Good day, ladies and gentlemen, and welcome to Laredo Petroleum Inc.'s Q4 2020 earnings conference call. My name is Josh, and I will be your operator for today. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir. Thank you, and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer, Karen Chandler, Senior Vice President, Chief Operations Officer, Bryan Lemmerman, Senior Vice President and Chief Financial Officer, as well as additional members of our management team. Before we begin this morning, let me remind you that during today's call, we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts, and assumptions, are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we will be making reference to non-GAAP financial measures. Reconciliations to GAAP financial measures are included in yesterday's news release. Yesterday afternoon, we issued a news release and presentation detailing our financial and operating results for fourth quarter and full year 2020. We will refer to the presentation by page during today's call. If you do not have a copy of this news release or presentation, you may access it on our website at www.laredopetro.com. Additionally, we published our inaugural ESG and Climate Risk Report, which can also be accessed on our website under the Sustainability tab. I will now turn the call over to Jason Pigott, President and Chief Executive Officer. Good morning, and thank you for joining us today. 2020 presented many challenges for our industry. As a team, we pulled together to quickly adjust to working remotely while maintaining focus on executing on our strategy. Our culture of continuous improvement resulted in substantial improvements across all aspects of our business. Our transition to Howard County development is a great example of how we strive to continuously improve our results. We moved all of our activity to a new area in 2020, and turning our Howard County wells online is a major milestone for Laredo. We are now able to demonstrate with results rather than words the impacts of pivoting the company to more capital-efficient assets. We completed our first 15-well package in Howard County. These wells have averaged total production over 10,000 gross barrels of oil per day until the recent inclement weather challenges curtailed some of the production. These production figures are largely driven by the Wolfcamp wells and the four Lower Spraberry wells that are just now beginning to ramp up their production. We also increased our leasehold position in Howard County during the year, adding 4,000 net acres at a very competitive price. We also took actions early last year to manage financial risk in our balance sheet. We pushed term debt maturities out to 2025 and 2028, opportunistically repurchased some of that debt, and maintained our robust hedging position to support our development plan in 2021. In 2020, we made significant strides to embrace innovation as we launched our digital transformation. We built a cloud-based framework from the ground up that will provide a foundation for the future. We started automating manual processes and have partnered with others to build our intelligent well application, which is designed to increase production, reduce operating expenses, eliminate paperwork, and so much more. Our culture of innovation is being driven at the highest levels of our company and will ultimately impact all aspects of our business. Operationally, we continue to successfully improve our business across our core position, reducing well cost, LOE, and G&A versus 2019 levels. Importantly, we reduced our environmental footprint, cutting flared emitted gas volumes by 58% and oil and water spills by 29%. Last night, along with our earnings release, we also published our inaugural ESG and Climate Risk Report. In this report, along with demonstrating past success in our greenhouse gas emissions metrics, we demonstrate our commitment to environmental leadership through our target to reduce greenhouse gas emissions by 20%, methane emissions to less than 0.2% of natural gas production, and the elimination of routine flaring, all by 2025. Recall, these reductions are versus levels that are already in line to lower than our industry peers. In 2020, the board worked with the executive team to align our compensation structure with environmental targets. We are experiencing the gains from this alignment at all levels of the organization. In addition to our environmental accomplishments and goals, we are very proud of our progress on social and governance issues. Nearly one-half of our board is now represented by women or minorities. We are also diversified on the backgrounds of the board, adding legal, financial, technological, and executive experience to our team. In our report, we also emphasize the strong impact the female workforce has at Laredo, with 33% of our professional roles being filled by women. In our report, we also highlight the generous spirit of our company and our employees as we partner with agencies in our local communities to have a lasting impact. For 2021, we build on the strong foundation we have put in place with our pivoting strategy that was communicated in November of 2019. The 2021 budget and development plan highlights the capital efficiency gains from our shift to Howard County. We expect consistent oil growth throughout the year, along with increasing free cash flow generation on the same D&C budget as last year. In fact, by maintaining a consistent development program throughout the year when paired with reduced costs, we expect to complete 25% more lateral feet in 2021 versus 2020 with the same D&C budget. We remain focused on opportunities to acquire additional oily, high-margin acreage at attractive prices. We also are committed to our valuation framework, and the opportunity set for accretive acquisitions is significantly stronger so far this year, and we anticipate one of these opportunities will be a catalyst for the continued transformation of Laredo. I will now turn it over to Karen for more details on our operations. Thank you, Jason. Despite the challenges presented by having to quickly pivot our 2020 development program early in the year, the Laredo operations team delivered impressive operational results. We transitioned from an aggressive completions program on our established acreage, completing 28 wells in the first quarter, to halting completions activity in the second quarter for four months. We then restarted our completions activity by fully transitioning operations to our Howard County leasehold. Through all of this, we reduced drilling and completion costs by 21%, increased drilling efficiencies by 4%, increased completions efficiencies by 14%, and completed our first package of wells in Howard County. In the fourth quarter, we also commenced operations on a company-owned, third-party-operated sand mine in the heart of our Howard County acreage. A first for an operator in the Permian Basin, the mine can supply our operations for 5 years, reduces truck traffic by 300,000 miles per month, and saves around $90,000 per well for a 10,000-foot lateral. At current service costs, we are confident in our ability to deliver wells in Howard County at $540 per foot or less. Our first wells in Howard County were developed as a 15-well package, with 11 wells in the Wolfcamp and four wells in the Lower Spraberry. Completions operations began on this package of wells in early September and wrapped up in early December. In general, we're finding wells in Howard County take longer to clean up than on our established acreage, especially in the Lower Spraberry formation. That being said, we are very happy with the early performance of these wells. As Jason mentioned, they're performing well and are tracking with our expectations, even as the Lower Spraberry wells are just now beginning to ramp up their oil production. We are currently finishing up completions on our second well package, a 12-well development with 10 wells in the Wolfcamp and two in the Lower Spraberry. This package was developed with well spacing similar to our first package, but the package size was reduced to avoid parent-child interactions with an offsetting operator. Operations on this package were ahead of schedule prior to the severe weather impacts over the past few days. Improved completions efficiencies pulled activity forward from Q1 of 2021 into Q4 of 2020 on a full well pad in the second Howard County well package. In 2021, we expect to bring on one large well package in Howard County each quarter. The four individual well packages will consist of either 12 or 13 wells each and will be developed on either eight or 12 wells per DSU spacing in the Wolfcamp, depending on our view of rock quality and commodity pricing at the time of the final investment decision. Our 2021 budget and production guidance incorporate all of the items I just referenced. Capital is slightly higher than originally communicated, as we are accelerating activity into 2021 from 2022, as we're getting more done than expected with our one fracker. Commensurately, our oil production expectations are also higher as completions are pulled forward, even after adjusting for the longer cleanup times that we're seeing in Howard County. I also want to mention that our production guidance for Q1 of 2021 reflects uncertainties associated with the current weather situation in the Permian Basin. Extended freezing temperatures and severe icing affected our drilling, completions, and production operations for the last 12 days. As always, our commitment to the safety of Laredo's team members and the company's environmental impact are our first priority, and we experienced zero safety incidents or releases due to the weather. Multiple challenges impeded our production operations over this 12-day timeframe, including lack of fuel gas and electricity, shuttered takeaway and processing capacity, limited access to well sites and facilities, and inoperable vapor recovery units, which are necessary for environmental compliance. Additionally, completions operations were unable to proceed, delaying the drill out of plugs by about a week on the company's 12-well Tercero-Whitmire package in Howard County. Currently, drilling and completions activities have resumed normal operations and production is rapidly returning to pre-storm levels. The company currently estimates that the combined impact of shut-in production and completion delays will reduce first quarter 2021 total production by approximately 8,000 BOE per day and oil production by approximately 3,000 barrels of oil per day. Lastly, I'll make a few comments on our reserves at year-end 2020. Obviously, the nature of SEC-mandated pricing can have a dramatic effect on the volume and value of proved reserves. Given that, book volumes, both proved developed and PUDs decreased as the economic life of wells was shortened, our wells became uneconomic at the low benchmark prices. That being said, Howard County development is starting to have a positive impact on our reserve value, already representing 11% of the company's proved developed PV-10. On slide seven of the company earnings presentation, we show what the value of our proved developed reserves would be at various oil prices. Remember, this is only for wells counted as proved developed at year-end 2020. No additional capital is required to generate the PV-10 value at the higher prices. I'd like to close by thanking all of our operations team members for their hard work and dedication to Laredo over the past few days. Everyone in West Texas has had numerous things going on, dealing with freezing weather, power outages, water issues, and icy roads, both at home and work. Thank you all for helping us manage through this difficult winter storm and working to keep everyone safe. I'll now turn the call over to Bryan for a financial update. Thank you, Karen. In his opening comments, Jason mentioned our success managing financial risk in 2020. For us, this is an ongoing and key principle of our strategic plan. Executing our plan in 2021 played a big part in the future cash flow generation capabilities of the company. Responding to abnormally low oil prices driven by COVID-related demand destruction, we halted completions activity for approximately four months. This was definitely the correct action to take, but it did result in a steep decline in oil production from Q2 2020 levels of 31,000 barrels a day to Q4 2020 levels of 22,000 barrels a day. Returning oil production levels to the 30,000 barrel per day range is a key driver for future free cash flow generation and keeping our net debt to consolidated EBITDAX ratios low. Our 2021 plan accomplishes our goals on many levels. Shifting to Howard County drives an inflection point in oil productivity and oil production. Running a consistent pace of two rigs and one completion crew throughout the year is highly efficient. These efficiencies drive free cash flow to the $25 million-$40 million range at current commodity price levels, including our hedges. To facilitate this program, we have continued our active hedge strategy that has served us so well in the past. We do not focus on price alone. We take a broad look at potential downside risk and measure the outcomes versus impacts on cash flow and our ability to execute our plan within cash flow. Currently, we believe we have mitigated downside risk to the point that we could execute our plan within cash flow in a $40-$45 WTI range. Looking briefly at the cost side of the ledger, LOE in 2020 continued to decrease on both a BOE and an absolute dollar basis. For 2021, other than a temporal increase in Q1 of approximately 10% due to production impacts from the winter weather freeze-offs, we expect to see a slight but steady increase throughout the year as we turn in line more Howard County wells and as our legacy production continues to decrease. We will also perform a few more workovers than we did in the 2020 low-price environment. This steady increase in LOE is in line with what we have been telegraphing for the last couple of quarters. G&A expense in 2020 also decreased on both an absolute and unit basis. As we reduced activity in response to lower oil prices, we made the tough decision to cut personnel to align with the new activity levels. We have maintained our discipline in managing G&A expense and expect them to remain relatively flat on an absolute basis in 2021 versus 2020 levels, and relatively flat on a BOE basis, again, other than the first quarter impact from the winter weather freeze-offs. Looking forward, our goal is to continue to improve our balance sheet and further our ability to fund additional bolt-on acquisitions with our bank facility. We plan to utilize free cash flow to pay down our revolver to increase our flexibility, and we continue to look for other opportunities to reduce net debt and interest costs. Ultimately, we are highly focused on accretive transactions that reduce leverage ratios and facilitate the execution of our corporate strategies. Now, I will turn the call back over to Jason for closing comments. Thank you, Bryan. I'm very excited about 2021 for Laredo. We're now positioned to demonstrate the expected capital efficiency, productivity, and cash flow generation capabilities of full development in Howard County. We are confident in our operational capabilities and will continue to focus on adding additional oily, high-margin locations at attractive valuations. Risk mitigation continues to be a basic principle of how we operate. Our balance sheet remains strong through the challenges of 2020, and we've demonstrated our strong focus on ESG performance. The transformational plan we've communicated just 16 months ago is working, and we are determined to drive it forward and build upon our success. Operator, please open the line for questions. Thank you. As a reminder, to ask a question, you'll need to press star one on your telephone. To withdraw your question, please press the pound key. Please limit yourself to one question and one follow-up. Please stand by while we compile a Q&A roster. Our first question comes from Derrick Whitfield with Stifel. You may proceed with your question. Thanks. Good morning, all. Good morning, Derrick. For my first question, I'd like to focus on Karen's comments on spacing in Howard County. Karen, based on the limited data you have, how are you generally thinking about spacing across your position at current pricing? Are there any other notable adjustments or areas of opportunity you'd like to incorporate in your go forward D&C design or flow back approach? Yeah, good morning. Thanks for the question. Yes. We've talked about in prior releases, that we wanted to look at different potential spacing, development plans in the Wolfcamp. We're looking at both the 12-well and an 8-well development there. The first two packages that we talked about are based on the tighter spacing. The next couple of packages that we're developing right now will be on the wider spacing. Really we're looking at, one, getting a little bit of different look at the spacing configurations in Howard County with our first well packages. Also, as we've mentioned, just making the decision based on spacing, based on the economic decision at the time. I highlight that because the packages that we'll be bringing on next, the third and the fourth packages, the investment decision was made in the middle of 2020 on those as drilling operations began, so in a little bit different commodity environment. As we continue to look at the different spacing, different development plans, we're continuing to look at completion designs, really around optimizing those both for the Wolfcamp at the different spacing and also for the Spraberry. Actually too, part of that is testing new completion designs. We don't have all the cost in, or we're getting the final cost in for the first package of wells and the wells we've drilled. I think there's going to be opportunity to continue to drive costs down. We just need to get all those costs in and fully baked, and we'll look at that as the year goes on at whether costs should come down from where we are today. That's great. For my follow-up, perhaps with Jason or Karen, with regard to your 2021 guidance, you effectively raised your old guidance despite the weather effects you experienced in Q1. That seemingly suggests a stronger production profile than previously thought. Could you perhaps speak to the production trajectory and potentially offer color on an expected exit rate for 2021? I can comment on the production profile itself. We actually added in the deck this time, early results of the first Howard County package coming online. We did split out the Wolfcamp and the Spraberry formation specifically. As we mentioned, it's early, but well performance on that first package is meeting expectations. Everything's looking good there. I'll also comment that in addition to the production profiles that we're seeing in the Howard County, again, with the first packages coming in and a little bit tighter spacing in the Wolfcamp, we also highlighted, but are seeing completion efficiencies continue to improve. Again, showed data for Q4, which is continuing to be on that upward trend. That also is impacting that production guidance, because just getting more footage done in 2021 than we originally went out with. Both of those two things are really impacting that increase in the guidance. Derrick, this is Bryan. On the production rates throughout the year, I think we've talked in the past that you'll see it as a steady increase throughout the year. The annual number will be the midpoint. We're a little bit below the guidance we gave for the year today, and we'll be above it by the end of the year. It's pretty much pro rata. We're going to see a pretty much steady increase. The timing of it could be a little lumpier with packages coming on. Generally speaking, on a quarterly basis, you should see that oil production step up throughout the year. The increase is really just a I'd characterize it as pro rata increase over what we kind of been expecting. One of the big changes for us this year are the pivot to co-development in Howard County. Our production now, when wells come on, they come on in 12-16 well slugs versus we were doing smaller pads before. We've been trying to incorporate some of that into our weather hit. It might be good for Karen to just talk a little bit more about the weather and how we thought about forecasting some of that as we're moving forward. Sure. Just to back up, as temperatures warmed up over this last weekend, that's really when we were able to get all of our drilling completions operations back up and really running at full pre-storm operations. Through the weekend, we were also able to bring on the majority of our production, get it all back online. Yesterday, we were estimating that we were back at about 80% of the pre-storm level from the production standpoint. We talked about in the release that operations were impacted in some way, a total of 12 days. I'll also add that we were at or below 50% of our production levels before the storm for about six of those days. Overall, as I mentioned, we're getting everything back online. Our production, as everyone on the call knows, is very concentrated to one area. For example, all of the new wells that we're bringing on in Q4, really impacting Q1 are from 1 well package in Howard County, so our 15-well package. Any events like the recent weather event can really be very impactful to our total production because it is so concentrated. We're still getting all of our operations and production back online from the storm, and we went with the higher end of the potential impact in our guidance release. We'll continue to evaluate as we get everything back on with production and get fully back online in the next few days. Great update, and thanks for your detailed response. Thanks, Derrick. Thank you. As a reminder, to ask a question, you'll need to press star one on your telephone. Our next question comes from Brian Singer with Goldman Sachs. You may proceed with your question. Thank you. Good morning. Good morning. Just one question this morning. It is a little bit of a follow-up to Derrick's first question. It's with regards to inventory. Based on the results that you are seeing from Howard County, is that impacting how you think about future locations? How does that impact, especially with commodity prices having moved higher, your interest and ability to acquire more in 2021 or beyond? Yeah. A lot of our inventory, again, we've got the range out there that's been updated for this year. There is some impacts with spacing, but again, it can be four wells. What we're talking about is a swing for 1,280 acres. We're going through that, and the answer changes some with price. We continue to look at price. We're ahead of that. When the 12-well packages were put out there when oil price was much lower, so we were drilling those when oil was in the $40 range. We'll continue to be flexible, but we also need to just get the results. We're doing our design different than some of our other peers. We've got four wells in the Spraberry, eight wells in the Wolfcamp. Some companies are six wells in the Spraberry, six wells in the Wolfcamp. We think this is the right design for us. We'll continue to test that. I think just with respect to bringing in inventory, it's something that we need to do. We've generated all the opportunities that we've got organically. We're continuing to do some blocking and tackling. There are instances where pulling in a section here or there gives us opportunity to drill 12 more wells via either a JV with another part or JOA with another partner or purchasing that acreage. Those are the blocking and tackling types of things that we do on a regular basis. We brought in acreage, 2,500 acres last year at $2,500 an acre that just sold for $10,000 an acre plus. We've been very good at bringing it in. It's hard to say exactly how that come in. All the acreage we've brought in to date has been some negotiated with landowners, some was a sale, some was a negotiated transaction. We bring opportunities in in multiple different ways. Everything that we're drilling today, we didn't have in our portfolio just over a year and a half ago. We'll continue to do well at bringing in those opportunities. It's hard to describe exactly how they came in, because we've used multiple methods to bring those in so far. Great. Thank you very much. Thank you. I'm not showing any further questions at this time. I would now like to turn the call back over to Ron Hagood for any further remarks. Thank you very much for joining us today. We appreciate your interest in Laredo, and this concludes this morning's call. Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.