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Edited Transcript of UPL earnings conference call or presentation 9-Aug-19 4:00pm GMT

Q2 2019 Ultra Petroleum Corp Earnings Call

HOUSTON Aug 12, 2019 (Thomson StreetEvents) -- Edited Transcript of Ultra Petroleum Corp earnings conference call or presentation Friday, August 9, 2019 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* C. Bradley Johnson

Ultra Petroleum Corp. - President, CEO & Director

* David W. Honeyfield

Ultra Petroleum Corp. - Senior VP & CFO

* Jerald Jay Stratton

Ultra Petroleum Corp. - Senior VP & COO

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Conference Call Participants

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* Dustin Tillman

Wells Fargo Securities, LLC, Research Division - Trading Analyst

* Eric Seeve

GoldenTree Asset Management, LP - Research Analyst & Portfolio Manager

* Jon Mano

Mariner Investment Group, LLC - Portfolio Manager

* Michael Altman

Ameriprise Financial, Inc. - Private Wealth Advisor & MD of Altman & Grubbs

* Michael Stephen Scialla

Stifel, Nicolaus & Company, Incorporated, Research Division - MD

* Patrick John Fitzgerald

Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst

* Wayne Manning Cooperman

Cobalt Capital Management, Inc. - President

* Zachary Goldstein

* Aaron Vandeford

EnerCom, Inc. - MD

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Ultra Petroleum Corp. Second Quarter 2019 Earnings Conference Call. (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.

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Aaron Vandeford, EnerCom, Inc. - MD [2]

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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'll turn the call over to Brad.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [3]

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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 a 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 margin.

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 to result in second quarter adjusted EBITDA of $94 million.

A specific note. Controllable cash costs 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've turned 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 about our progress in 2-string wellbore designs, where we successfully completed and bottom lined 8 2-string 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 will 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 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 costs, where the sum of LOE and cash G&A totaled $0.34 per Mcfe; and production taxes 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 to our shareholders.

While we are favorably levered to improved gas pricing, whether that is 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 one of the top tier gas assets in the country, where annual EBITDA cash costs approximate $1.15 per Mcfe and the controllable cash costs of LOE and cash G&A combine 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 expand 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 feed our manufacturing process of pad drilling through 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 has drilled more than 2,200 wells within the Pinedale and Jonah Fields. We know our asset well, and we will continue to 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 4 metrics that we believe illustrate how well Ultra ranks among a strong group of gas-related peers. In the top-left panel, controllable cash cost, 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 the 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 forecast 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 decline to be less than 25% for this calendar year.

EBITDA margin is shown on 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 this 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 rates on Slide 9., you will see what is supporting our strong peer performance on the previous slide. This plot provides a 5-year historical look at net production volumes in Pinedale. Since 2015, each year's 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 1 decline rate of 26% quickly drops to just 16% by year 2. And by year 4, our decline rates are less than 10% before settling into a final decline rate of 7% within 7 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 of 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.

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [4]

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Thanks, Brad. On Slide 10, I'll point out the updates to our 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 seen 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 costs 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-casing string design initiative.

As Brad shared earlier, we average $2.62 million per well for the 8 wells, where we were successful in using the 2-string design. 11 wells were attempted with the 2-string design, with the average of all 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 was 7 successful 2-string wells in the second quarter. We had a 16% reduction in CapEx compared to our 3-string design. 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 2-string wells on average of 400 feet above offset TDs and 1 to 2 less frac stages in the 5,000 to 6,000-foot completed interval. We will continue to evaluate the data and drive 2-string wells deeper where possible. We consider these results economically successful because the percentage of cost savings has more than doubled purely (inaudible) the volume impact, which nets out to a more favorable F&D cost and higher return profile. This is a meaningful capital efficiency improvement and we look to increase this improvement over time.

Based on the continued success of this program, we will complete the remaining wells on our most active drill pad exclusively with 2-string wellbores and continue evaluating 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 2 pads during the second quarter with results consistent with this process.

The pads we are drilling during the third quarter have a higher percentage of 2-string design wells, and the associated cost savings will be substantial. We also continue to see material reductions in completion costs through improved process and technology, which will be critical to creating value with the vertical program.

On Slide 12, we summarize the important milestones of 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 a very good correlation to our Lower Lance reservoir distribution in Wyoming test wells.

In addition, we've enabled the history match producing performance at 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 model to create performance at 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, the Mesaverde. We also expanded communication of the workflow field-wide, which can also be used to improve selection of vertical well placement and optimize opportunities for 2-string and 3-string well designs.

The simulation work, with its emphasis on detailed geomechanical modeling, also has application with further tuning to assist with more refined and optimized completions both for 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 released by continued application of rapidly evolving technology and processes available in our industry that can increase well performance and reduce costs.

I'll now turn the discussion over to Dave.

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [5]

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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 the (inaudible) 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 been highlighted 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 basis 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 $0.25 per MMBtu. I believe that this improvement is a result of the certainty of the infrastructure build-out 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 at cash flows and in an attempt to be opportunistic when we see favorable windows in the natural gas and 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 through the ensuing 18 months. This requirement decreases to 50% on September 30, 2019. Management also works to balance the ability to protect 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 its 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 contract 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 in the lower-right corner reflects the math for the remaining 6 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're 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 year-to-date. Based solely on PDP and pad 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're 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 have 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've outlined the company's outstanding debt amounts and debt maturities. Continuing from the themes from the previous slide, we have shown the coverage ratio of our proved developed reserves to both the outstanding and committed debt levels. What we'd point out is that the coverage for first lien debt outstanding is approximately 2.2x 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 it was not in 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 is to highlight and understand that 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're 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 3 to 2 operated rigs in response to changes in the commodity market. As summer has progressed and we've closely monitored the strip price in the market, we've made the decision to go to a single operated rig 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 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, noting 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.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [6]

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Thank you, Dave. We've made significant progress toward our goals for 2019. We will continue to demonstrate financial discipline. And as we have discussed, we made another capital adjustment in response to gas prices. We've continued to point out that there is a variable 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 opportunities ahead of us to continue reducing costs on our vertical program. We're also continuing our efforts to evaluate the incremental horizontal resource potential and will 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, the Fifth Circuit appellate court issued an opinion vacating the order of the bankruptcy court regarding the company's objection due to certain make-whole and post-decision interest claims. This order remanded 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 an en banc rehearing.

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 the holders 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's 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 enjoy the added value of the optionality we have to natural gas prices. As we have talked about before, with every $0.25 increase in the value of natural gas over our current production profile, we can generate over $55 million in additional cash flow on an unhedged basis.

Additionally, a price move from $2.50 to $2.75 per MMBtu at Opal creates 550 new economic drilling locations for us, illustrating how quickly moves to the upside in 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 control and efficiency, which are the keys to enhancing value of 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 will open the line for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And our first question comes from Mike Scialla from Stifel.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [2]

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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 I 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?

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [3]

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Mike, this is Jay. In regards to the well cost, that $2.62 million number for our monobores for 2-string designs in the second quarter is pretty solid. We've seen our first 3 wells in the third quarter, in fact, between $2.5 million and $2.6 million. So 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 on offset wells that gives us insight into where we should attempt drilling these wells to mitigate 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're seeing tangible results and being 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.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [4]

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So Jay, based on that, I guess it sounds like maybe preliminary, but do you have an idea of how much of your inventory is amenable to that 2-string design at this point?

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [5]

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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 in 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.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [6]

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Got you. Okay. And then 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 costs going back in the other direction?

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [7]

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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 all pretty well lined up with activity in the third quarter here.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [8]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [9]

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Mike, this is Dave. Yes, overall, we've factored in certainly strip pricing, so yes, I would suggest that's the right way to model free cash flow. As Brad mentioned, we got some proceeds in here on the make-whole. That's valuable, so that will help a little bit. And with the reduction in 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. We think that will be a reasonable number. I'm probably hesitant to give you 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 a 2% decline, so that indicates that there will be a fair amount of free cash flow. And that will 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 costs and overall improvement to the balance sheet. So I hope that more than giving you the exact answer to the question, I hope that, that gives you a good way -- in a sense the way we're thinking about it.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [10]

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And I might add just a few numbers to augment Dave's remarks. If you look at our second quarter EBITDA closing 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 incur during a calendar year, this is when we see that free cash flow generation really upon us and happening very soon for us here in the third quarter and really for -- and for the balance of the second half of 2019.

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Operator [11]

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Our next question comes from Wayne Cooperman from Cobalt Capital.

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Wayne Manning Cooperman, Cobalt Capital Management, Inc. - President [12]

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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? Obviously, if you can buy back bonds at a huge discount, that would really go a long way just fixing the balance sheet.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [13]

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So Wayne, I'm going to take a few of them, and then I'm going to ask the team to remind me the ones I might have -- points that I forgot or missed. As we look into 2020, we're 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. We're pursuing free cash flow. But 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.

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Wayne Manning Cooperman, Cobalt Capital Management, Inc. - President [14]

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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.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [15]

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Yes. Just to clarify, so we don't have obligations for our cash flow, but we do have some restrictions. It's important to point out. And we've shared before is that, currently, under our debt docs, 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 we'd like to put that cash towards.

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [16]

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Yes. Wayne, this is Dave Honeyfield. I think -- I mean you're hitting on some items that are very front of mind for...

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Wayne Manning Cooperman, Cobalt Capital Management, Inc. - President [17]

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I think you kind of just cut out.

(technical difficulty)

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [18]

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If we have an opportunity to work with our overall lenders...

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Wayne Manning Cooperman, Cobalt Capital Management, Inc. - President [19]

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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.

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [20]

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

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Wayne Manning Cooperman, Cobalt Capital Management, Inc. - President [21]

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I can.

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [22]

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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.

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Operator [23]

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Our next question comes from Eric Seeve from GoldenTree.

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Eric Seeve, GoldenTree Asset Management, LP - Research Analyst & Portfolio Manager [24]

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I have 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 of that based on the activity levels and the one rig that you're employing as you exit '19, what the 2020 CapEx would look like or what a reasonable range of expectations would be if you maintain that rig count and activity level?

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [25]

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Sure. Now as far as the one-rig operated program, for the rest of 2019, we're seeing about $10 million a month -- or 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 -- in your modeling.

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Eric Seeve, GoldenTree Asset Management, LP - Research Analyst & Portfolio Manager [26]

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Great. And then for those of us who are not as sophisticated between -- with respect to the 2-rig versus 3-rig casing, can you talk about what happens? It looks like you did 11 with 2-string casing: 8 were successful; 3 were not. Can you walk through for investors what happens on the 3 that were not, what happens to that well and what the implication is of not being successful?

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [27]

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Yes. This is Jay, Eric. We set up the wells to be drilled with a 2-string design, but we have a contingency available for those certain fences you just mentioned where we had 3 wells that didn't achieve the depth we wanted to under that scenario, where we drill a larger hole section below a deeper surface casing. So it offers us the opportunity to -- if the formation is not strong enough to support our designs -- 2-string designs, 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 with 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 extra money there. And then what we didn't -- when we weren't able to complete the well with only 2 strings, we had to add that extra string of casing. So sometimes, the costs can get as high as -- can exceed the 3-string cost by $200,000 or $300,000.

So in aggregate, as we've mentioned I think in our remarks, our costs were $2.9 million for all 11 wells. So we still are achieving the economic result that's positive for us. Even where we have the 3 that's -- where 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.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [28]

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And I may just add a few remarks there. Jay and his team has -- have made a lot of progress and posted 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 monobore or 2-string designs.

And then for those contingency plans, we want 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 designs deeper in a column so that we don't forego 1 or 2 frac stages down (inaudible) 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.

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [29]

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Yes. And the final piece of that and which we don't want to sell short is the reservoir characterization that we're 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 looking at more precision and where we should attempt it or not because we don't want to attempt it where there's potentially prolific sand that we should be reaching with the 3-string design.

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Eric Seeve, GoldenTree Asset Management, LP - Research Analyst & Portfolio Manager [30]

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Got it. Appreciate it. And lastly from me, just in terms of the settlement for the make-whole litigations, can you just repeat when was that 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 to be able to settle the one-off issue?

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [31]

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

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Operator [32]

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Pardon me, this is the operator. We're unable to hear you.

(technical difficulty)

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [33]

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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 is the amount we recovered through those settlements. It's more than one settlement that this represents, and so you can work through the numbers there where 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 points of the question?

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Eric Seeve, GoldenTree Asset Management, LP - Research Analyst & Portfolio Manager [34]

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You did.

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Operator [35]

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And our next question comes from Patrick Fitzgerald from Baird.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [36]

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So you're settling at a pretty big discount, and I'm wondering why. Is it just the timing -- you're worried about the timing or you're actually worried about the District Court on remand not following the Fifth Circuit opinion?

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [37]

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Well, with regard to the opinion, obviously, we deem their decision very favorable. But it has been 5 months, 6 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 and recovery rates we deem acceptable.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [38]

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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 en banc appeal would actually happen and when the bankruptcy court would come out with its decision on remand?

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [39]

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I 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 it would return back to the bankruptcy court in Houston. But again, I don't have time forecasts or an expectation on that at this time to share.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [40]

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

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [41]

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Yes, it's correct that the cash that came in, that there's no strings attached and no obligation at this point anywhere.

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [42]

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Those settlements are complete settlements.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [43]

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Yes.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [44]

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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?

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [45]

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Sure. So we started out the year with maintenance capital estimate of about...

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [46]

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Yes, your phone is cutting out again. Sorry.

(technical difficulty)

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [47]

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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 gas prices. Also during the course of the year, we've seen our base production exceed forecasts, and so that will create a much flatter decline. And what indicators suggest is that our maintenance capital might not be as high as we have forecasted at the beginning of this year. As the year plays out, we'll be able to update that maintenance capital for 2020 and beyond. But I do expect the opportunity to actually reduce that maintenance capital figure as we progress through the year.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [48]

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

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [49]

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Stay tuned.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [50]

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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 covenant 4.9x going forward for the next year?

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [51]

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So Patrick, this is Dave Honeyfield. The way that 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...

(technical difficulty)

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [52]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [53]

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Hopefully, we didn't cut out too much there. We're 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.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [54]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [55]

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Sure. So as you might have seen in some of our previous quarters, we've talked about some of the pre-bankruptcy proofs of claims and litigation that was out there. So one of them was with the Office of Natural Resources, ONRR, 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 this, 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 a 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 2 items during the second quarter since they're related to periods previous.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [56]

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Okay. But what's the cash impact, sorry?

(technical difficulty)

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Operator [57]

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Pardon me, this is the operator. We're not able to hear you.

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [58]

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Can we actually -- let's keep moving on this, Eric.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [59]

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Patrick.

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [60]

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Go ahead, Patrick. Any other questions?

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [61]

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No. Just what price there you're assuming on Slide 16 with your proved developed PDP? Just so I'm clear on what prices you are using.

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [62]

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Yes. So the -- for the PDP base, these were based on the year-end SEC price basis 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 you back to that page.

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Patrick John Fitzgerald, Robert W. Baird & Co. Incorporated, Research Division - High Yield Desk Analyst [63]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [64]

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

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Operator [65]

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Our next question comes from Michael Altman from Ameriprise.

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Michael Altman, Ameriprise Financial, Inc. - Private Wealth Advisor & MD of Altman & Grubbs [66]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [67]

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Michael, 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.

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Michael Altman, Ameriprise Financial, Inc. - Private Wealth Advisor & MD of Altman & Grubbs [68]

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

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [69]

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I mean there, our single focus as a leadership team is to drive shareholder value up. And there's been, obviously you can measure, lots of discretions. And we continue our strategy that we've stated about focusing on the balance sheet, driving efficiency in our operations, driving costs down and being financially disciplined. You've seen us be successful in reducing our debt through our dual exchange last year. We made a run at the 2025s earlier in May, and we're going to continue to do -- we see or pursue items where we think provide an opportunity to reduce debt. And then we have discussions all the time about strategic ways to drive share price up and look forward to sharing that at the proper time.

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Operator [70]

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Our next question comes from Zach Goldstein from RBC.

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Zachary Goldstein, [71]

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Thanks guys. My questions have actually been answered now. Appreciate it.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [72]

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Okay. Thank you.

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Operator [73]

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And our next question will come from Dustin Tillman from Wells Fargo.

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Dustin Tillman, Wells Fargo Securities, LLC, Research Division - Trading Analyst [74]

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We look forward to the borrowing base pre-determination on the fall. How are you thinking about the risk to the current borrowing base?

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [75]

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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 sticks on a map to maintain a sufficient borrowing base. Our RCF 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, where we have discussions with our bank group there, and we expect to provide an update on that process in October.

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Dustin Tillman, Wells Fargo Securities, LLC, Research Division - Trading Analyst [76]

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

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [77]

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Yes. And I think -- and then Dave pointed out a couple of times and I'll add to this is, yes, for sure the Henry Hub has weakened here 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. So -- but no doubt, the borrowing base is subject to price movement, and that will be as we work through this upcoming redetermination, we'll be able to share the results of that.

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Dustin Tillman, Wells Fargo Securities, LLC, Research Division - Trading Analyst [78]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [79]

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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 trial exchange. And we worked 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 -- that 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.

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Dustin Tillman, Wells Fargo Securities, LLC, Research Division - Trading Analyst [80]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [81]

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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 the exact 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. And that will be an item that's 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 tell you, note that we're working on trying to be constructive with all of our capital providers.

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Dustin Tillman, Wells Fargo Securities, LLC, Research Division - Trading Analyst [82]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [83]

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Yes. 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)

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Operator [84]

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

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [85]

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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.

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Operator [86]

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And our next question comes from Jon Mano from Mariner Investments.

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Jon Mano, Mariner Investment Group, LLC - Portfolio Manager [87]

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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 able to di it as opposed to just doing a tender?

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [88]

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Yes. 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.

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Operator [89]

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

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [90]

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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 further on 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.

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Operator [91]

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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.