SM Energy Company (SM) Q1 2013 Earnings Report, Transcript and Summary

Good morning. My name is Lynn, and I will be your conference operator today. At this time, I would like to welcome everyone to the SM Energy 1Q 2013 Earnings Conference Call. [Operator Instructions] I would now like to turn the conference call over to Mr. David Copeland, Executive Vice President and General Counsel. Please go ahead.

Thank you, Lynn. Good morning to all joining us by phone and online for SM Energy Company's First Quarter 2013 Earnings Conference Call and Operations Update. Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted on our website for this call and the Risk Factors section in our Form 10-K filed on February 21, 2013. We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Additionally, we may use the terms probable, possible and 3P reserves and estimated ultimate recovery, or EUR, on this call. You should read the Cautionary Language pages in our slide presentation for an important discussion of these terms and the special risks and other considerations associated with these non-proved reserve metrics. Company officials on the call this morning are Tony Best, Chief Executive Officer; Jay Ottoson, President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Brent Collins, Senior Director of Planning and Investor Relations; and myself, the company's Executive Vice President, General Counsel and Corporate Secretary. I'll turn – now turn the call over to Tony.

Good morning, everyone, and thank you for joining us for the first quarter 2013 SM Energy earnings call on this snowy day in Denver. We are changing the format of our earnings call this quarter to place more focus on performance, execution, new ventures and frequently asked questions from the Street. I will start with the quarterly performance recap and operational highlights. I'll then hand the call over to Jay to address some current questions we've received and review some of our exciting new ventures. Lastly, Wade will walk through our financial position, which, of course, includes a strong balance sheet. We'll be referring to slides this morning that we posted on our website last evening. With that, I'll begin my recap of the quarter on Slide 4. Results for the first quarter were solid, again, compared to our performance guidance. I trust that most of you reviewed our press release from last night, so I won't repeat all of that information on the call this morning. I'll just note that we came in on the high side of our production guidance and that we performed well against most of our cost guidance. We had GAAP net income of $16.7 million or $0.25 per diluted share. Adjusted net income for the first quarter was $55.3 million or $0.82 per diluted share. EBITDAX for the quarter was a record $329 million. I'd also note that both adjusted net income and EBITDAX were higher than their respective first call estimates. It looks to us that we came in higher on production and realizations compared to how the investment community had us modeled for this quarter. Moving to Slide 5. Our operated Eagle Ford Shale program reported average daily production of 51,800 BOE per day, which represents 15% sequential production growth. When looking at the production ramp over the last year, production has grown by 74%. Our rig program for the first quarter remained consistent with the fourth quarter of 2012 at 5 operated rigs. We made 28 flow-in completions during the quarter. Drilling in this program has been focused in what we refer to as area 3, also known as Galvan Ranch, and the eastern portion of area 1, also known as Briscoe Ranch. The majority of this drilling is being done on multi-well pads that are more efficient and require a smaller surface footprint. The efficiencies gained from these multi-well pads are expected to result in lower overall well costs. On Slide 6, our non-operated Eagle Ford Shale program continues to grow production at a healthy rate. First quarter production was 16,000 BOE per day, which represents 3% sequential growth from the previous quarter. The operator utilized 9 drilling rigs for this program during the quarter. We expect to be carried by Mitsui on our portion of drilling and completion capital into 2014. On Slide 7, our Bakken/Three Forks program reported average daily production of 12,200 BOE per day, a 3% increase from fourth quarter of 2012. We operated a 4-rig program and made 11 gross flow-in completions during the quarter on our operated acreage. In the second quarter, we expect to trade out 2 of our 4 rigs for a more efficient walking rig that is optimized for pad drilling. During the first quarter, we did not experience any significant weather interruptions to our operating activities in North Dakota. With that, I'll turn the call over to Jay.

Thank you, Tony, and good morning, everyone. It's another snowy day in Denver. Before discussing our new ventures activity for the quarter, I wanted to address a few specific questions we've been getting about our operated Eagle Ford program. First, I wanted to give an update on our condensate realizations. I'm now on Slide 9. In general, all of the oil we produce from the Eagle Ford has an API gravity higher than 45 degrees and may be considered to be condensate. In the first quarter, our price realizations for this product were above the NYMEX WTI price and were actually higher than in the fourth quarter of 2012. We manage our condensate sales through a basket of sales contracts, most of which are indexed to LLS pricing, which was at a $20 premium to WTI in the first quarter. We're in the market a great deal negotiating sales arrangements and have not seen material weakness in condensate gravity adjustments at this time. We're obviously pleased with the recent prices we've received for our Eagle Ford condensate, especially when you consider that our Eagle Ford economics assume a discount to NYMEX WTI of $7 to $8, which is still our long-term expectation. The second question I wanted address this morning relates to our operated Eagle Ford downstream transportation agreements. As discussed on Slide 10, during the first quarter, we regularly shipped wet gas production in excess of our firm downstream transportation capacity and we continue to do so in the second quarter. Our experience has been that there is sufficient interruptible space available, and we've had no trouble moving all the volume we produce on any given day. We have existing contracts for more firm downstream capacity starting at midyear, but at this point, we believe that interruptible capacity will continue to be available to us as well. We do not see downstream capacity as being a limit to our production growth at this time. Third, I wanted to update you on our ethane rejection status as this is a common question. We are still rejecting ethane in South Texas in contracts which allow for ethane rejection. Ethane rejection is a monthly election. And at this point, it makes economic sense to sell the ethane as BTUs in the gas stream versus recovering it and selling it separately. Right now, the strips for gas and ethane suggest that we will be rejecting for quite some time. We talked about the potential volume impact of this at our last call. As a reminder however, our plan is still to exit the year producing 50% liquids. We've had several questions regarding the historic production performance of wells in what we call operated Eagle Ford area 1 and the expected case data we put out for this area earlier this year. In our year-end resource summary table, we gave an expected average 3 stream EUR for area 1 of 600,000 BOEs. To be clear, this 600,000 BOE number was generated using rate transient analysis, not by averaging our historic decline curve results from wells in area 1. Our existing wells in area 1 have been impacted by high back pressures due to long flow lines and a lack of compression, which has prevented them from achieving their full rate potential. Rate transient analysis is a better tool for predicting EURs in this circumstance, and we expect that, with improvements we are making in area 1 facilities, that future wells will outperform our historic decline curves. Condensate yields from existing wells in area 1 vary widely from as low as 30 barrels per million cubic feet of gas to 310 barrels per million cubic feet of gas. Using our current spacing assumptions, we estimate an unrisked, location-weighted average yield for all area 1 potential locations of 125 barrels per million cubic feet of gas. For the AFE type curve and well economics, which we've provided and which are included in the appendix to this presentation, we used a value of 170 barrels per million cubic feet, which is the simple midpoint of the yield range and is a conservative estimate of the expected yield of wells in area 1 we plan to drill in the next year or 2. I should point out again that as reflected in our attached materials, our planned drilling programs in the Eagle Ford generate strong economic returns and would do so even at lower commodity prices than we're currently experiencing. Now I'd like to move on and talk about our exciting new venture program. We think it's of critical importance to continually be exploring for the next idea that will propel the company forward. Even the best assets have finite lives, so it's important to keep the pipeline of potential new projects full. At SM Energy, we have a very focused approach as to how we generate, test and, ultimately, develop ideas from our new ventures program. The goal is to add self-generated economic inventory that competes in our portfolio so that we can continually high-grade our development program. All the projects that I'm going to speak about today were internally generated new venture projects. We currently have 2 separate exploratory programs in the Midland Basin. Our Permian Shale program and our Mississippian Limestone program. Unfortunately, we had some delays in completion timing on some critical shale wells, so I don't have an update on that program today other than to say that we're currently drilling our first Wolfcamp Shale well on HBP'd acreage in the south Midland Basin. However, I do have a few slides starting on Slide 11 on our Mississippian program with some well updates I wanted to share. Just to remind you, our Permian Mississippian prospect is the same geologic age as the Mississippian other people are chasing in Oklahoma and Kansas, but it's more of a conventional play, which produces at lower water cuts. The slide shows a map of our entire acreage position with a blowup showing the horizontal wells we have drilled on the acreage to-date. As you can see, we've drilled more wells in the Roy area and a fewer wells in the Dana and Rebecca areas. On Slide 12, we've provided a listing of our horizontal Tredway wells with peak 30-day production rates and effective lateral link. I should say that we call this prospect area Tredway internally. And then I also should mention that when I talk about effective lateral length, I'm measuring that from the first perf to the last perf. Some people do it in different ways. You can see that with the exception of a couple of wells with mechanical or completion issues, we've had fairly consistent results with our short lateral program. We've recently begun using a longer lateral well design and our first result, the Roy 1803H has averaged 988 BOEs per day over the 12 days it's been online. I'm now on Slide 13. As the prior slide showed, we have the most well data in the Roy area and at this point, we're comfortable showing what we think the type curves are for that area, which represents about 1/3 of our acreage in the Mississippian play. The gray lines on the slide are data from the individual short lateral wells from the Roy area and the black line represents the average of those PDP wells. The red line is our projected type curve for our a 4,400-foot effective lateral well, which has a projected EUR of 310,000 BOEs and is 93% oil. We then have extrapolated that result for a 7,000-foot effective lateral, which is the upper blue line on this slide. It has a projected EUR of 440,000 BOEs and also 93% oil. So far, our Roy 1803 well looks like it's going to be our expected long lateral type curve. As we have more data in the Dana and Rebecca areas, we'll provide that to you. We're encouraged by our recent results and we continue to make progress in driving our costs down, which is going to be a common theme in all our new venture efforts this next year. I'm now turning to Slide 14. We haven't spent much time talking about our Powder River Basin assets recently, but we've been testing several wells in zones of interest. Our original target in this basin, you may recall, was the Niobrara, which had mixed results based on our testing. However, our recent results and the results of several other operators in the Frontier section have been very good. Our recent operated well, the Dandy State [ph], had a peak 30-day initial production rate of 927 BOEs per day. Two partner wells that we participated in had peak rates for 30 days of approximately 1,400 BOEs and 1,700 BOEs per day, respectively. We're really excited about the Frontier, and we think that the Shannon interval can be interesting as well. In fact, we recently completed a Shannon test that had a peak 30-day IP of approximately 500 BOEs per day. We recently entered into an agreement to add approximately 40,000 additional net acres to our Powder River Basin position for $65 million, which includes some seismic acquisition cost. After closing, we expect to have approximately 105,000 net acres in the total Powder River Basin, with about 62,000 net acres and what we consider to be some of the best rock for the Frontier play. You can see from the map provided that the acreage we are adding is a great bolt-on to our existing acreage position. Our combined position will have potential for about 250 gross Frontier wells. And we estimate that our aggregate acreage position will have about $90 million BOEs of total net resource potential. We'll have another Frontier well completed before midyear and I expect that well and other wells to be -- I expect that we'll be drilling additional wells in the second half with the potential for a 2-rig program in 2014. Lastly, I'll provide an update on East Texas. I'm on Slide 15. We've entered into an additional agreements which, subject to due diligence and closing, will expand our previously announced 105,000 net acre position to approximately 150,000 net acres, and we continue to acquire acreage in the area. Earlier this month, we released test results for a well in our East Texas play that targeted the Woodbine formation and we have more to Woodbine tests scheduled in the second half of 2013. The acreage position we've assembled has multi-pay potential and we'll shortly be drilling an Eagle Ford test as well. It's early days, but we're very enthusiastic about the potential of this project. I'll now turn it over to Wade to talk about the balance sheet.

Thank you, Jay. Good morning. I'll start on Slide 17 and discuss our financial position at the end of the first quarter. Not much has changed from the prior quarter with regard to our capital structure. It remains very straightforward with 3 pieces of long-term unsecured debt in our revolver. As of end of the first quarter, our debt to trailing 12-month EBITDAX remained at 1.4x, which is certainly below most of our peers. Our debt to book cap stands at 52% at the end of the first quarter. On the right half of the slide is a graph showing our debt maturities. You can see that we're in really good shape there with nothing coming due until 2018 and that's simply the current maturity of our revolver. Speaking of our revolver, on Slide 18, I'll discuss our amended secured credit facility. Earlier this month, we and our bank group amended the revolving credit facility and redetermined the borrowing base to $1.9 billion, up from its previous $1.55 billion. The increase in the borrowing base is a testament to the increased value of our PDP assets, driven by strong reserve additions at year end. Along with the increased borrowing base, we decided, and the banks agreed, to increase the commitments under the borrowing base to $1.3 billion. I'll now take a couple of moments to talk about our capital allocation process. Clearly, based on some of the new venture success that Jay talked about, there's the potential for a significant amount of capital to be deployed in these programs over the coming years with continued success. Our process is to evaluate our capital program twice a year and our next review will be around the middle of this year. We will look at opportunities to high-grade our existing program, as well as monetize assets that may not compete in our portfolio. We also have the ability to use the strength of our balance sheet to fund of some of these new programs. We're committed to a disciplined approach to allocating capital that generates high returns, preserves the strength of the balance sheet and doesn't dilute shareholders. So with that, I'll turn the call back over to Tony.

Thank you, Wade. Before handing the call over to Q&A, I'm on Slide 19, where I'll address the question, why invest in SM Energy? First, I would point to our recent performance. We were top quartile in a number of important debt adjusted share measures over the last 3 years, including production growth, proved reserve growth and EBITDAX growth. We were also in the top quartile of all sources finding and development costs. Next I point you to the near-term outlook for the company. We expect to grow production between 15% and 20% annually over the next 3 years. And consensus estimates have us growing EBITDA by 20-plus percent in both 2013 and 2014. As you've heard Jay talk about, we also have a pipeline of exciting new venture projects. We think that is very compelling as we move forward to continue growing our company. Lastly, I would point to our valuation. I believe that we trade at valuation multiples that present a great entry point for investors. With that, I will turn the call over for your questions.

[Operator Instructions] Your first question comes from the line of David Tameron with Wells Fargo.

I guess let me start with North Dakota. You guys talked about not having any weather impacts in the first quarter. Do you think you'll have any flooding impacts, I mean, anything more than you had expected going into 2Q given some of the late snowstorms?

David, this is Jay Ottoson. It's always cold up there and we always have -- I think what we tried to indicate, that we haven't had any abnormal related weather impacts. We always have weather impacts in the wintertime in North Dakota. At this point, we don't have any reason to expect that we're going to have any significant flooding events there. But, of course, it's not over yet. It's snowing here in Denver today and the weather is not over. So we'll see how it goes. But so far, nothing that really sticks out to us as being a big issue.

Okay. And let me jump to the Powder. Are you allowed to say if that -- was that QEP's acreage that you purchased? I don't know what you can or can't say, but is that -- can you answer that answer?

David, we have a confidentiality agreement with the seller, so we can't disclose who we bought the acreage from.

Okay. Fair enough. Can you talk about going forward. There's other packages out there. Do you wish to add to your position out there? And then second, just the operating environment. Can you get permits? How do you see your -- what do you see your activity level look like over the next 12 months out there?

Well, we certainly are interested in additional acreage. It would have to be in a very specific area for us and that's something we'll certainly look at. Permitting is something we gave long and hard consideration before we committed to this deal. We're convinced that we can get permits to run a reasonable program here that makes sense from an economic standpoint. I think you do have to be flexible. It takes time to get permits. A lot of this is on federal acreage. And you need to be permitting a number of wells at the same time, so you have opportunities to move around. So you got to be flexible. Frankly, the opportunity to be drilling in the Frontier and the Sussex and the Shannon, all 3 of those intervals are prospected, gives you even more flexibility in how you run your program. So we're confident we can generate the present value that we anticipated in the acquisition.

Your next question comes from the line of Mike Scialla with Stiffel. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: On the Powder, looks like you've got a couple wells there that are tracking above 1 million BOE type curve. I guess one of your issues with the Niobrara was inconsistency. You had some good results and then some not so good results. How do you compare that with the Frontier? Is this going to be similar to where you have wide variability in results or do you think you'll get more consistency here?

This is Jay again. I think we certainly anticipate the results being significantly more consistent. I would say in a general sense in the Niobrara and the Powder, we never really had a result that we were really enthusiastic about. The results were not great and inconsistent, I would say. In the Frontier, pretty much every well we've participated in, in this core area has been good. There's other wells out there that have data that we're aware of as well that look good. And we're just really excited about it. I think it is -- does have that opportunity to have consistent results. The other thing I'll say here and I think it's important is we've built a really top-notch drilling and completion team in the Bakken and Three Forks and this is just an opportunity for us to put them to work, really grinding away at the costs here in this area. These are expensive wells. A long lateral 1,280 Frontier well is probably $14 million, $15 million. And with opportunity to really work on that, we think we can generate even more value here by really grinding on costs. So to us, it really fits in that -- it puts it right in that flywheel of excellence that we have around our drilling program in the Rockies. It's just real great opportunity for us. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I guess a couple of follow-ups on that. What's the depth here? Can you get it down to sort of your Bakken-type costs over time? And are we really talking about the -- is it the Turner sand within the Frontier and is this analogous to 1 operator in particular is doing a lot of drilling to the east of you, is that -- do you think that looks analogous to the acreage you have?

Well, Mike, it'd be pretty easy for me to get out of my depth on the geologic intervals. My understanding has always been that these are essentially identical intervals. They call it the Turner on the east side of the basin, they call it the Frontier on the west side of the basin. It is fairly deep. I don't have a depth right here. I will have to get that to you after the call. And it's pretty hard drilling. I think there is some significant opportunity to reduce cost with a continuous rig program and optimizing our frac work. There's a lot of costs that goes into the frac here. So I do think there's significant opportunity to optimize cost and that's something we're going to be working on continuously.

Your next question comes from the line of Ryan Todd with Deutsche Bank.

A couple more questions. One, to follow-up on the new ventures. For activity levels in the Woodbine and the PRB, how should we think about it over the remainder of 2013? And the $65 million in your capital budget that's in that other operated bucket, should we expect that to fall in there? Or is there potential for upwards pressure on the $1.5 billion budget?

Well, this is Javan again. What we have said in the Woodbine is that we think we can cover the wells we'll be drilling there out of our new venture program and we won't be starting up our drilling program there until the second half. Again, it'll take us that long to get our rigs and permits in place. I think one thing I should mention, as a part of this, our Eagle Ford program, we're ahead of schedule, we're under budget, we're drilling wells faster than we expected. Quite frankly, we probably have some opportunity to shift some capital around in our portfolio to cover some costs. And that's something, as a Wade mentioned, that we'll look at very hard at our midyear allocation meeting. We have some knobs we can turn here other than just to go into more debt, if that's the question you're asking. And I think we will do that. At this point, we're talking about probably a single-rig program in the Powder in the second half, but it probably wouldn't start up until August or so. As I said, we have a well currently completing up there and we need to get prepared and get ready to really get after it. But I doubt we'd start drilling there really until the August, maybe almost the fourth quarter timeframe by the time you're through it all. So not a big spend during this calendar year. Next year, I hope we can mount a significant program, 2 rigs maybe even 3, depending on how it goes, depending on some of the permitting questions that David asked earlier. But we have a lot of knobs to turn, we have a lot of things to look at. We have some program that are going faster than we expected at lower costs and we're certainly going to use all those opportunities to try to manage our CapEx to a reasonable level.

Great. That's good to hear. And I guess you mentioned it briefly earlier, but you guys have done a great job of filling out some pretty attractive new venture regions here. You've got a decent number of other noncore assets that you're not deploying much or any capital to at this point, Haynesville, Woodford, Granite Wash, some of others. Should we expect to see some of those come onto the potential monetization market in terms of funding some of these other go-forward programs?

This is Tony. Let me address that one. As we've done over the last several years, we'll continue to high-grade our portfolio. And certainly, part of that potential upgrade involves the monetization of existing assets. And so we'll continue to look at those opportunities, some of which you've mentioned. But each year, we'll go through our entire portfolio and identify those assets that we think should go to market. Then obviously use the proceeds to help fund some of our new venture opportunities.

Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Tony, I'd like to reflect on that Slide 19 where you went through sort of the, why invest in SM? Operationally, no doubt, you guys have done an excellent job beating estimates, growing reserve base, building new positions, high-grading the portfolio, et cetera. But we still haven't seen the flow-through of those results to the share price, especially as it relates to the multiple, which I think was your last point. I'm sure you guys are frustrated internally with the way the stock has performed. And so my questions are really, what do you think the market is missing here today? And is there a point -- sort of like the question I asked last quarter. Is there a point when you believe other steps are necessary to bring forward shareholder value? And if so, what are you guys considering at this point?

I think first of all, Brian, while the multiple is something that we do look at, I don't get overly frustrated with that at all. So I think our focus is to continue to execute and bring forth new opportunities to make sure that our performance remains at a high level. So quite frankly, I'm very confident about our delivery, and we're going to continue to focus on our program at hand and on execution. And I think, over time, as I like to say, reason will prevail and those multiples will close with the peer group. But I think, absolutely, one of the things we're doing right now, and this call is evidence of that, is we are focusing on the key questions and issues that may be out there with investors and analysts to make sure that we are being very transparent, very clear in terms of our strategies and execution, and then we continue to execute against the plan. And so I think, a good way to think about that is we're on offense, executing well and we'll keep delivering results. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: No doubt, Tony. But you guys, for the last couple of years, have been probably one of the stronger executing companies within the E&P space. And I'm just trying to think forward, if you continue to post good results, but you don't see the follow-through, especially as it relates to the valuation, I mean what do you guys do at that point?

Well, first of all, as we foresee it, we've got a very strong long-range plan. We're going to continue to execute against that. You've heard us talk about maintaining a very strong balance sheet. We'll continue to look at high-grading our portfolio. If there are assets that it's timely to go to market, we will certainly do that. And I think if you look at our history over the last several years, that's exactly what we've done and that's how we've been able to position ourselves in some of the most exciting new ventures yet maintain what I think is a very strong balance sheet with significant funding capacity. And that strategy won't change going forward.

Your next question comes from the line of Subash Chandra with Jefferies. Subash Chandra - Jefferies & Company, Inc., Research Division: A follow-up on the Frontier here. Is there a lot of associated water with this formation?

Subash, could you repeat that? I couldn't hear which interval you were talking about. Subash Chandra - Jefferies & Company, Inc., Research Division: The Frontier.

The Frontier. No, there's not a lot of water associated with it. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. And just looking back at my prior notes, and you guys have had an active program there, I guess, an appraisal program for some time. This part of the basin is deep, over pressured, and if that's correct and sort of how -- your acreage, does it encompass that entire area or is there some flank in that acreage as well?

Well, Subash, we provided a map, so you can look at it and decide how you feel about it. We think there's -- as we released, there's about 62,000 acres there that we think are highly prospective for the Frontier. It is deep and it is over pressured and, frankly, that's why we like it. This is one of the keys to making resource pressures -- pressure is one of the keys to make resource plays work. And we were looking for pressure when we went here and that's certainly what these wells have. So I would say, and you'll note that as you look at the results, these are -- these wells produce a little more gas, say, than our Permian program. I think we said our Permian program, Tredway's 93% oil. The Frontier is considerably lower than that. So there's a lot of liquids that are produced out of the Frontier. It is a deep, over pressured system. So a lot of the value's in the gas liquids as well. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. So this is the map you were talking about on Page 14?

That's right.

Yes, that's right. I think we gave counties on there and -- but our view is this is the deeper parts of the basin. It's -- we call it the Deep Powder and it's clearly one of the areas where the Frontier is the most over pressured. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. Got it. And then another question in the Eagle Ford. Area 3 drilling activity, could you just refresh me on the rigs and the potential to accelerate development in area 3? Or sort of the thought process you might go through in order to make that decision?

Well, so far this year, this is Javan again, most of our drilling has been in area 3. And I think we had 28 completions in the first quarter and most of those were area 3 wells. And that's where most of our activity's been. We're moving quite a bit of our activity into area 1 here for the next quarter or 2. We have some specific wells we need to get drilled up there, mostly on the east side of area 1, and then we'll get back to area 3 later in the year. As I mentioned earlier, we think at this point, we're going to complete our scheduled program in terms of the program we had anticipated, we're going to complete early. And we're drilling the wells faster than we expected and we're drilling them at lower cost than we expected. So we're going to have to make a decision on whether we wanted to go ahead and complete more wells than we anticipated and potentially -- we're not drilling them as cheaply as we are quickly. So we'd have to spend more money to keep all 5 rigs running all the way through the year and potentially complete quite a few more wells. Or if we want to conserve that capital and spend it in our East Texas or Powder programs and just cut back to, say, a 4-rig program in the second half. I think we know for sure that we're going to move 1 rig out of here for some period of time to East Texas. We haven't decided how long that's going to be. That's really going to be a midyear decision for us. As Wade mentioned, we have a process we go through at midyear to look at all programs and reallocate. We just haven't made that call yet. We're certainly very mindful of where we are with respect to CapEx versus cash flow and where we are just in terms of our overall Eagle Ford program. We do think if we wanted to spend a little more money and keep 5 rigs running, that we could certainly do that. It's just there's trade-offs that need to be made there with respect to our overall capital budget and program. Subash Chandra - Jefferies & Company, Inc., Research Division: Jay, if I could just ask a strategy question there. So you have a very high threshold for returns, area 3 and area 1. East Texas, I think, looking at my prior notes, you were sort of anticipating 25% plus type. So good enough, maybe slightly lower, and PRB is to be determined. How do you think that might be translated if you're -- I guess you would -- if you're shifting from a higher to a lower, and if that's an accurate statement, IRR our business. And second, how do you think about spending within cash flows if every dollar is actually creating well above the cost of capital returns? Why sort of hold on to the spend within cash flow regime?

Well, there's 2 questions in there. Let me answer the first one and then I'm going to turn it over to Wade to answer the second. In terms of trading -- I understand what you're saying. You're saying why would we move rigs out of a very highly economic play into something that we haven't proven is highly economic? I don't know that we've ever said what we think returns in East Texas are going to be. Clearly, we think they'll meet our hurdles. Frankly, they're going to have to do a lot better than that if we're going to drill it long-term. The Powder numbers, if you look at 1 million-barrel well for the kind of costs that we talked about earlier in this call, will have very substantial economics and could be very exciting. Obviously, we're not quite there yet, we have to prove that up. So I don't think -- in my view at least, we would not necessarily be making a return trade-off. With that, I think I'll turn it to Wade to talk about the other question.

Your question about within cash flow. I mean, that's -- we've said for a long time that our objective was to get to that point and we still see it on the horizon by the end of this year. We've also said that we're not setting that as a limit for ourself going forward, just as simply as a marker, frankly, that shows that we have a portfolio that has the ability to generate significant growth within cash flow, which we think is a very important sign. At that point, if we have opportunities that are high return beyond that, we'll take a strong look at that and look at the balance sheet at the time and make the decision from there. As Jay said, it's all about the highest returns. And I think -- we'll say it again, I think the only way to do that corporately is to rank our projects and if some projects start coming in higher than others, we have to take a hard look at the ones on the lower end of the list and maybe those get divested or JV-ed or something else. But that's way we look at it.

Your next question comes from the line of Welles Fitzpatrick with Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: In the PRB, what's the working interest in those partner wells and how much of that 105,000 do you guys operate?

That's a great question. The average working interest in our Frontier position is going to be about 48%. So it's lower than our typical percentages. Of the whole 105,000, that's 105,000 net acres. I don't know exactly -- the reason it's hard is because operatorship is not necessarily determined -- it's determined by who permits first and a number of other issues that relate to operatorships. I'm not sure I can tell you exactly how much of the 105,000 we would operate. Depending on how the wells lay out, I think the -- we're thinking right now in the Powder, the Deep Powder section, where there's about 250 gross wells there, which is on the Frontier side, and then there's a significant number, it's in the presentation, about the Shannon and Sussex as well. I don't know that I can give you a percentage of operated, but that 48% number is a pretty good number for what we own in the sections we own. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay. Perfect. And then the permits that you guys have in the Frontier, it looks like it's kind of concentrated in that Finley Draw area. Is that correct or am I just looking at stale permits? And of the 42,000 Frontier acres, how many of those are represented in the 251 gross wells? Are those across the entirety of it or is that --could that number go up? I guess is my question.

Well, we think the 250 is a good number for the acreage as a whole. I don't know that I think that number is going to change a lot. We are drilling -- the well we're competing right now is on the north end of our acreage position. There's another non-op well that's been completed up there recently, which looks very good to us. So we kind of have it straddled. I would say that the individuals we're buying this acreage from had some existing permits as well on some wells there. So we don't just have our own permits to deal with, we have theirs as well and we'll be doing some additional permitting. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, perfect. And just one more quick one. You guys changed the wording a little bit from the Leonard to the Bone Springs. Obviously, the Leonard's in the Bone Springs. But is that -- are you guys looking for additional members or am I just reading too much into that?

I don't think we actually changed the wording. We are drilling some Bones Springs wells in New Mexico and we're drilling some Leonard Shale wells in the Midland Basin. So I think you may be -- we may have inadvertently confused you there with that. You're right, they're all that kind of Pennsylvanian age stuff or Leonardian age. But the Bone Springs wells we're drilling and we do have our rig running in New Mexico right now, drilling some Bone Springs wells. We just don't talk about it a lot because it's not a huge position.

Your next question comes from the line of Pearce Hammond with Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: Give some sense, if you are thinking about divesting some noncore acreage or positions, what might be the timing for that? Is that a process that could be ongoing right now? Or is that something you'd tend to look at during this midyear update or once a year or whatnot?

Yes, Pearce. This is Tony. I would say that we're going to be looking at all those issues and the various options kind of at midyear. And obviously, this is a great problem to have with some of our exciting new venture projects in front of us, but we'll look at that at midyear and then kind of decide which ones we might consider going to market with. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then just 2 quick ones on the Eagle Ford. First, do you have any potential impacts from the drought in Texas? And then secondly, Jay, relative to your planning at the beginning of the year, it sounds like the Eagle Ford's operating a lot stronger than the original plan. When you look at your original expectations for infrastructure like tank batteries, gas processing plants, takeaway capacity, et cetera, do you think that's also developing a little bit faster than what you originally thought?

Two great questions. Let me take the water one first. There is -- there are, no question, significant drought in Texas. The South Texas area is really under a lot of pressure. Fortunately, we get all our frac water out of the Rio Grande River. And we were -- I guess what I should say, we were knowledgeable enough or lucky enough to have acquired enough water to where even if they prorate the river substantially, we'll still have plenty of water to run our program. So we feel very fortunate to have been in that position. And frankly, just due to some terrific work by our land and operational people in South Texas that we made that commitment. Second issue, with respect to the infrastructure and our pace. We are ahead of schedule and we completed 28 wells in the first quarter, which is well ahead of where we expected to be. And it does give us some opportunity to be flexible in the second half of the year. Our gathering system provider, Regency, has just done a terrific job for us over the last 3 to 6 months in really catching up with us. And I was visiting with them just the other day on schedule. They're actually ahead of our planned schedule on a couple of facilities that are coming this summer. We have quite a bit of facility work to be done in the fall. At this point, I really don't anticipate that midstream or downstream facilities are going to be an impediment to our growth. It's really going to be about how we choose to allocate capital over the next 6 to 12 months. And how we look at trying to prove up these new plays, which is very important for a company that tends to be in business, versus monetize our existing assets. And those are choices we have to make and we'll be making those here around midyear.

Your next question comes from the line of Jeb Bachmann with Howard Weil.

A couple of quick questions. First on the non-op Eagle Ford. I noticed you guys had talked about costs increasing in the first quarter. Just wondering if the operator is doing anything to improve the efficiencies there with trucking and some of the other infrastructure to bring down those costs going forward?

Jeb, I think it's probably a great question to ask Anadarko. I don't -- you know as well as I do, it's difficult for us to know exactly what's going on at any point in time. We get bills and we pay them and we try to forecast those. Based on what I've seen, I think Anadarko is doing a terrific job. And to some of this, this is just that kind of lumpiness you get that's associated with non-op stuff. They did have some -- our LOE was a little higher in the first quarter than we expected. I will say from a budget standpoint, we were basically right on our LOE budget. We were probably a little optimistic based on the trend and took our guidance down a little bit more than maybe we should have. But I really don't think there's any significant problem, certainly nothing that we're aware of and we think Anadarko is doing terrific. So I would expect those numbers to come right back in line and we'll see what it looks like in the second quarter.

Okay. And then looking at those few drilling completion issues in the Mississip Lime in northern Midland, just wonder if you can give some color on exactly what happened there, if you can.

You bet. The Melanie well that's listed, we drilled into a cavern and ended up twisting off and had to complete a very short lateral well. Other than that, it's not a bad well for the amount of footage we put in it. It's just not what we hoped. There's a Dana well on there that I would -- was also short laterals. We ended up sidetracking the well, had 2 laterals going. As we completed the well, the well came on really nice and then started producing a bunch of water. And we're pretty sure we frac-ed up into another water section above us and that's how we ended up there. And then there's a Debbie well, which is sort of on the northeast corner of the Roy area, kind of the Roy area we developed. Looked like we drilled across a small fault, or into a fault block, and that well's just wet. It's making a lot of water. And so there's still significant risk associated with some of this. It is conventional in the sense that their porosity's in different intervals. You do have some seismic issues here. We've got a lot of seismic, done a lot of seismic reprocessing and work to understand what we're drilling. It's not an easy play and that's why it's taken us a while to get there. We're obviously gratified by some of the results we're seeing, but we need more consistent, more consistent results here. And I think that's what we're aiming for.

Okay great. And last one for me, Jay. Any high volume gas projects within the portfolio that you guys are looking at with the gas prices now moving closer towards $4.50, $4.75 this year?

Yes, we don't have any plans to intentionally drill dry gas wells. I would say that a lot of the acreage we have acquired in East Texas has some significant gas potential associated with it, that we are not currently pursuing. That's one of those other intervals that we can chase. In fact, we completed a well not long ago in the chalk that we hoped would be wet gas, it turned out to be dry gas and it's turned out to be a really good well. So, I think there's some wet -- more dry gas potential. Now this is one of those things, as Tony mentioned, as we look at our portfolio and how we decide to trade this and optimize our portfolio, obviously, gas prices improving some is going to be a consideration in that. How do we look at that? The biggest upside to us from gas price though is if you look at all those Eagle Ford economics we've been showing, they run at $3.50 flat, WTI or NYMEX gas. If you put those economics at $4.80, which is what January 2014 is right now, $4.75, I think, the last I looked, that's a big lever on our returns. And I think we have a significant opportunity in our gas portfolio without really having to try to go out and drill dry gas wells.

Your next question comes from the line of Joe Magner with Macquarie Capital.

Just looking out at the second quarter guidance versus the full year average, I know it's reiterated at the prior level, but it doesn't look like there's much difference between those 2 guidance ranges. Just curious, with the step-up anticipated in the second half, where are some of the leverage opportunities on seeing some increase to, I guess, second half volumes? You've talked about operational improvements and proved drilling times and that sort of things. Just kind of curious where we might see some impact down the road.

Well, maybe we were a little too subtle. We raised the lower end of that guidance, so the midpoint went up, and so we did raise our guidance, I would say that. The second thing in terms of we are ahead of schedule. We are -- a lot of that, if we stay on a 5-rig pace in the Eagle Ford, we will spend more money that we budgeted. And so we have to really decide, are we going to just kind of stick to the well count we had forecast or maybe a slightly higher well count at the same capital budget or are we going to go -- are we going to continue beyond that? We have not made that decision yet. We would make that decision at mid-year. If we made that decision, we'd have to increase our capital program. And I think -- and then at that point, we would probably have to acknowledge that we're going to produce more than we expected. At this point, given where we're at, with what we've said about our budget, I think the guidance we've given is appropriate.

Okay. And I guess, historically or over the past couple of years, as you've been waiting for the infrastructure to be built out, your completion schedule has sort of been targeted to sort of run alongside that. Now that you have more visibility on that takeaway and processing capacity and you've indicated a couple times recently that the interruptible capacity could continue to be very accessible, is there an opportunity to maybe get ahead of the volumes that you've committed to on a firm basis? Or just kind of curious how you're thinking about the takeaway from the basin now and the opportunity that presents.

Well, again -- this is Javan again. To me, this is all about returns. It doesn't necessarily have to do with infrastructure at this point, because I don't see it as a limit. We're looking at our overall capital program and trying to look at 3 years out and ask ourselves, okay, what's the best way to have the strongest portfolio for the longest period of time. And where do you spend the money to do that? And we're need to make some allocation decisions about how much of this goes into new ventures, how much of it goes into accelerating current assets. Clearly, you have choices. You can burn through your current inventory or you can build new inventory. You can drill more certain high returns, you can go after the long -- a little longer term view. And we have to make those choices. I think there's -- it's not an easy answer. I think it makes sense to us, to some extent, to use the opportunity we have here by drilling cheaper and faster in Eagle Ford, potentially, to be able to prove up some of this new stuff that we think is going to work. And frankly, has tougher lease terms, where we really have to get after it in an earlier time period. Eagle Ford is very unique in the flexibility of its leasing, of its lease terms. And we can run a 3 -- we could run a 3-rig program and still hold all our acreage together. So we need to use that flexibility where we can to improve our overall inventory and the outlook for the company as a whole.

Your next question comes from the line of Scott Hanold with RBC Capital Markets.

Just a couple of quick ones. Condensate, obviously, you said the pricing remains pretty robust. Is that something that you can effectively hedge out for any period of time?

I think, if you look at our condensate pricing, it's very directly connected to LLS. And so LLS hedges have some benefit. And there's also a connection to, say, natural gas lean prices. So there is some hedging you can do on that, although that is a thinner market. I think, in general, investors should be thinking of this in terms of we're pretty connected to the LLS market. And generally, we're going to track fairly closely with changes in LLS over the next few years.

Okay. So when you look at your hedge book, are you considering hedging the LLS side of things or is that just not a very good trade-off at this point?

Well, when we hedge, we hedge to a location. So we always hedge -- we hedge basis when we hedge location. So whenever we put a hedge in place, we're hedging to a specific location and trying to hedge that basis as well.

Okay. Understood. And then in the Permian Miss, a couple questions. What are -- or how do the returns kind of compare with -- based on what you see early on with, say, like the Bakken and the Eagle Ford? And then could you remind me on what the oil and oil and gas cuts are in that project?

I'll take the last question first, oil and gas cuts. The oil cut varies from about 80% to about 93%, I think, was what we released in the Roy area, depending -- it is a little different, depending on which portion of the Mississippian you're in. In terms of returns, I would have to say that they're still not where we'd like them to be. If we -- sorry about that. If we -- if every well we drilled looked like the Roy 1803H, it would be fabulous, okay? Fabulous returns. We've got really one of those. And until we see more of that, I would have to say, we still need to improve. And a lot of that is on the cost side. We just need get our costs down. We're having -- we're working hard in the Permian, in general, to get our costs down. It's a tough environment right down -- down there. But at this point I think the Roy area, we're fairly comfortable with what kind of wells we're going to make and we're getting better at drilling them. This last well was, frankly, even a bit of a pleasant surprise to us. We -- as you saw, our type curve wasn't that optimistic. But at that type curve, these wells make above-hurdle-rate economics at our current costs. The question is how much better can we get? And as we talk about, frankly, we talk about capital allocation this summer, that's going to be a big topic. It's where does -- how does this Mississippian project fall with respect to everything else we're doing? And is it something we should continue to pursue? Or is it something better off -- that's better off in the hands of someone else?

So it's more a cost versus a consistency issue based on what you know so far?

Well, consistency's been an issue. Obviously, you look at the well results and I think we're fairly comfortable in that Roy area now that we're getting pretty consistent results. We're obviously not trying -- we're hoping that you don't just extrapolate that to the other 2 areas, because we're just not that confident there yet.

Okay. Understood. And one last question. I think the best way to frame it is maybe, for Tony, is that when you step back and you look at what you perceive as a sizable valuation disconnect from some of your peers and sort of the recent or persistent activism in the energy space, how, I guess, aggressive do you all look at -- you're trying to stay in front of some of this stuff so that you don't have to deal with the situation where you're kind of being pushed to make decisions you may not want to do.

I would say, as I mentioned earlier, our level of confidence in our portfolio continues to grow. And I think you're seeing the quality projects that we're bringing forward, both some that are in the development phase, as well as the several new venture opportunities that Jay talked about. And I think, what we're doing and you are seeing it in this call, and if you've kept up with us in the conferences we've attended so far this year, we're going to be very out front in terms of issues that we hear and address those immediately and directly. And I think, you take a look over the last couple of years, we've been painted with some different brushes that were issues to some analysts and investors. But we're going to be very forthcoming with how we see our position relative to those issues. A good example is condensate pricing, NGLs, those are and have been issues with some analysts and we're taking those head on to let folks know that, sure, condensate could be an issue longer-term, but we've seen actually a premium near-term with that. But that's just a good example of making sure that we're being as transparent, that we're being timely in terms of responding to some of these issues when they crop up. Because if you take a look at the execution and performance, it is there. If you take a look at the confidence level in the growing portfolio, it is -- to me, it's a high-quality problem to have. We've got some great projects to select from. Now, we're to be making decisions in terms of how we fund those, and then we've got a lot of flexibility with our current asset slate. And as we've done in the last several years, we utilize those assets, those that fall out, we're not at all opposed to going to market to help fund some of the new opportunities. So I think what you'll see from is continued focus on execution, continuing to address issues as they come up and again, a continued increase in confidence in terms of delivery on our projects.

Scott, this is Wade. I think Tony said that well. The only thing I would add is that we're trying to be patient. I think the market will get it. Since we've started a lot of this, been somewhat encouraged by the stock's performance year-to-date. I think most of the comparisons I've seen, we have been outperforming the peer group. It's a good start. We're still trading at a discount, but we think it's going to get there.

Your final question comes from the line of Mike Kelly with Global Hunter Securities.

I was hoping to get a little bit more color on the potential progression in the southern Midland Basin. And really what do you still have to accomplish here before you talk about really a defined development drilling program. And I'm also curious to hear kind of, in your eyes, how this acreage ranks now between the Powder and also what you have in East Texas.

Well, thanks for that question. I think if you look at our Midland Basin position, we have acreage, shale acreages both south of Midland and north of Midland. We've been focusing most of our effort on our north of Midland area, the Leonard. And as we kind of wind up our testing program and make some decisions on that, we're really turning our focus to the Wolfcamp intervals, both north and south. We have 2 significant assets south of Midland, the Sweetie Peck asset, which is about 13 -- almost 13,500 acres, I believe; and another non-operated position, or operated by Concho, which is called Halff East, which is another 6,000 or so acres. So about 20,000 acres in the southern Midland Basin. Concho is about to spud their first Wolfcamp well on our acreage at Halff East. There have been some very good offset wells drilled and we're very optimistic about that potential result at Halff East. And we are, literally, in the middle of drilling our first Wolfcamp shale test at Sweetie Peck right now in one of the Wolfcamp intervals there. So as we see the results from those 2 wells, then I think we'll know where to go in the southern Midland Basin. That acreage is all HBP'd, so it's not going anywhere. So we have the opportunity to test and look and make the right choices in those things. We also have some Wolfcamp testing we'll be doing later on this year in the northern Midland Basin on some acreage we acquired last year, which, based on the core work I've seen, looks pretty prospective as well. So it's still very -- for us, it's very early stage. When -- we got into this, the shale plays in Permian a little later than some of the other folks, and had to pick up our acreage late. We're relying on some of this HBP acreage to work. It is in a great area. I mean, we're very close to Pioneer's wells, as I said, that Halff East area, there's a number of great wells around us. So I think it's pretty high chance stuff but still to be determined.

I would now like to turn the floor back over to Tony Best, CEO, for any closing remarks.

Thank you. Thank you, all, for joining us on the call today. We had another solid quarter and we have a lot of interesting things going on at our company. Our confidence continues to grow, as does the quality of our portfolio. Our operational groups are performing extremely well and I'm excited about our new venture's potential that was discussed on the call this morning. With that, again, thank you for calling in. We'll talk to you next quarter.

This concludes today's conference call. You may now disconnect.