Greetings and welcome to the EQT Corporation Third Quarter Earnings Conference Call. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Patrick Kane, Chief Investor Relations Officer. Thank you. You may begin.

Thanks, Christine. 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 Robert McNally, Senior Vice President and Chief Financial Officer. This call will be replayed for a seven-day period beginning at approximately 1:30 PM Eastern Time today. The telephone number for the replay is 201-612-7415. The confirmation code is 13637697. 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 EQGP, are consolidated in EQT's results. Earlier this morning, there was a separate joint press release issued by EQM and EQGP. The partnerships will have a joint earnings conference call at 11:30 today, which requires that we take the last question at 11:20. The dial-in number for that call, if you're interested, is 201-689-7817. In a moment, Rob will summarize EQT's third quarter 2016 results, Dave will discuss his retirement announcement, and finally, Steve will give a brief operational update. Following the prepared remarks, Dave, Steve, Randy, Rob will all be available to answer your questions. I'd like to remind you that today's call may contain 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 and under Risk Factors in EQT's Form 10-K for the year ended December 31, 2015 as updated by any subsequent Form 10-Qs, 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 measure. And now, I'd like to turn the call over to Rob McNally.

Thanks, Pat. Before reviewing third quarter results, I want to highlight our recent acreage acquisitions. As a reminder on May 6, we completed an approximately $800 million common stock offering. At the time, a portion of the proceeds were used to fund the approximately $412 million Statoil acquisition with remaining proceeds to be used for another acquisition of similar size. On Tuesday, we announced the acquisition of approximately 60,000 net Marcellus acres, which also includes 39,300 net Utica acres for $683 million. These acquisitions are consistent with the equity raised and will be paid for using those proceeds plus the proceeds from the latest dropdown to EQM. The signing of the recently announced acquisitions, combined with the Statoil acquisition and a few smaller deals and leasing activity during the year, bring year-to-date committed investment in undeveloped acreage to approximately $1.2 billion and represent the most Marcellus under contract for acquisition by a single producer this year. These investments are consistent with our consolidation strategy and create value through purchasing undeveloped acreage while minimizing the amount paid for flowing production, which tends to be value neutral. This year alone, for every 1 acre developed, 19 acres have been acquired. Our core Marcellus acreage has increased by 143,000 net acres or 55%. And our undeveloped location inventory has increased to almost 3,700 locations. Much of this acreage is contiguous with EQT's existing development area. Therefore, the lateral lengths of 190 existing EQT locations can now be extended from approximately 3,000 feet to 6,000 feet on average. At a flat $2.50 realized gas price, the IRRs on these wells increased from approximately 9% to 37%. Effective October 1, EQT completed the final drop of Midstream assets to EQT Midstream Partners for $275 million. The drop included the Allegheny Valley Connector, a transmission and…

Great. Thank you, Rob. I only have about one topic in my remarks. I was going to talk about the Cubs but Pat Kane discouraged me from doing so. So my only topic today pertains to my announcement of my intention to retire as CEO early next year and transition at that time to the role of Executive Chairman. It has been my honor to serve as an executive officer of EQT Corporation for nearly 19 years, including being CEO since early 2010. When my tenure as CEO began, EQT was already a well-run, shareholder-value-focused company. However, it did seem appropriate to elevate the importance of our financial strategy for a period of time, and that was a central focus of my tenure. During these nearly seven years as CEO, we have created additional value via the creation of two new public entities, several transactions between EQT and those entities, sales of non-core assets and acquisitions of assets complementary to our core business. We also raised sufficient capital to fund our value accretive growth and maintained a strong credit position through a very difficult time in our industry. Along the way, we made a variety of commitments to our investors and I believe that the recently announced Midstream drop in upstream acquisitions honor the commitments that we made. That said, while financial strategy will always be important, it no longer needs to have the outsized role it had during much of my time as CEO. In a sense, therefore, I believe that my work here is done. On the personal side, as many of you are aware, I do have a variety of other interests so it's my family being first amongst them but various not-for-profit endeavors also being increasingly important to me. Even as we have achieved much of…

Thank you, Dave. Good morning, everyone. I want to start by saying what a great honor it's been to be chosen to succeed Dave as CEO of EQT Corporation, and I'm humbled to be entrusted with the responsibility to lead this great organization forward. EQT's future is bright, thanks to the transformative leadership of Dave Porges. His vision, financial acumen and leadership abilities have fundamentally changed EQT, positioning us at the forefront of energy development and keeping us well positioned to face future challenges and opportunities for years to come. EQT has endured one of the industry's most challenging periods of cyclical uncertainty, primarily because of our stringent focus on costs, our strong balance sheet and our uniquely integrated business structure. The combination of our outstanding upstream and midstream assets, together with strong financial management and operational nimbleness, will enable us to continue creating and delivering value for EQT shareholders. Maybe the most important reason I'm so confident in EQT's future is the strong and dedicated leadership of our board and executive team and the continued commitment of the most talented employees in the industry. This is an exciting time to be a part of this company and this industry and I'm excited to be a part of it. Now let's continue with the review of our recent core Marcellus acreage acquisitions and our current thoughts on our Deep Utica program. Starting with our Marcellus acreage acquisitions, as Rob mentioned, we announced the acquisition of an additional 60,000 core Marcellus acres this week. Year-to-date, we've added 143,000 core acres, including 63,000 from Statoil and 20,000 through smaller and leasing efforts during the year. More importantly is that since 2013, we've added 230,000 core Marcellus acres. We've completed 477 wells over this same time period, developing 44,000 acres. The net result…

Thank you, Steve. This concludes the comments portion of the call. Christine, could we please open the call up for questions?

Thank you. Thank you. Our first question comes from the line of Holly Stewart with Scotia Howard Weil. Please proceed with your question.

Good morning, gentlemen.

Good morning.

Let me be the first, I guess, to give my shout out to Dave. Dave, very many accomplishments over, I mean, certainly my 12 years in covering this stock. I'm not sure another company has changed in so many ways, so a much deserved retirement.

Thank you.

Maybe starting off, Steve, you were kind of running through that fast. Can you give me the – you said one rig may be dedicated next year. What was the amount of wells drilled?

Six to eight wells with that one rig.

Okay, great. And then maybe just following up on the three acquisitions that we've talked about for 2016, I know there's some Midstream contracts that you're sort of working through on the Statoil deal, but can you maybe just talk to us about how you're thinking of development there? And maybe priorities in terms of those properties.

Yeah, I think in terms of how we'll develop that, we'll incorporate that acreage into our land process and we will allocate capital based on the best returns available starting in our 2017 plan, which we'll talk about in December. But I will say one of the main drivers behind all these acquisitions is our desire to extend laterals. And part of that then requires us to go re-permit a lot of the existing locations to take advantage of those synergies. So there is a bit of a delay before we get immediate benefits from the acquisition, so it'll probably be mid-2017 before a significant portion of our development program is incorporating the new acreage. But we don't want to drill short laterals when we can take a few months and go back and re-permit and get the better economics. So you will start to see benefits from the acquisitions next year, but it'll probably be the back half of the year before we really get full speed ahead.

Great. That's helpful. And then maybe just one last one for me. It looks like this is the first time that you guys have stripped out the ethane volumes. Maybe just a little color here, has there been a shift in strategy on extracting ethane? Or how should we be thinking about that?

Hey, good morning, Holly. This is Randy. As I've said in the past with respect to ethane, we are opportunistic in extracting ethane and, to the extent that the opportunity presents itself that we can extract the ethane and sell it above the methane pricing, we're taking that opportunity and we have 10,000 barrels a day of capacity that will allow us that. So we broke that out to demonstrate that.

Okay, so don't necessarily think about this as sort of a go forward. It's sort of a one-off quarterly opportunity.

Well, no. It's basically on market conditions so as we extract the higher Btu gas, to the extent that it's in EQT's best interest to extract the ethane and sell it into the capacity, we'll do that. Otherwise, we'll sell it for methane prices and the market has, with the improvement in ethane recently, it's been a core part of our business to go ahead and extract the ethane to increase value to the shareholder.

Holly, I would just add that this capacity, the 10,000 barrel capacity Randy mentioned, came on in the second quarter.

Perfect, thank you. Understood. Thanks, guys.

Our next question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question. Brian Singer - Goldman Sachs & Co.: Thank you. Good morning.

Morning. Brian Singer - Goldman Sachs & Co.: And, Dave, congrats on your retirement and, Steve, congratulations on your new role here. The press release referenced the transition towards more operational drivers from financial drivers. I'm wanting to see if perhaps in that context, Steve could discuss perspective on the importance of integration and, Steve, how you view leverage versus liquidity versus outspending cash flow at the E&P and midstream level.

Yes, I guess first on the integration. At the current time, we think we generate significant benefits from the ability to work – the two businesses working together. I think we do have a view that over the long term, the benefits received from that versus the benefits of separation might be outweighed by separation. But I think certainly in the short term, we continue to think that the combination of the two businesses makes the most sense for our shareholders. The second question around leverage and liquidity and outspend, I think as you've seen through this downturn, we appreciate the value of a strong balance sheet. We've historically – I think it's really a legacy from our utility days but we've been a investment grade-rated company. I think we continued to view that as valuable. So I think you'll see continued focus on keeping our balance sheet strong. I think we have a number of levers available to us to fund an outspend if we think that's the prudent path forward, particularly our large stake in EQGP is available to us to sell down to fund an outspend. But I would say, generally speaking, to grow at competitive rates does typically require a bit of an outspend. So I would think that's likely in the future but all depends on what we think the economics of our opportunities are. So I think I'll leave it at that. Brian Singer - Goldman Sachs & Co.: That's great and very helpful. My second question's also somewhat strategic. You know, a year ago, maybe eight months ago we get a lot of questions on the potential for EQT to expand in Appalachia and you've done a couple of acquisitions that you've referred to here. And I wondered whether you think you're at the asset in size and scope that you think is reasonable going forward or whether we should expect Statoil continue to be active in considering further consolidation opportunities in the basin and, if so, what that market looks like?

Well, I think there's two ways to answer that. I guess first, as it pertains to size and scope, I think we feel very comfortable where we're at. We have a very deep inventory and the ability to grow at competitive rates for quite some time. So I think we're not going to be driven by a desire just to gain scale. That said, one of the biggest value-creating opportunities we see in Appalachia is the efficiencies we get from drilling longer laterals. So the acquisitions we've done to date are designed to allow us to drill longer laterals and get those efficiencies and drive the unit cost down. And to the extent that opportunities become available that fit our acreage well and allow us to gain those synergies, I think we'll continue to be interested. Subject to the comments I just made about liquidity and balance sheet strength, we're not going to stick our neck out to do that but if there are opportunities to continue to put large blocks of acreage together that allow us to drill longer laterals, then we would be interested in taking a look. Brian Singer - Goldman Sachs & Co.: Great. Thank you very much.

Our next question comes from the line of Arun Jayaram with JPMorgan. Please proceed with your question.

Thanks, gentlemen, and congratulations to you both. I wanted to start off perhaps, Steve, in talking about the acquisitions, obviously, it appears that one of the drivers was just increasing the ability to drill longer laterals, and we did note that this quarter your laterals were, at least on the Marcellus side, were pushing close to 9,000 feet. But from a geological basis, can you talk about the quality of this acreage relative to your current core in terms of gas in place, thoughts on potential EURs and how does this acreage that you've added in this deal, plus the Statoil deal, compare to what you have previously?

Oh, I think, yeah, we're very happy with the quality of the acreage in all three of these deals. Specifically, Statoil and Trans Energy are West Virginia-focused or all in West Virginia focused, or all in West Virginia. All very connected to the acreage we already have in Wetzel and Marion counties and Tyler County, and we think very consistent with the results we've seen down there, specifically because I think I'd seen a question or two about Marion County. I think there's been less drilling there and some of the competitor results may be a little bit less than a little bit further to the west. I can tell you we turned in line six wells in Marion County in April of this year, and all six are exceeding our type curve for northern West Virginia. So I don't know if that's a result of the acreage we have, and the Trans Energy acreage is directly connected to the acreage where those wells were, or if it's different completion techniques or exactly why, but as a result, we're very encouraged by that portion of Marion County, which I would imagine is probably where, if you were going to speculate on the acreage, that would be where the concerns might be. From the data we have, we're very excited about it.

And just from a lease expiration standpoint, could these deals cause you to maybe run faster a little bit just to make sure that you lock up the acreage? Or how does that influence your plans in 2017 and 2018?

Well, I think in 2017 and 2018, it'll have very little influence. The vast majority of the acreage we got that's not held by production doesn't have expirations until 2019 and beyond, which is one reason we like these. So very little near term expirations. And I would say if it does affect our development plan it won't probably, that factor won't drive the pace. It might drive how we select locations. So we might have a preference for pads that hold acreage versus pads that are already held. I think the pace will driven more by economics and our liquidity position.

Okay. If I could sneak in one more. Just on the Utica program, it sounds like the last two wells that you've completed have maybe improved your bias or your thoughts around the Deep Utica. I think ceramics, we're seeing maybe in the previous calls, may be an enabler. But can you just talk a little bit about what's changed or the improving well productivity, but maybe a little bit about what's improved in terms of the overall Deep Utica program versus a prior call or two?

Yeah. As I said, we don't want to give out any specifics on what we're doing since right now I think we're the only company, perhaps one other is investing a little bit into Deep Utica. But the one factor we have talked about in the past that I'll comment on is the type of proppant. We started with ceramics. We had a view that maybe sand would work and at the time would be significantly cheaper than ceramics. We switched over. Those next couple wells were significant underperformers from the Scotts Run. And then we switched back to ceramics for the last couple wells and they were significantly better than the wells with sand. Those two wells have gotten us much closer to the target recoveries that we think we need. So I think ceramic, it does play a big role. Our current plan is to use ceramics for all wells in the future. And fortunately, we've also been able to cut the cost of the ceramics basically in half from the first well. So that also helped on the economic side. Beyond that, I will say we have been doing a lot of technical work on our drilling completion techniques, the typical stuff you would think about, types of sand, loading schedules, pump rates, targeting in the reservoir, all that kind of stuff. And I think as we drill wells and learn more, just as we saw in the Marcellus, we're seeing continuous improvement. That's one of the reasons we want to spend the next year basically doing one well at a time so we can try new techniques, learn from them, apply them to the next well and not get too far over our skis. But we do think with another six or eight wells, we'll be in a position where I'm confident we'll have the costs where they need to be. I'm pretty confident that the recoveries will get into that range that we think we need. And hopefully, we'll also have a chance to delineate the extent of the economic area of the Utica.

Okay. That's very helpful. Thank you, think Scott (sic) [Steve].

You bet.

Our next question comes from the line of Dan Guffey with Stifel. Please proceed with your question. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Hi, guys, and thanks and I'll echo my congratulations. I'm just curious, other operators in West Virginia have been touting productivity gains from completion optimizations and have you even discussed elevated type curves? And I guess just wondering if you can talk about how your West Virginia Marcellus completions are evolving and should we expect to see a change in the average per foot productivity or an increase in the type curves across that core area, and if any of these gains could influence your 2017 guidance?

Well, yes and no. One thing I'll say is we recently adopted a new standard frac design that uses considerably more proppant per foot based on some very early tests and a lot of reservoir modeling. We do expect this new technique to yield a higher MPV per acre and per well. We probably won't increase our type curve until we have sufficient production history from a number of wells to confirm the results. And we just started that in a broader way two or three months ago. So it'll take quite a few more months before we have wells online with production history. So if it plays out the way we expect, we would expect an increase in the type curve, but I don't think that's going to happen in the next couple of quarters. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay. Is that just in West Virginia, or are you seeing anything in Southwest PA as well?

That's actually in both areas. Across our whole core position, we're adopting a technique with more sand. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay, great. And then it looks like firm transportation volumes are obviously increasing to the Midwest, and it looks like that's going to continue to grow throughout most of 2017. Just curious what types of increase in transportation should we expect to see into 2017?

I'm sorry, you're talking about how much transportation additional capacity that we have? Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Correct, yeah. It looks like the additional volume is moving into the Midwest.

Yeah. With the completion of the OVC, we now have additional access, as you know. So we'll be moving up to about 650 million a day over the next few months and, depending on the market conditions, could move even more going forward. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Should we expect to see a per unit increase in transportation expenses moving forward as those volumes increase?

Those volumes and those capacity commitments are fixed in nature so essentially, you'll see that. But net in terms of realized prices, we should see an increase in our realized price. In fact, from an EQT perspective, we're taking action to ensure we're building the pipelines to get higher realized price. So yes, the transportation costs per unit but net realized prices should be increasing, obviously. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay, great. And then one last one on efficiencies. I see you guys are running three top hole rigs and three Marcellus rigs. Just wondering if you can discuss any efficiency gains made over the last year? And then currently, how many wells per year can a single horizontal rig drill with a top hole rig running out of it?

I guess, first, on the efficiencies, just a couple stats. Year-to-date 2016 versus 2015 actual data, on a dollar per thousand foot of pay, we've seen about an 18% improvement. So from a little over $1,100 per foot to a little over $900 per foot in 2016. Our current thinking is we're starting to put together a business plan for 2017 is that we should expect to see a further reduction in that cost or further improvement in efficiencies. A lot of that will be driven by longer laterals that we expect to be able to drill in 2017. And on the number of wells per rig top set, I actually don't have that number. I would guess it's probably 20. If we top set them we can drill 20 wells with the big rig per year. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay. Thanks for all the color, guys.

Our next question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question.

Good morning guys and congrats. Say, just one sort of general question here. You know, obviously now when you look at that core sort of rectangle to you guys, always break out when you include now all this additional great acreage you picked up. How much variation do you see in returns? I mean, you have a pretty big swath there, all the way from Allegheny down to Doddridge. And I'm just wondering, kind of in broad terms if you assume somewhat similar D&C techniques? How much do you anticipate the returns that are in there?

Neal, we actually see very little variability in the bulk of that rectangle. One little exception, potentially is once you get north of Pittsburgh, you'll see the rectangle goes up there into Southern Butler County and Armstrong County. Those returns are not quite as high and we're not really focused drilling up there. But there is consolidation opportunities potentially with long enough laterals they can be competitive. But with that exception, the returns are pretty equivalent. We get a little of the liquids benefit in the majority of West Virginia that we don't get in Pennsylvania, and that tends to offset a small productivity advantage that Greene County, Pennsylvania has.

And then Steve, just lastly, how much different completion design, I mean, besides the 10,000 for lateral, you said you you'd prefer on most as far as sort of sand and different things you're using there on this Marcellus? Is there much variability there?

No, our design is actually has become more standardized across that core area than I would've expected. It varies a little bit but not a whole lot.

Thank you.

We have no further questions at this time. I would now like to turn the floor back over to management for closing comments.

Thank you everybody for participating, and we'll see you on the next call in February.