Earnings Call: Q4 2019

Mar 16, 2020

Greetings, and welcome to the Ring Energy Inc. Twenty nineteen Fourth Quarter and twelve Month Financial and Operating Results Conference Call. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation. Please note this conference is being recorded. I will now turn the conference over to your host, Mr. Tim Rochford, Chairman of the Board of Directors of Ring Energy. Please go ahead, sir. Thank you, operator, and we'd like to welcome all the listeners to the twenty nineteen fourth quarter and twelve month financial and operations conference call. Again, my name is Tim Rochford, Chairman of the Board. Joining me on the call this morning is our CEO, Kelly Hoffman David Fowler, our President Randy Broderick, our Chief Financial Officer Danny Wilson, Executive VP of Operations and Holly Lamb, Vice President of Engineering as well as Bill Parsons, Investor Relations. Today, we'll cover the financials and operations for fourth quarter and twelve months ended December 3139. But because of the special circumstances and the recent events that we're experiencing right now, all of us, we feel it's necessary and it's of utmost importance to identify, discuss and summarize factors that both directly and indirectly affect the ongoing operations of the company. So we plan to do that in a broad sense. And at the conclusion of the fourth quarter twelve month review, we'll turn it back over to the operator, and we can open it up then for any questions you may have. For now, I'm going to ask Randy Broderick, our Chief Financial Officer, to just give us a brief overview. Thank you, Randy. Thank you, Tim. Before we begin, I would like to make reference that any forward looking statements which may be made during this call are within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our release issued Wednesday sorry, Monday, 03/16/2020. If you do not have a copy of the release, one will be posted on the website the company website at www.ringenergy.com. Revenues for the three and twelve months ended December 3139, were $52,200,000 and $195,700,000 Net income for the three months ended was $5,000,000 or $07 per share and for the twelve months was $29,500,000 or $0.44 per share. For the three month period, net income includes a pretax loss on derivatives of $6,100,000 For the twelve month period, net income includes a $3,000,000 pretax loss on derivatives, a $3,800,000 additional tax expense and acquisition related costs of approximately $4,200,000 Net cash flow from operations was 30,100,000 for the three month period and 107,500,000.0 for the twelve month period. This equates to $0.44 per share for the three months and $1.61 for the twelve months. Our oil sales volume for the three months ended December 3139, was 923,384 barrels as compared to 906,874 barrels for the three months ended September 3039. Gas sales volume was 779,099 Mcf as compared to 731,627 Mcf for the three months ended September 3039. On a BOE basis, our sales volume for the three months ended December 3139, was 1,053,233 as compared to 1,028,812 for the three months ended September 3039. For the twelve month period, 2019 oil volume was 3,536,126, and our gas volume was 2,476,472 Mcf. On a BOE basis, that is 3,948,871. For the three months ended December 3139, our received price per barrel of oil was $54.92 and our received price per Mcf of gas was $1.94 On a BOE basis, this equates to $49.59 For the twelve month period, our received price per barrel of oil was $54.27 and our received price per Mcf of gas was $1.54 On a BOE basis, this equates to $49.56 On our oil, the price differential from NYMEX WTI was approximately $2 per barrel for the three month period and approximately $2.75 for the twelve month period. On prior conference calls, we have made more comparisons of our current results with the prior year's results for the same period. We refrain from doing that this time in order to spend more time on current events. Those comparisons are in the news release put out yesterday as referenced previously. However, before I turn it back over to Tim, I would like to highlight a few key points that I believe would provide clarity regarding items referenced in recent publications. Again, we achieved not only cash flow neutrality, but we were cash flow positive in the fourth quarter in excess of $4,000,000 That's quite an accomplishment for a young company such as ours. We came in under our annual CapEx budget by approximately $9,000,000 Our LOE, including production taxes, for the three month period was $13.64 per BOE or approximately 27.5% of revenues. For the twelve month period, LOE was $14.59 per BOE or approximately 29.4% of revenues. Our total G and A for the three month period was $4.87 per BOE or approximately 9.8% of revenues. These numbers included year end cash bonuses of approximately 580,000 For the twelve month period, G and A was $5.27 per BOE or approximately 10.6% of revenue. These year end numbers included about $4,200,000 in acquisition related costs. Without the acquisition related costs, twelve month G and A would have been $4.19 per BOE or about 8.5% of revenues. We are compliant with the covenants of our senior credit facility. The balance as of December 31 was $366,500,000 We do have a scheduled redetermination in May. As noted as a subsequent event in our 10 ks and also in our press release, we have entered into hedges for 2021 that were done prior to this latest downturn. While we do not know what price decks the banks will use at the redetermination, these hedges will help us retain some of our value. We currently have 5,500 barrels a day for calendar year 2020 hedged with a floor of $50 and we have a total of 4,500 barrels a day hedged for calendar year 'twenty one, with 2,000 of that with a floor at 45 and the remaining 2,500 with a floor at 40. Even at a $30 received price per BOE, absent any drilling, management is confident that going forward, the company can not only service its current debt but reduce it. With that, I will turn it back over to Tim. All right, Randy. Thank you for that. Appreciate it. I'm going to ask Kelly Hoffman, our CEO, to review our three month and our full twelve month operations for 2019. Kelly? Thank you, Tim, and I want to thank everyone for joining us on our call today. We drilled four new one mile horizontal San Andres wells on our Northwest Shelf asset in the first quarter. We completed, tested and filed IPs on eight wells in the 2019, and the average IP rate for all of those eight wells was five zero four BOE per day, and that equates to 104 BOE per 1,000 lateral foot on an average of about 4,990 feet per well. We also participated in three non operated horizontal wells on the Northwest Shelf in the fourth quarter. At the end of the fourth quarter twenty nineteen, we had four additional wells in various stages of testing. And we performed 20 conversions from ESP to rod pumps in the 2019, and all drilling activities, workover projects were all completed on time, and they were all within our proposed budget. For the twelve months ending December 3139, we drilled a total of 30 new wells and 13 of which were located in the CVP, 16 of those wells were the Northwest Shelf, and one of the wells was in the Delaware project that we have. For the same period, we completed, tested and filed IPs on 39 horizontal wells. And the average IP of those wells was about four seventy two BOE per day, and that equates to about 105 BOE per 1,000 foot lateral. As it relates to the Northwest Shelf, since acquiring the Northwest Shelf in April, we've drilled a total of 16 wells, completed, tested and filed IPs on 14 of those wells, of which the IP rates were five fifty five BOE per day or 114 BOE per thousand foot. As you can see, the average IP rate for the Northwest Shelf is noticeably higher than the overall company average. And that just to give you that comparison, it's five fifty five versus four seventy two on the overall company. The net production in the 2019 was approximately 1,049,200 BOEs per day I'm sorry, BOE. That approximates to 11,400 BOE per day. When you compare that to the third quarter production of 1,015,000, that's an approximate increase of 3.4% quarter over quarter. I want to back up and take a moment here to talk a little bit about our 2019 acquisition, which was the Wishbone asset. We purchased the asset in April. Production was down somewhat, and that was due to a lack of spending, I think, all the way from October to the time we took it over in April. Once we took it over, we got control of the project. We started our drilling and maintenance program. We began seeing some immediate results. Moving forward to a snapshot today, and Danny Wilson is going to give you a little more color about this here in a moment, we now have a multiyear Tier one drilling inventory with very high IRRs and IRRs and ROIs even at today's pricing. So this asset allowed us to generate over, as Randy said, over $4,000,000 in positive cash flow in the fourth quarter alone. Tim mentioned at the beginning of the call that we believe it's very important to our shareholders that we discuss the current market conditions and how they affect the Ring Energy. We all are aware of today of the issues relating to the virus and what's happening to companies and what's happening to just in the overall communities and day to day life. And we're taking necessary precautions to protect the company. Anything that we can do to protect our people, the company and keep doing what we do best is what we're doing right now. And some of these things I'm going to talk about here for a moment. Currently, we've ceased all of our drilling. As of now, we've drilled four horizontal wells on Northwest Shelf. It's possible we may drill more wells by year end, but we're just going to have to wait and see how things play out for the next few months and make that decision. We have no obligations or commitments for equipment or services moving forward. However, if prices improve and the market changes suddenly, it becomes important to show growth or whatever, I want to be sure everybody understands, We can move equipment out in a day or two. These are conventional reservoir. Danny is going to give you a little more color on that. But if we want to get busy, we can get busy very quickly. And from the start to the end of putting wells online in the tanks and selling oil, it's about thirty plus days, maybe forty days, and we're in the tanks and we're making money. That's available to us at a moment's notice. We plan to continue capital expenditures for necessary upgrades, improvements so long as we can clearly see how they will lower our LOE costs going forward. Many of you realize that our breakeven may not realize that our breakeven cost is under $25 and that's a real number. It's also including lifting costs, production taxes, G and A, cash expenses and interest, and this excludes capital costs, of course. And we intend to make every effort to reduce costs and improve efficiencies. Already last week began seeing some of the vendors start to lower their costs. And so we're going to continue to see those costs ratchet down a little bit, and I think it will help increase margins. We're constantly running different scenarios internally, and those different scenarios will help us stay ahead of the market. Our main objective here is to stay focused on protecting the balance sheet. We continue to have ongoing discussions with a number of interested parties regarding our marketing efforts of the Delaware assets. Many of you may know, we started marketing those assets last year. At the end of the year, we've had a lot of conversations with a lot of people. We've got some very, very positive conversations going on today with a number of people. I believe the market is going to continue to allow us and others to transact. It just requires a lot of handholding. Things don't happen quite as fast as they used to, but they are still happening. To the extent we free up cash flow from nondrilling activities, we can further reduce our debt. It's very important. And let me say this another way. Absent of drilling at $30 oil, we're confident in our ability to not only service, but we can reduce our debt. That's a serious staying power. We will have redetermination in May. And currently, we're in compliance with all requirements and covenants. We maintain a close line of communication with our banks, a very strong relationship with our banks. And I know Randy mentioned this earlier, but it's worth mentioning again as it relates to our hedges. We have 5,500 barrels hedged at $50 for the rest of 2020, 4,500 barrels hedged for 2021, of which 2,000 of those barrels is a 45, as Randy has already stated. So we'll be sure everybody takes that away from this call. And the remainder is at $40 And with that, I'm going to hand it over to Danny and Holly and let them take you a little bit more and give a more color on some of these ideas. All right, Kelly. I appreciate that and appreciate everybody being on the call today. I'm going to spend part of my time today addressing some concerns that have come up regarding some recent articles that have been written about Ring Energy by persons with unknown motivations and that contain a series of half truths and some flat out misinformation. Without giving these articles too much credence, I'll address some of the more glaring issues that came out of those, because I know a lot of you have questions about those. And I know also that we have a lot of new obviously with the turnover in the market, we have a lot of new investors who may be hearing some of this information for the first time. So I'm going to go into a little bit more detail than I usually would. One of the criticisms that we've seen in some of these articles was the purchase of our Wishbone asset and I'll address that a little bit later. We've also seen people downplaying the quality of our IPs because they're not as good as the shale players. What they're failing to talk about in that is they're failing to mention the drill cost associated with those. And then also, we've had there was a question regarding our drilling economics, why if they're so good, we're not ramping up our program. And I'll address all of these. Let me start out though by saying, the comparison between us and the unconventional players is a little bit unfair. And I'll give you reasons why. There are several difference between conventional and unconventional reservoirs. The primary zone of interest for Ring Energy has been from the day we began business has been the San Andres formation, particularly on the Northwest or excuse me, on the Central Basin Platform. San Andres is a well established zone, has been producing in the Permian Basin for over ninety years. It's produced millions of barrels of oil. It's a dolomitized carbonate, which is considered a conventional reservoir. For over the century that oil has been produced traditionally, carbonates and sandstones are called conventional reservoirs and that's because they are able to produce without a great deal of stimulation. They're characterized by high porosity, high permeability, which is the ability of the fluids to flow through the zone without much stimulation. And that's opposed to unconventional reservoirs, which typically though they'll have some porosity, it's much lower. But they also do not have permeability. A lot of those wells when I'm talking about shales, silts, chalks, they're all considered unconventional place. Those wells can't produce without hydraulic fracturing. And that's because the throat sizes between the pore spaces are so small that the fluid just can't flow through it. So what the difference between our play and those plays is, we're using our hydraulic fracturing to connect porosity that's already existing and also enhance the permeability. And whereas they're creating permeability, otherwise their wells would not be able flow. So and in fact, over probably until about the last thirty years, most St. Andrews completions were done with just acid. Hydraulic fracturing in the long term of the oilfield is really a fairly new practice and particularly on conventional reservoirs. So it's this zone has been around a long time and has no comparison really whatsoever to the unconventional plays. Another difference between us and the shale players is that our wells are typically drilled to a true vertical depth of around 4,500 to 6,000 feet, whereas the shales are typically 8,000 to 12,000 feet depending on which target they're going after. Our frac jobs use about 400 to 800 pounds per foot versus the shales that need 2,000 to 3,000 pounds of sand per foot in some cases even higher. Our drill costs, we spend about 1,700,000.0 to 2,600,000.0 per well depending on the length of the lateral. While the shale wells typically cost between 7,000,000 and $10,000,000 One of the, I'll call half truth that was pointed out in one of the articles mentioned that 35% of the wells brought into production in 2019 had IP rate that were over double that of our wells. What the author failed to mention was that those wells cost three to five times more than ours did. So again, that's not a fair comparison without discussing the drill costs. As for the acquisition of the Wishbone assets, this acquisition was an absolute game changer for Ring. And although, look, we've been very pleased and we are very pleased with the results of our horizontal San Andres program on the Central Basin platform. The Wishbone acquisition gave us the opportunity to add an even greater number of high quality, high return wells to our drilling inventory. As good as our CBP wells are on the Northwest Shelf wells are even better. We're seeing higher IP rates, higher rates of return and higher returns on investment. And to emphasize that, I'm going to now turn it over to Holly for a few minutes and she's going to go through the economics of our drilling program. Thanks, Danny. We have now had that Northwest Shelf asset approximately a year and we've continued to discover and refine this exceptional asset. We have continued to such update our economics. When we initially rolled out the Northwest Shelf curve, we had an understanding of the production profile at the time. We have since refined the frac, reduced the drilling and completion costs, while at the same time decreasing the LOE with smart equipment deployment. Our production has exceeded our initial expectations, But until we have more data, the production curves will remain a conservative estimate of what we think the Northwest Shelf can do. I'm briefly going to review the changes on the type curves. These slides and the corporate presentation will be updated by close of business tomorrow so that you can review your numbers at your leisure. Due to diligent efforts in our drilling and completion departments, we have been able to reduce our drilling and completion costs. And as recently as today, vendors have continued to reduce our costs. We had an initial $2,400,000 drilling complete cost for a one mile lateral on the Northwest Shelf. Thus far, we've been able to reduce that to a $2,100,000 investment. These savings are on both sides of the equation, drilling and completion. It also includes a larger frac than the previous operator employed, the purchase of the ESP pump, which creates long term savings. This long term savings translates into a reduction in our LOE model. When combined with the robust well performance, both impacts create stellar returns at current commodity prices. We have modeled a net realized BOE price of 35, 40 and 45. These models have an internal rate of return that ranges from 71% at 35 to as high as 129 at 45. Our anticipated price will be positively affected by the hedges that both Kelly and Randy mentioned. For example, we have 5,500 barrels of crude hedged at $50 Combining those hedges with an open market price of $29 or $28 we would have an effective oil price above $40 This hedged effective crude price with the low cost of drilling and completion and our continued ratcheting down of our LOE means we can create value even in a depressed market. We additionally updated the CBP curves with regards to LOE and drill cost and completion costs. We have seen savings in that area as well. It demonstrates that the continued development on our legacy CBP assets are accretive as well. We've ratcheted down our drilling complete costs from 1.9 to 1.8 and had a slight reduction in LOE. We have modeled the same net 35, forty and forty five realized price per BOE and these models have internal rates of return from 46% at $35 to as high as 89% at $45 At this point, I'd like to hand it back over to Danny to discuss what we've done in 2020. Well, and thank you, Holly. Before I get to that, I have a few other things I want to visit about. As Kelly and Holly both mentioned, I want to remind everybody, look, we took over the Northwest Shelf properties from Wishbone in April 2019 when the acquisition closed. In 2018, Wishbone had a two rig drilling program running early in the year and that was in an effort to drive up the production prior to the sale, something we would all do. As the property went on the marketing in 2018, they shut down all the drilling and drilling wasn't resumed again until we took over operations in April. This obviously caused a spike in their production in late twenty eighteen, early twenty nineteen and then the production began falling off due to the lack of drilling. And once we were able to get back on there and get a hold of the property and start drilling in April, we were immediately able to arrest the decline and by a few months later, we actually had the trajectory moving back in a positive direction. And I bring this up because another article that was put out there was just completely false on the production that they've reported or tried to report to everybody and make our acquisition look like it was a failure. So, want to address that right now. That article came out and said that in January 2019, the average production for oil on the Wishbone properties was 6,603 barrels per day. And that by November 2019, it had fallen all the way to 4,205 barrels a day, which is a 35% decline, even though as they pointed out, we had started drilling again in April. This person was obviously very misinformed or was intentionally misleading the public for reasons known only to that person. In fact, the production on the Wishbone properties averaged 6,935 barrels a day in January 2019 and was 7,836 barrels a day in November 2019, which is actually a 13% increase. Now I'm going to give a little tutorial here for this person, so that next time they look up our production, they'll be able to do it properly. We can only assume that the author was unaware that production from newly drilled wells is reported under the drilling permit number until completion papers are filed and approved by the Railroad Commission. The completion reports contain all the pertinent information about the drilling and the completion of the well, but they also are not filed until the operator is ready to file the initial potential test, which can be several months after the wells begin producing. And prior to that time, a simple search for production by operator number will not show the production from these wells, which is usually during the times of peak production for the wells since it's early in the life. Once the completion papers are approved by the commission, historical production will show up during the normal operator search. Prior to approval, a knowledgeable individual can access the production through a search using the drilling permit number. I hope this helps. Another question which has been raised by in one of the articles was about our drilling economics and if they're so superior, why we aren't aggressively ramping up our drilling program. In the words of the author, we should be printing money. And as you can tell from our financial report, we did generate over $4,000,000 in free cash flow in Q4, which was all year long that was our stated goal of reaching positive cash flow by the 2019. In fact, the author had mentioned that we would have continued outspend in Q4, which obviously turned out to be false. I also want to address some of the criticism we've received regarding our non drilling CapEx. I've been mentioning all year long that we have begun a very aggressive program of rightsizing our pumping equipment, whether it's through replacing larger ESPs with smaller ones as the total fluid production in the wells naturally decrease or whether it's by converting the wells to a rod pump from ESP. The cost savings associated with these programs over time is very, very significant. The rod conversion program in particular is very beneficial as it reduces our future costs of working on these wells from about $200,000 per job down to $20,000 to $40,000 per job. And not to mention the savings in electrical costs and other issues as we're not having to maintain that high horsepower equipment. And we are already starting to see the benefits of this program, which is even more important as we move into these times of lower oil prices. I'm through talking about those other guys now. As Kelly mentioned earlier, we drilled 16 wells on the Northwest Shelf in 2019. At the end of the year, we had filed 14 IPs, which averaged five fifty five BOE a day for an average of 114 BOE per foot. From the time we began drilling in April, we've gone through an upgrading, would say, a refinement We've used three different styles of fracs during that period of time. And through the efforts of our engineers in house and with consultation with other operators in the area, we have refined that down to a point where we feel like we have the optimum frac program now moving forward. We use that new frac design when we drilled and completed our four wells in Q4. Preliminary results are extremely encouraging. The difference now that we're going to have between those the prior frac jobs and the one that we're using now is that we're using more perf clusters with fewer perforations per stage. We're doing a higher injection rate and we're using higher sand concentrations. Three of the four wells that were fracked with this new design in Q4 averaged had average IPs of six forty eight BOE per day or 136 BOE per foot. At the end of the year, the fourth well was still testing and but it was very encouraging. We were seeing similar results on that well. And while we can't say that all future wells will see this magnitude of increase, we are extremely encouraged. I'm going to take just a second now and turn it back over to Holly and she's going to discuss our year end reserves. Thanks, Danny. As we mentioned, we had completed our year end reserves. We acquired the Wishbone assets in April and since that time, we have grown our total proven reserves by above 10% with respect to oil, despite an SEC oil model price reduction of about $10 16%. This could only be achieved by a strong PDP base that is accentuated with our rod conversions and reductions in LOE and layering on strategic drilling. In 2019, our year end proved reserves consisted of 71,400,000 barrels of crude, which is approximately 88% black oil as a company percentage and 58.3 Bcf of natural gas. Of the 81,100,000 barrels of BOE in total proven reserves, 58% of these are proved developed. Overall, we have added PUDs as well, our proven undeveloped locations. On our CBP asset, we have 40 identified proven vertical drilling locations, 29 proven horizontal locations and over six sixty seven potential horizontal locations. In our Delaware, we have 43 proven vertical locations, four proven horizontal locations and 154 potential horizontal drilling locations. On our Northwest Shelf asset, which we've referred to as the Wishbone asset, we have 57 proven horizontal locations and 13 proven non operated horizontal locations, plus two thirty one potential horizontal locations. And all of this adds up to many years of drilling. At this point, I'm going to hand it back over to Danny to wrap up. All right, Holly, I appreciate it. I'm going give you a little more color on the information that Kelly gave you regarding our activity in the first quarter. To date, we have drilled and completed four additional wells on the Northwest Shelf. All the wells are on test and performing well. The first wells were put on production in mid February, which is a little later than we would have liked. But due to our reduced activity, we're drilling only four wells in a quarter. We are actually now having to share frac crews. With other operators, we kind of have to get in line where as opposed to couple of years ago or even last year when we had two rigs running, we were dictating the pace of completion. Now it's more of a shared activity with some of the other operators. So because of this delay, we are seeing a little bit of a reduction this quarter. From last quarter, we expect to see about a 5% to 7% drop in production from Q4. Doesn't reflect on the quality of the wells we're drilling only in the timing of the drilling. The program had if we had moved forward with the drilling program we proposed early in the year with our higher CapEx budget, we had modeled out that we would have seen some modest growth for the year. However, with the suspension of the program in the event that we do not drill any more wells, we're expecting to see an overall decline in our production from December 2018 excuse me, to December 2019 of about 15% to 20%. As Kelly mentioned earlier, in the event our economic position begins to improve, whether it's through better oil prices or reduced drilling costs, we can easily get back to drilling in a matter of days. In fact, we have a drilling rig sitting on one of the locations just waiting to rig up. So, in the event things change, can move quickly on that. And while we look, while we realize this by suspending the drilling program, we're sacrificing some growth. Our focus continues to remain on free cash flow and the strengthening of our balance sheet. But again, in the event that circumstances changes, we can immediately get back to work and we can turn that around very quickly. And with that, I'm going to turn it over to our President, David Fowler. Danny, thank you very much. Many of us were speculating 2020 would see a robust M and A market. But due to last week's precipitous drop in oil prices and what we saw yesterday, most all M and A talks have what I would say gone into a holding pattern as everyone looks to navigate their way forward in these unpredictable times. Despite the drop in the commodity prices, make no mistake, we remain market aware for potential ideas that we call value add opportunities that we're going to be able to pursue without further leveraging our balance sheet. 2019, as you've heard discussed this morning, was one of our best growth years in recent times. And as Randy mentioned earlier, we achieved our year end objective of becoming cash flow positive as we did so with a cash surplus of over $4,000,000 Again, I would like to remind everyone that our production averaged about 11,000 net barrels of oil equivalent per day. Now to achieve a free cash flow positive position with what many people would consider a low daily volume is an exceptional feat when you take into consideration many of our peers who produce over 10 times our daily volume or about 100,000 BOE per day have only recently achieved free cash flow themselves. The exceptional well economics on both the CBP and the Northwest Shelf, again this is what Danny and Hollie just detailed, is the cornerstone or foundation of our success and has proven our high stated IRRs are true and is the primary reason we achieved this free cash flow milestone. Let me remind everyone, it's only been three years since we drilled our first pilot horizontal San Andres wells at the 2016. Our CVP assets along with the addition of the Yoakum County assets or the Wishbone assets have secured many, many years of highly valued horizontal San Andres drilling locations. In addition to the high rate of return horizontal San Andres wells, there are several other key elements that make us different from our peers and have added to our ability to achieve this milestone such as it started with a low entry cost for acreage, which was about $500 to $1,000 an acre. All of our illustrations utilize $1,000 an acre, which was on the higher end. Again, it's also our high oil product mix, which you just heard reference was 88%. If you include into that production stream the liquids, that goes to about 94%. When you compare that to our Permian peers, typically they're going to be 20% to 25% below our product mix, our oil product mix of 88%. The higher percentage of oil results in a higher net realized price per BOE than our peers and is illustrated on a bar graph on Page 18 of our corporate deck, which is on our website. Another key factor is our short cycle times of just thirty two days. Now the thirty two days was what we illustrated in 2019. Again, that's going to be on Page 21 of our corporate deck. Let me define what a cycle time is. That's from the time that we spud a well to the time that we turn that well to the tanks. The quicker we can make that turn, obviously, the quicker we'll see the ability to count production and also see revenues coming from that well. Typically, the time that we spud a well to the time we start seeing revenues can be as early as ninety days and is maybe about one hundred and twenty days. So in that ninety day to one hundred and twenty day time period is what we can see a return on CapEx dollars expended. In comparison, on the Midland and the Delaware Basins, that cycle time is five to seven months. So you can see doing it in one month has a tremendous impact. Short cycle times don't negatively affect IRRs as much as it does for other peers of ours and also be reminded that we don't have any DUCs. Short cycle times also enable us to respond quickly to commodity price fluctuations in days and weeks, not months. Another attribute of the conventional San Andres Reservoir is its lower decline profile requiring less new wells to be drilled to maintain and grow production. You'll also note that in the early years, we invested CapEx dollars to build out our own pipeline infrastructure to dispose of produced water and transport oil and gas. As a result, it's now paying off in lower lease and transportation costs. An area that isn't normally highlighted in a lot of people's conversations is G and A, especially on the administrative side. Our G and A is low in relationship to almost all of our peers, as evidenced by our conservative C suite salaries, director salaries and bonuses. All the factors I've just mentioned result in a low cost structure that equals an all in cost per barrel of only $25 Now that includes lifting costs, production taxes, G and A and interest expense, not CapEx. Achieving and maintaining a free cash flow position is no easy task in today's volatile, some might even say hostile energy environment and it illustrates a high level of success when it can be accomplished at our low daily volumes of only about 11,000 net BOE a day. And it's proof that Ring is a low cost operator and is one of the most profitable drilling projects in the Permian, coupled with the other factors I just referenced. Though we all have to quickly tighten our belts to adjust this new $30 price environment that we're in, we are confident that Ring is well positioned to weather the storm. And with that, Tim, I'll turn it back to you for closing comments. All right, David. Thank you and thank everybody. The entire team doing a great job of illustrating and discussing the key points. Before I turn it back to the operator, and I know we're all anxious to get to that queue so that we can start with the Q and A. But again, reviewing the team, we applaud because execution, we did exactly what we said we'd do. We actually not only reached cash flow neutrality, we surpassed it in the fourth quarter with a surplus of cash. And by the way, we did it with production growth consistently through the year. So with that, that really concludes our presentation. We're going to turn it back to the operator, and we're going to open up for questions that the listeners may have, operator. Thank you. At this time, we will be conducting a question and answer session. Our first questions come from the line of Neal Dingmann of SunTrust. Please proceed with your questions. Good morning, Tim and team. Guys, my first question, just dive right into it, is more I mean, obviously, with the stock trading around the liquidity and CapEx, could you just Danny, you guys and Randy and everybody sort of alluded to this, but could you maybe Kelly, all of you all, give a little more color as far as when you look at with the redetermination coming with obviously not drilling any wells, just how you look at sort of liquidity and maintenance CapEx, kind of if I could intertwine those altogether for the remainder of the year to have the confidence of continued free cash flow? Yes. Well, Neil, let me just start off this is Tim. Let me start off by saying, as we were hopefully clear in our release from a week ago yesterday, I believe it was, we have ceased drilling for now. That's not to say that drilling couldn't come back into play. It will be measured a lot, of course, by the deck itself, the pricing. But we know we're confident right now that in that $30 environment that we can service the debt. We can take care of the somewhat modest CapEx that we have somewhat budgeted out with infrastructure and the conversions that Danny and Holly mentioned earlier. We know that I think everybody knows on this call that we continue with our efforts to monetize and look to sell the Delaware asset. And I can tell you, as I think Kelly mentioned earlier, surprisingly, even with today's environment, with the last couple of weeks, we still have some very serious interested parties and that they hopefully, as we do see a vision that goes beyond just this current pricing environment. So we're hopeful that we can continue to pursue that. And then along with the maintenance and the ongoing CapEx with reference to the conversions of the sump pump into the rod pumps, some workovers, etcetera. And at that $30 environment, keep in mind, the $30 environment gives us a yield much higher than that with that hedge component of $50 So we're hoping, Neal, that the added value from October 1, when we were last assigned or assessed value for the redetermination last fall, from that point until now that there's been a number of added value as it relates to the basket on wells that have been drilled and completed. I don't know if that's enough to keep up with the differential in the pricing then versus now. I think our price deck then was at $49 and maybe a little change. So we'll have to wait and see what that's going to look like in May. But we're having great communication with the banking group. We're trying to stay out in front of this, and we think we're going to do a pretty good job of keeping it and maintaining it going forward. And does that include you mentioned know you guys said it several times on not having to drill anything necessarily else. What about just if Danny could just comment on the need and how much you could pull back just on the rods and some of the other infrastructure costs that you've had? Sure. Danny? Yes, Neal. And that's a good question. We know everybody wants to know that. Look, we've taken a look at our budget. Obviously, we came out with the earlier one in the mid-eighty million dollars range. The new budget is probably and we haven't finalized anything yet. But I think right now we're looking at a spend of about 40,000,000 to $45,000,000 something in that range with about half of that already being spent in Q1. The deal with the rod conversions and ESP changes really have nothing to do with the drilling program. Those are the work we're doing on the existing wells. But I think you can see, I mean, we're seeing a dramatic drop in our costs on pulling these wells as we've been very aggressive, especially last year on getting a lot of these things properly sized and converting to the rods. Just for an example on the CVP during the first quarter, about half of the jobs that we've done now have been rod jobs as opposed and what I mean is working on wells that we converted last year to rods. About half of them have are now that rather than just pulling ESPs. So if you look at the difference in that at $200,000 a well versus $20,000 to $40,000 a well, it's money well spent. We're going to continue forward with that program. We are pulling it back little bit. We are not as aggressively looking at that, but we're still going to be fairly aggressive. But again, out of a 40,000,000 to $45,000,000 potential budget moving forward, half of it already being spent in Q1, you kind of see what the rest of the year is going to look like. Great, great details, Dan. And then one last one, if I could. Just, David, for you or Kelly, one of the guys who want to take it, just could you just talk about the decline? I know you mentioned, I think, year end to year end, but again, I'm not looking for just that. Again, could you talk about sort of how you all see sort of the natural I I guess, sort of two parts, but all dealing with the same question about the decline, Maybe how you all see it this year, I mean, than just quarter, just year end to year end, but maybe your assets and how should we be thinking in a plan where you potentially aren't going to drill any more wells, how should we potentially think about the decline? That's a really great question. Danny had mentioned this is Holly, sorry. In case you didn't know, I'm the girl. So, Denny had mentioned year over year decline. We're anticipating in that 17% to 20% range. If we halt drilling now and don't pick up the drill bit this year, we're going to see further decline next year, but it's into that flattening phase because we don't have new wells on that high steep decline. They've already kind of hit their B factor and have a lesser decline. So I would anticipate somewhere in the neighborhood of 10 to 12 the following year if we didn't pick up a drill bit this year. Very good. Thanks so much for the details. Our next questions come from the line of Noel Parks of Coker and Palmer. Please proceed with your question. Hey, good morning. Good morning. Just wondering, when you were talking about the big improvement you had in production from the new frac design, and you said you don't necessarily assume that every well will be that high going forward. I was wondering what would be the source of variability in production of future wells? Would it just be geology or just different performance? Like if successfully brought production forward with the new frac design, but arrive at essentially the same EUR. So what would that variability be going forward? I'll answer part of that and then I'll let Holly address the EUR part of that. No, so far, look, we have a sample size of now eight wells that we've used the new frac on. Now, we also have we developed this frac job in relation with several other operators in the area, particularly the Stewart. And they are having tremendous success. The variability, yes, will come through the geology. Not every area is equal. We do have and we have different landing zones depending on the areas. In some areas, we have multiple landing zones. So that will be it. So that which to answer your question is geology. So but we are seeing that the wells that we're using the new frac job on are superior so far. The results are very superior to the wells that we've done in the past. I mean, when you look at the difference between five fifty five BOE a day and six forty eight, that's a pretty dramatic increase for and really the prices didn't change that much on the as far as the completion goes. Do I think I think we'll start seeing I think we'll see continued success with that. Holly also mentioned earlier that and I'll reiterate for everybody, our type curve is based on 400 BOE per day. So you can see they're far exceeding that. However, we're not ready yet because of the small sample size to change the type curve. But I'll let Holly address the EUR question. So as Danny alluded that the geology plays a big factor in how we land these wells. The St. Andrews in the Northwest Shelf is about 400 feet thick. We've identified basically five potential horizontal benches depending on where you are in the structure. They're not omnipresent. You don't have five in every well or five in every section. And so there is some variability in EURs based on landing zones and completions. The best thing for us to do is take a conservative approach. And as we build more data that can be verified, then we'll look at changing the type curve. The EURs overall are a statistical play. We are seeing pretty consistent clustering, but we're looking at exploring all the benches and maximizing that asset. Yes. And Noel, I think just to add to that a little bit. The bigger frac job with more sand and the higher injection rates, I think we're opening more zone. Again, we've only had these wells on since part We really can't tell what the EUR is going to be, but I would expect that they are going to increase just because I feel like we're draining a larger part of the reservoir with each well. Great. And just for some perspective, across the industry, do you have an idea roughly how many rigs are running right now on the Northwest Shelf in the platform at the moment? That's a good question. I think in our particular play, now that's all I can really speak about. I don't know of any of the offset operators who are drilling on the Northwest Shelf or do you, Collyn? Our field guys haven't reported anybody drilling right We are always in constant contact with a lot of the operators up there. We have non op interest in their wells. They have non op interest in our wells. Talking to Stuart and Riley, I don't believe any of them are drilling on the Northwest Shelf, particularly in the St. Andrews right now. I am trying to look up on Baker rig count. That's a good source of rig count availability and they have them listed by operator. I'm just not quick enough. Yes. And on the CBP, Noel, I'm not aware of anybody. I mean, we've really been the only company drilling horizontally for quite a while on the CBP. Right, right. Think that's it for me. Thanks a lot. Thank you, Dalton. Thanks, Dalton. Our next questions come from the line of Dun McIntosh of Johnson Rice. Most of my questions have been asked. I think you all did a great job kind of walking through everything on the call. But just for a point of clarity, you talked about earlier in the call, I think, bringing in the event that prices do come back and when you do get out in the field, bring in having a rig and spud to TO and TIO and kind of thirty days. And then later in the call, mentioned ninety days. Just kind of any some color around there about how quick you could get operations back up and running in the event of a price recovery in the next twelve months? Yes. Yes. No, I mean, if somebody said ninety days, was incorrect. The only thing I mentioned that and typically, our cycle time is about thirty to thirty five days, somewhere in that range. We were a little longer this time. And as I mentioned, it was because when we had two rigs running, we controlled the frac crew, we controlled everything in the field. And we occasionally would let the frac crew go and work for somebody else. But now obviously, with the reduced activity, there's a little more sharing. And I mean, we're in communication. We share frac crews with Stewart, Riley and a few other small operators in the area. And it's just kind of a coordination thing. But I can tell you, nobody else uses the drilling rigs that we use. We use a rig that's too big for vertical wells. It's too small for the shale wells. We use a company called Robinson out of Big Spring. They have two or three of these rigs that they've modified just for the Central Basin Platform in the Northwest Shelf San Andres drillers. Those rigs literally have one sitting on the next location. So I mean, it's just a matter of rigging it up. Our drilling superintendent, our manager and our completion guys have been on the phone constantly. As you can tell, we're using the lower drill cost now in our economics. Look, I think there's going to reach a point where just like it did in 2014, we're going to figure out a way to work at $30 $35 a barrel. We did it before. We'll do it again. But those costs are going to have to come down a little bit farther. So it's a can we get it turned around very fast? Yes, absolutely. These vendors are sitting on our doorstep. They are waiting to go back to work. So, can get it up and running very quickly. All right, great. Thank you all. And like I said, everything else was answered. Look forward to following along. Thanks, Don. Our next questions come from the line of John White of Roth Capital. Please proceed with your question. Good morning, everybody. Good morning, John. Good morning. Congratulations on the quarter and congratulations on your execution. Very nice. I liked seeing you stop drilling and stop your CapEx devoted to drilling. In as much as you're continuing your infrastructure spend on rods and pump and the change out, would you it might be helpful, would you consider putting out a CapEx budget for the rest of the year that just addresses those items? And as you've noted, I mean, understand your from an operation standpoint, you can get back to drilling much quicker than the shale operators. But for having a more precise number on infrastructure spending in a press release might be helpful for people? You bet, John. That's a great point, actually. And that's something that we are working on, and we plan on doing that. Just give us a little more time so that when we put that out, we'll be pretty certain where we're standing. Okay. Just wanted to suggest that. And yes, I know the Robinson drilling guys, Lou Crown over, that's a good group. Yes. And we're very pleased with their equipment. By the way, just to clarify, obviously, Stewart's listening in and they texted us, they have a rig running. There you go, no, there is one rig running. Thanks for all the information. I appreciate it. Thanks, John. Our next questions come from the line of Andrew Barnes of Alliance Global Partners. Please proceed with your question. Hey, morning, y'all. I'm calling in for Bhakti. Thanks for taking our questions. You bet. If you're able to share, how many of your caller contracts have you exercised so far this year? Randy, is that something you can respond to? Sorry, want to understand when you say exercise. What we have is costless collars with a floor and a ceiling. They're with the price declining, they've come into play. We haven't it's based on the average price. So most likely for March, we'll end up receiving a payment. We did not receive or pay anything for January or February as the price was between the callers. Does that I'm not sure what you meant by exercising. Yes. I guess helpful. Maybe then just as a follow-up to get a little more detail. Would then those contracts maybe you can help like kind of the exercise not exercise, just kind of the process. While spot prices are below your below the floor prices, would then the lowest call prices be paid out first? Or do you is there a decision process there? Or is it kind of just whatever rolls off? So all of our callers for 2020 are the same with the $50 floor. And so on a monthly basis, the average price is compared to that $50 floor, and we receive that amount times the 5,500 BOE a day that we have hedged. So there's no exercising. It's essentially kind of an automated process. Once the price for a month is finalized, if compared to those floors and then multiplied by the volumes that we have hedged. Yes, that makes sense. That's helpful. I guess I'm just trying to figure out kind of these different kind of levels of puts and calls kind of trying to figure out which ones will, for lack of a better word, disappear first. None of them really disappear, I guess, the thing. I guess they come off a month at a time, but we have the 5,500. If you're talking about the ceilings, those will all stay the same for the year. We have that amount. As far as the floor, the $50 is the same for all of them. And so say the price ends up being $30 for March, we will then receive $20 times the 5,500 BOE a day. I'm not sure how else to Right. No, no, no. That makes perfect sense. I'm more so trying to figure out, I guess, I understand the gain there below the 50, but as maybe I'm missing something here on the call price. Was just trying to figure out how those will change those volumes will change as you're getting the gains for the as prices are below the put price. The ceiling won't change. The average price is going to stay the same for the entire year. Our next questions come from the line of Logan Moncrief with Thelmus Capital. Please proceed with your question. Thank you, gentlemen, for taking my call. And focusing on the spring redetermination, using the reserve report that was published in the K, I guess I'm kind of calculating back of the envelope PDP value at strip at around $400,000,000 The question is, I mean, just kind of the way the banks are kind of gearing up, I guess you'd assume that there'd be some sort of haircut to that. So I guess the question is kind of mechanically kind of how does that work? If they come in with a borrowing base that's lower than what's drawn on the line right now, How much time do you have to cure that? And kind of what options do you have to cure any deficiency there? Certainly. That's a good question, Logan. So let's try to address it best we can. So looking back at the value that was given the last redetermination, I think we mentioned earlier in the call, that was based on a $49 deck. Obviously, that number is going to change. And the result of that is going to so put the pressure on, as you're suggesting, which you're correct, rather than expect a four twenty five million dollars base, what would the adjustment look like? So one thing that we have to consider is in our favor is that since that last determination, that last evaluation, whether you make up the difference between October 1 and year end, which is a catch up on the third party reserves you're making reference to, there's also the activity that's flowed over both on the completion side as well as the drilling and completion side for the new wells. And of course, that will add to the basket value. Now whether or not that's enough to make up remains to be seen. I doubt that it will be as we're seeing the strip today. I can tell you that we've run some preliminary numbers as recent as of late last week, and we feel that across the board that we are going to probably still be closer to maybe $500,000,000 Of course, that depends on where that deck is going to be when they run it. But strip last week and Holly, help me if you can here. I know that we were working on that Wednesday or Thursday. I think we were somewhere in that $500,000,000 number? Yes. I ran it with a strip last week and then adjusted for the hedges. And that put us in the PDP number of around $540,000,000 And so as Tim has mentioned, it may adjust our borrowing, but we were near that in our fall redetermination. So is it safe to assume that if they use something that resembles strip here that your borrowing base would go up, would increase? No, I don't I'm not I don't expecting that at all. I think what we're suggesting is that if they if we stay on the same similar parameters as before or as in past years and with the adjustment from and I'll share with you that at back at October 1, our PV-ten or actually, it was PV-nine on PDP was right in the round numbers of six seventy five million dollars for example. PV-ten at year end or at that time was I should say, at October 1 was about $650,000,000 but PV-nine was right at that $675 So with adjustments, keep in mind that they were at $49 So with those adjustments now, we would anticipate that, that base could, in fact, realistically, could come down. I guess the other part of your question is to try to respond to that is, so okay, well, what can we do about that? What are our options? Well, we do have free cash flow taking place as we speak. So we feel we're in a position where we can whittle away at that principle right now, not significantly, but to some degree. So I think it's going to go a long ways to be able to show the banking group that we've demonstrated we can do that. Aside from that, you know that we've been marketing for some time the Delaware asset. And even though you would sit in an environment today and say, who in the heck is going to write a check? Well, there are believe it or not, as Kelly mentioned, there are those that maybe not banging the door down, but they're at a front door, very serious parties that we're still talking to at numbers that are reasonable for us to consider. So that's an option. And of course, if the bank comes back and says, well, look, your new base has been adjusted to $375,000,000 and you borrowed $366,000,000 that gives us very little liquidity. But we don't plan, Logan, we don't have a plan to outspend. So hope is one thing. That's not a strategy. The strategy is we're going to stay within the boundaries of our cash flow and adjust that and manage that the best we can. Okay. Perfect. And I appreciate you taking my questions. And just one more on Q4 production, kind of the scenario where oil stays in this $29.30 dollars range and you just significantly cut your activity and just let some cash flow a little bit of cash flow be generated from the assets. This kind of gets to what Holly was talking about in terms of declines. But what does Q4 production look like under that scenario, that draconian scenario? You're talking about Q4 or Q1? 2020, kind of an exit rate production. Yes, Holly, I think you're best to probably address that. Am me and Danny are both looking at each other, and neither one of us have that on our cheat sheets that we have in front of us. So unfortunately, as Danny mentioned, it was going to be in that 15% to 20% reduction from where we currently are and so year over year. So we can do the back of the napkin calculations, but we don't have that number. Yes. I think you could just kind of shoot for somewhere. If you look at our Q4 number from this year, just kind of shoot for about 15% to 20% less than that, and that should be you should be in the ballpark. Great. Thank you for taking my questions. Thank you, Logan. Our final questions come from the line of Richard Tullis of Capital One Securities. Please proceed with your question. Just a quick one for me. I guess, probably best for Danny or Holly. Talked a little bit about higher oil price or lower well cost to get back to drilling. Can you kind of frame up for us really what you are looking for, for that combo of higher oil price and maybe even more importantly, lower well cost to resume drilling in Northwest Shelf? Sure. No, and that's a great question. Richard, we went through this like I mentioned before, we went through this in 2014. And what we saw was that the prices on commodity not the commodities, but on pipe on drilling on everything lower down to a point. I mean, these vendors don't want to go out of business. So they're going to lower their costs down, whether it's through cuts to payroll, just whatever it is. They're going to do everything they can to get prices down to the point where we can go back to work. And I think it may take a little bit of time for everybody to get to that point. Depending on if we see any obviously any rebound in the pricing. We would have to sit down and run our models and see at what point can we service our debt, pay down maintain free cash flow and then also have some excess cash to go back to drilling. I think that these points will be clarified probably in the next thirty to sixty days. I think we'll have a better feel because what I mentioned to Kelly and Tim and the rest is, I've been surprised at how quickly the vendors have responded. Typically in the past and all the other downturns we've been through since I've been in the business, but it typically takes about six months for the vendors to come to their senses and realize that they're going to go out of business if they don't lower the prices. We were getting calls on after Russia announced they weren't going to get in line with OPEC. We had calls the next day from vendors already slashing. I mean, we've had we've seen reductions already anywhere from 15% to 20%. I expect those to get a little deeper as continue forward. I would be surprised if we don't reach a point where these costs are going to get down to a point we can go back to work, at least on a limited basis. Thank you, Daniel. That's helpful. Appreciate it. Thank you, Richard. We have reached the end of the question and answer session. I will now turn the call back over to management for any closing remarks. Thank you, operator. Listen, we know that it's a busy time, and there's a lot of distractions out there. So once again, thank you for giving us your time and listening in this morning. Everybody, well. Thank you. This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation, and have a great day.