Atlas Resource Partners LP (ARP) executives plan to put a herculean effort toward demonstrating the value of the exploration and production (E&P) assets as it prepares to spin off from its parent following a merger agreement with Targa Resources Corp.

Houston-based Targa Resources Corp. and its midstream pipeline partnership plan to acquire Atlas Energy LP (ATLS) and its midstream assets in a transaction valued at $7.7 billion (see Daily GPI, Oct. 13). The combined entity would serve the Permian and Williston basins, Midcontinent, East/South Texas, the Gulf Coast and the Gulf of Mexico.

The merger provides a “great map, great math and a great opportunity for employees and investors,” said Targa CEO Joe Bob Perkins, who led a conference call Monday to discuss the transaction. “This is a blockbuster deal based on a real structure that is highly appealing to Targa and Atlas constituents…”

Targa provides midstream services for natural gas, natural gas liquids (NGL), terminaling and crude oil gathering services for the U.S. onshore and the Gulf of Mexico. The ATLS midstream assets would add Midcontinent depth in the Woodford Shale and emerging South Central Oklahoma Oil Province, or SCOOP, as well as in the Mississippian Lime. The merger also would expand the combined company’s Eagle Ford and Barnett shale coverage in Texas and the Bakken Shale, the Permian Basin coverage in Texas and New Mexico, and on the Louisiana coast.

Under terms of the transaction, Targa would acquire subsidiary Atlas Pipeline Partners LP for $5.8 billion, including $1.8 billion of debt. ATLS is to spin off its non-midstream properties, and Targa would acquire it for $1.869 billion.

ARP was created by ATLS after predecessor Atlas Energy Inc. in 2011 sold its one-million-plus onshore acreage to Chevron Corp. (see Shale Daily, Feb. 17, 2011; Nov. 10, 2010). ATLS, reconfigured as a master limited partnership (MLP), formed the E&P as a MLP (see Daily GPI, Nov. 9, 2011).

In a separate conference call on Monday, ARP CEO Ed Cohen told analysts that spinning off the E&P assets parallels somewhat the Chevron sale. However, ARP’s assets today are undervalued and management has work to do to correct that perception ahead of the spinoff, he said.

“We’re in the process of directing all of our skill and effort to effecting transformative solutions to the present undervaluation of ATLS’s non-pipeline assets,” Cohen said.

He would not compare the value of the current portfolio of E&P leases to those sold to Chevron in 2011. It’s not about the past, but about the future, he told analysts. It wouldn’t be a fair comparison, he said. It’s a different time for unconventional plays. It’s no longer about acquiring leases but about developing oil and gas.

Warehouse of Leases

ARP has a warehouse of onshore leases in a long list of plays. Leases are spread across the Barnett Shale in Texas, Marcellus/Utica shales, the Raton Basin in New Mexico, Alabama’s Black Warrior Basin, the Mississippian Lime in Oklahoma, Colorado’s Niobrara formation, the Chattanooga Shale in northeastern Tennessee and the New Albany Shale in Indiana. Altogether, the independent owns an interest in more than 14,000 producing gas and oil wells, representing 1.5 Tcfe of net proved developed reserves.

At the end of 2013, ARP had stakes in around 620 wells in the Barnett and Marble Falls formation in Texas; 2,950 coalbed methane gas wells in the Raton and Black Warrior basins; and 8,170 wells in the Marcellus/Utica. The warehouse has been stocked through deals made since early 2012, particularly in the Barnett (see Shale Daily,Nov. 21, 2012;May 21, 2012).

Proved gas reserves were added last year in the Raton and Black Warrior basins (see Shale Daily,June 11, 2013). Earlier this year West Virginia gas assets were added, along with an oil-rich leasehold in the Rangely Field in Colorado. Last month ARP bought Eagle Ford Shale property (see Shale Daily,Sept. 24).

ARP generated record production of 261.3 MMcfe/d in 2Q2014, a 6% sequential increase and a near-100% increase in output year/year. Volumes included a 515 b/d (33%) increase in crude oil output from 1Q2014 and a 268 b/d increase (8%) in NGL volumes from 1Q2014.

Pro forma for the merger, Targa would have 38 gas processing plants with a combined 6.9 Bcf/d gross capacity; 17 gas treatment facilities; 573,000 b/d gross fractionation capacity; 22,500 miles-plus of gas/crude oil gathering pipelines; three crude oil/refined products terminals with combined 2.5 million bbl of storage; and a 6.5 million bbl/month capacity liquefied petroleum gas export terminal.

“It boils down to results,” Perkins said of the transaction. “The math is what to focus on right now…It doesn’t get much better from a win, win, win, win perspective…”

Even though the price deck outlook has been somewhat challenging for NGLs in the past few months, Targa’s executive team wasn’t put off by commodity prices. Spot prices for NGLs were considered “in and around the mid-$80s,” and it was determined it would be “good for Targa even at a sensitized price deck.” Added Perkins, “we certainly looked at it under the latest prices” and didn’t feel any pressure to end the discussions.

Last year, Targa produced 137,000 b/d of NGLs, while Atlas produced 115,000 b/d. This year Targa expects to produce 149,000 b/d of NGLs, while Atlas should produce 118,000 b/d, for a combined 268,000 b/d.

Second Largest Permian Processor

The Permian’s growth story underscores one of the merger’s primary draws, said Perkins. The Atlas WestTX system sits in the core of the Midland sub-basin, between Targa’s existing San Angelo Operating Unit and the Sand Hills systems, also in West Texas. More than 75% of the rigs now running in the Midland are in counties served by the combined systems. Pro forma, Targa would become the second largest Permian processor with 1.4 Bcf/d in gross processing capacity.

Targa and Atlas also have expansions recently placed into service in West Texas, with more expansions underway. Targa in June ramped up its 200 MMcf/d High Plains plant, while in September Atlas put its 200 MMcf/d Driver facility online (see Daily GPI, July 17, 2013). Within the Delaware sub-basin, Atlas has the 200 MMcf/d Buffalo plant expansion set to begin in mid-2015 (see Shale Daily, April 24). Targa’s 300 MMcf/d Delaware Basin plant is scheduled to ramp up in early 2016.

Last year, Targa’s field gathering and processing segment processed an average of 780.1 MMcf/d and produced an average of 91,900 b/d of NGLs. In addition to its gas gathering and processing, its Williston Basin Badlands operations include a crude oil gathering system and two terminals with operational storage capacity of 70,000 bbl.

Targa’s Coastal Gathering Segment last year processed an average of 1,330 MMcf/d and 45,000 b/d of NGLs. Targa also is majority owner (76.8%) of Venice Energy Services Co. LLC has aggregate processing capacity of 750 MMcf/d, and the Venice Gathering System has nominal capacity of 320 MMcf/d. Targa has organic growth capital spending plans of $1.2 billion for 2014 and more than $1.2 billion for 2015. The partnership now is anticipating 11-13% distribution growth in 2015.

Atlas affiliates own and operate 17 processing plants, 18 treating facilities and around 11,300 miles of active intrastate gathering pipeline mostly in Oklahoma, Texas, Kansas and Tennessee. In 2004, ARP began operating in the Midcontinent when it acquired the Velma Gas Processing Plant and its 2,000-mile gathering system from Spectrum Field Services. It currently operates four gas gathering and processing systems in the Midcontinent: the Velma system in Southern Oklahoma and North Texas, the Arkoma system in southeastern Oklahoma, the WestOK system in Northwest Oklahoma and Southern Kansas, and the WestTex system in West Texas.

Standard & Poor’s Ratings Services (S&P) said the merger would be a positive for Targa.

“In our view, the transaction complements Targa’s core competencies in the gathering and processing business, enhances its asset position in the Permian Basin, and expands its operating footprint to attractive regions such as the Anadarko Basin and Eagle Ford Shale,” said S&P credit analyst Nora Pickens. “Pro forma for the transaction, we expect fee-based arrangements to represent about 60% of the partnership’s operating margins and that Targa will continue to manage its commodity risk in a disciplined manner.”