Amplify Energy Corp (AMPY) 2013 Q3 法說會逐字稿

Good morning. My name is our Arnika and I will be your conference operator today. At this time, I'd like to welcome everyone to the Midstates third-quarter earnings conference call. (Operator Instructions). Thank you.

I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator.

Good morning, everyone, and welcome to Midstates Petroleum's third-quarter 2013 earnings conference call. Joining me today as speakers on our call are John Crum, Chairman, President, and CEO, and Tom Mitchell, our Executive Vice President and CFO. John will begin today's call with highlights of the third quarter, a review of operations, and plans for the balance of 2013. Tom will follow with key financial highlights of the third quarter and provide guidance for the fourth quarter. John will then wrap up with some closing comments.

Before we begin, let's get the administrative details out of the way with our Safe Harbor statement. This conference call may contain forward-looking information and statements regarding Midstates. Any statements included in this conference call or in our press release that address activities, events, or development that Midstates expects, believes, plans, projects, estimates, or anticipates will or may occur in the future are forward-looking statements.

These include statements regarding reserve and production estimates, oil and natural gas prices, the impact of derivative positions, production expense estimates, cash flow estimates, future financial performance, planned capital expenditures, and other matters that are discussed in Midstate's filings with the SEC.

These statements are based on current expectations and projections about future events and involve known and unknown risks, uncertainties, and other factors that may cause actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to Midstate's filings with the SEC and the third quarter Form 10-Q that will be filed shortly for a discussion of these risks.

Also, please note that any non-GAAP financial measures discussed in this call are defined and reconciled to the most directly comparable GAAP measure in the tables in yesterday's earnings release.

I will now turn the call over to John for his comments.

Thanks, Al. Good morning, everyone, and thank you for joining us today. I've been looking forward to this call for a while now. The third quarter of 2013 was a very exciting one for all of us here at Midstates. Most importantly, we hit the significant milestone of exceeding $100 million in adjusted EBITDA. We continued to see strong production growth and lower unit costs and expenses, allowing us to comfortably meet production and cost guidance targets for the quarter. Drilling and completion activity reached record levels in the quarter. We spud 39 wells and brought 40 new wells online, and ended the quarter with 10 active rigs drilling under contract.

Our Mississippian Lime program is clearly delivering on the promise we envisioned when we acquired the assets just one year ago. The recently acquired Anadarko Basin assets are now are providing us with additional low-risk proven drilling targets, primarily in the Cleveland Sands, as well as upside in the numerous other known pay intervals present in the Anadarko Basin. Our Gulf Coast program continues to provide us exposure to high-value oily production targets to round out our portfolio.

Production growth remains our focus, and we are pleased to report today's production was over 32,000 BOE's per day, up 385% in our short, 19-month public life. We are especially proud of the progress we've made in the Mississippian Lime acquisition, closed just over one year ago on October 1, 2012. At closing, those properties were making 7200 BOEs per day. In just one year, we had those same assets producing over 17,000 barrels equivalent per day. This strong year-over-year growth demonstrates our ability to execute. We expect to execute similarly on our newly acquired Anadarko Basin assets.

Overall, the Company averaged 28,464 barrels per day in the third quarter, from our diversified, three-state asset base. In spite of the significant weather-related downtime we had earlier this year, we expect to average at least 24,000 barrels equivalent for 2013, up 140% year-on-year. We remain firmly focused on efficient execution of our development plans across our asset base to drive further growth.

During the quarter, our Mississippian Lime and Hunton production grew to 14,364 barrels equivalent per day, up almost 38% from the second quarter. This growth was driven by an active five-rig drilling program in the Mississippian Lime, where we have been concentrating on our most prolific acreage. We believe drilling results continue to support the fact that our acreage position is among the best in the play. We now have 115 Mississippian wells that have been on production more than 30 days, with an average 30-day initial production rate of 570 BOEs per day.

During the quarter, we invested $105 million and spud 22 operated wells and completed 29 operated wells. Given the issues we faced earlier this year with snow and thunderstorms, a key focus was to increase the reliability of our power grid. During the quarter, we continued to transition our rental generator fleet from diesel to natural gas, with 80% of our generated electricity now coming from low-cost natural gas generators. By the end of the year, we expect to bring in 5 megawatts of new power from the main grid through a new substation we recently built in cooperation with another operator. An additional 5 megawatts of power will be available through the same substation this coming spring.

We have also purchased a new 5-megawatt gas-fired generator that will be in place by early 2014. These additions will greatly reduce the stress on the local co-op to provide for our growing demand, and significantly reduce the need for rental generator sets.

In addition, to mitigate the downtime we experience from lightning strikes, we had a big program installing overhead lightning protection and tank battery grounding on all of our facility sites. As a result of these efforts, there have been no shutdowns due to lightning strike since the program was implemented.

Another area of improvement is with our produced water. To accommodate the increased water volumes we have upgraded our saltwater disposal system with main trunk lines, looping, and automation, and level controls in our most active areas to provide system redundancy. Those infrastructure improvements, which are substantially complete, have helped to reduce lease operating costs in the third quarter, and will allow us to experience less downtime the future.

We've seen our lease operating cost per BOE in the Mississippian drop to the low $6 range, and believe this is a sustainable number going forward. Since assuming control of the properties, Midstates is employing a number of different technologies in the Mississippian Lime, which includes 3-D seismic, pad drilling, and a variety of completion techniques to maximize the value of our asset base. We are actively working the high-resolution 3-D seismic survey covering our core acreage position in Woods and Alfalfa Counties, and we are already seeing the benefits of this data.

Specifically, we are utilizing the data to high-grade our inventory in order to identify and test unique structural and stratigraphic features. We are also using it to guide the placement of our horizontal wellbores in the most geologically attractive intervals within the Mississippian section; and perhaps just as importantly, avoiding potential trouble areas such as major faults.

Pad drilling has also been a key driver in our success in gaining efficiency and providing drilling and completion cost savings. We are realizing cost savings of about $400,000 per well, based on rig move time and shared facilities. We are typically building pad sites for six-well capacity, but currently only drilling to four per pad, in an effort to minimize the amount of time to bring the new wells onto production.

The timing from spud to first well of the four wells being brought onto production -- to all of the wells being brought on production -- is roughly 100 days. As we've indicated in the past, this process will lead to some fluctuations in the number of wells brought online in any given quarter.

We are continuing to examine different completion techniques in the Mississippian Lime, trying to optimize fluids, sand volumes, frac stage sizes and numbers. We are also in the early stages of testing open hole completions and seeing some encouraging results. We hope to save as much as 40% of drilling and completion costs, and reduce cycle times in a subset of our wells, particularly those with good access to high-permeability streaks and/or natural fracturing, as well, as on the other end, wells with high initial water rates. Potentially, this technique could make some of our more marginal areas more attractive. Those lower costs could also make downspacing more economical and result in higher ultimate recoveries per section.

For the fourth quarter, we plan drilling and completion spending of approximately $85 million in the Mississippian, completing wells drilled in the third quarter and spudding 20 to 25 new wells. In the Anadarko Basin we have made meaningful strides with our efforts to integrate and grow the asset. As we've discussed, the entire Panther staff is under a transition services agreement which terminates at the end of this month. We are pleased to announce that 51 of Panther's staff have agreed to continue their careers with Midstates, ensuring that we retain the learnings from Panther's successes over the past eight years.

At the beginning of the third quarter, we had three operated rigs drilling primarily Cleveland Sand targets. We added a fourth rig in July and a fifth rig in August to primarily focus on the Marmaton, Tonkawa, and Cottage Grove prospects on our acreage. We invested $32 million and spud 16 operated wells, and completed 10 operated wells during the quarter; nine of those wells targeted the Cleveland, and one the Marmaton formation. We will continue to drill our low-risk Cleveland Sands inventory and are pleased with the early results. We have been experimenting with increasing stage volumes for sand and fluid to see if we can improve performance.

As of today, we have 11 Cleveland wells that have been on production more than 30 days since closing the acquisition, and have a gross 30-day initial production rate of 387 BOEs per day. We are encouraged by these results, as this flow rate is above the range of 270 to 360 BOEs per day that we had used in our type curve when we -- that we utilized during the acquisition. Importantly, the best five of those wells averaged 629 BOEs per day, giving us reason to believe that as we continue to optimize our frac parameters, we can bring the overall average up.

We are just getting started with the evaluation and the potential upside that we see in the Marmaton, the Tonkawa, and the Cottage Grove acreage holdings. Our first Marmaton well tested 413 BOEs per day for its first 30 days. We will have more results to share from all of those targets during the fourth quarter.

For the fourth quarter, we plan to spend $45 million. This encompasses completing the wells that are in progress at the end of the quarter and spudding 20 new wells, about 12 of which will be Cleveland, the remainder a combination of Marmaton, Cottage Grove, and Tonkawa targets.

Moving on to the Gulf Coast, as previously discussed, we are taking a measured approach to the development of our horizontal programs at North Cowards Gully and South Bearhead Creek. We completed the Musser Davis 27 HC-1 at South Bearhead Creek on September 10, 2013, targeting the lower Wilcox D. The well is currently producing at restricted rates of 483 BOEs per day, 85% liquids, with a flowing tubing pressure of 1300 PSI after two months on production. We now have successful completions in both the Lower Wilcox C and D intervals at South Bearhead Creek, demonstrating the potential for stacked horizontal development in the field.

The Wood 10H-1 sidetrack at North Cowards Gully was drilled in the third quarter and came online in early October. After one month of production, the well has currently produced at a restricted rate of 375 BOEs per day, 83% liquids, with a flowing tubing pressure of 2300 PSI.

In Pine Prairie, we are continuing to work the recently acquired 3-D data to high-grade locations and build inventory for the future. The 3-D results indicate good potential to extend the productive area of the Wilcox on the east side of the dome, in similar fashion to our earlier successes on the west side. We have also filed an application to start injection for a pilot waterflood project and anticipate proceeding in early 2014.

In the Fleetwood area, we have completed our interpretation of the 200-square-mile 3-D survey and have identified numerous leads and prospects. We are currently high-grading the opportunity set identified and expect to drill the first prospect as early as Q1 of 2014, followed by additional tests as land and partnerships are finalized. For the fourth quarter, we have no rigs active in the Gulf Coast, but we will continue to evaluate our opportunity set, and certainly expect a number of these projects will compete strongly for future capital.

I am pleased with our third-quarter results, and proud of the job our team has done to integrate another major acquisition and continue to grow our business. We will stay focused on execution to help drive growth. I am confident that many of the initiatives mentioned above will deliver the production growth, cost savings, and attractive rates of return to create the most value for our shareholders.

I will now turn the call over to Tom to provide you some detailed information on our financial results.

Good morning, everyone. As is customary, my comments today will focus primarily on the third-quarter financial highlights and providing fourth-quarter guidance. Like John, I'm very pleased with the solid quarter that we've turned in.

To begin, adjusted EBITDA was $101.6 million, nearly double the $53.4 million reported in the second quarter. The sharp rise in adjusted EBITDA was the result of strong organic growth in the volumes in the Mississippian Lime and the Anadarko, as well as a full quarter of production from the new Anadarko Basin assets.

Exceeding $100 million during the quarter is a significant milestone for us. As reported, the net loss of $23.6 million before preferred dividends compares with net income of $3.3 million for the quarter. Adjusted net income for the third quarter, which excludes the impact of unrealized losses on derivatives, as well as the Panther acquisition and transaction costs, was a net loss of $800,000 or $0.01 per share. Production in the third quarter rose 45% to 28,464 BOE per day, from 19,634 in the prior quarter. 50% of the third-quarter volumes came from our Mississippi Lime properties, 30% from our Anadarko Basin assets, and 20% from the Gulf Coast area.

Included in the third-quarter volumes was a 751 BOE per day imbalance settlement related to prior-period Mississippi Lime natural gas production. We exceeded the midpoint of our production guidance range with production of 27,713 BOE per day, even after excluding that prior-period adjustment from third-quarter volumes. The product breakdown was what we had anticipated.

As we discussed during the last call, pad drilling in Oklahoma resulted in a number of wells coming online concurrently in September, which led to a nice increment in production that has carried over into the fourth quarter. We are currently producing about 32,000 BOE per day. Going forward, we will continue to see the impact of pad drilling in Oklahoma resulting in some unevenness in production volume adds.

Looking ahead to the fourth quarter, we expect production to be in the range of 31,500 to 32,500 BOE per day, with about 55% from the Mississippian, 30% from our new Anadarko Basin properties, and the remainder from Louisiana. That fourth-quarter guidance gets you into the annual range that we established earlier this year. The regional product breakdowns, as well as expected realization differentials, including transportation, remain unchanged from prior guidance, and all are reflected in the updated guidance summary that we posted to the website for you.

You'll notice a new line item in our income statement for gathering and transportation. These expenses relate to the commencement of an amended gas transportation gathering and processing contract in the Mississippi Lime region that we discussed on the last call. Midstates entered into a new gas processing agreement with [Syngas] effective June 1, which gives us 155 million per day of cryogenic processing capacity under a fee-based processing agreement. Previously, we had only 30 million per day capacity, so the new plant provides firm capacity and increased efficiency for our current volumes and future growth. This allows us to process our gas and receive the associated increment in value of about $0.60 per MMBtu, which is reflected in our NGL realizations, as opposed to selling the gas wet.

Turning to a review of expenses, total cash operating expenses, which includes LOE, production taxes, and cash G&A, but excludes the acquisition and transaction costs, decreased 19% to $16.98 per BOE from $21.07 per BOE in the second quarter. This reduction was driven by cost efficiencies and strong production growth. Our lease operating and workover expenses fell to $8.32 per BOE for the third quarter, which was better than our expectations of $8.50 to $8.75 per BOE, and 15% below the second-quarter rate of $9.83 per BOE.

Even after excluding the prior-period imbalance settlement, we would have been at the very bottom of the range, at $8.54 per BOE. In addition to the benefit of higher volumes during the quarter, this improvement is driven by cost savings from investments beginning earlier in the year to reduce saltwater disposal expenses in the Gulf Coast and Mississippian Lime areas, as well as utilizing new natural gas generators rather than diesel generators when needed to maintain productions during power outages in Oklahoma.

For the fourth quarter, we expect our LOE and workover expenses to be in the range of $7 to $7.50 per BOE. This lower rate reflects our growth in Mid-Continent volumes, as well as continuing benefits from our cost efficiencies.

Severance and ad valorem taxes were 5.2% of sales revenue, before derivatives, a bit lower than the 6% to 7% rate we guided to for the quarter. For the fourth quarter we are maintaining the same guidance of 6% to 7%. Third-quarter general and administrative expense was $13.9 million, which was at the bottom of our guidance of $14 million to $15 million. On a BOE basis, our third-quarter G&A of $5.31 per BOE was 38% lower than the second quarter's rate of $8.55. The third quarter included non-cash compensation of $1.9 million. We expect G&A in the fourth quarter to be in the range of $12 million to $13 million, with about 10% to 15% being non-cash.

Our DD&A rate in the quarter of $28.56 per BOE was in line with our guidance of $28 to $30 per BOE. For the fourth quarter we also expect that same range. We added an Other Expense line item in the income statement this quarter to reflect a $600,000 loss on disposal of field equipment inventory that was no longer essential to our operations. From time to time, we may incur some inventory cleanup, but this is largely a nonrecurring type item and not expected to be material in the future.

Total interest expense incurred in the third quarter was $35.6 million. Of that, we capitalized $9.6 million and expensed $26 million. For the fourth quarter we expect to again capitalize about $10 million to unproved properties. The only incremental interest expense we expect in the near-term will be for additional borrowings under our credit facility. The tax rate utilized for the quarter was 36%. That's lower than the 40% we booked in earlier quarters. But for the fourth quarter, we would assume the typical 40% rate, with all being non-cash.

During the third quarter, excluding capitalized interest, we invested approximately $164 million in capitalized expenditures, with $105 million in our Mississippi Lime, $32 million in the Anadarko Basin properties, and the remainder in the Gulf Coast. For the fourth quarter we expect to invest $130 million to $140 million, with about 65% in the Mississippian, 30% in the Anadarko, and the balance in the Gulf Coast. The full-year guidance is unchanged.

During our September borrowing base redetermination, we experienced a very nice increase to the borrowing base, from $425 million to $500 million. We are pleased with that redetermination, which reflects the 2013 production growth we have achieved. We expect to have similarly positive revolver increases in the future as we continue to grow volumes and reserves. Our next regular redetermination date is April 1, 2014. On September 30, liquidity was $219 million, consisting of $194 million available under the credit facility, and $25 million of cash.

In conclusion, I'd like to reiterate my satisfaction with the quarter. Obviously we've been busy, extremely busy, since our IPO, with making two significant acquisitions. It's very nice to have a relatively normal quarter with strong performance and achieving our guidance targets.

And with that, let me turn the call back over to John.

Thanks, Tom. As you heard today, we had a great quarter, both operationally and financially, which we believe clearly illustrates the benefits derived from our focus on execution. We are currently working on the 2014 capital budget which will be submitted to our Board later this year. Once that budget is approved, we will come back to you with spending plans for 2014, as well as a production outlook and an operational update.

We believe we've made great strides with extracting value from our expanded asset base; and, as Tom indicated, believe that with continued execution, our revolver growth will provide the sufficient liquidity to fund our capital program in the coming years. That said, we are evaluating options to create additional cushion on the balance sheet. Those options include possible joint ventures on our properties, farmouts, and even outright sales of some assets. It's still too early to provide any specific details or timing of actions we may take. As always, we will keep you informed of our progress.

Now, before we take any questions, I'd like to introduce you to a new member of our IR team that will be talking to you quite a bit in the future. Danielle Burkhart was recently named Vice President of Investor Relations. Danielle joined Midstates in 2010, well before we went public. She holds degrees in petroleum engineering and an MBA. I want say how long she's been working in the industry, but I will say she started with Texaco at Hobbs, so you can run with that. We think her technical background will be of great value to helping us communicate our story.

And with that, Al, I think we're ready for questions.

Okay, John. Thank you. Please limit your questions to one and a follow-up. And, Operator, we are now ready to take questions.

(Operator Instructions). Neal Dingmann, SunTrust.

Morning, guys. Good quarter; nice production ramp. Say, John, I was wondering -- obviously the results in the Mississippian continue to improve. Just wanted -- I know some others and your peers -- I know you've previously talked about potentially some other formations there, or on your upside with the five rigs on the Mississippian particularly, what you'll target, both formation-wise and then sort of within your geographic region.

Well, thanks, Neal, and appreciate the support. We obviously have some interest in testing a variety of intervals, especially this second and third Mississippian within the 300 to 400-foot column of Mississippian that we hold. We have been concentrating on the first porosity interval in the Mississippian, trying to get volumes up, as we talked about earlier. Just working on our EBITDA right now, but we do have plans to evaluate Woodford as well as deeper sections within the Mississippian.

Okay. And then just a follow-up. Over on the Gulf Coast, you certainly have become more focused over there. I know you have got a lot of seismic things going on. Is the plan just to wait for some of that data to come out and then decide how you'll progress with both the horizontal and the vertical program over there? Any color, John, as far as the next couple of quarters, how you could see activity in that region.

Yes, Neal, we're still putting together our plans for 2014. And I guess, as we've indicated to you in the past, we're pretty pleased with what we are seeing out of this horizontal program. But we do want to get months of production, rather than days of production, before we make future investment decisions there. So we're pretty excited about the potential that we could have for water flooding at Pine Prairie. We've done a pretty significant study there, and feel like that has some real good potential. And as I indicated, the 3-D at Pine Prairie sure looks like we're going to be able to pull that Wilcox down the east side, just like we did on the west side earlier.

All right, guys. I look forward to all that activity.

Brad Carpenter, Wells Fargo.

Hi. Good morning, everyone; and nice quarter, everyone. Just curious, on your cash operating expenses, they had a nice sequential decline, and LOE alone had an impressive decline on a per-unit basis. You pointed out that cost efficiencies were one of the reasons behind the move, and specifically related to LOE the reduction in saltwater disposal costs helped out this year.

But I was hoping you could offer some additional details on the decline, and how we should think about LOE going forward. That is, have the majority of benefits from investments been realized already, or is there more improvement to come?

Yes, I think you should look to our guidance for where we think things are going. Last quarter, we told you about some of the things we had done in Louisiana where our costs were, frankly, getting out of line, certainly in the first half of the year. And those were associated with water hauling, and we've got that completely behind us now, and with chemical use, and we've resolved that with a variety of different techniques. So we feel like the numbers we're laying in front of you are a pretty good way to look at what we think is the go-forward case.

You'll recall also in the Mid-Continent, with the storms and things we went through early this year, we ended up having to put out a kind of emergency generation. And we were having to run that stuff on diesel, and you can imagine the cost of that. I think I've indicated to you guys in the past, diesel-fired generation costs about $0.45 a kilowatt hour, so it's horribly expensive. So moving to natural gas for our expected needs, and more importantly, tying into the grid with a large portion of it on a more reliable system, is going to make a big difference on operating costs there.

Okay, great. And then my follow-up would be a little bit bigger-picture, I guess. You continue to see success in the Miss Lime and Anadarko, while you've moved capital away from Louisiana, and, as you mentioned, have no further activity down there for 2013. I know you're still evaluating the opportunities down there in Louisiana and have some Q1 activity planned, but, John, you touched on evaluating options to bolster the balance sheet. And I was curious how you think about Louisiana longer-term, and how it fits into your portfolio going forward.

Well, I get that question a lot. Basically, would you consider selling Louisiana? And I guess the way I usually answer that is we would consider selling anything. But it certainly is the case that the rate of return that we are seeing out of our programs that we're putting on in the Mid-Continent now appear to be stronger than what we're seeing on our Louisiana portfolio. And that's why you're seeing the capital shift. So I think that -- hopefully that tells you what you're asking.

Yes, yes. That's very helpful. I appreciate it. And once again, great quarter.

Leo Mariani, RBC.

Morning. Just to follow up on your prepared comments regarding potential JVs, asset sales, farmdowns -- is that something you think we'll get a decision on by the end of the year, in terms of trying to bring some additional liquidity into the Company?

Leo, we're working it really hard, I got to tell you, from a whole range of ideas. And I just can't tell you when it'll happen. We're not in a position where we're going to give something away, so we need to make sure if we do something that we're getting the right value for it. So we're going to continue to work it. All I can tell you is that we recognize some increased liquidity would be useful to us and make all of you a little more comfortable, so we're focused on it very clearly.

Okay, that's helpful. I guess just hopping over to the Mississippian, can you give us a sense of what your current well costs are out there? And maybe where you think those can go, if there's any room to increase efficiencies and shave those down as we get into 2014?

Yes, I think I mentioned we feel like we're down about $400,000 from the first half of the year in this quarter. That's primarily associated with pad drilling, and with some changes in our completion techniques. But we think we have further potential to continue to drive those down. We're continuing to experiment with different completion techniques, which should give us more savings. We feel like our drilling days -- we maybe have kind of maximized that. So it'll be our around some other efficiency with rig moves and things like that that'll help us on the drilling side.

All right. So what is the current well cost, then?

We averaged $3.4 million in the last quarter.

Okay, thanks.

Drew Venker, Morgan Stanley.

Morning, guys. I was hoping you could speak to maybe the incremental activity you might expect across your different plays, where you'd be most interested to either increase or decrease into 2014.

Yes, I apologize, but I'd really like to come back with you in another month or so after we finalize these plans. Right now, we're pretty happy with the rate we're drilling at in the Mid-Continent. We've got five rigs in the Anadarko and five in the Miss. But we've got to plan this out and see where we go. And obviously some of the things we're doing now, experimenting with some of the new plays in the Anadarko, as well as watching the performance in the Mississippian and even in Louisiana, is going to affect the ultimate decision on where our 2014 capital will go.

Okay. And I guess following up on the efficiencies you're talking about in the Mississippian, could you speak to where you see service costs, independent of drilling efficiencies, between the Mississippian and the greater Anadarko Basin in general?

Yes, again, I think our real gains up there are going to be more in just getting down the number of days and the amount of time it takes to do something. We certainly have -- I've mentioned this in the past -- a lot more easy access to the equipment we need to do the work, which in itself actually helps with the costs, because you're not standing by waiting on something when you really need it. So I think those will continue to help. I have not seen the rates actually drop that much over this last year. But it's a matter of just getting more efficient, which is the right answer for all of us, including the service companies.

And then as a follow-up to that, can you speak to the impact of the open hole completions?

Yes, I didn't talk a lot about it, and I guess I'm somewhat loath to get too carried away here, because this is a pretty early experiment. I will tell you, we feel pretty good about what we're seeing. And I think what it's pointing to is we don't understand everything we'd like to understand about the Mississippian in general. So this is going to help us quite a bit in getting our arms around some of the technical details.

Ultimately, the way we see this is there will be some wells that we could look at and say, well, I wouldn't want to waste a fracture stimulation on a well that's already making -- pick a number -- 5000 barrels of water and 50 barrels of oil.

So that's the way we started looking at this is we have some areas that produce at higher gas cuts and higher water cuts. And perhaps the way to make those look a little better economically is not spend the money on the fracture stimulation, because we don't know that it's actually improving the overall takes on those.

Okay. So is it just naturally flowing?

No, we're pumping them. We're just pumping them in an open hole.

Okay. Thanks for the color.

Stephen Shepherd, Simmons and Company.

Good morning, guys. Just one for me. During the earnings season, it seems like more than one misfocused producer has reported impressive gas production growth but directionally lower oil production growth, which to me doesn't come as a big surprise given that oil decline rates in the play are steeper, just from the type curve perspective in gas decline rates.

I'm just curious to get your thoughts regarding whether or not you think that's ultimately going to lead to an uptick in the gas production [miss] going forward, relative to your 45% cut that you're seeing in the play right now.

Well, I guess, first of all, if you looked at our numbers you would see we're probably -- we've got a pretty good cut. And, interestingly, as we focus in the better area, it also has solid oil cuts. I've said in the past I would never argue against somebody saying that in tight formations you would expect your GOR to increase as time goes on. But I think sometimes people believe it's going to gas out. That's not going to happen. We are going to talk about some change in GOR moving from maybe 4000 to 6000 over a number of years. So we would expect to have every well, well paid out by then, and maybe not be an issue.

The issue, I think, is geography matters in the play. And so there are areas that are oilier and there's areas that are gassier, and it depends on what you're drilling.

Okay, thanks. Appreciate it.

Matt Portillo, TPH.

Good morning, guys. Just two quick questions for me. The first on the Miss, you guys now have over 100 wells, with a 30-day average rate of about 570 barrels a day, which is almost double your peers. But you're using pretty similar EURs in terms of your type curve. I was just curious if you could comment a little bit around how you think about final decline on these wells, and how you guys are thinking about the type curves you've previously talked about in the play.

We study that all the time. And I guess what I would say is I hope our peers are right, because it would imply that the b-factor is pretty high, and that these things are going to flatten out. We are trying to be conservative. And what we're running with is perhaps lower b-factors and therefore, declining a little harder than what our peers are showing. But there is no question our IP rates are significantly higher than peers.

So we study it, but we're not prepared to move our numbers up yet. But we have some hope that that is ultimately going to be the answer after we get a little history behind us.

Great, thank you. And then just the second question, in regards to the Cleveland, you mentioned that five of your wells showed some standout production, and that you are changing some of your completions in the play. Are those five wells under a different completion technique? Or was that in a concentrated part of the field?

And then, secondly, alongside that, could you maybe expand a little bit more in terms of what you are testing in terms of the incremental sand and stages on the Cleveland? Thank you.

Yes, basically three of those five, we did upsize the standard completion that had been done in the past by about 50% on both sand volumes and water volumes. But I'll have to say, two of that in that group were the original completions, so back to the original premise -- geology matters. So if you're in the right place, lots of things work. But we do have some faith.

I think other operators are routinely using more sand and fluid in their fracs, and actually more stages as well, so those are the kind of pieces we're using. And we're watching what the industry is doing, as well. It's one of the fun things about playing the Mid-Continent, I got to say, is we can actually learn from others instead of carrying the can on R&D.

Great. Thank you very much.

(Operator Instructions). Jeb Bachmann, Howard Weil.

Morning, guys.

Morning, Jeff. How are you?

Good. Just had a few questions. Looking at the comment on the JV partnerships, just wondering if you would be looking at maybe some dynamic partnerships where you would go in, not only on current assets but also future opportunities down the road?

Jeb, that's one of the scenarios we've laid out, as well. So when I said we're looking at lots of different things, I was dead serious. I don't know how many options Curtis and others are looking at right now. But it's a wide range of potential ways of doing this. And we're considering them all; but, like I say, just a little too early to tell you where we think this will end up landing.

Okay. Then looking at the Wood well down in the Gulf Coast, just wondering what kind of pressure draw-down did you guys see on that well with the sidetrack, versus the original hole or the original wellbore?

We didn't really see any difference in the pressure. In fact, honestly, it was slightly higher on initial rate, but I don't know that that means anything. You'll remember the original Wood collapsed within a few weeks of coming on production, so that's not a surprise to me that we wouldn't have a depletion problem. And so that is why we're flowing them at reduced rates here, trying to make sure we bring that pressure down slowly.

Okay. And then, I might've missed this during the call, but on production for the year, the guidance has come down from prior expectations. Just curious what that was due to.

It's come down from -- well, we have kind of been in this 24 range. I think we told you last quarter that, given what we went through in the first part of the year, getting to 25,000, which was kind of the midpoint of our original guidance, was going to be difficult. And so, in fact, that is the case. We would expect to crawl over that 24,000 for the year line.

Okay. And then last one for me. John, I know you said you've been working on the budget for next year. But just curious, you guys still targeting a 2.5 to 2.7 times debt to EBITDA in 2014?

Well, that would be a little hard for us to get to, Jeb. We don't see any way we could get below 3 next year. And we would expect the number to be closer to probably 3.5.

Okay, great. Thanks, John.

At this time, there are no further questions.

Well, if there's no further questions, I really appreciate you guys being there. I hope the message that came through today is we are pretty excited about what we've been able to accomplish, certainly in the Mid-Continent, as we've continued to integrate both the original Eagle assets and the Panther assets.

Excited about a new team coming together; and, for those of you who get a chance to get to Tulsa, go visit that office. It's a pretty exciting operation up there. They're wound up because they're really making numbers move quickly.

I appreciate your time, and you can call Al and Danielle and the rest of us after the call if you have other questions. Thank you.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.