Cabot Oil & Gas Corp (NYSE:COG)
Q4 2015 Earnings Conference Call
February 19, 2016, 09:30 ET
Dan Dinges - Chairman, President & CEO
Scott Schroeder - EVP & CFO
Steve Lindeman - VP of Engineering & Technology
Jeff Hutton - SVP of Marketing
Charles Meade - Johnson Rice & Company
Michael Glick - JPMorgan
Pearce Hammond - Simmons & Company
Jeffrey Campbell - Tuohy Brothers
Bob Bakanauskas - JMP Securities
Brian Singer - Goldman Sachs
Marshall Carver - Heikkinen Energy Advisors
David Beard - Coker Palmer
Mark Hanson - Morningstar
Karl Chalabala - SunTrust Robinson Humphrey
Jon Wolff - Jefferies
Dan Guffey - Stifel Nicolaus
Welcome to the Cabot Oil & Gas Fourth Quarter 2015 Earnings Conference Call. [Operator Instructions]. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President and CEO. Please go ahead, sir.
Thank you, Carrie and good morning to all. Thank you for joining us today for Cabot's fourth quarter and full-year 2015 earnings call. With me today, as usual, are several members of Cabot's executive management team. Before we start let me say that the standard boilerplate regarding forward-looking statements are -- included in this morning's press release, applies to the comments on today's call.
This morning's press release, along with our press release from two weeks ago outlining our updated 2016 budget, highlights that while our industry continues to struggle to adjust to persistently low commodity prices, Cabot remained well-positioned to navigate through this challenging market environment due to our high-quality asset base, low-cost structure, strong balance sheet and our capital discipline.
While most financial metrics were down year-over-year, admit a backdrop of lower commodity prices, I am pleased with our overall report card for the year which included 13% production growth despite continued price related curtailments and a significant reduction in capital spending. Additionally, we grew reserves 11% despite reduced operating activity and lower SEC prices used in calculating year-end reserve. I believe these results highlight the quality of our assets and their ability to generate positive result in most commodity price cycles.
Our ability to grow production and reserves in a capital efficient manner is certainly impressive equally as pleased with the continued reduction in our cost structure throughout the organization. 2015 marked another year of lower operating costs and finding cost for Cabot, driven by a combination of internally driven efficiencies and lower service cost. This reduction in cost has allowed for improving project level economics despite lower commodity prices and positions the Company well for the eventual recovery in both natural gas and oil price realizations.
Capital discipline has been a hallmark of Cabot strategy over the years and 2015 was no exception. We ended 2015 with a capital program that came in 14% lower than budget while still delivering on our production guidance for the year. This reduction in capital spending was especially apparent in the fourth quarter as we generated positive free cash flow despite realizing our lowest price for the year. Our previously announced 2016 budget also highlights the Company's financial discipline with another 58% year-over-year reduction in capital spending. We remain committed to our prudent capital allocation strategy and will strive to continue to improve capital efficiencies throughout our operation which we believe will result in continued value creation for our shareholders.
As I highlighted to our shareholders over the last 18 months, our game plan has remained relatively unchanged during this down cycle, giving our strategy has always been to first maintain balance sheet strength while also align our capital spending with anticipated operating cash flows and allocate capital to our highest return projects. We also run a lean, efficient operation in order to keep operating costs, including low overhead. And we focus on delivering long-term value creation from our high-quality asset base. This strategy has allowed us to prosper in most favorable price environments and we think we will continue to be able to navigate successfully through this current downturn.
Now let's move to the Marcellus. 2015 was another successful year for our Marcellus program which generated positive free cash flow for the year despite lower natural gas prices realizations. We continue to allocate the majority of our capital to our high-return asset in the Marcellus which still generate good returns despite the low realizations.
We averaged approximately 1.5 Bcf per day of net production despite curtailing over 75 Bcf of net production during the year. This surplus curtailed volume at year end gives us significant flexibility this year and allowed us to reduce capital spending substantially year over year with minimal impact to our production.
On the operations front we went from three drilling rigs in the fourth quarter down to one rig in the mid-January. We're currently running one frac crew on daylight operations only and plan to continue at this pace throughout 2016. With a decrease in drilling activity, we plan to work down our backlog of drilled uncompleted wells throughout the year from 63 at year-end 2015 to 48 at year-end 2016. This inventory, along with expected curtailed year end volumes, provides us with flexibility to ramp our volumes in 2017, assuming both a timely in-service for Constitution and Atlantic Sunrise and an improvement in realizations in Appalachia.
Our team in the Marcellus continues to improve their operating efficiencies which is evident from the reduction in well cost by over 30% relative to the prior year. We expect to average a 7,000 foot lateral from 2016 Marcellus program at a well cost of approximately $6.7 million or approximately $960 per lateral foot. This well cost does include all capital associated with roads, pad build-out, production facilities and things of that nature.
On the operating cost front, we continue to see a reduction in our per unit cost with direct OpEx decreasing to $0.04 per Mcf and total cash cost per unit decreasing to $0.82 per Mcf with gathering and transportation being the biggest component.
In this morning's press release we announced an increase in our Marcellus EUR guidance as well as a 15% increase in our Marcellus inventory to 3,450 locations and an increase in our lower Marcellus guidance per EUR per 1,000 foot from 3.6 Bcf to 3.8 Bcf, further reinforcing our estimated recoveries as best-in-class across the entire Marcellus.
Pricing remains the biggest challenge for us in the northeast PA; however, we're optimistic about the future, giving the significant reduction of activity in our operating area which should ultimately result in a reduction of supply. For example, in the six county area in northeast PA that accounts for over 8 Bcf per day of natural gas production, there are currently only four rigs operating and four daylight-only frac crews working.
While no one can refute the wells in this part of the state are very productive and there is a backlog of wells still waiting for completion that can add volumes to the mix with a relatively limited capital investment, these production levels are simply not sustainable based on the reduced level of activity we see today. This could set us up for a favorable rebalancing of supply and demand later this year or in early 2017 which could certainly greatly benefit Cabot.
While it is far too early to provide any significant details on our plans for 2017, I would highlight that our unique set of assets in the Marcellus provides us with optionality as we assess our plans for the future. If market conditions improve and our takeaway capacity is placed in service according to our current expectations, then we can deliver on a program that generates double-digit production growth in 2017.
More importantly, this program can provide even greater cash flow growth due to increasing margins as we assess more favorable markets, all while deleveraging the balance sheet of today's strip. However, if there are any unexpected delays in infrastructure build-out or, more generally, market conditions remain depressed, we have an asset that requires minimal capital investment to maintain flat production. In that scenario, while top-line production volumes would be flat, we would still realize significant cash flow growth in 2017 due to improving price realizations while generating free cash flow and deleveraging the balance sheet.
While there is still a lot of uncertainty on how market conditions will evolve over the next 12 to 24 months, we're fortunate to have this set of assets that allow for this type of flexibility as we weather the storm.
Moving down south into Texas in the Eagle Ford, our team experienced another exceptional year operationally which was unfortunately overshadowed by lower crude prices. Our drilling team continued to outperform expectations reducing our spud-to-TD drilling days for a 7,700 foot lateral to eight days. This has resulted in a 45% reduction in drilling cost relative to 2014, almost all of which was driven by internal efficiencies as opposed to service cost reductions, given that our rig was under a long-term older contract priced environment during the year.
The team drilled is longest lateral to date of 11,588 feet in 11.6 days from spud to TD with the total measured depth of 19,930 feet. Kudos to the drilling team. Additionally, the rig we utilized during 2015 ranked second in total footage drilled among the roughly 200 rigs that our third-party provider contracted throughout all basins in 2015 -- another good indication of our efficiency.
We do anticipate an eventual recovery in oil prices and we believe our 86,000 net acres in the Eagle Ford can provide for long-term value creation in a slightly more favorable price environment. As a result our focus in 2016 is to reduce our operating activity to the minimum levels needed to ensure we maintain all our core acreage.
We recently released our Eagle Ford drilling rig. Based on our anticipated level of activity, we will be able to maintain all of our lease-hold obligations through 2016. We exited fifth 2015 with 23 net wells, drilled but uncompleted and we'll work down some of that inventory throughout the year due to conditions -- continuous operation commitments which should help arrest some of our natural declines we see in the field. We plan to exit 2016 with 13 net drilled uncompleted wells in our backlog.
Now move to the approved reserve results. In this morning's release we announced our sixth consecutive year of double-digit reserve growth which is truly an impressive, giving the increasing trend of declining reserves across industry due to price related revisions. Our year-end reserves increased 11% to 8.2 Tcfe, despite a 40% and 47% reduction in natural gas and oil price realizations used in our reserve report, respectively.
Cabot's all source finding and development cost for the year were $0.57 per Mcfe while our Marcellus all source finding and development cost were $0.31 per Mcf, both significantly lower than prior years, driven by strong performance revisions in the Marcellus as our well performance has continue to exceed expectations. Approved developed percentage decreased slightly from 61% in 2014 to 59% in 2015, primarily as our percentage of proved undeveloped reserves associated with drilled but uncompleted wells increased from 7% to 11%. 2015 is another positive year report for Cabot, especially in light of the environment we're operating in today.
To get to Constitution, I'm sure it's on many of your minds. Recently we had a flurry of activity surrounding Constitution Pipeline. While we do not have specific details we can share today regarding our final permit issuance, I can assure you that discussions to have the permit issued as soon as possible are ongoing.
As a backdrop of 2016 activity, on January 8 Constitution asked FERC for a partial notice to proceed with non-mechanized tree clearing. On January 29 FERC issued the Notice to Proceed for tree felling but limited our activity at this time to Pennsylvania. Tree felling began February 5 in Pennsylvania. As of today, approximately 60% of the trees in Pennsylvania on the Constitution right-of-way are down. This represents approximately 18% of the trees for the entire right-of-way. Additionally, the FERC is still considering our request for felling trees in New York.
Also, on January 28, the FERC issued an order on the pending rehearing request regarding the December 2014 order that issued our FERC certificate. The order thoroughly considered and firmly rejected all arguments and ultimately declined all requests for rehearing -- another positive step for Constitution.
Moving on to the Atlantic Sunrise project, as a reminder, this new pipeline will transport 850,000 decotherms on Cabot's behalf to markets in the Atlantic -- in the mid-Atlantic area. To date, the project remains on schedule with initial pipe shipments already on location and the draft environmental impact statement expected shortly from the FERC.
Before I move on, I would like to make one quick point on perceived versus real impact of pipelines. Bottom line, pipelines get buried, the right-of-way gets reclaimed with a much faller footprint than renewables. In the case of Constitution, there are approximately 1,100 acres of right-of-way. For example, for solar to produce an equivalent level of power generation it would require instead of an 1,100 acre foot right-of-way of a buried pipeline, solar equivalent would take 25,600 acre footprint of solar panels. And for wind, on an equivalent level of production as Constitution might produce, it would require approximately 2,000 turbines spread across 260 miles which is double the length of the Constitution buried pipeline right-of-way. Certainly staggering differences, yet the narrative is not discussed much. Again, just fun facts.
In addition to Constitution and Atlantic Sunrise Pipelines, Cabot is also involved in three other significant projects in the Northeast beginning in late 2017, the PennEast pipeline, Tennessee's Orion pipeline and the Moxie Freedom power plant. Collectively, these projects add approximately 445,000 decotherms per day of new long-term sales and transport capacity for Cabot.
Our involvement in the Moxie Freedom project is especially unique as we will be the sole supplier of up to 165,000 decotherms per day of natural gas to this new facility located just a few miles away from our existing infrastructure. These projects highlight our ongoing marketing strategy along with other projects in the queue.
Another marketing related item I would like to highlight is our mix of firm sales and firm transportation capacity moving forward relative to our planned production profile. There has been a lot of discussion recently around the industry about capacity being over-built and the significant commitments and liabilities that producers have subscribed to over the past few years.
While we have been questioned during the past few years for not having enough firm transportation out of our supply area as the Northeast market became over-supplied, longer term, I believe our strategy of not over committing to FT and instead focusing on high-quality capacity with strong demand on the other side of the pipeline, is the appropriate strategy. As a result, we feel our overall marketing strategy and the modest amount of commitments we have going forward will continue to provide significant growth from our future production plans and continue our long-term strong financial position.
I'll move to our guidance -- brief comment there. As a reminder, earlier this month we released our updated guide for 2016. Our updated budget of $325 million was designed to allow us to spend within operating cash flows at strip prices while still providing measured growth in 2016 in the 2% to 7% range. We also anticipate between $80 million and $150 million in contributions for investments in Constitution and Atlantic Sunrise which will be dependent upon the ongoing regulatory process and the corresponding impact of the timing of actual construction activities.
Drilling completion and facility capital account for approximately 92% of the capital budget with approximately 70% allocated to the Marcellus and 30% allocated to the Eagle Ford shale. In total, we plan to drill approximately 30 net wells in 2016 and complete approximately 55 net wells. This level of activity allows us to meet all of our obligatory drilling and operating commitments and maintain operating efficiencies throughout the program, while our anticipated year-end backlog of 61 drilled uncompleted wells Company-wide provides us flexibility into 2017.
As for pricing, we're currently forecasting a Company-wide natural gas differential of $0.70 per Mcf for the full year before the impact of derivatives which represents a $0.15 improvement relative to our 2015 differential. Obviously, this overall program is dependent upon the reference to infrastructure projects and their timing. If delayed, these numbers could move lower.
In summary, that is our program. And, Carrie, I would be more than happy to answer any questions.
[Operator Instructions]. Our next question will come from Charles Meade of Johnson Rice. Please go ahead.
Thank you for your comments and I particularly appreciated the fun facts session. But if we could go back to -- you have already touched on a lot of these themes. But if I could try a question that would maybe tie it together.
Looking ahead to the time when you have the more takeaway and more local demand, how should we think about the cost and the number of wells that you will need to turn the line to fill up those new pipes? And with this -- what I'm really after is how should we think about your capital efficiency? Because it's hard to judge, based on your results, because you guys have been infrastructure constrained for so long. So when you look to the day -- you have to deliver another 500 million a day, how many wells and how much capital should we think about that requiring?
That's a good question. And we have certainly put together a five-year budget. We don't layout our five-year budget but we talk about it. And we look at all of the scenarios, both upside, downside and a lot of sensitivities.
But as you roll forward into 2017 and looking at fulfilling our growth opportunities with additional infrastructure, in 2017, as an example -- and let's look at it historically, Charles and historically we have never been over six rigs. And we have had the majority of the time one to two frac crews, episodically we have had three frac crews on a one-off pad site or something like that. But typically in the past we have never been greater than two frac crews.
When you roll into 2017 and looking at our buildup of our program in 2017, we do not envision to get much greater, if greater at all, than the six rigs and two or so frac crews to fulfill our additional infrastructure capacity that we create.
And this is maybe a follow-up to that and the part of the same question, I suppose. When you mentioned 75 Bcf was curtailed or you ended up behind choke in 2015, by my math that works at around 200 million a day, is that the right number for year-end 2015 or is year-end 2015 that number a little lower?
No. And keep in mind that 75 Bcf is a net number and also 2015 at year-end it was higher.
Our next question comes from Michael Glick of JPMorgan. Please go ahead.
Maybe just to dovetail on Charles' question a little bit, as it relates to new pipes, how should we be thinking about price points where you grow versus displacing existing volumes and maybe how much flexibility you have on that point?
Okay. That's a good question, Michael. And certainly the macro environment at the time of commissioning of new infrastructure is going to play in our decision on how much will be acceleration incremental volumes, if you will, versus how much is going to displace off the three pipes that we're currently producing on. And I'll let Jeff answer some of this in a brief second.
But in the beginning, Michael, I think it would be prudent for us to fill the new infrastructure first because the price points we're going to be receiving on the new build is going to be a price point out of the challenged realizations that we have had either on Millennium, Tennessee or the Leidy Line. So we would fill that immediately and there will be a transition period of the backfill of the displaced volumes that we put into the new pipes. And we will continue to, again, backfill.
But we do expect that we would probably see with the volumes that we would be lifting out of the current area and off of our current three pipes, we do expect to see a compression of the deferential. And when you look at the timing of commissioning of those -- the new pipes out of that area, we think it could be contemporaneous with an inflection point of the supply side due to the limited amount of activity up in that particular area as we speak.
So there's going to be a combination of things that will help dictate and set the table for us on how we would grow into that new capacity. I will also say this though, we're delivering returns today and we're in a -- been in a punitive price environment and realizations, more so than most, for an extended period of time.
The program still, today, delivers free cash flow with good returns. The incremental volumes that we move into, new areas with, we think, improved realizations is going to -- even in spite of keeping the current strip, we think is going to significantly improve our life from where we're today.
And could you maybe just speak to how you're thinking about leverage and maybe what leverage ratio you're comfortable with kind of over the next year or year and a half.
You want my opinion and then Scott's?
Well we certainly have tried and I think we have done a good job to keep our balance sheet with strength and allowed optionality on our program. And lower realizations have certainly pressured everybody's balance sheet and we're seeing it now in the market. Not only in what's going on out there with a lot of companies but certainly the reduction in capital programs is reflective of a balance sheet. But I will let Scott discuss our leverage and he can lay out what he is comfortable with. And I will weigh in if I need to.
Well you better weigh in. Michael, we're comfortable with where we're at. As Dan said in his comments, we have always tried to target and our guidance highlights that also, that we're trying to stay -- create a capital program that is right on top of where -- or inside of the anticipated cash flow based on the assumptions. Now the one caveat to that is we do have the two infrastructure projects that we're watching very closely and its impact on our leverage and looking at what levers we may or may not need to pull on that as we go forward.
As you look back in history, Cabot has always done a great job of -- when it did want to ask to expand capital in better markets, it used the combination of asset sales and the like to make -- hit our desired levels and kind of maintain our financial strategy. And that is no different today, although that market, that asset sale market is very challenged. And you hear a lot of people that are going to be there. But we're very comfortable with the base plan. We're comfortable with the low 50% debt to total capital.
Our year-end number 2.5 times -- obviously just the math will move up. We would like it to stay at 2.5 times. But clearly with the underlying commodity prices and where cash flow is it is going to move up some during the course of 2016 which we're comfortable with. Because as Matt laid out in Dan's comments, we see a delevering event in 2017 just by the nature of these infrastructure and what our new volumes will get to. So we're very comfortable where we're at right now.
Our next question comes from Pearce Hammond of Simmons & Company. Please go ahead.
My first question, just following up on Charles Meade's question, is how much production was curtailed at year-end 2015? And then how much do you think could be curtailed at year-end 2016 if you assumed the current ford strip and your differential assumption?
300 million to 400 million.
300 million to 400 million at year-end 2015?
At year-end 2015, yes.
Okay, and then what about year-end 2016? I know that's hard but--
Year-end 2016 -- that is a hard one, Pearce. Kind of depends on the macro market. We do think we're going to have, as I indicated, we do think we're going to have volumes available to us to be able to respond to the infrastructure build-out that we anticipate to occur in 2017. But it's a hard number and I don't have the exact number. It is a hard number two project in year-end 2016.
And then what is your base decline right now? And then I was intrigued with your prepared remarks. And you mentioned in 2017 you felt like even if some projects were delayed that you could still generate -- you can keep production flat, you could generate free cash flow and continue to delever. So I was curious some of the assumptions around that as far as what base decline might be and maintenance CapEx.
Base decline is 25%, 28% or so -- is the base decline. And CapEx, as we indicated in some of the comments in the speech, to keep that production level maintained flat, it is going to take very little capital intensity and activity to be able to do that into our 2017 program.
Our next question comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
First question I want to ask is I just wanted to make sure I understood the Eagle Ford. It looks like you're not running a rig there now but you're going to drill five wells. So can you just add some color as to when you're going to get a rig or how that's going to take place?
Yes. We have Steve Lindeman in here who's running our region -- south region and can comment on that.
We have drilled three wells to date and released the rig. And then the two remaining that we have will be late in the year. We've got one -- I think it's in August timeframe and then we'll come back in December.
I wanted to ask a different pipeline question. And as a New York State resident, I guess I'm not really happy with them, but to your knowledge, are there any examples of FERC ultimately superseding state authority and forcing the construction of a FERC-approved pipeline after a sufficient period of stalling on the part of the state?
Jeff, I don't know if that ground has been plowed yet. And there is a number of considerations. And as you might appreciate, we have looked at all angles and all options and all scenarios on getting to the commissioning and construction stage of Constitution. We do think that there has been adequate amount of time and deliberation in New York. 29 months is the process to date.
So we have had great discussions in the past with New York on trying to address all concerns and mitigate the -- each stakeholder's concerns about laying the pipeline, how it would be done. We have rerouted, we have discussed about stream crossing and how to bore, how to open cut, all of those things. In this environment and in the environment we live right now there is certainly a contingent out there that don't want hydrocarbons in the mix. And that contingent is vocal and they speak out.
There is a belief that we have that the Constitution pipeline, from what we have been able to tell from the Governor's of New York's plan and looking at the energy future for New York, natural gas is an energy source that is required for him to be able to fulfill his plan. So we think we're going to get to the endgame and we certainly would like the input of New York into the process and all of the work that we have done in the past to be used to -- actually for us to follow to the endgame on Construction for this pipeline.
The FERC has a job to do also. They have a fiduciary role to the public to have projects move forward. They have a lot of projects in front of them. Certainly their jobs have become more challenged in the world we live today. But nevertheless, I think they have a job to fulfill to be able to take all parties issues under consideration, look at the validity of all of this considerations and make prudent decisions that is best for the public's need.
And we think they will do that. But I do not think, Jeff -- again, back to your -- the core of your question, I don't think it's ever been challenged yet through the court system that the FERC is going to have to override a state's either lack of response or a negative response.
Well I appreciate that comprehensive answer. And I guess just a follow-up to that and then I'm done. How do you see the FERC backing down on the tree felling in New York State as part of this fed-state dynamic? Or does that say something potentially about their view that some kind of resolution of this coming sooner than later? Do you have any opinion about that?
Yes I do. First off, just from a chronology standpoint, we had early approvals from Pennsylvania in regard to the 401. And we had -- and we have the ongoing delay from New York. In FERC making that determination, they felt like that they had all of the things they needed to see handily to be able to rule on the right-of-way in Pennsylvania.
And during this period of time, the FERC has worked diligently to look at all aspects of their ongoing decision process to grant non-mechanized tree felling in New York and make sure that they have addressed all concerns that might be out there by all of the stakeholders. The rulings have certainly made clear what authority they have. And we think, in due time, that FERC will make a decision in regard to tree felling in New York.
Our next question comes from Bob Bakanauskas of JMP Securities. Please go ahead.
Just a follow up quickly on Constitution, given the FERC -- given FERC rejected the request for the rehearing, what has been communicated to you as the reason for the delay at this point?
I will turn it over to Jeff, Bob.
Bob, I'm sorry, I heard the first part of the question. I did not hear the end. Do you mind repeating?
Sure. Given FERC already rejected the request for the rehearing, what has been communicated to you guys in terms of the delay now in New York State in terms of the reason for the delay?
Okay. So in New York State, the communication has been sparse. But we do understand that the application itself has been thorough. There has been no data request to supplement it. There has been no routes or reroutes requested. But just don't have a good answer to that question except to say that it's been fully considered and it's on the -- we think it's on the verge of being issued.
And just can you remind us on the timeline in terms of -- I know it's sort of a difficult thing to answer given you need the final approval from New York State. But can you just remind us of how you're thinking about -- do you need the permit in the next couple of months to get it on by the end of the year? Are you assuming that 2017 at this point? Or just generally, can you put some parameters around it?
We're still sticking with the fourth quarter 2016 as our in-service dates. Our time is running out but we still have weeks. And we used to have month but now we have weeks. But we still are good with the second half of -- or late 2016 in-service.
Bobby, I might add also that we have crews cutting trees right now. We have additional personnel that we anticipate being able to utilize for felling trees. And we continue to do the appropriate training and mitigation efforts to answer any concerns that any party might have in regard to non-mechanized tree felling.
And then just switching to the Marcellus noticing the longer laterals going from a 5900 to about 7000 feet. Understand that some production is being curtailed at the moment, but just in general, could we assume a proportionate increase in ITs and URs relative to lateral length?
Yes. You certainly can.
Just one more quick one just on maintenance capital. Should we think of this -- the $325 million in 2016 as an ongoing maintenance capital to keep production flat?
I would think that it would be probably $350,000 million to $400,000 million.
Our next question comes from Brian Singer of Goldman Sachs. Please go ahead.
As you watched the Easter movement of the Utica shale into northern West Virginia and southwest PA, how concerned, if at all, are you that this will represent greater long-term competition for you gas to find an accretive home directionally south and west? It's really more of a longer-term question above and beyond Atlantic Sunrise and Constitution and how you weigh the asset quality improvements you have discussed with whether it makes sense to be northeast PA or more diverse beyond your existing Eagle Ford position.
I will let Jeff kind of take some of this. But first comment is in looking at the two areas and you've kind of identified in laying out your question, Brian. But the northeast of where we're, majority of gas is -- goes east and southeast. We do have gas on Atlantic Sunrise which will go towards the south also. Although, all that volume, 850 million is committed right now to WGL and to the co-point LNG facility.
We think that the volume of gas that is out there right now obviously strains the supply demand curve. We think additional demand is coming. We think there will be in the South -- to your point -- in the South and along the Gulf Coast we think there's significant amount of LNG displacement that will occur with some of the supply volumes that are in the South. And we think that we have is equally as good opportunity to be able to market our gas, not only directionally to the east, northeast and southeast up into our area, but we do think that we will be able to market our gas into the South.
More supply -- just on a general note -- more supply, whether it's oil or gas, into a limited demand circumstance is going to be -- is going to have that dynamic of lower prices. We think that maybe through this period of time, looking at what's going on in our industry and looking at the capital programs that have been reduced, looking at the ratings that have been imposed -- public rating -- on some of the companies, looking at the oversupplied market, maybe there would be some rationalization in the market as we move forward also. I'll let Jeff comment also.
Yes, Brian, it's been interesting to watch the last few years as we've gone from 5 Bcf a day from production in northeast PA to the current level of 8 Bcf. And if you examine it closely and look at the meters along the six county area that we produce in, we're actually the null point for the three pipes that we produce in.
So for example, most of our gas that goes into Millennium goes to the east where a majority of the gas out of Bradford, Tioga County for example goes west. Same thing happens in Tennessee and the same thing happens on Transco. So we're -- we like where we're geographically and getting into the pipes. I think with Constitutional and Atlantic Sunrise it enhances that. But I don't see a large over-built situation in northeast PA like we do and southwest PA and the Utica. We feel like that over-built infrastructure will absorb some of the Utica gas but it will definitely head west and northwest and south.
And then separately on the resource side of things, you highlighted the impact that some of the measures you have taken over the last year reducing the spacing along the laterals and then how you do the 200 foot stages and the impact that's had on your resource per well and location count. Can you talk about the 2016 program and whether -- what you're testing in 2016 and to what degree you are able to do that within the capital program that you have set up?
Well we have recently -- on the spacing side we have ongoing wells currently producing that have term production and certainly setting their own production curve that we will continue to utilize and evaluate the spacing that we think we can get down to. We just had enough data -- enough well results to be able to determine that between 700 foot and 800 foot and we were comfortable that stage.
But we will continue to look at it -- down the road we will continue to look at the viability of the spacing that we think we can get down to without the creation of an acceleration profile to our mix. So and with that being said, we have tried all different frac stage spacing scenarios and we have a fairly voluminous database in that regard and feel that 200 foot spacing is a good design.
We continue, though, to look at any of the ideas that are new to industry, whether it's something as simple as more profit per stage or different profit size. All of the things that are discussed and looked at out there by the industry, we will continue to look at it.
And both Steve Lindeman and Phil Stalnaker, who runs our North and South region, they and their crew continue to read and look at and, in some cases, test all the different ideas that are out there in industry that we all hear about and we talk about and they visit with the third-party service sector on what might be applicable to enhance efficiencies in our program. So I don't have anything specific that I will talk about today but we do look at all of it, I can assure you.
Our next question comes from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.
One question around the shut-in production factored into your 2016 guidance. What would your average shut-ins be that's cooked into that 2016 guidance?
It's a number based on timing of when we decide to bring on any given pad location. For example, if we bring on a pad location that has three wells on it versus -- and that -- we still have some opportunities to address where we go with our frac crew. And that movement of where we move a frac crew can dictate how much in a snapshot period of time, our a finite period of time, we would curtail.
If we bring on a 3 well location that has 32 frac stages per well versus an 8 well location that has 40 stages per well the -- and the timing of that is three or four months, it affects the amount of volumes that we might have curtailed for 2016. So it's a hard number to just say exactly what it is. I'm not trying to dance around your question. I'm just saying that it's hard to be specific but it's certainly 100,000 to 200,000 cubic foot per day.
Okay. And on the increased inventory count, is that a mix of upper Marcellus and lower Marcellus and what would the--
Keep in mind just as a backdrop, Marshall, the entire area that we have out there has both the upper and lower Marcellus under our acreage. So as we reduce the spacing in those areas, we will have both upper and lower Marcellus in those additional wells that we're adding to the inventory.
Okay. So it's roughly an even split?
Our next question comes from David Beard of Coker Palmer. Please go ahead.
I just wanted to follow up a little bit to just understand what you're thinking relative to balance sheet and cash flow. Should the pipelines get approved and you say you wouldn't want to go above six rigs, is there an out-spend number which gates how quickly you would add rigs? Or do you think your balance sheet is strong enough that you will bring the production on to fill the pipes or something in between?
Let me give it a stab, David. We feel very comfortable about our balance sheet. We feel very comfortable about being able to ramp up a level of activity to a level that we have already experienced in the past. We feel very comfortable that our balance sheet will be able to handle that level of activity and the outspend being minimal through that process. I'm sorry, the last part about your question --
No. You have answered that just relative to the outspend and the ramp in production -- just try to get your feel there and, no, you have answered it. Appreciate the time and congratulations on nice year.
Thank you, David.
Our next question comes from Mark Hanson of Morningstar. Please go ahead.
So just curious here -- at current strip prices and given your 2016 drilling plans, obviously knowing that things can change over time, where do you envision total debt to EBITDAX ending up at year-end 2016? And if you do get tight, what are some of the levers that you can pull to kind of move around that 4.75 times max under the senior note amendment that was recently filed?
Mark, you are correct. We model the upper 3's the low 4's. We're not -- unless there's a dramatic drop in the strip even further, the 4.75 does not come into play. But we do have some -- as I mentioned earlier, we have some assets that we could potentially trade.
We do have a level of interest -- not committed to doing that but it is an option. We could also slow down activity further if we really decided. And one of the comments is our activity level at 3.25 which we reaffirmed, is contingent on continuing progress on the infrastructure project.
If those get delayed, that spend which is part of our overall analysis, goes down also. So we could conserve capital to manage through that process. Our effort and the amendment process of the covenants was to give us enough flexibility through 2016 and we believe we accomplished that.
Our next question comes from Karl Chalabala of SunTrust Robinson Humphrey. Please go ahead.
I had a couple issues I would like to raise. One, can you give some clarity -- I have June 18 for the startup day for the Moxie Freedom Power Plant over there. Is that good? And then what is the index price that is tied to? And are you in any other conversations with the new power plants up in Pennsylvania?
Yes. You are correct on the in-service for the Moxie plant, June 2018. That could be a little bit early, a little bit later than that but the project has all the financing and is full steam ahead for that facility.
In terms of pricing on the Moxie, we did the press release along with Moxie that the pricing terms on that could also contains a power net-back pricing mechanism so that our gas price does move somewhat with power pricing. However, we also put in the press release that we have natural gas protection -- price protection in the agreement.
So that we have -- I think we quoted in the press release -- a guaranteed high rate of return on the development of the reserves for that project. So in other words, there is a gas price floor that is attractive to us that we haven't revealed. So it's a gas price that moves with power pricing. Yes, on the third part of your question, when we press released the news about Moxie, we had a number of power developers who like the structure and we're in conversations with several.
And then how should -- there's some concerns with the deal with Williams and CapEx spend there. You guys are an equity investor and you have commented that you're continued -- or you're planning to have that spend planned in CapEx. What would -- how should we be thinking about slippage risks for Atlantic Sunrise which does not face the sort of regulatory environment concerns that Constitution does?
Okay. If I understood the first part of your question, you were asking about whether or not we felt that Williams could continue to fund the projects?
Okay. So we have had that discussion with Williams. And I don't know if you listen to the call yesterday or a press release they made a few weeks ago, but they are committed to their interstate projects. They feel any cutback on funding would have to do with expansion of nonregulated interstate projects such as processing plants or even in the gathering infrastructure world where they operate in Ohio and southwest PA.
But they are committed to the funding on the interstate pipeline projects. And I think they even mentioned that they are really not moving ahead with any projects that are in the design phase but are going to concentrate on the ones that are fully committed to and in the queue.
Our next question comes from Jon Wolff of Jefferies. Please go ahead.
I was going to ask about the interesting observation about the pipelines coming on contemporaneously with potentially production slowing or falling in northeast PA. Production has obviously been resilient with other operators in the region not being very active at all. Any evidence that an industry shut-ins are lower than they were and/or any evidence that there is some hope that production in the region can fall and help you gain a little share?
I think the lack of activity drilling and completion, Jon, is going to show up in any curtailed volumes, just like Cabot. Any curtailed volumes that were back earlier in the year and whatever volumes they were, you're going to have some natural runoff with the lack of activity of your base decline. I think that is certainly going on. I can't give you an exact figure of what's curtailed today. But whatever is curtailed today, I think is significantly less volumes than that were curtailed back in the summer of 2015.
All I can really answer is directionally, I'm sure less volume curtailed.
We look at the number of [indiscernible] and a guess we're only able to really see it on statewide basis but any feel for -- I guess you know your own ducks -- but of uncompleted wells counts of -- I would imagine if I had to come down given the rig count has been so low.
Yes. I think that is exactly the case. Ducks are -- will be coming down some and with 4 rigs and 4 daylight frac crews running up there in an area that has 8 Bcf, you could do some real simple math and determine that it's not going to maintain production flat. We get the question, what kind of maintenance capital is necessary to keep 1.5 Bcf or 2 Bcf flat. And you look at that maintenance capital that is necessary and we had the absolute best rock in the northeast area of Pennsylvania.
So that other 8 Bcf, you might note, is not coming from the similar rock as Cabot. It's good rock and I'm not throwing stones at it but it nevertheless -- statistically, it is not as good as Cabot's rock. So 4 rigs and 4 frac crews is not going to keep 8 Bcf flat.
Just out of curiosity, what is non-mechanized tree felling? Is that using in axe or something?
That's a hatchet.
Our next question comes from Dan Guffey of Stifel. Please go ahead.
Transportation and gathering has trended around low $0.70s per m in 2015 -- expected to be there in 2016. I guess as you look at your five-year budget, once Constitution and Atlantic Sunrise are in service, where do you see that trending?
I think it's between $0.85 to $0.90.
And then just one follow up on Constitution. So you mentioned you have a few weeks window to get this online by fourth quarter. Assuming New York sits on their hands and this gets pushed out another month or two, assuming it gets approved in the spring, how far back with the in-service date get pushed?
It would go to the end of the first quarter, end of the second quarter of 2017.
And this concludes our question and answer session. I would now like to turn the call back over to Dan Dinges for any closing remarks.
Thank you, Carrie. I appreciate the time today. And I appreciate everybody's interest. And I can assure you by the results that you've seen in our 2015 program that we're going to be able to navigate through this difficult environment. And we expect that 2016 numbers will be equal to, if not better, than 2015. Thanks again and we will see you at next quarter call. Thank you.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.
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