SilverBow Resources Inc (SBOW) 2012 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. And welcome to the Swift Energy Company second-quarter earnings call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

I would now like to turn the call over to Mr. Paul Vincent, Director of Finance and Investor Relations. Mr. Vincent, please go ahead.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations.

Welcome to Swift Energy's second-quarter 2012 earnings conference call. On today's call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review our financial results for the second quarter. Then Bruce Vincent, President, and Bob Banks, Executive Vice President and Chief Operating Officer, will provide an operational update. Terry Swift will then summarize before we open up the line for questions. Also present on the call is Steve Tomberlin, Senior Vice President of Resource Development and Engineering, and Jim Mitchell, Senior Vice President, Commercial Transactions and Land.

Before I turn the call over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us, our industry, and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports, to which we refer you, along with cautionary statements contained in our press releases, and our actual results could differ materially. We expect our presentation to take approximate 25 to 30 minutes and have allowed additional time for questions.

Thanks, Paul.

And thank you, everyone, for joining our call today. Swift Energy's emphasis on crude oil and liquids-rich projects during the first half of 2012 is now delivering better than expected growth. Our crude oil production for the quarter was above our previous expectations, and current projections are for a sequential crude oil production increase of approximately 20% in the third quarter. We also expect a similar increase in our natural gas liquids production and remain on track to delivering and having in the fourth quarter average daily production volumes being over 50% crude oil and natural gas liquids. Total corporate production for 2012 is on track to be a new record for Swift Energy Corporation.

We have spent several years putting together the assets, people, and processes necessary to achieve this type of growth. As part of this long-term approach to developing our resources, we have anticipated periods of time in which our capital expenditures would outpace our current cash flows and, when necessary, have secured additional financing to support our spending levels. As our acreage is developed and our production grows, our cash flow levels should increase.

It's important to note that we have repeatedly stated this year that we will reduce our capital expenditure levels during the second half of 2012 to achieve a better balance between spending and our growing cash flows. Even with reduced spending and activity levels that may continue through next year, we believe we will still deliver oil and gas liquids growth in 2013, consistent with our long-term strategic growth targets of 7% to 12% annual production growth. I want to remind folks that this is not any particular guidance for next year, it just emphasizes that we do have strategic growth plans, and that for a much reduced capital spending program next year, we could easily achieve those plans.

We are sensitive to the current sentiment by some market participants to have forward -- to look forward in the future of hydrocarbon pricing and the uncertainties that it has, as well as the general macroeconomic environment. Our long-standing philosophy of maintaining low levels of leverage and high levels of liquidity is tailor-made for the type of efficient operating organization that we are managing today, even given as uncertain an external environment as we all currently face.

Although we realize the greatest cost effectiveness in our operating program when we are at higher activity levels than the expected three-rig South Texas program that we will have in place by year-end, we have positioned the Company to be flexible enough to operate effectively and deliver growth even in a wide range of operating scenarios. Bruce and Bob will detail our current activity levels and what type of activity we expect to have as we enter 2013 in just a few minutes.

The volatility of hydrocarbon pricing has persisted and without question is the primary challenge facing our industry today. Our crude oil price realizations have been well above our budgeted expectations, and crude oil sales accounted for 74% of our second-quarter revenues. As we increase our percentage of production levered to crude oil pricing, we will continue to benefit from stout Gulf Coast pricing relative to the NYMEX.

Of greater concern has been natural gas and natural gas liquids pricing. Although natural gas front month prices have now recovered sharply from their earlier lows, our second-quarter realized natural gas and liquid pricings have decreased significantly from the first quarter of the year. While we believe that liquids pricing will return to historical levels relative to crude oil over time, it is clear that the industry's focus on liquids-rich drilling has impacted short-term supplies of certain products.

This type of volatility does impact the economics of certain types of drilling activity and adds complexity to spending and development plans. At Swift Energy, our strategy of diversification, both geographically as well as across commodities, allows us to exploit acreage that benefits from the strongest commodity prices, even with reduced spending and activity levels.

Operational highlights of the second quarter include drilling three new wells in Lake Washington and completing three wells in the field. This activity has almost entirely halted earlier period production declines in the field and has opened up several new areas of prospectivity for future development. Results in Lake Washington to date support continuing our drilling program, and we now expect to drill up to 10 wells there this year from a prior target of 6.

In the South Burr Ferry field in Vernon Parish, Louisiana, our partner tested one well during the quarter with greater than expected results. A second well has been completed early during the third quarter, and initial test rates on that well are showing 979 barrels of oil a day and 7.5 million cubic feet of natural gas per day, with a flowing tubing pressure of 6,300 psi on a 25/64-inch choke, a very nice well.

In South Texas, we entered into a long-term agreement for natural gas gathering and processing services in La Salle County, Texas. With much of our 2012 drilling activity focused on our crude oil and liquids-rich acreage in La Salle County, this particular agreement was very important to our plans. As we continue to mitigate third-party risk from our program to these long-term agreements, we can focus even more closely on improving and optimizing our drilling and completion practices.

Also at South Texas, our operating pace remained at a high level, with six rigs running during the quarter. 17 wells were drilled, while our completion team brought 14 new wells into service. Our first of several multi-well zipper frac operations was conducted on a two-well pad site in La Salle County. This type of innovation allows us to continue to reduce our cost, even as we reach new technical efficiency goals with drilling and completion activities.

In addition to reducing cost in the second quarter, we are also drilling more wells and completing more fracture stages than we had earlier anticipated with our contracted drilling rigs and fracture stimulation spread. Through June 30, we had drilled 32 wells in South Texas, with four rigs operating today. I want to stress that. We are already at four rigs operating today and anticipating three rigs to be operating in the fourth quarter. We will drill approximately 19 wells in the second half of 2012. Even as we drill longer laterals than we had originally budgeted for, planned, and designed for because of our operating efficiency, this will be four to five more wells than we had originally planned to drill in the area for this year.

This increased well count helps keep our fracture stimulation crew fully utilized. Our completion crew increased the number of stages it completed in the second quarter to 227 stages, up from 188 in the first quarter. This is a remarkable achievement and improvement in efficiency over a short period of time, and highlights the benefits of operating in a pure development mode.

Additional activity in South Texas and southeast Louisiana this year will add to our capital expenditures, which we believe is the correct course of action, given the results we are seeing. This additional activity will further support production growth through this year and into next year, as we moderate activity and spending in anticipation of persistently weak hydrocarbon pricing. We also expect to increase our reserve growth this year, and we now have guidance to a range of 15% to 20% increase, up from our prior guidance of 10% to 15%. This is a result of all the additional activity.

Reserve additions this year will primarily consist of crude oil and natural gas liquids. We now expect the percentage of our total reserves that will be crude oil and liquids to be approximately 40%. We also expect our year-end daily production mix will be greater than 50% crude oil and natural gas liquids. We will spend more in the aggregate during 2012 than previously anticipated, but we will have better reserve results, and we already have altered the trajectory of our spending levels and dramatically reduced our rig activity and spending levels in South Texas in the third quarter. These levels will be reduced even further in the fourth quarter.

Please be mindful that our cash flows are also improving as our production rises and as we are seeing better oil and gas pricing. We also move into the fall and begin to formalize our budget for 2013. We maintained a significant level of flexibility. Our activity in all areas is yielding good results, and we have ample liquidity to allow us to make the best short-term decisions to reach our long-term goals.

We expect that no matter how conservative or how aggressive we decide to be with our initial spending plans relative to cash flow next year, we will grow our crude oil and liquids production and reserves in 2013. Swift Energy Company is an exceptional position in terms of our assets, as well as our financial management. We believe that we are just beginning to deliver the types of results we expect to achieve for a long time to come.

Now, I will ask Alton to present our second-quarter 2012 financial results.

Thank you, Terry, and good morning, everyone.

As Swift continues its focus on oil and liquids-rich projects with excellent results, low natural gas prices continue to impact our financial results. Our production increases of 11% from 2Q '11 and 4% from 1Q '12, all weighted toward oil and liquids, did, however, help to mitigate the effect. For the second quarter of 2012, oil and gas sales were $132 million, while hedging gains resulting in additional income of $2.6 million. Net income came in at $3 million or $0.07 per diluted share, cash flow before working capital changes for the quarter was $1.69 per diluted share, and 2Q '12 production was 2.92 million barrels of oil equivalent, above the high end of our quarterly guidance.

Crude oil prices were down slightly from the second quarter 2011 levels, while natural gas prices were cut in half from 2Q '11, with an overall 25% decrease in our realized price per BOE in 2Q '12 versus prior year. As Terry pointed out, the second quarter of 2012, approximately 74% of our oil and gas revenues were from crude oil, and 86% of the total came from crude oil and liquids sales. As to our controllable cost and metrics compared to guidance, production costs came in at $10.10 per BOE, on the low end of guidance; G&A came in at $4.18, slightly below guidance; DD&A was also below guidance at $21.40, due to the higher reserve volumes in the improved cost efficiencies.

Interest expense came in at $4.56 per barrel, again on the low end of guidance, and production and ad valorem taxes were just slightly above guidance at 9.1% of revenue. As previously mentioned, the net result from all of this was income for the quarter of $3 million, $0.07 per diluted share, well above the first column mean estimate. Our effective income tax rate for the quarter was 40.8%.

Cash flow before working capital changes, again for 2Q '12, came in at $73 million or $1.69 per diluted share, while EBITDA was above $81 million for the quarter. Quarterly CapEx on a cash flow basis was $187 million, again in line with previously discussed plans. With the high pricing volatility, our hedging activity added $2.6 million of revenue during the second quarter, while the recent -- while with the recent strength, we've been able to layer in some natural gas floors for the third and fourth quarters. Please see our website for complete and current detailed oil and gas hedging information.

As of the end of the second quarter of 2012, we had no outstanding balance on our line of credit and had $32 million of cash on hand. Natural gas and NGL prices in the near-term pose a challenge to our sector, though as Terry mentioned, recent improvement in both are positive signs.

With our quarter-end liquidity, our inventory of liquid-rich projects, and approximately 86% of our revenues coming from oil and liquid production, we are very well-positioned to execute our 2012 and forward strategic plans. As always, we've included additional financial and operational information in our press release, including guidance for the third quarter and full year 2012.

With that, I will turn it over to Bruce Vincent to begin the discussion of our operations.

Thanks, Alton.

And good morning, everyone, and thanks for listening. Today I will discuss second-quarter 2012 activity, including our production volumes, our recent drilling results, activity in our core operating areas, and our plans for the third quarter and full year 2012.

Beginning with production, Swift Energy's production during the second quarter of 2012 totaled 2.92 million barrels of oil equivalent, above our previously issued expected range. Second-quarter production was 11% greater than the second quarter 2011 production of 2.64 million barrels of oil equivalent and increased 4% from the 2.8 million barrels of oil equivalent produced in the first quarter of 2012.

For our second-quarter drilling results, Swift Energy drilled 20 operated wells during the quarter and participated in 2 non-operated wells. In South Texas, 14 operated horizontal development wells were drilled to the Eagle Ford Shale formation in South Texas, and 8 of these wells were drilled in La Salle County and 6 in McMullen County. Three wells were drilled to the Olmos formation, all in McMullen County. In Swift Energy's southeast Louisiana core area, three wells were drilled in the Lake Washington field.

In the Company's Central Louisiana and East Texas core area, two non-operated wells targeting the Austin Chalk were drilled in the Burr Ferry field. We currently have four operated drilling rigs in our South Texas core area, drilling Eagle Ford shale wells. We also have one operated barge rig drilling in our Southeast Louisiana area, and two non-operated drilling rigs are active in the Central Louisiana/East Texas area.

In the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields, production during the first quarter averaged approximately 6,289 net barrels of oil equivalent per day, which is down 2% when compared to the first quarter of 2012 average net production from the same area. Lake Washington averaged approximately 5,927 net barrels of oil equivalent per day, a decrease of 2% when compared to the first quarter 2012 average daily volumes.

Drilling activity in Lake Washington in the first half of 2012 has brought new wells online, and these new wells are mitigating the natural production declines. As Terry indicated, we now plan on maintaining our one-rig drilling program for the entire year. Additional wells from this program should allow for a relatively flat production profile in Lake Washington for the rest of 2012.

Bay de Chene's sequential production decline decreased 26% to 362 net barrels of oil equivalent per day. This sequential decline is due to no new drilling activity and natural declines. In our South Texas core area, which includes our AWT, Sun TSH, and Las Tiendas/Olmos fields, and AWP Artesia wells and Fasken Eagle Ford fields, second quarter to 2012 production averaged 23,313 net barrels of oil equivalent per day, a 6% increase in production when compared to first quarter 2012 production in the same area and a 56% increase over second quarter 2011. The sequential increase is primarily from newly completed wells and production optimization projects that came online during the quarter.

Earlier this morning, we published specific information on wells brought online during the quarter in our quarterly press release. We continue to see well performance improve as we extend the length of our laterals and increase the number of frac stages per well. Bob will detail what we are accomplishing with multi-well drilling pads, longer laterals, and zipper frac completions. As result of our drilling performance in South Texas, particularly our shorter than expected drilling times, we intend to drill four to five additional wells beyond what our original capital budget contemplated.

While this does add spending to this year's program, we believe the increased production rates we experience as result of additional wells will improve our cash flow profile in 2013 and allow us to better align our spending with our cash flows. We also expect to add additional crude oil and natural gas liquid reserves associated with this additional activity.

The Central Louisiana/East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry, and South Bearhead Creek fields, contributed 2,407 barrels of oil equivalent per day of production in the second quarter of 2012, an increase of 22% over first quarter 2012 production in the same area. Higher production levels in this area are due to the non-operated wells at Burr Ferry during the second quarter.

I will now turn the call over to Bob Banks to review operational highlights for the fourth quarter.

Thank you, Bruce.

At the Lake Washington field during the quarter, we completed 10 wells and performed 12 production optimization projects, which includes sliding sleeve shift changes, gas lift enhancements, and returning shut-in wells to production. We drilled three wells during the second quarter at Lake Washington and expect to drill up to five wells in the second half of the year. We also completed three wells at Lake Washington during the second quarter.

The initial production test of these completions are detailed in our press release issued earlier this morning, but I would like to highlight that these three wells, along with our most recent well, have logged an average net vertical pay of 210 feet across seven production horizons throughout different parts of our field. Two of the wells have logged deeper pay intervals that continue to encourage as we explore on the flanks of this great salt dome. Based on our first-half results, we have decided to keep one rig active in Lake Washington for the remainder of the year and drill up to 10 wells in total.

In the Central Louisiana/East Texas area and South Burr Ferry field, the non-operated GASRS 23-1 well was completed in the Austin Chalk during the quarter. Initial production rates of this well were 744 barrels of oil per day and 7.2 million cubic feet of gas per day, with flowing tubing pressure of 4,100 psi on a 34/64-inch choke. A second non-operated well, the GASRS 29-1, was also completed.

Initial production test rates on this well were 979 barrels of oil per day and 7.5 billion cubic feet of gas per day, with flowing tubing pressure of 6,300 psi on a 25/64-inch choke. These well results support our belief that the Austin Chalk project area has the potential to be a very meaningful growth area for us.

Two non-operated wells are currently being drilled in the Burr Ferry area, and we anticipate up to two additional wells to be drilled, for a total of six in this area for 2012. Also in this asset area, we are continuing our appraisal of the Wilcox acreage in Beauregard Parish. This appraisal work includes evaluating horizontal drilling potential in South Bearhead Creek, performing base optimization optimization work, and evaluating workover and recompletion opportunities.

Moving to our South Texas area, nine Eagle Ford horizontal wells and five Olmos horizontal wells were completed during the second quarter. In the morning's press release, we included a table highlighting all the data from these completions. We do continue to optimize and adjust our completion and production techniques as we bring more wells online across our acreage.

Production and performance data we have collected to date leads us to believe that we can continue to improve well productivity into the future. We've also determined that extending the length of our horizontal laterals and increasing the amount of frac stages per well will result in higher rates of production in hydrocarbon recoveries per well. Where it is possible, we are drilling our lateral lengths to approximately 6,800 feet, which will support up to 20 frac stages.

Another benefit of longer-term production data is the determination that in certain portions of our acreage, we may be able to further downspace our drilling locations. To test this concept, we will be drilling two 60-acre tests on our acreage this year. To date, we have only drilled down to 80-acre spacing, so successful downspacing tests would immediately affect our potential drilling inventory, resource potential, and asset value.

As Terry mentioned, the amount of frac stages our completion crew executed in the second quarter increased 21% from the first quarter to 227 stages or an average of 76 per month. This improvement was driven entirely by improving the efficiency of our equipment and continuous improvements made to our completion process.

In July, we completed our first two-well pad location using what is known as the zipper frac technique. This technique allows us to simultaneously complete two wells. Using this process, we expect to complete two wells in approximately seven days, which is almost a 50% time saving from the standard five days that it takes us to complete an individual standalone well.

Now, to quantify the impact of this technique, we completed 93 stages during July. That's up dramatically even from our record second quarter productivity, up over 20% again. So use of the zipper frac is an innovation that we are just beginning to employ, but will utilize much more of as a greater proportion of our wells are drilled on multi-well pads.

As we have previously disclosed, our 2012 work program and budget called for reducing activity in South Texas from six to five to four rigs as the year progressed. We did have an unexpected opportunity to utilize a rig we were familiar with for a period of time during the second quarter, which we did take advantage of. This rig, which has now been released, was originally scheduled to be utilized in the fourth quarter, so this change to our schedule resulted in a higher capital and activity level in the second quarter than planned and will result in Swift Energy running only three rigs by year end, as opposed to four.

As Terry noted, while we have reduced rig activity in South Texas, we are ahead of our schedule relative to the amount of wells we had expected to drill this year, due to this rig timing and the efficiencies that we talked about. Our operating drilling rigs are under contract through the end of this year, and we will keep them fully utilized and drill more wells than originally planned in South Texas this year. While we will effectively be bringing wells and capital from our 2013 program into 2012, we will also be adding production rate and liquids-weighted reserves in 2012, as well.

Additional activity this year is particularly important, as we intend to manage our capital spending in 2013 at levels more closely aligned with our realized cash flows. We have determined that with a three-rig program in South Texas next year, along with unchanged levels of activity in Lake Washington and our Austin Chalk project areas, we can still grow primarily crude oil and natural gas liquids production in line with our longer-term strategic growth targets.

Before turning the call back to Terry, I believe it is very important to share with the audience that we believe operating between five and six rigs in South Texas over a 12-month period maximizes all of the cost and operational efficiencies that we have realized, given the performance of our drilling rigs and fracture stimulation crew. Sustained activity below this level may result in periods of time where our fracture stimulation spread will be idle and will add an element of lumpiness to our production growth that we are not currently experiencing.

We are on track for a record year as measured by production and reserve volume, and I have every reason to expect to repeat that statement next year. Our premier assets present a balance of crude oil and liquids-rich natural gas development opportunities. And, as our current resource development projects mature, we are going to add new play areas and projects into our portfolio.

With that, I thank you for your attention this morning, and I'm going to turn it back to Terry to recap.

Thanks, Bob.

Before we open the line for questions, I will summarize Swift Energy's second-quarter results and review some of the highlights from today's call. Second-quarter production growth of approximately 11% over second quarter 2011 production. Additional drilling activity in our South Texas and Southeast Louisiana core areas. An increase in expected year-end 2012 reserve levels from a previous guidance of 10% to 15% increase to the new guidance of 15% to 20% increase. Year-end 2012 reserves are expected to be approximately 40% crude oil and natural gas liquids. Year-end daily production is expected to be greater than 50% crude oil and natural gas liquids.

227 frac stages completed during the quarter in South Texas, or an average of 76 per month. In July alone, we completed 93 fracture stages. Our first multi-well pad completion was performed during the quarter. 74% of our revenue was derived from crude oil production. Fourth quarter average daily production will be approximately 55% crude oil and natural gas liquids production, up from 45% in the first quarter of this year.

With that, we'd like to begin the question-and-answer portion of our presentation.

(Operator Instructions)

Your first question comes from the line of Neal Dingmann.

Good morning, guys, and great color this morning.

Maybe Bruce, for you or Terry -- one of the guys -- just looking at those initial results that you all put out. And it looks like that some of these -- the Eagle Ford wells and La Salle have a little bit more gas, NGL mix to them versus oil. Is that kind of as you were expecting, and now that -- again, now that you've drilled a number of these La Salle and Webb County Eagle Ford wells and a number of Olmos wells -- when you see the go forward, is there one area you are going to be targeting here for the remainder of the year and early next year that might have a bit more oil? Or how are you going to approach that?

We will let Bob answer that.

Neal, in terms of the La Salle County acreage, there are really some transitional areas in terms of gas/oil ratio from more of our northern acreage coming down into the southern acreage. The wells that we are reporting here are a little bit down into the southern side, so those tend to be a little bit more natural gas liquids-prone than some of the ones further to the north. So, we really have about three very specific models coming from north to south across that acreage. So, I wouldn't extrapolate that across all of the acreage. That's more in our southern area.

Okay. And do you see -- staying with that same acreage, now with these zipper fracs, and I assume going forward, you'll see some more pad drilling -- what do you anticipate on, and if you even stay at this lateral length, do you anticipate well costs coming down just because of efficiencies? Or is the oil service prices coming down? Or if you can just comment on the well cost?

Yes, I sure will. We are doing really good out there, even with the increase in the guar pricings that we've all been hearing about. We are actually -- I think when we had Analysts Day, we talked in terms of those 5,000-foot laterals in that area being in the $6.8 million to $7.2 million range before the guar increases. Well, after the guar increases, those two wells that we just reported on, we drilled those under $7 million. So even with that guar increase, we are managing our well cost to the lower side.

We have brought into the rig fleet a state-of-the-art walking rig, and so we actually expect even further efficiencies as we start getting into multiple well pads in the future in that area. So I think you can see, even from that below-$7 million number for a 5000-foot lateral, I think we can squeeze that down even further.

Okay. Two more, if I could.

Just on Lake Washington and just one on -- maybe I missed this -- besides the wells that you're going to be drilled, the additional wells, how do you see as far as additional opportunities for recompletes and other opportunities to boost production that way?

On the recompletes, I think we have a whole stack of recompletes sitting there in inventory, I think, as we try to show you at Analyst Day from time to time. We do maintain a rich inventory of recompletion projects. A lot of it really depends, as I mentioned during the call, when we drill these wells -- as an example, the last four wells we drilled, we had seven pay intervals on average. And so we typically start producing the wells from bottom up. And so the recompletion opportunities are really the behind-pipe reserves that you just wait until the sand you're producing out of starts to become uneconomic or plays out. Then it is time to move up-hole and recomplete the next zone.

So, to a certain extent, we are watching Mother Nature help determine our schedule on when to execute those production optimization projects. But we do have a number more we are going to do this year in parallel with the drilling activity.

Okay. Last one, if I could. Just quickly on hedges, either to Alton or Bruce -- wondering, you mentioned all the volatility you're continuing to see in the NGLs, and even, you could say, with even gas prices themselves. Any thoughts about putting additional hedges on just a -- not, obviously, prices aren't great yet, but just to take some of that volatility out?

Absolutely. You can see we've put on some floors for natural gas here just recently; and I think, given the market conditions, we are absolutely looking for an opportunity to do more of that. Clearly, the market has not been something that you would want to go out along on the gas side, but we've seen it strengthen. And as we've done so, we've started putting floors in place, and expect us to continue to do that if the market allows us to.

Perfect. Thank you all. Great quarter.

Thanks, Neal.

Your next question comes from the line of Kyle Rhodes.

Hey, guys.

Hey.

After dropping the three rigs in the fourth quarter, what are you guys modeling in terms of run rate cash back? Is $120 million to $130 million in the ballpark?

Yes, I think it would be easy to try to extrapolate a fourth quarter spend into all of 2013. It is not going to work exactly that way. As we ramp down, we do have an inventory built up of wells ready to be fracked and completed and brought online. So as we work through that inventory, that ramp continues down into the first quarter of 2013. So, while I think some people would like to talk in terms of $150 million, I think it is going to be less than that going into 2013 as we prosecute that inventory.

Yes, I think I'd like to add -- this is Terry.

It is really early to be giving guidance for 2013. And though we certainly respect the concerns that folks have out there, we are looking at these issues as well, because these are long-term development activities. We've got multi-year projects in front of us. I think we'd like to just assure you that next year, we are going to be very balanced between cash flow and capital spending. That's certainly our strategic objective.

Okay, thanks.

And then, is there a price oil could hit over the next three months that would cause you to reconsider dropping the three rigs in the fourth quarter?

Absolutely. I think if oil climbs enough and we see the cash flow available, we absolutely could go to an extra rig.

Yes. I think that's the flexibility that is built into our programs right now. Clearly, we're going to watch this market. You don't do things on a single-day basis, but you can anticipate 90 days out changing things if you've had a sustained increase in prices. I want to emphasize that it would need to be sustained.

And recognize that our preference would be to do that, but you'd have to have the cash flow to convince yourself to make those decisions.

Fair enough, guys. Thanks.

Thanks, Kyle.

Your next question comes from the line of Noel Parks.

Good morning.

Good morning, Noel.

I just had a couple of questions. Earlier in the call, you were talking about how at Lake Washington, the wells you drilled there, if I understood right, they pointed toward some additional prospects out there. Can you just talk some more about that?

Yes, I will just say that of those four wells that were mentioned in our morning release, two of them were on our west side, different positions of the dome. And the other ones are more northeast and east in parts of the dome. So, yes, part of the program has been designed to test areas that do lead onto additional drilling on these parts of the dome that we have not been working very heavily in the past couple of years. So we are very encouraged, not only with the shallower to medium-level production horizons, but as I mentioned, we have a couple of those wells that went into deeper sands and logged net pay. And so those deeper sands really encourage us to continue to move down-flank on this world-class asset, and continues to amaze us how much pay is really out there.

Lake Washington continues to be one of these areas where you could drill a low-risk development well but design in what we'd call an exploratory tail for very minimal dollars. Very nice area to be working.

Great.

Moving out to -- you were talking about something I had forgotten about, which was Wilcox potential, in and around the South Bear Head Creek. Could you just talk a little bit more about that, as it is an area I hadn't focused a lot on?

Yes, well, it is a great area. It is not an area we've done any horizontal drilling in. We have drilled vertical wells in that area. But we think with the technologies that we're utilizing and have developed down in South Texas with some of the horizontal drilling tools and completion tools that we are using, we really think it is well-suited to horizontal development drilling. And we really intend to test that concept in early next year. But we are pretty encouraged, using the knowledge we've developed in South Texas as to how we could deploy that in that area.

And would you expect those would be gas or oil? And if gas, what sort of cost structure do you think you would be looking at if those worked?

Well, this is primarily an oil area, very good oil. In terms of well costs, I don't think we are ready to throw numbers around at that yet. There's a lot of well design, a lot of planning going on right now concerning whether it's going to be an upper Wilcox test or lower Wilcox test. So, we are still in the design phases of that, so I think we will be back to you here; maybe next time talk a little bit more about that.

Great. Just one more housekeeping thing.

Of the increase in the budget that you've talked about, about how much of that is Eagle Ford/Olmos, and then how much of that is Lake Washington?

I don't know that we have the numbers right here, but suffice it to say, pulling those operational efficiencies we talked about in the call, bringing more wells in, in South Texas. The majority of it is going to be in South Texas, but clearly some of it is in Lake Washington, because we are, as Terry and Bruce mentioned, drilling a few more wells there than was in the original budget. But I don't think we have the exact split. Probably more heavily weighted to South Texas right now.

Great. That's it for me. Thanks.

Thanks, Noel.

Your next question comes from the line of [Yitzhak Fall]

Good morning. Congratulations on a great quarter.

Thank you. Good morning.

Good morning.

Anyways, my first question -- I guess from what I understand, the reason for the decrease in the rig counts is to wait for the fracture crews to catch up in terms of completing inventory. Can you give us a sense of what the backlog is right now at Eagle Ford?

Two things -- let me just preface that -- the real reason for the decrease in rig count is really to get capital spending better in line with cash flow. I will let Bob specifically address the backlog, though, because that is part of it, but that's not the driver. The driver is really capital spending versus the cash flow.

Yes, just to address the backlog issue -- we really right now have about 11 ready for fracking operations. So, when we have a nice inventory of projects there, and with these completion efficiencies that we are talking about, we think we can prosecute that backlog very quickly.

How many wells do you think you could complete in the quarter? Is that 14 number that we saw this quarter a good run rate?

Yes, we actually were on -- we reported on the two-well pad. We are actually now on our fourth two-well pad. We also mentioned we are drilling longer laterals. I don't have the exact number for third and fourth quarter for you; but suffice it to say, our efficiencies are improving like crazy. So I don't think we're going to go backward in number of wells we are completing.

But it is also dependent upon whether we are doing pad drilling and completing wells on a pad, because you do them quicker than you do if you have to move it to further away. A lateral length, number of stages within that lateral, but 14 is probably a good number to use. But there's a lot more involved in it than just well count.

I see. And then, just one final question.

Can you give me a quick update on Masters Creek? I think you guys drilled that one infill well in the first quarter -- is that still holding up? And what are your thoughts in terms of activity there in the back half of this year and going into '13?

We don't really have any plans to do anymore infill drilling. Yes, it is still producing -- the well we reported on. But the results we are getting from our Burr Ferry area are so extremely positive and economic that we are really choosing to spend our capital there preferentially right now.

And we're having to pull capital back, as it is, from South Texas from a level that we would like to spend at because of reduced cash flow. So, Masters Creek is kind of losing out in terms of the capital allocation.

I think the good news is that it was a proof-of-concept well. We definitely proved that you've got infill opportunities there. The bad news is, gas prices went down so hard and fast on everybody that you do have to be very aware of how you allocate capital right now.

And one other thing is, that's all held by production acreage, so we are not pushed to drill there.

All right. Thank you so much.

Your next question comes from the line of Dan [Teske].

Hi, guys. Thank you for taking the call. Two questions for you.

The first one is, you guys have 2017 bonds that are currently callable, and the capital markets are wide open. Do you have any thoughts on potentially addressing those and then also increasing your liquidity to fund potentially increased CapEx?

The second question is, it looks like on a number of metrics, your Company is undervalued versus peers. How do you plan to close that value gap?

This is Alton. I will answer the first question.

Obviously, we like the rate that those 2017 bonds have. So we hope that we are talking to you about refinancing those, because that would mean the rate we could get longer-term would be better than that. That's a low 7% bond, as you are aware.

So, with respect to our liquidity, we are in good shape, as we mentioned. Dry powder at the end of the second quarter, actually cash in the bank. We've got a good bank group. We've got a solid bank line of liquidity that's available. We've really haven't pushed that borrowing base up. It is currently $375 million. We think at the next redetermination in November, it should be significantly up from there.

We are good shape, have dry powder. We can handle any of the activity we've got. But as we've indicated in this call -- hopefully you've gotten the signal -- we are never one to get too far out over our skis. So we've got the liquidity, if we need to ramp it up a little bit.

In terms of the value gap and closing that gap, it disappoints us in terms of our valuation out there. And obviously, we have a number of things that we are trying to do to do that; but number one thing is to perform. When we have talked to investors, their concern was whether or not we could actually do what we are say we are going to do. We've now had three quarters in a row of being in the high end or slightly over the high end of guidance, and we are delivering the oil and liquid growth which was a concern that a lot of people have. If you look at our guidance into the third quarter, we will continue to do that. Actually, if you look at it for the full year, we will continue to do that.

The feedback we've gotten is, people need to see that we can do what we say we're going to do. We believe that we are doing that. We need to continue to do that. We need to continue to get out there and tell the story and convince people that we are going to do exactly what we say; that we are driving the liquids side, both reserves side, both production side. And you're ultimately going to see that reflected in the valuation.

Okay. Thank you.

Thank you.

Your next question comes from the line of Curtis Trimble.

Everyone, just wanted to drill down a little bit in terms of the nice increase in completion stages, and see if you had some measurements on yield per stage, if you will, over the last handful of wells, vis-a-vis where you were at, say, the end of 2011?

Curtis, no, we don't have those numbers here in front of us. We're looking at that all the time, but we are also altering a number of things with frac stages and lateral links. Yes, and all the NPT. So, we don't have numbers like that. We are --

We don't have them here available.

Available. Yes. We do review this very closely with the teams on a quarterly basis. I would say, certainly at the next Analysts Day, we will have a lot of data to present on that. We may be able to make some data available on that prior to that time, but don't have that type of reconciliation for you here today.

I think we showed some information on, like, cost per stage and how it was coming down at the Analyst Day. And a lot of that has to do with any number of small things that cumulatively add together, driving costs down, coupled with a significant reduction in non-productive time. The trend really is continued, and I think if we were to put out the additional information on that, we will look for an opportunity to do that. You would just see our ability to continue to be more efficient.

Okay. Just looking at in a less granular way, that $7 million well cost you talked about it, is that a good average go forward, even with the extended laterals and the increase in completion stages?

Well, no. I think that was under $7 million that we are talking about. Those were around 5,000-foot laterals. So as we get up into the longer laterals, I think we showed you a model at Analysts Day of about a 6,000-foot lateral of the $7.2 million to $8.2 million range. I think the takeaway from what we told you about our 5,000 is, even with the guar increases, the efficiency capture that we've been able to get, we are kind of on the low end of those ranges, even with that guar increase. If you just go back to those, I think even the longer laterals, we're going to be on the low side of that $7.2 million to $8.2 million range that we gave you.

Good deal.

Also, just getting a little bit of idea of, let's call it near-term production history on the Austin Chalk. Can you talk in terms of a 30-day rate or some of the wells that had been on a little longer and how pressure is being managed there? And maybe some reserve estimates for what you've seen out of the handful of data points you've got?

Well, It is still early. I think we showed you the very first two wells that we drilled in the Burr Ferry area, how they stood up very nicely, unlike a lot of experience in Austin Chalk and Texas and other places. So, these two wells are still pretty new. This last one is just very new. So I think by next call, we will be able to give you a little more look, like we did on those first two wells; and we really expect these two wells to be holding up in a similar manner to the first two wells.

I think there's nothing that we know that would cause us to expect it to be significantly different than the other wells that we showed you. The decline curves on those were put on production in fourth quarter 2010, so we had a lot of good history. One of the things that helps mitigate decline on that -- there's a water drive component to those wells, and we would expect those probably to produce at similar decline curves.

And I think as we talked to you about those first two wells, we paid them out in six months. We don't expect these to be any different, really.

And just an overall statistic -- not for the first several wells we've drilled, in fact, we are more than happy with those -- but to go into that play in general in that area, you are targeting in excess of 500,000 barrels per well, up to 1 million barrels a well. It's a very high-quality type of play that doesn't need the actual fracture stimulation. So, that piece of it you don't have to manage or fit into the picture.

Good deal. One other little data point.

Can you tell us what portion of the Eagle Ford you're going to try your 60-acre test on?

The 60-acre test is going to be cut in that northern La Salle County oilier area, is where we are going to go to that first test.

Perfect. I appreciate it.

Thank you.

Your next question comes from the line of Gordon Douthat.

Good morning, guys.

Hello, Gordon.

My question revolves around 2013 CapEx. I know you don't want to provide guidance, but just trying to see if my thought process is correct. On a per-rig basis, what is an annualized CapEx rate that you guys are currently experiencing in South Texas?

Currently, as to third quarter --

On an annualized rate, maybe $100 million, in the ballpark.

If you just take that $7 million, multiply it times a well a month. That's where that is. If we drill longer laterals, maybe it is more like $8 million times a well per month. So you can kind of -- per rig -- so you can kind of figure it out, depending that way whether we are drilling the longer laterals or more of the 5,000-foot laterals.

To be clear, I know you're trying to fill in your models, we are not talking about just the rig cost here. You're talking about one rig running for a full year, what's that burn rate. So that range is $80 million to $100 million.

It is all in, yes.

Okay. So ballpark, three rigs next year, $300 million roughly.

In South Texas.

In South Texas, yes.

In South Texas. And then you've got Austin Chalk, Burr Ferry, and Lake Washington. So, adding all those pieces together, does that get you to like a $450 million, $500 million range? Am I thinking about that correctly?

Yes. You're thinking correctly, but I want to emphasize, we are not ready to provide guidance for 2013. There are still a lot of dynamics in terms of what the pricing will be next year, but we are saying that we are reducing our capital spending. We have already done that. By year-end, we will have brought it down to three rigs in South Texas. And depending upon how prices have gone and how the results have gone -- and by the way, we are getting some great finding cost results. So that's got to be factored into how you are looking at us. We could have a minimal program next year and still deliver what we think is very substantial production growth.

Okay. I think it looks good from my standpoint.

What percentage of wells will you be drilling on longer laterals going forward in South Texas?

Yes. I guess if we were just to thumbnail, we have these very specifically scheduled out, but it is probably in the 50/50 range. We design our laterals into our lease position. Where we can get the longer laterals, we drill the longer laterals, but it is all tied to how we want to develop, delineate, and hold our lease structure against those lease boundaries. But I would say about half and half, long laterals to more normal laterals.

Okay. And then -- let's see -- the La Salle County firm transport you announced a couple weeks back, that goes into effect in the fourth quarter, if I understand that correctly.

No, that went into effect in June.

It graduates, the volumes graduate, and then they ultimately decline, so that it matches the production profile of the drilling activity.

Okay. So the portion of interruptible capacity will be reducing between now and the fourth quarter?

It will be reducing.

It is tied to our ramp-up of drilling.

Okay.

We don't have any interruptible now.

Just to clarify that -- it is basically -- we have a de minimis amount of interruptible right now. It is a very tiny part of this production stream.

I think where you are seeing most operators, including ourselves, have agreements in place. But sometimes midstream players either have issues going on with their pipeline or issues going on with the processing plant, and those have caused various interruptions for people, sometimes insignificant, sometimes significant. We've had small stuff, but nothing significant of recent. But we have had that last year, you may recall.

So it looks like you've got that -- at least that leg of the stool locked up

Yes, we do.

Okay. Very good.

Then, with the three rigs, or once you get to the three rigs, where do you plan on having those drillings? Do you have them just hopping around various areas in South Texas, or do you have a specific layout plan?

Yes, we have a very specific layout plan, actually, probably for the next three years. But for next year, you will see a lot of drilling activity in the oil and liquids-rich areas of La Salle County, as well as those same areas in McMullen County.

Okay. And then at Fasken, I know you've got it held by a production right now. At some point do you have to return to drilling there to continue to hold that lease?

No. We've earned all that position -- all locked up.

We've earned it as long as we are producing, and those wells are going to produce a long time. There's no obligation on there for many years out. The gas market will come back well before we ever have to worry about that.

Okay. Thank you very much.

Your next question comes from the line of Kyle Rhodes.

Just a quick follow-up.

You guys said your backlog in the Eagle Ford was about 11 wells right now. Where do you have that by year-end?

By year-end? I think by year-end, we will probably be down to a couple. With pulling back the rig count and the efficiencies that we are seeing out of our frac crews right now, so we will go through that by the end of the year.

Probably a couple by year-end, and then work that first quarter -- is that right?

Right.

Okay. All right. Great. Thanks.

Your next question comes from the line of Michael Hall.

Thanks. Good morning.

Good morning.

Let's see. I guess one question I have is -- it seems like you've clearly done a good job executing here in the first half, come in high end of your range each quarter or better. Why not take a step higher on full-year guidance? Is there anything lingering out there on your end that's keeping you from doing that? Or is it just an effort to stay conservative and better to underpromise and overdeliver?

I think there's just a lot of variables out there, many of which aren't under your control; most of which have to do with timing. I think the important thing is that we don't see performance issues affecting our production profile at all. We do see timing issues affecting production profile. Third-party issues can affect production profile. But well performance is not.

I think we just would like to stick with what we have seen in the beginning of the year, and that's what we see happening. We are hesitant to take it anywhere beyond what we see.

I think I'd add to that, that the one thing that we did change, we really want to highlight that we feel very confident that in our reserve additions this year and how we are going to close out the year, not only with better reserve results, but also stronger liquids mix within there. That is probably the fundamental thing that we are ready to change right now.

Got you. Clearly positive.

In McMullen, as I'm just kind of looking through the update, looks like all the wells there were focused in the Olmos. Any particular reason no Eagle Ford wells during the quarter? And as I recall, you had a pad that you were drilling there. When is that planned to come on?

Yes, the big area in McMullen that you are going to see next, we have a four-well pad up at our SMR lease, and we are going to be doing that simultaneous operation here about mid-August. You will see a lot of results coming out of that area. We pushed that back to really make sure we got the zipper frac technique down over these two-well pads. Plus, we had to actually expand our SMR facilities to handle the production volumes that we are going to get out of that four-well initiative. So, we did a little optimizing there.

That four-well pad has actually been ready to complete, but we pushed it back because we were expanding the facilities up there. In order to test it, we would've had to spend about $2 million to put test equipment in there, and that didn't make any sense. We had plenty of other wells that we could fracture stimulate and move forward, so you will see those results when we talk about third quarter.

Yes. And just to kind of bolt on to close the loop -- of those 11 that we have in inventory we mentioned, 10 of those are Eagle Ford. And only one of those is Olmos. It's just the timing of when we are releasing data in the quarter.

Okay, kind of figured that was the case. Great. And I think the rest of mine have been answered. Appreciate it.

Thanks, Michael.

There are no additional questions at this time.

Okay. We'd like to thank you for listening in to our second-quarter 2012 conference call, and look forward to getting together with you again next quarter. Thank you.

Thank you.

Ladies and gentlemen, that does conclude today's call. Thank you for your participation. We do ask that you disconnect your lines at this time.