Good day, and welcome to the Cabot Oil and Gas 4th Quarter 2018 Earnings Conference Call. All participants will be in listen only mode. Please note this event is being recorded. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President and CEO.
Please go ahead.
Thank you, Allison, and good morning. Thank you for joining us today for Cabot's 4th quarter 2018 earnings call. With me today are several executive members of team Cabot. I would first like to emphasize 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.
As some of you may recall, this time last year, we laid out a strategy for 2018 that was focused on 1st, delivering growth in production and reserves per debt adjusted share, while generating positive free cash flow secondly, generating and improving return on capital employed that exceeds our cost of capital 3rd, increasing our return of capital to shareholders through dividends and share repurchases and 4th, maintaining a strong balance sheet to maximize financial flexibility. I'm very happy to report that we have successfully delivered on all the strategies that we had laid out for 2018. For the year, we delivered growth in production and reserves per debt adjusted share of 12% 25%, respectively. Most importantly, the company generated $297,000,000 of free cash flow, a 92% increase relative to the prior year. I would highlight that this is the 3rd consecutive year of positive free cash flow generation during a period in which the company generated an adjusted earnings per share CAGR in excess of 100%.
The company generated a 15.9% return on capital employed for the year, far exceeding our weighted average cost of capital and representing an improvement relative to prior year of 8 60 basis points. This 15.9% return on capital compares favorably to the average S and P 500 return on capital, highlighting that there is a company in the E and P sector that can in fact deliver returns that are competitive across the broad equity market. Additionally, we exceeded our initial expectations by returning over $1,000,000,000 of capital to shareholders, including increasing our quarterly dividend twice and repurchasing over 38,000,000 shares in 2018. This represented over a 9% shareholder yield to equity holders. Also, we have now reduced our shares outstanding by over 9% since restarting our share repurchase program in 2017.
Lastly, we demonstrated our continued commitment to maintain a strong balance sheet by reducing debt levels by approximately $300,000,000 resulting in a year end debt to EBITDAX ratio of 1 time. When considering the combination of cash dividends, stock repurchases and debt reduction, the company delivered a total stakeholder yield of over 12% for the year. In addition to these highlights, we delivered growth in adjusted earnings per share by 125%. Our results for the year demonstrate that despite the negative sentiment around the energy sector and return on capital, return of capital, while return on capital, return of capital, while maintaining investment grade balance sheet. As it relates specifically to the Q4 of 2018, the company generated net income of $275,000,000 or 0.64 dollars per share and adjusted net income of $236,000,000 or $0.55 per share.
Cabot's cash from operating activity in the 4th quarter was $316,000,000 while discretionary cash flow in the 4th quarter was $493,000,000 Cabot also delivered $241,000,000 of free cash flow during the Q4 of 2018, exceeding our previous expectation of $200,000,000 All of these improvements relative to the Q4 of 2017 were driven by higher production, stronger natural gas price realizations and a significant improvement in our cost structure. In fact, 20 18 represented the company's lowest unit cost in history. One specific operating expense I want to highlight is the exploratory dry hole cost we incurred in the 4th quarter resulting from unsuccessful drilling results in our second exploratory area. As a result, we do not expect to allocate any incremental capital to exploration at this time. Let's move on to reserve discussion.
Cabot reported year end proved reserves of 11.6 trillion cubic foot equivalent, an increase of 19% over year end 2017 despite the divestiture of our Eagle Ford property in 2018. Cabot's total company all source finding and development costs were 0.30 dollars per Mcfe, while our Marcellus only all source finding and development costs were $0.26 per Mcf. These results reaffirm our acreage position in Susquehanna County as the lowest cost natural gas asset in North America. As many of you are aware, we tested a sample of Upper Marcellus wells during 2018 with our Generation 5 completion design to further demonstrate the resource potential of this distinctive incremental reservoir. Based on the production history to date, the Gen 5 Upper Marcellus wells placed on production during 2018 have outperformed the average EUR per 1,000 lateral feet of 2.9 from our earlier generation Upper Marcellus completions.
To answer several questions regarding the Upper Marcellus, these results reconfirm our previous Upper Marcellus well results demonstrated, which is while the Upper Marcellus reservoir has its own distinctive characteristics relative to the Lower Marcellus, it remains one of the most economic reservoirs in North America. Our plan is to continue to drill and complete a small sample of Upper Marcellus wells each year to build a larger population of Gen 5 Upper Marcellus wells. Once again, these results coupled with our previous Upper Marcellus completions have extensive production history, reconfirming our conviction on the distinct nature of this reservoir and reinforce our views on the multi decade inventory life remaining from this world class asset. All right, move to the marketing and pricing update. Much of our success for the Q4 and full year was driven by the long awaited addition of new takeaway capacity in the basin, demand projects that have been work that we've been working on for years.
Cabot's realized natural gas prices before hedges improved by 50% relative to the prior year comparable quarter, driven by a combination of higher NYMEX prices and a significant improvement in differentials, which came in at $0.42 below NYMEX, our lowest level since the Q4 of 2013. Given the exposure we now have to highly seasonal markets in the Mid Atlantic, we expect our Q1 2019 price realizations to be flat to or even a slight premium to NYMEX. For the full year, we still expect our weighted average differential before the impact of hedges to be $0.30 On the hedging front, we utilized the short lived winter rally to layer in NYMEX and basis hedges, which we posted on our website this morning. We anticipate these hedges will generate over 55,000,000 dollars of additional revenue this year based on the current forward curve. We will continue to be opportunistic in layering in hedges during the market rallies in order to anticipated free cash flow for the year.
Now I'll provide commentary for 2019. For the full year, we updated our 2019 capital budget to $800,000,000 resulting in production growth of 20% or 27% on a debt adjusted per share basis. Our decision to target the lower end of our preliminary capital guidance range is the direct result of current market conditions, feedback from shareholders and the broader investment community and our continued strategic focus on returns and free cash flow over top line production growth. We believe that we have an industry leader and we have been an industry leader in deemphasizing growth for the sake of it and prioritizing return of and on capital while maximizing free cash flow. Our updated program for the year reaffirms our commitment to this philosophy and echoes our commentary from the Q3 earnings call last October.
We've certainly heard data points from the Appalachian peers that imply more rational approach to capital allocation in 2019 and Cabot fully supports the rationalization of capital to bring stability to the market. With that said, we have actually witnessed a slight increase in rig count in the Marcellus, Utica and Haynesville since our call last October. Meanwhile, despite early winter related rally, the NYMEX strip remains in backwardation. While we are cautiously optimistic on the supply demand outlook for the next 24 months, due in large part to significant demand growth and material based declines across the U. S, we believe it is prudent for us to plan more conservatively and utilize an incremental free cash flow resulting from higher prices for additional returns of capital to shareholders as opposed to funding additional outsized production growth.
As a result, we are using a 2.75 NYMEX assumption for budgeting purposes in 2019, which is below the current strip of approximately $2.90 when taking into consideration account an account for actual NYMEX settlements for January February. Under this more conservative price assumption, we expect to generate between $600,000,000 $650,000,000 of free cash flow, implying a 6% free cash flow yield. I would highlight this differs slightly from the $650,000,000 to $700,000,000 of expected free cash flow that we discussed on the Q3 call, which was based on a higher NYMEX assumption of $285,000,000 instead of the $275,000,000 we are using. As we highlighted on our Q3 call, we plan to return at least 50% of this free cash flow to shareholders annually through the combination of growing dividend and share repurchase, resulting in a minimum total shareholder yield of 3%. At 2.75 NYMEX, our 2019 program is expected to deliver between 40% 55% growth in adjusted earnings per share and between a 21% 23% return on capital employed.
Even under a 250 NYMEX assumptions, which some of the sell side is calling for, our program would deliver between $475,000,000 $525,000,000 of free cash flow, which implies a 5% free cash flow yield at the midpoint, also between 20% and 35% growth in adjusted earnings per share and a return on capital employed between 19% 21%. We believe these metrics are very compelling relative to the broader equity market, especially at these trough commodity price assumptions. I think it is also important to highlight that we are going to generate this type of free cash flow while continuing to reinvest in the disciplined growth of our assets via the drill bit. We will we have been numerous excuse me, we have seen numerous 2019 budgets released across the sector that implies significant reduction in capital spending year over year in order to target free cash flow neutrality. However, for some, the limited capital investment, there could be a day of reckoning in 2020.
In contrast, assuming price realizations are flat to 2019, our program for 2020 is designed 1st and foremost to deliver an improving return on capital employed and to generate strong free cash flow for the 5th consecutive year from a capital program that is lower than 2019, all while maintaining a pristine balance sheet. We expect to continue to deliver growth in cash flow and earnings per share in 2020, driven by disciplined capital allocation resulting in measured production growth. Additionally, the continued reduction in our shares outstanding resulting from our buyback program should further accrete per share metrics. Our decision to be more disciplined with our capital allocation for the year and deliver more measured growth will only do so much to help balance the market. We believe it is important to send a message to investors, both energy specialists and generalists alike that there is a company in the industry that is committed to disciplined capital allocation and has the assets that can generate a compelling combination of returns and growth in per share financial metrics even under much lower natural gas price assumptions and a reduced capital program.
In summary, I believe our strategic effort have continued to create incremental value for our shareholders as we have transformed Cabot into the lowest cost producer in industry with the lowest headcount and capital intensity, the highest capital efficiency and ultimately resulting in return on capital employed, free cash flow and per share growth metrics that are not only industry leading, but also extremely competitive when compared to all other sectors across the S and P 500. So with that, Allison, I'd be more than happy to open it up to questions.
Thank you. We will now begin the question and answer session. Our first question today will come from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning, Brian.
You've been very upfront on the return of capital to shareholders committing to at least 50% of free cash flow. How do you think about the at least or the plus in that as it relates to 2019? Cash balances seem to have kind of come down here at the end of the year. And maybe you could also comment on what you see as the right sustainable cash balance as you think about trying to manage the plus and the 50% plus of returning free cash flow to shareholders? Yes.
By design, we brought our cash balance down, felt comfortable with the infrastructure build out Atlantic Sunrise, the commissioning of those 2 power plants that with that and our ability to grow into deliveries on those infrastructures that our cash flow was not just an assumption, but it was a reality. And so we felt comfortable not only drawing down that cash balance, but repaying the $300,000,000 of debt and increasing the dividend anticipate in 2019. We kind of layered in a base assumption, Brian, at the 2.75 and the plus would come if in fact, we realize the 2.90, which the strip sits at today, if we realize the 290, then or something above that, then we're going to do what we've done in the past and that is to deliver some of the funds back to the shareholder. We'll make a decision whether it's in the form of dividend or buybacks. But it's not our intent with our confidence level of the cash flow we generate.
It's not our intent to leave a lot of cash on the balance sheet.
Great. Thanks. And then my follow-up is on the the midstream front. I don't know if you or Jeff are teed up for just the latest and greatest update on the various timing of projects and anything that's new that's coming onto the chalkboard, but that would be great if that's a possibility.
Yes, I'll flip it over to Brian I mean to Jeff, Brian.
Good morning, Brian. Yes, I think on the midstream, it's relatively quiet as we await some additional ruling with PennEast. I can tell you there are some new projects that have been laid out in front of us over the last few months that we're interested in. I don't think a lot of those has reached out into the public domain yet, but there's still a lot of movement on midstream projects. Additionally, I think even maybe more importantly is the additional in basin demand project that we're viewing.
There's quite a bit of activity, not just in Susquehanna County, but in that northeast corner of Pennsylvania with additional projects that are being developed to keep gas in the basin. And that's been exciting to watch as well.
Can I ask on the new projects you're talking about, are those to move gas to the New Jersey, New York markets, to the Southeast markets or dare I ask to the Northeast markets?
Yes. So I think a couple of them will do both. And the I don't think anyone's given up on building pipe out of Pennsylvania into either Jersey or New York and additionally moving gas back down into the South. But I think the pipelines will be talking about those in the next few months.
Yes, Brian. I'd like to add also on that point that not only would gas move out of basin like Jeff is referring to, there are also a number of in basin projects that he alluded to that we continue to work on that we think would not have it on the long haul pipes, but would have it from the tailgate of our gathering system. And we think that is meaningful just simply from the standpoint of how it assists in balancing the basis up there. I would also like to point out, while I take this time, some of my colleagues here want me to maybe not expand on questions. But I would point out that in the New York Post today, there was an interesting article and the results of his crusade against natural gas and the beginning of some of the issues that New York is experiencing up there, experiencing the form where it is starting to hurt small businesses, it's starting to hurt the development of new housing.
I think it's clear that businesses are going to be turning away from New York. And with all of this, including the largest utility in New York, representing that they will no longer accept applications for natural gas hookups, and that's Con Ed beginning March 15. I think these are all the early signs of that a policy that is creating a significant calamity in New York, and I think it will continue to have companies evacuate from doing business there.
Thank you.
Our next question will come from Jeffrey Campbell of Tuohy Brothers. Please go ahead. Mr. Campbell, your line is open.
Let's move on. Thank you.
The next question will come from Michael Hall of Heikkinen Energy. Please go ahead.
Yes, just curious, I guess, on as I was looking at your 1Q guidance, it seems pretty clear you guys aren't really like leaning into the winter market, let's say. Is that a view on the market's ability to take the volumes? Or is it more a function of just a strict adherence to your approach on capital discipline?
Well, we have our scheduled program. We have the time completion, Michael, when we get our pads, all the drilling completion done on particular pads. And at various times of the year, just sequentially, they come on at various different times and it gets a little bit lumpy. And so there's no particular master design on where we are in the Q1.
Okay. And do you have any sort of tail volumes that you could theoretically open up for opportunistic accessing of the market, I guess, for lack of a better way to put it, or are you kind of running full out in any given period?
No, we're producing what we can. The curtailed, if you will, volumes would be volumes that are adjacent that are wells that are adjacent to completing pads. We do shut in our existing production on some of the surrounding pads, surrounding wells, while completions are going on to help avoid frac hits and things like that. So but as far as having a block of curtailed volumes, we do not have that. Not only anticipate anybody in industry has that.
Okay, great. That's helpful. And then I guess last on my end is just on the Upper Marcellus. I'm just curious, yes, just exactly how much do you think you will allocate in the 2019 program on the Upper Marcellus? And are there any changes in completion design associated with We'll have a handful of wells
that we'll drill and whether 10, 15, that's kind of in the queue right now. I don't have the exact count in front of me, Michael, on the status of the drilling completion of the ones that we have scheduled for 2019. But we had a we're just a good sample pool of Upper Marcellus completions.
Great. I appreciate it and congrats on the execution guys.
Thank you.
Our next question will come from Charles Meade of Johnson Rice. Please go ahead.
Good morning, Dan, to you and your team there. Good morning, Charles. I wanted to pick up on you touched on this a bit in your earlier question, but wanted to explore a little bit more. When I look at the you guys have a slide showing how the basis has improved up to the Northeast. When I look at that, it looks to me that delivering volumes, you moved all these volumes on to Atlantic Sunrise, but delivering volumes into that local market looks it certainly looks more attractive than it has for most of the last few years.
And so but it my read on what you guys are doing is you guys are electing not to do that because you're keeping your CapEx low and it looks like you guys are or you've committed to doing more cash return to shareholders. So can you talk about how you went through that decision? I know it's something you look at all time, but how was the evaluation of delivering the incremental volumes into the local market look to you right
now? Well, and I'll flip it to Jeff to make commentary on the basis. But one quick comment is, with Atlantic Sunrise coming on, we knew we were going to transfer those volumes at a basin with a couple of long term contracts that we were fulfilling and price points out of the basin that were better than in basin pricing. So we're doing that. On the question about backfilling, we saw contemporaneous with the commissioning of Atlantic Sunrise and these power plants.
We saw a fairly drastic narrowing of the differential. And with that, that improved not only did we have an improvement by the gas that we moved on the new infrastructures and to the power plants, But that dramatic improvement in the basis also enhanced every other molecule that we were still selling into the basin. So with that uplift and the rest of our gas, we feel comfortable that maintaining that volumes we're producing and having just a measured growth by our capital allocation and allocating back some of our free cash and buying back shares and having a per share metric component to growth, we think that fits what we're trying to accomplish on improving realizations throughout not only the basin, but also where we're moving gas outside of the basin.
Yes. Good morning, Charles. Without getting too far into the weeds on this, we in Atlantic Sunrise, the reaction in the marketplace was pretty much what we expected. Of course, Cabot did redirect a large amount of volume from other pipes to fill Atlantic Sunrise. On the other hand, the other half, I guess, of Atlantic Sunrise, those volumes were being delivered into the Leidy system directly.
And so what we saw was a large amount of gas leaving the Leidy system as well as Cabot gas leaving the Leidy system, but then that influencing that Leidy basis fell back into the other pipelines as well. So and then along at the same time, we have a number of in basin projects, not just Cabot related, but other producer related projects. So it was somewhat of a perfect storm in a very good way this fall for the pricing and the basis in Northeast PA.
Got it. Thanks for that added color on that, you guys. And then if I can also ask Dan, back on the Upper Marcellus, what would you guys need to see in terms of well productivity or whatever the metric the relevant metric is for you? What would you need to see from those Upper Marcellus completions before you decided to perhaps co develop those with Lower Marcellus locations and save on the surface and bulb costs and things of that nature?
Well, I'll make a couple of comments. First, I'll make a comment regarding our comfort level since we received a number of not a number, but a couple of questions regarding our Upper Marcellus and how do you know it's distinctive. And I'm going to just give one example. We have a number of examples that we could give to you. But I'll give you one example that most people are not going to have any problems understanding how we have the conviction we do.
We laid 2 this recently, we laid 2 Upper Marcellus wells in an area that we had prior completions on our in the Lower Marcellus. And in this specific example, I'll give you, we had 2 Lower Marcellus wells that had been producing for an extended period of time. We put 2 Upper Marcellus wells, 400 feet, get that context, 400 feet from 2 Lower Marcellus wells that had produced a long time and we completed those 2 Upper Marcellus wells that were 400 feet from these 2 Lower Marcellus wells. It just so happened to be the 2 Lower Marcellus wells that we chose to do this experiment on have each cumed over 20 Bcf. Okay.
So we laid 2 Upper Marcellus wells, 400 feet from 2 wells that have cumed each 20 Bcf. Those Upper Marcellus wells came on normally as you might expect. The early time production from those Upper Marcellus wells have actually fit a curve. And again, I'm going to caution the comment here on curve fit with very little data. But those 2 Upper Marcellus wells came on fitting a curve of 3.3 Bcf per 1000 and 3.7 Bcf per 1000.
I'm not saying that that's what we're going to go to. So don't take it and I hope nobody comes and ask about what about the 3.3, 3.7 Bcf type 1,000 EUR. That might be our poster, Charles, from this point forward. I'm just giving you an example of our competent level. If there's any place we would have seen some issues, it would have been where we had produced over 40 Bcf, 400 something feet away from a couple of Upper Marcellus.
So that's that soapbox commentary in that. What was the rest of your question? Scott wants to Scott's been raising his hands.
But Charles, I think back to the at what point would you go to taking a word out of the West Texas, the Encana playbook, the cube kind of concept. The other thing that plays into that is what is the takeaway capacity in that part of our field at this point in time. What we wouldn't want to do is do all of the lowers and the uppers and then be constrained because we wouldn't be able to get that gas to market. And why in addition to it being most efficient to do the lowers than the uppers and come back and do the uppers later. And Dan's example right now highlights that there's no degradation when we came back.
That's still the primary focus of how we're going to do it. The really only downside is the mob cost you mentioned because we're building the pads where we can come back on them and all that kind of stuff. So there's not a lot of lost efficiency. What we don't want to do is instruct Williams to put a huge pipe out there that will never be filled again after the initial production. That's just not efficient from that side of the equation.
So that's kind of the dynamic. We will do some science tests like Dan highlighted earlier where we'll do we got 10 or 15 that we think I think that's the latest number in the 2019 program. We did 9 in the 2018 program. We'll continue to do a few handfuls of these as part of the science project going forward. But in terms of full development of the full pad outside of maybe 1 or 2 for science purposes, it's still most efficient to do what we're doing.
That's helpful, Scott. And thank you, Dan and Jeff, for your comments as well.
Thanks, Charles.
The next question will come from Mike Kelly of Seaport Global. Please go ahead.
Hey, guys. Good morning. Good morning. Just wanted to check-in with you guys on the of that project. And just wanted to get your perspective on it and your thoughts.
Thanks.
Well, we have maintained our efforts to get some movement in Constitution. The DC Circuit Court of Appeals had a ruling, a favorable ruling in a similar case, a fact pattern case that was favorable to Constitution's fact pattern. And the FERC is there's still consideration out there, I guess, and a sense on maybe what might happen next. And we think the ruling in the BC Circuit Court of Appeals is again favorable if you then take the fact pattern that we have in constitution. And that has to do with the waiver consideration.
So we hope we'll have maybe at some point in time another time to have this addressed and we continue to work on that.
Okay. Any sense of timing on that or what the next step is for us to look for?
No. We have with all the uncertainty, I'd be speculating, Mike. But I would think that I would hope that sometime in the first half of twenty nineteen that we would have some additional consideration from the courts, from FERC or something that might opine on this.
Our next question will come from Leo Mariani of KeyBanc. Please go ahead.
Hey guys, don't want to harp too much here on the Upper Marcellus, but
I know you guys I think said you
had 9 wells that you guys did work on in 2018, not ready at this point to kind of come out with any more defined EUR estimates. But out of curiosity, I mean how much production history do you think you need to see on some of those wells to give you guys a better sense of what the Upper Marcellus EURs look like? And what how old are some of the kind of wells that you fracked in 2018? Just trying to get a sense of how much history you have now and how much you think you need to give us a little better handle on it?
We need a year, year and a half and the 18 wells are none of them are a year old yet.
Okay. That's helpful. And I guess just turning to the exploration side, I guess obviously you guys kind of abandoned your most recent effort here of late. I just wanted to get a sense, I mean, is there a continued appetite for Cabot to kind of look at other plays either this year or next to try to continue to sort of build the company? Just want to get a sense of your thoughts on looking at other plays.
Obviously, you've got a tremendously high rate of return opportunity right now, which is a pretty high bar. So how should we think about that going forward?
Yes. Right now, we have no interest in allocating any additional capital to exploration. And so the answer today is that's where we stand.
All right. Thank you.
Our next question will come from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Thanks. Good morning, Dan, and thanks for all the information this morning. I'm just wondering if you could give us an update on your exploration ambitions beyond obviously the news today. What's next? Are you going to stick with Marcellus in a go forward basis?
We
you might have been might not have heard the answer previous call, But we're not going to allocate any more capital to exploration at this time and that's kind of where we are.
Okay. Sorry, I did miss that. I apologize. My follow-up is really just a quick one, I guess, because we haven't really asked your opinion on the gas market for quite some time. And obviously, after the Q1, the Q4 strength that we saw, I think that some folks were of the view that the idea of just in time production was probably not the right model going forward and we are in fact going to have a more resilient outlook.
I'm just wondering if you could give us your prognosis on how you see things playing out over your plan period? And I'll leave it there. Thanks.
Couple of moving parts in that and that's a that can be a long winded response, but a couple of moving parts in the way I look at it is, 1, I think it is imperative that our industry rationalize the market in a way that is prudent for all shareholders. And I think there are signs that rationalization is taking place even though from October to current, there seems to be more rigs working today than they were back in October. We did see in December January a little bit of reduction in at least up in the Appalachia area, a flattening or reduction in production up in that area. So that would be helpful. But in looking at the demand side of the equation, I'm optimistic that there is going to be another 3 Bcf or 4 Bcf a day going offshore by commissioning of the LNG facilities.
We're seeing incremental demand that is needed up in New York and up in the Boston area. When utilities now in Boston are talking about not taking application for new natural gas hookups. That means that demand is increasing and there's a need for additional natural gas up there. So I'm encouraged by incremental demand up there in that particular area. So and I also think that it's proven from your side of the equation, Doug, that if in fact there's reward on value and there is expectation that value would be returned to shareholders in the form of buybacks of dividends and that's meaningful, then that is going to help assist with the market as opposed to some that keep focused on growth at the at all cost.
And so I think all of this is part of the forward look on natural gas. But I also think that natural gas plays a role on any of the renewable footprint out there, natural gas better be part of the equation. Otherwise, the responsiveness to the and security of a delivery of energy is going to be challenged.
Well, Don, you guys have done an outstanding job in a tough gas state. So congratulations on that and I really do appreciate your perspective. Thank you.
Thanks, guys.
The next question will come from Jane Graseckow of Stifel. Please go ahead.
Good morning. Dan, could you please expand on what drove the 19% year over year increase in proved reserves in 2018. It looks like the increase in reserves is well above the 3 year average run rate. And I was just curious if it's due to the outperformance of the existing wells. So is it like the recent well results have been particularly strong or something else that would explain that?
Thanks.
All right. And I'll Steve Lindeman is in here and he is responsible for our reserve bookings and I'll let him cover that. Thanks for the
question. So part of what drove most of our revision this year was drilling longer laterals than we had modeled in our '17 reserve report. As time has progressed, we've upped our lateral length. Our average PUD was about 5,000 500 feet and our wells that we drilled were in the 8,000 foot range.
Okay. Got it. Got it. And then my second question is for Jeff. Jeff, could you please expand a little bit on fixed price sales that account for 16% of the sales mix in 2019, is it something that we should expect to take place in 2020 plus as well?
And how do you think the pricing for those volumes will evolve over time?
Jane, I'm going to grab the table real quick Steven, sure. Thank you, Matt. You're asking about the change on in 2019 on the NYMEX portion?
Yes. So you have fixed price sales. It seems to me that those are firm sales, but I'm not sure if those are firm sales that you roll over maybe on a quarterly or an annual basis. And I'm just curious how that portion will evolve over time in terms of volumes and pricing?
Okay. Well, on the fixed price portion, that's, of course, is a combination of some of our contracts that have fixed price floors in them. And so going forward, that piece of that fixed price 16% will remain static. However, another part of the fixed price is just from opportunities we've seen in the marketplace. So I would expect that to continue to be dynamic If we have opportunities to convert some NYMEX or some index based pricing to fixed price, we will take advantage of that.
So that one is more of a moving target that we can't really elaborate on going forward into 2021 or 2022.
I see. I see. And in terms of pricing, how are those volumes priced? Is it should we think about them in terms of comparable pricing to 'nineteen? Or can you comment on that as well?
No. That's built into the overall how we calculate the overall basis differential to NYMEX looking forward, so it moves around.
Ladies and gentlemen, this will conclude our question and answer session. At this time, I'd like to turn the conference back over to Mr. Dinges for any closing remarks.
Just briefly, I appreciate everybody's interest in Cabot. I think it is interesting and I reflect on the release we've made and looking at our not only our press release, but the comments in this morning's report. It's interesting to have an E and P company make a report that does not talk about how much a particular pad has come on or what a zone has done, what a yield is on the well, but talk strictly about what type of financial performance we can deliver to the shareholders. And I think that is certainly what we're hearing is the shareholders are very interested in value and value creation. And I hope it is getting a little bit agnostic that just because we do it with natural gas does not mean that we have a flawed company.
So with that, Allison, I appreciate the interest and we'll conclude the call.
And thank you, sir. The conference has now concluded and we thank everyone for attending today's presentation. You may now disconnect your lines.