Swift Energy Q1 2009 Earnings Call Transcript

| About: Swift Energy (SFY)

Swift Energy Co. (NYSE:SFY)

Q1 2009 Earnings Call

May 07, 2009 10:00 AM ET


Paul Vincent - Manager of Investor Relations

Terry E. Swift - Chief Executive Officer

Alton D. Heckaman, Jr - Executive Vice President and Chief Financial Officer

Bruce H. Vincent - President and Secretary

Robert J. Banks - Executive Vice President and Chief Operating Officer


Andrew Coleman - UBS

Ken Carroll - Johnson Rice & Company

Jeffrey Robertson - Barclays Capital


Good morning. My name is Kristy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy First Quarter 2009 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 will now like to turn the call conference over Paul Vincent, Manager of Investor Relations. You may begin.

Paul Vincent

Good morning. I am Paul Vincent, Manager of Investor Relations. I'd like to welcome everyone to Swift Energy's first quarter 2009 earnings conference call.

On today's call Terry Swift, Chairman and CEO will provide an overview. Alton Heckaman, EVP and CFO will review the financial results for the fourth quarter. Then Bruce Vincent, President and Bob Banks, EVP and COO will provide an operational update. Terry Swift will then summarize before we open it up to questions. Also present on today's call is Mike Kitterman, SVP of Operations.

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 E. Swift

Thanks Paul. Thank you again for joining this morning's conference call as we review Swift Energy's first quarter 2009 results.

While the global economic and commodity price picture remained weak during the first quarter, we've recently seen signs that the settlement may be beginning to improve. Crude oil prices have in fact improved from their lows in February. Although, the natural gas prices have stayed weak as demand has softened and activity has just recently begun to slow, rig counts continued to be increased during the quarter, which will also help the supply and demand imbalance in the future.

We expect to see an overall decrease in the U.S. domestic natural gas supplies for four year end. We think that's a very strategic assessment right now.

We've witnessed over third... we've seen 30 years of business activity, the company will be celebrate its 30th anniversary later this year in the fall. And we know that lower energy prices have generally contributed in a significant way to economic growth.

We've also seen the federal government follow through on its commitment to supply liquidity to a variety of markets. Should these combinations of significantly reduced energy prices and government support be effecting, we should see a pick up in economic activity at some point which will begin to reverse the energy demand and usage declines that we've seen.

In this slide, Swift Energy is balancing its efforts to protect our balance sheet and ensure liquidity in a poor economic and operational environment with the flexibility to act and deploy capital quickly when the economy and the commodity pricing environment improve.

We've begun to see oil fuel drilling and service costs decrease, but we know that these cost can and will continue to move downward until they more accurately reflect the current oil and natural gas pricing environment. As stated in previous calls, we have a conservative approach to the financial side of our business.

During the first quarter, we worked closely with our banking group to successfully re-determine our revolving credit facility. Times have not only difficult in our industry, but in the financial sectors as well. We are thankful to be working with the group of banks who have faired well during this recent turmoil in the financial markets.

With a borrowing base of $300 million and only $224 million drawn our line as of the end of April, we have access to sufficient capital to continue our basic business activity and maintain our strategic opportunities.

If the environment were to deteriorate further from here, we still have running room, but would obviously consider further defensive measures such as further cost cutting, monetization of strategic acreage and deferral of other growth plans. Alton and Bob will provide some more details on this in just a few moments.

In a time when the capital markets are not functioning efficiently, we have many more projects that are internally generated cash flows will allow us to develop on our own. We're also evaluating potential of including industry partners in some of our plans. We believe that we have a tremendous strategic value in our resource play acreage and our dig gas prospects. This value can be tapped and accelerated with the right financial and operating partners.

Operationally, even with the significantly reduced capital spending budget and activity levels, Swift did have an excellent quarter. Bob and Bruce will review our activity in a bit, but first I'd like to touch on the highlights of the quarter.

Operational highlights of the quarter include the successful hookup of the State Lease 18669 #1 exploration well at the Shasta prospect in our Southeast Louisiana core area. Developing an idea into an exploration prospect and seeing it ultimately owned production is very rewarding. This well is now flowing to sales through the West Side facility in Lake Washington. These types of projects always serve as a reminder that the people in our organization are the true value creators and that they grow the assets that they work.

We continued to evaluate our large regional 3D dataset in Southeast Louisiana and have developed a number of exciting opportunities in the Bay de Chene and Lake Washington fairway area.

Recovery from damage caused during the 2008 hurricane season in Bay de Chene has progressed, but there is still work left to be done. Some natural gas production has been restored, but the company currently has approximately 1,500 to 2,000 net barrels of oil equivalent per day of shunted production awaiting facility repairs in Bay de Chene.

As we near the 20th anniversary of our operations in AWP in our South Texas core area, we have begun utilizing new drilling and completion technologies, which may allow us to be active in this field for 20 plus years.

Our first horizontal well in the Olmos formation, the Robert Bracken 33H well continues to perform inline with our pre-drilled models. This performance encourages us as we proceed to drill our next horizontal well in this area during the second quarter. This next well will also be located in the southern portion of the field and should support an extension of the productive day elements of AWP itself.

Just as importantly, this next well will cost approximately $2 million less than the first horizontal well, the Robert Bracken 33H.

We continued to annualize the potentials that all of our South Texas acreage has for both the Eagleford Shale formation and other emerging place. Bob will discuss our land position in greater detail. But I am pleased with the work our folks have done to grow our Olmos and Eagleford positions at a very attractive price. We're planning to drill at least one well in 2009 to test the Eagleford Shale formation on our acreage.

For the duration of 2009 and beyond, we will make prudent, capital and operations decision with the interest of our stakeholders first and foremost. Although, the 12 months outlook for oil and gas prices is still relatively weak, we continued to build, maintain and high-grade a large inventory of properties and projects which will create values for many years to come.

With that, I'll ask Alton to present the first quarter 2009 financial results.

Alton D. Heckaman, Jr

Thank you, Terry and good morning everyone. The oil and gas sector experienced continued volatility during the first quarter 2009 and lock-step with the global economic environment.

Swift Energy's financial results for the first quarter reflect this volatility. Revenues were $76.4 million, a 62% decrease from 1Q '08. Swift recorded a $79.3 million non-cash, full cost ceiling write-down at the end of 1Q '09 as our pyridine prices further declined from year-end 2008. The write-down was $50 million after tax.

Excluding this non-cash write-down, our loss from continuing operations would have been $9 million or $0.29 per diluted share, beating the First Call mean estimate of a $0.38 loss, while our cash flow before working capital changes came in at a $1.49 per diluted share. Both crude oil and natural gas prices declined significantly from first quarter 2008 levels.

Swift's average realized price received in 1Q '09 decreased 58% to $32.29 per Boe as crude oil prices averaged just over $41 per barrel, versus $99 per barrel in 1Q '08 and natural gas prices averaged approximately $4 per Mcf, compared to almost $8 per Mcf last year, resulting in an overall decrease in our quarterly oil and gas revenues of 62% when compared to the first quarter of 2008.

We continued to vigilantly focus on our controllable per unit cost and metrics, especially given the recent pricing volatility and the downturn in the industry.

With respect to our 1Q '09 results, G&A came in at $3.56 per barrel, slightly below our guidance. DD&A per unit came in at $18.57 per Boe within guidance.

Production costs came in below our guidance at $8.37 per barrel as targeted cost reductions in several categories were realized.

Interest expense came in at $3.16 per barrel, below our guidance and production taxes came in within our guidance as a percentage of revenue, mainly due to the production mix for the quarter.

As previously noted, the company recorded a 79 million pre-tax non-cash reduction in the carrying value of oil and gas properties at the end of 1Q '09, in accordance with SEC, fuel cost ceiling test rules. As you know, the ceiling test rules require the use of period end pricing held cost and forever into the future.

The chart of this quarter was based on March 31 prices. Both oil and natural gas prices have subsequently increased from the March 31 levels. By way of example is current prices were substituted, the same computation would not have resulted in the ceiling test charge thus highlighting the volatility and sensitivity of this computation.

The bottom-line result was a loss from continuing operations for the quarter of 59 million, which is a $1.90 both basic and diluted. And excluding the non-cash full cost ceiling write-down, our loss would have been $9 million, $0.29 per diluted share, again beating First Call mean estimates.

Cash flow before working capital changes for 1Q '09 came in at 46 million or $1.49 per diluted share, while EBITDA was 39 million for the quarter or $1.26 per diluted share. Accrual basis CapEx was 47 million, primarily the result of the completion of 4Q '08 projects.

Given the recent global credit crisis and the effect on the financial markets, let me spend a moment to highlight Swift's solid financial position and discuss a few of our cost containment initiatives.

As previously announced, our line of credit re-facility with our 10 member bank group that currently runs through October 2011 was recently set at 300 million for both the borrowing base and the commitment amount.

Applicable LIBOR and prime borrowing margins were also increased, but are still quite attractive in this current credit environment.

Swift had an outstanding balance underlined of 237 million at the end of the first quarter result of the previously mentioned rollover of year-end '08 cost into '09 and a lower nature gas pricing environment. And as of April 30, the most recent month in, the outstanding amount have been reduced to 224 million.

Our current cash forecast currently do not anticipate our draw downs exceeding 215 million at any point in 2009. We therefore feel our liquidity and resources are solid and provides Swift with the ability to weather these difficult financial times.

Swift has initiated several programs that mandate greater fiscal discipline with an emphasis on reducing our cost across the enterprise. In 1Q '09, we implemented a reduction and in our workforce and have also implemented other cost saving initiatives in the G&A area that will have a meaningful impact going forward, and which is reflected in our guidance.

We're also looking closely at our capital expenditures and operating expenses and have identified several cost saving opportunities in all of our core operating areas. We're working very closely with our vendors for additional cost savings for all of the goods and contract services that we use.

We will continue to maintain a conservative financial discipline and have a 2009 budget that enables us to live within our means with limited draw downs in our line of credit. We're in compliance with all our debt covenants and expect to remain so into all future periods.

We continually monitoring review the credit worthiness of the banks that fund our credit facility. And as Terry mentioned thus far our bank group has faired very well during the recent financial turmoil. And finally, as always, we've included additional financial and operational information in our press release, including guidance for the second and full year 2009.

These continued to be clearly difficult times. But as Churchill once said, The pessimist sees difficultly in every opportunity. The optimist sees the opportunity in every difficulty.

Swift is indeed optimistic and well positioned both financially and operationally to take advantage of the opportunities that always present themselves during periods of uncertainty and adversity.

And with that, I'll turn it over to Bruce Vincent for an overview of our operations.

Bruce H. Vincent

Thanks Alton and good morning everyone. We appreciate your listening in on the call today.

Today, I will discuss first quarter 2009 activity, including our production volumes, recent drilling results, activity in our core operating areas and our plans for the rest of 2009. Bob Banks, our Chief Operating Officer will then provide greater detail and color on a couple of our activities that we want to highlight this morning.

Beginning with production. Swift Energy's production during the first quarter of 2009 totaled 2.37 million barrels of oil equivalent or 14.2 billion cubic feet equivalent. This was above our first quarter 2009 production guidance, primarily as a result of better than anticipated performance from our Bay de Chene field and the R. Bracken 33H well in AWP.

First quarter production decreased 8% from the 2.57 million barrels of all equivalent or 15.42 billion cubic feet equivalent produced in the same quarter in 2008 as a result of no new drilling activity, shut-in production at Bay de Chene and natural declines.

Sequential production decreased 4%, when comparing first quarter 2009 production to production in the fourth quarter 2008.

Now for our drilling results. Swift Energy completed one of two development wells in Lake Washington during the quarter, and completed drilling two natural gas wells in South Texas, which were both awaiting completion.

In total, the company drilled four wells during the quarter, completed one and will complete two more in the future.

I'll briefly review our activity in each of our core operating areas. Starting with the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields.

Production during the first quarter of 2009 averaged approximately 13,056 net barrels of oil equivalent per day, or 78 million cubic feet equivalent per day in this area, a decrease of 3% when compared to our fourth quarter 2008 average net production for the same area.

This quarter-over-quarter production decrease is primarily due to little drilling activity and natural declines, which were partially offset by production optimization program which began at Lake Washington during the quarter.

Lake Washington averaged approximately 10,617 net barrels of oil equivalent per day, or 64 million cubic feet equivalent per day as a net number of oil wells, a 19% decrease when compared to the fourth quarter 2008 volumes.

Bay de Chene's sequential production increased 481% to 2,439 net barrels of oil equivalent per day as high pressure gas production was online from the entire quarter.

Oil volumes at Bay de Chene along with the low pressure natural gas remains shut-in until further hurricane related damage repairs are completed later in the year.

For the month of April, the field averaged approximately 21 million in gross cubic feet equivalent of production per day. In total, approximately 1,500 to 2,000 net barrels of oil equivalent per day production is currently shut-in in the Bay de Chene field.

At the Lake Washington field in Plaquemines Parish Louisiana, the company completed one of two wells drilled during the first quarter. The State Lease 19338 #1 well, located on the west side of the field was drilled to a depth of 16,535 feet and in encountered 35 feet of true vertical pay in one zone. This well was recently completed and is currently producing a 3.6 million gross cubic feet per day of gas, with a flowing tubing pressure of approximately 2,150 psi.

An extensive production optimization program involving gas lift, enhancements and sliding sleeve shifts began during the first quarter of 2009. Bob will provide more details on this program as well as an update on the Shasta prospect, which is now flowing to sales in just a few moments.

In Bay de Chene during the first quarter, the company continued to rebuild infrastructure that was damaged or destroyed during the 2008 hurricane season. As repairs have been made and new wells put on stream, production rates have increased. All of shut-in productions should be restored upon completion of activities, upon completion of facilities construction, which is expected during the second half of 2009. These upgraded and new facilities will be more durable and should prevent extensive downtime after severe weather events in the future, a very similar of we did in the Westside facility at Lake Washington.

In response to oil prices demonstrating more resilience and natural gas recently, and drilling and service cost beginning to moderate, the company is currently evaluating low cost methods to increase its oil production during the second half of 2009 in the Southeast Louisiana core area.

Moving to our South Texas core area, which includes our AWP field, Sun TSH, Briscoe Ranch and Las Tiendas, first quarter 2009 production averaged 7,981 barrels of oil equivalent per day or 48 million cubic feet equivalent per day, a 3% decrease in production when compared to the fourth quarter of 2008 production in the same area. This decrease is primarily result of significantly reduced drilling activity in this area.

Drilling operations were concluded on one well in the Sun TSH field and one well in the Briscoe Ranch field during the first quarter. These wells are currently awaiting completion.

As discussed on our last call, the completion of the first horizontal well, Swift Energy has drilled in the Olmos formation, occurred in the first quarter of 2009. This well has performed very well and we're excited about future opportunities there and we'll have Bob discuss this well and provide a little more color on our 2009 plans.

Moving to the Central Louisiana/East Texas core area which we have previously referred to this Toledo Bend, started contributed 2,397 barrels of oil equivalent per day of production in the first quarter of 2009. A gas conditioning system was recently brought online in the South Perry Creek field and has had a positive impact on production in this field. This system will allow for increased production rates.

In our Southeast Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sally and Jeanerette, Cote Blanche Island and Bayou Bijou, production averaged approximately 2,239 barrels of oil equivalent during the fourth quarter, an increase of 2% when compared to fourth quarter production in this area, primarily as a result of slightly higher production in Cote Blanche Island and Bayou Bijou.

Let me now turn the call over to Bob Banks to review some of our more notable activity during the quarter.

Robert J. Banks

Thanks Bruce. First, the previously announced discovery well and our Shasta prospect in the company Southeast Louisiana core area just began production and is now producing the sales at our Westside facility in Lake Washington.

As previously reported, this well tested in the rate of 11 million cubic feet of gas per day and 739 barrels of oil per day, with a flowing tubing pressure of 11,279 psi on a 1,464 inch choke. Our working interest in this well is 50%. We are currently increasing production cautiously in order to ensure that we maximize our understanding of this new reservoir and how that will ultimately behave.

As Bruce mentioned, we began a production optimization program in Lake Washington during the quarter. We've conducted 10 sliding sleeve shift changes to different productive zones and four gas lift enhancements during the first quarter.

On average, per operation, production was approximately 68 barrels of oil equivalent per day higher after 30 days in each of these wells. More importantly, these operations only costs between 3 to $5,000 to perform. This low cost program will continue throughout the year and will assist in the mitigation of natural field declines until we resume drilling operations in the field.

Moving to the AWP field located in the company's South Texas core area, the R. Bracken 33H well continues to perform inline with our models and provides us with confidence in our assumptions. We still expect the R. Bracken 33H to recover between 3 and 5 billion cubic feet of natural gas.

We are moving forward with three additional horizontal wells in this area during 2009. Bench for these wells have been secured and the company expects to drill each for slightly less than $7 million. With continued success, we are confident that we will establish a multiyear drilling inventory with a potential for excellent economic returns in the Olmos formation alone.

We also continued to evaluate our exposure to the Eagleford Shale on our acreage. This is an exciting new play and we are optimistic about its potentials, but cautious about making predictions until we have data to support them.

Our AWP field is where we will focus our evaluation of this play in 2009. We have approximately 60,000 acres on Eagleford rights and in around AWP field, most of which we believe to be on trend with current competitor activity in the area.

We are currently forming a strategy to accelerate the development of our Eagleford rights which will consider all options available to us including the addition of potential joint venture partners. Swift energy plans to drill a well to test the potential of Eagleford Shale formation during the second half of this year.

We continued to evaluate and acquire acreage prospective for both Olmos and the Eagleford Shale across our entire South Texas core area. Our current acreage position has approximately 97,000 acres with new Olmos potential and 82,000 acres with Eagleford potential.

Thanks for your attention this morning. And I'll turn it back to Terry now to recap.

Terry Swift

Thanks Bob. Before we open the line for questions, I want to summarize Swift Energy's first quarter results to review some of the highlights from morning's presentations.

Swift Energy's credit facility was re-determined ensuring adequate liquidity to fund our 2009 capital program. Our Shasta discovery is now on production ahead of our previous mid-year estimate. The area around this discovery has a great deal of upside and planning to develop other prospects in this area has begun.

At Bay de Chene, the company has restored some but not all of our production, which were shut in by hurricanes in 2008. And currently we have approximately 1,500 to 2,000 net barrels of oil equivalent per day as shut-in production awaiting facilities repairs.

Our first quarter horizontal well in the Olmos sand continues to perform at the high-end of our expectations. The first of three additional wells in our 2009 drilling program will begin drilling later this month. We will continue to provide updates of these results for these wells along with other opportunities that we see in our South Texas area in our future calls.

Swift Energy Company is well positioned to weather this downturn, and we will be well positioned to create value as we grow out of this downturn.

At this time, we'd like to begin the question-and-answer portion of our presentation.

Question-and-Answer Session


(Operator Instructions). Your first question comes from the line of Andrew Coleman with UBS.

Andrew Coleman - UBS

Good morning folks.

Terry Swift

Hey Andrew. How are you doing?

Andrew Coleman - UBS

Good. Hey, I had the question about the PV-10. I mean it sounds like, I know you guys can't give exact numbers here, but with regard from, from some quick math, it looks like, given the small impairment you guys took a year... is been measures it's going to be pretty close to what it was at year-end. Could you comment on, a) how much cushion there was in the forecast pool at the end of the period? And b) do you think that that split between pods and PDTs would be similar to what might have been at year-end?

Alton Heckaman, Jr.

Andrew, this is Alton. Let me see if I can answer that. As you know, year-end 10-K when we took a pretty significant write-down, the pricing that was used for that which is disclosed in the 10-K was, for oil it was $44 and for gas it was just under $5.

Now, we don't disclose a lot of those things on the quarterly basis that you've asked for, but I can tell you because its really public information that at year, excuse me, period-end March 31, crude oil prices that actually rebounded about little over 10% from year-end '08 pricing, but natural gas prices had declined about a third. And so that's the pricing -- we're roughly half and half crude oil and natural gas on a reserve basis. So that's why when we compute period and prices March 31, we have those small write-down that we did or the relatively small write down.

So the prices have obviously since then crudes up another, came actually today 15% from March 31, and natural gas was rebounded another probably 10, 15% as well. So, I don't know if that answer... so the answer is that yes that I would think the standardized measure would be relatively close to year-end because we have not initiated our '09 activity, given the drilling that we're going to start in the second quarter et cetera. So get all your answer --

Terry Swift

Let me finish up, this is Terry. Almost by definition, it's a complex set of equations when you get through the actual sealing test calculation. But almost by definition you end up, when you take a write-down there is no cushion remains at the time of the write-down.

Now subsequent to that as prices increase which we're all looking to increasing prices to developed cushions. But at the time you take the write down almost by definition there is no cushion that remains. Also as it relates to that question, we also needed note that there were substantial basis deferential problems during the first quarter of this year, principally on the oil side. But we didn't seen it on the gas side. And when we do our PV-10 analysis of course, we have to take in consideration those different... those basis differentials.

Bruce Vincent

And I think the other comment that I would make, you talked about pods and crude developed reserves, when you have those lower prices, certain of your reserves become uneconomic and some of that is producing tail-end reserves. But quite frankly a good portion of that is pods and so I'd have to go back and look what our percentages. We might had a slightly smaller percentage of pods. As we did at March 31 using those prices lose as a substantial amount of pods, which now would be back on the books if you re-determine using today's prices.

Andrew Coleman - UBS

Okay. Yeah, it was about I think 900 million PDT and about 500 million of pods there at year end. So, thank you for that clarification. Looking at the Shasta well, can you just again refresh our memory with the size of the facilities at Westside and kind of how much capacity is left out there? If that was 20 million of gas and 10,000 barrels of water day handling capacity? Is that correct?

Alton Heckaman, Jr.

Yeah. Andrew, that's right. We've got 20,000 barrels of oil a day and 40 million cubic fuel gas per day.

Bruce Vincent

The efforts are considered to be able to compare.

Alton Heckaman, Jr.

Yeah. We've doubled that capacity here in the past year. So, yeah, we definitely have sufficient room to kick shafts in there. And we still have some remaining capacity at Westside.

Bruce Vincent

Yeah, just to clarify the Westside was originally commissioned with 10,000 barrels of oil process compares to E&P and 20 million of gas. We've actually installed additional equipment on there to double that to 20,000 barrels of oil producing capacity and 40 million for gas. That allowed us to really... it allowed us to have more capacity for things like Shasta, but it also allowed us to temporarily shutdown the old 2/12 platform which was the oldest of the platforms which will enable us to lower operating cost.

Andrew Coleman - UBS

Okay. And as you move forward with your optimization program, can you give us just an update in terms of I guess how the permitting is going through injection wells and I guess what you'll be doing over the next probably three to six months to kind of I guess move that along as well?

Bruce Vincent

Yeah. We've gotten a certain number of our permits in hand now that did take longer than anticipated. But I think we are in good state relative to the permits. But what I can say is that as a result of the performance that we've seen out there and in some part because of the hurricane shutting in wells and giving us additional pressure measurements all over the field, we've done some very extensive reservoir modeling. In fact we've focused on several of the reservoirs.

I want to remind folks that Newport is really not one reservoir, its numerous reservoirs. And as we've done that modeling, we've actually seen that there are some areas in there that we want to defer some of this pressure maintenance while others we want to get more aggressive on it. We're sorting all that out. It's fair to say that we are moving on that. And we don't expect however to actually see pressure responses or production increases this year and as a result of the activity that's there.

I would say that by the fourth quarter this year, we'd probably line out in detail which sands are being injected in or will be injected in and what kind of response we either are having by end of the year or expect to have going in 2009. But not to expect any pump this year.

Andrew Coleman - UBS

Okay. Then just a last question and I'll get out of the way for the folks. Just a clarification, perhaps I didn't see it in release blazing through all that numbers here this morning, but can you give the amount of cash taxes that were paid in the first quarter?

Terry Swift


Andrew Coleman - UBS

Okay. Was zero on, thank you.

Terry Swift

Thanks Andrew. Thanks.

Bruce Vincent



(Operator Instructions). Your next question comes from the line of Ken Carroll with Johnson Rice & Company.

Ken Carroll - Johnson Rice & Company

Hey guys. Good morning.

Terry Swift

Hey, how you're doing?

Ken Carroll - Johnson Rice & Company

Good, good. Just in certainly back to the Eagleford, you're talking about most of your focus these drill on will on be laid up in peak and going back through kind of presentations, you show Sun TSH and Fasken and Briscoe having potential lot in that area. Of the 82,000 you got acres that you've identified, I assume most of that related to AP with some at TSH, is that correct?

Terry Swift

That is correct.

Robert Banks

60,000 is around... in an around AWP and we have a total of about 82,000. So --

Bruce Vincent

82,000 that undeveloped.

Robert Banks

Undeveloped that's out between AWP and the other areas.

Ken Carroll - Johnson Rice & Company

Now, when you say other areas, is that scattered between Briscoe and Fasken as well or based on --

Robert Banks

Briscoe, Fasken and Sun TSH.

Ken Carroll - Johnson Rice & Company

Got you. So there is... we wouldn't look for a meaningful increase in that acreage number as you evaluate that you have there been? Got you. Okay. I appreciate it. Thank you.

Terry Swift

Thank you.


Next question comes from the line of Christina Tudlata (ph) with RBC.

Unidentified Analyst

Hi. Good morning. It's Frieda (ph) actually. Just one quick question, on the horizontal Olmos well that you just completed. You said that it's producing at the high end of expectations. So I was wondering if you could quantify what your arrangements for that. And how you're looking at well rates for the second well? Or are you expecting any of them?

Robert Banks

Well. Yeah, I mean what we did before we drilled the well is we created a number of predrilled models based upon different laterals and frac concentrations. And basically when we say it's producing on the high end of expectations, it's producing between the 3 to 5 Bcf EUR track that we pre-modeled, where that's going to end up is a little bit to early to say. We've already taken quite a bit of production out of that well in the first three months. So, we really like the way the well has behaved, we like the way the well has started to flatten out.

So whether that's going to end up more on the lower side of that three to five or the higher side of the three to five, we think it's inline and very good results for our very first well. In the new wells that we are getting right to drill, we think we actually have room for improvement. So we're really expecting even better performance on the remaining wells that we're going to drill this year.

Bruce Vincent

I think another way to look at that, another way we've looked in is we did nine multistage fraction that well and as you compare that to what nine vertical wells we'll do, the horizontal well with those nine fraction is actually doing quite a been better than equivalent of nine vertical wells and it's basically about half of price of nine vertical wells. So performance wise, from a economic standpoint, it's just a home run.

Unidentified Analyst

Alright. Understood. Thank you.

Robert Banks

The other thing I might point out too because it is important this was down on the southern edge of the field, so it's actually a field extension of the Olmos. And we had reached that southern-end not because we were running Olmos sand, but we were running out of Olmos sand in the economic under the conditions that you had. And the horizontal developed program with the multistage tracking really opens it up substantially because you've significantly improved the economics the way you're doing.


Your next question comes from the line of Jeff Robertson with Barclays Capital.

Jeffrey Robertson - Barclays Capital

Thanks Bob. At AWP, have you all actually... have you all penetrated the Eagleford with any other wells to have any idea of what the fitness or what any of the rock characteristics are?

Robert Banks

As you may we aware, we actually purchased our regional position out AWP from Shell and certain of the wells of Shell drilled that actually all going all the way down to the Edwards which did in fact then give us a look at the Eagleford though there weren't any specific tests in those vertical wells.

In and about the field at Shasta, there are enough controlled points around us that we can tie into a very extensive 2D seismic database that we that have in and by extensive. I mean we got that thing covered over which way with 2D. And then to the north, we've actually got 3D in the area.

So, well we are very confident that we understand the Eagleford. We will also been able to tied on strike with some of the activity that the competitors doing out there. We know this owns underneath our acreage and obviously it's in our developing play status and certainly not a mature play. But we have every reason to believe we've got a really excellent Eagleford position.

Jeffrey Robertson - Barclays Capital

Terry, can you tell much about the factoring under AWP from what you've... from the data that you do have?

Terry Swift

Factoring in terms of the Eagleford itself?

Jeffrey Robertson - Barclays Capital


Robert Banks

Natural fracturing?

Terry Swift

The natural fracturing itself while it's a component out there, we actually have a lot of fall prices up in the... through the Olmos sand, we know where the falls moves extensively through that zone and I think the Eagleford is really only, how many feet below that has gone down, roughly a 1000. So we've got a real good handle on the debt structure, the rate of change in depth in the area. And I think we know as well as anybody what kind of fraction to expect there.

Jeffrey Robertson - Barclays Capital

And then your drilling plans in the second half of the year, do you just plan the one wells in 2009 or would you try to ... will it be drilled early enough in the second half to benefits works the way you hope it does, you'd be able to fit in another well?

Robert Banks

Well, there is a lot of what ifs there. We definitely want to get to well in and get it in soon enough that we've got an evaluation on this year and you can make plans for 2010. That's the reason we get that well.

Now we're also looking at as we noted in our call, we're looking at brining in a partner and should we bring in a partner into the Eagleford activity, the whole purpose of that would be to accelerate, to get more than one well, get a much better mileage and get some momentum into 2010.

Jeffrey Robertson - Barclays Capital

Thank you.


(Operator Instructions).

Terry Swift

Any further questions?


There are no further questions at this time. Do you have any closing remark?

Terry Swift

Okay. Thank you very much for joining us today for our first quarter 2009 conference call. We look forward to a good second quarter and getting back with you. Thank you again.

Robert Banks

Thank you.


This concludes today's conference all. You may now disconnect

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