Coterra Energy Inc (CTRA) 2017 Q2 法說會逐字稿

Good morning, and welcome to the Cabot Oil & Gas Second Quarter 2017 Earnings Conference Call. (Operator Instructions) Please note, today's event is being recorded.

I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO. Please go ahead, sir.

Thank you, Rocco. And thank you all for joining this morning for Cabot's Second Quarter 2017 Earnings Call. I have Cabot's executive management team with me for the call this morning.

Before we get started, I would first like to highlight that on this morning's call, we will make forward-looking statements based on current expectations. 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 measures, are provided in this morning's earnings release.

For the second quarter, Cabot delivered another successful report card, highlighted by 14% year-over-year production growth, while generating positive free cash flow for the fifth consecutive quarter. Our production growth for the quarter was driven by 15% increase in net Marcellus volumes year-over-year. This production...

(technical difficulty)

Pardon the interruption, ladies and gentlemen. It appears we've lost the audio from the speakers' location. We will order to be reconnected. In the meantime, we're going to put some music into the call. Thank you.

(technical difficulty)

[id="-1" name="Operator" />

Pardon with the interruption, everybody, this is the conference operator. I've joined Mr. Dinges' line back to the call. The floor is yours, sir.

Floor is mine. I'm not sure where I left the floor.

[id="-1" name="Operator" />

You disconnect right after the forward looking statements, sir.

Okay. All right. We can retool. Would you check and see if we pay phone bill, please. For the second quarter, Cabot delivered another successful report card, highlighted by 14% year-over-year production growth while generating positive free cash flow for the fifth consecutive quarter. Our production growth for the quarter was driven by 15% increase in net Marcellus volumes year-over-year. This production growth, coupled with an increase in Marcellus cash margins of almost 100%, were the primary drivers for our strong cash flow growth year-over-year.

Our year-to-date results further highlight what our high-quality asset base is capable of delivering, including the generation of $123 million of positive free cash flow despite realizations of an average price of about $2.50 for natural gas and $45 for oil. This positive free cash flow is net of the capital we utilized during the first half of the year to invest in growing our year-to-date production volumes by 10% year-over-year, to contribute to our equity ownership interest in the Atlantic Sunrise and Constitution Pipeline projects and to fund our grassroots-leasing efforts in our two exploratory ventures, all of which provide us with optionality to create value for our shareholders. Of the $123 million of positive free cash flow, we have returned $100 million to the shareholders year-to-date via dividends and share repurchases. As a reminder, during the second quarter, we increased our dividend by 150% and repurchased 3 million shares at an average share price of $22.41.

As I've reiterated over the past few quarters, we are committed to returning cash to shareholders while generating double-digit, returns-focused growth for the foreseeable future. And I believe our actions during the quarter demonstrate that commitment. We will continue to focus on increasing our return of capital to shareholders as we gain more conviction in the timing of our new infrastructure and power plant projects and our resultant ability to execute on our robust growth plans over the coming year.

I would highlight that when I mention robust growth in the future, I am referring not only to production growth but also growth in free cash flow. While many of our industry peers are highlighting the ability to generate double-digit production growth within cash flow a few years from now at commodity price assumptions that are higher than the current strip, we are already delivering on this plan today.

Our balance sheet continues to improve as we exited the second quarter with a net debt to trailing 12-month EBITDAX ratio of 1.1x, which is in line with our long-term target as we continue to manage our business around maintaining an investment grade-like balance sheet. We continue to maintain over $500 million of cash on hand and have approximately $1.7 billion of available commitments under our credit facility. This little liquidity allows us flexibility in the volatility -- in the volatile environment as we assess all opportunities to create value for our shareholders and manage risk.

In this morning's release, we also reaffirmed our production growth, unit costs and capital guidance for the year despite a small sequential decline implied by our third quarter guidance due primarily to mechanical issues at a third-party compressor that will likely continue until late August. We are very confident of being able to achieve our full year production targets.

To illustrate this point, if you were to hold the midpoint of our third quarter guidance flat in the fourth quarter, we would hit the midpoint of our 8% to 12% full year production guidance range. However, our current intent is to grow our volume sequentially in the fourth quarter based on our price expectations. Additionally, we are still targeting a 15% to 25% of returns-focused growth in 2018, which will ultimately be dependent on the timing of infrastructure projects throughout the year.

Moving on to our operations for the quarter in the Marcellus. Our volumes for the second quarter were essentially flat to our first quarter volumes, which was in line with our expectations and guidance. We brought online only 6 wells as we had planned to do. Our Marcellus price expectations and realizations remained strong during the second quarter, increasing approximately 50% year-over-year. While we are forecasting a slight widening of basis steering in the third quarter, based on the current strip, we anticipate that fourth quarter differentials will revert back to levels similar to the first quarter of this year before significantly improving in the first quarter of '18. This anticipated improvement is driven by the potential for approximately 6 Bcf per day of new takeaway capacity to be placed in service throughout the basin between now and the end of the first quarter.

On the well productivity front, we continue to see positive momentum, driven by the results of our Gen 4 wells. Year-to-date, we have placed 26 Gen 4 wells on production and the average production per lateral foot continues to outperform our 4.4 industry-leading Bcf per 1000 feet type curve. We recently implemented a pilot program to test a new completion design that is focused on reducing our overall completion cost, highlighting our ongoing effort to identify new efficiency gains and to mitigate potential well cost inflation in the future.

In our Eagle Ford, we grew our daily oil production by 9% sequentially during the quarter despite a few operational delays, most of which were outside our control. Additionally, as we highlighted in the press release, our long lateral wells are taking a little longer to clean up and reach peak production levels, which has caused us to adjust our timing of the estimated production profiles for these wells. However, the overall estimated recoveries from these wells on a per lateral foot basis has not changed, given that our longer lateral wells ultimately catch up to the type curve within a few months of production and have demonstrated a shallower decline.

On the cost front, we realized another 9% decrease in our Eagle Ford cost -- drilling cost per foot relative to the first quarter, driven by faster drill times, for which the cost savings has helped us offset the incremental completion cost associated with the higher-density completions. We have obviously experienced a weakening in the outlook for oil prices since our first quarter call, which puts pressure on all oil projects, including returns in our Eagle Ford, despite continued improvement in our operating efficiencies.

Our current plan is to continue to execute on our program for the remainder of the year, given that most of the capital we are allocating in the Eagle Ford during the second half the year is committed to or related to leasehold maintenance obligations. However, as we've began formulating our plans for '18, I want to reiterate that we plan to remain disciplined with our capital allocation. We evaluated all of our opportunities, and we continue to evaluate all our opportunities to create value for shareholders in a sub-$50 oil price environment. Allocating any incremental capital to the Eagle Ford above what is needed to hold production flat and to maintain leasehold likely falls behind our superior returns in the Marcellus acceleration program and returning cash to shareholders in the pecking order.

Infrastructure. Atlantic Sunrise remains on schedule for a potential start -- construction start date beginning this quarter. As most of you are aware, we filed our final PADEP and U.S. Army Corps of Engineer permit application back in May, late May. We are now planning to receive both of these permits by late August, which would likely result in a mid- to late-September construction start. I also want to highlight that the Chapter 102 and 105 permits from Pennsylvania and the U.S. Army Corps of Engineers 404 permits are unrelated and will not necessarily be issued in any particular order. Based on the expectation of a 10-month construction period, the expectation remains for the pipeline to be in full service by mid '18. We feel very confident in the timing of our remaining projects, given that the TGP Orion is now expected to be placed in service in December, which is significantly ahead of the original schedule, while our 2 power plant projects, Moxie Freedom and the Lackawanna Energy Center, are currently under construction and on schedule.

Also, a short update on Constitution, as there's been a few interesting Constitution-related data points regarding similar projects that have also been denied permits or delayed by the New York DEC. We continue to await the outcome from Constitution appeal in the Second Circuit court, which will likely see some movement during the third quarter. In the meantime, Constitution operator continues to assess various legal strategies in addition to our ongoing appeal. Williams has recently been vocal regarding their ongoing dialogue with the current administration surrounding our options on this project. We will continue to monitor this process. But we feel more optimistic about this project at -- and becoming online in the next few years than we did, say, a year ago.

A brief comment on the exploration front. The exploration effort is on schedule with our program. We have amassed a similar level of net acreage as our Eagle Ford footprint in one of our prospects, which is located in Texas. We have also secured a significant amount of acreage on our second prospect. The plan is to -- on the -- the plan is to drill and evaluate the prospects with 5 wells between now and the end of the year. Additionally, we plan to remain within our budget of $125 million for all of this effort. This effort does not deter from, in any way, our laser focus on generating our superior returns from our Marcellus operation.

In summary, based on our increasing confidence and the timing of the infrastructure build-out in Appalachia, coupled with our deep inventory of high-return drilling locations, we believe that we can execute on a program that will provide double-digit, returns-focused production growth while generating free cash flow, further strengthen our balance sheet and liquidity position, improve our unit cost and margins, drive further improvements in capital efficiency, delivers an improving return on capital employed, and returns an increasing amount of cash to shareholders, all while assuming commodity prices that are no higher than today's strip. There are not many companies that can support a bullet point list similar to this.

With that, Rocco, I'll be happy to answer any questions

(Operator Instructions) Today's first question comes from Charles Meade of Johnson Rice.

I wanted to ask about your share buybacks. I think I understand your -- what you're trying to indicate about the confidence in your cash flows from the midstream deals. But I wondered, can you elaborate more on what are the other pieces of your thought process as you're going to evaluate future stock buybacks?

Yes, I'll let Scott -- Scott loves handling all the money and make these money calls. So...

Charles, when you look back on our history, even in the last 10 years, we've been in and out of the market at various points based on our level of cash and things like that. At the end of the day, it is an opportunistic buyback. We've had authorization for a long period of time. Our authorization now is down to about 7 million shares when it was split-adjusted. that means we bought in about 13 million shares in our history in the last 10 years.

And again, it is simply the fact that when we see -- internally see a disconnect with what we know what's going on versus the marketplace and we have no dilutions, we understand the market is efficient. But there are -- at times, there is those disconnects, and we saw that in the second quarter, and we want to send the message. So we're using some of that free cash flow, rather than just let it sit on our balance sheet, to buy in the shares. And again, right now, we've made a very economic decision with $22.41 versus the $25 we're trading at now.

We will continue to be opportunistic. And I don't want to leave the impression that it's got to get back to $22 before we will be active in the market. Again, when we see weakness, we'll be opportunistic.

Charles, I might add also, as we progress in our plan and we get the infrastructure approval that we anticipate, we start ramping our program into filling that -- those lines and incremental production. We see the compression that we expect in the Marcellus of the differential up there. Our realizations improve. We're going to be generating a significant amount of cash. So that also will be a strong influence on -- and a dictator of how we allocate cash back to shareholders.

Dan and Scott, that's helpful insight in your thinking. And Dan, I wanted to ask my second question about the -- these Gen 4 completions. And I liked the update that you gave us. I think it's on Slide 10 of your new presentation. But I'm wondering if you can -- could guide our interpretation a bit of that. When I look at it, I see that those 2 lines are separating in the early days. But then they kind of seem like they're becoming more parallel on that cume versus time. So to me, I'm thinking maybe these Gen 4 has outperformance in the early days, but then kind of settles in to a -- similar to your past completions. But is that the right way to look at it?

Well, I agree that it's maybe running a parallel course which, in my opinion, is actually good. We see that it does go past the 4.4 Bcf type curve on the slide that you're referring to. But running parallel and above that 4.4 Bcf line is what we are seeing and what we're pleased with. So as you travel out, if it continues running parallel, it's obvious that we would be capturing maybe greater than the 4.4 Bcf per 1000 foot of lateral.

And our next question today comes from Doug Leggate of Bank of America Merrill Lynch.

This is John -- no, this is not Doug. This is John Abbott calling in on behalf of Doug. Just a couple of quick questions on our side. First, how are you thinking about the ramp, your ramp into Atlantic Sunrise? Are you thinking about growing aggressively into that or taking volumes potentially from -- that are constrained elsewhere and moving it over?

And then second, what -- and second, with regards to the Pennsylvania permit, what is the -- what benchmark should we be looking there in order to see that get finished? I mean, you're expecting it here shortly, but what else needs to be done?

Okay, I'll return -- I'll give the second part of that to Jeff. But on the Atlantic Sunrise growth, we've kind of been clear on the ramp. It's not going to be instantaneously incremental. We are going to shift volumes out of basin where we've had punitive differentials. We think with that shift that we should see, as we expect, a narrowing of that differential in basin, which would affect positively the gas that we do continue to produce in basin. And then we will continue to grow the volumes incrementally into the new capacity that Sunrise affords us. So it'll be -- it won't be instantaneous. But we certainly are planning our '18 program as we're preparing to present to our board in October an increased capital program for '18 that would allow us to grow our production in the 15% to 25% range, as we have outlined.

Appreciate that. And then with regards to the Pennsylvania permit, what do you see -- what's left there for that to be done?

Yes, okay, John. Yes, we have 2 outstanding permits. They're commonly known as the Section 102 and Section 105 permits. You're probably aware that the Pennsylvania DEP went out for public comments back in May on these 2 permits, but that was closed late June. There were several thousand comments submitted. And quite frankly, a lot of them were positive. And right now, the DEP is sorting through those comments, preparing answers and finalizing the last-minute data request from questions that may have come up during that comment period. So we're expecting, going forward, that these permits are just getting the final touches put to them, so to speak. And they'll be out the door here mid- to late August.

And our next question comes from Brian Singer, Goldman Sachs.

Dan, in the past, you've indicated interest in maintaining some level of diversification in the portfolio, even if modest, with the Eagle Ford representing that place in the portfolio today. With the focus, understandably, on returning cash to shareholders even ahead of Eagle Ford drilling, are you now more comfortable with the asset base being even more leveraged to Northeast PA? And if so, are there changes that are increasing your long-term confidence in growth from the region beyond a couple of pipelines and power plants that you've spoken about today?

Well, as we get closer to the realization that we will be able to start construction on infrastructure and move significant volumes, not only in the pipelines up there, but I think there's other projects that would be supportive of the differentials and realizations that -- and improve the realizations that we've seen in the past. As we go through that process and we get shovels in the ground, absolutely, we're incrementally more comfortable about, not only our growth horizon, but also our ability to return even more free cash to our coffer by virtue of the growth and improved differentials. There's still a look at a -- the 2 exploration programs that we feel like, if successful, could return significant value for our shareholders. And we are going vet those through the data-gathering process that I've outlined. With the -- going out and looking out in the Northeast and looking at the power plant projects, looking at the Atlantic Sunrise, yes, we have anticipation of Constitution also securing the approval later, whether it's 2019 or 2020. We think that can be an incremental gain. We do know that there is committed-to-firm capacity in the infrastructure up there that might not be filled by those holders of that firm that also provides an avenue for future growth up there also.

So between now and 2020, compared to where Cabot has been on the last 3 years, just trying to battle the regulators and the anti-group trying to stop pipeline from being installed, I am extremely optimistic about the near term for Cabot. And our concern about diversity or growth mitigates each day as we get closer to these infrastructure approvals.

Great, and that's helpful. Small follow-up on exploration. And I think in your comments you mentioned that one of the 2 projects was in Texas. Can you just -- I think last quarter, you said that at least one of the projects was seeking oil. Is that still the case? Can you give any color on the second project? And when, on either one, there'll be more color that you can share from a well-performance perspective?

Yes, we are. With these 2 prospects, they are tied to a diversity, if you will, in the commodity mix. So yes, oil is the focus. And as we gather additional information through between now and the end of the year, we would only be speculating in the, what we anticipate we do, continue to do our due diligence and looking at the data that we have in hand, looking at the reprocess seismic that we continue to work and continue to gather more data, and some of it being subsurface data from the past in each of these prospect areas. So the data we gather continues to reinforce our concepts on both of these prospects.

So from timing, Brian, on when we might have something solid, I really think it would be after the first of the year. Ideally, what I would love to see would be 4 or so wells in each prospect area tested, some flow back period. And with those test and flow back period, we can give you cost examples. We could give you return profiles. We could even look at the quality of fluid mix to talk a little bit more in-depth about what it's going to take on the surface side of the business and infrastructure side and give assurances that we've mitigated risk on program execution from logistics. That's when I would feel great about talking about it. I'm sure we'll be asked about it, and maybe we'll process out a little bit of information along the way. But that's kind of, overall, in a summary fashion, how I look at releasing data on exploratory projects.

Are there any wells that are down today? Or is it just the 5 that are going to be drilled between now and the end of the year?

The only wells that are down today are wells that had been drilled subsequent to us getting into the area. And that was typically wells drilled years and years and years ago.

And our next question comes from Bob Morris of Citi.

Go, Bob. You must be on mute.

Hello, Mr. Morris? Okay. Well, we will go to the next question, which is from Jeffrey Campbell of Tuohy Brothers.

I think my first question is probably a Jeff one. I was just -- recently, it looks like New Jersey is trying to imitate New York with the recent PennEast permit denial. I was just wondering if Jeff could give me his take on whether or not he thinks this is particularly significant at this point in the -- well, with PennEast?

Yes.

Sure, Jeffrey. So we, as a shipper on that project, we do communicate quite a bit with the operator and the other partners. The New Jersey denial was not unexpected. They realized that there's additional data that was necessary and required. And quite frankly, they were moving toward that. And when we lost the FERC quorum, as you know, PennEast is still pending a certificate. But in this law, I guess, the -- what I understand is they've moved toward the complete application at this point, and it will get a second look.

Okay, great. And then just on -- I just want to make sure I wasn't confused. Did you say that you're going to drill 5 total exploratory wells second half? Or is it going to be 5 in each one of these 2 exploratory areas that you've referred to?

Yes. Two different things. One, we're going to plan within our $125 million budget to drill 5 exploratory wells in the second half. My comment on having 5 wells in each prospect was just an example that says that ideally, I would like to have, before we make full disclosure or full release, I would like to have that level of detail to be able to lay out and give the shareholder the confidence that we have really vetted these projects, as opposed to coming out with just a little bit of information that would be maybe somewhat more speculative or not having any type of term to a test, except for -- in 1 area or 2 areas or something like that. I'd like to be able to see a little bit more information before we would make any release. I understand entirely though, as we get pushed to release information, that we'll do our best to accommodate those request without giving away too much information and without speculating too much.

Okay. And with that color that you just provided, I'm just wondering, the 5 wells you're going to drill, are you going to do some preliminary exploration in both of the plays? Or are you concentrating the 5 wells in 1 of them at this time?

No. We are, right now, have -- we have 4 wells in 1 area. And the 4 wells that we have in the one area is the area that we had less subsurface control points to be able to mature our concept. And so we are gathering additional data there. One well in the other area -- in this other area, we had and have more subsurface information. And we have more information to mature our concept upfront in that area. But the drilling of the well would assist us in proof-of-concept on some of our ideas.

And our next question today comes from Holly Stewart of Scotia Howard Weil.

Maybe first one for Scott, just on uses of capital. Just how are you thinking about sort of balancing the buyback versus the '18 maturity?

I think it's not a -- it's definitely not with our financial position in either/or. As you know, we have a fully undrawn revolver and -- of $1.7 billion. So in worst case scenario, if we saw an opportunity to use disproportionate share of that free cash plus what's on our balance sheet, being opportunistic, buying in shares, we would follow through on that opportunity and not worry about that we need to hold some of that reserve for the '18 maturity. The '18 maturity does go current. So you'll see it as current. Actually, this month, most of it does. So you'll see it in current in the third quarter 10-Q.

As many of you know, Cabot is unrated by design over the years. One of the things we're going to explore is a refinancing strategy on that, where we actually go to the public markets, get some indications from the agencies. We haven't been hurt by not being rated. At the same time, the size of the company we are and where we're at in our kind of life cycle, it's probably time to explore that option. So that will also be taking place over the next, probably, 6 to 8 to 10 months.

Okay. So help me with that. If you're not considered investment grade, don't you have to post LCs for the pipes?

No, because we have a long-standing track record. And we are investment grade in the private placement market. And we've worked through all those hurdles over the years.

Okay, great. And then maybe one just for Jeff on Constitution, given what we've seen with Millennium and Northern Access here as of late. I mean, any insights into the appeal? Or maybe how you're thinking about the future paths to take going forward?

Sure, Holly. Of course, not just with Millennium and also with National Fuel. I hesitate to use the word, plot thickens. It may be appropriate. And regarding the Constitution and our appeal, we're kind of on the tail-end of the path period, where we expected the Second Circuit to give us a ruling. So that's getting close. It is a complicated case, so it may not be right around the corner. But our expectations are that we'll see something out of the courts fairly soon. I think that the bottom line on the Millennium case was the impending back authority levels to the FERC is obviously a very good thing, and we'll see how that plays out. Probably has a shorter duration to play out as we -- in the next few months as we see what the DEC actually does with that permit application here soon.

And then National Fuel, of course, has such a similar set of facts that we have with Constitution in their plate with the short pipeline and can be a New York-based company and the job creations and all the good things that, that new pipeline does is, again, very similar to Constitution. And we expect some clarity on just how we're going to be operating in New York.

And our next question comes from Drew Venker of Morgan Stanley.

I was hoping you could speak to how this exploration program might play into your decisions around plans to accelerate return of cash to shareholders, and how you kind of envision the timing. Because obviously, results are difficult to predict, as you had noted. And you might want to engage in a lot more testing before making a call to go to development mode, or you might be disappointed and decide to cool down the program. So maybe you can just speak to that.

Yes, that's -- it could be a -- I can make a short answer a long answer. I'll try to get it in between. But our idea is to always improve our lie and to improve our capital efficiency. We believe that the best areas to allocate capital are in core areas, and I would define core areas are -- as like our Marcellus. And there are probably are several others may be very core areas in the oil areas that would allow capital to be allocated, returns that would generate, not only growth, but also free cash. Our objective is to try to improve our lie over any areas, like our Eagle Ford, that I do not -- it's a good asset, certainly we're running, even at these lower-threshold commodity prices, our weighted average cost of capital. But I don't believe the company survives on just drilling areas that have a return profile based on the weighted cost of capital. So our objective would be to improve our lie and be able to do it in a way that would return, not only significant returns-focused growth, but also free cash, which would in fact allow us to generate more free cash to give back to shareholders.

So that's our objective. If we were on your fail case or uncertain case, if we were to not be able to get to a core asset profile with our exploration program, and then, though we saw that our infrastructure projects we're taking off of the Marcellus, we decided to go in that direction solely as an ongoing project, which by the way, is a high-class problem to have with those assets, if we made that decision, I am confident with the subsurface data we have, with the concept design we've created, that there is going to be incremental value in these assets, in these 2 projects. And if, in fact, they were not core-type projects for us, I'd still think that with the dollars invested, entry level at a very, very low cost, that we would be able to generate significant returns for the shareholder if, in fact, we decided to monetize those assets.

Okay, and that's all very helpful color, Dan. And just on the timing of when you think you would be able to make a call or would like to make a call, is that in the next 12 months? Or is it end of '18 or potentially beyond that before you decide, it really does look like a core play or it doesn't?

Yes, yes, Drew. I would think that -- I would be surprised if it goes beyond 12 months that we would not be able to rationalize where, with a fairly high degree of confidence, where in our return profile expectations that these 2 projects would fall.

Okay. And then to the envision that you did, you did not have as much success as you wanted. Is that when you would try to accelerate that cash return to shareholders or let's say, its in 12 months or something like that?

Well, we would make a decision at that time, similar as we make decisions today, with the facts and information in front of us.

And our next question comes from David Deckelbaum of KeyBanc.

Could you elaborate a little bit more on the pilot program that you have in the Eagle Ford to reduce well costs? Is that a function that you've tried some enhanced completions there, and you're looking at some tweaks on just optimizing that cost down, and perhaps you maybe use a bit too much services on these wells? Or is it a -- how are you guys thinking about balancing that? And what's the pilot program really looking at?

Yes, yes, good question, David. I'll let Steven Lindeman fill that question.

David, throughout the year, we've done a number of things. Again, as we released, we've been working to drive our drilling cost by drilling longer laterals. In this quarter, we completed lateral lengths up to 12,000 feet. And in addition to longer laterals, we've been doing some cluster spacing testing, some diverter testing, and those are the kind of results that we're digesting right now. We've also upped our sand volume, which is one of the things of late that have increased completion costs. And so as we get more production data in on this population of wells, we're going to look at what combination, or what -- how we can optimize that to increase the return, whether we decrease sand, whether we adjust our clusters or look at what lateral lengths we might go to. So those are all the knobs that we're working out right now.

Okay. And is that just a function of the longer clean-up times? This might cannibalize some of the returns there, just with the larger sand volumes.

Yes. The -- clearly, what we're trying to do from a return perspective is up the initial rate. But obviously, our long-term goal is to increase reserves from each well. And we're happy with what we're seeing in terms of the reserve profile that we're seeing a flatter decline. But we just -- with the additional water that's being applied, and maybe it's a function of the additional cluster, so that water is staying nearer to the wellbore. It's just taking us longer to update those decrease.

That's helpful color. And the last one for me, Dan, this -- I think recently, you kind of discussed the sensitivity around the Eagle Ford program. It sounds like the back half of the year, you said that capital is locked in for a leasehold. As you get into '18, is the Eagle Ford program -- are you at a decision point, really, that's sensitive to commodity price as to whether you want to sell this asset or sort of continue in a single rig sort of development mode? And is that price point closer to $50? Or...

Yes, at the level that we're in right now for oil commodity prices, what we've been doing with the capital allocation and the decision point to allocate capital to the Eagle Ford has been really based on lease obligations and maintaining our commitment and not losing any of the optionality that we would have in the future. And certainly, in the event that we do get improvements in the commodity price, that either way, whether we decide to allocate additional capital to it or if we decide to monetize, in either case, we want to maintain and keep all of our optionality and -- in it. And so the pinch point is, what kind of lease requirements that we need to complete, to maintain that full leasehold position.

So when you look at our entire program, we have -- we're running dual tracks here. We're looking at our return profile with every dollar we spend, and I understand the angst with shareholders on, why are you allocating money to a project that is not returning the superior returns, that maybe a Marcellus would. But again, there's a lot of capital in the industry being allocated that don't return what the Marcellus does. And I think, though, that when we move forward with our exploratory projects, we do increase our optionality with infrastructure build-out. It gives us the ability to be a little bit more aggressive, if you will, in the decisions we make on where you want to allocate, how we want to allocate, what we want to monetize, and do we have some other options to maybe create additional new venture projects that need a threshold definition, as we would say, as a core asset for us.

So we're really running some dual tracks right now with -- and still trying to maintain our acreage position in the Eagle Ford. And the team has done a great job. That has allowed us to, again, continue to get the returns we want. But everybody is wanting to have a program that would generate greater returns from the cost of capital.

And today's next question comes from Mike Kelly of Seaport Global.

I was hoping to just probe a little bit more into this -- the, really, the hurdle rate or threshold rate you're going to judge these new venture plays against. And if you can give us kind of a ballpark project return that really will improve your lie, or generate growth and free cash flow. I know you've laid out the Eagle Ford is 45% project return at $50 and Marcellus Shale is 120% at $2. I would imagine it is somewhere in between there. What's kind of your ballpark rule of thumb? Or what's acceptable to you?

Yes. Mike, I'm not going to get down that granular. We have described exactly what you just laid out, that we're looking to improve our lie. We're looking to be able to find projects that would enhance the shareholders' value. And we think that from an Eagle Ford position-type asset, I don't consider that level of return as core. I do return -- I do define our Marcellus that you've laid out as core. And we're just trying to, again, improve our efficiency, and we look at a project that will allow us to do what I've said in the past. And that's be able to grow the asset and generate free cash. So you're going to be in a good return zip code if you're able to accomplish that.

Okay, great. Fair enough. And just a follow-up for me. Just wondering if I'm making the right read here, read between the lines, that the share repurchase is really kind of a sign that your confidence in receiving the final permit -- permits that Atlantic Sunrise has really only increased over the last quarter and remains pretty high.

Well, it's 2 things: One, that we had the available cash. We had -- as you came out of the third quarter of '16, fourth quarter of '16, and then the first quarter of '17, we saw how significantly the differentials narrowed. And we saw, under a more normal condition, what our project would generate in free cash with realizations in the range that we realized for the first half of this year.

So a combination of, again, seeing good realizations that we hadn't seen in maybe 3 years come to fruition, but also, to your point, getting closer to the approval process and narrowing down on the commissioning of these infrastructures. Both of those gave us the confidence to not only increase our dividend by 150%, but also to do the share repurchases that we've made. And Scott's point was made about -- we have a reauthorization still of 7 million shares. And yes, we're going to be opportunistic. But we also feel very confident of our future generation of free cash, and that is instrumental in our decisions to move forward with the share repurchases.

And our next question today comes from Paul Grigel of Macquarie.

Just one last follow-up on the shareholder-friendly activities. With the high levels of expected free cash flow, if you don't deem the exploration program as a large use of capital, will the shareholder-friendly activities be all in the form of buybacks, a special dividend or yearly dividend increase? Trying to understand where the thought process is moving forward on that one.

Well, we have 2 of the 3 we've already implemented. And those 2: one, increased dividend; and two, the buybacks. Special dividends, you can look at special dividends. But what we like to see, we like to see every shareholder in our stock, and we like to see every shareholder hold our stock for a period of time and enjoy the ride up. And by having a consistent dividend yield and increasing maybe dividend policy and also buybacks, I think would be -- the higher priority focus is then trying to suggest that we would be issuing special dividends.

Fair enough. And then on the operational front, could you provide any additional color on the compressor downtime into 3Q, location or risks that it may extend into September? And then tangentially to that, any comments on either service cost inflation or availability within the Marcellus that you're seeing?

Okay, I'll let Jeff take care of the compressor counterpart.

Sure, Paul. We got notified by DTE, who owns and operates the Bluestone Pipeline, which cuts through the core of Susquehanna County in our area. We were making deliveries from the station there, and they have done an inspection on a compressor station, that actually pumps gas in the Millennium Pipeline on the north end of their system. Long story short, they noticed some vibration damage to the engines and immediately shut it down, removed the engines, check out the foundation and decided that, in this particular case, the best idea going forward was simply lease 4 new engines, rebuild the station as quickly as possible and get back online. The current in-service dates we were getting now are August 23. Yes, give or take a few days. So we think we will be back in business around September 1.

Do you have any follow up on that? Or...

No, no that's good amount. Just on the service costs and availability, any issues there.

No, in the Marcellus right now, we're just -- it's basically been fairly flat, Paul, on the service cost side.

And our next question comes from Karl Chalabala of Stifel.

I just have one question. I was curious if you could -- because Cove Point has been commissioned and looks to be taking some feed gas here. You guys, obviously, are a big supplier of that gas to Sumitomo. Are you going to be able to get physical down or through some other backhaul arrangement before Sunrise comes online and capture any margin there? Or will that gas be coming from somewhere else?

Yes, I'll -- Jeff can handle that one, too.

Yes, Karl. Thanks for the question. We talked about this quite a bit in preparing for a good, little while now, since we've known that Sunrise was going to be slightly delayed, on what is the best path on getting Susquehanna County gas down to the Cove Point pipeline. We currently own existing capacity to get some of that gas down to the Cove Point pipeline. We're contracting with a few others that have path leading Susquehanna County to get additional volumes down the Cove Point. We have some other options with capacity holders that have valid path to feed our gathering system that run past the Cove Point pipeline. So we're working out the arrangements with them as we speak. We're looking at this from a variety of angles. For example, we're still not entirely sure when Cove Point will be up and running. We're taking on the best case that they'll be up in January, which fits us rather nicely. And i hope that we won't have any problem contracting for various path and cobble together enough transportation options to get our gas down to the pipeline.

And can you remind me, please, the agreement on price for that. Will that be a NYMEX Light deduct on the FG cost?

Yes, so reaching way back to when we press released the deal, we -- everyone know that it was a Henry Hub-based price that had other opportunities associated with it. Due to the confidentiality with Sumitomo, we have stated to not disclose any particulars about the pricing.

And our next question comes from Bob Morris with Citi.

I think you called me earlier, Dan, and I'd stepped away. So I apologize if you did call me earlier. But just looking at the Gen 4 completions, which you've pointed out are outperforming the 4.4 Bcf per 1000 foot type curve. I recall that in going to Gen 4 from Gen 3, it was a combination of enhanced cluster spacing, some higher sand loading, some tweaks to the pumping system there. But as you look at the economics of that and the higher cost to put in a higher sand, in particular, and the tighter cluster spacing, how much of an uplift are you seeing in the actual economics, given that higher cost for what is now that higher type curve?

As far as the 4.4 increase over the Gen 3 or even looking at now our current type curve, I'm going to do a swag here and I'm probably going to get slapped back. But I think it's about 10% to 15% is the uplift, I think, we're seeing.

And then, I guess, similarly in the Eagle Ford, I know you didn't put out the type curves because it's taken longer for the longer laterals to clean up. There, you'd gone from 1,600 pounds per foot to 2,000 pounds per foot. Similarly, is that providing enhanced economics, and you then go to even higher sand loading? Or what are you seeing as far as optimizing the sand loading in the Eagle Ford?

Well, we have a little bit of discussion, Bob, on additional loading, cluster spacing. Steve went over. And looking at our flow-back periods with the longer laterals, more water pump to carry the excess -- extra load and more clusters, we're looking at the tweaks. And as Steve mentioned, if you have more water around near wellbore, more loading, you push back some of the volumes back until they work their way back to the wellbore. Initially, it certainly, with the rate it comes back, does affect the rate of return. And so we're at early, early stage of trying to evaluate just exactly what is going to be the best recipe to get the most return out of those project without compromising EUR and cost. So it's still early, and it's work in progress. And all the data gathering and database that we're building, trying to build our big data platform as others are, we are going to be looking at it and utilizing the data to make decisions in the future.

An then just lastly, real quick, back to the Gen 5 completions. Is that strictly just reducing cost? Or does Gen 5 in the Marcellus also entail some greater sand loading or even tighter cluster spacing?

Well, it's just different. And yes, we are trying to do a little bit of both. We're trying to see what cost can be taken out by different a completion there. We're trying to make a determination, does it also affect initial rates and EURs on the completions. Too early time to speculate where we are with that.

And today's final question comes from Marshall Carver of Heikkinen Energy Advisors.

Yes, just trying to connect the dots here. Your comments that you're looking for core rates of return with your exploration programs similar to the Marcellus, that just seems like an almost an impossibly high hurdle. If it doesn't compete, would you expect to sell it and, therefore, you probably would sell it because it's hard to find anything that could possibly compete? Or am I thinking about that wrong? It just seems like 100% rates of return are -- it's a really, really tough bar to clear.

Yes. Marshall, I don't put the core definition as only what our return is in the Marcellus. There are some areas out there that I think have core -- what I would define as core returns that might not be the returns of the Marcellus. But their returns, if that was where you are strictly focused, would allow for -- even though less returns than the Marcellus, would still allow for growth and return of free cash. And that is somewhere in between, which I have not defined, between our Eagle Ford and our Marcellus.

So there is a swap in between there. Obviously, on the upper end, that says, yes, these would be core projects. And you're right in your assessment. How you define a core and looking at the number of companies that are able to spend the money, drill the wells, complete them, put them in the pipeline, grow double digits and generate free cash and give free cash back to shareholders, there's not many that fall in that definition. But that definition is, I think, somewhat below what our Marcellus return is, but it is a very, very high bar to get to.

And that's what we're trying to do. We recognize that if you go -- just like the comments we've made on the Eagle Ford, some would say that, "Why are you spending money in the Eagle Ford? Go spend it all in the Marcellus, because you're diluting your return profile." We get the math. The difference is that, that has not deterred from anything we've done in the Marcellus. We've been handicapped without infrastructure up there. We think we're getting close to that. We don't think anything we're doing in these 2 projects to try to determine, can we find a really, really good -- another return project to get -- some of our capital allocation. It will not impact $1 that we plan to allocate to our Marcellus and our anticipation of filling, all incrementally, the infrastructure volumes that we're going to grow, too, in the Marcellus. But what we are -- and to the point that maybe another question referred to, how do we balance giving back to shareholders as opposed to investing into a -- or a gas well.

Well, we've decided to give some back to shareholders right now because we don't have a place that is going to allow us to meet our benchmark of growing and generating free cash after you do the full-cycle return profile of our projects. And if we get to the point that we would hope to get -- and I might add that in our initial economics that we run to make the first decisions to spend capital, to look for those type of ideas, we certainly have economics and a development plan in scope, though speculative, that would do what I'm talking about. And that is invest, develop, have a development program, get to the point of growth where free cash -- the program is supporting on its own cash generation and also generating free cash for other optionality and as we have suggested and as we have done, and that is to get back to shareholders.

And this concludes the question-and-answer session. I'd like to turn the conference back over to the management team for any final remarks.

Okay. Thank you, Rocco. I think with the questions that have been asked and the answers provided, you can see that we remain focused on returns. We are going to continue to focus on returns. And with the right projects where we allocate capital, we think we're going to be able to achieve exactly what we've been able to achieve in the second quarter. Thanks for your interest, and I look forward to a discussion, again, on the third quarter call.

Today's conference has now concluded, and we thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.