Good day and welcome to the EQT Corporation First Quarter 2015 Earnings Call. Today’s call is being recorded. [Operator Instructions] At this time, I’d like to turn the conference over to your host, Patrick Kane. Please go ahead, sir.

Thanks, Danny, and good morning, everyone, and thank you for participating in EQT Corporation’s conference call. With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream and Commercial; and Steve Schlotterbeck, Executive Vice President and President of Exploration and Production. This call will be replayed for a 7-day period beginning at approximately 1:30 PM Eastern today. The telephone number for the replay is 719-457-0820 with a confirmation code of 2277056. The call will also be replayed for 7 days on our website. We remind you that results of EQT Midstream Partners, ticker EQM, are consolidated in EQT’s results. There was a separate press release issued by EQM this morning and there’s a separate conference call at 11:30 AM today, which requires that we take the last question at 11:20. The dial-in number for that call is 913-312-9034. In just a moment, Phil will summarize EQT’s results; next, Steve will summarize the capital budget revisions; and finally, Dave will provide an update on two projects. Following the prepared remarks, Dave, Phil, Randy and Steve will 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, 2014, as updated by any subsequent Form 10-Qs, which are on file with 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. I’d now like to turn the call over to Phil Conti.

Thanks, Pat. As you read in the press release this morning, EQT announced first quarter 2015 adjusted earnings per diluted share of $1.08, which represents a 20% decrease from adjusted EPS in the first quarter 2014. Adjusted operating cash flow attributable to EQT also decreased by about 16% to $386 million for the quarter. We had another very solid operational quarter, including record produced natural gas sales and record gathering volumes at Midstream. A high level story for the first quarter was strong volume growth more than offset by lower realized prices. Our pricing was significantly below last year. Our average differential was better than expected, offsetting some of the impact of lower prices. This came primarily as a result of moving gas to higher priced Northeast markets in the first quarter 2015. As a reminder, EQT Midstream Partners’ results are consolidated in EQT Corporation’s results, and EQT recorded $47.7 million of net income attributable to noncontrolling interests or $0.31 per diluted share in the first quarter 2015, as compared to $18.7 million or $0.12 per diluted share in the first quarter 2014. This increase also had an impact on the effective tax rate in the quarter, which was around 20%, and they have been lower than some of you expected. That is a function of both the increasing noncontrolling interest portion of EQM, which is not tax affected, as well as Production income, which is tax affected being a smaller piece of the overall pie versus last year as a result of lower commodity prices. Other than that, the first quarter was very straightforward and I will keep my remarks fairly brief. The story in the quarter at EQT Production continues to be growth in sales of produced natural gas. Production sales growth in the recently completed quarter was…

Thank you, Phil. As you read in today’s press release, we are lowering our 2015 CapEx forecast by $150 million to reflect the midpoint of our negotiated service cost reductions that we published in our March analyst presentation. Based on these reduced service costs, we expect our average cost per well to be between 10% and 15% less than last year. If weak commodity prices persist, we believe there could be more opportunities to cut costs, but for now, we think 10% to 15% is a reasonable expectation. Also in response to weak oil prices, we’ve decided to suspend drilling in the Permian Basin which was already reduced to drilling the minimum number of wells to hold certain leases. As a result, we will lose our development rights to approximately 700 Upper Wolfcamp acres. It’s always a tough decision to let leases expire, but we think in this environment, that’s a prudent economic decision. Moving on to our dry gas Utica well, as you know, we spud this Greene County well in November. During the drilling of the curve, we encountered higher than expected reservoir pressures, and based on the pressures observed, we needed to significantly increase our mud weight, which required a larger rig. We deployed the larger rig in March and completed the drilling of the well with a final lateral length of 3,300 feet. We’re currently running some reservoir tests and expect to begin fracing in early June. Despite this timing setback, we continue to be excited and optimistic about the dry gas Utica potential beneath our acreage. Upon completion of the Greene County well, we plan to drill a deep Utica well in Wetzel County, West Virginia later this year. Since we still do not have any results from our first well, we will not speculate about those results, but we will provide you with updates as we learn more. I’d now turn the call over to Dave Porges for his comments.

Thank you, Steve. Given the straightforward results for the quarter, I will limit my prepared remarks to an update on two previously announced projects. Let’s cover the Master Limited Partnership first, the new one. As we discussed in February, we decided to take public a new vehicle that will own all of EQT’s interests in EQT Midstream Partners or EQM. This means the new vehicle, whose New York Stock Exchange symbol is expected to be EQGP, will own EQT’s general partner or GP interest, including the incentive distribution rights, and it will also own the 22 million EQM limited partner units owned by EQT. On February 12, we filed the initial draft S-1 registration statement with the Securities and Exchange Commission. We received comments from the SEC on the draft and incorporated them into a revised S-1, which was filed on April 1. This is an iterative process of review by the SEC and response by us so we cannot accurately predict the timing of a final S-1, but we reiterate our hope to be ready for an initial public offering of EQGP by about midyear. Now for an update on the Mountain Valley Pipeline or MVP, in the first quarter, MVP announced the addition of WGL Holdings and Vega Energy Partners, a WGL subsidiary, to the joint venture. As we have previously discussed, this project will be built and operated by EQT Midstream Partners. EQM’s ownership interest in the JV is 55%. NextERA owns 35% and WGL and its subsidiaries own 10%. In addition to their ownership stake, WGL will be a shipper on the pipeline and has also agreed to purchase 500 million cubic feet per day of natural gas priced at Transco station 165. We believe this further validates the demand market’s desire to access the abundant Marcellus and Utica supply resource. EQT shareholders will benefit in two ways from this project. First, it will provide EQT Production access to one of the fastest-growing gas consumption markets in the United States. And second, it will provide cash flow growth at the MLP, which adds to the value of our GP and LP interests. In conclusion, EQT is committed to increasing the value of our vast resource by intelligently accelerating the monetization of our reserves and other opportunities. We have a very strong balance sheet which will allow us to continue to be focused on doing what we can to increase the value of your shares. We look forward to continuing to execute on our commitment to our shareholders and appreciate your continued support. With that, I’d like to turn the call back over to Pat Kane again.

Thank you, Dave. This concludes the comments portion of the call. Danny, can we now open the line for questions?

[Operator Instructions] We’ll take our first question from Neal Dingmann with SunTrust.

Steve, for you and the guys, you mentioned obviously for the service costs, I know you took the CapEx down considerably. Could you talk a little bit, it looked also like LOE we was down considerably and then on a go forward, it appears to be – what are you doing in that category to continue to bring that down so nicely?

I think it’s just more of the same, Neal. Production continues to increase at a much faster pace than the costs required to maintain that production. So I don’t think there’s anything in particular I would point to other than just continue trying to manage our water costs as best we can. That’s probably the one area that we focus a lot of attention on and it’s a pretty high cost area relative to the others and is an area that’s continuing to prove how we handle our water will help us continue to keep our unit costs in line.

I know it’s early, obviously, on that Utica well drill, and obviously a bit away from the one you’re going to drill in the west. I’m just wondering, on a bigger scope, Steve, any thoughts on – because it is so early on the dry Utica, what that could mean as far as allocating capital dollars? At this time, as you see it for at least the next 12 months, the bulk even as I expect as you are about the dry gas, the bulk is still going to be in Marcellus and then, if so, are you continuing to target sort of a concentrated area there or how are you tackling that now?

I think our view there, Neal, is this year will certainly be a year of testing the Utica. So we’ve drilled our first well. The second well will be in Wetzel County. We could potentially drill up to four additional wells this year depending on timing and what we see. But regardless, this year we’ll be testing. I think a good bit of next year we’ll still be gathering data before we’ll be in a position to even make a decision about reallocating capital between Marcellus and Utica. And I think the driver there will be, regardless of the IPs, which clearly our peers have had some pretty impressive IPs, we’re certainly hopeful we will as well, we need to define what the type curve, the decline curve looks like to really understand the economics. And I think our view is it’ll be a minimum of a year’s worth of actual production data before we’ll have enough comfort to shift any significant amount of capital away from Marcellus into Utica, assuming that indications are that the economics are similar or hopefully better.

One last one, if I could. Probably for Dave, as far as, obviously, after the drop down, Dave, and even prior, you guys have if not the best, one of the best financial positions out there today, certainly in the – not just the East Coast, but really in the universe out there. Acquisition-wise, I know you guys continue, with Steve and his group, continue to look at everything. Are you open to adding in the East? Would you consider adding another basin? When you look at – I guess I have two questions around this. Given the financial position, are you more apt to do acquisitions these days? And then secondly, if so, or even if not, would you like to stay in the same basins or would you go somewhere else?

I don’t think I would characterize our perspective as being more interested in an acquisition because of our financial situation. We’re executing the transactions we are with the Midstream because we think it’s the best way to create value. It’s the money, as I’ve said multiple times, is not burning a hole in our pocket. With that said, we do recognize that this could be an opportunity to acquire, and I’d say really in core areas would be the priority if the opportunities presented themselves at values that recognize the depressed commodity price environment. So I think I kind of answered your second question too, which is...

Our next question is from Scott Hanold with RBC Capital.

Specifically, could you give us some color on CapEx? Obviously, the number has come down and maybe a little bit of color on where you’ve seen the reductions really come in, was it backdating contracts with a specific service there? And then as a follow on to that, will you be comfortable at any point in time if you do see service costs continue to come down to actually use that money and put it in the ground, or do you just feel comfortable enough just building – putting the cash balance at this point?

I think the – because the biggest line item in our drilling costs is pumping services, that’s what really drives that number more than anything. I would say a few of our contracts have been backdated a little bit, but for the most part, most of them have been pulling forward from the time we negotiated the lower costs, so most of that is prospective. The one line item I will comment on in the opposite direction is our rig cost, our day rates. Most of our rigs are under longer term contracts that don’t expire this year. So we have relatively little leverage in that area. So our lack of leverage is reflected in that 10% to 15% estimate. If soft prices continue into next year and the year after, we’ll be in a position to benefit from lower rig costs, but for now, we’re not. I think our plan right now regarding redeployment of that capital is to keep it on the balance sheet. We think in this low-price environment and the growth rates we’re expecting, we’re in a pretty good spot and don’t feel compelled just because we’ll have some extra money to run out and spend it just because we have it. So for now, it’ll stay on the balance sheet and we’ll revisit that periodically as commodity prices move.

Maybe if I could rephrase the question, what price do you think on the forward curve it would take for incremental capital to be spent to start to become interesting?

That’s hard to say. We just really look at the economics. Actually, I would say the one benefit we get though of having the cash on the balance sheet is, unlike what we, infer is the case of the number of our peers, we will obviously have the financial flexibility to revise our programs upward if the economics improve as opposed to if you live in hand to mouth experience where you have to wait until the money starts rolling in. In our case, the money is already there. So really it is just the judgment about the prospective economics. But we really haven’t come up with new sense of a magic price at which we would revise upward. It’s just something that we really look at pretty frequently.

Dave, what would you sense your – with these reduced well costs because of services coming down, service costs coming down, what is the after-tax breakeven price to get a 10% rate of return today on your core acreage?

Pat’s already looking to find the right page in the right presentation. And I probably want to refer you to that because we don’t – as you know, I think, we don’t just look at it as core acreage. We tend to differentiate between Southwestern PA versus Northern West Virginia wet, Northern West Virginia dry, et cetera. Those are the categories we use. Pat, I’m happy for you to [indiscernible].

Hanold, I don’t know what the 10% return would be, but if you look at the Southwest PA, which is one of the two core areas, the other is Northern West Virginia wet. Southwest PA at $2.50 realized price would give you an 18% after-tax return. And Southwest – or Northern West Virginia wet would be 24% at $2.50 realized price. So the returns are still quite good even at today’s prices.

Is that today’s service costs that you’re stating me those numbers on?

Yes. That includes the service cost reductions.

From Tudor, Pickering, Holt & Company we have Michael Rowe.

I just wanted to talk to you real quickly about the production guidance change, understanding it’s only about 1% increase at the midpoint, but has anything changed with respect to completion timing on your 2015 program, or wells performing better than expected? I’m just trying to tie your CapEx reduction in February which was activity-driven with the production guidance increase this morning?

I think for the most part, it’s just driven by – we have one quarter under our belt, so the range of possible outcomes narrows with the first quarter being ahead of our original guidance. So I think that should be expected to be reflected in raising the lower end of guidance up. So that’s what we did. I think well performance continues to improve. So there’s a little bit of that. But it’s mostly just around certainty having been a quarter of the year in the bag.

You had a good NGL realization relative to WTI at about 46%. This looks in line with what you experienced in Q1 of last year. So is it reasonable to assume NGL realization should moderate closer to the low 30s on a percentage basis relative to WTI as we enter Q2 through Q4 of this year?

I don’t know that we have a particular view on that. But when you’re looking at percentages also you do need to be a bit careful to make sure that you’re looking at NGLs the same way. I mean, as you know, generally speaking, when we’re thinking NGLs, we are thinking C3s and above is what we’re actually selling, right? The rest of the ethane, generally speaking, you should assume is being sold as methane. And there are some folks who are selling ethane as ethane. They would obviously have a lower percentage if they’re making the calculation that way. That said I’m not sure that we have a particular forecast, any great insight into what is going on in the NGL market any more than anybody else would have.

Maybe one last one, if I can, just we talked a little bit about type well economics and the updated ones that you all have in your March presentation. Can you just remind us what the differentials you have baked into those are? Is that just your outlook on basis differentials at that point in time when you ran the calculation?

So whenever we show there is IRRs, we are using the local price. So it’s not really taking an assumption of a differential. It’s the local price. So if you’re looking at $2.50 local price, that could be $3.59 minus $1 dollar diff, or $3 and then with minus $0.50. Operator Our next question is from Drew Venker with Morgan Stanley.

Wanted to follow up on the dry gas Utica. I want to make sure I had that lateral length right, so can you just repeat that for us, and given the challenge that you had in the drilling portion, I wonder if that changes your expectations of costs at least for the drilling portion going forward?

The lateral length was 3,300 feet. And I think our expectation is while we did have a lot of challenges, I don’t think it changes our long-term view of the cost other than maybe a little bit on the mud side. So the mud cost will probably be a bit more expensive since we had to use heavier mud than we would have originally thought. I think everything else, over time, there will be a learning curve. It’ll take us probably several wells to get the costs in line with where we think they’ll be long term. Maybe the one additional color I’ll add that maybe is on the positive side, although right now it’s a theory, not practice, is on the proppant where – for our first couple of wells we’re going to use ceramic proppant, which is quite a bit more expensive than sand. It looks like it’s going to run about $100,000 per stage or $2.5 million for a typical well to use ceramic versus sand. Our reservoir engineering at this point is suggesting that it might be possible to use sand in these wells. So that’ll be something we’re testing, probably not in these first two wells, but in subsequent wells. So that’s some positive news from our end in terms of what the long-term development costs for deep Utica will be on our acreage.

I’m sorry, just a follow-up to that, was that 3,300 feet the original lateral length you had planned?

We had planned anywhere from 3,000 to 4,500. So our internal discussions were we need 3,000 to get the reservoir test we really want, which is the purpose of this well, we’ll go as far as 4,500. We had room to, but really the guidance to the drilling team was get 3,000, and at that point any hint of a problem and we’re going to call it and TD the well and move on, because really the whole goal of this well is to test the reservoir and we can do that with a 3,300-foot lateral.

And so it wasn’t that you had significant drilling issues and that you thought you wouldn’t be able to drill the full lateral length? It was enough to the test the reservoir.

It was. We had a lot of difficulties on this well and the costs were pretty high. And when we got to 3,300 feet, there were some indications that more problems could be developing. And we just didn’t want to take – once we had the 3,000 feet, we didn’t see any reason to take any additional risk, put the well bore at risk where we might not even be able to complete it, so that’s when we called it at 3,300.

Okay. And the last one and then I’ll leave the Utica alone. Was that $2.5 million incremental completion cost baked into your original well cost estimate?

Well, our original one, yes. If you look in our investor presentation, we have a pretty wide range of $12 million to $17 million. The $12 million is closer to what we would hope long-term we could do if we can use sand. And the $17 million is sort of a worst-case scenario with ceramics and accounting for other unknowns. But yes, we did have the $2.5 million in our original thoughts.

Okay. And then on the Midstream side, you guys obviously had a big beat on third-party recoveries. Can you give us a sense of what portion was related to selling firm that you didn’t need versus other uplift?

Sure. The majority of it was actually moving to higher-priced markets to sell our gas, and a smaller percentage was really on the overall capacity, because, as you know we manage our overall portfolio to maximize our price. And so our commercial team did an excellent job and they make those decisions daily as to whether to move our product or release the capacity to move to another market. But overall, the whole driver is really the realized price for our production.

From JPMorgan we have Joe Allman.

Just a couple income statement questions, I noticed that exploration expense is up. Is that from dry hole expense or G&A or something else?

It’s not dry hole expense, it’s some lease impairments in the Permian that Steve talked about. A small amount of it is also related to the lease impairment in Ohio Utica.

G&A also increased in the Production business, can you talk about that?

Some of it’s just the natural growth in the Production business, but we laid out several expenses and I mentioned in my comments that were, I guess, you’d call unusual, and we’ve adjusted them out in some of the tables in the release this morning. It was about $13 million of expenses like that related to the rig release in the Permian Basin. We did take a further impairment on Ohio Utica value and then there were some casing that we won’t be able to use. That was in casing and we wrote down as well. So things like that. And that totaled to about $13 million in the SG&A line.

Lastly, just in terms of the rig count and the terms of those rigs you mentioned earlier that you’re not getting the leverage of lower service costs fully because of the longer-term rig contract, could you describe the number of rigs and the terms of those contracts?

Typically those contracts were three or four-year contracts. Most of those are one or two years in. I think we have one or two in 2016 that will come up, so those would be the first – that’s the first opportunity we really have to lower those costs.

At this time, there are no further questions in our queue. I’d like to turn things over to our speakers for any closing or additional remarks.

Thank you all for participating, and we’ll see you next quarter.