Cabot Oil & Gas Corporation
Q2 2016 Earnings Call Transcript

Published: 29 Jul 2016

[Operator:]

Good day and welcome to the Cabot Oil & Gas Corporation's Second Quarter 2016 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, Ericson, and thank you all for joining this morning for Cabot's Second Quarter 2016 Earnings Call. I have today with me several members of the executive team. Before we start, let me do say that the standard boilerplate regarding forward-looking statements included in this morning's press release applies to my comments on today's call. Cabot's second quarter results highlight our ability to deliver production growth while also generating positive free cash flow even in a low commodity price environment. We believe this characteristic sets us apart from most of our industry peers. Cabot averaged 1.67 Bcfe per day of net production during the quarter, an increase of 10% compared to the second quarter of 2015. This increase was driven by 14% increase in our Marcellus production volumes as compared to the prior-year comparable quarter. Despite a realized natural gas price of only $1.63 per Mcf, we generated positive free cash flow for the quarter and we anticipate that the company will be able to deliver a more meaningful level of free cash flow during the second half of the year based on current strip prices. Natural gas realizations did improve by 9% sequentially, as compared to the first quarter of the year, due in part to a significant improvement in local basis differential during the quarter. Before the impact of derivatives, Cabot's realizations were $0.40 below the average NYMEX settle price of $1.95 during the quarter, as compared to $0.60 below the average NYMEX settlement price in the first quarter. While basis differentials have subsequently widened in the third quarter due to a significant increase in the NYMEX prices, the good news is that we are forecasting much higher price realizations during the second half of the year, resulting in more free cash flow for the year than originally forecast. This increase in expected cash flows has allowed for the introduction of a second frac crew in the Marcellus for a portion of the second half of the year, which will help give us a jumpstart on 2017 production. Using the current five-year forward curve for Leidy Line, which is a good proxy for the most punitive pricing a portion of our Marcellus production receives, our well level internal rate of returns are over 100% and our PV-10s are approximately $14 million. I cannot think of another asset that generates those economics in the current price environment, and therefore, we feel extremely comfortable about slightly increasing our levels of operating activity beginning with this additional frac crew. The second quarter results also demonstrate our continued emphasis on cost control with unit costs declining by 12% compared to the prior-year comparable quarter, and 2% compared to the first quarter of this year. We have now delivered a sequential decline in unit costs for 12 of the last 13 quarters and expect this trend to continue, further improving our industry-leading cost structure. Our balance sheet remains extremely strong with over $500 million of cash on hand and a net-debt-to-EBITDAX ratio of only 1.8 times at quarter-end. Based on our current forecast, we anticipate de-levering between now and year-end while our current liquidity of $2.2 billion should continue to improve, given our outlook for positive free cash flow in the second half of the year. This financial flexibility will serve us well as we formulate our plans for 2017 and beyond. In the Marcellus, we continue to operate one drilling rig, and as mentioned, have recently added a second frac crew to accelerate the completion of our DUC inventory, which will allow for an acceleration of production in the first quarter of 2017. During the quarter, we drilled seven wells, completed eight wells, and placed 12 wells on production. The average lateral length for the seven wells drilled during the second quarter was approximately 7,000 feet. However, given that all the wells, 100% of the wells we placed on production year-to-date were drilled in 2015, and the average lateral length was a little bit shorter and closer to 6,000 feet. The good news is that we should continue improvements in capital efficiency in 2017, as we've began placing on production the longer lateral wells from this year program. On the production front, we averaged approximately 1.54 Bcf per day of net production for the Marcellus during the quarter, which was slightly below the midpoint of our expectations due to unscheduled downtime related to infrastructure maintenance in the region. Had we not experienced this downtime, we would have eclipsed the high end of our production guidance range for the quarter. Unfortunately, July production volumes have also been impacted somewhat by outages on Transco for the majority of the month. However, we are confident that we'll be able to keep production levels flat to the second quarter based on our plans of placing 12 wells on production during the third quarter. On the operations front, our drilling team continues to capture more efficiency gains, which was evident by a new record for drilling days during the quarter of approximately nine days for spud to TD, and 13 days for spud to spud. We also drilled our longest Marcellus well today, with a total measured depth of over 18,000 feet and a lateral length of over 10,000 feet, which the schedule will be completed in 2017. A brief comment on our Eagle Ford Shale. Despite a significant reduction in our Eagle Ford operating activity, including no wells drilled and only three wells completed during the quarter, our oil volumes for the second quarter exceeded our guidance due to outperformance from the newer wells that were placed on production. Given that our last Eagle Ford well was placed on production in May, we are not placing any wells on production during the third quarter, we are forecasting declines in our oil production volumes for the remainder of the year which is in line with our original plan. At this point in time, based on our current outlook for oil prices, our plan is to continue to allocate a minimum amount of capital to our Eagle Ford assets and instead focus on arresting base declines, meeting our leasehold obligations, and waiting for our slightly higher oil price environment before allocating any additional capital to this asset. I would highlight that even in today's prices, our returns in Eagle Ford far exceed our cost of capital; but given the much higher returns we see in the Marcellus, we believe the best place for additional capital today is in Susquehanna County. As you may all be aware, Cabot is directly involved with multiple pipeline ventures that focus on our growth opportunities over the next several years. I would like to provide a few updates and comments on the progress of these important infrastructure projects since our last call. Regarding Constitution, our initial appellate brief was filed on July 12, 2016 with the U.S. Court of Appeals for the Second Circuit. Included in this brief is a very comprehensive summary of the issues we found regarding the New York DEC water quality application process and additionally outlines the schedule for the appeal process. Together, this brief should answer a majority of your questions concerning Constitution. We have made progress as well with Atlantic Sunrise. During early March, the FERC issued a scheduling notice for Atlantic Sunrise and on May 5, 2016 issued the draft Environmental Impact Statement. Our expectations are to receive the final Environmental Impact Statement during October and to remain on schedule for a late 2017 in-service. For the Tennessee Gas Pipeline Orion project, the FERC also issued their scheduling notice for environmental review during June and indicated that the final environmental assessment would be issued by mid-August 2016. This $135 million per day project remains on schedule for a June 18 in-service date. Also of note was the recent issuance of the draft Environmental Impact Statement by the FERC on the 1 Bcf a day PennEast project. The final EIS is scheduled for mid-December, and this project remains on schedule for late 2018. As a reminder, Cabot has $150 million a day committed to the PennEast project. Moving on to our recent announcements of the Lackawanna Energy Center power facility. We are very excited to be the exclusive provider of up to 240 million cubic foot a day to Pennsylvania's largest natural gas facility and one of the most efficient power plants in the U.S. Together with our previous announcement to provide 100% of the natural gas requirements to the Moxie Freedom plant, Cabot will be providing more than 400 million cubic foot a day to local demand projects. Both facilities are essentially tied into our gathering system, eliminating the need to commit to expensive, long-term FTE agreements. And our pricing terms, although confidential, provide very attractive rates of returns with netbacks that are expected to be materially better than our anticipated netbacks in the local region. Assuming a gross exit rate for this year of approximately 2 Bcf per day, we have line of sight to double our production to over 4 Bcf per day, assuming all of the announced projects are approved and built. For all the Constitution naysayers out there, while we are still extremely confident that the project is ultimately constructed, even without Constitution volumes, we still have direct line of sight to have the ability to produce over 3.5 Bcf per day by the end of 2018, which is effectively double the production levels we averaged during the second quarter. Not to mention, our marketing team continues to evaluate additional projects that would all be incremental to the numbers I just discussed. I have an outlook comment. As a result of continued efficiency gains and incremental cost savings, the company plans to complete an additional 15 to 20 Marcellus wells during the second half of the year and will also incur an additional $20 million of capital. The production impact of accelerated Marcellus completions will not be realized until early 2017. Therefore, we're leaving our current 2016 production guidance unchanged. While our plans for 2017 are still being evaluated and our official budget will not be announced until October, I can say that measured growth in the 5% to 10% range in 2017 is a prudent and reasonable assumption. And based on today's outlook, we would generate even more positive free cash flow next year than we will this year. When you look at Cabot's story over the next several years, I see a company with a strong balance sheet that continues to get better, best-in-class economics that continue to improve, cash margins that are expected to almost double by 2018 at this current strip, a growth outlook that allows for a doubling of Marcellus production volumes once the majority of our infrastructure is in service and a significant level of free cash flow accumulated during the period of time, providing optionality for program acceleration, dividend enhancement, share buyback, balance sheet management, et cetera. Needless to say, the outlook for Cabot is certainly bright and I look forward to providing more details about our long-term plans in October. Ericson, with that brief statement, I'll be more than happy to answer any questions.

[Operator:]

Excellent. We will now begin the question-and-answer session. At this time, we will pause momentarily to assemble our roster. And our first question comes from Neal Dingmann of SunTrust. Please go ahead.

[Neal D. Dingmann:]

Good morning. And nice details, Dan. Say, Dan, a question for you. Given the single well economics that you're discussing out there, obviously very positive, over 100%. When you look at that and when you look at inventory, why not bump production even more given the efficiencies? Is it more about takeaway or are there other bottlenecks that you're considering?

[Dan O. Dinges:]

It's a great question, Neal, and we have that internal debate often. When you look at the macro market and you look at the volatility still out there in the macro market, even though there are additional volumes we could move today, we do think it's prudent to be rational into the market. We've seen NYMEX increase in the third quarter, beginning of the third quarter, but we've seen the differentials expand a little bit. Even though our realizations have improved over second quarter, we still think as we gain traction, continue to get regulatory approvals on the infrastructure buildout, we think it's prudent to be rational at this point in time until we see the infrastructure projects put in place. And at that particular time, be prepared for the ramp-up. And by doing so in concert with that buildout, we don't think it's going to create liabilities to the existing basin and the limited infrastructure we have.

[Neal D. Dingmann:]

And then, yeah, Dan, I just want to hit on efficiencies real quick. You mentioned about 13 days spud to spud. Is that now what you guys – is that just occasionally? What do you guys look at now as a typical spud to spud, given you've had some great value improvement on efficiencies?

[Dan O. Dinges:]

Yeah. We have Phil Stalnaker here, who's our VP of our North Region up here, and he's looked at it across the quarter. And Phil, what do you see for that?

[Phillip L. Stalnaker:]

Those numbers on the wells that we drilled during the quarter, that was actually the average for the quarter. So, yeah. We continue to build on those efficiencies. It's not just a one-off. It's what we're projecting right now.

[Neal D. Dingmann:]

Wow. Very good. And then lastly, just, Dan, any comment on the diffs. Is that just seasonal? Again, they certainly were a bit lower for second. I think guidance was back up again. Just any thoughts on the gas diffs.

[Dan O. Dinges:]

Yeah. The gas diffs stay volatile just as the market does. We saw a nice day this week yesterday after storage numbers how rapidly it can swing. I'll let Jeff make a brief comment on the diffs, Neal.

[Jeffrey W. Hutton:]

Yeah. Okay, Neal. The differences in the second quarter certainly improved and a lot of that was related to the drop in NYMEX. We saw Henry Hub in the second quarter average $1.95, and compared to the second quarter of 2015, for example, it was $2.64, and we saw about half the differential this year compared to last year. Of course, we had (18

[Neal D. Dingmann:]

Very good. Thanks, guys. Great quarter.

[Dan O. Dinges:]

Yeah. Thanks, Neal.

[Operator:]

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

[Drew E. Venker:]

Good morning, everyone. I was hoping you could talk about what you're seeing in terms of acquisition opportunities. You have significant free cash flow generation, which I think is rare nowadays amongst your peers. So, just would like to hear what you're thinking about it.

[Dan O. Dinges:]

Yeah, Drew. It's a good question. We get that M&A question because we do have such a strong balance sheet and great cash flow. We look at deals out there. We look at opportunities, and we try to stack them against what we have as our ongoing model. We put together, or I should say, on the process of putting together a five-year model. We'll present this five-year plan to our board in October. In discussions with that model, we look at organic program, what we are able to achieve, what the assumptions that we place in there on commodity pricing. And then, we also look at the available opportunities out there and also just our own internal ideas of what we might be able to do different to enhance long-term shareholder value. And that's a continuing discussion we have in our board meeting, not only in every board meeting but we also have an off-site meeting that many are aware in September that is a strategic discussion at the 30,000-foot level, of the macro market, the movements in the market, strengths of the market, opportunities in the market to see how we can continue to enhance shareholder value. So, we have not been an acquisitive company but we have been a company that continues to evaluate the opportunities that are out there and the asset basis and/or, in some cases, the corporate companies that have possible needs and their future to do something different. So, we haven't made any decisions but we do evaluate the market.

[Drew E. Venker:]

Yeah. Thanks, Dan. Just a follow-up on that. I guess part of what I'm curious about is with the rates of return you can generate in the Marcellus, whether you really see much that's competitive with that on the acquisition front or if that's how you think about it. And as you've gone through the deal process, has there been anything that's come close to meeting those thresholds that you'd need to move forward with an acquisition?

[Dan O. Dinges:]

Yes. We have, I think, demonstrated with our plan how we're running the company and what we have done in trying to rationalize our growth, and measured growth is what we have provided. We do that because we are trying to maximize our return in a soft commodity price environment, and we're certainly trying to look at the market in the macro sense to determine what we think best – our input into the market and how we think that would best maintain the margins and strength of Cabot. So when you look at the M&A market, diversity is one of those areas that we discuss, not only geographic diversity but also commodity diversity. We look at that in a way that compares what we have in our organic program, the risk of execution of our organic program, and how we might be able to enhance the valuation, the return profile in our program, if in fact, we had a bolt-on, we had a new greenfield operation or we had a merge opportunity out there. And to your point of what we receive on a return profile, with every dollar that Cabot invests, it does challenge us to look at the market out there and to look at other assets and to be able to say that we're prepared to displace any capital allocated to our Marcellus and allocate elsewhere. And we don't get comfortable with that, in essence, dilution of that investment in that context. We do look at the infrastructure buildout. We know we have a significant growth profile coming for Cabot, and it's just around the corner. It's now not measured really in years. It's measured in months of when we're going to see that. So, our focus is more internally right now to get our program lined up and to be prepared to grow into that market, double our production or greater, and do that as efficiently as we can.

[Drew E. Venker:]

Thanks, Dan.

[Dan O. Dinges:]

Thanks, Drew.

[Operator:]

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

[David A. Deckelbaum:]

Good morning, Dan, and Scott and Jeff. Thanks for taking my questions.

[Dan O. Dinges:]

Hi, David.

[David A. Deckelbaum:]

Dan, can you give any color, I guess you talked about exiting this year I think at 2 Bcf a day growth and then, I guess you'd be ramping into that first quarter there. Is the thought I guess you'd be basically at your capacity almost in 1Q in terms of deliverability, and you'd more or less hold that number kind of flattish throughout the rest of 2017, unless there was some other release capacity out there?

[Dan O. Dinges:]

Yeah. We think that the – and I'll let Jeff talk kind of about the market and how we might grow into the market a little bit and focus on 2017 pre-infrastructure buildout. But when we look at the exit at 2 Bcf, again, we're measuring our growth at this point in time. We have cash on the balance sheet, we have the ability to ramp up as you might suspect. But we think prior to, again, getting closer to the in-service of the infrastructure, we think it is a benefit to keep this in-basin dynamic of restricted growth on the three pipes and the supply side in somewhat of a balance. But we do see it relatively – and our plan is to stay relatively flat from an exit volume of 2 Bcf and that's what got to my measured growth comment in 2017 of 5% to 10%. Jeff, you want to make any comments about kind of the dynamics of the market up there right now?

[Jeffrey W. Hutton:]

Yeah, sure. David, if you recall, we've been to 2 Bcf before, 2 Bcf today is not a stretch in terms of moving gas, and finding capacity, and expanding our existing markets and our customer bases. Right now, and we've talked a little bit about this on the first call, about the availability of excess firm capacity in the marketplace and the secondary market. We look at that every day. We're pretty happy we didn't pull the trigger back in February on a number of these capacity deals. Quite frankly, the rates keep improving, the options keep getting better, the volumes are more to our liking, the durations are more to our liking. And so we're watching this capacity release market very closely. And as we get further into the year, we find that there's more producers or I should call them producer-shippers that aren't using their capacity, and it's quite dynamic. But it's something that we think at some point we will pick up some additional capacity that just bridges the gap over to – closer to 2018. So, a lot of options right now, and I think they're really good options to improve netbacks.

[David A. Deckelbaum:]

I appreciate that color, Jeff. So, it sounds like there is some potential I guess to see some release capacity in 2017, then.

[Jeffrey W. Hutton:]

Potential, yes.

[David A. Deckelbaum:]

Just the last one that I had for you guys is, how are you thinking about hedging right now? We've seen a lot of your peers putting out hedges sort of in this $3 range in 2017. And you guys kind of set foot on that right now. How are you guys thinking about the hedge book going into next year?

[Dan O. Dinges:]

Yeah. Our desire is to underpin some of our volumes with the hedge. We continue to look at the market, and again, trying to get a feel for the forward curve. We think that the opportunity to place hedges in the range that have been in the recent past, we think that opportunity still exists out in front of us. And we think actually the opportunity could maybe improve from where some of the hedges have been placed behind us.

[David A. Deckelbaum:]

Got it. So, it sounds like you'd probably wait until like wintertime I guess before layering in something more.

[Dan O. Dinges:]

Yeah. We'll be opportunistic. I can't – the market is, as you know and we all know, is very dynamic and hard to predict with accuracy. But at least, it is our consensus with our hedge committee that we can still protect our volumes into 2017 between now and the end of the year.

[David A. Deckelbaum:]

Thanks, Dan. Appreciate all the color.

[Dan O. Dinges:]

Thanks, Dave.

[Operator:]

Our next question comes from Holly Stewart of Scotia Howard Weil. Please go ahead. Holly Barrett Stewart - Scotia Capital (USA), Inc. Good morning, gentlemen.

[Dan O. Dinges:]

Hello, Holly. Holly Barrett Stewart - Scotia Capital (USA), Inc. Just, Dan, you outlined in your prepared remarks just a lot of the projects that are coming online over the next couple of years to increase your capacity and ultimately your pricing. I think, Jeff, if you could maybe just help us a better understand these power agreements, I think it's close to or over 400 million a day. Just trying to get a sense of maybe how we should model it. You mentioned I think within one of the releases that your gas price is directly linked to power prices. So, is that based on a market heat rate, and then maybe which power price is that associated with, I'm assuming PJM?

[Dan O. Dinges:]

I'll turn it over to Jeff to give color, and he knows and I'm sure he will reiterate the confidentiality of it, but it should be able to help give some better scoping of the power pricing.

[Jeffrey W. Hutton:]

Okay, Holly. This is, of course, a sensitive subject. Holly Barrett Stewart - Scotia Capital (USA), Inc. Sure.

[Jeffrey W. Hutton:]

And we've – first of all, we're very, very happy to be with our partners in the power generation business, diversifying our commodity a little bit more to power from gas and it being in the local PJM areas you mentioned, it's our benefit to link some power pricing to our gas prices. So, the benefit of these two particular projects are unique and that, as Dan, mentioned in the speech, that we – literally, no FTE that we had to buy to get there, so we're all of a sudden out of the gate, were $0.50 to $0.60 better than having to purchase long-term liability FTE to get to these power plants. That said, the pricing for the power plants, a small portion of each one of these plants is local pricing because power plants generally just buy gas, daily gas. So a small percentage of that load is related to local gas daily pricing. However, what we've done is set arbitrary floors and caps under the agreement that protect Cabot and also protect the power generator. And we fluctuate between those floors and caps based on day forward power prices or at least a percent of day forward power price. And that enables essentially the generator and for Cabot to win, and it's a great structure for everyone. Holly Barrett Stewart - Scotia Capital (USA), Inc. Okay. So is there like a minimum volume if the plant doesn't dispatch? Do you still get paid?

[Jeffrey W. Hutton:]

Keep in mind, these are brand-new, high-efficiency plants. Their run time in the first five years will be at least 95% to 96%. So you'll have a couple of days of maintenance each year. Recall, too, that we have a fuel manager between us and the power generator. And that fuel manager's role is to continue to purchase gas and move gas during days or an hour or whatever the case may be, that the plant may not be operating. But we fully expect these plants to operate at a very, very high load rate, at least through the first five years to seven years. Holly Barrett Stewart - Scotia Capital (USA), Inc. Got you. Okay. Great. That's helpful. And then maybe just one on – I know you mentioned the pipeline maintenance, there's a lot of maintenance going on during the third quarter. Have you anticipated any curtailments in your guidance for 3Q?

[Dan O. Dinges:]

There's a minimum curtail volume. I don't have the exact amount of curtailed volume. As we typically do, Holly, we put a risk profile on our production volumes and we have a curtail volume there also. I don't have that number right in front of me. I'm sorry. Holly Barrett Stewart - Scotia Capital (USA), Inc. Okay.

[Jeffrey W. Hutton:]

And, Holly, this is Jeff. One more thought on that. These projects sometimes tend to get out of control. In other words, when the maintenance is done, sometimes it extends longer than the notice scheduled it for. But in this case, the majority of the maintenance that we're experiencing on Transco in particular and – quite frankly, just pipe replacement, we're almost through it. In fact, it ends on July 30. Holly Barrett Stewart - Scotia Capital (USA), Inc. Okay, great. Great color. Thank you.

[Dan O. Dinges:]

Thank you.

[Operator:]

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

[Charles A. Meade:]

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

[Dan O. Dinges:]

Hey, Charles.

[Charles A. Meade:]

I'd like to explore a little bit more your intent to be opportunistic in 1Q 2017 and how that interacts with your decision to accelerate your completion pace here in the back half of the year. Is this the sort of thing where you're committing to delivering more volumes in 1Q 2017, anticipating some better realizations there? Or is this more about you building the optionality to perhaps capture just a week's worth of high local pricing in the event of a cold winter?

[Dan O. Dinges:]

Yeah, we're not really doing it just for a short-term grab, Charles. If you look at our plan that we're going to present in October to our board and you look at – I obviously have the benefit of looking out a little ways with the draft we have currently. And if you look at that bill that we have out in front of us and you go back to the infrastructure projects that we've highlighted here, and there's other things that Jeff is working on, we have to start at some point in time to plan, schedule in an efficient way and the most efficient way, getting out ahead of a ramp of almost 2 Bcf a day additional production. And if you think about that, you'd say real quick it's not that difficult. I have Phil Stalnaker sitting over here beside me and he squirms every day when we look out at the end of 2018, which is not that far out in front of us, and it's his group that is less than 100 people up there but with some excellent rock. His job is to manage the economic growth of our operation up there and to build into this infrastructure. Now, what ideally we were hoping would happen is Constitution would have come on by now. And as everybody knows, the pains of that process. But we've stacked these other infrastructure projects in line now. But the good news is they're all going to happen, but they're going to happen kind of on top of each other and contemporaneous, which does require us to start out ahead of that ramp-up in a way that would have some of the decisions we're making today in preparation for what we expect to be able to build into as these projects come online. So we like the dynamics of where the market is and we certainly like the better pricing we see. For example, to your point in the first quarter of 2017. That's all good and certainly we'll be in that space to benefit from it. But we're looking at more of long-term build and getting up to the 3.5 Bcf, 4 Bcf production range towards the end of 2018.

[Charles A. Meade:]

Dan, that's helpful increment detail. And if I could pick up on one of the things you talked about with this, your really much stronger roster of options on takeaway and demand things in the area. My read is that really the big one, both in terms of volume and time line, is really Atlantic Sunrise. But I'm wondering if you'd agree with that and if you could kind of rank or maybe put on a discussion in terms of both time line and volume, which of the other of these projects, whether it's the Tennessee Gas or the PennEast line that, that would be number two behind that Atlantic Sunrise in terms of the ports?

[Dan O. Dinges:]

Yeah. Quick comment. We had 850 million a day on Atlantic Sunrise, that is the largest project that we have in the pool. And again, without Constitution and these other projects, we can get to the 3.5 Bcf plus or minus capacity without Constitution, and so that's all positive. And I'll let Jeff talk about the lineup, but each of these projects get different price points for us and should be an enhancement to our realizations. Go ahead and run through it, Jeff.

[Jeffrey W. Hutton:]

Okay, Charles. Thanks for the question, by the way. The Atlantic Sunrise project is a big project in anyone's eyes. The scope is large and the good news there is, 850,000 a day of new capacity with a brand new pipe coming into our backyard, but also 100% of the 850,000 a day of gas is sold, and it's sold to two very good markets in the – the Cove Point LNG with Sumitomo, and of course, Washington Gas light in the D.C. area. So absolutely, that's a standout project for us. As we move down the list, it's interesting that the next four projects that we have and in total these all add up to about 1.5 Bcf a day, I'll just make one comment. The good news is on the 1.5, all but 50,000 a day is already placed and sold to very good markets. So in terms of ranking or just how excited we are about these projects over the next 18 months, both power plant facilities are way up there on the list. Good markets, no transport, ratable burns, I mean it's very exciting. The TGP Orion project of 135,000 a day again, 100% of that gas is sold. It's going to South Jersey to a power plant that they're going to operating in the southern part of New Jersey. There's been great pricing there. And then, the PennEast pipeline, that pipeline is 1 Bcf a day and we have 100,000 sold already and 50,000 of capacity, but keep in mind the impact of a PennEast or the impact of Atlantic Sunrise, what that's going to do to basis differentials on Transco. As you start moving a lot of gas off that pipe and a lot of gas out of our supplier, our expectations are that pricing basis differentials both on Tennessee and on Transco are going to improve. I mean, there's just no doubt in my mind. So not only do we have all these projects to take away to the region, a rising tide lifts all ships. And in this case, we expect an upgrade to local pricing connected to all these projects.

[Charles A. Meade:]

Jeff, that's great detail. Thanks a lot.

[Dan O. Dinges:]

Thanks, Charles.

[Operator:]

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

[Brian Singer:]

Thank you. Good morning.

[Dan O. Dinges:]

Hi, Brian.

[Dan O. Dinges:]

Dan, you talked to your lateral length of drilled wells rising to 7,000 feet and then a record well I believe at about 10,000 feet. Can you talk to how you see your average lateral lengths trending as we go into 2017? And as well, give us an update on any changes impacting productivity and from wells adjusted for lateral length.

[Dan O. Dinges:]

Yeah. Well, we have been able to continue to push our laterals out, and in 2017, we expect our lateral lengths to continue to expand out beyond the 7,000 feet. So that's an ongoing project up there in Phil's area, and certainly an objective of ours to continue to lengthen laterals. The productivity is, as you might suspect, is in the – several that we have in this range, we do see very good productivity and it's simply a function of more stages in the lateral lengths and it's staying fairly consistent with the average that we see per stage.

[Brian Singer:]

Got it. So the increased well performance will be a function essentially of the higher lateral length, if we divide it by lateral length, we'd get to a similar type rate?

[Dan O. Dinges:]

Yeah, yeah.

[Brian Singer:]

Okay, thanks. And then I wanted to follow up on Holly's question with regards to the power plant contracts. And maybe I'll try to characterize it this way and I'm sure we can all model and come up with our estimates for the future, but to the degree that you had all the incremental volumes from the local power plant contracts on now or in the second quarter, would that be accretive, dilutive or neutral to corporate – to your average gas price realization before hedging?

[Dan O. Dinges:]

Well, the one comment I would make, first is when you're modeling, keep in mind one of the biggest components of the power plant is going to be the – don't put any firm transportation in the mix. We just don't have any of that, so that's going to be a firm input into your model.

[Jeffrey W. Hutton:]

Yeah. Brian, if we laid it all out today and made the assumptions, we will be $0.25, $0.35 below NYMEX.

[Dan O. Dinges:]

Got it. Fair – got it. So, that is – that would be relative to, say, what you reported in the second quarter or your guidance for – where you'll be below NYMEX for the third quarter, which should be a substantial improvement even before we talk about probably the reduced FTE, or is that more of an overall margin point, or can you add a little bit more color there?

[Jeffrey W. Hutton:]

That's just a point in time the market.

[Brian Singer:]

Okay. Got it. So, $0.25 to $0.30 below NYMEX. And then in addition to that, the benefit of not having FTE.

[Dan O. Dinges:]

Correct.

[Jeffrey W. Hutton:]

Correct.

[Brian Singer:]

Thank you.

[Operator:]

Our next question comes from Mike Kelly of Seaport Global. Please go ahead.

[Michael Dugan Kelly:]

Hey, guys. Good morning.

[Dan O. Dinges:]

Good morning, Mike.

[Michael Dugan Kelly:]

Dan, you gave this kind of softer hypothetical 5% to 10% production growth scenario for 2017, saying that that'd be reasonable. Do you have a sense of how much CapEx would be required to get to that range? Thanks.

[Dan O. Dinges:]

I'll say, we'll put that number out in October...

[Scott C. Schroeder:]

October. But it probably – Mike, it'd probably be about 50%, 60% higher than where the guidance is this year.

[Michael Dugan Kelly:]

Okay. Great. Appreciate that. And I'm curious if you'd give us an update on what the current DUC count is and how you intend to manage this in 2017, especially in light of all this fixed transport that comes on in 2018. Thanks.

[Dan O. Dinges:]

Yeah. The DUC count we anticipate at year-end is approximately 15 wells in the Eagle Ford and 30 to 35 wells in Pennsylvania.

[Michael Dugan Kelly:]

Okay. Great. If I could sneak one more in. Just curious also if you're still curtailing any gas up in the Marcellus. Thanks.

[Dan O. Dinges:]

Not really. We were force curtailed by virtue of the unscheduled downtime. But if our analysis including the volumes for Cabot – it's our analysis that the gas that can move up there is moving not only by us but our peers, and we think that the day of the curtailed volumes is behind us.

[Michael Dugan Kelly:]

Great, guys. Appreciate it.

[Dan O. Dinges:]

Thanks, Mike.

[Operator:]

Our next question comes from Pearce Hammond of Simmons Piper Jaffray. Please go ahead.

[Pearce Hammond:]

Hi, good morning. And thanks for taking my questions.

[Dan O. Dinges:]

Hello, Pearce.

[Pearce Hammond:]

Just now on the last questioner, you had mentioned that CapEx might be 50% to 60% higher to – relative to this year's guidance to meet that 5% to 10% growth rate for next year. Is that sort of the level of CapEx that you'd need to kind of get to that double your production by the end of 2018, or would you need to build upon that?

[Scott C. Schroeder:]

We would have to build upon that, Pearce.

[Dan O. Dinges:]

Yeah. Again, the ramp up into that infrastructure will start with our 2017 capital program. And, again, a SWAG number and it's anywhere from 650 to 675 for 2017 as kind of a SWAG number. And then, as we go into 2018, I do plan on putting out a little bit more forward-looking statements in either October or November of what we see building into that infrastructure buildout. I probably would not get granular with numbers on capital at all in 2018 at that time, but I do plan on and we will have discussion on how much of a look do we want to give – what we look – and our comfort level of our five-year plan. And with that, I think that would give the market a great deal of comfort on what Cabot is going to be able to do to deliver value. And some of this, what you do need to keep in mind, something different than where we are in 2016, we kind of stripped out of 2016 our investment capital, pipeline investment capital, out of 2016. And we have, in that number I'm giving you out there as a SWAG of 650 to 675, we have in that number plus or minus $125 million of that investment capital back in the 2017 capital number. So...

[Scott C. Schroeder:]

For the pipeline.

[Dan O. Dinges:]

Yes. For the pipelines. That's right. So, it's a risk of throwing numbers out here because I'm not being granular on it, but I don't want it to be confused that we're not including the investment capital in that number I threw out.

[Pearce Hammond:]

Okay. That's super helpful. Thank you. And then my follow-up just relates to what's the latest on the Pennsylvania potential severance tax on natural gas production? I thought that here recently when they were looking at the state budget that, that had been kind of dropped off as a potential proposal or is that an option that was being discussed. So, it seems like that might be a positive thing.

[Dan O. Dinges:]

Yes, it is. You're accurate. It is – it was discussed early on, trying to get the budget approved. But it is not a topic of conversation at this time.

[Pearce Hammond:]

Thanks very much, guys.

[Dan O. Dinges:]

Thanks, Pearce.

[Operator:]

Our next question comes from Bob Morris of Citi. Please go ahead.

[Robert Scott Morris:]

Thanks. A little late in the queue here, Dan, but I've got one more question on the budget. You bumped that up by $20 million, but that's for the additional completion crew. And you mentioned that is partially offset by the efficiency gains and cost savings. So can you quantify the efficiency gains or cost savings? In other words, if you had not added that completion crew, then that $325 million budget would've come down to what?

[Dan O. Dinges:]

I don't have that number handy. I'm sorry, Bob. I don't have that number handy. And we have slides that show a percentage of efficiency gains through the process. And Phil had shown some of that to the board. And some of it was the example where we are on the quarter on more rapid penetration rates and running pipe and spud to spud moves. But I don't have it in the form you're asking.

[Robert Scott Morris:]

Sure. That's fine. And then just a clarification. When you said you're going run that additional completion crew for a portion of the second half, does that just relate to adding it here shortly and continuing to run it throughout the rest of this year and into 2017? Or might you drop that later in the year?

[Dan O. Dinges:]

Well, we're looking at that right now. It's part of forming our buildout of our plan in the fourth quarter of 2016 and how we finalize our recommendation to the board in October for our 2017 programs. So, we're looking at the utilization of that crew for the entire second quarter. But I thought it was prudent to represent that at this stage. That is for a portion of the quarter.

[Robert Scott Morris:]

Okay. Great. Thanks.

[Dan O. Dinges:]

Thanks, Bob.

[Operator:]

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

[Jeff L. Campbell:]

Good morning.

[Dan O. Dinges:]

Hi, Jeff.

[Jeff L. Campbell:]

You noted in your most recent presentations that you added 15% more locations with recent spacing tests. I'm just wondering, is this effort more or less complete? Or are you still testing downspacing in the Marcellus?

[Dan O. Dinges:]

Yeah, we will continue to test, not only how tight we can get locations. And Phil has a couple of downspace opportunities or wells that we look at. But we'll also continue to explore with the stage loading and spacing between clusters as part of our efforts to see how we can enhance the program. One of the dry period for (53

[Phillip L. Stalnaker:]

No. Our guys are doing a great job. Kind of like Dan said, we're looking at every aspect of it, so stage spacing, clusters, number of clusters, landing points. The challenge is breaking down each component of the reservoir. So, again, it's an ongoing effort here to continue to optimize our potential out there.

[Dan O. Dinges:]

And one of the things also is not only looking at the upper Marcellus all the way through the Purcell over Marcellus, but the complexity of the geology, looking at the relationship to production profiles within some of the proximity to some of the larger faulting systems. And also looking at a couple of different zones in the section that we think hold what I would couch today as exploratory promise.

[Jeff L. Campbell:]

On that last point, would the Utica be one of those that you might look at at some point?

[Dan O. Dinges:]

Well, the Utica is certainly out there. And my reference was from an exploratory standpoint and the data that we have. And actually the shallower section above the Marcellus is an area that we have significant data points that we think holds the potential I was specifically referring to. But certainly, the Utica is the deeper section.

[Jeff L. Campbell:]

Right. You mentioned earlier in the call, 30 to 35 Marcellus DUCs year-end 2016, if I got that right. You've also been talking about a production bump-up in first quarter 2017. So, I was wondering, do you have an estimate of how many of these DUCs you're going to actually tie and line in the first quarter of 2017?

[Dan O. Dinges:]

I don't have that yet, Jeff. I would say it's probably going to be between 10 and 15 wells. We have a little bit of scramble looking at the piece of paper that might have that on it. But my guess is going to be 10 to 15 wells.

[Jeff L. Campbell:]

Okay. And if I could last finish with kind of the upside, a quick question...

[Dan O. Dinges:]

And Scott just pointed to me, the number is 11.

[Jeff L. Campbell:]

Okay, great. If I could finish with kind of a little devil's advocate question, but it also relates to something that Jeff was talking about earlier about the potentially growing availability of capacity on existing infrastructure. To what extent do you think you could protect your incipient Atlantic Sunrise volumes if that project is delayed? Meaning can you scramble around on some of the existing infrastructure and the freeing up capacity to help you if there is some kind of environmental pushback on that and I guess delayed by six months or nine months or whatever?

[Dan O. Dinges:]

Yeah, I'll let Jeff answer that.

[Jeffrey W. Hutton:]

Yes, so we have – let me back up. We watch this very closely, of course. And we are very comfortable with where we stand with the permitting process and the regulatory process. So, we are content for the project that's moving forward and excited that it's moving forward and have some in-service opportunity late 2017. That said, we do have plan B and plan C and plan D to move on into different directions and different places to – or should I say just in case that the project is delayed a month or three months or something to that extent, so probably wouldn't be able to find a home day one for 850,000 a day into premium markets, but we would be able to adjust to that based on the deadline that we would see if it was delayed.

[Jeff L. Campbell:]

Great. And yeah, I didn't mean to dampen the enthusiasm, but we've all had some disappointing surprises with this stuff over the last year or so. So, it's just – I think it provides some comfort to investors to know that you guys are really looking at that and have some (59

[Dan O. Dinges:]

Yeah. I think it's a good question, Jeff. And it is one that we tried to plan the contingencies around and certainly, we've had an ongoing education and effort doing that by virtue of the delays that have been – we've seen with the New York DEC and Constitution.

[Jeff L. Campbell:]

Okay. Thank you very much. I appreciate the answers.

[Dan O. Dinges:]

Yeah. Thanks, Jeff.

[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:]

All right, Ericson. I don't have any additional remarks but just to reemphasize that we are extremely pleased with the operational side of our program. We are building into the infrastructure buildout, starting the early stages of some excitement about seeing some tangible results in that area. And I think it's going to be fun for our operating group to now diligently start being able to use their talents, secure the services and equipment and start a very diligent process in building these significant volumes. If you look out there in the space, I don't know of any other company that has an opportunity and the rock to be able – and the balance sheet to be able to grow production, double production in the next couple of years and have the benefits to its shareholders as Cabot does. So thank you for your interest, and we are excited about presenting our five-year plan to our board in October. And we do anticipate offering maybe a little bit more color either in October or February – we haven't made that call – of a little bit longer outlook for what Cabot has to offer. So, thanks again and look forward to the next quarterly call.

[Operator:]

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