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QEP Resources (NYSE:QEP)
Q1 2019 Earnings Call
April 25, 2019 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Greetings, and welcome to the QEP Resources first-quarter 2019 earnings conference call. [Operator instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, William Kent, director of investor relations. Thank you, sir.

You may begin.

William Kent -- Director of Investor Relations

Thank you, Christine, and good morning, everyone. Thank you for joining us today for the QEP Resources' first-quarter 2019 results conference call. With me today are Tim Cutt, president and chief executive officer; Richard Doleshek, executive vice president and chief financial officer; Joe Redman, vice president of our Southern region; and Jeff Tommerup, senior vice president of the Northern region and HSE. If you've not done so already, please go to our website, qepres.com, to obtain copies of our earnings release, which contains tables with our financial results along with the slide presentation with maps and other supporting material.

In today's conference call, we'll use certain non-GAAP measures, including EBITDA, which is referred to as adjusted EBITDA in our earnings release and SEC filings, and adjusted transportation and processing costs. These measures are reconciled to the most comparable GAAP measures in the earnings release and SEC filings. In addition, we'll be making numerous forward-looking statements. We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which are beyond our control.

We refer everyone to our more robust forward-looking statement disclaimer and discussion of these risks facing our business in our earnings release and SEC filings. With that, I would like to turn the call over to Tim.

Tim Cutt -- President and Chief Executive Officer

Thanks, Will, and good morning, everyone. And thank you for joining the call. Today, I will provide an update on our first-quarter operating performance, including progress against the planned reset of G&A expense. I will then turn the call to Richard to discuss the details of our financial performance.

As I noted on our last call, the company and the board has engaged legal and financial advisors, and we are progressing our review of all strategic alternatives to maximize the value of QEP. As a reminder, this effort may or may not result in a transaction, and we do not plan to comment further until the process is complete. For the first quarter, I am pleased to report that operational performance is consistent with guidance in every category. Our overall production is on target, and we expect Permian oil production to grow by approximately 10% during the second quarter as a result of increased completion activity.

We've accelerated our Williston drilling program by two months, which will help to ensure delivery of a planned production increase during the fourth quarter of the year. On the well spacing front, the drilling spacing units drilled at lower density during the late 2017 and 2018, along with the wells brought on during the first quarter of 2019, continued to deliver as expected. This gives us great confidence in meeting over production forecast as we move forward with our 2019 development program. We have been successful in delivering repeatable, highly economic wells in mustang springs, with the current spacing of six to 10 wells per mile per zone.

The primary zone is being developed at the Spraberry and Wolfcamp A and B along with selected wells in the bien, Jo Mill and Wolfcamp B. This drilling configuration results in a well density of 30 to 35 wells per mile as compared to the high-density tests at 45 wells per mile. We have optimized our capital spend profile for the new production facilities in the Permian at non-consented marginal third-party operated wells in the Williston. In addition, our operations teams are delivering continuous improvement on both cost and effectiveness, which is positively impacting cycle time and capital intensity.

As a result of this work, drilling and completion costs have decreased by approximately $500,000 per well. As capital is freed up, we will shift on toward executing additional drilling and completion activity in the Permian. We now plan to drill and complete an additional 10 to 12 wells in the Permian during 2019, while still living within overall capital guidance. We have not changed volume guidance for 2019, given that the additional Permian wells will come on later in the year and the associated production from the wells will be partially offset by non-consenting the Williston non-operated wells.

We do, however, expect the additional wells to add more than 1.5 million barrels of oil equivalent to our 2020 business. LOE per BOE increased as anticipated during the first quarter due to the sale of the Haynesville gas asset and production decline related to lower completion activity levels in the fourth quarter of 2018. As a reminder, the Haynesville was operated below $2 per barrel of oil equivalent. We have a laser-sharp focus on LOE and expect to see it trend down throughout the year in line with full year guidance.

I will now spend a few minutes discussing efforts to reset our G&A expense. During the quarter, we notified our employees of a planned reduction to take place during the first half of the year. We expect to be operating at our go-forward staffing level by mid-year of 2019, at which point we will have reduced the total workforce by approximately 60% since the announcement of our strategic initiatives in February of 2018. In addition, we have lowered non-employee costs substantially and are confident of achieving the targeted normalized G&A expense reduction of 45% between 2018 and 2020.

Although we have been aggressive with our reductions, we are confident that we have retained the core business, technical and operating staff and systems required to execute our forward plans. G&A expense in the first quarter included retention and severance payment, consistent with our business plan. G&A expense will come down significantly throughout the year with an eye on achieving our stated $3 per BOE run rate for the full year of 2020. With our focus on cost reduction and volume delivery, we remain confident in our ability to reach cash flow neutrality before year end, and we continue to keep an eye on product price as the year progresses.

We are currently running three rigs in the Permian, and we'll make the final judgment on dropping to two rigs consistent with our guidance closer to midyear. We have established the well spacing in the Permian that should deliver predictable results over a continuous acreage acquisition, substantially all of which is held by production. We're progressing through a reset of our cost structure, which will deliver significant value moving forward, and we have retained a world-class employee base prepared to deliver outstanding results. At $55 oil price, we will be able to maintain flat production and live within cash flow, and at $60 we can grow our Permian business by 15% per annum and overall volume at 12% per annum, while growing positive cash flow over time.

Our goal is to deliver a low-cost competitive, predictable long-term oil investment opportunity in the Permian basin, while maximizing the value of the Williston basin through execution of selective drilling and refrack opportunities. I'll now turn the call to Richard to discuss our financial results.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Thank you, Tim, and good morning, everyone. I'll give some color on the first quarter, and update our 2019 guidance, including the progress we have made on the G&A front. Then we'll open the call for Q&A. In the first quarter of 2019, we generated $119.8 million of adjusted EBITDA.

The lower adjusted EBITDA compared to the fourth quarter of last year is reflective of, among other things, starting our Haynesville assets, which contributed about 18% of our fourth quarter revenue, and oil prices that were at their lowest level since the third quarter of 2017.Production in the first quarter was 7.8 million barrels of oil equivalent. Oil volumes were right down the middle of the fairway of our guidance we issued in February at 5.08 million barrels. Permian basin oil volumes were down about 331,000 barrels to 2.91 million barrels, which is down about 10% from the fourth quarter, but up 755,000 barrels or 35% from production in the first quarter of last year. In the Permian, 12 wells were placed on production during the quarter, two more than originally forecasted.

Williston oil volumes were 2.16 million barrels, down about 324,000 barrels from the fourth quarter. At the very end of the first quarter, we commenced drilling operations on the seven well Vegas pad, which we expect to put on production in the fourth quarter of this year. Natural gas lines were nine bcf of which two bcf was from our Haynesville asset, which we owned for 10 days in January. NGL volumes were 1.18 million barrels, marginally down from the fourth quarter.

With regard to production guidance for the year, due to improved drilling and completion of facilities in the Permian basin, faster and cheaper in both phases of the well construction process, we expect to be able to drill and complete 10 to 12 initial wells in the Permian basin this year. However, those wells will not contribute significant volumes in the year. So our guidance for oil volumes for 2019 is unchanged at 20.5 million to 21.5 million barrels. Our guidance for natural gas lines for 2019 is increased to a range of 25.5 to 27.5 bcf, which reflects the volumes from our Haynesville assets, which we had amended from our initial guidance.

Our guidance for NGL volumes for 2019 is unchanged at 3.7 million to 4.2 million barrels. For the second quarter, our production guidance is 6.75 million to 7.22 million barrels of oil equivalent. Please see our earnings release for additional details. Combined lease operating and adjusted transportation expenses, including the $13.8 million of transportation expenses that are netted against revenue, were $76 million in the quarter, down from $98 million in the fourth quarter.

On a per unit basis, lease operating expenses were $6.60 per BOE, which is $1.49 per BOE higher than in the fourth quarter. Adjusted transportation expense was $3.17 per BOE, which is down $0.14 per BOE from the fourth quarter. The divestiture of our Haynesville assets was primarily responsible for the decrease in absolute expense and the increase in per unit expenses. Our guidance for lease operating and adjusted transportation expense for 2019 is unchanged at $9 to $10 per BOE.

G&A expenses were $63 million in the quarter, up $6 million from the fourth quarter, including the quarter where $26 million of expenses related to our evaluation of strategic alternatives and scaling down our corporate cost structure to better match our E&P activities. We have reduced the midpoint of our guidance for G&A expenses for 2019 by $5 million to $170 million of which $35 million is share-based compensation expense. Our guidance includes $50 million to $55 million of expenses associated with our strategic initiatives, including our employee retention and severance programs. We expect to incur a significant portion of the expenses in the first half of the year.

We provided more detail in the slide deck that accompanied our earnings release yesterday, which illustrates our path to a G&A level that is at or below $3 per BOE in 2020. Excluding advances driven by our stock price, we expect G&A in the second quarter to be around $45 million, which will include about $15 million of what we are referring to as special G&A expense. For the first quarter, we reported net loss of $117 million. Driving the net loss was $176 million of unrealized loss associated with the mark-to-market value of our commodity derivatives portfolio.

At December 31, the portfolio was a net asset of $123 million, compared to a net liability of $55 million at March 31. DD&A expense was $123 million, which was $60 million less than we reported in the fourth quarter. Capital expenditures, excluding acquisitions, on an accrual basis in the first quarter were $167 million, of which $163 million was directed to the Permian basin and $5 million to the Williston basin. Our guidance for capital expenditures for 2019, excluding acquisition and divestiture activity, is unchanged.

Capital expenditures in the second quarter, excluding acquisitions, should be in the range of $185 million to $205 million, which reflects the Vegas pad drilling activity in the Williston basin. With regard to our balance sheet, at the end of the quarter, total assets were $5.47 billion and shareholder equity was about $2.64 billion. Total debt was approximately $2.1 billion, of which all was our senior notes, and we had nothing asking under revolving credit facility, and had $90 million in cash at the end of the quarter. With those prepared comments from me, we'll now open the call for Q&A. 

Questions and Answers:

Operator

[Operator instructions] Thank you. Our first question comes from the line of Gabe Daoud with Cowen.

Gabe Daoud -- Cowen and Company -- Analyst

Hey, good morning guys. Maybe just starting with the density slide, Slide 8. Could you just talk a little bit about how going from the high-density case to the current density case, how does that impact inventory? Obviously, it'll be lower, but can you quantify the impact at this point? And then also what have you learned about, I guess, the Middle Spraberry basin's 2017 dynamics that zone outside of your near-term development plan?

Tim Cutt -- President and Chief Executive Officer

Yeah, I think that we put the slide out to kind of demonstrate where most of our money is going over the next year. Obviously, we're developing other zones, including the bien, the Jo Mill, the Wolfcamp B. We're bringing on wells in the bien now that are very positive. So we didn't want the slide to represent any change in our thinking.

It just says these are the ones we had the most data on, and we're delivering what we thought we deliver. So you should feel good about the consistency. Although the density has come down per zone, the more we learn about the alternate zones out of these three, the more we can add into that. So it was really hard to ask the answer of the remaining location question, it's a lot more about kind of are we on price? I mean, at a much higher price, you know we might go back to a higher density, if it makes economic sense.

The spacing could change with time. We're on a continuous improvement kind of cycle and also there, it was lateral length. So we look at it as kind of we've got another, you know, 10 million to 15 million lateral feet to drill and how we attract that will change through time. So we felt like it was important to show you that when we went from high-density to a bit lower density, we've got right on the type curve.

And if you do your comparisons, which you will, you'll find that we are well in line with our competitors, if not near the top of that curve.

Gabe Daoud -- Cowen and Company -- Analyst

Got it. thanks, Tim. That's helpful. And then follow-up.

Your comment on the third rig, you mentioned you'd make a final decision, I guess, around midyear. Can you just maybe elaborate a bit more on what exactly you're looking for and what will determine whether or not you keep that third rig? Is it -- is there anything on the gas side, just in terms of pricing or maybe even -- any kind of tightness in the field that you're seeing? Just any additional color there would be helpful.

Tim Cutt -- President and Chief Executive Officer

Yes. It's really around the backwardation in the forward curve. I mean, if we saw $60 plus going forward, I think we'd have a compelling case to talk to our board about potential -- keeping that rig running. You know, $55 and dropping to three rigs, we can stay kind of flat on cash flow neutrality.

We talked about -- it's interesting, but we'd like to grow our cash flow over time, and take back debt, and do all those interesting things. And so, you know, our desire would be to grow our Permian basin as we take cash out of the Williston. And so there's a desire to keep it, but we're going to be very, very rigorous of staying within guidance, achieving the cash flow neutrality and making sure we don't go ahead of ourselves on that. So we'll watch right now, I'd say.

If the forward curve doesn't change a lot, I would think we'd probably drop the rig. If we see over the next few months either the base price goes much higher or we see change in the backwardation, I think we might, might consider a change in that strategy.

Gabe Daoud -- Cowen and Company -- Analyst

All right. Great. Thanks so much guys.

Tim Cutt -- President and Chief Executive Officer

Thanks, Gabe.

Operator

Our next question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Good morning, [Inaudible]. Nice details in there. Tim, my, my question is, you mentioned here about the cost savings along with the efficiencies that enable the 10 to 12 wells. I'm wondering if you can maybe shed a little more light on that? I mean, as far as is it some of the service costs you're seeing are going down and then just the efficiencies? I'm trying to, you know,is it more on the completion side, just any details you could give on that, Tim, it would be appreciated.

Tim Cutt -- President and Chief Executive Officer

Yeah. So I think we gave a slide in the deck that really does talk about kind of the completion efficiencies we're seeing and some of the -- some of the drilling efficiencies. You know, if we drill 10 wells and hopefully we can drill a few more, our drilling completion cost, say, is a round number of $6 million a well, so it would be about $60 million we need. If you break that down into the components where the money comes from, it's basically non-consenting the Williston wells at about $20 million.

The wells we non-consented were in kind of a remote acreage area. We'll now evaluate that acreage to see it. Now that we're non-consenting, it is better to sell the acreage, but it is a pretty small piece of our portfolio. Timing in the Permian facility spend is important.

So in the first quarter, we spent a lot of time saying we would like a manufacturing process where we have just-in-time facility availability. And we're, we're building ahead of ourselves quite a bit to assure that every barrel had availability on time, that cost us money and the timing has been adjusted. So that will save us about $10 million to $15 million, and we continue to try and optimize that. And then finally it's on the drilling completion cost.

It was about $25 million or $500,000-plus per well. I think that number will go up throughout the year. And that comes down to all the basics, about optimization, full utilization of in-basin sand, increase with recycled water. We recycle water for $0.15 of BOE versus buying it for $1.

And then pump [Inaudible] and perforation optimization. So a whole lot going on there. So not only are we working on the G&A costs, we're focused on the entire cost structure, bringing that down as massive amounts of MTV over time, and we'll continue to do that.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Great, great details. And then just one follow-up. Since they've obviously to your strategic alternatives in you comment there, but you know, your point about going non-consent or is what should -- you know, maybe the dealings in the Bakken, is that part of the strategic alternatives? Or you know, as you said, if you decide to sell a piece of that or whatever is that that outside of that, I guess, I'm just wondering?

Tim Cutt -- President and Chief Executive Officer

Yeah, I mean, it's just smart business. I mean, we look at every capital investment. These were subpar compared of our inventory. The operator felt like in their inventory was good to afford, and we have to make these tough decisions.

We also then need to say, we don't want to destroy value by potentially staying in too long. So we'll look at that kind of acreage. But once you understand what that acreage is, it's outside of the core, it's outside of anything we're focused on, and we want to make sure we have that cash available to reinvest in you know, what we think are 30% to 45% returns as projects.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Thanks so much for the details, Tim.

Tim Cutt -- President and Chief Executive Officer

All right. Thank you.

Operator

Our next question comes from the line of Derrick Whitfield with Stifel. Please proceed with your question.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Good morning all and congrats on a strong operational update.

Tim Cutt -- President and Chief Executive Officer

Thank you.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Perhaps for Tim, going back to Page 8, thanks for sharing those plots and the details on your current spacing approach. Would it be fair to assume that you're utilizing those density patterns for both state line and mustang springs areas?

Tim Cutt -- President and Chief Executive Officer

That's a good question. So most of our activity recently has been in mustang springs. When we finish out our DSU 12, which is on the eastern edge of mustang springs, we're going to move the rig across. And our primary activity in the second half of the year will be associated with county line.

Configurations are a little bit different there. I would say the overall concept of down spacing will we brought into that, but we'll be able to talk to you probably next quarter about the optimum spacing for that. It's a little bit complex because the zones are at a little bit different configuration, slightly different, but the overall thought process and concept of sticking with the [Inaudible], avoiding interference early and kind of maximizing returns of this project is how we're taking into the kind of line. But we've done pretty drilling over there.

We feel good about it. We think a lot of it is repeatable success in county line as well.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Thanks, and then shifting over to the Bakken. Could you offer some color on estimated remaining inventory for both South Antelope and FBIR?

Tim Cutt -- President and Chief Executive Officer

Yeah. I'll talk about the -- starting little bit at a higher level. So when we think about -- we've had a lot of questions about what's going on with Bakken decline. You know, if you look at our year, we have -- we're drilling in the Vegas pad.

We'll drill seven wells, bring them on the fourth quarter. So we're going to end the fourth quarter -- the fourth quarter will bounce up pretty equivalently with the first quarter. So we'll have a dip in the middle, and we're looking at what's the best inventory we have. We're looking at all the follow up on our, on our inventory of refracks and the results have been quite positive.

And so although we're not doing a lot in the near term because we're drilling obligation wells, we're actually quite excited for the long term on that. So I think we'll have a substantial amount of inventory in our refrack program and hope to get going on that probably in 2020 depending on what price does. As far as the drilling inventory, I don't have the exact numbers on the top of my head. It's certainly more limited than we see in the Permian basin.

We all understand that, but it does grow substantially the price. And then we do have quite a few wells, and I don't really want to put a number out there even, but it's greater than 100 wells in the core of our assets where we feel really good about going forward. So not the same kind of growth profile that we see in the Permian, but certainly with refrack program and a mix of a drilling program, I think we've got a good opportunity to certainly halt the decline and show some modest growth over time.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

That's very helpful. Thanks for your time.

Tim Cutt -- President and Chief Executive Officer

Richard's going to -- Richard's going to jump in on --

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Derrick, we -- Derrick, it's Richard. We kind of amortize 300 to 400 wells spread across the South Antelope and Fort Berthold with more wells on the Fort Berthold side than in South Antelope side just because of where our drilling activity has been. So that's kind of the number that we've been talking about historically. And then on the refrack number, we think we can refrack virtually every well that doesn't have some sort of mechanical condition across both areas.

So it's a pretty substantial inventory. We just haven't spent, lots of time there because we're focused on the Permian basin.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Understood. Thanks, Richard.

Operator

[Operator instructions] Thank you. Our next question comes from the line of Kevin MacCurdy with Heikkinen. Please proceed with your question.

Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst

Hey guys. I wonder if maybe you could comment on the liquids realization outlook for the remainder of the year? How you see -- particularly, how you see Bakken realizations trending and maybe NGL realizations in the Permian? How should those trend? It has looked a little lower than expected this quarter.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Hey Kevin, this is Richard. These things -- these black boxes at the end of our gathering facility is called gas processing plants that we don't control, and it's a challenge to predict it because sometimes those guys are ethane recovery when you wouldn't think they would be in ethane rejection. So our forecast is trying to look at the last 15 to 18 months of history and predict what those gas plant operators are going to do. Sometimes they're putting ethane back into the gas stream because there's a ethane pipeline constrained with regard to getting to Mt.

Belvieu or other places. So the NGL number is probably the weakest part of our guidance because we're not controlling those plants and the vast majority of those decisions are outside of our control. So if the NGL guidance looks funny to you, it's because we're just trying to be consistent with how we've done in the past and, and, and asking you to acknowledge that we don't really have a lot of control between the recovery and the rejection elections that those guys are making because of either commodity price or pipeline constraints. So we'll ask your indulgence on that one.

Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst

Thanks and any color on the Bakken realizations?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

The NGL realizations or --

Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst

No. The oil realizations?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Just the volatility of what's been going on in the Bakken with the refinery turnarounds that went on in the first quarter, we are selling some of our crude at Brent index, and made a differential off of that. So there are couple of different things that are going on in the Bakken versus what's going on in the Permian.

Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst

Thanks for the color, Richard.

Operator

Our next question comes from the line of Tim Rezvan with Oppenheimer. Please proceed with your question.

Tim Rezvan -- Oppenheimer and Company -- Analyst

Good morning folks. Thanks for taking my question. I was curious on the capex issue, the non-consents drove one key capex well below the guidance you had given a quarter ago, so there seems like kind of onetime spending off the books. Curious why the annual capex guide is unchanged? Is that based on consideration of number of rigs in the Permian or just curious why you wouldn't take the annual capex down?

Tim Cutt -- President and Chief Executive Officer

Yeah. Like we said previously, the good news is, we are able to redeploy that capex into the Permian and finish out the drilling of DSU 12, which is on the eastern side of the field. That will deliver -- it will hold up this year, but delivers about 1.5 million barrels equivalent. Again, we want to move past cash flow neutrality into positive cash flow as quickly as we can.

We thought that was a good business decision to do. So the first quarter was a mix of the non-consents, but also timing of wells that we were actually consenting in our non-operated business. So the overall Williston spend was low, some of that will come back in, but we've got -- in Richard's forecast, we've built that all back in. So if we did save money, we're going to try and redeploy it in the high-returning wells, and push that Permian volume up while staying within cash flow neutrality.

Tim Rezvan -- Oppenheimer and Company -- Analyst

OK. Thanks, and then thinking about the rest of the year, should we think about fairly steady capex cadence going forward?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Yeah. Tim, if you look at the first quarter, and then what our guidance for the quarter is, the guidance is about $195 million, and we talked about dropping that that third rig in the Permian basin. I think, if anything, the second and third quarter look pretty much the same, and then the fall off in activity with regard to that that third rig coming out of the equation drives fourth quarter -- you can do the math and see what that results in, in terms of reduced capital spend in the fourth quarter, but second and third quarters should be relatively consistent.

Tim Rezvan -- Oppenheimer and Company -- Analyst

OK. Thank you for the context.

Operator

Thank you. It appears we have no further questions at this time. Mr. Cutt, I would now like to turn the floor back over to you for closing comments.

Tim Cutt -- President and Chief Executive Officer

Thank you very much. Well, thanks, again, for everybody for joining the call and asking your questions and also calling in with your questions. Hope you're seeing that we're focused on cost and predictability. For some people, that's not as exciting as some other things that might happen, but that's what we have.

We got a great inventory. It's all caught up in the best part of the Midland basin, all around Martin county and we want to turn this into a manufacturing process, and we've all heard that a lot, we've heard for many years, and I helped deploy some of that back in the '90s on a heavy oil project. And I think it's just something we need to do. There is no reason we can't be the best in every category, and our workforce is all -- is focused on that.

And we're trying our very best to show off the best in every category and prove that we have good investment opportunities. So thanks, again, for joining.

Operator

[Operator signoff]

Duration: 30 minutes

Call Participants:

William Kent -- Director of Investor Relations

Tim Cutt -- President and Chief Executive Officer

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Gabe Daoud -- Cowen and Company -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst

Tim Rezvan -- Oppenheimer and Company -- Analyst

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