For all the rising market fervor about the Permian Basin lately, t turns out a pure-play Colorado E&P company successfully closed the first upstream IPO in two years. Extraction Oil & Gas Inc., based in Denver, did it October 11, raising $728 million, well above the anticipated range. The 33.3 million shares issued went out at $19 but rose 15% the first day, valuing the company at about $3 billion. They trade on NASDAQ under the symbol XOG.

The offering was attractive because Extraction had shown rapid production growth, and it promises yet more potential in the Denver-Julesburg (D-J) Basin’s core, on acreage it says is within the historical boundaries of the famous Wattenberg Field. Extraction claims some 14 years of drilling inventory ahead based on three rigs working and its current, highly efficient spud-to-spud time frame of only four days per one-mile well.

In Wattenberg, Extraction is drilling the Codell and Niobrara A, B and C formations, but it has also studied opportunities in the J Sand, Sussex and Greenhorn formations for longer-term drilling activity. In addition, it has approximately 120,000 net acres in the northern extension of Wattenberg, although no locations are identified there yet.

To bring value to the surface from the 3,900 gross horizontal locations it has identified in the core, the company counts on its strong technical team for success. It has brought together a highly experienced group of young employees formerly with other D-J players such as PDC Energy Inc., Anadarko Petroleum Co. and Noble Energy Inc.

Extraction was founded in November 2012, backed by Yorktown Partners, OZ Manage-ment, Blackrock Inc. and Neuberger Berman Group. It grew rapidly by drilling and since inception, had also made five acquisitions. Most recently, it bought additional Wattenberg assets from Bayswater Exploration & Produc-tion LLC in October 2016.

The company was co-founded by three expe-rienced D-J engineers: chairman and CEO Mark D. Erickson, president Matt Owens and operations manager Jesse Silva. Erick-son was formerly chairman and CEO of Gasco Energy Inc. and in 1997, co-founded Penneco Energy Corp. Owens was an operations and optimization engineer for Gasco and PDC Energy and was an honoree featured in Oil and Gas Investor’s 2015 Thirty Under 40. Silva has supervised the completion of over 1,500 wells, many in Wattenberg, while at BJ Services and PDC.

Extraction’s 2016 budget was $365 million for drilling 90 net wells and completing 82 net wells, but the 2017 plan will be bigger, some $675 to $775 million. Part of that increase comes from activity on the Bayswater acreage.

We spoke with Erickson recently about the new company’s future. “I’d like to reiterate that we are more than an emerging company. We’ve demonstrated operational excellence, and we have a robust inventory and strong balance sheet. We aimed for a $500 million to $550 million offering, but given how well our story was received it was oversubscribed by over 11 times ... so we upsized to nearly $730 million, including exercise of the overallotment option.” Investor Why do you think you were you able to go out first when many other IPOs were in the pipeline?

Erickson Being as we were the first company to go public in the last two years, we knew this IPO came to market with very high stan-dards to meet. But I think it was also that we’d demonstrated huge growth from mid-2014 to our IPO in October 2016. We grew our production from 200 barrels per day to over 35,000 barrels per day during that time period. And, we’ve had some of the best wells in Wattenberg Field.

Investor How did you accomplish such rapid growth and the best wells?

Erickson It came through our operations. When you look back at 2014, there were companies

that had gone public that had only drilled 40 or 50 wells. During that period, most of our growth was organic; we’d drilled over 250 wells, and we’d shown some of the lowest well costs and highest productivity. That was received very favorably. What’s more, we demonstrated our development costs were on par with the best wells in the Permian Basin, which I think caught a lot of people by surprise.

A lot of this was really the quality of our team and how we did it differently. Our oper-ations team had touched 50% of the first 600 horizontal wells drilled in the basin when they came to work for us from PDC, Anadarko and Noble Energy.

Investor How did you proceed?

Erickson First, we looked at everything that everybody was doing in the basin and we said, “What are some little things we can do to make improvements?” We integrated all those thoughts and immediately it had a tremendous result with no real learning curve. One little thing may not matter all that much, but when you come up with about 20 things, all together that makes a big difference. Right away we were completing some of the best-performing wells in the basin.

Another thing the market liked was our inventory. With the series of acquisitions we’d made, we were able to assemble over 100,000 net acres in the core, the historic boundaries of Wattenberg. We wanted the acreage we acquired to have high-quality reserves in the ground that we knew we could develop. That will yield us approximately 14 years of devel-opment opportunity.

Investor Your timing turned out to be great for other factors too.

Erickson Yes. Finally on the check list of things they were looking for, we were able to demonstrate a net debt to EBITDA of less than 1.5, which is at the top of the industry. There were only a few other companies that could have broken the ice on an IPO and we were fortunately one of those. Some of the others that had been planning an IPO were acquired instead.

In October, when the frack referendum failed to get on the Colorado ballot and OPEC was signaling a production cut, our timing was fortunate. It was just well-received. Colorado is now essentially de-risked from a regulatory standpoint. It didn’t take expectations of really high oil prices either—most of our acreage can be economically developed at $45 per barrel or lower. All we needed was some stabilization in the energy market to move forward.

Investor Ryder Scott said on your PUDs, the average estimated EUR is 556 Mboe in the Niobrara and 574 in the Codell.

Erickson That’s right. But keep in mind, our Ryder Scott reserves only cover about 25% of our core Wattenberg inventory. We have about 225,000 acres overall, 100,000 of which are in the historical core boundaries of the field—plus the northern extension. Investor So, no thoughts of expanding to the North Park Basin or Wyoming?

Erickson Right now, we have a very large and highly economic inventory within Watten-berg itself, and we’ve had very encouraging results in the northern extension that could add hundreds of locations, so we expect to be focused in the D-J for some time to come. That expertise will be very exportable to other plays in North America, but for the time being, we’ll be a pure play in Wattenberg.

Investor What about your production mix? Currently you are two-thirds liquids. Any thoughts about buying something to become a little more gassy?

Erickson We expect to focus on liquids-rich plays. I’m not very bullish on natural gas prices, with all that has been discovered, and most of the horizontal oil plays produce a lot of associated gas, so we’ll have a lot of expo-sure to gas just through our oil production. Investor Focus, focus, focus.

Erickson That’s what the market really likes about Extraction. Barclays Bank, RBC, Wells Fargo, Goldman Sachs, Credit Suisse and others have initiated coverage with favorable reviews.

Investor What are your immediate D-J plans going forward?

Erickson Looking at our strategy in general, we now have three rigs running in the basin. That’s the result of the anticipation of a more robust oil price and from the upsizing of the IPO. A three-rig pace will yield approxi-mately 250 to 270 one-mile equivalent wells per rig per year.

We are currently on pace to drill about 90 one-mile equivalents per rig per year, which is a multiple better than in other plays. In the Permian, for example, they look at something like maybe 15 to 20 wells per rig per year. Our very high drilling pace here is some-thing that differentiates Wattenberg from other plays. When you look at the amount of growth that can be derived from the amount of capital employed, we can grow faster than they can in the Permian because of the pace we can maintain here.

In our 2017 program, it’s going to be 250 one-mile equivalent wells and 125 two-mile laterals. Everyone in the basin is going forward with extended laterals if their acreage allows for it. Virtually all our 2017 program will be extended, averaging around two-mile long laterals. With the changing commodity price, we are focused on using the proceeds of our upsized IPO to drill.

Investor To what extent are you still leasing?Erickson We need to add about 5,000 acres per year, and we’ve done that historically. In 2016, we exceeded that, and in 2017, we have clear line of sight to do so again.

Investor Aren’t lease costs getting expensive? Erickson Those costs have gone up, but that’s a small component of being able to develop the assets. The capex of drilling and completing far exceeds that. A lot of the leases we pick up are from people who retain overrides and really want us to drill those leases. That gives us an advantage as we are actively developing and have shown some of the best results in the basin. Lastly, we want to use our balance sheet—we have significant liquidity with an undrawn revolver of $450 million to take advantage of any large-scale acquisitions that come up. We feel we are advantaged at pursuing these opportunities in the basin.

Investor What is the deal flow like in the D-J now?

Erickson In 2015, 2016, we were pleasantly surprised. We feel there will continue to be consolidation in the basin, but the key is you don’t know the timing, so you need to be well-positioned and ready to take advantage of them when they come up.

Investor How has your operational capability improved?

Erickson One of the things we’re most proud of is we reduced our development costs by about 40% and increased our well perfor-mance by about 20%, due to efficiencies. We have reduced our development time from drilling 1,500 feet per day to in excess of 6,000 feet per day. We can drill one-mile equivalent wells in two to three days now.

For completions, we adopted plug and perf fracking in 2014 and, at the time, we were only able to do six-to-eight stages a day. Through some proprietary techniques and equipment, we’ve been averaging 25 per day, although that number will go down somewhat as we move into our new enhanced frack designs, which we expect to yield between 20% and 50% higher esti-mated ultimate recovery. On the back-half of the well we were able to achieve a record 41 stages per day using the standard completion design. Those things take days or weeks out of the development of a pad and will be ongoing.

Investor Are service prices starting to creep up as activity increases and we come out of the downturn?

Erickson We’re seeing costs comparable to 2013. We’ve already locked in our major service costs for 2017. We might see small increases if steel prices go up, but we feel we have solid controls in place for the 2017 program.

Investor Where do you stand on the Sussex, J Sand and Greenhorn?

Erickson We’re looking at those horizons in general, and there’s definitely upside. The J is going to be more oily, so it’s targeted first. The Greenhorn is chock full of oil, but we haven’t yet come up with the technology to unlock that resource commercially. There are lots of opportunities in other zones.

I still think we’re a long way from opti-mizing completions in the Niobrara; similar to what you’ve seen in other plays, you’ll see increased frack design or frack intensity. So, we’ll end up investing more capital but increasing production and increasing net present value of the acreage.

If we can unlock the Greenhorn, that will be a whole new game. But we have such a robust inventory with the Codell and Niobr-ara that those are the near-term things. Investor What more can you say about the northern extension?

Erickson We started putting it together in 2013, and at the same time we started leasing there, EOG was leasing on the Wyoming side of the border. We wouldn’t have been able to compete with EOG at the time, so we’re glad they stayed on their side of the border. It looks to be very favorable geology—we’ve drilled four initial tests that look very encouraging. EOG has been drill-ing north of us with excellent results.

The drivers will be oil prices and also, this is a high GOR area, so fine-tuning arti-ficial lift design will be key to moving this play along. At $50-$55 WTI, we’ve got a good shot at moving this into the economic window. This is achievable in the next 12 to 18 months; we should be able to demonstrate its value. We are already learning about opti-mizing the completions there.

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