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

Q1 2019 Ultra Petroleum Corp Earnings Call

HOUSTON May 21, 2019 (Thomson StreetEvents) -- Edited Transcript of Ultra Petroleum Corp earnings conference call or presentation Thursday, May 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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* Michael Stephen Scialla

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

* Wayne Manning Cooperman

Cobalt Capital Management, Inc. - President

* 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. First Quarter 2019 Earnings Results Conference Call. (Operator Instructions)

I would now like to hand the conference over to Mr. Aaron Vandeford. You may begin.

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

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Thank you, operator. Thank you all for joining us. With me today 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 first quarter 2019 earnings release and Form 10-Q. We also filed a press release announcing the launch of a private offer to exchange our outstanding 2025 notes for new third lien notes subject to the terms and conditions set forth in the confidential offering memorandum that was distributed to holders of the 2025 notes.

In this call, we will provide additional information on our first 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 the comments during this call are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more details in the Risk Factors and Forward-Looking Statements section of our annual and quarterly filings with the SEC. Although we believe 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 First Quarter 2019 Earnings Call. Today, we will provide an update on our progress toward this year's goals that we outlined during our last earnings call. To summarize these goals, we are focused on strengthening our balance sheet, optimizing the value of assets with maximum run times and minimum operating expenses, enhancing returns with lower well costs and further studying how to unlock incremental resource through horizontal development of Pinedale.

On Slide 3, you'll see a brief overview of our company with updated numbers. Over the quarter, we reduced our total debt by $80 million from year-end, demonstrating our ongoing focus on the balance sheet and progress toward meaningfully reducing debt. We posted 62.2 Bcfe of production in the first quarter, which is above the midpoint of our guidance. This outperformance was driven by strong base production and development activity occurring ahead of schedule. We will continue to be tenacious in our ongoing pursuit to reduce cycle times and well costs, maximize the value of our significant base production and provide cash flow visibility through our prudent hedging program.

Several highlights for the first quarter can be found on Slide 4. As I mentioned previously, production came in above the midpoint of our guidance. On an average daily basis, first quarter production was 691 million cubic feet equivalent, which includes 662 million cubic feet per day of gas and 4,900 barrels a day of premium-price condensate. During the first quarter, pricing at Opal continued to improve, which led to realized prices of $3.07 per Mcfe, including hedges, and adjusted EBITDA totaling $115 million.

Our capital investment for the quarter totaled $92 million and was in line with our 2019 capital budget plan, which included a slightly heavier allocation for the first quarter due to higher-working interest wells scheduled early in the year. With a continuous 3-rig operating program focused on vertical development, we turned 27 gross operated vertical wells online during Q1 with an average 24-hour IP rate of 6.5 million cubic feet equivalent per day. Cost for our vertical wells averaged $3.15 million in the first quarter of 2019, which included an incremental $100,000 invested in additional data to advance certain technical initiatives that are expected to help accelerate the next step change reduction in vertical well costs. In a few moments, Jay will share more about our successes in 2-string wellbore designs and completion operations.

Cycle times remain critical to costs and margin performance, and we are excited to share a new drilling record. In the first quarter, our average time from spud to total depth in Pinedale was 8.05 days.

Regarding the financial discipline and our stated goal to strengthen the balance sheet, we've reduced long-term debt by $17.6 million through the follow-on second lien debt exchanges. To date, the amount of debt reduced with our 2-well debt exchange has been $253 million. Over the course of the first quarter of 2019, we also reduced the amount outstanding on our revolving credit facility by $66 million.

Earlier today, we launched a Barclay-marketed private exchange offering to holders of our 7.125% senior unsecured notes due in 2025. For information and details regarding this offering, please refer to the related Form 8-K and corresponding press release filed by the company.

As I mentioned earlier, we reduced total debt by $80 million during the quarter. This was driven by changes in working capital and stronger-than-modeled natural gas pricing on our unhedged sales volumes. This decrease includes the reduction of the outstanding balance on our credit facility by $66 million, ending the period at $38 million as of March 31, 2019.

Moving to first quarter operating metrics, Slide 5 tabulates our results. The 691 million cubic feet equivalent per day translates into 62.2 Bcfe of production for the quarter. In addition to production coming in on the high end of the guidance, other highlights for the quarter are dominated by the continued overall low cost of operations for the company. These results include strong performance in LOE that hit $0.28 per Mcfe, and as forecasted, production taxes hit $0.49 per Mcfe with this higher level relative to 2018 as a result of the strong realized pricing during the quarter. Continued operational execution, combined with stronger pricing, brought adjusted EBITDA to approximately $115 million.

The last item of note on this slide is the controllable cash cost line highlighted at the bottom of the table on the left. Beginning January 1, 2019, the company made a change with respect to the estimated amount of administrative cost associated with its operations, which is classified as lease operating expense on the consolidated statement of operations. The effect of this change reduces the amount of cost categorized as lease operating expenses, with general and administrative expenses absorbing a larger portion of the total costs. This change in estimate methodology does not impact the summation of LOE and cash G&A expenses, a combination the company refers to as controllable cash costs. In the first quarter of 2019, controllable cash costs were $0.35 per Mcfe, which fall in the favorably low end of guidance and significantly lower than compared to the $0.48 posted in the fourth quarter of 2018.

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 is the fuel to invest in our business through our drilling and completion activities as cash flow continues to support ongoing operations and other efforts completed by the team in the first quarter to advance our business.

With a clear strategy for 2019, our teams are empowered to execute the plan. We are fortunate to be in a position 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 differential 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 cost of LOE and cash G&A combined to less than $0.40 per Mcfe.

Our ability to adjust the pace of development effectively and prudently 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 have compiled data on 4 metrics that we believe illustrate how well Ultra ranks among a 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, where Ultra is among the best-performing 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%, Ultra's base decline is estimated at 26% for 2019, second-best among this peer group. 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 low cost, lower base declines relative to peers and high-ranking margins, even with Ultra's 2018 margins uniquely impacted by a decade-low Rockies differentials, Ultra's production and cash flow profiles are more resilient than many other companies.

With this favorable cost and margin profile, along with large inventory of low-risk conventional vertical locations and the upside potential of lower well costs and resource expansion with horizontal development, we believe Ultra offers a very compelling investment opportunity among its gas-weighted peers.

At this time, I will turn things over to Jay.

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

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Thank you, Brad. Continuing to Slide 8, I want to take a moment to remind everyone of the scale and opportunity of our asset in the Pinedale Field. Our 83,000 contiguous acres hold an inventory of 4,000 drilling locations within the core of our asset that can fuel our lower-risk manufacturing process and pad drilling.

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 the largest operator in the basin and has produced over 3.5 Tcf of natural gas, 26.5 million barrels of oil and drilled more than 2,200 wells within the Pinedale and Jonah Fields. We know our asset well and continually advance new insights to extract more value.

Turning to Slide 9. During the quarter, we brought 27 gross operated vertical wells online with an average 24-hour IP rate of 6.5 million cubic feet equivalent per day. Our first quarter wells performed lower than the fourth quarter 2018 wells but fall within the historical range. We expect some variability quarter-to-quarter, and so we provide a range of returns for various EUR, well costs and gas prices. Our inventory is resilient to low gas prices and offers upside margin expansion with improved pricing. While we cannot control gas prices, we are committed to reducing well costs.

On Slide 10, you'll see an update to our vertical well optimization efforts. Vertical well costs averaged $3.15 million per well in the first quarter of 2019, which included more than $100,000 of incremental costs for data to advance our technical initiatives. Excluding the investments in incremental data, average well costs were down $50,000 per well. We are expecting well costs to continue to decline, targeting an average well below $3 million by year-end.

We're spending incremental dollars on additional open-hole logging to leverage staged optimization with a new petrophysical model. Additional production logging, advanced analysis and techniques are informing us of performance attributes. When combined with better reservoir characterization, this insight will help us become more precise and cost-efficient in our development activity.

Year-to-date, we have successfully drilled and completed 3 2-string casing design wells in the pilot program. Our 2-string well design, still in the early stages and seeing improvements in each iteration, has realized an average cost savings of approximately $400,000 per well or about 13% less than our current average. Based on the continued success of this program, we have planned for 9 additional 2-string wellbores to be drilled in the second quarter. We look forward to updating everyone on the results for our new well design as we progress this initiative through the year.

Drilling efficiency overall continues to improve as we achieved a single well record for a 3-string well with a spud to total depth of 6.7 days in the first quarter. We're seeing overall efficiency gains in our execution from the systematic application of new technology and processes available to our Pinedale team.

On the completion side, we have fully transitioned to an improved HVFR or high-viscosity friction reducer fluid system in all of our wells, allowing us to reduce the complexity of the completion equipment we have on location and saving an average of $15,000 to $20,000 per well. Ultra has been recycling produced water in completions for years, but advancements in this fluid system allow us to recycle produced water on the same pad for subsequent completions. As we ramp up the utilization of on-pad water recycling, a full quarter of efficiency should be realized with this new process by the end of the year. The Ultra team will continue to implement new technology and processes. When successful, we'll deploy them at scale in an ongoing effort to increase margins and development program returns. As we implement these innovations, we expect to realize material well cost reductions in our program.

Turning now to Slide 11. We want to share progress in understanding the potential to extending the resource in Pinedale to our horizontal drilling program. Early in the first quarter, we implemented an optimized completion procedure on high-graded intervals in Warbonnet 13-13 A1H drilled earlier in 2018. By leveraging the data and analysis from our advanced petrophysical model and also well performance, we were able to focus on completing only the most productive intervals. The result was an IP rate of 2.9 million cubic feet equivalent per day per 1,000 lateral feet, making it one of our stronger-performing horizontal wells to date.

Longer-term well performance on 2 horizontal wells drilled last summer, one each in the Lower Lance C1 and Lower Lance E1 zones, are also very encouraging. With 9 months of production data and the integration of our ongoing technical work, results show that both of these zones perform on par with some of our best A1 zones, including the recently completed Warbonnet 13-13 A1H.

To further understand this performance, we've completed the initial phases of the 3D seismic conversion project with encouraging results in both the Lower Lance and Mesaverde. Inversion results have been validated in predictive tests using existing wells in the core of the field. Our next step is to use predictions of productive sands along with the simulation work to history-match well productivity. The inversion results can then be used to better predict the productivity of prospective areas and specific targeting wells in flank.

For the remainder of 2019, we plan to fully leverage our 20 square mile seismic conversion volume by integrating these results into a geo-cellular earth model and complete the simulation of horizontal well performance in an effort to prioritize our horizontal development opportunities. The relatively low cost of the technical work scope for high grading potential horizontal locations gives us greater confidence that there will be areas where more capital-intensive horizontal wells can produce at levels where they will compete with our vertical wells for capital. Given this progress, we're methodically advancing toward the selection of our next horizontal locations to drill.

And with that, I'll turn things 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 12, which has an infrastructure overview, you'll 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 provides a number of 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 point out on this slide, historically trades at a premium to the CIG delivery point.

The Opal pool, which is our primary delivery point, has enjoyed 107% premium to Henry Hub pricing through the first 5 months of 2019 and historically has been a premium market to other gas delivery points as a result of the optionality. 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 discount or wider differentials to Henry Hub pricing.

Moving to Slide 13 and staying on the topic of commodity pricing. Here, you'll find a summary of our hedge 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 in a strengthening natural gas and Rockies basis market. The company has a minimum hedging requirement under its revolving credit facility to hedge at least 65% of its forecast proved developed producing natural gas production for the ensuing 18 months. Management also works to balance the ability to predict 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 given our low operating costs. 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 always helpful to remind people that it's necessary to take both the NYMEX contract and the Northwest Rockies basis contract into effect and then multiply the per MMBtu price on the derivatives by the company's average Btu factor of 1.07 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 reflects the math for the remaining 9 months of the year for our 2019 hedging program.

Looking at Slide 14. We have outlined the company's debt amounts and debt maturities. Brad has already highlighted the significant reduction in debt that occurred during the quarter. A real value to the company and important to understand is that we do not have any near-term debt maturities. As we continue to work to further strengthen the balance sheet, the company continues to have good liquidity.

Also shown is the coverage ratio of our proved developed reserves to both the outstanding and committed debt levels. As displayed in the table in the upper left corner of the slide, the coverage for first lien debt outstanding is approximately 2.25x based on year-end 2018 pricing for proved developed reserves and taking into account the outstanding debt balances as of March 31, 2019. We remain keenly focused on continuing to proactively manage our balance sheet, and I will note that we are in compliance with all of our debt covenants as of March 31, 2019.

Again and to follow up on Brad's comments earlier, we launched a third lien exchange offer this morning. A separate press release related to this offer was filed along with the corresponding Form 8-K. Barclays is serving as dealer manager, and Centerview is serving as the company's financial adviser.

Turning to Slide 15, you can see our guidance for the second quarter and the remainder of 2019. We are currently maintaining a 3-rig operated program, drilling vertical wells in Pinedale. Accordingly, we are reaffirming our capital investment plan of $320 million to $350 million and full year production guidance of 240 to 250 Bcfe. The allocation of capital remains unchanged from when we initially issued our 2019 guidance.

In the second quarter, we anticipate production to range between 660 million and 680 million cubic feet equivalent per day. We have provided a detailed breakdown of our second quarter and full year guidance on cost per Mcfe, noting that our EBITDA cash cost for the full year remains at approximately $1.15 per Mcfe. This table also reflects the revised guidance for the LOE and G&A per Mcfe, including the reclass of about $0.04 between LOE and G&A that was described earlier.

I'll now 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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While we believe we have made significant progress toward our goals for 2019, we also believe that there is valuable optionality and upside to the Ultra story, which we have outlined here on Slide 16. With our continued focus on operation 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 costs on our vertical program.

We are also continuing our efforts to gain a better understanding of the incremental horizontal resource potential, and we are encouraged by our results from our recent horizontal completion in January. The balance sheet remains a key area of focus for our leadership team. We are continuing the work we did over the last year to help strengthen the balance sheet, as evidenced by the launch this morning of a third lien exchange to further reduce our debt.

Another positive item to strengthen the balance sheet, we also have the potential to recover approximately $260 million of make-whole claims from the January decision by the Fifth Circuit Court of Appeals. Our high-margin operations also enjoy the added value of the leverage we have to natural gas prices. For example, with every $0.25 increase in the value of natural gas over our production profile, we generate over $55 million in additional cash flow on an unhedged basis. The price move from $2.50 to $2.75 per MMBtu at Opal creates 550 incremental economic drilling locations for us, illustrating how quickly moves to the upside of natural gas price can positively impact our story.

Turning now to our final slide. 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 own 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 our vertical inventory. We also believe there's significant upside potential in expanding recoverable resource from Pinedale to horizontal development, and we look forward to sharing our progress on this effort throughout 2019.

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 your first question comes from the line of Mike Scialla of Stifel.

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

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Wondering about the timing of completing the 3D seismic inversion and getting that integrated with the vertical wells, that simulation, when will that be complete and maybe the potential timing of another horizontal test based on that data.

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

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Mike, this is Jay. The technical work itself will probably be complete this quarter, by the end of second quarter. But then it's the integration of the results of that technical work into our development program. So depending on the results and the excitement that it creates within our portfolio of wells and our economic conditions at the time, we'd love to be looking at a well in the last half of the year. But that will, again, depend on the technical results that we see from the inversion. But the results themselves have been encouraging, so we're excited that we'll be able to apply them with some specificity.

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

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Okay. And I guess while we're on the topic, Jay, what was the data that you saw with the new petrophysical model that led to the improved results on the last horizontal? I guess is it all just about maximizing net pay to gross interval? Or have you learned anything else in terms of fluids or frac design or how to flow the wells?

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

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Well, there's -- the focus primarily has been on the petrophysical model and the improvement of understanding beyond just the net to gross basis, which was kind of the initial criteria that we plan a lot of our wells on. So as we saw results from the petrophysical model, we have a better idea of saturations and probably flow potential or net pay, you might refer to it as, in a lot of areas, so we are able to pinpoint even within that lateral length where we would complete. So -- and we're continuing to study the data and apply it to other wells in the field. And as we get more confident, that will also help inform us in these new areas that we look at through the inversion results.

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

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Good. And then just one last one for me, and I'll jump back in the queue. But if your 2-string design works, what could the potential savings there be for this year's program? And then I assume that would come with faster drilling. So would that savings go just into drilling more wells? Or what would you do with the savings there?

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

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Well, I won't predict what our long-term program will be for the rest of the year. That will depend on, again, the commodity prices and our development program. But as far as the wells themselves go, we do have 9 wells planned for the second quarter, which is more than we anticipated previously. So as we gain confidence in the areas we're drilling in the use of the 2-string design, I think we could see that number grow. But actually, predicting full year, what that could accomplish, I think, is a little bit early. But we're hopeful that it'll be a growing part of our portfolio.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [8]

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I'll just add a few remarks on that. I mean obviously, we're very excited with the results of the 3 wells to date for $400,000 of savings each on average. And so that is the potential. With the early results, Jay mentioned earlier, 9 wells are planned for the second quarter, which is roughly 1/3 of the program for the quarter. And then with continued success and confidence and pushing the envelope, frankly, we do see the opportunity to expand the program as we move throughout the year. And the final comment I'll make is it's certainly true, with that efficiency and the cycle times getting reduced, which we always are pursuing, improved cycle times, that can create a capital burn pace that will be faster. So as we work through it, we'll manage that and provide updates accordingly.

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Operator [9]

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(Operator Instructions) Our next question will come from the line of Wayne Cooperman of Cobalt Capital.

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Wayne Manning Cooperman, Cobalt Capital Management, Inc. - President [10]

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Any update on the make-whole recovery? Where are we in -- where's the legal process? Are you guys negotiating with people? Any kind of update on timing or dollars will be great.

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C. Bradley Johnson, Ultra Petroleum Corp. - President, CEO & Director [11]

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Sure. Regarding make-whole, no meaningful update at this time. But just to affirm what has occurred, of course, in January earlier this year, the Fifth Circuit Court of Appeals ruled favorably for us. And subsequent to that, the petitioners or the...

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David W. Honeyfield, Ultra Petroleum Corp. - Senior VP & CFO [12]

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Claimants.

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

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Claimants, thank you, Dave, did file an appeal for an en banc rehearing, and we're waiting to hear from the Fifth Circuit on that decision. We did file subsequent to that our position on that to the court. Beyond that, because it's ongoing litigation, I really don't want to share anything more regarding the make-whole at this time.

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

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Is there a time frame that you would expect them to rule on that hearing on that motion or whatever?

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

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No specific timing expectation.

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

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Wayne, this is Dave. We don't -- unfortunately, they're not compelled by any particular schedule. So the court's just -- they're going to -- they're on their own timeline there.

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

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Sometimes they give indications to you one way or the other.

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

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Yes. Nothing else, I think, we can really comment on that front.

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Operator [19]

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And we do have a follow-up question from the line of Mike Scialla of Stifel.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [20]

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Yes. Just wondering, on the data that you gathered with the vertical wells that you drilled in the first quarter, was that all in relation to the 2-string design? Or anything else you can share there on the data that you've gathered with those wells?

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [21]

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No. The data acquisition is really unrelated to the 2-string project. It's really to just give more refinement in our normal 3-string design in areas and try to become more precise in our completion strategy. So a large amount of those costs are from open-hole logging and using our new petrophysical model.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [22]

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Okay. Got it. And the decline in the vertical well IP rates for the first quarter average versus fourth quarter sounded like that was pretty well anticipated. Can you talk about where those wells are drilled relative to the fourth quarter wells? And I know you guys have nailed it down pretty well even on short-term IP rates. Can you give a sense of where the EURs for that group would average for the first quarter wells?

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [23]

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Well, as far as the well locations, we have been primarily on the same pad. So we try to high-grade all of our development decisions, and sometimes we're -- we've been fortunate in being successful in high-grading them on pad. And so some of the layer wells on pads may statistically add some variability that are lower. So I think we're seeing kind of a typical variability. Even though we had a very good 2018 average, we're seeing typical variability within the pads that we're still drilling. We've only had one rig moved to another pad, but it's very early, and we only have a couple of wells under our belt on that new pad. So it's really the same mix of pad. It's just actually being successful in high-grading the early parts of those pads, and now we're probably getting more statistical variation on the second half or later half with those pads.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [24]

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And in terms of, say, the first quarter well average EUR, would it be -- when I look at that Slide 9, you think could be maybe on the lower end of that range of 3.5 to 4.5 Bcf?

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Jerald Jay Stratton, Ultra Petroleum Corp. - Senior VP & COO [25]

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I think it's really too early to predict EURs. We've seen wide variability relative to IPs of EURs. So I'd say we want to keep an eye on those long term and just to see how those pan out. But I wouldn't predict an EUR at this point for that group of wells. We'll see them as varying greatly from our typical EUR, though.

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Operator [26]

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And there's no further questions at this time. I'd 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 [27]

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Yes. Thank you. In addition to sharing our results for the first quarter, we also set out today to make sure and affirm for everyone our focus and progress towards our 2019 goals as well as illustrate the upside value we see in Ultra Petroleum. If you have any further 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 [28]

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Ladies and gentlemen, thank you for your participation on today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.