SilverBow Resources Inc (SBOW) 2009 Q1 法說會逐字稿

Good morning. 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 would now like to turn the conference over to Paul Vincent, Manager of Investor Relations. You may begin.

Good morning. I'm Paul Vincent, Manager of Investor Relations. I would 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 release and our actual results coil differ materially. We expect our presentation to take approximately 25 to 30 minutes, and have allowed additional time for questions.

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 remain weak during the first quarter, we have recently seen sign that is the sentiment may begin improve. Crude oil prices have in fact improved from their lows in February although the natural gas prices have stayed weak as demand as softened and activity has just recently begun to slow. Rig counts continue to decrease during the quarter, which will also help the supply and demand end balance in the future. We expect to see an overall decrease of US domestic natural gas supplies before year end, we think that's a very strategic assessment right now.

We have witnessed over 30, we have seen 30 years of business activity. The Company will be celebrating 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 have 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 effective, we should see a pick up in economic activity at some point which will begin to reverse the energy demand and usage declines we have seen.

In this light, Swift Energy is balancing its efforts to protect our balance sheet, and insure 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 have begun to see oil field drilling and service costs decrease, but we know that these costs 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 redetermine our revolving credit facility. Times are not only difficult in our industry, but in the financial sector as well. We are thankful to be working with a group of Banks who have fared well during this recent turmoil in the financial markets. With the borrowing base of $300 million, and only $224 million drawn on 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 mans. Alton and Bob will provide more details on this in a few moments.

At that time when capital markets are not we have more project that is are internally generated cash flows will allow us to on our own. We are 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 deep 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 would like to touch on the highlights of the quarter. Operational highlights of the quarter include the successful hook up of the state lease 18669 number one exploration well at the Shasta prospect in our Southeast Louisiana core area. Developing an idea into an exploration prospect and seeing it ultimately on 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 remind their the people in our organization are the true value creators and they grow the assets that they work. We continue to evaluate our large regional 3-D data set in southeast Louisiana and have developed a number of exciting opportunities and 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's still work to be done.

Some natural gas has been restored but the Company has approximately 1500 to 2,000 net barrels of oil equivalent per day of shut-in 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 drill for 20 plus years. Our first horizontal well in the Olmos formation, the Robert Bracken 33H well continues to perform in line with our predrilled models. This performance encourages us as we proceed to drill our next horizontal well in this area during second quarter. This next well will also be located in the southern portion of the field, and should support an extension of the productive limits 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 continue to analyze the potential that all of the south Texas acreage has for either the Eagleford shale formation and other emerging plays. Bob will discuss our plan 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 are planning to drill at least one well in 2009 to test the Eagleford shale formation acreage. For the duration of 2009 and beyond, we will make prudent capital and operations decisions with the interest of our stakeholders first and foremost. Although the 12 month outlook for oil and gas prices is still relatively weak, we continue to build, maintain and high grade a large inventory of properties and projects, which are will create values for many years to come.

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

Thank you, Terry, and good morning, everyone. The oil and gas sector experienced continued volatility during the first quarter 2009, in lockstep 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 2008. Swift recorded a $79.3 million noncash oil cost ceiling write down at the end of 1Q 2009, as our period end prices further declined from year-end 2008. The write down was $50 million after tax. Excluding this noncash writedown, 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 $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 2009 decreased 58% to $32.29 per BOE, as crude oil prices averaged just over $41 per barrel versus $99 per barrel in 1Q 2008, and natural gas prices averaged approximately $4 per MCF, compared to almost $8 per MCF last year resulting in a decrease in the oil and gas revenues of 62% when compared to the first quarter of 2008. We continue to vigilantly focus on our control per unit cost and metrics especially given the recent pricing volatility in the downturn in the industry. With respect to our 1Q 2009 result, 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 pretax noncash reduction in the carrying value of oil and gas properties at the end of 1Q 2009, in accordance with the SEC full cost ceiling test rules. As you know, the ceiling test rules require the use of period-end pricing held constant forever into the future. The charge 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, if 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 $1.90 for both basic and diluted and excluding the noncash full cost ceiling write down our loss would have been $9 million, $0.29 per diluted share, again beating First Call mean estimate. Cash flow before working capital changes for 1Q 2009 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. Our full basis CapEx was $47 million, primarily the result of a completion of 4Q 2008 projects.

Give, the recent global credit crisis and effect on the financial markets, let me spend a moment to highlight Swift's financial position and discuss a few cost containment initiatives. As previously announced our line of credit REIT facility was with our 10 member bank group that runs through October 2011 was recently set at $300 million for the borrowing 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 under the line of $237 million at the end of the first quarter, the result of the previously mentioned rollover of year-end 2008 costs into 2009 and the lower natural gas pricing environment. But as of April 30, the most recent month in, the outstanding amount had been reduced to $224 million.

Our current cash forecasts currently do not anticipate our draw downs exceeding $250 million at any point in 2009. We therefore feel our liquidity and resources are solid and provide Swift with the ability to weather these difficult financial times. Swift has initiated several program that mandate greater fiscal discipline with an emphasis on reducing our costs across the enterprise. In 1Q 2009, we implemented a reduction in our work force 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 are 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 are 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 on our line of credit. We are in compliance with all our debt covenants and expect to remain so in future periods. We continually monitor and review the credit worthiness of the banks that fund our credit facility, and as Terry mentioned, thus far, our bank group has fared very well during the weakened financial turmoil. Finally, as always, we have included additional financial and operational information in our press release, including guidance for the second quarter and full-year 2009.

These continue to be clearly difficult times, but as Churchill once said, the pessimist sees difficulty in every opportunity, the optimist sees the opportunity in every difficulty. Swift is indeed optimist and well positioned, both financially and operationally, to take advantage of the opportunities that always present themselves during periods of uncertainty and adversity. With that, I will turn it over to Bruce Vincent for an overview of our operations.

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.

Begin 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 and the R Bracken 33H horizontal well and AWP. First quarter production decreased 8% from the 2.57 million-barrels of oil equivalent or 15.42 billion cubic feet equivalent, produced in the same quarter of 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 of the fourth quarter of 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 are both awaiting completion. In total, the Company drilled four wells in the quarter, completed one, and will complete two more in the future.

I will briefly review our activity in each of our core operating areas. Starting with the Southeast Louisiana area which includes the Lake Washington and Bay de Chene fields. Production during the first quarter 2009 arched 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 of 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 a 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 a day, that's a net number also, a 19% decrease compared to the fourth quarter 2008 volumes.

Bay de Chene sequential production increased 481% to 2,439 net barrels of oil equivalent per day as high pressure gas production was on line for the entire quarter. Oil volumes at Bay de Chene, along with low pressure natural gas, remain 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 gross cubic feet equivalent of production per day. In total, approximately 1500 to 2,000 net barrels of oil equivalent per day of production are 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 released 19,338 number one well, located on the west side of the field, was drilled to a depth of 16,535 feet, and encountered 35 feet of true vertical pay in one zone. This well was recently completed and is currently producing at 3.6 million gross cubic feet per day of gas, with a flowing tubing pressure of approximately 2150 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 shut in production should be restored upon completion of the facilities construction, which is expected during the second half of 2009. These upgraded and new facilities will be more durable, and should prevent extensive down time after severe weather events in the future, very similar to what we did in the West Side Facility in Lake Washington. In response to oil prices demonstrating more resilience than natural gas recently, and drilling and service costs 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, Sun TSH, Briscoe Ranch and Faskin fields, first quarter 2009 production averaged 7,981-barrels of oil equivalent per day, or 48 million cubic feet of oil per day, a 3% decrease in production when compared to the fourth quarter of 2008 production in the same area. This decrease is primarily a 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 is drilled in the Olmos formation, occurred in the first quarter of 2009. This well has performed very well, and we are excited about future opportunities there and going to have Bob discuss this well and provide more color on the 2009 plans.

Moving to the central Louisiana east Texas core area, which we have previously referred to as Toledo Bend. This area 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 Bearhead Creek field and has had a positive impact on production in this field. This system will allow for increased production rates. In our south Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sally, Generet, Cote Blanche Island, and Bayou Pinchella, production averaged approximately 2,239 barrels of oil equivalent during the fourth quarter. An increase of 2% when compared to fourth quarter in this area, primarily as a result of slightly higher production in Cote Blanche Island and Bayou Pinchella.

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

Thanks, Bruce.

First, the previously announced discovery well at our Shasta prospect in the Company's southeast Louisiana core area just began production and is now producing the sales at our West Side Facility In Lake Washington. As previously reported, this well tested at a 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 1464-inch choke. Our working interest in this well is 50%. We are currently increasing production cautiously, in order to insure that we maximize our understanding of this new reservoir and how it will ultimately behave.

As Bruce mentioned, we began a production optimization program in Lake Washington during the quarter. We 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 of each of these wells. More importantly, these operations only cost between $3,000 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 cotton south Texas core area, the R Bracken 33H well continues to perform in line with our models and provides us with confidence in our assumptions. We still expect the R Bracken 33H to recover -- of natural gas. We are moving forward with three additional horizontal wells in this area during 2009.

Bids 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 the potential for excellent economic returns in the Olmos formation alone. We also continue to evaluate our exposure to the Eagleford shale on our acreage. This is an existing new play and we are optimistic about it potential 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 of Eagleford rights in and around AWP field most of which we believe to be on trend with the 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 the potential joint venture partners. Swift Energy plans to drill a well to test the potential of the Eagleford shale formation toward the second half though year. We continue to evaluate and acquire acreage perspective for both Olmos and the Eagleford shale across the 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 will turn it back to Terry now to recap.

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 this morning's presentation. Swift Energy's credit facility was redetermined, 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 was shut in by hurricanes in 2008 and currently we have approximately 1500 to 2,000-barrels of oil equivalent per day of shut in production awaiting facilities repairs.

Our first 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 rater this month. We will continue to provide updates of these results or 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 would like to begin the question-and-answer portion of our presentation.

(Operator Instructions). We will pause just a moment to compile the Q&A roster. Your first question is from Andrew Coleman with UBS.

Good morning, folks. I had a question about the PV 10. It sounds like, I know you guys can't give me an exact number, it looks like given the small impairment you guys took that your centerized measure is going to be pretty close to what it was at year end. Could you comment on how much cushion there was in the full cost pool at the end of the period. Do you think that the split between puds and PDP would be similar to what it might have been at year-end?

Andrew, this is Alton. Let me see if I can answer that. As you know, in our 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 things on the quarterly basis that you've asked for, but I can tell you if it is really public information at year-end, period end March 31, crude oil prices had actually rebounded about a little over 10% from year-end 2008 pricing. But natural gas price had declined about a third. So that is the pricing vector, we are roughly half and half crude oil and natural gas on a reserve basis. So that is why when we compute with period end prices, March 31, we had the small write down or the relatively small write down. So, with prices up obviously, since then, crude is up another 10 actually today, 15% from March 31 and natural gas has rebounded another probably 10 to 15% as well.

So I don't know that -- 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 2009 activity given the drilling that we are going to start in second quarter et cetera. So did I get all of your answers there.

Let me finish up. This is Terry. Almost by definition, it is a completion set of equations when you get to the actual ceiling test calculation but almost by definition, when you take a write down, there is no cushion that remains at the time of the write down. Now subsequent to that, if prices increase, which we are all looking to increasing prices, you do develop cushions but at the time you take the write down, almost by definition there's no cushion that remains.

And also as it relates to that question, we also need to note that there were substantial basis differential problems during the first quarter of this year principally on the oil side, but we've even seen it on the gas side. We think that's going to close also. And when we do our PV 10 analysis we have to take into consideration those basis differentials.

The other comment that i would make, you talked about PUDs and proved develop reserved, 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 PUDs. So I would have to go back and look at our percentages are. We might have had a slightly smaller percentage because we did at March 31 lose a substantial amount of PUDs which would be back on the books if you redetermine using today's price.

Okay. Yes. It was about I think 900 million PDP and about 500 million of PUD there at year end. Thank you for that clarification, and looking at the Shasta well, can you just again refresh our memory the size of the facilities at West Side and how much capacity is left out there is this it was something like 20 million a day gas and 10,000-barrels of water a day.

Andrew, that's right. We have 20,000-barrels of oil a day and 40 million cubic feet of gas per day.

Need to be clear.

We have doubled that capacity here in the past year. So, yes, we definitely have sufficient room to take Shasta in there and we still have remaining capacity at West Side.

Just to clarify, West Side was originally commissioned with 10,000-barrels of oil processed capacity and 20 million of gas. We have 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 have more capacity for things like Shasta but also allowed us to temporarily shut down the old 212 platform, which was the oldest of the platforms which enabled us to lower operating costs.

Okay. And then as you move forward with your optimization program, can you give us an update in terms of how the permit as good going for the injection wells and what you will be doing the next three to six months to kinds of move that along as well?

We have gotten a certain number of permits in hand now that did take longer than anticipated but I think we are in good stead relative to the permits. But what I can say is that as a result of the performance we have 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 have done some very extensive reservoir modeling. In fact, we have focused on several of the reservoirs. I want to remind folks that Newport is really not one reservoir. It is numerous reservoirs, and as we have done that modeling we have 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 and we are sorting all of that out.

It is fair so say that we are moving on that. And we don't expect, however to actually see pressure responses or production increases this year as a result of the activity that's there. I would say that by the fourth quarter this year we would 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, any pump this year.

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

Zero.

Okay. It was zero. All right. Thank you.

Thank, Andrew.

Thanks.

(Operator Instructions). Our next question comes from the line of Ken Carroll, with Johnson Rice.

Hey guys. Good morning.

How is it going?

Good. Just in circling back to the Eagleford you talked about most of your focus will be AWP. Going back through your presentation, you show Sun TSH and even Faskin and Briscoe having potential out in that area. Of the 82,000 acres you have identified I assume most of that is AWP with some at TSH; is that correct?

That's correct. 60,000 is around, in and around AWP, and we have a total of about 82,000. So, that's --

82,000 undeveloped.

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

Now when you say others is that scattered between Briscoe and Faskin as well.

Briscoe and Faskin and some TSH.

Got you. So there's, you wouldn't look for a meaningful increase in that acreage number as you evaluate what you have there then? Got you. All right. Guys, appreciate it. Thank you.

Thank you.

Your next question comes from the line of [Christina Culotta with RBC].

Good morning. It is (inaudible) actually. One quick question on the horizontal Olmos well you just completed, you said that it producing at the high end of the expectations, I was wondering if you can quantify what your range was for that and how you are looking at flow rates for the second well? Or what you are expecting there, rather?

Yes. What we did before we drilled the well is calculated a number of predrilled models based on different laterals and frac concentrations and basically when we say it is producing on the high end of expectations, it is producing between the 3 to 5 BCF EUR track we remodeled. Where that's going to end up is a little too early to say. We have 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 is going to end up more on the lower side of the 3 to 5 or the higher side of that 3 to 5, we think it is in line and very good results for our very first well. And in the new wells that we are getting ready to drill, we think we actually have room for improvement. So we are really expecting even better performance on the remaining wells we are going the drill this this year.

Another way to look at that, another way we have is we did nine multistage fracs in that well, and if you compared that to what nine vertical wells would do, the horizontal well is actually doing quite a bit better than the equivalent of nine vertical wells and it is about half of the price. So performance wise, from an economic standpoint, it is just a home run.

All right. Sounds good. Thank you.

The other thing I might point out too because it is important is this is on the southern edge of the field. So it is a field extension of the Olmos and we reached that southern end because you were running out of Olmos sand but running out of Olmos sand and it was economic under the conditions we had in the horizontal development program with the multistage fracking really opens it up substantially, because you have significantly improved the economics the way you are doing it.

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

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

As you may be aware, we actually purchased our original position out in AWP from Shell and certain of the wells that shell had drilled had gone 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 itself, there are enough control points around us that we can tie in to a very extensive 2-D seismic database that we have and by extensive, I mean that we have that thing covered every which way. To the north we have 3-D in the area. So we are confident we understand the Eagleford, we have also been able to tie it in on strike with some of the activities that the competitors do out there. We know the zones underneath our acreage and obviously it is in a developing play status, and certainly not a mature play, but we have every reason to believe we have a really excellent Eagleford position.

Can you tell much about the fracturing under AWP from the data you do have?

Fracturing in terms of the Eagleford itself?

Yes.

The natural fracturing itself, while it is a component out there, we actually have a lot of fault traces up in the, through the Olmos sand. We know where the faults move extensively through that zone, and I think the Eagleford is really only how many feet below?

Thousand.

Roughly a thousand. So we have a real good handle on the depth structure, the rate of change of depth in the area. I think we know as well as anybody what kind of fracturing to expect there.

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

Well, there's a lot of what ifs there. We definitely want to get a well in soon enough that we have an evaluation done this year and can make plans for 2010. That's the reason to get that well. Now we are also looking at as we noted in our call, we are looking at bringing 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, to get a much better knowledge and get some momentum into 2010.

Thank you.

(Operator Instructions).

Any further questions?

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

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

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