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Swift Energy Co. (NYSE:SFY)

Q2 2012 Earnings Conference Call

August 02, 2012 10:00 AM ET

Executives

Paul Vincent - Director, Finance & IR

Terry Swift - Chairman & CEO

Alton Heckaman - EVP & CFO

Bruce Vincent - President & Secretary

Bob Banks – EVP & COO

Steve Tomberlin – Senior VP, Resource Development

Jim Mitchell – Senior VP, Commercial Transactions & Land

Analysts

Neal Dingmann - SunTrust Robinson Humphrey

Kyle Rhodes - Hester Capital Management

Noel Parks- Ladenburg Thalmann & Company Inc.

Unidentified Analyst

Dan Keski - Analyst

Curtis Trimble - MKM Partners

Gordon Douthat – Wells Fargo Securities

Michael Hall – Wells Fargo Securities, LLC

Operator

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

Paul Vincent.

Good morning, I’m Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy Second Quarter 2012 earnings conference call. On today’s call, Terry Swift, Chairman 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 approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift.

Thanks, Paul and thank you everyone for joining our call today. Swift Energy’s emphasis on crude oil and liquid’s 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 to which our capital expenditures would outpace our current cash flows and when necessary 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%-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 look forward in the future of hydrocarbon pricing and the uncertainties that it has as well as the general macroeconomic environment. Our longstanding 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 and external environment as we all currently face. Although we realize the greatest cost effectiveness in our operating program when we’re at higher activity levels than the expected 3 rig South Texas Program that we’ll 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 liquids pricing. Although natural gas front month prices how now recovered sharply from their earlier lows, our second quarter realized natural gas and liquid pricings had 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’s 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 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 six. 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 6300PSI on a 25 64th choke of very nice well. In south Texas we entered into a long term agreement for natural gas gathering and processing services in Warsaw County Texas, with much of our 2012 drilling activity focused on our crude oil and liquids rich acreage in Warsaw County. This particular agreement is very important to our plans.

As we continue to mitigate third party risk from our program through this long term agreements, we can focus even more closely on improving and optimizing our drilling and completion practices. Also in 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 side in Warsaw County. This type of innovation allows us to reduce our cost even as we reach new technical efficiency goals with drilling and completion activities.

In addition to reducing costs in the second quarter, we’re 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 30th we had drilled 32 wells in South Texas. With 4 rigs operating today, I want to stress that we are already at 4 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 or planned and designed for because of our operating efficiency, this will be four to five more wells than we have 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 operating in a pure development mode.

Additional activity in South Texas and South East 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 arrange a 15 to 20% increase up from our prior guidance of 10 to 15%. This is a result of all the additional activity.

Reserves 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 the 2012 than previously anticipated, but we’ll have better 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’re 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 in 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.

And now I’ll ask Alton to present our second quarter 2012 financial results.

Alton Heckaman.

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 2Q11 and 4% from1Q12 all weighted to oil and liquids, did however help to mitigate the effect. For the second quarter 2012, oil and gas sales were 132 million while hedging gains resulted 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 2Q12 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 2Q11, with an overall 25% decrease in our realized price for BOE in 2Q12 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 liquid sales. As to our controllable cost in metrics compared to guidance, production cost came in to $10.10 cents 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 approved 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 this was income for the quarter of $3 million, $0.07 per diluted share well above the first call mean estimate.

Effective income tax rate for the quarter was 40.8%. Cash flow before working capital changes again per Q, 2Q12 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 with the recent strength we’ve been to layer in some natural gas flows 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 2012 we had no outstanding balance on our line of credit and had 32 million of cash on hand. Natural gas and NGL prices on the near term pose a challenge to our sector though as Terry mentioned, recent improvement in both are positive signs. With our quarter and liquidity, our inventory of liquid rich projects and approximately 86% of our revenues coming from oil and liquid production, we’re 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.

And with that I’ll turn it over to Bruce Vincent to begin the discussion of our operations.

Bruce Vincent

Thanks, Alton and good morning everyone and thanks for listening. Today, I want to discuss second quarter of 2012 activity including our production volumes, our recent driller results, activity in our core operating areas and our plans for the third quarter and full year of 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 of production was 11% greater than the second quarter of 2011 production of 2.64 million barrel of oil equivalent, an increase of 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 eight of these wells were drilled in Warsaw County and six in McMullen County.

Three wells were drilled to the Olmos formation all in McMullen County. In Swift Energy’s South East 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 shack were drilled in the Burr Ferry area. We currently have 4 operated drilling rigs in our South Texas core area drilling in Eagle Ford shale wells. We also have one operated budge rig drilling in our South East Louisiana area and two non-operated drilling rigs are active in the Central Louisiana East Texas area.

In the South East Louisiana core area, which includes the Lake Washington and Bater Sain 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 of 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 a one rig drilling program for the entire year. Additional wells in this program should allow for a relatively flat production profile in Lake Washington for the rest of 2012. Bater Shane’s sequential production decline decreased 26% to 362 net barrels of oil equivalent per day. The 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 Giendes/Olmos Fields and AWP or Tisher wells and Fascon Eagle Ford fields, second quarter of 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 lengths of our laterals and increase the number of frac stages per well.

Bob will detail what we accomplished and with multi-well drilling valves, longer laterals and zipper frac completions. As a result of our drilling performance in South Texas particularly are shorter than expected drilling times, we intend to drill four to five additional wells beyond what our regional capital budget contemplated. While this does have spending to this year’s program, we believe the increased production rates we experienced as a 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 an additional crude oil on natural gas liquid reserves associated with this additional activity. The Central Louisiana, East Texas core area which includes our Brooklyn, Masters Creek, Burr Ferry and South Ferry Creek fields, contributed 2,407 barrels of oil equilibrium per day of production in the second quarter of 2012, an increase of 22% over first quarter of 2012 production in the same area. Higher production levels of this area are due to the non-operated wells at Burr Ferry during the second quarter.

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

Bob Banks

Thank you, Bruce. At the Lake Washington field during the quarter, we completed 10 wells and performed 12 production optimization projects, which includes sliding sleeves shift changes, gas lifting enhancements and returning shedding 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 to be 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. They continue to encourage us as we explore on the flanks of these great salt dome. Based on our first half results, we’ve 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 of Louisiana, East Texas area in South Burr Ferry field, the non-operated GASRS 23-1 well was completed in the Austin choke 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 4100 psi on a 3464-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 million cubic feet of gas per day, with flowing tubing pressure of 6300 psi on a 2564-inch choke.

These well results support our belief that the Austin choke project area has a 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 the Southside 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 and optimization work, and evaluating work over 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 on line 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 links to approximately 6800ft, 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 down space 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 down spacing test would immediately affect our potential drilling inventory, resource potential and outset value.

As Terry mentioned, the amount of frac stages our completion crew executed in the second quarter, increased 21% form 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 the quantifier of the impact to this technique, we completed 93 stages during July. And that’s up dramatically even from our record of second quarter productivity, up over 20% again. So use of the Zipper frac is an innovation that we are just beginning to employ, that we’ll utilize much more of as a greater proportion of our wells are drilled onmulti-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 has been released was originally scheduled to be utilized in the fourth quarter. So this changed our schedule, resulted in a higher capital and activity level in the second quarter than planned and will result in Swift Energy of 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 operated 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 end of 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 are determined that with the three rig programs in South Texas next year, along with unchanged levels of activity in Lake Washington and our Austin choke project areas, we can still drill, primarily crude oil and natural gas Lakewood’s production, in line with our longer terms strategic growth targets.

Before turning the call back to Terry, I believe it’s very important to share with the audience that we believe are 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. So staying the 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 good reason to expect to repeat that statement next year. Our premier assets present a balance of crude oil, liquids rich natural gas development opportunities. As our current resource development projects mature, we are going to add new players in projects into our portfolio.

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

Terry Swift

Thanks, Bob. Before we open the line for questions, I’ll summarize Swift Energy 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%-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 fractured 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 with question and answer portion of our presentation.

Question-and-answer session

Operator

(Operator instructions). Your first question comes from the line of Neil Dingmann.

Neal Dingmann - SunTrust Robinson Humphrey

Morning guys, and great color this morning. Just kind of maybe Bruce or Terry or one of the guys, just looking at those initial results that you all put out, it looks like that some of these wells, the Eagle Ford well in the south have a little bit more gas NGLsmixed to them versus oil. Is that kind of as you are 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’re 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?

Terry Swift

We’ll let Bob answer that.

Robert Banks

Neal, yeah. In terms of the La Salle County acreage, there are really some transitional areas in terms of gas-oil ratio. From kind of more of our northern acreage coming down into the southern acreage. The wells that we’re 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 kind of more in our southern area.

Neal Dingmann - SunTrust Robinson Humphrey

Okay, and do you see same in 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 stay at this lateral length you anticipate well costs coming down just because of efficiencies or is there oil service prices coming down or if you could just comment on the well cost?

Robert Banks

Yeah, sure will. We’re doing really good out there, even with the increase in the guar pricings that we’ve all been hearing about, we’re 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’ve just reported on, we drilled those under $7 million. So even with that guar increase we’re managing our well cost to the lower side. We have brought into the rig fleet a state-of-the-art walk-in 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 5,000-foot lateral, I think we can squeeze that down even further.

Neal Dingmann - SunTrust Robinson Humphrey

Okay, and two more if could, just on Lake Washington, just one and maybe I’ve missed this. Besides the wells that you’re going to be drilling, the additional wells, how do you see as far as additional opportunities for recompletes and other opportunities to boost production that way?

Robert Banks

On the recompletes I think we have a whole stack of recompletes sitting there on inventory. I think as we try to show you at Analysts 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. 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’s time to move uphole and recomplete the next zone. So to a certain extent we’re watching Mother Nature to help determine our schedule on when to execute those production optimization projects. But we do have a number more we’re going to do this year in parallel with the drilling activity.

Neal Dingmann - SunTrust Robinson Humphrey

Okay, and last one if I could. Just quickly on hedges, either to Alton or Bruce, just wondering you mentioned all the volatility you’re continuing to see NGLs and even I guess you could say with even just gas prices themselves. Any thoughts about putting additional hedges on just to, obviously prices are great, but just to take some of that volatility out?

Bruce Vincent

Oh absolutely. You can see did put on some floors for natural gas here just recently and I think given the market conditions we’re absolutely looking for an opportunity to do more of that. Clearly the market has not been something that you would want to go out long on the gas side. But we’ve seen it strengthen and as we’ve done so we started putting floors in place and expect those to continue to do that if the market allows us to.

Neal Dingmann - SunTrust Robinson Humphrey

Perfect. Thank you all. Great quarter.

Operator

Your next question comes from the line of Kyle Rhodes.

Kyle Rhodes - Hester Capital Management

Hi guys.

Bruce H. Vincent

Hey.

Kyle Rhodes - Hester Capital Management

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

Bob Banks

Yeah, I think – well I think it would be easy to try and extrapolate fourth quarter spending to all of 2013. It’s not going to work exactly that way. As we ramp down we do have an inventory built up of wells ready to be fracd 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’s going to be less than that going into 2013 as we prosecute that inventory.

Terry Swift

Yeah, I think I’d like to add, this is Terry, it’s really early to be giving guidance for 2013 and though we certainly respect the concerns that folks have out there, we’re 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’re going to be very balanced between cash flow and capital spending. That’s certainly our strategic objective.

Kyle Rhodes - Hester Capital Management

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?

Bruce Vincent

Absolutely. I mean I think if oil climbs or nothing we see the cash flow available, we absolutely could go to an extra rig.

Bob Banks

Yeah, I think that’s the flexibility that is built into our programs right now and clearly we’re going to watch this market. I mean you don’t do things all on a single day basis, but you can anticipate 90 days out, changing things if you have a sustained increase in prices. I want to emphasize because it would need to be sustained.

Bruce Vincent

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

Kyle Rhodes - Hester Capital Management

Okay, fair enough. Thanks.

Operator

Your next questions come from the line of Noel Parks.

Noel Parks- Ladenburg Thalmann & Company Inc.

Good morning.

Bruce Vincent

Morning Noel.

Noel Parks- Ladenburg Thalmann & Company Inc.

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 towards some additional prospects out there? Could you just talk some more about that?

Robert Banks

Well, yeah. I’ll just say that 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 in more northeast and eastern 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’re very encouraged, not only with the shallower to medium level production horizons, but as I mentioned, we have a couple of those wells than 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 it continues to amaze us how much pay is really out there.

Bruce Vincent

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

Noel Parks- Ladenburg Thalmann & Company Inc.

Great. And moving out to, you were talking about something I’ve forgotten about with this Wilcox potential in and around the South Bearhead Creek. Could you just talk a little bit more about that or is that a scenario you haven’t focused a lot on?

Robert Banks

Yeah. Well, it’s a great area. It’s not an area we’ve done any holes or 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’re using. We really think it’s well suited to horizontal development drilling and we really intend to test that concept in early next year. But we’re pretty encouraged using the knowledge we’ve developed in South Texas as to how we could deploy that in that area.

Noel Parks- Ladenburg Thalmann & Company Inc.

And would those – would you expect those would be gas or oil? And if gas sort of what cost structure do you think you’d be looking at if those were?

Robert Banks

Well, this is primarily an oil area, very good oil. So in terms of Wilcox I don’t think we’re ready to drill numbers around that yet. There is 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’re still kind of in the design phases of that. So I think we’ll be back to you here maybe next time to talk a little but more about that.

Noel Parks- Ladenburg Thalmann & Company Inc.

Great. And just one more sort of housekeeping thing. Out of the increase 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?

Robert Banks

I don’t know that we have the numbers right here but suffice it to say pulling in 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 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.

Noel Parks- Ladenburg Thalmann & Company Inc.

Great. That’s it from me, thanks.

Operator

Your next question comes from the line of (inaudible).

Unidentified Analyst

Good morning. Congratulations on a great quarter.

Bruce Vincent

Thank you. Good morning.

Unidentified Analyst

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?

Bruce Vincent

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’ll 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 low cash flow.

Robert Banks

Yeah, just to address the backlog issue, we really right now have about 11 ready for fracing operations. So we have a nice inventory of projects there and with this completion efficiencies that we’re talking about, we think we can prosecute that backlog very quickly.

Unidentified Analyst

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

Robert Banks

Yeah, I think – but we actually were on – we reported on the two-well. We’re actually now on our fourth two-well pad. We also mentioned we’ll drill along the 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’re completing.

Bruce Vincent

But it is also dependent upon whether we’re doing pad-drilling and completing wells on a pad because you do them quicker than you do if you have to move it 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.

Unidentified Analyst

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 kind of what are your thoughts in terms of activity there in the back half of this year and going to ’13?

Robert Banks

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’re getting from our Burr Ferry area are so extremely positive and economic that we’re really choosing to spend our capital there preferentially right now.

Bruce Vincent

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

Terry Swift

I think the good news is where the 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 allocated capital right now.

Robert Banks

Yeah, and one other thing is that’s all held by production acreage, so we’re not pushed to drill there.

Unidentified Analyst

Alright. Thank you so much.

Operator

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

Dan Keski - Analyst

Hi guys, thanks 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? And 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?

Alton Heckaman

This is Alton. I’ll answer the first question. Obviously we like the rate that those 2017 bonds have. So we hope that we’re 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’re aware. So with respect to our liquidity we’re 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 really haven’t pushed that borrowing base up. It’s currently $375 million. We think at the next redetermination in November it should be significantly up from there. So we’re in good shape and have dry powder. We can handle any of the activity that we’ve got. But as we’ve indicated in this call, hopefully you’ve gotten the signal. We never want to get too far out over our skis. So, we’ve got the liquidity if we need to ramp it up a little bit.

Bruce Vincent

This is Bruce. In terms of the value gap and closing that it disappoints us in terms of our valuation out there. And obviously we have a number of things that we’re trying to do to do that, but number one thing is to perform. When we’ve talked to investors their concern was whether or not we could actually do what we say we’re 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, but 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’ll continue to do that. Actually if you look at it for the fully year we’ll continue to do that. The feedback we’ve gotten is people need to see that we could what we said we were 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 said, that we are driving the liquid side, both reserve side, both production side, and you’re ultimately going to see that reflected in the evaluation.

Dan Teske - Analyst

Okay, thank you.

Operator

Your next question comes from the line of Curtis Trimble.

Curtis Trimble - MKM Partners

I 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-à-vis where you were at say the end of 2011.

Terry swift

Curtis, no. We don’t have those numbers here in front of us., I mean we are looking that all the time, but we are we are also altering a number of things, which frac stages and lateral links –yeah and all the MPT. So, we don’t have numbers like that. We are…

Bruce Vincent

We don’t have them here available.

Terry swift

Available, yeah. We do review this very closely with the teams on a quarterly basis and I would say certainly at the next analyst 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.

Bruce Vincent

Yeah, I think we showed some information on like cost passage and now it’s coming down at the analyst day and a lot of that has to do with – a lot of – any number of small things that cumulatively add together driving cost down, coupled with a significant reduction in nonproductive time. The trend really has continued and I think if we could have put out the additional information on that, we’ll look for an opportunity to do that. You would just see our ability to continue to be more efficient.

Curtis Trimble - MKM Partners

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

Terry swift

Well, no. I think I think there 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 analyst day of about a 6,000-foot lateral of the $7.2 million to $8.2 million. I think the takeaway from what we told you about our 5,000, 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. So if you just go back to those I think even the longer laterals, we are going to be on the lowest side of that $7.2 million to $8.2 million range that we gave you.

Curtis Trimble - MKM Partners

God deals. Also just to get a little bit idea of or let’s call it near term production history on the Austin choke. Can you talk in terms of a 30 day rate or some of the wells that have 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?

Terry swift

Well, it’s still early. I think we showed you the very first two wells that we drilled in Burr Ferry area, how they stood up very nicely, unlike a lot of experience in Austin choke 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.

Bruce Vincent

Yeah, I think there is 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 like fourth quarter of 2010, so we had a lot of good history. One of the things that helps mitigate decline on that, there is water drop component to those wells and we would expect those probably to produce that similar decline curves.

Terry swift

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

Bruce Vincent

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

Curtis Trimble - MKM Partners

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?

Terry swift

Yeah, it’s – the 60 acre test is going to be in that Northern La Salle County oilier area is where we are going to go to that, that first test.

Curtis Trimble - MKM Partners

Perfect. Appreciate it.

Operator

Your next question comes from the line of Gordon Douthat.

Gordon Douthat – Wells Fargo Securities

Morning guys.

Bruce Vincent

Hey Gordon?

Gordon Douthat – Wells Fargo Securities

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

Bruce Vincent

Currently as to third quarter, well I think…

Alton Heckaman.

On annualized rate maybe 100 million in the ballpark.

Bruce Vincent

It’s probably more…

Robert Banks

Yeah, I mean, 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’s more like $8 million times a well to a month per rig. So you could kind of figure it out depending that way, whether we are drilling along the laterals or more of the 5,000 foot laterals.

Bruce Vincent

And to be clear, I know you’re trying to fill into your models, we are not talking about just the rig cost here. You’re talking about one rig running for a full year, what sort of that burn rate. So I mean that range is 80 to 100 million.

Terry swift

It’s all in, yeah.

Gordon Douthat – Wells Fargo Securities

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

Bruce Vincent

In South Texas…

Gordon Douthat – Wells Fargo Securities

In South Texas and then you’ve got Austin Choke, Burr Ferry and Lake Washington, so adding all those kind of pieces together, does that get you to like a 450, 500 range? Am I thinking about that correctly?

Bruce Vincent

Yeah, you’re thinking correctly but I want to emphasize, we are not ready to provide guidance for 2013. There is 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’ve already done that. By year-end we will have brought it down to three rigs in South Texas and dependent upon how prices have gone and how the results have gone, and by the way we are getting some great funding cost results. So that’s got to be factored in to 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.

Gordon Douthat – Wells Fargo Securities

Okay. No, I think it looks good from my standpoint. What percentage of wells will you be drilling on longer laterals going forward, in South Texas?

Terry swift

Yeah, I guess if we were to just thumbnail, we have these very specifically scheduled out. But it’s probably in the 50-50 range. We design our laterals into a lease position where we can get the longer laterals we drill the longer laterals, but it’s 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.

Gordon Douthat – Wells Fargo Securities

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

Terry swift

No, that, that went into effect in June.

Bruce Vincent

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

Gordon Douthat – Wells Fargo Securities

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

Bruce Vincent

It will be reducing…

Terry swift

Yeah, it’s tied to a rump up of drilling.

Bruce Vincent

Yeah, we don’t have any interruptible now.

Gordon Douthat – Wells Fargo Securities

You don’t have any interruptible?

Robert Banks

Yeah. Just to clarify that. It’s basically – we have a de minimis amount of interruptible right now. It’s just very, very tiny part of the production stream.

Bruce Vincent

Yeah, I think where you’re seeing most operators including ourselves have agreements in place, but sometimes mid-stream 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.

Gordon Douthat – Wells Fargo Securities

So it looks like you’ve got that – at least that leg of the stool locked up.

Bruce Vincent

Yes, we do. Yes

Gordon Douthat – Wells Fargo Securities

Okay, very good. And then with the three rigs and once you get to the three rigs, do you plan on – where do you plan on having those drilling? Do you have them hopping around various areas in South Texas or do you have a specific layout plan?

Robert Banks

Yeah. We have a very specific layout plan, actually probably for the next three years. But for next year, yeah, you’ll 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.

Gordon Douthat – Wells Fargo Securities

Okay. And then at Fascon, I know you’ve got held by a production right now. At some point do you have to return to drilling there to contain the whole bad lease?

Robert Banks

No. We’ve earned all that position, all locked up.

Bruce Vincent

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

Gordon Douthat – Wells Fargo Securities, LLC

Okay. Thank you very much.

Operation

Your next question comes from the line of Kyle Rhodes.

Kyle Rhodes - Hester Capital Management

Hey guys, 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 kind of by year-end?

Robert Banks

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

Kyle Rhodes - Hester Capital Management

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

Robert Banks

Right.

Kyle Rhodes - Hester Capital Management

Alright, great thanks.

Operator

Your next question comes from the line of Michael Hall.

Michael Hall – Wells Fargo Securities, LLC

Thanks. Good morning.

Terry Swift

Hey Michael.

Michael Hall – Wells Fargo Securities, LLC

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, coming high end of year-end each quarter or better. I guess, why not take the, take a step a higher on full year guidance? Is there anything kind of lingering out there on year-end that’s keeping you from doing that or is it just an effort to stay conservative and better under promise and over deliver?

Bruce Vincent

Well, I think there is 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 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 year and that’s what we see happening. So we’re hesitant to take it anywhere beyond what we see.

Terry Swift

Yeah. I think I’d add to 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’re going close out the year and not only with better reserve results but also a stronger liquids mix within there. So, that is probably the fundamental thing that we’re ready to change right now.

Michael Hall – Wells Fargo Securities, LLC

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 well during the quarter and as I recall you had a pad that you were drilling there. When’s that planning to come on?

Robert Banks

Yeah, 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’re going to be doing that simultaneous operation here about mid-August. So you’ll see a lot of results coming out of that area. We pushed that back to really make sure we 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’re going get out of that four-well initiative. So we did a little optimizing.

Bruce Vincent

Yeah. That four-well pad has actually been ready to complete, but we pushed it back because we were expanding the facilities up there and in order to test it we would have had two 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’ll see those results when we talk about third quarter.

Robert Banks

Yeah and just to bolt on to close the loop, of those 11 that we have an inventory we mentioned, 10 of those are Eagle Ford and only one of those is Olmos. So it’s just the timing of when we’re releasing data in the quarter.

Michael Hall – Wells Fargo Securities, LLC

Okay, I’ve got to figure those. Great, I think the rest of mine have been answered. Appreciate it.

Operator

And there are no additional questions at this time.

Terry Swift

Okay. Well we’d like to thank you for listening in to our second quarter 2012 conference call and look forward to getting together again with you next quarter. Thank you.

Operator

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.

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