AREX an early player in Wolfcamp

OGFJ: What prompted the shift from vertical natural gas wells to horizontal Wolfcamp oil wells?

CRAFT: From 2004 to 2010, we drilled approximately 600 vertical deeper gas wells on our acreage and collected a large amount of data - open hole logs, mud logs, and flare reports across the shallower Wolfcamp. Many of these wells had significant hydrocarbon shows, but that's not actually what prompted us to explore the Wolfcamp. The natural gas price collapse in 2009 forced us to try our hand at the Wolfcamp shale.

Most of our acreage was held by production at the time. So when natural gas prices collapsed, I dropped all of our rigs - a less-than-ideal situation for a growth company, but it gave us the time, capital, and energy to closely evaluate the Wolfcamp.

This was no easy task. Our market cap was about $160 million, and we were estimating Wolfcamp horizontal well costs at $8.8 million. So my colleague, Dr. Qingming Yang, and I, started collecting data. Late in 2010, we hosted an analyst day in New York City with about 100 analysts. This is where we unveiled the horizontal Wolfcamp play in the southern Midland Basin. Late that year, we drilled our first horizontal Wolfcamp wells. Our first horizontal Wolfcamp wells were trial and error at best, until we figured out the proper completion technique. I often joke and say 'Our first two wells didn't produce enough grease to grease a tricycle.' By the fourth well, we believed we had it figured out. The rest is pretty much history at that point. Since then, the industry has completed approximately 1,700 Wolfcamp horizontal wells in the southern Midland Basin.

OGFJ: What has surprised you about the Wolfcamp as theplay has evolved?

CRAFT: The size and potential of the play surprised me the most. The thickness of the Wolfcamp trumps all other shale plays. The formation is thickest, about 1,200 feet, where we are in the southern Midland Basin - South Reagan, South Upton, Irion, and North Crockett counties. The Wolfcamp A, B, and C benches are all productive in this area, and each zone is about 300 to 350 feet thick. As you move north, you lose pay in the C bench, and as you move northeast you lose pay in the B and C benches. We were the first to commercialize all three benches.

When you look at the formation from a resource potential standpoint - it's staggering. Currently, we estimate approximately 130 million barrels of oil equivalent in place per section, which is up from our original forecast of 118 million barrels of oil equivalent. The industry has proved, or de-risked the Wolfcamp on a little more than five million acres. That represents approximately one trillion barrels of oil equivalent of Wolfcamp potential. Using a conservative recovery factor of about 4%, this makes it one the largest plays ever discovered.

OGFJ: You and your team have been able to amass quite a footprint since 2010. How many acres do you have, and were you able to accumulate this before acreage costs sky-rocketed?

CRAFT: We lease approximately 147,000 gross acres in the southern Midland Basin. Most of this was acquired prior to 2010 for roughly $50 to $100 per acre. However, from 2010 to present, we added approximately 35,000 acres of higher-priced leases, bringing our all in acreage cost to around $500 per acre.

OGFJ: Earlier, you talked about the risk of transitioning from a $1 million vertical gas well program to an $8.8 million horizontal oil well program. But now, your horizontal well costs are averaging $4.6 million. What has been the key driver behind Approach's ability to reduce well costs, and what has this done to your project returns?

CRAFT: In 2012, we had enough production history to provide a clear understanding of our reserves from a type-curve perspective. Once we looked at the project as a whole, we knew the long-term sustainability of this play would require us to reduce well costs in order to boost our project economics. I set the goal of reducing well costs to $5.5 million. Two years later, in 2014, our average well costs were $5.5 million. This was the product of doing things better, safer, and more efficiently. For example, our first well took us 70 days to drill to a total measured length of 15,000 feet - now it takes six-and-a-half days.

Simultaneously, we had a long-term vision and invested more than $100 million in an infrastructure system, which reduced our well cost by approximately $1 million per well, bringing us to the $5.5 million range. In March of 2015, we completed our large-scale water recycling facility, which shaved an additional $500,000 off of the $5.5 million well cost. Then, with the commodity price downturn, third-party service providers reduced their costs, allowing us to decrease our well costs by another $400,000 - down to $4.6 million. Together, these measures reduced our well costs by almost $2 million dollars, substantially increasing our returns.

OGFJ: What's been Approach's operational/financial response to the sub-$60 per barrel environment?

CRAFT: We took steps to ensure that we will come out of this downturn an even stronger company. We've reduced our capital budget, but even with the reductions we'll still grow production this year by approximately 10% to 14%. We looked at the low-price environment and said there is not a reason to accelerate activities, much less maintain our 2014 capital structure. Our acreage is largely HBP, and we don't' have to drill. In addition, we have no long-term contracts to deal with. So our capital expenditure budget for 2015 is $160 million, and we will run one rig. Last year it was $400 million, and we ran three rigs.

OGFJ: If the current oil price remains at $60 per barrel for a prolonged period, how is your company positioned to operate in this price environment?

CRAFT: We can't control the price of oil - all we can do is control our costs and our balance sheet. We believe we've positioned ourselves to remain a low-cost Wolfcamp shale producer - even if prices go back up. This is a commodity business, and prices will go back up. When they do, oil service providers will adjust their prices up accordingly. But because of the steps we've taken, even if prices go back to $80 or $90 per barrel, we'll still be able to drill and complete our wells for $4.8 million, making us one of the lowest-cost producers, if not the lowest-cost producer in the southern Midland Basin.

And unlike some of our peers, we have strong credit metrics and no near-term debt maturities. Maintaining a strong balance sheet has always been key to our growth and our success. From a financial perspective, we are very conservative. As of first quarter 2015, our debt-to-long-term EBITDAX was only 2.6x, which is top quartile among our small-cap peers, and our liquidity was more than $240 million. So we are set to survive. It won't be comfortable, but we are geared to survive and grow the company.

At $60 oil, no one is making much money at the corporate level. At the well level, $60 oil will generate around a 20% ROI for us - and that's good in this environment, but at the corporate level it's tight. I'm confident that by 2016, we'll be back to a more balanced supply/demand picture, and the industry can make a little money once again.

OGFJ: Do you have hedges in place to meet your 2015/2016 goals?

CRAFT: Our disciplined hedging strategy moderately sheltered us from the downturn in 2014/2015. Approximately 64% of our projected 2015 oil production volumes are hedged at around $80 per barrel, and 44% of our natural gas is hedged at around $4.00 per MMbtu. We are starting to add small additional hedges for 2015 and early 2016 as we watch prices move upward.

OGFJ: Decline curves continue to outperform your initial projections. As you drill more wells and move along the learning curve, can you talk to us about the production mix you are seeing, and what are you expecting from your wells going forward?

CRAFT: We've drilled approximately 160 horizontal Wolfcamp wells - 17 Wolfcamp A-bench wells, 44 C-bench wells, and 101 B-bench wells. Our type curve was 450,000 barrels of oil equivalent (boe) and that's been with us since 2011. We now have three to four years of production history. At the end of 2014, we raised our type curve to 510,000 boe, and the increase was predominately from natural gas and NGLs, not oil. The oil type curve is still approximately 230,000 barrels per well. What we are seeing is that the natural gas portion of our type curve is declining at a lower rate than originally anticipated, so we made the decision to raise our EURs. Going forward, we estimate our product mix to be approximately 45% oil, 25% NGLs, and 30% natural gas.

OGFJ: How should investors and industry professionals compare and contrast results from southern Midland Basin and northern Midland Basin Wolfcamp horizontal wells?

CRAFT: The biggest misconception we're still faced with is, "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." I look gassy because I have 600 vertical gas wells that contribute to my production profile every day. The northern Midland basin has vertical oil wells that contribute to their production stream. Optically, it does make a difference.

The Wolfcamp does get deeper as you go north, meaning more pressure and higher drilling cost. In Midland and Martin counties, TVD's will be 10,000-plus 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 2,100 Wolfcamp completions, and 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.

Approach's Wolfcamp reserves in the southern Midland Basin are based on a probability distribution study focusing on the mean reserve value on each production stream using all wells completed. We do not normalize a lateral if it is less than 6,000 feet. We exclude it from the study. We, along with most operators in the Midland Basin, have our share of exceptional P-10 wells, ranging from 700 to 800 thousand barrels of oil equivalent (Mboe) with lateral lengths of between 6,300 feet and 6,500 feet - but they are not the norm. The key when you are looking at a new play - you shouldn't just look at P-10 or best well economics.

All in all, before investors jump to a conclusion based on an IP rate or a P-10 EUR number, they need to take more into consideration. Repeatability, number of wells completed as a function of total acreage, step-out vs. manufacturing results and well cost all need to be evaluated in order to determine true economics.

OGFJ: With regards to getting your product to market, what does the current infrastructure picture look like surrounding your acreage?

CRAFT: Because of its legacy natural gas development, the southern Midland Basin has a well-established natural gas infrastructure - but there was almost zero oil infrastructure when we first started. As I mentioned, we made a significant $100 million investment in our infrastructure. Based on a development pattern of 7,500-foot laterals, we identified all our future drilling locations. As part of the 2012 infrastructure build, we laid six, eight-inch lines to 70% of the identified locations, three steel lines used for oil and gas gathering lines, plus a high-pressure gas lift supply line. On the water side, we laid three, eight-inch poly lines, one low-chloride frac water supply line, one high-chloride frac water supply line and a produced water line. The investment in water handling and supply equipment reduced our D&C cost by $1 million per well. In addition we built approximately 20 miles of high-pressure sales lines to our six custody transfer points.

In 2012, we built a 38-mile 100,000 barrel per day oil pipeline from our acreage up to Plains Interconnect at Owens. We did that as a joint venture with a midstream operator. That gave us a throughput to Plains and then a throughput to Cushing. This pipe also crosses the Longhorn, which moves oil to Houston-area refineries.

This project ensured our oil would flow real time via LACT, and we would realize a total differential of between $4.50 and $5.00. If you remember, trucking was almost $10 per barrel in 2011 and 2012, assuming you could find trucks to haul your product. While the construction was taking place, we purchased a small fleet of company-owned oil transport trucks. In 2013, we monetized the pipeline for a 6x return, but retained our transportation rights. We also negotiated a long-term processing agreement with DCP to go south with our gas instead of north. That was important, because we wanted to avoid fighting pipeline congestion from northern Midland Basin wells. All this, we believe, sets us up long-term for marketing our products.

OGFJ: And what about water. Water has been a big issue for operators in drought-stricken West Texas. How has your company been able to secure your water volumes, processing and storing capacity?

CRAFT: We are proud of our water handling infrastructure. In 2012 we knew that the only way to achieve our targeted wells cost was to build a massive water infrastructure system - SWD wells, water lines, low-chloride frac water surface pits, water supply wells, and recycling facilities. Today we re-use 100% of our produced and flow back water. By reusing this water, we reduce the amount of truck traffic on our leases, as well as on the highway system. We also reduce the amount of water being disposed of in the commercial system and eliminate the need to use fresh, potable water. It's truly a win-win for everyone.

Early in 2014, we ran two small-scale water recycling pilot tests for the purpose of quantifying the feasibility of using recycled produced water for frac fluids. The biggest challenge with this was water chemistry. The pilot program proved we could clean and reuse produced water, which would lead to further D&C cost savings, as well as LOE reductions field wide. At that point, it was time to construct a large-scale water recycling facility. By March of 2015, our 329,000 bbl recycle system was operational and was delivering clean, recycled produced water to our frac sites (see illustration of Approach's water recycling system).

In the past, before the recycle system was constructed, a typical well required 250,000 barrels of frac water. The cost to secure and transport the water to the frac site was about $3 per bbl. After stimulation, you had to remove and dispose of the produced water. In the first year, you're not going to recover all 250,000 barrels. You'll probably recover somewhere around 70,000 barrels. Trucking and disposal of the produced water can run anywhere between $2 and $5 per barrel, depending on the distance the water is transported and the disposal fees. Our total water handling costs ranged from $5 - $8 per bbl. Our full-cycle water recycling cost is between $0.80 and $1.40 per barrel, depending on the water mix, and represents a savings of between $4.20 and $6.60 per barrel of water.

It saves money on the drilling and completion side, but it also reduces LOE costs. In 2014, we paid $1.05 per boe for water transportation and disposal. We have virtually eliminated that expense. Since March 2015, we've processed 1.5 million barrels of water through our recycling facility. In addition, the plant could generate an additional $0.75 per boe savings on our LOE, making us one of the lowest-cost operators out here.

OGFJ: What will AREX look like five years down the road?

CRAFT: We have to be bigger. Size and scale are very important to a public company. We also need to expand our footprint to other areas.

OGFJ: How do you do that?

CRAFT: We have to continue to grow - and that's hard to do organically in this market. To date, our growth has been all organic. But to take this company to the next level, we have to explore potential mergers, JVs, and complementary acquisitions. I'd like to have another leg on this wooden stool - meaning another basin to build in. Diversification is a good thing for us. Pure play companies are embraced by Wall Street, but they do come with risk. Pair trading has put unwarranted pressure on our stock price over the last 12 months.

My goal as chairman and CEO of the company is to create value for my shareholders. And I have a vested interest for this company to do well, since I'm a large shareholder as well. We have one of the best and most talented teams in the industry - I'll rate them with anyone. If my strategy and long-term plans don't pan out as expected - you can blame me.

OGFJ: Thanks very much for your time today, Ross.