Dan O. Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee Jeffrey W. Hutton - Vice President of Marketing James M. Reid - Vice President and Manager of South Region Scott C. Schroeder - Chief Financial Officer, Vice President and Treasurer

Brian Singer - Goldman Sachs Group Inc., Research Division Abhishek Sinha - BofA Merrill Lynch, Research Division Pearce W. Hammond - Simmons & Company International, Research Division Marshall Carver Louis Baltimore - Macquarie Research Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Andrew Venker - Morgan Stanley, Research Division Gilbert K. Yang - DISCERN Investment Analytics, Inc Raymond J. Deacon - Brean Capital LLC, Research Division Biju Z. Perincheril - Jefferies LLC, Research Division Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Good morning, and welcome to the Cabot Oil & Gas Corporation's Second Quarter 2013 Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO. Please go ahead.

Thank you, Andrew, and thank you all for joining us on this call. I have our executive team gathered here in the room with me, and they'll be prepared to answer any questions the group might have. Before we get started, let me say that the standard boilerplate language and forward-looking statements included in the press release do apply to my comments today. I plan to be brief with my comments regarding our operations discussion. However, in light of the many questions that we have received and the many media articles and speculative comments over regional basis differentials, we're going to change our typical approach to this call in order to discuss our marketing efforts in the Marcellus. We have posted a presentation titled Marcellus Marketing Supplementary Materials to our website, which can be found under the Presentations section of our website. We plan on talking about this material later in the call, and it will frame the majority of the discussion today. However, before we jump into that discussion, let me first discuss a few of the highlights of this past quarter, which happens to be the best quarter in Cabot's history, both operationally and financially. For the quarter, we grew production 52% over the second quarter of last year to a record 95.2 Bcfe, which equates to 1.046 Bcf per day of total company net production. Most of that growth was driven by our operations in the Marcellus, where the current gross production rate is approximately 1.2 Bcf per day. The recent jump in gross Marcellus production to over the 1.2 Bcf per day is a result of several new wells turned in line in addition to the commissioning of the Central compressor station in late June. The commissioning of Central had a very minimal impact on our…

[Operator Instructions] The first question comes from Brian Singer of Goldman Sachs.

Appreciate the color with regards to the basis differentials in your comments and the -- in your contracts. When you put your firm transport and your long-term sales contracts together and look at it in 2015, how, if at all, would your exposure to the 65% NYMEX, 30% local hubs that we see in 2013 -- you detail on Slide 5 -- change? Do you expect a meaningful shift in that split?

No.

And so then, I guess the question -- the follow-up question then would be, what is the current market like to sign NYMEX-linked agreements? Because the worry by others -- or the worry by some would be that for incremental contract signs, that would have to be or will stay at a discount to NYMEX.

Okay, I will pass that baton to Jeff Hutton.

You're exactly right, in today's environment would not be ideal to be signing long-term agreements. We expect that environment to obviously improve. We think this it is just a temporary glitch. The majority of our contracts were signed -- I'm not going to disclose weeks, months, years, whatever -- a while back. We've only had one small long-term contract we've entered into recently, and it was one that was negotiated for a number of months. And the pricing never changed on it.

And then lastly, as you've seen your production grow since Central compression has come on, or since the end of the quarter, can you just talk about how recent growth in the Marcellus -- how much of that has been because of favorable line pressures that have come as a result to bringing Central compression on, the tying in of new wells or just better well performance and really trying to isolate whether you've seen an improvement in well performance or whether the recent increase in -- the very recent increase in production is more to just the timing of some of these midstream and completion factors?

So we have felt good about the -- what we've seen on Central. Keep in mind, Central is still in the start-up phase. In my opinion, we have -- we've done a great job. And certainly, Williams has done a great job in getting a very complicated infrastructure system up, running and in place. But as any big operational project, we have ups and downs and starting at different times -- starting and stopping at different times. And we also have -- as part of the turbine process at Central, we have 3 re-sips at Central also. So when you look at the area of our current production, let's take the gross 1.2 Bcf, Central does not touch all of that. But when you look at the impact, we think we have seen early stage and the results of just Central and not of new production, we think it has been a plus or minus 15% positive effect on existing wells.

The next question comes from Abhi Sinha of Bank of America.

I'm standing here for Doug Leggate. Just want to -- a quick one. So now you have added a sixth rig early on in the Marcellus. So we wanted to see like what stack really actually looks like in 2014 or in the outer years. And the follow-up will be like, where do we see the activity levels ultimately going up, given you have step-up in the cash flow?

Well, as far as the rig count is concerned, we haven't given any guidance out beyond '13 at this time. We'll get more color at our next conference call in October. But our tentative plan at this stage would be to add another rig to have 7 rigs running in the field in '14. And certainly, with the growth that we see out in front of us right now, we are quite optimistic and positive about continuing our story out in front of us.

Sure. And just again, in the Marcellus, how far you think you're away from being in full pad development mode? And would you have, like, 500 feet spacing and all developing forward?

Well, as we were still moving the rigs around in the field, capturing primary term acreage, so we have not gotten to the stage yet where we have gone and can go into full development mode. We do anticipate in '14 to have some rig activity on pads to implement pad development. But some of our rigs, also in '14, will continue to capture acreage. Full pad development will move out towards '15 when we can start talking about maybe all of our activity being on pad drilling. And as far as the spacing is concerned, we will continue to evaluate the most efficient spacing on our wells. Some of that work will be -- began in earnest once we are able to do some pad drilling.

The next question comes from Pearce Hammond of Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Dan, what are current well costs right now in the Marcellus for Cabot? And how do you see them changing when you do start drilling some of those very large pads that you were just referring to?

Well, we've seen efficiencies. And looking at our typical -- again, back to our typical type 14 Bcf well, we're in the, say, upper-$5 million to mid-$6 million range, depending on effects on roads and locations and whatnot. And we have -- as you're aware, we have in our presentation, our media presentation, we have a slide that depicts some of the savings that we think we're going to realize comparing a 10-well pad versus a 2-well pad. And we think that, that savings -- from what we drill right now, we think that savings would be greater than $500,000 per well once we are able to move to pad drilling. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then one follow-up. Any updated thoughts on the potential divestiture of the Marmaton?

No. We continue to have our same mentality about the Marmaton and the other areas that we are not allocating a great deal of capital to. And if we find the right opportunity, and it looks like we could find a win-win deal out there, then we would consider divesting the Marmaton or saving the Marmaton.

The next question comes from Marshall Carver of Heikkinen Energy Advisors.

A couple of questions. You talked about the Central compression still being in the start-up phase. How do you see the growth from Q2 to Q3 and from Q3 to Q4 for the overall production for the company this year?

Oh, I don't have that in my fingertips. We did revise the overall guidance from the 35% to 50% to the 44% to 54%. I -- Marshall, I'm sorry, but I don't have just right at my fingertips the progression through third and fourth quarter. But we are -- and we do anticipate that the Central compressor, as we continue to work it, the fuel guys continue to manage the fuel directionality of our gas based on the areas of lower pressure on the gathering system. We do expect it will be a learning curve from our guys in the field, and we do expect to see efficiency gains by virtue of this reduced line pressure.

And one -- switching modes to the Eagle Ford. The longer lateral was significantly better. Do you think the -- you're going to plan on drilling mostly longer laterals heading forward? And what would you say your overall Eagle Ford EURs are now, based on the better results?

Well, certainly, we're very pleased with the longer laterals and are -- the longer lateral. And by virtue of those results, our guys are evaluating the layout in the field and will make an effort to drill the longer laterals than what we have been drilling in the past. I don't have and have not seen a well count yet on how many we'll be able to get out to 7,000 or 8,000 feet, but I know that they are working on that. And with the assumption and continued good curve bits over and above our typical wells, we think we could move our EUR up in the Eagle Ford, but we're not prepared to do that at this stage.

The next question comes from Louis Baltimore of Macquarie.

In the Eagle Ford, while the first extended lateral have a very strong IP rate, after 120 days of production, it was producing essentially right in line with that 24-hour IP. Can you comment on basically what was done in this well to keep production essentially flat for an entire 4 months?

Well, I'll make a brief comment then I'll throw it to Matt. Certainly pleased and knew -- when we look at the flowback profile and it had a lot of stages in there, and I don't know, as it flowed back, it's made a difference or -- if we're in fractures or what. But I'll let Matt make a brief comment.

As Dan said, we frac-ed 30 stages in that well, and that well came on and was relatively flat, decreased slightly in its performance. But I think what we -- what happened was we continued to get contribution from additional stages as we went on. I think we got contribution early along from the field. And later on, we started to get contribution from the other stages. And as a matter of fact, it just continues to get stronger. We've been seeing that well continue to improve in performance even today. So I think what's happened is we're getting additional contribution from additional stages. We also have done a few things differently in our completion techniques, and I think that's helped as well.

And then I just have one follow-up question related to the Marmaton. Initially, it looked like the returns in the Marmaton were as good, if not better, than those in the Eagle Ford. And so I was wondering what drove the move of that one rig from the Marmaton to the Eagle Ford? Is it the increased efficiencies you're seeing in the Eagle Ford now?

Well, we have the increased efficiencies that we are realizing in the Eagle Ford. We have higher cost acreage in the Eagle Ford. We have more of a maintenance -- my primary term, maintenance issue in the Eagle Ford that we need to focus on. And then that is the motivation to focus 2 rigs down there versus 1. We are very pleased with the Marmaton, and your numbers are accurate and consistent with ours on the good returns we get from the Marmaton. We think for '13 that our primary term acreage position up in the Marmaton is in pretty good shape. So that -- all of that has influenced our decision on how to allocate our capital.

The next question comes from Amir Arif of Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a couple of quick questions. On the step-out well to the north, the production for frac stage was even better. Are you moving to higher frac stages out there? Or is this just something specific to that one area that you needed to do?

No. We see variability in the wells. And no, it was not more frac stages. We see variability in some of the wells -- not a great delta. But we do see some in some areas. We have a better, maybe fracture system that we're connected to and can fracture into, but -- we have seen those type of performances not only in the wells you are talking about, but we've seen those type of performances on a per-stage basis on some of the wells also in our areas we've done majority of our drilling. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So there's no real meaningful change happening in the number of frac stages you're doing per well? [indiscernible] own program?

That's correct. Correct. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And then just a -- and then a follow-up quick question on the Eagle Ford. Is -- or are you holding that well back? Is that well being choked back? Or is there surface constraints? Or is that [indiscernible] what you talked about in terms of other stages slowly coming on?

Yes. No, we don't have it -- we don't have it choked back or held back at this stage. I think along the lines, what Matt indicated, it's seeing -- as we go and as we produce, think additional contributions from additional stages.

The next question comes from Bob Brackett of Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Question on new venture strategy. Are you guys going to be doing anything along that for the next year or so?

Well, we have talked about new ventures in the form of portfolio management. And the Marmaton has been an area that we've discussed on maybe new venture opportunity. We have also looked at some of our legacy conventional assets in the Gulf Coast, and we also look at some of our East Texas properties as far as maybe an opportunity that we would create for Cabot.

The next question comes from Matt Portillo of Tudor, Pickering, and Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick questions from me in regards to the Eagle Ford. First, I was just hoping if we could get a little bit of color on the date to drill at this point?

Okay. As far as the reduction in days to drill from down to approximately 9 from spud to TD? Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Correct.

Okay. Matt? I'm...

Sure. We've done several things. It's not just one. We've changed our bottom hole assembly so that we don't trip as many times for our directional assemblies. We've cut that trip time basically almost to one trip. That's been a big, big plus. We've pushed our motors to differentials such that we're -- our P rates are much higher -- penetration rates are much higher than they were. And also, we've changed the way that we check our directional surveys such that we don't have to [indiscernible] the way we used to. We take regular signals, so we cut that time drastically in half. It just [indiscernible] from other rig efficiencies as well. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Perfect. And then as we think about the 2 rigs you're running in the play today, could you give us a little bit of color on how many wells that would be per year in terms of drilling completion? And I guess, as you mentioned, the 500 net wells in the play kind of -- it looks like there could be some potential for acceleration as you move out into '14 and '15, given the free cash flow generation, but just trying to get a little bit better understanding of how you think about capital allocation to the Eagle Ford.

All right. On the rig efficiency, we're probably looking at 20 to 25, plus or minus, as far as moving forward.

Yes. I could speak a little bit. Just -- you can look at it this way: we -- on our pad drilling on our first well and our rig move, it's about an 18 day from move to rig release to the next well. And then on every additional well, it's additional 13 days. So roughly, you can take that on a 4-well pad, I think that's roughly 57 days, and you can do the math on the 6-well pad. So you can do the math as far as that goes on a [indiscernible] basis. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Perfect. And I guess just in regards to the 500 net wells, do you think you're kind of optimally completing or allocating capital to the play with the 2 rigs running? Or is there the potential to accelerate it as you move into '14 and '15, given the corporate free cash flow generation?

Certainly. Certainly, there's the opportunity to improve that. And my reference to an extended 500-well program and how long that would last -- I would just reference to 2-well program because that's where we're going to drill right now. But when you look at the efficiency gains that we anticipate making on pad drilling and you then roll back, and once we are able to justify and realize consistent efficiency gains, get the well costs down, show the improvement hopefully that we plan on seeing in the IPs and 30-day average in the IRR, then we will make a decision on how much of our free cash we will continue to allocate to the Eagle Ford, which, certainly, if Matt and his guys can do this pad drilling, they can drive the costs down and continue to deliver and we can get the returns up into the 60%, 70%, 80% range, there's a lot of justification on allocating CAPEX to those type of projects.

The next question comes from Drew Venker of Morgan Stanley.

I'm assuming you could talk about the Marcellus infrastructure capacity in the second half of the year and into 2014. I guess are you -- your facility is constrained now at that 1.2 Bcf a day?

Well, I don't think we're facility constrained per se. Where our gas is producing, though, into a high line pressure, I think we have seen that by adding additional facilities in the form of the Central compression station, that by reducing those line pressures, I think -- well, we think we have seen a plus or minus 15% improvement from the existing wells. So if by definition that is part of facility constraints, maybe so.

Okay. So I guess you have -- it's sounds like you have a number of projects underway to help I guess reduce line pressure and allow you to continue to grow throughout the year. So we have to bring those additional projects online to increase production in the back half of the year? Or is the -- I guess is the Central Station going to help you increase production in the back half?

We plan on producing production in the back half, and I'll let Jeff make some comments.

Drew, I think you hit the nail on the head. There's multiple, multiple projects that are going on. Some happened leading up to Central. Central obviously was a major milestone, and a lot will happen between now the end of the year. And these projects include additional horsepower throughout the system, bridge lines, larger diameter pipes, additional section lines. I mean, the list goes on and on. The idea is to build a system that will -- that can enhance our production with lower line pressure, and we've got a ways to go. But these facilities are on schedule, and it's very dynamic, very fluid. So there's always something going on as we build this out.

Okay. And then in terms of the downspacing tests you've already drilled, can you talk about the performance so far?

I'm sorry, on which one?

On the downsizing test. You guys drilled upper and lower Marcellus, I believe?

Yes. Well, we -- yes, we have very few examples on the -- with the upper Marcellus, and we've been pleased with those results. And what we've indicated in the past is what we see as far as the curved pit is kind of an A+ Bcf type run on the upper.

The next question comes from Gil Yang of DISCERN.

Following up on Brian's question from early on, you outlined nicely how the firm transportation grows and -- but your exposure to NYMEX doesn't really change with those new contracts. But does the differential change with the increase in firm transportation versus the long-term contracts?

Okay, Gil, I think I got your question, but we'll try this. The trades -- or excuse me, the FT, the transportation contracts, as they increase, we expect to have less exposure to basis differentials. Our long-term contracts are -- I mean, we've kind of outlined here very specifically just how they play out and what we're currently experiencing on basis. Is that helpful?

I think so. But I -- yes. So your exposure to NYMEX doesn't change as you've said, but at the same time, you're long-term contracts that are -- but because you're more firm transportation, you also have less exposure to long-term contracts overall. So I would expect that the differentials improved.

Well, if -- in a perfect world, if differentials didn't move around like we all know they do, then the firm transportation contracts do take us places that have higher and better basis differentials in today's world.

Okay, got you. And then with the Eagle Ford well, I was just curious -- very strong well obviously, and you've commented why it's got a good decline rate. But why -- is there something different about this well that allows those extra stages to come online, whereas other wells don't do that as consistently?

I just think it's a longer lateral. I mean, it's just basically just friction. It think you tend to produce the heel stages first and then you get contribution from the tow stages as you draw down the pressure in the heel stages.

Okay. So you're just saying that, that dynamic is just more pronounced with the longer lateral?

It's just a limit capacity.

The next question comes from Ray Deacon of Brean Capital.

Dan, I was wondering if you could comment on your EURs per 1,000 foot of lateral drilled. It seems like a couple of your competitors have increased their numbers, and your number is still around 2.3 Bcf. I guess, have you seen any data that would back up an increase in that?

Which ones?

Well, basically, EURs in the Marcellus per 1,000 foot of lateral drilled, I guess the 14 Bcf EURs.

Well, we're not -- we're looking at our curved pits, Ray, and we have a 14 Bcf-type of well that we've assigned and identified as our typical well because there's always variability in the number of stages and the lateral lengths. But on a per thousand foot of lateral length, we're comfortable with where we are. And if down the road we can see some improvements, then we'll recognize those. But we're comfortable where we are right now and don't feel like we need to push it.

Okay, got it. And just to follow up on your earlier comments about interstate pipeline capacity additions, I guess do you have an estimate of how much capacity will be added in terms of total takeaway on big trunk lines over the next year or 2 in Northeast Pennsylvania?

Yes, I'll let Jeff handle it, Ray.

Ray, I've got some numbers. They're more fun facts that -- like a bentex [ph] where someone would publish. But essentially, Northeast -- there's probably 1.5 Bcf of new capacity coming on by year end as a number of new projects. Again, it's very dynamic. There's just a ton of projects that are proposed. And just like any other, about half of these projects will get built. But we look at it 2 ways because you look at pipelines that are normal expansions, like the Texas [indiscernible] that we do not have capacity on, we don't produce into. It does regionally influence where gas flows and what happens to pricing. And then we look more specifically at the pipelines we're connected to and will be connected to and the expansion projects that those pipes have. Over the next few years -- it's a big number. And some of those projects won't get built, and some will get built and then expanded upon. So it's a moving target, but we feel good about the expansions that have just happened in the last 12 months, for example. And so the ones going forward will only enhance what our opportunities are.

The next question comes from Biju Perincheril of Jefferies.

One more marketing-related question. So it looks like you're probably moving about 500 to maybe plus million cubic feet of gas on short-term contracts. Can you talk about, say, in the next couple of years, how many of those contracts or maybe aggregate volumes that are falling over or expiring?

No, we're not going to get that detail. But just for an example, this year, we're probably 80% of our production is sold under contracts that are existing. That number moves around. We have -- the market is quite dynamic in how it purchases gas. There's still a lot of buyers out there for 1-year deals and a lot of buyers for April, October deals and November, March deals and 1-month deals. I mean, it's all over the place. But if it helps, we're about 80% sold for this year currently.

Okay. And then -- so then, is the remaining 20% then moving on interruptible capacity? Or...

No. It's moving under firm capacity. It's just sold in the month-to-month market.

Got it. Okay. And then Central compressor station. Is there still a phase 2 expansion there this year? And how do we think about -- is that the same sort of impact to lower field-wide pressures?

There is a phase 2 to Central. It is not this year. It's at the end of 2014.

Okay. And when that comes on, it'll have a similar impact? Or is that more at that point, a discharge point for Constitution?

It'll do both, and there will be -- there's a lot of projects between now and then, so we have no idea of the effect, but we know that it's from the hydraulics perspective, from our planning teams. It's going to be very helpful.

The next question comes from Jack Aydin of KeyBanc.

Most of the questions were asked, but I've got 3 to follow up. A, when you did last year's reserve, what -- is it pad? What kind of booking did you book those wells? At PUD -- PDP or PUD -- on a PUD basis?

Zick?

Yes.

Zick was on a PDP basis for the majority of that.

Okay. So it's fair to assume that the performance of those wells that you just announced 2 miles and 5 miles away, you were looking at the same type of reserve kind of booking?

Well, we're pleased with those wells out there. The early curved pit is good, and the consistency we see from -- Halliwell [ph] has come on and how they continue to pit the curve is consistent, I should say. And so we're very pleased with what we're seeing out there.

Good. Now, Dan, what do you think -- what percentage of your acreage now in Susquehanna have been de-risked in your mind?

80%.

80%? Okay. Next question I have for you is this: in the Marcellus over there in Susquehanna, you've got different formations. Are you doing any different -- drilling different pilot projects to test the other formation beside the Marcellus? Or that -- or you don't need to do it now?

Well, we don't -- one, we don't need to do it now. And right now, we are focused on the lower Marcellus at this stage. We have -- in the past, to gather data, we have drilled deeper than the Marcellus. And certainly, we've looked at sections shallower than the Marcellus. But that's just data in the bank right now.

The next question comes from Gordon Douthat of Wells Fargo.

Have you -- I know you've been asked this question before, but given kind of the dividend increase and the increase in production, how do you -- going forward, how do you look at balancing acceleration versus returning cash to shareholders as you've kind of looked at this free cash flow profile going forward?

Gordon, this is Scott. Clearly, the -- what we have said throughout the second quarter and throughout the first half of this year when we've been asked the question, based on the parameters, the number one thing to do is to accelerate the Marcellus and that we made an initial attempt to do that with the sixth rig. Clearly, the horizon for the free cash flow and the level of free cash flow, while we haven't given guidance to '14, we're very comfortable with that concept for '14. And so we did take the opportunity, as we have done every time we've split the stock before, to make some move on the dividend. Dividend, this is not a final step with the dividend, but at the same time, we're not going to guarantee we're going to move it again in '14, but it is going to continue both the Marcellus and with the latest kind of results from the Eagle Ford, will become part of the operational acceleration discussion, as Dan said, depending on what kind of returns we can affect in the Eagle Ford. But dividend will still be a close kind of second to that operational discussion as we talk in the future.

Do you have a longer-term growth target for the company? Or...

In terms of dividend or just growth from the...

For production growth?

We are working on a model out through '17 that we'll finalize in the next month. But historically, we've kind of done it 1 year at a time simply because there is a lot of noise.

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

Thank you, Andrew. I appreciate everybody's diligence and the questions that were asked. Again, a lot of questions on clarity from the marketing side of it. I think the takeaway is that we are very comfortable where we sit today and our marketing and its impact on realized pricing for Cabot in spite of the volatility we see out there. And I think you've also seen some very good results in the eastern portion, again, supporting our thesis all along, the de-risking of acreage out that way. And I think -- and I was pleased to see a number of new questions regarding our Eagle Ford operation as we are now starting to show some efficiency capture and some gains in that particular operation. So I'm pleased with where we are. Thanks for the interest, and we will continue to perform. Thanks. And that concludes my remarks.

Thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect. And have a good day.