Good day, welcome to the Cabot Oil & Gas Fourth Quarter 2018 Earnings Conference Call. All participants will be in 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 then one on your telephone keypad. To withdraw your question, please press star then two. 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. Good morning. Thank you for joining us today for Cabot's fourth 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, first, delivering growth in production and reserves per debt adjusted share while generating positive free cash flow. Secondly, generating an improving return on capital employed that exceeds our cost of capital. Third, increasing our return of capital to shareholders through dividends and share repurchases.
Fourth, 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 for debt adjusted share of 12% and 25%, respectively. Most importantly, the company generated $297 million of free cash flow, a 92% increase relative to the prior year. I would highlight that this is the third 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 860 basis points.
This 15.9% return on capital compares favorably to the average S&P 500 return on capital, highlighting that there is a company in the E&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 billion of capital to shareholders, including increasing our quarterly dividend twice and repurchasing over 38 million 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 million, resulting in a year-end debt-EBITDAX ratio of one 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 specifically as it relates to natural gas base, Cabot is generating a compelling combination of growth, free cash flow, return on capital, return of capital, while maintaining investment-grade balance sheet. As it relates specifically to the fourth quarter of 2018, the company generated net income of $275 million, or $0.64 per share, and adjusted net income of $236 million or $0.55 per share. Cabot's cash from operating activity in the fourth quarter was $316 million, while discretionary cash flow in the fourth quarter was $493 million.
Cabot also delivered $241 million of free cash flow during the fourth quarter of 2018, exceeding our previous expectation of $200 million. All of these improvements relative to the fourth quarter of 2017 were driven by higher production, stronger natural gas price realizations, and a significant improvement in our cost structure. In fact, 2018 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 fourth 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 per Mcfe, while our Marcellus only all source finding and development costs were $0.26 per Mcfe. 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's 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 fourth quarter and full year was driven by the long-awaited addition of new takeaway capacity in the basin, demand projects 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 fourth quarter of 2013. Given the exposure we now have to highly seasonal markets in the mid-Atlantic, we expect our first quarter 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 million 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 protect our anticipated free cash flow for the year. Now we will provide commentary for 2019. For the full year, we updated our 2019 capital budget to $800 million, 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 been an industry leader in de-emphasizing 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 third quarter earnings call last October. With that said, we have actually witnessed a slight increase in the 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 base 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 and account for our actual NYMEX settlements for January and February. Under this more conservative price assumption, we expect to generate between $600 million-$650 million of free cash flow, implying a 6% free cash flow yield.
I would highlight this differs slightly from the $650 million- $700 million of expected free cash flow that we discussed on the third quarter call, which was based on a higher NYMEX assumption of $285 instead of the $275 we are using. As we highlighted on our third quarter 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 $275 NYMEX, our 2019 program is expected to deliver between 40% and 55% growth in adjusted earnings per share and between a 21% and 23% return on capital employed.
Between $250 NYMEX assumption, which some of the sell side is calling for, our program would deliver between $475 million and $525 million of free cash flow, which implies a 5% free cash flow yield at the midpoint. Between 20% and 35% growth in adjusted earnings per share and a return on capital employed between 19% and 21%. We believe these metrics are very compelling relative to the broader equity market, especially at these trough commodity price assumptions. I think it's 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 have seen numerous 2019 budgets released across the sector that imply significant reduction in capital spending year-over-year in order to target free cash flow neutrality.
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 first and foremost to deliver an improving return on capital employed and to generate strong free cash flow for the fifth 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 efforts have continued to create incremental value for our shareholders as we have transformed Cabot into the lowest cost producer in the 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&P 500.
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. To ask a question you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause for a moment to assemble our roster. Our first question today will come from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
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. 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.
Yeah. By design, we brought our cash balance down, felt comfortable with the infrastructure build at Atlantic Sunrise, the commissioning of those two power plants. With that and our ability to grow into deliveries on those infrastructures, our cash flow was not just an assumption, but it was a reality. So we felt comfortable not only drawing down that cash balance, but repaying the $300 million of debt and increasing the dividend twice this last year, and with a billion dollars of buyback. Right now, with the free cash flow generation that we anticipate in 2019, we layered in a base assumption, Brian, at the 275. Excuse me. The plus would come if, in fact, we realize the 290, which the strip sits at today.
If we realize the 290 or something above that, 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. 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. My follow-up is on 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.
Yeah. I'll flip it over to Jeff. Brian.
Good morning, Brian. Yeah, I think on the midstream, it's relatively quiet as we await some additional ruling with PennEast. I can tell you that 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 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 that 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? Yeah.
I think a couple of them will do both. I don't think anyone's given up on building pipe out of Pennsylvania into either Jersey or New York, additionally moving gas back down into the South. I think the pipelines will be talking about those in the next few months.
Thank you.
Yeah, 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. 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 on Cuomo 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. 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 15th.
I think these are all the early signs of a policy that is creating a significant calamity in New York, and I think it'll 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.
Yeah. Just curious, I guess as I was looking at your 1Q guidance, seems pretty clear you guys aren't really 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. 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 first quarter.
Okay. Do you have any sort of curtailed volumes that you could theoretically open up for opportunistic accessing of the market, I guess, for lack of a better way to put it? Are you running full out any given period?
No, we're producing what we can. The curtailed, if you will, volumes would be volumes 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 frack hits and things like that. As far as having a block of curtailed volumes, we do not have that, and I don't anticipate anybody in the industry has that.
Okay, great. That's helpful. Then I guess last of mine is just on the Upper Marcellus. I'm just curious. Just exactly how much do you think you will allocate in the 2019 program on the Upper Marcellus? Are there any changes in completion design associated with-
We have a handful of wells.
- activity?
We'll have a handful of wells that we'll drill whether it's 10, 15, that's 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, we had a good sample pool-
Okay
-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.
Morning, Dan, to you and your team there.
Hey, Charles.
Hey, You touched on this a bit in your earlier question, but wanted to explore a little bit more. You guys have a slide showing how the basis has improved up in the Northeast, and when I look at that, it looks to me that delivering volumes, you moved all these volumes onto Atlantic Sunrise, but delivering volumes into that local market certainly looks more attractive than it has for most of the last few years. 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 looks like you guys or you've committed to doing more cash return to shareholders. Can you talk about how you went through that decision?
I know it's something you look at all the time, how was the evaluation of delivering the incremental volumes into the local market look to you right now?
I'll flip it to Jeff to make a commentary on the basis. One quick comment is, with Atlantic Sunrise coming on, we knew we were going to transfer those volumes out of 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. 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 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.
With that uplift and the rest of our gas, we feel comfortable that maintaining the 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.
Good morning, Charles. Without getting too far into the weeds on this, 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. What we saw was a large amount of gas leaving the Leidy system as well as Cabot gas leaving the Leidy system.
That influence in that Leidy basis fell back into the other pipelines as well. Along, at the same time, we have a number of in-basin projects, not just Cabot related, but other producer-related projects. 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. 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 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 mob 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 couple of questions regarding our Upper Marcellus and how do you know it's distinctive. 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. Recently, we laid two Upper Marcellus wells in an area that we had prior completions in the Lower Marcellus. In this specific example I'll give you, we had two Lower Marcellus wells that had been producing for an extended period of time. We put two Upper Marcellus wells 400 feet.
Get that context, 400 feet from two Lower Marcellus wells that had produced a long time. We completed those two Upper Marcellus wells that were 400 feet from these two Lower Marcellus wells. It just so happened to be the two Lower Marcellus wells that we chose to do this experiment on have each cum'd over 20 Bcf. Okay, we laid two Upper Marcellus wells 400 feet from two wells that had cum'd 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. Again, I'm going to caution the comment here on a curve fit with very little data. Those two Upper Marcellus wells came on fitting a curve of 3.3 Bcf per thousand and 3.7 Bcf per thousand.
I'm not saying that that's what we're going to go to. Don't take it, and I hope nobody comes and ask about what about the 3.3.7 Bcf type thousand EUR? That might be our poster child from this point forward. I'm just giving you an example of our confident level. If there's any place we would've seen some issues, it would've been where we had produced over 40 Bcf 400 something feet away from a couple of Upper Marcellus. That's soapbox commentary in that. What was the rest of your question?
Well, what would-
Scott wants to Scott's been raising his hand, so.
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. 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. 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. That's the dynamic. We will do some science tests like Dan highlighted earlier, where we got 10 or 15 that we think I think that's the latest number in the 2019 program. We did nine in the 2018 program. We'll continue to do a few handfuls of these as part of the science project going forward.
In terms of full development of the full pad outside of maybe one or two for science purposes, it's still most efficient to do what we're doing.
That's helpful, Scott. 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. Great update.
Mike.
Just wanted to check in with you guys on the Constitution Pipeline. RBN had an article out this week that at least expressed some sort of hope in a revival of that project. 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 D.C. Circuit Court of Appeals had a favorable ruling in a similar case, a fact pattern case, that was favorable to Constitution's fact pattern. The FERC, there's still consideration out there, I guess, in a sense on maybe what might happen next. We think the ruling in the D.C. Circuit Court of Appeals is, again, favorable if you then take the fact pattern that we have in Constitution. That has to do with the waiver consideration. We hope we'll have at 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?
With all the uncertainty, I'd be speculating, Mike, but I would hope that sometime in the first half of 2019, that we would have some additional consideration from the courts, from FERC or something that might opine on this.
Got it. Thanks, guys.
Thank you.
Our next question will come from Leo Mariani of KeyBank. Please go ahead.
Hey, guys. Don't want to harp too much here on the Upper Marcellus, I know you guys, I think, said you had nine wells that you guys did work on in 2018. Not ready at this point to come out with any more defined EUR estimates. Out of curiosity, 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? 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 and a half. The 2018 wells, none of them are a year old yet.
Okay, that's helpful. I guess just turning to the exploration side, I guess obviously you guys abandoned your most recent effort here of late. I just wanted to get a sense, is there a continued appetite for Cabot to look at other plays, either this year or next, to try to continue to just 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. How should we think about that going forward?
Yeah. Right now, we have no interest in allocating any additional capital to exploration. 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 on a go-forward basis?
You might not have heard the answer previous call, 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 fourth quarter 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. I'll leave it there. Thanks.
Couple of moving parts in that can be a long-winded response. A couple of moving parts in the way I look at it is, one, I think it is imperative that our industry rationalize the market in a way that is prudent for all shareholders. I think there are signs that that rationalization is taking place, even though from October to current, there seems to be more rigs working today than there were back in October. We did see in December and January a little bit of reduction in, at least up in the Appalachia area, a flattening or reduction in production up in that area. That would be helpful. In looking at the demand side of the equation, I'm optimistic that there is going to be another 3 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. I'm encouraged by incremental demand up there in that particular area. 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 all cost. I think all of this is part of the forward look on natural gas.
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, Dan, you guys have done an outstanding job on a tough gas tape, congratulations on that, I really do appreciate your perspective. Thank you.
Thanks.
The next question will come from Jane Trotsenko of Stifel. Please go ahead.
Good morning. Dan, could you please expand on what drove the 19% year-over-year increase in approved reserves in 2018? It looks like the increase in reserves is well above the three-year average run rate, I was just curious if it's due to the outperformance of the existing wells, or is it like the recent well results have been particularly strong or something else that would explain that? Thanks.
All right. Steven Lindeman is in here, he is responsible for our reserve bookings, I'll let him cover that. Thank you for the question.
Part of what drove most of our revision this year was drilling longer laterals than we had modeled in our 2017 reserve report. As time has progressed, our lateral length, our average PUD was about 5,500 feet, and our wells that we drilled were in the 8,000-foot range.
Okay. Got it. 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? How do you think the pricing for those volumes will evolve over time?
Jane, I'm going to grab the table real quick to make sure. Thank you, Matt. You're asking about the change in 2019 on the NYMEX portions?
Yeah. 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. I'm just curious how that portion will evolve over time in terms of volumes and pricing.
Well, on the fixed price portion, that of course, is a combination of some of our contracts that have fixed price floors in them. 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. 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. That one is more of a moving target that we can't really elaborate on going forward into 2021 or 2022.
I see. In terms of pricing, how are those volumes priced? Should we think about them in terms of comparable pricing to 2019, or can you comment on that as well?
No, that's built into how we calculate the overall basis differential to NYMEX looking forward. It moves around.
Okay. I understand. Thanks.
Thank you.
Thank you.
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 not only our press release, but the comments in this morning's report. It's interesting to have an E&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. I think that is certainly what we're hearing, is the shareholders are very interested in value and value creation. 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. With that, Allison, I appreciate the interest, and we'll conclude the call.
Thank you, sir. The conference has now concluded, and we thank everyone for attending today's presentation. You may now disconnect your lines.