Matador’s private equity joint venture partner is now Five Point Capital Partners. It holds a 49% equity interest in the joint venture, formed in February of this year as San Mateo Midstream, allowing Matador to maintain operational control. Matador contributed its midstream assets in the Delaware basin plus a capital commitment of $76.5 million, while Five Points contributed $171.5 million plus a capital commitment of $73.5 million.

Plans for the San Mateo Midstream JV include expanding the Rustler Breaks cryogenic natural gas processing plant to an inlet capacity of up to 260 mmcf/d by as early as first-quarter 2018. Projected capex for 2017 for the JV is $110 million to $125 million, with Matador’s 51% share of the capex being $56 million to $64 million.

‘Every Bit As Good’

Sendero Midstream was formed in 2014 with backing from private equity sponsor, Energy Capital Partners. The firm has equity commitments of $1.5 to $2.0 billion and aims to develop a critical mass of midstream assets and “become IPO-ready in two to three years,” according to CEO Clay Bretches.

Sendero is currently developing gas-related assets in the northern Delaware, but also has interest in oil and water projects so that is has “multi-commodity, multi-basin” diversification, said Bretches. Around its plant there is growing activity in Wolfcamp, Bone Spring and Avalon objectives, especially on private land on the Texas side of the border, but gradually growing on government acreage in New Mexico.

According to Sendero’s geologic team, the region’s rock is “every bit as good as what you see down in Culberson, Reeves and Loving count.” And with a mix of large and small producers, the region offers “an opportunity to weave together midstream services for various players, whether they have contiguous acreage or whether they’re disconnected,” he said. “There are a lot of unconsolidated positions.”

Sendero’s assets are mainly in Eddy County and are due to be operational in October. Assets include a 130 MMcf/d cryogenic facility, a 100-mile gathering system and a 30-mile NGL pipeline. The gathering assets and pipelines are all on private or state lands. Construction is “on time and on budget,” said Bretches, adding that the site is large enough to build two additional 200 MMcf/d plants.

Chris Sheehan can be reached at csheehan@hartenergy.com.