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spk00: Welcome to SM Energy's 2021 results and 2022 operating plan webcast. We have a lot of good news to cover today. Before we get started on our prepared remarks, I remind you that our discussion today will include forward-looking statements. I direct you to slide two of the accompanying slide deck, page eight of the accompanying earnings release, and the risk factors section of our most recently filed 10-K and 10-Q, which describe risks associated with forward-looking statements that could cause actual results to differ. We will also be discussing non-GAAP measures. Please see slides 30 to 33 of the deck and pages 15 to 23 of the earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures. Today's prepared remarks will be given by our President and CEO, Herb Vogel, and our CFO, Wade Purcell. I will now turn the call over to Herb.
spk07: Thank you, Jennifer. Good afternoon, and thank you for your interest in SM Energy. 2021 was an awesome year. It was an exceptional year for many reasons, and what makes today's discussion even more exciting is that 2022 looks to be even better. Our four key priorities in 2021 were to, first, generate free cash flow. Second, improve the balance sheet by reducing absolute debt and lowering our leverage. Third, maintain top-tier inventory. And fourth, demonstrate differential ESG performance. Turning to slide three, let's see how we did. Last year at this time, we estimated that our optimized 2021 operating plan could generate approximately $100 million in free cash flow based on then current strict prices. In 2021, we generated $378 million in free cash flow, exceeding expectations by nearly three times. We targeted leverage at less than two times EBITDAX by year-end 2022. Instead, we were at 1.47 times at year-end 2021, and we reduced net debt by more than $475 million. We not only maintained our high-quality drilling inventory of 13-plus years, but increased proved reserves by 22%, with the largest portion of proved reserve additions attributable to our success in the Austin Chalk. And our fourth priority, to demonstrate differential ESG performance was evidenced by meeting our internal targets for methane intensity, greenhouse gas intensity, and spill rates, all of which were tied to compensation. Exceeding all of our 2021 priorities results from the hard work, excellent ideas, and collaboration of the SM Energy team from all functional areas, and I thank each of our employees and contractors. Turning to slide four, key factors that led to our 2021 successes include outstanding well capital efficiency and discipline, a long-term plan designed to optimize sustainable free cash flow, and high-quality assets that support continued reserve growth. Turning to slide five, let's look at our updated balance sheet metrics. Including the redemption this month of all of the outstanding 5% senior notes due in 2024, SM has no maturities before 2025, and the majority of remaining outstanding debt is callable by the company or will be callable by mid-year. We will continue to apply free cash flow to the reduction of absolute debt, transferring that value to our equity holders. Net debt to adjusted EBITDAX was at 1.47 times at year-end 2021, and at current strip prices, we expect to be around one times sometime in the middle of the year. We have said before that we are targeting around one times debt to EBITDAX, assuming sustainable commodity prices, and around $1 billion in absolute debt as an inflection point at which time we will consider additional options to drive shareholder value. Turning now to slide six and proved reserve growth. This is a great story that really highlights the quality of our asset base and reflects the success of the Austin Chalk. 22% proved reserve growth includes 143 million barrels equivalent net reserve additions and performance revisions equating to 277% production replacement. Reserve additions include 83 million barrels equivalent from the Austin Chalk, plus another 46 million barrels equivalent from our Rockstar and Sweetie Peck assets in the Midland Basin. I'll also highlight a few metrics here. Our standardized measure of future net cash flows from approved reserves was $7 billion and approved pre-tax PV-10, $8 billion. It almost goes without saying that our enterprise value is less at approximately $6 billion and we have a whole lot of upside beyond proved reserves. Turning to slide seven in inventory. We have maintained our long runway, 13 plus years of inventory, replacing 2021 drilling, and continue to have one of the highest quality inventories among our peers. Based on internal calculations run at $55 oil, the average return exceeds 55%. Based on Enveris data, we have nine years of inventory at sub $50 oil and 250 gas which just speaks to the high quality and resiliency of our portfolio. I'll now hand the call over to Wade to talk about our 2022 plan and guidance. Wade?
spk04: Thank you, Herb, and good afternoon, everyone. I agree. 2021 was a tremendous year, and 2022 is shaping up to be even better. We generated $378 million of free cash flow in 2021, and in 2022, we should roughly double that. delivering a very attractive and competitive free cash flow yield. We expect to achieve this with a reinvestment rate of around 50%, generating low single-digit production growth. I'll reiterate that we reduced net debt by more than $475 million in 2021, and after year end, we redeemed the 5% 2024 senior notes. The majority of the remainder of our outstanding debt is callable, and the 10% second lien notes are callable mid-year 2022. The one and one inflection point, Herb mentioned, should be achieved late in 2022 or early 2023, depending on commodity prices. And as we have indicated, that would be the appropriate time, we believe, to consider a return of cash to shareholders. Regarding 2021 results, I think the numbers speak for themselves, so I'm going to use the remainder of my time today to look forward. We are very excited about the 2022 plan, where we have opted to increase the capital allocation to South Texas, to approximately 45%, which underscores our confidence in the Austin Shock and presents the opportunity to drive NAV growth. Let's go to slide nine. Our 2022 objectives are largely a continuation of what we pursued last year. Number one, build net asset value through establishment of a scaled up Austin Shock program. Two, grow free cash flow generation and reduce leverage and absolute debt to the targeted levels of around one times and $1 billion respectively. while maintaining a low single-digit production growth trajectory. Three, maintain top-tier inventory. And four, demonstrate differential ESG performance, including progress on near-term goals for flaring, scope one and two emissions, and methane emissions. Turning to slide 10 on the nuts and bolts of 2022 guidance, capital expenditures are expected to approximate $750 million, with D and C capital allocated about 45% again to South Texas and 55% to the Midland Basin. This will include drilling a total of 90 to 95 wells and completing 75 to 80 wells. Although I will note that capital costs also include about 50% of the capital for four pads with 20 wells in Midland that are scheduled to turn in line in early 2023. Well costs bake in around 15% inflation over 2021. Expanding the Austin Shock Program requires some additional investment, including $18 million for additional science and completion testing in order to optimize well design, very similar to what we've done in Midland, and an incremental $20 million for oil handling infrastructure and facilities to accommodate the higher oil volumes from the region. For the year, capital activity should be highest in the second and third quarters. Production is expected to range between 51 to 54 million BOE, or 140 to 148,000 BOE per day, with about 46 to 47% of that being oil. That results in low single-digit growth, as I mentioned earlier. The higher capital allocation of South Texas will result in increased NGLs and natural gas in the commodity mix, but very importantly, deliver the same great returns. LOE ticks up a little from 2021. including more workovers and inflation for certain components, partially offset by lower-cost Austin chalk. Transportation also ticks up slightly per unit due to increased South Texas gas volumes. In the first quarter of 2022, we expect capital to range between $180 to $190 million and production to range between 13.5 to 13.8 million BOE, or 150 to 153,000 BOE per day. with 46% oil. Looking beyond 2022, I would expect continuation of our sustainable long-term plan, that is modest reinvestment rate, significant free cash flow generation, nominal production growth, maintenance of a high-quality long-term inventory, and premier operatorship. On slide 11, we update our hedging summary. Consistent with our policy to align hedge volumes with debt levels, we have reduced hedge volumes to less than 50%. In addition, with leverage continuing to fall, you can expect a further reduced percentage in 2023, say 30 or 40%. Summing it up, the 2022 plan is a piece of a longer-term strategy to deliver value creation to shareholders. And in 2022, we have the opportunity to realize value creation to shareholders through both debt reduction and building the Austin Chalk, which could be sizable. With that, I will now turn it back to Herb to elaborate on the plan by region.
spk07: Herb? Thanks, Wade. I'll start with the Midland Basin. Slide 13 gives a general overview of Midland operations, including plan details. Here we plan to drill about 55 net wells and complete about 40 net wells. Turning to slide 14, last quarter we highlighted the performance improvements from our latest completion design at our MiracleMax pad which is located in the northeast portion of our acreage position. This slide updates the performance chart. For the first nine months of production, you can see that cumulative oil production for the three wells on that pad is more than 50% higher than our forecast for these wells assuming our previous completion design. Additionally, the 50 plus completions with higher sand loading occurring in the first half of 2021 are beating the base completion type curve by nearly 15%. Turning to slide 15, we are again seeing superior performance, this time in the northwest portion of our Midland Basin position. Those of you who subscribe to Enveris may have seen the write-up last week with the headline, quote, larger frack jobs make SM a Midland rock star, unquote, highlighting three wells in the North Martin area that recently set record IP90 rates for our company. The Matador B well in the Wolf Camp A, the Slider D well in the Wolf Camp B, and the Smales D well in the Dean had IP 90s ranging from 2,200 to 2,900 BOE per day with 90 to 91% oil. These record wells have breakeven oil prices below $20 per barrel. Last quarter, I described this kind of performance improvement as part of our relentless drive to optimize returns. The next slide, 16, provides a general overview of our South Texas operations where we intend to drill about 37 net wells and complete about 38 net wells. Eighty-five percent of new wells are Austin Chalk, plus we will co-develop a couple of Eagleford wells and complete four Eagleford ducts. Turning to slide 17, we highlight the Austin Chalk program in South Texas. To date, we have delineated a large portion of our 155,000-acre position. We are partway through testing development spacing, and we are just getting started with completion design optimization. As a reminder, the Austin Chalk program is pure value add, building high value inventory on our existing acreage position. In 2021, we completed 26 gross wells in the Austin Chalk for a total of 35 producing by year end. 2021 was a really pivotal year in delineating the area and initiating development spacing in the play. Early this year, we turned in line another five Austin Chalk wells, and they are also performing well. As we've indicated before, we believe we have the potential to develop around 400 Austin Chalk locations across our position, and this continues to be the case. On the right side of the slide, we have mapped wells drilled to date in the area. It looks like our 2021 program will deliver an average nine month payout per well, and these high return wells are spread across a large portion of the acreage position. You can also see on this map that our planned 2022 activity spans across the position. As I mentioned last quarter, our 2021-2022 drilling program in the Austin Shock has an average PV10 greater than $10 million per well, assuming flat $60 oil and $3 gas prices. Confidence gained from the 35 wells producing through year-end resulted in the addition of 83 million barrels equivalent to our year-end 2021 approved reserves. The chart on the left provides an average production curve of wells drilled to date, intended to be somewhat directional for your modeling. Of course, it is higher liquids content to the north and higher gas content to the south. As Wade discussed, our capital costs in South Texas will include some additional investment in science to further refine targeted landing zones and completion designs. This will include cores and advanced open-hole log analysis, micro-seismic, fiber optics, and pressure data in support of our fracture and reservoir models. I'm not going to specifics as we consider our work here leading edge. If you've been tracking rigs over the past year, you'll have seen a large uptick in activity offsetting our acreage in Webb County. Clearly, our Austin Chalk success has not been a secret. With 141 industry completions in the county during the year, almost a third of them Austin Chalk. Now let me conclude with slide 18. Our strategic priorities remain unchanged. First, optimize free cash flow which we expect to roughly double in 2022. Second, reduce debt and transfer that value to the equity holder, where we expect to meet long-term targets by late 2022 or early 2023. Third, maintain a sustainable reinvestment rate over the long term, which for 2022 should be around 50%. Fourth, demonstrate measurable top-tier ESG stewardship, including working toward new near-term emissions objectives announced in December as well as safety and spill performance, all tied to compensation. With that said, we look forward to our live call tomorrow morning to take your questions.
spk01: At this time, all participants are in a listen-only mode. To ask a question during this time, you will need to press star 1 on your telephone keypad. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jennifer Samuels. VP of Investor Relations. Please go ahead.
spk00: Thank you. Good morning, and thank you for joining us for our question and answers call. To answer your questions today, we have our President and CEO, Herb Vogel, and CFO, Wade Purcell. As always, I will remind you that our discussion today may include forward-looking statements and discussion of non-GAAP measures. I direct you to slide two of the accompanying slide deck, page eight of the accompanying earnings release, and the risk factors section of our most recently filed 10-K and 10-Q, which describe risks associated with forward-looking statements that could cause actual results to differ. We will also refer to non-GAAP measures. Please see slides 30 through 33 in the accompanying slide deck and pages 15 to 23 of the accompanying earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures Also, look for our 2021 10K file this morning. With that, I will turn it over to Herb for brief opening commentary.
spk07: Thanks, Jennifer. First off, I want to acknowledge the gravity of current events. Our prayers go out to the people of Ukraine. Oil and gas are central in geopolitics, and SM Energy is positioned to maintain a sustainable, long-term plan under a range of macroeconomic scenarios while recognizing the importance of providing reliable, affordable energy. Second, I would like to add some color regarding the oil production component of our guidance. Importantly, I will reiterate something we say every quarter. Production and the components of oil, NGLs, and gas are outputs of our three-year plan to optimize free cash flow. Our 2022 plan is expected to roughly double free cash flow over 2021, delivering a highly attractive free cash flow yield. Two things are going on at the same time in the 2022 plan that impact our oil rates. One, the increased allocation of capital to South Texas, 45% versus 35% of CapEx last year, moves the production mix to more natural gas and NGLs than in 2021. And two, we had unique quarterly phasing of midland completions last year and this year, which was the result of the Texas freeze in the first quarter of last year. Some key points to keep in mind. We completed a total of 64 net wells in Midland in the second and third quarters last year. The subsequent two quarters we complete nine wells in the Midland Basin. The first year decline rate on new wells is approximately 75 to 80%. So you will simply have a decline in Midland production in the first half of 2022. New Austin Chalk wells will on average have a projected mix of 42% oil, 30% NGLs and 28% gas. The increased capital allocation to South Texas therefore contributes to higher gas and NGLs, changing the mix at the company level. In addition, I will repeat Wade's comment from yesterday that our 2022 capital spend includes a good portion of the capital for 20 wells in the Midland Basin that will not turn in line until early 2023. So again, it's timing that will affect the oil percent in 2022. As we have demonstrated with actual well performance, the returns in our Austin Chalk compete with the Midland Basin. As shown in the deck, our 2021 Austin Chalk wells are expected to have an average nine month payout per well. Development of the Austin Chalk is a sizable opportunity to build NAV and realize that value creation for shareholders. Again, free cash flow is expected to roughly double year over year because we have a highly efficient, high return operating plan where production is an output. Thank you, and I will turn it back to the operator to take our first question. Deb?
spk01: Ladies and gentlemen, if you would like to ask a question, you can press star 1 on your telephone keypad. And your first question comes from the line of Gabe Dowd with Cowan.
spk08: Thanks. Morning, everyone. We're just hoping we can maybe Just, again, a little bit more on the guide. I appreciate all the remarks last night and your comments just now, but just also just trying to get a sense of, you know, what's baked in from a conservatism standpoint, whether it's, you know, PDP downtime for offset fracks or just kind of how you handicap weather events or just trying to get a sense, because at first, plus just given, you know, the improved Austin Truck Program, obviously, Midland Wells getting better, I would have thought, even with the increase in all-central capital allocation, that the oil volumes would have been a little bit better to what you'd got it to. So, can you maybe just give us a little bit of comfort around how much, if at all, conservative is baked in the guide?
spk07: Yeah, Gabe, this is Herb. So, we just have basically assumed normal events, normal performance. We don't really do anything where we steer something in one direction conservative or aggressive in any way. It's what our well-performance is expected to be, and then if we have outperformance, like new completion design, you know, we've been very fortunate with those Midland baseballs on how well they've performed with normal weather, and then we do assume a certain number of offset fracks from offset operators where we have to shut in, and sometimes there's more, sometimes there's less, and those can influence. So in the fourth quarter, there were less offset fracks from offset operators, and that helped us. We also had really good weather in the Midland Basin. So those are really the key things. But we don't do anything in terms of trying to be conservative or trying to be aggressive.
spk08: Okay.
spk07: Thanks, Herb. That's helpful.
spk08: And then regardless of what the production output is, as you mentioned, it is just an output of your capital allocation framework. There's still a lot of free cash flow coming. Just talk about once you get to your leverage targets, whether it's the one-time net debt to EBITDA figure, which we think you kind of get there next quarter. Could you maybe just talk about steps or use of pre-cash flow once you get there? Any thoughts around capital return to equity holders?
spk07: Well, Gabe, I'll start on this one, then I'll hand it over to Wade. But I would just say we're just really pleased with how fast we've got to this point. We are way beyond our expectations. You know, we've got a tailwind with commodity prices, but just the performance of both the chalk and Midland Basin has really enabled us to be at this point much faster than we ever expected. And we are obviously thinking about what are the best means for return of capital to shareholders over time. And I'll turn it over to Wade to just give some thinking about it from our perspective.
spk04: Yeah, sure. Yeah, good question. And I'll just kind of reiterate, you know, a few guideposts that we laid out, I think, last quarter for the first time and then actually mentioned it again on the call yesterday. But as Herb mentioned, we are getting there quicker, which is very exciting. But I think we mentioned that, you know, delevering is really, really important to us, and we're pleased how that's going. uh we want to get down to one times but we also look at absolute debt is very important as well so we said we said one and one basically get down to one times and one billion of absolute debt so as you mentioned the one times uh assuming the macro hangs in there is coming pretty quick uh you know some some time around the middle of this year uh probably and uh the one billion i think i mentioned uh looking at our forecast just assuming you know the prices that we assumed, which are somewhat conservative compared to today's strip, but looks like something toward the end of this year or maybe early next year. So it is on the horizon, and as we get close to that, we'll start considering what the right options are, and that certainly includes meaningful dividend or potentially buyback program. People love to ask which one of those, and I think it's too early to declare which one of those we think would be the appropriate one. I think stock valuation is a big factor in that compared to NAV at the time. So that would be a factor when we start contemplating those decisions. You know, just to add color to that, if we were considering it today, I think it would be, shouldn't shock anybody to assume we might be leaning toward buyback given our view of the stock. evaluation versus NAV, but that's a theoretical answer today. I think it'll be a more prudent answer when we get closer to reality.
spk08: Thanks, Wade. That's a great caller. And just before I go, so just to confirm, there's no difference in the way, you know, you issued or prepared 22 guidance versus years past, right? Thank you.
spk04: Same consistent approach.
spk08: Awesome. Thanks, guys. Yeah.
spk01: And your next question comes from William Howell with Stiefel.
spk03: Hey, good morning, guys, and congrats on the quarter. My first question is on inflation. In the print of March, you mentioned that you have about 15% inflation baked into well costs. I'm wondering if you could talk a little bit more about where you're seeing that and how much efficiency gains are affected into that.
spk07: Thanks, William. Yeah, definitely the topic of the year, inflation. So you've probably seen that activity did ramp up to some degree last year. And when we look at the supply chain, we're well positioned in terms of having availability of everything we need. Definitely through the first half, almost everything's locked in for us. So we know what those cost increases are over last year. And we baked in that 15%. The areas where we're seeing inflation, obviously, Like diesel, clearly with oil prices up, diesel prices are up. Steel prices are up. Labor, trucking, those sorts of things, not as much on the drilling rig side or on the completion spread side if you run a continuous program and lock in the contracts. But overall, we don't know what the geopolitical events recently are going to do to the supply chain, so that's an unknown. But we did take in 15%, which seemed reasonable based on what we were seeing right at the year end.
spk03: Okay, got it. Thank you. And my other question is on the decision to allocate about half of the most half of the capital to South Texas. Talk a little bit more about the kind of long-term economics that you see there and how that stacks up against the Midland Basin.
spk07: Yeah, so that's what we're really pleased about. So we've shown over time, now we have 40 Austin Chalk wells producing. And based on the results that we're seeing in the commodity price environment we had at the end of last year, start of this year, that there are comparable returns. And we saw a big potential NAV addition from giving recognition for the Austin Chalk. So we've allocated 10% more of the capital to the CHOC than we had last year. So we went from 65-35 to 55-45 to accelerate that recognition of the CHOC. And the returns are very comparable between the two. The commodity mix is somewhat different, but the returns are the same. Great. Thanks.
spk01: Your next question comes from Zach Parham with JP Morgan.
spk05: Thanks for taking my question. Just a follow up on the oil guide. You know, maybe could you talk a little bit about your base decline rate for oil as of year end? You know, really just trying to reconcile that the 1Q guide that at the midpoint implies that 18% sequential decline in oil during a quarter when you're still going to turn in line, I think around
spk07: Zach, I think I heard your question there. So, you know, we showed in the slide deck that year over year our base decline on a BOE basis is 38 percent. But the key here is that in the second and third quarter last year in the Midland Basin, we turned on 64 wells. In the fourth quarter, we turned on four. In the first quarter, we turned on five. Those wells that started up in Q2 and Q3, they're on a 75 to 80% annual decline like normal unconventionals. So you'll see a relatively rapid decline. While the base is at a certain decline, like 38%, those new wells are on more rapid decline. And since we don't have a rateable program because of that freeze event last year, that's why you're seeing this dip in the first half of 2022. And then you'll see it come back around It's really the quarterly phasing of oily midland wells versus the gasier, NGL-rich Austin chalk wells.
spk05: Got it. Thanks for that, Culler. And I guess, one, just following up on Gabe's question on cash return, you've got the one turn of leverage and $1 billion debt target out there for the balance sheet. Do you want to reach both of those before considering cash return, or would you consider some level of cash return while also reducing leverage once you've hit one of the targets?
spk04: Yeah, good question. I would say, generally speaking, we want to reach both. We'd put them both out there as a target. It doesn't mean once we reach one and start approaching the second one, we wouldn't start considering something in the meantime, I guess is the way I would say that.
spk05: Got it. That's helpful. Thanks a lot.
spk01: Yeah. And if you'd like to ask a question, please press star 1 on your telephone keypad. Your next question comes from Carl Blunden with Goldman Sachs.
spk02: Hi, good morning. Thanks for the time. Didn't hear a lot of discussion about M&A, but with the balance sheet now in a better position, when does that come into consideration, if at all?
spk07: Yeah, Carl, thanks for that question. So, you know, the M&A, we've been pretty consistent over time and we really don't see any need for a change in our position there. So, first of all, you know, we're open to looking at somebody approaches and we're open to considering an acquisition that makes sense. And when we say makes sense, what are we talking about? Really have to have really high quality assets or the high returns that we have in our portfolio. We don't want to diminished portfolio or where you wouldn't be able to drill the acquired acreage for several years out because the returns aren't there. Second, have to be comparable from a leverage standpoint, so not basically levering us up significantly. And then from an earnings standpoint, cash flow standpoint, it should be accretive. So those are really our criteria. Asset quality, you know, not impeding us from a leverage standpoint and then helping us out on the cash flow standpoint. But we're open.
spk02: That makes sense. You outlined and reiterated this plan for about a billion dollars of debt reduction, which is encouraging. When you think about the different parts to get there, you have a couple of different opportunities. You have some bonds due in 2025, some in 2026. Some of the 25 bonds have higher call prices. How do you go about prioritizing, you know, taking on high coupons versus paying high call prices? Just interested in how you do those MPV calcs internally.
spk04: Yeah, sure. Great question. And you kind of outlined a summary of it. We'll just kind of walk forward as we move through the year generating free cash and, you know, take out the notes that make the most sense from a math standpoint. But also, you know, there's I mean, obviously, I've mentioned in the past, you know, the second lien notes, we have a, you know, we have a high desire to get those out of the capital structure. So they become callable in about four months. So those are a target. But, you know, we'll run math on that as we get closer. And, you know, the 25 unsecured notes as we approach midyear are callable at 100 point, you know, they get down to 100.9, I think, when we get to the middle of the year. And then moving on into this, you know, the 26 is, By the time you get those paid off and you're toward the end of the year, you know, they're callable at 102. So, you know, the math is, I think it's always going to be compelling. We're always going to have compelling options with the cash to get debt down to the level we desire to get to. Hopefully that helps.
spk02: Yeah, that's helpful. Thanks very much for the time. Yeah.
spk01: Your next question comes from Nicholas Pope with Seaport Research.
spk06: Morning, everyone.
spk03: Morning.
spk06: Morning. I was hoping you could talk a little bit about Austin Chalk performance down in South Texas and maybe, you know, really understanding how consistent the results have been. It feels like that's been a knock on the formation, you know, across Texas and Louisiana in the past is kind of consistency and repeatability of performance. And I guess maybe what's changed there and how has performance kind of What's that spread look like as you kind of have a much bigger output of wells?
spk07: Nicholas, that's a great question, and I'll give you kind of a long answer to that. First of all, just starting with the consistency of the Austin Chalk across our entire position, we had 600 wells drilled to the Eagleford through the Austin Chalk, so we can map it extremely well. Then we have core. And we also have done an enormous amount of science data, and we're going to get more science data. We have not yet optimized the completion. But when you look at our results, you have to consider two big factors. One is there's variation in the fluid quantity. So, from the northwest, it's oilier, and it gets progressively gassier and NGL-rich as you move east and south, as it gets deeper and higher pressure. The variability, there is going to be fluid type variability, and that's fine, very predictable. The other is the lateral lengths will vary, and then what we really look at is the per thousand lateral feet performance, and there it's much narrower, a P1090, than you would have seen from the Austin chalk that I would have been developing in East Texas in the late 80s. A lot of people say, well, Austin Chalk and NOC, it's not predictable. Well, here it is actually quite predictable, and the properties are quite uniform compared to the days of old, which were more a fracture system that was unloading for the wells. Here it's much more consistent. I hope that helps.
spk06: Yeah, that's great, actually. I mean, you guys have kind of outperformed my model for... Four quarters in a row. So just trying to get a little understanding of how repeatable that is. So I appreciate the time. That's all I had. Thanks. Thanks.
spk01: We have no further questions in queue at this time. I would now like to turn the conference back over to Herb Vogel, President and CEO, for closing remarks.
spk07: Thank you, Deb. And thank you all for joining us. Best wishes for the rest of the year.
spk01: And ladies and gentlemen, this does conclude today's conference call. Thank you for your participation. You may now disconnect your lines.
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