Paddle upstream

USA

TOGY talks to Bill Fairhurst, CEO of Riverford Exploration. Riverford is a Texas-based E&P company with onshore interests in the USA.

Bill Fairhurst is credited with economic discovery of the WolfBone play in the Permian Basin. His company has producing oil and gas assets in the Elm Coulee Field in the Bakken formation of eastern Montana, both the Midland and Delaware Basins of the Permian Basin, and in the Woodford Shale of Oklahoma. About 60-70% of Riverford’s business comes from E&P, and the balance comes from providing consulting services.

• On making the WolfBone economic discovery: “The third well we drilled was 1 mile [1.6 kilometres] into the basin. That zone, which looked like less than a foot [30 centimetres] of a fracture, was a 20-foot [6.1-metre] shale and more. That is when the light bulb went off in my head. I said, ‘Guys, this isn’t about the sandstone; it’s about this Wolfcampian shale.’ I went to the engineers and told them that the Wolfcamp was shale, and what we needed to do was stop focusing on these sandstones that everyone is so interested in, and instead frack [hydraulically fracture] the Wolfcampian shale like we were doing in the [Haynesville-Bossier].”

• On the importance of local knowledge: “Those that find the big discoveries in most of the big fields in the US have been small shops; small one- or two-man shops or small exploration shops that understand the plays in those areas. They are the ones more likely to find the big reserves.”

Besides touching on these topics, TOGY talked at length to Bill Fairhurst about the company’s beginnings, its development work in the Permian Basin and how the industry interacts with the market. Most TOGY interviews are published exclusively on our business intelligence platform TOGYiN, but you can find the full interview with Bill Fairhurst below.

What has been Riverford’s approach to the Permian Basin?
Riverford Exploration has been in existence since 2003. It started out with a conservative method of purchasing PDP [proven, developed and producing] properties. We acquired our first property in early 2003, and that well and property are producing today at about levels it did when it was first purchased. Part of the goal was for long-term, long-life types of reserves. That property ended up being in the middle of our assets in the area over time, so that has worked out pretty well. The second property we bought was on the eastern shelf of the Midland Basin.
When I started Riverford, I used the model of buying EDP [Exploratory Drilling Program] property to generate cash. We started drilling in the Haynesville-Bossier [HB] area in 2009, and drilled some of the best early, successful wells in the region with much higher EURs [estimated ultimate recovery], and we continue to drill wells in the Delaware Basin.
None of the companies that were active in in the heart of the WolfBone were drilling anything called the WolfBone at that time. They were drilling the sandstones immediately above the Wolfcampian shale, and there is some sandstone below the Wolfcampian shale, which was the primary target of all the companies that were out there at the time.
We drilled our third well out there in 2009, and what I recognised in 2010 before anyone else was that we had drilled three wells, and the first two were 17 miles [27.4 kilometres] apart, and right on strike. At one point in the Wolfcamp, something that looked like a fracture 17 miles [27.4 kilometres] away, looked like the same zone again. I was very curious that there would be something that looked like a fracture that would be in the exact same spreadographic position to put oil into the pits.
The third well we drilled was 1 mile [1.6 kilometres] into the basin. That zone, which looked like less than a foot [30 centimetres] of a fracture, was a 20-foot [6.1-metre] shale and more. That is when the light bulb went off in my head. I said, “Guys, this isn’t about the sandstone; it’s about this Wolfcampian shale.”
I went to the engineers and told them that the Wolfcamp was shale, and what we needed to do was stop focusing on these sandstones that everyone is so interested in, and instead frack [hydraulically fracture] the Wolfcampian shale like we were doing in the HB.

What advice would you give to those starting work in the Permian Basin?
There are a number of challenges to look at. First of all, I think the Permian Basin is still very much a Midland- and Odessa-driven play in Texas. It is very important to meet a lot of people in Midland or have good sources there for what is going on. It is good to have people there on the ground. It really has been an independent’s world.
When ExxonMobil bought the Bass Brothers’ interest in the DB [Delaware Basin] at the end of 2016 for USD 6 billion, a lot of the comments were, “It’s about time Exxon showed up!” They were right on time, though. That is exactly the way the cycle goes and the way the major gas companies are. They are right in the place where you would expect them to be.
Those that find the big discoveries in most of the big fields in the US have been small shops; small one- or two-man shops or small exploration shops that understand the plays in those areas. They are the ones more likely to find the big reserves.
We talked about the discovery of WolfBone. Had I not known about the mud logs, not had good geological experience and not talked about it with the geologists from Midland, I would not have known all those things about the WolfBone play. That is usually who finds them: people with experience like my own at smaller or mid-sized shops.
They may have the capital to go out and put the land together and drill a couple of wells, but they do not have the capital that is required to make it a true manufacturing play, because the number of wells it will take to develop these resources is mind-blowing.

Can you give an example from Riverford’s experience?
I am drilling between three and six wells each year now at our current drilling rate, but we have about 150 HBP [held by production]-PUD [proven undeveloped] locations to drill. That is a 33-year drilling inventory.
If you look at Noble’s work at the Permian Basin, they currently have 4,700 PUD locations in their HBP now with their Plank and Rosetta acquisition. But earlier in 2017, they were throwing four or five wells. Even if every rig is completed every 20-30 days, that is something like a 48-year drilling inventory.
Wall Street likes that. They like to know that the pioneer has a drilling inventory of more than 50 years. However, what you truly get value for is if you look at present value. It is likely the present value of anything will halve within five years, so wells should be completed as soon as possible.
Ten years out, when you start discounting 12%, it has a quarter or less of the value. You really cannot say anything more than 10 years out has a value. The only way to realise that value is to start drilling at a faster and faster rate.
That is why we are seeing the Permian Basin pick back up in 2017 compared to what it was in January 2016. That is also why the Permian Basin is getting so much attention. Since there is so much well defined production, we can capture out there with modern completion techniques, which we know we can do.
Companies like Pioneer Natural Resources or Noble Energy cannot possibly drill the acreage position they have. For example, in the Midland Basin, they would need ExxonMobil, Chevron or some other large, international company that has the capital to increase the rate of drilling five- or sixfold to come in and buy them to bring as much value as they can forward.
I think that is going to be the big play. The challenge is knowing that corporations that have the largest asset base understand where we are in the resource cycle. We are no longer at the point where a one- or two-man shop can be in there competing. But eventually companies like Noble and the Pioneer will be gobbled up by even larger organisations, like national oil companies or super-major multinational oil companies.

How have drilling patterns changed as the cycle of the Permian Basin has changed?
When we started the first horizontal wells in late 2011 to see through 2012 or early 2013, we were still drilling both vertical and horizontal wells. Early in that development people asked which one was better. It really depended on your company and what your metric was.
For a family-run company that is only looking to build wells and long-term wealth, and not necessarily looking for the best return on investment, drilling a USD 3.5-million vertical well and completing multiple zones on that actually worked out better.
But if you wanted to make a big bang on Wall Street and have a big announcement that you are producing at a higher rate, you need to drill horizontal wells, which have a higher initial production rate and a higher return on investment. Therefore, you can make a bigger amount on Wall Street and a get bigger impact for investors.
I think the answer is horizontal wells. There is a period of overlap, but I think everybody can meet their metric, and that is something that could happen with horizontal wells. I believe the Permian Basin now has around 80-85% horizontal wells. That will continue to be the trend in the Permian Basin and other basins.

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