Mariner Energy Inc. Q3 2008 Earnings Call Transcript

Mariner Energy, Inc. (ME)

Q3 FY08 Earnings Call

November 5, 2008, 4:00 PM ET

Executives

Patrick Cassidy - Director of IR

Scott D. Josey - Chairman, CEO and President

John H. Karnes - Sr. VP, CFO and Treasurer

Analysts

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Scott Hanold - RBC Capital Markets

Neal Dingmann - Dahlman Rose & Co.

Richard M. Tullis - Capital One

Philip Dodge - Stanford Group Company

Pavel Molchanov - Raymond James & Associates

Nicholas Pope - JP Morgan

Brian Kuzma - Weiss Multi-Strategy Advisers

Rehan Rasheed - Friedman, Billings, Ramsey & Co.

Presentation

Operator

Good day ladies and gentlemen and welcome to the Mariner Energy Incorporated Third Quarter Earnings Conference Call. My name is Amesia [ph] and I'll be your coordinator for today.

At this time, all participants are in a listen-only mode. We'll be facilitating a question-and-answer session towards the end of this conference. [Operator instructions]. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Patrick Cassidy. Please proceed.

Patrick Cassidy - Director of Investor Relations

Thank you, operator. Good afternoon and welcome to Mariner Energy's third quarter 2008 earnings release conference call. Today's call is being webcast and a replay will be available on the Mariner website following this call for the next 10 days.

This is Patrick Cassidy, Director of Investor Relations for Mariner Energy. On the call today are Scott Josey, Chairman, Chief Executive Officer and President of Mariner Energy; and John Karnes, Senior Vice President, Chief Financial Officer and Treasurer.

The news release announcing the company's results was issued last night after the market closed and is available on our website. In today's call, Scott will provide opening remarks and an operational update. John will discuss the company's overall financial performance. You're welcome to ask questions after we complete our prepared remarks. Before Scott begins his review, please note that today's presentation may include forward-looking statements reflecting Mariner's view about future events and their impact on company performance.

All remarks other than statements of historical fact that address activities that Mariner assumes, plans, expects, estimates or anticipates and another similar expressions will, should or may occur in the future are forward-looking statements. Such forward-looking statements and that information may involve risks and uncertainties that could affect the company's operations and financial results causing our actual results to differ from our forward-looking statements.

These risks and uncertainties are described in Mariner's filings with the Securities and Exchange Commission including our Form 10-K for the year ended December 31, 2007.

The SEC generally has permitted oil and gas companies in their SEC filings to disclose only proved reserves. Mariner's uses the terms probable, possible and non-proved reserves, reserve potential or upside or other descriptions of volumes and reserves potentially recoverable that the SEC may prohibit in SEC filings.

These estimates are by their nature more speculative than estimates of proved reserves, and accordingly are subject to substantially greater risk that should be realized by Mariner. Information disclosed during this conference call does not constitute an offer to sell or solicitation of an offer to buy any of Mariner's Securities.

Now, I will turn the call over to Scott Josey.

Scott D. Josey - Chairman, Chief Executive Officer and President

Thanks, Pat. Good afternoon. As you've seen from the press release, we've had another quarter with record results. We achieve this despite shut-ins caused by hurricanes that continued to affect third party facilities and prevented us from producing at full capacity.

Prior to the hurricanes, we were producing approximately 390 million cubic feet equivalents per day and on track to produce at or above the upper end of our guidance range of 130 Bcf to 140 Bcf equivalents.

As we have previously reported, our Gulf of Mexico facility sustained essentially no damage from Hurricane Gustav, and damage to production facilities from Hurricane Ike was relatively minor.

We expect our property damages to be fully insured subject to applicable deductibles. Within days after Ike made land fall our material facilities were capable of producing, the restoration of our production has been delayed by repairs primarily to third party transportation and processing facilities.

Our onshore production was also temporarily curtailed due to hurricane damage at the plant at Mark Belleview where our natural gas liquids from a Permian Basin are processed. As repairs to these third party facilities are completed, our production will resume. We have provided periodic updates on our production levels on our website. We are currently producing about 270 million cubic feet equivalents per day, which is approximately 70% of our capability.

We expect our production rate to approximate our pre-hurricane levels by yearend. Of the amount currently shut in approximately 30% is in the deepwater and the remainder is in the shelf. We currently estimate that we will be producing around 85% of capability by the end of November and 97% by the end of December. Based on this we estimate we will produce a 120 Bcf to 123 Bcf equivalents for 2008.

Considering our original expectations and how well the company is performing we are disappointed in the revised forecast. Nevertheless it is noteworthy that our revised guidance still reflects over 20% growth compared to 2007. We expect no material loss of reserves and the production short fall will be differed mostly into 2009, which we anticipate being another record year of production at Mariner.

Our total net production for the quarter was 27.1 Bcf of natural gas equivalents, 17% increase compared with 23.2 Bcf reported for the same period a year ago. But due to effect of the '08 hurricanes it effectively represents only two full months of production from our asset based in '08 versus three month in '07.

Deepwater contributed approximately 33% of our total production for the third quarter with the Shale at 54% and onshore at 13%. Before evacuation was required due to Hurricane Gustav, we completed the top side facility's expansion at Devils Tower that enabled us to bring both of our Bass Lite wells online at their full capacity briefly before being shut in for Gustav.

We were able to produce Bass Lite briefly before we had to shutdown again for Ike, and as we previously disclosed Bass Lite was shut in for 11 days during October as part of the scheduled work program on the host facility to connect third party production. Once the work program was completed both wells were brought online and are currently producing at a gross rate of about $105 to $110 million cubic feet equivalents per day.

Compression facilities for the Bass Lite wells are currently being installed on the host facility as schedule. Although compression is not currently necessary at Bass Lite, we estimate that we may commence compression in the first half of '09 to enable us to optimize reservoir recovery. We operate Bass Lite and all the 42.2% of working interest.

Oil wells are back online in Northwest Nansen, production returned soon after Ike made landfall with gross production rate of approximately $125 million cubic feet equivalents per day at the end of the quarter.

As announced in June we made a discovery at Gopher which is located on Garden Banks Block 462, and water debts of approximately 2,700 feet. Gopher well initially be a two well subsea tieback to a house facility of approximately 40 miles away. Initial gross production rates are expected to range from $125 million to $150 million cubic feet equivalents per day. Mariner has a 60% working interest in the project.

Originally we expected the wells to be online prior to yearend, have reduced the hurricane delays; we now estimate being online during the first quarter of 2009.

We have completed both wells and laid the flow line. We expect to lay the umbilical shortly and are preparing to drill the third Gopher well. Another deepwater developments, we expect... we continue to expect that Daniel Boone project and Green Canyon 646 and the Viosca Knoll 821 project to come online during the second half of 2009.

We have a 40% interest in Daniel Boone and 30% interest in VK 821. On the shelf, we were in the process of completing a well at SM 150 when the drilling rig was toppled during Hurricane Ike. We have contracted a replacement rig and expect to resume operations there and like November, which will consist of finishing the completion as well as drilling three additional wells.

Offshore, we participate in the drilling of five wells during the quarter with three successes. We were participating in seven other wells at the end of the quarter, two in deep water five on the shelf. As stated in the press release, three of those seven are successful and we are 16 to 20 year-to-date in the Gulf of Mexico, which is an 80% success rate. We expect to spud up to four additional wells by year-end including two in the deepwater, one deep shelf and one conventional shelf.

One of the deepwater wells that we expect to reach TD later this month is surge, a salt overhang prospect acquired in last October's lease sale, located in Garden Banks Block 334. We are the operator with a 40% working interest. This is a salt overhanging well and our pre-drill estimate of gross reserves is 100 Bcf to 300 Bcf equivalents.

The rig is on location at the Heidelberg prospects, which is a deepwater subsalt test of four blocks in the Green Canyon 859 area, which is an expanded... which is in the expanded Miocene trend, approximate to other significant Miocene discoveries, including Knotty Head, Tahiti and Tonga. We hold a 12.5% working interest in Heidelberg which we acquired by farm-in from Anadarko who will operate.

Lastly, I would note the success we've had at the Dalmatian discovery on De Soto Canyon Block 48. This is a deepwater conventional amplitude play with free drill estimates ranging between 50 Bcf and 150 Bcf equivalents. We hold a 12.5% interest in the discovery and Murphy is the operator. This prospect leveraged the company's early successes... earlier successes at Swordfish and Aconcagua. Another positive aspect of this discovery is that it supports more exploration in the area and we have interest in five additional prospects covering 9 blocks contiguous to the Dalmatian discovery.

Onshore, we drilled 29 wells in the third quarter with a 100% success rate. We currently have five rigs operating in West Texas and expect to drill about 120 wells there for the year. We have drilled and logged the first well on our Deadwood prospect. The Deadwood prospect is a Wolfcamp Detrital play with secondary objectives in the client strong formations. Mariner has a significant acreage position in this play with approximately 24,000 net acres at an average 67% working interest.

The logs on the first well are encouraging and we're in the process of drilling a second well, which should reach TD soon. After the second well, we'll frac stimulate both wells and produce our flow line beginning in early December. Although we're cautiously optimistic about the prospect, the production results and possible additional drilling will determine the success of the project and our plans going forward.

Another positive news concerning our Permian Basin assets, the Texas Rail Road Commission has issued a final order amending field rules for the Spraberry trend. This is a significant change affecting the entire Spraberry trend as it will allow for optional 20 acre down-spacing. This amendment could permit the drilling of several hundred to more than a thousand additional locations on our 50,000 plus acres in the Spraberry trend. We continue to be pleased with our progress onshore.

On capital spending, earlier this year we provided guidance for 2008 operating CapEx, our estimates then was $760 million with the possibility for expansion to $950 based on drilling successes and cash flow.

With Gopher, VK 821 and Daniel Boone being developed along with the success of our shelf exploitation program and onshore programs we stated on our last call that we expected to spend $1 billion to $1.1 billion excluding acquisitions.

At the time we expected excess cash flow of approximately 200 million, which was targeted for debt reduction. Given the effects of hurricane Ike and Gustav on our production, as well as the more recent downward trend in commodity prices, we expect to generate cash flow for 2008 in the range of $950 million to $1 billion just slightly below our capital spending.

We are currently developing budget plans for 2009. As I said previously we expect 2009 to be another strong production year for the company which should result in strong cash flow through opportunity rich and able to control the timing of most of our capital spending, which provides a flexibility to tailor our capital spending within our cash flow.

Recognizing that we are in an environment that maybe more challenging, Mariner in my view is in a good position. We are strong financially, opportunity rich, have good cash flow and ample liquidity. Our financial hedges which are currently in the money and with counterparties rated AA minus or better and consists primarily of members within our bank group. We have no exposure to Lehman Brothers or Sync crude [ph].

Mariner's management team has faced difficult times before when we were a private company. We continue to abide by the principles that enabled us to overcome those difficult periods, one of which is our goal of living within our means.

I notice now that many financial reporters and others are talking about living within your means and the need for fiscal discipline, and I have said that quarter-after-quarter for years now, and we plan to continue with that philosophy, focusing on building and diversifying our asset portfolio cost effectively while living within our cash flow. This approach has served us well in the past and we believe we'll continue to work in the future.

Finally, as you are aware, the Board recently adopted a shareholder rights plan, otherwise known as a poison pill. Mariner is a shareholder friendly company and this measure was put in place in order to protect our shareholders from colossus or unfair takeover techniques. We continue to believe the company share price does not reflect the value of the company.

With that, I'll turn the call over to our CFO, John Karnes to highlight financial results.

John H. Karnes - Senior Vice President, Chief Financial Officer and Treasurer

Thanks Scott. Quickly covering the highlights of our earnings release last night. For the third quarter 2008 we posted record quarterly net income of $65 million, an 80... a 187% increase compared with the same period in the prior year. This equates to earnings of $0.74 per basic share and $0.73 for a fully diluted share, up from $0.26 per share a year ago.

Our third quarter earnings included non-cash provision for an additional retrospective premium adjustment equating to $0.05 per share in connection with our membership in the industry insurance mutual, OIL Limited. Notwithstanding the shut in our 7 billion to 9 billion cubic feet equivalent of potential production due to hurricanes Gustav and Ike, total revenues for the quarter increased 62% to about $318 million, also a quarterly record up from a $197 million reported for the third quarter of 2007.

And while we saw prices fall dramatically during September, where the quarter as a whole, we continued to enjoy near record average realized prices across all of our product streams. The average realized price for natural gas during the third quarter was $10.50 per Mcf compared with $7.18 for the same period in 2007.

Our average realized price for oil was $92.97 per barrel, compared with $70.68 for the third quarter of 2007. For NGLs, we averaged $61.05 per barrel compared with $49.02 in 2007. These prices reflect settlements during the period under Mariner's hedging program.

During the third quarter of 2008, hedges lowered Mariner's average natural gas price by $0.67 per Mcf and $28.33 per barrel of oil. Combined, this resulted in a net recognized hedging loss of about $42 million. For the same period in the prior year we recorded a net recognized hedging gain of about $11 million. The cash losses on our hedging contracts settled during the third quarter of 2008 were $47 million compared with cash gains of $12 million during the same period a year ago.

Unfavorable settlements for the quarter were partially offset by an unrealized hedging gain under FAS 123 of about $5 million related to the ineffective portion of open contracts.

Turning to expenses. Our lease operating expense for the third quarter of 2008 was just under $65 million or $2.38 per MCF equivalent up from $1.52 per MCF equivalent reported in the sequential quarter and $1.42 reported in the third quarter last year. The major reasons for the increase in NOE on a unit basis during the quarter were first and foremost hurricanes Gustav and Ike, which again shut in between 7 and 9 Bs of production during the quarter that would otherwise have absorbed a significant portion of our fixed deal overhead.

Second our $7 million retrospective premium adjustment taken during the quarter in connection with our membership in Ohio as previously mentioned. This provision while non-cash in nature added about $0.27 per Mcf equivalent to our unit LOE.

And lastly a total of about $5 million of maintenance deferred from the second quarter and contingency reserves established during the period. Checking of these effects... the effects of these items, I believe, our LOE would have settled into the mid $1.50 range once again for this period.

Our overhead expenses for the third quarter 2008 were just under $13 or about $0.48 per Mcf equivalent. About even with the same period a year ago. In terms of our G&A run rate however, G&A in the third quarter was down well over a million on an absolute basis from the second quarter although as you might expect given the hurricanes it was up substantially on a unit basis given our sharp drop in Q3 production.

Depreciation, depletion and amortization expense increased during the third quarter to about $114 million compared to $91 million in the third quarter last year. This increase is the two pronged result of both increased production volumes primarily attributable to our Statoil acquisition and the start-up at Bass Lite and Northwest Nansen as well as a higher DD&A rate for the fourth quarter.

Our DD&A rate $4.22 per Mcf equivalent for the quarter compared to $3.93 per Mcfe last year is primarily a function of Statoil and a substantial drilling the development projects underway during the quarter, most notably Gopher with respect to which we only expect to book a minor portion of the reserve potential, we ultimately hope to realize.

Finally, in terms of our balance sheet, we exited the quarter with around $300 million of net debt under our credit facility with approximately $380 million currently outstanding. This allows us nearly $500 million of un-drawn borrowing capacity under our $850 million borrowing base.

With our conservative debt to cap ratio, substantial liquidity through our committed bank grew and our tremendous internally generated cash flows, we feel we're well positioned to finish our 2008 as a record year operationally and financially, even in this potentially lower price environment as well as to execute a robust growth program next year with ample financial flexibility to adjust the commodity prices and to respond to any acquisition opportunities that may present themselves as the industry adjusts through these current tighter credit markets.

So, hurricane complications aside, another quarter of progress and strong results. With that Scott and I will be glad to entertain your questions.

Question And Answer

Operator

[Operator Instructions]. And the first question comes from the line of Michael Jacobs with Tudor, Pickering. Please proceed.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Hi, good afternoon everybody.

Scott D. Josey - Chairman, Chief Executive Officer and President

Good afternoon.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Scott, why don't you start off with some onshore questions. Working under the assumption that you want to increase your onshore presence, how do you think about accelerating the onshore program versus adding additional resold and are you seriously looking at other areas outside of the Permian currently?

Scott D. Josey - Chairman, Chief Executive Officer and President

Mike, just to be clear, I mean you say adding other leasehold, are you... do you mean at onshore or are you comparing that to offshore?

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Just onshore specifically.

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, I think as you... first off, we like onshore. We like our position in the Permian. We are starting to expand not just in West Texas but also into Mexico. As we stated on prior calls, we have a very strong team of people working the Permian from engineers, geologists, geophysicists and operations personnel. So... and we've gone from 12,000 net acres to over a 100,000 net acres and continue to see what we think are good rate of return opportunities in that area. So Mike, we are committed to onshore particularly in the Permian. We will continue to expand in that area. Very pleased with what we've seen thus far and again we'll just... we'll continue to look for opportunities. Today we've been primarily a Spraberry player and about half of our acreage position is in the Spraberry. We still like it and we'll continue to try to build positions there.

But we've also significantly diversified that into numerous other plays including the client, Detrital, Devonian/Fusselman some other plays and the... this Deadwood prospect that we mentioned earlier is kind of our first step and to enter something we think is going to... is potentially pretty exciting.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Okay.Just building off that a little bit. A large Permian operator announced that the plans laid on rigs and take rigs termination charges. Can you update us on your onshore rig contracts kind of over the next year, what you have contracted, what's not and whether you are considering laying down rigs-near term to take advantage of a lower service cost environment?

Scott D. Josey - Chairman, Chief Executive Officer and President

As we mentioned we have five rigs running in West Texas. Anywhere are in the Permian, anywhere from two to three are working on Spraberry opportunities and the others are working on some of these other opportunities. I've seen the press release and the comments of the other large operator to that. I think you're referring to the tough looking comparisons. Is it... is that the cost that they have or tend to be higher and the cost that we have, the projects that we are perusing currently are still in our view very economic.

There's a possibility we might... going back to our rig contracts, we don't have any contracts under long-term arrangements; they are all short-term in nature and we tend to renew them on kind of 5 to 10 well programs which made last several months... two to three months at a time. So we don't have any significant termination fees or any thing like that. But if commodity prices were to drop substantially if would be very easily... easy for us to back away and do something else. But currently, everything that we're perusing is still generates very good results.

We would anticipate that with the... that if the commodity price environment persists then we would begin to see some relief in some of the other cost and drilling cost as well as other service company costs and those wells would become even would maintain their rates per turn.

We have been drilling Spraberry wells since October of 2002 when the commodity price market was around... commodity price environment's around $30 a barrel, and the cost to drill those wells were about $450,000 to the tanks, we had good rates of return then. In the current environment we spend about $850,000 to drill the same wells and you know we are in a somewhat doing $65 or $75 environment. So they are still are working out okay.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

It's great. Thanks for that color. Question for John, just looking at '09 CapEx and recognize it's too early to get specifics on what your budget could look like. But just kind of looking at last year when you initiated CapEx in kind of that $700 million to $800 million range and knowing that it goes up with success but also thinking about oil prices being about $35 a barrel higher. Can you help us think conceptually about '09 CapEx and whether '09 should be a look-alike to '08 or is there a chance that you initiate lower '09 CapEx guidance given the drop in commodity prices?

Scott D. Josey - Chairman, Chief Executive Officer and President

Mike, this is Scott. I'm going to answer that question. What we do every year is we lay out our opportunities that we estimate what we think our production is going to be under reasonable circumstances. We try to come with a conservative price curve, and then we tailor our capital spending to be... to live within our means. The board gives us flexibility to as conditions improve or deteriorate we can either add or take away some projects. And some of that depends on where you are during the year.

The $760 million that we refer to and you mentioned that was basically a assumed little bit more success with the success at Gopher and others and our spending went to about 950. And that was with our budget this year, it was based on roughly 750 GAAP, I believe, in either $80 to $85 dollar oil. So, we didn't do anything based on $110, $120, $130, $140 barrel oil or $9, $10, $11 gas. This year we are currently in the process of putting our budget together as we speak and... but we will go through the exact same approach.

And as I mentioned in my script, we control most of our projects. We control the spending, the timing and therefore we will be able to tailor our spending to the environment. And I would anticipate we will present our Board again with a budget that lives within our cash flow and accomplishes other objectives such as potentially further reducing our revolving debt.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Great,I'll just follow-up and then I'll hop back in the queue. Just thinking about the exploration mix and can you give us any sort of guidance that kind of with the current commodity prices that you are assuming. How you think about deepwater mix between conventional deepwater, salt overhang, subsalt as we think about a six to nine well program. Has that changed given the pullback in commodity prices? Should we be thinking closer to six well program? Has the mix become shallower relatively?

Scott D. Josey - Chairman, Chief Executive Officer and President

I can't answer all that today. I'll be able to talk of that more fairly soon. But what I will say is it nothing in our inventory... all our prospect inventory was around at 7 to 750 gas and $65 to $70 oil. So we have nothing in our prospect inventory that is depended upon what at least recently would be considered high commodity prices.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Great, thank you.

Scott D. Josey - Chairman, Chief Executive Officer and President

Okay, thank you.

Operator

And the next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.

Scott Hanold - RBC Capital Markets

Thanks, good afternoon.

Scott D. Josey - Chairman, Chief Executive Officer and President

Good afternoon.

Scott Hanold - RBC Capital Markets

Into the plans here is to I guess, bring those two wells on line sometime in first quarter in the first quarter and in that 125 to 150 rate, is that assuming just those two wells and can you just talk about sort of the ramp to get to that. And, you said that you're drilling the third well. Would that be incremental to that rate or will that sort of fall within that 125 to 150?

Scott D. Josey - Chairman, Chief Executive Officer and President

On the 125 to 150 assuming it was just the first two wells. The ramp up, anytime we bring on these wells, we start off slow and bring them up but because they have such good porosity and permeability, you can generally ramp them up fairly quickly. Usually we assume kind of a... usually about a 30 day timeframe. But the reality is, you can usually bring them up over about up two week timeframe.

The third well, which we were in the, just about the spud, will be incremental and assuming its successful then that will be incremental production as I said.

Scott Hanold - RBC Capital Markets

Okay. And so how do you think about sort of these wells, those first two wells, are they going to hold up pretty well for say for the first year and then to start to take a financial acclaim?

Scott D. Josey - Chairman, Chief Executive Officer and President

You never know for sure, Scott, but as we have indicated, we believe those wells are in the vicinity of 100 Bcf type of range, that we are producing pretty higher rate and I think, I suspect it to be fairly flat for a while and then we'll start to see some decline, since when how much water support that we would have to see or how much they, I guess more of a depletion drive effect. So some of it we just have to get them online and just see how they perform.

Scott Hanold - RBC Capital Markets

Okay, fair enough. Going to onshore a little bit more I guess talk about the Spraberry. On average what are you down space to and could you remind me of you have got approval to go to?

Scott D. Josey - Chairman, Chief Executive Officer and President

With the fuel growth the recent change we can go to 20s. And that's throughout the Spraberry trend. And depending upon the field or area the that we are drilling it ranges anywhere currently from... we are at 40s to even 160 I prospect. There are parts of the trend that are more perspective than others. And the odd oilfield in particular tends to be in the heart of the trend. We see very good results there and so that is an area that we feel pretty comfortable that we'll be able to down space that probably to 20, 25 acres spacing like I said its... we are not quite to 40s but we're approaching 40-acre spacing there.

A lot of the other areas that we have picked up, some of those areas we may only be able to take down to 80s but some of those areas we might be able to take down to 40s and 20s. So it really just depends on the area and but just that oil well alone we could have as I mentioned 100s of additional locations and if we contain our success throughout the trend in down spacing we could have 1000 plus of locations. So we think there is a quite a bit of opportunity in the Spraberry trend for us.

Scott Hanold - RBC Capital Markets

Okay. And then, if your current thought that there is water on the 120 wells per year so that's obviously a lot of inventory, what's your sense in ramping that up. I mean you have got five rigs running in the area. How do you kind of take a look back going to '09? Would you continue to sort of test whether the concepts or at some point, are you going to want to obviously attack it for more aggressively, to sort of maximize the present value of it?

Scott D. Josey - Chairman, Chief Executive Officer and President

I think we'll be doing some of both. I mean, we will and we constantly high grade our opportunities. If we are in a lower commodity price environment, then there maybe some areas that we table and spend more time testing some of the newer concepts. But I suspect, it will be a fairly balanced program consisting of probably... maybe about half or so of new things and the other half being down spacing our existing position as well as trying to add to our position out there.

Scott Hanold - RBC Capital Markets

Okay. So do you expect kind of keep at that, 120 well clipped in the Spraberry at least in the near term?

Scott D. Josey - Chairman, Chief Executive Officer and President

In this year, the 120 wells not all those will be Spraberry. I believe we drilled about 30 or 40 Wolfberry wells, if I'm not mistaking this year, they are about maybe 20 to 25. So, not all of those have been Spraberry wells. So I think as we go forward in West Texas, and try and give more to a 50 - 50 mix between Spraberry and other play types.

Scott Hanold - RBC Capital Markets

Okay, I appreciate it. Thanks.

Scott D. Josey - Chairman, Chief Executive Officer and President

Sure. Thanks, Scott.

Operator

And the next question comes from the line of Neal Dingmann with Dahlman Rose. Please proceed.

Neal Dingmann - Dahlman Rose & Co.

Good afternoon, guys.

Scott D. Josey - Chairman, Chief Executive Officer and President

Good afternoon.

Neal Dingmann - Dahlman Rose & Co.

Say, Scott could you give me an idea, obviously you've outlined a number of what I think a very attractive sort of deep prospects. I'm trying to get a sense now, when you look sort of cover one of these prospects have been drilled. Just how big that looks? I mean can you give a sense of how many more you've identified or will you have to go back in the leasing round. I'm trying to get a sense of sort of what the deep will look like for you all maybe late next year or even in the 2010?

Scott D. Josey - Chairman, Chief Executive Officer and President

Wellwe've... just in the last couple of sales and this is on top of my head. But I believe, we picked up about 28 new deepwater leases. A large chunk of those are in the subsalt and salt overhang and even real COGS prospects. So we've got a pretty substantial inventory whether we are drilling five to six wells per year in the deepwater. But we will continue to be active at the lease sales and attempting to pick up additional, what we believe are good quality prospects.

Neal Dingmann - Dahlman Rose & Co.

Okay. And then, just looking on, looks like I know at least for the last couple of quarters, the G&A has remained at least on a margin basis, pretty flat, do you anticipate I guess as you are seeing, I mean, would you build any of our estimates I guess costs coming down a bit both sort of looking on the LOE side and then thinking about G&A sort of going forward. What are your thoughts and what are John's thoughts there?

John H. Karnes - Senior Vice President, Chief Financial Officer and Treasurer

In general, we've over the past couple of years, we have increased our staff significantly to be able to handle it fairly aggressive program and as well as to be able to consolidate the various acquisitions that we have made. I think the staff is in pretty good shape, I think our future hiring needs will not be near as great as what they have been over the past couple of years, although we still have a few positions yet to fill. So we anticipate our production being even higher next year than it was in 2008. So I would hope that we would see it on a unit basis probably see those costs begin to go down.

Neal Dingmann - Dahlman Rose & Co.

Okay. And then lastly it's unlike you said at least on the onshore that you weren't concerned as far as medium rigs or what in rigs go as you need that you think as availability or more than the... I guess there depending what you all decided to do is that the occasion you'll go kind of on a well-to-well program?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, I think there are a lot of companies that are laying down rigs for various reasons. And so we think there could be some surplus in that market. Hopefully, that works to our benefit going forward and we'll just see how that plays out. But everything that we are doing right now meets our economic thresholds and we continue to monitor that and as I said earlier to the extent that commodity prices were to dip on us and projects weren't meeting our threshold then it will be very easy for us to lay down rigs and if conditions improve we think that we would also be able to add some rigs as well.

Neal Dingmann - Dahlman Rose & Co.

Okay, thanks.

Scott D. Josey - Chairman, Chief Executive Officer and President

All right, thanks.

Operator

And the next question comes from the line of Richard Tullis with Capital One Southcoast. Please proceed.

Richard M. Tullis - Capital One

Hi, good afternoon, just a couple of questions. Scott looking at the acquisitions environment in the Gulf of Mexico, I just want to get your thoughts on perhaps why we are not seeing really any activity at all to speak of given that I guess over the last couple of years the average transaction went for about $4.20 in Mcfe and now we are seeing a lot of companies trading that around 250 in Mcfe?

Scott D. Josey - Chairman, Chief Executive Officer and President

I don't think we are seeing a lot of activity and there hasn't been very many opportunities on the markets, lot of the activity was large independents or majors moving out of their shale positions and so lot of that has been done, probably the largest company that still has a significant shell position is Chevron or Apache still has a significant shale position which they acquired not long ago.

So there hasn't been a lot of opportunities to review. In terms of why companies are trading at their levels I think I and probably anyone that runs an E&P company today you know feels that there is a significant disconnect between the value of the company and where it's trading.

We also have not seen, in my view, really any... there's been very few transaction that's any in this recent commodity price environment to establish kind of what the value for transactions will be. We saw the transaction I guess ATP sold some North Sea assets; I am not aware of any other Gulf of Mexico transactions. I am not really aware of many... if any onshore transactions here over the last couple of months to be able to establish with the new price thresholds. I think companies that have assets they may want to sell and they pulled them off and kind of waiting to see kind of whether commodity price environment shakes out.

Richard M. Tullis - Capital One

Okay. Scott do you envision any share buyback opportunities at this price level?

Scott D. Josey - Chairman, Chief Executive Officer and President

I think it's... at this point, it's something that our Board... it's on the mind of the Board but it's not something that we are going to do at this point. We think that should be done in conjunction with our overall capital program which we will present to our Board here in about a month. And at that point we will discuss it with the Board to determine whether or not if we want a use our liquidity to acquire shares or not.

So at this point, it's not something we are perusing, but it's not something that we are necessarily opposed to under the right circumstances. But it's something that our Board would need to approve and we're not at that point yet.

Richard M. Tullis - Capital One

Okay. What's the production outlook for Daniel Boone in VK-821?

Scott D. Josey - Chairman, Chief Executive Officer and President

I would probably go to the operators to that, I believe W&T is the operator course of Daniel Boone and I believe they have sized those facilities for around 10,000 barrels a day. And so it should be somewhere...it's probably in the 7,000 to 10,000 or so barrel a day range. But I would leave that really more to them. And on VK-821 as you recall we drilled and operated the project through completion and then while oil and gas will finish up the umbilical and pipeline and tying work and, that's probably in the 2,000 to 3,000 barrel a day range.

Richard M. Tullis - Capital One

Okay. What's the status on surge, I know you have mentioned at the very beginning, but I didn't catch it?

Scott D. Josey - Chairman, Chief Executive Officer and President

The prospect size range is right in the 150 to 300 Bcf range.

Richard M. Tullis - Capital One

Okay. And your drill your on location there?

Scott D. Josey - Chairman, Chief Executive Officer and President

We are on location. The well should be down before the end of the month.

Scott D. Josey - Chairman, Chief Executive Officer and President

Okay. And I guess the final question; just going back to LOE outlook for the next quarter or two, do you expect to still be kind of at the same dollar amount level that we're seeing this past quarter?

Scott D. Josey - Chairman, Chief Executive Officer and President

I think our production level is probably going to be similar in the fourth quarter, as it was in the third quarter as based on our restated guidance. So I guess I wouldn't be surprised if the numbers came in somewhat similarly. But we shouldn't have to deal these one-time charges that John mentioned with these theoretical charges with OYL [ph] and other things.

Richard M. Tullis - Capital One

Okay. One more, what about your Gulf of Mexico rig inventory? What do you have right now near term?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, we have the Diamond Ocean, America under contract and then we also have time allocated to us under the Noble Lorris Bouzigard. So we still have time on two rigs enabling us to be able to drill our prospect inventory.

Richard M. Tullis - Capital One

Okay. Any thing else?

Scott D. Josey - Chairman, Chief Executive Officer and President

No, other than more short-term rigs there is no shelf rigs and that we have from time-to-time to do that inventory. We have rig at SMI 150 this is going to drill three wells there. And so we give rigs under... for enough time to be able to drill our programs and our programs usually are two to three, four or five wells at any given project.

Richard M. Tullis - Capital One

Okay, all right, thanks very much. I appreciate it.

Scott D. Josey - Chairman, Chief Executive Officer and President

Sure, thanks, Rich.

Operator

And the next question comes from the line of Philip Dodge with Stanford Group. Please proceed.

Philip Dodge - Stanford Group Company

Good afternoon. Thanks for the comments.

Scott D. Josey - Chairman, Chief Executive Officer and President

Good afternoon.

Philip Dodge - Stanford Group Company

Only to ask you a couple of things about reserves first gopher which John discussed if you just go through the time table for being in a position to book significant reserves there maybe specifically how much production history does it require?

Scott D. Josey - Chairman, Chief Executive Officer and President

It varies but typically what we see in the deepwater and maybe targeting used this line before the best place to drill, generally anywhere but particularly the deepwater wells in order to maximize the recovery. It is usually the worst place to drill it in order to receive proved reserve booking.

So typically what we see is a small amount but when you drill the well it's on high on structure in order to maximize the recovery. You typically get a small amount in the proved category and then the remainder is in the probable and/or possible category. That ranges still sometimes that it can be 15% to 30% you might see in the proven category at first. And then, and you will see the remainder in the other categories. Once the well comes online and produces for three or six months? And then you are usually able to then begin converting some of those probables and possibles into the proved category.

Usually over or after a couple of years then you tend to get the flow of bookings, something is like that. But each well is different but that's generally how it works. Small amount initially and then we see the rest of it coming on over a kind of a one to two, three year timeframe as we have performance.

Philip Dodge - Stanford Group Company

All right. And then would except to book anything additional at Bass Lite or Northwest Nansen this year?

Scott D. Josey - Chairman, Chief Executive Officer and President

We are hopeful because at that time we will have almost a year's worth of production... 10 to 11 months of production as well as a one well and they will have about five or so months of production on both wells. And so we are hopeful that Ryder Scott will allow us to build a book from additional reserves there. And those wells are performing very, very well. So, we will be presenting that to them as you know and as we stated many times. Our proved reserves are fully engineered by Ryder Scott and about 50% of our probable reserves are fully engineered by Ryder Scott which is why you see such high proved reserve revision each year that are positive year-after-year in our company.

Philip Dodge - Stanford Group Company

And finally in the Spraberry with the 20 acre spacing, you have any preliminary thought of how much, as they call out resource potential, that might set up?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well this is all just come about. And what we know is that as you down space the wells, the recovery from each well gets smaller. What we've seen in our... like at wells as we gone from kind of 160 acre down to 80 acre spacing, down to 40 acre spacing, you tend to loose around 20,000 barrels or so per wells. So our current wells that all dwell on 40 acre spacing, and we assume... those are generally intend to around 100,000 barrels to 110,000 barrels equivalent per well.

And they are about half gas, half oil but the equivalents is in the 100,000 barrels to 110,000 barrels. So if that our ratio continues then hopefully we will see something in the potentially the 80,000 or so barrels per well but that's pretty mature. We have done some testing and we are encouraged by what we have seen thus far. But now with these change in the field rules we will be able to do more of this and apply a better feel for that here over the course of the next six to 12 months. But we do think we... a fair significant portion of our properties we will be able to further down space and have quite a bit of reserves.

Philip Dodge - Stanford Group Company

Yes, all right sounds good. Thanks Scott.

Scott D. Josey - Chairman, Chief Executive Officer and President

All right, thanks Bill.

Operator

And the next question comes from the line of Pavel Molchanov with Raymond James. Please proceed.

Pavel Molchanov - Raymond James & Associates

Good afternoon guys. Question about your Gulf of Mexico lease sale strategy. As you look out to, I guess, it's in March, what will be your budget or your expectations for spending and then on a related point what are you hearing in terms of acreage valuations nowadays?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, I am not... I don't know how to answer that... I don't know how well I can answer that Pavel. What I know is that Mariner has always been active at lease sales. We will continue to be active at the sales. We have... it's just part of the... it's a key part of our company, it's a key part the way that we add value and grow the company. So... and we also have lots of seismic data and we have people dedicated to looking at opportunities in the Gulf.

The last... the past few sales have been some of the biggest in the history of the Gulf; the future sales are not quite as large as some of the past sales but I believe the one coming up in March is still fairly significant, fairly sizeable. So I would anticipate that we would be active at it and if we see good prospects, we will continue to do more than likely aggressively bid.

In terms of what those will go for, I don't know. It really depends on the type of prospect... over the past few sales we've seen major as well as international companies pay significant dollars for prospects and... but sale after sale we have been able to compete pretty well and we've generally been pretty pleased with results after each sale. So, I guess to try to answer that I think it will be business as usual for us at the lease sales with the main emphasis being the sale in March as... we've never been big participants in the sale we've held in August.

Pavel Molchanov - Raymond James & Associates

Sure, that's helpful. And would you be willing to potentially outspend your cash flow with regard to acreage if you see opportunities or would you still try to stay within cash flow?

Scott D. Josey - Chairman, Chief Executive Officer and President

The answer is generally no. I mean we strive, not counting acquisitions, but we try to stay within our means. This year we were as I said earlier we were pretty excited about the... we're having a... just a phenomenal year and probably going to have a couple 100 million of excess cash flow on top of the pretty aggressive capital spending program and... so the hurricanes cut through a bit of a ridge in that but we try to... we continue to strive a little within our means and that's our intention. So we've always done that and will do that going forward.

Now sometimes as things change... like at this point in the year, it's hard for us to change what we are going to spend for 2008, but we can make adjustments in 2009.

Pavel Molchanov - Raymond James & Associates

Sounds good. Thanks very much.

Scott D. Josey - Chairman, Chief Executive Officer and President

All right, thank you Pavel.

Operator

And the next question comes from the line of Nicholas Pope with JP Morgan. Please proceed.

Nicholas Pope - JP Morgan

Afternoon guys.

Scott D. Josey - Chairman, Chief Executive Officer and President

Good afternoon.

Nicholas Pope - JP Morgan

I was hoping to get a little more detail about the surge prospect. I mean it sounds like if you are near TD, I was wondering how, I guess how drilling is going versus expectations and... I mean have you all gone through the salt overhang and how it is like... where you see [ph] matched your modeling and your models?

Scott D. Josey - Chairman, Chief Executive Officer and President

We can't comment on that at this point in time but this is a... and we've got things and pictures of that prospect in some of our presentations if I am not mistaken. But it is a salt overhang prospect. Thus far the drilling has going fairly well and... but we're not at the objective yet. So until we get to the objective really don't have anything to provide in terms of what it looks like thus far. So we are in something like I said for the end of the month.

Nicholas Pope - JP Morgan

Right, sounds good. And I guess just with hurricane levels, what kind of milestone should we be looking for again in terms of pipelines and platforms coming back online. So which would be better for you there?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, as I mentioned on the call we believe that we will be... we are currently at about 70%. By the end of November we will be at about 85%, by the end of December we will be at about 97% of our pre-hurricane levels which are... which was about 390 million cubic feet equivalents per day.

Nicholas Pope - JP Morgan

But are there any milestones in terms of like specific pipelines or platforms that need to be brought back online?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well absolutely, but those numbers are based on conversations with a variety of pipelines and onshore processing facilities, et cetera, that... I mean there's numerous ones there, and so that's what we based our estimates on assuming that they do what they've told us they are going to do and we think they are reasonable. So --

Nicholas Pope - JP Morgan

All right. Sounds good, thanks a lot.

Scott D. Josey - Chairman, Chief Executive Officer and President

Okay. Thank you.

Operator

And the next question comes from the line of Brian Kuzma with Weiss Multi-Strategy. Please proceed.

Brian Kuzma - Weiss Multi-Strategy Advisers

Hey, good afternoon guys.

Scott D. Josey - Chairman, Chief Executive Officer and President

Good afternoon.

Brian Kuzma - Weiss Multi-Strategy Advisers

And one of my questions was on... in your onshore program, how do you think about it? What does a net rig cost to you guys per year to run in the Permian?

Scott D. Josey - Chairman, Chief Executive Officer and President

You know the... I guess... Brian, the way we look at it is we look at and so do folks on the rig, we look at the entire cost and as I mentioned, the total cost of drilling of Spraberry well for us is essentially an $800,000 to $900,000 that's the whole nine yards. So the rig is just a piece of it.

Brian Kuzma - Weiss Multi-Strategy Advisers

Okay, sure. And how many wells can one rig drill a year then?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, it takes anywhere from 10 to... 9 to 12, 13 days to drill one well.

Brian Kuzma - Weiss Multi-Strategy Advisers

Got you. And what did you guys spend onshore... what did you guys budget onshore this year?

Scott D. Josey - Chairman, Chief Executive Officer and President

It was in the vicinity of around $100 million.

Brian Kuzma - Weiss Multi-Strategy Advisers

Okay. And then do you look at some of your deepwater projects like Daniel Boone and VK 821 and Gopher next year, how much capital do you guys have committed to those projects in 2009?

John H. Karnes - Senior Vice President, Chief Financial Officer and Treasurer

Let's see. Brian I don't know if I can answer that off the top of my head. I think that I will have to get back to you and I think when we... after we do our budget process, I'll be able to answer that in a more detailed... but... it's well within our capabilities.

Brian Kuzma - Weiss Multi-Strategy Advisers

Okay. So think it's like less than a 100 million?

John H. Karnes - Senior Vice President, Chief Financial Officer and Treasurer

Well, we are spending a large portion of the capital at Gopher. This year there will be some carryover into next year. We've already spend and say we... W&T is the operator of Daniel Boone and a fair amount of that capital will be spent this year with the remainder into next year. And then VK 821, we've also spend a fair amount of the capital this year as well. So, I don't think it's going to be a... it will probably be material, but I don't think it's going to be... those three projects won't be a dominant part of our budget.

Brian Kuzma - Weiss Multi-Strategy Advisers

Okay, that's perfect. Thank you.

Scott D. Josey - Chairman, Chief Executive Officer and President

Thank you.

Operator

And the next question comes from the line of Michael Jacob. Please proceed.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Thank you. Just a follow-up on Brian's question. When you talked about 800,000 to 900,000 for Spraberry wells. Are you commingling Strawn, Wolfcamp Detrital, any of those intervals. And perhaps if you could breakdown the 800,000 to 900,000 in terms of drilling and completion cost that will be helpful?

Scott D. Josey - Chairman, Chief Executive Officer and President

Mike it's mainly our Spraberry wells tend to be Spraberry, Dean commingled wells. And then in terms of cost and just the drilling part of that off top of my head I don't know what that is.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Okay. And just to confirm it, to 100,000 to 110,000 barrels equivalent just from Spraberry and Dean together?

John H. Karnes - Senior Vice President, Chief Financial Officer and Treasurer

Yes.

Scott D. Josey - Chairman, Chief Executive Officer and President

Yes.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

And the following up on Deadwood as you are testing the play, can you walk us through your basic EUR assumptions and cost per well and just to kind of compare to your other onshore inventory?

Scott D. Josey - Chairman, Chief Executive Officer and President

Yes. The cost of those wells are somewhere around a $1.5 million range. They are testing a variety of formations will camp to try to also potentially you have will some potential Straw and you have Atoka even a little bit of Spraberry. So there is... its roughly about a two plus thousand section of interval that you are looking at.

So in terms of recovery we don't know yet because we haven't cracked and haven't tested the wells. We have assumed that they are going to be in the kind of 100,000 to 150,000 barrel range, but it seems work like we think and we think they could be much higher than that up in the 200,000 even 300,000 barrel equivalence range. So there is an enormous production that leads us to believe that we could see the middle or even the upper end of that range which is why we establish a significant acreage position.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Sure. That's helpful. And then just kind of since its too early to put Deadwood in this list, but if we think about your onshore program in terms of kind of highest RORs and thinking that the Wolfberry probably as better returns than the Spraberry. Can you talk about kind of drilling priorities and where in New Mexico falls in and kind of why you don't drill or why you wouldn't drill all Wolfberry before moving on to the Spraberry?

Scott D. Josey - Chairman, Chief Executive Officer and President

We drill a balanced program and so in that program consist of some very simple straight forward Spraberry, Dean wells, the Wolfberry wells are low higher risk but we tied good results there. Then you move up to something like the Deadwood prospect that is really more exploratory in nature. So like we try to do throughout the company, we try to have a balanced type of an approach. As we go forward in the next year it will be probably more the same, as there will be some exploration. We won't have the exploration in West Texas like we have in the Gulf of Mexico but there will be some and there will be some more moderate risk things like Wolfberry and others. Some of this trying to find types of plays and then you will see some very simple things in the Spraberry, Dean. So it will be a balanced program. But if we are not getting the right return, we don't do anything unless we get the right return that we are looking for.

Michael Jacobs - Tudor, Pickering, Holt & Co., LLC

Great, thank you.

Scott D. Josey - Chairman, Chief Executive Officer and President

All right, thanks Mike.

Operator

[Operator Instructions]. And the next question comes from the line of Rehan Rasheed with FBR Capital Markets. Please proceed.

Rehan Rasheed - Friedman, Billings, Ramsey & Co.

Hi, Scott.

Scott D. Josey - Chairman, Chief Executive Officer and President

Hi, Rehan.

Rehan Rasheed - Friedman, Billings, Ramsey & Co.

Just from a deepwater standpoint, the risk tolerance as we go out into '09. How would you guys be thinking about that. What will you... go ahead sir.

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, in terms of risk I think we've have said this before that probably the risk profile of our deepwater program going forward is probably a little higher than what it has been in the past. In the traditionally matters than a conventional amplitude player in the deepwater, and those are more bright spot types of plays.

We continue to pursue that, that approach that's what gopher is and we Dalmatian, with that type of play and we got numerous of those types of prospects in the inventory. But also when you look at projects like Surge and Heidelberg and we have other like those for next year. Those are subsalt or salt overhang probably little higher risk but also higher returns potential. So we try to look at things on a risk adjusted rate of return basis and then balance that with a number of low to modest risk of opportunities as well.

Rehan Rasheed - Friedman, Billings, Ramsey & Co.

Got it, got it. And do you feel that you have made enough progress on the technical front to continue to help the risk as you kind of move along? I understand risk a little better I presume.

Scott D. Josey - Chairman, Chief Executive Officer and President

Well, you just never know until you drill the well. And we do everything that we think is reasonable and appropriate before we drill the well. And but at some point you just, you are not going to know until you put a bit through it and the way we approach the subsalt trend as we were not the leader in that trend, we watched how other people who are ahead of us, and but we monitored the trend, we brought in the data, we brought in expertise, and then... and now we are starting to take a step at it.

And we won't be able to judge our success in that trend by any one well, you need to drill several to see how the shale's working. Same thing with the salt overhang trend, we saw other people and we feel like we are leveraging of their successes or failures. And so we take the same approach to this that we do to really anything in our business.

But you know, Mother Nature is difficult to figure out and sometimes it doesn't cooperate, sometimes you get positively surprised. But, these are good prospects, we have good partners, people that we have endorsement of other good companies. So we think they are worthwhile projects to expose to our shareholders.

Rehan Rasheed - Friedman, Billings, Ramsey & Co.

Thanks on that front. And I guess our last Marsh Shale [ph] from Spraberry questions as well. What IP rates do you expect from you normal Spraberry and Dean wells and kind of what IRRs are your basic typical hurdle rate?

Scott D. Josey - Chairman, Chief Executive Officer and President

Well I would say our typical Spraberry well is coming on between 30 and 50 barrels a day plus some varied components or so 2 to 3 Mcf a day as well. It's very rich gas and we're seeing rates of return that we believe exceed 30% or we wouldn't be drilling it.

Rehan Rasheed - Friedman, Billings, Ramsey & Co.

Okay, thank you.

Scott D. Josey - Chairman, Chief Executive Officer and President

Okay, thanks Rehan.

Operator

[Operator Instructions]. There are no further questions at this time. I would now like to turn the call back over to Mr. Patrick Cassidy. Please proceed.

Patrick Cassidy - Director of Investor Relations

Thank you, operator. As a final note I would remind you that this conference call will be posted on the company's website this afternoon; will be available for replay through November 15th. Thank you for participating in our call this afternoon.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. .

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