SilverBow Resources Inc (SBOW) 2012 Q3 法說會逐字稿

Good morning. This is Sabrina and I will be your conference operator today. At this time, I like to welcome everyone to the Swift Energy third-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. I would now like to turn the call over to Paul Vincent, Director of Finance and Investor Relations. Please go ahead, sir.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's third-quarter 2012 earnings conference call. On today's call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review our financial results for the third quarter.

Then Bruce Vincent, President; and Bob Banks, Executive Vice President and Chief Operating Officer will provide an operational update. Terry Swift will then summarize before we open up the line for questions. Also present on the call is Steve Tomberlin, Senior Vice President of Resource Development and Engineering; and Jim Mitchell, Senior Vice President, Commercial Transactions and Land.

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

Thanks, Paul, and thank you to everyone joining the call today. Although we are on track to enter 2013 with our expected levels of operational momentum and production mix, we did encounter several challenges and opportunities during the third quarter which have led us to recalibrate and adjust some of our objectives.

As previously disclosed, Hurricane Isaac caused us to shut down approximately 175,000 barrels of oil equivalent, of primarily oil production, during the third quarter and will defer approximately another 50,000 barrels of production from the fourth quarter. We're proud of how the production team safely prepared for and recovered from the hurricane.

In South Texas, the initial test rates for our first four-well pad met our expectations but lower-than-expected associated gas required installation of artificial lift much sooner than previously anticipated. These lower-than-expected gas-to-oil ratios required us to conduct operations which required significant production downtime as the proximity of these wells to one another required all of them to be shut in to conduct tubing and gas lift installation operations.

We also had some temporary facility issues with this four-well pad operation. These operational complexities with our first four-well pad, zipper-frac design in northern McMullen County have led us to reduce our production forecast. Bob will discuss this particular situation, which we believe is isolated to this particular set of wells a bit later on in our presentation.

Recently in the fourth quarter we completed the McClarty 1H and 2H wells in this same area. These wells have demonstrated significantly higher gas-to-oil ratios and experienced stabilized flow tests rates above 700 barrels of oil per day and 1 million cubic feet of gas per day. This type of result is in line with our expectations for this area and further suggests the unique event with our four-well pad SMR in that area.

As we develop the Eagle Ford and try new techniques to become more efficient, we do continue to find variations in fluid characteristics, rock properties and operating conditions that present both challenges and opportunities as we go through our Eagle Ford development. These challenges, together with the effects of Hurricane Isaac have led us to adjust our full-year 2012 guidance to the 11.6 million to the 11.7 million barrels of oil equivalent range.

Prospectively, we are now a even more confident that we will have meaningful 60-acre downspacing opportunities within our Eagle Ford inventory. Bob will provide more details on our Eagle Ford downspacing tests that we have conducted or are in the process of reviewing in LaSalle County. Our drilling program has also delivered slightly higher concentrations of crude oil and natural gas liquids than forecast, resulting in lower volumes of production, but volumes which yield higher overall value.

Finally, we are executing more production optimization projects on our South Texas horizontal well inventory than originally planned. Which is important relative to long-term performance of these wells, but does require us to shut in wells we are working on to conduct this work, which does also impact in the short-term production.

In spite of these events, our 2012 program will result in production growth of approximately 11% and reserve growth towards the higher end of our expected 15% to 20% target. For the fourth quarter, daily production rate should be greater than 33,000 barrels of oil equivalent per day and fourth-quarter production will consist of between 55% to 60% crude oil and natural gas liquids, further demonstrating the value of our proven asset base.

We've also committed to lower capital expenditure levels, approximately 25% to 30% in 2013, from our 2012 levels, while still been positioned to meet or strategic long-term production growth targets, which are in the range of 7% to 12%.

With the commitment to lower spending levels and growing current inventory, several new strategic growth areas we have developed in an uncertain commodity price environment, we have multiple scenarios that we're looking at for our 2013 work plans and capital budgeting, which we're working through. Our current base expectations for 2013 include keeping three rigs fully utilized in South Texas throughout the year.

We intend to operate one barge rig for a portion of the year in Lake Washington and participate in three to four wells in our Burr Ferry joint venture area targeting the Austin Chalk. We also expect to dedicate a portion of our budget to strategic growth and exploration which will better define our future growth opportunities. As of now, we expect to drill at least one horizontal Wilcox well in Louisiana early in 2013 in our South Bearhead Creek Fields.

Later in 2013, we intend to drill a well in Southwest Colorado targeting the Niobrara formation. Over the past several years, we've put together over 50,000 net acres as position in this area that's prospective in the Niobrara. While there are risks associated with these oil opportunities, we enjoy a very low cost of entry in both these areas and control the acreage we intend to test.

We are also evaluating a third opportunity that, if successful, could also have meaningful growth potential for the Company. As our asset base evolves and becomes more predictable, we will look to mitigate risk to our cash flows through more active natural gas hedging as prices allow. We will look forward to use long-baited swaps, collar transactions and floors to cover portions of our base production. This will naturally and partially reduce our sensitivity to near-term price volatility and enable us to commit to longer-term drilling schedules.

During the quarter, we accomplished several meaningful operational milestones which include -- we drilled 11 wells in South Texas and now have drilled over 100 horizontal wells in total in South Texas. Drilling times continue to improve, driving costs lower. Three new wells were drilled in Lake Washington during the quarter and we conducted a recompletion at our Jelly Bowl prospect with excellent results. We expect to drill a new offset well in this area next year.

In the Burr ferry field in Vernon Parish, Louisiana, our partner tested two wells during the quarter. One well tested above 1,000 barrels of oil and 3 million cubic feet of gas and the other well tested above 800 barrels of oil and 5 million cubic feet of gas.

In South Texas our completion efficiency continued to improve. Costs are decreasing as a greater number of our completions are conducted on multi-well operations. We completed a $150 million bond offering priced at a effective yield below 7%. This successful transaction, coupled with our recent borrowing base increase significantly improves our liquidity.

At the beginning of the fourth quarter, we successfully completed and tested a three-well 60-acre downspacing test in LaSalle County. While further downspacing tests will be required to validate this work, we are excited about the potential to increase our inventory in this high-value area. When I contemplate the opportunity set a company of our size has, with as many options to exploit it as we have, I am extremely excited. We also enjoy a solid operational foundation and financial position and a commitment to expand our operating areas in 2013.

Finally, before turning the call over to Alton, I feel it is important to acknowledge that we here at Swift Energy appreciate the damage and disruption that storms like Hurricane Sandy can cause on daily activities and we do hope for a quick recovery for those affected by this particularly powerful storm. And now I will ask Alton to present our third-quarter 2012 financial results.

Thanks, Terry, and good morning everybody. This quarter continued to be a challenge for Swift Energy as Hurricane Isaac paid the Gulf Coast a visit. But natural gas prices did increase from recent lows and oil prices continue to be relatively strong. Even with the affects of the storm, our production increased 13% from the third quarter of 2011 and declined only slightly from the second quarter of 2012, resulting in oil and gas sales of $128 million, income from continuing operations of $3.1 million or $0.07 per diluted share.

Cash flow before working capital changes for the quarter of $1.66 per diluted share and 2.9 million barrels of oil equivalent of 3Q '12 production. Crude oil prices were 3% lower than a year earlier and natural gas prices decreased by one-third, resulting in an overall 21% decrease in our realized price per Boe in 3Q '12 versus 3Q '11. With our current mix, approximately 83% of our revenues came from crude oil and liquid sales during the quarter.

Our controllable cost and metrics compared favorably to guidance, even with hurricane-affected production volumes. Production costs came in at $9.26 per Boe, well within guidance. G&A came in at $4.16 in the middle of guidance. DD&A was well below guidance at $20.52, due to higher reserve volumes and improved cost efficiencies. Interest expense came in at $4.79 per barrel, slightly above guidance. And production and ad valorem taxes were slightly below guidance at 8.3% of revenue, due primarily to the hurricane-affected production mix.

As previously mentioned, the net result was income for the quarter of $3.1 million or $0.07 per diluted share, well above the first call mean estimate. Our effective income tax rate for the quarter was 43.7%. Cash flow before working capital changes for 3Q '12 came in at $71 million or $1.66 per diluted share, while EBITDA was $79 million for the quarter. CapEx on a cash flow basis was $201 million.

Let me wrap up my discussion by highlighting two recent financial events. As Terry mentioned, in early October we issued an additional $150 million of Senior Notes as an add-on to our 2022 debentures, and used the proceeds to pay down the balance on our credit facility. These notes were priced at a yield of a little less than 7%. We're also pleased to report that we recently, in conjunction with our semiannual borrowing base review, extended our credit facility through November 1, 2017 and increased our borrowing base and commitment amount to $450 million.

Depressed natural gas and NGL prices in the near-term still pose a significant challenge to our sector. But with our expanded liquidity, our inventory of liquid-rich projects, and over 80% of our revenues coming from oil and liquid production, we feel we are very well-positioned to continue to execute our strategic plans. As always, we have included additional financial and operational information in our press release, including guidance for the fourth quarter of 2012. With that I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton. Good morning everyone and thanks for listening. Today, I'm going to discuss the third-quarter 2012 activity, including our production volumes, our recent drilling results, activity in our four operating areas and our plans for the fourth quarter in 2012. And then I'll turn it over to Bob for a little more color with regard to these areas.

Beginning with production, Swift Energy's production during the third quarter of 2012 totaled 2.87 million barrels of oil equivalent, within our previously issued expected range when adjusted for the 175,000 barrels of oil equivalent impact from Hurricane Isaac. Approximately 50,000 barrels of oil equivalent of production are also expected to be deferred from the fourth quarter as a result of that storm.

Third-quarter production was 13% greater than the third quarter of 2011 production of 2.54 million barrels of oil equivalent, and decreased 2% from the 2.92 million barrels of oil equivalent produced in the third quarter of 2012. The third-quarter drilling results, Swift Energy drilled 14 operated wells during the quarter and participated in two non-operated wells.

In South Texas, 11 operated horizontal development wells were drilled in the Eagle Ford shale formation in South Texas. Seven of these wells were drilled in McMullen County and four were drilled in LaSalle County. In Swift Energy's Southeast Louisiana core area, three wells were drilled in the Lake Washington Field. In the Company's central Louisiana-East Texas core area, two non-operated wells targeting the Austin Chalk were drilled in the Burr Ferry Field.

We currently have three operating drilling rigs in our South Texas core area, all of them drilling the Eagle Ford shale wells. And we also have one operated barge rig drilling in our Southeast Louisiana area. And one non-operated drilling rig active in our Central Louisiana-East Texas area.

In the South Texas core area which includes our AWP, Sun TSH and Las Tiendas Olmos Fields and AWP Artesian wells and Fasken Eagle Ford wells. Third-quarter 2012 production averaged 23,620 net barrels of oil equivalent per day, a 1% increase in production compared to the second-quarter 2012 production in the same area, and a 52% increase over third-quarter 2011 production in the same area.

As drilling activity slows from our decision to reduce rig activity in this area to better match capital spending and cash flows, we also expect sequential production growth will flatten as fewer new wells are added each quarter over time. As evidenced by our higher-intensity drilling activity, we are moving closer to having appraised all of our high-value acreage through the drill bit and we will be closer to a full scale manufacturing mode by the end of the 2013 program.

In our Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene Fields, production during the third quarter averaged approximately 5,040 net barrels of oil equivalent per day, down 20% when compared to the second-quarter 2012 average net production for the same area.

Lake Washington specifically averaged approximately 4,750 net barrels of oil equivalent per day, a decrease of 20% when compared to the second quarter of 2012 average day logs. Production volumes would have grown approximately 10% over the second-quarter 2012 levels, had Hurricane Isaac not shut in the 175,000 barrels of oil equivalent during that quarter.

Bay de Chene's sequential production decreased 20% to 290 net barrels of oil equivalent per day. This sequential decline is due to no new drilling activity and natural declines as well as the downtime associated with Hurricane Isaac.

The Central Louisiana-East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry and South Bearhead Creek Fields, contributed 2,558 net barrels of oil equivalent per day of production in the third quarter of 2012. An increase of 6% over the second quarter 2012. Higher production levels in this area are due to non-operated wells that were brought online at Burr Ferry Field during the third quarter. I'm now going to turn the call over to Bob Banks to review operational highlights of the quarter.

Thanks, Bruce. At the Lake Washington field during the quarter we completed four wells and performed 14 production optimization projects, which include sliding sleeve shift changes, gas lift enhancements, choke changes and returning shut-in wells to production. These types of operations are the backbone of our current base production management program in the field.

One re-completion in particular, on the LL&E No. 5 well, also referred to as the Jelly Bowl prospect, tested at rates above 1,500 barrels of oil per day. This type of result highlights the opportunities that still exist in Lake Washington, in addition to the new drilling activity.

We did drill three wells during the third quarter at Lake Washington and we will maintain a one-rig program throughout the end of the year and on into next year in this area. We completed one well at Lake Washington during the third quarter, the CM 423, which was drilled through a measured depth of 9,016 feet, encountered 202 feet of true vertical pay and tested 912 barrels of oil per day in 0.3 million cubic feet of gas per day on a 22/64-inch choke.

Over in the Central Louisiana-East Texas area, in the Burr Ferry Field, the non-operated GASRS 34-1 well was completed in the Austin Chalk during the quarter. The initial production rates on this well were 840 barrels of oil per day and 5.1 million cubic feet of gas per day, with flowing tubing pressure of 2,520 psi on a 30/64-inch choke.

A second non-operated well, the four-star 18-1, was also completed. Initial production test rates of this well were 1,056 barrels of oil per day and 3 million cubic feet of gas per day with flowing tubing pressure of 4,000 psi on a 30/64-inch choke. We remain encouraged by the strong well results from this area and continue to believe the Austin Chalk project area has the potential to be a meaningful growth area for us. One non-operated well is currently being drilled in the Burr Ferry area and we expect to participate in at least three more wells in this area next year.

Moving on to South Texas, 12 Eagle Ford horizontal wells were completed during the third quarter. In this morning's press release, we included a table highlighting test data from these completions. Swift Energy continues to adjust our completion and production techniques to optimize production. In addition, we continue to benefit from more efficient drilling and completion times as we move past appraisal mode and into development mode in some areas.

As Terry mentioned earlier, we did experience some unexpected delays during the completion of a four-well pad project in the FMR area in northern McMullen County. The first delay was related to the simultaneous fracking operations themselves, where faulting in the area caused interference between these close-proximity wells, resulting in sticking some tools downhole. The second and more significant delay, was related to the unexpectedly low GORs of the Eagle Ford wells compared to offset SMR Eagle Ford locations, as well as the greater northern AWP area of McMullen County.

Most wells in these areas have of GORs 1,000 to 2,000 to 1. These wells had GORs of about 600 to 1. That is requiring us to move much more quickly than planned on our tubing installation and gas lift operations. Due to the close proximity of the wells on this four-well pad, we were required to shut in all wells on the pad for most of October to conduct these operations, thus delaying production from this key area.

While the lower GORs of these wells were below original forecasts, we did achieve expected initial oil production rates and still expect these wells to perform well once they are all on gas lift and have tubing installed. As a result of the lessons learned, we have modified our pad fracking operations to ensure that we do not cause this type of pressure interference in our pad wells in the future. Especially in areas with known faulting.

A good example of the changes we made can be found in the next two wells in this area that we have recently completed. The McClarty 1H and 2H were recently completed and are currently flowing back at an average stabilized rate of 708 barrels of oil per day and 1.3 million cubic feet of gas per day. The GORs in these wells are much more in line with our model expectations throughout northern AWP area.

As we have pointed out, we have reduced our South Texas drilling activity to three rigs, down from the six. Primarily to better align our spending levels with cash flows. This reduced pace of drilling has allowed our asset team to spend more time evaluating existing wells and developing production optimization programs based on historical production data.

One of the results of this evaluation work has been to increase the amount of tubing installations we are conducting on the in-service wells. While we have to shut in a while for several days to perform this activity, it better manages the reservoired results in flat or production and pressure declines for the long term. This operation is really important for all of our lower GOR wells.

While we have elected to maintain a slower pace of drilling in South Texas, we have also taken steps to increase our inventory through downspacing. In artesian wells we recently completed the base 1H, 2H and 3H, all on a 60-acre spacing design. These wells all tested at rates above 1,000 barrels of oil equivalent per day and were greater than 55% liquids.

I believe our acreage in LaSalle County may prove be our highest value acreage. We're seeing our lowest drilling costs in this area, while drilling liquids-rich wells with good pressure support and higher GORs. While we need to continue to test our downspacing assumptions, we are thrilled by the early results here.

Terry indicated earlier a commitment to expanding our operational horizon to its strategic growth and exploration. This is a critical component to our future and we work very hard to put in place a strategic growth framework, which will support intelligent risk-taking and move toward to steady diet of growth opportunity for Swift Energy.

In 2013 alone, we will test at least two opportunities in different areas where the Company controls significant acreage and has a low entry cost. We are also evaluating a third opportunity with meaningful running room but this play hasn't yet been sufficiently de-risked.

Early in the year, we will drill a horizontal Wilcox test in our South Bearhead Creek Fields in Beauregard Parish, Louisiana. We have already drilled a number of strong vertical wells in this area, giving us confidence in our ability to utilize our horizontal drilling and multi-stage frac technology in this prime position of the trend. Additionally, we have observed high-quality offset operators significantly improving their results through the use of horizontal drilling technology.

In a second area, our land organization has done an incredible job of putting together a large acreage position in the Four Corners area of Colorado that is prospective for Niobrara development. Their work, as well as the subsequent technical evaluations that we have conducted, have put us in a position to drill at least one test well in this area next year.

All of these growth opportunities exist in regions with extensive histories of oil and gas production and represent the types of opportunities we will continue to develop through our strategic growth framework. It is safe to say that although we expect to have less South Texas drilling activity next year, we will be busier than we have ever been. We are in a growth mode at Swift Energy and continue to build an asset base and opportunity set unlike any the Company has ever seen. With that, I thank you for your attention this morning and I going to turn it back to Terry to recap.

Thanks Bob. Before we open the line for questions, I will summarize Swift Energy's third-quarter results and review some of the highlights from today's call. Despite Hurricane Isaac and isolated delays with the four-well completion pad in South Texas, we anticipate fourth-quarter daily production above 33,000 barrels of oil equivalent per day. We also expect reserve growth to be at the high end of our 15% to 20% growth target, continued strong drilling results in Louisiana and improving drilling and completion costs in South Texas.

Fourth-quarter production will be close to 60% crude oil and natural gas liquid production, up from 45% in the first quarter of 2012. We recently completed a successful 60-acre downspacing test with three wells in La Salle County. We expect to test three new play areas with the drill bit in 2013. With that, we'd like to begin the question-and-answer portion of our presentation.

(Operator Instructions)

Neal Dingmann, SunTrust.

Morning, guys.

Morning

A question, obviously the success you have had in LaSalle, it looks like, or just recently had in the downspacing. I was wondering if you could give me an idea, is that going to be, you think, now the downspacing and that will be throughout La Salle? Is that going to -- you'll try the same thing over in McMullen and some other countries in the Eagle Ford? I wonder if you had that success, will you just immediately start to go to the downspacing? Or do you still have to hold some other acreage first?

Oh, that's a good question, Neal. Let me take a crack at that. Yes, in La Salle County we feel very good about the 60-acre spacing. We will probably even test further downspacing after we get a little more production history from these three wells on the 60s. Over in McMullen County, we are actually doing a downspacing test now where we are just completing the drilling of them and we will be fracking them and bringing those onto production. So we are continuing to down test over in McMullen County. So the answer is we are going to continue to do downspacing tests in all of our areas. And we would like to get to the answer sooner rather than later. Because obviously it's more effective development if you can walk away at the ultimate optimized downspacing than to be coming back later and drilling in between wells that have already been producing. So that is our objective.

Got it. And then just wondering, maybe just one last one and I'll turn it over. Just for Alton or maybe Terry, an overall strategist on hedges. Your thoughts, again I know you've got -- had a little bit on -- it looks like a bit rolling off at the end of the year. Your thoughts today, obviously you are sitting pretty well financially, so just your thoughts as far as potentially adding hedges as we go into next year?

Yes, I think as we mentioned in the conference call script, that we're starting to have discussions and look at potentially longer swaps in those items as opposed to utilizing the floors and participating collars. So we see it as the inability to lock in prices and be able to take particular areas and accelerate those projects, once you have got your locked-in pricing. So it's something we're looking at and you're right, we basically had a small amount of protection in the form of floors in the fourth quarter, but we don't have anything right now into 2013. But we have those discussions on an ongoing basis.

And I think, Neal, this is Bruce, we would if we saw a market out there. Right now you look at the forward curve, it is really not conducive on the gas side yet, to pick something up there.

Bruce, if I could just sneak one last one, your partner on Burr Ferry, what -- I know you've talked around this, just your thoughts as you go into next year on how, if they'll stay as active in that block.

We expect them to -- we indicated that we thought we would drill three to four wells. We expect them to stay active in that. We have not together settled on a plan yet, but we think three to four is probably a pretty good -- could be five, but somewhere in that neighborhood.

Yes, Neal, I think we had some regular partner meetings going on here this week and we're going to bring a little more clarity to budget more program issues for next year.

Very good, thank you.

Biju Perincheril, Jefferies.

A couple of questions. First, in the Eagle -- you talked about in the press release, rock properties, you referred to in your comments about [byreams], or guidance, production guidance. I'm just if you could elaborate a bit more on that and if you see any impact to your [UR] assumptions with that?

No, I think, yes, the reference to the rock properties, obviously as we're moving around, drilling wells in this area, GORs are changing around fairly rapidly. And that northern AWP area as an example, we are probably going to some sub-models of our general model there based on wells that continue to be drilled in close proximity, changing slightly some of our GORs. In terms of the rocks properties that was mentioned, really that is a positive thing in my mind. And that really comes from the 3-D seismic that we shot over the area. We have a very strong geo-technology group here at Swift that has used that 3-D seismic to extract a number of different attributes, some of which are proprietary that have been developed, that really, now, help us to take that lower Eagle Ford sweet spot zone where we would drill our horizontal lateral and geo-steer in a wider 40-foot or 50-foot interval. These guys now have been able to break down that lower Eagle Ford into even some sweet spots where we may have more brittleness. They may want to target even a 10-foot to 20-foot zone to make sure we stay within the most brittle of the rock. So that is the type of rock property analysis that we're doing based upon the 3-D and the geo-technology.

Have you drilled any wells with the new and improved targeting? Or if not, when will that be tested?

Yes, actually these three wells, or two of the wells that we talked about, the McClarty wells, we targeted that brittle zone. We also have another PCQ well on flowback right now that is looking very strong. We targeted that brittle zone. So it is early to talk too much about that. But we are testing that.

Okay. And then, Lake Washington and the Jelly Bowl. I think that well was initially completed early last year. So having to recomplete that in less than two years, was that expected? And the new reservoir that you are recompleting in, how does that compare to the initial reservoir?

I think the lower zone that we completed was just one of the intervals that we logged in that well bore. We have still have behind-pipe zones. We only completed it using a single selective method as opposed to a dual selective. So what we like to do is really start at the bottom and work our way up, when we do a completion methodology like that in these deeper parts of the reservoir. So it is not unexpected that we are going to take the lower interval first. That was also a strong producer. But it is depleted to the point, and we have had some water encroachment, that we are just now coming back up the hole. So that is a pretty typical operation at Lake Washington. And we will always try to start at that lowest sand interval.

Okay so in this new -- should we think about having some similar type of life fuel?

Yes I think probably similar. I don't have the maps here in front of me. But probably pretty similar.

Okay. And then one last question. The Austin Chalk wells, the two completions. Were they turned into sales in the third quarter, if you could use roughly what -- when they were turned into sales?

I'm sorry? I think I missed that question.

Where are they in relationship to the other wells that we drilled.

Oh, yes. Okay. There were two wells drilled. The GASRS 34-1 was in generally that same area where we drilled our earlier GASRS wells. But the Four Star 18-1 well was quite a step out. That actually went into our AMI 2 area to the east. That was a very positive development. We really liked seeing the fractures that were developed over in that eastern position. So that now builds us a lot of confidence to drill back towards that AMI 1 area and those GASRS wells.

Yes, you may recall, Biju, that we had an original AMI in the joint venture with Anadarko then added a second AMI which adjoins -- the AMI 1 and AMI 2 border each other AMI 2 is acreage to the east. So what that Four Star well does is actually extend the play further to the east. So that is very encouraging with that kind of result.

Yes and then you have the mineral rights in AMI 2?

The mineral rights? No.

Just another thing to point out. AMI 1 is a 50/50 working interest joint venture where we do have a lot of mineral rights in some of the acreage. AMI 2 is a 55% Anadarko, 45% Swift and we really don't have any mineral rights in the AMI 2.

Got it. And then, I was wondering if you could say when these wells were turned into sales?

First production --

Right around the --

Yes, mid-September. Something like that, mid-September, late September.

Okay. Got it that's all I had. Thank you.

Thank you, Biju.

Kyle Rhodes, RBC.

Hi, guys. Wondering what your current Eagle Ford well costs are running and what you are budgeting for 2013?

Well, yes, that is a good question. Over in LaSalle County we are actually beating our well costs quite a bit. I think what we put out at analyst day was probably around $7.5 million, completed and hooked up. One well we drilled this quarter, we drilled from spud to TD in 12 1/2 days, as an example. So we are regularly drilling these wells much faster. The completion operations where we have gone from last quarter, doing about 227 stages in the quarter, to about 260 stages this quarter. We're routinely getting seven stages a day. Probably our best day this quarter was nine stages. So, I would say you are down in the LaSalle County area in the mid to high sixes now. Over in the AWP area, we're pretty much tracking those costs that we've presented at our analyst day and put out there publicly, so we're right on those. And then up in the SMR area, we are probably beating our well cost there little bit. So we are fine-tuning our cost estimates by area, for the next year's budget. But overall, we have seen a pretty good trend that we are happy with, in two of the three areas.

Yes, let me add to that. The well costs Bob is referring to do not include some of the other costs that you front-load these campaigns with, such as your land cost, your facilities, you're gathering, your water and handling. So just remember, you do front-load a lot of this activity with those kinds of costs, and he's just referring to the well cost.

Okay great. And then are you guys still acquiring acreage in Colorado? Or are you happy with your position?

Oh, we are still acquiring acreage.

I think it is a yes and a yes. (laughter) We're happy with the position and we're still acquiring acreage.

Fair enough. And then one last one for me. Does your 7% to 12% production growth tentative guidance, does that include any production from Wilcox, Niobrara, or your stealth area?

We don't really have anything in there from Niobrara. We do have some expectation in there, a small piece from the Wilcox.

Okay. And nothing in the stealth area?

I'm sorry?

And then nothing from your unidentified area?

Oh, nothing from the unidentified.

Okay, thanks. That's it for me, guys. Appreciate it.

Thank you.

Noel Parks, Ladenburg Thalmann

Good morning.

Good morning. Hi, Noel.

Sorry if I had to drop off for a bit. But did you -- the particular area that you were going after in the Niobrara and considering the areas that the play covers, discuss how you picked that particular neck of the woods?

Why that area?

Well, I think it suffices to say the Niobrara is a very, very significant play in the Rocky Mountains in general. And it is present in many basins, and these inter-mountain basins in particular. We are looking at it in more than one place. But what we are talking about now, in terms of the 50,000 acres where we are interested in acquiring more acreage, is the Four Corners area, the northwestern portion as you get near the monocline coming up out of the San Juan basin. And there we do see some really nice vertical oil completions in the Niobrara. Traditionally they are small little wells. But with this technology, we think we can go in and do multi-stage completions and make some nice oil growth out of it. But we still got to test it, it's still early. It's got to be de-risked. But we like the Niobrara section. The section as a whole is like 1500 feet, but there are two members within it that are smaller than that in there, 150-foot, 300-foot range, that we probably will be testing both members of what is referred to as like the Smoky Hills section.

Okay, great. And if I remember, you have had some acreage in that area for at least a few years, if I remember right. I thought you were going for deep gas there at one point, maybe the Mancos, or something like that. Is this the same area or just near where you had previously had acreage?

Well, there may be a little bit of confusion, there. You know the San Juan Basin is a massive gas play. And whether you are looking at Niobrara, or you're looking at -- as you get deeper into the basin, the Niobrara can be gassy. We are up on what we think is the condensate to oil window is what we are playing. But the San Juan Basin, there have been some horizontal multi-stage fracs done deeper in the basin and they have been successful for gas. We are not targeting gas. Our acreage is not there. It's more along what we think is the oil prospectivity. There are other formations, Dakota-Gothic formations in that area that have other potential that might involve gas. We have taken multi-year leases. A lot of these are long-term, five-year with five-year kicker kinds of leases. So we weren't jumping in there trying to do something real fast and quick. We have made this a long-term type of play. We're going to test it appropriately. We may test more than just the Niobrara. We're focused on the liquids though. And that is not deep. We're typically going to be looking at somewhere between 5,000 feet to 8,000 feet, something in that range.

Noel, to answer the first part of your question, yes. This is the same acreage that we have been showing in our public filings up in that area for a number of years. We have been methodically acquiring this acreage and getting a big enough footprint before we wanted to talk about it, just more than anything to protect our flanks.

Great. That was just what I was wondering. That's it for me. Thanks a lot.

Porter Pursley, Raymond James.

Hi. Good morning, guys. Just a quick question in regards to the Eagle Ford wells that you completed in South Texas in the table in the release. Can you identify which wells you characterize as oil versus condensate in both LaSalle and McMullen?

I am pulling that out now. I think one of the other things I want to point out, too, out of here, you will see we're really, in these tests, experimenting with some of the restricted choke settings a bit, we are going through some calibration to our baseline models. But, if we just start at the top of that table, I would say the first five wells, those are in the condensate window. And then as you get down to the haze to the SMR, those are all would be in the oil window of McMullen County.

Okay. Well, great, that's all I have. Thanks guys.

Thank you, Porter.

(Operator Instructions)

Michael Hall, Robert W. Baird.

Hi. Can you hear me all right?

We can, Michael.

Sorry about that. Yes, I guess just a couple of quick ones on my end. If you could, you have got a decent ramp down needed in terms of the trajectory of spend fourth quarter versus third quarter. Maybe can you add some additional color around how you execute on that and get us a bit more comfortable there?

Yes, okay, so let's just take it by area, kind of at a high level. We can talk more detail, if you'd like. But in South Texas, we've reduced from six rigs to three rigs. In the Central Louisiana-East Texas area and the chalk, we've reduced from two rigs to one rig. Down in Lake Washington we have reduced one of our work-over rigs. So that is the ramp down and how we are going from Q3, where we actually had a lot of efficiencies in drilling and completion times that really pulled some capital into that cooler. But the ramp down, if you go through all of this, we are ramping it down probably another $70 million or so, to what our fourth-quarter numbers are going to look like.

Great. That's very helpful. And I guess the only other outstanding one on my end is on that Wilcox, do you have any idea in terms of how that well will be designed yet, in terms of lateral length frac stages, and that sort of thing? Or is that still in the works?

Well, it's being fine tuned. We have some pretty good ideas about what kind of lateral length we want to get and how many stages want to put in there. We may not -- the first step, we may not push it out into these 6000-foot laterals. But we will give it a good go and get a good lateral length out there and get the multi-stage fracking in, similar to what we do down in the Olmos and the Eagle Ford. We do have quite a bit of experience in the vertical wells here, fracking vertical wells. So we have a good idea how we want that to be ultimately designed.

Yes, I'd like to add that this field where we want to apply this has really has got at least five Wilcox zones in there that vertically have been very commercial in their own right. And, yet, across the field those five zones do change a little bit. We do think we are in the sweet spot of the overall Wilcox trend. So if you look at a typical vertical well in a typical zone in there, it's not unusual to make a 0.25 million barrels out of one of those zones. So we are pretty excited about how we can optimize using this technology in that area.

Yes, just a bolt on to what Terry said, it is not that large of an acreage position aerially. But we do have multiple pay horizons staffed up. Each would require probably horizontal wells into those different zones. So it does present us with a fair bit of running room if we can get this technology working for us.

Great. It will be interesting to see how it shakes out. I appreciate the color guys. Thanks.

Thank you, Michael.

(Operator Instructions)

At this time there are no further questions.

Okay, well, we would like to thank you for joining us on our conference call and look forward to our next report with you. Thank you.

This does conclude today's conference call. You may now disconnect.