Coterra Energy Inc (CTRA) 2014 Q4 法說會逐字稿

Good morning and welcome to the Cabot Oil & Gas Corporation fourth-quarter 2014 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, CEO and President. Please go ahead.

Okay, thank you very much, Gary.

Good morning and thank you all for joining Cabot's fourth-quarter and year-end earnings call. I do have members of the executive group with me today. And, also, the forward-looking statements included in the morning's press release do apply to my comments.

As you did see in the morning's press release, 2014 marked another successful year for Cabot Oil & Gas, as we generated top-tier growth in production, reserves, earnings, cash flow, despite continued price challenges in the Marcellus, coupled with a deteriorating oil price environment during the second half of the year. Going over a couple of the bullet points, Cabot generated record production volumes of 532 Bcfe, an increase of 29% over 2013 levels, and an increase of 32% when adjusting for the sale of the Mid-Continent West Texas assets in 2013. This included record liquids production that increased 55% year over year when adjusting for the 2013 asset sales.

Net income, excluding select items for the year, was $405 million or $0.97 per share, an increase of 36% over 2013. And operating cash flows for the year was $1.2 billion, an increase of 21% year over year. This growth in earnings and cash flow was driven primarily by our strong production growth combined with a 16% year-over-year decrease in unit cost.

The Company did take a non-cash after-tax charge in the fourth quarter of approximately $487 million related to the impairment of certain non-core properties, primarily in East Texas, due to the significant decline in commodity prices and a decision not to pursue further activity in these legacy operating areas at this point in time. As a reminder, these assets were the focus of the Company prior to our development of the Marcellus and Eagle Ford, and have not seen any meaningful levels of drilling activity since 2010 so there was no impact to the Company's reserve report.

I would also like to highlight that during the year, we purchased 4.3 million shares of our common stock and added approximately 40,000 net acres in our Eagle Ford position, all while we maintained a strong balance sheet with conservative leverage metrics and over $1.3 billion of available borrowing capacity under our current facility at year end.

On our proved reserves, in addition to the strong operational and financial performance during the year, we also generated significant growth in the year-end proved reserves, which increased 36% to over 7.4 Tcfe. Cabot's all source finding and development costs for the year was $0.71 per Mcfe. This is particularly impressive given that over 43% of our 2014 capital was allocated to our oil properties in the Eagle Ford that by nature are more capital intensive. Excluding the purchase of reserves in place associated with our Eagle Ford acquisitions last year, the total Company finding and development cost was $0.65 per Mcfe.

In the Marcellus, our all sources finding and development cost was $0.43 per Mcf, highlighting the capital efficiency of our wells in the Northeast PA. Obviously one of the components is that our wells in this area do deliver very strong EURs. Cabot's average EUR for the 2014 program on proved developed wells was over 18 Bcf, up from the 16.9 Bcf for our 2013 program.

As a result of our continued performance improvements, we have also increased our reserve bookings on PUD locations in the Marcellus from an EUR of 10 Bcf to 11 Bcf per well. Our proved developed percentage increased from 59% in 2013 to 61% in 2014, highlighting our fairly conservative philosophy regarding our reserve bookings. For example, we booked a modest 0.7 offset PUD locations for each of our proved developed wells in the Marcellus at year end.

Our year-end reserves were 96% natural gas, down from the 97% in 2013, which was driven by a 100% increase in our liquids reserve base. Approximately 89% of our proved reserves are located in the Marcellus Shale. I would also like to highlight that the Pennsylvania Department of Environmental protection released the production data for the second half of 2014 this week, and once again, Cabot dominated the list with the top 16 wells in the state.

Let's move to our 2015 program. While our 2014 operational financial performance are in the rear view mirror, the results do highlight Cabot's ability to deliver strong results in a challenged price environment. However we aren't immune to the market conditions the entire industry is currently facing.

On our third-quarter earnings call in October of last year, I laid out the Company's initial 2015 program, which was predicated on realized natural gas price and oil prices of $2.80 and $88, respectively. As you are all aware, the operating environment the industry is facing has changed drastically since our call less than four months ago. While much of the focus over the last few months has been on the declining oil price, we have also experienced a fairly meaningful decline in the natural gas prices, including the regional index prices in Appalachia.

No different than what we are seeing in the major US oil basins, Cabot and its peers have done an excellent job of finding an abundant supply of resources in the Marcellus, and as a result the supply/demand balance is currently out of sync. Until we see the rebalancing of the market with the reduced activity, which I think is currently underway, I believe the industry will continue to see pricing pressures on both oil and gas.

As you will recall, in the fourth quarter of last year, we saw a significant increase in natural gas supply on the three major pipes in our area, which included a 15% sequential increase in Cabot's volume in anticipation of winter. However, winter demand did not materialize as we all would have expected, and as a result, we have seen the local indices in January and February set at levels significantly lower than our initial forecast. In response to this lower commodity price environment we have adjusted our 2015 program with a focus protecting the balance sheet and maximizing our return on investment, while still managing our growth profile.

Despite the change in our absolute levels of activity in 2015, our strategy remains unchanged: a focus on aligning our capital spending to be primarily funded by operating cash flows, focus our drilling efforts on maintaining our acreage position and optimizing operating efficiencies, and a retention of our high-quality employee base. This strategy has positioned us favorably leading into this commodity cycle, and we believe this strategy will allow us to exit this cycle extremely well positioned.

The Company updated capital budget for 2015 is $900 million, which is a 42% decrease compared to our initial budget. Approximately 80% of the program will be directed towards drilling and completion activity, with 60% allocated to the Marcellus and 40% allocated to the Eagle Ford.

In the Marcellus we are currently operating five rigs with plans to decrease to three rigs by the end of the second quarter. Based on this level of activity, we expect to drill approximately 70 net wells and place 65 to 70 wells on production during the year. Given the backlog of wells we carried into 2015 and our anticipated level of activity during the year, we expect to exit the year with approximately 45 wells in the queue for 2016.

Despite drilling longer laterals in 2015 we expect well costs to average between $6 million and $6.5 million as a result of operating efficiencies and the service cost reductions that we have received to date. However, as we are all aware, this is a dynamic market and our expectation is that as commodity prices remain depressed for a sustained period of time, and the level of activity industry wide continues to decline, we will likely see a further reduction in cost.

In the Eagle Ford we are currently operating three rigs with plans to decrease to one rig by the end of the second quarter. Given where oil prices are currently, our focus is solely on lease maintenance and meeting all drilling obligations. Based on our planned rig count for the year, we expect to drill approximately 45 net wells and place 40 to 45 wells on production during the year. Again, given our backlog of wells that we carried into 2015, our anticipated level of activity during the year, we expect to exit 2015 with approximately 20 wells teed up ready for 2016.

Similar to the Marcellus, we expect well costs for the year to average between $6 million and $6.5 million, with an opportunity for further cost reductions as we move through the year. We remain excited about what we have seen so far in our 90,000-acre net position, which is all contiguous. However, in light of the current price environment we believe the prudent decision is to maintain all of the acreage and wait until a sustained recovery in prices before we start accelerating activities in the future.

Based on this updated operating program, we have adjusted our production guidance range for the year to 10% to 18%, which includes 50% to 60% growth in liquids production. This guidance range assumes a modest level of curtailments in the Marcellus in anticipation of maintenance and high line pressures at certain points during the year. Additionally, we have also included a wedge of price-related curtailments in this guidance to account for those periods where price simply does not meet our threshold.

Obviously, the natural question would be how much and at what price we would take these actions. For competitive reasons we will not disclose specifics, but I will say that our production profile for the year assumes higher volumes in the first quarter, with a reduction in the second and third quarters, and increasing again in the fourth quarter.

The realized commodity prices used in this updated budget to make our $900 million program were $0.45 per Mcf, $2.45 for natural gas, and $55 per barrel for oil. This includes the impact of our natural gas hedges which covers about 28% of our natural gas volumes at the mid point of our updated guidance range.

Also, for the full year approximately 50% of our gas sales are priced at three major indices in Northeast PA, which is Tennessee, Leidy and Millennium. Under these assumptions our operating program would result in a very small level of outspend, allowing us to maintain the same financial strength we demonstrated prior to this down cycle, while still providing double-digit growth and generating returns.

Some of you may have questions about 2016, given our reduced level of activity this first year. First let me say that our internal model shows continued growth in 2016, with the level of growth dependent upon factors that will certainly be understood better as 2015 progresses. However, one key factor is how the commodity price environment evolves throughout 2015.

We do anticipate similar operational and supply reductions by other operators in Northeast PA in reaction to the current prices. And our expectation is that this will ultimately result in a rationalization of the supply and demand dynamics in our area. Given an expectation for a tapering of supply growth, coupled with new takeaway capacities in the Northeast, that's the Leidy Southeast expansion and the TETCO East side expansion that's coming online in the second half of the year, we will remain flexible with our program if the market warrants us to make changes.

Given the productivity and the low capital intensity of our wells in the Marcellus, we are well-positioned to adjust our operations in short order. As a reminder, we grew to our current production levels by never operating more than six rigs in the Marcellus. And given the anticipated backlog of 65 wells Company-wide at year-end 2015, we do have plenty of optionality to accelerate completions in the second half of the year, as we see fit. As I mentioned earlier, our plan is to maintain our high-quality employee base and we believe that positions us very well in the event of a quick recovery.

Another key factor that will drive 2016 growth and enhance program returns will be the anticipated in-service of Constitution pipeline, which is currently planned for the second half of 2016. Cabot has 500 million a day of capacity on this pipeline, so the timing of when this pipeline comes online will obviously have an impact on 2016 production levels.

As a quick update on Constitution, there were a few significant accomplishments at the end of last year that bear repeating. As you are aware, on December 2, 2014, the FERC issued a certificate of public convenience and necessity, approving the Constitution pipeline. In addition, on December 24, the New York DEC issued a formal notice of complete application regarding the final permits necessary from New York.

We are currently awaiting the conclusion of the New York State public comment period which is scheduled to end on February 27, 2015. Moving forward we are hopeful to receive our final permits from New York during the second quarter and immediately file for the implementation and construction plan with the FERC, with construction beginning this summer.

So, in summary, we covered many topics. We are well-positioned to adapt and succeed in this price environment. I think it's clear our asset base and our disciplined focus lends itself to allowing us to generate returns at these price levels that maybe many other operators will not or may not experience. Despite the current market conditions, we remain committed to delivering our long-term shareholder value and certainly maintaining our strong balance sheet.

Gary, with those comments, I'll turn it back over to you to tee up some questions.

(Operator Instructions)

Our first question comes from Doug Leggate with Bank of America Merrill Lynch.

Good morning, Dan, good morning, everybody. Dan, a couple of things, if I may. First of all on Constitution, just to be clear, what is the precise holdup now then on moving forward with construction outside of -- I get the right of way issues in New York are still a bottleneck but in terms of all the other preparation can you actually start now or are you still waiting? Can you not [fire] the starts in there until everything is lined up? I'm just trying to understand what the bottleneck might be.

Good question and a question that's obviously on a lot of people's minds. I'll make a brief comment and turn it over to Jeff for any specific color. But we have submitted all the permits. We submitted our original permits back in August of 2013.

There has been significant dialogue between Williams, the operator of the pipeline, not only to FERC but also the New York DEC. The protocol in moving through this process is that the DEC has made the determination, as I mentioned, on the 24th of December that we have fulfilled our obligation to give them all of the information they need to deem the project complete.

With that, though, there comes a public comment period, and that public comment period we are in at this period of time and it ends at the end of this month. Subsequent to that, the expectation is, with no new issues that have not come up over the last couple of years, that the New York DEC will grant a final permit and then that would allow us to make the application to FERC to begin construction.

Yes, Doug, just to add a few points to that. The application process in New York, and Pennsylvania for that matter -- and of course we're finished in Pennsylvania -- has been pretty much what we expected. It's taken a little bit longer than we expected but the process is what it is. And by getting the notice of complete application, it does signal that the New York DEC has all the information they need to issue the final permit. The process we're in now is standard operating procedure where public comments are welcome based on the action that New York DEC took.

In terms of getting construction started, Williams will file an implementation plan with FERC probably next month, and that implementation plan will include permits from all the agencies involved including the ones that FERC issued, and it will be complemented with the final permit from New York once that's issued. When FERC gets that final determination, they will issue a notice to proceed with construction. At that point construction can begin. So, it's a lot of moving pieces but you really cannot dig dirt until all the pieces are in place.

That's really helpful fellas, thank you. Just two quick follow-ups on some numbers, if I may. First, can you quantify the curtailments that you've assumed in your guidance for the current year? And, finally, any scale of anticipated cost reduction from this point forward over and above what you've already achieved in terms of service costs? And I'll leave it there, thank you.

On the curtailments, we will not be exactly specific but I can say that if, in fact, all the available production would move, we would certainly approach the lower end of our previous guidance. And in regard to cost, again, we have seen the costs roll off no different than the other operators that have made a release. And we anticipate, though, also, as you continue to see service programs lay down rigs, there's going to be a natural tendency to continue to keep equipment and people teed up and busy through the service sector and we could see additional service cost reductions throughout the year.

Some folks are talking about 20%, 25% Q4 over Q4. Is that scale reasonable to you or would you (inaudible) them up?

No I think that's reasonable.

All right thanks very much.

The next question comes from David Deckelbaum with KeyBanc.

Good morning, Dan and Scott and everyone. Thanks for taking the questions. I just wanted to follow-up on the EURs that were booked this year. Obviously, very encouraging data on the PDPs at 18 Bcf versus 16.9 last year. Would you all attribute all of that to just longer lateral's?

We are fortunate to have our VP of our Marcellus region in here, Phil Stalnacker. We had our Board of meetings yesterday. Phil's group does a number of things up there that we try to tweak and gain additional efficiencies. Phil, why don't you just talk about a couple of the efficiency things that we've done what we're looking at.

On the completion side, of course, one thing we're continuing to look at is the optimum spacing between frac intervals and testing from the 200 feet down to the lateral 50-foot spacing. Again always we're looking at optimizing our landing point, too. So, again, we're continuing to tweak the formula and look for ways to improve.

That's helpful. And do you have that data at all for the Eagle Ford? I didn't know if I missed that on just what Eagle Ford was booked at this year?

Yes, we have also Steve Lindeman who is coordinating our South region effort. Steve, why don't you offer some comments.

Yes, for the Eagle Ford we're still in line in the range that we've talked about before, about 500,000 barrels for a roughly 7,000-foot lateral well.

Okay, great. So, then all of the incremental improvements that are being made now weren't factored in until last year's reserve report yet, at least in the Eagle Ford?

That's correct.

And the only other one I had was just on the well cost reduction that you're seeing so far, what percentage of that is just your own optimization versus third-party service declines?

We have specific numbers on the third-party service declines. You've seen it through, again, the releases that have occurred to date out there. But rig costs coming down and pumping services coming down are the major components.

The operational efficiencies is an ongoing effort in our program. And we continue to try to do those things that would allow us to create more efficiencies either by enhancements to the amount of production or EURs that we can recognize or tweaking the components of a completion, for the most part, or landing points that would allow us to gain time and/or frac efficiencies with either spacing considerations or the amount of proppant pumped, those common things that we all look at.

I don't have a specific break down, though, between the components of service cost reductions and operational efficiencies. The majority that has occurred most recently has been from the service side.

Okay, thanks, Dan. And last one, if I might, with the updated guidance now looking to spend fairly close to cash flow and preserve that balance sheet, are you starting to see opportunities in and around your core areas to expand your positions from some other folks that are maybe a little bit more stretched?

In these environments where commodity price fall off so rapidly, particularly there's a lull between the time when that fall off occurs and the M&A activity -- and I think we're in that period right now -- the expectation by those that have assets and that might have some stress points, they are going to hold as long as they possibly can in hopes of a quick bounce off the bottom. But I can say, from a strategic standpoint, we do look at this period of time as an opportunity. And if we see the bolt on, as you're referring to, fit what our long-term plan is, because we're balancing this market for the long term and not just the short term, we'll take advantage of it.

And our balance sheet certainly allows that. At the end of the year, as we mentioned, we had $1.3 billion of available capacity to utilize. So, we're in good shape to take advantage of what opportunities come along.

Great, thanks for the answers, Dan.

The next question comes from Brian Singer with Goldman Sachs.

Thank you, good morning. Dan, you've generally in the past spoken to building a backlog of wells in anticipation of Constitution coming online. How much of your CapEx reduction here is a function of greater flexibility, given the lack of clarity on the Constitution startup time? Or has there been any strategic change in which you would plan to fully supply Constitution with wells yet to come on line versus wells contributing to the oversupply today of the local market?

We have reacted with our capital program today, based on commodity price. We've looked at the differentials and we all realized the loss of $45, $50 on a per barrel. And we have reacted with a reduction in our activity, i.e., capital that translates into the number of wells drilled and completed, just purely based on that commodity price assumptions and maintaining our cash flow neutral program.

In looking at Constitution, and looking at, as I've mentioned, the queue that we had built up of 40, 45 wells that we'll have at the end of 2015, we are going to be in good shape to be able to build our volumes into the expected commissioning date of 2015. We continue to see efficiencies, as we reported, from our 2013 program to our 2014 program. We expect continued efficiency gains in our 2015 program, which I think is going to translate into maybe higher IPs and higher EURs, which would allow for a more rapid increase in the amount of deliverability leading up to Constitution.

I think, again, a point to illustrate is the fact that in one of the premier gas fields in the entire world, and an area that's growing probably faster than any other place than I'm aware of in the world, is a six-county area in Pennsylvania. And in all of the Marcellus, Cabot had the top 16 wells in the entire field. So I think that speaks volumes on our ability to be able to grow into an additional 500 million a day that is our volumes on Constitution in a fairly quick order. And, I might add, without a whole lot of capital intensity.

Great, thanks. And then, separately, you built up your Eagle Ford commensurate with your growth in the Marcellus over the last few years. Does the down cycle in both oil and natural gas prices provide an opportunity to materially shift your exposure around these areas or are you committed to the balance currently in the portfolio?

Are you talking about the 60/40 balance we have in the Eagle Ford and the Marcellus?

Exactly. Or if you think about the production percentages or the resource percentages, do you see an opportunity for larger-scale M&A here to move around your core areas and the weighting of your core areas, get new core areas? Or should we expect when we come out of it that you'll have a similar weighting to the Eagle Ford, Marcellus and nothing else?

That's a good question also because, again, a lot of opportunity occurs to those that have a strong balance sheet and optionality in a down market, and we're certainly one of those companies. We don't have anything on the books, Brian. But, again, to think about our long-term runway and to position us to take advantage of a uptick in the oil market, for example, I think it is prudent for us to look at what type of area we might want to be in the long term, and how we might want to position, and how we create that position.

But again, as it being a singular focus or a strong need at this particular period of time, it is not that. But certainly it's a idea that we kick around and we look at, we build database on, to be able to understand the markets out there in the longer term. If we move around the balance of commodities -- i.e., more oil versus our 96% gas versus 4% oil -- it will be a long-term view, and we'll take advantage of it. And I think we could do something in the future.

Thanks.

The next question comes from Jeffrey Campbell with Tuohy Brothers Investment Research.

Good morning. To start out I just want to be clear -- once you finally break dirt, what's the time range for finishing the Constitution, based on experience?

Construction is going to be a rather short-term project. But go ahead, Jeff. And Jeff can fill you in on the number of crews that we have, the pipelines on the ground there, and the things that have been lined up from a construction standpoint.

Okay, Jeffrey. Actually, of course, the pipe is on location and the construction bids have gone out and we have contractors waiting on the notice to proceed. Everything is set up and staged and ready to go waiting on the final permits.

That said, there are a few operating windows that have to be considered such as stream crossings and tree clearing, and that sort of thing. But basically, regardless of when you start, and if you adhere to all of the windows of construction, you're talking about less than a year to get everything in place, tested and operating.

Okay, great. Thanks. That's very useful. Dan, based on prior guidance it looks like you reduced your 2015 wells to drill by a greater percentage in the Marcellus than in the Eagle Ford. Can you add a little color on that? And the reason why I'm asking is because you recently said that Marcellus returns at $2 per million BTUs are better than Eagle Ford returns at $70 a barrel. So I thought some color might be useful.

We, one, have some new acreage that we acquired in the Eagle Ford, and that new acreage we acquired in the Eagle Ford had near term-lease expirations that required drilling activity. So, our balance of capital with bringing it down to our cash flow level just dictated, based on the acreage capture in the Eagle Ford, how much activity we were going to have in that particular area.

And in regard to where that places our activity in the Marcellus, we have ample supply to sell into the market that would give us a growth profile greater than what we have represented in our guidance. However, every incremental amount of gas that we would produce in the Marcellus goes in to the indices that are the most challenged right now.

So, to grow into that with additional drilling even though we are, yes, recognizing very good returns, it still boils down to the balancing act between our cash flow and the amount of activity that's necessary for a maintenance program. So, that's the balance that we see short term being our 2015 program.

Okay, that makes great sense. And if I could sneak one last quick one in. You stated previously that you intended to target investment grade leverage metrics in 2015 and I'm wondering if your revised CapEx is guided by this goal. And does it remain a primary balance sheet metric during any future commodity volatility in 2015?

Yes, I'll pass that to Scott.

Hi Jeffrey. Yes, that's still a goal. Again, Dan hit on the key points of why we did what we did related to the capital. But we've had a strategy around our capital modeling, both in good times and in bad, that we want to be right on top of or very near the anticipated cash flow. And as a result of that we have built a Company that is very close to investment grade.

Clearly, from a debt to EBITDA perspective, that is going to test those limits in terms of investment grade metrics simply because of the underlying cash flow. But the overall leverage won't change, as we alluded to in our opening comments.

Okay, great, thanks. Appreciate it.

The next question comes from Bob Brackett with Bernstein.

I had a quick one and then a follow-up. The quick one is, what's the best daily rate that your Marcellus operations have achieved?

Recently we had a 42 million, almost 43 million a day type of well.

I mean for the whole operation.

We have been over 2 Bcf a day -- in between 2 and 2.1 Bcf a day.

Okay, great. The other one is a bit more strategic. We're spending a lot of time thinking and worrying about Constitution. That's 2016. What's the 2017 and beyond strategy for getting your volumes to market? And what are you doing now to make sure there aren't delays like we've seen with Constitution?

We have a significant runway out in front of us that is already inked and moving forward. Not only is the Constitution teed up for the middle of 2016 at 0.5 Bcf a day, I'll let Jeff go into the order of additional projects we have. And he might also just touch on what we have at the end of this year, too.

Sure. I'll try to keep it fairly larger numbers. We have a number of projects at 20,000 a day here and 25,000 a day there that do add up. But probably in the near term we have the Columbia East expansion that's coming on later in 2015, and Cabot has a 50,000 a day position there.

The Leidy Southeast project comes on in December of 2015 and we have some additional long-term market associated with that. I might mention one other, the Penn East project coming along in October of 2017, we have a 100,000-a-day position on that. That will connect and take gas off the Leidy system.

But the big project is the 850 million a day coming on in September of 2017. That's a Williams project that's known as Atlantic Sunrise. And that's a new 30-inch pipe connected in the heart of our production area.

As we mentioned late last year, the capacity of that 850,000 a day, 100% of those volumes are committed and for sale. We announced the Cove Point Sumitomo long-term sale of 350,000 a day for 20 years. And we announced a 0.5 Bcf a day sale to Washington Gas Light for 500,000 a day. So that's certainly going to take us into 2017 with a good program and a good plan, and currently working on the next projects.

Thank you.

The next question comes from Drew Venker with Morgan Stanley.

Good morning, everyone. Dan, before you spoke about the volumes in the Marcellus ticking down in Q2 and Q3. Just curious if you can provide color if that's managing to expectations of demand or if there's something else going on there.

It's two things. We, in looking at just the system as a whole, depending on what type of inflection we get with the supply side, and the propensity of gas being curtailed, if, in fact, the indices fall off or stay too low, I think selling into a low-value market is going to be rationalized a little bit.

But what occurs during the, i.e., shoulder months, would be some pressure on the pipelines, and during that period of time it can back gas off of the market, even though there's been a number of projects to compress and to mitigate the line pressures in the past. So, that is one component to the lower volumes that I've alluded to in the second and third quarter.

The other is just putting a soft spot in our guidance for low gas prices. If we see low gas prices, we're just not going to give our gas away and we would take gas off the market. So, that's the reason, nothing operational except for the midstream part of the operation to give us that lull.

That's helpful, Dan, thanks. And just to follow up on that, essentially weak pricing in the middle of the year, it's my understanding that up in Leidy there's somewhat limited power gen demand, especially in the summer. But we've heard some expectation that will expand over the next couple of years. Can you guys provide me color there or any thoughts just the potential quantity of the impact?

Jeff?

Yes, Drew, there are certainly, as you're aware there's an announcement by Panda just this week on new power generation in Central PA. There is also several facilities planned in and off the Leidy system and we are actively in negotiations for those facilities. They are good loads, they are a base load, power gen, something producers loved. So it's a little premature to say how far we've come but we're certainly in negotiations.

And, Jeff, do you have a sense of what the volume impact would be in 2015 in terms of demand?

Yes. Overall, these plants are in that 300 million-a-day-plus range. It's up to the power generator if he wants to split the load between different parties and so forth, or if he wants to deal with one party, just have the same scenario that happened at Cove Point where you have half the LNG buyer wanting to go one supplier and the other went with three or four. So it's yet to be seen. But we're in a great position to serve a couple of these plants and we're in a great position to serve all their needs.

Thanks for the color, Jeff, appreciate it.

The next question comes from Subash Chandra with Guggenheim.

Yes, hi, good morning. Is there an update on percent of sales in 2015 into Leidy? I think the last one I saw was mid- to late-2014 around 20%.

I know that, as I've mentioned in my comments, on the three indices, we have between approximately 50% that is moving into those three indices -- Leidy, Tennessee and Millennium. I don't have the break out in front of me on what's going into Leidy.

Got it, okay. And then on the reserve increase, you talked about the wells being better, 18 Bcfs from 16.9. Is there an average Bcf per 1,000 lateral feet that you can boil it down to?

In the past we've indicated approximately 3.6 to 4 Bcf per 1,000 foot of lateral, and that's a range that we feel comfortable with.

Okay. So, we're still in that range going from 17 to 18, I suppose?

Yes.

Okay. And then for the PDP wells you talked about the offset locations. The number of PDP wells is 360 or so in the Marcellus, is the right number to be using?

I think it's actually 380, 385, something like that.

Okay. That's the gross?

Yes.

And net will be high, as well. Okay, got it. And then service costs, what we've heard from other operators in Appalachia is that, unlike some of the oil-producing basins, there wasn't really excess margins that service companies were generating last year. So, the view was that, given 2015 dynamics, they don't have that much room to give to where the types of cost deflation we're seeing from the oil basins of 20%, 25% expected Q4 to Q4, may not be realized. I think you did say that 25% is possible. But what would you say about that context provided by other Appalachian operators?

I would just make a statement about our own experience. Each service provider can be a little bit unique on what their ultimate goal is. Some would prefer to capture margin and some would prefer to keep their equipment and their personnel busy and they would sacrifice margin.

Our operation is a very consolidated acreage position. We have a very efficient operation from the standpoint of the service providers. And I'll talk about frac crews just as being the highest percentage of any one completed well besides the rig.

But we move from one location to the other and everything is set up ready to go, so they keep their equipment and personnel running 24/7 in a -- very efficient. And I think that is attractive to them. But you look at the reduction we've referenced already, and we go from, say, a $7 million well to a $6 million to a $6.5 million well, we're already seeing those incremental reductions in service costs. And, again, whatever the rest of the market does, and what service cost realizations they see, is going to be all unique and individual, but we are seeing fairly significant service cost reductions.

All right, okay. And a final one for me -- thanks so much -- the final one is, transportation costs, $0.70 or so from $0.65 or so in 2014, if you look forward to 2016 what do you think that could look like?

It's probably going to be close to the same. A lot of that is dependent on if the transport costs end up with our customers or not.

Could you repeat that, I'm sorry?

Okay. The additional transport costs that will be realized by Constitution and Atlantic Sunrise, if those rates are showing up in the revenue by higher gas prices they'll offset the transport costs.

Right, but I guess you would have a separate line item for transport, and the revenue line will show up separately?

Yes it will.

So, if you were to just strip out the transport cost if Constitution came on as expected in 2016, could you hazard a guess what that line -- ?

What we anticipate in 2016 is having a similar range of transportation costs as our current guidance.

All right, great. Thank you much.

The next question comes from Joe Allman with JPMorgan.

Thanks, operator, hi everybody. In terms of dropping the rig activity, are you terminating rig contracts early to reduce the rig count? And could you just talk about the process involved in dropping the rigs, any costs you're incurring? And did you explore other options including drilling wells and deferring the completions?

Steve, why don't you grab that.

Joe in the South region, the first rig that we released had a very short-term contract on it so we were within that term. We are still negotiating the terms of that release with our other contractor, whether we add time on and so forth, and that's what we are working on right now.

Okay. Could you talk about other options you've explored or are exploring in terms of including drilling of the wells, deferring completions, as EOG announced yesterday?

Yes. As Dan stated in his comments we'll exit the year with about 20 Eagle Ford wells in inventory, and so that's completion activity that we had scheduled for the latter part of the year that we're going to defer into 2016.

Okay, that's helpful. And could we just review again the trajectory of production for the year? Are you expecting production to be up in the first quarter? It sounds like it's going to be down in the second, down in the third. And then is it going to be a fairly meaningful ramp in the fourth? And do you expect fourth quarter to be flattish with Q4 2014? Could you just help us with that and break it up North versus South, if you could?

I think you summed it up on what our expectation is through the year, we've given that 50% to 60% expected growth in the liquids for the year. Liquids production or the production profile in the South region is going to be more consistent than the production profile that we've guided and put into our program in the North region. We just have more flexibility on swing volumes in the North region and the Marcellus area than we do in the South region.

So, at high level summary, Joe, we would maintain and grow a little bit of our production year over year in the South region, and in the North region higher first quarter, just like you've rolled through the year the second and third quarter down and then increasing again in the fourth.

Okay, that's helpful. And then lastly, just a quick one. For Constitution, just to be clear, are there not any other permits that you need, including Army Corps of Engineers, just to be clear on that?

I'll pass that to Jeff.

Yes, Army Corps of Engineer permit is included within the New York permits, as well.

Okay. All right, very helpful. Thank you, guys.

The next question comes from Holly Stewart with Howard Weil.

Good morning, gentlemen. Thanks for squeezing me in. Just maybe a couple quick follow-ups. Jeff, I appreciate all the detail on the different pipes. Could you just maybe sum up 2015 through 2017 for both SP and FS for us?

I'm sorry, I didn't quite catch the question.

Just the overall firm sales and firms transportation totals. I love the detail on the different pipes but can you just give us your overall position?

Our firm sales -- we have a lot that we currently have and then we have some that drop off and then we have some that we have later this year and 2016 and 2017. I don't have it all added up here for you, I'm sorry.

Okay, we'll follow back up. And then maybe, Dan or Scott, just back to the capital allocation, should we expect anything on the share repo in 2015?

We don't have that as a budget item. You're going to have to see a different price point in both oil and gas for us to make that consideration. Both commodities are fairly low, and a number of companies, I think, are struggling even to make a program that they can maintain some level of growth and also fund. It's not in the cards right now, and the only way it's going to get into consideration would be having a difference in the price points from today.

Got you. And then one final one just on the upper Marcellus, anything in the 70 net wells? And then were there any changes to the EUR bookings there?

No, our focus right now is to complete in the deeper section first, and then we'll have a longer-term plan that we'd move up the hole as we continue drilling out the field.

Okay, appreciate the details.

The next question comes from Marshall Carver with Heikkinen Energy Advisors.

Yes, good morning. A question on the seasonality of production. Is there any reason that pattern wouldn't persist in future years like 2016 and 2017? Maybe it wouldn't be quite as dramatic but is there any reason to think that wouldn't happen again with the line pressures, et cetera?

Yes, possibly a couple of reasons. One would be that we're restricted right now. And the reason why we have punitive differentials is because of the volumes of gas moving into the three pipes up there. In the future, we would expect, and the pipes that Jeff has been talking about that are on the drawing board and moving forward and have expected commissioning dates, with those pipes and allowing additional gas or gas to get out of that particular area and off of those three pipes in particular is going to allow certainly different dynamics going forward than we're experiencing today.

I can't predict exactly what the impact is going to be on the supply side or the demand side, let's say, at the end of 2017, but I can say that you are going to have a significant level of additional volumes of our gas that would be seeking and priced in different markets than we're experiencing today. So, operationally, Marshall, you could still have operational floors and pressures on pipes based on the amount of volume running through them, but I think the opportunity to and the flexibility that additional pipes is going to afford us in the future is going to be fairly significant.

So, with Constitution coming on in the second half of next year, maybe there could be some seasonality between Q1 and Q2 but you wouldn't expect it once Constitution comes online?

Yes. And I would say you would probably see, since there's not the volumes of gas that have access to the air core system, I would say that you would probably, on those particular volumes, I would think that you probably would not see as much of the seasonality effects on that pipe as we experience today on the three pipes, Tennessee, the Leidy and the Millennium, with the volumes of gas that is trying to force their way into those pipes today.

Okay, thank you. And one more question. Do you have the expected lateral lengths for the Marcellus wells that will be going online this year versus last year, and also the expected number of stages?

I don't have the granular nature of the stages but we will be over 5,000 foot on our lateral lengths.

Okay, thank you.

The next question comes from Matt Portillo with Tudor, Pickering, Holt.

Good morning, all. Just two quick questions for me. On Constitution, I wanted to clarify, to hopefully get a little bit more color on how you're thinking about those volumes in 2016 and beyond. Is the plan to potentially shift some of your existing production away from Leidy and Tennessee into that pipe and therefore improve margin, or are you planning on completing new wells to grow production into 2016?

Yes, both are good questions. The indices, the price received in the three-pipe area that all of the operators are exposed to right now up in that six-county area, is going to be somewhat of a determining factor on whether or not we relieve the amount of gas that is on those three pipes by just a flat sale transfer of 0.5 Bcf -- actually it would be 650 million a day because Southwest is part of that Constitution pipeline, being at 650 million a day capacity. Or would it be a incremental volumes that we'd flow into the pipe.

And that decision, Matt, is going to be a combination of price point and the ability to diverse the amount of gas that is flowing into those three pipes with some of the new pipes that are coming online, i.e., Leidy, Southeast, the impact on those three pipes, the TETCO expansion and some of the other smaller projects that Jeff mentioned. So, I can say this, though, from a planning standpoint, we're going to be prepared to have incremental volumes going into the Constitution pipeline. But we're also going to remain focused on the best returns and price rationalization if the market has not done that for us.

Great. And then my second follow-up, as you've talked about previously, your Eagle Ford assets continue to improve in terms of the breakeven economics, given the enhanced completions you've put into place. Could you provide some color as to how you're thinking about potentially reaccelerating that program in the out years and potentially what commodity price you'd need to see at this point given service costs to add rigs back to that market?

Again our balanced focus, Matt, has been on let's look at the amount of cash flow we're generating, and the amount of cash flow we generate is going to dictate what we do with our capital program. So, it would go hand in hand. We have a higher price point, better cash flow will roll into a consideration for adding rigs, whether it be in the Marcellus or the Eagle Ford.

It is our objective, though, in the Eagle Ford to maintain all of the acreage we have out there. We like what we're seeing, we like what the group is doing now, and we like the returns that we can get. But at $50 we're not impressed with the returns at $50. At $60, $65 certainly it has a return profile that starts getting attractive again.

Thank you very much.

The next question comes from Robert Christensen with Imperial Capital.

Yes, thank you. First question is how do you balance between debt paydown and share buyback? What are the things we should think of in that decision?

That's a good financial question and I have a financial expert sitting right across the table from me.

Bob, it's Scott Schroeder. As Dan alluded to, based on Holly's question in terms of the repurchase, clearly for 2015, the question you pose isn't on the table in light of how far we had to ratchet back our capital program. And we're still not quite exact equal with cash flow. But at the end of the day, when we're balancing that decision in different times we're looking at the disconnect between the underlying value we see in the shares and what the market at any one moment is giving for our shares in the marketplace. We've seen those disconnects over the last couple years and that's why between probably between 2013 and 2014 we've bought in just under 10 million shares on that kind of dynamic.

Thank you. In terms of the termination of a couple of the rigs, we, then, haven't seen the expense related to whatever negotiations that you're having with the rig provider. Is that in front of us, some termination type expense?

Yes, but we balled it up in our capital program number. It's in the $900 million number.

Got it. And my final question is, could you just put a little more color out there on this concept of gas by wire, if you will, off of Leidy and Panda and other projects? What's the time frame of some of these potential projects and volumes, and the economics versus selling gas directly on a pipeline to somebody? This sounds interesting. Thank you.

Bob, some of the projects that are being proposed, there's actually probably in excess of 20 I have on my desk that we're interested in, some more than others, some that we have very good access to, some that may be more difficult to get to. And I'm talking about transportation paths.

But there's a lot of projects planned in the middle Atlantic states and in Pennsylvania. There's been a push to, in conjunction with the ISO in that area, to build some power generation and then feed it with local supplies. So we're looking at projects that are close by Susquehanna county or have direct routes, pipeline routes, that we can reach these projects.

I think some of the planners of these, and we did mention the Panda project, they probably have four or five other projects that are well on the way in terms of finding locations and permitting and financing and so forth. But most of these guys, they get their power deal done first. In other words, access to the grid, and then they become the gas suppliers. And they have their wish list and we have our wish list and we try to work through those and come to terms.

There is four or five power generators off the air core system that we're working with, as well. And there's some off the Tennessee system and there's some off the Leidy system.

This is going to be a process that goes on probably the next five, ten years even, just a lot of opportunity for power generation with natural gas and with coal retirements, and with coal switching and oil switching. It's a piece of the demand puzzle, and it's very active and very dynamic. Where we're situated in the Northeast corner, we're probably the closest supply to market there is, and so we're comfortable with these kinds of markets. And we'll probably be announcing, if we [affirm] successful in the next year or two, on some of these projects.

Thank you.

The next question comes from Eric Otto with CLSA Americas.

Good morning. Thank you. Just a quick follow-up on the DEC. Can you give us a little bit of color behind your thinking about the permit approval in Q2, just thinking about the fact that the DEC has never had to review a linear pipeline project of this magnitude, the time it took them to issue notice of completed application, and attendance at the three public hearings?

I think at some point -- Williams, I think they had their call yesterday, I think they had some questions on this, as well. But the way we understand the process and getting feedback from Williams on the progress, I'm not sure I agree with what you said about the magnitude of the project versus what DEC has seen in the past. There's lots of major pipelines through the state of New York, lots of gas pipelines, lots of power corridors, lots of water lines, and so on and so forth.

This is a relatively simple 124 mile pipeline through rural New York. It's got its environmental challenges, as all pipelines do. I think New York, the EC, is doing a very careful and thorough examination of the route and the issues, and listening to the concerns of surface owners. And they are doing exactly what they should be doing. And at the end of the day we hope to get a permit that lets this pipeline be built in the time frame that we've illustrated so far.

Okay, very good. Just hypothetically, if this slips to Q3 how does that impact construction and the in-service date? Would it move it insignificantly?

No. I think I mentioned earlier it's going to be a year of construction, plus or minus a month or so, depending on when the permits actually come out and when the notice to proceed is granted by FERC, just given the windows during the construction period.

Okay, thank you.

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

All right. I appreciate everybody's interest in Cabot. I think we have been able to demonstrate a good 2014 program. We have a Q down 2015 program. But our expectation is that we will end the year in a very good order. And we look forward to our next conference call. Thank you, gary.

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