Former Eagle Scout J. Ross Craft must rely on all that he learned as a scout, to weather the ups and downs of running a small E&P company caught in the oil price downdraft. Fortunately, he operates in one of the most prolific oil basins in the world, the southern Midland Basin. As chairman, CEO and president of Approach Resources Inc., he is pursuing the Wolfcamp A, B and C benches while managing to wring costs out of the operation and move forward.

He says he sees the glass as half full, with an oil price recovery ahead and some 2,000 horizontal Wolfcamp locations in the hopper.

Last year Approach’s production rose 47%. At press time, second-quarter results were not ready yet, but in the first quarter the company posted a small loss as a result of delaying first-quarter completions due to low commodity prices, while it produced 14,300 barrels of oil equivalent per day (boe/d). The average IP of wells brought on line was 723 boe/d.

A petroleum engineer out of Texas A&M University, Craft was named a regional winner for the Ernst & Young Entrepreneur of the Year award in 2012.

We caught up with him after he spoke at our DUG Permian conference to delve a little deeper into how Approach has reduced completion costs, experimented with well spacing and installed a state-of-the-art water recycling system that has materially reduced well costs.

Approach Resources chairman, CEO and president Ross Craft sees the glass as half full, with an oil price recovery ahead and some 2,000 horizontal Wolfcamp locations in the hopper.

Investor: How did it evolve that you are pursuing the Wolfcamp in Crockett County?

Craft: We were originally in the southern part of the Midland Basin in northeastern Crockett County, and we started collecting acreage in 2004 for a deeper Canyon, Strawn and Ellenberger vertical gas well program. It wasn’t until the downturn in gas prices in 2009 that we elected to suspend drilling operations, pay down debt and look for other opportunities. The market was not kind to us during this period: Our share price fell close to $20, bottoming out around $6.

As a result of our vertical program, we drilled close to 600 deeper gas wells on our acreage between 2004 and 2010 and collected a large amount of data—openhole logs, mud logs, flare reports. We started to focus on the Clearfork and Wolfcamp shales where we were seeing significant hydrocarbon shows. About the same time, EOG Resources started looking at the Wolfcamp shales on its acreage just north of us. For a small public company, it was quite a feat for us to go from drilling $700,000 vertical gas wells to projected $8.8 million horizontal oil wells. At the time, I think our market cap was about $160 million. It had to work.

Investor: What was your strategy?

Craft: Luckily for me, I was able to entice geologist Qingming Yang to come on board. Qingming is a gifted geoscientist, and now one of my close friends and our COO. He was able to help. We broke it down into segments like a classroom, and every segment came back positive. In late 2010, we started our horizontal venture. Our first two horizontal wells were disappointing and expensive, but by our fourth, we figured out the proper completion technique. In fact, the thickest portion of the Wolfcamp net pay is in the southern Midland Basin. Our pay zone target is approximately 1,200 feet thick when combining the A, B and C benches.

We also knew, based on our whole core analysis, openhole logs and petrophysical modeling, that we had a significant amount of in-place reserves, approximately 118 MMboe of in-place reserves per section. With that, and given our large acreage position, we knew we had something big. Actually, when Qingming and I first calculated the in-place reserves, we thought we had made a mistake: approximately 1 Bboe of gross resource potential. Today I think that number might be on the low side.

Investor: How have you cut costs?

Craft: When our horizontal program kicked off, wells were about $8.6 million and took approximately 20 days to drill. Today our well costs are averaging $4.4- to $4.6 million. The Wolfcamp horizontal shale play started in the southern Midland Basin in Crockett, Irion, Reagan and Upton counties. Pioneer Natural Resources with its vast amount of Midland Basin acreage soon expanded the play into Martin and Midland counties. Laredo Petroleum expanded the play east and northeast into Irion, Glasscock and Howard County.

When you look at the number of horizontal Wolfcamp wells drilled in the Midland Basin to date, there are probably 2,100 completions, of which around 1,800 are in the southern Midland Basin.

Investor: Can you repeat your 2014 growth this year?

Craft: Last year was very robust for us. We set a $400 million capital budget supporting three rigs and we targeted 40% year-over-year production growth and reserve growth in the 20% range. At year-end, we had drilled 68 wells and placed 64 on line, and realized a 47% annual production growth … and we came in under budget.

Then in November we started seeing a pretty sharp decline in crude prices. Our 2015 budget will be about $160 million, and on average, we’re going to operate one rig.

Drilling is going to be front-end loaded, so we’ll probably not complete too many wells in the fourth quarter, unless we see some significant increase in oil prices. But I truly believe we will see the oil price continue to slowly move up, as we are already beginning to see it. Even so, we aren’t just waiting around for the price to go higher; our technical team is focused on further reducing costs.

Investor: How do you achieve that?

Craft: We were already the lowest-cost driller in the Midland Basin, due in part to the shallower depths where we are operating. Our cost in 2014 was $5.5 million a well compared to our northern Midland Basin neighbors, where costs ranged around $8.5 million a well. We were able to cut costs through our extensive infrastructure system, our two pilot water recycle facilities, and further program efficiencies as a result of our experience in the area.

Investor: Your water program is instrumental in this.

Craft: In March we finished construction on our $3 million centrally located water recycle facility. This has 329,000 bbl of recycled water storage and can clean and process 20,000-plus bbl of produced water a day. With a few low-cost modifications, we can increase our processing capacity to more than 40,000 bbl of produced water per day. Since March we have processed and reused more than 1.5 MMbbl of produced water. Being able to reuse this produced water has further reduced our D&C cost by approximately $500,000 per well.

Investor: What’s job No. 1 this year to survive the downturn?

Craft: The last thing we want to do, and the last thing anybody wants to do right now, is spend money at these low prices unless you absolutely have to. One advantage we have, and because we’ve been operating in the Permian for such a long time, is we hold a lot of our acreage with the vertical wells. We have no long-term contracts, so we’re very flexible. We can start up, slow down and speed up at will. In addition we have 100% working interest in the majority of our properties.

Obviously, being a small company, our balance sheet is key. We’ve been through these commodity price cycles several times before. We entered into 2015 with a clean balance sheet and ample liquidity. At the end of the first quarter our debt-to-LTM EBIDAX was 2.6 times, and we have $240 million of undrawn liquidity with no near-term debt maturities.

Investor: What oil price would cause you to add back another rig?

Craft: What I need to see is meaningful growth in crude prices, not an uptick of $3 in one week and a downtick of $4 the next. I need to see a consistent gain—I need to see three or four more months of improved pricing. Obviously, and this is no secret, nobody’s making real money in the industry when crude prices are low like this. We’re doing what we have to do to survive.

But don’t get me wrong. At current strip prices, my wells are averaging approximately $4.6 million in costs and are delivering a 20%-plus return—not bad considering the vast inventory of locations we have. Do I want to actively drill in this environment? No! When I see WTI start approaching the mid- to low $70s, then I’ll start getting excited again, and say, ‘Well, it’s time to start thinking about bringing some additional rigs in.’

I think the turning point will be July or August. If we don’t see it by then, it probably means that we’re going to be in for a longer downturn.

Investor: How have you high-graded to the best locations?

Craft: The beauty about the southern Midland Basin is the thickness of the Wolfcamp. We have three productive benches in the Wolfcamp, A, B and C. We were one of the first companies to commercialize all three benches. We have 17 wells in the A bench, more than 100 wells in the B and 44 wells in the C bench.

All of the benches have similar reserves, although producing characteristics of each bench will vary slightly. For example, the A bench is slower to come on—it normally takes 30 to 60 days before it reaches peak production, at which time it tracks the type curve. The B bench reaches peak production fairly quickly, and the C bench peaks even faster.

Investor: Have you changed your models or EURs?

Craft: Our 450,000 boe type curve model for a 7,500-foot lateral has held up nicely since starting this project. At the end of 2014, and with the help of having three to four years of production data (along with our probability distribution study focusing on the mean reserve value on each production stream), we adjusted our type curve upward to 510,000 boe per well, driven primarily by shallower-than-expected gas declines.

Our oil type curve did not change and represents about 230,000 boe per well. Obviously from a percentage calculation, if you raise your gas and NGL volumes and do not change your oil volumes, your percentage of oil will have to go down.

Investor: What factors into your drilling program decisions?

Craft: As far as picking the highest-return locations, it is based on where we have existing infrastructure. Today our infrastructure covers approximately 70% of our acreage.

In 2012, our D&C costs were averaging $7 million per well, and my targeted well cost was $5.5 million. How was I going to reduce my well cost by $1.5 million? By 2012, I had enough production data to feel confident about my type curve and made the decision to invest $100 million in infrastructure.

Now we are focusing on dual-bench development, due to our reduced rig activity in response to low commodity pricing. For every pad site, we will have a C-bench well in combination with either an A-bench or a B-bench well. To place three laterals per pad using one rig and one completion crew would greatly extend spud to first sales, resulting in lumpy production. Once we increase our rig count, we will continue with our triple-stack pad program.

We have 147,000 acres, of which we have derisked 107,000 acres to date. Of our 2,000 identified locations, none is located on our southeastern 40,000-acre position in an area we call Ozona northeast.

It’s really hard to say which area is better than the other, or which bench is better than the other. We have commercialized all three benches across our core acreage position.

Investor: Talk about the concept of staggering within the same bench.

Craft: We are spacing our laterals somewhere around 650 to 800 feet apart; that’s the closest spacing we want between wells in the same bench. We originally came up with the idea to do a chevron pattern between benches. We would stack our A-bench wells and C-bench wells on top of each other, separated only by depth. Our B-bench well would be located between the next set of A and C bench wells, plus or minus a 400-foot diagonal offset.

Now we’re seeing that because of the rock mechanics, we might be able to do the staggering within the same bench. That’s something we’re all working on, and hats off to EP Energy; they’re the guys who started working on this and staggering inside the bench. For example we might drill an A-bench well, and then drill another A–bench well offsetting it, but at a different depth within the same bench.

These benches are each about 300 to 350 feet thick. Based on what I’ve seen so far, I’m very impressed. I think this drilling pattern is going to be adopted by a lot of folks.

Investor: Compare the southern and northern parts of the Midland Basin.

Craft: That’s the biggest misconception we’re still faced with, ‘Your production mix looks too gassy, and your well EURs are less than what is being reported by operators in the northern part of the basin.’

We look gassy because we have 600 vertical wells that contribute to our production profile every day. The Wolfcamp does get deeper as you go north, meaning more pressure. In Midland and Martin counties, TVDs will be 10,000 feet as compared to 6,000 feet in our area. The northern part of the basin, due to depth, will have higher oil cuts and EURs, but the well costs are considerably higher due to the depth of the wells.

The southern Midland Basin has more than 80% of the completed well inventory; many of these wells have three and four years of production history. The northern Midland Basin has approximately 400 Wolfcamp completions with the majority of these wells drilled within the last two years. I think the verdict is still out concerning final oil cut and P-50/mean EURs.

Our 510,000 boe per well will generate a very nice rate of return, even at today’s prices. The southern Midland Basin is very good, but it’s really controlled by about five or six operators.

Investor: Do you think the “fracklog” will keep oil prices low when all that new production comes on?

Craft: Let’s put it in perspective. If you think about it, with one pad, one rig, they’ll have at least two wells waiting on completion at any one time. So if you have 1,000 rigs working, you’re going to have 2,000 wells waiting on completion. If the industry is averaging three to four wells per pad, the number could be 3,000 to 4,000 wells waiting on completion.

Let’s assume that 50% of these wells will be the very big wells P-50 and up, and the other 50% will be P-50 and below. If you could bring them all on line at the same time, which would require a huge amount of capital and equipment, the impact on the global oil supply would be less than 0.3%.

Fracklog is a good buzz word. With pad drilling, you will always have a large inventory of wells waiting on completion. That’s just the nature of the business.

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