EQT Corporation
Q2 2016 Earnings Call Transcript

Published: 28 Jul 2016

[Operator:]

Greetings, and welcome to the EQT Corporation Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Patrick Kane, Chief Investor Relations Officer. Thank you. You may begin.

[Patrick J. Kane:]

Thanks, Adam. Good morning, everyone, and thank you for participating in EQT Corporation's conference call. With me today are Dave Porges, Chief Executive Officer; Steve Schlotterbeck, President of EQT and President of Exploration and Production; Randy Crawford, Senior Vice President of EQT and President of Midstream and Commercial; and Rob McNally, Senior Vice President and Chief Financial Officer. This call will be replayed for a seven-day period beginning at approximately 1

[Robert J. McNally:]

Thanks, Pat. Before reviewing second quarter results, I want to highlight our recent acreage acquisition from Statoil, which closed on July 8. In connection with the acquisition, on May 6, we completed an approximately $800 million common stock offering. A portion of the proceeds were used to fund the acquisition of 62,500 net Marcellus acres and 53,000 net Utica acres, primarily in Wetzel, Tyler, and Harrison Counties of West Virginia, for $407 million. The acquired acres include current natural gas production of approximately 50 million per day which will add about 7 Bcf to our sales volume during the second half of the year. The acquisition also includes approximately 500 undeveloped locations. Much of this acreage is contiguous with EQT's existing development area. I will now provide a brief overview of the second quarter results. As you read in the press release this morning, EQT announced second quarter 2016 adjusted loss per diluted share of $0.35, down from an adjusted loss of $0.06 in the second quarter of 2015. Adjusted operating cash flow attributable to EQT also decreased by $32.7 million to $113.8 million for the quarter. During the quarter, we terminated the remaining vestiges of our defined benefit pension plan. As a result, we've recognized a loss of $9.4 million to earnings, $7.7 million of which are attributable to Midstream. In connection with the purchase of annuities, we made a cash payment of $5.4 million to fully fund the plan. As a reminder, EQT Midstream Partners and EQT GP Holdings results are consolidated in EQT Corporation's results. EQT recorded $77.8 million of net income attributable to non-controlling interests in the second quarter of 2016. We currently forecast $77 million of net income attributable to non-controlling interests for the third quarter of 2016 and $320 million for the full year, assuming the midpoints of EQM's guidance. The high-level story for the second quarter was strong volume growth in a lower commodity price environment. We had another very solid operational quarter, including record produced natural gas sales and record gathering volumes at Midstream. The second quarter was very straightforward, so I'll keep my remarks brief. EQT Production continued to grow sales and produce natural gas. Production sales volume of 184.5 Bcf in the recently completed quarter was 26% higher than the second quarter of 2015. As discussed, the lower average realized price more than offset the volume growth. The average realized price at EQT Production was $2.11 per M compared to $2.75 per M in the second quarter of last year. You will find the detailed components of the price differences in the table in this morning's release. Net marketing revenues totaled $2.1 million in the second quarter of 2016, $7.7 million lower than the same quarter last year due to incremental capacity costs in 2016. Total operating expenses at EQT Production were $516 million or $60.3 million higher quarter-over-quarter, including a $7.1 million legal reserve. DD&A, gathering, transmission, and processing expenses and production taxes were all higher consistent with the significant production growth, although exploration expenses were lower for the quarter. Moving on to the Midstream business, operating income was $124.5 million, up 15% over the second quarter of 2015. Operating revenue was $214.3 million, $21.9 million than the second quarter of 2015 as a result of higher Marcellus volumes. Total operating expenses at Midstream were $89.8 million, $5.5 million higher over the same period last year, including the pension charge. On a per-unit basis, gathering and compression expenses were down 23% as a result of volumes growing faster than expenses. And then, finally, our standard liquidity update, we closed the quarter in a great liquidity position, with zero short-term debt outstanding under EQT's $1.5 billion unsecured revolver and $2.2 billion of cash in the balance sheet, which excludes cash on hand at EQM and EQGP. We currently forecast approximately $750 million of operating cash flow for 2016 at EQT, which includes approximately $150 million of distributions from EQGP. With that, I will turn the call over to Dave.

[David L. Porges:]

Thank you, Rob. My comments today are focused on updates to thoughts we shared during April's call regarding the macro environment, first, regarding rig count as a leading indicator of production. At that time, there were 174 gas-equivalent rigs down from the 700 to 800 level that prevailed from mid-2012 through the end of 2014. Since that April call, the gas-equivalent rig count has stabilized. It is up 4% since then, though the gas-directed count itself is exactly what it was back then with an increase in oil-directed rigs accounting for that small overall growth. If one assumes, as we do, a nine to 12 month lag between a rig arriving on site and gas flowing through a meter, the relevant relationship is that the current gas-equivalent rig count is down 47% versus nine months ago and 53% versus one year ago. That leads to the impact of this on natural gas supply. In April, we were not yet sure we were seeing a decrease versus just noise, but July U.S. gas production is about 2.6 Bcf per day lower than the February peak. Though there is still noise in the system due to DUCs and other factors, it seems reasonable to conclude that we are seeing the impact of activity reductions that occurred throughout 2015. The further sharp reductions in activity versus nine to 12 months ago are not yet showing up in these already lower production numbers. Still, the reductions we have seen, among other factors, have helped lift natural gas prices for the five-year strip, that is to say, 2017 through 2021, from a low of $2.63 per MMBtu in February, to a current level of just over $3. This price is still below our estimated equilibrium price of about $3.25 to $3.50 per MMBtu, however, these somewhat higher prices, especially in the context of our expectation of further supply declines, have caused us to conclude that this is a good time to begin the process of restoring our pace of development, adding 63 incremental wells to our 2016 drilling program. Given our capital strength and the fact that we have not had to make dramatic reductions in staff, we are well positioned to take advantage of the low service costs currently available to us. Another benefit of beginning this process now is that we have incremental takeaway capacity scheduled to come online in the fourth quarter this year, including 100 million cubic feet per day to the Gulf Coast with the TETCO Gulf Markets project and 650 million cubic feet per day on EQM's Ohio Valley Connector, which gets us to our REX capacity and ultimately to Midwest markets. While we always planned on an OVC in-service date before year-end 2016, the impending reality of that pipe becoming operational certainly adds confidence to a development increase that will result in incremental 2017 sales volumes. We are getting in front of a broader industry ramp-up, which we expect when gas prices improve further. We are focusing on our better prospects, not returning to the Huron or to lesser Marcellus areas, for example, as our belief that the price recovery will continue is moderated by our somewhat rueful conclusion that the inevitable overshoot of equilibrium prices will be followed by the equally inevitable overreaction in our industry, though we do not think the industry overreaction will be as pronounced as it was a few years ago, since there is likely to be more skepticism about the enduring nature of too much of an upward move in price. We still think the best place to position ourselves is to be amongst those companies that are moving a little bit earlier in the cycle in both directions. As a final note, while we are adding to the number of wells that we will spud in 2016, our CapEx forecast is unchanged. As you know, nearly 75% of the cost per well is for well completion. The majority of these incremental wells will be completed in 2017, so the CapEx related to completions will mostly be included in next year's CapEx budget. As for the CapEx that these new wells will incur in 2016, this increase is fully offset by the impact of lower service costs and improved drilling and completion efficiencies in the first half of 2016. For those of you who are starting to get a better feel for 2017 numbers, our preliminary estimate is that this increase in activity will cause our 2017 sales volumes to increase from the prior estimate of 750 Bcfe to 760 Bcfe to a new estimate of roughly 800 Bcfe to 810 Bcfe. We will refine those estimates later this year. And with that, I will turn the call over to Steve Schlotterbeck.

[Steven T. Schlotterbeck:]

Thank you, Dave. My focus today is to provide an update on our deep Utica program. Our two objectives for 2016 were to get costs per well down to a target range of between $12.5 million and $14 million per well and to achieve consistent well results with EURs of approximately 3.5 Bcf per thousand feet. If we can achieve both, returns will be as good or better than our core Marcellus wells. Since the last call, we have one new data point to talk about. In June, we turned-in-line to Shipman well in Greene County. Shipman was fraced with ceramic proppant versus the previous two wells that were fraced with sand. The IP showed improvement over the previous two Utica wells, the Pettit and BIG 190. Our preliminary estimate is that the Shipman EUR will be between 2 Bcf per thousand feet and 3 Bcf per thousand feet which shows improvement from the Pettit and BIG 190. On the cost side, we've also made progress as the Shipman well came in at approximately $14 million. We are pleased with our cost reductions thus far and see additional opportunities to further lower these costs. We are now estimating the costs per well in development mode to be between $12 million and $13 million. We continue to approach the Utica as an exploration project, trying various techniques, reviewing results, repeating what worked, and trying new things in our effort to improve results, both on recoveries and costs. We are currently fracing the West Run well in Greene County and we are again utilizing ceramic proppant on this well. We expect to turn West Run in line in August. And after West Run, we plan to move back to West Virginia to drill the BIG 177 well in Wetzel County. We talked before about spudding 5 wells to 10 wells this year. And given the one-by-one nature of our program and our desire not get ahead of the data, we expect to end up closer to 5 wells for 2016. We will continue to provide quarterly updates on our progress in the Deep Utica. And I'll now turn the call over to Pat Kane.

[Patrick J. Kane:]

Thank you, Steve. Adam, please open the call up for questions.

[Operator:]

Thank you, sir, and thank you, ladies and gentlemen. We will now be conducting our question-and-answer session. One moment while we poll for questions. Our first question comes from the line of Neal Dingmann from SunTrust. Please go ahead.

[Neal D. Dingmann:]

Morning, guys. Just a question for Steve or Dave. Just your thoughts, you put the new – in the prepared comments you talked about obviously adding the wells. I'm a little surprised to see that the wells added, potentially been added in the Upper Devonian. How you think about adding – well, how you came about sort of the rationale of adding there versus just purely more activity in the Marcellus and Utica?

[Steven T. Schlotterbeck:]

Hey, Neal. There is a number of factors that went into that decision. And a few of those are, since we discontinued the program about this time last year, we've brought on 38 additional Upper Devonian wells that had been spud by that time. And based on the results we're seeing, our type curve is now 18% higher on a EUR per foot basis. So the economics of Upper Devonian have improved. That's combined with approximately 14% lower well costs. And I would remind you that our view of the Upper Devonian is, it's basically a use it or lose it play. If we don't co-develop it at roughly the same time as the Marcellus, we think that reserve will effectively be lost. So, when we look at the economics on the development of our resource base aspect versus just well-by-well economics, if we factor in these long lateral economic Upper Devonian wells and defer additional Marcellus wells for a time to make room for the Upper Devonian, we generate a lot more NPV versus drilling all Marcellus and forgoing the Upper Devonian forever. And I guess the bottom-line is the individual well returns for all of these Upper Devonian wells are well above our cost of capital. So they're economic opportunities that otherwise would be lost if we don't capture them now.

[Neal D. Dingmann:]

And, Steve, I assume takeaway fine in Upper or that in incremental Marcellus.

[Steven T. Schlotterbeck:]

Yes, yes. There's takeaway capacity for all of these wells.

[Neal D. Dingmann:]

Okay. And then just lastly, just how you guys think about M&A right now. Just anything you're still looking is still in that designated area, if you – maybe just a little color on M&A out there, Dave, for you, or Steve?

[David L. Porges:]

Yeah. I don't know if we've got any further color we'd like to highlight. I mean I guess my current topic is basis, and frankly we're still just looking at Marcellus, Utica, the focus area is still that rectangle we put out, et cetera. As you're aware, since the last call, of course, we did announce and closeout a deal and I guess you're aware that there are a couple others that we did get involved in the process but other folks wound up making those acquisitions.

[Neal D. Dingmann:]

Very good. Thank you, all.

[David L. Porges:]

Great. Thanks, Neal.

[Operator:]

Thank you. Our next question comes from the line of Holly Stewart from Scotia Howard Weil. Please, go ahead.

[Holly Barrett Stewart:]

Good morning, gentlemen. Just a couple of quick ones, you mentioned on the flat CapEx and increased activity at lower well costs. Do you have new numbers to give out this morning?

[Patrick J. Kane:]

Yeah. The Marcellus well will come in at $5.7 million. And we're publishing a new updated analyst presentation that will show you the new numbers.

[Holly Barrett Stewart:]

Okay.

[Patrick J. Kane:]

The $5.7 million on the Marcellus.

[Holly Barrett Stewart:]

And that's down from the $6.3 million, if I remember right?

[Patrick J. Kane:]

That's right.

[Holly Barrett Stewart:]

Okay. Great. And then maybe, Steve, on the 33 more Marcellus wells, where are those primarily located? And is any of that on the newly acquired acreage?

[Steven T. Schlotterbeck:]

No. Those 33 wells are all in Pennsylvania. It'd be Greene County, Eastern Washington County, and Southern Allegheny County. And none of those are on the new Statoil acreage at this time.

[Holly Barrett Stewart:]

Okay, great. And then maybe just one on basis, you came in a little bit wider than we were anticipating for the quarter, just given that I think Appalachian prices did relatively well versus NYMEX. So is there, I guess, any one-offs during the quarter and then maybe some comment on 3Q expectations?

[Patrick J. Kane:]

Well, Holly, as far as the basis, some of the recoveries end up in that net marketing line item and not...

[Holly Barrett Stewart:]

Yep.

[Patrick J. Kane:]

...end up in the differential line. So the net marketing was a little bit above our guidance and the differential line was a little bit below our guidance. But if you look at the two together, we're kind of right in line.

[Holly Barrett Stewart:]

Okay.

[Patrick J. Kane:]

So, again, our guidance for the rest of the year is based on our mark-to-market of our – and we do have some fixed price sales which locks in the basis at the time. And also, basically, we're marketing our book to the forward curve for all of our sales points.

[Holly Barrett Stewart:]

Okay, Pat. And then 3Q I guess the basis is a bit wide. But there's a lot of maintenance going on, on REX and Transco. I'm assuming that's just sort of rerouting?

[Patrick J. Kane:]

Yeah. The summer's always tougher than the full year. So you're right. Maintenance is the main factor.

[Holly Barrett Stewart:]

Okay.

[David L. Porges:]

And we'd expect you'll start to see some of the OVC impacts by the time we are reporting on fourth quarter our full year numbers.

[Holly Barrett Stewart:]

Okay. Great. Thanks, Dave.

[Operator:]

Thank you. Our next question comes from the line of Michael Hall from Heikkinen. Please, go ahead.

[Michael Anthony Hall:]

Thanks. Heikkinen Energy. Just curious as it relates to Greene County specifically, what's the remaining development inventory look like in Greene County? And how would you rank the – or characterize the economics in Greene relative to the other counties in, what you call, core?

[Steven T. Schlotterbeck:]

Well, regarding the economics, Greene is one of our better areas, but that Southern Allegheny, Eastern Washington, Greene and Northern Wetzel County area are all fairly similar in returns and that's kind of the core of the core. Overall, in the core, I think we're roughly 20% of our acreage is developed, so one-fifth of it's developed, four-fifth remains undeveloped, so still have a pretty good runway in that high-quality area.

[Michael Anthony Hall:]

Okay. That's helpful. And I guess specific to Greene, how much would you say that's developed? Is it similar to that 20%?

[Steven T. Schlotterbeck:]

I don't have the specific number. It's probably a little more developed than that average, but not a lot, maybe 30% developed.

[Michael Anthony Hall:]

Okay.

[Steven T. Schlotterbeck:]

I don't have that – that's a guess, so I don't have that specific number in front of me.

[Michael Anthony Hall:]

Okay. And then I guess the only other one on my end, I'm just curious, can you – do you all have how much of the cash flow – the increase in cash flow guidance, how much of that was just price related versus other volume or cost related?

[Robert J. McNally:]

It's primarily...

[Michael Anthony Hall:]

Meaning marking to markets to (22

[Robert J. McNally:]

It's primarily price-driven. I mean there's some volume increase, which we explained in the guidance, but the bigger part of the move for cash flow is price.

[Michael Anthony Hall:]

Okay. Just wanted to make sure I was thinking about it right. Thank you. That's all I have. Thanks.

[Operator:]

Thank you. Ladies and gentlemen, we have no further questions in queue at this time. I would like to turn the floor back over to management for closing comments.

[Patrick J. Kane:]

Thank you, Adam, and thank you, all, for participating in today's call. And, hopefully, we'll talk to you next month – or next quarter. I'm sorry. Thank you.

[Operator:]

Thank you, ladies and gentlemen. This does conclude our teleconference for today. You may now disconnect your lines at this time. Thank you for your participation, and have a wonderful day.