EQT Records $2.3 Billion Non-Cash Impairment Charge

EQT Corporation (ticker: EQT) reported a net loss of income attributable to EQT of $1,586 million, or $(5.99) per diluted earnings per share.

The net loss attributable to EQT for the first quarter of 2018 was impacted by an impairment charge of $2.3 billion associated with the Huron and Permian Plays, increases in other operating costs, lower gains on derivatives not designated as hedges and higher interest expense. According to EQT, this more than offset higher revenue from an 88% increase in sales volume, lower corporate income taxes, and higher pipeline and net marketing services revenue.

In Q1 2018, the company had average daily sales volumes of 3,967 MMcfe/d and capital expenditures in the quarter were $675 million.

Wells spud and turned-in-line

Wells drilled (spud)

• Q1 2018 average lateral lengths: Marcellus 14,000; Upper Devonian 16,800; Ohio Utica 11,700
• 2018 forecasted average lateral lengths: Marcellus 12,600; Upper Devonian 15,800; Ohio Utica 11,000

Wells turned-in-line (TIL)

• Q1 2018 average lateral lengths: Marcellus 7,900; Upper Devonian 11,300; Ohio Utica 10,000
• 2018 forecasted average lateral lengths: Marcellus 8,700; Upper Devonian 11,300; Ohio Utica 11,500

Permian assets sold

EQT entered into an agreement to sell its Permian Basin assets located in Texas for $64 million. The sale, expected to close by end of June 2018, will reduce the company’s 2018 production sales volume guidance by 5 Bcfe.

2018 guidance

The company projects total production sales volumes of 360-370 Bcfe for Q2 2018 and 1,520-1,550 Bcfe overall for 2018. As for total liquids sales volumes, the company expects 4,475-4,595 Mbbls for Q2 2018 and 17,200-17,800 Mbbls for 2018.

In the Marcellus/Utica, EQT expects to run 8-10 rigs, with 4-5 top-hole rigs and 9-11 frac crews.

Conference call Q&A excerpts

Q: Just wondering if you could maybe just elaborate a little bit on streamlining the spinoff transactions. Why did you choose this structure? And could this be step one of two? And I guess, my follow-up, is just thinking about at some point, are you contemplating a GP/LP simplification down the road?

SVP and CFO (of Rice Midstream Management LLC) Robert J. McNally: So the next step is going to be the spin of NewCo, and when we spin NewCo, it will still have this structure. We’ll have EQGP with EQM underneath and the IDR still in place.

So the ultimate decision on what happens with the IDR simplification and it will be up to the NewCo board of directors and management team. I would give you my opinion that that structure is probably not viable long-term in this market and so I think it’s something that we’ll start putting our minds to. But again, I would emphasize that it’s going to be a NewCo Board and management decision on the timing of any potential simplification.

Interim President and CEO David L. Porges: Back to what Rob had to say, I completely agree.

I think in Rob’s comments, he’s talked about a shelf life of IDRs, and that’s going to be one of our first priorities with NewCo and the management team and board to see what that timing is.

Q: Two small questions… one related to the restructuring, which is the EQM shares that EQT would be taking on, what is the long-term view on the sustainability of keeping EQM as part of the EQT structure?

And then if I could just follow up with regards the 20,000-foot technical limit on lateral lengths in the Marcellus. Can you just refresh us on any ongoing acreage acquisition spending that you think you would need to be able to increase the number of those types of wells in the portfolio?

McNally: On the EQM shares, our plan is that we will take all of our midstream assets, EQM and EQGP units, and that will be under NewCo or SpinCo. And that’s what will be spun out by September 30. And then at that point, EQT would no longer own any of the midstream interest.

In terms of the spending on acreage, the guidance that we’ve previously given still stands. We think that we’re going to spend somewhere between $100 million and $200 million a year for fill-ins and blocking up acreage and protecting leases.

Q: As you guys continue to push the technical limits of lateral lengths, I was just wondering about the types of completions that you’re using and how you are thinking about spacing between laterals, especially as you push on beyond 18,000 feet, does it change your spacing assumptions between wells? Can you just give us a little bit more color around that? Are you going from five wells per section to four or…?

SVP and President of E&P David E. Schlosser: I don’t think going longer changes our spacing assumptions, but I just think, in general, we’re leaning towards increasing spacing over time because that’s where the technology is pointing. I think we’re becoming more efficient with our fracturing technique, and we sort of know the boundaries of them.

And I think over time you’ll see our spacing probably increasing, which we think will ultimately result in lower development cost. So that’s why we’d do it, or development cost per Mcf. So that will be forefront on our thinking on that… and I wish we had sections here, but we don’t have them unfortunately. I would say that we are in the 750 to 800-foot spacing range right now. I think you’ll see the industry and us going more in the 1,000-foot range over time.