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Coterra Energy Inc
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Good morning, and welcome to the Cabot Oil & Gas Second Quarter 2018 Earnings Conference Call and Webcast. All participants will be in listen only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO. Please go ahead.
Thank you, Garry, and good morning to all. Thanks for joining us today for Cabot's second quarter 2018 earnings call. With me today are the members of Cabot's executive team. I would first like to emphasize 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 of the most directly comparable GAAP financial measures are provided in this morning's earnings release.
For the second quarter of 2018, Cabot generated adjusted net income of $57.9 million or $0.13 per share, compared to $0.14 per share for the prior year comparable quarter. Our adjusted net income for the quarter was impacted by $51.1 million exploration dry hole expense resulting from our decision to cease investment on one of our two exploratory operating areas. Excluding this one-time charge, our adjusted earnings per share for the quarter would have been approximately $0.09 higher.
Daily equivalent production for the quarter was 1.895 Bcfe per day, which came in at the high end of our guidance range and represented a sequential increase of 4% relative to the first quarter when adjusting for the Eagle Ford Shale that closed at the end of February. Our unit cost continued to improve as we posted an 8% decline in cost relative to the prior year comparable quarter. Excluding the previously mentioned exploratory dry hole expense and a onetime noncash interest expense related to income tax reserves, our unit cost would have improved by 24% relative to prior year comparable period and by 4% sequentially relative to the first quarter of 2018.
Despite strong production volumes continued improvement in our cash operating cost, the Company did generate a free cash flow deficit during the second quarter, driven primarily by lower than anticipated realized prices in May and June and the funding of the majority of the remaining capital associated with our equity investment in Atlantic Sunrise pipeline project. We anticipate a return to positive free flow generation in the third quarter based on our expectations of improved price realizations and higher volumes.
On the pricing front, I would highlight that while May and June bid week prices were about 18% lower than April, which placed downward pressure on our realized prices for the quarter. We have seen an improvement in Northeast Pennsylvania pricing with July bid week prices settling 15% higher than the second quarter average and early indications imply August prices will look similar to July. Based on the forward curve, our third quarter differentials would be 10% to 15% better than the second quarter.
On our share repurchase program there in the second quarter of 2018, Cabot did repurchase an additional 11.6 million shares at a weighted average price of $23.54, bringing our year-to-date total to 20 million shares repurchased. Including our year-to-date dividend payments, we have returned approximately $535 million of capital this year represented a total shareholder yield of 5%. At our board meeting yesterday, we obtained approval to increase our authorization by an additional 20 million shares, which effectively reloaded program back to 30 million shares or approximately 7% of our current shares outstanding.
Given our strong balance sheet and our outlook for continued free cash flow expansion, we remain committed to opportunistically executing on our share repurchase program as long as we continue to see a disconnect between our share price and our view on the Company's intrinsic value. Since we reactivated our share repurchase program in the second quarter of 2017, we have reduced our shares outstanding by 5% to 441 million shares and assuming we fully execute on the current 30 million authorization. We will reduce shares outstanding to levels lower than before our equity issues in early 2016.
Moving to the exploration front, as I mentioned, during the second quarter, we recorded an exploratory dry hole expense associated with one of our two exploratory operating areas. Based on the data we gathered over the last year, we have ultimately made the decision to cease capital allocation to this area. Over a year ago, we announced our intention to allocate a nominal amount of capital to exploration. We were clear with the market that our primary focus was on generating returns focused growth from the Marcellus shale and returning an increasing portion of capital to shareholders via dividend and share repurchases. However, at the same time, we did see the merit in allocating a limited portion of our capital budget to testing new concepts that have the potential to create long-term value.
We're also very clear that we have an extremely high hurdle for capital allocation internally given the returns we generate from our world-class asset in the Marcellus. If a new venture did not generate competitive full cycle rates return, provide meaningful inventory depth and resource life and the ability to be self funding in a low commodity price environment and we would have no problem walking away, and that is where we find ourselves today as it relates to this exploratory area. We will also continue to test our second exploratory area and plan to provide an update on this area on the third quarter 2018 earnings call in October. Our financial position remains strong as ever with over 2.4 billion of liquidity and a net debt to trailing 12 month EBITDAX ratio of 0.8 times at quarter end.
Subsequent to the end of the quarter, we did close on our previously announced Haynesville divestiture for approximately $30 million. Additionally, we paid down our $230 million 6.5% senior note that matured this month with cash from the balance sheet. While this transaction had no impact on net debt to EBITDAX, it did improve our absolute debt to EBITDAX from 1.5 times to 1.3 times, which is right in the fairway of our target leverage range of 1 to 1.5 times. We are forecasting a continued deleveraging over time as our cash flows expand in the coming quarters driven by increased production volumes and improving price differentials resulting in additional balance sheet capacity for future capital deployment.
Operationally, we delivered another strong performance in the Marcellus during the second quarter with volumes up 4% sequentially despite meaningful downtimes both planned and unplanned throughout the quarter. Our production guidance for the third quarter of 2.1 to 2.2 Bcf per day of net production represents an 11% to 16% sequential increase relative the second quarter and is driven by our expectations of placing 37 wells on production throughout the quarter. Due to our year-to-date actual volumes being slightly lower than originally budgeted primarily resulting from delays in third-party compressor stations in the first quarter and downtime on Transco and Millennium during the second quarter, we have lowered the top end of our annual production guidance range from 10% to 15% to 10% to 12%.
Additionally, we're guiding more conservatively for the second half of the year given our unprecedented ramp in production that's occurring during a time a year when we tend to see some issues with high line pressure and pipeline maintenance. As a result, we are much rather air on the side of the conservatism. As it relates to our asset productivity, we continue to complete additional wells in the Upper Marcellus together more data related to our enhanced Gen 5 well completions. As we have highlighted previously, we have 30 Upper Marcellus wells that were completed with older completion designs that are on average tracking our 2.9. Bcf per thousand lateral feet type curve.
Our ongoing work continues to support the unique and incremental Upper Marcellus reservoir independent of the lower Marcellus. We are extremely confident in our resource potential in both the upper and lower Marcellus and that both zones productivity will deliver top tier economics when compared to the vast majority, if not all, oil and gas resource plays across the U.S. As we reported last quarter, we have enjoyed significant progress on multiple fronts regarding infrastructure and our in-basin demand projects. As a short recap, we announced the Dominion Cove Point LNG facility was placed in-service April 9th and the subsequent notification that our 20 year supply agreement with Pacific Summit Energy is now in effect.
We have been fulfilling that obligation through a combination of purchase staff and equity production. As I'm sure you are aware, William last week announced Atlantic Sunrise project is very near completion, and their expectations fall in-service subject to weather conditions is during the second half of August. This new greenfield pipeline is Cabot's unique transportation path to supply 100% of our LNG commitment with a direct connection to Cobot's equity production and Susquehanna County.
We are excited to deliver approximately 350 million per day via Atlantic Sunrise to Cove Point in the very near future. Additionally, let me remind everyone that Cabot's 15 year agreement with Washington Gas Light for approximately 500 million cubic foot per day along with several additional sales agreement will also take effect with the in-service of Atlantic Sunrise project. In summary, this long-awaited new pipeline infrastructure positions Cabot to deliver approximately 1 Bcf per day of production to new markets with significantly better price realizations.
Moving on to our in-basin power projects. First, the Lackawanna Energy Center was placed in-service on June 1st. As expected, train 1 is burning approximately 70 million cubic feet per day and has been very consistent in its early operation. As a reminder, train 2 and 3 remain on schedule in-service. And on October 1st and December 1st, respectively in fact train 2 is currently receiving test gas as the developer takes additional steps towards commissioning.
Regarding Moxie Freedom power generation facility, we had previously reported that an early in-service date of June 1 was obtainable. Unfortunately, the facility required some additional modifications and further testing. However, we have been notified recently that the full in-service of Freedom plant could be as early as the first week of August. We are currently providing large volumes of test gas initially awaiting final go-ahead for this 160 million per day project.
These three projects will drive a significant improvement in differentials going forward resulting from access to premium markets post-Atlantic Sunrise in-service and exposure to seasonal higher power prices. These are very exciting times for Cabot as our long-term infrastructure and growth plans have finally come together and will provide I think huge benefits for years to come.
In summary, we continue to believe our differentiate strategy of high return growth coupled with increasing return on capital and return of capital is unappreciated by the market due primarily to general apathy for natural gas as a model. But I think if you replace natural gas with another widget and delivered the same financial return and leverage metrics, we would -- and that we’re delivering today in our year-to-date share price performance would likely look significantly better than they do today.
With that being said, I have been in this industry long enough to know that sentiment around commodity will change over time. I especially believe to be the case today with natural gas both near-term given the current storage deficit, to a 5-year average is the lightest as being since 2014 and long term as we’re nearing major inflection points for natural gas demand from exports. Regard to where the sentiment on the commodity is I can promise you that the team at Cabot will continue to execute on this strategy in an effort to create long-term value for our shareholders.
Gerry, with that, I’d be more than happy to answer any questions.
We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Drew Venker with Morgan Stanley. Please go ahead.
Dan, in your prepared remarks, you talked about the Upper Marcellus test that you drilled in the past. I know it’s something in the focus of yours right now. Can you just talk about what assumption do you made in that in case you’ve made out before like a 20-year production forecast? What assumptions are made in that forecast for the Upper Marcellus?
20-year forecast that you’re talking about we’ve assumed where we’re today and what we’ve seen Drew with the 30 completions that have been completed in our old technique. We’ve assumed the 2.9 in that forecast.
And then, on the focus on return of cash to shareholders, the incremental buyback today obviously positive with -- what you guys have said in the past more I think you used to have more preference for buybacks, but also would like to grow the dividend over time. Can you just update us on thoughts on dividend?
Yes, on the dividends each board meeting, we had discussion on dividend. We made it clear when we started ramping the dividend and we took kind of incremental step last year. And we’ve taken a smaller step again beginning of this year but our commentary at that time was that it was our intent and the board’s intent to see the commissioning of these infrastructure projects that are imminent to commission. And we felt it was prudent at the time to make sure that we're not going to be any delays. We’ve all experienced the pains of the delays of some of these projects and getting them commissioned. So we thought it was prudent to keep the dividend where it is right now once we get the cash flow coming in the door from the commission and these infrastructure projects, we would then again revisit the dividend policy.
Thanks a lot Dan. Just one last one from me. When you all started this exploration play process I think in the beginning that you said if you didn't have success then you would market the acreage on the backend. Is that still the plan?
We've taken the write-down on some of the capital expenditures that we spent and we have -- the acreage is still intact, and we will go through that process on the back end.
The next question comes from Leo Mariani with NatAlliance Securities. Please go ahead.
Hey guys just a question around CapEx here, obviously, you had a tiny bump in your full year guide. But just trying to get a sense of where we should see kind of CapEx over the next couple quarters? Is 2Q the high point? Does that come down at all in 3Q? I know you got quite a few more completions in 3Q, the thinking you can sort of do to kind of about any of that quarterly apex cadence over the next couple of quarters here.
Well, our guidance on CapEx for the full year will remain intact, as we bring on wells into the infrastructure, we'll continue to complete those wells and bring those wells inline. So, we have a little bit of a ramp up heading into the commissioning of Atlantic Sunrise.
Okay and I guess just looking at the share repurchases obviously you guys came out and increased the program here. But I guess if I just sort of look at that, high level we have kind of seen some weakness in NYNEX gas prices and you guys also had this debt repayment that you had to recently make here over the last couple weeks. Irrespective of that stuff, I mean, should you guys still plan on being pretty aggressive here in the in the second half of the year with the buyback program?
Yes, Leo, the conversation again at our board meeting this week was specifically along the lines that I have mentioned in the past and that was that our authorization is not optics, it is proaction and that it is our intent to execute on the authorization that the board has granted. So the take away would be that we fully intend to continue our program that we have implemented.
Okay, that's helpful. And I guess just lastly on the Upper Marcellus wells that you mentioned, completing some wells you know recently here. Just any kind of early indications out of those and when might you have a little bit more robust look at those for the market here?
Well, the early indications are wrapped up in my comment that we continue to believe and that our Upper Marcellus is incremental and accretive reservoir independent of the lower. We work as indicated that and we're also of the opinion that our completion techniques will improve off of the 2.9 per thousand foot lateral.
The next question comes from Charles Meade with Johnson Rice. Please go ahead.
One quick question for you and then maybe a bigger second question. As far as the completion pace that you have in the back half of this year. I'd like this disclosure where you gave out, what, 37 in Q3 but then about half of that Q4. Can you give us a sense of what we should be looking for going into 2019 on whether you're more going to be on that 37 sort of pace or on that 20 pace? And then, are you moving frac crews? Are you bringing any frac crews or sending them home? What's the outlook?
The increased second half 2018 has always been in our design, as we get to the commissioning of Atlantic Sunrise. So that level of activity and timing this activity is right on cue. In regard to '19, we don’t anticipate bringing in any additional frac crews than what we have done in 2018. And we are going to stay fairly consistent with our completions in '19 and some of that is depended upon -- and the timing is depended upon how many wells we have on any given pad and how many stages in the lateral links on those pads.
We had recently a long pad -- not a long pad -- a pad that had long laterals and 12 wells. And we had been on that location for good while completing that 24x7. And we have another pad that in that particular area of the field, we had 6 wells. And those 6 wells were not quite as long at least a couple of more not quite as long as say the 12 wells pad. So to look at I won't say lumpy because we are scheduling these things out fairly consistently with turning in line in areas of the field that returns these in line. Then we have our forward looking plan for that. But I think through '19 as being fairly consistent with what we have seen in '18.
And it sounds like you've spent several months on that 12 well pad. But going back to a comment you made in your prepared remarks about guidance being conservative in the back half of the year. I wanted to ask you a couple of questions about that because as I look at your guidance you are guiding for an incremental 250 million a day about in 3Q over 2Q, and I just start add up the pieces whether it's the -- to be honest, I don’t have the numbers for this piece, but the Transco and Millennium downtime but then also you have got that first train of Lackawanna on that’s probably 55 to 60 net to you, right. And then you have got some volumes from market that for you and then you have got really the big whopper with Atlantic Sunrise. So when I start to add those pieces together and I recognize that Atlantic Sunrise volumes are not all incremental on big one, but I started to add those pieces together. And it feels to me like I must be missing something on what's going to happen with sequential volumes?
Are you missing the conservative part?
Well, I -- maybe the magnitude of it, Dan. But it's -- maybe -- I appreciative your comments, but you may be you said is -- I know in the past he said all of that -- all of Atlantic Sunrise, when it comes online, are given the take in volumes that go from, that are in the local market, onto Atlantic Summers. But is it possible that you not actually be delivering your Bcf a day on within a couple of weeks of startup that you going to ramp to that?
Atlantic Sunrise?
Right.
Charles, we’re planning on utilizing the capacity available in at Atlantic Sunrise as soon as it is available. The connection to our gathering system of the upstream portion of Atlantic Sunrise is designed to take the volume of gas that we committed to and is our full intent to deliver the gas as soon as Atlantic Sunrise will take it. One other thing on our conservative, I wouldn't try to be cute on the comment on conservatives, Charles, but one of the things that I think is relevant, the ramp up and shifting in a small area a Bcf a gas and coordinating two power units that are coming on at the same time and moving gas around in a small geographic area, is done with a -- the switch of the valves I guess, but it's multiple valves it’s multiple coordination to get it done and get all smoothed out.
So in light of the time of the year which the shorter month time of the year, when you get a little bit of the early cool weather, it ramps up the pressure in the pipes, the pipes that are within the basin. And the amount in volumes that the pipelines will accept at a higher pressure starts creating some reduction in the volumes that you're going to be able to put into the pipe. That has happened every year back to back, back to back without exception. So the timing of that and when that occurs is a very difficult proposition to be able to forecast. What we have done is, is made some swag, it's saying, okay, how much gas is going to be knocked off by higher line pressure into the pipeline, us moving the gas out into Atlantic Sunrise should help, but to what extent is still a swag.
We’ve had now as an example that you know we thought maybe there was a chance of Atlantic Sunrise coming on in July. Well, we've kind of moved it to the back half of August. That is a large swing large volume of gas being moved around out there. When you look at the Lackawanna plant and it’s come on very good and it's kind of operated in a timely fashion and we’re happy with that. In our forecast when we look at the deliveries of end of Moxie Freedom plant, we had thought June would've been a good time to fill that up and they thought the same thing. And I'm sure they still think the same thing however to line out the facility to get it commissioned to the fullest extent under all the protocol and safety reasons that commissioning takes place, and has a test period, that's what they're in right now and they're tweaking that.
Well that goes from June to August as possible date right now. How do you account for that Charles in your earlier forecast? Well, we try to do it and part of what we try to do is, plan on these contingencies and in fact, if we get delays or we see line pressure go up or we don't immediately get the full acceptance of the Bcf and Atlantic Sunrise, we forecast some of that contingency. If we can over jet and we can get on the high side of our numbers we're ecstatic about it but we think and it’s been consistent with our policy and our demeanor to guide conservatively more so than aggressively. And we're comfortable with that.
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Looking at Slide 10 that Charles is just referencing and then taking and your remarks that 2019 completions will be fairly consistent with 2018. Does that imply that you see less variance from quarter-to-quarter than we had in 2018 and I'm bearing in mind that there were no completions in first quarter of '18?
That's getting fairly granular, Jeffrey. I'd have to get back to you with -- but my top line comment would be and my expectation is because I haven't looked at quarter to quarter to quarter, I've kind of looked at the entire guidance but I think the guidance is going to be fairly consistent throughout the year.
Jeff, this is Matt. One thing I'd add is, we have to be careful about looking at quarterly turning lines because if we have an 8 well pad that's completed in the last week or two of the quarter and it get pushed into the next quarter that would drastically change the outcome. So we like to think about it more holistically as a full year. We just on slide 10 got a little bit more granular given we're a quarter away.
No, I appreciate that. I think the reason I'm asking is that if you just look at it, it kind of looks like there's this huge push as Atlantic Sunrise is coming on and then there's backing off. But if in fact you had been able to complete wells in the first quarter of '18, this might have looked a little bit smoother and that doesn’t challenge what you're just saying because pads can always slip a week or two and have a big effect on the quarter but that is really where I was trying to go.
Jeffrey, keep in mind on that point you just made as a reminder, we did not turn one well in line in the first quarter.
Right, and that's kind of where I was trying to get at. I would assume in '19 if you don't have that kind of gap that things would look a little bit smoother over the course of the years as opposed to this big jump in the third quarter, which was probably predicated on Atlantic Sunrise and the first quarter of '18. The other question is. It sound like your bias for 2019 is to continue increasing lateral lines. Would 2018 average laterals at 8.3 thousand feet and those are the average? Do you think 2019 increases are going to be incremental or can that average move meaningfully longer?
I think it'd be incremental, right now. We have efforts ongoing to in any areas that we can to extend laterals and we will continue with that effort. Right now we think '19 is just going to be incremental if we are successful as again we have been throughout '17, throughout '18 to throw in longer laterals in the mix. We will continue to try to do that.
The next question comes from Bob Morris with Citi. Please go ahead.
Dan, you hit on some of my questions. But let me just circle back on the exploration play that you didn’t write off here. And you did mention you come back to the process and try to monetize what you do have there. But I know you can't disclose what it is, but can you give us some color on whether potentially it's economic even though it didn't meet you hurdle and there some value there you can find hydrocarbons in that it just didn't meet your current rate but might be attracted to someone else?
No, we did find hydrocarbons and there's some dynamics going on, as we are all aware of in the Permian. In the last couple of years working on this project, you are seeing near term headwinds on infrastructure out there. You have seen service cost increase out there in the last couple of years. And even though you have seen certainly an increase in the commodity price there's still some punitive differentials today and going to be apparent for a little bit longer till we get the pipeline build out there. But the results that -- we have gotten the field and consideration the other impacts that affect our return we made the decision not to move forward.
And then of the $50 million write off you took how much of that were dollar spent this year in the $75 million budget for total exploration?
That was too close. Bob, it was about 35 million this year 17 million related to last year.
The next comes from Brian Singer with Goldman Sachs. Please go ahead.
I wanted to ask on the competitive dynamic [indiscernible] it's the question you have gotten before. But as see asset maintain a balance sheet improved amongst some of the players. How do you -- the plans of others [indiscernible] through wells behind pipe ducks or rig activity influence the level of activity that you may gear towards in 2019?
I think that in looking at Appalachia and looking at natural gas, looking at macro dynamics of what's going on in the natural gas space. I think parties that have the ability to increase their profiles -- production profiles, complete ducks to move gas to a different price points to obtain better realizations, I think is a prudent course of action. If in fact that you have some gas under this environment moving into the same punitive realizations and ramping up gas into that type of environment, I think there's going to be a point in time when particularly for public companies that shareholders are probably going to want to see some kind of rational approach in the environment and moving gas into again oversupplied markets that create the lower realizations just like what we have dealt with now for a number of years.
And I would not be surprised to see some management take the opportunity to look at the space and try to get more efficient with their capital dollars -- highly allocated capital dollars in a way that would allow every dollar they spend to maybe obtain better realizations from the efficiency created by model that would have controlled growth, as opposed to growth just for the sake of growth. And every company has its own strategic initiatives its own internal complexities, but I just can't help believe with where we are in the natural gas space and the supply dynamics that everybody talks about out there that there’s not conversations and a lot of boardrooms that talk about how we get more capital efficient with our allocation in a way that allows for there to be some rationalization in the marketplace.
And then I wanted to follow up on the CapEx conversations that -- and questions that have already come up on the call just maybe add a little bit of more clarity. There’s three different elements of the CapEx budget, the Marcellus upstream exploration then an investment in equity method investment. Is it fair to say that as we think about 2019, the investment in equity method investments go away because of Atlantic pipeline, Atlantic Sunrise pipeline pending design, explorations CBD depending on the second results of the second play and that the CapEx in the Marcellus seems that in your comments to be relatively flat in ’19 versus ’18. And when is the flex on share repurchase depending on the exploration side of the equation?
On the equity side, it is -- the answer is, yes, that the equity investment in 2019 goes away. We continue as I mentioned on the second exploratory effort. We continue to spin a little bit of capital there, very-very manageable on the capital allocation in that particular area. And on the allocation to our Marcellus, it’s going to be fairly consistent with the allocations that we’ve had this year.
The great question comes from David Deckelbaum with KeyBanc. Please go ahead.
Just curious I know like in the -- and you've reiterated your multiyear long-term outlook and free cash generation for various sensitivities. I know in those assumptions you have a lot of things around cost, but specifically I am curious about your assumptions on the LOE side. And if we should see any optimization at all or should we expect a step change in optimization at the field level, once you sort of fill in some of these larger volumes into a more unconstrained environment?
From our number that we're seeing in '18 I think it is safe to say looking at '19 that we would expect a tick down in our direct costs associated per unit.
Okay and then just a little bit more color on the Moxie Freedom project. Did that plant originally begin testing gas in April and then the project needed to be re-modified after that? Or has it not tested gas yet?
Yes, David, I'll let -- Jeff has been kind of live in that project. I'll let him talk about that.
Sure, David. Just to back up a minute. The project was originally scheduled for in server August 1st from the time we first started negotiating our contract and going through financing and the rest of that. So, they made a lot of progress on the construction front and was able to move up the in service date what we thought at one point would be around the June 1st date. And so, they did take a little bit of gas in April and took some larger volumes of test gas in May, and they have gone through a number of performance testing and emissions testing that sort of thing.
And on the specifics, I can't go into that on the -- and I would call very, very slight modifications that they're simply tweaking and finding the best way to operate the facility. This is a beautiful 1,000 megawatt facility that's kind of in any day now start up or COD event. And so, we're really excited about the facility, but it's again just some minor tweaks on how they plan to operate it surely and I wouldn’t say anything much more than that.
Appreciate that Jeff. And just the last one from me, on the exploration side, Dan, I know you kind of gave some guidance around how much capital was spent and the reasons why. Just curious if you could remind how many wells or zones have been tested? And then how does that compared to the second play with how comprehensive the evaluation is going to be?
Well, we had -- we had five wells that we tested and we tested several zone in our project, second project we will have similar number of wells and we'll be testing what we find in those wells.
The next question comes from Jane Trotsenko with Stifel.
Could you please update us on East project and what do we need to pay attention from a regulatory standpoint? And what's the probability of PennEast getting built?
Okay, Jane, I’m going to turn that to Jeff to answer that, thank you.
Yes, Jane. PennEast from our understanding and keep in mind that we are a little bit from position, we already shipped on that facility. But from the conversations that PennEast operations have had with the shipper group and the customer group. PennEast has not changed their disclosure for the second half of 2019. My understanding is that they made a lot of accomplishments on permitting in Pennsylvania.
They still have some remaining challenges in New Jersey to get their final permits there. I do understand that the PennEast owners all have our public companies have analyst calls coming up in a few weeks. And so, we will be watching that to see if they push that into back a little bit. But right now they continue to through surveys and building the information make sure to get the proper permits. And that’s where it stands from our perspective.
My next question is should we expect any impact from maintenance on Transco line this quarter?
No, from our understanding and the maintenance on Transco was early on. This year, we actually had two events just regular maintenance playgrounds that sort of thing. Of course we have the outage when time Cabot/Williams gathering system into Atlantic Sunrise which is something that we had expected. So looking out we have no maintenance notices from any of the three pipelines.
And then the next question is on Atlantic Sunrise. It looks like a section of the Atlantic Sunrise is already on line. It's like 500 Bcfe COD. My understanding is that you are not flowing on the --- do you know if any gas flows on that section already?
I didn’t quite understand what section, you're specifically talking about. Let me just try to answer it this way. There's been gas introduced into the pipeline, we are aware of that. The commissioning process for the stations and the hydro testing of the pipe and of course all of the meters and regulation stations is ongoing. I can't -- as a shipper, we don't have the details of which sections of the pipe. There is actually jam packed in for example, but I do know that the commission is ongoing and that gas has been introduced into the pipe in certain areas.
And my last question is on the difference between first and the second exploratory areas. Is it only geographic allocation that different? Or is there something else to that?
You asking every identified the geographic area?
No, I’m just trying to understand is it -- the board's exploratory areas are targeting Upper Marcellus. So the difference, is it on your geographically different locations? Or is it like different debt? I don’t know different pressure or something else makes it -- you identify as separate exploratory operating areas?
Yes, the Upper Marcellus is not an exploratory project for us. And where we’re allocating and identifying a second exploratory area is geographically different than the Marcellus.
So difference between the first and the second exploratory operating areas just solely based on geography right, all the allocation of the wells?
No. It’s based on geology.
Geology or away from in the Marcellus.
So it’s geography and geology, but it’s same Upper Marcellus. Is it the same Upper Marcellus into of all that you're testing, right?
Let me clarify. The exploration projects that we’ve are not in the Marcellus. They are located in different parts of the United States. The Marcellus is a development project. It has been for more than a decade.
So, the exploration result, so the dry hole to that you guys reported this quarter they’re not related to Upper Marcellus, right?
That’s correct.
My last question sorry about this, the activity levels in Northeast Pennsylvania, do you see it becomes from other operators in front of Atlantic Sunrise coming online?
Activity levels?
Yes.
Yes, we keep track on the activity levels and going in the past activity levels have traditionally been a small ramp up at a summer period of time in anticipation of maybe moving some winter gas. That has occurred each year. The level of increased activity that we see up there right now is not atypical of that type of activity.
I see but it’s not like really through the Atlantic Sunrise coming online and everybody is picking up drilling?
No.
The next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead.
A lot has been covered. I guess one thing as just about costs, you guys kind of reiterated the nearly 0.3 million coverage well costs. So if memory serves well, there has some inflation in it, spin some commentary around Northeast service cost pricing perhaps improving a little bit. Do you guys seeing any of that? Anticipate any of that? Just kind of curious on what the latest on well costs are for you guys?
We’re fairly comfortable with a flat trajectory on the cost up there and we kind of benchmark review as Michael has been a $1,000 per lateral foot and we’re pretty good with that.
So then you don’t anticipate any potential reduction on a near-term basis?
Well, keep in mind our major costs that we moved the needle are where we’re contractually committed on both rigs and frac crews, so that's…
What's the term on your frac crew costs like how long are those contracts?
We go through the end of the year.
Okay and then I guess the other side is just kind of following up a little bit on the exploratory programs but in the context of the dividend -- I'm sorry of the buyback. You talked about one thing that is kind of gaiting item for the buyback has been getting the infrastructure up and running and commissioned as expected. Just wondering to what extents have the exploration programs also been kind of governors on committing the even more on all your buybacks? And to the extent you did see or you did move on let's say from the second program? Would it be fair then to assume you achieved another step up in buybacks, any commentary along those lines?
Well, the exploratory portion available cash has not influenced our decisions on the level of buybacks. We anticipate our buyback program to be as we've laid out opportunistic and it dovetails now, along with the comment I made on mayo dividend, it dovetails now with our anticipation of both in-basin power demand and our commissioning of Atlantic Sunrise. So the amount of money compared to Cabot's available capital and cash that is being allocated to the exploratory effort is de minimis and it does not impact our decision on buybacks.
I guess more kind of thing about the potential forward capital requirements would maybe restrain buybacks and I guess maybe more so dividends but it doesn't sound like that.
No, no, I'm comfortable that we will be able to have our growth profile into new market areas for better pricing. I'm comfortable that we'll have our capital program allocations to the Marcellus with undeterred. And I am also comfortable we'll be able to buyback our authority shares that the Board has granted. And I'm also comfortable that we would be very prudent on allocation of a capital into an exploratory and hopefully into an exportation phase of this exploration area we're on right now.
The next question comes Sameer Panjwani with Tudor, Pickering, Holt. Please go ahead.
You touched on this a little bit in the prepared remarks, but with leverage tracking below your target range and set to further improve in the coming years. Can you just provide some color on your willingness to use the balance sheet to return additional capital to shareholders?
Yes, we have at our last board meeting we got the authority to increase our authorization by 20 million shares. And the board's expectation is that we would execute on that authorization as we have indicated in the prepared remarks that would fall in completion of that buyback would be a 7% yield, 7% of our outstanding shares. And that is our full intent to execute on that authorization, as we continue to see a disconnect in our intrinsic value additionally, once we get Atlantic Sunrise and the power plants commission that we are generating the free cash that we anticipate. I’m sure the board will revisit our dividend policy also.
Just to clarify, I’m thinking more longer term, I think right now and in the presentation you guys highlighted trailing 12 months levered is 0.8 times, but your target is 1 to 1.5 times on the leverage. So overtime, should we expect you guys to use that leverage capacity let's call it between the 0.8 times and the 1 times GAAP between your low end to increase buybacks further?
I think our policy is going to be fairly consistent even though we have identified as opportunistic policy at this stage, and again I preference it several times on infrastructure build out commissioning. The use of a component of a regular buyback plan is certainly something that we have visited. But we have also made it clear that we wanted to see the steady stream of cash that we anticipate. So, using leverage, I’ll let Scott talk about the leverage position and the balance sheet and how we might look at the balance sheet what we might do with maturities or reload.
Sure, thanks. Sameer, in terms of that long-term look, historically, we haven't leaned on the balance sheet. We haven’t borrowed money to buy back shares and then that doesn't change really. When you look out forward into the long term, we will be generating a significant level of free cash flow. So, obviously, the first part of that would be to use -- would be the first funding source for any buyback. But I’d emphasis that if we saw a big disconnect outsize disconnect we have no problem reading on our undrawn revolver at any point in time if we had to make an impact in the buyback program.
That's not our optimal use at this point, but at the same point we wouldn’t shy away from that on any of those disconnects. Keep in mind, we are at 1.3 on an absolute debt to this point that 1 to 1.5 is a target level but we are not. If we fall below the target we are not going to go on borrow money or do something with money just to get back to that level. It’s a guide level. It’s a nice sweet spot to be in. We will work towards that but there's a lot of dynamics that play into that decision.
And then last question, if I may. I know you guys are always looking to expand the takeaway portfolio. Is there anything to provide an update on right now or anything that's become more likely since the last quarter call?
Yes, I'll let Jeff to answer that.
Sameer, we talk about this quite a bit and we continue to have two very active on the initiatives, both with the in-basin demand project and an additional pipeline takeaway. And just to -- maybe talk a little bit about the in-basin demand program, we were out there in a various challenged environment, we were trying to relocate industry and we’re trying to find the right sized projects, the right scale.
And we’re trying to find projects with ultimately improved our realizations and it’s -- right now, it’s all moving in nature but it’s also exciting. We’ve all learned a lot about natural gas users and their requirement and working in Pennsylvania and those requirements and it’s exciting. And I am pretty confident we’re going to find several in-basin demand projects that are good for Cabot and good for those industries.
That said, we’re always looking at pipeline options every day. But together remember we’ve got the -- we’ve always had the underlying question that does this project improve our price realizations. And currently with the outlook on basins and the in-basin demand that we have, our realizations are improving. That said, we’re going to be up there for a long time, and I think there’s -- there are additional pipeline projects to be built and that would be good for Cabot. We’re just being very selective and working through the details.
I might add that we have really good idea for a project that goes from our field into Evercore pipeline. And there’s a much demand in many users over there and New York have asked when we could get some gas up in that area. So, we haven’t given up on that effort to deliver much needed gas to that part of the country.
This concludes our question-and-answer session. I’d like to turn the conference back over to Dan Dinges for any closing remarks.
Thank you, Gerry, and I thank everybody for the questions and interest in the details. We are looking forward to our October quarterly call. That call will be the first call in many years that hopefully we’ll have the privilege of discussing commissioning of lot of overdue infrastructures and I would look for the opportunity for us to again support the shareholder friendly decisions that we have made in the past and with the clarity of cash flow that we’ll continue to make in the future. So, thank you, look forward to the third quarter conference call.
The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.