Ultra Petroleum Corp. (UPLC) CEO Brad Johnson on Q3 2019 Results - Earnings Call Transcript

Nov. 10, 2019 8:48 AM ETUltra Petroleum Corp. (UPLCQ)4 Comments2 Likes
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Ultra Petroleum Corp. (UPLC) Q3 2019 Earnings Conference Call November 7, 2019 12:00 PM ET

Company Participants

Aaron Vandeford - IR Coordinator

Brad Johnson - President & CEO

Jay Stratton - SVP & COO

David Honeyfield - SVP & CFO

Conference Call Participants

Patrick Fitzgerald - Baird

Dustin Tillman - Wells Fargo.

Gaurav Berber - Invest Corporation

Michael Altman - Ameriprise Financial


Ladies and gentlemen, thank you for standing by. And welcome to the Ultra Petroleum Corporation Third Quarter 2019 Earnings Conference Call. At this time all participants' lines are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. [Operator Instructions]

I would now like to hand the conference over to your speaker today, Mr. Aaron Vandeford, Investor Relations. Thank you Please go ahead, sir.

Aaron Vandeford

Thank you, operator, and thank you all for joining us today. 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 third quarter 2019 earnings release. In this call, we will provide additional information on our third 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 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 or 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.

Brad Johnson

Thanks, Aaron. Hello and welcome to Ultra Petroleum's third quarter 2019 earnings call. Today we will provide an update on our efforts to the third quarter, as well as discuss some of the recent adjustments to our business plan. To summarize our consistent goals for this year, we are focused on disciplined decision making around the deployment of capital, the generation of free cash flow and strengthening our balance sheet. We remain diligent in optimizing the value of assets with maximum runtime and minimum operating expenses, enhancing returns with lower well costs and studying further on how to unlock incremental resource to advance subsurface analysis and maybe realize through either horizontal or vertical development of Pinedale.

On Slide 3 you'll see a brief overview of our company with an updated snapshot of our enterprise value. We posted 60.2 BCFE of production in the third quarter, which was at the high end of our guidance. This strong performance was driven by our base production, Pinedale's low decline rate profile and 18 new wells brought online during the quarter.

Several highlights for the third quarter can be found on Slide 4. As I mentioned previously, production came in at the top end of our guidance range. On an average daily basis, third quarter production was 654 million cubic feet equivalent, which includes 627 million cubic feet per day of gas and 4,600 barrels a day of premium price condensate. During the third quarter, we realized prices of $2.67 per MCFE, including hedges and generated adjusted EBITDA of $98 million. Our capital investment for the quarter was $56.4 million as we ramp down our doing program and are controllable cash costs for the quarter total $0.40s per MCFE.

Previously, announced in September Ultra suspended all drilling activity for the remainder of 2019 and into 2020. This decision demonstrates our commitment to financial discipline in our capital investment decision making. And the current gas price environment is difficult to support investment in new well development in Pinedale even with the significant improvements recently achieved in our drilling costs. Fortunately, we have a significant low decline production profile coupled with the low-cost structure that can generate strong cash margins from our PDP reserve base. This will generate substantial free cash flow for the foreseeable future and will provide the company with sufficient liquidity to operate the business in a prudent and disciplined manner.

Before we suspended our operating drilling program, we realized continued improvements in our well cost of approximately 12%. Reducing average well cost in the third quarter down to $2.8 million. In a few minutes, Jay will provide more details on the increased success rate of our 2-string well design. We are proud of these results achieved where meaningful reductions in well cost significantly enhanced the value of our undrilled inventory in Pinedale. Once commodity prices improve and we have further reduced that, we will be positioned to resume drilling in Pinedale and achieve better investment returns.

During the quarter Ultra Petroleum realized positive free cash flow of $5 million. This free cash generation is expected to increase nearly 10x in the fourth quarter, using strip commodity prices and our significantly reduced capital program. The reduced capital investment in conjunction with the amended RBL credit facility that eliminated the maintenance financial covenants increases our free cash flow, enables us to reduce debt at a faster pace.

Moving to third quarter operating metrics; Slide 5 presents our results. The 654 million cubic feet equivalent per day translates to 60.2 BCFE production for the quarter. All of our cash costs for the third quarter posted within guidance. Production taxes were towards the low end of our guidance at $0.24 and with the curtailment of the drilling program our DDNA rate came down to $0.82 per MCFE. Our total EBITDA cash cost came in at $1.04 per MCFE which compares very favorably to our peers. Despite gas prices reaching its lowest level in 2019 during the quarter, commodity price realizations averaged $2.67 per MCFE boosted by gas and all hedges as well as liquids contributing to 19% of the quarter's unhedged revenue.

Combining these modest price realizations with Ultra's low cash costs still delivered a strong EBITDA margin over 60%, with the company generating $1.63 per MCFE of adjusted EBITDA. For the third quarter adjusted EBITDA totaled $98 million, bringing the first 9 months of 2019 adjusted EBITDA to $305 million.

Turning now to Slide 6. We have summarized our performance on controllable cash costs, which is the sum of lease operating expenses and cash GN&A. Ultra has been a low-cost leader for years, and we will continue to emphasize the relentless effort to drive better margins with rigorous cost control. This effort becomes increasingly important as we move forward as into 2020 for the PDP only production forecast. As we experience natural production decline all of our cash costs on a per MCFE basis will be pressured. This includes LOE facility least expenses, gathering and transport fees and G&A. Some of these costs are fixed and others are variable. We recently implemented cost reduction projects on several fronts and are planning additional efforts. We are currently establishing our cost budget for 2020 and expect to announce our full budget for next year, including cost guidance in early 2020.

Moving to Slide 7. 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, which we intend to use to further strengthen our balance sheet. As responsible stewards of capital, our decision in the third quarter to halt new drilling activity, for the time being, was in the best interest of the company and our shareholders. Free cash flow continues to support ongoing operations and other efforts completed by a team in the third quarter to advance our business. We remain favorably positioned to benefit for improved natural gas pricing. Whether that is Henry hub, Northwest Rockies basis or a combination of both.

We remain prepared to deploy capital toward a resumed drilling program in Pinedale once prices indicate a sustained improve level, and we have made further reductions to our debt. The excellent pro-well cost performance results we realized that our capital program during the third quarter will enable us to deliver better returns and stronger EBITDA margins once we resume drilling. We will continue to be a low-cost leader and one of the top tier gas assets in North America with 2019 annual EBITDA cash costs projected below $1.15 per MCFE, and the controllable cash cost of LOE and cash G&A combined at approximately $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 reduction and gas price improvement. This combination of excellent assets, superior operations and disciplined management will allow us to generate EBITDA margins that rival any natural gas company in the space today.

Talking a bit more about our decision to reduce our recount during 2019 and ultimately suspend the drilling program in September, we have attempted to add some color to the timing and sequencing of our decisions here on Slide 8. As you can see, the natural gas pricing environment began to feel pressure in the first quarter. As this pressure became more intense into the second and third quarters, we made decisions to incrementally drop rigs. Meanwhile, we were achieving success with our drilling performance with decrease cycle times and improved results from the 2-string design. Ultimately, however, given the backdrop of the pricing environment, we simply were not in a position to invest capital at the rate to return needed to organically generate net free cash flow and we determined that it made more sense for the business as a whole, to focus on free cash flow generation and the use of this cash to repay debt. Frankly, not all EMP businesses have the ability to do something as bold as we have done on the capital investment front. It is the quality of the Pinedale assets and the nature of the low decline long-lived PDP reserve base, coupled with a determination to remain a top quartile low-cost operator that has allowed us to make these moves. This decision also took into account the projected impact to our borrowing base. Later on in our prepared remarks, Dave will talk more about the financial considerations of our zero rig plan.

Before turning the call over to Jay, I want to walk through what has become my favorite slide. Slide 9 provides a graph of our net production in Pinedale and shows annual wage volumes since 2015. For Pinedale, the shapes of those wages are directly related to the pace of investment. Over the last 5 years, we have built a significant large scale, low decline production base that will actually 2019 around 600 million cubic feet equivalent per day. I've said it before in other settings and it warrants being said again, we are very fortunate to be the stewards of the Pinedale field with a team that Ultra has managed and operated this asset exceptionally well. There are very few assets that have the scale of Pinedale and the resiliency of its proved reserve base. As we look at our forecasts and production for full year 2020, we expect our PDP based decline rate to be approximately 18% to 20%. Annual production decline rates in the following years flattened out to just 16% by Year-2 and after Year-4 our decline rates are down in the single digits.

With that, I would like to turn things over to Jay to discuss our operational successes during third quarter.

Jay Stratton

Thank you, Brad. Our operations team made their greatest progress to date by exceeding our performance goals for both 2-string and 3-string wells in the third quarter of 2019.

We successfully drilled 7 of 8 2-string wells attempted during the quarter at an average cost of $2.6 million. A total of 18 wells were drilled with an average cost of $2.8 million, down 12% from $3.2 million in the first half of the year. For the year, we successfully drilled 16 2-string wells with a total average cost of $2.6 million per well, well below our budget of $3.1 million per vertical well. Lowering well costs by $500,000 for 2-string wells we used resulted in a 16% reduction in DC&E cost for those wells over the course of the year. We continue to improve our understanding of where the 2-string well design can be deployed with success. The third quarter of 2019 marked the third sequential quarter in which our success rate improved. Each new well we drill offers us great understanding of the Pinedale asset and the most effective way to recover the resource located in the field.

On Slide 11, you'll see the summary of our vertical well development results and the impact from our reduced well costs. During the quarter we brought 18 gross operated vertical wells online, with an average 24-hour IP rate of 5.8 million cubic feet equivalent per day. Even though we saw a reduction in the 24-hour initial production rate with 2-string wells, early projections of EUR are indicating an improvement in FD cost of approximately 6% for these wells. The IP rate is also typical of the lower average productivity from wells at the end of our pad development program due to early hydrating of drilling order. I continue to believe that the industry has now developed a full appreciation of the advances made by Ultra over the years. I think it's important to remind folks that these are very large multi-direction development pads.

As an example, one of the pads that 57 wells drilled and completed safely utilizing true simultaneous operations of drilling, completion, construction and production operations since moving the rig on location back in October 2017. We expect that the new efficiencies developed over the year along with our historically efficient execution will allow us to replicate these strong results when commodity prices improve and we resume our drilling program. Our focus on controllable costs and a step-change in drilling costs have made our returns resilient even at low natural gas prices.

Turning now to Slide 12. We want to recap our progress in 2019 from the advanced reservoir characterization project. Our methodology has been employed in the industry's most capable subject matter experts alongside our Ultra subsurface team to leverage a rich data set of well results, set physical data and 3D seismic to better understand location and productive attributes of the best completion targets. With over 6,000 feet of targeted interval in our vertical development footprint, we still see opportunity on the applying to this area to locate commercial horizontal targets for several thousand feet productive interval remain. Our initial phase of the 3D seismic conversion project was completed with encouraging results in both the lower Lance and Mesaverde.

Conversion results have been validated in blind test wells evaluating the predictability of reservoir distribution in the core of the field. The modeling was also predictive of the wildly variable productivity trends of our existing horizontal wells to further improve competence in the characterization results. The long term work of building off the geo-cellular earth model of these insights has begun. Additional technical scopes of work are in progress that will also feed into better understandings of productive attributes and specific locations of these intervals within the lower Lance and Mesaverde. The inversion scope of work is being evaluated and refined for all productive intervals within our original pilot area and more broadly across the field.

Continued progress in this technical workflow will be used to identify most perspective horizontal locations on Pinedale flank. Important to this advanced subsurface work is that it will also serve to highlight opportunities to exploit our vertical development program with more precision and less risk when the commodity price environment improves and development drilling can be resumed. The relatively low cost of this advanced technical work scope for high grading potential horizontal locations gives us confidence that there will be areas where more capital intensive of horizontal wells can compete for capital, along with refined vertical development, using more precise placement of lower costs 2-string wells.

During this pause in our Pinedale development, the Ultra team will continue to implement new insights and enhanced processes, with plans to deploy them at scale and an ongoing effort to increase margins and future development program investment returns. As we gain traction on new innovations, we expect to realize additional and material development efficiencies and opportunities in our Pinedale development.

And with that, I'll turn the call back over to Dave.

David Honeyfield

Thanks, Jay. On Slide 13, we've outlined the results of our fall borrowing base redetermination. In providing the reserves to the banks for the fall borrowing base, we had contemplated the impact of potentially suspending the drilling program. Therefore, pads were not used in setting the fall borrowing base. What is important to recognize, however, is that the borrowing base for the company has proven to be resilient, even during periods of depressed commodity prices because of the low decline rates and Ultra's vigilant cost management. The fall borrowing base was established at $1.175 billion based on mid-year reserves prepared by [indiscernible] and run at the bank's price deck. The revolving credit facility commitment was established at $200 million with an agreement to reduce the commitment amount to $120 million at the end of February 2020. This reduction lines up well with our expectations of timing related to reducing the outstanding's under the RBL and therefore, I believe that the $120 million commitment level at this time will be sufficient for the company.

Last item to highlight here is that the borrowing base will continue to be determined on a semi-annual basis. And our intent is to maintain the RBL credit agreement through maturity, even if it is with a lower commitment level. As part of our fall borrowing base redetermination, we were also able to secure the fifth amendment to the credit agreement, which greatly improves our financial flexibility. The details of this amendment were previously disclosed on September 16. So I won't go through them in too much detail, except to remind the market that this amendment eliminated all of our financial maintenance covenants in the credit agreement. The amendment in conjunction with our commitment to disciplined capital investment provides a path forward to reduce our debt at today's commodity prices. Given the curtailment of the drilling program, we're confident that the current and reduced commitment amount will continue to provide adequate liquidity to operate the business in a responsible manner.

Looking at Slide 14, we have outlined the company's debt amounts and debt maturities. While I believe most folks are aware, I do want to reiterate and highlight that we do not have any near term debt maturities. The next scheduled maturity comes due in 2022 with the maturity of our RBL facility and the 2022 senior unsecured notes. We have these dates firmly in mind as we continue to work to further strengthen the balance sheet. Also shown is the coverage ratio of our approved 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 2.2x based on year-end 2018 SEC pricing for proved developed reserves and taking into account the debt balances as of September 30, 2019. Suffice it to say, we are keenly focused on the proactive management of our balance sheet.

Turning now to Slide 15; you'll find a summary of our hedge book. Ultra is approximately 50% hedged on its 2020 GDP natural gas production and has provided itself the opportunity to participate in upside given the nature of the hedge program being predominantly comprised of costless collars and deferred premium puts. At the current time, we believe that we are hedged at a reasonable level and we will look for opportunities to lock in value when and where the market allows. Under the fifth amendment to our current agreement, our minimum hedging requirements were relaxed. Previously, the company was required to hedge at least 65% of its forecast proved developed producing natural gas reserves for the ensuing 18 months. Under the amendment, that amount has been reduced to 50% and the tenor shortened to have the requirement only through the first quarter of 2020.

When factoring in the impact of our hedging program and our realized pricing in general, it's always worth reminding people that it is necessary to take both the NYMEX contract and the Northwest rock spaces contract into effect, and then multiply the per MMBTU price on the derivatives of the company's average BTU factor of 1.07 in order to calculate 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 reflects the map for the remaining 3 months of the year for our 2019 hedging program.

Turning now to Slide 16 which has an infrastructure overview of natural gas flows, you will see a variety of destinations into which we can sell our production. The concept of the Opal pool is valuable, in that it affords deliveries into 5 major pipelines. Having this flexibility provides us assurance of flow and deliverability to valuable markets. Because the Opal pool gas provides several takeaway options, it has historically yielded 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 PEONs [ph], 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.

We're clearly a business advantage. It's also an important modeling point for investors to make sure this location is captured accurately. For example, relative to pricing for natural gas price at CIG, Northwest rocks has been particularly strong through October and early November, with an approximate $0.40 per MMBTU higher realization for our natural gas. This is largely due to the fact that CIG gas competes more directly with mid-continent and the eastern markets. In comparison, our sales go into the relatively predictable Western markets, where there tends to be more bias to tightening price spikes than for those markets that flow east. The Opal pool, which is our primary delivery point, has traded within 5% of Henry hub, as we have seen historically in this region, and much better than the decade-low levels of 2018. This delivery point 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.

Turning to Slide 17; you can see our guidance for the fourth quarter and the full year 2019. As discussed previously, in September, we made the decision to halt new drilling activity in response to changes in the market. With the decision to go to a zero rate program, we expect our capital program for the full year to range from $240 million to $250 million. During the first 9 months of the year, total capital was $234 million. So the CapEx forecast in the fourth quarter includes minimal drilling and completions carry over from the third quarter and a small amount of corporate capital. The full year production guidance of 239 million to 241 million BCFP reflects a narrower range given the visibility we have at this point to total production for the year. In the fourth quarter specifically, we anticipate production to range between 590 million and 610 million cubic feet equivalent per day. In addition, we have provided a detailed breakdown of our fourth quarter and full year guidance of cost per MCFE, noting that our EBITDA cash cost for the full year remains at approximately $1.15 per MCFE when using the midpoints of our guidance ranges, demonstrating the predictable profitability of our operations.

Turn into Slide 18 now. Looking forward to 2020, our low decline rates indicate a predictable production profile that can be extrapolated further into the next couple of years when considering our historical annual decline profile. Currently, we have tightened the range we are guiding for 2020 to 182 to 192 BCF of production for the full year. While we are still going through our budgeting process for 2020, this production profile is consistent with previous guidance and is representative of our historical decline profile for PDP reserves, including the low 16% and 12% annual decline rates associated with 2021 and 2022.

The bullet points here on slide 18 are designed to assist investors in modeling the company, whereby we are describing the elements of our operations that are variable and fixed, as well as highlighting that we expect to limit capital to no more than $5 million per quarter during 2020. Ultra has a long track record of being a low cost producer, and we expect that focus to continue moving forward. While a decreasing production profile may put some pressure on the per MCFE metrics, it is clear that Ultra will continue to deliver strong operating margins, even in the current commodity price environment.

Now, I'll turn the call back to Brad.

Brad Johnson

Thank you, Dave. Slide 19 highlights additional upside for realtor. Our disciplined management of the Pinedale asset is evident through some of the lowest controllable cash costs among our peers, which in turn generates strong margins. This favorable structure coupled with control over each element of our operations gives us a great deal of certainty in our ability to continue generating positive free cash flow. We continue to lower the average cost of new wells in Pinedale, a 12% reduction in well costs in the third quarter of 2019. As commodity prices improve, and when we look to restart our drilling program in Pinedale, the knowledge gained from our operations over the course of this year, will support the improved low costs we have realized in 2019. In addition to the successes achieved in driving down low cost in the third quarter, the investment in the sub-service work will also support further horizontal well potential as we further unlock value in Pinedale.

Our optionality to improve natural gas prices leaves us in a position to benefit greatly from any increase in the commodity price. Every $0.25 increase in natural gas pricing translates into approximately $35 million of additional cash flow on an unhedged basis, and adds to our inventory of economic wells. With the lower capital costs posted in the third quarter, our economic locations expanded to just under 2,000 locations at a $2.75 Opal price. Gas price alone impacts inventory, and with a price improvement from $2.50 to $2.75 at Opal, approximately 600 economic locations are added. These stats should help demonstrate the option value for Ultra with improved pricing and continued cost discipline.

We are fortunate to own such an exceptional asset. While we wait for a sustained improvement in commodity prices. To justify future drilling activity, we were able to manage existing production to generate free cash flow and further improve our balance sheet. To that end, we remain vigilant in pursuing any opportunity we believe will improve our financial flexibility. Our proactive efforts on liability management continues with our engagement with center view partners. Recently we engaged Tudor Pickering Holt as advisors to assist the company in evaluating strategic alternatives. As disclosed in our press release earlier today, each advisor is focused on a specific mandate. There is no predefined outcome or timeline for these efforts, and there are no additional updates or details to disclose at this time.

With our prepared remarks now concluded we will open the line for questions.

Question-And-Answer Session


[Operator Instructions] And our first question comes from the line of Patrick Fitzgerald with Baird.


Thanks for all the helpful floods. Answers a lot of questions. But I wanted to ask about the potential $240 million related to the may call and post position interest. Is there any update on that from a procedural standpoint? And also, any update on potentially settling more of those amounts with the previous bankruptcy OpCo holders?


Hi Patrick, this is David Honeyfield. Thanks for your question. As you know and in pretty consistent with what we've said in previous calls this item is still with the Fifth Circuit Court of Appeals. The note holders filed a petition back in the end of January for an onboard re-hearing. And in February we filed a response to that rehearing. We have not had any updates from the Fifth Circuit. All I can really point out is that cumulatively through 2019 we have collected on approximately $13.5 million of settlements and the $240 million of potential unsettled claims is still out there. So pretty hard for us to comment any further or even really to speculate on timing, given that there's not a required timeline that the Fifth Circuit has to adhere to.


Okay. And the case wouldn't be reheard in bankruptcy court until the onboard decision is made, or is there some parallel process?


No. Our understanding and appreciation from legal counsel is that the onboard request will have to be determined, and then it will likely get remanded at that time to the bankruptcy court but there's not a parallel process.


Okay. Thanks. Could you comment on the prospects of being able to buy back your bonds below par or repaying your term loan closer to where it's currently trading? I guess that's what you hired the advisors to do.


Sure. So maybe a couple of things Patrick that are helpful on that. Certainly, we see an opportunity to -- for those being value add transactions. What I think is helpful to understand though is that the RP baskets, in the dentures for both the first lien and second lien and then as well in our RBL, we are prohibited from using cash to repurchase indebtedness at this time. So while we got that amendment in the RBL to have the flexibility to do it, it would be contingent upon approval from first lien and second lien or lenders. All that said, there's, like you said, reference depth is really what we're studying, and they're pretty broad base alternatives that we continue to evaluate with our advisors and we'll keep the market updated. And I think it just probably goes without saying but I'm going to say it anyhow. This is what we're focused on right now. We think that this is where we can make significant progress for the company here in the near term.


All right. Just one more for me. I know it's in ways in the future, potentially, but have you started trying to track down all the holders who would potentially due to pay you back on the may call? Is that like an easy process that you've already started or is that just kind of something you're going to focus on when the decision is actually made?


That list is a well-defined list. And it's probably something that the public can see through bankruptcy filings, et cetera so it's not really a matter of finding the folks. We have confidence that collectability would be there. These are all high-quality institutions so not much more I can really add to that.


All right, thanks.


Thank you. And our next question comes from the line of Dustin Tillman with Wells Fargo.


Thanks for taking my call. I have a question about differentials and realizations when the Rockies Express commitment comes back online. Do you expect any uplift in realizations or is that just going to be a cost item?


Dustin, this is Dave again, and I'll give a few comments. Brad obviously may have some more color to add here too. So Rockies Express, as you know, we do have the FT commitment on that. It's $0.37 a dekatherm, 200 million dekatherm a day starting in December. We continue to look at opportunities to utilize that capacity to potentially transfer it, release it et cetera. Right now, the way we've modeled it is that it will be an expense item and that's basically the penny that's out there in our guidance range. What is helpful to understand and I think folks that follow the market knows there are points in time where that can be in the money for us and we would have the ability to flow our gas. Clearly over the winter right now, the relative strength of basis for Northwest rocks compared to flowing all the way to Zone 3 would tell us that we're better off selling our gas at Northwest rocks and so we'll continue to evaluate it. But it is something that we're aware of. It's something we've modeled into our outlook and our cash flow streams. At this point, Dustin, what I would say is we're really working to optimize that best we can for the company.


Okay, that's helpful. Obviously, going into managed decline mode here is an attempt to wait for higher commodity prices. Strategically, how do you think about I mean, other than just filing for bankruptcy, how do you create value and what gas prices are required to ever have equity value here?


Good question. This is Brad just touching on that. As you saw on our slide deck and prepared remarks, we put a lot of emphasis on the low decline that we have in Pinedale and that does afford us the opportunity to ramp back our CapEx in the current gas price environment. There's not a set price for us that we've defined explicitly for when we would resume drilling in Pinedale. We would look for that pricing to be improved on a more sustained level. And certainly with the cost improvements that Jay and his team captured in the third quarter, certainly lowers that threshold for when we would return to drill. Our efforts here are focused on long term success of this company. You've seen us address proactively the balance sheet and be opportunistic there in our liability management efforts. And again, we're looking at other strategic alternatives as well. But we're clearly focused on what we've been talking about for 18 months, and that's generating cash, reducing debt and being disciplined with CapEx.


Appreciate it. One last question for me is, if you do receive additional proceeds from the may call settlements, do you have freedom to use that cash however you want? Does it create additional RP capacity or is it limited similar to any cash regeneration at the business today? And how do you envision using that cash if it does come in?


Yes, for may call recovery, there is no specific obligations for the use of those proceeds but there are restrictions and Dave touched on that earlier. For example, right now we can't go buy debt at a discount while our net debt dollar is over 3x. So that is one restriction we have. We are focused on cash generation. May call recovery would certainly accelerate the cash bill and that opens up options for us, certainly, for which we don't have a defined use for that at this time. But that's part of our evaluation process that we're undergoing right now, specifically in the strategic alternative space.


Thank you.


Thank you. And our next question comes from the line of Gaurav Berber with Invest Corporation.


Hi, good afternoon. And just one quick question. You alluded to sort of the cost structure when the decline sets in. Can you give us any sort of guidance in terms of should we expect LOE inflation in single-digit or double-digit range once that decline sets in?


Sure. We're not yet ready to prepare guidance. We'll be rolling that out in the next few months. So if you can appreciate as we're working through year-end and getting ready for 2020. We look forward to sharing that with the market very soon. And as you noted in our remarks there, we wanted to give folks a heads up, that there is going to be some pressure on our unit basis. And so we do expect it to go up not down in the near term. But we are focused on driving costs down in our operating costs. As we talked about, and Rick and Dave shared a little bit of remarks about Rex, we think about that as a cost burden, but looking for ways to reduce that burden. So you'll see us -- it will be sharing updates with our efforts to reduce costs, expand that margin as best we can on the revenue side as we go forward. But it is important and you noted we do -- as we have declining production on a per unit basis, there's going to be some cost pressure.


And hopefully Gaurav, you've seen on Slide 18, we did give a little bit of kind of guidance to the market in terms of how to think about each of the individual line items. So our hope at this point is that you can take that and Brad's point is directional and we'll update the market with more specific guidance as we wrap up our budgeting process.


Okay, are you thinking that this would be outward sort of your 4Q announcement, or would you be able to put guidance out ahead of then?


January or February timing.


As Brad mentioned on the call, we're looking at early 2020.


Okay, thank you.


[Operator Instructions] Our next question comes from the line of Michael Altman with Ameriprise Financial.


Thanks for taking my call. I just want to make sure I heard that correctly that you said cash flow in the next quarter should improve 10x. So that would come to about $15 million, is that correct? And if so do you anticipate in the next 3 or 4 quarters going forward to have that same sort of cash flow generation?


As we look into 2020, at this point in time, we have given guidance for production and CapEx. So stay tuned for free cash flow projections in 2020 when we roll out our full budget, again in January, February. But circling back fourth quarter 2019, we are providing a projection of cash flow to be around $15 million for the quarter.


How would that translate into profitability? In other words, cash flow isn't necessarily income, but is that going to be fairly close? Would you anticipate?


Michael, this is Dave. One thing that might be helpful to look at are some of the reconciliation tables that we have in our press release and in the slide deck because that'll walk through kind of the way that you can get from net income to EBITDA. And then keep in mind we're defining free cash flow as EBITDA less CapEx and less the cash interest service. So hopefully those give you the tools there to do that other than just kind of regurgitating the tables. There's probably not too much more I can add. The one caveat that I'll put out there is we've tried to make this as clean and crisp as we can and we're always going to have working capital items based on just payable type -- receivables and payables, et cetera. So use it as a guide. And you think about the pace of -- it was about $10 million a month per rig and so overall, I think all those numbers came together pretty well.


Okay, thanks. Again, appreciate it and you guys are doing a great job.


Thank you. And I'm showing no further questions at this time. I will now turn the call back over to President and CEO Brad Johnson for closing remarks.

Brad Johnson

I want to thank everyone for joining our conference call. In addition to sharing our results for the third quarter we also set out to affirm for everyone our focus and progress towards generating free cash flow and improving our balance sheet. 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.


Ladies and gentlemen, this concludes today's conference call. Thank you for participating and you may now disconnect.

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