November 2015 marked the 22nd year of Tom Jorden’s career with what is now called Cimarex Energy. Based in Denver, Cimarex had its roots in Key Production Co., which in early 2002 acquired the oil and gas division being spun off by Helmerich & Payne. Key Production re-christened itself Cimarex, with an equity market cap at the time of around $600 million. Another milestone was the $2 billion-plus purchase by Cimarex of assets from Magnum Hunter in 2005.

A graduate of the Colorado School of Mines, where he earned BS and MS degrees in geophysics, Jorden began his career at Union Pacific Resources and Superior Oil. He joined Key Production as vice president of exploration, moving up to executive vice president of exploration in 2003. He was named president and CEO in 2011. A year later he was named chairman.

Cimarex’s recent market cap was around $11 billion. Jorden is modest about the E&P’s ascent to these levels under his leadership. While it is an honor to be CEO, it is also humbling, he says, in view of the “very talented and highly engaged executive management team,” whose intimate involvement on a daily basis has been critical to the effectiveness of Cimarex.

Tom Jorden

Investor Tom, when you look back at the early days of Cimarex and its predecessor, Key Production, and you compare those early assets to what you have to work with today, it’s hard not to think you have an embarrassment of riches. What have been the keys to success for the Cimarex team?

Jorden There are lots of elements to our success, and I’ll start with luck. There’s always a certain amount of luck. We found ourselves in areas that had multipay potential, in areas that were really well positioned for the explosion of horizontal drilling. With the H&P transaction, we picked up a much stronger position in the Midcontinent, and with the Magnum Hunter transaction in 2005 we found ourselves in the middle of the Delaware Basin. The Delaware would become an absolute laboratory for the success of the horizontal drilling revolution. It was full of small, vertical recompletions that would be harbingers of future horizontal targets.

So there is a certain amount of luck as to where our assets are today, but it was also an outgrowth of our core philosophy. We got into the Delaware Basin because we generate prospects internally, and we saw that if you put a good team together and assign them to a good multipay basin, they’re going to find lots of things to do. We weren’t buying PDP [proved developed producing]; we’ve never been interested in primarily PDP. Every time we look at a deal, including today, it’s always about the upside. And the Delaware Basin has tremendous upside.

Investor You were more measured in your approach to unconventionals, and certainly not leading the charge.

Jorden We came late to the resource play party. We never got into coalbed methane. And in the early days of the shale revolution, we couldn’t see how making the kind of basinwide land investments, on a risked basis, generated full-cycle returns. We were slow to act. And in any event, the bar is really high at Cimarex for a major new venture.

In 2006-2007, we got into Cana Field in the Midcontinent. Our moves into Cana and later into the Delaware Basin were both driven by our internal prospect generators, who had creativity, a detail-oriented focus, and a lot of credibility. Getting into Cana ended up being a tremendous place to be. And now we have the Meramec sitting on top of it.

Investor You’ve got a reputation for being returns-driven. How does that work at Cimarex?

Jorden Our goal is to drill wells with the best full-cycle returns. Generally, we’re looking to make after-tax rates of return, on a full-cycle basis, in the mid- to high teens, after fully burdening wells with costs of land, general and administrative costs and so on. And to achieve that, our experience is that you need to be targeting 25% to 30% after-tax returns in drilling wells on a half-cycle basis. Our underlying commodity assumptions are run down to $40/bbl West Texas Intermediate (WTI) and $2.50/Mcf, both held flat forever.

We run Cimarex on data. We have a lot of systems here that force us to look at actual results in the cold light of day. It’s deeply uncomfortable, but it’s central to the health of our company. Our experience is that lots of things can go wrong, and often more things tend to go wrong than go right. So we want our actual results to drive decision-making.

To that end, we do an annual look-back, in which we look at all the wells we’ve ever drilled, comparing actual results against what was originally projected in terms of production, cash flow, etc.

Investor Earlier this year, Cimarex did a secondary equity raise for the first time in its history. What analysis did you undertake before going ahead with that offering?

Jorden The equity offering we did was hotly debated. It was something that, back in the fall of 2014, I wouldn’t have predicted that we do. We didn’t want to dilute our shareholders. But we found ourselves facing a couple of challenges. One was that we entered 2015 completely unhedged—we can debate that at length, but it was what it was. And so our cash flow was poised to go down significantly.

Yet in front of us we were seeing operational efficiencies and well performance improvements, coupled with tremendous assets, and our well-level returns were still healthy. So we asked ourselves, ‘If we raise additional capital, would that be accretive by accelerating these investment opportunities?’

And we ran a lot of internal models. One assumed no offering, and that we lived within cash flow and whatever level of borrowing we were willing to incur, and that gave us one model of what Cimarex would look like in 2017. Another assumed a modest-sized equity offering, with proceeds invested in assets that would bring value forward, giving us another model for Cimarex in 2017. And comparing those two models, the equity offering was going to be greatly accretive to the benefit of Cimarex shareholders.

So we pulled the trigger and did it. I think it was the right size of an equity offering. Our proceeds are well invested, and I feel as strongly now as ever that the Cimarex shareholder in 2017 will be in much better shape. But it was an extremely difficult decision. We don’t plan to make it a habit. We never want to be serial equity issuers.

Investor So how does that greater capex flexibility translate into a budget for 2016? At one point, Cimarex was planning for a marked increase in rig activity, going from seven operated rigs up to as many as 16; now that number is 12. What color can you give in terms of the direction for 2016?

Jorden We’re planning to live within cash flow, based on current strip pricing, plus a portion of the $899 million of cash on hand as of September 30. We’ll be at 12 operated rigs going into 2016, and thanks to the greater efficiencies and cost savings we’re realizing, we can accomplish more with those 12 rigs than we could just three months ago. Of course, we can accelerate activity if conditions change.

In terms of area, the 12 rigs will be split evenly between the Permian and the Midcontinent. Of the six in the Midcontinent, four will work in the Woodford and two in the Meramec. In the Permian, three rigs will work in Culberson County, drilling Wolfcamp D wells, while another will operate in Reeves County, drilling Wolfcamp A wells. The remaining two rigs will target the Second Bone Spring in the White City area.

Investor How are you planning to slice the capex pie in 2016? Which areas will get a little more?

Jorden The biggest slices of the pie obviously go the Wolfcamp in the Delaware Basin, at 41%, and the Woodford in the Midcontinent, at 35%. But the two areas that are gaining share, growing to 13% and 11%, are the Bone Spring and the Meramec. Those are the two best programs on a rate-of-return basis.

The Bone Spring is not really a resource play; there is a lot of geologic risk associated with it, and so there’s always likely to be some governor on the amount of capital you can put into the play. But it’s a wonderful play, with our acreage mainly in Eddy and Culberson counties. It continually amazes us; it continually carries forward with legs, but has never carried a deep inventory. We’ve had about a two-year rolling inventory since 2009, and that will likely continue for the foreseeable future.

Investor What about the Meramec, where your first long lateral (10,000-foot) well came on at an IP-30 (30-day initial production rate) of 16 million cubic feet equivalent per day?

Jorden Meramec is still a big delineation area for us. We have lots of areas of our assets where we haven’t drilled any wells yet, and we have lots of landing zones we haven’t tested yet. Those are typically one-off wells, and we want to do that aggressively. The beauty is that they are generating wonderful returns, and we’ve decided to pick up the pace.

Our long lateral well, the Clayton 1HX, has been a horse. The well provided a 72% uplift in production relative to the prior 11 wells drilled with 5,000-foot laterals. Going forward, we plan to drill long laterals on all our dedicated acreage, wherever possible. In that vein, we have designed a downspacing pilot with a total of 11 wells to be stacked and staggered in both the Meramec and Woodford formations. The pilot will comprise six Meramec wells, staggered between upper and lower zones, and five Woodford wells.

As I said on the third-quarter conference call, our programs are rapidly evolving to being dominated by long-lateral wells. We have a bias towards pressured reservoirs, and these reservoirs have tremendous deliverability and the necessary energy to give long-lateral wells a turbo-charged uplift. Our acreage positions support a growing long-lateral program in the Woodford and Meramec in the Midcontinent, as well as the Woodford A and D in the Delaware Basin.

We love where we are playing in the Meramec. It’s a pressured part of the play. It’s a place where the pressure combines with the wet gas in the reservoir to produce a tremendous amount of energy. These are good, good wells. A lot of things we worry about in other areas we don’t worry about here.

Investor How much acreage is suited to development with 7,500-foot or 10,000-foot horizontal wells?

Jorden In the Woodford/Meramec, we have 115,000 acres in the pressured part of the play, of which about 70,000 acres are de-risked. In the Delaware Basin, we have approximately 170,000 acres, which includes Wolfcamp A and Wolfcamp D in Culberson County and Wolfcamp A in Reeves County. A lot of it will typically be developed for two or more zones. For the Wolfcamp, that represents a decade or two of drilling, and it could easily be more. That’s all grade A. I’m excluding some other targets that have lower rates of return, but may make sense to drill concurrently rather than have them left behind as “orphans” and never subsequently exploited.

Investor It looks like you’ve started to do more hedging, which is a departure from your prior practice. What’s changed your philosophy there?

Jorden Our historical philosophy was that our balance sheet was our hedge, and we used to view hedging as a zero sum game. Historically, there was a nice balance at Cimarex between cash flow and capex. You typically had a situation where, when commodity prices were poor and your cash flow was down, you didn’t want to make the investment because of the weak commodity outlook. There was less of a need to invest.

A couple of things happened we didn’t anticipate. The commodity fell further and faster than we anticipated—from $90 to $45/bbl. But we also never anticipated that, if oil fell that far, we would still have investments in our portfolio we would want to make. Now, because of the quality of our assets, lower costs and the tremendous innovations we’ve made, we’re in a $45 to $50/bbl oil environment, and we have tons in our portfolio where we would like to invest. That’s caused us to rethink our hedging. We’re layering in hedges with the aim of gradually becoming about 50% hedged over a couple of years.

Investor What’s your best guess for oil and gas a year out from here, in late 2016?

Jorden I’m guessing $65/bbl for oil and $2.75/Mcf for gas.