Good morning, everyone, and welcome to Cabot Oil and Gas Corporation's 4th Quarter and Year End 2017 Earnings Conference Call. All participants will be in a listen only mode. Please also note today's event is being recorded. And at this time, I'd like to turn the conference over to Mr. Dan Dinges, Chairman, President and CEO.
Sir, please go ahead.
Thank you, Jamie, and good morning to all. I appreciate you joining us for Cabot's 4th quarter full year 2017 call. With me today are the members of the executive management team. I would first like to highlight that on this morning's 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, I plan to discuss the highlights from our Q4 and full year 2017 results, followed by an update on our 2018 budget as well as an update on the company's current 3 year plan. For the Q4, Cabot generated adjusted net income of 59,000,000 dollars or $0.13 per share, an increase of over 10 times relative to the Q4 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 Q3, production increased 8% over the prior year comparable quarter. I would also highlight that the 4th quarter represents the 7th consecutive quarter in which Cabot has generated positive free cash flow.
For the full year 2017, Cabot generated adjusted net income of $245,000,000 or $0.53 per share compared to a $97,000,000 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% 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 $155,000,000 of free cash flow, marking the 2nd consecutive year of positive free cash flow generation. Keeping with our commitment to return an increasing amount of capital to shareholders, the company repurchased 5,000,000 shares during the year for a total of $124,000,000 and paid out $79,000,000 in dividends for a total return of capital of $203,000,000 or 21% of our discretionary cash flow.
Return on capital employed for the year 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, our ROCE increases another 100 basis point 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 source 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 source finding and development cost of $0.22 per Mcf in 2017 as well as an F and D 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 combined proceeds of approximately $840,000,000 positioning us as a pure play Marcellus company that offers peer leading production and reserve growth per debt adjusted share, return on capital employed, free cash flow generation, return up capital and one of the strongest balance sheets in the industry with a net debt to EBITDAX ratio of 1 time and approximately $2,200,000,000 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 30,000,000 shares or 6.5 percent of our current outstanding shares. At yesterday's closing price, this would imply the potential to return approximately $720,000,000 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 and our view of the company's intrinsic value.
We have been in an earnings related blackout period since year end. However, a year to date decline in share price represents one of the aforementioned disconnects, given that our fundamental view of Cabot's intrinsic value has not changed. On the dividend front, given 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 remain fully committed to delivering sustained dividend growth over the coming 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 20 18 daily production growth guidance range of 10% to 15% or 18% to 23% on a divestiture adjusted basis. We also refined our capital budget guidance to $950,000,000 consisting of $800,000,000 in the Marcellus, dollars 75,000,000 in our exploration plays and $75,000,000 for pipeline investments in Atlantic Sunrise and other corporate capital expenditures. We plan to operate 3 rigs and utilize 2 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 weighted towards the second half of the year due to the mid year in service dates for our 3 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 $75,000,000 of capital to initially test these areas this year. However, given our 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 Q3 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 of 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 $180,000,000 a delevering of the balance sheet to below onetime net debt to EBITDAX and a 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. Comment 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 for which we have several significant updates to provide. 1st 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 continue 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-twenty 18 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's diversity of market and price realizations. We are currently preparing for increased activity around this project as PennEast receives its final approval to move forward. Currently, PennEast is scheduled to begin construction during 2018 and expects to be in service approximately 7 months after construction begins.
As most of you are aware, Cabot has been active with 2 significant in basin projects, the Moxie Freedom Power Plant and the Lackawanna Energy Center. Combined, these two state of the art natural gas fired generating facilities will add approximately 400,000,000 cubic foot per day of demand exclusively for Cabot. The Moxie Freedom plant remains on track for a June 1, 2018 start up date and will be burning 160,000,000 cubic foot per day. Regarding the Lackawanna facility, its first train capable of burning 80,000,000 per day also remains on track for June 2018 in service with Trains 23 scheduled for October 1 December 1, respectively. These 2 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 for the FERC 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, out last month, we petitioned the U. S. Supreme Court to review the judgment of the U.
S. Court of Appeals for the 2nd 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 3 year plan does remain intact regardless of the timing of this pipeline.
Our current 3 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 1 or more of the following avenues: additional sales on currently approved takeaway projects, including Atlantic Sunrise and PennEast incremental sales potential future expansion projects, increasing our in basin market share, new in basin demand projects and future greenfield takeaway projects. On our 3 year outlook, in light of our announced divestiture of the Eagle Ford and the recent change to the U. S. Tax code, we have updated our total company 3 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 3 year period assuming a range of NYMEX prices of $2.75 to $3.25 We believe these are reasonable through cycle price assumptions giving our view of supply demand fundamentals during this period and also corroborated by the strip and consensus estimates. 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, company wide free cash flow of $1,600,000,000 to $2,500,000,000 and a range of ROCE that increases to the high teens to low 20 percent level by 2020. We believe this level of growth, free cash flow and corporate returns are not only best in class in the E and P sector, but are also extremely competitive across the broad S and P 500 index, which currently and historically trades at premium valuations to the energy sector. I would highlight that this plan assumes no contribution from our exploration program in 2019 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 Q3 call, if we were encouraged 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 deploy 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.
And our first question today comes from Michael Glick from JPMorgan. Please go ahead with your question.
Hey, guys. Good morning.
Good morning, Mike. Just
on the buyback, do
you see 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?
A couple of things on the buyback. We've had some questions on timing and keep in mind our evolution and where we are right now. In the past, we've had authorizations and the execution of that authorization was constrained, if you will, plow back into our operations side of the business. In light of where we are right now with the growth of our free cash flow estimates and our program 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 3, 7 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're going to generate a significant amount of free cash.
Got it. And then I noticed you guys put
some basis hedges on. Can you talk about
the liquidity in those markets and how that's changed of late and maybe how you're thinking about hedging basis strategically going forward?
Yes. I'll pass that baton to Jeff.
Yes, Michael. As you know, in December early January, we had a good strong rally for Dominion South, also 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 fairly strong basis differentials for Leidy. And we're going to continue to look at that. We're looking at some summer only and some winters of 2018 2019 right now.
But again, if the twin opportunity knocks, we'll be hedging the bases up there.
Got it. Okay. Thank you, guys.
Yes. Thank you, Michael. And I might add that we are in the about 34% range of 2018 hedged at approximately $2.80
Thank you.
Our next question comes from Jeffrey Campbell from Tuohy Brothers. Please go ahead with your question.
Good morning and congrats on the seemingly inexorable cog machine. I was going to ask 2 questions. 1, the press release said that Gen 5 completions were going to be on the majority of 2018 wells. Why not make it on all of them? What are the constraints?
Yes, it's a good question. Excuse me, in fact when Phil made the presentation to the Board the other day, I ask a similar question. But when you look at the Gen 5 and the longer laterals that we drill, we are drilling some of these wells out beyond 10,000 feet. And with this type of completion and 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 or the completions and frac stages that are beyond 10,000 feet, we are actually going to our Gen 4 completion.
And then once we bring in the same wellbore, 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 you can from the longest lateral, right?
Absolutely. We know the efficiency of the long laterals, but we do have some constraints on the geometry of some of the units out there due to geographics. And we do our best to be able to continue with the lateral length extensions.
Right. My other question is likely for Jeff. Although it's a smaller portion of the growth, PennEast 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's now resorting to eminent domain to conduct surveys there. With all this going on, do you still see 2019 as a realistic in service year for the pipeline?
Yes. 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've laid out there for the most part and in other places has a component of eminent domain to be able to secure the last few sites that have holdouts. Holdouts are either those that resist or holdouts 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 in the markets associated with 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's more clarity on the in service. But Van is correct, the wrapping up the surveys on the last few years. 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's been some information requested by the New Jersey DEP 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're still expecting construction to be 2018.
And but yes, it could be later in the year rather than sooner.
Okay. Thanks for the color. I appreciate it.
Our next question comes from Drew Ventor from Morgan Stanley. Please go ahead with your question.
Good morning, everyone.
I was hoping you could talk about your approach for the exploration programs if you do conclude they weren't continued spending about how you might approach the next phase of development in 2019 2020, whether that would be more delineation drilling in 2019 before you could move into development mode or any color you can provide there would be helpful?
Yes. 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 have laid out with our expectations. 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 does it also fit our model and design of continuing with a high 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. So I don't think and I would be shocked and I would hope that majority of the shareholders that know Cabot and how 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 exploratory areas, making an outlay for a multibillion dollar company, dollars 75,000,000 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 I think you'll 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 had. Thanks, guys.
Yes. 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?
Good.
Maybe the first one, I think probably for Scott, just trying to think through reconciling that cumulative free cash flow. And so 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's working. Okay.
Holly, it's Matt Cairn. Yes, I think the biggest thing to highlight on that front is when we provided that 3 year cumulative outlook in October, we were showing that on a pretax basis because we weren't really sure what was going on with EBITDA at the time as well as with tax reform now that we've been able to sharpen the pencil a bit more. I think what's been really encouraging is as a result of the tax rate coming down as well as AMT going away, whereas the October forecast would have assumed about $450,000,000 cumulative current tax leakage during the 3 year plan. We're now talking about maybe only $50,000,000 of taxes during that period and that's net of obvious refunds that we'll get during the period. So that's an incremental, call it, dollars 400,000,000 of after tax free cash flow relative to what we were looking at back in October.
Got it. Perfect. And that AMT that's refundable for 2018, are you all expecting that in 2018?
No. The reality is that we won't get until we file our tax return the subsequent year.
Okay. And then maybe just as my follow-up. 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 movement in commodity prices that we see throughout the year?
You mean from a program consideration and allocation of capital in 2018?
Yes, sir.
Yes. 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 service providers on the drill side and the completion side that we have had in the recent past. And with our annual contract and lock in for the most part, we're 85% to 90% locked in on service cost that and that is off of that understanding, that's how we built this 2018 program. So the additional 10% to 15% that isn't locked in annually is not the 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 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 the potential upside to your guidance or at least extension of growth longer term. You highlighted 4 opportunities, future expansion projects, in basin market share, I think new basin demand and then 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'll 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 your first part of your question really has to do with in basin pipe that exists today. Our expectations here in the next 6 months is we're going to see quite a bit of flowing 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 and space on the existing pipes going forward.
And quite frankly, we're going to be part of that initially. So market share in the basin up there near term and longer term is certainly a growth item for us.
Got it. So should we expect that 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'll look at our opportunities with Sunrise and PennEast. And given that we're also looking at additional opportunities on Atlantic Sunrise and we're 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 new industry and new opportunities there. So it all goes hand in hand, but I think as you see differentials tighten in Northeast PA that we'll take advantage of that.
And that was a little bit of my follow-up as well on the latter two points on the new in basin demand and the future greenfield takeaway projects. Where 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?
Okay. Both of those questions have to do with ongoing projects that we're 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 when we're talking with and what type of industry that we're 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 county 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, maybe 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're not all big scale, but they're additive in nature.
One of the real unique ideas that we have and hadn't got a lot of traction is to lay a pipe line right across the fence 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 clean or burning natural gas.
Great. Thank you. I'd ask a 5th question on what the interest level is on the other side of the board, but maybe I'll take that offline.
Thank you, Brian.
Our next question comes from Dave Kifler from Simmons Piper Jaffray. Please go ahead with your question.
Good morning, guys. Thank you.
Real quickly and not to understate the success that you've seen from the Gen 5 completions, you guys have consistently been improving the rate of returns on these wells through better completions, etcetera. Can you talk about kind of what you're thinking about as far as potentially Gen 6, what you can tweak or are 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 the question about where do you reach maximum efficiencies and you can look historic and see the progress that's been made. And Gen 5, Gen 6 is one of those efforts that we're trying to create incremental gains and efficiency and that gain and efficiency comes really in 2 ways. 1, 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 Gen 6.
We only have a few wells that we're measuring and reading and trying to determine the level of efficiencies for Gen 6. With that being said, we'll continue to monitor what we've 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've decided to conserve the cash, allocate into a Gen 5 completion where we can and deliver superior returns.
Makes sense. I 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, etcetera? 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 $1.0
M? Well, we've always been prudent in rationalizing how we deliver gas into the system and we'll 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 off the market and keep it in the shareholders' pocket as opposed to giving it away. But if in fact, there's such a tentative market out there, we would consider a curtailment. And by doing that proportionally across the field respond to the punitive market.
Yes, we can with our cost structure now, what our finding cost is, what our cost of capital is, we still would receive a return. But I thought I think it's also important that the rationalization of the market in the form of managing expectations on financial metrics for our shareholders is important to consider also.
Great. I appreciate that color and certainly applaud you guys on the capital stewardship. Phenomenal.
Yes. Thank you, Dave.
Our next question comes from Michael Hall from Heikkinen Energy. Please go ahead with your
I guess maybe just on that 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 see today?
Yes. We look at across the whole spectrum you just mentioned, Michael. We 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 buybacks. We also think the shareholder appreciates allocation of capital to 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're in or a basin that we're not looking at all the pitch books that are slid across our desk.
We scrub, 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 and 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 years years. And even though there's assets out there in the street that many have thought and we were rumored many times, for example, when the Permian was frothy 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'll continue to look at the future that way.
If there's 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'll take a look at it.
Okay. Understood. Yes, it seems like there's a potential willing sellers in your direct neighborhood there. So I guess TBD will keep an eye out. I guess second on the kind of continuing on the inventory theme.
You guys provide a 35 year inventory life based on 2018 activity in the deck. I'm just curious how that looks on just the lower Marcellus only. Is there any way to break that out?
Well, the lower Marcellus, we go out to almost 20 pushing latter part of 2020 is where we go out on A decade. A decade. Year 2020. Yes, the latter part of yes, the decade. Scott has always been there to protect me.
The latter almost to 2,030 about that, we're comfortable with our lower Marcellus position. And I might add, and looking at the upper Marcellus, we have tests scheduled this year for the Upper Marcellus with the expectation that we will be completing those Upper Marcellus wells with the newer technology, newer method, newer loading, cluster spacing, the whole gambit of our completion recipe that we've been so effective within the lower Marcellus. We're going to move from the Gen 1, 2 and just a couple of 3s that we had in the upper Marcellus in the past. We have not had any Gen 4s, 5s or 6s in the Upper Marcellus. So I'm anxious to see what the Upper Marcellus will do with the new completions.
So and keep in mind, even on the older gen completions, the delivery that we had on a 1,000 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 for Marcellus to where we're 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 Gen 6. I'm just curious on 5 versus 4.
Yes, 5 versus 4 were in fact about 10% more cost effective on the Gen 5 than we were on the Gen 4.
Great. That's all I had. Thanks, guys.
Thanks, Michael.
Our next question comes from Mike Kelly from Seaport Global. Please go ahead with your question.
Hey, guys. Good morning. I wanted to follow-up on Brian Singer's questions 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 just get a sense if we're talking a year from now in the Q4 2018 call, if we're 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.
Okay. Yes, Mike, and I'll 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 advanced sales on like Atlantic Sunrise and having a complete tie down of the volumes from delivery into the pipe all the way to the sales point.
So that was one thing we did different and the a lot of our gas moves on 3rd party firm as opposed to a Cabot dedicated firm. 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'll see some not necessarily announcements, but some progress with the Atlantic Sunrise project as we get closer to in 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 in service this summer and then full in service. I think you'll see progress by us around that time period.
And actually, the same thing goes for PennEast. The market is there. They're ready. We've had multiple discussions. Again, getting clarity is important for a gas buyer, and it's important for us too to plan our business.
So I think you'll see, again, progress as we get closer to in service maybe around the time the PennEast gets its notice to proceed with construction. I think that will kind of set the bar on where we expect to land in terms of winter sales to these utilities. The in basin activities are ongoing. We're close on a couple of smaller projects that I can't elaborate on. But as we build that in basin activity, it's going to add up.
I mean, we're currently outside the power plants. We're probably in the $50,000,000 $60,000 a day range currently. We're getting ready to gasify a small town up there in Pennsylvania calling for the mechanic and not a big load, but we continue to add customers up there. So it's going to all add up. I think 2018, we'll see a lot of progress.
And toward year end, it could be that we're able to finally get some progress on another niche project with the greenfield pipe. So, more on that to come. We're still a long way off, but we never stop looking.
Good color. Appreciate that. And maybe just out of curiosity, how big of a project could that pipe to ultimately displace the fuel oil in New York be? How get a sense of that size?
Well, since I put the corn out there, I'll let Jeff pick it up. It'd be twin 42 inches There is a significant amount of fuel oil being used up there though. There's 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 by not being able to take advantage of something that's right across fence line from them. It's just one of those unfortunate circumstances that that we're 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 just Gen 5 or I guess or any of the Marcellus type curves right now you're guiding to 4.4 Bcf per 1,000. I guess in 2018 when more capacity comes online or any point I guess in your long term plan, are you it doesn't sound like you're baking in any performance improvements. And is it fair to say that we haven't necessarily gotten the full look with more capacity coming online to perhaps show a with more capacity coming online to perhaps show a better productivity uplift?
And would that begin 2018?
Well, we again, I kind of made the comment earlier, historically, we've been able to ramp up our expected EUR per 1,000. The rates that and 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 header 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 and take advantage of any disconnect in the market. So I think we'll see things once we are able to take advantage more proactively of a more versatile 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, 1, gathering system provides us, but also the additional flexibility of moving gas in and out of the basin. And that moving out of the basin cannot be overemphasized on what I think it will do to the some of the in basin differential issues that we've 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 designs, it wouldn't really start coming through until 2019 or 2020, I guess. Is that fair?
Yes. And you can look at it a little bit differently. You can look at it, for example, in the Q1 of 2018, we didn't quite we had a little bit of we haven't had the volumes in the first half so far or the Q1 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 and normal winter stuff that slowed 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 these, in fact, 2 large pads, 15, 20 type of wells in the Q2 in April that with the volumes coming out of a geographic area so small, again, a couple of 8, 10 well pads, we're not going to bring those wells on full tilt because we just cannot move them on. But the choke management to your point that Phil and his group deals with is built in at this point in time. But I think even the future that's going to be the case because there's a lot of gas coming into our gathering system in one area off of 1 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 move 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 snapshots.
I appreciate the responses, Dan.
Thanks, David.
Our next question comes from Dara Leggate from Bank of America Merrill Lynch. Please go ahead with your question.
Thanks for squeezing me in guys. I just got 2 quick follow ups. It's maybe for Matt, first of all, on tax. You've given us the 20% to 50% 25% to 50 percent deferred tax assumption in 2020. Is that should we think of that as a kind of normalized range on a maintenance sustaining capital type of number or does it change further beyond that on your expectations?
And I've got a quick follow-up please.
Yes, thanks for the question. It's ultimately going to be dependent on realized price and level of capital spending and a lot of variables. It's really depending on what you're assuming. But at a call it $3 natural gas price holding 3.7 flat, you'll 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 deck have some benefits of either AMT or NOLs. So 2021, the assumption would be that we've utilized all of our NOLs and monetized all of our AMT.
That's pretty clear, Matt. Thanks. And I guess my final one is, Dan, it's probably for you, but as you step up the buyback and obviously you've laid out the free cash flow for the next several years, You're kind of transitioning to something like kind of annuity you would guess and your free cash flow type of investment case. In that scenario, what is the right 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 2. 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 dividend policy that we retract at some point in time with a draconian period in 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 mitigate that somewhat just simply by 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 meet our internal thresholds. So I'm sorry, I don't have a formula to give you, but I can tell you both are 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 very quickly here on the $75,000,000 you've allocated this year to your exploration projects, how much is in there for leasehold acquisitions and how many drilled and completed wells does that entail?
It's just a very small amount and it might be $1,000 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 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 5 or 6 wells. And from a science perspective, we would anticipate those wells to gather a great deal of science.
Okay, great. Thank you. Next quarter.
Thanks. Thank you.
Ladies and gentlemen, at this time, we've reached the end of today's question and answer session. I'd like to turn the conference call back over to management for any closing remarks.
Thank you, Jamie, and thanks for all the questions. And I assure you as a shareholder, I appreciate the consistency of Cabot's ability to deliver on its forecast. And quite frankly, additionally, I really appreciate the fact that its 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 all these 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 do thank you for attending. You may now disconnect your lines.