SilverBow Resources Inc (SBOW) 2011 Q2 法說會逐字稿

Good morning. My name is Felicia and I will be your conference operator today. At this time I would like to welcome everyone to the Swift Energy Company second-quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. Mr. Vincent, you may begin your conference.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy Co's second-quarter 2011 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 Jim Mitchell, Senior Vice President, Commercial Transactions and Land.

Before I turn it 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.

Thanks, Paul. And thank you again to everyone listening for joining our conference call today. The pace of our operations continued to accelerate during the second quarter. We now have 4 rigs drilling horizontal wells in South Texas and we'll add a fifth rig in September. Our dedicated frac fleet has resumed activity and is completing an average of 4 wells per month and we expect that pace to continue. A new pipeline is being constructed and will open up approximately 90 million cubic feet a day of natural gas processing and transportation to us later on this quarter. The entirety of our acreage position in South Texas has proven to be extremely productive by our activity as well as by offset operators' activity. This acreage position as it stands today provides in excess of 1,000 drilling locations for us to develop over the years to come.

During the second quarter, we did experience some production curtailments as a large pipeline operator performed maintenance to their system in South Texas. We prepared for this by making arrangements in February with another pipeline operator.

We expect a pipeline currently under construction to be in service later this quarter. Until this pipeline is constructed and activity has commenced there, there is some uncertainty regarding our near-term interruptible capacity. And we have guided the third quarter production to account for this uncertainty. This new pipeline will effectively meet all of our processing and transportation needs in McMullen County.

We also view recent incidences of pipeline capacity issues along the trend as just one more indication that the productivity of the wells in the Eagle Ford shale is greater than and improving faster than anyone had expected. While we are spending the bulk of our capital dollars in South Texas developing shale and tight gas ends, we have not done so at the expense of our high-margin traditional assets.

High value oil production in our Lake Washington field accounted for 46% of our revenues in the second quarter and benefits from widening Gulf Coast crude oil premiums. In our central Louisiana operating area, we are applying new technologies to a traditional asset and seeing outstanding results.

Our development on the Austin Chalk, both on Swift-operated acreage and within our growing joint venture operated area, is progressing with 2 wells drilling today and plans for increased activity over the next 12 months. This area yields oil and liquids-rich natural gas production and also benefits from Gulf Coast crude oil pricing.

As we develop this acreage and prove that current drilling technology can improve the repeatability and reduce the variability of results in the Austin Chalk, we may capture meaningful amounts of high-return, high-margin reserves. These 3 areas provide a diversity that is rare in companies our size and as a result of our work over the past several years, we're poised to grow our operations in all of them.

Additionally, we are always evaluating strategic opportunities that will further leverage us to large acreage positions prospectively for crude oil and liquids production. Alternatively, as in the case of our South Louisiana area, we are also prepared to sell non-strategic assets that no longer fit our operational plans.

Moving to specific accomplishments for the second quarter, Bruce and Bob will detail all of our operational activity and performance in just a few minutes. But first, I'll review some of the highlights, which include the completion of the SMR Eagle Ford 3H well, the SMR Olmos 1H well at rates of 1,200 barrels and 550 barrels of oil per day, prospectively. These set up additional Eagle Ford and oil Olmos drilling in this area and a rig will be deployed there continuously through the end of the year.

Our frac fleet returned to our operations at the end of the second quarter, and is now completing an average of 4 wells per month in South Texas. With a backlog of 7 wells at the end of the second quarter, and 4 rigs, soon to be 5 operating, we believe we've achieved balance between our drilling and completion activities.

Pipeline curtailments throughout the quarter demonstrate the strategic importance of having dedicated capacity, which we have negotiated for in McMullen and Webb counties and will continue to work towards in other emerging plays as we drill them out.

In Southeast Louisiana, we brought 2 new wells on production during the quarter. The LL&E Number 5 tested at close to 2,300 barrels of oil per day and settled in at a rate of 700 barrels to 800 barrels of oil per day with 2 million cubic feet of natural gas and strong pressure.

The CM 420 drilled on the west side of the Lake Washington field encountered approximately 150 feet of pay and 5 productive horizons and tested at about 400 barrels of oil per day. Both of these wells set up additional drilling activity in the Lake Washington field area.

In our central Louisiana/east Texas area, we now have drilling a Swift operating well and are participating in a non-operated well in the Burr Ferry area. We have also recently expanded our relationship and the scope of the area we're working in with our joint venture partner. We believe this area is highly prospective for liquids-rich production and high-rate wells drilled here should have excellent returns and complement the growth in our other areas.

Finally, we have widened our full-year production guidance slightly to 10.7 million to 11.2 million barrels of oil equivalent, principally because of the possibility of periodic pipeline constraints and the timing associated with our new dedicated outlet for McMullen County natural gas production. Although uncertainty is always present in our business, there should be no doubt that we have built an organization with proven leaders and high-quality assets that will provide consistent and predictable growth for years to come.

And now I'll ask Alton to present second-quarter 2011 financial results.

Thank you, Terry, and good morning. The second quarter was indeed another great financial quarter for Swift Energyhighlighted by considerable production and revenue growth compared to the prior year. Oil prices improved significantly during the quarter and were clearly reflected in Swift's financial results.

Oil and gas sales, excluding hedging effects, were $159 million, a 52% increase from 2Q '10 and a 10% increase from 1Q '11. Income from continuing operations was $26.7 million, or $0.61 per diluted share up from $0.32 in the second quarter 2010 and $0.47 in the first quarter 2011.

Cash flow before working capital changes came in for the quarter at $2.47 per diluted share and 2Q '11 production was up 30% for the prior year at 2.64 million barrels of oil equivalent. Crude oil prices were 44% higher than second-quarter 2010 levels while natural gas prices increased by 6%, resulting in an overall 16% increase in our realized price per Boe.

Our controllable cost and metrics came in as follows. Production costs came in at $10.11 per Boe, which was above guidance. G&A came in at $4.11 on the low side of our guidance. DD&A came in at $21.14, slightly above.

Interest expense came in at $3.27 per barrel within our guidance, and production and ad valorem taxes came in well below guidance at 7.8% of revenue, primarily the result of higher-than-expected tax benefits that were realized. The net result was income from continuing operations for the quarter of $26.7 million, or $0.61 per diluted share, exceeding first-call mean estimate.

During the second quarter we also recognized a $14 million gain from discontinued operations related to sales proceeds from the Company's final New Zealand permit, which was sold in 2008. The gain was originally deferred and is now being recognized during the second quarter after a settlement was reached and all legal claims were dismissed in relation to the property sale.

Finally, our effective income tax rate for the quarter was 36.3%, which was slightly below our guidance. The overall result was net income for the quarter of $41 million.

Cash flow before working capital changes for 2Q '11 came in at $106 million, or $2.47 per diluted share, while EBITDA was $107 million for the quarter. Quarterly CapEx on a cash flow basis was $113 million. Basically cash flow neutral for the quarter.

During the quarter we continued to lock in price floor hedges when market conditions were favorable. For the third quarter 2011 we have executed gas floors covering over 30% of our expected production at an average NYMEX strike price of $4.62 per MMBTU. Please see our website for complete and current detailed oil and gas hedging information.

I would like to conclude by taking a moment to again highlight Swift's solid financial position. During the second quarter, we renewed and extended our credit facility through May of 2016, increasing the borrowing base to $400 million while maintaining the commitment amount at $300 million. As of the end of the second quarter, we had no outstanding balance on the line of credit and had $32 million of cash on hand.

This strong liquidity position puts Swift on a solid financial footing to continue to execute our 2011 strategy. As always, we've included additional financial and operational information in our press release, including revised guidance for the third quarter and full-year 2011. With that, I'll turn it over to Bruce Vincent for an overview of our operations.

Good morning, everyone. We appreciate your listening in. Today, I will discuss the second-quarter 2011 activity, including production volumes, recent drilling results, activity in our core operating areas, and our plans for the third quarter for 2011. Bob Banks will then provide greater detail on operational highlights during the quarter.

Beginning first with production. Swift Energy Co's production during the second quarter 2011 totaled 2.64 million barrels of oil equivalent or 15.84 billion cubic feet equivalent, an increase of 30% over second quarter of 2010 production of 2.03 million barrels of oil equivalent and a decrease of less than 1% from the 2.65 million barrels of oil equivalent or 15.47 billion cubic feet equivalent that was produced in the first quarter of 2011, and slightly below our previously stated guidance range.

A large pipeline operator that currently provides interruptible processing and transportation, or a natural gas production in McMullen County Texas, shut in our operator production for a bit more than 4 days at the end of the quarter. We were given approximately 2 weeks' notice ahead of this maintenance project, making it very difficult to forecast.

The same pipeline operator experienced periodic capacity constraint throughout the quarter, which also limited our natural gas production. These constraints, no doubt caused by the ever-increasing productivity of the Eagle Ford shale in South Texas, caused us to be slightly below our guided second-quarter production.

Under a previously-announced agreement, we will have up to 90 million cubic feet of gas per day of firm processing and transportation capacity available to us with the new midstream provider once construction of the pipeline is completed later this quarter.

Until this pipeline construction is completed, we do expect to have some temporary curtailments, which may increase in size as industry activity and production increase. These curtailments will have no long-lasting effect on our business.

We will have the ability to rapidly increase our daily net corporate production rate and expect our year-end daily production exit rate to be between 34,000 barrels a day and 36,000 barrels a day of oil equivalents, a 28% to 35% increase over our 2010 production exit rate.

With additional uncertainty around third-party activity, which we don't control, we feel it is prudent to account for that with a wider range of production outcomes for the year. We now expect 2011 production to be 28% to 34% higher than 2010 full-year production. Our previous guidance was a tighter range of 30% to 33%.

The second-quarter drilling results. Swift Energy Co drilled 8 operated wells and participated in 2 non-operated wells during the quarter. In south Texas, 3 horizontal development wells, 1 operated and 2 non-operated, were drilled in the Eagle Ford shale formation in South Texas. 6 horizontal development wells, all operated, were drilled in the Olmos formation. All drilling activity during the quarter in south Texas was in McMullen County, Texas.

We drilled more Olmos than Eagle Ford wells simply as a result of our drilling schedule and rig moves during the quarter. Our rig schedule has shifted during the third quarter and we're drilling primarily Eagle Ford wells.

In the Lake Washington field in Southeast Louisiana, 1 development well was drilled. Four rigs drilling horizontal wells into Eagle Ford and/or Olmos are active now in South Texas. As Bob will discuss, we're developing more acreage that is prospective for oil and liquids production in this environment.

1 operated and 1 non-operated rig are active in the Central Louisiana/East Texas core area with the joint expansion of our opportunity set with our partner in the area, we're prepared to be active in this area for many years to come.

I'll briefly review our activity in each of our core operating areas for this quarter and then Bob will detail the highlights of our more recent activity.

In Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields, production during the first quarter averaged approximately 9,117 net barrels of oil equivalent per day, or approximately 55 million cubic feet equivalent per day in this area, down 4% when compared to the first quarter of 2010 average net production for the same area.

Lake Washington averaged approximately 7,845 net barrels of oil equivalent per day, or about 47 million cubic feet equivalent per day, a decrease of 4% when compared to the first quarter of 2011 average daily volumes and primarily due to natural declines and lower initial production responses from our ongoing production optimization program.

Bay de Chene's sequential production decreased 19% to 1,172 net barrels of oil equivalent per day, or about 7 million cubic feet equivalent per day. This sequential decline is due to no drilling activity and natural declines.

In our South Texas core area, which includes our AWP, Sun TSH, Las Tiendas, and Briscoe Ranch Olmos fields and AWP Artesia wells and Fasken Eagle Ford fields, second quarter 2011 production averaged 15,242 net barrels of oil equivalent per day, or about 91 million cubic feet equivalent per day, a 3% increase in production when compared to the first quarter of 2011 in the same area and a 91% increase over the second quarter 2010 production volumes.

This sequential increase is primarily from 3 operated and 2 non-operated new wells that were brought online during the quarter, in addition to our ongoing production optimization efforts.

In McMullen County, 2 Olmos horizontal wells, 1 operated Eagle Ford horizontal well and 2 non-operated Eagle Ford horizontal wells were completed during the quarter. We are focusing on areas within this area that are yielding higher percentages of oil and natural gas liquids. Bob will spend time discussing our Olmos and Eagle Ford programs in greater detail.

The Central Louisiana/East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry and South Bearhead Creek fields, contributed 3,290 barrels of oil equivalent per day, or about 20 million cubic feet equivalent per day of production in the second quarter of 2011, an 18% increase in production over the first quarter 2011 volumes and 248% above second quarter 2010 production from the same area.

Higher production levels in this area result from the performance of 2 high-rate, non-operated wells in the Burr Ferry area that were completed in the fourth quarter of last year. Our partner in the Burr Ferry area is currently drilling a well in our expanded, original joint operating area.

We expect activity to increase in this area as well as in our newly-formed second joint operating area with the same partner. Swift Energy is also drilling an operated well in the Burr Ferry area and will move this rig to the Masters Creek field next to drill 1 well.

In our South Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island, and Bayou Penchant, production averaged approximately 1,539-barrels of oil equivalent per day, or about 9.2 million cubic feet of oil per day during the second quarter. As we have noted before, we are in the process of marketing these assets in this area and expect to announce and close a transaction before the end of the year.

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

At the Lake Washington field, we drilled 1 well, completed 2 wells, recompleted 4 wells, and performed 24 production optimization projects during the quarter.

The CM number 420 was recently drilled to a measured depth of 9,882 feet and encountered 150 feet of true vertical net pay in 5 productive horizons. The initial production rate of this well was 399 barrels of oil per day and 0.12 million cubic feet of gas per day with flowing tubing pressure of 230 PSI on a 40-64-inch choke.

We also completed the LL&E number 5, which is our jelly bowl well, during the quarter. The initial production rate of this well was 2,294 barrels of oil per day and 1.2 million cubic feet of gas per day with floating tubing pressure of 1,080 PSI on a 26-64-inch choke. The most recent test rate of this well was 799 barrels of oil per day and 2.4 million cubic feet of gas per day with flowing tubing pressure of 1,020 PSI on a 32-64-inch choke.

Both of these wells set up additional project areas where we expect to drill, produce and book crude oil reserves over the next several years.

The recompletions we performed averaged an initial production response of approximately 280 gross barrels of oil equivalent per day. Our production optimization projects, which include sliding sleeves, shift changes, gas lift enhancements, and returning shut-in wells to production, averaged an initial production response of 126 gross barrels of oil equivalent per day.

Production in this area has a very high rate of return associated with it, and these returns are made higher by the strong price realizations we receive along the Gulf Coast. Many industry experts believe that the recent increase in Gulf Coast crude oil price realizations will continue for some time. We are acknowledging this pricing trend by planning more activity in this area later this year and into 2012.

In our Central Louisiana/East Texas area, we are drilling a 100% working interest well in the Burr Ferry area and our joint venture partner is also drilling a well in this area. We have also increased our commitment to this area through an expansion of a relationship with our joint venture partner.

We have expanded the original joint operating area and have entered into a second agreement to jointly develop acreage in a second operating area adjacent to the first operating area. There are now approximately 70,000 -- 73,000 gross acres leased in the first joint operating area in which Swift Energy holds a 50% working interest. The Company also owns approximately 39,000 feed mineral areas in this acreage.

In the second most recently defined joint operating area, there are now approximately 32,000 gross acres leased in which Swift Energy holds a 45% working interest. The Company's position in both areas is non-operated and additional leasing is expected to continue in both areas.

Moving to our South Texas area, 3 operated and 2 non-operated wells were completed in McMullen County in the second quarter. As a result of more efficient operations and a faster-than-anticipated pace of well completions, we did return our dedicated frac fleet to Weatherford for approximately 50 days during the second quarter. This is in addition to the 30 days in the first quarter when we also returned the fleet to Weatherford.

By the end of the second quarter when this frac fleet returned to Swift Energy, we had built a backlog of 7 drilled but not yet completed wells. We expect this fleet now to average 4 well completions per month in the future and now have enough drilling activity to keep this fleet fully utilized. The Company does not anticipate releasing this frac fleet again in 2011 and expects to have 4 to 5 operated drilling rigs running in South Texas for the remainder of the year.

I'll touch on third quarter activity in a moment, but first, a review of second quarter well tests and results.

In McMullen County, our joint venture partner completed the Bracken JV 8H and Anthony JV 1H Eagle Ford wells during the second quarter. The initial production rate of the Bracken JV 8H was 10.9 million cubic feet of gas per day with flowing casing pressure of 6,575 PSI on a 20-64-inch choke. The Anthony JV 1H had an initial production rate of 8.2 million cubic feet of gas per day, with flowing casing pressure of 4,922 PSI on a 20-64-inch choke.

Moving to our operated wells in McMullen County, 2 Olmos horizontal wells and 1 Eagle Ford horizontal well were completed during the quarter. The R Bracken 38H Olmos well had an initial production rate of 7.5 million cubic feet of gas per day and 578 barrels of natural gas liquids per day, with flowing casing pressure of 5,475 PSI on an 18-64-inch choke.

The SMR 1H Olmos well had an initial production rate of 552 barrels of oil per day, 1.1 million cubic feet of gas per day, and 82 barrels of natural gas liquids per day, with flowing casing pressure of 2,450 PSI on a 20-64-inch choke. The SMR 3H Eagle Ford well, with a lateral length of 4,850 feet, was completed with initial production rate of 1,230 barrels of oil per day, 0.78 million cubic feet of gas per day and 60 barrels of natural gas liquids per day with a flowing casing pressure of 1,975 PSI on an 18-64-inch choke. As we've mentioned, we are now completing wells at a pace of 4 per month.

So far, in the third quarter, we have completed 5 wells; 3 Olmos and 2 Eagle Ford wells. The R Bracken 40H Olmos well had an initial production rate of 6.2 million cubic feet of gas per day, 480-barrels of natural gas liquids per day, and 12 barrels of oil per day, with flowing casing pressure of 5,800 PSI on a 20-64 inch choke. The Siddons 3H Olmos well had an initial production rate of 5.1 million cubic feet of gas per day and 398-barrels of natural gas liquids per day, with flowing casing pressure of 5,400 PSI on a 20-64-inch choke.

The Whitehurst 3H Olmos had an initial production rate of 608 barrels of oil per day, 1.4 million cubic feet of gas per day and 106 barrels of natural gas liquids per day, with flowing casing pressure of 2,685 PSI on a 20-64-inch choke. The remaining 2 wells completed this quarter are in various stages of flow back and are being tied into facilities.

Operationally, we now have a rig dedicated to drilling Eagle Ford and Olmos oil wells in our northern McMullen County acreage. We are preparing for a fifth rig to join our South Texas operations in September and will use this rig to increase our oil and liquids-rich drilling activity.

With our drilling and completion activity now at an optimal balance, we do not expect that we will need to release our frac fleet again and that it will be fully utilized on Swift operated activity.

The periodic interruption of natural gas transportation we have recently begun to experience only underscores how important the long-term relationships and contracts we have entered into over the past 2 years are to the successful implementation of our particular approach to resource development.

We believe the way we have gone about evaluating our acreage positions, hiring integrated top-tier industry professionals into our operations, the way we've contracted dedicated drilling, completion, transportation, and processing services, as well as the way we've built a reliable supply chain for essential materials and equipment should provide stakeholders with the confidence that we will deliver on the growth that Terry mentioned as seeing more clearly now than he has ever seen in the history of the Company.

With all these pieces I just described fitting together, and our operations focused around 1 of the world's most prominent shale developments, as well as our high-value oil properties in Louisiana, we're going to provide consistent, reliable production growth for years to come. Thanks for your attention this morning, and I'll turn it back over to Terry to recap.

Before we open the line for questions, I'll summarize Swift Energy's second-quarter results and review some of the highlights from today's call. Second-quarter production growth of 30% over second-quarter 2010 production have us tracking towards 28% to 34% full-year production growth.

We expect to have 90 million cubic feet a day of dedicated natural gas processing and transportation capacity available to us by the end of the third quarter. We completed 1 Olmos and 1 Eagle Ford oil well in our San Miguel Ranch area, where we have an active drilling program for the rest of the year.

Our frac fleet has returned and is on pace to complete an average of 4 wells per month during the quarter. We have an adequate well backlog and drilling activity to keep this fleet fully utilized. We have expanded our exposure to the Austin Chalk trend with our partner in the Burr Ferry area of Vernon Parish, Louisiana.

We are also drilling 1 operated and participating in 1 non-operated Austin Chalk well in the same area. Recent drilling results support increased activity in 2 areas of the Lake Washington field in Southeast Louisiana. With that summary, we would like to begin the question-and-answer portion of our presentation.

(Operator Instructions) Your first question comes from the line of Leo Mariani with RBC. Mr Mariani, your line is open.

Hello? Can you guys hear me?

Now we can.

Sorry about that. I think there was a problem with the phone briefly. But, yes, I just wanted to check in real quickly on third-quarter production. You guys talked about experiencing periodic down time due to this third-party pipeline. Can you give us any indications as to what down time you might have seen here in July and thus far in August? Are you getting hit with sort of random interruptions thus far?

We have provided that in our guidance. We've kind of wrestled with trying to understand the whole trend and what other operators might be bringing into the system or might not, but as we've talked with our providers and the service companies that are -- pipeline operators that work with us -- we're pretty confidence that we're going to have very meaningful deliveries throughout the third quarter but we -- there is some uncertainty and we've already put that into the guidance here. We did see some brief interruption recently and we've -- that kind of went away, but it could come back and we put that in.

I think the key element here is that we do have our Southcross deal and its construction progress is very good. We do expect by the end of the third quarter to be fully up and operational. There will be some transition there. We've guided -- oh, I hate to put a particular number -- but we have guided to have a certain amount of down time, though that might not happen, and we also have recognized that we're going to have a fair amount of activity that we've adjusted -- for example, we've moved into some areas where we won't have the constraints so we have adapted our program a little bit to mitigate any potential constraints coming out of AWP.

Yes. Just a little more color on that, Leo, it is third-party, so we don't have all the information. I'm not sure they do. But, as we understand it, what's happening in south Texas is you have a number of projects, whether they're pipeline or processing-related or other operators completed wells, there's clearly some pipeline projects that are under construction. They expect to have them come online and those operators have firm capacity and that will have preference to anyone with interruptible capacity, so depending on the nature of when those projects actually come on stream, we may get pushed back a little bit.

It hadn't been as bad as we thought it was going to be in July, which is helpful. We've tried to estimate what we think it might be or cover that in the range of guidance, particularly on the low side of that guidance, but as Terry pointed out, the important thing is the Southcross deal is done and pipes in the ground, they're burying it now and we expect that to be operational certainly by mid-September, which will alleviate that problem.

And we've also adjusted our activity, for instance, fracing wells down in the Webb County area at Fasken which aren't impeded by those same bottlenecks to minimize the constraints from new production that we're going to be bringing on during the rest of the quarter.

Okay. I guess just quickly and sort of Webb County on Fasken here, do you have firm capacity down there on the pipeline? I want to get a sense of what that capacity is.

We do have firm capacity there and the firm capacity with our line out of Fasken is 40 million cubic feet per day.

Got you. Okay. I guess I imagine you just kind of mentioned in your prepared comments, but I imagine you're pretty much going to be seeking firm capacity deals going forward on any other infrastructure build out -- is that a fair assumption?

I think that's a fair presumption to make. Basically the 1 area we have left to focus on is the what we call Artesia wells in LaSalle County and we would anticipate making a similar type arrangement.

Okay. Just wanted to see if you could address well costs in your major areas, briefly, focusing on horizontal Olmos, Eagle Ford and Austin Chalk. Trying to get a sense of where those are at right now.

Well, in general, in south Texas, obviously we have come through a period of upward pressure on pricing. I think it's -- every area is a little different in terms of commodities and rigs and frac services and all the rest, but I would say the way we could characterize it is there's still a little bit of upward pressure but we really see that rate of upward pressure starting to turn over and starting to flatten out now, which is kind of a good thing for us.

The other balancing aspect that we're doing is we're drilling longer laterals now in south Texas. We've gone to the 6,000-foot laterals and we think that is much more efficient in getting the best return for the capital investment.

I think we're still in the 6,000-foot lateral range. That $8.5 million to $9.5 million we talk about, we always pick for economics around the $9 million number -- I think that's still a pretty good number. We're balancing out some efficiencies to go with that.

We'll move into pad drilling. We're looking at our casing designs. We have gone to in 1 case, a walking rig to save us time for laying down pipe and picking up pipe. We're looking into more efficient completion designs to speed up our completions and go to even pad fracing.

If we go to pad drilling, we go to pad fracing. All those efficiencies come to bear along with the longer lateral, so we think that we're being very proactive in pushing back on that upward price increase, but just on the price increase side, I think it's starting to level out some.

Okay, great. Looks like your last several horizontal Olmos wells reported had a bit higher liquids content. Are you drilling those in a different part of the play there? Is that why you're getting a little bit more liquids? I'm looking for any color around that.

Yes, certainly we understand the Olmos very well and up in the northern part of the field, that's the more liquids-rich area of the field along with the western portion of the field. As you move down south it gets more gassy. The beautiful thing about the Olmos, either way we go, we get a lot of NGL stream, it's a very rich gas. When we get that combination of oil and natural gas liquids in the Olmos, those economics hold up very, very well comparatively, so we're very happy and pleased with our Olmos program. We think we have a lot of room to deliver great results in the Olmos.

All right. Thanks, guys.

Thank you.

Thank you.

Your next question comes from the line of Neal Dingmann with SunTrust.

Good morning. Good color. Say, Bruce or 1 of the guys, you mentioned about the longer lateral lengths and potential pad drilling. Can you speak a little bit about the number of frac stages you see and then (inaudible) when you were talking about the pad drilling, is that something that will become more and more likely and then where do you all sit as far as holding acreage in some of these plays? Obviously, pad drilling would likely be cheaper, but could you get by with that and still hold all your needed acreage?

Those are good questions and the things that we wrestle with all the time. As far as the 6,000-foot lateral, we usually pump about 16 to 17 stages for the 6,000-footers about 300-foot apart. In terms of going to pad drilling, pad fracing, yes, that does really play into how you hold your lease position.

The first wave of our activity is we want to hold our acreage position, but of course each acreage position has to stand up economically on its own merits. The second wave is to get into that more manufacturing mode because that's where we really start to squeeze the efficiency.

I think it's fair to say we have a little of both going on right now and going into 2012, we'll still have some spread out, hold the acreage positions, but we'll start moving -- I think it would be fair to say, we'll start moving more into the infield drilling late 2012. By the time we're in 2013, we're going to be shifting more heavily into the pad drilling and the infield drilling.

Can you talk about maybe the holding acreage? Obviously, to your credit you have not done as much on the gas over in east Texas/central Louisiana area with no drilling. I think you mentioned in the press release last quarter, but wondering if you could address that and how you see the decline rate playing out the remainder of the year next year if the lack of activity continues over there?

Can you clarify what area are you speaking of in particular?

You mentioned in here about the no drilling, especially around the Burr Ferry field and some of the other areas in that Vernon Parish. Didn't look like you had any activity in the area.

Oh, no. Yes, the Burr Ferry area that is all the Austin Chalk play.

Okay.

Which is an oil play. And that is the area where we announced 2 different waves of AMIs and joint venture agreements with a partner. This is the area where we're drilling two horizontal Austin Chalk wells at the current time. We actually are pretty excited about this area because this is very good oil production.

The first 2 wells that we drilled there came in at very high rates of oil and gas. We've looked at the well performance since then and they have been very good, very steady, very flattish, so we don't really see some of the declines like you've heard about in the Austin Chalk before.

Both of these wells that we drilled late last year have already paid out and they're still performing beautifully, so we have a lot of hopes for this area and this will be a very liquids component to our portfolio. We would expect -- we have 2 rigs running there now. We would expect, next year, to have anywhere between 1 and 3 rigs running in that play.

And what did you say -- what kind of payout can we expect on that area? It does sound, obviously, much better than I was expecting.

Yes. Well, I think -- well, the first well we drilled was in September. That probably paid out by about April. I think the second well came on about November. That's paid out by now.

So, half a year -- 6 months kind of payout so, it's unbelievable economics. So, we're very, very keen on that area, but we have to go about it the right way. We're using technology to approach this. New and different technology. So far, it's working for us, but it is still very much in an appraisal phase. We hope to move that along more into a development phase here next year.

Yes. The other thing that Bob mentioned that is worth just highlighting a second time is the decline curve on these wells, if you actually pull the production plots. There is some water drive support underneath it. It tends to make it a little flatter than your pressure depletion Chalk wells over in Texas, so it's not quite as hyperbolic as some of the other Chalk that you might have seen.

Okay and then maybe just lastly, could you comment on -- it looked like you raised the oil differential just a little bit, was that in regards to any certain areas or address as far as differentials you're seeing right now in the various areas?

Yes. It's hard to predict prices, but that's -- our Louisiana oil both in south Louisiana and central Louisiana is either getting LLS or HLS pricing. That tends to be even a premium to what Brent pricing is, a substantial premium to WTI. We had a really good spread last quarter, as you noticed, and we think that, that trend is apt to continue, so that is what that reflects.

Got it. Thank you.

Thank you.

Your next question comes from the line of Michael Hall with Wells Fargo.

I guess just a couple quick ones for me. First on the kind of expanded JOA and the new JOA out in the Austin Chalk, any reason to think that will be meaningfully different in terms of well composition and liquid splits and that sort of thing relative to what you're doing in the current JOA? Or is that expected to be pretty similar?

We like both areas. The first area, as we noted, we actually expand that AMI, and we're a 50% partner in there, though we're not the operator. We do have a lot of mineral position in there that we;ve talked about. Definitely liquids both where we started and the expansion of the first AMI, we also think is still very liquidy.

We moved from there in Burr Ferry more to the east towards Masters Creek. The second AMI is actually bigger than the first AMI, although there's not as many acres accumulated in there just yet, though we're working to increase our position. That moves towards Masters Creek, again, very oily, great oil wells over that way, that direction, not as deep as Masters Creek.

We think it's on trend and going to be very similar, though it's getting a little bit farther away from where we have established some really great wells. More to come on that.

Okay. And in terms of leasing appetite there, can you quantify maybe what you would think -- you could spend on additional leasing out there, and how that contemplated in the current budget?

The Austin Chalk is really not -- got on a lot of radar screen with a lot of people. We've been playing it for a long time. It's our back yard, going all the way from east Texas, Burr Ferry, into Masters Creek. So, yes, we're interested in a more position. It's not a big-ticket item. There's just not a lot of people that really play this the way all the shales -- everybody is focused on the shales.

Sure.

This is a nice complementary for us. It's not going to be a big acreage cost number. Quite frankly, a lot of people just don't drill these wells today, so I'm kind of low-playing it because we're drilling it out like a normal play.

Okay. Fair enough. And then I guess on the flip side on the asset sale process -- sorry if I missed commentary around that -- but any indications on timing there?

Yes. We've indicated that we would hope to have a transaction completed by the end of the year. Hopefully be in a position to announce it maybe by the end of this quarter.

Okay. That's helpful. And then I guess looking at second half activity and depending levels, clearly ramping up activity again in south Texas and Lake Washington has been doing well and Austin Chalk program ramping as well. How will we think about any potential upside risk to spending in the second half or do you feel pretty comfortable with your current budget?

Well, the first word I'd question is your use of the word risk. I think it'd be a good thing if we are able to increase spending because it means we're increasing activity level and can grow production when we do that. We're trying to ramp up our spending, as Bob noticed. We have another rig coming.

That's not the kind of thing you can just do overnight, but we hope to be able to spend -- ramp that spending up, but also drive production to higher levels in particular focus on momentum going into 2012. In terms of putting that into perspective, we don't see that significantly above the levels that are currently announced, though.

Our cash flow continues to look real good this year. The oil pricing is obviously helping that quite a bit. You may recall we started with $85 million in the bank. We've got it $30 million to $40 million of the disposition, so use the upper range of that number and we're in good shape.

The balance sheet is in great shape. If we outspend cash flow it's going to be pretty small numbers and insignificant to the shape of the balance sheet.

Okay. I guess, then kind of following up to that, as you pointed towards the good momentum into '12, good strong exit rate guidance, any reason to think you wouldn't continue to grow that rate as you move through 2012?

Go ahead, Bob.

No. I don't think so at all. I mean --

Okay.

We have the rigs contracted and we have the momentum. We have the frac crew in place. We've got the acreage position. We derisked our acreage. We can foresee nice, steady growth for some time to come, actually.

Okay, great. That's all I have. I appreciate it, guys.

Thanks, Michael. Take care.

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

Just a few questions. First, starting out in the Eagle Ford, just wondering if you're using the highway frac technology on your frac jobs -- not only with Hawk but also on your operated acreage down there?

The answer to that is we are using that in conjunction with Petrohawk on some of the JV acreage. We're looking at the results there. We have not brought that into our frac completion design as yet. I think some of the results we're getting from the way we are pumping our hybrid jobs, especially in the liquids-rich area, we think are extremely good, exceptionally good.

So, we have not seen any need, really, to bring that into our area yet, but we're watching the wells obviously. We have the data. We participate with Petrohawk in those designs, but we have not wholeheartedly shifted to that technology yet. We haven't seen the results in that way to cause us to do that.

Particularly in the liquids

Particularly in the liquids-rich areas.

And just to get an idea on the cost, that $9 million you talk about on the 6,000-foot laterals, that doesn't include the highway frac job I'm assuming. Is that correct?

No, that would be our normal hybrid frac job, the 16 to 17 stages.

How much would -- if you were to, down the road, go to the highway frac jobs across a larger portion of your completion activity, what kind of cost increase would that add to that $9 million, do you think?

Actually, I don't -- that's kind of a little specialty number that it doesn't really fit us because we're not headed that direction. Just to be candid, we've seen a lot of different frac technologies over our careers and, of course, we're always interested in all the changes.

But right now, we think the rock itself is 1 of the material things in this play and we've just got some excellent, excellent rock. And our hybrid fracs are working really well for us, so that cost increase that might come by going down that path, we certainly don't see it as part of our operation right now.

Okay. Fair enough. And then with the pending acquisition of BHP of Hawk, do you guys anticipate any kind of change in activity on that joint acreage or do you think it's going to continue along the same path you are on right now?

We actually don't see any kind of material change. Just to remind folks, that's actually a small percentage of our acreage position. It was a meaningful transaction when we did it at the very beginning. We really have integrated in all the technologies, all the expertise, so while we've enjoyed Petrohawk as a partner, it's a small part of our business.

I would just like to remind folks that even after we get the wells drilled and completed, Swift is the operator of those wells. If anything, maybe it's a positive Because we're pretty sure the folks that made that evaluation and bought that property want to keep doing what they're doing.

Yes. They didn't buy to it slow down.

And them on the Chalk, I know you guys have drilled I think 1 well in the Brookeland area, just wondering if that has any plans for next year or if that might be 1 of the asset sale targets, that east Texas side?

Again, we have not contemplated any kind of asset sale. We do not have the Brookeland drilling as a priority right now. I think the Burr Ferry Masters Creek areas are really where we want to focus our efforts, at least for the next couple of years, but that doesn't mean that there still isn't that type of potential at Brookeland. We don't think it will be as good as the Burr Ferry and Masters Creek area, so that's where we're focusing.

All right, I appreciate all the comments. Thanks, guys.

Thanks.

Thank you.

Your next question comes from the line of Adam LightLeight with RBC Capital Markets.

A lot's been covered. Just real quickly on Lake Washington area, can you give us a sense of what the Hershey well cost and whether you've got some reserve estimates and what you learned from that well relative to that field?

Well, let me take a stab at that. The Hershey well cost, I think, about $4 million to $5 million. We drilled that very efficiently, completed it very efficiently. In terms of reserves, I don't think we're prepared to release reserve estimates or anything like that at this conference call.

I will say this. In this particular fault block or embayment area, this is the west side of Lake Washington. This is a new area for us as far as drilling goes. We encountered 5 productive horizons in this well bore. This particular well alone allows for 2 to 3 more follow-on wells in that embayment or fault block area.

It also sets up additional fault blocks along the west side of Lake Washington and derisks those for us. So, I think the answer to your question is it was a very meaningful well and very strategic well for us and we're very pleased with the results and what that means for us down the road.

Okay, great. Thanks. And then I'm not sure if you answered this, but in terms of -- I know it's early -- but some preliminary thoughts on trends next year spending?

Well, we haven't completed our -- yes, it is early. We go into our budget cycle in October and November with our board and we've got numerous scenarios. In fact, as we noted, we have got line of sight growth for easily the next 5 years, so we could clearly push the capital higher but that's not really the objective.

The objective is to be very efficient and do this in a way, also, that optimizes all the economics. So, yes, I would suspect next year's spending to be higher, but we're just not at a point, really, where we can lay that out.

That's fine, okay. Thanks a lot, guys.

Take care, Adam.

Thank, Adam.

Your next question comes from the line of Biju Perincheril with Jefferies.

A couple of questions. First in the Olmos well that had a pretty good condensate cut, can you talk about the inventory that you have around those locations and the drilling plans there?

Well, yes. I think in general, in this Olmos area, I think we have identified that as about a 40,000-acre position for horizontal drilling. That would be about 250 locations. In terms of the oily part of that, all of the Olmos has very good NGLs associated with it. All of that positioned.

I don't think I can sit and break up that 40,000 acres for you as far as which is more the oily component, but clearly we know where the oily components are. That's where we're going to be drilling as a priority in the Olmos. So, I think we do have a pretty good feel for where we want to be drilling our Olmos wells.

Okay. Okay. That's fair. And then Lake Washington, can you talk about -- I think you mentioned that both the Hearst and the Jelly Bowl wells have set up additional locations. What's your plans there?

I think our plans there is very much in concert with what Terry was talking about, going into our budget cycle and our 5-year planning. What we would like to do, really, with this increased pricing realization that we get, we would like to pick back up again in the fourth quarter and drill a number of wells back-to-back going into 2012. So, really, I wouldn't -- don't be surprised to see us coming forward, picking up a rig and going back-to-back later this year going into 2012.

Okay. And in south Texas, when you return your frac crew back to Weatherford, how do you account for that? Do you still incur costs and is that in your CapEx numbers or --

We actually get a credit under the contract. We have the right to farm that back out. We get a credit back.

But, the terms of that are confidential, so we kind of have to leave it at that. It's a good commercial arrangement.

It effectively nets against the capital spending.

Okay. Can you talk about what you're sort of factoring in, in terms of savings or your activities? Sort of look at the active levels I'm thinking it's going to be rising in the second half? CapEx levels, I think, what you have guided to is spending rate that much higher in the second half?

I think we've factored that into our guidance that's out there. We show that capital spending is a net number in particular the disposition, which we hope to have completed before the end of the year.

To the extent we can ramp up capital spending, we want to do that because we are having a lot of success, but there's only a certain pace that you can do that for so we believe we have factored that in. If we're able to ramp it up a little bit more than that, we'll update guidance at the time and hopefully update production outlook at the time.

Okay. But, is it fair to say there are no savings -- you're not assuming well cost or anything like that coming down in the back half of the year?

That's correct. And we're not assuming we give the frac crew back, either. We think we're now synched up and in tandem, and feel like we can execute the projects that we've got for the entirely of 2011.

Yes. The other thing that really doesn't shine out in the numbers is, during the first half of the year you're also doing a lot of facilities work and pipeline infrastructure work around your activity, water work. You can't forget there is a big water system behind all this, so we have been spending other capital dollars on the front side of the year in preparation for the back side of the year.

Okay. Can you quantify that? How much in the first half on infrastructure in general?

No, it's everything from acreage to seismic, to facilities and we'll break that out at the end of the year as to all that specific.

Got it. And then 1 last question on the asset sales. I think you guided to something like $40 million of proceeds. I was just wondering, I think the PV 10 number for what your mark for sale is significantly higher. Is that a risk number or are you assuming only part of what's out there now will get completed this year?

If we don't get the price we're looking for, it won't be sold so, yes, effectively, it's a risk number because we anticipate the estimate of $30 million to $40 million the entirety wouldn't be sold.

Okay. So, that $30 million to $40 million is only for a portion of it. Okay.

It's a risk number.

Got it. Okay. And then I think the -- I think bids were due last week or maybe earlier this week, is that still on schedule?

What was the question again, Biju?

The process is going as planned and when we have something to report on that, we'll report it, of course.

Got it. Okay. Thanks. Appreciate the time.

Thank you.

Take care.

(Operator Instructions) Your next question comes from the line of Marcus Talbert with Canaccord.

I had a couple of quick questions. Looking at the productivity uplift that we've seen on the first few Eagle Ford wells here, kind of comparing the SMR number 3 well versus the number 2 well, which is drilled on a shorter lateral but I think is exhibiting a better initial productivity, what do you attribute that to? Were there any changes in the completion from those 2 wells?

No, the completions were very similar. So, we don't, we don't have anything in particular to show why that little productivity increased there. There is going to be some variability around these wells. Some will come down to just the efficiency of the fracture stimulation as it's being pumped. But, we did not change anything in particular from that well to the second well.

Okay. Helpful. And I think on the last call you mentioned that the number 2 well was still flowing at approximately 1,000-barrels a day after 2 weeks or so. Can you comment on sort of the daily production on that well now or if you'd be inclined to provide a 30-day rate for each of those SMR wells?

We can do that. We don't have that number now, but we do track our 30-day numbers. We just don't have that here at the call.

Yes, but going back to your first point and Bob's answer to that, I can't overemphasize that acreage in this play, whether it's Eagle Ford or Olmos, the success of that acreage is going to be very, very dependent on actual rock characteristics. So, when you see variation from 1 well to another, it often might be the actual rock, the thickness of the rock, the permeability or the porosity, or as Bob says, how effective was a specific frac job in getting into the higher quality rock areas. You want to be care and never just look at the frac job and say that alone is determining how good wells are. The rock quality is also a key attribute.

That's helpful. Given the rock quality and the productivity you're seeing there in McMullen, I think you've got 2 of the rigs running in the northern part of McMullen AWP. Is the idea that the next rig coming next month is going to maybe bounce between that area of McMullen and Sun TSH or would you be inclined to move that to a Webb or Zavala and kick off a pad, given the delays that are potentially going to impact the third quarter?

No. I don't think we're quite to the point of going to pad drilling out in the Fasken area in Webb County. I think our key to Webb County is to hold our position because that is very, very high-quality Eagle Ford. Very economic.

In fact, some of the results, some of the early decline curve work that we're doing, we're becoming more and more bullish on what our EURs are going to be in that area. We're going to hold that position and tie further drilling to commodity pricing. I think the other big rig coming in September will probably bounce between AWP and the Artesia wells area is really where we have that slated.

Keep in mind, Marcus, we have got an abundance of time in Fasken and only need eight more wells to hold the entirety of that acreage, so we have been guiding 1 well a quarter down there will be on average the next couple of years.

Okay. Great. And the new production, I'm assuming, the wider revision accounts for the fifth rig. We've been hearing a couple of the other operators talk about some incremental spot market frac capacity coming online.

Do you think there would be any upside to that number based on a smaller backlog? I think the last backlog number you guys talked about at the analyst day might have been 4 or 5. At this rate you would be 4 to 6. Do you think that could be brought down sooner?

No. I think we're bringing it down with our own crew and we would see a need to add a spot frac, it would probably be expensive. We will get to it and probably have our backlog worked down very quickly, actually.

But 1 other side to that, we also want to keep a small inventory to allow us some flexibility operationally for a variety of operational reasons.

Okay. Great. Well, that's all I have. Thank you very much, guys.

Thank you.

And there are no further questions at this time. Presenters, are there any closing remarks?

Well, we just want to thank everybody for listening in and appreciate the shareholders and analysts for their support. If you have further questions, please call Paul. We're available. Thanks again.

Thank you. This concludes today Swift Energy Company's second quarter earnings conference call. You may now disconnect.