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. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on a touch-tone phone. To withdraw your question, please press star then two. 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, Gary, 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'd 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 to 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 a $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've 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 sale 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 one-time non-cash interest expense related to income tax reserves, our unit cost would have improved by 24% relative to prior comparable period and by 4% sequentially relative to the first quarter of 2018.
Despite strong production volumes, continued improvement in our cash operating costs, 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 cash flow generation in the third quarter based on our expectations of improved price realizations and higher volumes. On that pricing front, I would highlight that while May and June bidweek 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 bidweek 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 $0.10-$0.15 better than the second quarter. On our share repurchase program during 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, representing 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 our 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 share authorization, we will reduce shares outstanding to levels lower than before our equity issue 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. 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 of return, provide meaningful inventory depth and resource life, and the ability to be self-funding in a low commodity price environment, then we would've no problem walking away.
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 EBITDA 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 EBITDA, it did improve our absolute debt to EBITDA from 1.5x to 1.3x, which is right in the fairway of our target leverage range of 1x to 1.5x. We are forecasting a continued de-leveraging 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 downtime, both planned and unplanned, throughout the quarter. Our production guidance for the third quarter of 2.1-2.2 Bcf per day of net production represents an 11%-16% sequential increase relative to 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%-15%, to 10%-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 of year when we tend to see some issues with high line pressure and pipeline maintenance. As a result, we would much rather err on the side of the conservatism. As it relates to our asset productivity, we continue to complete additional wells in the Upper Marcellus to gather 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 1,000 lateral feet type curve. Our ongoing work continues to support the unique and incremental Upper Marcellus reservoir independent of the Lower Marcellus. We're 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 purchased gas and equity production. As I'm sure you're aware, Williams last week announced Atlantic Sunrise project is very near completion, and their expectation full 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 Cabot's equity production in 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 one is burning approximately 70 million cubic feet per day and has been very consistent in its early operation. As a reminder, train two and three remain on schedule for in-service on October 1st and December 1st respectively. Train two is currently receiving test gas as the developer takes additional steps towards commissioning. Regarding the Moxie Freedom Power Generation facility, we had previously reported that an early in-service date of June 1st was obtainable. Unfortunately, the facility required some additional modifications and further testing.
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 and are anxiously 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 differentiated strategy of high return growth coupled with increasing return on capital and return of capital is underappreciated by the market, due primarily to general apathy for natural gas as a commodity.
I think if you replace natural gas with another widget and deliver the same financial return and leverage metrics that we're delivering today, then 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 that to be the case today with natural gas, both near term, given the current storage deficit to a five-year average is the widest it has been seen since 2014, and in the long term, as we are nearing major inflection points for natural gas demand from exports. Regardless of where the sentiment on the commodity is, I can promise you that the team at Cabot will continue to execute on the strategy in an effort to create long-term value for our shareholders.
Gary, with that, I'd be more than happy to answer any questions.
We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. Our first question comes from Drew Venker with Morgan Stanley. Please go ahead.
Good morning, everyone.
Hey, Drew.
Dan, in your prepared remarks, you talked about the Upper Marcellus tests that you've drilled in the past, and I know it's not been the focus of yours right now. Can you just talk about what assumptions you've made in that? I guess I've laid out before, like a 20-year production forecast. What assumptions are made in that forecast for the Upper Marcellus?
The 20-year forecast that you're talking about, we've assumed where we are 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.
Okay. That's helpful, Dan. 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 guys have said more preference for buybacks, also would like to grow the dividend over time. Can you just update us on thoughts on the dividend?
Yeah. On the dividends, each board meeting, we've had discussion on dividend. We made it clear when we started ramping the dividend, we took kind of an incremental step last year, we've taken a smaller step again the beginning of this year. 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. We felt it was prudent at the time to make sure there were not going to be any delays. We've all experienced the pains of the delays of some of these projects and getting them commissioned. 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 commissioning of these infrastructure projects, we would then again revisit the dividend policy.
Thanks for that, Dan. Just one last one from me. When you all started this exploration play process, I think in the beginning of that, you said if you didn't have success, you would market the acreage on the back end. Is that still the plan?
No. We've taken the write-down on some of the capital expenditures that we've spent. The acreage is still intact, we will go through that process on the back end.
Great. Thanks, Dan.
Thanks, Drew.
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. Just trying to get a sense of where we should see CapEx over the next couple quarters. Is 2Q the high point? Does that come down at all in 3Q? I know you've got quite a few more completions in 3Q. Just anything you can sort of do to talk about any of the quarterly CapEx cadence over the next couple 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 in line. We have a little bit of a wrap-up heading into the commissioning of Atlantic Sunrise.
Okay. I guess just looking at share repurchases, obviously you guys came out and increased the program here. I guess if I just sort of look at that, high level, we have kind of seen some weakness in NYMEX gas prices. I know you guys also had this debt repayment that you had to recently make here over the last couple of weeks. Irrespective of that stuff, should you guys still plan on being pretty aggressive here in the second half of the year with the buyback program?
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 for action, and that it is our intent to execute on the authorization that the board has granted. The takeaway would be that we fully intend to continue our program that we've implemented.
Okay, that's helpful. I guess just lastly on the Upper Marcellus wells that you mentioned completing some wells recently here, just any kind of early indications out of those, 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, that our Upper Marcellus is incremental and accretive reservoir independent of the Lower Marcellus work has indicated that. We're also of the opinion that our completion techniques will improve off of the 2.9 per 1,000 foot of lateral.
Okay, thanks.
Thank you.
The next question comes from Charles Meade with Johnson Rice. Please go ahead.
Morning, Dan, to you and your team there.
Hey, Charles. How are you?
I'm doing well, thank you. One quick question for you, and then maybe a bigger second question, but as far as the completion pace that you have in the back half of this year, I'd like that disclosure where we're getting what, 37 in Q3, but then about half of that in Q4. Can you give us a sense on 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 are you moving frac crews? Are you bringing in frac crews or sending them home, or what's the outlook there?
Yeah. The increased second half of 2018 has always been in our design as we get to the commissioning of Atlantic Sunrise. That level of activity and timing this activity is right on queue. In regard to 2019, we don't anticipate bringing in any additional frac crews than what we have done in 2018. We're going to stay fairly consistent with our completions in 2019. Some of that is dependent upon the timing is dependent upon how many wells we have on any given pad, and how many stages in the lateral lengths on those pads. We had recently a long pad that not a long pad, a pad that had long laterals and 12 wells. We had been on that location for a good while, completing that 24/7. We have another pad in that particular area of the field, we had six wells.
Those six wells were not quite as long, at least a couple of them were not quite as long as, say, at the 12-well pad. To look at, I won't say lumpy, because we are scheduling these things out fairly consistently with turning in line and areas of the field that we turn these in line, then we have a forward-looking plan for that. I think you'd see 2019 as being fairly consistent with what we've seen in 2018.
Got it. Thank you, Dan. It sounds like you spent several months on that 12-well pad. 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 questions about that, because as I look at your guidance, you're guiding for an incremental 250 MMCFD about in Q3 over Q2. I just start to add up the pieces, whether it's the and honestly, I don't have the numbers for this piece, but the Transco and Millennium downtime. Also you've got that first train of Lackawanna on that's probably 55, 60 net to you. Right? Then you've got some volumes from Moxie Freedom. Then you've got really the big whopper with Atlantic Sunrise.
When I start to add those pieces together, and I recognize that Atlantic Sunrise volumes are not all incremental on day one. I start to add those pieces together, and it feels to me like I must be missing something on what's going to happen with crunch of volumes.
Are you missing the conservative part?
Well, maybe the magnitude of it, Dan. Anyway. I appreciate your comments, maybe you say it is I know in the past you said all of the Atlantic Sunrise, when this comes online, are going to be taking volumes that go from, that are in the local market onto Atlantic Sunrise. Is it possible that you're not actually going to be delivering your Bcf a day within a couple of weeks of startup, that you're going to ramp to that?
On Atlantic Sunrise?
Right.
Charles, we're planning on utilizing the capacity available in 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've committed to, and it is our full intent to deliver the gas as soon as Atlantic Sunrise will take it. One of the things on our conservative, I wasn't trying to be cute on the comment on conservatism, Charles, one of the things that I think is relevant, the ramp-up in shifting in a small area of a Bcf of 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 the switch of the valves, I guess.
It's multiple valves, it's multiple coordinations to get it done and get it all smoothed out. In light of the time of year, which the shoulder months time of the year, when you get a little bit of the early cooler weather, it ramps up the pressure in the pipes that are within the basin, and the amount and volumes that the pipelines will accept at the 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 to back without exception. The timing of that and when that occurs is a very difficult proposition to be able to forecast.
What we have done is made some swag at saying, "Okay, how much gas is going to be knocked off by higher line pressure into the pipeline?" Us moving this gas out into Atlantic Sunrise should help, but to what extent is still a swag. We've had now, as an example, we thought maybe there was a chance of Atlantic Sunrise coming on in July. 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 into 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. That goes from June to August as a possible date right now. How do you account for that, Charles, in your earlier forecast? We try to do it, and part of what we try to do is plan on these contingencies.
In fact, if we get delays or we see line pressure go up or we don't immediately get the full acceptance of a Bcf in Atlantic Sunrise, we forecast some of that contingency. If we can overachieve and we can get on the high side of our numbers, we're ecstatic about it. We think, and it's been consistent with our policy and our demeanor to guide conservatively more so than aggressively. We're comfortable with that.
Dan, I really appreciate you adding all that insight into those below-the-surface complexities. Thank you for that.
Yeah. Thank you.
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning.
Okay.
Preliminary congratulations for the pipelines and all the transportation to come.
Thanks. Fingers crossed.
Yeah. We've all had them crossed for a while now.
Yes, we have.
Looking at slide 10 that Charles was just referencing, then taking in your remark 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? I'm bearing in mind that there were no completions in first quarter of 2018.
That's getting fairly granular. Jeffrey, I'd have to get back to you. 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. 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 eight-well pad that's completed in the last week or two of a quarter, and it gets pushed into the next quarter, that would drastically change the outcome. 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.
Right. No, I appreciate that. I think the reason I'm asking is that if you just look at it kind of looks like there's this huge push as Atlantic Sunrise is coming on, then there's backing off. If, in fact, you had been able to complete wells in the first quarter of 2018, this might have looked a little bit smoother. That doesn't challenge what you were just saying, because pads can always slip a week or two and have a big effect on a quarter. That was really where I was trying to go.
Yeah. 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. That's kind of where I was trying to get at. I would assume in 2019, if you don't have that kind of gap, that things would look a little bit smoother over the course of the year, as opposed to this big jump in the third quarter, which was probably predicated on Atlantic Sunrise and the first quarter of 2018.
Yeah.
The other question is, it sounds like your bias for 2019 is to continue increasing lateral length. With 2018 average laterals at 8.3 thousand feet, and that was the average, do you think 2019 increases are going to be incremental, or can that average move meaningfully longer?
I think it'll be incremental right now. We have efforts ongoing in any areas that we can to extend laterals, we'll continue with that effort. Right now, we think 2019 is just going to be incremental. If we're successful, as again, we have been throughout 2017, throughout 2018, to throw in some longer laterals in the mix, we will continue to try to do that.
Okay, great. Thank you. I appreciate it.
Thanks, Jeffrey.
The next question comes from Bob Morris with Citi. Please go ahead.
Thank you. Dan, you hit on some of my questions. Let me just circle back on the exploration play that you did write off here. You did mention you'd come back to the process of trying to monetize what you do have there. I know you can't disclose what it is, but can you give us some color on whether it potentially is economic, even though it didn't meet your hurdle? Is there some value there? Did you find hydrocarbons in that it just didn't meet your hurdle rate, but might be attractive to someone else?
Yeah, we did find hydrocarbons, there's some dynamics going on, as we're all aware, out in the Permian. In the last couple of years working on this project, you're seeing near-term headwinds on infrastructure out there. You've seen service cost increase out there in the last couple of years. Even though you've 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 built out there. The results that we got in the field and consideration of the other impacts that affect our return, we made the decision not to move forward.
Okay. Then of the $50 million write-off you took, how much of that were dollars spent this year in the $75 million budget for total exploration?
That was too quiet, huh? Bob, it was about $35 million this year, $17 million related to last year.
Okay. Super. That helps. Thank you very much.
Thanks, Bob.
The next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning.
Hey, Brian.
Wanted to ask on the competitive dynamic in Appalachia. It's a question you've gotten before, but as we see assets change hands and balance sheets improved amongst some of the players, how do the plans of others, be they through wells behind pipe DUCs 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 the macro dynamics of what's going on in the natural gas space, I think parties that have the ability to increase their production profiles, complete DUCs to move gas to different price points to obtain better realizations, I think is a prudent course of action. If, in fact, that you have 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 in moving gas into, again, over-supplied markets that create the lower realizations, just like what we have dealt with now for a number of years.
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, how they allocate capital dollars in a way that would allow every dollar they spend to maybe obtain better realizations from the efficiency created by a model that would have controlled growth as opposed to growth just for the sake of growth. Every company has its own strategic initiatives, its own internal complexities. 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 in 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.
Got it. Thank you for that color. Then I wanted to follow up on the CapEx conversations and questions that have already come up on the call, just to maybe add a little bit more clarity. There's three different elements of the CapEx budget, the Marcellus upstream, the exploration, and then the investment and equity method investments. Is it fair to say that as we think about 2019, the investment and equity method investments go away because Atlantic Sunrise Pipeline segment is done, exploration is TBD depending on the results from the second play, and that the CapEx in the Marcellus seems, based on your comments, to be relatively flat in 2019 versus 2018? What is the flex on share repurchase depending on the exploration side of the equation?
On the equity side, the answer is yes, that the equity investment in 2019 goes away. We continue, as I've mentioned, on the second exploratory effort. We continue to spend a little bit of capital there. Very manageable on the capital allocation in that particular area. On the allocation to our Marcellus, it's going to be fairly consistent with the allocations that we've had this year.
Great. Thank you.
The next question comes from David Deckelbaum with KeyBank. Please go ahead.
Morning, Dan. Thanks for all the color today.
Hey, David.
Just curious, you reiterated your multi-year 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'm 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're sort of filling some of these larger volumes into a more unconstrained environment?
From our number that we're seeing in 2018, I think it is safe to say, looking at 2019, that we would expect a tick down in our direct cost associated per unit.
Okay. 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?
Yeah, David, I'm going to let Jeff, who's been kind of living that project, I'll let him visit about that.
Sure, David. Just to back up a minute, the project was originally scheduled for in-service August 1st from the time we first started negotiating our contract and going through financing and the rest of that. 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. They did take a little bit of gas in April. They took some larger volumes of test gas in May, they have gone through a number of performance testing and emissions testing, that sort of thing. On the specifics, I can't go into that. I would call them very slight modifications that they're just simply tweaking and finding the best way to operate the facility.
This is a beautiful 1,000-megawatt facility that's kind of an any-day-now startup or COD event. We're really excited about the facility. It's, again, just some minor tweaks on how they plan to operate the facility, and I wouldn't say anything much more than that.
I appreciate that, Jeff. Then 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 us how many wells or zones have been tested. Then, how is that compared to the second play with how comprehensive the evaluation's going to be?
Well, we had five wells that we tested. We tested several zones. In our second project, we will have similar number of wells, and we'll be testing what we find in those wells.
Appreciate it, Dan. Thank you, guys.
Thank you.
The next question comes from Jane Tsentsiper with Stifel. Please go ahead.
Good morning. Could you please update us on PennEast project, and what do we need to pay attention to 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're in a little different position, we are a shipper on that facility. From the conversations that PennEast operations have had with the shipper group and the customer group, PennEast has not changed their disclosure from second half of 2019. My understanding is they've 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 are public companies and have analyst calls coming up in a few weeks. We're going to be watching that to see if they push that in-service back a little bit. Right now, they continue to put through surveys and building the information necessary to get the proper permits. That's where it stands from our perspective.
I see. My next question is, should we expect any impact from maintenance on Transco line this quarter?
No. From our understanding.
No impact.
The maintenance on Transco was early on this year. We actually had two events, just regular maintenance, pig runs, that sort of thing. Of course, we had the outage when tying Cabot's slash Williams' gathering system into Atlantic Sunrise, which is something that we had expected. Looking out, we have no maintenance notices from any of the three pipelines.
Okay. Sounds good. The next question is on Atlantic Sunrise. It looks like a section of the Atlantic Sunrise is already online. It's like 500 MMCFD. My understanding is that you are not flowing on it. 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 hydrotesting of the pipe and of course, all the meters and regulation stations is ongoing. As a shipper, we don't have the details of which sections of the pipe. There's actually line pack in, for example. I do know that the commissioning is ongoing and that gas has been introduced into the pipe in certain areas.
I see. My last question is on the difference between the first and the second exploratory areas. Is it only the geographical location that's different, or is there something else to that?
Are you asking have we identified the geographic area?
I'm just trying to understand. Both exploratory areas are targeting Upper Marcellus, the difference, is it only geographically it's different locations, or is it different depth? I don't know, different pressure or something else makes it, you identified as separate exploratory operating areas.
Yeah. The Upper Marcellus is not an exploratory project for us.
Where we're allocating and identifying a second exploratory area is geographically different than the Marcellus.
The difference between the first and the second exploratory operating areas is solely based on geography, right? Of the location of the wells.
Yeah.
No, it's based on geology.
Geology.
On-
They're away from the Marcellus.
Oh, yeah.
Yeah.
I'll defend that.
It's geography and geology, but it's the same Upper Marcellus interval that you're testing, right?
Let me clarify. The exploration projects that we have are not in the Marcellus.
Okay.
They're located in different parts of the United States. The Marcellus is a development project, has been for more than a decade.
I see. The exploration results, so the dry holes that you guys reported this quarter, they are not related to Upper Marcellus, right?
That's correct.
That's correct.
Okay. That's perfect. Okay. My last question, sorry about this. The activity levels in Northeast Pennsylvania, do you see a pickup from other operators in front of Atlantic Sunrise coming online?
Activity levels?
Yeah.
Yeah, we keep track on the activity levels, Jane, 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. It's not related to the Atlantic Sunrise coming online, everybody is picking up drilling?
No.
No.
They're not.
Okay, got it. Thank you so much. That's very helpful. Thanks.
Thank you.
The next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead.
Morning, guys.
Hey, Michael.
Appreciate the time. A lot's been covered. I guess one thing is just well costs. You guys kind of reiterated the $8.3 million average well cost. If memory serves, though, that has some inflation in it. There's been some commentary around Northeast service cost pricing perhaps improving a little bit. 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. The kind of benchmark we've used, Michael, has been $1,000 per lateral foot. We're pretty good with that.
Okay, you don't anticipate any potential reductions on a near-term basis with that?
Well, yeah.
Okay.
Keep in mind, our major cost that would move the needle are. We're contractually committed on both rigs and frac crew.
Got it.
So that's-
What's the term on your frac crew costs? How long is this contract?
Yeah, we go through the end of the year.
Okay. Then, I guess the other side is just 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 has been a gating item for the buyback, has been getting the infrastructure up and running and commissioned as expected. Just wondering to what extent have the exploration programs also been governors on committing to even more in the way of buybacks? 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'd see another big step-up in buybacks or any commentary along those lines?
Well, the exploratory portion of our 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 dividends, it dovetails now with our anticipation of both in-basin power demand and our commissioning of Atlantic Sunrise. The amount of money compared to Cabot's available capital and cash that's being allocated to the exploratory effort is de minimis, and it does not impact our decision on buybacks.
Okay. Yeah, I guess I was more kind of thinking about the potential forward capital requirements would maybe restrain buybacks, and I guess maybe more so dividends, but it doesn't sound like that's at all the case.
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 u ndeterred, and I'm also comfortable we'll be able to buy back our authority of shares that the board has granted, and I'm also comfortable that we'll be very prudent on allocation of capital into an exploratory and hopefully into an exploitation phase of this exploration area we're on right now.
Perfect. Okay. Thanks very much.
That's fine.
The next question comes from Sameer Panjwani with Tudor, Pickering Holt. Please go ahead.
Hi, good morning.
Hey, Sameer.
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?
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've indicated in the prepared remarks, that would, upon 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 commissioned, that we're generating the free cash that we anticipate, I'm sure the board will revisit our dividend policy also.
Okay. Sorry, just to clarify, I'm thinking more longer term. I think right now in the presentation you guys highlighted trailing 12 months leverage is 0.8 times, but your target is 1 to 1.5 times on the leverage. Over time, should we expect you guys to use that leverage capacity, let's call it between the 0.8 times and the 1 time the gap between your low end to increase buybacks further?
Well, I think our policy is going to be fairly consistent even though we have identified as an opportunistic policy at this stage. Again, I've prefaced 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've also made it clear that we wanted to see the steady stream of cash that we anticipate. Using leverage, I'll let Scott talk about the leverage position and the balance sheet and how we might look at the balance sheet and 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. 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. Obviously, the first part of that would be the first funding source for any buyback. I would emphasize that if we saw a big disconnect, outsized disconnect, we have no problem leaning 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.
The 1 to 1.5 is a target level, if we fall below the target, we're not going to go out and 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, there's a lot of dynamics that play into that decision.
Okay. That's really helpful. 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?
Yeah, we'll let Jeff answer that.
Yeah, Sameer, we talk about this quite a bit. We continue to have two very active ongoing initiatives both with the in-basin demand projects and an additional pipeline takeaway. Just to maybe talk a little bit about the in-basin demand program, we're out there in a very challenged environment. We're trying to relocate industry, we're trying to find the right size projects, the right scale. We're trying to find projects that ultimately improve our realizations. Right now it's ongoing in nature. It's also exciting. We've all learned a lot about our natural gas users and their requirements and working in Pennsylvania and those requirements. It's exciting. I'm 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 always are looking at pipeline options every day.
You got to remember, in our world, we always have the underlying question that, does this project improve our price realizations? Currently, with the outlook on basis 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. I think there are additional pipeline projects to be built. That would be good for Cabot. We're just being very selective and working through the details.
Great, thank you.
This concludes our question and answer session.
Yeah, I might add that we have a really good idea for a project that goes from our field into the Iroquois pipeline. There's much demand and many users over there in New York have asked when we could get some gas up in that area, 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, Gary, and thank everybody for the questions and the 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 will have the privilege of discussing commissioning of long overdue infrastructures. 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. Thank you. Look forward to the third quarter conference call.
The conference is now concluded. Thank you for attending today's presentation.