Good day, and welcome to the Cabot Oil & Gas Corporation First Quarter 2015 Earnings Conference Call and Webcast. All participants will be in a listen-only mode. [Operator Instructions] After today’s presentation there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, CEO, and President. Please go ahead, sir.

Thank you, Dan, and good morning all. Thank you all for joining us today for the Cabot first quarter call. With me today as usual are several of our management team. Before we start, the standard boilerplate regarding forward-looking statements do apply to my comments today. I would first like to touch upon a few financial and operating highlights from the first quarter that were outlined in this morning’s press release. First, equivalent net production for the first quarter was slightly above 1.9 Bcfe per day, an increase of 43% over the prior year’s comparable quarter and a sequential increase of 15% over the fourth quarter. Of particular note, our daily liquids production for the quarter increased 132% compared to the prior year’s comparable quarter and 20% sequentially over the fourth quarter, highlighting the success of our team in the Eagle Ford. Net income, excluding select items, for the quarter was 49 million or $0.12 per share and discretionary cash flow for the quarter was $240 million. Both of these items decreased relative to the first quarter of ’14 due to a 34% decline in realized natural gas prices and a 55% decline in realized oil prices. On the cost side, our team continues to work hard and deliver on driving down unit cost, which is evidenced by the 10% decline in cash unit cost to $1.22 per Mcfe. I think this decline is even more impressive when considering that we have increased the percentage of oil focused activity in our mix, which typically is more costly to operate on a per unit basis. Additionally we reaffirmed guidance even with the planned curtailment, which is I think the right economic decision. In the Marcellus, our operational results for the quarter exceeded expectations. The company averaged over 2 Bcf per day…

[Operator instructions] Our first question comes from Subash Chandra of Guggenheim. Please go ahead.

Yes, hi, good morning. I was curious strategically if there is any interest at all in securing a southern Marcellus foothold, as I suspect there is a shakeout coming, the American energy folks of the world et cetera, and if there is any interest in doing that, and then secondly, if you can maybe get more granular on the impressive operating costs experienced in the first quarter? Thanks.

Okay. First I will respond to any M&A considerations within our company. We are proactive in evaluating opportunities out there. Each year I think as you are probably aware that we have our strategy session and certainly in environments as we are in today, we have a time set aside in our executive board session just as we did yesterday to talk about all the macro-environment including M&A opportunities, considerations. We are not in any discussions with a southwest Marcellus or Utica opportunities down there but we want to be aware of what opportunities are available, and we will continue to evaluate any possible opportunities, but specifically for the southwest part of the state, again we are not in any transaction discussions or anything at this particular time. In regard to the operating side of the business, two of the guys here, Steve Lindeman, who is running our South region and Phil Stalnaker running our North region, I will let them comment on just some of the things that we have seen in the operating side of our business.

Yes. For the South region in the first quarter we really tackled our unit saltwater disposal costs. So that is one of the big drivers, and then secondly we switched out some of our treating chemicals and have driven that cost down. And we’re still looking at – there are some things we are trying to tackle for the second-half of the year in terms of electrification and other things that we can do to reduce our operating cost.

Again for the North region, this is more of the same thing on the optimization, yet looking at our recycling and our trucking cost just kind of across the board working just to lower the cost.

If I could just follow up just on the Eagle Ford, the electrification is, I suspect that is for the artificial lifts et cetera, is there – do you see that happening in a timely fashion with getting land owner consent and that kind of stuff, and given a sense of what kind of operating cost efficiencies we can have by maybe getting off diesel, which might be what is being used currently?

Yes, we do. We have made a significant effort over the last half of the year and into the first quarter to get right away purchased. One of the main substations that we need for electrification was put in service in the first quarter. As a matter of fact we are – some of our team was over there for an opening ceremony last night, and we are in the queue for several projects to get put online and we are hoping to have a portion of the field on power kind of into the third quarter of this year.

Okay, great. Thank you very much.

Thank you.

Our next question comes from David Deckelbaum of KeyBanc. Please go ahead.

Good morning guys. Thanks for taking my questions. Dan just curious if last quarter you alluded to this, or you guys communicated that you wouldn’t have a high point in production in the first quarter and naturally with seasonal winter demand and taking advantage of some of the firm sales contracts and then decline into 2Q and 3Q and rebound in the 4Q, is the plan today with the reiterated guidance, are you guys more or less within the original plan that you had set out a few months ago?

Yes, we are. We cannot predict exactly what the realizations were going to be. We thought they were going to be a little softer. We were glad to see quarter-over-quarter a little bit of reduction in the differentials, but our plans is still intact with our original guidance.

And just for context and maybe you could go into little bit more how you are managing the curtailments, I know that there is downtime associated with project maintenance and construction, but, just allowing sort of field volume pressures to build and naturally curtailing volumes that way, and what sort of recovery in prices are we thinking about before you would start accelerating the volumes here?

Well, we are not going to go into specifics on the pricing for that decision process, David. But we do expect to see better realizations later in the year than we anticipated during this period when the maintenance projects were going to be implemented and you were in the shoulder months. In regard to our field operations and methodology of how we are reducing the volumes out there, we have discussed in the past that we have a very flexible gathering system that allows us to move gas even from one particular pad to multiple outlets. We do anticipate that as we raise the field pressures in the field and allow that to happen that we would naturally bring down some of the volumes that we would be moving into the pipe. And so it is not a shut in a particular portion of the field and produce the others at those volumes that they were at. It is more of a across-the-board consideration of how we would bring the field pressures up a little bit to allow the volumes to be reduced.

Got it and if I could just raise here one more, perhaps for Jeff or anyone who wants to take it, with Constitution potentially coming on in the summertime of ’16 how are you guys thinking about the [ends] [ph] market there right now in terms of pricing and, is it – I know that you would partially do it naturally be better than Appalachia, but do you have a sense of how close that pricing should be to NYMEX and what you see – how you see that dynamic kind of building out?

Well, certainly on a historic look, the price points up there at that [right station] [ph] and into that line are close to the NYMEX pricing. Various times of the year it exceeds NYMEX pricing by a considerable margin. We’ve already kind of broadcast that we will make that call on how we would roll into the Constitution volumes whether it would be just total incremental volumes to what our current production is at that point in time of commissioning or if it will be a phase in by displacing the volumes from our current price points to the Constitution pipeline. I think it is safe to say at that point in time regardless of when Constitution is commissioned, whether it is in the middle of summer or right at the beginning of the third quarter I think it is safe to say that those price points more likely if they are consistent with historic is going to be at a higher better price point than the current indices that we are selling into. So we would naturally move and fill 100% of constitution immediately, but it may be just a displacement from the Millennium or Transco or Tennessee lines.

Thanks for that color Dan.

Thank you.

Our next question comes from Brian Singer of Goldman Sachs. Please go ahead.

Thank you. Good morning.

Hi Brian.

Actually wanted to follow up on that exact point, which is how you strategically determine the appropriate mix of filling constitution with production you already have versus kind of new production, when do you have to make that call? Are you planning on increasing your production capacity from where it is today by the full 500 million a day, and then you make that – you can make that call at the last second or is there a point where earlier on where you have to figure out your rig count and make that call on the split between transferring production currently oversupplying or potentially oversupplying the local market versus new production to go onto constitution?

That is a big question Brian, and how I answer the question will be dependent upon how much I make Phil Stalnaker squirm over here in front of me. But keep in mind that the capital intensity necessary for us to ramp up our volumes is minimal comparatively speaking when you look across the space to be able to find another half a Bcf a day. The driving consideration for that volume of production is going to be not necessarily in the rig count, but it is going to be how we stage in frac crews to allow timely completions of those wells that we have in the queue. So the plan building up to that decision point it would be our intent to have in the queue that will allow us to have that maximum flexibility is to have wells drilled and in the queue waiting on completion if you will as opposed to backing up a step and saying that we haven’t even drilled the wells or drill those pad sides yet. So when you get towards the end of this year, the discussions that we will have with the North will be all right, let us look at our capital program, let us look at our cash flow, let us look at the dynamics of the macro market, and let us make a call on bringing on another rig if we felt we needed it in the first part of 2016 but also looking at ahead at the end of the second quarter beginning of the third quarter how many frac crews do we want have land up to get ready to move those volumes in the constitution. Again, keep in mind that constitution is going to be failed immediately upon commissioning the decision is going to be do we back fill Tennessee Transco Millennium with those volumes and how long do we want to take to backfill those volumes. But at the end of this year, as we go into the planning stage for our initial budget for 2016 which we present to the board in October will have some of these discussions.

Great, thanks. And my follow up is if you could just two other points one whether you’re seeing any substantive cost deflation that unrelated to your activity levels could push down your budget this year or not. And then your outlook for committing to additional substantive [indiscernible] arrangements?

Once you cover the midstream going to have that’s going to roll out.

Okay Brian, this is Jeff. I think there is a number of smaller projects that were involved with what we felt this fall being the very important project that we’ve some long term sales associated with the petroleum per pricing. There is of course, following up with that there is the Columbia east side expansion we’ve some additional capacity come along at that point. After that we have of course constitution midsummer of next year and those are the – more or less short term drivers on new capacity and Atlantic Sunrise in 2017 and also new project for Tennessee at the smaller scale project about 150,000 a day that’s – over into New Jersey area from our production area. So that’s the kind of the short longer term of projects.

And Brian on your question about cost let me just answer this and if I don’t answer this and if I don’t answer fully just let me know but we do anticipate seeing additional incremental cost reductions and the inter operations we have not realized any of the saving as state indicated inside electrification of solar operations in the Eagle Ford. But we also think that the service providers are up, also obtaining and getting additional cost concessions from their providers that would naturally be shared somehow with the operators. So, we do anticipate that additional cost reductions would roll through our program between now and year end.

Great, thank you.

Thank you, Brian.

Our Next question comes from Pearce Hammond of Simmons, please go ahead.

Good morning and thanks for taking my questions. Dan, there are being many reports in the press about frac log or significant backlog of drill but not completed wells and previously Q1 earnings you said that cabbage should exit 2015 with approximately 45 wells in the queue for 2016 in the Marcellus and approximately 20 wells in the Eagle Ford and I know you talked about this little bit in the Q&A and in some prepared remarks. But I want to see if that was still the case and then if so, how do these figures compare to the number of wells that you had queued up entering this year and if you have any big picture thoughts regarding this industry frac log, is it real, is it overstated or what not, love to get that color as well?

Well, first off, on our expectations for year end 2015 we do still maintain our expectations, 20 wells in the Eagle Ford and 45 wells or so in the Marcellus that is going to remain consistent, I don’t see much getting in the way of that expectation. In regard to frac log and looking at the backlog it’s always seems to be a moving number that you see out there and I’ve seen different accounts what is backlog at any one give time. I do know that from a operation standpoint and I’ll talk more geographically about say where that could have a larger impact in our Northeast Pennsylvania in that six county area, if you look at that area, we’ve talked in the past about how many rigs are running and how many frac crews are up there. Our most recent intelligence is that you had through say January, February, March, a certain number of rigs running up there and most recently in April we place the number of rigs up there in that particular area and our neck of the woods had only 12 rigs that are currently running and we have at any given time 6 to 8 frac crews operating in that neck of the wood. Now if you do the simple math, and you look at the 8BCF or so a day that's kind of coming from that area 12 rigs and 6 rig frac crews are going to have one hell of a time keeping up with any natural declines that you might suspect from the volumes that are being produced. Now do you think that there were and have been just like we had some curtailed volumes that could keep maybe back filling some of that gas volume and you are maybe today not seeing any type of real inflection point but it doesn’t take a [indiscernible] to do the quick numbers on RPs and 30 day averages and all that for those number of pieces to the equipment to say that there has to be some depletion of the backlog if you will and the ability of wells to keep up with the natural depletion that would occur and under those circumstances. So on 2014 at the end of 2014, I think we had a similar number we might actually have a couple of more wells at the end of 2015 as we had at the end of 2014 but for the most part we are going to have a similar backlog for us.

Thank you for that. That color is very helpful and then my follow-up is some oil service providers have highlighted the tremendous opportunity in re-fracing wells can you see the same opportunity for Cabot and so and in what region?

Well, I have had a just a recent discussion with Phil in regard to our Eagle Ford operation just the industry in general on kind of what’s being done out there and then it kind of end up in a high level I’ll let him just kind of talk about maybe some of the areas that a re-frac might be considered.

So Pearce, when we look at that successful re-frac throughout the industry really what has been targeted is wells that have had I would say less sand concentration or lower con activity of frac jobs pump as compared to what the current standard would be and then secondly a group of wells that might have different pup clustering then what's being used. So a lot of people are targeting wells that may have been let’s say pup at 100 foot spacing and now what people are targeting 50 foot spacing and the same thing kind of on the sand basis where people may have done 800 pounds per foot versus now what people are pumping closer towards 1600 pounds per foot. Cabot does have some opportunity for refracs. I would say that we would target those when we would do the down spaced wells and do those in conjunction with that so you could get the full benefit of the zipper frac both on the refrac and on the new wells that we drill in the down spaced perspective.

Great. Well thank you very much for the color.

Thank you.

Our next question comes from Robert Christensen of Imperial Capital. Please go ahead.

Yes. Thank you. My understanding that 60 days after the public commentary in New York which ended February 27, under the uniform procedures that 60 days we should have some news out of the DEC of New York at that would imply next week. Is that the case we should hear from them one way or another next week?

No Bob that's not the understanding we have from – at this time. The DEC has taken the time to thoroughly review the comments that were submitted in the public comment period. Our understanding is that they are close to releasing the answers so to speak on these comments. There is still some work in progress surrounding the permits but we made a lot of progress here in the last couple of months and our expectations are that those permits will be issued sometime in the second quarter May, June time period.

And if you could answer a little bit about nothing materially that was –

Absolutely. So, from the comments that have been submitted our understanding from Williams is that the comments are very similar in nature that the comments were submitted to PERC as so there has been nothing in their review of the comment has been substantially different I guess than what they have seen before so we are encouraged by that so far.

One worry I have is that they would come with something that said we have got to study this and study it equally to the study period of the PERC and that period I believe took from February and go forward to October, February 14 to October 14 like 8 months. And we want the same time that the said tab I am studying this that's the concern I have. Should I have that concern that they can come with that type of thing.

I think the application for the permit has been in New York DEC hands for a much longer period of time than what you’re referring to, I think they have had a very lengthy time to review.

Got it. Well thank you very much.

Thanks Bob.

Our next question comes from David Beard from Iberia. Please go ahead.

Hi good morning gentlemen. I apologize if this question has been asked, to access I’ve trouble getting on my call but I just wanted to review just to see to have a bit more volatile production here first quarter, second quarter I was surprised with the prices being fairly week I would have expected volumes to be commensurately low or can you just talk a little bit about the press volume relationship, I know we are talking a fairly short term point of view and maybe what to expect on forward relative to that price volume relationship?

Well, we made an early determination and based on our crystal ball which again is no better than anybody else but with our crystal ball we made and placed our guidance out there early on that did take in considerations curtailed volumes and where we are right now our first quarter volumes were robust and we felt good about our operational performance in the first quarter but in the second quarter when anticipation again the maintenance projects and all particularly affecting the pipes that we sell into up in the Marcellus, we thought that by the continued supply increase and the construction project and maintenance projects up there that we would see softness in prices at this period of time. I think that is holding true. We are backing up some of the volumes and we think just from a prudency standpoint to protect shareholders assets and not to compromise our margin to the extent that the current price would yield we think it is prudent in this environment to take some of the gas and protect our margins. I think that's a prudent economics decision on our part and we are going to stick to that.

That's helpful. And just to change subjects on a follow-up, given we have seen some reduced rigs operating in the Marcellus both east and west do you think there will be an impact relative to production from the curtailment in the second half of the year or is that likely to be pushed off into next year for the industry?

I think by the second half of the year whether or not you see a rollover is debatable, I think you will see a possible inflection point in any of the growth profile. Again back to just the numbers that are out in front of us if you believe that up in that 6 can area that there is in April beginning in April there were 12 rigs running and 6 to 8 frac crews in that area and producing approximately 8 BCF a day even if all those wells were to the degree and to the performance levels of Cabot type wells, you are going to have a difficult time being able to maintain much less grow the production volumes from that product base. So I think the numbers have reflected that the other wells that are drilled out there are not like Cabot wells and so therefore I would be inclined to believe that some point in time you are going to see an inflection point on the volumes produced.

Now that's helpful. Thank you gentlemen. I appreciate the time.

Thanks David.

Our next question comes from Dan Guffey of Stifel, please go ahead.

Thanks. You guys continue to generate salary results and you referred specially compared to earlier vintage wells I guess could you give details surrounding your current standard completion zone and any technical improvements you are currently testing to further enhance productivity?

Well, I will get real granular on it but I will let Steve answer some of this but our lateral links are beyond 6000 feet and our profit per lateral foot is 1600 or so right now when we certainly are aware that some companies have gone up to 2300, 2400 maybe 2500 pounds per lateral foot and our south region will explore with some of that as we continue our operation we have got our down spacing program that we feel comfortable with and have a number of pilot programs that had given us the confidence at 300 down spaced is going to be how we place our wells from this point forward as we have been successful in maintaining our primary term acreage and we have had responsive landowners negotiate with us in regard to the timing of obligatory wells or continuous development wells out there on their properties some of those mineral owners do not want to produce their well into a low price environment. So we have been able to extend some time on those particular leases. So between now and the year with one rig, and a not a 24/7 frac crew some of the experimentation if you will and completion efforts that we would be implementing are not going to be very numerous simply because we are kind of in a somewhat of a holding pattern with one rig and one crew.

Okay. Thanks for the detail. You kind of touched on the 300 foot space in your prepared remarks just now I am curious how many pilots you have at 300 feet space is that kind of standard completion is on and how are you looking at it is it stack and staggers or are you just landing kind of in the lower zone and keeping it at 300 foot apart.

Well, we are in the lower zone with our 300 foot spacing but we have several points within the lower zone that we are landing our wells. And we have 20 or 30 of the pilots that are out there that have shown good results. But again, we have not gotten to the point of doing anything yet in the upper Eagle Ford on the staggers that some have been talking about. Our staggers are in a narrower range within the lower Eagle Ford on our placements. But we have also had 300 foot space laterals that have been in the same landing points also within the lower Eagle Ford that we feel comfortable about.

Okay. Great. And you touched on M&A previously but curious do you guys are interested in seeing bolt on acquisitions and opportunities in South Texas?

Well again, to not get granular on it we look at all the opportunities that are available out there. We are just fresh up taking up two properties that were good fits to our operation in the Eagle Ford that we closed in the fourth quarter the results that we have seen from that efforts proved out an efficient program and consistency with our expectations or exceeding expectations with the wells that we drilled on those properties. So it all comes together and you can get into an environment that is little bit more robust and a $50 roll price then it will make sense.

Thanks. I appreciate your color guys.

Yes, thank you Dan.

This concludes our question-and-answer session. I would now like to turn the conference back over to Dan Dinges for any closing remarks.

Okay. Right appreciate it, appreciate everybody's focus on Cabot as you are well aware and we are all well aware we are in a challenged commodity price environment in both oil and gas, efficiencies are being realized and cost reductions realized, the radar operations both side cash cost basis for our unit production but also in our capital program and we expect to see continued improvement throughout the year. And thanks again for your interest in Cabot.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.