Coterra Energy Inc (CTRA) 2016 Q2 法說會逐字稿

Good day and welcome to the Cabot Oil & Gas Corporation's second quarter 2016 earnings conference call and webcast.

(Operator Instructions)

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.

Thank you, Erickson, 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 [boiler plate] 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 a 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 settlement 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 jump start 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 well 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 cost 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 delevering 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 [duck] inventory, which will allow for an acceleration of production in the first quarter of 2017.

During the quarter, we drilled 7 wells, completed 8 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 of 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 begin 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 will be able to keep production levels flat through 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 9 days for spud to TD and 13 days for spud to spud. We also drilled our longest Marcellus well to date, with a total measured depth of over 18,000 feet and a lateral length of over 10,000 feet which is scheduled to 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 3 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 minimal amount of capital to our Eagle Ford assets. And instead focus on arresting base declines, meeting our lease-hold obligations, and waiting for a 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 the Eagle Ford far exceed our cost to 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 [appellant] brief was filed on July 12, 2016 with the US 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 a schedule for the appeal process. Together, this brief should answer the 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 and 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 ORON 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 US. 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 FT 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 nay-sayers 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 that 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.

A 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 are 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 will look forward to providing more details about our long-term plans in October. Erickson, with that brief statement, I will be more than happy to answer any questions.

(Operator Instructions)

Our first question comes from Neal Dingmann of SunTrust.

Morning, and nice details, Dan. Dan, a question for you. Given the single well economics that are you discussing out there, obviously were very, very positive, over 100%.

Why not, when you look at your -- look at that and you look at inventory, why not bump production even more given the efficiencies? And is it more about takeaway, or are there other bottlenecks that you're considering?

It is 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 volumes, additional volumes, we could move today, we do think it is prudent to be rational into the market.

We have seen NYMEX increase in the third quarter, beginning of the third quarter. But we have 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 is 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 is going to create liabilities to the existing basin and the limited infrastructure we have.

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

We have Phil Stalnaker here who is our VP of our north region up here, and he has looked at it across the quarter. And, Phil, what do you see for the -- ?

Those numbers on the well to the drill during the quarter, that was actually the average for the quarter. So, yes, we continue to build on those efficiencies. It is not just a one-off, it is what we are projecting right now.

Wow, very good. And then lastly, just, Dan, comment on the difs. It that just seasonal?

And again, they certainly were a bit lower for second. I think the guidance was back up again. Just any thoughts on the gas difs.

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

Okay, Neil. The differentials in the second quarter certainly improved, and a lot of that was certainly related to the drop in NYMEX. We saw Henry Hub in the second quarter average $1.95, and compared to the second first quarter of 2015, for example, was $2.64. And we saw about half the differential this year compared to last year.

And of course, we had the rally during June on NYMEX going forward for the rest of the year, so our difs definitely widened out a little bit. But we're going to see that volatility all year long as we watch these storage injection numbers and watch the market tighten.

Very good. Thanks, guys. Great quarter.

Thanks, Neil.

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

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. Just would like to hear how your thinking about it.

Yes, Drew, it's a good question. And we get that M&A question because we do have such a strong balance sheet and great cash flow. W 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, are in the process of putting together a 5-year model. We will present this 5-year plan to our Board in October.

In discussions with that model, we look at our organic program, what we are able to achieve with 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 is 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 inquisitive 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 in their future to do something different. So we haven't made any decisions, but we do evaluate the market.

Thanks for that, Dan. Just to 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 is competitive with that on an acquisition front, or if that is how you think about it? And as you have gone through the deal process, has there been anything that has come close to meeting those thresholds that you'd need to move forward with an acquisition?

Yes, we have I think demonstrated with our plan how we are 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 are 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 valuations, the return profile in our programs. 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 [turn] profile with every dollar that Cabot invests, it does challenge us to look at the market out there, to look at other assets. And to be able to say that we are 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 is just around the corner.

It is now not measured really in years, it is measured in months of when we are 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.

Thanks, Dan.

Thanks, Drew.

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

Morning, Dan and Scott and Jeff. Thanks for taking my questions.

Hey, David.

Dan, can you give any color, I guess you talked about exiting this year I think at 2 Bcf a day gross. And I guess you would be ramping into that first quarter there.

Is the thought I guess you would be basically at your capacity almost in 1Q in terms of deliverability? And you would more or less hold that number flattish throughout the rest of 2017, unless there is some other release capacity out there?

We think that the -- and I will let Jeff talk about the market and how we might grow into the market a little bit and focused on 2017 pre-infrastructure buildout. But when we look at the exit at 2 Bcf, again, we are 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 is what got to my measured growth comment in 2017 of 5% to 10%. Jeff, you want to make any comments about the dynamics of the market up there right now?

Sure. Dave, if you recall, we have been to 2 Bcf before. 2 Bcf a day 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 talked a little bit about this on the first call, about the availability of excess firm capacity in the marketplace in the secondary market. We look at that every day. We are 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 are watching this capacity release market very closely. And as we get further into the year, we find that there is more producers, or I should call them producer/shippers, that are not using their capacity, and it is quite dynamic.

But it is 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 are really good options to improve netbacks.

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

Potential, yes.

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

Our desire is to underpin some of our volumes with a 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.

Got it. So it sounds like you'd probably will wait until winter time I guess before layering in something more?

Yes, we will 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.

Thanks, Dan. Appreciate all the color.

Thanks, Dave.

Our next question comes from Holly Stewart of Scotia Howard and Weil. Please go ahead.

Good morning, gentlemen.

Hello, Holly.

Just, Dan, you outlined in your prepared remarks a lot of the projects that are coming online over the next couple years to increase your capacity and ultimately your pricing. Jeff, if you could just maybe help us better understand these power agreements. I think it is 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 prices directly link to power prices. So is that just based on a market heat rate?

And then maybe which power price is that associated with? I am assuming PJM.

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

Okay, Holly, this is, of course, a sensitive subject. And we are, first of all, we are 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 area, as you mentioned, it is to our benefit to link some power pricing to our gas prices.

So the benefit of these two particular projects are unique in that as Dan mentioned in the speech, that we literally no FT that we had to buy to get there. So we are all of a sudden out of the gate we are $0.50 to $0.60 better than having to purchase long-term liability FT 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 have 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 four power prices, or at least a percent of day four power price. And that enables essentially the generator and for Cabot to win, and it is a great structure for everyone.

Okay. So is there a minimum volume? If the plant doesn't dispatch, do you still get paid?

Keep in mind, these are brand new high efficiency plants. Their run time in the first 5 years will be at least 95% to 96%. So you will 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 very, very high load rate, at least through the first 5 to 7 years.

Got you. Okay, great. That's helpful. And then maybe just one on -- I know that you mentioned the pipeline maintenance.

So there is a lot of maintenance going on during the third quarter. Have you anticipated any curtailment in your guidance for 3Q?

There is a minimum curtail volume. I don't have the exact amount of curtail volume. As we typically do, Holly, we put a risk profile on our production volumes and the average curtail volume there also, and I don't have that number right in front of me. I'm sorry.

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 are experiencing on TransCo in particular, and quite frankly it is pipe replacement, we are almost through it. In fact, it ends on July 30.

Okay, great. Great color. Thank you.

Thank you.

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

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

Hey, Charles.

I would like to explore a little bit more your opportunities to be or 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 volume 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?

We are not really doing it just for a short term grab, Charles. If you look at our plan that we are 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 build that we have out in front of us and you go back to the infrastructure projects that we have highlighted here, and there is other things that Jeff is working on.

We have to start at some point in time to plan, schedule in an efficient way, in 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 say real quick, it is 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 in front of us. And it is 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 in to 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 have stacked these other infrastructure projects in line now.

But the good news is, they are all going to happen but they are going to happen 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 are 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 is all good and certainly we will be in that space to benefit from it. But we are looking at more of long-term build, and getting up to the 3.5, 4 Bcf production range, towards the end of 2018.

Dan, that's helpful incremental 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 seeing some (inaudible).

My read is that really the big one, both in terms of volume and timeline is really Atlantic Sunrise. But I'm wondering if you would agree with that. And if you could rank or maybe you could put on a -- discuss in terms of both timeline and volume which of the other of these projects, whether it is the Tennessee Gas or the PennEast line, that would be number two behind that Atlantic Sunrise in terms of [reports]?

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 plus or minus capacity without Constitution. And so that is all positive.

And I will 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.

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 is sold to two very good markets, into Cove Point LNG with Sumitomo and of course Washington Gas Light in the DC area. So absolutely that is a standout project for us.

As we move down the list, it is 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. It is 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 operate in the southern part of New Jersey. Great pricing there.

And then the PennEast pipeline, that pipeline is a Bcf a day, and we have 100,000 sold already and 50,000 in capacity. But keep in mind, the impact of a PennEast or the impact of Atlantic Sunrise what that is going to do to the 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. There is no doubt in my mind. So not only do we have all of these projects, the takeaway to the region, a rising tide lifts all ships, and in this case, we expect an upgrade to local pricing connected to all of these projects.

Jeff, that is great detail. Thanks a lot.

Thanks, Charles.

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

Thank you. Good morning.

Hello, Brian.

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

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 is an ongoing project up there in Phil's area, and it's certainly an objective of ours to continue to lengthen the 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 is simply a function of more stages in the lateral lengths, and staying fairly consistent with the average that we see per stage.

Got it. So the increased well performance would be a function essentially of the higher lateral length, if we divide it by lateral length, we'd get to a similar type rate? Yes. Okay. Thanks. And then, I wanted to follow up on Holly's question with regards to the power plant contracts. And maybe I will try to characterize it this way, 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?

Well the one comment I would make first is, when you are modeling, keep in mind one of the biggest components of the power plants is going to be the -- don't put any firm transportation in the mix.

Yes.

We just don't have any of that. So that is going to be a firm input into your model.

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

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

That is just a point in time in the market.

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

Correct.

Thank you.

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

Hey, guys. Good morning. Dan, you gave this soft or hypothetical 5% to 10% production growth scenario for 2017 saying that would be reasonable. Do you have a sense of how much CapEx would be required to get to that range? Thanks.

Let's see. We will put that number out in October.

But it probably, Mike, it would be probably be about 50%, 60% higher than where the guidance is this year.

Okay, great. Appreciate that. And then curious if you would give us an update on what the current duck count is, and how you tend to manage this in 2017, especially in light of all of this fixed transport that comes out in 2018? Thanks.

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

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

Not really. We have been -- we were forced curtail by virtue of the unscheduled downtime. But our analysis, including the volumes for Cabot, it is 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.

Great, guys. Appreciate it.

Thanks, Mike.

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

Good morning. Thanks for taking my questions.

Hello, Pearce.

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

We would have to build upon that, Pearce.

We have, again, the ramp-up into that infrastructure will start with our 2017 capital program. And, again, a swag number and it is anywhere from the [$650 million] to [$675 million] for 2017 as 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 a discussion on how much of a look do we want to give of what we look -- and our comfort level of our 5-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 stripped out of 2016 our investment capital, pipeline investment capital, out of 2016. And we have that number that I'm giving you out there as a swag of $650 million to $675 million, we have in that number plus or minus $125 million of that investment capital back in the 2017 capital number.

For the pipelines, that's right. So it is 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 are not including the investment capital in that number I threw out.

Okay. That's super helpful. Thank you. And then my follow up just relates to what is 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 had been dropped off as a potential proposal or as an option that was being discussed. So it seems like that might be a positive thing.

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

Thanks very much, guys.

Thanks, Pearce.

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

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 is 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 ended that completed that crew then that $325 million budget would have come down to what?

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 or efficiency gains through the process, and Phil had showed 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.

That's fine. And then just a clarification, when you said you were going to 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?

Well we are looking at that right now. It is 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 program. So we are just -- we are 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 it's for a portion of the quarter.

Okay. Great. Thanks.

Thanks, Bob.

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

Good morning.

Hey, Jeff. You noted in your most recent presentations that you added 15% more locations with recent spacing tests. I was just wondering is this effort more or less complete, or are you still testing down spacing in the Marcellus? 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 will also continue to explore with the both stage loading and spaces and spacing between clusters as part of our efforts to see how we can enhance the program.

One of the July period for Cabot at our Board meetings is the opportunity for our geologists to stand before the Board and talk about our exploration projects ideas that we have. And we do have some, and we did present several to our Board on Wednesday.

But one of the things also the technical group has done in the north is taking a step back. And we have a huge database, as you can surmise, and look at the entire space and determine what we might do different with a blank piece of paper, starting over, to try to look at all the different aspects. All the way from the landing areas, steering, penetration rates, how we initiate fracs, how we bring back the wells.

All of that is being scrutinized in a project orientated fashion that I imagine Phil would come back and discuss at a later date. Phil, do you want to make any -- ?

Our guys are doing a great job. And like Dan said, we are looking at every aspect of it.

So stage spacing, clusters, number of clusters, landing points, challenges breaking down each component of the reservoirs. So again, it is an ongoing effort here to continue to optimize our potential out there.

And one of the things also is not only looking at the upper Marcellus and all the way through the Purcell, lower 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 for what I would couch today as exploratory promise.

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

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.

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

I don't have that yet, Jeff. I would say it is 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 there, but my guess is going to be 10 to 15 wells.

Okay. And if I could last finish with a (multiple speakers) question.

Jeff, I just got it pointed to me. The number is 11.

Okay, great. If I could finish with 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 an existing infrastructure. To what extent do you think you could protect your insipient 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 environmental pushback on that and it gets delayed by 6 months or 9 months or whatever?

I will let Jeff answer that.

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 that the project is moving forward, and excited that it is moving forward and has an in-service opportunity late 2017.

That said, we do have plan B and plan C and plan D to move volumes in different directions and to 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 it probably wouldn't be able to find a home in day one for 850,000 a day to the premium markets. But we would be able to adjust to that based on the deadline that we would see if was delayed.

Great. And I didn't mean to dampen the enthusiasm, but we have all had some disappointing surprises with this stuff over the last year or so. So it is just -- I think it provides some comfort to investors to know that you guys are really looking at that, and have some ways to be able to respond.

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

Thank you very much. I appreciate the answers.

Thanks, Jeff.

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

All right, Erickson, 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 is 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 its shareholders as Cabot does.

So thank you for your interest, and we are excited about presenting our 5-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.

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