EQT Corp (EQT) 2016 Q2 法說會逐字稿

Greetings and welcome to the EQT Corporation second-quarter, earnings conference call.

(Operator Instructions)

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.

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; Steven 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 1:30 PM today. The telephone number for the replay is 201-612-7415. The confirmation code is 13637693. The call will also be replayed for seven days on our website.

To remind you, the results of EQT Midstream Partners ticker, EQM, and EQT GP Holdings, ticker EQ GP, are consolidated in the EQT's results. Earlier this morning there was a separate, joint press release issued by EQM any EQ GP. The partnership will have a joint earnings conference call at 11:30 AM today, which requires that we take the last question of this call at 11:20 AM. The dial in number for that call is 201-689-7817.

In a moment Rob will summarize EQT's second-quarter 2016 results. Dave will discuss our increase in activity, and finally Steve will give a brief Utica update. Following the prepared remarks Dave, Steve, Randy, and Rob will all be available to answer your questions.

I'd like to remind you that today's call may contain certain forward-looking statements. You can find factors that could cause the Company's actual results to differ materially from these forward-looking statements, listed in today's press release under risk factors in the EQT's form 10-K for year ended December 31, 2015 as updated by any subsequent form 10-Q's which are on file at the SEC and available on our website.

Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's press release for important disclosures regarding such measures including reconciliations to the most comparable GAAP financial measures. I'd now like to turn the call over to Rob McNally.

Thanks Pat. Before reviewing second-quarter results I want to highlight our recent acreage acquisition from Statoil which close 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 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 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 noncontrolling interest in the second quarter of 2016. We currently forecast $77 million of net income attributable to noncontrolling interest for the third quarter 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 a record gathering volumes at Midstream. The second quarter was very straightforward so I'll keep my remarks brief. 1

EQT production continued to grow sales that produced 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 annum compared to 275 per annum in the second quarter of last year.

You'll find the detailed components of the price differences in the table of this morning's release. Net marketing revenues totaled $2.1 million in 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, were $60.3 million higher, quarter over quarter, including a $7.1 million legal reserve. DD&A, gathering, transmission of 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 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. 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 on the balance sheet, which excludes cash on hand EQM and EQ GP.

We currently forecast approximately $750 million of operating cash flow for 2016 at EQT which includes approximately $150 million of distributions from EQ GP. WIth that I will turn the call over to Dave.

Thank you, Rob. My comments today are focused on updates to thoughts we shared during Aprils 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 700/800 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 of oil directed rigs accounting for that small overall growth. If one assumes, as we do, a 9 to 12 month lag between a rig arriving on site and gas blowing 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 US gas production is about 2.6 Bcf per day lower than the February peak. Though there's still noise in the system due to [ducts] and other factors, it seems reasonable to conclude that we're seeing the impact of activity reductions that occurred throughout 2015. The further sharp reductions in activity, versus 9 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, let's just say 2017 through 2021, from a low of $2.63 per MMBTU in February, to a current level of just over $3.00. 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 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 mid-west markets. While we always planned on an OBC 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 prospect, 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 [frugal] conclusion that the inevitable overshoot of equilibrium prices will be followed by the equally inevitable overreaction 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 occur 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 are starting to get 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 to 760 Bcfe to a new estimate of roughly 800 to 810 Bcfe. We will refine those estimates later this year. And with that, I will turn the call over to Steve 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 to $14 million per well and to achieve consistent well results with the 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 the shipment well in Greene County. Shipment was fracked with ceramic proppant versus the previous two wells that were fracked with sand. The IP showed improvement over the previous two Utica wells, the Pettit and Big 190 wells. Our preliminary estimate is that the shipment EUR will be between 2 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 shipment 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 with develop mode to be between $12 million and $13 million.

We continue to approach the Utica as an explanation 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 fracking the [West] Run well in Greene County as we are again utilizing ceramic proppant on this well. We expect to turn West Run in line in August and half the West Run we plan to move back to West Virginia to drill the Big 177 well in Wetzel County.

We talked before spudding 5 to 10 wells this year and given a one by one nature of our program and a desire not to get ahead of the data we expect to end up closer to five 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.

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

Thank you, sir.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning, guys.

Just a question for Steve or Dave: just your thoughts you put the new on -- in the prepared comments you talked about obviously adding in the wells. I'm a little surprised to see about the wells potentially being added in Upper Devonian. How you came about the rationale adding there versus just purely more activity in the Marcellus and Utica?

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 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 an 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 a play. If we don't codevelop 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 foregoing 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.

And Steve, I assume takeaway find in upper or that incremental Marcellus

Yes, there is takeaway capacity for all these wells.

Okay and then just lastly -- how you guys think about M&A right now? Anything you're still looking that is still in that designated area? If you -- maybe just a little color on M&A out there, Dave? For you or Steve.

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

Very good. Thank you.

Holly Stewart, Scotia Howard Weil.

Good morning, gentlemen. Just a couple quick ones.

You mentioned on the flat CapEx and increased activity at lower well costs, you have new numbers to give out this morning?

Yes, the Marcellus well will come in at $5.7 million, and we're publishing a new updated annuals presentation that will show you the new numbers.

Okay; and that's -- that's down from the $6.3 million, if I remember right?

That's right

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?

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

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 appellation prices did relatively well versus NYMEX. So are there any one-offs during the quarter and then maybe some comments on 3Q expectations?

Well, Holly, as far as the base, some of the recoveries end up in that net marketing line item and not 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 right in line. Again, our guidance for the rest of the year is based on our mark-to-market of our -- 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

Okay, and then 3Q the basis is a bit wide, but there's a lot of maintenance going on, on reqs and Transco I'm assuming that's just rerouting

Yes; the summer's always tougher than the full year so -- you're, right it's maintenance is the main factor.

Okay

Except we'd expect to still start to see some of the OBC impacts by the time we are reporting on fourth quarter or full year

Okay, great. Thanks, Dave.

Michael Hall, Heikkinen.

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 or characterize the economics in Greene relative to the other counties in what you call core?

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 are roughly 20% of our acreage at developed. So, 1/5 of it is developed, 4/5 remains undeveloped, so still have a pretty good runway in that high-quality area.

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

I don't have the specific numbers, it's probably a little more developed than that average, but not a lot -- maybe 30% developed. I don't have -- that's a guess, so I don't have that specific number in front of me.

Okay. And then the only other one on my end: I'm just curious, 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? Meaning marking to markets and NYMEX how much of that drove the --?

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

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

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.

Thank you, Adam, and thank you all for participating in today's call. And hopefully we'll talk to you next quarter. Thank you.

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