Dan O. Dinges - Cabot Oil & Gas Corp. Jeffrey W. Hutton - Cabot Oil & Gas Corp. Scott C. Schroeder - Cabot Oil & Gas Corp. Steven W. Lindeman - Cabot Oil & Gas Corp..

Michael A. Glick - JPMorgan Securities LLC Phillip J. Jungwirth - BMO Capital Markets (United States) Charles A. Meade - Johnson Rice & Co. LLC Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. David A. Deckelbaum - KeyBanc Capital Markets, Inc. Brian Singer - Goldman Sachs & Co. Karl J. Chalabala - Stifel, Nicolaus & Co., Inc..

Good morning, and welcome to the First Quarter 2017 Earnings Call. All participants will be in listen-only mode. Please note this event is being recorded. I would now like to turn the conference over to Chairman, President and CEO, Mr. Dan Dinges. Please go ahead..

Thank you, Phil, and good morning to all. Thank you for joining us today for Cabot's first quarter 2017 earnings call. With me today are several members of our executive team.

On the call today, I will be referencing slides from the earnings presentation we've posted to our website this morning, which highlight our operational and financial results for the quarter. Before we get started, I would like to move to slide 2 of the presentation, which addresses our forward-looking statements.

Please note that we will make forward-looking statements based on current expectations this morning. Also, some of our comments may reference non-GAAP financial measures.

Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures are provided in both the earnings release and this presentation. Now let's move to the highlights of the quarter on slide 3.

Cabot grew daily production volumes by 7% relative to the prior year quarter, driven primarily by an increase in Marcellus volumes that benefited from a much improved natural gas price environment during the first quarter.

Our production levels were right on top at the high end of our production range for the quarter, which resulted in 6% growth sequentially over the fourth quarter of last year.

The company pivoted from a net loss of $51 million in the first quarter of last year to a net income of $106 million during the first quarter of this year while increasing EBITDAX by over 200%.

The improvements were primarily driven by 7% increase in daily production volumes; a 77% increase in natural gas price realizations; and 11% decrease in operating expense per unit. Of the utmost importance, the company was able to grow production and cash flow, while generating positive free cash flow for the fourth consecutive quarter.

Based on our strong performance during the first quarter coupled with the improved outlook for regional pricing for the remainder of the year, we have increased our full year 2017 production growth guidance range from 5% to 10% to 8% to 12% without increasing our drill and complete capital for the year.

Slide 4 illustrates the significant improvement we have seen in our pre-hedge price realizations over the last four quarters. Realizations for April and May will likely be about $0.25 lower than the first quarter average.

However, this implies that our average natural gas price realizations for the first five months of the year will be about 70% higher than the same period in 2016, highlighting the significant improvement in cash margins we are realizing to-date.

Moving to slide 5, it speaks to the improvement we have seen in the outlook for regional differentials, which is driven in large part by the anticipation of significant regional takeaway capacity additions in the near future, including Rover, Atlantic Sunrise, and Leach XPress, coupled with a supply side that has not kept pace with recent takeaway capacity additions.

This improving outlook for differentials has driven our decision to modestly increase our anticipated production levels for the year. Now I'll move to slide 6 which illustrate our updated capital budget for 2017.

As I mentioned previously, we are increasing our production guidance range for the year without increasing our drilling capital – drill and complete capital, which is largely driven by the outperformance we have witnessed in our recent Gen 4 Marcellus completions.

As we highlighted in the press release this morning, we have included up to $125 million of capital in this year's budget for exploratory lease acquisition and testing in new areas that have been analyzed.

As we communicated on the year-end call in February, we have been evaluating new platforms for future growth that has the potential to generate competitive full-cycle returns and we have identified two new areas that we believe warrant further testing.

These are areas where we have direct line of sight towards building sizable contiguous acreage positions that allow for an efficient operations at, most importantly, a low-cost of entry. I will define a sizable position as one that has the potential to provide over a decade of high-quality drilling inventory.

I would also highlight that the $66 million or over 50% of the spending occurred in the first quarter. So, these expenditures are front-end loaded this year and the first quarter capital outlay are not indicative of the quarterly run rate we anticipate going forward.

While these projects are in the early stage of evaluation and carry the risk that come along with exploration, based on the geo-modeling our team has performed to-date, we are cautiously optimistic about their potential. And that is why we moved forward with the leasing and will subsequently test our ideas later this year.

We will keep you updated on these projects if and when there is something commercial to discuss. Keep in mind, even with the spending, we still forecast over $250 million of positive free cash flow based on recent strip prices.

Moving on to operations, slide 7 and 8 highlight the outperformance we're seeing in both the Marcellus and Eagle Ford for wells placed on production during the first quarter. While there is limited production data on these wells, the early results are very encouraging.

In the Eagle Ford, we plan to place 14 enhanced completion wells on production this quarter and we'll continue to analyze the results over the coming months to determine the impact on estimated recoveries we are expecting as a result of the recent completion design enhancements. However, I am pleased with the results we have seen to-date.

Slide 9 illustrates the continued reduction in drilling costs we have experienced in both of our operating areas.

While we are still forecasting some cost inflation throughout the year primarily on the pumping side of the component of our well cost, we only anticipate about a 5% increase in total cost in the Marcellus and possibly a 10% increase in our Eagle Ford well cost by year-end.

However, in fact, our first quarter Marcellus and Eagle Ford well cost actually came in under budget. Moving to slide 10, slide 10 demonstrates the strength of our balance sheet and highlights how our leverage metrics have been reduced to pre-downcycle levels.

Based on our current three-year plan, we continue to see a material deleveraging as we grow EBITDA at a healthy rate without adding any incremental leverage to the balance sheet given our positive free cash flow outlook. Now, let's move to slide 11 on which we have provided a brief update on the status of our upcoming takeaway projects.

For purposes of this discussion, I will focus primarily on Atlantic Sunrise on the left-hand side of the slide. As most of you are aware, we received the FERC certificate approving the project back in early February.

Since then, the Atlantic Sunrise team has been working on obtaining access to the remaining property in order to complete the surveys needed for final permit application with the Pennsylvania DEP. I'm happy to report that we have now completed 100% of all cultural and environmental surveys required for the remaining permits in Pennsylvania.

We expect to file the final permit application in early May and anticipate full approval and permits in early July. Based on this timing, we anticipate that construction on the greenfield portion of the project will begin in early third quarter 2017.

Based on the expectation of a 10-month construction period, we remain confident that the pipeline will be fully in-service by mid-2018.

We continue to hear from thousands of people who support the projects – individual, chambers, business groups, labor unions – who recognize the economic benefit of the project in addition to recognizing the important role it plays in supporting the tens of thousands of jobs tied to the State's natural gas industry.

As far as other projects on the right-hand side of the slide, all of these important capacity additions remain on schedule for our targeted in-service date with the exception of Constitution, the status of which is currently pending our appeal process.

We are hoping for a positive outcome sometime in late second quarter based on the timing of appeals. Slide 12 is a new slide that we rolled out at an investor conference last month, highlighting the capital efficiency and free cash flow potential of our Marcellus asset.

For purposes of this analysis, we assume that we held production flat at 3.7 Bcf per day, which is our estimated productive capacity assuming we maintain our existing market share in-basin and, ultimately, fill the incremental capacity additions we have listed with new production.

This also excludes Constitution capacity given the uncertainty around the project timing. As you can see, this asset has the ability to generate significant amounts of annual free cash flow even in a lower natural gas price environment.

Currently, we modeled a long-term weighted-average differential of approximately a negative $0.35 off NYMEX for the Marcellus asset, assuming no contribution from Constitution.

Given that assumption, we would only need to see a $2.35 to $3.35 NYMEX price annually to achieve the $900 million to $2 billion range of pre-tax free cash flow highlighted on the bottom of this slide.

I think most would agree the range of NYMEX price is not a stretch especially in light of all the demand growth we are anticipating throughout the remainder of this decade. The obvious follow-up question from this slide is, what are you going to do with all the free cash flow? We have attempted to address some of the possibilities on slide 13.

Assuming the takeaway capacity is there and pricing is favorable, our first option would always be to reinvest it back into the Marcellus asset given that we believe this is one of the most economic assets in the country.

Assuming we cannot reinvest at all in the Marcellus, we will continue to look at allocating a small portion of the cash flow into the Eagle Ford assuming the returns justify it.

I believe our increase in Eagle Ford capital earlier this year, coupled with our planned increase in Marcellus capital in 2018 to grow into a new takeaway capacity, highlights our commitment to this portion of the strategy. The bottom left box is a current focus of discussion for our Management and the Board and one that we take very seriously.

Obviously, we have been in a bit of a holding pattern over the last few years as we await clarity on the timing of infrastructure and what that ultimately meant for our capital requirements as we began to ramp activity levels and production into these projects.

As a result, even though we saw the likelihood of free cash flow on the horizon, we were hesitant to commit to any incremental return of cash to shareholders.

However, as we get closer to having some of these projects in service and, therefore, have more confidence in the timing of being able to deliver free cash flow projects that our income model implies, we are more focused on this discussion.

I would highlight that in the past, we have demonstrated our commitment to returning cash to shareholders via our doubling of dividends in 2013 and the repurchase of shares in both 2013 and 2014, so, it is certainly a priority of ours.

For several years, I've been asked numerous times what Cabot plans to do with its anticipated cash flow outside of reinvesting in our current high level operating areas and returning cash to shareholders. As you may suspect, I have received a plethora of ideas from many different circles.

The Cabot team has worked overtime evaluating many plausible uses of our anticipated free cash with the objective to create long term sustainable value for Cabot shareholders. I have never deviated from this objective. Having a world-class asset as the cornerstone only enhances the challenge, although I might add it is a high class challenge.

The search carries us to many areas including bolt-on acquisitions, joint ventures, acreage trades, and our internally generated greenfield ideas. In order for these greenfield ideas to warrant consideration, capital allocation, our team participates in an exhaustive evaluation process to determine if the idea meets our objectives.

Several examples of our objective include the cost of entry. Do we think the idea can potentially generate full-cycle returns and compete with our current portfolio? We also ask about high-quality drilling locations.

Is the idea scalable and well positioned for efficient operations? What's the initial term from leasing to full-scale efficient development? When do we get positive free cash flow? Impacts on balance sheet? Potential growth? So, as you can see, all of these ideas have gone through our decision that we've come up with.

I'm confident that Cabot's process of evaluation, risk assessment, and methodology, and methodical capital allocation will result in enhanced long-term value for its shareholders. As we highlighted earlier, there is a high degree of risk associated with a grassroots leasing exploration effort.

However, compared to our evaluation of the acquisitions made in the M&A space and the implied first-cycle economics on those transactions, we are comfortable with the risk profile and the potential project returns of our ideas to support this grassroots effort.

After all, approximately 10 years ago, we drilled our first well in our grassroots Marcellus play in Northeast Pennsylvania and we have certainly been pleased with those returns. With that, Phil, I'll be happy to answer any questions..

Thank you, Dan. We will now begin the question-and-answer session. Okay. Our first question comes from Michael Glick from JPMorgan. Please go ahead..

Good morning. Just on the exploratory plays. I mean, recognizing you're probably hesitant to provide a ton of color given its early-stage nature.

But just any high-level thoughts from the types of plays you're chasing in the competitive landscape within the plays? And then are hydrocarbon or geologic – geographic diversification some of the goals here?.

Yeah. Primary goal, really one, two and three, is could we find an area to allocate capital that would compete with the return profile we see in our existing portfolio. And therefore, deliver the returns to our shareholders that would exceed where we're investing capital right now.

So, we were indifferent regarding the commodity diversity and looking at the areas, potential competitive landscapes and a lot of areas that we're all aware of. Through an exploration effort, we evaluated every basin that is out there. We looked at, actually, areas that were not necessarily in traditional fairway of the key basins.

But all-in-all, and balling all of that up, also looking and evaluating all the M&A transactions that have transpired, we did go through some data rooms and get a good feel for valuations out there and that's based to be able to compare to not only did that meet our threshold of full-cycle returns, but also, did it allow for us to enhance our portfolio of projects on a go-forward spend.

And as we continue to do our exploration effort, our guys came up with good ideas that we felt justified further expenditure.

And so, when you look at our cost of entry and you look at the possible returns that we see in these two projects and you look at the scale that we're comfortable with being able to develop, we are excited about where we've allocated the capital and we're also excited about moving forward with some incremental testing..

Got you..

But you're right. I don't want to be coy on the exploration ideas. But as you appreciate in your – the way you catch the question, we're just not going to talk in-depth about specifics of what we're doing. But I do appreciate the question regarding kind of our thought process on what we're trying to achieve..

Got you.

And then just jumping to the Marcellus, what do you think the drivers are of the outperformance of your Q1 wells versus your Gen 4 type curve?.

Well, we've seen the enhanced cluster spacing. We've loaded a little bit more in the lateral foot basins. We have tweaked our pump pressures and our pump rates and we feel good about what we're seeing in the results and the early time curve.

We are, in fact, have seen now a number of wells off of several different pads come online, short time, Michael, knowing that it is again, just kind of near-term cleanup production, 30, 40, 50 days, some of these. But it is exceeding our 4.4 type curve that we came out with at the beginning of the year.

So, all those things are, I think, contributing to just our ability to maybe break a little bit more rock, a little bit more near-wellbore conductivity and we're seeing the results..

Got you. And then if I could sneak one last quick one in.

Just on Atlantic Sunrise, does FERC need a quorum to issue a Notice to Proceed?.

I will turn that to Jeff..

Michael, the simple answer is no..

Okay.

So, basically, you get the other permits from the states and then the current situation, they could approve it?.

Yes. If you've been following the other projects in Southwest PA, in Ohio, West Virginia, et cetera, the Notices to Proceed are coming out on a regular basis from the staff.

Additionally, we've got some partial Notices to Proceed on Atlantic Sunrise for the mainline construction and you see those pop up about every week and they range from compressor station work to looping and other projects on the mainline..

Got it. Well, thank you very much..

Thank you Michael..

Okay. Our next question comes from Phillip Jungwirth from BMO. Please go ahead..

Thanks. Good morning..

Hey, Phillip..

Wondering if you could talk to the decision to budget $125 million this year for exploration and really just the need for a new core area when, I mean, on the surface, it's a little less obvious with 3,000 Marcellus locations remaining.

And then also could you just update us on your view of incremental Marcellus production capacity beyond the 3.7 Bcf a day ex-Constitution?.

Okay. I'll leave the second part of that question to Jeff. But in looking at our allocation of an additional $125 million, if you look historically at exploration budget and you assess the amount that we've allocated in the past, the $125 million is frankly right in line with where we've allocated in the past, less than except the last two years.

So, there's nothing unique about that level of capital allocation. When we began our effort of looking at our needs in the future to enhance shareholder value, we look at the Marcellus and the Marcellus is such a low capital intensity asset, i.e.

the need for the number of drilling rigs and the need for a number of frac crews to grow our production that we knew we were going to generate a significant amount of free cash. As I mentioned, even in the most punitive realizations Cabot has had in its corporate history, in 2016 we still generated free cash and grew that asset.

With this infrastructure build-out that is occurring as we speak and looking at the amount of capital necessary to fulfill all of the capacity of those new projects, it again is not going to take near the amount of free cash – near the amount of capital that we're generating and we'll have the free cash.

So, the need to do something with the free cash is an obvious question because we have it. We put that slide together where we've tried to box out and include on slide 13 the number of different considerations that we will consider with our free cash. We will touch on a number of them.

We'll touch on, I think, the distribution to shareholders with some of it. We'll also allocate the necessary amount to our Marcellus to grow every opportunity that we get but, again, it doesn't take much capital. And you could see by maintaining 3.7 Bcf flat for 25 years, we don't get much over $500 million, $600 million. So, the free cash is there.

We could do all these things that we're talking about.

One of the ideas that every company that is in our space, the E&P space – every company out there, and you can look at the hierarchy of valuations and those that you, in your portfolio, you recognize as companies that have significant value and have the opportunity to grow, you give them better multiples and more consideration and valuations and future valuations than you do those that do not grow.

Again, we're not in the business to burn capital. We thought we could make a entry into new areas, take a cost-effective look at our opportunity to find new return projects that compete with or exceed what we're allocating capital to right now.

And if we are successful in that endeavor, I think Cabot shareholders are going to be rewarded handsomely for the decision..

That's really helpful. And there's also, I mean, as you mentioned, a lot of focus on free cash. Wondering if you would expect to be free cash positive in 2018 in a material way after considering the pipeline contributions, increased Marcellus activity, core growth in the second half.

Or is 2019 really the inflection point for free cash where you get a full year's benefit of production and lower both pipeline and growth CapEx?.

I'll turn it to Scott for some, a little color. But the short answer is yes, we'll be free cash flow positive in 2018..

Hi. And Philip, that is correct. And the magnitude at least right now with current strip pricing, it will be in the same zip code or fairway as what we're expecting around the $250 million, slightly more than the $250 million, even with the expanded program in 2018.

So, if you think $250 million to $300 million is material, then the answer is a very definitive yes..

Okay. Great. And then last question just in the new slide deck, you point out that Northeast PA indices have been trading at a slight discount to Dom South.

I was curious if you have a view on whether this narrowing of price differentials between the two areas is sustainable as you look at pipeline capacity, expected to come on in the next year or two in both Southwest PA, Northeast PA.

And if so, is hedging Dom South an option that you guys would consider in the future?.

Yeah. I'll make a quick comment, Phillip, but yes, we're extremely positive about the direction of the differentials, what we're seeing right now in the narrowing has taken place. We gave some brief reasons in the teleconference talk about the reasons why we think that phenomenon has taken place. And yes, we do think it is sustainable.

And I think as the build-out occurs, I think we're going to see a better hedge market further out, but I'll let Jeff comment on some color..

Yeah, Phillip. I'm probably even the most optimistic in the group. Not only do I think it's sustainable, I think it's encouraging how the market has reacted to the initial onslaught of overbuilt infrastructure in the Southwest part of the play. To me, the best is yet to come on the – with the local demand.

Back to your original question, with the local demand in Northeast PA picking up, I mean, who would have thought even a year ago that we'd be supplying two major power generation facilities in mid-2018.

So, we're really optimistic that a lot of flowing gas will reach Atlantic Sunrise as opposed to a lot of the development gas throughout the Northeast region, a lot of projects being kicked around on gas-to-liquids, on methanol to gasoline, the CNG with moving around the different utilities up there.

So, very optimistic on the basis and how the optionality is going to be improved with all of the infrastructure..

Great. Thanks a lot..

Thanks, Phil..

Our next question comes from Charles Meade from Johnson Rice. Please go ahead..

Good morning, Dan, and to the rest of your team there..

Hi..

I apologize if I missed this in your prepared comments but did you give us a sense of the timeline for when you'd be able to give a verdict one way or another on these two exploratory areas?.

No, Charles. I hadn't given any timeline. But it is in our capital budget that we put out that we would be testing both of these ideas in 2017..

Got it.

And so, is it the right interpretation then, Dan, that you will be able to give a thumbs up or thumbs down in 2017?.

I think it's plausible that we'll have a lot of data that would give the likelihood that we could..

Got it. Thank you. And then if I could ask a question about your appetite to add in the Eagle Ford, it sounds like the way you describe your exploratory plays, that the Eagle Ford doesn't really fit as one of those because it's not greenfield leasing. But there seems like there's a lot of acreage that's coming up trading hands now.

And how does that stack up in your capital allocation evaluation?.

Yeah. A couple of ways. One, our Eagle Ford has improved as you've seen with the deck we just went through, our efficiency, our cost of business, cost of operations, the return that we are able to deliver and the strip pricing that we have out there right now. We're getting good returns in our Eagle Ford operation.

Now, those returns do not compete with our Marcellus operation. So, what our objective in looking out ahead is not only did we evaluate some of the acreage in the Eagle Ford when we assessed where we might be allocating additional capital.

But in the areas that we have gone to, we felt comfortable that we would be able to maybe even enhance our return profile in these new areas above what we are seeing in the Eagle Ford. And if, in fact, that is the case, we are going to certainly be pleased with those results.

When you look at the other assets that are in the Eagle Ford, that might be in play out there, you have to burden some of that with the full-cycle consideration that we have talked about in other basins where there was a lot of activity.

And when you stack that on top, again, you have to measure the full-cycle returns to see if it's what we want on a go-forward basis or do we keep looking someplace else..

That's helpful color. Thanks, Dan..

Thank you, Charles..

Okay. Our next question comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead..

Good morning, and congratulations on all the fine results..

Thank you, Jeffrey..

I wanted to ask a little bit different questions about the exploratory tests, if I could. I just want to kind of get an idea of what you're going to do, not trying to ferret out locations and whatnot.

I was just wondering, are you going to shoot any seismic prior to drilling? Is there an existing well control in the plays that you're in? And will the first test be vertical or horizontal wells?.

Yeah. On all of that, we have seismic. We do plan on shooting additional seismic. We have control points, subsurface control points that we've incorporated into our interpretation. And the initial process would involve a combination of both verticals to gather core data.

And then probably a short lateral to evaluate the section a little bit more thoroughly. So, yeah, and all of that is included within our capital program..

Okay. That's very helpful. Appreciate it. Your Eagle Ford results, I thought, actually, I mean, it has significantly improved. I was wondering, you've listed three variables – 25% more sand, 58% reduced cluster spacing, and intra-stage diversion where you weren't doing that before.

I was just curious, are any one of these variables any more important than the other or is it just sort of a fairly even and cumulative effect?.

I'm going to turn it to Steve Lindeman who runs our Eagle Ford operations. But there is a cumulative impact, but I'll let him articulate..

Yeah. I agree with Dan's comment. It's cumulative in our opinion. We're studying each one of those components. Obviously, as we see sand costs increase in the area, we're looking at what gives us the biggest bank for the buck. And so, we're dissecting all of those components so that we spend the completion dollars as efficiently as possible..

Okay. And if I could just ask one more on that point.

So far, how much is the increased completion design increase the completed cost of the wells?.

So far, it has been very nominal for us. Roughly, I don't want to get too granular, let's see, maybe less than $400,000 or so a well. As we go into the latter half of the year, we do and we have budgeted for an increased sand cost and that's where we're going to be further analyzing each one of these components..

Right. Understood. Thanks very much. Appreciate it..

Thanks, Jeffrey..

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

Good morning, guys. Thanks for taking my questions..

Hi, David..

Just curious on the Marcellus completions now.

Have you seen early data for outperformance relative to curve? And then I guess even with the Gen 4 curve, has the choke management philosophy changed at all over the last year or so with the new completions relative to your prior design?.

We are – well, from the last year, not really. We do kind of bring these things on slow. We are able to turn them in line fairly soon after initial completion and we do manage it, but it's not like you might think if it was a high over-pressured reservoir choke management, but we do manage it. And we've been doing that though for over a year..

Okay. And then the last one for me, I think other people have asked plenty of questions, you've given good color on the exploration initiatives. But you mentioned also earlier that you were evaluating a lot of different opportunities including being in data rooms for valuation markers.

And I guess, is it fair to say that for most bolt-on deals or deals that you were in data rooms for some larger packages out there that the full-cycle returns would have been sort of prohibitive to pursue that relative to some of the other assets that you have and that maybe the best course of action was to do more greenfield activity right now?.

Absolutely. Yeah. When we first began well over a year ago, couple years ago, actually, and as the M&A market intensified and the number of deals increased, we were very proactive in trying to understand valuations and understand the dollars that were going into these projects and wanted to evaluate the full-cycle returns.

So, we did gather a significant amount of data to look at that, but we had to approach this in a little bit of a unique way because we did have and do have a company that has really good assets. We were growing this company and anticipate further growth, certainly, once the infrastructure gets in place.

We were generating free cash even in the most punitive price realization environments that we have seen in years.

So, we didn't want to mess that aspect of what we can deliver to shareholders up and confuse the market on whether or not the investment of that any free cash going into another area for a large M&A transaction, what it would do to a full-cycle return profile once you melt it altogether.

And we made the decision, actually fairly early on that, that did not return, again, full-cycle the values to the shareholder that we wanted to see. So, we began, continued in earnest, to look for ideas that we thought we could create as a grassroots effort and that's where we have gone..

Appreciate it all..

And I'm pleased with a couple things. One, I'm pleased with, one, being able to find ideas in this competitive environment that would fit that portion of our evaluation. And again, with a company of Cabot's size, I'm also pleased that we're going to be able to get to the scale that we need to be able to move forward on these projects also..

Thanks, Dan.

And then just the last housekeeping one for me, the $60-some-million or $66 million spent in 1Q on these initiatives, does that largely reflect the cost of entry? Or I guess should we see that coming through – I guess if I was to split up the budget in half, is the remainder of it just for more well specific and planning evaluation-type work or is there still some entry costs coming in in the second quarter?.

The $66 million in the first quarter covers a large percentage of the lease acq [acquisition]. A very large percentage of the lease acquisition. We'll have a little bit more on top of that, but we feel very comfortable that the remaining amount, i.e.

the $125 million total budgeted for this effort is going to be adequate to not only cover all of our anticipated lease acq, but also cover the testing phase..

Thanks, Dan, and best of luck..

Thanks, David..

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

Thank you. Good morning..

Hello, Brian..

You mentioned in one of your slides that you're still exploring other outlets for Marcellus gas and I wondered if you could give us an update on how that's looking beyond the projects that you've talked about that are going to be hitting the books in the next couple years? What some of those other outlets are and how significant they could be?.

Thanks, Brian. I will turn it over to Jeff..

Yeah, Brian. Thanks for the question. I think earlier, I touched on a few initiatives that we're looking at particularly local demand in the region that we operate. The projects that we're looking at are in a somewhat smaller scale attached to our gathering system.

There's a lot of ideas floating around the CNG aspect, moving CNG gas to different markets. Also the small peaking power plants, we've added a couple of those just up here in the last few months. We're looking at several larger scale projects with ethanol developers and methane, the gasoline projects.

We're also looking at additional market share and teaming up partnership with market on a couple projects. We have not ruled out another pipeline although pipelines are challenging in this environment but we're continuing down that path with, again, a couple of markets.

I think the PennEast project is going to allow for some additional development that we're, I would say, in the midst of finalizing negotiations on additional market share there. So, it's exciting up there.

There's still a lot going on, a lot of moving pieces and I still expect the landscape to be quite different a year from now in a positive way than even where we sit today..

Great. Thank you. And one quick one and I apologize if you said this earlier.

But with regards to the exploratory areas, can you say whether you are looking for or whether your expectations are for oil, dry gas or liquids-rich gas?.

Yeah. What I had indicated, Brian, was that our focus again, one, two, and three was just on a return, that we were indifferent on the commodity. At this stage, it's looking at, like, that our focus is going to be oil at this time though, where these ideas have floated to the top..

Thank you very much..

Okay. Our next question comes from Karl Chalabala. Please go ahead..

Good morning, gentlemen..

Good morning, Karl.

How are you?.

I'm well. Thank you. There's a view that NIPA growth is somewhat finite near term until these capacity expansions come on line but the guidance raise would indicate production, including Cabot's, can grow prior to that and local pricing likely remains supportive given the current bound storage levels and then, of course, the evacuation on the horizon.

Could you sort of discuss what this in-basin market share looks like, Cabot's market share potential near-term particularly next winter? And then how the company is thinking about potentially capturing local market share growth above FTE capacity when the basin debottlenecks?.

Yeah, I will – we do have a slide out there that has – I'm thinking we had a slide in one of our presentations that had the market share and our percentage contribution to each indices, but I'll let Jeff handle the other question..

Okay. So, it really follows along what we've talked about here on this call and a few areas on the local band (47:37). We've got a very active program on market development up there. We've explored a lot of opportunities.

We continue to think that having dependable, reliable reserves and the optionality that we have with our infrastructure up there, our gathering infrastructure, gives us a lot of advantages in moving gas to different markets and during different time periods.

We went through a number of expansions on the gathering system with our partnership now with Williams and we've really created a unique opportunity for Cabot in allowing our gas to have access to multiple markets even on a daily basis. We've tested this concept.

We're able to move gas between pipes to take advantage of pricing but also just to take advantage of capturing market share when a pipeline goes underutilized.

We do expect though longer term and even as we enter early 2018 to mid-2018, as our power plants get ready for service and the Atlantic Sunrise project and even further out a little bit, PennEast, we expect to see a lot of flowing gas that's currently on our three major pipelines to fill the capacity that some producer-shippers and market shippers have purchased on these new projects.

We think that's going to free up some capacity in the existing pipeline infrastructure and we'll be able to grow some market share, particularly on the pipes that we do business with our customers on a daily basis. So, I guess we're teeing it up to take advantage of what we've participated in, in terms of commitments of FTE and the power generators.

But we also think there's a unique opportunity to grow our market share based on what we see on the activity level with our peers and how we perceive the basins, fulfilling the new capacity in the next 18 to 24 months..

Got it. Thank you. That's very helpful color. And then I guess sort of subsequent to that, if you could discuss your – obviously, this production growth this year, the rates, just getting done with the one rig, one completion crew plan.

Can you sort of discuss how the company plans to add either rigs or more completion crews into and through early 2018 as Sunrise and the rest of the power, Orion, and other projects come on line?.

Yeah. We do plan in 2018 that we'll most likely just be adding a rig and a frac rig. That's all that's going to be necessary to grow into the new capacity. And then the 2018 program, when you look at outside of the Marcellus, the 2018 program is going to take in consideration not only where we are with our Eagle Ford.

And again, the gaining efficiencies in return that we see there, but it will certainly be augmented with new data coming from our couple of areas of testing that we're going to do during 2017..

Got it. Thank you, guys. That's all I have for today..

Thanks, Carl..

This concludes our question-and-answer session. I would like to turn the conference back over to Chairman, President and CEO, Mr. Dan Dinges, for closing remarks..

Well, again, thank you, Phil, and thank you, all, for taking the time for the call.

When you look at Cabot, you look at the efficiency of our operation, generating significant free cash, you look at the improving macro environment, you look at the new infrastructure that's coming and now, you layer on top a low cost entry into evaluating a couple of ideas that could mean significant value for our shareholders.

I know all of our team is very excited about what we have out in front of us. So, stay tuned. Look forward to visiting with you next July. Thank you..

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