Goodrich Petroleum Corporation
Q1 2015 Earnings Call Transcript

Published: 6 May 2015

[Operator:]

Good morning, and welcome to the Goodrich Petroleum Corporation First Quarter 2015 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Daniel Jenkins, Director of Corporate Planning and Investor Relations. Please go ahead.

[Daniel Jenkins:]

Good morning, everyone, and welcome to our first quarter earnings conference call. With me here in Houston this morning, I have the entire Goodrich Petroleum senior management team. After a few opening comments, I will turn the call over to Mr. Gil Goodrich, our Vice Chairman and Chief Executive Officer. As is our practice, we would like to make everyone aware that comments and answers to questions made during this teleconference may be considered forward-looking statements, which involve risks and uncertainties as have been detailed in our SEC filings. We will begin with our prepared remarks and then conduct a question-and-answer session. Finally, I'd like to remind everyone that we posted an updated slide presentation that we will reference throughout this conference call. You can access those slides through our website at www.goodrichpetroleum.com through the Investor Relations tab in the Events and Presentations section. Below the first quarter conference call announcement, you can click on the More Information link, and the slide deck will appear. Now I will turn the call over to Mr. Gil Goodrich, our Vice Chairman and Chief Executive Officer.

[Walter G. Goodrich:]

Thanks, Daniel. Good morning, everyone. Despite commodity prices for oil and natural gas approximately 50% lower than the year-ago period, adjusted revenues for the first quarter were only 24% lower than the year-ago period, as we increased our oil production mix from approximately 32% to 56% of total production. In addition, reported EBITDAX was only 16% lower than the year-ago period on 50% lower commodity prices, both reflecting the benefits of our existing hedge position. The first quarter was a transitional period for us, as we decelerated drilling and completion activity in response to lower oil prices, reducing our TMS rig count from 3 rigs in January to 0 rigs today. In addition, we began delaying completions of previously drilled wells, with only 2 additional completions late in the first quarter, and have increased our backlog of drilled but uncompleted wells in the TMS to 6 as of the end of the quarter. During the quarter, we initiated significant cost-cutting measures across the company, leading to reduced cash G&A, lower lease operating expenses as well as reduced well costs going forward. Finally, as previously reported, we raised approximately $148 million during the quarter to strengthen the balance sheet and enhance liquidity. Coming off a high level of activity in the fourth quarter of last year, we decelerated capital spending in the first quarter to approximately $48 million. Going forward, we further reduced planned capital activity levels and are projecting second quarter capital expenditures between $10 million and $15 million. Production for the quarter averaged approximately 8,700 BOE per day, 56% being crude oil, as we intentionally delay completions which we plan to complete later this year as oil prices improve. Our aggressive cost-cutting efforts are starting to show up, as operating expenses were lower in almost every category, with an absolute reduction in the quarter of just over $16 million or 44% lower versus the year-ago period. Field level operating expenses, including LOE, production taxes, transportation and processing, were all lower on both an absolute and per BOE basis, with per unit BOE expenses down by approximately 30% compared to the year-ago period. Finally, we are seeing very impressive industry-wide results of late in the TMS, which Rob will review with you in just a minute as well as our updated activity and wells in the play. And with that, I'd like to turn it over to Jan Schott for a review of the financials.

[Jan L. Schott:]

Thank you, Gil. Good morning, everyone. I will cover a few items on the financial side. Adjusted revenue, which includes net cash received in settlement of derivative instruments for the first quarter, totaled $37.1 million, down from $49.1 million for the comparable period last year and down from $57.6 million for the fourth quarter of 2014. Our first quarter average realized prices were $45.86 per barrel for oil and $2.02 per Mcf for natural gas. Including the impact of net cash received to settle derivatives, the oil price was $75.95 per barrel for the quarter. For 2015, we have a total of 3,500 barrels of oil per day hedged at a blended price of $96.11. We will plan to continue to monitor the current commodity price environment and layer on additional oil derivatives. We will also continue to watch natural gas pricing for opportunities to hedge portions of our natural gas production. We are giving second quarter 2015 production guidance ranging from 4,250 to 4,650 barrels per day for oil and 22,500 to 26,500 Mcf per day for natural gas. We expect oil volumes to increase as we exit the second quarter, and as Gil mentioned, begin to complete 6 TMS wells waiting on completion. We are reaffirming our previous full year 2015 guidance of 4,800 to 5,200 barrels per day for oil and 23,000 to 26,000 Mcf per day for natural gas, with a total net capital expenditure budget of $90 million to $110 million. Before moving on to expenses, I want to point out that oil -- with oil representing 56% of production, as Gil mentioned, in the first quarter, we are now including unit measures on a BOE basis. LOE was $4.1 million or $5.30 per BOE compared to $6.54 last quarter and $7.98 for the prior year quarter. The decrease was the result of the sale of our noncore East Texas natural gas field in December 2014, generally lower workover activity in the first quarter of this year and the first phase of service cost reductions. We would anticipate that our LOE per BOE will run from $5.50 to $6 per BOE for the balance of 2015. Production and other taxes continue to trend lower as we add production from the TMS at a 0 severance tax rate. The sale of East Texas field also contributed to lower production and other taxes and lower transportation and processing expenses in the first quarter. We would expect 2015 rates to remain consistent with first quarter rates. DD&A was $20.2 million or $25.93 per BOE for the quarter compared to $38.56 per BOE last quarter and $27.09 per BOE for the prior year quarter. We will reset DD&A rates for the last half of 2015 upon receipt of our midyear reserve report. Exploration expense of $3.7 million for the quarter includes $0.7 million in early drilling rig release fees and $1.6 million lease amortization for expiring leases in our noncore TMS and Eagle Ford Shale Trend acreage. G&A costs came in at $7.8 million, $9.93 per BOE this quarter compared to $7 million last quarter and $8.9 million in the prior year quarter. We incurred $0.3 million in severance-related payments in the first quarter due to a 20% reduction in staff. About $1.9 million or $2.42 per BOE at the first quarter rate represents noncash, stock-based compensation. We would expect cash G&A for the balance of 2015 to trend about 20% lower than the first quarter cash G&A. We are projecting a 0 tax rate for 2015. We have included reconciliations on the last pages of our press release for all non-U.S. GAAP measures to the closest U.S. GAAP measure. Please refer to these reconciliations for more detail. We plan to file our first quarter 2015 10-Q with the SEC later today. Please see our 10-Q for a more detailed financial discussion. I will now turn it over to Rob Turnham for an update on the TMS.

[Robert C. Turnham:]

Thanks, Jan. As Daniel stated earlier, we have posted an earnings call slide deck on our website, and I will walk you through those slides now, concentrating primarily on our assets in the TMS in particular. We have an extensive inventory of both oil and natural gas resource potential, our natural gas reserves and acreage are in the core of the Haynesville Shale, which gives us an abundance of optionality and upside when natural gas prices ultimately find a bid. Our oil reserves are concentrated in 2 areas

[Walter G. Goodrich:]

Thanks, Rob. We are taking a very disciplined approach to our 2015 capital plans, with a focus on improving margins through cost reductions, preserving liquidity with dramatically reduced CapEx and positioning the company to resume activity and production growth as oil prices improve. We are confident these efforts will have us better positioned with a lower cost structure and enjoying reduced well costs in the latter part of this year and going into 2016. That concludes our prepared remarks. I will now turn it back over to the operator for questions.

[Operator:]

[Operator Instructions] First question comes from Neal Dingmann from SunTrust.

[Neal Dingmann:]

Just a quick question. I guess, Robert, Jan, when you look at the CapEx that you put out, does that assume, I guess, the June completions and then the one rig coming back? I guess, maybe talk about when that rig coming back and then working for the rest of the year.

[Robert C. Turnham:]

Yes, Neal, this is Rob. Yes, the June completions, clearly in there, we do drag a rig back in at the end of the second quarter, not a whole lot of that CapEx is baked into that. I would say we're not -- we don't plan to have one rig running full-time, but for most of the back half of the year, we would expect that to happen.

[Neal Dingmann:]

Okay. And then just looking -- I was looking at that, let me see, Slide 6, that shows all these upcoming completions. Rob, it looks like a good bit of that activity is on that -- mostly on that eastern side, the northeast to be exact. On the sort of plan going forward for the remainder of the year and such, will you stick in that area? Or just, I guess -- that's my first question, will you stick in that area? And then just your thoughts about the other part of your other acreage further west and a bit further north.

[Robert C. Turnham:]

Yes, about -- at least 70% of our activity in '15 is planned for Area 3. It's really likely going to alternate a little bit with Area 1, with one exception. We have the T. Lewis well in Area 2 that's 1 of the 6 wells that is scheduled for completion. So I think a concentration, certainly, in Area 3, Tangipahoa Parish in particular, with an occasional well drilled in Area 1 and the one completion in Area 2 is how it currently reads.

[Neal Dingmann:]

Okay. And then very lastly, Rob, for you or Gil, just when you think about -- it seems like these wells are holding up. Your thoughts on EURs as well as just sort of what you're seeing at today's commodity prices on returns of these wells, I guess, which would factor based on what you're assuming on the EUR.

[Walter G. Goodrich:]

Yes, so Neal, it's Gil. Clearly, as Rob outlined for you, the bias is towards increasing EURs. I think you said it exactly right. As we see these most recent wells start to flow through the normalized curves, that's going to lift the EUR projections. Hard to say a hard number on it today, but we would certainly say, if you take these most recent wells and play them out, they're certainly going to be north of 800,000-barrel EURs. So even going back now with that in mind, taking a look at the 700,000-barrel curve, as Rob outlined, generating very attractive rates of return for all the reasons he outlined, even at $65 to $75 a barrel. So we feel -- we still feel great about the play. We think it's going to be a tremendous play and are anxious to see oil continue to do what it's been doing of late. And you'll see us pick up our activity level in the second half of this year.

[Operator:]

The next question comes from Kim Pacanovsky of Imperial Capital.

[Kim M. Pacanovsky:]

A couple of questions. First of all, Rob and Gil, what IP rate are you actually modeling in for your guidance?

[Robert C. Turnham:]

Yes, we're -- we tend to risk our mid-case curve by about 15%. So I think the 30-day average is probably close to what, 875 to 900 in our budgeting or modeling. Obviously, what affected the first quarter volumes is just the fact that we really didn't add any significant volumes in the quarter. Our Foster Creek 81 and 82 came on at the tail end of June, and that was really -- I'm sorry, at March, and that was the vast majority of our completion activity. We talked about the Kent well. We still have plans to go back in and drill those frac plugs out. Going forward, as we mentioned in the press release, these dissolvable plugs basically eliminates not only about $0.5 million of costs, but the necessity to go in with coil tubing and drill the plugs out. So that's a material change operationally, both from a cost standpoint and just risk mitigation.

[Kim M. Pacanovsky:]

Okay. And actually, that leads to my next question. I recall a well, I don't know, it was 1 year or 1.5 years ago, where you used dissolvable plugs and you had an issue with those plugs. So maybe can you talk about the different -- are you using a different type of product, et cetera?

[Walter G. Goodrich:]

Yes, Kim, this is Gil. Entirely different type of plug. What we were using a year ago that we had problems with were permanent plugs that had a 2-inch ID, or interior diameter, and we were using dissolvable balls to create pressure [indiscernible]. So this is an entirely -- this, as Rob described, is a fully dissolvable plug, fairly new on the market. I think they first rolled them out in August, September of last year. The utilization of those plugs has ramped up dramatically in the last 6 months. We used them on the 81 and 82 with absolutely spectacular results. We let the well shut in for about 72 hours, plugs dissolved, and we started flowback. So in this case, the entire plug itself was dissolving, not just the ball.

[Kim M. Pacanovsky:]

Great, super. And then just one last quick question. I know you probably don't want to speak for Encana. But obviously, their last well result was excellent with the higher proppant per foot. Do you have any indication of what they're planning on doing?

[Walter G. Goodrich:]

Yes, not really, Kim. I think we will let them speak for themselves. I think they got a release coming up here in a day or 2. From our perspective, as we said, industry results have been the best we've seen in the entire play over the last 4 to 5 months. So we would be very surprised if they're not allocating some incremental capital to it, certainly, in the second half of this year. But we don't have any specific information about what they plan to do.

[Operator:]

The next question comes from John Mills (sic) [ Ron Mills ] of Johnson Rice.

[Ronald E. Mills:]

Just to follow on what Kim was just asking, the proppant concentration. I know your optimized wells, you had been using more in the 1,500, 1,800 pounds per foot, I think. Any data in terms of what Encana was using, and as you go forward, what your proppant concentration is? Are you going to stay around that 2 000, 2,500 pounds? Will you potentially test even higher?

[Robert C. Turnham:]

Yes, we're under confidentiality agreements, data exchange agreements with those guys. But I can tell you what our plan is, is to definitely go to the 2,000 to 2,400 pounds per foot. You do pump a little more fluid with it just in proportion to the increased amount of sand. But very important that you stay with the hybrid job, as we've been doing. It's just -- it's a pretty nice correlation or -- the R square is pretty high when you look at proppant per foot. Certainly, you can argue lateral length also has a pretty good correlation, at least on flattening curves. But we're-- it's pretty convincing, and that's why you -- that's why we baked that into our current well estimates. And you'll see us pumping bigger frac jobs.

[Ronald E. Mills:]

And associated with that, whether it's lateral lengths or number of stages, I think last quarter, you talked about widening out the frac stages. Where do you stand in that method? And is it -- is part of the widening of the frac stages also related to the increased sand concentration?

[Robert C. Turnham:]

Yes, to some degree. We're about 300 feet right now, which is higher than what we had been. But it's all about your perf clusters and the spacing of the clusters and then the proppant per foot. So regardless if it's 250-foot intervals or 380-foot intervals, the proppant per foot is basically the same. So we're going to go to 300. Currently, some of the other operators are widening those intervals, but again, increasing the sand amounts. So we feel pretty good that the 300 is a good fit for us.

[Ronald E. Mills:]

And then if you looked at Page 16, which is the cost breakdown, the dissolvable plugs, you talk about saving $500,000, is that inclusive of coil tubing savings, number one? And number two, does Slide 16 -- how did the increased proppant concentrations impact the costs on Slide 16? Or are those baked into those numbers?

[Robert C. Turnham:]

Yes, I think, to me, the better slide -- yes, it is Page 16, you're right. Yes, it does include the higher proppant concentration. I think we baked in 2,000 pounds per foot and 300-foot intervals. And therefore -- and it does include the new dissolvable plugs. So we baked that into the $10 million or $9.3 million estimates that we see on that page.

[Ronald E. Mills:]

Okay. And then last for me, just on the Tangipahoa Parish or Area 3, where most of your completions are coming up and most of your activity will be focused. Can you walk through any differences, if any, you're seeing in terms of ability to drill, rock qualities, something that maybe -- are there anything different about that -- is there anything different about that acreage?

[Walter G. Goodrich:]

Ron, this is Gil. Nothing really different in rock quality. The performance, as Rob said, our best well to-date on a per lateral foot is our Blades well. So clearly, we believe there's some incremental naturally occurring fractures in that area. We really like it. And yes, we have seen really, really good drilling performance in that area. I think all of those wells have come in, almost every single one of them, many of those wells of late have come in with the best drill times we've seen to-date. So it's just -- we've done some different things from a technical standpoint with our downhole assembly, which is certainly helping, but that area does drill quite well.

[Operator:]

The next question comes from Mike Scialla from Stifel.

[Michael S. Scialla:]

Most of my questions have been answered. But Rob, you alluded to, well, obviously, the relationship you're seeing between EUR and proppant per foot. But you also mentioned EUR per lateral foot, just going with longer laterals. But it looks like you've kind of settled in on maybe 5,000 to 6,000 feet. Is that because you think that's the optimum length? Or is there a risk in going longer? It looks like Encana is having good success going longer. I guess, wondering why you're not going to that length.

[Robert C. Turnham:]

Sure. That's a great question, and really, and the more history we get from their wells that are outperforming, the better. We think it will follow the shape of our curves. But it's all about costs versus commodity prices and rates of return. And the question we have is, obviously, as oils start to -- continues to move up, then we're going to trend back towards longer laterals with the higher proppant concentration. But as we sit here right now, without the benefit of longer history on these more recent wells, the 6,000 -- 5,000 to 6,000-foot laterals at $10 million to slightly more than that, are generating very good rates of return. But there is going to be a bias towards going longer because our experience in the Eagle Ford has been -- and certainly, you're seeing at the Haynesville, too, is the longer laterals ultimately make more sense. But it's all a factor of rates of return and commodity markets that we currently play in.

[Michael S. Scialla:]

To that end, have you -- but I realize you haven't drilled any of that length, but have you investigated what the cost, assuming everything else stays constant, say, comparing your 5,000-foot lateral, $10 million well cost projection, how that would compare if you were to go to a 9,000-foot lateral?

[Robert C. Turnham:]

Yes, so it kind of depends on rate of penetration in the lateral. If you can do it without tripping for new bits, and of course, the longer you get out in the lateral, the higher the likelihood that you will have to trip, which adds days. We're working through that right now because costs have come down so rapidly. So we might be -- it's fairly linear, I would say, $1.5 million to $2 million of additional costs perhaps to get there. But again, there is added risk. The longer you go as to -- we don't think getting out of the zone or making hole is just having to trip and stand still while you wait to get back on bottom.

[Michael S. Scialla:]

Okay, got you. And then it sounds like you had a lot of wells that are going to be coming on in the June, July timeframe. Can you kind of walk us through after that, what the second half of the year is going to look like, both in terms of drilling and completions?

[Robert C. Turnham:]

Yes, again, don't really have one rig scheduled for the entire second half, although for most of the second half, we will be drilling with that one rig. Obviously, cycle times are much faster now with the 24-day drill time. You're probably looking more like 45 days spud-to-spud instead of 60, where we had been. We've given some guidance on the number of wells that we're going to drill and complete. It's on our inventory chart. I believe it's 11 gross, 8 net wells. This is obviously 6 gross completions plus the 2 that we completed, the 81 the 82. So we'll be at 8 gross once we complete the 6 that are currently shut in. So another 3 gross, 2 net wells after that probably makes sense, based on our current budget. But as Gil said, look, if oil prices continue to rise, you could see us accelerate a bit over and above that.

[Operator:]

The next question comes from Steve Berman of Canaccord.

[Stephen F. Berman:]

Just a follow-up on Mike's question in terms of quarterly progression here with the rig coming back assuming at the end of this quarter and the 6 wells waiting on completion all online by the beginning of September. How do you see Q3 and Q4 production progressing to get to your guidance for the full year that hasn't changed from prior guidance, and taking 2Q guidance into account?

[Robert C. Turnham:]

Sure, Steve. Yes, we've given you 2Q guidance. Obviously, third quarter is going to be up a pretty good bit. The question is just the exact timing of the completions. We have a schedule right now. Those things can be a bit fluid. But clearly, the back half of the year, the production adds are going to come in pretty quickly. So we would suggest perhaps layering in, in equal growth, third quarter and fourth quarter, with the possibility that you're going to see more growth in the third quarter than what you see in the fourth quarter. But again, we haven't given that guidance yet because of the completion schedule can be fluid. But we do have plans to try to complete these wells back-to-back. And if we start kind of mid-to-late June, that puts the third quarter getting the lion's share of the 6 completions. And then, of course, with the rig coming back in, we'll be adding to that. So probably greater growth in the third quarter, but certainly, some growth in the fourth quarter over what you're seeing in the second to get you to that midpoint of guidance of 5,000 barrels a day for the year.

[Stephen F. Berman:]

And Rob, the 6 wells waiting on completion, are any of those on pads? Sorry, if you already said that.

[Robert C. Turnham:]

Yes, no, we didn't mention that. But the B-NEZ 1 and 2 and Tangipahoa Parish in Area 3 is a 2-well pad.

[Stephen F. Berman:]

Okay. And then on the CMR/Foster Creek 2-well pad, did you achieve your $9.3 million completed well cost target on that pad? Or is that still, call it a target, and you're on your way there?

[Robert C. Turnham:]

Yes, those wells were drilled some time back with the higher rig rates and the higher costs. So on the drilling side, we clearly spent more on those money than what we're expecting on the future 2-well pads. We did release that rig. Obviously, that was roughly $25,000-a-day rig rate. We're seeing $16,000, $17,000-a-day rates currently, which is baked into this $9.3 million estimate for the 2-well pads. So across the board, were seeing much reduced costs that we didn't -- we weren't able to capture on the 81 and 82. B-NEZ 1 and 2, obviously, will have the benefit of the reduced frac costs, even though we're pumping the higher proppant concentration. So it's going to be closer to this, although, again, we drilled those wells back prior to the cost reductions that we've seen recently.

[Stephen F. Berman:]

Got it. And then one more maybe for Jan. Can you tell us what the current share count is? Or do I have to wait for the 10-Q to come out?

[Walter G. Goodrich:]

Well, yes, this is Gil. It's ballpark around 55 million shares.

[Robert C. Turnham:]

57 million.

[Walter G. Goodrich:]

Yes, 57 million. You'll see this afternoon when she files.

[Operator:]

The next question comes from David Meats of Morningstar.

[David Meats:]

I was just wondering, the slide from the presentation with the type curves for the different areas that you've now defined, and I noticed that these, the production history is BOE. Is there a material change in oil cut from one area to another?

[Robert C. Turnham:]

No, there's not. I mean, we have seen some wells, like our Crosby well when we first announced it, it was 90% to 91% oil, which was on the low end. And frankly, that's been the one well that's kind of been the outlier. For the most part, they're 92%, as much as 98% oil. In fact, if anything, we see a little more -- a little higher oil concentration in the Area 3 than we do when you get back towards the Crosby well. So most of these wells that we're going to be completing we're expecting as high as 97%, 98% of potentially oil cut. But we won't know for sure until we frac the wells. I think the Blades well was a very high percentage of oil. We just never saw as much gas on that well as we did, for example, in the Crosby.

[David Meats:]

Okay. And with higher oil prices, I think we're all hoping to see at some stage, when it comes to adding rigs, is there one of those areas that will be a priority going forward? Or will you kind of just develop them fairly evenly?

[Robert C. Turnham:]

Yes, so one of the things we didn't discuss in our prepared remarks or haven't had a question, is basically lease retention. We have a $10 million budget this year, which allows us to maintain the core position of 150,000 acres, plus as much as 100,000 acres by the end of the year. So that's one aspect of it. If you look at our lease position, we have more acreage in Area 3, of 100,000 acres, and our goal there is to get out ahead of any lease expiration. So I think you'll continue to see a skewing of our activity in Area 3 versus the other areas, which are a little bit -- a little longer-dated lease expirations or are under continuous drilling provisions already, which is very manageable. So just because of the size, because of the lease schedule, I think you'll continue to see us skew towards Area 3.

[Operator:]

The next question comes from David Snow of Energy Equities.

[David Snow:]

Have you got any thoughts about a closer well spacing than the 100 acres you're assuming?

[Walter G. Goodrich:]

Yes, David, we do have a little bit of -- this is Gil. We do have a little bit of microseismic work that was done some time ago out there that indicates you probably can downspace from that. Obviously, with our footprint being what it is, at 100-acre spacing, we've got more wells to drill and more capital to deploy than we can possibly even contemplate over the next 10 years or so. So it may get tighter. I think if you look at the rock properties and rock qualities, plus the microseismic, it certainly would suggest you could layer in an additional well in between those. But again, that's all in the future for us.

[Operator:]

And we have a follow-up from Ronald Mills from Johnson Rice.

[Ronald E. Mills:]

Just on the Kent well, curious, what exactly happened there with the tight hole? And I assume that the dissolvable plugs, if used in that well, you wouldn't have had that issue?

[Walter G. Goodrich:]

Yes, Ron, this is Gil. That is exactly correct and one of the things that spurred us to do that. We basically went in, we went in with an oversized mill. We probably should've gone with a slightly smaller mill, but we did. It was right at the time that oil prices were really tanking. It got a little tight on us. And rather than trying to push it in, we decided to rig down the coil tubing in and cut the cost and get it off there. And as Rob said, we do plan to come back in with an undersized mill and go in and drill those plugs out, which we had thought we would probably do by now. But again, we've been kind of waiting and watching oil prices, being cautious with the capital. I think we currently have that planned for June, perhaps early July, to go back in. But the main point, I think, is one you just hit on, which is with the dissolvable plugs, that issue goes away.

[Ronald E. Mills:]

Okay, great. And then with the rebound in oil prices, I know it's new here with the past 2 or 3 weeks. But as it relates to your -- the potential sale of the Eagle Ford, it can't hurt that process. Where -- I don't think you started a formal process. So just can you update us on what your thoughts are about the Eagle Ford assets?

[Walter G. Goodrich:]

Yes, we have not started a formal process. We are starting to see some movement in oil, which we certainly believe is helpful for that. As we've said in prior calls, our objective was to do the things we did from a financing perspective in the first quarter to give us the flexibility around the timing of the Eagle Ford. It's still -- it's something we plan to do. We think it makes sense given the TMS footprint and the rates of return we're seeing in the TMS. So hard to handicap that, Ron. We're watching the market every day. But certainly, in the scope of the second, third and going into the early fourth quarter, the probability is fairly high that we would -- assuming the bids come in like we would hope, we would divest ourselves of that asset. But no specific plans at this moment.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Gil Goodrich, Vice Chairman, Chief Executive Officer, for any closing remarks.

[Walter G. Goodrich:]

Thank you, everyone. We appreciate your participation this morning, and we look forward to reporting our second quarter to you at the end of the summer.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.