Swift Energy CEO Discusses Q2 2011 Results -- Earnings Call Transcript

Aug. 5.11 | About: Swift Energy (SFY)

Swift Energy Company (NYSE:SFY)

Q2 2011 Earnings Call

August 4, 2011, 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

Analysts

Operator

Good morning. My name is Felicia and I’ll 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 speakers’ remarks, there will be a question-and-answer session. (Operator Instructions)

Thank you, Mr. Vincent. You may begin you conference.

Paul Vincent

Good morning. I’m Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’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.

Terry Swift

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 four rigs drilling horizontal wells in South Texas and we will add a fifth rig in September. Our dedicated frac fleet has resumed activity and it’s completing an average of four 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 operator’s activity. This acreage position as it stands today provides an excess of a thousand 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 is 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’ve 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’re applying new technologies to 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 two 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 proved 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 three areas provided diversity that is rare in companies of our size and as a result of our work over the past several year, we are poised to grow 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 will review some of the highlights which include the completion of the SMR Eagle Ford 3H well, the SMR Olmos 1H well at rates of 1200 barrels and 550 barrels of oil per day prospectively.

These well 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 operations at the end of the second quarter and is now completing an average of four wells per month in South Texas.

With a backlog of seven wells at the end of the second quarter and four rigs, soon to be five, operating, we believe that we've achieved balance between our drilling and completion activities. Pipeline curtailment throughout the quarter demonstrates 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 two new wells on production during the quarter. The LL&E No. 5 tested close to 2300 barrels of oil per day and settled in at a rate of 700 to 800 barrels of oil a 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 five 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 operated 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 are 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 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 outlook for McMullen County natural gas production. Although, uncertainty is always present in our business, there should be no doubts as we have built an organization with prudent leaders and high quality assets that will provide consistent and predictable growth for years to come.

And now I will ask Alton to present second quarter 2011 financial results.

Alton Heckaman

Thank you Terry and good morning. The second quarter was indeed another great financial quarter for Swift Energy, highlighted by considerable production of revenue growth compared to the prior year.

Oil prices improved significantly during the quarter and were clearly in reflected 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 of 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% from the prior year at 2.6 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 than our realized price per Boe.

Our controllable cost metrics came in as follows. Production cost 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 the production in ad valorem taxes came in 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.

And 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 our EBIDTA was $107 million for the quarter. Quarterly CapEX on a cash flow basis was $113 billion, basically cash flow neutral for the quarter.

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

I like to conclude by taking a moment to again highlights Swifts solid financial position. During the second quarter we renewed and extended our credit facility through May of 2016 increasing the volume to 400 million or maintain the commitment now at 300 million. As of the end of the second quarter we had no outstanding balance on line of credit and have 32 million of cash on hand. This strong liquidity position puts Swift on a solid financial footing to continue to execute our 2011 strategy.

And as always we’ve been 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.

Bruce Vincent

Thanks, Alton. 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 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’s production during the second quarter of 2011 totaled 2.64 million barrels of oil equivalent, or 15.84 billion cubic feet equivalent, an increase of 30% over the second quarter 2010 production of 2.03 million barrels of oil equivalent and a decrease of less than 1% from the 2.65 million barrels 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 for a natural gas production in McMullen County, Texas, shut in our operative production for a bit more than four days at the end of the quarter. We were given approximately two weeks notice ahead of this maintenance project making it very difficult to forecast.

The same pipeline operator experienced periodic capacity constraints throughout the quarter, which also limited our natural gas production. These constraints no doubt caused by ever-increasing productivity in 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 a new midstream provider, once the 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 to ability to rapidly increase our daily net corporate production rate and expect our yearend 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 drilled operated wells and participated in two non-operated wells during the quarter. In South Texas, three horizontal development wells, one operated and two non-operated were drilled in Eagle Ford shale formation in South Texas.

Six horizontal developmental wells, all operated were drilled in the Olmos formation. All drilling activity during the quarter in South Texas was in McMullen County. We drilled four almost wells in Eagle Ford wells simply as a result of our drilling schedule and rig moves during the quarter. Our rig schedule is shifted during the third quarter; we are now drilling primarily Eagle Ford wells.

In the Lake Washington Field Southeast Louisiana one development well was drilled. All rigs drilling horizontal wells in the Eagle Ford and are almost are active now in South Texas. As Bob will discuss we are developing more acreage that is prospective for oil and liquids production in this environment.

One operated and one non-operated rig are active in Central Louisiana East Texas core area with the joint expansion of our opportunities and with our partner in the area we are prepared to be active in this area for many years to come.

I’ll briefly review of 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 Lake Washington and Bay de Chene Field, 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, is 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 decline.

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 2011 in the same area and a 91% increase over the second quarter 2010 production volumes.

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

In McMullen County, two Olmos horizontal wells, one operated Eagle Ford horizontal well and two 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 in the same area. Higher production levels in this area resulted from the performance of two 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 we will move this rig to the Masters Creek field next to drill one well.

In our South Louisiana core area which is comprised of Horseshoe Bayou/Bayou Sale, Jeanerette, Cote Blanche and Bayou Penchant, production averaged approximately 1,539 barrels of oil equivalent per day or about 9.2 million cubic feet equivalent 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 the transaction before the end of the year.

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

Bob Banks

Thanks, Bruce. At the Lake Washington Field, we drilled one well, completed two wells, recompleted four wells and performed 24 production optimization projects during the quarter. The CM#420 was recently drilled to a measured depth of 9,882 feet and encountered 150 feet of true vertical net pay in five 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 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 of cubic gas per day with flowing tubing pressure of 1080 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 1020 psi on a 32/64 inch choke.

Both of these wells setup 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 project which includes sliding sleeve, shift changes, gas lift enhancements and returning shut-in wells 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 well in this area. We’ve also increased our commitment to this area through an expansion of a relationship with our joint venture partner. We’ve 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 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 feet minerals 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, three operated and two 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 an 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 have built a backlog of seven drilled, but not yet completed wells. We expect this fleet now to average four 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 four to five 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 4,900 and 22 psi on a 20/64-inch choke.

Moving to our operated wells in McMullen County, two Olmos horizontal wells and one 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, the flowing casing pressure of 5475 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 2450 psi on a 20-64 inch choke.

The SMR 3H Eagle Ford well, with a lateral length of 4850 feet was completed with an 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 1975 PSI on an 18/64-inch choke.

As we have mentioned we are now completing wells in a pace of four per month. So far in the third quarter, we have completed five wells, three Olmos and two 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 5800 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 5400 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 1.6 barrels of natural gas liquids per day, the flowing casing pressure of 2685 PSI on a 20/64 inch choke. The remaining two 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 country acreage. We are preparing for a fifth rig to join our South Texas operations in September and we will use this rig to increase our oil and liquid’s rich drilling activity.

With our drilling in completion activity now and 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've recently begun to experience only underscores how important the long-term relationships and contracts we've entered into over the past two 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 an integrated top tier industry professionals into our operations, they we have contracted and dedicated drilling completion transportation 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 is seeing more clearly now than he has ever seen in the history of the company.

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

Terry Swift

Thanks Bob. Before we open the line for questions, I will summarize Swift Energy’s second quarter results and review some of the highlights from today's call.

Second quarter production growth of 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 one Olmos and one 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 in its own pace to complete an average of four wells per month during the quarter.

We have an adequate well backlog and drilling activity to keep this fleet fully itilized. 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 one operated and participating in one non-operated Austin Chalk well in the same area.

Recent drilling results support increased activity in two areas of the Lake Washington field in Southeast Louisiana. With that summary, we’d like to begin the question-and-answer portion of our presentation.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Leo Mariani through RBC.

Leo Mariani - RBC

I just wanted to check in real quickly on third quarter production. You guys talked about experiencing periodic downtime due to this third party pipeline. Can you give us any indications as to kind of what downtime you might have seen here in July and thus far in August? Are you going to hit with kind of random interruptions thus far?

Terry Swift

We’ve provided that in our guidance. We kind of wrestle, we are trying to understand the whole trend and what other operators might be bringing into the system or might not. But as we talk with our providers and the service companies, the pipeline operator that works with us, we are pretty confident that we are going to add very meaningful deliveries throughout the last third quarter but there is some uncertainty and we’ve already put that into the guidance here. We did see some brief interruption recently and that kind of went away, but it could come back and so we put that in. I think the key element here is that we do have our Southcross deal and it is construction progress is very good. We do expect by the end of the third quarter to be fully up and operational and there will be some transitions there.

We’ve guided, I hate to put a particular number, but we have guided to have a certain amount of downtime that might not have and we also have recognized that we are going to have a fair amount of activity that we have adjusted. For example we have moved into some areas where we won’t have all the constraints. So we have adapted our program a little bit to have mitigated any potential constraints coming out of AWP.

Bruce Vincent

Just a little bit color on that Leo and it is third party and so we don’t have all the information. I am not sure they do, but as we understand it what has happened in South Texas is that you have a number of projects in the pipeline and processing related and other operators could completing a well but there is clearly some pipeline projects that are under construction. They expect them to 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 make it push back a little bit. It hasn’t been s 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 into range of guidance particularly on the low side of that guidance. But as Terry pointed out the important things is Southcross deal is done and pipes in the ground. They are 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 fracking wells down in Webb County here in Fasken which are embedded by those same bottlenecks to minimize the constraints from new production that we’d be bringing during the rest of quarter.

Leo Mariani - RBC

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

Bob Banks

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

Leo Mariani - RBC

Got you. Okay. I guess I imagined that you guys kind of mentioned in your prepared comments, but I imagine you pretty much could be seeking firm capacity deals going forward on any other infrastructure build out. Is that a fair assumption?

Bob Banks

As to fair presumption to make. Basically the one area we have left to focus on is what we call Artesia wells in LaSalle county and we would anticipate making similar top arrangement.

Leo Mariani - RBC

Got you. Okay. Just wanted to see if you could address well cost 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.

Bob Banks

Well, in general in South Texas obviously we’ve come through a period of upward pressure on pricing. I think every areas a little different in terms of commodities in the rigs and frac services and all the rest, but I would say, the way we will characterize is, there are still a little bit of upward pressure but we really see that rate of upward pressure starting to turnover and starting to flatten out now, which is kind of good thing for us.

The other balancing aspect that we’re doing is we’re drilling longer laterals now in South Texas. We’ve gotten to 6,000-foot laterals and we think that’s 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 to $9.5 million that we’ve talked about, we always kind of 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 move into pad drilling.

We’re looking at our casing design, we’ve gone to in one case of walking rigs to save us time from laying down pipe and picking up pipe, we’re really looking into more efficient completion design to speed up our completions and go to even pad fracking. If we go to pad drilling we go pad fracking. All those efficiencies come to bear along with the longer laterals. 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.

Leo Mariani - RBC

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

Bob Banks

Yeah. We understand the Olmos is very well and often in the northern part of the field. That is the more liquids-rich area. The field along with kind of western portion of the field. As you move down south, it gets a little more gassy. But a beautiful thing about the Olmos, either way we get a lot of NGL stream. It’s a very rich gas. So when we get that combination of oil and natural gas liquids in the Olmos, those economics hold up very, very well comparatively. So we are very happy and pleased with our Olmos program. We think we have a lot of room to deliver great results in the Olmos.

Operator

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

Neal Dingmann - SunTrust

Good morning. Good color. Say, Bruce or one 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 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 just 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?

Bob Banks

Yeah. Those are good questions and the things that we rehearsal with all the time is as far as the 6000 foot lateral, we usually pump about 16 to 17 stages for the 6000 footer. So, about 300 foot apart. In terms of going to pad drilling, pad fracking, yeah. That does really play into how you hold your lease position. We have a kind of a first, kind of the first wave of our activities. We want to hold our acreage position. But of course, each acreage position has to standup economically on is own merits.

The second wave is to get into that more manufacturing mode because that's where we really start to squeeze the efficiency. So I think its fair to say we have a little of both going on right now and going into 2012 we will still have some spread out to hold the acreage positions but we will start moving, I think it will be fair to say we will start moving more into the infield drilling late 2012. By the time we are in 2013 we are going to be shifting more heavily into the pad drilling and the infield drilling.

Neal Dingmann - SunTrust

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

Bob Banks

Can you clarify, what area are you speaking of in particular.

Neal Dingmann - SunTrust

I guess you mentioned in here about the node drilling, especially around the Burr Ferry field and some of the other areas kind of that Vernon Parish. Do you look like getting any activity in the area?

Bob Banks

Oh no, yeah, the Burr Ferry area, that is all the Austin Chalk play, which is an oil play. And that's the are where we announced two different ways of AMIs and joint venture agreements with a partner. This is the area where we are 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 two wells that we drilled there came in at very high rates of oil and gas, and we look at the well performance since then and they’ve been very good, very steady, very flattish. So we don’t really see some of the declines like you heard about in the Austin Chalk before. Both of these wells that we drilled late last year have already paid out and they are 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, you know we have two rigs running there now, we would expect next year anywhere between one and three rigs running in that play.

Neal Dingmann - SunTrust

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?

Bob Banks

Yes. I think 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 you know, half a year, you know six months kind of payouts. It’s unbelievable economics. So we are very keen on that area. But we have to go about it the right way. We are using technology to approach this, new and different technology, and so far it’s working for us but it’s still a very much in an appraisal phase. We hope to move that along more into a development phase, here next year.

Bruce Vincent

The other thing that Bob mentioned is worth just highlighting this. The second time is the decline period on these wells if you actually pull the production life, there is some water drive support underneath it. It tends to make it 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.

Neal Dingmann - SunTrust

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

Bruce Vincent

I believe, I would predict prices but that’s our Louisiana oil both in South Louisiana and Central Louisiana is either getting the LLS or HLS pricing you know That tends to be even a little premium to what Brent pricing is, the substantial premium the WTI, we had a really good spread last quarter as you noticed and we think that that trends have to continue. So that’s what that reflects.

Operator

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

Michael Hall - Wells Fargo Securities

I guess just a couple quick ones from 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?

Terry Swift

We like both areas, the first area as we noted we actually expanded that AMI and we are 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 move from there in Burr Ferry more to the East towards Masters Creek, and the second AMI is actually bigger than the first AMI although there is not as many acres accumulated in there just yet though, we are working to increase our position. That moves towards Masters Creek again, very oily, great oil wells over 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 where we’ve established some really great wells, so more to come on that.

Michael Hall - Wells Fargo Securities

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

Terry Swift

The Austin Chalk is really just not got a whole of radar screens with a lot of people. We’ve been planning it for a long time; it’s our backyard going all the away from East Texas, Burr Ferry and the Masters Creek. So yes we’re interested in a more position, but it’s not a big ticket item and there is just not a lot of people that really play this they way all the shale, so everybody’s focus on the shale. So this is a nice complimentary for us; it’s not going to be a big acreage cost number and quite frankly a lot of people just don’t drill these wells today. So I am kind of low plan it because we’re drilling it out like a normal play.

Michael Hall - Wells Fargo Securities

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

Bruce Vincent

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

Michael Hall - Wells Fargo Securities

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. I guess how will we think about any potential upside risk to spending in the second half or you feel pretty comfortable with your current budget?

Terry Swift

Well first were the questions as you used the word risk. I think it’d be a good thing if we’re able to increase spending because it means we’re increasing activity level and we can grow production when we do that. We are trying to ramp up, we’re spending as Bob noticed so we have another rig coming you know that’s not the kind of thing you can just do overnight, but we hope to be able to ramp that spending up but also drive production to higher levels and particular focus on momentum going into the 2012.

In terms of putting that to 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 guided 30 million to 40 million of dispositions, so use the upper range of that number and you know, we’re in good shape. The balance sheet’s in great shape. We have spend cash flow, it’s going to be pretty small numbers and insignificant to the shape of the balance sheet.

Michael Hall - Wells Fargo Securities

Okay. I guess, then just 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?

Bob Banks

No, I don’t think so at all, I mean we have the rigs contracted and we have the momentum and we have the frac crew in place, we got the acreage position, we de-risk our acreage. We can foresee nice steady growth for sometime to come actually.

Operator

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

Jeb Bachmann - Howard Weil

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

Bob Banks

The answer to that is we are using that in conjunction with Petrohawk in some of the JV acreage, we are 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 are watching wells obviously, we have the data, we participate with Petrohawk in those designs, but we have not whole-heartedly shifted to that technology yet, we haven’t seen the results in that way to cause us to do that.

Bruce Vincent

Particularly, in the liquids.

Bob Banks

Particularly, in the liquids rich areas.

Jeb Bachmann - Howard Weil

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

Bob Banks

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

Jeb Bachmann - Howard Weil

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?

Bob Banks

Actually, I don’t. That’s just kind of a little faculty number but it did really fit us, because we’re not heading in 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 of the changes, but right now we think the rock itself is one 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 increases might come by going down that path. We certainly don't see it as part of our operation, right now.

Jeb Bachmann - Howard Weil

And then with the pending acquisition of BHP by 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?

Terry Swift

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 Petro Hawk as a partner, it’s a small part of our business and I would just like to remind folks that even after we get the wells drilled and completed, Swift is the operator of those wells. So, if anything maybe it’s a positive because we are pretty sure that the folks have made that evaluation about that property. We want to keep doing what they are doing.

Bruce Vincent

Yeah, they didn’t buy at the slowdown.

Jeb Bachmann - Howard Weil

And then on the Chalk, I know you guys are drilling one well in the Brookeland area, just wondering if that has any plans for next year or if that might be one of the asset sale targets on that East Texas side?

Bob Banks

Yeah we have not contemplated any kind of asset of sale. We do not have the Brookeland drilling as a priority right now. I think the Burr Ferry Masters Creek areas are really one, where we want to focus our efforts at least for the next couple of years. But that doesn’t mean 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 are focusing.

Operator

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

Adam Lake - RBC Capital Markets

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 estimate and what you learned from that well relative to that field?

Bob Banks

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 are prepared to release reserve estimates or anything like that at this conference call.

But I would say this that 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 five productive horizons in this well bore. This particular well alone allows for two to three more follow on wells in that embayment or fault block area. But it also sets up additional fault blocks along the Westside of Lake Washington and derisk those for us.

So, I think the answer to your question, it was a very meaningful well and a very strategic well for us and we are very pleased with the results and what that means for us down the road.

Adam Lake - RBC Capital Markets

I am not sure if you answered this, but in terms of I know it’s early but some preliminary thoughts on trends next year spending.

Terry Swift

We haven’t completed that and that is early. We go into our budget cycle in October and November with our Board and we’ve got numerous scenarios and factors we’ve got. We’ve got a line of side growth for usually the next five 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 be higher, but we are just not a point really where we could lay that out.

Operator

Our next question comes from the line of Biju Perincheril with Jefferies

Biju Perincheril - Jefferies

First 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?

Bob Banks

Well I think in general in this Olmos area, I think we’ve identified that as about a 40,000 acre position for horizontal drilling, that would be about 250 locations. In terms of, the only part of that. I mean all of the Olmos has very good NGLs associated with it, all of that position. I don’t think I can sit and break up that 40,000 acres for you as far as you know, which is more the oily component but clearly we know where the oily components are, that’s we’re going to be drilling. Its a priority in the Olmos. so I think we do have a pretty good feel for know where we want to drilling our Olmos are almost wells.

Biju Perincheril - Jefferies

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

Bob Banks

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

Biju Perincheril - Jefferies

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 --?

Bob Banks

We actually get a credit. Under the contract we have the right to form that back out we get a credit back so.

Terry Swift

But the terms of that are confidential so we’ve kind of have to leave it at that but it is good commercial arrangement.

Alton Heckaman

And it was a effective mix against the capital expending.

Biju Perincheril - Jefferies

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

Terry Swift

Well, yeah, I think we’ve factored that into our guidance that’s out there. We show that capital spending is a net number and in particular the disposition, which we hope to have completed before the end of the year. You know to the extent that we can ramp up capital spending we want to do that because we’re having a lot of success but there’s only a certain pace that you can do that for. So we believe we’ve factored that in. If we are able to ramp it up a little more than that, we’ll update guidance at the time and hopefully update production outlook at that time.

Biju Perincheril - Jefferies

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

Alton Heckaman

That’s correct and we’re not assuming that we gave the frac crew back either. So we think we’re now synced up and in tandem and feel like we can execute the projects that we’ve got for the entirety of 2011.

Terry Swift

Yeah, 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 activities, water work and you can't forget that there’s a big water system behind all these. So we’ve been spending all the capital dollars on the front side of the year in preparation for the backside of the year.

Biju Perincheril - Jefferies

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

Terry Swift

No. You know, its every thing from acreage to seismic, to facilities and we will break that out at the end of the year as to all that specific.

Biju Perincheril - Jefferies

Got it. And then one 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 you’ve earmarked for sale is significantly higher. So is that a risk number or are you assuming only part of what's out there now will get completed this year or..?

Alton Heckaman

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

Biju Perincheril - Jefferies

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

Alton Heckaman

It’s a risk number.

Biju Perincheril - Jefferies

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

Terry Swift

Well, what was the question again, Biju?

Alton Heckaman

The losses is going as planned and we have submitted the report on that. We will report it, of course.

Operator

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

Marcus Talbert - Canaccord Adams

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 guys attribute that to? Were there any changes in the completion from those two wells?

Bob Banks

No, the completions were very similar, so I mean we don’t have anything in particular to show why that low 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 its being pumped, but we did not change anything in particular from that well to the second well.

Marcus Talbert - Canaccord Adams

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 two weeks or so. Can you comment on sort of the daily production on that well now or if you would be inclined to provide a 30 day rate for each of those SMR wells?

Bob Banks

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

Bruce Vincent

Yeah but going back to your first point and Bob’s answer to that I can’t over emphasize that you know acreage in this play whether its Eagle Ford or the Olmos, the success of that acreage is going to be very, very dependent on actual rock characteristics. So when you see variation from one well to another it often might be the actual rock, the thickness of the rock, the permeability or the porosity or as Bob said just how effective was a specific frac job and getting into the higher quality rock area. So you have to be careful in that and just look at the frac job to say that alone is determining how good wells are. The rock quality is also a key attribute.

Marcus Talbert - Canaccord Adams

Okay, that's helpful. I guess given the rock quality and the productivity you guys are seeing there in McMullen, I think you’ve got two 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 the pad, given the delays that are potentially going to impact the third quarter?

Bob Banks

No. I don’t think we’re quite to the point of going to pad drilling out in the Fasken area and 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 are doing, we’re becoming more and more bullish on what our EURs are going to be in that area. But there 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.

Bruce Vincent

And keep in mind Marcus we’ve got an abundance of time in Fasken and only need eight more wells to hold the entirety of that acreage. So we’ve kind of been guiding though one well a quarter down there will be on average for the next couple of years.

Marcus Talbert - Canaccord Adams

Okay, great. And the new production, I am 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 four or five and at this rate you would be I think four to six. Do you think that could be brought down sooner?

Bruce Vincent

I think we are bringing it down with our own crew and then we’re going to see a need to add a spot frac, it would probably expensive and we’ll get to it and probably have our backlog worked down very quickly actually.

Bob Banks

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

Operator

And there are no further questions at this time; presenters are there any closing remarks?

Bruce Vincent

Well, we just want to thank everybody for listening and I appreciate the shareholders and analysts for their support and if you’ve got any further questions please call Paul, we are available. Thanks again.

Operator

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

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