Good morning, and welcome to the Cabot Oil and Gas Corporation fiscal year-end and fourth quarter 2013 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your telephone keypad. If your question has been addressed, you may withdraw from the queue by pressing star then two. Please note this event is being recorded. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President, and CEO. Please go ahead, sir.
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. Before we get started, the boilerplate language and forward-looking statements included on the press releases do apply to my comments today. 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 water mark 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, this was the largest percentage growth we have ever reported and came on the heels of, 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. 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 cost, another measure of our efficiency, including financing, dropped 18% to just over $3 per Mcfe in 2012, with a 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 five Tcf milestone, which is clearly a significant achievement, the manner in which this was accomplished was also significant. For the last five years, Cabot has operated a 100% organic drilling effort while simultaneously rationalizing our reserve portfolio. During this time, year-end reserves has grown 180% or 23% compounded annual growth rate.
This was after removing 441 Mcfe due to asset sales and the booking of 559 Mcfe of PUDs from legacy areas in response to SEC rules for a total of a 1 Tcf that had been removed. 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 2013, 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 2013 program of 16.9 Bcf, up from our 13.9 Bcf 2012 program. 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 pool 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. 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 nine Bcf to 10 Bcf per well. Our undrilled PUD reserve percentage remained flat at 36%, while the overall PUD percentages 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 break-even 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 as the release highlighted, now exceeds 100% pretax at $3 realization, which is up from 70% compared to our 2012 program. Also, before we begin discussing guidance, I would like to clarify one point from our press release last night. We've 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. Let me move to guidance. Because of our improvement in productivity, our focus on efficiency, and our commitment to fiscal 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 2013 with, which includes six in the Marcellus and two in the Eagle Ford.
While we will be permitting and be prepared to add additional rigs during the year, we are pleased that our revised program spends less capital but delivers the same absolute midpoint of production guidance. 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 2013 and the initial 2014 levels, those equal the midpoint of the absolute volume guidance disclosed last night.
The outperformance for 2013 growth over 2012 is offset some due to the sale of all of our Midcontinent properties that we closed, as you're aware, in December, making the pro forma growth remain at what we guided at 30%-50% for 2014, but on absolute terms, 25%-45%. As it relates to capital, the guidance has been reduced to reflect one less rig, yet partially offset by increased completion activity, which is basically reducing our backlog. 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 a one rig reduction without any impact to our production. We've had some questions in this area, additionally, the only impact to 2015 will be a reduced level of our backlogged 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 are targeted to decline once again by double-digit percentages, both for total cost and for cash cost. In pricing, at our last call, we discussed the desire to have a good cold winter. 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 quarterly.
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 secure 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 markets. 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. We continue to evaluate additional opportunities such as this. For now, however, we will continue to manage through another cycle as we have done throughout our careers.
We've had a number of questions on the timing of the Constitution. With regard to Constitution, two critical events have occurred since our last call. First, on December 13th, 2013, FERC issued its scheduled notice for the final EIS statement to occur by July 14th, 2014. Although FERC's timeline for approval extended beyond our original target, this is great news and a very important milestone. As we indicated in our press releases back then, by setting this date for July, it also moved our in-service date to late 2015 or possibly 2016, as Williams indicated in their release yesterday. Next, moving again to another milestone for Constitution, on February 12th, 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.
In summary, we just experienced our best year ever. We continue to be well-positioned with our improving economics and returns, affording Cabot the ability to continue with our operating plan, a plan that delivers the same absolute production levels from fewer capital dollars in our 2014 program. We will put up at year-end very good financial metrics. We will stack 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.
Ladies and gentlemen, we will now begin the question-and-answer session. To ask a question, you may press star then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. If your question has been addressed and you would like to withdraw from the queue, please press star then two. At this time, we will pause momentarily to assemble our roster. Our first question will come from Drew Venker of Morgan Stanley. Please go ahead.
Good morning. I was hoping you'd 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.
Well, it's 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.
Can you give us a sense of what you expect for differentials for the remainder of the year?
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 have different price points to them. 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 use the $3 bogey that demonstrates, as we mentioned in our release, that our program is expected to yield, and 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 the 100% return metric Or greater, and that's how I'd like to couch the differential. The differential is the 800-pound gorilla in the room right now, and everybody's models are different.
To couch 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 than make a crystal ball guess on what the differential's going to be.
Okay. Lastly, Dan, just going back to the flattish production growth in the 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?
Yeah. Drew, it was mainly a couple of things. One, the weather, and we've had a significant level, in my opinion, of 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, in the April-May time period, when we see an updraft of the number of wells that we're turning in line. Our original guidance, and that we have right now, took all this into consideration. This is not the flattish first portion of 2014. Production 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.
Thanks for the color.
Yeah. Thank you.
The next question will come from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Thank you. Good morning, Dan.
Hey, Doug.
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, begs the question as to how you are stacking up the use of cash and relative opportunities within the portfolio now. 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? I've got a follow-up, please.
Yeah. Okay, Doug. It's a good question, and as I've indicated in the past, in regard to capital allocation, first on the rig portion. We had presented yesterday our revised budget to our board, which we do every February. 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 completion side of our business, allocate a little bit more money to completions. Do not add the seventh rig. We ran sensitivities to see if we could still deliver a similar production profile, and we determined that we could. We also looked at would it affect 2015 production, and we decided it didn't, though it does take our backlog down somewhat.
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. As an example, I've indicated that once we see consistent results on these longer laterals and the IPs and 30-day rates that we will expect, then we have that opportunity to deliver more capital. To that point, we don't have a lot of new benchmarks on the production profile. We had just finished drilling our six-well pad, which is the largest pad and one of the ones that we had indicated we were going to try to get out 8,000 foot or so. Frankly, four of the six were able to get out 8,000 foot or so.
The average on that is certainly going to be much longer than the average we've realized for those six wells, much longer than the average we've realized throughout our program, we haven't fracked those wells yet. We're staging up to frack those wells right now. If we see good results from that, we still have optionality on increasing our level of activity in the Eagle Ford.
Okay. You're not ready to step it up yet, I guess, is the message.
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. Now we are going to evaluate the results and flow backs of our most aggressive wells to date and make that final determination. We have it teed up, Doug.
Okay. That's good to know. Thank you. If I can go back to Drew's question on differentials. I'm just curious, was storage really some issue in the first couple of months of this year, I guess we've had a couple of discussions with folks now about gas being put in at low prices and pulled out by consumers, or is that inconsequential in the grand scheme of things? I'm just trying to figure out again the reason for the wide differentials given how strong gas has been.
I'm sorry, Doug, in the middle of your question, I could not hear it.
Oh, I'm sorry. I'm wondering if the release of gas from storage contributed to what you believe is the wider differentials in the first couple of months of the year, as opposed to it just being production growth. Has there been any material storage changes that you're aware of that may have contributed to that?
Well, I think certainly it had some bearing on it, Doug, I don't think it had the majority of bearing on the differentials that we've seen. I think it is more akin to and related to the production growth in the immediate area that has affected the differentials the most.
All right. I'll let someone else jump on. Thanks, Dan.
Thanks, Doug.
The next question will come from Gordon Douthat of Wells Fargo. Please go ahead.
Thanks. Good morning, guys. Question on the Upper Marcellus for you. Well, first off, just want to confirm, what was your prior EUR estimate for the Upper Marcellus? I think I recall 7 Bcf-9 Bcf, is that correct?
Yes, that is correct, Gordon.
Would that be on a 4,100-foot lateral, or what lateral length did you drill those wells on?
Well, one, we were fairly conservative, I think, in our original estimate because we didn't have as many wells. We have several more wells now in our sample pool. Two things. One, we're getting good results, slightly longer laterals on the numbers that we're giving you. We're also now more data points in the upper that we're seeing the consistency on the deliverability and 30-day averages, and we're feeling good about it.
Okay. 2.7 Bcf per 1,000 foot is up versus prior estimates, anywhere from 40%, if my math is correct. Is that the way you're looking at it?
That's probably close from our original number.
Okay. As you get more into pad drilling, 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?
Yeah. One of the things that is really unique, 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. 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're only going to drill slightly over 100 wells and still be able to grow off of over a Bcf a day. Again, there's not many programs that can deliver that with only six wells. Our ability to get to an extensive sample pool for the upper is pushed out a little bit simply because we're not drilling many wells in the field.
Sure. Okay. Last question from me is on share buybacks. Where do you stand with that going forward?
Well, Scott and I 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'd be 50/50 on whether or not there was going to be a negative outlook for us or a positive outlook because of operations. 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 $3 and $4, and our program delivers over 100% return in that bandwidth. We know that there's going to be investors that look at the differential and with the uncertainty, and nobody's crystal ball is exact, that the volatility in Cab is probably going to be recognized. We traded 12 million shares yesterday.
With that volatility and our position, we certainly see an opportunity that is 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. This is a finite period of time that we are dealing with this differential concern that has been expressed out there. On share buybacks, if it does get soft, we will do just as we did in 2013. We will step in, and we will buy our shares back and be happy to do it.
Thank you very much.
The next question will come from Biju Perincheril of Jefferies. Please go ahead.
A couple of questions related to reserves. I guess firstly, an update on the Lower Marcellus infill test that you announced in December as far as how those wells are holding up relative to the parent wells.
I'm sorry, Biju, which wells?
The infill wells, the 500 feet apart between laterals that you announced in December.
Yep. They're doing good. They are on our curve fit, probably a couple of them above our curve fit.
Compared to the 16.9 Bcf EUR?
That's right.
Okay. Compared to that 3.6 Bcf per 1,000 foot of lateral, do you have a number for those?
3.6 Bcf per 1,000 foot of lateral? Do I have a number for?
For the infill wells.
Oh, no. I don't have that.
Okay. You're not seeing anything to say significant degradation in EURs compared to the wider spaced wells? Is that?
No. In fact, I read 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 PUD. 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.
Okay. That's very good. How does your drilling program then changes based on, in terms of wells that are going to be spaced 500 feet between laterals versus 1,000 feet?
We are on our plan and going to 6 rigs. Phil has had to adjust his schedule a little bit just because of how we're still capturing primary term acreage out there. Keep in mind, Biju, 60% of our program, compared to the mid-20% of our program in 2013, 60% of our 2014 program will be drilling on pads that have five or more wells. We are going to continue down spacing our wells on those pads differently from the 1,000-foot spacing.
Okay, good. On reserves, I guess in the prior years you mentioned that you had only booked about 0.7 PUD location per PDP in the Marcellus. Is that sort of the same ratio again this year?
Yes. It is. In fact, that is it, Biju, 0.7 offset PUD locations for each well we booked.
Okay. I was coming up with.
Let me add to that. We did raise the amount of reserves we're placing on a PUD from nine Bcf to 10 Bcf.
Again, that's sort of a placeholder number until you have the lateral lengths designed there.
That's right.
On the locations that you've booked, I'm estimating something like you have a little more than 300 PDP locations and a little more than 200 pad locations total in the Marcellus now. Am I in the ballpark?
Yep, that's ballpark. Excuse me.
Okay. 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 before?
Absolutely. The Upper Marcellus has began on a course just as our Lower Marcellus did. Keep in mind, several years ago, before we had the data, we started out at bookings of less than five Bcf per Lower Marcellus well, 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 Upper Marcellus, we have some flow history from those wells now. I think you are saying that we are in the middle of marching that number up.
All right. Great. Thank you.
Thank you.
The next question will come from Gil Yang of Discern. Please go ahead.
Good morning. Thanks for taking my question.
Gil.
Hey, Dan. The EUR per 1,000 foot was up about 6% when I do the math. 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're getting from the tighter frac spacing, or do you think there's much more to go in that opportunity?
No, we're not. Again, keep in mind that we like everything we're seeing on the curve fit early time on our downspacing. Downspacing, regardless of where you are, downspacing on the pilot programs takes time to look way out and to see the ultimate results of that downspacing. Right now, all we can say, because that's all we have, is that we're very pleased with the downspacing, and it's fitting what our expectations would be on a curve fit that would not indicate we should have concerns about how far we've downspaced those wells.
Dan, just to be clear, I was asking about the frack spacing in terms of on one lateral, 200-foot versus a 220. Is that what you were referring to when you said downspacing?
No, I'm sorry, Gil. I was talking about the distance between lateral lengths.
Between lateral lengths.
I wasn't talking about frack clusters. I misunderstood your question.
I was just asking that as you put the frack clusters tighter together, you decrease the spacing between the clusters by about 12%, but the EURs per 1,000 foot went up by about six. It sounds like you're getting into a regime where the frack clusters are interfering with each other.
No, 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 that standard deviation is pretty tight.
Okay. Maybe there's some opportunity to put them even tighter than 200 foot?
Yeah. Let's back up a ways. We had, at one time, went all the way down to about 150 feet. We don't have many samples of that. The completion techniques are modified just a little bit continuously as we go, whether it's pump pressures or amount of proppant or whatever. I know 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 have a number of different things that they're doing out there on a stage here or stage there, or well here or well there. We'll continue to look at how we can squeeze efficiencies.
Okay, great. Just second question is, the $0.76 cash cost for Marcellus, could you break that into the direct operating cost and transportation and anything else?
I'm looking at Scott. What's your question, Gil?
The $0.76 you highlight for the Marcellus cash costs, can you just break that down into its components?
I can give you total company. Total company LOE is anticipated this year to be $0.25. Transportation has a low $0.60 handle 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 tax is [inaudible] , $0.5.
All right, thanks.
Thanks, Gil.
The next question will come from Bob Brackett of Sanford Bernstein. Please go ahead.
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?
No, we have not quoted that, Bob.
Okay. That was the short one. The longer one, given how big you are in northeast P.A., have you ever looked at the elasticity of your price versus supply? Could you guys literally choke back pads, put less supply into the grid, but earn a higher revenue?
Well, since we've run a number of sensitivities, we always do with our budget and price deck. In your example, if you make the assumption that we reduce to a certain level and price is a corresponding rebound, certainly that would hold true. In practice, in our actuality, would that result happen? I couldn't tell you. 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. We did that last year when the day markets on the small percentage of our gas that we sold in the day market, if the differentials got too high, we said we weren't going to sell that gas into the day market.
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-$4, I'm comfortable with that.
Okay. You're comfortable that you can reduce production without damaging any of the reservoirs or the program?
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 there's not any liquids in, no water, no liquids in the reservoir. Typically, if you have concerns in opening up and shutting in, opening up, shutting in, and letting 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.
Thanks.
Mm-hmm. Thank you.
Our next question will come from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.
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 6 rigs through next year?
Well, in 2014, we'll have over 3,000, right at upper 2,000 wells, frack stages put on. Anywhere from 2,600, 2,800, something like that. We haven't given any guidance for 2015.
If you run the same number of rigs, would it probably be about the same number? Is that a reasonable assumption?
Well, if we ran the same number of rigs in 2015?
Right.
If we ran six rigs in 2015, it depended on how far down we took our backlog that we'd have going into 2015 and towards the end of 2015, 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 2015, we'll have a smaller backlog, but we're still going to have a significant backlog going into 2015. If we keep the same number of rigs and we continue to chip away at the backlog, we could still complete the same number of stages or more with the same number of rigs.
Okay. That's helpful. On the weather-related downtime and compression station runtime in Q1 and Q2 of this year, do you have a feel for how much that impacted production, how many million a day was impacted in Q1, and what you're factoring in for Q2?
Yeah. I don't have it at my fingertips, Marshall, at this time. There were days that we were $100 million down, $150 million down, and the other days we were $25 million down. As a swag number, $75 million a day, ±.
For each quarter?
Well, we're still in the tip for the first couple of months of 2014, Marshall.
Okay.
Yeah.
Final question. On the Upper Marcellus, when will that start to get significant capital, or will it still be a When would you expect it to get a significant number of wells drilled there?
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-pads, as indicated by 60% of our program drilling from pad sites that well five or more wells. Along with that being said, we will continue to look at various different points that we'll place Upper Marcellus wells just to continue gathering our database. Again, operation prudence says complete the lower wells first, 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.
Okay. Thank you.
Thank you.
Our next question will come from Brian Singer of Goldman Sachs. Please go ahead.
Thanks. Good morning.
Hey, Brian.
You talked on how you'd re-look at differentials quarterly in your view there. How does that impact how your capital allocation process works and what you'd need to see to add another rig? Or maybe a better way to ask it is, what differential should we expect when your long-term solutions, like Constitution, are in place? Do you see keeping your rig count flat until then?
Well, there's not going to be a lot of swing in our budget in the first half of 2014. Typically, when we've made some adjustments, it's been in the second half of the year. I would expect that 2014 will be no different than that. When you look at what our expectation would be on a forward look. 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. That is moving to, and you can go to indexes aside from some of the current ones on Transco, Leidy or the Tennessee line. As you move away from those two lines, it is apparent that the differentials improve considerably, in different markets and price points.
All of that gas that I'm talking about in these new ventures will be at different price points than what we experience today.
I guess when you layer in the transport costs associated with that, what does that get you back to? You may have mentioned, I think, a $3-$4 number in terms of it. I wasn't sure whether that was in reference to an ultimate realization earlier in the call. Maybe you could add some color on that.
Yeah. 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. 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 Iroquois line or the non-New York area that we might be going into. Those are going to be similar to our expectations also-
Great
on realizations.
Yep. Thanks. Lastly, on the stock buyback, what should we expect going forward? Do you see ultimately your buyback program, including what was done in fourth quarter 2013 exceeding your asset sale proceeds?
I don't want to cut. We're going to go through the year, we'll make that decision excuse me, more opportunistically. Again, the value of Cabot and 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. 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. In fact, if we got beat up too much around the ears, I'd add to my position, personally. I see us having a significant opportunity behind the headwinds and that we face in the differential side. I'm optimistic that the market is going to rationalize the differential.
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. 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 a May release by FERC. We'll deal with it. Again, I'm here for the long term, we'll deal with that, and we'll manage our program in a prudent manner as we always have. Frankly, we'll still be able to deliver not only an operationally impressive program, but a financially impressive program at year-end.
Thanks, Dan.
Yeah. Thank you, Brian.
The next question will come from Charles Meade of Johnson Rice. Please go ahead.
Good morning to you, Dan, and the rest of your team there. I wonder if we could just pick up on that point about Constitution a bit. Recognizing that Williams is the operator there, can you maybe be a bit more explicit on what your current plans reflect on when that line will come into service for you? Could you possibly talk about if there's any local permitting that you still have in front of you, or if what you got last week with the EIS is really the last definitive thing to look at?
I'm going to pass this to Jeff real quick, but my comment on the timing that we're working with, as I've stated in this comment on my teleconference here, that later 2015 is our hope that we would be able to secure all the remaining permits and some being local. The outside would be moving into 2016 a little bit. I'll let Jeff make any comments that he might have.
Sure. Okay, Charles. As you know, we all knew this would be a three-year process through the FERC and the way they operate. Quite frankly, we're very pleased how the FERC has handled this process and the issuance of the draft EIS. Those are all very positive steps. In terms of the schedule itself, I'm sure you read Williams' transcripts 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, and has shared that with some of the owners, or with the owners, that there's a little bit of resistance at the state level in getting some permits generated from the DEC.
That's something that Williams is working through on the government relations side, on the regulatory side, and we continue to get the updates from them. The process is working good, but it does take state permits, as well as federal permits to get the project built.
Got it. Thank you. I had seen that yesterday with Williams. I was curious if you guys had any different take on it. That's good color, Jeff. Thank you. 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 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 sole most important project, or is it still the biggest thing for you guys?
Well, it's the nearest term, Charles, 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 he has found additional pathways for over 400 million cubic foot of gas in being able to keep moving our gas into the marketplace. 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. That is just with a couple of pipelines going out of a high supply area, that it pushed the gas on gas competition in the center stage. We do have a vision out in front of us that we're going to be accessing what has typically been very good demand areas, and very good price points.
We know where we're going is also expanding demand areas that will bode well for the future.
Thanks for taking that question Dan, Jeff. I appreciate it.
Thanks, Charles.
The next question will come from Jack Aydin of KeyBanc Capital Markets. Please go ahead.
Good morning, guys. How are you?
Hey, Jack. Good, thanks.
Good. Most of the questions were answered, but just a couple ones. What are you budgeting for well costs on the longer lateral for 2014?
Jack, between 6.8 in the Marcellus-
Yes
coincidentally, in the Eagle Ford. $6.8 million-$7 million.
Okay. Now, if I look at the data, what you said, you have about 200 pads booked at 10 Bcf. You're drilling about 100 wells with extended lateral closer to 5,000 and using the 3.6 Bcf per 1,000 foot. Are you going to revise your EUR per wells mid-year, or are you going to wait until the year-end?
We will continue with our MO, and that is looking at year-end before we actually do any public reserve announcements.
Okay, thanks.
Yeah. Thank you, Jack.
The next question will come from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.
Good morning.
Good morning.
Dan, I'd like to return to the Eagle Ford. Your recent 2014 Eagle Ford guidance was for 40-50 wells. Does the 50 well count reflect pushing the pedal if the six-well pad results are positive, or could we get beyond 50 Eagle Ford wells if the pad is successful?
Yeah, with our guidance right now and what we've done, if we added, depending on timing, another rig, we could ramp up. Frankly, on our guidance right now, Jeffrey, we're at the 36 to 38 type of Eagle Ford wells right now, and that's incorporated already in our guidance. Moving that up to even 50 would be a impactful move for our current guidance.
Great. Thank you. That's helpful. This is a little bit broader, your current discussion of the Eagle Ford pad drilling is highlighting increased lateral length. When do you think Eagle Ford downspacing tests might be relevant to think about?
Jeffrey, we have already had quite a bit of production coming from downspace laterals at 400 feet, even though we have some term on those, we are very comfortable at 400 feet. We will be doing some pilots at 300 feet.
Okay. My last question is really pretty broad, I just wanted to ask it, that's, with the Marcellus significantly outperforming the Eagle Ford on returns, can you give us some idea of what's the objective of the current new ventures program, what are you looking for? How actively is it out there being in the weeds?
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 exploration wedge out of our capital of $1.3 billion-$1.4 billion. We'll utilize that exploration wedge to further evaluate whether or not these greenfield areas will compete for future capital.
Okay. Thanks very much. That's it for me.
Thank you, Jeffrey.
Our next question will come from Matt Portillo of Tudor, Pickering, Holt. Please go ahead.
Hey, Matt.
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.
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.
Great. My second question moves to 2015 marketing, as you guys have mentioned, you'll be watching the gas price to determine your acceleration plans. How do you guys think about the 2015 market dynamics as you look at incremental takeaway capacity from the basin and with the market as it stands today? Should we be expecting a relatively flat rig count, or is there potential for acceleration as you see some incremental pipes coming on stream?
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 in the differential impact today. I think everybody is trying to guesstimate what type of impact the midstream market and new takeaways are going to have on the market. From where it is today, I think it is only going to improve as you're able to access additional markets, as the demand continues to improve in areas that not only are currently being served, but the new markets that are going to be established on new infrastructure build-out. Certainly, there's going to be an impact from the LNG facilities that will start coming on stream as we look out into the latter part of 2015.
I think all these dynamics are going to improve price points in different areas. Again, our objective has been not only for 2015, but what we've tried to do in 2014, marketing our gas, but 2015 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 of what I'm saying.
Great. One last quick question from me. You guys continue to see your rates of return improve with tighter spacing and longer laterals. I was hoping to get just maybe a bigger picture view over the next few years as to where you think your lateral lengths could move to in the play as you look at your total acreage position. Thank you.
Well, we think certainly 2014's going to be longer laterals than 2013, and I don't have that exact comparison for our 2015 program. Suffice it to say that our objective will be to lay out an operational program in a way that will maximize the efficiencies of our dollar.
Thank you.
Thanks, Matt.
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.
Well, 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've identified it as a finite period because I do believe as we move out into the midterm, 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 I kind of equate it similar to the way I'm looking at my views in the political life and what this country is faced with. 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.
I'm looking forward also operationally for Cabot as we move forward to not only our infrastructure build-out 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. Appreciate everybody's patience, and we'll look forward to the next quarter call. Thank you, Denise.
Thank you. The conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.