Ring Energy Inc (REI) 2019 Q4 法說會逐字稿

Greetings, and welcome to the Ring Energy, Inc. 2019 4th Quarter and 12-month Financial and Operating Results Conference Call.

(Operator Instructions)

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 2019 4th quarter and 12-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 Broaddrick, our Chief Financial Officer; Danny Wilson, Executive VP of Operations; and Hollie Lamb, Vice President of Engineering as well as Bill Parsons, Investor Relations.

Today, we'll cover the financials and operations for fourth quarter and 12 months ended December 31, 2019, 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 12-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 Broaddrick, 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, March 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 3 and 12 months ended December 31, 2019, were $52.2 million and $195.7 million. Net income for the 3 months ended was $5 million or $0.07 per share and for the 12 months was $29.5 million or $0.44 per share.

For the 3-month period, net income includes a pretax loss on derivatives of $6.1 million. For the 12-month period, net income includes a $3 million pretax loss on derivatives, a $3.8 million additional tax expense and acquisition-related costs of approximately $4.2 million. Net cash flow from operations was $30.1 million for the 3-month period and $107.5 million for the 12-month period. This equates to $0.44 per share for the 3 months and $1.61 for the 12 months. Our oil sales volume for the 3 months ended December 31, 2019, was 923,384 barrels as compared to 906,874 barrels for the 3 months ended September 30, 2019.

Gas sales volume was 779,099 Mcf as compared to 731,627 Mcf for the 3 months ended September 30, 2019. On a BOE basis, our sales volume for the 3 months ended December 31, 2019, was 1,053,233 as compared to 1,028,812 for the 3 months ended September 30, 2019. For the 12-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 3 months ended December 31, 2019, 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 12 months 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 3-month period and approximately $2.75 for the 12-month period.

On prior conference calls, we have made more comparisons of our current results with the prior year's results for the same periods. We have refrained 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 million. That's quite an accomplishment for a young company such as ours. We came in under our annual CapEx budget by approximately $9 million. Our LOE, including production taxes for the 3-month period, was $13.64 per BOE or approximately 27.5% of revenue. For the 12-month period, LOE was $14.59 per BOE or approximately 29.4% of revenue. Our total G&A for the 3-month period was $4.87 per BOE or approximately 9.8% of revenue. These numbers included year-end cash bonuses of approximately $580,000. For the 12-month period, G&A was $5.27 per BOE or approximately 10.6% of revenue. These year-end numbers included about $4.2 million in acquisition-related costs. Without the acquisition-related costs, 12-month G&A would have been $4.19 per BOE or about 8.5% of revenue.

We are compliant with the covenants of our senior credit facility. The balance as of December 31 was $366.5 million. We do have a scheduled redetermination in May. As noted, as a subsequent event in our 10-K 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 '21 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 cannot 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. I appreciate it. I'm going to ask Kelly Hoffman, our CEO, to review our 3 months and our full 12-month operations for 2019. Kelly?

Thank you, Tim, and I want to thank everyone for joining us on our call today. We drilled 4 new 1-mile horizontal San Andres wells on our Northwest Shelf asset in the first quarter. We completed, tested and filed IPs on 8 wells in the fourth quarter of 2019. And the average IP rate for all of those 8 wells was 504 BOE per day. And that equates to 104 BOE per -- per 1,000 lateral foot on an average of about 4,990 feet per well.

We also participated in 3 nonoperated horizontal wells on the Northwest Shelf in the fourth quarter. At the end of the fourth quarter 2019, we had 4 additional wells in various stages of testing. And we performed 20 conversions from ESP to rod pumps in the fourth quarter of 2019 in all drilling activities. Workover projects were all completed on time, and they were all within our proposed budget. For the 12 months ending December 31, 2019, we drilled a total of 30 new wells and 13 of which were located in the CBP, 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 472 BOE per day, and that equates to about 105 BOE per 1,000-foot of lateral. As it relates to the Northwest Shelf, since acquiring the Northwest Shelf in April, we drilled a total of 16 wells; completed, tested and filed IPs on 14 of those wells; of which the IP rates were 555 BOE per day or 114 BOE per 1000-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 a comparison, it's 555 versus 472 in the overall company. The net production in the fourth quarter of 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. And 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 1 drilling inventory with very high RIRs and IRRs and ROIS, even at today's pricing. So this asset allowed us to generate over -- as Randy said, over $4 million 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, 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 4 horizontal wells on the 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, 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 2.

These are conventional reservoir, Danny's 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 30-plus days, maybe 40 days, and we're in the tanks and we're making money. That's available to us in 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 cost 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&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 cost 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 distant 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 at 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 some serious staying power.

We will have redetermination in May. And currently, we're in compliance with all requirements of 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 at $45, as Randy has already stated so 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 Hollie and let them tell you a little bit more and give more color on some of these ideas.

Right. Kelly, I appreciate that. And I 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 differences 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. The San Andres is a well-established zone, has been producing in the Permian Basin for over 90 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 had -- 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, seals, 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 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 to flow. So -- and in fact, over -- probably until about the last 30 years, most San Andres 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 it has no comparison really whatsoever to the unconventional play. 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 $1.7 million to $2.6 million per well, depending on the length of the lateral while the shale wells typically cost between $7 million and $10 million. 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 rates that were over double that of our wells. What the author failed to mention was that those wells cost 3 to 5x more than ours did. So again, that's not a fair comparison without discussing the drill cost.

As for the acquisition of the Wishbone asset, 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 Hollie 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 cost. And as recently as today, vendors have continued to reduce our cost. We had an initial $2.4 million drilling complete cost for a 1-mile lateral on the Northwest Shelf. Thus far, we've been able to reduce that to a $2.1 million 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 cost from $1.9 to $1.8 and had a slight reduction in LOE. We have modeled the same net $35, $40 and $45 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.

Thank you, Hollie. And before I get to that, I have a few other things I want to visit about. As Kelly and Hollie both mentioned, I want to remind everybody, look, we took over the Northwest Shelf properties from Wishbone in April of 2019 when the acquisition closed. In 2018, Wishbone had a 2-rig drilling program running in -- early in the year, and that was in an effort to drive up the production prior to the sale. It's something we would all do. As the property went on the market in Q3 of 2018, they shut down all the drilling. And drilling wasn't resumed again until we were -- until we took over operations in April. This obviously caused a spike in their production in late 2018, early 2019, and then the production began falling off due to the lack of drilling. And once we were able to get back in 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 I want to address that right now. That article came out and said that in January of 2019, the average production for oil on the Wishbone properties was 6,603 barrels per day and that by November of 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 of '19, and was 7,836 barrels a day in November of 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. Obviously, 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 million in free cash flow in Q4 which was -- all year long, that was our stated goal of reaching positive cash flow by the end of 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 nondrilling Capex. I have been mentioning all year long that we have begun a very aggressive program of rightsizing our pumping equipment whether 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 cost 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. 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 555 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, I would say, a refinement of our frac process. We've used 3 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 used that new frac design when we drilled and completed our 4 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. 3 of the 4 wells that were fracked with this new design in Q4 averaged -- had average IPs of 648 BOE per day or 136 BOE per foot. That -- at the end of the year, the 4th 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 Hollie, 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 priced reduction of about $10 or 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 71.4 million barrels of crude, which is approximately 88% black oil as a company percentage and 58.3 Bcf of natural gas. Of the 81.1 million 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 667 potential horizontal locations. In our Delaware, we have 43 proven vertical locations, 4 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 nonoperated horizontal locations, plus 231 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, Hollie. I appreciate it. I'm going to 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 4 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 of drilling only 4 wells in the quarter, we are actually now having to share frac crews with other operators, we kind of have to get in line whereas opposed to a couple of years ago or even last year when we had 2 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. That 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 of 2018 -- to December of 2019 of about 15% to 20%.

And 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, we 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&A market, but due to last week's precipitous drop in oil prices and what we saw yesterday, most all M&A talks of 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 million.

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 10x our daily volume or about 100,000 BOE per day, have only recently achieved free cash flow themselves. The exceptional well economics in 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 achieve this free cash flow milestone. Let me remind everyone, it's only been 3 years since we drilled our first pilot horizontal San Andres wells at the end of 2016.

Our CBP assets, along with the addition of the Yokum County assets or the Wishbone assets, have secured many, many years of highly valued horizontals 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 referenced 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 32 days. Now the 32 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, from the time that we spud a well to the time we start seeing revenues can be as early as 90 days, and is maybe about 120 days. So in that 90 to 120-day time period is what we can see a return on CapEx dollars expended.

In comparison, on the Midland and Delaware basins, that cycle time is 5 to 7 months. So you can see doing it in 1 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 ducts. 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&A, especially on the administrative side. Our G&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 cost, production taxes, G&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 belt 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&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.

(Operator Instructions)

Our first questions come from the line of Neal Dingmann of SunTrust.

Guys, my first question, just dive right into it, is more -- I mean, obviously, with the -- where the stock's trading around 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 all together for the remainder of the year to have the confidence of continued free cash flow.

Yes. Well, Neal, let me just start off. This is Tim. Let me start off by saying as we're hopefully clear in our release -- or at least 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 deck. We can take care of the somewhat modest CapEx that we have that somewhat budgeted out with infrastructure and the conversions that Danny and Hollie 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 sub-pump into the rod pumps, some workovers, et cetera. And at that $30 environment -- keeping in mind, the $30 environment gives us a yield much higher than that with that hedge component at $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 -- I 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. No, 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-$80 million range. The new budget's probably -- and we haven't finalized anything yet, but I think right now, we're looking at a spend of about $40 million to $45 million, something in that range, with about half of that already being spent in Q1. The deal with the rod conversions and the 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 are 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 rod. Are some -- just for an example, on the CBP, during the first quarter. About half of the jobs that we've done now have been rod jobs as opposed -- what I mean is, working on wells that we converted last year to rods, about half of them are down that rather than just pulling ESPs.

So if you look at the difference in that at $200,000 a well versus $20,000 or $40,000 a well, it's money well spent. We're going to continue forward with that program. We are pulling it back a 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 million to $45 million 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 details, Danny. And then one last one, if I could just, Danny 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 net -- I mean, I guess, sort of 2 parts, but all dealing with the same question about the decline maybe how you all see it this year, I mean, more 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 kind of drilling more wells? How should we potentially think about the decline?

That's a really great question. Danny had mentioned -- this is Hollie, sorry. In case you didn't know, I'm the girl.

I think I got that one figured out now.

So Danny 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 had 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.

Our next questions come from the line of Noel Parks of Coker & Palmer.

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 just wondering what would be the source of variability in production of future wells, would it just be geology or just different performance, like if you successfully brought production forward with a 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 Hollie address the EUR part of that. No, so far -- look, we have a sample size of now 8 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

Steward 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 area, in some areas we have multiple landing zones. So that will be it, 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 555 BOE a day and 648, that's a pretty dramatic increase for -- and really, the prices didn't change that much on -- as far as the completion goes. So do I think -- I think we'll start seeing -- I think we'll see continued success with that. Hollie also mentioned earlier that and now 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 Hollie address the EUR question.

So as Daniel alluded that geology plays a big factor in how we land these wells. The San Andres and the Northwest Shelf is about 400 feet thick. We've identified basically 5 potential horizontal benches, depending on where you are in the structure. They're not omnipresent. You don't have 5 in every well or 5 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 mid part of Q4. 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 from the platform at the moment?

I -- that's a good question. I think in our particular play, 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 EU. Our field guys haven't reported anybody drilling right now.

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. And talking to Steward and Riley, I don't believe any of them are drilling on the Northwest Shelf, particularly in the San Andres right now. I'm 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, no, I'm not aware of anybody. I mean, we've really been the only company drilling horizontally for quite a while on the CBP.

Our next question is coming from the line of Dun McIntosh of Johnson Rice.

Most of my questions have been asked, I think you 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 [TIO] in kind of 30 days. And then later in the call, you mentioned 90 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 12...

Yes. And if somebody said 90 days, that was incorrect. The only thing I mentioned that -- and typically, our cycle time is about 30 to 35 days, somewhere in that range. We were a little longer this time. And as I mentioned, it was because -- when we had 2 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 Steward, 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 2 or 3 of these rigs that they've modified just for the Central Basin platform in the Northwest Shelfs, 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 or management 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 -- 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 we can get it up and running very quickly.

Our next question is coming from the line of John White of Roth Capital.

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-outs, 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 understand your -- from an operations 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 good -- 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 I know the Robinson drilling guys, Luke Crownover, that's a good group.

Yes. We're very pleased with their equipment. By the way, just to clarify, obviously, Steward's listening in and they texted us, they have a rig running, so...

There you go, Noel.

So there is one rig running.

Our next questions come from the line of Andrew Bond of Alliance Global Partners.

I'm calling in for Bhakti. So if you're able to share, how many of your collar contracts have you exercised so far this year?

Randy, is that something you can respond to?

Sorry, I want to understand when you say exercise, what we have is costless collars with a floor and a ceiling. So 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 collars. Does that -- I'm not sure what you meant by exercising?

Yes, I guess that's 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 collar prices be paid out first? Or is there a decision process there? Or is it kind of just whatever rolls off?

So all of our collars 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 received 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, it's 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 out of 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. So 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 collar price. 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 foot 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 from Thomist Capital.

In 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 million. 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 as 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 $425 million 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 million. Of course, that depends on where that deck is going to be when they run it. But the strip last week and -- Hollie, 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 million 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 million. And so as Tim has mentioned, and me, adjust are boring. But we were near that in our fall redetermination.

So is it safe to assume that if they use something -- the resemble strip here that your borrowing base would go up, would increase?

No, I don't -- no, I'm not 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 the past years, and with the adjustment from -- and I'll share with you that back at October 1, our PV10 -- actually it was PV9 on PDP, it was right in the round numbers of $675 million, for example. PV10 at year-end or at that time was, I should say, at October 1, was about $650 million, but PV9 was right at that $675 million. 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, and realistically could come down. I guess, the other part of your question is to try to respond to that is, 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 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, they're -- believe it or not as Kelly mentioned, there are those that maybe not banging the door down but they're at the 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 million, and you've borrowed $366 million. 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 just 1 more on Q4 production, kind of this scenario, where oil stays in this $29, $30 range, and you just significantly cut your activity and just let some cash flow, a little bit of cash flow to be generated from the assets. This kind of gets to what Hollie was talking about in terms of declines. But what does Q4 production look like under that scenario, that draconian scenario?

Are you talking about for Q4 or Q1?

Q4 of '20 -- Q4 of '20, kind of an exit rate production.

Hollie, I think you're best to probably address that.

I -- 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 our -- 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.

Our final questions come from the line of Richard Tullis of Capital One Securities.

Just a quick one for me. I guess probably best for Danny or Hollie. 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 too, 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 -- not the commodities, but on pipe, on drilling, on everything, lower down to a point. I mean, the -- these vendors don't want to go out of business. So they're going to lower their cost down, whether it's through cuts to their payroll. Just whatever it is, they're going to do everything they can to get these 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 30 to 60 days. I think we'll have a better feel because what I've 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 6 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 the 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 we continue forward. I would be surprised if we don't reach a point where these costs are going to get down to a point when we can go back to work, at least on a limited basis.

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 stay 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.