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Eclipse Resources Corp (ECR) Q4 2018 Earnings Conference Call Transcript

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Eclipse Resources Corp  (NYSE: ECR)
Q4 2018 Earnings Conference Call
March 13, 2019, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Ladies and gentlemen, good day and welcome to Montage Resources Fourth Quarter and Full Year 2018 Earnings Conference Call.

I would now like to turn the conference over to your host, Douglas Kris, Head of Investor Relations. Thank you. You may begin.

Douglas Kris -- Head of Investor Relations

Good morning and thank you for joining us for Montage Resources fourth quarter and full year 2018 earnings conference call. With me today are John Reinhart, President and Chief Executive Officer; Oleg Tolmachev, Executive Vice President and Chief Operating Officer; Michael Hodges, Executive Vice President and Chief Financial Officer; and Mathew Rucker, Executive Vice President, Planning and Development.

If you have not received a copy of last night's press release regarding our fourth quarter and full year 2018 financial and operating results, you can find a copy of it on our newly launched website at www.montageresources.com.

Today, we will spend a few minutes discussing the close of the merger between Eclipse Resources Corporation and Blue Ridge Mountain Resources that formed Montage Resources, followed by a review of the operational and financial highlights for the fourth quarter of Eclipse Resources Corporation on a stand-alone basis and then conclude with comments regarding the future of Montage Resources.

Before we start our comments, I would like to point out our disclosures regarding cautionary statements in our press release and remind you that during this call, Montage management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Montage Resources and are subject to a number of risks and uncertainties, many of which are beyond Montage Resources' control. Actual outcomes and results may materially differ from what is expressed, implied or forecast in such statements. Information regarding these risk factors can also be found in the Company's filings with the SEC.

In addition, during this call, we do make reference to certain non-GAAP financial measures. Reconciliation to applicable GAAP measures can be found in our earnings release. We will file our 10-K later this week, which will be accessible through our website or the SEC's EDGAR system.

I will now turn the call over to John Reinhart, our President and CEO.

John Reinhart -- President and Chief Executive Officer

Thank you, Doug and thank you to everyone for participating on our call today. Before discussing the quarterly and full year 2018 stand-alone Eclipse results, I will provide a brief recap of the merger close and then I will end prepared remarks with a path forward for Montage Resources.

First, I would like to thank the teams from both Eclipse and Blue Ridge for their professional and diligent efforts in consummating the strategic transaction while remaining focused on operational execution. Through outstanding cooperation during the transition -- during the close process, Montage Resources was able to align corporate and development execution to realize accelerated merger integration benefits that facilitates delivery of the Company's 2019 plan.

As you can see from the results released after the market closed last night, Eclipse ended 2018 with strong operational execution. These results were driven by continuously improving efficiencies as well as strong commodity pricing that provided free cash flow generation during the quarter.

With a new management team assuming control of the pro forma company, a strategy shift has been initiated that is aimed at enhancing the focus on corporate, operational and financial efficiencies. The Company has set in motion a Focus Five plan, which consists of the following core principles: cash flow and returns; cost structure improvement and integration; financial and operational flexibility; portfolio optimization; and enhancing scale with disciplined growth. At our upcoming Analyst Day, we will drill down in granularity on each of these five focus areas and illustrate how these will differentiate the Company among its peers and unlocking corporate value throughout 2019 and beyond.

The development plan being executed this year is aimed toward maximizing cash flow and arresting outspend, creating and maintaining an attractive balance sheet, optimizing operational and strategic flexibility, all while unlocking the asset value of Montage Resources' high quality inventory to enhance shareholder value.

In conjunction with the closing, the Company finalized its new credit facility that facilitated a borrowing base of $375 million, which is an increase of $150 million and when coupled with the cash flow from operations, will provide ample liquidity to internally fund our planned operations in 2019 and beyond.

The Company also provided to the market a summary of the 2019 capital plan as well as guidance for both first quarter and full year 2019. Each of the guidance metrics were calibrated for January and February Eclipse Resources' stand-alone expected results and March through December of pro forma expected results when considering the close timing of the transaction between Blue Ridge and Eclipse. These high level numbers provide for a full year Montage Resources' capital spend range of $375 million to $400 million to fund a two rig development program prioritized on returns and focused on the Company's core Marcellus and Utica acreage, predominantly located in Monroe County, Ohio. Approximately 90% of the capital spend is allocated toward growth-oriented drilling and completion operations and is expected to achieve full 12-month pro forma year-over-year production growth of approximately 16% while continuing to keep the Company's leverage at the targeted level of approximately two times.

2019 production growth is back half weighted driven primarily by second half 2019 turn to sales as well as developing higher working interest wells when considering the balance of the Sequel joint venture program is expected to be completed during the first half of 2019.

The merger has brought together two talented teams with a demonstrated ability of Appalachia-focused operational execution and when combined with the strong performance of the underlying assets and attractive balance sheet, provides the foundation for value creation in the months and years ahead.

Switching back to Eclipse stand-alone company results, for the fourth quarter, I am pleased to announce that the Company has exceeded internal and consensus expectations. The Company remained highly focused on execution during the merger process, delivering results within the full year 2018 capital budget.

During the fourth quarter of 2018, our average daily production was approximately 405 million cubic feet equivalent per day while full year production was approximately 343 million cubic feet equivalent per day. More importantly, the total pre-hedge revenue was a Company record $171 million for the quarter and $515 million for the full year, a 64% and 34% increase over 2017 respectively.

These records reflect the strategic decision to focus activity toward the high quality liquids portion of the Company's portfolio of assets, which accounted for approximately 45% of our overall revenue mix for the full year 2018.

During the quarter -- during the fourth quarter of 2018, the Company drilled nine gross, 5.7 net Utica wells, which included six dry gas and three condensate wells. Additionally, in the fourth quarter, the Company completed six gross, 3.1 net dry gas Utica wells and turned to sales three gross, 0.8 net dry gas Utica wells. The Sequel joint venture activity in the fourth quarter included partner participation in two drilled dry gas wells, five completed dry gas wells and all three Utica dry gas wells that were turned to sales. The final joint venture wells are planned for turned to sales mid-year 2019.

Regarding capital spending, we continue to see reduced service pricing in the area and are expecting to achieve approximately 10% well cost reductions throughout 2019 when compared to 2018. These cost reductions are a combination of optimized well designs, operational efficiency gains as well as service cost reductions.

Moving to the Flat Castle project in Pennsylvania, the Company continues to monitor the Painter 2H well and I am pleased with the strong production results that have been achieved to date, which truly highlight the potential for this area. The well's production has continued at target rates, which is aligning with the high end of our publicly stated EUR range of 2.2 Bcf per 1,000 feet of lateral. We will continue to watch this well's performance closely in order to refine the long-term potential for this area.

As previously stated, the Company will be assessing strategic options for the Flat Castle prospect, which targets acceleration of value for this high quality acreage in the Company's portfolio. We look forward to sharing more information about the recent well results in the Flat Castle area at our upcoming Analyst Meeting.

Overall, I remain thoroughly impressed with the team's performance and their push to enhance value throughout our asset base. The Company has shown the ability to outperform during this transition period and anticipate that this will continue as the combined company moves forward.

With that, I'll turn the call over to Michael.

Michael Hodges -- Executive Vice President and Chief Financial Officer

Thanks, John. During the fourth quarter, the Company continued to achieve strong results in almost every area of the business. Adjusted revenue, which includes settled hedges and excludes brokered revenue, was over $138 million for the fourth quarter and adjusted EBITDAX was almost $81 million during the same time period, both of which were records for the Company.

The increase in adjusted revenue for the quarter of 14% over the third quarter of 2018 was largely due to an increase in production of 17% as compared to the third quarter of 2018. During the fourth quarter, our all-in realized price was $4.25 per million cubic feet equivalent before the impact of cash settled derivatives and firm transportation.

Our natural gas price differential before transportation expense was negative $0.05 (ph) per million cubic foot compared to the average monthly Henry Hub settle price during the quarter. This strong differential was driven by the continued improvement of in-basin pricing dynamics as well as our ability to sell gas into underutilized firm transportation agreements contracted by others at prices which were at a premium to in-basin benchmarks. This strategic advantage, which we believe is a differentiator of Montage compared to its peers going forward, is something we will look to further leverage in the future, as we consider all the options available to us to achieve the highest possible gas realizations.

As the Company has brought wells online and marketed production has grown, we have quickly grown beyond the firm transportation we have under contract and we are selling incremental production in-basin at very tight differentials, resulting in outstanding netbacks.

Moving to operating costs, we achieved a decrease in fourth quarter per unit operating expenses versus third quarter numbers due to our growing scale while at the same time experiencing the benefit of better pricing at the Gulf Coast and at the Dawn Hub, where our Rover production is flowing.

The per unit cash production costs for the fourth quarter were $1.34 per million cubic foot equivalent, which included $0.40 per million cubic feet equivalent in firm transportation expense while cash production costs averaged $1.41 for the full year of 2019 (ph). On the liquid side, we realized a $22.40 per barrel NGL price equating to 37% of WTI while the full year 2018 equated to $24.59 or 38% of WTI.

Moving forward, and as we outlined in our recent guidance release, we have begun utilizing our Mariner East II capacity during the first quarter of 2019. This capacity, coupled with the sales volumes from Blue Ridge that are sold at strong netbacks to Mont Belvieu prices and without ethane recovery, should allow us to realize NGL pricing in the range of 40% to 50% of WTI for 2019 as opposed to the 38% realized in 2018.

While the incremental impact to our bottom line cash flows from the volumes delivered on Mariner East II and from the Blue Ridge barrels is positive, the transportation cost on Mariner East II does come with an incremental $0.08 to $0.10 of added per unit production cost for the full year 2019 as was noted in our 2019 guidance release issued previously.

Our realized oil price during the fourth quarter of $53.10 per barrel implies a negative $6.87 differential to WTI, which is inclusive of all transportation expenses. For the fourth quarter, our $45.8 million of capital expenditures consisted predominantly of $41.3 million in drilling and completion capital and $4.2 million in land and related capital. These figures also include capital reimbursements that relate to our drilling joint venture with Sequel.

Finally, and most importantly, I would like to turn my comments to the balance sheet where our outstanding operating performance generated substantial EBITDAX that allowed us to end 2018 with a debt to trailing 12-month of EBITDAX ratio of 2.1 times and with almost $172 million of liquidity, all before considering the borrowing base increase to $375 million that John mentioned in his opening remarks.

When taking into consideration the borrowing base increase, a reduction in our letters of credit previously noted in the guidance press release last week and borrowing subsequent to year-end, our initial borrowing capacity for Montage Resources at close was $264 million, more than sufficient to fund our development plan for the foreseeable future.

As we consider our current liquidity position and our capital plans, we're comfortable that Montage remains well-positioned to fund its drilling program with cash flow from operations and our revolver while generating an attractive level of production and cash flow growth. This revolver will provide the base funding for the Company's combined growth in 2019 as we target becoming cash flow neutral by the end of the year.

From a leverage perspective, our financial condition is further enhanced by the consummation of the merger with Blue Ridge as we have added significant cash flows to the business while assuming no net debt at close. In fact, pro forma for the payoff of the Blue Ridge term loan at closing, Montage added approximately $13 million (ph) of cash.

As John mentioned, we project to end 2019 with a leverage ratio of approximately two times and we will be positioned with many financial options as we look to 2020 and beyond.

On that note, I will turn the call back over to John, who will wrap up the prepared remarks.

John Reinhart -- President and Chief Executive Officer

Thank you, Michael. I would like to briefly conclude the prepared remarks this morning with a recap of the Company's strategic shift in focus areas moving forward. We have refined the 2019 business plan to significantly reduce cycle times, enhance cash turns and cash flows, and maximize return on capital all while continuing to grow production in order to achieve enhanced scale.

This scale brings with it attractive operating margins and an improved cost structure, which is based upon a foundation of low risk, repeatable drilling program. For 2019, that two rig program will be internally funded from cash flows and the revolver with over 90% of the CapEx being focused on the drill bit to provide maximum capital efficiency.

The experience, innovation and achievements of the combined operating teams will allow us to deploy this plan effectively. With a portfolio of assets that gives the Company equal exposure to oil and gas as well as balanced midstream and downstream commitments, that will provide price diversification through in-basin and out of basin commodity sales, we have maintained the optionality in our planned well mix to maximize revenues and make true economic development decisions that are not driven by the need to fill transportation commitments or the need for HBP drilling. We believe that this optimized plan delivers repeatable, high rate of return wells, which will create long-term values for shareholders.

We thank everyone for joining us today. This concludes our prepared remarks. Operator, please open the line for questions.

Questions and Answers:

Operator

Thank you. Ladies and gentlemen, we will now be conducting our Q&A session. (Operator Instructions) Our first question comes in the line of Arun Jayaram from JPMorgan. You are now live.

Arun Jayaram -- JP Morgan -- Analyst

Good morning, gentlemen. I was wondering if you could give us a bit more of a flavor on your 2019 program, two rigs, maybe some details on the split between the Utica and Marcellus and perhaps I know in 2018, you completed just under 18 net wells for $224 million of D&C, which is around $12.7 million a well. In '19, I think you've guided to just around $400 million in CapEx. I was wondering if you can give us some details on the D&C portion of that total plus how many net wells you expect in '19.

John Reinhart -- President and Chief Executive Officer

Yes, sure. This is John. I'll start with highlighting with regards to the capital allocation program. We're looking at allocating approximately 25% to the outstanding acreage in Ohio for the Marcellus development. What we've seen with these first two initial wells were really great results from the prior Eclipse releases and there is currently infrastructure that we're going to take advantage of with regards to midstream buildouts and pads that exist. So this really creates a very attractive returns focus for us and certainly the liquids portion helps enhance the value of this.

So outside of that, if you look more granularly, there is another 25% of the CapEx budget that's geared toward the Utica condensate window and then lastly, about half of the CapEx on the D&C side is really geared toward our core acreage in Southern Monroe in the dry gas area. So that gives you an overall kind of split between where the capital is being allocated between the Utica and the Marcellus for 2019.

With regards to the service cost and well cost moving forward, what I can tell you is you can -- we'll share more of this in the Analyst Day, but we've seen outstanding results with regards to service cost improvements over the last quarter and certainly as recently as last week with some increased pricing coming in, we feel extremely positive about 2019 drilling CapEx reductions of approximately 10% per well whenever you compare 2019 type curve expectations to 2018.

Now, whenever you stop and take a look at that, you can think about a Utica Dry Gas well being on the order of magnitude from a gross perspective of about $950 per foot of lateral to $975 per foot of lateral and you can think about that Marcellus in that range of about $750 per foot of lateral to $775 per foot of lateral. So service cost continued to go down, but it's not only just the cost, just as a reminder, it's very specifically well designs that are being optimized for more full development in an engineered approach and it's also efficiencies that we're realizing with regards to taking these longer laterals which were truly a technological innovation that the Company had before, but now, we're actually taking these down to more industry averages of 12,000 feet, which is actually at the top-end of the average range and what you're finding is the efficiencies that we're gaining with regards to the operational improvements with things like using one VHA (ph) run in the lateral and just various other efficiencies you gain by just taking the laterals down, we're seeing substantial reductions based on those factors as well. So overall, a 10% plus reduction in our well cost for 2019 that's going to lead to further efficiencies with regards to the spend.

Arun Jayaram -- JP Morgan -- Analyst

Okay and just do you have a count for the net wells for the 2019 program for our modeling?

Matt Rucker -- Executive Vice President, Resource Planning & Development

Yes. This is Matt. We'll be spudding approximately 30 to 32 net wells for the year.

Arun Jayaram -- JP Morgan -- Analyst

Okay and just my follow-up question here, as you think about the cash production cost, you had a good quarter $1.34, which is quite a bit below us (ph) for the quarter. Next -- or this year you've guided call it to $1.60 at the midpoint, but it seems like some of the increases the ME2 (ph) cost, I was just wondering if you can just walk us through the $1.34 you did in 4Q relative to the $1.55 to $1.65 guide for cash production cost?

Michael Hodges -- Executive Vice President and Chief Financial Officer

Yeah, Arun, this is Michael. I'll take that question. It's a good question. So I think if you look at the $1.34 and then you try and bridge that up to the guidance that we've given, there's a few different factors. You mentioned the ME2 cost, so as we move out into 2019, we're going to pick up call it $0.08 to $0.10, as I mentioned in my remarks related to the ME2. I think there's also some workover cost in our numbers as we go out into 2019 that bump us up just a little bit.

And then lastly, the main factor there is that we've got some firm transportation that was only in a partial year last year and then with respect to the fourth quarter, we had certainly a flush amount of production for that firm transportation. So, when you combine all those things together, you get that uptick call it from the $1.34 up into the midpoint. I think we're optimistic that we have a chance to be at the lower-end of that range, but we certainly want it to be kind of prudent in the way that we guided the market with this new ME2 space that we're taking on and some of the other things that we've got going. So, I think we're hopeful to be at the lower-end of that, but certainly feel like the right thing to do is to give it a little bit of a broader range to start out.

Arun Jayaram -- JP Morgan -- Analyst

Okay, thanks a lot.

Michael Hodges -- Executive Vice President and Chief Financial Officer

Thank you.

Operator

Thank you. Our next question comes from the line of Ron Mills from Johnson Rice and Company. You are now live.

Ron Mills -- Johnson Rice and Company -- Analyst

Good morning, guys. John, I think -- you started to reference this at least part of this question to Arun's question, but when you came out with the budget, you talked about the move to shorter laterals of just under 12,000 feet and also to smaller pads. So wondering if you could expand a little bit further on what you started to say on the earlier answer about the -- basis behind that and in terms of what -- how much improvement in capital efficiency and cycle times are you expecting that to provide? And is that's what's really helping drive the free cash flow by year-end.

John Reinhart -- President and Chief Executive Officer

Yes, sure Ron. Happy to answer that, it's a great question. I think this really points back to one of our Focus Five points on cash flows and returns. As we look at the development first of all from 2018 to 2019, what you're realizing is a program is approximately 42 plus or minus days reduction in total cycle times and what I mean about cycle times is from the moment you actually start your CapEx spend to the moment you get revenue in the door from these wells and 42 days is a substantial reduction.

Now, what drives that quite frankly is the lateral length and the cycle times associated with it. That goes along as well with the drilling component and the completion component with these longer laterals. So our intent is to take the cycle time, crunch it down to get increased cash turns, which allows us to accelerate the cash indoor and allows us to actually achieve free cash flow moving forward toward the end of '19 as we've publicly communicated.

These lateral lengths as you think about it, this is all geared around focusing the core of the 2019 development in a low-risk area with repeatable results because it's very important for us as we come out right out of the gate with a merger to deliver results. So, focusing in on this core delineated area with a development plan that actually shrinks cycle times by 40 days to 45 days, it also allows us from our initial well per pad, if you think about another key factor that rolls into that efficiency gain, whenever we talk about four to five or three to four wells per pad initially, we're not saying that the full pad is limited to that.

What we're doing is and we'll talk about this more in the Analyst Day is we're going to be actually completing and drilling the northern or the southern respectively rows of these Uticas out on the pads. So we'll drill them out. Now the impact to that actually is you can refine and not drill five to six initial wells initially. You can drill four wells so for a pad that would hold a total of eight and I think whenever you look at the cycle time improvements from drilling six to three or four, that dramatically decreases the time drilling and completing these wells as well as the production facilities.

So all that said, it's a function of actually taking lateral length, increasing cash turns, reducing the actual cycle times, getting revenue in the door and improving cash terms, all of which actually helps the discounted return on capital that we're employing and helps actually facilitate free cash flow generation.

Arun Jayaram -- JP Morgan -- Analyst

Thank you for that. And then my follow up or second question, you talked about the Flat Castle performance continues to kind of point toward the higher end from an EUR per thousand foot standpoint, but also trying to reconcile that with the comment in your capital outlook about assessing multiple options related to Flat Castle in terms of how to enhance value there? It didn't sound like you really have any plans to drill there in '19. So curious for more color in terms of what you meant by assessing multiple options for value creation there?

John Reinhart -- President and Chief Executive Officer

No, absolutely, happy to comment on it. I'll start out by saying that we are extremely pleased with the well results from this Painter 2H well as well as some offsetting wells from the industry up there, which is significantly delineated the area. So publicly, the Company has previously stated a range of approximately 2 to 2.2 Bcf per thousand feet. Where the well is trending is certainly toward the higher end of that. We're going to continue to monitor the well over the next two or three months, whenever it reaches boundary flow and we can put a particular EUR on it to be able to refine that, but it's certainly very positive, it's attractive and it actually is starting to compete for the capital allocation when compared to our Ohio Marcellus and our Ohio Utica dry gas wells.

Now having said that, it's a great problem to have, to have an overabundance of high quality acreage that has high EUR per foot and high returns. So as we step back and look at it with our -- but be very mindful on cash flow generation and not stressing the balance sheet. We're also very sensitive to the fact that we're carrying an asset on the books. It's really not we're realizing any value from the market's perspective in the stock price. So options to actually accelerate value is what's being considered. Now, these strategic options could be anywhere across the board that could actually accelerate and bring and monetize this asset, but I'll give you an example of a particular one that's of interest to us.

We are assessing and tossing around the idea of bringing on a working interest partner in the area and this working interest partner, if you think about the benefits of one doing that, you would basically sell down a portion of your working interest, but those funds could go directly to funding the D&C from a Montage aspect moving forward, thereby without putting any new capital outlay, you would actually start developing, producing reserve value and increase carry value of that asset.

Now, that's just one example of an option that we're going to be looking at and assessing. Obviously, we're going to consider all options that are presented to us and that we explore, but that's just a really good example Ron of how we're thinking about accelerating value with maintaining balance sheet strength, maintaining capital discipline, but still yet focusing on our portfolio to enhance the value of our carried assets.

Ron Mills -- Johnson Rice and Company -- Analyst

Great and thank you and congratulations on getting the deal done.

John Reinhart -- President and Chief Executive Officer

Thank you, Ron.

Operator

Thank you. (Operator Instructions) Our next question comes from the line of Stark Remeny from RBC Capital Markets. You are now live.

Stark Remeny -- RBC Capital Markets -- Analyst

Hey guys, congrats on the solid quarter. I guess my question on Flat Castle, kind of got answered, but I'm curious if you guys can maybe talk around what the opportunity set or how you view the strategic portfolio optimization in terms of maybe either non-core or lower tier assets outside of Flat Castle. So is there anything that was acquired from Blue Ridge that or maybe some legacy Eclipse acreage that you view as maybe Tier 3 outside of the Monroe County focus area for this year?

John Reinhart -- President and Chief Executive Officer

It's a great -- this is John. It's a great question Stark. What I would comment on is just kind of give you a little bit of history of the management team here is we have a proven track record and we can certainly talk about this more on the Analyst Day. Over the last year and half, this management team has transacted won (ph) over '18 individual transactions and actually accelerated cash in the door to the tune of about $175 million and these are all related to more non-core assets and partnerships that we've achieved over the last two years to bring Blue Ridge to the point where it was as an attractive partner for the Eclipse combination.

I would say that when we step back and look at it, the Company has about 22 years of inventory as we look at a two rig program moving forward and whenever we step back and assess, I would say that any opportunity that the Company has with regards to accelerating or enhancing value of that inventory to the Company, we're going to be very open and mindful of assessing. So, this is something that we are all very keen and we stay very focused on historically and we'll continue to do that with regards to how we manage Montage.

So the answer is yes, there will be opportunities where acreage or a particular area won't warrant capital over the next three to five to seven to 10 years and it's certainly well within our purview and it's important for us to consider how we can take actions to accelerate value of that acreage for the Company.

Stark Remeny -- RBC Capital Markets -- Analyst

Okay. Excellent. Excellent and then just one kind of quick clarification on the well cost savings. You guys mentioned 10% per well. Can you maybe give some color on how that breaks down in terms of savings from lateral savings from service cost reductions et cetera?

John Reinhart -- President and Chief Executive Officer

Yes and I'm happy to hit that at a high level and we'll certainly hit at a lot more detail at the Analyst Day coming up and Oleg will speak to that in very deep -- in a lot of great detail then, but if you think about it overall, where we're really focused on, we're going to take advantage of price reductions, price softening anytime they come, but if you really at least how view it, if you really want long term cost reductions, that's where the efficiencies come into play and the well designs come into play. So, if I were to put a high level number on it, I would probably say somewhere in that 60%-ish to 65%-ish is going to be geared more toward efficiencies and engineered well designs with 35% at more near-term price reductions be price driven.

And I would say that we feel very confident in that 10% cost reduction moving forward. This is a great execution team and what we're really focused on is concentrating on efforts to reduce long-term capital requirements and well cost and not just be at the whim of any kind of market sensitivities with regards to pricing.

Stark Remeny -- RBC Capital Markets -- Analyst

Excellent. Thank you.

Operator

Thank you. Ladies and gentlemen, we have no further questions in queue at this time. I'd like to turn the floor back over to management for closing.

Douglas Kris -- Head of Investor Relations

We'd just like to thank everyone for joining our call today and look forward to seeing everyone next week on Wednesday, the 20th in Houston at our Analyst Day. Have a great day.

Operator

Thank you, ladies and gentlemen. This does conclude our teleconference for today. You may now disconnect your line at this time. Thank you for your participation and have a wonderful day.

Duration: 39 minutes

Call participants:

Douglas Kris -- Head of Investor Relations

John Reinhart -- President and Chief Executive Officer

Michael Hodges -- Executive Vice President and Chief Financial Officer

Arun Jayaram -- JP Morgan -- Analyst

Matt Rucker -- Executive Vice President, Resource Planning & Development

Ron Mills -- Johnson Rice and Company -- Analyst

Stark Remeny -- RBC Capital Markets -- Analyst

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