Good day ladies and gentlemen and welcome to the Third Quarter 2008 Gulfport Energy Corp. Earnings Conference Call. My name is Krista and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question and answer session towards the end of this call. (Operator Instructions). I would now like to turn the presentation over to your host for today's call, Mr. Paul Heerwagen, Investor Relations. Please proceed sir.

Thank you, Krista and good morning. Welcome to Gulfport Energy's third quarter 2008 earnings conference call. I am Paul Heerwagen, Investor Relations. With me today are Mike Liddell, Chairman of the Board; Jim Palm, Chief Executive Officer; and Mike Moore, Chief Financial Officer. During the conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and business. We caution you that the actual results may differ materially from these that are indicated in the forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted to our website. An updated Gulfport presentation was posted this morning to our website in conjunction with today's earnings announcement. Please review it in leisure. At this time, I would like to turn the call over to Mike Moore.

Thanks Paul and thank you all for joining us for our call. For the third quarter, Gulfport recorded net income of $14.1 million or $0.33 per diluted share based on average diluted shares outstanding of 43.1 million. This compares to net income of $12.7 million and diluted earnings per share of $0.33 during the third quarter of 2007. EBITDA for the third quarter of 2008 was $24.8 million, an increase of $3.5 million compared to the third quarter of 2007. For the third quarter, production was approximately 400,000 barrels of oil equivalent or 4,352 BOEs a day. Gulfport's production mix for the third quarter was 94% oil and natural gas liquids and 6% natural gas. For the third quarter, our realized price for oil after the affects of our fixed price contracts was $95.08 per barrel. Average realized price for gas was $9.91 per MCF and average realized natural gas liquids price was $1.75 per gallon or $73.55 per barrel. For the remainder of 2008, 3,500 gross barrels per day in production are hedged to fixed price contracts at an average price of $86.60 before transportation. We have also hedged 3,000 gross barrels per day at an average price of $89.06 per barrel for 2009. Our hedging program consists entirely of fixed price contracts negotiated directly with our fuel purchaser. These instruments do not require the company to post collateral or variation margin. A schedule of our fixed price contracts detaining our hedge position are available on our website under the Investor Relations page. Lease operating expenses for the third quarter were $6.4 million or $15.89 BOE while G&A was $1.7 million or $4.37 per BOE. The increase in unit cost is partially attributable to unexpected repairs and reduced production volumes related to the hurricanes. Total loss production from the…

Thank you, Mike and now onto our operational results and let's start first with our West Cote Blanche Bay field in Southern Louisiana. West Cote continues to prove itself to be a long-lived production base. In the third quarter, a rig returned to the field to finish our 2008 drilling program. We've released the drilling rig on October 27, having drilled eight total wells this year with 42 recompletion opportunities logged behind pipe. In the fourth quarter of 2008, we will exploit our inventory of recompletion to sustain production of the field as we did in the first half of this year. Hurricanes Gustav and Ike had the potential to significantly damage our facilities with the eye of hurricane Gustav passing within 15 to 20 miles of the field. However, our upgraded and improved facilities reduced to a minimum the amount of necessary repair work and downtime to re-establish production. At the beginning of this year, we stated that the goal of our capital program of West Cote was to hold production flat over the year. At that time, we were producing at rate of 3,622 net barrels of oil equivalent per day. At present, daily outflows from West Cote has risen to an average of 3,943 barrels of oil per day according to a recent 14-day average. Now, let's move on to Hackberry. According to a recent 14-day average, Hackberry is producing at a rate of approximately 785 BOE per day with State Lease 50 still shut in as we finish up our hurricane repairs. At the four wells drilled in Hackberry earlier this summer, all four were completed and are currently strong producers and their decline curves has been in line with expectation. At present, we have 13 permitted locations ready to go and our geologists are working…

Operator, please go ahead and queue up for Q&A

(Operator Instructions). Your first question comes from the line of Ron Mills with Johnson Rice. Please proceed.

Good morning.

Good morning, Ron.

I missed the first couple of minutes. So, I apologize Mike for your prepared remarks. Question just as it relates to the West Texas/Permian Bakken break down in your 2009 budget, of the $15 million, can you break that down a little bit further. How much would be towards the Permian and how much would be towards the Bakken?

Ron, I'd say we're probably look at probably look about 50-50. That allows us to; we don't really have any CapEx spend to maintain production. So, that allows us to drill two wells in the Permian and at today's prices, it'll be least driven. And when we go to the Bakken, we're kind of the tail on the dog up there because we are not operators. So, we respond to the proposals that are given to us and we've already seen signs of the proposals are going to start dropping off. So, it's our best guess at what we will drill in good areas.

And you said how many wells in Permian would that allow for?

We have a half interest in even at the $2 million per well, we spent about a million, we think those costs will be coming down. So that gives us room to drill seven wells easily. And that’s about what we think we’ll need to drill to maintain the leasehold of what that they are (inaudible) and so we will have some increase coming in from them.

Okay. And I know the cost have increased out there leading to that, one of the reasons for the limited activity there. But in terms of wells completed, how have they performed, I just want to trying to see if we should read anything more into if they were performing as expected or below expected in terms of why [heard] the thought process behind the extensive analysis that you are giving right now?

The reason we cut back is due to the drop in the price of oil, we just hate to give away those reserve at these low prices. If the costs come down, then we will go back to drilling there. But we’d like the way the wells have responded. We mentioned like the frac sand, we’ve been delayed in doing some of our completions. It took a little longer to get going than we thought, but individually, the wells are coming on good and you can see we were ramping up on the production. We just recently fraced a lot of wells, and as you know, every frac I mean it takes about three months to get up to production. So, we like the way things are going. That's where looking at right now at an acreage package and looking at possibly acquiring some more acreage in there in the Permian.

Okay. Excuse me, and in the oil sand project with the new CEO in place, it sounds like you are looking at your winter drilling program. Where does the process stand in terms of you know, the resource evaluation? Is that going to updated number one, and number two, where do all lie in the process of moving down the permitting process for your first facility up there or has that been delayed by increased costs we’ve read in some other company leases?

We are looking forward to get another resourced evaluation. But the firm that was doing most of work for Grizzly, I remember their oil sands evaluation team left for another company and so rather than go ahead and try to get that up today, we're getting so close to the drilling season that we decided to wait until we drill this program and then get a full evaluation next year. So, we won't have that for a while, but I tell you what, John really knows his business. He's been through the permitting process with Jackfish and with Jackfish 2. He knows the ins and outs of all other things. So, obviously, we're taking advantage of his knowledge and letting him go over the permits that we've got. He knows what buttons to push and not push with the regulators up there. We are delaying it. But, we're going to streamline it lot more for getting through the permitting process which you know it takes about a year up there. So, we'll just have to wait and see what happens as far as timing goes, but John knows so much about the reservoirs and so forth. It's going to be time well spend to do this.

Just to clarify, so you're basically delaying the permitting process until most likely after the winter drilling program as well?

That's correct.

Okay. I'll let someone else jump on and get back in line. Thanks.

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

Good afternoon guys.

Hey, Neal.

Maybe a question for Mike, just obviously with the cut in CapEx and doing most of the recompletions; just wondering what we can kind of look forward, let's assume this happens for the next quarter or two. Is it fair to say operating expenses would come down quite dramatically?

Well, we do expect costs to rollover as Jim has talked about and we do expect that to spillover into LOE as well. We may not see a 25% direct reduction, but I think we will see some reductions in LOE. For this year, I think we are still going to be in the $10.50 to $11.50 range. But remember, that include million dollars of hurricane expenses. So without that, we would have been right in $15 per BOE.

Okay. And then personnel and just kind of look at the rest of G&A is that do you think will remain pretty flat or pretty good now as far as personnel stuff either from Jim or Mike?

That should be flat. You're not going to see any increases and you should not see any increases in G&A.

Okay. And then just last question, I guess how quickly or what you've said I know you want to pay down some debt, I guess how quickly or what is your goal of where you like to be mid-year or next year anything on that?

I think, our approach at this point is and if you have a model, I’m sure you do, you're going to see that we've drawn out quite a bit of cash flow next year, so we're just going to take that and as much as we can through the year and give us some dry powder to take advantage of whatever opportunities we think have the best or more accretive for our shareholders.

Okay and that was my last question was going to, I guess maybe for Jim as far as looking at possible deals down the road sometime later next year, would you look in interview areas or would you look even outside of your sort of three main areas right now?

We’ve not only we'll be looking, but we have been looking. We actually made a bid on a South Louisiana property a few weeks ago. We lost that bid but in another month or two, that same type bid comes along, they make it. So, there are going to be some good acquisition opportunities. As I mentioned, we are looking in the Permian, we had an acreage acquisition right now to decide if we want to pull the trigger on that one. We're evaluating. We primarily look in our areas. The first place we look is in our areas where we are active. First place, first kind of prospect we like is still in oil prospect. If a gas prospect comes along, we'll take a look at that. If it's a good opportunity and not in our existing areas, we'll take a look at that too. So, but we like to look first towards close to our home.

All right, perfect. Thanks guys.

Your next question comes from the line of David Kistler with Simmons & Company. Please proceed. David Kistler - Simmons & Company: Hi guys. Real quickly pop it back to the tar sands for a bit. On the last call, you guys kind of outlined almost $20 million for CapEx for '09 there and obviously coming down to five and a little bit steeper decline in the overall portfolio on a CapEx cut. But, can you just walk us through what you're cutting out there. Is it purely permitting stuff you are chasing, cost of extra people out there, just trying to get to get a handle on that.

Part of that costs, remember, it was for the beginning of the facility construction that is going be spread over a three-year period. So, I don't really think we can cut that much activity here.

No, we really haven't. Most of what we'll do next year is some additional drilling at Algar Lake to learn a little bit more about that reservoir and despite and that will be the first one that we do. Kodiak, we really like Kodiak and we'll do additional drilling there. The rest of the areas, we are going to kind of let the industry drill around it. There's been a lot of drilling going on around this. We're going to take advantage of that. We're going to work the good data that we've got. When people started drilling a couple of years ago, now that's been released to public information and so there's a lot of geological information to deal with there and it will help us more effectively target good areas where we got lot of the acreage to evaluate and using this the other pre-information will help us (inaudible) next year. David Kistler - Simmons & Company: All right, thanks for that additional color. Hopping over to the Bakken, can you talk a little bit I know, more of an non-operated role, but can you talk a little bit about pricing differentials there and can you talk a little bit how you're transporting commodity out of there. That would be very helpful.

Well, the differentials are certainly are high up there. In lot of cases, but really what’s going to happen this year is that we believe that people are going to drill. There are really good areas like the Parshall that we’ve been participating in and even with the prices where they are, that kind of areas would be well economical this year. As far as long-term on the differential, there is a lot of things that are going around now. Some people are looking at pipelines, some people looking at truck and some people are looking pulling in railroads to carry the product out of there. So, I am not sure, where it's all going to settle out. But we’re looking everywhere we can to try to figure out to minimize our differentials up there, but there is only so much you can do. David Kistler - Simmons & Company: Okay. And in the Permian, I guess you guys are about 175 barrels a day. Kind of looking at it in exit rate at least of last calls kind of 1,200 to 1,400; is that still about right. Is there that kind of growth that we should be or trajectory we should continue to look at?

Well, we have the ramp up slightly more recently. I think at this point David, we are looking in the range of 1,000 barrels or 1,100 a day. David Kistler - Simmons & Company: Okay, great. And then last housekeeping one; also on last call you had talked about being able to reveal some of the drilling results from the four wells in Hackberry area, didn't see that in the press release. I was curious if one it was either you are still working through issues there as a result of the hurricanes or can you share information on those wells?

Well, I can share some information which is pretty public information which is stated down there so. But basically, those last four wells, we didn't start really bringing them on until August. So, we really got August, September, and October and that's really about two and a half months or less than two and a half months because of the impact of the hurricane. And those four wells together, have made about 61 MBOE in those three months or two and a half months. So, you can see it's a nice… David Kistler - Simmons & Company: Yeah, great. Well, that's very helpful, guys. Thanks so much.

Thanks, David.

Your next question comes from the line of Sven Del Pozzo with CK Cooper. Please proceed.

Yeah. I wondered in your different operating regions, I was wondering if in Southern Louisiana, if that might be considered more of a niche, it might be less competition with regard to rigs as compared to West Texas. In another words, would you envision West Texas rig rates falling by greater in percentage terms more than they might in Southern Louisiana?

I think there's going to be pretty good drops in all the areas. And those two there is a lot of drilling going on in both places and you're right Sven, there's a lot of drilling going on in Midland and things do respond pretty quick there. But maybe they would drop a little bit faster, but there are going to be substantial reductions going on in both places.

And am I correct in thinking that you've got barge mounted rigs in Southern Louisiana or that's what you typically use?

Yes, depending most of what we drill by that time at West Cote is using barge mounted and over to Hackberry, we did and those four wells were land rigs.

Okay. And so the fact that their barge mounted, that doesn’t make any, might there be a particular market for barge mounted rigs and might make it different from a land base rig?

Well, from what we see there's, rather a few months ago, there was an availability and prices were firm. Today, there is plenty of availability actually on both of them and both land and our general think, we’ve seen the prices start dropping in but that's kind of the cycle you go through. First, there is availability when there wasn't any and then the prices start to drop.

All right. Thank you, Jim.

(Operator Instruction). You have a follow-up question from the line of Ron Mills. Please proceed.

Hey, Mike just to clarify. It sounds like that '08 LOE average includes some storm related cost, would you expect there to be much difference on your what had been your prior cost guidance on BOE basis for either LOE DD&A or G&A?

No, I think G&A, we should be fine. DD&A, we should be fine. LOE with the extra hurricane expenses, we are going to be a little above the rate that we originally spend.

I was more looking ahead to 2009, if we don't forecast a couple of million dollars of hurricane expense.

Yeah, I think 2009, Ron, without factoring in any cost reductions, we're looking in the probably $9.50 to $10.50 range, but we would expect to see some reductions in some of the supply cost and service cost, so those are factored in.

Okay. And I missed something. You are saying someone asked about the Permian Basin and you all mentioned something about 1,000 to 1,100 barrels a day. Is that where you all expect the production to eventually reach once all these recently fraced wells cleaned up and start producing?

That was exit rate. I believe…

So, that's exit rate. Okay.

Yes. And then at the end of the year, we will still have wells ramping up that we're getting ready to frac, like the wells we are getting ready to frac, we've got free, we're getting ready to frac and they won't come to match until three months after and we just fraced some wells last month. So, we will still be climbing at the end of the year.

Okay.

In the first part of the '09.

Thanks for the clarification.

And I might say that it was, we think we are doing pretty well. We have reduced that some. But you know, originally, we were talking about drilling 35 to 45 wells and with the decrease in the price of oil, we only drill 29 wells this year. So, you can see why we are not disappointed in the way things went. We think we got pretty good exit rate considering we had significantly less wells than we started out with.

Your next question comes from the line of Sven Del Pozzo. Please proceed.

Yes. I was just looking at maturity schedule for your debt. I mean, given that with the new CapEx budget and prices say where they are although I know things might change, would you be willing to reduce debt prior to the maturity in 2010. And also wondering when in 2010 that $83 million matures?

It matures in March 2010. It's what your question Sven, I am sorry.

Yes. Would you just your attitude versus paying down debt should prices stay where they are. Should you stick to that CapEx that you've laid out for 2009; you're going to have free cash flow and would you pay down debt with it?

Well, I think initially whatever free cash flow we had, we didn't need it. We're going to pay down debt. We don't want to pay interest on it. That builds us some dry power to give us some opportunities to look at later in the year, commodity prices recover, cost go down, we look at acquisition opportunities and we are expanding our CapEx program. Does that answer your question?

Yes. Okay. Thank you.

At this time, there are no further questions. I would like to turn this presentation back over to Mr. Paul Heerwagen.

Thank you, operator and I believe that concludes this morning's call. A replay of this call will be available temporarily through the company’s website and can be accessed at gulfportenergy.com. Thank you for your time and interest in Gulfport Energy this morning. This concludes our call.