A version of this story appears in the November issue of Oil and Gas Investor magazine.

The horizontal San Andres play on the Central Basin Platform in West Texas is generally categorized as two plays. If you draw an east-west line to divide Gaines County, Texas, in half, operators drilling to the north of the line focus on the lower San Andres and to the south, on the upper San Andres. There is considerable geographic distance between each play, as it’s approximately 140 miles from northern Cochran County to southern Ector County.

The geologic setting and depositional environment of the San Andres in each play is vastly different, and what’s more, the completion methods and the production profile of each play are different.

With improved well results in established areas and year-over-year higher crude oil prices, activity is increasing. Operators have driven the permitted, drilling or producing well count in the horizontal San Andres to 808 wells as of June 30, 2018.

The number of operators involved now stands at 63. Private entrants abound, as expected. Capstone Natural Resources II, Mack Energy Corp., Verdugo-Pablo Energy, Fortuna Resources, Mammoth Exploration LLC, Paladin Petroleum and Energy Hunter Resources have now posted wells that were permitted, drilling or producing, but were not on the list last year. Windy Cove showed stepped up activity with a well count of 13 this year vs. only one a year ago.

Although relatively new, Capstone shares a bloodline with Ring Energy Inc., as chairman and co-founder Phil Terry once worked for Tim Rochford, co-founder and chairman of Ring, while both were at Arena Resources Inc. (also co-founded by Rochford).

Smaller publics in the play include Ring Energy and Yuma Energy Inc. However, Hunter Oil recently exited, having closed the sale of its operating subsidiary, Ridgeway Arizona, to Pacific Energy Development Corp., a wholly owned subsidiary of PEDEVCO Corp. (also public), for $21.3 million. We are awaiting news from Yuma Energy, which has initiated strategic alternatives to remedy its limited liquidity and financial covenant issues.

Larger public E&Ps such as Apache Corp., Concho Resources Inc., Devon Energy Corp., EOG Resources Inc., Energen Corp., Occidental Petroleum Corp. and SandRidge Energy Inc. have acreage and production in the play, but we found no evidence of recent activity or plans for future activity. The same is true for privately owned CrownQuest Operating LLC, based in Midland, Texas. (At press time, Energen agreed to be acquired by Diamondback Energy Inc.)

As we did for our 2017 report on this play, we again collaborated with Ted Mowers, an independent consulting geologist with his own firm, TMG Consulting, based in Midland. He has an extensive background in the San Andres.

Results north to south

Mowers undertook a detailed analysis of wells completed in the northern and southern portions of the San Andres, centered on the average daily rate in the peak month of production. He chose this metric for its consistency and objectivity, because there can be wide variation between the peak rates companies often cite, i.e. 24-hour rate, IP-30, etc. He created a database of average daily rate in the peak month of production of the wells in the northern play (237 wells) and in the southern area (291), totaling 528 wells (vs. 297 wells studied in 2017).

Mower’s data indicates the northern wells had a mean of 265 barrels of oil equivalent per day (boe/d) average rate in the peak month, just underneath the 269 boe/d average rate in the peak month seen in last year’s report.

In the southern portion of the play, wells had a mean of 280 boe/d average daily rate in the peak month, just slightly higher than the 277 boe/d average daily rate in the peak month from last year’s report.

What do these flat results indicate? Some of the wells were so-called science wells, drilled primarily to gather geoscience data rather than pursue a commercial completion, but we don’t believe wells in this category are numerous enough to weigh on the data significantly. Some wells were drilled to satisfy lease obligations, but again, we think this category was relatively small.

A large number of below-average wells were completed here during the last 12 months, in part given the large number of new entrants to the play. Because we wanted more confirmation of this thesis, we sorted the data for the 20 wells in the northern play and southern play, in each period ending June 30, 2017, and June 30, 2018, ranked by boe/d average daily rate in the peak month, with the results shown in the accompanying chart.

Note the considerable overlap of the operators of the top performing wells in each year and also note the increases in the mean and median of the boe/d average daily rate in the peak month. In our opinion, this means the more experienced operators improved their efforts in terms of selecting the right locations, drilling techniques, frack designs and execution.

Reservoir subtleties

We learned in many of our conversations with active operators that the better year-over-year well results are also likely due to the nature of the San Andres reservoir itself. Many refer to the play as a “de-watering” play, because after certain volumes of water are produced the oil production commences or increases.

Still others call the play a “de-pressuring” play, because removing the water stimulates the oil production by reducing the reservoir pressure below the bubblepoint, or the level where the natural gas dissolved in the oil escapes from the oil solution and expands, thus driving the oil production higher.

“Continued entrance, and subsequent exit, of new operators to this horizontal play is, in my opinion, primarily by operators who approach the San Andres as if it is a blanket deposit and don’t sufficiently research the subtleties of the reservoir,” Mowers said.

“The differences in geology between the north and south are dramatic. Many new operators seem to approach the play with a drilling and completion plan of: 1) land the lateral somewhere in the San Andres and 2) stimulate it with a large, ‘shale-type’ hydraulic fracture. This usually results in high-volume water wells with very little oil.”

Single-well economics vary widely based on a well’s lateral length and its location within the northern or southern part of the play.

  • In the southern play, a 1-mile lateral can yield an internal rate of return (IRR) of 114%; and a 1.5 mile lateral yields an IRR of 206%;
  • In the northern play, a 1-mile lateral yields an IRR of 131%.
  • In the southern play a 1-mile lateral using the mean of 280 boe/d average daily rate in the peak month, from Mowers’ statistical analysis, yields an IRR of 49%.

At $40 per barrel (bbl), the IRR is 14%, which we believe many in the industry would regard as breakeven. Many companies use an IRR in a range of 10% to 20% as a breakeven point. We note these are economics at the well level, not corporate; thus they are not burdened by general and administrative expenses.

Frack design changes

In conversations, we’ve learned operators are trying a much more diverse set of frack designs today compared to 2017. They are experimenting with numerous variations, including smaller or larger proppant amounts, pumping proppant at lower rates, increased volume of gels, increased strength of gels and employing single entry-point fracks. Each of these choices is driven by the variability of the reservoir and the goal of more appropriately containing the frack.

Another change surfacing during the past 12 months, according to Matt D. Gentry, president and CEO of Monadnock Resources LLC, is the use of single entry-point fracks, where a much-reduced number of perforations per stage, often just one, are used to deliver the frack.

Gentry pointed us to a service company that has seen fairly widespread acceptance of its specialized tool for single entry-point fracks, NCS Multistage. One of the main reasons for using the NCS Multistage tool is to avoid downward frack growth into higher water-saturated rock.

In a conference call, Ryan Hummer, CFO, and Brenton Cheeseman, business development manager, of NCS Multistage said NCS developed its Multistage Unlimited technology as a more efficient and more economical alternative to plug-and-perf and ball-sleeve frack systems, both of which pump fluids down the casing with no feedback about formation response at the frack zone, no recourse in the event of a screenout, and no way to manage water and chemical consumption.

A screenout occurs when the solids carried in a treatment fluid, such as proppant in a fracture fluid, create a bridge across the perforations or similar restricted flow area. This creates a sudden and significant restriction to fluid flow that causes a rapid rise in pump pressure.

Operators also told us that because this does not employ a plug-and-perf or ball-sleeve frack system, there are large savings in dollars and time. There is nothing to run in the well between frack stages, nothing left in the wellbore and nothing to drill out; just a full, open production-ready wellbore.

Hummer and Cheeseman said their tool uses coiled tubing, working string that provides a circulation path to the frack zone, and they have executed more than 168,000 frack stages. With the ability to circulate or reverse circulate during completions, this system offers more operating control, as acid and other leading-edge fluids can be circulated down to the isolated zone before frack pressure is applied, with returns back up the coiled tubing.

Private company snapshots

It is apparent that private equity firms will play a large role in any such consolidation effort. Most of the major private-equity providers are involved in the San Andres already. We have identified Alliance Bernstein, ArcLight Capital Partners, EnCap Investments, Energy Trust Partners, Kayne Anderson Capital Advisors, Lime Rock Partners, Natural Gas Partners, Och-Ziff Capital Management, Quantum Energy Partners, TPH Partners, Warburg Pincus and Yorktown Partners.

Comparing this list to the 63 operators and 808 wells that are permitted, drilling or producing, it appears private-equity firms have an influence on about one-third of the total operators and 60% of the well count

Here are snapshots of some of the private E&Ps in the play; they could represent potential consolidation candidates:

Lime Rock Resources

Lime Rock is active in the upper Hz San Andres, southern play area, and distinguishes itself by being the third-largest operator, with 95 wells as of June 30, 2018. Further, it operates eight of the 20 best wells as ranked by highest average peak month production rate in the southern play area.

Its 2017 acquisition of the Shafter Lake, oil-weighted assets from seller Forge Energy signaled Lime Rock’s entry into the horizontal San Andres play.

Pacesetter Energy

Pacesetter holds the record for the two most prolific wells in the play. In fourth-quarter 2016, it completed these wells, ranked by highest average peak month production rate. These are in Shafter Lake Field in Andrews County, about 8 to 10 miles south of Ring Energy’s activity.

The company’s University JV 14 #8H recorded an IP of 1,345 bbl/d, 109,000 cubic feet per day (cf/d) of gas and 3,106 bbl/d of water, or 1,363 boe/d (therefore, 859 boe/d for the 90-day average). It was drilled with an 8,069-foot lateral and completed with a 5.1-million pound frack job.

The University JV 14 #3H IPed for 1,239 bbl/d, 211,000 cf/d of gas and 5,271 bbl/d of water, or 1,274 boe/d (607 boe/d on the 90-day average). This well was drilled with a 10,720-foot lateral and completed with a 6.7-million pound frack job.

Oakspring Energy

Oakspring was founded by Bryant H. Patton, principal, and Jeff Miller, president, and is backed by private-equity provider Yorktown Partners LLC. Miller was most recently vice president of geoscience technology at Chesapeake Energy Corp.

Oakspring has approximately 16,000 net acres focused in western Gaines County, Texas, and eastern Lea County, N.M. It’s a nonoperator that has participated in five horizontal San Andres wells to date, including three in another area of the San Andres in Winkler County, Texas.

Fortuna Resources Development

Aaron Davis is co-founder and CEO of Fortuna. Prior to that, he was a reservoir management team leader at Occidental Petroleum in charge of the Delaware Basin and Central Basin Platform. Polidoros Trejos is also a co-founder and is the CFO. He was a vice president of finance at Sanchez Energy Corp.

This relative newcomer to the play is getting off to a good start, with about 18,000 net acres in southwest Gaines County, west of the Ring Energy acreage position. Fortuna recently completed the Challenger well, a 1-mile lateral with an IP-24 of 399 boe/d. This company is backed by private-equity firm Och-Ziff Capital Management.

Steward Energy II

In August 2012, Steward Energy LLC (Steward I) partnered with Natural Gas Partners to build a 10,000-acre position in the southern Delaware Basin targeting the Wolfbone play. Steward I marketed and sold its position in late 2014 prior to the oil price collapse.

Following the successful exit, founder Lance Taylor and an enhanced team formed Steward Energy II LLC, backed again by Natural Gas Partners. They have targeted drilling horizontals in the lower San Andres, primarily in Yoakum County, Texas, and eastern Lea County, N.M.

In November 2016, Manzano Energy II sold its San Andres holdings in Yoakum County to Steward Energy II for $225 million. The acquisition of this prospect, known as Bronco, was pivotal for Steward, which has since expanded its position to more than 23,000 net acres which it operates with a working interest of more than 88%, and it is delivering strong results on the play.

Based on data we have seen, Steward Energy II has likely encountered more success in the northern portion of the play than any other company. It operates 15 of the top 20 wells as of June 30, 2018, ranked by the highest average peak month production rate.

Founder Taylor informed us that recent completion techniques, in certain areas, have involved “increased crosslinked gel volumes with higher gel loading designed to more efficiently treat only the rock we wish to stimulate” together with “less proppant pumped at lower rates.” Steward is also testing “slightly choked-back flow rates in the initial months of production” to flatten decline rates.

Riley Exploration-Riley Permian

Riley is a privately owned E&P company that traces its roots back to 2004. Bobby Riley, the co-founder and CEO, is a third-generation oilman with nearly 40 years of experience in the independent sector. Bobby is currently the CEO of Riley Exploration Permian LLC and was co-founder and served as CEO and chairman of Riley Exploration Group Inc. from 2007 to 2012. Kevin Riley is the co-founder and COO of Riley Exploration Permian. While at Riley Exploration, he led the successful acquisition and development of 100,000-plus acres across three active areas, the Permian, Eagle Ford and Arkoma-Woodford Shale.

Riley is the fifth-largest operator in the overall play, ranked by wells permitted, drilling or producing as of June 30, 2018, with 51. Based on the public data we have seen, Riley has enjoyed successful results in the northern portion of the play.

It operates three of the top 20 wells as of June 30, 2018, ranked by the highest average peak month production rate. Riley encountered early success, with its Beaten Path 597-648 1XH well in Platang Field in Yoakum County. First production was December 2015, and the highest average peak month production rate was 508 boe/d.

Other success stories include its Desperado 538 4H well in Platang Field. First production was in May 2017, and the highest average peak month production rate was 645 boe/d.

As mentioned, Riley operates three of the top 20 wells as of June 30, 2018, ranked by the highest average peak month production rate. This ranking is, in our view, not reflective of Riley’s total production as it participates as a nonoperator in a large number of the big Steward Energy and Wishbone Energy wells.

Riley believes in combining core analysis with advanced openhole logs to reduce risk and improve well location selection.

On May 17, 2018, Riley announced an agreement with Rockcliff Energy LLC (also private) to acquire 36,300 net acres and 140-boe/d production for about $20 million. Even giving zero value to the production, this is approximately $550 per net acre, an attractive value.

Wishbone Energy Partners

Craig Clark is a founder, CEO and director of Wishbone, the sixth-largest operator in the overall play, ranked by wells permitted, drilling or producing as of June 30, 2018, with 49. Wishbone owns about 40,000 net acres in the play. Clark told us wells in the play have improved over the last 12 months due to better drilling and completion practices. He also cited what we have heard from others: better results are also due to the nature of the San Andres reservoir.

Wishbone’s better wells include two in Platang Field, Yoakum County, Texas: the Badger 709 A 2XH, with first production in July 2017, and the highest average peak month production rate of 376 boe/d; and the Badger 709 C 4XH well, with first production in November 2017. Its highest average peak month production rate was 352 boe/d.

Manzano Energy III (private)

In November 2016, Manzano Energy II sold its San Andres holdings in Yoakum County to Steward Energy II for $225 million. Some members of management re-upped with private-equity backer Energy Trust to form Manzano Energy III to pursue the San Andres in New Mexico. Off to a strong start, Manzano III is operating seven wells: three horizontals in Roosevelt County, three in Lea County, and one vertical in Roosevelt County.


Where consolidation makes sense

With 561 wells permitted, drilling or producing among the top 10 operators and another 261 wells spread among 52 additional operators, should consolidation be considered? In our experience it is being considered every day in every play in the U.S.

Potential buyers include the large and mid-sized, oil-weighted operators pursuing Wolfcamp and Spraberry development in the Midland and Delaware basins. However, a number of the larger companies in these plays are under scrutiny by institutional investors to rein in capital expenditures, to accommodate a cash dividend or stock buyback program, or both. That said, an all-stock transaction would still be an option.

It also might make sense for the large-cap, natural gas-weighted E&Ps to consider entering the horizontal San Andres through an acquisition in order to diversify. This group includes Antero Resources Corp., Cabot Oil & Gas Corp., Southwestern Energy Co. and Range Resources Corp.

Acquiring an oil-weighted San Andres company would add higher valued crude oil to these companies’ predominately gas production stream. The issue of material size comes into question. As of Aug. 24, 2018, our large-cap gas peer group had a median enterprise value of $8.7 billion and a median market capitalization of $5 billion.

Compare these figures to Ring Energy’s market cap of $724 million, and you have to wonder if a member of our large-cap gas group pursuing acquisitions of San Andres companies would find a company large enough to meet a materiality test for the potential acquirer. Given these figures, if a large-cap natural gas E&P were to pursue a horizontal San Andres campaign, it would, in our opinion, likely target more than one San Andres company to be material.

John White is a managing director and senior research analyst at ROTH Capital Partners in Houston. This article is adapted from his lengthier September 2018 report on the horizontal San Andres Formation.