Ultra Petroleum Corp. (UPLC) CEO Brad Johnson on Q2 2019 Results - Earnings Call Transcript

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Ultra Petroleum Corp. (UPL) Q2 2019 Earnings Conference Call August 9, 2019 12:00 PM ET

Company Participants

Aaron Vandeford - Investor Relations Coordinator

Brad Johnson - President & Chief Executive Officer

Jay Stratton - Senior Vice President & Chief Operating Officer

David Honeyfield - Senior Vice President & Chief Financial Officer

Conference Call Participants

Mike Scialla - Stifel

Wayne Cooperman - Cobalt Capital

Eric Seeve - GoldenTree

Patrick Fitzgerald - Baird

Michael Altman - Ameriprise

Zach Goldstein - RBC

Dustin Tillman - Wells Fargo.

Jon Mano - Mariner Investments

Operator

Good day, ladies and gentlemen, and welcome to the Ultra Petroleum Corp. Second Quarter 2019 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions] As a reminder, this conference call may be recorded.

I would now like to introduce your host for today's conference, Mr. Aaron Vandeford, Investor Relations Coordinator. Sir, you may begin.

Aaron Vandeford

Thank you, operator. Thank you for joining us today. With me on the call is Brad Johnson, our President and Chief Executive Officer; David Honeyfield, our Senior Vice President and Chief Financial Officer; and Jay Stratton, our Senior Vice President and Chief Operating Officer.

Earlier this morning, we filed our second quarter 2019 earnings release and we'll be filing our Form 10-Q following the call. In this call, we will provide additional information on our second quarter results. Our prepared remarks will reference our updated investor presentation that was posted on our website earlier today. I'd like to point out that many of our comments during this conference call are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statement section of our annual and quarterly filings with the SEC. Although, we believe that the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results and developments may differ materially. Also this call may include discussion of certain non-GAAP financial measures. Reconciliation and calculation schedules can be found on our website and in our news release.

Now I will turn the call over to Brad.

Brad Johnson

Thanks, Aaron. Hello and welcome to Ultra Petroleum's second quarter 2019 earnings call. Today we will provide an update on our progress towards this year's goals that we outlined earlier this year. To summarize those goals, we remain committed to strengthening our balance sheet and optimizing the value of assets. This optimization is achieved by managing capital investment levels, maintaining low operating expenses, enhancing returns with lower well costs and a never ending pursuit of unlocking incremental value from the Pinedale field.

On slide 3, you'll see a brief overview of our company with updated numbers. We posted 62.5 Bcfe of production in the second quarter, exceeding the high end of our guidance. This outperformance was driven by strong base production and efficient execution of our development program. I think it is always worth reminding everyone that the Pinedale field is a large-scale producing asset, with a predictable low decline production profile that generates significant operating margins.

Several highlights for the second quarter can be found on slide 4. As I mentioned previously, production for the quarter came in above our guidance. On an average daily basis, second quarter production was 687 million cubic feet equivalent, which includes 657 million cubic feet per day of gas and 4,900 barrels a day of premium price condensate.

Realized prices including hedges of $2.51 per Mcfe and low-end cash cost of $1 per Mcfe combined the result in second quarter adjusted EBITDA of $94 million. A specific note, controllable cash cost were $0.34 per Mcfe, which came in at the low end of our guidance range and demonstrates our continued focus on optimizing our operations.

Last quarter we moved from a 3-rig to a 2-rig operated drilling program, focused on vertical development. We turned to 26 gross operated vertical wells online during Q2, with an average 24-hour IP rate of 6.3 million cubic feet equivalent per day. Costs for our vertical wells averaged $3.19 million in the second quarter. In a few moments, Jay will share more of our progress in two string wellbore designs where we successfully completed and bottom-line eight two-stream wells at an average cost of $2.62 million.

In light of the ongoing weakness in gas prices, we have decided to drop another rig and we'll move to a 1-rig operated drilling program for the remainder of 2019. This adjustment to our investment base reduces our full year 2019 capital investment to a new range of $260 million to $290 million. With this capital reduction, we are adjusting our full year production guidance to a new range of 238 Bcfe to 244 Bcfe. This results in a guidance midpoint of 241 Bcfe, which is a less than 2% reduction to our original guidance for the year.

Including the 18% reduction to CapEx, combined with the substantial level of base PDP production, we are forecasting a cash flow positive business beginning in the third quarter of this year.

Moving to second quarter operating metrics, slide 5 tabulates our results. In addition to production coming in above guidance, other highlights for the quarter include the results of a lower cost structure. These results include the following: LOE coming in meaningfully below guidance at $0.25 per Mcfe; low LOE also helped to contribute to our low controllable cash cost with some of LOE and cash G&A totaled $0.34 per Mcfe; and production is coming in line with the low end of our guidance at $0.26 per Mcfe, driven by the lower realized prices during the quarter.

Strong cost management across the quarter helped us to have EBITDA cash cost of $1 per Mcfe, which contributed to a strong EBITDA margin of $1.51 per Mcfe. Our overall strategy continues to be guided by the disciplined investment of capital and the pursuit of free cash flow. Our base production provides significant cash flows and provides us the ability to appropriately withdraw capital when gas prices move lower. With a clear strategy for 2019, our teams are empowered to execute this plan. We are fortunate to be the stewards of a tremendous asset and we are focused on low-cost responsible development and the expansion of margins to drive value for our shareholders.

While we are favorably levered to improved gas pricing whether that’s at Henry Hub or Northwest Rockies or a combination of both, we cannot depend on something we cannot control. Therefore, we will continue to be a low-cost leader in more of the top Tier gas assets in the country where annual EBITDA cash cost approximate $1.15 per Mcfe and the controllable cash cost of LOE and cash G&A combined to be $0.40 per Mcfe or less.

Our ability to adjust the pace of development effectively in response to the price environment, along with a large inventory of low-risk locations, help us to manage commodity price cycles and provide exposure to expanded margins with ongoing cost improvement and/or gas price improvement.

On slide 7, we’ve highlighted some of the factors that make this asset so valuable. Our 83,000 contiguous acres hold an inventory of 4,000 drilling locations within the core of our asset that can fuel our manufacturing process of pad drilling to effective execution using simultaneous operations.

Our acreage is in the core of the Pinedale play, where we sell gas from the Opal Hub, with significant takeaway capacity to multiple destinations. Ultra is largest operator in the basin and has produced over 3.5 Tcf of natural gas, nearly 27 million barrels of oil, and drilled more than 2,200 wells within the Pinedale and Jonah Fields. We know our asset well and we will continually pursue new insights to extract more value.

The real strength of this asset is our ability to flex our investments in response to the market. Our low decline rate, large inventory and core operating position, make it possible to be resilient during low prices and opportunistic when gas prices improve.

On slide 8, we have compiled data from 2018 on four metrics that we believe illustrate how well Ultra ranks among the strong group of gas-weighted peers. In the top left panel, controllable cash costs, which is the sum of lease operating expenses and cash G&A, Ultra is among the best-performing of its peers at $0.36 per Mcfe. In the top right panel, corporate base declines range from a low of 20% to a high of 33% with a median value of 32%. At the beginning of this year, Ultra's base decline was forecasted to be 26% in 2019, second-best among the peer group. If the base production continues to outperform our forecast, we have the opportunity for this base declined to be less than 25% for this calendar year.

EBITDA margin is shown in the bottom left graph. The median value in this peer group is 53%. Ultra ranks third among this group at approximately 60%. And finally, we show adjusted operating margins in the bottom right section of the slide. At 33%, Ultra ranks well above the peer group median of 24%.

Based on the company's combination of a large and resilient PDP production base, low-cost, lower base declines relative to peers and high-ranking margins, Ultra's production and cash flow profiles are more resilient than many of our peers in this sector.

Taking a closer look at our decline growth rates on slide 9, you will see what is supporting our strong peer performance on the previous slide. This slide provides the five-year historical look at net production volumes in Pinedale.

Since 2015, each year development wedge are sequentially layered to show the multiyear impacts to the current corporate base decline forecasted at 26% for 2019. The plot also shows how the annual declines flatten out in subsequent years and we have labeled this at the right edge of the plot.

Our year one decline rate of 26% quickly drops to just 16% by year two and by year four our decline rates are less than 10% before settling into a final decline rate of 7% within seven years.

Ultra Petroleum's ability to consistently deliver this profile is a testament both to the quality of the rock in Pinedale as well as our team's unparalleled understanding how best to exploit it.

To give some more insight into the operational side of that equation, I will now turn things over to Jay.

Jay Stratton

Thanks Brad. On slide 10, I’ll point out the update for vertical well development optimization efforts. Year-to-date, we have successfully drilled 13 2-string casing design wells in our pilot program. Our 2-string well design, still in the early stages and seeing improvements in each iteration, has increased or realized savings to approximately $500,000 per well during this period or about 16% less than our current average.

Vertical well cost averaged $3.19 million per well in the second quarter of 2019. We continue to expect cost to decline to below $3 million per well before the end of the year and likely in the third quarter as we refine and implement a successful 2-case and string design initiatives.

As Brad said earlier, we averaged $2.63 million per well for the eight wells where we were successful in using the 2-string design. 11 wells were attempted with 2-string were accounted with 2-string design with the average value of these wells coming in below $2.9 million, which continues to offer us a low-cost option for developing our Pinedale field.

Our most active drill pad with seven successful two-string wells in the second quarter, we had a 16% reduction in CapEx compared to our three-string designs. Based on early production data, we're estimating these wells to have EURs that are only 7% lower than offset wells. While the data set is small, we did line most of the two-string wells on average of 400 feet above offset TDs, at one to two less frac stages in the 5,000 to 6,000-foot completed interval.

We will continue to evaluate the data and drive two-string wells deeper where possible. We consider these results economically successful, because the percentage of cost savings has more than doubled for fuel and gas and the volume impact, which nets out to a more favorable F&D costs and higher return profile. This is a meaningful capital efficiency improvement and we look to increase this improve over time.

Based on the continued success of this program, we will complete the remaining wells on our most active drill pad exclusive with two-string wellbores and continue to evaluate future pads for opportunities to use this design.

Moving to slide 11. During the quarter we brought 26 gross operated vertical wells online with an average 24-hour IP rate of 6.3 million cubic feet equivalent per day. Well performance for the quarter was on the low side of our recent quarterly ranges, which have variability due to our process of high-grading the order of the pads drilled.

We completed drilling on two pads during the second quarter, which results consistent with this process. The pads we're drilling during the third quarter have a higher percentage of two-string design wells and the associated cost savings will be substantial. We also continue to see material reductions in completion cost to improve process and technology which will be critical to create value with the vertical program.

On slide 12, we summarize an important milestone in our Pinedale reservoir characterization project. The 3D seismic conversion project has been completed over the 20 square mile Pinedale area of our core horizontal development, which has very good correlation to our Lower Lance reservoir distribution in volume test wells.

In addition, we've been able to hit the mass-producing performance in our calibration wells and validate productivity trends that tie to the very good performance in our horizontal wells. In the second half of the year, we expect to use these results to continue building out our geo-cellular earth model to predict performance of high-grade locations for future horizontal well development.

Given the value of the reservoir characterization results to date, we are working towards validating deeper sections of the Lower Lance and Mesaverde. We also expanded communication of a workflow field-wide where it can also be used to improved selection of the vertical well placement to optimize opportunities for two string and three-string well designs.

The simulation work with its emphasis on detailed new mechanical modeling also has application with further tuning to assist with more refined and optimized completions of Ultra vertical and future horizontal drilling.

Ultra continues to discover additional stored value that can be unlocked in our world-class Pinedale gas resource. That value can be released by continued application of rapidly evolving technology and processes available in our industry that can increase well performance and reduce cost.

I'll now turn the discussion over to Dave.

David Honeyfield

Thank you, Jay. Turning now to slide 13, which has an infrastructure overview. You will see the variety of destinations, into which we can sell our production. Having this flexibility provides us assurance of flow and deliverability to valuable markets.

The Opal pool gas provides several takeaway options that offer premium prices compared to other natural gas markets such as CIG and Dominion South. I want to emphasize that there is a difference between Opal and CIG pricing. The CIG market traditionally serves more of the Powder River and DJ Basin production, whereas our gas in the Pinedale area goes into the Opal market, which, as we've highlighted out on this slide, historically trades at a premium to the CIG delivery point.

On average the Opal pool, which is our primary delivery point, has traded nearly in line with Henry Hub through the first half of the year and historically has been a premium market to other gas delivery points as a result of the delivery optionality provided from this location. This is a true advantage for Ultra as a gas player in the Rockies region, when you consider that many of our peers are selling their natural gas production at a wider discount to Henry Hub pricing.

Moving to slide 14, I believe it is interesting to point out the improvement in Northwest Rockies basin's pricing over the last year. This has been somewhat quiet, but very meaningful. The current 12 month strip shows a 36% improvement over the same 12-month period a year ago, an improvement of nearly a $0.25 per MMBtu.

I believe that this improvement is a result of the certainty of the infrastructure build-out of that is occurring in the Permian. This reality has relieved some of the bid pressure against Western Rockies delivery points and as a result has improved our basis differential.

Moving to slide 15 and staying on the topic of commodity pricing, here you'll find a summary of our hedging book. The company will continue to hedge a portion of its production in order to provide a degree of certainty of cash flows and in an attempt to be opportunistic when we see favorable windows in the natural gas and the Rockies basis markets. The company has a minimum hedging requirement under its revolving credit facility to hedge at least 65% of our forecast proved developed producing natural gas production for the ensuing 18 months. This requirement decreases to 50% on September 30, 2019.

Management also works to balance the ability to project a significant portion of its production base against material declines in commodity price, while providing upside price exposure as the increase in future commodity prices has a meaningful impact on our cash flows. For this reason, the company has furthered it use of costless collars and deferred premium puts in its 2020 hedging program. When factoring in the impact of our hedging program, it's important to remember to take both the NYMEX and the Northwest Rocks basis contract into effect and then multiply the per MMbtu price on the derivatives by the company's average Btu factor of 1.07 in order to yield the impact of the realized price of the natural gas derivative. This value is then combined with the oil contracts to get the final per Mcfe value of the hedges. The table on the lower right corner reflects the math for the remaining six months of the year for our 2019 hedging program.

Turning now to slide 16, I want to draw your attention to the per share value of our proved reserves. On this slide, we take a look at our PV-10 value per share adjusted for net debt. In this example, we are using year end 2018 SEC PV-10 values. And I want to point out that SEC required pricing today for valuing reserves is similar to year-end pricing given the improvement in Rockies basis, we've seen here today.

Based solely on PDP and PUD values using the 2018 SEC PV-10 results and our shares outstanding our proved reserves represent $12.15 per share. When we take into account, the book value of our outstanding debt obligations and the cash on our balance sheet at June 30, the remaining value is approximately $2.15 per share.

We are not representing this as indicative of equity value. However, we do believe it's appropriate to consider the underlying value of our asset base and not just be swayed by current market sentiment when thinking about the value of our company.

Ultra Petroleum has a significant base of PDP reserves that are proven over a long time to be durable and resilient. As Brad has described, we will continue to work on improving our operational performance and lowering our operating costs to further improve the durability of our operations.

Transitioning to slide 17, we have outlined the company's debt amounts and debt maturities. Continuing some of the themes from the previous slide, we've shown in the coverage ratio of our proved developed reserves to both the outstanding and committed debt levels. What we point out is that the coverage for first lien debt outstanding is approximately 2.2 times based on year-end 2018 SEC PDP-only reserve value and taking into account the debt balances as of June 30.

Shifting gears slightly as folks have seen, we undertook an effort to reduce outstanding debt in the second quarter with the proposed exchange offer of senior notes due in 2025 for new third lien notes. Ultimately, we decided to terminate this offer. After fully exploring the possibilities of this exchange in the market, we decided that was it was not the best interest of our shareholders to move forward with this transaction.

That said, we will continue to explore every avenue open to us to strengthen our balance sheet. Also of importance as to highlight and understand what we do not have any near-term debt maturities. As we work to further strengthen the balance sheet, the company continues to generate significant cash flows from its operations and by managing our level of capital investment in this price environment, we are setting ourselves up to generate free cash flow beginning here in the third quarter.

Turning to slide 18 and wrapping up my prepared remarks, you can see our guidance for the third quarter and the remainder of 2019. As mentioned earlier in the call, during the second quarter we made the decision to reduce our rig count from three to two operated rigs in response to changes in the commodity market. As summer has progressed, and we have closely monitored the strip price in the market, we made the decision to go to a single operated rigs starting here in the third quarter.

To reiterate Brad's comments earlier, with the decision to go to a single rig, we expect our capital program for the full year to be in the range from $260 million to $290 million, delivering full year production and guidance of 238 to 244 Bcfe. With this move, we anticipate that $220 million to $240 million of the forecast will be invested in our operated vertical well program.

In the third quarter, we anticipate production to range between 635 million and 665 million cubic feet equivalent per day. We have provided a detailed breakdown of our third quarter and full year guidance on cost per Mcfe knowing that our guidance for EBITDA cash cost remains at approximately $1.15 per Mcfe for full year 2019 and that our operating margin stays strong at approximately 60%.

With that, let me turn the call back over to Brad.

Brad Johnson

Thank you, Dave. We have made significant progress toward our goals for 2019. We will continue to demonstrate financial discipline. And as we have discussed, we've made another capital adjustment in response to gas prices. We continue to point out that there is a viable optionality and upside to the Ultra story, which we've outlined here on slide 19.

With our focus on operational execution and management of base production, we can deliver margin expansion. We remain focused on cost control and are pursuing the opportunities ahead of us to continue reducing cost on our vertical program. We are also continuing our efforts to evaluate the incremental horizontal resource potential, and we'll be judicious in any future horizontal activity.

The debt structure remains a priority for our leadership team, and we will continue our efforts to strengthen the balance sheet. We often receive inquiries about the status of our Make-Whole litigation. As previously disclosed, on January 17, 2019 Fifth Circuit Appellate Court issued an opinion, vacating the order of the bankruptcy court regarding company's objection to the certain Make-Whole and Post-Petition Interest claims. This order reminded the matter and those determinations back to the bankruptcy court for further reconsideration.

On January 31, 2019 the holders of these claims filed a petition for non-monetary hearing. Prior to the Fifth Circuit's favorable opinion, the company had previously settled certain claims, and we reported that as of March 31, 2019 the company had approximately $260 million of claims still outstanding. During and subsequent to the second quarter, the company entered into additional settlement agreements with holder's of certain Make-Whole and Post-Petition interest claims. Pursuant to these settlements the parties agreed to settle the pending disputes between such holders in the company and the holders collectively agreed to pay approximately $13.5 million to the company. Therefore, as of today, there is approximately $240 million of unsettled claims subject to the Appellate Court decision and potential further recovery.

Turning back to our cash flow, our high-margin operations also enjoyed the added value of the optionality we have to natural gas prices. As we've talked about before with every 25% increase in the value of natural gas over our current production profile, we can generate over $55 million in additional cash flow on an un-hedged basis.

Additionally, the price move from $2.50 to $2.75 per MMBtu at Opal creates 550 new economic drilling locations for us. Illustrating, how quickly it moves to the upside natural gas price can positively impact our story. Our operating fundamentals are rooted in optimizing our base production with emphasis on maximum run times and minimum LOE, each of which translates to stronger operating cash flow. We augment that foundation with investments in our Vertical Well program high grading the opportunity set and delivering low-risk and consistent well results.

Financially, our priority is to continue to strengthen the balance sheet and maintain liquidity to execute our plan. Ultra is hyper-focused on cost controlling efficiency, which are the keys to enhancing value of our operations, and our drilling inventory. We also believe there is significant upside potential in expanding recoverable resource from Pinedale through horizontal development, and we will continue to evaluate opportunities to translate this upside potential into incremental value for shareholders.

At this time, we'll open the line for questions.

Question-and-Answer Session

Operator

Thank you. [Operator Instructions] And our first question comes from Mike Scialla from Stifel. Your line is open.

Mike Scialla

Yes. Hi, guys. I wanted to see where you think you can drive the well cost with that 2-string design. Is that $2.6 million number reasonable? And also want to get a sense of the -- what causes the degradation in the EUR, I assume, that's the fewer frac stages. Is there anything there that you can do to mitigate that?

Jay Stratton

Yes. Hi, Mike. This is Jay. In regards to the well cost that $2.62 number for our [indiscernible] for 2-string designs in second quarter is pretty solid. We've seen our first three wells in the third quarter in fact between $2.5 million and $2.6 million. We we're working hard to make that -- a bigger mix in our well count.

In regard to the EUR reduction there is some data we have been offset wells that gives us insight into where we should attempt drilling these wells to mitigate the EUR reduction. But also the reservoir characterization project we talked about in our comments also gives us insights. So we're working towards refining or understanding of those deeper depths and we were seeing tangible results to be able to visualize where the sand is most productive or where it isn't. So that's also going to give us some additional precision on mitigating that EUR reduction.

Mike Scialla

So Jay, based on that I guess, it sounds like may be preliminary. But do you have an idea of how much of the inventories are amenable to that 2-string design at this point?

Jay Stratton

Well right now, it depends on what we see in the adjacent wells and how much data we have in an area, but right now we're at about a 50-50 mix with our current drilling program and one pad we're exclusively focused on it. So as we find insight and more evidence of where we can use it, we'll try to increase that mix.

Mike Scialla

Got you, okay. And I want to see if you feel like you can maintain efficiencies moving to a 1-rig program or do you think that's going to put some cost pressures on well cost going back in the other direction?

Jay Stratton

Well, we're talking to our vendors. They're all engaged and focused on our operations and certainly our staff is. So we don't see any issues that would lead us to believe that we'd become less efficient with a 1-rig program. So we're pretty well lined up with activity in the third quarter drill.

Mike Scialla

Great. And one last one for me. Based on the strip prices, you mentioned your plan in free cash flow positive in the second half. I want to see what kind of projections for free cash flow you're anticipating. And assume the free cash flow there would be used to pay down debt. Do you want to give your thoughts on that? Thanks.

David Honeyfield

Mike, this is Dave. Yes, overall, we factored in certainly strip pricing. So I would suggest that's the right way to model free cash flow. You know, as Brad mentioned we did – we got some proceeds in here on the make-whole. That's valuable so that will help a little bit.

And with the reduction on the CapEx program moving to a single rig that will also be helpful, so all those items give us very good confidence about being free cash flow positive. Yes, we think that will be a reasonable number probably hesitant to give you an exact numbers here, but I think over the course of the year what we're showing is that reduction in overall CapEx -- I'm just using midpoint numbers here, but that reduction is 18% and the production is only at 2% decline. So that indicates that there will be a fair amount of free cash flow.

Now come in more so in the fourth quarter for sure -- just when you think about the timing. But yes, overall, I think for kind of combination of those quarters, it will be a significant number. And you're thinking about it exactly right that reducing indebtedness is really the focus. It's about balance sheet management and that's just a virtuous cycle when we think about reduction in interest cost in overall improvement to the balance sheet. So, I hope -- well it doesn’t give you the exact answer to the question, hopefully that gives you a good way -- good sense of the way we're thinking about it.

Brad Johnson

And I might just to add just a few numbers to augment Dave's remarks. If you look at our second quarter EBITDA, posting at $94 million and I think about the capital forecast that we've laid out for the rest of the year, we're suggesting about $50 million or so per quarter of capital investment.

And then circling back to second quarter EBITDA, which second quarter has historically been some of the lowest realizations we incurred during a calendar year. This is what we see that that free cash flow generation really upon us and happening very same for here in the third quarter and really for the balance of the second half of 2019.

Mike Scialla

Yes, that helps. Appreciate it guys.

Brad Johnson

Sure. Thank you.

Operator

Thank you. Our next question comes from Wayne Cooperman from Cobalt Capital. Your line is open.

Wayne Cooperman

Hey guys. Two questions. First just any -- can you put a little framework around what 2020 might look like with the one-rig program as far as production and capital spending?

And second question would be as you generate this free cash flow that you are predicting and hopefully, more money comes in from the settlement, can you go out and buy back your bonds in the market that are trading at single-digit percent of face? Or do you need to pay off the banks first? And obviously if you can buy back bonds at a huge discount that would really go a long way just fixing the balance sheet.

Brad Johnson

Wayne I'm going to take a few of them and I'm going to ask the team to remind me of the ones I might have that I forgot or missed, but as we look into 2021, we're increase not yet providing guidance for the calendar year 2020, but certainly it's worth pointing out that as we go down to one rig, we're reducing CapEx and start generating cash flow really in a matter of weeks frankly. That sets up 2020 to also be a period of cash positive cash flow generation. As we look at cash flow coming in the door I think it's important to point out well first reaffirming that's our pursuit that we're pursuing free cash flow.

Second, we don't have an obligation for the use of that cash. We have options and certainly some of our first choice options is to pay down debt. So that is on the table for sure.

Wayne Cooperman

Well, I guess, my question was if you could buy back some of the public debt that yields 100% or more or if you need to -- if the banks have the first call on that free cash flow which would obviously be in a much lower rate of return to you.

Brad Johnson

Yes. Just to clarify so we don't have obligations for our cash flow. But we do have some restrictions, that's important to point out. And we've shared before is that currently under our debt docks we can only purchase debt when our ratio falls below 3x and we're not at that point at this time.

So, right now, that is a restriction for use of proceeds. But certainly it's a place that we'd like to put that cash to work.

David Honeyfield

Wayne this is Dave. I think what you're hitting some items that are very front of mind for us.

Wayne Cooperman

So, I think you kind of just cut out.

David Honeyfield

[Technical Difficulty] opportunity to work…

Wayne Cooperman

I don't know if you can hear me, but you cut out for the last 30 seconds. I couldn't hear what you said.

David Honeyfield

Okay. Wayne this is Dave Honeyfield, can you hear me better now?

Wayne Cooperman

I can.

David Honeyfield

Okay. Thank you. What I was going to say is that the things you're mentioning are very front of mind for us as a management team. And certainly we see the ability to; one, lower overall indebtedness. And if we have an opportunity in working collaboratively with our overall lenders to figure out a way to buy back debt in the open market is something that we will pursue. But it will require overall cooperation from the full capital structure.

Wayne Cooperman

Got you. Thanks.

Operator

Thank you. Our next question comes from Eric Seeve from GoldenTree. Your line is open.

Eric Seeve

Hey guys. Thanks for the call. A few questions. First on the CapEx side, I hear you that you're not giving guidance for 2020. But can you give us a sense that based on the activity levels and the one rig that you're deploying as you exit '19? What the 2020 CapEx would look like or what a reasonable range of expeditions would be if you maintain that rig count and activity level?

Brad Johnson

Sure. As far as a 1-rig operated program for the rest of 2019, we're seeing about $10 million a month -- excuse me, it's about $50 million per quarter when we throw in corporate CapEx as well, so, about $50 million per quarter CapEx burn per rig is about $10 million a month or so. And so, you can take that and extend that into 2020 as your modeling.

Eric Seeve

Great. Thank you.

Brad Johnson

Sure.

Eric Seeve

And then, for those who are not as sophisticated between with respect to the two rigs versus three rigs casing, can you talk about what happens? It looks like you did 11 with 2-string casing, eight were successful three were not. Can you walk through for investors what happens on the three that were not? What happens to that well? And what implication is if not being successful?

Jay Stratton

Yes. This is Jay, Eric. We set up the wells to be drilled with two-string design, but we have a contingency available for those certain offenses you just mentioned where we had three wells that didn't, but definitely wanted to in that serial where we drill a larger whole section below a deeper surface casing. So it offers us the opportunity to -- if the formation is not strong enough to support our designs, two-string design, we can run that third string of casing prior to reaching TD. And then complete the well to a total depth that we would have designed a conventional well.

That adds additional cost because of course we started the well with a plan to drill deeper surface casing. So we spend some extra money there. And then, what we didn't, when we weren't able to compete well, only two strings we had to add that extra string of casing. So sometimes the cost can get as high as -- can exceed the 3-string cost by $200,000 or $300,000.

So, in aggregate as we mentioned I think in our remarks, our cost were $2.9 million for all 11 wells. So we still are achieving economic result that's positive for us even where we have the three with the contingent cost impacts. So, we're trying to reduce that and we are having success in reducing the cost of those contingent wells and also reducing the number of them.

Brad Johnson

And I may just add a few remarks there. [indiscernible] have made a lot of progress as opposed to just really, really good results on this 2-string design program. But we're not satisfied. There's more to chase here. What we want to do is we want to increase our success rate on one of our 2-string designs. And then for those contingency plans, we’re going to look to reduce the cost of those contingency plans, so that we get a win-win for both.

And then, I think the final piece then is driving those 2-string design's deeper in the column, so that we don't forgo one or two frac stages down to Maxumburg [ph], which is much higher pressure and tends to boost IPs. We're going to continue to drive that forward. So, really early success really pleased with the progress of what the team has accomplished. But again, we're not satisfied. There's more to chase here.

Jay Stratton

And the final piece of that which we are not so sure is that reservoir characterization that were involved with is really giving us insight into where those additional sands are below the TD that we're drilling with the 2-strings. So, we're booking more position and where we should attempt it or not because we don't want to attempt at where there's potentially prolific sands that we should be reaching with the 3-string design.

Eric Seeve

Got it. Thank you. Appreciate. And lastly for me, just in terms of the settlement for the Make-Whole Litigation, can you just repeat when was the settlement entered into? When do you expect to receive the cash? And are you in active conversations for more potential settlements? Or do you need one-off issues?

Brad Johnson

So answering the last question first we are having conversations. So this was not a one-off item. The settlements that we [Technical Difficulty].

Operator

This is the operator we're unable to hear you. [Technical Difficulty]

Brad Johnson

Hello can you hear me now?

Operator

We can hear you now. Thank you. You may proceed.

Brad Johnson

So this is Brad and addressing Make-Whole questions that came through. So the last question I'll answer first. We are having conversations with additional folks. This is not a one-off event. We did provide an update on the amount of remaining unsettled claims which is $240 million. That's a reduction on unsettled claims quarter-to-quarter and the $13.5 million are the amount we recovered through those settlements.

It's more than one settlement as this represents and so you can work through the numbers there. Whereas the unsettled claims were reduced by about $20 million for which we recovered $13.5 million. And those proceeds are in the door as of today. Did I catch all the point of the question?

Eric Seeve

You did. Thanks guys. Good quarter.

Operator

And our next question comes from Patrick Fitzgerald from Baird. Your line is open.

Patrick Fitzgerald

Hi guys. So, you're settling at a pretty big discount and I'm wondering why? Is it just the timing – you’re are right about the timing or you're actually worried about the District Court on Remand not following the Fifth Circuit opinion?

Brad Johnson

Well, with regard to the opinion, obviously we deem their decision very favorable. But it has been five months six months since we've heard back from those guys. So the Board, the management has been obviously very focused on this issue, and we are moving forward with settlements that rates we deem acceptable.

Patrick Fitzgerald

Okay. So what's the status of -- if you let this kind of play out rather than settle these amounts is there any sense of timing on when the En Banc appeal would actually happen and when the bankruptcy court would come out with its decision on remand?

Brad Johnson

Don't have any comments on predicament timing of the court's actions, other than we're waiting like everyone else for them to take action. We do expect when the Fifth Circuit considers the En Banc rehearing then they will act on that and then we would return back to the Bankruptcy Court in Houston. But again, I don't have the time forecast on expectation on that at this time to share.

Patrick Fitzgerald

Okay. So that cash comes in with no strings attached. It's not an escrow this is just regardless of what happens with the rest of the case, like you've got $13.4 million is - you can spend that? Is that correct?

Brad Johnson

It's correct. That cash that came in there's no strings attached, no obligation at this point anywhere.

Jay Stratton

Those settlements are complete settlements.

Patrick Fitzgerald

Okay. Great. So a lot of moving pieces and you're taking cost per well down. And you have like a 2-string versus 3-string design that you're implementing. What's the view on like annual maintenance CapEx to keep production flat?

Brad Johnson

Sure. So when we started out the year with maintenance capital estimate of about [Technical Difficulty].

Patrick Fitzgerald

Your phone is cutting out again sorry.

Brad Johnson

So, this is Brad resuming again on the maintenance capital question. So we started the year out with maintenance capital estimate of $325 million to $350 million. Certainly through the course of the year, we've been pulling back CapEx in response to the gas prices.

Also during the course of the year, we've seen our base production exceed forecast. And so that will create a much flatter decline and with indicators suggested our maintenance capital might not be as high as we forecasted at the beginning of the year, as the year plays out we'll be able to pay that maintenance capital to 2020 and beyond. But I do expect the opportunity to perhaps reduce that maintenance capital figure as we progress through the year.

Patrick Fitzgerald

Okay. So like below $300 million do you think?

Brad Johnson

Stay tuned.

Patrick Fitzgerald

Okay. What's this -- so obviously, if you're generating free cash flow cash is coming in the door, you obviously feel pretty comfortable with this covenants 4.9 times going forward for the next year?

David Honeyfield

So Patrick, this is Dave Honeyfield. The way I would think about it is driving the free cash flow is an important part of the equation. And it's something that we're keenly aware of. As you know, we're filing our 10-Q here today. The metric today at the end of the quarter is 4.44. We're keenly aware of where they are and we believe that the free cash flow generation is our best path forward. And frankly, we have the tools to do that. So I think managing.

Patrick Fitzgerald

Yes, you cut out again, I'm sorry.

David Honeyfield

Hopefully, we didn't cut out too much there. Saying that we've got the tools to do that. We've got a very resilient PDP base that generates a lot of cash by managing the level of capital investment to levels that we think are appropriate in the current price environment. We see all those as positives for the company overall. So hopefully, that gives you a feel for how we're thinking.

Patrick Fitzgerald

Yes, great. So what was other expenses $50 million this quarter, sorry.

David Honeyfield

Sure. So as you might have seen in some of our previous quarters, we talked about some of the pre-bankruptcy groups of claims and litigation that was out there. So one of them was with the Office of Natural Resource, ONR, and there was a proof of claim of around $35 million. We were able to come to agreement on that at $12 million. And it will have an extended installment payout period associated with it. So we've come to that agreement here in the second quarter or I'm sorry prior to filing here. And then the other item was related to a royalty claim that also was pre-petition claim and we were able to negotiate a settlement in principal there that we believe was very good for the company and minimizes any cash outflow going forward. So we recorded those two items during the second quarter, since they related to periods previous.

Patrick Fitzgerald

Okay. But what's the cash impact?

Operator

Pardon me this is the operator. We are not able to hear you.

David Honeyfield

Can we actually -- let's keep moving on this Eric. Go ahead Patrick, any other questions?

Patrick Fitzgerald

Just what prices are you assuming on slide 16 with your proved developed PDP? Just so I'm clear on what prices you're using?

David Honeyfield

Yes. So the -- for the PDP these were based on the year end SEC price cases or price deck that was outstanding. I don't have those committed to memory, but they were disclosed in the Form 10-K and if you'd like we can point to that.

Patrick Fitzgerald

No, no, no. I just want to make sure that, that's what you're using. Thanks.

David Honeyfield

Yes. The piece I would add there and I think we mentioned it during our call is that interestingly our midyear prices are very consistent. So, thankfully that -- it’s just one of those items we like to highlight is reserve basis is very durable and as we've seen a little bit of strengthening on the -- little bit of strengthening on the basis side it's really what's kept pricing flat for the operation purposes.

Patrick Fitzgerald

Okay, great. Thank you very much.

Brad Johnson

Thank you.

David Honeyfield

Thank you.

Operator

Our next question comes from Michael Altman from Ameriprise. Your line is open.

Michael Altman

Yeah, you mentioned you got some debt restrictions for buying back in the open market. What about stock restrictions? Are you able to buy back the stock?

David Honeyfield

Mike, this is Dave Honeyfield. We really have the same type of restrictions related to the restricted payments basket that the current debt holders really want to make sure that that's staying in the debt structure, subject to leverage ratios that Brad had mentioned.

Michael Altman

Is there any strategies in place to try to get the stock price up a little bit from where it's at today?

David Honeyfield

That is our -- our single focus as a leadership team is to drive shareholder value up and there's been, obviously, you can imagine lots of discretions and we continue our strategy that we stated about focusing on the balance sheet, driving efficiency in our operations, driving cost down and being financially disciplined.

You've seen us be successful in reducing our debt through 3L exchange last year. We made a run it up to 2025s earlier in May and we're going to continue to do -- we see or pursue items where we think we provide an opportunity to reduce debt. And then we have discussions all the time about strategic ways to drive share price up and we look forward to sharing that at the proper time.

Michael Altman

Thank you.

Operator

Thank you. Our next question comes from Zach Goldstein from RBC. Your line is open.

Zach Goldstein

Hey, thanks guys. My questions have actually been answered now. Appreciate it.

Brad Johnson

Its Okay. Thank you.

David Honeyfield

Thank you.

Operator

Thank you. And our next question will come from Dustin Tillman from Wells Fargo. Your line is open.

Dustin Tillman

Hey guys have we look forward to the industry determination in the fall? How are you thinking about the risk to the current borrowing index?

David Honeyfield

Sure. When it comes to our borrowing base, I think it's important to note that our PDP reserves and of course the borrowing base is dominated -- or excuse me our 1P reserves and our borrowing base is dominated by our PDP production. And so that means that our borrowing base is very resilient. We're not dependent on PUDs or six on the map to maintain sufficient borrowing base.

Our RBL commitment right now is at $325 million. We've got cash flow, positive cash flow on the horizon. So we feel very good about our liquidity position, all of which we believe sets us up well for executing our plan over the next year. Our borrowing base is due up for the fall. We're already discussions with our bank group there and we expect to provide an update on that process in October.

Dustin Tillman

Right. But you're borrowing base is based on forward-looking on commodity not on the backward look that you've been giving in the PDP stuff in the deck ,right? So the reduction in the strip should -- has the potential to be material?

Brad Johnson

Yes. I think and Dave pointed out a couple of times and I'll add to this is, yes for sure the Henry Hub has weakened particularly over probably the last 60 days. But Rockies differential has improved. And so when we look at our reserves and we look at our own internal model, about our borrowing base, we're seeing very similar prices to what we were evaluating reserves at the year-end. But no doubt the borrowing base is subject to price movement and that will be as we work through this upcoming redetermination, we will be able to share the results then.

Dustin Tillman

That's helpful. Certainly you have restrictions on buying unsecured bonds and you're talking about debt reduction. Would you consider doing in open market tender for secured debt?

David Honeyfield

I think, Dustin the way I would respond to that is, I mean, frankly that's what the offer was when we tried for the 3L exchange and we work pretty hard on, trying to understand where the market was thinking on it.

And ultimately, we had objectives around reducing debt, reducing interest. And make sure, that we maintain some of the limited flexibility that we have. And frankly, the market wasn't supportive of that. So, we're going to continue to explore, different alternatives.

And in terms of inability just to use cash in a tender situation like the, may be behind your question. Brad has already, provided the feedback relative to our current restricted payment baskets in our credit facilities and lending documents that require us to be at a certain pro forma metric.

Dustin Tillman

Sorry, if that was unclear. You have first lien term loan that is trading in the 70s. I was asking about that.

David Honeyfield

Okay. I mean certainly, I don't know -- I would refer you back to where the coverage metrics are. And frankly, I don't know if that group would be interested in something that will fit into our overall strategy of trying to pursue all efforts out there, to strengthen the balance sheet.

That will be an item that, certainly an option that we need to explore. And it's been on the hit list, for a while here too. So, I'd just note, that we are working on, trying to be constructive with all of our capital providers.

Dustin Tillman

No. That's helpful. I would suggest giving unsecured bonds in the single digits, that the focus on driving shareholder value is, probably a little bit in the wrong place.

David Honeyfield

Yeah. I mean, I think, it's all virtuous right? To the extent that we can strengthen the balance sheet, I think that bodes well for, the shareholders but [Technical Difficulty]

Operator

And pardon me, this is the operator. We were unable to hear you.

David Honeyfield

So Dustin, what I was saying is we think. It's a virtuous goal for us to pursue strengthening the balance sheet. We think that's good for the shareholders. And we think the asset base is a strong resilient asset base that has a high value to it.

So, we're going to work on all those fronts. And think that they all hang together.

Dustin Tillman

Thanks guys. I appreciate it.

David Honeyfield

Sure.

Operator

Thank you. And our next question comes from Jon Mano from Mariner Investments. Your line is open.

Jon Mano

Hi. Most of my questions have been answered. But, just on that last question. So do you have the ability just to make open market purchases of term loan, these opportunities to be as opposed to the tender?

David Honeyfield

Yeah. I'm going to answer that question. I think in the same way that it would be subject to really a hierarchy that exists, in the debt repayment schedule. We do have the ability to prepay, certainly subject to repayment terms. But in terms of open market, I think, that would probably be defined as a cash outflow and the restriction under the RP would be my sense.

Jon Mano

Okay. Thanks.

Operator

Thank you. And I am showing no further questions, from our phone line. I'd now like to turn the conference back over to, Brad Johnson for any closing remarks.

Brad Johnson

I would like to thank everyone for joining us today. In addition to sharing our results for the second quarter, we also set out to affirm our focus on operational excellence, low-cost leadership and financial discipline.

If you have any questions, regarding what we discussed today, please follow-up with Aaron, at your convenience. Thank you and good day to all.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program. And you may all disconnect. Everyone, have a wonderful day.

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