Operator Spotlight
Goodrich Petroleum president and COO details company’s plans
Confidence in gas prices and low service costs solidify the Haynesville E&P’s 2021 operations.
Brian Walzel, Senior Editor


hile the oil and gas industry might be hard-pressed to find many bright spots in 2020, the recovery of natural gas prices, and subsequently the role of gas producers, can be one of them. Among those that are riding the natural gas wave is Goodrich Petroleum. Goodrich, primarily focused on the Haynesville Shale, produces 138,000 Mcfe/d largely from its approximate 24,000 net Haynesville acres. Historically low service costs and stable Henry Hub price points are allowing Goodrich to set its goals on top-tier growth and the potential for free cash flow in 2021.

Goodrich President and COO Robert Turnham recently provided an exclusive interview with E&P Plus where he discussed in more detail the company’s plans for the remainder of the year and into 2021. He also touched on the company’s well completion strategy and how to position itself amid volatile times in the oil and gas industry.

E&P Plus: What is Goodrich’s plan for the coming year in terms of spending?

Turnham: Gas prices have moved up dramatically, and so I think it’s likely that we’ll actually spend more money in 2021 than we spend in 2020. The margins are actually as good as we’ve ever seen in that basin, through a combination of better gas prices and much lower service costs. Based on what we’re seeing in the field, I think it’s likely that we spend more. We’ll continue to grow at a double-digit rate and generate a significant free cash flow that we’ll likely use to pay down debt initially and then ultimately start paying dividends at some point in the future.

Goodrich holds 240,000 net acres where it produces exclusively from the Haynesville Shale. (Source: Goodrich Petroleum)
E&P Plus: How might Goodrich deploy that capital next year?

Turnham: We’re not really an acquisition company. We’re really organic growth through the drill bit. All of our acreage is held by production, for the most part, in North Louisiana. We’re now drilling very predictable development wells, tying into existing facilities and selling that gas at a very good net back to Henry Hub. So it’s really just a matter of how much capital we want to spend that still yields a very good free cash flow yield. And then that will itself drive the growth in volumes. We won’t be setting out to grow for growth sakes. It’s really how much money [and] what are the economics associated with the wells? How much money do we want to spend that generates a very good free cash flow yield on the capital that we spend?

And so, whereas we spent $100 million last year drilling wells, we’ll spend about half of that in 2020. But we’ll be surging our production here in the fourth quarter. So as we enter 2021, we’ll be at very high rates of production and likely ramp up our activities as we head into 2021, and then sustain that growth throughout the year.

“Gas prices have moved up dramatically, and so I think it’s likely that we’ll actually spend more money in 2021 than we spend in 2020.”
—Robert Turnham, Goodrich Petroleum
Robert Turnham, Goodrich Petroleum
E&P Plus: What is your approach to your DUC inventory for the rest of this year and into next?

Turnham: We had at one time two rigs running. Then we kept one rig running but did not complete a series of wells just due to low prices. And we also have received extremely competitive frac bids that we, frankly, had not seen since the play has gone through the renaissance. We have prepared those DUCs to be fracked as we head into the fourth quarter, where we see the significant improvement in gas prices. So even though the third quarter will be down production volumes versus the second quarter, and the fourth quarter will be up significantly, we’ll pick the rig, if not two rigs, back up in January or perhaps late December so that we’re well into our program as we enter 2021. Then our plan would be to not create DUCs. It would just be completion in a normal time frame because gas prices obviously for next year are much higher.

E&P Plus: How do you evaluate completion designs in the current pricing environment?

Turnham: At a time where service costs are higher, you tend to look at how to cut corners. In this case, with prices being so low—and at the peak, we were probably spending more than a $100,000 per stage—we’re now less than $30,000 per stage. So we’ve gone the other direction. We have tightened our interval spacing to 100, maybe at most 125 feet per stage. And instead of just banking all of the savings from the reduction, we’re actually adding some stages, still seeing significant savings and well costs, but making better wells. If you look at our well performance versus our type curves and versus the industry, you’ll see that we’re probably as productive, if not the No. 1 productive company, per foot of lateral drilled. And it’s because we think we’ve gotten the sweet spot on how best to complete these wells.

Goodrich Petroleum has grown its gas production from 70,000 Mcfe/d in 2018 to 140,000 Mcfe/d this year. (Source: Goodrich Petroleum)
Goodrich Petroleum has grown its gas production from 70,000 Mcfe/d in 2018 to 140,000 Mcfe/d this year. (Source: Goodrich Petroleum)
E&P Plus: How do you approach your planning and activity for this type of environment—when it looks good now but considering how volatile things can be?

Turnham: So let’s talk about volatility and the necessity to hedge a portion of your volumes. We really believe in 40% to 70% of your projected volumes, locking in a price that gives you the insurance policy to go ahead and spend the money necessary to drill the number of wells that you want to drill. And you can’t get out ahead of yourself with long-term drilling contracts because of the volatility that you just described. Another scenario can happen. You can see better pricing or attractive prices, and therefore rig activity gets higher. Service costs start to creep up, which we would not be surprised to see. Usually anytime you see rates of return like you see on our [investor presentation] slides, that just cant last for very long, because guys are either going to put rigs to work or service costs are going to go up, such that you have good rates of return, but not exceptional rates of return.

Another thing that’s different now is just availability of capital and what investors are wanting to see. They’re not wanting to see you outspend. They want to see free cash flow, return of capital to shareholders either through dividends or pay down debt, such that the commodity prices do stay at favorable levels.

In addition to that, you have commercial banks that are becoming more conservative, [and] debt covenants are getting more conservative. So I think you throw all of that in a pot, and I think you have a recipe for better pricing [and] lower service costs.