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. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star and then one using your telephone keypad. To withdraw your questions, you may press star and two. Please also note today's event is being recorded. At this time, I'd 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. I appreciate you joining us for Cabot's fourth 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 the 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 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 $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 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 ROC 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-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 Eagle Ford closes as expected next week, our go-forward finding cost will be primarily related to our Marcellus asset, which recorded all-source finding and development costs of $0.22 per Mcfe in 2017, as well as an F&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 a combined proceeds of approximately $840 million, 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 of capital, and one of the strongest balance sheets 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 and our view of the company's intrinsic value. We have been in an earnings-related blackout period since year-end. However, our 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. Moving on, a couple of comments on our operating plan. This morning's release, we reaffirmed our 2018 daily production growth guidance range of 10%-15%, or 18%-23% on a divestiture adjusted basis. We also refined 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 weighted towards the second half of the year due to the mid-year in-service dates 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. 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 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 million, a de-levering of the balance sheet to below a one-time net debt to EBITDA, 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. 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. A 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. 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 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-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'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 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-fired generating facilities will add approximately 400 million cubic foot per day of demand exclusively for Cabot. The Moxie Freedom plant remains on track for a June 1st, 2018 startup date and 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 1st and December 1st, respectively. These two high-profile local demand projects will provide opportunities for growth and improve 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.
Last month, we petitioned the U.S. Supreme Court to review the judgment of the U.S. 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. 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.
We expect to be able to grow our production base above this level through one or more of the following avenues: additional sales on currently approved takeaway projects, including Atlantic Sunrise and PennEast, incremental sales on potential future expansion projects, increasing our in-basin market share, new in-basin demand projects, and future greenfield takeaway projects. On our three-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 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 $2.75-$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%-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 $1.6 billion-$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 contribution 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 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.
Ladies and gentlemen, at this time, we'll begin the question and answer session. To ask a question, you may press star and then one on your telephone keypad. If you are using a speakerphone, we do ask that you please pick up your handset before pressing the keys to ensure the best sound quality. To withdraw your question, you may press star and two. Once again, that is star and then one to ask a question. And our first question today comes from Michael Glick from JPMorgan. Please go ahead with your question.
Hey, guys. Morning.
Hi, Michael.
Just on the buyback, do you see the program ultimately transitioning from being opportunistic in nature to more of a systematic program? 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, by just really available cash and the plowback into our operations side of the business. In line with 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.
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're going to generate a significant amount of free cash.
Got it. I noticed you guys put some basis hedges on. Could 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?
Yeah. I'll pass that baton to Jeff.
Yeah, Michael, as you know, in December and early January, we had a good, strong rally for Dominion South, also Leidy, Tennessee, Millennium, and also down in non-New York areas. We took advantage of that to layer in about 100,000 a day of fairly strong basis differentials for Leidy. We're going to continue to look at that. We're looking at some summer onlys and some winters of 2018, 2019 right now. Again, when opportunity knocks, we'll be hedging the bases up there.
Got it. Okay. Thank you, guys.
Yep. Thank you, Michael. I might add that we are in about the 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.
Morning, Jeffrey
Congrats on the seemingly inexorable COG machine. I was going to ask two questions. One, 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?
Yeah, 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. 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. 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 a Gen 5 completion. Those levels that are the completions and frack stages that are beyond 10,000 feet, we are actually going to our Gen 4 completion. Once we bring in the same wellbore, come back to the frack stages inside of 10,000 feet, we go to the Gen 5.
Okay. That's an interesting color, 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. 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?
Yeah. 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. I'll let Jeff talk about his expectations for commissioning.
Yeah, Jeffrey, we watch it very closely, of course. 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 more importantly, the timing of when those utilities will be out searching for new supplies, and obviously it'll be closer to when there's more clarity on the in-service. Dan's correct, the last remaining land issues are generally solved after the FERC certificate has been issued, and that's what's 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. That's what's going on right now.
There has been some news and some resistance by some of the environmental groups, there's been some information requested by the New Jersey DEP as of last week with FERC. A lot of that is work in progress, yes, it slows down the pace. As kind of an outsider on this project, but close to it, we're still expecting construction to be 2018. 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 Venker from Morgan Stanley. Please go ahead with your question.
Morning, everyone.
Hello, Drew.
I was hoping 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 could move into development mode or any color you could provide there would be helpful.
Yeah. 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 and beat our returns that we have laid out with our expectations. 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 to 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.
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 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. 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 an outlay for a multi-billion dollar company, $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. Still think you'll be on track to make a call on whether you should move forward or not later this year?
Yes, I do, Drew.
Okay. That's all I had. Thanks, guys.
Yeah. Thank you.
Our next question comes from Holly Stewart from Scotia Howard Weil. Please go ahead with your question.
Good morning, gentlemen.
Hey, 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. 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 worked intimately with it.
Okay.
Hey, Holly, it's Matt Kerin. Yeah, 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 what was going on with EBIT for 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 as a result of the tax rate coming down as well as AMT going away, whereas the October forecast would've assumed about a $450 million cumulative current tax leakage during the three-year plan. We're now talking about maybe only $50 million of current taxes during that period, and that's net of obvious refunds that we'll get during the period.
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. That AMT that's refundable for 2018, are you all expecting that in 2018?
No, the reality is that we won't get it until we file our tax return in the subsequent year.
Okay. 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. 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.
Yeah. We feel very good about our budget. I think you saw in 2017 how close we were to our expected expenditures, I feel equally confident in 2018 about our program. The Marcellus is a consistent, consolidated block up there. We use the service providers on the drill side and the completion side that we have had in the recent past. With our annual contract and lock-in for the most part, we're 85%-90% locked in on service cost. That is off of that understanding. That's how we built this 2018 program. The additional 10%-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. We think with 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.
Hey, 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?
Yeah. I'll just pass it over to Jeff. He does this day in and day out. 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. He's working diligently every day to accomplish the future.
Okay, Brian, 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. 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. Market share in the basin up there near term and longer term is certainly a growth wagon for us.
Got it. 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. We will watch the regional prices up there, and we'll look at our opportunities with Sunrise and PennEast. 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. We're also looking at the opportunities we have off the gathering system with new businesses and new industry and new opportunities there. It all goes hand in hand, but I think as you see differentials tighten in Northeast P.A., that we'll take advantage of that.
That was a little bit of my follow-up as well, 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? Then where geographically do you think the next greenfield takeaway goes?
Okay, well, both of those questions have to do with ongoing projects that we're looking at. 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're talking with and what type of industry that we're talking with on connecting a new industry to the gathering system. 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.
In basin, 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 really unique ideas that we have and hadn't got a lot of traction is to lay a pipeline 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 cleaner burning natural gas.
Great. Thank you. I'd ask a fifth question on what the interest level is on the other side of the board, maybe I'll take that one offline.
Thank you, Brian.
Our next question comes from Dave Kistler from Simmons & Company International, Energy Specialists of Piper Jaffray. Please go ahead with your question.
Good morning, guys. Thank you. Real quickly, 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, et cetera. Can you talk about what you're thinking about as far as potentially Gen 6, what you can tweak, or are we at a maximum level of IRR per well at this juncture?
Well, each call, I think, Dave, we've had the question about where you reach maximum efficiencies. You can look historic and see the progress that's been made. Gen 5, Gen 6 is one of those efforts that we're trying to create incremental gains in efficiency. That gain in 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 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. 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 ±20% more effective than the Gen 6. 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.
That makes sense. I appreciate that coloring. 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 threshold prices, realizing that you recover your cost of capital at north of a dollar and a half?
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 shareholder's pocket as opposed to giving it away. If, in fact, there's such a punitive market out there, we would consider a curtailment, and by doing that proportionally across the field, respond to the punitive market. Yes, with our cost structure now, what our finding cost is, what our cost of capital is, we still would receive a return. 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 coloring, certainly applaud you guys on the capital stewardship. Phenomenal.
Yeah. Thank you, Dave.
Our next question comes from Michael Hall from Heikkinen Energy. Please go ahead with your question.
Thanks. Good morning.
Hi, Michael.
Hi. 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?
Yeah. We look at it 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. 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. To determine whether or not it fits in our portfolio, though, is still an extremely conservative process. The history that Cabot has displayed and the decisions that we've made on being acquisitive 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. 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. 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. Yeah, it just seems like there's potential willing sellers in your direct neighborhood there. I guess TBD. We'll keep an eye out. Take a 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-
Okay
is where we go out on-
Decade. Yeah.
A decade.
Yeah, not month. Year 2020.
Yeah. The latter, yeah, the decade. Scott has always been there to protect me. The latter, almost to 2030, about that.
Okay. That's clear.
We're comfortable with our lower Marcellus position, 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 with in 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. I'm anxious to see what the upper Marcellus will do with the new completion, so.
Great.
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. I expect an uptick from what we historically have seen in the upper Marcellus to where we're going.
Okay, great. That's helpful. I guess, can you just remind us what the cost savings are on Gen 5 versus Gen 4? You said it's 20% cost effective versus 6. I'm just curious on 5 versus 4.
5 versus 4, we're 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.
All right. Thanks, Michael.
Our next question comes from Mike Kelly from Seaport Global. Please go ahead with your question.
Hey, guys. Good morning.
Hi, Mike.
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. 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. Yeah. Mike and I'll let Jeff answer that. I will make a comment that, 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 companies did and commit to that structure. We've worked around it by advanced sales on Atlantic Sunrise and having a complete tie-down of the volumes from delivery into the pipe all the way to the sales point. That was one thing we did different. A lot of our gas moves on third-party firm as opposed to a Cabot dedicated firm. We're not in a situation where we have to move gas under firm contracts. I'll pass it on to Jeff.
Sure. Mike, maybe just to elaborate on the few answers that we had 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. 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. I think you'll see progress as we get closer to in-service, maybe around the time that PennEast gets its notice to proceed with construction.
I think that'll 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. As we build that in-basin activity, it's going to add up. We're currently outside the power plants. We're probably in the 50,000, 60,000 a day range currently. We're getting ready to gasify a small town up there in Pennsylvania called Pocono. Not a big load, but we continue to add customers up there. It's going to all add up. I think 2018 will 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. More on that to come. We're still a long way off, we never stop looking.
Good call. Appreciate that. Maybe just out of curiosity, how big of a project could that pipe to ultimately displace the fuel oil in New York be? 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 inchers.
All right, Jeff. Appreciate it.
There's 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. 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 the fence line from them. It's just one of those unfortunate circumstances that we're living with today. 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.
Morning, Dan, Jeff, Scott, everyone. Thanks for squeezing me in.
Yeah.
My question is really just Gen 5 or any of the Marcellus type curves right now you're getting the 4.4 Bcf per thousand. 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're baking in any performance improvements. Is it fair to say that we haven't necessarily gotten a full look at the productivity of these completions just given a constrained environment? Should we expect to see kind of accelerating type curves with more capacity coming online to perhaps show a better productivity uplift? 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 and the way we bring on the wells, Phil and his guys are committed to maximize the EURs in these wells. Yes, we have been somewhat constrained by how we bring these wells online. 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 to take advantage of any disconnect in the market. I think we'll 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 than we measure them today. I just don't have an answer on what the results might be with that additional data. We are certainly encouraged with the flexibility that one, our gathering system provides us, but also the additional flexibility of moving gas in and out of the basin. That moving out of the basin cannot be overemphasized on what I think it will do to some of the in-basin differential issues that we've had in the past.
Okay. Certainly, I understand it on the pricing side. It sounds like testing at least pressure management would be more of a later 2018 thing. If there was a change to designs, it wouldn't really start coming through until 2019 or 2020, I guess. Is that fair?
Well, yeah. You can look at it a little bit differently. You can look at it, for example, in the first quarter of 2018, we haven't 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. 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 us down. 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. By that measure, we still are moving the gas that we need to move and all of that.
In the beginning of the second quarter, we're going to bring on these, in fact, two large pads, 15, 20 type of wells in the second quarter 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 you cannot move them all. The choke management, to your point, that Phil and his group deals with is built in at this point in time. 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 one pad site, and that has to be managed through the gathering system. That's some of the effort that's ongoing by Williams and our gas controllers on how we can manage that.
Having the additional flexibility, how we can move that gas is going to help as we bring on these large volumes. It's the nature of the beast, 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. 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 Doug Leggate from Bank of America Merrill Lynch. Please go ahead with your question.
Thanks for squeezing me in, guys. I've just got two quick follow-ups. It's maybe for Matt, first of all, on tax. You've given us the 25%-50% deferred tax assumption in 2020. 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? I've got a quick follow-up, please.
Yeah, thanks for the question. It's ultimately going to be dependent on realized price and level of capital spending and a lot of other variables. It's really depending on what you're assuming. At a, call it $3 natural gas price, holding three seven flat, you'll actually probably be closer to 75%-85% current. 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. 2021, the assumption would be that we've utilized all of our NOLs and monetized all of our AMT.
No, that's pretty clear, Matt. Thanks. I guess my final one is, Dan, it's probably for you, as you step up the buyback, obviously you've laid out the free cash flow for the next several years, you're kind of transitioning to something of a kind of annuity, you would guess, an annuity 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 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 retract at some point in time with a draconian period in the commodity space. 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 give back to the shareholder.
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. I'm sorry I don't have a formula to give you, 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.
Our next question comes from Bob Morris from Citi. Please go ahead with your question.
Thanks. Dan, just very 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 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. 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. 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. 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. I can assure you, as a shareholder, I appreciate the consistency of Cabot's ability to deliver on its forecast. 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. I assume the job of continuing to deliver on these stellar results. Thank you again for the interest, and I'll 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.