Amidst speculation of a joint venture, equity raise or a straight-out corporate sale to fund development of its 790,000 acres in the Marcellus shale, Fort Worth, Texas-based Range Resources Corp. instead made a bold move this past April and sold off its legacy Barnett shale holdings to fund the gap. Along with its undrawn credit facility, the company now has the powder to tackle the Marcellus head on.

As a whole, Range’s production averaged 537.2 million cubic feet equivalent (MMcfe) per day in the third quarter (76% natural gas), 15,429 barrels per day of natural gas liquids (17%) and 5,680 barrels per day of oil (7%). In addition to its featured wet-gas Marcellus holdings in southwestern Pennsylvania and dry-gas development in the northeastern part of the state, Range is also expanding operations into liquids-rich plays in the Midcontinent and the Permian Basin. Year-over-year, the company’s liquids production increased 12%, while natural gas production grew 5%.

Chairman and chief executive John Pinkerton, a Texas Christian University grad and long-time steadfast figure in Fort Worth, is on the cusp of handing off the CEO reins to current president Jeff Ventura at year-end. Pinker-ton has been affiliated with Range since 1988 and as chief executive since 1992. Now set to become executive chairman, he visited with Oil and Gas Investor to share his insights into the vast opportunities and obstacles in the Marcellus shale play, and the lingering question of whether Range is ripe for a corporate takeout by an industry major.

Range Resources Corp. chairman and chief executive John Pinkerton says, “We think we can develop 700,000 acres in the Marcellus without having to do a big joint venture or sell a lot of equity.”

Investor: How do the proceeds from the Bar-nett sale translate to your Marcellus program?

Pinkerton: Several things drove the Barnett sale. One, as the Marcellus and some of our other plays like the St. Louis and Mississippi Lime started looking better and better and the risk went down, the economics of those plays looked better than the Barnett. We made a decision to sell the Barnett to reinvest those proceeds into what we thought were higher-quality and higher-return plays.

Also, there was a lot of speculation in the market in terms of how we were going to fund all this Marcellus drilling. There was some trepidation that we were going to have to do a joint venture or do a big equity issuance or a combination. As we modeled the play, it became clear to us there was another way to finance it without having to sell off the upside in a joint venture or dilute ourselves in an equity raise. That was to sell other properties to help fund the growth.

That was a good decision for our shareholders, and it has worked out better than I thought. We replaced 20% of our total production from the Barnett in five months, which is amazing. We’re taking that money and using some of it to drill more Marcellus, St. Louis and Mississippian wells that are lower cost to drill and complete. It’s going to drive down our LOE (lease operating expense) per Mcfe and make us more profitable.

Investor: Was a joint venture entirely out of the question?

Pinkerton: Call it what you want, but joint ventures are just asset sales. You’re selling off part of your assets in exchange for cash to help fund your development. Instead of selling our best asset through a joint venture, it made more sense to sell our lower-quality assets. I want more Marcellus, not less. We want to hold onto every high-quality Marcellus acre we can get our hands on, because the returns are so good.

Investor: Do you have the capital you need to execute your plan?

Pinkerton: We do. We did the Barnett deal at $900 million. That capital allowed us to completely pay off our bank debt and have about $300 million in the bank. We still have our $2-billion credit facility when we use up that excess cash. We’ll just eat into the credit line a little as we drill up.

Our original goal was to be cash-flow positive by the end of 2013. Now, with gas prices down a little, we’re not quite sure we’ll get there. But we’ve got such a good balance sheet that, whether it’s third-quarter 2013 or the sec- ond quarter of 2014, it really doesn’t matter to me. What matters to me is we can execute our capital program knowing we don’t have to dilute our shareholders through an equity raise or a joint venture.

We can slow down if we so choose. It will take us longer to hold the acreage, and we may have to release some of it.

Investor: What became of your Barnett team?

Pinkerton: We took the Barnett team and split up the Marcellus. That team is now running the entire drilling operation related to the development plan in our 200,000-plus acres in the northeastern part of the Marcellus. That’s allowed the other Marcellus team to focus on the southwest. Instead of having one team developing the Marcellus, we now have two. Our view is to put your capital on your best people and your best project.

Investor: Under what terms might Range consider a sale similar to the Petrohawk Energy deal?

Pinkerton: There’s a big difference between Petrohawk and Range. First, we think we can develop 700,000 acres in the Marcellus without having to do a big JV or sell a lot of equity. Petrohawk sold significant chunks of equity along the way.

Also, most people believe the economics in the Marcellus are superior to the Haynesville and therefore have greater capital efficiency. Because we were a leader in the Marcellus, a lot of our leases are 10 years, and the shorter ones are five years. In the Haynesville, it got so competitive a lot of people were signing one-, two- and three-year leases. The Marcellus has better returns than the Haynesville. It’s just a whole different play. Even with these low gas prices we can still make good money in the Marcellus.

And the Marcellus is unique in that it is not a single-formation play. We’ve got the Upper Devonian shales above the Marcellus that look quite attractive. We’ve drilled the first horizontal Upper Devonian shale well; it was encouraging. And we’ve drilled a horizontal Utica well that was encouraging as well. We have less than 5% of our Marcellus acreage classified as proved reserves. We’re just in the infancy of the Marcellus, and in the upper Devonian and Utica, which we think covers a substantial amount of our acreage.

Most of the economics in the Marcellus have been done on 80-acre spacing. Some of the Barnett was productive on 10-acre spacing. Parts of the Haynesville have been productive on much shallower spacing than 80 acres. You’ve got a big upside with downspacing in the Marcellus.

It’s a much different analysis for Range than for Petrohawk. It’s just way, way too early in my opinion. There’s too much to be developed and too many unknowns. Our job is to develop this out and, instead of letting somebody else’s shareholders get the benefit, it’s our job to make sure Range’s shareholders get the benefit.

Investor: Do you think any operational risks remain in the Marcellus, or are we in development mode?

Pinkerton: In the southwestern part of the play we believe we’ve got over 550,000 acres essentially derisked. That doesn’t mean they are proved reserves, it just makes them much lower risk in our view. Now it’s just a question of developing it out. The question then becomes what it is ultimately going to cost.

In the northeast it’s not that way, just because we haven’t drilled as much up there. It will take some time.

Investor: Is the Marcellus dry-gas area economic at current gas prices?

Pinkerton: It’s not as economic as the wet gas, but it’s still economic. We wouldn’t be drilling it if it weren’t economic. Everything we’re doing is economic at today’s price.

However, we’d rather develop and sell that gas in a higher-price environment. As the economy returns and gas demand goes up, the price will go up. Clearly, the future strip suggests that. It’s just a matter of balancing, holding acreage and proving up the acreage.

We’ve got years and years of drilling to do. We’ve got about 790,000 acres total, in the “fairway,” and our plan is to hold about 700,000. By the end of this year we ought to have about half of our acreage held by production. Each year thereafter we’ll hold another 10% to 15%. In four to five years, we should have all of that acreage held.

Investor: Your estimated ultimate recoveries (EURs) per well look to be on par with other operators, but your lateral lengths and number of stages appear to be less. Why?

Pinkerton: We’re experimenting in terms of lateral lengths. We were drilling such good wells and getting such good economics with 2,500- to 3,000-foot laterals that we decided, in the low-price environment that we’re in, to be very conscious of the capital requirement. Our theory was to simplify the process so we could get as much bang for our buck in terms of our wells. Obviously, shorter laterals mean you can drill more wells, so therefore we hold more acreage.

We are drilling longer lateral lengths in some areas. Every area takes work to figure out and to maximize the economics. In some plays across America you’ve got to drill longer laterals to make them economic. The Marcellus isn’t that way.

Investor: Would the laterals extend out when you go to infill drilling to capture more resource?

Pinkerton: It all depends. When you drill longer-lateral wells, you open up more of the rock, but each of those sets of perforations roughly every 300 feet has got to compete for hydrocarbons and pressure. There is a point of diminishing returns. The question is where is that point?

Investor: Have you found it?

Pinkerton: We are drilling some great wells, but in this price environment, my theory is to focus on trying to drive returns. When gas prices are low, the key is to simplify things and tend to your knitting.

The Marcellus is such an attractive play because you can make good money in a low-price environment if you watch your nickels. Focus on driving down the cost.

To the extent that every well is a Mona Lisa—different lateral lengths, different stages, different number of fracs per stage—all that costs money. If you can standardize it and do the same thing over and over again, it reduces your costs. When gas prices increase, then we’ll have more money to do more science projects.

Investor: Has take-away capacity affected your operations? Where do you stand now?

Pinkerton: Like in any big play, it takes a while for the infrastructure to catch up. We’re at the point now that other than the normal gathering system and compression after drilling a well, we’re in good shape. In the southwestern part of the play, MarkWest has just added 200-MMcf-per-day of capacity to its gas-processing plant in Houston, Pennsylvania, so we can sell everything we can produce. Now we’re building out the gathering system and putting in the compression.

In the northern part of the play, in Lycoming County, we’ve got a similar arrangement with PVR (Penn Virginia Resources Partners) on a pipeline. When that is done between now and the end of the year, we’ll be connecting 27 new wells, which will have a significant impact on production at year-end.

By year-end we will have far more takeaway capacity than production. We’ll have about 600 MMcf per day of capacity. Our exit rate target for the end of the year is 400 MMcf.

Investor: Have Marcellus operators followed infrastructure rather than best geology? Is there the potential that some of the best locations might not have been drilled yet?

Pinkerton: It’s hard to say. There are some areas in the play that we stayed away from because we thought the infrastructure was going to be difficult. We’d rather go where you can get high-quality production and reserves with reasonable infrastructure. Those are the first places we leased.

There are some areas that haven’t been drilled yet that still could be pretty good. It’s a huge play, covering 50 million acres. The central part of the play probably has the toughest infrastructure issues vs. the northeast and the southwest. But even there companies are building infrastructure. It just takes time.

Investor: What’s your response to reports that the industry may be overstating shale-gas reserves?

Pinkerton: The jury is still out on some of these plays, but the best thing to do is look at the shale plays that are already in place. Clearly, the Barnett and the Haynesville are the two largest-producing gas fields in the U.S. It tells you there is a lot of gas there, and these are really important plays.

Shale-gas production is now 25% of all production in the U.S. The Marcellus is now producing over 3 billion cubic feet per day. The proof is in the production. The production in these fields is fabulous, and in a relatively short period of time.

There is an enormous amount of production history in the Barnett and an enormous amount in the Haynesville. We’ve got horizontal wells now in the Marcellus with three or four years’ worth of production history. It just takes a little time before people get comfortable.

Investor: What does your ethane sales contract with Nova Chemicals mean for Range?

Pinkerton: Ethane is a big part of the wet-gas area of the Marcellus. Right now we are just leaving the ethanes in the gas stream and selling them as gas. Obviously, they have higher value than that.

For the deal with Nova, we’re pricing the ethane slightly above—a nickel or a dime—the Appalachia gas index. It’s not a huge uplift in terms of overall economics.

What it does do is give us surety that we will be able to continue to ramp up our production irrespective of what comes out in terms of the pipelines. At some point in time when the production gets up, they are going to start limiting the amount of ethane we can put into the gas stream.

The contract with Nova covers just a small portion of our ethane. As other ethane solutions come together, deals number two, three and four should be economically positive to our margins in terms of realizations.

Investor: Considering future Marcellus production, is export a viable option?

Pinkerton: Obviously, we’ve somewhat overwhelmed the current demand, at least in the U.S. There are two ways for it to catch up. One is to sell it locally in the U.S. The second is to export it internationally.

Dominion’s LNG terminal off the East Coast has put in a request to export gas. The one in Houston (Cheniere Energy’s facility) is doing the same thing. It’s going to happen, the question is when.

Investor: What do you think the Marcellus will look like in five years?

Pinkerton: Back in October of 2004 when we drilled the first well, we were just hoping we could make the play work and have it be special to us. We never thought it would be this big, and be so transformative not only to our company, but a lot of other companies.

It’s got huge potential. It’s in the best place to sell gas in the U.S. It could have an impact on energy policy across the U.S. and potentially the whole world. Amazing things do happen, and we feel blessed by that.

For more Q&A with John Pinkerton, see OilandGasInvestor.com?.