Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Cabot Oil & Gas Corporation (NYSE:COG)

Q4 2013 Results Earnings Conference Call

February 21, 2014 9:30 AM ET

Executives

Dan Dinges - Chairman, President and CEO

Scott Schroeder - Chief Financial Officer

Jeff Hutton - Vice President, Marketing

Analysts

Drew Venker - Morgan Stanley

Doug Leggate - Bank of America Merrill Lynch

Gordon Douthat - Wells Fargo

Biju Perincheril - Jefferies

Bob Brackett - Sanford Bernstein

Marshall Carver - Heikkinen Energy Advisors

Brian Singer - Goldman Sachs

Charles Meade - Johnson Rice

Jack Aydin - KeyBanc Capital Markets

Jeffrey Campbell - Tuohy Brothers Investment

Matt Portillo - Tudor, Pickering Holt

Operator

Good morning. And welcome to the Cabot Oil & Gas Corporation Fiscal Year End and Fourth Quarter 2013 Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation there will be an opportunity to ask questions. (Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO. Please go ahead, sir.

Dan Dinges

Thank you, Denise, and good morning, all. Thank you for joining us for the call. I have with me today as usual the executive management team. Also before we get started, the boilerplate language and forward-looking statements included on the press releases to apply to my comments today.

Now let’s go into last night’s press releases. They included another year of record financial performance, record reserve metrics and another new long-term infrastructure solution to move our gas in the Marcellus.

Specifically, the financial and operating results were record. Revenues of $1.7 billion, up 45% over the previous high watermark established in 2012, recurring net income and that is net income excluding select items like asset sale gains reached an all-time high of $298.1 million, cash flow from operations exceeded $1 billion for the first time, as did discretionary cash flow, an increase of 57% and 61%, respectively, over 2012.

Production increased at 55% over 2012 and this was the largest percentage growth we have ever reported and came on the heels as you’re aware of two solid years of 43% growth each.

Most impressive about our recent record growth is that it has been off an increasingly larger base and accomplished by running only five rigs for the majority of the year. Certainly, running five rigs at this production reserve base is the least amount of any of our peers in the basin. And it is fully funded by operating cash flows and proceeds from non-core asset sales.

Total proved reserves increased 42% over 2012 with no change in percentage mix between our proved, developed and our proved undeveloped.

Unit costs, another measure of our efficiency including financing dropped 18% to just over $3 per Mcfe in 2012 with total cash cost of $1.46 per Mcfe. We continue to show a commitment to returning cash to our shareholders by increasing our dividend by 100% and we repurchased $165 million of our shares. Certainly those metrics without question was Cabot’s best year ever reported.

On the year-end reserves, in terms of that report, we crossed the 5 Tcf milestone, which clearly a significant achievement. But the manner in which this was accomplished was also significant. For the last five years, Cabot has operated 100% organic drilling effort, while simultaneously rationalizing our reserve portfolio.

During this time unit reserves has grown 180% or 23% compounded annual growth rate. This was after removing 441 Bcfe due to asset sales and de-booking of 559 Bcfe of PUDs from legacy areas in response to SEC rules. For a total of 1 Tcf that had been removed. So in light of that and looking at our growth profile it’s truly an impressive effort.

From a finding cost perspective these five years saw an all source finding cost figure of $0.88 per Mcfe in ‘13, Cabot added to its reserves at a $0.55 per Mcfe all source finding cost figure, while the Marcellus alone was $0.40 per Mcfe exceeding expectations.

With this latest reserve report, Cabot reported an average EUR for our ‘13 program of 16.9 Bcf up from our 13.9 Bcf 2012 program a as another measure, our 3.6 Bcf EUR per 1,000 foot of lateral remains best-in-class among key players in the basin.

Certainly, also worth noting which we did point out is that the sample approval for the wells that we drilled in the upper Marcellus measures up remarkably well in the same comparison to the entire -- lower Marcellus at a 2.7 Bcf per 1,000 foot of lateral.

Recently the Pennsylvania DEP released the second half statistics for the entire state and Cabot had its best performance. We’ve always been a player in the top 10 but this year Cabot had the top 13 wells in the entire Marcellus and we had the top 17 of 20 wells. As a result of this continued improved performance we increased our reserve bookings on PUD locations in the Marcellus from an EUR of 9 Bcf to 10 Bcf per well.

Our undrilled PUD reserve percentage remained flat at 36%, while the overall PUD percentage remained at 41%. We continue to be fairly conservative in our reserve bookings, recognizing a modest 0.7 offset PUD locations for each of our proved developed wells in the Marcellus. Our year-end reserves were 97% natural gas, which is in line with last year’s percentage.

We have continued to lower the breakeven levels for our Marcellus operation as a result of higher EURs and cost savings from increased operating efficiencies, resulting in continued improvements of our return profile, which has release highlighted now exceeds 100% pretax at $3 realization, which is up from 70% compared to our ‘12 program.

Also, before we begin discussing guidance, I would like to clarify one point from our press release last night. We had a couple of questions regarding the first half production levels remaining relatively flat were the questions, along with the severe weather conditions experienced throughout our operating area came mechanical issues that essentially prevented a somewhat material amount of production from reaching our interstate markets, compressor station runtime was definitely impacted from the weather and our midstream provider is still working out the issues to provide expected levels of service.

Now let me move to guidance, because of our improved -- improvement in productivity our focus on efficiency and our commitment to physical responsibility, we have adjusted our 2014 plan in response to the macro price environment.

Specifically, we have elected to stay at eight rigs in our total program, which is what we ended at our -- ended ‘13 with, which includes six in the Marcellus and two in the Eagle Ford. And while we will be permitting and be prepared to add additional rigs during the year, we are pleased that our revised program spending -- spends less capital but delivers the same absolute midpoint of production guidance.

And this highlights the impact of gains from our overall operating efficiency including pad drilling and the improvements we’re seeing from some of the longer laterals that we drill.

An important note on our production guidance is when you take the corresponding midpoints and we’ve had some questions in this area, when you take the corresponding midpoints of guidance issued in September for both ‘13 and the initial ‘14 levels? Those equaled the midpoint of the absolute volume guidance disclosed last night.

The outperformance for ‘13 growth over ‘12 is offset some due to the sale of all of our Mid-Continent properties that we closed as you’re aware in December, making the pro forma growth remain at what we guided at 30% to 50% for ‘14 but on absolute terms 25% to 45%.

As it relates to capital, the guidance has been reduced, reflect one less rig yet partially offset by increased completion activity, which is basically reducing our backlog. So, effectively right now, we currently have one full year of backlog wells that one rig year would provide for us in the uncompleted category, which allows for one rig reduction without any impact to our production.

Additionally, and we’ve had got some questions in this area additionally, the only impact to ‘15 will be a reduced level of our backlog wells, which will not affect our 2015 growth profile. Going into 2015 we will just have a reduced backlog but will not affect our 2015 expected production levels.

Unit costs were targeted to decline once again by double-digit percentages both for total cost and for cash costs.

In pricing, at our last call we discussed desire to have a good cold winter and the farmer’s almanac was correct, it did show up and it drove NYMEX prices above everyone’s screen level. However, similar to last fall, the NYMEX indication remained strong but most of the underlying sales points have remained under pressure throughout the Marcellus area, because of this dynamic we are widening our discount to NYMEX a bit for the year and we’ll provide our views on this quarter.

This dynamic somewhat influenced our operating decision to maintain our rig count as we ended 2013. As we were very deliberate last September, we do not anticipate chasing gas prices lower even having a usually economic project with our economic efficiencies that does not change our operating strategy.

Currently, we have approximately 50% of our 2014 anticipated volume sold at an average discount to NYMEX. During the course of the year, we intend to manage price risk through a combination of summer sales and spot sales combined with our current extensive hedge position.

We have continued to look for long-term ways to move gas out of the basin to different market areas. Last night’s announcement indicates we have been successful in that effort, working in tandem with Transco pipeline and Washington Gas Light.

Cabot as a producer has created another long-term opportunity to move gas out of Susquehanna County to one of the fastest growing markets in the country. To steer both a long-term sales contract of this magnitude plus match up perfectly, the required capacities is a unique opportunity for us.

To put this in perspective, this venture combined with the Constitution Pipeline will move 1.35 Bcf per day out of Susquehanna County to new and diverse market. This 1.35 Bcf per day, by the way represents 90% of our record level of daily production, highlighting the impact to Cabot down the road and we continue to evaluate additional opportunities such as this.

For now, however, we will continue manage through another cycle as we have done throughout our carriers. We’ve had number of questions on the timing of Constitution and with regard to Constitution, two critical events have occurred since our last call.

First, on December 13, 2013, FERC issued its schedule notice for the final EIS statement to occur by July 14, 2014. Although, FERC’s timeline for approval extended beyond our original target, this is great news and a very important milestone.

And as we indicated in our press releases back then, by setting this date for July, it also moved our in-service date to late ‘15 or possibly ‘16, as Williams indicated in their release yesterday.

Next, in moving again to another milestone for Constitution on February 12, 2014, FERC issued the draft EIS for Constitution. This is an important release and was another giant step for the project and puts Constitution very close to its final approvals.

So, in summary, we just experienced our best year ever. We continue to be well-positioned with our improving economic and returns affording Cabot the ability to continue with their operating plan, a plan that delivers the same absolute production levels from fewer capital dollars in our ‘14 program. We will put up year end very good financial metrics and we will start the bank with new reserves at the best in class finding cost in the Marcellus.

Denise, with that, I’ll be more than happy to answer any questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question will come from Drew Venker of Morgan Stanley. Please go ahead.

Drew Venker - Morgan Stanley

Good morning.

Dan Dinges

Hi, Drew.

Drew Venker - Morgan Stanley

I was hoping you would talk about whether there’s anything unusual driving your wider differentials year to date, if there’s any infrastructure outages or if this is just more related to volume growth from the region?

Dan Dinges

Well, predominantly related to the volume growth in the region. The differential is a real phenomenon. We have a plan in place with our exit strategy out of Susquehanna County. Certainly, going to be a little bit of time before we reach that milestone, but it’s predominantly related to the growth in the area.

Drew Venker - Morgan Stanley

Dan, can you give us a sense of what you expect for differentials for the remainder of the year?

Dan Dinges

Well, as far as specific differentials, when we run our model we have, as I mentioned, I think in the last call, we have over 400 something contracts that are at different price points to.

As opposed to the differential, I’ll say it like this, that our expectation is that our realized price is going to be north of $3 and under $4, I used the $3 bogey that demonstrates, as we’ve mentioned in our release, that program is expected to yield in using the differentials that we use in various different scenarios and sensitivities. We think our program by the end of the year is still going to deliver 100% return metric or greater and that’s kind of how I’d like to catch the differential.

The differential is the 800 pound gorilla in the room right now and everybody’s models are different. So to catch it in the terms of what we expect our program to deliver it’s a hell of a lot easier for me to discuss that and kind of make a crystal ball guess on what the differential is going to be.

Drew Venker - Morgan Stanley

Okay. And lastly, Dan, just going back to the flattish production growth in first half, you talked about some weather-related issues, is there anything else in terms of just field infrastructure that needs to be put in place before you start to grow in the second half or can you provide any more color there?

Dan Dinges

Yeah. Drew, it was mainly a couple of things. One, the weather and we’ve had a significant level in my opinion downtime associated with the compressors out there, some weather-related issues. But it is really more in line with the timing that we had out in the field with the larger pads we’re drilling, the timing of those completions of those wells and the expectation, which we’ve always had, the expectation that a lot of these wells are going to be completed and turned in line kind of in the April, May time period when we see a updraft of the number of wells that we’re turning in line.

And in our original guidance that we -- and that we have right now took all this in consideration that this is not the flattish first portion of ‘14 production, is not anything -- is not a surprise, it’s not an operational issue, as far as infrastructure is concerned or anything. It is impacted a little bit by the downtime on compression. But it was built into our guidance and we still feel very comfortable with our guidance.

Drew Venker - Morgan Stanley

Thanks for that color.

Dan Dinges

Yeah. Thank you.

Operator

The next question will come from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

Doug Leggate - Bank of America Merrill Lynch

Thank you. Good morning, Dan.

Dan Dinges

Hi, Doug.

Doug Leggate - Bank of America Merrill Lynch

Thanks for all the color on the first half. I guess the commentary about not adding a rig, and the backlog that you have currently? I guess basic question is to how you are stacking up the use of cash and relative opportunities within the portfolio? And so, I guess, my question is, with the activity in the Eagle Ford and the fact that you’re not increasing activity in the Marcellus at least not in the first half, how do we think about how you reallocate capital and whether or not the Eagle Ford gets a little bit more of a piece of your budget on a go forward basis and I’ve got a follow-up also?

Dan Dinges

Yeah. Okay, Doug. It is good question. And as indicated in the past in regard to capital allocation, first on the rig portion, we have presented yesterday our revised budget to our Board, which we do every February. And through our October budget that we had prepared and gave to the Board and looking at the efficiency gains that we had in the Marcellus area.

We started looking at what we might be able to do with the completions side of our business, allocate a little bit more money to completions. Do not have -- do not add the seventh rig, we ran sensitivity to see if we could still deliver a similar production profile and we determined that we could and we also looked at would it affect ‘15 production and we decided it didn’t though it does take our backlog down somewhat and so we were able to reduce our capital program.

In the Eagle Ford, Matt and his group have continued to make strides and improvements in our operation there. But as an example, I’ve indicated that once we see consistent results on these longer laterals and IPs and 30-day rates that we will expect then we have that opportunity to deliver more capital.

But to that point, we don’t have a lot of new benchmarks on the production profile. We had just finished drilling our sixth well pad which is the largest pad and kind of one of the ones that we had indicated we’re going to try to get out 8,000 foot or so. And frankly four of the six were able to get out 8,000 foot or so….

So and the average on that is certainly going to be much longer than the average we have realized for those six wells, much longer than the average we’ve realized throughout our program. But we haven’t fraced those wells yet. We’re staging up to frac those wells right now. And if we see good results from that, we still have optionality on increasing our level of activity in the Eagle Ford.

Doug Leggate - Bank of America Merrill Lynch

Okay. So you are not ready to step it up yet, I guess is the message?

Dan Dinges

Well, no. We are ready to step it up that’s why we got the permits in place and that’s why we have the regulatory requirements in place and now we are going to evaluate the results and flow backs our most aggressive wells to date and make that final determination but we have a teed up, Doug.

Doug Leggate - Bank of America Merrill Lynch

Okay. That’s good to know. Thank you. If I could go back to Drew’s question on differentials, I’m just curious, we are starting to reed some issue in the first couple of months of this year. And I guess, we’ve had a couple of discussions as folks know about gas being pulled in at low prices until done by consumers, or is that inconsequential in the grand scheme of things? I’m just trying to figure out, again, the reason for the right differentials given how strong gas has been?

Dan Dinges

I’m sorry, Doug, in the middle of your question I could not hear it.

Doug Leggate - Bank of America Merrill Lynch

I’m sorry. So, I’m trying to -- I’m wondering if storing the release of gas from storage contributed to what you believe is the right differentials in the first couple of months of the year as opposed to adjusting production growth. Have there been any material storage in this that you are aware of that might have contributed to that?

Dan Dinges

Well, I think certainly it had some bearing on it, Doug. But I don’t think it had the majority of bearing on the differentials that we’ve seen. I think it is more akin to the -- and related to the production growth in the immediate area that has affected the differentials the most.

Doug Leggate - Bank of America Merrill Lynch

All right. I will let someone else jump on. Thanks, Dan.

Dan Dinges

Thanks, guys.

Operator

The next question will come from Gordon Douthat of Wells Fargo. Please go ahead.

Gordon Douthat - Wells Fargo

Thanks. Good morning, guys. Question on the Upper Marcellus for you, it looked like -- well, first off, just want to confirm, what was your prior EUR estimate for the Upper Marcellus? I think I recall 7 to 9 Bcf. Is that correct?

Dan Dinges

Yes. That is correct, Gordon.

Gordon Douthat - Wells Fargo

And then, would that be on a 4,100-foot lateral, or what lateral length did you drill those wells on?

Dan Dinges

Well, the -- one, we were fairly conservative, I think in our original estimate because we didn’t have as many wells. We had several more wells now in our sample pool. So, two things, one, we’re getting good results, slightly longer laterals on the numbers that we are giving you. But we are also now more data points in the Upper and that we’re seeing the consistency on the deliverability, 30-day averages and we’re feeling good about it.

Gordon Douthat - Wells Fargo

Okay. So, 2.7 Bcf per 1,000 foot is probably -- it’s up versus prior estimates anywhere from 40%, if my math is correct. Is that the way you are looking at it?

Dan Dinges

That’s probably close from our original number.

Gordon Douthat - Wells Fargo

Okay. And then, as we get more into pad drilling, how does that -- I know your activity will be concentrated in the lower Marcellus, but how does that, the Upper factor in as you get more into pad drilling going forward?

Dan Dinges

Yeah. We have -- one of the things that is really unique, if we had -- if we had 20 wells out there, 20 rigs out there drilling, we would be able to make all kinds of pilot programs and do all kinds of different things and testing this, testing that. But our program is really unique in the sense that we only have six rigs out there in the field and our deliverability is so strong.

We are only going to drill slightly over 100 wells and still be able to grow off of, over a Bcf a day. Again, there is not many programs that can deliver that with only six wells. And so our ability to get to an extensive sample pool for the Upper is just -- it’s pushed out a little bit simply because we are not drilling many wells in the field.

Gordon Douthat - Wells Fargo

Sure. And then, last question for me is on share buybacks. Where do you stand with that going forward?

Dan Dinges

Well we have -- Scott and I’ve visited about that earlier today. We looked at all these reports that everybody put out and it was pretty clear that you could flip a coin 10 times and it would be 50-50 on whether or not there was going to be a negative outlook for us or a positive outlook because of operations. And we know we have some differentials that will affect the realized price like I said our realized price that we think we’ll receive when all the dust settles will be between the $3 and $4. And our program delivers over a 100% return in that bandwidth.

But we know that there is going to be investors that look at the differential and with the uncertainty and nobody’s crystal ball is exact that our -- the volatility in Cabot is probably going to be recognized. We traded 12 million shares yesterday. But with that volatility and our position, we certainly see an opportunity that’s not too far off that we are going to be able to move a significant volume of our gas out of the basin to different price points. And this is a finite period of time that we are dealing with this differential concern that’s been expressed out there. So on share buybacks if it does get soft, we’ll do just as we did in ‘13. We’ll step in and we will buy our shares back and be happy to do it.

Gordon Douthat - Wells Fargo

Okay. Thank you very much.

Operator

The next question will come from Biju Perincheril of Jefferies. Please go ahead.

Biju Perincheril - Jefferies

Hi. Good morning. Couple of questions related to reserves. First, I guess, first is an update on the Lower Marcellus in-flow test that you announced in December as far as how those wells are holding up, relative to the parent wells?

Dan Dinges

I’m sorry, Biju. Which wells?

Biju Perincheril - Jefferies

The infill wells, the 500-feet apart between laterals that you announced in December?

Dan Dinges

Yeah. They are doing good. They are on our curve pit. Probably, a couple of them above our curve pit.

Biju Perincheril - Jefferies

Compared to the 16.9 Bcf EUR?

Dan Dinges

That’s right.

Biju Perincheril - Jefferies

Okay. And so compared to that 3.6 Bcf per 1,000 foot of lateral, what was the -- do you have a number for those, or…?

Dan Dinges

3.6 Bcf per 1,000 foot of lateral. It will have a number for…?

Biju Perincheril - Jefferies

For the infill wells?

Dan Dinges

No, no. I don’t have that.

Biju Perincheril - Jefferies

Okay. Okay. But you are not seeing, anything significant degradation in EURs compared to the wider spaced wells, is that…?

Dan Dinges

No. In fact, our one report, I can’t remember whose it was -- I read a report that somebody questioned the 10-well pad, and I had a hard time understanding the concern for that particular report. We’re very pleased with the 10-well pad. We’re very pleased with what we’ve seen in the spacing. And we have compared to our EURs, compared to how it fits into our overall program, the numbers that we’ve laid out. We’re very pleased with that pad.

Biju Perincheril - Jefferies

Okay. That’s good. So, how does your drilling program, then changes based on then, are you in terms of wells that are going to be spaced 500-feet between laterals versus a 1,000 feet?

Dan Dinges

We are on our plan and going to six rigs. Phil has had to adjust his schedule a little bit, just because of how we are still capturing primary term acreage out there. Keep in mind, Biju, 60% of our program compared to the mid-20% of our program in ‘13. 60% of our ‘14 program will be drilling on pads that have five or more wells. And we are going to continue down-spacing our wells on those pads differently from the 1,000 foot spacing.

Biju Perincheril - Jefferies

Okay. Good. And then on reserves, I guess, in the prior years, you’ve mentioned that you had only booked about 0.7 PUD locations per PDC in the Marcellus. Is that sort of the same ratio again this year?

Dan Dinges

Yes. Yes, it is. In fact that is at, Biju, 0.7, offset PUD locations for each well we booked.

Biju Perincheril - Jefferies

Okay. And then since I was coming up with…

Dan Dinges

Let me add to that, we did raise the amount of reserves we’re placing on a PUD from 9 Bcf to 10 Bcf.

Biju Perincheril - Jefferies

All right. Right. Okay. And again, that’s sort of like, I guess, sort of a placeholder number until you have the lateral length design there. So, on the locations that you’ve booked, I’m estimating something like you have a little more than 300 PDC locations and a little more than 200 PUD locations in total in the Marcellus now. Is that -- am I in the ballpark?

Dan Dinges

Yeah, that’s ballpark.

Biju Perincheril - Jefferies

Okay. Okay. And then, so I guess, with the success you now have in the Upper Marcellus, I guess you have a higher confidence in that 3,000 location total you’ve talked about from before?

Dan Dinges

Absolutely, we have -- the Upper Marcellus has begun on a course just as our Lower Marcellus did. Keep in mind, several years ago before we had the data, we started out bookings of less than 5 Bcf per Lower Marcellus well. And we have stepped that up to fairly robust type of wells. We have limited data, though more data than we had last year in the Lower Marcellus and some plumbing in the Upper Marcellus. And we have some flow history from those wells now and I think you are saying that we are in the middle of marching that number up.

Biju Perincheril - Jefferies

All right. Great. Thank you.

Dan Dinges

Thank you.

Operator

The next question will come from Gil Yang of Discern. Please go ahead.

Gil Yang - Discern

Good morning. Thanks for taking my question.

Dan Dinges

Hi, Gil.

Gil Yang - Discern

Hi, Dan. The EUR per 1,000 foot was up about 6%, when I do the math. But you increased the number of stages per foot, so to speak by about 12%. Are you beginning to see a convergence in terms of the benefits you are getting from the tighter frac spacing, or do you think there is much more to go in that opportunity?

Dan Dinges

Again, keep in mind that we like everything we are seeing on the curve fit, early time on our down-spacing. Down-spacing, regardless of where you are, down-spacing is a pilot programs takes time to fill it way out and see the ultimate results of that down-spacing. And right now, all we can say because that’s all we have is that we’re very pleased with the down-spacing and it’s fitting what our expectations would be on a curve pit. That would not indicate we should have concerns about how far we’ve down spaced those wells.

Gil Yang - Discern

Dan, you’re talking about -- just to be clear, you’re talking about -- I was asking about the frac spacing in terms of the on one lateral, 200-foot versus the 220. Is that what you were referring to in the down-spacing?

Dan Dinges

No. I’m sorry, Gil. I was talking about the distance between laterals. I wasn’t talking about frac clusters. I misunderstood your question.

Gil Yang - Discern

No, I was just asking that as you put the frac clusters tighter together, you put 12%. You decreased the spacing between the clusters by about 12%. But the EURs per 1,000 foot went up by about 6%. So it sounds like you’re getting to a regime where the frac clusters are interfering with each other?

Dan Dinges

No. It’s just -- those numbers, I think, Gil, are within the tolerance. Those guys are continuing looking at our completion efforts. And I’m comfortable with where the numbers are and what they’re doing. Between 12% and 6%, I think our standard deviation is pretty tight.

Gil Yang - Discern

Okay. Okay. And so, maybe there’s some opportunity to put them even tighter than 200-foot?

Dan Dinges

Well, let’s back up our ways. We had at one time -- we went all the way down to about 150-foot. And we don’t have many samples of that and the completion techniques are modified just a little bit continuously as we go, whether it’s pump pressures or amount of propane or whatever.

But -- I know Phil is, and Phil is with us today. He came in for a Board Meeting obviously yesterday and his guys are always looking at ways to improve. And they only have a number of different things that they’re doing out there on a stage here or stage there, a well here, a well there. But we’ll continue to look at how we can squeeze efficiencies.

Gil Yang - Discern

Okay. Great. And just second question is, the $0.76 cash cost in the Marcellus, could you break that into the direct operating cost and transportation and anything else?

Dan Dinges

I’m kind of looking at Scott.

Scott Schroeder

What’s your question, Gil?

Gil Yang - Discern

The $0.76 you highlighted for the Marcellus cash costs, can you just break that down into its components?

Scott Schroeder

I can give you total company. Total Company, kind of LOE is anticipated this year to be $0.25. Transportation has a low $0.60 number on it because of one of the dynamics. We have some transportation agreements in the south that are now being captured in that line for the oil pipelines that we’ve had in place for a year or so and taxes and other income of $0.05.

Gil Yang - Discern

All right. Thanks.

Dan Dinges

Thanks, Gil.

Operator

The next question will come from Bob Brackett of Sanford Bernstein. Please go ahead.

Bob Brackett - Sanford Bernstein

Hey, good morning. A quick one and maybe a longer one. The quick one, do you guys quote your exit rate for end of 2013 anywhere?

Dan Dinges

No, we have not quoted that Bob.

Bob Brackett - Sanford Bernstein

Okay. Then that was the short one. The longer one, given how big you are in Northeast PA, have you ever looked at the elasticity of your price versus supply and could you guys literally kind of choke back pads, put less supply into the grid, but earn a higher revenue?

Dan Dinges

Well, since we run a number of sensitivities and we always do with our budget and price tag. And in your example if you make the assumption that we’ve reduced to a certain level and price is a corresponding rebound then certainly that would hold true in practice and actuality would that result happen. I couldn’t tell you but I can say this Bob that if prices get too bad for us, we will manage our operation practice and we’ll manage our assets.

And we did that last year when the day markets on the smaller percentage of our gas that we sold in the day market differentials got too high. We said we weren’t going to sell that gas into the day market. But again from our expectation and what we’ve guided on both our ability to continue to grow at the levels we’ve discussed and our ability to manage the differential concern in a way that would allow us to realize between 3 and 4 bucks. I’m comfortable with that.

Bob Brackett - Sanford Bernstein

Okay. And you are comfortable that you can kind of reduce production without damaging any of the reservoirs or the program?

Dan Dinges

Absolutely, yeah. One of the things, Bob, in our reservoir that I think does make that call a lot easier than it might be in other reservoirs is keep in mind that we are dry gas. We’re about 1,020 Mmbtu quality gas, and it is a very -- there’s not any liquids in the water, liquids in the reservoir.

And typically if you have concerns in opening up and shutting in, opening up, shutting in and let them sit for a while, typically, it’s been my experience that you would have more concerns in reservoirs that you have a liquid component to it than if you were doing that in a dry gas reservoir.

Bob Brackett - Sanford Bernstein

Thanks.

Dan Dinges

Thank you.

Operator

Our next question will come from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.

Marshall Carver - Heikkinen Energy Advisors

Yes. You’ll be working through your completions backlog this year next. How many wells or stages should be put online this year versus next year, assuming you keep running the six rigs through next year?

Dan Dinges

Well, we’ll have -- in ‘14, we’ll have over 3,000 right at, upper 2,000 wells or frac stages put on anywhere from 2,600, 2,800 something like that and we haven’t given any guidance for ‘15.

Marshall Carver - Heikkinen Energy Advisors

If you run the same number of rigs, would it probably be about the same number, is that a reasonable assumption?

Dan Dinges

Well, if we ran the same number of rigs in ‘15.

Marshall Carver - Heikkinen Energy Advisors

Right.

Dan Dinges

If we ran six rigs in ‘15, it depends on how far down we took our backlog that we will have going into ‘15 and towards the end of ‘15. We would still have -- again, my point I made earlier about keeping our rig count the same and still growing our production profile.

If we go into ‘15, we’ll have a short, a smaller backlog, but we’re still going to have a significant backlog going into ‘15. If we keep the same number of rigs and we continue to chip away at the backlog, we can still complete the same number of stages or more with the same number of rigs.

Marshall Carver - Heikkinen Energy Advisors

Okay. That’s helpful. On the weather-related downtime and compression station runtime in Q1 and Q2 this year, do you have a feel for how much did that impacted production and how many million a day was impacted in Q1 and what you’re factoring in for Q2?

Dan Dinges

Yeah. I don’t have it at my fingertips, Marshall, at this time. But there were days that we were 100 million down, 150 million down and then other days we were 25 million down. So as a swag number, 75 million a day plus or minus.

Marshall Carver - Heikkinen Energy Advisors

For each quarter…

Dan Dinges

Well we’re still in the -- for the first couple of months of ‘14, Marshall.

Marshall Carver - Heikkinen Energy Advisors

Okay. And final question, on the Upper Marcellus, will that start to get significant capital or will it still be a very -- when would you expect it to -- significant number of wells drilled there?

Dan Dinges

Well operation prudence dictates that we complete from the bottom up. We are now again not fully maximizing the number of wells that we ultimately anticipate drilling per pad. Though we are drilling more wells from multi-pad as indicated by 60% of our program drilling from pad sites that will have five or more wells.

But along with that being said, we will continue to look at various different points that will place Upper Marcellus wells just to continue gathering our data base. But again operation prudence says complete the lower wells first and then move up and complete the upper wells at a later date. Again without full pad development yet, majority of our wells will continue to be lower Marcellus wells.

Marshall Carver - Heikkinen Energy Advisors

Okay. Thank you.

Dan Dinges

Thank you.

Operator

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

Brian Singer - Goldman Sachs

Thanks. Good morning.

Dan Dinges

Hi Brian.

Brian Singer - Goldman Sachs

You talked on how you’d relook at differentials quarterly in your view there. How does that impact how your capital allocation process works and what you need to see to add another rig. Maybe a better way to ask you, what differential should we expect when your long-term solutions like Constitution are in place and do you see keeping your rate count flat until then?

Dan Dinges

There is not going to be a lot of swing in our budget in the first half of ‘14 typically when we’ve made some adjustments it’s been in the second half of the year. And I would expect that ‘14 will be no different than that. When you look at what our expectation would be on a forward look in differentials keep in mind just the two deals -- really, three deals that we’ve announced, the Constitution, the Cove Point deal, and the most recent deal we’ve made with Transco and Washington Light, that’s 1.35 Bcf a day, and that is moving to -- and you can go to indexes aside from some of the current ones on Transco, Leidy or the Tennessee Line.

And as you move away from those two lines, it is apparent that the differentials improve considerably in different markets and price points. And all of that gas that I’m talking about in these new ventures will be at different price points than what we experienced today.

Brian Singer - Goldman Sachs

I guess when you layer in the transport cost associated with that, what does that gets you back to, you may have mentioned, I think, a $3 to $4 number in terms of whether that was in reference to an ultimate realization earlier in the call. Maybe you could add some color on that?

Dan Dinges

Well, on the transportation side of the business, our transportation cost for this is not going to be much different than any transportation deal or firm transportation arrangement that’s being executed across the basin today. So whatever realizations that you see out there to different price points that would be equivalent to the price points that we’re going into, whether it’s air core line or the non-New York area that we might be going into. Those are going to be similar to our expectations also on realizations.

Brian Singer - Goldman Sachs

Thanks. And then lastly on the stock buyback, what should we expect going forward, do you ultimately -- do you see ultimately your buyback program including what was done in the fourth quarter of ‘13 exceeding your asset sale proceeds?

Dan Dinges

It could. We’re going to go through the year and we’ll make that decision more opportunistically and again, the value of Cabot, what we see going forward though we have some of the headwinds that we’ve all been discussing, facing us today. I see those headwinds as a finite period of time and I’ve held shares in this company for greater than 10 years.

I continue to hold a considerable amount of shares in Cabot and I’m happy to do that. I have no plans of selling those shares and in fact, if we got beat up too much around the years, I’d add to my position personally. So I see us having a significant opportunity behind the headwinds that we face in the differential side. And I’m optimistic that the market is going to rationalize the differential and there’s billions of dollars spent to redirect gas and to rebalance the market in a way that is going to again, capture the efficiencies and that’s always been the case.

I was disappointed that Constitution slid out a little bit, just by the timing of the July release versus the May release by FERC, but we’ll deal with it. Again I’m here for the long-term and we’ll deal with that. And we’ll manage our program in a prudent manner as we always have. And frankly we’ll still be able to deliver not only an operationally impressive program but a financially impressive program at year end.

Brian Singer - Goldman Sachs

Thanks Dan

Dan Dinges

Yeah. Thank you Brian.

Operator

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

Charles Meade - Johnson Rice

Good morning Dan. You’d anniversary your team there. I wonder if we could just pick up on that point about Constitution a bit. Can you -- I’m recognizing that Williams is the operator there. Can you maybe be a bit more explicit in what you are current plans reflect on when that line will come in to service for you. And could you possibly talk about some of the -- if there is any local permitting that you still have in front of you or if you are really this -- what you got last week with EIS is really the last definitive thing to look at?

Dan Dinges

Yeah. I’m going to pass this to Jeff real quick. My comment on the timing that we’re working with as I have stated in this comment, teleconference here that later ‘15 is our hope that we would be able to secure all the remaining permits and some being local and the outside would be moving into ‘16 a little bit. I’ll let Jeff make any comment that you might have?

Jeff Hutton

As you know, we all knew this would be a three year process with the FERC and way they operate and quite frankly we are very pleased now the FERC has handled this process and the issuance of their schedule and the issuance of the draft EIS. Those are all very, very positive steps.

In terms of the schedule itself, I’m sure you read Williams’ transcript or heard it yesterday, they also are very pleased with how the process has been working on the federal level. They have some feedback as the operator that -- and that is -- has shared that with some of the owners or with the owners that there is a little bit of a resistance at the state level in getting some permits generated from the EC.

So that’s something that Williams is working through on the government relation side, on the regulatory side, and continue to get updates from them. But the process is working good, but it does take state permits as well as federal permits to get its project built.

Charles Meade - Johnson Rice

Got it . Got it. Thank you. Yeah, even I had seen that yesterday, so I was curious kind of how you -- if you guys had any different take on it, but that’s good color, Jeff. Thank you. Then, is it -- would it be right to think that Constitution is -- I don’t want to say getting less important, but it’s maybe just one of -- that in light of these bigger -- or more recent deals you guys have signed for additional takeaway out of the area that it’s more becoming one of many solutions, rather than the kind of -- the sole most important project, or is it still the biggest thing for you guys?

Dan Dinges

Well, it’s the nearest term, Charles. And the other projects, in addition to what we just announced that Jeff looks at and continues to try to find ways to move our gas and we have found additional pathways for our over 400 million cubic foot of gas and being able to keep moving our gas into the marketplace.

But it is certainly our objective to be able to move gas on as many pipes as we can which eliminates or alleviates and mitigates what we’re experiencing today and that is just with a couple of pipelines going out of a high supply area that it pushes the gas on gas competition in the center stage.

But we do have a vision out in front of us that we’re going to be accessing what has typically been very, very good supply base or demand areas and very good price points. And we know where we’re going is also expanding demand areas that will bode well for the future.

Charles Meade - Johnson Rice

Thanks for taking that question, Dan, Jeff, I appreciate it.

Dan Dinges

Thanks Charles.

Operator

The next question will come from Jack Aydin of KeyBanc Capital Markets. Please go ahead.

Jack Aydin - KeyBanc Capital Markets

Good morning guys. How are you?

Dan Dinges

Hi Jack. Good.Thanks.

Jack Aydin - KeyBanc Capital Markets

Most of the questions were answered, but just a couple ones. What are you budgeting for well cost on the longer lateral for 2014?

Dan Dinges

Jack, between 6 point, the end of Marcellus.

Jack Aydin - KeyBanc Capital Markets

Yes.

Dan Dinges

And coincidentally in the Eagle Ford, $6.8 million to $7 million?

Jack Aydin - KeyBanc Capital Markets

Okay. Now, if I look at the data what you said you have about 200 PUDs booked at 10-b. And then you are drilling about 100 wells with more -- extended lateral of closer to 5,000 and using the 3.6 b per 1,000 foot. Are you going to revise your EUR per wells mid-year or you are going to wait until the year end?

Dan Dinges

We’ll continue with our MO and that is looking at year end before we do any major -- we actually do any public reserve announcements.

Jack Aydin - KeyBanc Capital Markets

Okay. Thanks.

Dan Dinges

Yeah. Thank you, Jack.

Operator

The next question will come from Jeffrey Campbell of Tuohy Brothers Investment.

Jeffrey Campbell - Tuohy Brothers Investment

Good morning.

Dan Dinges

Good morning.

Jeffrey Campbell - Tuohy Brothers Investment

Dan, I’d like to return to the Eagle Ford. Your recent 2014 Eagle Ford guidance was for 40 to 50 wells. Does the 50 well count reflect pushing the paddle if the six well pad results are positive or could we get beyond 50 Eagle Ford wells if the pad is successful?

Dan Dinges

We could get with our guidance right now what we’ve done. We could -- if we added depending on timing and other rig, we could ramp up and frankly on our guidance right now Jeffrey. We are kind of at 36 to 38 type of Eagle Ford wells right now. So and that’s incorporated already in our guidance. So moving that up to even 50 would be an impactful move for our current guidance.

Jeffrey Campbell - Tuohy Brothers Investment

Okay. Great. Thank you. That’s helpful. This is a little bit broader but your current discussion of the Eagle Ford pad drilling is highlighting increased lateral length. When do you think Eagle Ford downspacing test might be relevant to think about?

Dan Dinges

Jeff, we were -- we have already had quite a bit of production coming from downspaced laterals at 400 feet. And even though we have some term on those, we are very comfortable at 400 feet. We will be doing some pilots at 300 feet.

Jeffrey Campbell - Tuohy Brothers Investment

Okay. And my last question is really pretty broad but I just wanted to kind of ask it, and that’s, with the Marcellus significantly outperforming the Eagle Ford on returns. Can you give us some idea of what’s the objective of current new ventures -- the new ventures program and what are you looking for, how actively is it out there…?

Dan Dinges

Yeah, our new ventures program has really consisted with a greenfield effort as opposed to allocating a lot of time and resources to look at buying into existing areas. We don’t feel that a buy-in to existing areas would yield a return profile that would meet our expectations.

The greenfield effort continues. We have, as I’ve mentioned before, multiple areas where we have 25,000, 30,000 acres that we have under lease. And we will be utilizing a expiration wedge out of our capital of $1.3 billion to $1.4 billion. We’ll utilize that expiration wedge to further evaluate whether or not these greenfield areas will compete for future capital.

Jeffrey Campbell - Tuohy Brothers Investment

Okay. Thanks very much. That’s it for me.

Dan Dinges

Thanks Jeffrey.

Operator

Our next question will come from Matt Portillo of Tudor, Pickering Holt. Please go ahead.

Dan Dinges

Good morning.

Matt Portillo - Tudor, Pickering Holt

Good morning guys. Two quick questions for me, just in terms of the Upper Marcellus, I wanted to get a little bit more color on how you think about the consistency across your acreage given your well control.

Dan Dinges

Well, keep in mind, our well control on the Upper Marcellus is extensive and it’s across our entire position that we think there is a similar consistency in the Upper Marcellus as we have in the lower Marcellus across our position. What we don’t have in the Upper Marcellus that we do have in the Lower Marcellus is just the production data.

Matt Portillo - Tudor, Pickering Holt

Great. And then my second question moves to 2015 marketing and as you guys have mentioned you’ll be watching the gas price to determine your acceleration plans, but how do you guys think about kind of the 2015 market dynamics as you look at incremental takeaway capacity from the basin and kind of with the market as it stands today, should we be expecting a relatively flat rig count or is there a potential for acceleration as you see some incremental pipes coming onstream?

Dan Dinges

Yeah. I think everybody is going to be looking at the effects on differentials in every part of the Marcellus, Southwest and Northeast; Northeast certainly getting the majority of the attention and the most differential impact today. But I think everybody is trying to guestimate what type of impact the midstream market and new takeaways are going to have on the market.

From where it is kind of today I think it is only going to improve as you are able to access additional markets as the demand continues to improve in areas that not only are currently being served but the new markets are going to be established on new infrastructure build out.

And certainly there is going to be an impact from the LNG facilities that will start coming on stream as we look out into later part of ‘15. So I think all these dynamics are going to improve price points in different areas.

And again our objective has been not only for ‘15 but what we are trying to do in ‘14 marketing our gas but ‘15 certainly holds true and beyond. We’re trying to access different markets to mitigate. Our singular price points every way we can. We don’t have singular price points right now, but you get the impact what I’m saying.

Matt Portillo - Tudor, Pickering Holt

Great. One last quick question for me, you guys continue to see your rates of return improve with tighter spacing and longer laterals. I was hoping if you get just maybe a bigger picture of you over the next years as to why you think your lateral lengths could move to in play as you kind of look at your total acreage position. Thank you.

Dan Dinges

Well we e think, certainly ‘14 is going to be longer laterals than ‘13. And I don’t have that exact comparison for ‘15 program but suffice it to say that our objective will be to lay out operational program in a way that will maximize the efficiencies of our dollar.

Matt Portillo - Tudor, Pickering Holt

Thank you.

Dan Dinges

Thanks Matt.

Operator

Ladies and gentlemen, that will conclude our question-and-answer session. I would like to turn the conference over to Mr. Dan Dinges for his closing remarks.

Dan Dinges

No, thank you, Denise. I appreciate everybody’s patience and the questions hopefully clarify some of the points that everybody had. I kind of equate this period, and again, I identified it as a finite period because I do believe as we move out into the mid-term that we’re going to be able to eliminate some of the questions that we have.

Certainly, mitigate the questions we have on the differential, and then kind of equate it similar to the way I’m looking at my views in the political life and what this country has faced. Every day I look at it from a political standpoint; every day that we’re getting closer and closer to an environment that will be more suited for my beliefs.

And I’m looking forward also operationally for Cabot as we move forward to not only our infrastructure buildout and commissioning, but also as the midstream market continues to have projects that would build out this market. I think we have significantly better days and more optimistic outlook out in front of us. So appreciate everybody’s patience and we’ll look forward to the next quarter call. Thank you, Denise.

Operator

Thank you. The conference has now concluded. We thank you for attending today’s presentation. You may now disconnect your lines.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Cabot's CEO Discusses Q4 2013 Results - Earnings Call Transcript
This Transcript
All Transcripts