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Coterra Energy Inc
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Good morning everyone, and welcome to Cabot Oil & Gas Corporation’s Fourth Quarter and Year End 2017 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please also note, today’s event is being recorded.
And at this time, I would like to turn the conference call over to Mr. Dan Dinges, Chairman, President and CEO. Sir, please go ahead.
Thank you, Jamie, and good morning to all. Appreciate you joining us for Cabot's fourth quarter full year 2017 call. With me today are the members of the executive management. I would first like to highlight that on this mornings call we will make forward-looking statements based on current expectations. Also, some of our comments may reference non-GAAP financial measures, forward-looking statements, and other disclaimers, as well as reconciliations to the most directly comparable GAAP financial measures are provided in this morning's earnings release.
On this call, this morning our plan is to discuss the highlights from our fourth quarter and full-year 2017 results, followed by an update on our 2018 budget as well as an update on the company’s current three-year plan. For the fourth quarter, Cabot generated adjusted net income of $59 million or $0.13 per share, an increase of over 10 times relative to the fourth quarter of 2016.
Daily equivalent production increased by 5% relative to the prior year comparable quarter on a divestiture adjusted basis, which reflects the impact of the West Virginia divestiture that closed during the third quarter. Production increased 8% over the prior year comparable quarter. I would also highlight that the fourth quarter represents the seventh consecutive quarter in which Cabot has generated positive free cash flow.
For the full-year 2017, Cabot generated adjusted net income of $245 million or $0.53 per share, compared to a $0.97 million adjusted net loss in 2016. The significant increase in earnings was primarily driven by a 10% year-over-year increase in daily equivalent production, a 36% and 29% year-over-year increase in realized natural gas and crude oil prices, respectively; and a 7% year-over-year improvement in operating expenses per unit of production.
In addition to delivering another year-over-year improvement in our unit cost we also demonstrated our continued focus on cost control in our capital program, highlighted by our capital expenditures for the year coming in 3% below our full year guidance.
During the year, Cabot generated $155 million of free cash flow marking the second consecutive year of positive free cash flow generation. Keeping with our commitment to return an increasing amount of capital to shareholders the company repurchased 5 million shares during the year for a total of 124 million and paid out 79 million in dividends for a total return of capital of 203 million or 21% of our discretionary cash flow.
Our return on capital employed for the year, it increased by over 800 basis points to 7.3%, which is in-line with our weighted average cost of capital. If you were to calculate capital employed net of cash as many of our peers do ROCE increases another 100 basis points to 8.3% for the year. This morning we also announced our year-end proved reserves, which increased by 13% year-over-year.
Our total company all-sources finding and development costs were $0.35 per Mcfe, which included the impact of the soon to be divested Eagle Ford assets. Assuming the sale of the Eagle Ford closes as expected next week, our forward - our go forward finding cost will be primarily related to our Marcellus asset, which recorded all-sources finding and development cost of $0.22 per Mcfe in 2017, as well as an FNB cost associated with our ongoing exploration program.
On the strategic front, during the year, we announced the divestiture of our lower return non-core assets as mentioned West Virginia, and also East Texas and the Eagle Ford for a combined proceeds of approximately $840 million positioning us as a pure-play Marcellus company that offers pure leading production and reserve growth for debt-adjusted share, return on capital employed, free cash flow generation, return of capital, and one of the strongest balance sheet in the industry with a net debt-to-EBITDAX ratio of one-time and approximately $2.2 billion of liquidity, which will be further enhanced upon closing of the Eagle Ford transaction. This strong financial position provides us financial flexibility to reinvest in the business and increase our return of cash to shareholders throughout the natural gas price cycle.
Now on the distribution outlook, as it relates to increasing our return of capital to shareholders, this morning, we announced that our Board of Directors approved an increase in our share repurchase authorization to 30 million shares or 6.5% of our current outstanding shares. At yesterday's closing price, this would imply the potential to return approximately $720 million of capital through repurchases.
As we have stated in the past, we plan to be opportunistic in our share repurchase activity as we look to exploit any material disconnect between our market valuation in our view of the company's intrinsic value. We have been in and earnings-related blackout period since year-end. However, our year-to-date decline in share price represents one of the aforementioned disconnects giving that our fundamental view of Cabot's intrinsic value has not changed.
On the dividend front, we know that Cabot has increased its dividend twice in the last 10 months. Our run rate dividend payments for 2018 are expected to be 40% higher than 2017. We will remain fully committed to delivering sustained dividend growth over the upcoming years as this is one of our top priorities for capital allocation.
Now moving a couple of comments on our operating plan, this morning's release we reaffirmed our 2018 daily production growth guidance at a range of 10% to 15% or 18% to 23% on a divestiture adjusted basis. We also refine our capital budget guidance to $950 million consisting of $800 million in the Marcellus, 75 million in our exploration plays, and 75 million for pipeline investments in Atlantic Sunrise, and other corporate capital expenditures.
We plan to operate three rigs and utilize two completion crews in the Marcellus during 2018. Our Marcellus program in 2018 not only generates strong double-digit growth in 2018, but also positions Cabot for an even higher growth in 2019, given our production growth in 2018 is waited towards the second half of the year, due to the mid-year in service stage for our three primary infrastructure projects.
In the presentation posted to the website this morning, we provided our expectations for sequential quarterly production growth throughout the year highlighting the robust growth in our exit to exit production rate. On the exploration front, we are still targeting 75 million of capital to initially test these areas this year. However, given that one of the areas is further behind in testing than the other, we will likely not have an incremental update to share until the third quarter call, and I will be able to fully update hopefully at that time.
I stand by that we will remain disciplined with our capital allocation to exploration and methodically in our being methodical in our testing these concepts to determine if they have the attributes that can create long-term value for our shareholders, which is no easy task given that we have set high hurdles internally for these projects in this effort. Based on a $2.75 NYMEX assumption for the year, which is below the current strip, we expect to execute on a program that would deliver the following highlights.
Double-digit return on capital employed, double-digit growth in production, and reserves per debt adjusted share, positive free cash flow of approximately $180 million, a delivering of the balance sheet to below a one-time net debt-to-EBITDA, and a s significant expansion of available cash on hand, which provides us flexibility to reinvest in returns focused growth and increase return of cash to shareholders.
Not many companies can deliver at this level, and our commitment to delivering on these metrics is further highlighted by the board's decision to incorporate debt adjusted per share growth and ROCE metrics to our 2018 incentive compensation plan. Common on the infrastructure of critical importance as many are aware, is to deliver on our growth targets for the year is the timing of our upcoming infrastructure projects which we have several significant updates to provide.
First and foremost, our Atlantic Sunrise project continues to make significant progress on all fronts despite a challenging winter in the Northeast, pipeline work including stringing and welding, ditching and backfill, and tie-ins are in full swing as multiple construction crews continued to work extended hours. Last week, Williams reported that they are over 30% complete with the pipeline segment of the project, and over 40% complete with the compressor stations. We continue to target a mid-2018 in-service for the project and look forward to serving our new markets this summer.
Also, of note, the new PennEast project received its FERC certificate approving the pipeline during January of this year. This 1.1 Bcf per day project delivering Northeast Marcellus production to the East Coast is a big part of our future growth and important for Cabot diversity of market and price realizations. We are currently preparing for increased activity around this project, this PennEast, receives its final approval to move forward.
Currently, PennEast is scheduled to begin construction during 2018, and expects to be in-service approximately seven months after construction begins. As most of you are aware, Cabot has been active with two significant in basin projects, the Moxie Freedom power plant, and the Lackawanna Energy Center. Combined these two-state-of-the-art natural gas fire generating facilities will add approximately 400 million cubic foot per day of demand exclusively for Cabot. The Moxie Freedom plant remains on track for June 1, 2018 start-up date, and we will be burning approximately 160 million cubic foot per day.
Regarding the Lackawanna facility, its first train capable of burning 80 million per day, also remains on track for June 2018 in-service with trains two and three scheduled for October 1 and December 1, respectively. These two high-profile local demand projects will provide opportunities for growth and improved price realizations to Cabot's overall portfolio. One additional comment regarding constitution pipeline, after recently receiving an unfavorable ruling from the FERC regarding the New York DEC’s authority under the Clean Water Act, last Monday we filed a request to the FERC to reconsider its decision.
Additionally, last month we petitioned the US Supreme Court to review the judgement of the US Court of Appeals for the second circuit. We believe these latest filings will shed additional light on New York's failure to appropriately act on our Section 401 water quality certification. We will continue to update you on our progress. However, our three-year plan does remain intact regardless of the timing of this pipeline.
Our current three-year plan is predicated on the company reaching the 3.7 Bcf per day of gross Marcellus production target that we have outlined in the past in 2020, which is based on our current market share in basin and incremental growth into our new infrastructure projects. In addition, we expect to be able to grow our production base above this level through one or more of the following happenings. Additional sales on currently approved takeaway projects, including Atlantic Sunrise and PennEast, incremental sales of potential future expansion projects, increasing our work in-basin market share, new in-basin demand projects, and future Greenfield takeaway projects.
On a three-year outlook, in-light of our announced divestiture, the Eagle Ford and the recent change to the US tax code we have updated our total company three-year plan through 2020. In the presentation, posted to our website this morning, we have highlighted expected growth in production, earnings, cash flow, and ROCE that Cabot can generate during this three-year period assuming a range of NYMEX prices of 275 to 325. We believe these are reasonable through cycle price assumptions giving our view of supplier demand fundamentals during this period, and also collaborated by the strip and consensus estimate.
Of particular note, is a 20% to 24% divestiture adjusted production CAGR. A range of cumulative after-tax and I might make that note after-tax, companywide free cash flow of 1.6 billion to 2.5 billion, and a range of ROCE that increases to the high teens to low 20% level by 2020. We believe this level of growth, free cash flow and corporate returns are not only best-in-class in the E&P sector, but are also extremely competitive across the broad S&P 500 index, which currently and historically trades at premium valuations to the energy sector.
I would highlight that this plan assumes no contributions from our exploration program in 2019 and 2020, as it remains uncertain as to whether we will allocate any incremental capital to those areas beyond 2018. However, as I mentioned on our third quarter call, if we incurred by initial results in those areas and made the decision to allocate incremental capital beyond this year, we would utilize a portion of cash proceeds from our recent divestitures to fund that incremental spend. However, that also allows us to ploy our current cash on the balance sheet and future operating free cash flow for incremental returns of capital to our shareholders.
Jamie, with that, I’d be happy to answer any questions.
[Operator Instructions] And our first question today comes from Michael Glick from JP Morgan. Please go ahead with your question.
Hi guys, good morning. Just on the buyback, do you think the program ultimately transitioning from being opportunistic in nature to more of a systematic program? And if so, how would you expect to execute that mechanically?
Couple of things on the buyback. We’ve had some questions on timing and keep in mind our evolution in where we are right now. In the past, we’ve had authorizations and the execution of that authorization was constrained if you will, but just available cash and the plough back into our operations side of the business. In-light where we are right now with the growth of our free cash flow estimates and our program is still growing in production and generating the levels of free cash.
We do anticipate and I'm not going to give you a sideboard on the time consideration, but we do anticipate fully executing on this authorization that we have in a timely fashion. But when you look at the buyback program and it being opportunistic today, it’s opportunistic today, but as we get further into our growth mode of three, seven, or in greater production, and looking at the entire macro market it could go into a combination with continuing our efforts on any projects that would be operational in nature to create value, it certainly could be in conjunction with more of a systematic buyback program also, because we are going to generate a significant amount of free cash.
Got it. And then I noticed you guys put some basic hedges on, could you talk about liquidity in those markets and how that’s changed of late, and maybe how you're thinking about hedging basis strategically going forward?
I would pass the baton to Jeff.
Michael as you know in December and in early January we had a good strong rally for dominion sale of Leidy, Tennessee, Millennium and also down in non-New York areas. So, we took advantage of that to layer in about 100,000 a day of early strong basis differentials for Leidy. And we're going to continue to look at that. We're looking at summer only and winter is at 18, 19 right now, but again it is when opportunity knocks what would be - we had to do the basis up there.
Got it. Okay, thank you, guys.
Thank you, Michael, and I might add that we are in the - about 34% range of 18 hedged at approximately $2.80.
Thank you.
Our next question comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead with your question.
Good morning and congratulations on the seemingly inexecrable COG machine, I was going to ask two questions, one, the press release said that Gen 5 Completions are going to be on the majority of 2018 wells, why not make it on all of them? What are the considerations?
Yes. It’s a good question. Excuse me, in fact when Phil made the presentation to the board the other day, I asked a similar question, but when you look at the Gen 5 and longer laterals that we drill, we are drilling some of these wells out beyond 10,000 feet and with this type of completion in getting out beyond 10,000 feet due to some of the friction issues that raises the risk profile a little bit beyond 10,000 feet for Gen 5 Completion, those levels that are the completions and back stages that out beyond 10,000 feet. We are actually going to our Gen 4 Completion and then once we bring in the same well bore it will come back to the Frac stages inside of 10,000 feet, we go to the Gen 5.
That’s interesting color, and I assume this is all generated by lease geometry and trying to capture the most resources that you can from the longest well alright?
Absolutely. We know the efficiency, the long laterals, but we do have some constraints on the geometry of some of the units out there due to geographies and we do our best to be able to continue with the lateral length extensions.
All right. My other question is likely for Jeff. Although, it’s a smaller portion of the growth PennEast, it is part of the growth to 3.7 Bcf per day and it’s getting a lot of resistance in New Jersey, I read recently it is now resorting to eminent domain to conduct surveys there. With all this going on, do you still see 2019 as a realistic and service year for the pipeline?
And I’ll pass that to Jeff in one second, I just want to make a comment on the eminent domain. Every pipeline that we have laid out there for the most part and in other places has a component of eminent domain to be able to steer the last few sites that have holdouts. Holdouts are either those that resist or holdout are those that are just looking for a better deal, but I’ll let Jeff talk about his expectations for commissioning.
Yes Jeffrey. We watch it very closely of course and as an active shipper and supplier on that pipe, we have been in discussion with the owners and the shippers on the markets associated with pennies PennEast trying to understand the timeline and the - more importantly the timing of when those utilities will be out searching for new supplies and obviously it will be closer to when there is more clarity on the in-service, but Dan is correct, the last remaining land issues are generally solved after the FERK certificate has been issued and that’s what has happened in January.
I'm sure PennEast is looking forward to wrapping up the surveys on the last few tracks and getting that survey information to New Jersey and Pennsylvania for the remaining permits. And so that’s what’s going on right now. There has been some news and some resistance by the - some of the environmental groups and there has been some information request by the New Jersey DET as of last week with FERC, but a lot of that is work in progress and yes it slows down the pace, but as a kind of an outsider on this project, but close to it, we are still expecting construction to be 2018, and - but yes it could be later in the year rather than sooner.
Okay, thanks for the color. Appreciate it.
Our next question comes from Drew Venker from Morgan Stanley. Please go ahead with your question.
Good morning everyone. I was hoping if you could talk about your approach for the exploration programs if you do conclude there weren't continued spending about how you might approach the next phase of development in 2019 and 2020 whether that would be more delineation drilling in 2019 before you sort of move into development mode or any color you can provide there would be helpful.
Our approach at this stage is data gathering to be able to have enough information to determine whether or not the development mode, if we were so inclined to move into development, if in fact that development mode would yield the - and beat our returns that we had laid out with our expectation, and those - that hurdle is not only looking at the per well yields and returns, but certainly looks at the infrastructure necessary to get to that type of full cycle returns and as it also fit, our model and design of continuing with a higher return program that not only has growth, but also would allow for incremental capital to be created through this effort to return cash to shareholders.
So. we're not going to - when we get the adequate data to be able to make that call, I think it’s going to come down to a fairly bright line on, do we move forward with the project or do we monetize what we have and go about our business. I don't think and I would be shocked and I would hope that majority of the shareholders that know Cabot now we make decisions that they would be equally surprised if in fact we let this thing drag on and leak out to a large capital outlay with uncertainty on what our plans are moving forward.
So, I don't anticipate that happening, I do anticipate being able to get the data with the outlays that we’re making and again for a couple of exploratory areas making in an outlay for the multibillion dollar company and $75 million for the opportunity to achieve what we have in mind as success, I think is a reasonable risk profile.
Okay, thanks for the color Dan and still think you will be on track to make call on whether you should move forward or not later this year?
Yes, I do Drew.
Okay. That's all I have. Thanks guys.
Thanks.
Our next question comes from Holly Stewart from Scotia Howard Weil. Please go ahead with your question.
Good morning gentlemen.
Hi Holly.
How's it going. Maybe the first one I think probably for Scott, just trying to think through reconciling the cumulative free cash flow until maybe specifically the question is what were the taxes assumed in the previous kind of cumulative free cash flow guidance that you were going to pay?
Holly I'm going to let Matt handle that because he has walked in it.
Hi, Holly it is Matt Kerin. I think the biggest thing to highlight on that front is when we provided that three-year cumulative outlook in October. We were showing that on a pre-tax basis because we weren't really sure on what was going on with Eagle Ford at the time, as well as with tax reform, now that we have been able to sharpen the pencil a bit more, I think what has been really encouraging as a result of the tax rate coming down, as well as AMT going away whereas the October forecast would have assumed about 450 million cumulative current tax leakage during the three-year plan.
We are now talking about maybe only 50 million of current taxes during that period and that’s net of obvious refunds that we will get during the period. So, that’s an incremental call it 400 million of after-tax free cash flow, relative to what we were looking at back in October.
Got it, perfect. And that AMT is it refundable for 2018 or are you all expecting that in 2018?
No. The reality is that we won't get until we file our cash return in the subsequent year.
Okay. And then maybe just as my follow-up, you know Dan it seems activity levels are pretty much locked in just kind of given all the infrastructure additions that are coming online, but how do you think about that just kind of given normal moment in commodity prices that we see throughout the year?
I mean from a program consideration and allocation of capital in 2018?
Yes, sir.
We feel very good about our budget. I think you saw in 2017, how close we were to our expected expenditures and I feel equally confident in 2018 about our program. The Marcellus is a consistent consolidated block up there. We use the service providers of drill side and the completion side that we have had in the recent past. And with our annual contract in locked in for the most part we’re 85% to 90% locked in on service cost that - and that is off of that understanding that is how we build this 2018 program.
So, the additional 10% to 15% that did lock in annually is not that big cost, it’s the ancillary providers that we haven't locked in annual contracts, but we think with our not only our component of that being GDS, our wholly-owned subsidiary that manages a lot of our business up there. We think also the other providers will be within the range that we budgeted.
That's great. Thanks guys.
Thank you.
Our next question comes from the line of Brian Singer from Goldman Sachs. Please go ahead with your question.
Thank you, good morning.
Hi, Brian.
I wanted to follow-up on the comments that you made on potential upside to your guidance or at least extension of growth longer term, you highlighted for opportunities future expansion projects in-basin market share, I think new basin demand and some greenfield takeaway, maybe we could start with the in-basin market share, can you just talk to how you make your decision on whether you would want to increase in-basin market share and any rate of return or local price hurdles that that would entail?
Yes. I will just pass it over to Jeff. He does this day-in and day-out and that additional capacity that goes beyond the power plants and the PennEast and the Atlantic sunrise has been on Jeff's radar for over a year. So, he's working diligently every day to accomplish the future.
Okay, Brian. So, the first part of your question really has to do with in-basin pipe that exists today. Our expectations here in the next six months is we are going to see quite a bit of falling gas leave some of the existing pipes, particularly Tennessee and Transco as some of the producer shippers up there get ready for Atlantic Sunrise and also as we look down the road with PennEast. So, there is going to be some freed-up capacity on space on the existing pipes going forward, and quite frankly we’re going to be a big part of that initially. So, market share in the basin up there, near term and long term it certainly is a growth wagon for us.
Got it. So, should we expect if local prices do improve or differentials narrow that you would take that opportunity to potentially become more active in your activity and ultimately in your production?
Well Brian it goes hand-in-hand. So, we will watch the regional prices up there and we will look at our opportunities with Sunrise and PennEast and given that we are also looking at additional opportunities on Atlantic Sunrise and we are comparing those with how we see the market shaping up in-basin and we’re also looking at the opportunities we have off the gathering system with new businesses and the industry and the opportunities there. So, it all goes hand-in-hand, but I think as you see differentials have tightened in Northeast PA that we will take advantage of that.
And as a little bit of my follow-up as well, the latter two points on the new in-basin demand in the future Greenfield takeaway projects, we are within the basin, are you seeing the greatest opportunity for new demand projects is it more power plants in Pennsylvania or is it somewhere else regionally? And then where geographically do you think the next Greenfield takeaway goes?
Both of those questions have to do with ongoing projects that we are looking at and being in a very competitive market we’re not quite there on disclosing where we think the next Greenfield ought to go, and exactly whom we are talking with and what type of industry that we are talking with on connecting the new industry to the gathering system, but I will say, I don't think it’s going to be power generation in that three, four accounting area. I think we’ve reached a good solid level of new power growth there.
I think the power generation will continue to be a good demand component, may be more in the mid-Atlantic states and maybe along the coast, but in-basin there is, we're talking to, and I think we’ve talked about this on the call, previously a number of different opportunities and we’re getting closer on some and they are not big scale, but they are additive in nature.
One of the real unique ideas that we have and hadn't got a lot of traction is to lay a pipeline right across the offense line from Pennsylvania into New York and source all those fuel oil heating facilities that are up there in that part of the country with cleaner burning natural gas.
Great, thank you. I would ask a fifth question and on what the interest level is on the other side of the board room, maybe I will take that one off-line.
Thank you, Brian.
Our next question comes from Dave Kistler from Piper Jaffray. Please get our head with your question.
Good morning guys, thank you. Real quickly, and not to understate the success that you have seen from the Gen 5 Completions you guys have consistently been improving the rate of returns on these wells through better completions et cetera, can you talk about kind of what you're thinking about as far as potentially Gen 6, what you can tweak or we kind of - at a maximum level of kind of IRR per well at this juncture?
Well, each call I think Dave we’ve had a question about where do you reach maximum efficiencies and you are going to look historic and see the progress that’s been made and Gen 5, Gen 6 is one of those efforts that we are trying to create incremental gains and efficiency. And that gain and efficiency comes really in two ways. One, it’s in cost, you can gain a better return profile or you can gain a better profile in more gas coming out of the ground at a quicker rate, or you can do both. Right now, the balance between our decision in Gen 5 and Gen 6 was that in looking at now the cost side, and keeping in mind we have a very small sample pool for our Gen 6. We only have a few wells that were measuring in reading and trying to determine the level of efficiencies for Gen 6. With that being said, we will continue to monitor what we have done in Gen 6, but right now with the ability to implement Gen 5 we see in the early stage no big difference in Gen 5, Gen 6, but the cost of Gen 5 is, plus or minus 20% more effective than the Gen 6. So, with that and looking at our desire to return cash back to the shareholder we have decided to conserve the cash, allocate into a Gen 5 Completion where we can and deliver superior returns.
Makes sense. Appreciate that color. And then maybe switching over to something you talked about last call, where you had mentioned the possibility of curtailing gas in a weaker commodity price environment, can you talk a little bit about how you're thinking about that, this year given hedges have increased basis hedges are in place et cetera, is that something that’s still on the table and what would be kind of threshold prices realizing that you recover your cost of capital at north of a dollar now [ph]?
Well, we’ve always been prudent in rationalizing how we deliver gas into the system and we will continue to be rational about our decision process, I'm not going to set a benchmark of when we think we ought to move gas of the market and keep it in the shareholder's pocket as opposed to giving it away, but if in fact there is such a tentative market out there, we would consider a curtailment and by doing that proportionately across the field respond to the punitive market.
Yes, we can, with our cost structure now, what our finding cost is, what our cost to capital is, we still would receive a return, but I think it’s also important that the rationalization of the market in the form of managing expectations on financial metrics for our shareholder is important to consider also.
Great. I appreciate that color and certainly applaud you guys on the capital stewardship, phenomenal.
Thank you, Dave.
Our next question comes from Michael Hall of Heikkinen Energy. Please go ahead with your question.
Thanks, good morning.
Hi Michael.
Hi. I guess maybe just on the topic of allocating capital, can you just discuss a little bit how you evaluate, I guess returning cash to shareholders and or building cash balances relative to potentially consolidating your corner of the Marcellus and what your appetite is there and what sort of opportunities you today?
Across the whole spectrum you just mentioned Michael, you know we want to return our cash that we generate back to shareholders and we’re going to continue to do that as I mentioned in my remarks, prioritizing dividends and buy backs. We also think the shareholder appreciates allocation of capital through our operations program assuming it meets the hurdles that allow us to continue delivering cash back and when we evaluate consolidation or the basin impacts or quite frankly anything out there, we’ve always participated in understanding the space whether it’s in a basin that we are in or a basin that we are not.
Looking at all the pitch books that are solid across our desk, we scroll we look at, we understand, and we measure how we perform compared to how our peers perform with those assets that we become more familiar with when we look at all these books. So, to determine whether or not it fits in our portfolio though is still an extremely conservative process and the history that Cabot has displayed in the decisions that we’ve made on being acquisitive has - is all I can say is, that’s the way I am, and that’s the way we’ve done it now for years and years and years, and even though there is assets out there in the street that many have thought and we were rumored many times for example when the Permian was faulty [ph] that we would be out there buying those assets.
We didn’t make that decision because I could never get our arms around a full cycle returns for those assets. So, we will continue to look at the future that way. If there is an opportunity that presents itself and the value proposition and consideration is good and it meets with our long-term strategy of delivering cash back with growth to our shareholders we will take a look at it.
Okay. Understood, yes it seems like there is potential willing sellers in your direct neighborhood there. So, I guess [indiscernible] we will keep an eye on. To take a second on continuing on the inventory team, you guys provided a 35-year inventory life based on 2018 activity in the deck, I'm just curious how that looks on the just lower Marcellus only in-light of to break that out.
The lower Marcellus, we go out to almost 20 - pushing latter part of 2020, is where we go out on our decade - the latter part of the decade. Scott has always been there to protect me. Almost to 2030, about we are comfortable with our lower Marcellus position and I might add, and looking at the upper Marcellus we have test scheduled this year for the upper Marcellus with the expectation that we will be completing those upper Marcellus wells with the newer technology, newer unloading, cluster spacing, the whole gambit of our completion recipe that we have been so effective with in the lower Marcellus. We are going to move from the Gen 1, 2 and just a couple of 3’s that we had in the upper Marcellus in the past. We have not had any Gen 4’s, 5’s or 6’s in the upper Marcellus. So, I’m anxious to see what the upper Marcellus will do with the new Completion.
So, and keep in mind even on the older Gen completions, the delivery that we had on a 1000 foot was better than the majority of the Marcellus that we see out there. So, I expect an uptick from what we historically have seen in the upper Marcellus to where we are going.
Okay. Great. That’s helpful. And then I guess, can you just remind us like what the cost savings are in Gen 5 versus Gen 4, you said 20% cost effective versus 6, I am just curious Gen 5 versus 4.
Years 5 versus 4, we are in fact about 10% more cost effective on the Gen 5 then we will with Gen 4.
Great. That's all I have. Thanks guys.
Thanks, Michael.
Our next question comes from Mike Kelly from Seaport Global. Please go ahead with your question.
Hi guys, good morning. I wanted to follow-up on Brian Singer's question about the firm sales, firm transport opportunities, and really just wanted to get a sense on the timing and scale of some of these if you could get into it, just also get a sense of we're talking a year from now in the Q4 2018 call for looking at Slide 12 where you lay out all these future opportunities, if that could look significantly different, I guess more advanced where it is now? Thanks.
Mike, and I will let Jeff answer that. I will make a comment that - and Jeff can maybe give additional color on the firm transportation side, keep in mind that we did not jump on that firm commitment side as many, many companies did and commit to that structure. We’ve worked around it by advance sales on like Atlantic Sunrise and having a complete tie down of the volumes from delivery into the pipe all the way into the sales point. So, that was one thing we did different and a lot of our gas moves third party firm as opposed to Cabot dedicated firms. So, we’re not in a situation where we have to move gas under firm contracts, but I’ll pass it on to Jeff.
Sure, Mike. Maybe just to elaborate on the few answers that we have for Brian. I think you will see some not necessarily announcements of some progress with the Atlantic Sunrise project says we get closer to end service and other producer shippers evaluate their positions and we see a reaction in the marketplace on basis differentials and we get closer to partial and services summer and then full in servers, I think you will see progress buyers around that time period. And actually, the same thing goes for PennEast. The market is there, they are ready, we have got multiple discussions, again getting clarity is important for a gas buyer and certainly important for us to plan our business.
So, I think you will see again progress as we are closer to in-service may be around the time that PennEast gets it's and others perceive with construction, I think that will concept the bar on where we expect to plan in terms of winter sales to these utilities. The end base in activities are ongoing, we’re close on a couple of smaller projects that I can't elaborate on, but as we build that end base in activity it’s going to add up.
I mean, we are currently outside the power plants for probably in the 50,000, 60,000 a day range currently. We are getting ready to gasify small - excuse me up there in Pennsylvania called [indiscernible] and not a big load, but we continue to add customers up there. So, it is going to all add up, I think 2018 will see a lot of progress and towards year-end it could be that we are able to finally get some progress on another niche project with the Greenfield pipe. So, more on that to come. We are still a long way off, but we never stopped looking.
Great color, appreciate that. Maybe just, out of curiosity, how big of a project could that pipe to ultimately displays the fuel oil in New York, could you help get a sense of that size?
Well since I have put the corn out there, I will let Jeff take it.
[Indiscernible] answers.
There is a significant amount of fuel oil being used up there though. There is not the ability for that part of the country to utilize natural gas in a dependable manner and they are, from my understanding is certainly from our feet on the ground, a lot of disappointment, not being able to take advantage of something that is right across fence line from a - it is just one of those unfortunate circumstances that we are living with today, but I can tell you this, we're going to continue to fight it, and we’re going to prevail at some point in time.
Good deal, appreciate it.
Thanks.
Our next question comes from David Deckelbaum from Keybanc. Please go ahead with your question.
Good morning Dan, Jeff, Scott everyone. Thanks for squeezing me in. My question is really Gen 5 or I guess any of the Marcellus type curve, right now you're getting the 4.4 Bcf 2000. I guess in 2018 when more capacity comes online or any point I guess in your long-term plan, it doesn't sound like you are baking in any performance improvement and is it fair to say that we haven't necessarily got the full look at the productivity of these completions, just given a constrained environment and should we expect this expect to see kind of accelerating type curves with more capacity coming online to perhaps show a better productivity uplift and would that begin 2018?
Well, again, I kind of made the comment earlier. Historically, we’ve been able to ramp up our expected EUR per thousand, the rates that in the way we bring on the wells Phil and his guys are committed to maximize the EURs in these wells and yes we have been somewhat constrained by how we bring these wells online, but we have worked with Williams extensively to put together what we think is a world-class gathering system and ahead our system out there that gives us the optionality and also allows us to reduce pressures in different parts of the field, and move gas around when need be to take advantage of any disconnect in the market.
So, I think we will see things once we are able to take advantage more proactively of a more versatile market, I think we will be able to see things and measure performance of wells in certain areas of the field differently, then we measure them today, but I just don't have an answer on what the results might be with that additional data. But we are certainly encouraged with the flexibility that water - our gathering system provides us, but also the additional flexibility of moving gas in and out of the basin. And then moving out of the basin cannot be over emphasized on what I think it will do to the, some of the end base and differential issues that we have had in the past.
Okay, certainly, I understand it on the pricing side, but it sounds like testing at least pressure management would be more of like a later 2018 thing, so if there was a change to design that wouldn't really start coming through until 2019 or 2020, I guess is that fair?
Yes, and if you look at it little bit differently. You can look at it for example, in the first quarter of 2018, we didn’t quite - we had a little bit of, we haven't have had the volumes in the first half so far or the first quarter of 2018, yet because we have had a couple of large pads that we have been on for a long time. And I'm talking about 10 well type pads. And when you look at that completion of those 10 well type pads we had the cold weather up there in normal winter stuff that slows down, but because we had such a large pad, a lot of Frac stages on that pad, we didn’t turn in line one well so far this quarter.
And by that measure we still are moving the gas that we need to move and all of that, but in the beginning of the second quarter we’re going to bring on the - in fact two large pads, 15, 20 type of wells in the first, second quarter in April that with the volumes coming out of a geographic area so small, again a couple of 810 well pads, we're not going to bring those wells on full tilt because we adjust, you cannot move them on, but they showed management to your point that Bill and his group deals with is built-in at this point in time.
But I think even the future that is going to be the case because there is a lot of gas coming into our gathering system in one area of one pad site and that has to be managed through the gathering system and that’s some of the effort that’s ongoing by Williams and our gas controllers on how we can manage that and having the additional flexibility how we can know that gas is going to help as we bring on these large volumes. So, it’s the nature of the base and I don't have an exact on the impact, but that is just a definition of what we deal with out there, it’s a high-class problem by the way I think, but nevertheless we deal with it and it does affect us on any short-term snapshot.
All right. Appreciate the responses Dan.
Thanks David.
Our next question comes from Doug Leggate from Bank of America Merrill Lynch. Please go ahead with your question.
Well thanks for squeezing me in guys. Just got two quick follow-ups. It may be for Matt first of all on tax, you have given us that 20% to 50% - 25% to 50% deferred type tax assumption in 2020, should we think of that as kind of a normalized range on a maintenance sustaining capital type of number or does it change further beyond on your expectations and I have got a quick follow-up please.
Thanks for the question. It’s ultimately going to be depending on realized price and level of capital spending, and a lot of other variables. It’s really depending on what you’re assuming, but I would call it $3 natural gas price holding 3.7 flat, you will actually probably be closer to 75% to call it 85% current. So, it does widen out a little bit. In 2020, you still in some cases depending on the price tag have some benefits of either AMT or NOLs, so 2021 the assumption would be that we've utilized all of our NOLs and monetize all of our AMT.
That was pretty clear Matt. Thanks. And I guess my final one is, Dan it is probably for you, but as you step up the buyback and obviously you have laid out the free cash flow for the next several years. You are kind of transitioning to something kind of an immunity you would guess, your free cash flow type of investment case. In that scenario what is the right volume balance between dividends and buybacks on a go forward basis?
I have a hard time Doug being specific with that. We don't have a defined formula on how we might allocate between those two. I will say as part of the consideration. One of the things we don't want to do is, with a little bit of cyclical nature to a commodity we don't want to get so far dedicated to a dividend policy that we will retract at some point in time with the draconian period and the commodity space. But I do think that with the production level that we will be at, the low-cost structure of our program, I do think we medicate that somewhat just simply buy those two metrics.
I would look at our buybacks and look at the authorization and assume if you will that again within a reasonable time we will be buying back and making every effort to get back to the shareholder, but we are also going to keep some dry powder in the sack to be able to take advantage of opportunities and operational ideas that we have that we think made our internal thresholds. So, I’m sorry I don't have a formula to give you, but I can tell you both our priorities along with us being able to be prudent with our capital allocation.
Appreciate the answers guys. Thanks again.
Thanks Doug.
And our next question comes from Bob Morris from Citi. Please go ahead with your question.
Thanks. Dan, just really quickly here on the 75 million you’ve allocated this year to your exploration projects, how much is in there for leasehold acquisitions and how many drill and complete wells does that entail?
It’s just a very small amount and there might be $1000, that’s how small it might be because we kind of have the acreage that we want to work with, and the number of wells is a little bit dependent upon the timing of the area that’s kind of a little bit behind, it’s a little bit dependent upon some of the timing considerations that we have ongoing in that area, but I think it’s about five or six wells and from a science perspective, we would anticipate those wells to gather a great deal of science.
Okay, great. Thank you, nice quarter.
All right. Thank you.
Ladies and gentlemen, at this time, we’ve reached the end of today's question-and-answer session. I would like to turn the conference call back over to management for any closing remarks.
Thanks Jamie and thanks for all of the questions, and now I can assure you as a shareholder, I appreciate the consistency in Cabot's ability to deliver on its forecast and quite frankly, additionally I really appreciate the fact that it’s forecast program is top tier, if not industry-leading metrics that I think will deliver future value creation. And I assume the job of continuing to deliver on the stellar results. So, thank you again for the interest and I look forward to our call in the latter part of April. Thank you.
Ladies and gentlemen that does conclude today's conference call. We thank you for attending. You may now disconnect your lines.