Cabot Oil & Gas Corporation
Q2 2015 Earnings Call Transcript

Published: 24 Jul 2015

[Operator:]

Good day, and welcome to the Cabot Oil and Gas Corporation's Second Quarter 2015 Earnings Conference Call and Webcast. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President, and CEO. Please go ahead.

[Dan O. Dinges:]

Thank you, Kate, and thank you all for joining us this morning for the second quarter earnings call. With me today, as usual, are several members of the executive team. Before we start, let me say that the standard boilerplate regarding forward statements do apply to my comments today. First, I'd like to touch upon a few financial and operating highlights from the second quarter that were outlined in this morning's press release. Equivalent net production for the second quarter was 1,516 million cubic foot equivalent per day. Our quarterly results reflect the impact of our previously announced strategic decision to reduce our production levels during the quarter as a result of the lower price realizations throughout Appalachia. We estimate that we reduced our gross production volumes by approximately 500 million cubic foot per day during the quarter. Despite this significant reduction in volumes during the second quarter, the company's equivalent production for the first half of 2015 increased 25% as compared to the first half of 2014 and the company's liquid production for the first half of 2015 increased 95% relative to the first half of 2014. The company generated a net loss of $0.07 per share for the quarter. However, when adjusting for select items including a $36.5 million non-cash mark-to-market loss on derivatives, Cabot generated adjusted earnings of $0.03 per share. Operating cash flow, discretionary cash flow and EBITDAX were $171 million, $183 million, $204 million respectively. All of these financial metrics were lower relative to the second quarter of 2014 primarily as a result of a 38% decline in realized natural gas prices and a 43% decline in realized oil prices. Moving to specific comments regarding the Marcellus. As I mentioned, in light of the continued weakness in Appalachian pricing, we curtailed a significant level of volumes in the Marcellus during the second quarter. And we plan to continue this strategy into the third quarter as we await potential improvement in pricing in the fourth quarter with the addition of new takeaway capacity and stronger winter demand. While our marketing team continues to take advantage of short-term opportunities to improve netbacks in the Marcellus, there are limitations on the pricing front in the near term as we await some of the larger, more impactful projects like Constitution and Atlantic Sunrise pipelines. However, we continue to accomplish our ongoing focus of enhancing margins by improving the cost side of our operations through efficiencies, and also with cost reductions. Drilling operations in the Marcellus continue to set new records for the company. Our SPUD to SPUD cycle time during the quarter was under 15 days as compared to approximately 19 days for full-year 2014 due in large part to new highs established for gross feet drilled per day during the quarter. As a result of these efficiencies, we have seen a 15% reduction in cost at rig release year-to-date. We anticipate further cost reductions as we move into 2016 as two rig contracts will expire in December of this year, and our expectations are for a significant reduction in day rates going forward. On the completion side of our operations, we have been successful in working with our service providers to realize additional cost reductions. All of these drilling and completion efficiencies and savings have allowed us to achieve the lower end or slightly below our $6 million to $6.5 million range for a completed well cost. I would like to highlight that our wells placed on production year-to-date in 2015 are tracking our industry's best type curve of 3.6 Bcf per thousand feet, highlighting the consistency of our wells throughout our lease position. Regarding pricing, our second quarter natural gas realizations were $2.15 per Mcf which is $0.49 below the average NYMEX for the quarter, an improvement relative to the $0.52 differential in the first quarter. Excluding the impact of hedges, our realizations were $0.89 below NYMEX. Assuming the regional differentials we observed in the second quarter persist in the third quarter, we anticipate that Cabot's third quarter price realizations will be somewhere between $0.95 and $1.05 below NYMEX before the impact of hedges. Additionally, we anticipate another $0.30 to $0.35 per Mcf uplift in realized prices from our hedges based on the current strip. If you want more details on the split of our pricing exposure by index, check out our guided slide on the website. Similar to the second quarter, we expect to produce between 1.55 Bcf and 1.6 Bcf per day of gross production in the Marcellus during the third quarter. We will continue to be patient as we anticipate a better opportunity to move additional volumes in the local market. We firmly believe that stronger demand and improved price realizations for Cabot are on the horizon, and we will continue to be disciplined in our approach to managing through this lower price environment as we have through all the commodity cycles. The bottom line is that we remain focused on improving margins and returns and maximizing long-term value, which I believe is evident by our ability to continue to efficiently grow our production and reserves in this low price environment without straining our balance sheet or issuing equity. This clearly sets us apart in the industry. In the Eagle Ford, couple of comments there. Our second quarter volumes were flat to our first quarter volumes despite decreasing our rig count to one and slowing down our completion activity. Our efficiencies in the field continue to improve as we have decreased our drilling days by about 20% relative to 2014 and increased the average number of completions per day by about 20%. As a reminder, much of our activity in the first half of the year was driven by near-term primary lease terms and continuous development obligations. Given that we have already met the majority of these obligations for 2015, we only plan to operate one rig during the second half of the year. We still anticipate exiting the year with over 20 wells waiting on completion. We frequently get asked at what price we would look to accelerate our completion activity in the Eagle Ford. Despite the significant reduction in cost that we have achieved, upwards of 30% across all service lines, we do not believe that allocating incremental capital in the Eagle Ford is the prudent investment decision in this oil price environment, especially given the implied increases in cash flow deficit that would result from the increased spending. Okay. let's move to Constitution Pipeline update. During our first quarter teleconference, we highlighted the additional progress that was made regarding our efforts to finalize the permit process for Constitution. Today we can continue that update with the following. Constitution filed its implementation plan with the FERC on May 19, 2015. This was a critical step documenting how Constitution will comply with the environmental conditions placed in the FERC order and it's the last step prior to the FERC issuing its Notice to Proceed regarding construction. Also, Constitution is now providing a weekly update to the FERC. Constitution filed its final reroute variance report also with the FERC last week. This completes all outstanding issues regarding the route, and Constitution now has 100% of the required right of ways. Regarding the New York DEC, our understanding is the last reroute that I just mentioned was one of the final loose ends prior to their issuance of 401 water quality permit. Therefore, our expectations are that we are very close to wrapping up and completing all remaining New York DEC outstanding issues. In summary, we continue to make important progress and remain optimistic that we will receive final clearance so that we can begin construction this fall and place the project into service during the second half of 2016. Regarding our third quarter guidance, production guidance included in the press release this morning implies approximately 1.5 Bcfe per day of net equivalent production at the midpoint. Natural gas guidance for the quarter is unchanged relative to second quarter guidance, while the midpoint of our liquid volumes we reduced by 1,500 barrels per day as a result of the slowdown in completion activity that we have discussed previously due to front-end loaded capital program resulting from drilling obligations in the first half of the year. We have remained our 2015 full-year production growth guidance range of 10% to 18%. If we were to hold the midpoint of our third quarter guidance flat into the fourth quarter, we would achieve the low end of our full-year guidance. However, we do anticipate at least a moderate ramp in our Marcellus volumes in the fourth quarter in response to seasonal winter demand. Our capital program for 2015 remains unchanged at $900 million. We have received a few questions about our program spending this year, so I'd like to take a brief moment to clarify our guidance. The $900 million for 2015 refers to the capital associated with activity incurred in 2015 for this year's operating plan. However, because of the timing gap between activity incurred and payments for services, we have had cash outflows this year associated with activity incurred in 2014. And because of the significant decline in capital spending year-over-year, we are in a position this year where cash outflows on the cash flow statement will be higher than our capital guidance for the year. The majority of this impact occurred in the first half of the year where the capital incurred for 2015 activity was $540 million, but the capital expenditure on the cash flow statement were approximately $660 million. The $550 million incurred in the first half of the year for our 2015 program is approximately 60% of our full-year guidance which is, in fact, below the 65% guidance we provided last quarter. Our unit cost guidance for the year remains unchanged. However, I would highlight that year-to-date cash unit costs were $1.25 per Mcf, $0.07 below the midpoint of our full-year guidance. This includes a $0.85 per Mcf cash unit cost in the Marcellus and a $15 per barrel cash unit cost in the Eagle Ford. While we are pleased with these low costs, the mandate the organization has is to continue to focus on further improving our cost structure. As for 2016, we're still in the planning phase and we'll have more detail to provide on the third quarter call in October once we've had an opportunity to fully vet our plans with the board, including an updated review of our five-year plan. Based on a preliminary look at the five-year plan, we are extremely excited about the long-term value created by our Marcellus asset as we begin to assess more favorable price markets which will allow Cabot to not only accelerate production and cash flow growth, but also significantly improve corporate-wide margins and returns. In summary, we continue to focus on improving efficiencies, reducing cost and increasing our margins, with an emphasis on maximizing the long-term value of this top-tier portfolio we have. In the near term we remain optimistic about Constitution construction beginning in the fall and remain confident in the second half of 2016 in-service date. Additionally, we are pleased with the progress being made on the Atlantic Sunrise pipeline which is another important step in our strategy to monetize our low-cost Marcellus assets at premium prices. Lastly, we will continue to be disciplined through this low commodity price environment with an emphasis on managing the balance sheet and protecting returns and margins. Kate, with those brief comments, I'll be happy to answer any questions.

[Operator:]

We will now begin the question-and-answer session. The first question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

[Doug Leggate:]

Hi. Thanks. Good morning, Dan. Good morning, everybody.

[Dan O. Dinges:]

Morning, Doug.

[Doug Leggate:]

I've got a couple, if I may, Dan. First of all, thanks for the clarification on Constitution, but I guess it's a tough question to answer, but when Atlantic Sunrise and Constitution and so on are where you expect to them to be, let's say, a year or so from now, what do you think the steady state differential for Cabot is going to look like?

[Dan O. Dinges:]

The commissioning or two years after the commissioning, it's not...

[Doug Leggate:]

No – well – yeah, well, what I really mean is when all is said and done, if you want to think about the long-term sustainable basic discount, if you like, or transport discount, what – I know it's a tough question to answer, but just order of magnitude compared to the kind of dollar you're getting to in Q3, I mean, where does it get to in your mind when you don't have the bottlenecks that you have in place today?

[Dan O. Dinges:]

Yeah. It is a good question. Again, it's one that we have made a specific effort to clarify. In fact, we have commissioned a third party recently and engaged them, had them evaluate the entire space out there, looking at every aspect of the market on the supply side, the demand side, looking at the North America market as a whole, the macro market as a whole. And then narrowing down to Cabot specific and the parts of that dynamic, supply-demand dynamic that would affect Cabot. We have reviewed that study, and we have incorporated the findings – excuse me, of that study in our first effort towards our five-year plan. And we are building and fleshing out that five-year plan to present at our board meeting in October. The early look of this third-party assessment and analysis of the dynamics in the market and where Cabot's realizations would be as we work through this five-year plan is that at – towards the end of that five-year plan and as you commission some of the infrastructure, and you look at some of the demand dynamics that were specific in the study, we get to a very low differential to a positive differential to NYMEX.

[Doug Leggate:]

Okay. That's very helpful. I appreciate the full answer. My follow-up just also, a little quicker, Dan. Hedging for 2016, I don't think there's anything in place right now. Just thoughts on that and I'll leave it there. Thanks.

[Dan O. Dinges:]

Yeah. Hedging is going to be just subject to what the market will yield. Right now, in looking at the strip, we don't see anything in the strip that would have us place any incremental hedges on at this point in time. But as an ongoing part of our business, we continue to be interested in placing hedges. And historically, we've always liked to be between 25% to 75% hedged depending on what the market would give us. So, it is going to be and will continue to be part of our program. We just don't see that opportunity today.

[Doug Leggate:]

Okay. Thanks again.

[Dan O. Dinges:]

Thanks, Doug.

[Operator:]

The next question comes from Phillip Jungwirth of BMO. Please go ahead.

[Phil J. Jungwirth:]

Yeah, good morning.

[Dan O. Dinges:]

Hello, Phillip.

[Phil J. Jungwirth:]

Last quarter, you had discussed the possibility of Constitution displacing volumes from some of the weaker price indexes, but also achieving 50% returns at a $2 realized gas price. So would we be right to assume that the threshold for displacing volumes is below $2 an Mcf? Or could you take a view that it's NPV accretive, play it for higher prices?

[Dan O. Dinges:]

Well, we're going to evaluate the market upon the commissioning of Constitution, and how I've had to answer the question with uncertainty in what the market is going to be at that snapshot in time on the commissioning. What we've said is that we're going to have a program that would allow flexibility in displacing or adding incrementally to our growth profile in placing the 0.5 Bcf a day into Constitution. Or in fact, if the market is challenged at that point in time, we've talked about just displacing, taking volumes off the pipes that we're selling into today and moving that 0.5 Bcf into the Constitution Pipeline. So, that decision in how we fill the line and flow into Constitution will be made based on market parameters. We have not discussed and I'm not prepared to discuss whether it's at a $2 benchmark or not on how we would handle our commissioning of Constitution.

[Phil J. Jungwirth:]

Okay, great.

[Dan O. Dinges:]

But certainly our objective is to – and I'm extremely confident that the commissioning of Constitution is going to enhance our overall price realizations.

[Phil J. Jungwirth:]

Great. And I appreciate the update on Constitution. I was also hoping that you could discuss some of the key milestones to watch for, for Atlantic Sunrise over the next 12 months to 18 months.

[Dan O. Dinges:]

Yeah, Phillip. I'm going to let Jeff Hutton, who's our VP of Marketing, to discuss where that project is. Good question, because it's a great project for us.

[Jeffrey W. Hutton:]

Yeah, Phillip. So far so good on the Atlantic Sunrise front. I think there's been a lot of progress that came right out of the box. There is – as you know, we've already filed the application for the project. There's already been quite a bit of boots on the ground in terms of community outreach and run past all of the open houses for example. At this point, we continue to purchase right of way and options on right of way. I think if I recall, the survey permission level is above the 80% number at this point, which is – if you kind of go back to when we started pre-filing that's quite a lot of – accomplished in a short period of time. So, things look good in – for Atlantic Sunrise, particularly, as you know, the project is 100% in the State of Pennsylvania. And there's quite a bit of effort from a manpower resource perspective on Atlantic Sunrise and we feel good about it right now.

[Phil J. Jungwirth:]

Great. Thanks a lot.

[Dan O. Dinges:]

Thanks, Phillip.

[Operator:]

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

[David A. Deckelbaum:]

Good morning, Dan and everyone else. Thanks for taking my questions.

[Dan O. Dinges:]

You bet, David.

[David A. Deckelbaum:]

I'm just hoping to get a reconfirmation on the Leidy Southeast Expansion, is that still expected to be in service by the end of the year?

[Dan O. Dinges:]

Yeah, Jeff?

[Jeffrey W. Hutton:]

Yes. That's a December 1 in-service date. And we understand that the Greenfield portion of that, the new pipe looping has been completed and now it's some adjustments to compressor stations and I think away we go.

[David A. Deckelbaum:]

We should see, I guess, a benefit from the firm sales that you'll have going on once that expansion is complete in terms of basis.

[Jeffrey W. Hutton:]

Yes. That's correct. The – two things. The capacity that's been created on Leidy Southeast, the 525,000 a day is – was a market poll project, so you'll have a new area to market the Leidy Line production or receive gas into, about 0.5 Bcf a day, we think that's going to benefit Leidy Line pricing as a whole. In addition to that, Cabot has some long-term sales that will kick in December 1, when the project starts. And the sales are more related to the market area than the supply area, so they will benefit our realizations.

[David A. Deckelbaum:]

Okay. That's helpful color, Jeff. Thank you. And, Dan, if I might ask about Wood County. Is there any update on your thoughts around there in Utica activity? I know you said on past calls that you're kind of evaluating the area out there one way or the other. Can you give us any color on what you're looking out there now?

[Dan O. Dinges:]

Well, with our effort being exploratory in nature, we're usually cautious when it comes to discussing exploration efforts. And our position in West Virginia as you head around Wood County and as you head south, we have a fairly significant acreage position throughout West Virginia. We have almost 1 million acres in West Virginia. So, we do have an ongoing exploration effort looking at the deeper section. We have drilled a deeper test south of Wood County and we are flowing that well just to get a test. It's a vertical well. Just to look at a section. We also have some additional section to look at in addition to what we're flowing back right now. And we have another area that we are – there are a couple of areas that we're continuing to look at that we think has exploratory opportunity anyway. We don't have anything we could add as far as color, David, that would say here's our next development program at this stage. But we do have acreage that's HBP in these areas, we do have B minerals in the areas that we're looking and we have enough reason to believe that it merits further capital at some point in time.

[David A. Deckelbaum:]

Got it. So it might merit your own capital or someone else's capital?

[Dan O. Dinges:]

Well, we're going to spend our own capital at this stage.

[David A. Deckelbaum:]

Thanks for the color, Dan. I'll get back in queue.

[Dan O. Dinges:]

Yeah, thanks, David.

[Operator:]

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

[Charles A. Meade:]

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

[Dan O. Dinges:]

Hey, Charles.

[Charles A. Meade:]

I wanted, if I could, to ask you a bit about what kind of circumstances or what are the pieces you're foreseeing to bring some of these volumes that you voluntarily curtailed up back on. I think Jeff already talked about that Leidy Southeast Expansion coming on December 1 and your firm sales there, so that will be a piece of the step-up in volumes for Q4. But to the extent you're willing to share, can you talk about at the margin what kind of local pricing you would need to see on that Leidy Line to open up some of the chokes and reduce your gathering pressure?

[Dan O. Dinges:]

Yeah, Charles, we're not going to get in price specific. And I'll flip it over to Jeff to talk about the dynamics of the market. What we would hope to see, though, that would influence us to open up some of the wells more so than they are today would be just the seasonal dynamics that we anticipate rolling into the winter period. We also have a couple of things that Jeff had mentioned and he can flesh those out. But as far as being price specific, we're not just going to get price specific at this stage on what we might do on bringing additional volumes on. But, Jeff, would you – yeah.

[Jeffrey W. Hutton:]

Sure. Yeah, I think the market dynamics of worst-case have bottomed out and we're seeing some optimism in the marketplace, not to the point where gas is going to come back on, but we're certainly gearing up for a better fourth quarter. And for the winter, we have some utility sales that kick in in the winter that aren't around in the summer for feeding load. And we mentioned Leidy Southeast. We have another project that we're involved in, the Columbia East Side Expansion, which adds well over 50,000 (30

[Charles A. Meade:]

Got it. Thanks for the detail, Jeff. And, Dan, certainly understood that you don't want to talk individual or specific price. But if I could go back, Dan, to one of your prepared comments on the CapEx picture, and that's definitely helpful, the detail on the CapEx incurred versus your cash flow CapEx. But just taking your $540 million for the first half 2015 CapEx incurred, you're still looking like a pretty significant drop for a run rate for the back half of the year. And I'm wondering if you could maybe offer some commentary, you're keeping four rigs running, but you have that CapEx dropping. Is that a function of deferring more completions on that? I know you gave us your drill to complete count at year end, but how does that look from your perspective? How are you going to get to that reduced CapEx run rate?

[Dan O. Dinges:]

Yeah, that's exactly what it is, Charles. We have guided that we would have the 20 wells or so in the Eagle Ford and we've also guided that we would have 45 wells in the Marcellus and that's anywhere from probably 1,200 to, I don't know, 1,400 or so stages that we have at the end of the year. And it is our plan to sometime between now and the end of the year, for example, in the Eagle Ford, we would plan to cycle out the frac crew that we have right now and then bring that frac crew back in towards the latter part of the year in the Eagle Ford. And we would anticipate sliding some of the frac stages that we have in the Marcellus to the beginning of 2016 also. So you're exactly right on the management of our capital discipline is going to be through completions for the most part.

[Charles A. Meade:]

Got it. That's helpful, Dan. Thanks a lot.

[Dan O. Dinges:]

All right. Thank you.

[Operator:]

The next question comes from Subash Chandra of Guggenheim Securities. Please go ahead.

[Subash Chandra:]

Yeah, hi. Good morning, Dan. I was hoping you could break down that five-year study with a potential impact of Constitution only. And then I guess you talked to the Constitution plus the Atlantic Sunrise, but is it possible to talk about what that study is saying about the Constitution impact on differentials? And I guess the second part of that question is, did that differential outlook include what are presumably higher transport expenses which are a different line item, or was it all-inclusive?

[Dan O. Dinges:]

Well, to answer the last part of that first, the study was an extensive study. It utilized all the available data out there, certainly integrated all of the positions that were out there that you can see and the different crags (34

[Subash Chandra:]

That was great. Thanks. And to follow up, just real quick. Can you just comment on the number of completions in the second quarter, Marcellus and Eagle Ford?

[Dan O. Dinges:]

Well, on the Eagle Ford, in the third quarter – I'm not going to go with the rest of the year. But in the third quarter, I think we have about five wells we're going to complete. And I don't have that number in the Marcellus. But it's going to be a similar number that we had in the second quarter. And I want to say that's probably going to be 18, 20 type wells.

[Subash Chandra:]

All right. Got it. Thank you very much.

[Dan O. Dinges:]

Yeah.

[Operator:]

The next question comes from Pearce Hammond of Simmons & Co. Please go ahead.

[Pearce Wheless Hammond:]

Good morning and thanks for taking my questions.

[Dan O. Dinges:]

Hello, Pearce.

[Pearce Wheless Hammond:]

Dan, as you peer into 2016, do you think that you can keep CapEx flat year-over-year and grow production? I think, in the past you mentioned that maintenance CapEx was around $600 million, $700 million.

[Dan O. Dinges:]

We – yeah. We think we can grow production at the same capital exposure. We think we can also – the volumes that we're capable of producing today, which is over 2 Bcf, we think we could quite frankly reduce the capital we have in the – we're spending in the Marcellus this year and maintain a flat production profile for slightly better than 2 Bcf a day.

[Pearce Wheless Hammond:]

Great. Thank you for that. Then my follow-up, can you remind me of the stream-crossing window and tree-cutting windows for the construction process for Constitution.

[Dan O. Dinges:]

Yeah. Jeff, why don't you...

[Jeffrey W. Hutton:]

Yes. Pearce, the stream crossings are June 1 through September. And the tree clearing is October 1 through March.

[Pearce Wheless Hammond:]

And so, Jeff, if you were able to get the permits from the New York DEC relatively soon, I know you said second half 2016 – I don't know if you want to get this granular, but when you take all that in to account, do you think it's a more kind of a late 3Q or 4Q of 2016?

[Jeffrey W. Hutton:]

Yeah. At this point, we're sticking with the second half of 2015.

[Dan O. Dinges:]

Pearce, what I think is going to happen is that hopefully we'll get the approval from the DEC. Again, we know that we have continued to be as transparent as the information is available to us, but we would hope to get the DEC approval. What we would also expect is that some of the stream crossings we think we can complete in – prior to the September closure period for open cuts and streams. But I don't know and I don't think that we could get all of those stream crossings done prior to September. Some of it depends on weather and certainly some of it is based on the timing the DEC gets out there. We did change our capital allocation number a little bit from – reduced it from 70 to 38 I think as – with our assumption that how much we're going to be able to do on those stream- crossings in 2015 versus 2016. But coming out of the 2016 – into 2016, the beginning of the summer of 2016, depending on how many stream crossings we have remaining, if we have some remaining, we anticipate to start immediately on those, complete those, and then the project would then – could be commissioned following that. Keep in mind during this period of time, it's the stream crossings that have these sideboards on them. The rest of the pipeline, we can keep continuing the tie-in and do all of those things that we have to do. It's just those stream crossings and tying in those pinch points on the streams that we're juggling in the schedule. So, sometime – if we have stream crossing sometime after the June period, depending on how many and when we hook those up, will dictate when we can commission the pipeline.

[Pearce Wheless Hammond:]

Thank you, Dan. Very helpful.

[Dan O. Dinges:]

Yeah. Thank you, Pearce.

[Operator:]

The next question comes from Phillips Johnston of Capital One. Please go ahead.

[Phillips Johnston:]

Hey, guys. Thanks. I just wanted to clarify the quarterly cadence of the Eagle Ford completions this year. I think the plan was to complete 40 to 45 wells. And I think you completed 20 in the first quarter. I think you said you expect five wells in the third quarter. What was the second quarter number again? I think I missed that one.

[Dan O. Dinges:]

Yeah. Steve Lindeman is in here also.

[Steven W. Lindeman:]

See, we completed in the second quarter about 350 stages, and so we had about 13 wells in the second quarter.

[Phillips Johnston:]

Okay. And then if we look at liquid volumes, I guess you were flat for the quarter sequentially. Looking at the guidance, it sort of implies mid- to high-single digit sequential declines in both Q3 and Q4 with that one rig program. I'm wondering what you guys estimate is your natural PDP decline rate in the Eagle Ford if no activity is assumed.

[Steven W. Lindeman:]

Well, that's a good question. I would say that the blended rate would probably be in the 15% range in terms of decline. We'll look at that more carefully at yearend. But that's what I would I guess right now.

[Phillips Johnston:]

Okay. And just one more if I could. Last quarter, you guys noted that 10 wells that were drilled on the new acreage in Eagle Ford were sort of tracking 50% above your type curve. Can you give us an update on how those wells are holding up now relative to the curve? And of the 13 completions you had in the second quarter, can you tell us how many of those were on the new acreage?

[Steven W. Lindeman:]

Yeah. I would say a significant number of the 13 were on the new acreage. The ones that we've got, I would say, 60 to 90 days' worth of history, we're very, very confident in how they're producing and they look like we indicated right in with their expectations. And obviously, the new wells, we're still monitoring how they're coming online.

[Phillips Johnston:]

Okay. Thank you, guys.

[Dan O. Dinges:]

Phillip, one thing that I would add is that in looking at the production profile and our deliveries, one of the things that you have to take in consideration, and it is a variable, is it's dependent upon what pad site we are fracking, when we – how many days we stay on that pad site, and how much production and the type of wells that we shut in, offsetting that pad site during the cycle does affect your production volumes for that brief quarterly calculation. So, you have to take that in consideration also.

[Phillips Johnston:]

Okay.

[Dan O. Dinges:]

Yeah.

[Phillips Johnston:]

Thank you, Dan.

[Dan O. Dinges:]

Thank you.

[Operator:]

The next question comes from Drew Venker of Morgan Stanley. Please go ahead.

[Drew E. Venker:]

Good morning, everyone.

[Dan O. Dinges:]

Hey, Drew.

[Drew E. Venker:]

I was hoping you could – Dan, if you could expand a little bit more on the Utica acreage you mentioned – or West Virginia, I'm sorry. Could you talk about how much is prospective for Utica or if you have a sense for that?

[Dan O. Dinges:]

Being exploratory and looking at what we're doing, everybody is aware there is – the deep Rome Trough runs through the middle of West Virginia. We have a significant amount of acreage on this Rome Trough. It is a deep section, predominantly unexplored, and very few penetrations into that deep section. So we have, not just the Utica section, but other sections that we would look at in West Virginia. I might also add that, certainly, our Utica opportunities, as we move to the east, in Pennsylvania and under our Susquehanna properties, we think we have Utica in that particular area of our portfolio also. So, in summary, we're looking at not only what Utica potential there would be, but other section that might be an opportunity in the Rome trough in West Virginia. But we're also looking at different section and will look at different section at some point in time in our Susquehanna acreage.

[Drew E. Venker:]

And is that something that – the Rome trough, would that get a fair amount of capital in 2016? Or is it still be determined? I mean, is there plans to test that near term I guess really is the question.

[Dan O. Dinges:]

Yeah. 2016 and looking at what percentage of our capital will be allocated to exploratory is still in the works. We are – we do a bottoms-up build, we look at our program, we look at the landing area that we would want to achieve on our production. And certainly, that is in concert, and it will continue to be in concert with the macro-infrastructure aspects. And then we would – then as not an afterthought, but as not as high a priority look at the cash flow and our available cash to allocate on exploration programs and we dovetail into that any lost opportunities we would have if we didn't allocate capital, both on our development areas and our exploratory efforts.

[Drew E. Venker:]

Okay. And then just a follow-up on that in Susquehanna for the Utica, if you can compare for us the Utica rock in that area versus the Marcellus of a similar thickness and rock quality?

[Dan O. Dinges:]

Well, I can't yet, we haven't drilled it. But I would say from our deeper mapping and carrying some of the Utica drilling that's been done in Tioga and looking at that section, that section there is a couple of hundred feet thick. And certainly we are modeling an eastern extension of that Utica. And we think we have some equivalent thicknesses and we think we have similar maturities and TOCs as seen in the Tioga area.

[Drew E. Venker:]

Thanks, Dan. That's very helpful.

[Dan O. Dinges:]

Thanks, Drew.

[Operator:]

The next question is from Eric Otto of CLSA Americas. Please go ahead.

[Eric Otto:]

Good morning. Could you give us just an update on the Corps of Engineers Section 404 permit status?

[Dan O. Dinges:]

Yes, Eric. I'll let Jeff go over that.

[Jeffrey W. Hutton:]

Yeah, so when the State of Pennsylvania issued their 401 permit and what we're waiting on with New York on their 401 permit, that essentially is what enables the U.S. Corps of Engineers to issue their 404 permit. So it's the data coming out of the New York 401 permit that is missing. And our understanding is it's a supplemental addition for the U.S. Corps to add to their 404 permit and that permit generally comes out just a few weeks after all the information is received.

[Eric Otto:]

Okay, thank you.

[Dan O. Dinges:]

Thanks, Eric.

[Operator:]

The next question is from Brian Singer of Goldman Sachs. Please go ahead.

[Brian A. Singer:]

Thank you. Good morning.

[Dan O. Dinges:]

Hey, Brian.

[Brian A. Singer:]

With the sharp move down in valuations in the forward curve, what are your latest thoughts on willingness to add to positions? And would you consider adding in Appalachia or be more focused on oilier assets, if at all?

[Dan O. Dinges:]

That's a good question. We have continued to run our operation with the primary focus of maximizing returns, as I've said, and the efficiencies, trying to protect the margins or improve our margins. We think in this environment that a good strong balance sheet and one that affords the greatest flexibility not only allows you to conduct your operations prudently and allows you to manage from a position of strength, but if there is an opportunity that presents itself, then we're certainly in a great physical and financial position to take advantage of it. As far as looking at the two commodities, looking at oil, gas, we're really returns-focused and we feel like that is going to remain our focus. You can get into the discussion about how you would want to look at a more diverse program, add a little bit more oil to our program, obviously diversify us a little bit. But I've been in the business a long time, Brian, and looked at these different cycles that we've gone through. And our view of our crystal ball rolling forward for our position in the natural gas space and what we think we can do with improved infrastructure, we think we're going to be able to deliver extremely strong returns with our natural gas position. And we think it is going to be with our crystal ball look at the liquid side of the business that natural gas liquids are going to be challenged for an extended period of time. And we think that on the oil side, it's such a dynamic market with the international influence that affects the oil market, that crystal ball is not, in my opinion, I'm not as confident as what the oil price is going to do as I am what I see available to us on the natural gas side. So with that being said, we're focused in natural gas, we'll remain focused in natural gas. If we have the opportunity to improve our liquids position, it's going to have to compete with what our view is long term in natural gas.

[Brian A. Singer:]

That's very helpful. And then secondly, you may have mentioned this before, in which case apologies. But are you still planning to have the wells needed to source your 500 Mcf a day Constitution commitment drilled but not completed by yearend? And how are you thinking about the merits of completing those wells in 2016 versus keeping them in inventory?

[Dan O. Dinges:]

Well, our position on Constitution still remains to have the flexibility to add incrementally to our growth position, but also a decision that we could just displace our level of production at the time of the Constitution commissioning and transfer those volumes to Constitution. So it is our intent to manage our completion schedule in light of what we see as the commissioning date of Constitution. And the macro market is going to dictate a little bit how we respond. To our filling of Constitution, that will absolutely happen regardless of what the macro market is doing, but the macro market would influence is it going to be incremental or is it going to be just a displacement initially.

[Brian A. Singer:]

Thank you.

[Dan O. Dinges:]

I'm sorry I can't be any more specific than that. We are going to look at the market at that time and make the call.

[Brian A. Singer:]

I'm sure we'll ask again next quarter. Thank you.

[Dan O. Dinges:]

That's all right, Brian.

[Operator:]

And the next question comes from David Beard of Coker Palmer. Please go ahead.

[David E. Beard:]

Good morning, gentlemen.

[Dan O. Dinges:]

Morning, David.

[David E. Beard:]

A lot of detailed questions have been answered so I wanted to hear your thoughts, big picture, really back to the very first question of this call relative to differentials. It seems people in the industry, you and others in the Marcellus are fairly optimistic, two, three, four years out on differentials, narrowing down pretty substantially, while there's – it seems like many financial players are saying the differential is going to stay at $1 or more relative to transportation costs. I'd just like to hear your thoughts about why there is such a, I guess a variant view relative to what takeaway capacity can ultimately do to differentials? Thanks.

[Dan O. Dinges:]

Yeah, David. I think the market is going to be – is going to continue to be diverse. I don't think differentials are going to be equal across all spaces. I think differentials will be – continue to be subject to – even in the longer term, will continue to be subject to gas-on-gas competition. In our specific instance, what we see is getting to price points and to areas in the market that we feel like will have the demand side of the equation matching the supply side and the ability for just that amount of gas to get to different price points. Constitution, as an example, we're going to be able to move gas, not only south from Wright Station, but we're also going to be able to move gas north into Canada from that position. We also would hope to be able to move gas to a different price point when the Atlantic Sunrise comes on. Cove Point is a unique project for us and the differentials that are attached to that project are basically part of a contractual – a confidential contractual arrangement. So we feel confident about what our realizations are going to be on that marketing of that volume of gas. We also have a price point set at the 500 million, the remaining 500 million of the Atlantic Sunrise volume. So, in looking out where we are, we just feel in looking at point-specific areas that the narrowing of the differential seems to – and tying it to the demand situations in those areas and at that particular – those particular price points, we just feel confident that the volume of gas that can get to those price points is going to measure up to the demand that we see. In other areas, to your point, David, on some of the modeling out there has – still has differentials of $0.50 a dollar. There might be areas that have those type of differentials and those are going to be areas that have ongoing bottlenecks where gas-on-gas competition is not going to be able to get the volumes of gas out that are on the supply side to reach the demand areas and there could be those specific areas that have those type of differentials. What our – and kind of to your to point, David, that was part of the reason why we commissioned a unique independent study for Cabot's behalf to answer some of those questions on the market dynamics from a macro sense and also a micro sense on its effect on Cabot, and where we're moving our gas.

[David E. Beard:]

All right. Good. I appreciate the color and thank you for the time.

[Dan O. Dinges:]

Yeah. Thank you, David.

[Operator:]

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

[Dan O. Dinges:]

Thanks, Kate. And thanks for all the questions. The focus remains on the macro market as it probably should at this period of time. I think everybody is clear that our operation will deliver the volumes into the market. But certainly I've been in this business over 30 years. I've seen a lot of cycles. And this is one of those draconian down markets. But I do reflect back on what we have available in our program, what our market will be able to – what our properties will be able to yield and what our program will yield. And I'm very confident if we get these pipes out and we get to the markets that are available to us at the end of the pipes that we already have in progress that Cabot's outlook for the future, and when you look at this five-year plan, Cabot is going to be a company that's going to deliver significant growth. It's going to deliver that significant growth with the realizations I think we'll see with a free cash flow program. And we are going to be able to generate a significant level of free cash. So with that, I appreciate everybody's patience. I understand the frustrations with this type of market, but I can assure you that there are better days ahead. So, thank you again, and we look forward to a visit in our third quarter conference call. Thank you.

[Operator:]

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