Gulfport Energy Corporation (GPOR) Q4 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corp. Fourth Quarter 2011 Earnings Conference. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Paul Heerwagen, Director of Investor Relations.

Thank you, Javon, and good afternoon. Welcome to Gulfport Energy's Fourth Quarter and Year End 2011 Earnings Conference Call. I'm Paul Heerwagen. And with me here today are Mike Liddell, Chairman of the Board; Jim Palm, Chief Executive Officer; and Mike Moore, Chief Financial Officer. During this 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 actual results could differ materially from those that are indicated in these 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 certain 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 at your leisure. At this time, I'd like to turn the call over to Mike Moore.

Thanks, Paul, and good morning to each of you. I'm pleased to report that Gulfport recorded strong fourth quarter results, both operationally and financially, producing 662,000 barrels of oil equivalent or BOEs and generated approximately $53 million of EBITDA, $53.8 million of operating cash flow and $31 million of net income. As a result in 2011, Gulfport generated approximately $173.6 million of operating cash flow, $172.7 million of EBITDA and $180.4 million of net income on production, totaling 2.3 million barrels of oil equivalent. In the fourth quarter of 2011, production averaged approximately 7,193 BOEs per day, increasing 12% sequentially over the third quarter and 23% from the fourth quarter of 2010. For the year ended December 31, 2011, production averaged 6,392 BOEs per day, which was an 18% growth production over 2010. Our production mix for the fourth quarter was 95% oil and natural gas liquids and 5% natural gas, with approximately 55% of our production coming from West Cote, 29% from Hackberry, 14% from the Permian and 2% from Niobrara, and a miscellaneous other rights in the areas. Our full year production mix consisted of 94% oil and NGLs, and 6% natural gas. Revenues for oil and natural gas and natural gas liquids in the fourth quarter were $68.9 million, an increase of 19% sequentially over the third quarter. Full year 2011 oil and gas revenues totaled $229 million, up 79% year-over-year. In the fourth quarter, our realized price for oil after the effects of our fixed price contract was $109.18 per barrel. Average realized price per gas was $3.67 per MCF, and average realized price for natural gas liquids was $1.39 per gallon, or $58.42 per barrel. Our blended price for the quarter was $104.11 per barrel of oil equivalent, and our average realized price per barrel of oil equivalent for the full year of 2011 was $98.13. Subsequent to year-end 2011, production through Q2 '11 [ph] has averaged approximately 7,250 BOEs per day. Lease operating expense for the fourth quarter was $5.8 million or $8.76 per BOE, down 10% sequentially on a unit basis. For the full year, LOE was $20.9 million, or $8.96 per BOE. G&A was $1.9 million, or $2.82 per BOE for the quarter. For the full year, G&A was $8.1 million, or $3.46 per BOE. To conclude our income statement discussion, EBITDA for the fourth quarter was $53 million, an increase of 20% sequentially over the third quarter. EBITDA for the full year 2011 totaled $172.7 million, which was an increase of 93% year-over-year. Net income was $31 million in the fourth quarter, or $0.59 per share based on approximately 53 million average diluted shares outstanding. For the full year, net income totaled $108.4 million, or $2.20 per share. Operating cash flow before changes in working capital came in at $53.8 million for the fourth quarter and $173.6 million for the full year of 2011. Moving on to the balance sheet. As of the end of December 31, 2011, the company had $2.3 million of total debt outstanding and was completely undrawn on our revolving credit facility, which has a current borrowing base availability of $150 million. This $150 million is an increase as a result of our Spring Reed [ph] termination, our legal vendor has just completed their review and recommended an increase from $125 million to $150 million, of course, subject to the approval of the other banks in the syndicate. In terms of capital expenditures, we invested a total of $158.4 million on 2011 activities, including $26 million spent in Canada but excluding the capital invested per unit to acreage totaling $118.2 million. Turning towards reserves, as of December 31, 2011, our total proved reserves for the lower 48 were 16.8 million barrels of oil and 15.7 billion cubic feet of natural gas, or 19.4 million BOEs. In Canada, we are proud to announce that Gulfport now has 16.8 million barrels of proved reserves, attributable to our 25% interest in Grizzly, Algar Lake SAGD project. In addition, third-party engineers have issued a probable reserve report estimating 1.7 -- I'm sorry, estimating 17.9 million barrels of oil, 13.9 billion cubic feet of natural gas and 1,700 barrels of natural gas liquids, or 21.9 million BOEs of probable reserves associated to our lower 48 assets and 11.8 million barrels of probable reserves attributable to our interest in Grizzly. Moreover, third-party engineer GLJ has provided an updated year-end resource report of some of Grizzly's properties and has identified 565 million barrels of Best Estimate Contingent Resource, net to Gulfport's interest. And keep in mind, these numbers do not include Grizzly's May River acquisition, which is set to close February 28 and will include 22.7 million barrels of probable reserves and 156 million barrels of Best Estimate Contingent Resource, net to Gulfport's interest. Using SEC pricing of approximately $96.19 for oil and $4.12 natural gas, the PV-10 value of our lower 48 proved reserves was $490 million at year end. However, to get some sense of relevance, in our earnings release this morning, we provided a comparison of the estimated PV-10 of our lower 48 proved reserves using the SEC pricing to a December 31, 2011, price held flat, as well as a comparison to a February 15, 2011-- 2012 NYMEX case. Compared to our $490 million year-end SEC case, the flat price case results in a PV-10 value of $519 million, while the NYMEX case yields to PV-10 value of $507 million. Including our probables, the NYMEX case totals over $917 million, and remember this does not include any value or interest in Grizzly or other non-producing assets in the Utica. At present, we currently have 2,000 barrels per day of hedged volume for the remainder of February at a weighted average price of $108 per barrel. Beginning in March, our hedged volumes increased to 3,000 barrels per day for the remainder of 2012 at a weighted average price of $109.73. We have also begun layering on a base layer of hedges for 2013, which now currently includes 1,000 barrels per day of hedged volumes from January 2013 through June 2013 at a weighted average price of $113.20. Our current 2012-2013 hedge program hedges Brent crude at the underlying index. Schedules summarizing our 2012 guidance and our current hedge position can be found in the updated presentation that was uploaded to our website this morning. Looking ahead to the rest of the year, I would like to take the time to reaffirm our 2012 guidance, which includes capital expenditures totaling $215 million to $225 million, excluding our portion of Grizzly's May River acquisition. And keep in mind, we do plan to fund our activities from -- within cash flow from operations this year. In addition, Grizzly recently informed us that they intend to pursue a capital raise, which they expect to be executed in the next 18 months. Capital raise should satisfy the future funding needs for Grizzly's currently contemplated growth plan and should allow Gulfport to redirect capital towards accelerating growth in its assets in the lower 48, such as the Utica and Permian Basin. Thank you for your time today and interest. And now I would like to turn the call over to Jim to cover our operational highlights.

Thanks, Mike, and thank you all for joining us for our call. I'll jump right into it starting with an update in the Utica Shale of eastern Ohio. This is a play that has the potential to make a significant impact on Gulfport within a short-time horizon. We currently have approximately 125,000 gross, 62,500 net acres under lease with 5-year primary term and 5-year options. We're in the final process of paying off our leases, and to-date, have closed on over 85% of the position. As of today, Gulfport has filed 5 permits in the play, 2 in Harrison, 2 in Belmont and 1 in Guernsey Counties. Along with the 5 permits that have been formally filed with the state, Gulfport has 30-plus locations in various stages of the process leading up to permitting. It's worth noting that as we plan and build our locations, we're constructing them to be large enough for super pads, which would allow us to drill multiple laterals from one surplus location. This should deliver significant efficiencies from a completion and midstream perspective once we move from delineation to development mode. Our first drilling location in southern Harrison County has been built. The drilling rig is currently on location, and we have spud our first horizontal well in the play. The rig is under contract through the remainder of 2012 with Union Drilling, and we plan to add a second rig as early as April of this year. We've also bid out and contracted our tubular needs for 2012 in the Utica, where the contract that caps the price but also allows us to participate in any future price reductions. With each passing day, we learn more and more about the play and become increasingly enthusiastic about its potential. At last count, there were 18 horizontal wells actively drilling in the Utica. With the addition of every new well, industry drilling and completion techniques are refined and efficiencies are gained. Our peers are helping us learn about the play, and we are already leveraging the knowledge acquired by our service providers. Moreover within the industry, there seems to be a spirit of cooperation among the companies in the play. We've had a good reception in terms of willingness to share data and jointly build drilling units. And finally, with regard to takeaways in the Utica, over the past months, we have added midstream expertise and have been working through a detailed process to identify whom we will work with as a midstream partner in the Utica. We are nearing the end of that process and expect to execute a Letter of Intent within the next week with definitive agreements to follow shortly thereafter. Selecting the right midstream partner is important to our success because much of our acreage in the Utica is in the rich gas area, and given the current pricing environment, maximizing the value of the natural gas liquids is critical. The agreements that we are finalizing will allow us to maximize the value of our produced gas and natural gas liquids, minimize our gathering and processing costs and move our gas to market as soon as possible. The proposed agreements will also provide for our potential ownership in the system. The details of our negotiations are covered under confidentiality agreements so I cannot expand further at this time. However, we plan to issue a press release with more details when we execute definitive agreements. We're extremely pleased with where we expect to end up in this process. And now let's move on to Canada. Grizzly has seen an active winter season on the exploration and acquisition front. As Mike mentioned earlier, at the end of the year, Grizzly received a third-party resource report from GLJ, reflecting 16.8 million barrels of proved reserves, net to Gulfport's interest and Grizzly's first SAGD project at Algar Lake. To put this into perspective, Gulfport's interest in Algar Lake, added together with Gulfport's lower 48 proved reserves, represents an increase of more than 70% year-over-year in proved reserves. On top of that, we also had exposure to 11.8 million barrels of probable reserves and 565 million barrels of Best Estimate Contingent Resource attributable to Gulfport's interest and only 34% of Grizzly's acreage. Grizzly is ramping up for the 2011-'12 winter drilling season, and to-date has drilled 22 core hole evaluation wells at Thickwood. Data from these cores and seismic that is currently being shot will supplement the necessary information needed to begin the regulatory application process. We are encouraged about the preliminary results and anticipate Grizzly will file the Thickwood Hills application during the second half of 2012. Meanwhile at Algar Lake, Grizzly continues to be on budget and on track for commissioning in the fourth quarter of 2012 with first production by midyear 2013. In the updated presentation that was posted this morning to our website, we've included some pictures to update you on the progress being made on the project. Construction on the all-weather road and facility site is underway. In-shop fabrication of the central processing facility modules is ongoing in Edmonton, and components of the precision slant rig are arriving on location with SAGD well-paired drilling set to begin in the second quarter. With these 2 projects well underway, Grizzly has added another very attractive project to its inventory. As previously announced, Grizzly has entered into an agreement to purchase Petrobank's May River property for approximately $225 million, or $56 million net to our interest. This asset adds a high-quality resource and significant scalability to Grizzly's existing portfolio of projects and brings Grizzly's total footprint in the oil sands to over 800,000 acres, with approximately 3 billion barrels of reserves and contingent resources. May River is located in arguably one of the most active areas in the oil sands. The asset is surrounded by 4 major projects, which combined to make over 130,000 barrels of bitumen per day, with new permits and expansion plans pointing toward 1.4 million barrels of capacity in the near future. Grizzly's May River asset stands to add another 75,000 barrels per day of capacity to the area. This area of the oil sands is characterized by very low steam-to-oil ratios, which provide for very attractive capital efficiency ratios and strong operating net backs. Infrastructure is in place, and we believe May River has been substantially derisked by activities surrounding it. Traditionally, U.S. E&P companies have played in all of the North American basins with the exception of the Canadian oil sands. In 2006, Gulfport decided to buck this trend and began accumulating a position in the play. We took the long-term view that the oil sands would become a major contributor in supplying world energy demand. So here we are today, 1 of 2 U.S. independents, the other being Devon, with a meaningful position in the oil sands. By virtue of our investment in Grizzly, we have exposure to over 800,000 acres in a known oil play, second only to Saudi Arabia in size, with a low-decline resource base that provides for several decades of meaningful growth. We've long intended Grizzly to be one of the last major oil sands companies to not have done a JV and now are in a position of strength as one of the last man standing. Grizzly has already seen a lot of interest from both domestic and foreign holders. And now let's turn to West Texas. The Permian continues to be a growth driver for Gulfport, with production increasing 28% year-over-year during 2011. Last year, a total of 34 Windsor-operated wells were drilled on our acreage in the Permian. At present, 2 rigs are drilling ahead on Gulfport acreage, and we expect to add another rig in March. Over the past several months, the operator of our acreage has made significant advances in drilling and completion efficiencies. While they used to do a 10-stage frac on our 2,000 foot Wolfberry interval, they've refined their techniques to do a 7- or 8-stage frac over the same interval and make wells as good as the older ones. Meanwhile a year ago, they used to drill a typical Wolfberry well in about 20 days spud to TD, and now we expect to drill that same well in 15 days. In fact, one of our Bison-owned rigs recently drilled a 10,000-foot well in 10 days spud to TD. In addition, as we fully exploit these properties, existing tank batteries, roads, electric lines, frac water-holding ponds and other infrastructure are already in place and will afford efficiencies both operationally and financially going forward. On another note, over the past several months, we have monitored the horizontal drilling activity of offset operators and have been encouraged by the results being reported. Similar to the Utica, we have leveraged out the experience and drilling dollars of others to help refine our horizontal drilling plans. Currently, the first horizontal well on our acreage is set to spud next month. This well is 8 miles south of Pioneer's recent horizontal wells. And this rig will be drilling nothing but horizontal wells for the rest of this year. We have a number of horizontal targets on our acreage, including the Cline, the Dean, the Strawn and the Atoka. Early on in the play, we did extensive geological and engineering evaluation over our acreage, and we believe it will serve us well going forward. Our library of cores, microseismic and 3-D seismic should help us pursue this very exciting emerging horizontal play. And now let's go on to Southern Louisiana. At Hackberry, we continue making some solid wells and are pleased to report we increased production by 51% year-over-year. During 2011, we drilled 22 wells at Hackberry, completing 17 wells as productive, with 3 wells waiting on completion at year end. In addition, we performed 24 re-completions. Our 2011 activity at Hackberry represents a 91% drilling success rate. Currently, we are running 2 rigs at the field and are drilling ahead on our third and fourth wells in 2012. At West Cote, we continue to see steady success. During 2011, we drilled 21 wells, completing 19 as productive, with one well waiting on completion at year end. In addition, we performed 68 re-completions. At present, 2 barge rigs are active at West Cote and are drilling ahead on the fourth and fifth wells of our 2012 program in that field. Now moving along to Colorado. In the Niobrara, we drilled and completed 3 wells during late 2011. All 3 wells tested commercial quantities of oil with an unstimulated natural open-hole completion. However, the wells have continued to present challenges with sloughing and fill collected in the wellbore. As such, we are currently in the process of running in slotted liners. Meanwhile, we have finished processing our 60-square mile 3-D seismic survey over Craig Dome. We are currently picking vertical well locations along clearly defined faults identified by the seismic. These locations will be permitted over the next several months, and we expect to resume drilling in the Niobrara by May of this year. And finally shifting to Thailand. In our TEW-E well in Thailand operated by Tatex, while encouraging, was not, at this point, commercial. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing the well did not exhibit that there was sufficient permeability to producing commercial quantities. During testing, the well produced rates as high as 16 million cubic feet per day of gas for various short intervals but would quickly fall to a sustained rate of 2 million cubic feet per day. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Now let me put this in perspective. First, our all-in net investment in this play, including acreage, seismic and drilling, is very minimal at $8.3 million. Second, as you know, we have a small interest in the Phu Horm field, which last year averaged 83 million cubic feet of gas per day and 380 barrels per day of condensate. And as we pointed out before, Phu Horm produces from the same carbonate formation that we drilled in the TEW-E. Remember that Phu Horm was not an overnight commercial success. The first well at Phu Horm was drilled by Exxon and tested at rates as high as 24 million cubic feet per day of gas, but quickly declined to a sustained rate of 4 million cubic feet per day. Later, Gulfport and others participated in another test on the structure, and the first 3 wells tested at a combined rate of approximately 100 million cubic feet of gas per day. These results demonstrate the variable quality of the reservoir within very large productive structures. We know we have the structure, now we just have to find the quality rock. We intend to continue testing the structure, as well as some of the other structures identified through our 3-D shoot and are beginning the application process for 2 more drilling locations. We hope to drill the first located to the south of the TEW-E late this year or early next year. And keep in mind, these wells only amount to about $1.8 million net to Gulfport. So that pretty well covers our current results. To wrap things up, we're looking at a compelling set of milestones ahead of us during 2012. Aside from 35% production growth, the market can look forward to: First, our activity in the Utica this year will include results from approximately 20 gross wells, which we believe will help -- will begin to help the market appreciate the considerable value to be unlocked from this asset. Second, valuation milestones for Grizzly in 2012 include the commissioning of its first SAGD project at Algar Lake, the submission of its regulatory application for Thickwood Hills and the addition of a high-quality asset at May River, which will contribute 75,000 barrels per day of production to Grizzly's growth story. Third, the addition of a horizontal drilling component to Gulfport's growth story in the Permian, which could accelerate growth and amplify the already attractive returns of the play. And finally, our strong balance sheet, together with continued free cash flow generation, will continue to allow for organic production growth from our core areas of operation. I thank you for joining us for our call today, and we look forward to answering your questions.

Operator, please open up the lines for questions from our participants.

[Operator Instructions] And our first question comes from Mark Lear with Crédit Suisse.

Mike, you had mentioned earlier in your prepared remarks about potential capital raise at Grizzly to fund CapEx. Can you talk about some of the things you're considering there or that Grizzly's considering there? You had mentioned maybe a few weeks back that your monetization might have been in the cards as well.

I think there are lots of options on the table, Mark. Of course, it's early in the process, so we don't know for sure. But certainly, I think they're looking at both debt and the equity markets as well. But it also could include a JV or again an IPO. All those options are available to us. As Jim mentioned, there's lots of interest especially since the May River acquisition that we announced. It certainly has -- and it seems like accelerated the interest in Grizzly. And then there are other activities up there, I think, that could also influence which way they go, for instance, the Sunshine deal that's been announced. So I think there's lots of different options on the table, so we're just -- it's just early on, we just don't know for sure which way they're going to go.

Our next question comes from the line of Ron Mills with Johnson Rice.

Mike, a question for you just on oil realizations. Obviously, real strong again in the fourth quarter, really driven by the South Louisiana contribution. When you look at your oil production build throughout the year, one, how would you try to suggest people forecast the South Louisiana pricings given that volatility in the spreads, number one? And then number two, as you start bringing production on, or more production on, from either the Permian and more importantly the Utica, what kind of pricing scenario should we assume for that just so we can look at a blended differential for your production, which will likely be increasing here?

Okay, that's -- I'll try to answer all those. What we do know at this point is that for January and February, there was about a $10 premium for Southern Louisiana crude. But after that, more recently, we've seen some widening differentials again, so that actually widened to $17 to $18, it looks like for March. I think for the rest of the year, Ron, because there is a lot of volatility here, I think $10 premium would be a safe assumption probably. It could be a little more than that, we're just not sure what's going to happen. But I think, at the very least, I would use a $10 premium. Now kind of going to your question on the production mix as we bring on Utica, while there certainly will be a different price structure there -- remember, a lot of that production is back-end loaded in the year, so I would say generally that for the first 6 months, it's still going to be mainly driven by Southern Louisiana pricing. Those differentials would probably be good. And then we're not sure what the exact production mix is going to be, Ron, in Utica, so it's hard for me to tell you exactly what numbers to use there. We can talk offline about that. But I'd say, generally, a $10 premium is probably a good way to look at it, and that would probably account for any differentials that we might also see in Utica.

Okay. And then Jim, in the Permian, when you talked about the horizontal drilling, where was this, first of all, going to be drilled? Is it in Upton County? I think you said it can be south of Pioneer. And the one formation that you didn't mention was the Wolfcamp. Where are you planning on targeting this first horizontal? You mentioned Cline and Dean and Atoka but not the Wolfcamp.

Yes, that's right. Well, Wolfcamp is -- that's where the shale is that we're going to first. I'd call it -- I'd call this shale -- it's a marker shale that shows up all over the place. You can take it from down in Upton County, and that you're right, that's where we're starting with our -- in the area of our original acquisition. And you can follow that shale all the way up through Midland and up into Andrews County. So it's a good one for Pioneer to have put those wells into. So we're starting off with that. I'd call it a lower middle Wolfcamp shale. And then of course, as you know, when we talk about the Cline, we're talking about the Lower Wolfcamp. And that we could drill Lower Wolfcamp down there, but we're close to the shales, they have a lot of carbonates in. It will be a little bit different than a shale play down there. But when you move up north to Midland and Andrews County now, it's further from the shale pads and it's lower energies, and there's lots of shale. And so up there, when you drill the Cline, it turns into a shale play, and that's where we're looking next. And then these other formations like the Strawn and the Atoka, we and Windsor have a number of ideas about that, so that's why I say, this rig was one that was drilling in the Cana Woodford and was drilling horizontal wells, and we bought it for Bison. Actually we bought 2 of them out there, moved them down to Midland. So we took off the -- some of the equipment and started drilling vertical wells, but now we're re-equipping it for the horizontal wells, and this rig will drill these different ideas, which are all the way, like I say, up to Andrews County, they're on different concepts, and so we know we need to test them all. And then depending upon where we have success, we may re-equip the other rig and bring it down and start drilling some development wells, where we have the successes. So it's going to be an active horizontal drilling program up there.

Okay. And then last one, then I'll jump back in. If you look at your Utica map, you have your 5 permits highlighted on the presentation. Which well are you drilling now, and do you have a sense as to what order your first 5 wells will be coming in?

Well, the first one is on the border -- southern border of Harrison County. And again in this particular one, to give you an idea of what we're doing, we've got 4 laterals marked out on it. We're going to drill the first one as our first test, and it's just about on depth with the fuel well that was drilled by Chesapeake. So we think that's the kind of everybody wonders how oily is it going to be, how wet, how gassy, and that's the Wagner #1. And so it should be similar to the fuel well. And we're also -- of course, early in the game here, we're coring it and we're doing all the normal science that one does when you start off in the program, but then the rest of them are in the northwestern Belmont and over into Guernsey County. We're going to drill Brushy port next probably. We have one called the Boy Scout that we're going to drill third most likely. We think that when we finish the Wagner, we're going to move to probably Brushy Creek and then maybe within a couple of weeks after that, we may put a second rig going on Boy Scout. And we actually have, as we said, about 30 locations that we're working on, but we've got 5 that are high graded there in the kind of the corner where those 3 counties come together. But then we'll begin the delineation process, and we're going to drill from north to south and then east to west this year with these 20 wells. And we'll find out where it's gassy, where it's oily, what the amount of liquids are, all that kind of stuff. And then once we've determined that with this year's drilling, then of course, we'll start developing with pad rigs and we'll drill -- we'll go from 20 wells this year to 50 next year and 70 the next couple of years just to hold acreage. So it's going to be an active program, but we'll delineate it this year, and then we'll follow up next year with more development and acreage holding.

Our next question comes from the line of Brad Heffern with RBC Capital Markets.

Just on the back of the previous question, I wonder if you can talk a little bit about how long it takes to get the permits in the Utica. Obviously, you have 5 already, but is it no problem getting to the 20 that you plan for in '12?

Well, it's like any place else. It's like South Louisiana. Will actually probably take long to get -- a lot longer to get a permit down there. You've got all kinds of oyster surveys and coastal use permits you have to get. So it's just a normal thing. And I think the state's doing just fine. They're really being swamped with a lot of permits, they seem to be handling it just fine. I don't see that acquisition of permits is going to be a delay for us.

Yes, and you can actually walk those permits through the state in a very quick manner, I think, as quick as a week. You can physically walk them through and get them approved.

Okay, got it. And switching gears over to reserves. I was wondering if you guys could provide a little more detail on sort of the changes year-over-year. It looked like the PDPs sort of stayed in basically the same place, but there's a reasonable decline on the pud side, I wanted to see what that was due to.

Yes, we actually grew PDP and PDMP over the year, but total proved reserves did go down, and that was mainly as a result of the nature of our drilling this year. We drilled -- a majority of the wells we drilled were PUD wells. And so of course, as you drill those PUDs and you produce those barrels, you lose those barrels off your reserve report. And so that was something that applied really to all of our fields and was the major factor in that reserve decline. But specifically, in Permian Basin, we also lost some reserves as a result of some temporary ethane takeaway issues. That's a current market condition that we think fixes itself by the end of this year, but because there's no way to sell that product, we lost the associated barrels there, as some other companies have as well. We're not the only ones. In Hackberry, even though we had a tremendous year, we drilled 22 wells, we had a 51% reserve growth, we're continually reprocessing the seismic. We've identified several trends, and that's what's generated the tremendous growth and success there. But as a result of that processing, we had a few PUDs that we decided to take off the book, so we lost a few PUDs there. So 2012 is going to be a very different year for Gulfport as we grow Utica and Niobrara. Obviously, as you drill Utica, you'll get 100% of those reserves once you drill and produce for a little bit. So it should be a very, very different year for Gulfport this year but also going forward. And in addition, we will book new PUDs in Hackberry and West Cote Blanche Bay this year, but those are the major factors.

I might comment, too, about Canada, Grizzly last year had 0 proved reserves. This year, because of Algar Lake and the fact that we're building up there, we've been approved, we're building, we got a timetable. Now we have added substantial proved reserves up there and amounts to about 17 million barrels net to our interest up there. So we really feel like -- we can't book them, obviously, as Mike said, their financial investment. But they're real, and really, that suggests overall about a 50% increase in our reserves since last year when you look at proved reserves and include what's going on in Canada.

All right, okay. And then just going back to the ethane in the Permian, is that just going to result in a little bit higher gas volumes, a little bit higher gas pricing and less NGL volume?

That's right. That's exactly right.

Our next question comes from J.B. Lowe with Sidoti.

I just had a quick question on well costs first in the Permian on the vertical side. I know way back when we were talking like $1.6 million to $1.8 million. I just wanted to see what the drilling efficiencies have done to those. And then on the horizontal Permians and then in the Utica finally.

J.B., I'll tell you we're seeing some nice decreases. Of course, when we look at what our drilling company is doing down there, they keep some graphs, they show how fast they drilled the well. Just to kind of give an idea, one area we drilled we call the Barren [ph] area. And they've gone from about 18 days to 14 days down there on their spud. Just in the drilling part of things, that saves about $200,000 on the cost of the well. Another place we call University 2 and 3, down from about 17 to 18 days down to 15 days, and there they're saying about $250,000. So that's on the drilling side of things. And like you said, we've increased our operating efficiencies. Those numbers that you're talking about are good numbers although we often -- now because we have 3-D seismic, we go down deeper, we go to the Strawn, we go to the Atoka. So we actually may spend a little bit more than those numbers because we go to deeper depths, and just -- when we started out, they were just a Wolf-grade play, but there's a lot more now. Now with regard to the horizontal wells, I'd say, I think in terms of instead of $2 million to get an IP around 100 or 100-plus barrels per day, now you're going to spend about $6 million. But based on Pioneer, get around 700 barrels a day. So for the cost of 3 wells, you can end up with well over double the production. That's the advantage of the horizontal.

So on the vertical side, to answer your question, J.B., generally with the additional depth that Jim talked about, I think generally, you can think in the range of $1.8 million to $2 million, and then he just gave you the horizontal numbers.

Okay, great. And then are you guys still looking at the $6 million per Utica well or is that kind of like once you get it up and running on off the pads?

Well, I think, as we said, there's science when you do the first ones, but Chesapeake had some comments about their costs. And when they were talking, they were saying they think they can be down to $5.5 million to $6 million as they get past that. But you've got to remember, too, that we've looked at the Chesapeake wells, and even within their estimates, some of -- in some wells, they perforated like 4,100 feet of lateral and in other wells, they perforated like 6,100 feet. So obviously, they're going to spend more on a long lateral than a short one. So a lot of it has to do with where it is. Now those wells are at a depth, where if you came down to our acreage would be a little west of them. Those would be like our Guernsey County wells that we're going to drill. So that's the kind of cost we'd expect to see in Guernsey County and the oil -- more the oily leg and at that depth. So obviously, as you go deeper, if you were to go out to Jefferson County where Marquette was drilling and they're going 9,300 feet for a horizontal, that's a different ballgame. But in general, I think if you would use something like -- when you do longer laterals, you get more bang for your buck. So think in terms of around $1,200 per foot for an 8,000-foot lateral, these are real rough numbers. And $1,500 per foot for a 5,000-foot lateral, it then just depends on what depths you're drilling and, of course, there's a few other things, but it also has to -- it also depends on how deep they are. Obviously, the same lateral in a deep well is more than a given lateral cost for a shallow well. That kind of gives you a feel.

And just to clarify what Jim just said, that is just the lateral part.

Our next question comes from the line of Dan Morrison with Global Hunter.

Most of mine, I believe, have been answered. But to the kind of follow-up on the reserve question, what's your kind of remaining PUD -- if you drilled up PUDs in -- I presume a lot of that was in Permian, and what do you have kind of teed up for additional bookings in the Permian? Can you book additional reserves within your current acreage footprint with the verticals, or will it require adding additional acreage?

No, we can. We've certainly -- we've got probable and possible reserves in Permian so we -- right now, we estimate we have 281 probable locations and another 64 possible locations.

Now Let's say, too, that those were all based on basically 40-acre spacing, but we and Pioneer and others have been drilling wells on 20-acre spacing. Basically, your fracs are -- people used to think of them as a fast football, if it was a quarter mile long and covered 40 acres with our microseismic that we've done, we've figured out that they're really a cigar that covers 20 acres and it's a half-mile long. So we've drilled wells from -- it goes east-west generally. So from north to south, we've been drilling wells where the wellbores are 10 acres apart north to south, and we don't see interference between those. So that 20-acre spacing, of course, whatever numbers Mike gave you, you can just about double.

And of course, in Southern Louisiana, we also have -- we talked about lots of pud locations that we have that we can book. So we've got years of drilling in both those areas.

Okay. And with respect to your horizontal that you're drilling, is that going to be a fairly long lateral? And can you kind of comment on how your acreage is configured to handle those long laterals that the offset guys are drilling?

Well, generally, people are drilling north to south, and they've -- where the first well is, we actually have 2.5 sections, 1 section wide and 2.5 deep from north to south, so it lends itself very well to long laterals. So just depends on -- I'm not sure just exactly how long it's going to be on this first well, but certainly, it's the kind of place the way our acreage sets up in there -- and that's the nice thing about Bloxom, this first area that we acquired acreage in, it's really chunked up if you look at our map. And so it really lends itself to these common tank batteries. You can do multiple wells off a pad when you get into the horizontal. So it's really looking like a great place to drill wells.

Our next question comes from the line of Irene Haas with Wunderlich Securities.

Especially with Grizzly, I mean, it sounds like you were -- to do an IPO is going to be a pretty big payday, so I was wondering what you have invested in the oil sand projects thus far. Second question, I would like you to help me kind of walk through the Utica. You're going to drill 20 gross wells, so really, I figure by fourth quarter, you'll have some production to sell. And so how should we think about it? How much of it is oil? How much will be NGL? Who's going to extract it for you? And related to this question really is really by fourth quarter, how should we think about your production profile in terms of percent Louisiana, percent Permian and percent Utica?

Okay. Irene, those are all good questions, I'll try to remember to answer each one of them. So first of all, let's just talk about your last one first. Production, obviously, is going to be back-end loaded. And so I think the way you should think about our production this year is the first quarter is going to be fairly flat over fourth quarter, and then you'll see some modest growth in the second quarter, and then you'll begin to see a larger ramp-up in the third quarter with the very large ramp-up -- I'm sorry, third quarter with a very large ramp-up in the fourth quarter. So I think that's the way to think about modeling as we bring on the Utica wells, which is going to be in the back half of the year. Again, I just -- we're going to have to wait and see what the production mix is going to be. It's going to be hard for me to give you some guidance on pricing. Part of that because our midstream activity will dictate some of that pricing for us. So we'll be able to give more color probably on the first quarter call, Irene, but it's going to be hard for me to tell you what the exact production mix is going to be as we delineate that acreage. It's going to be about who's processing our gas, and we're still in those final discussions with those midstream folks. So I can't give you some specific color. By the first quarter call, we can.

There are enough midstream folks around to have the job done. So I mean, what I'm really after is I don't want to see a situation whereby you drill all these wells and wouldn't able to connect it. And is that correct?

Oh no, no, no. We're...

That's part of our deals that we're doing.

We have both short term, and we're looking at some also for the long-term solutions. So we've certainly got our first wells taken care of, that's not an issue. We will be able to sell as soon as we're ready to sell. So that's not a concern at all, we would tell you that if it where. And then to your first question just for our -- before I forget, right for today, we have about $69 million invested in the Grizzly activity.

And so potentially, you're talking about multiple sort of scenario, and there's one scenario where you actually can just fix it and monetize and sort of redeploy the money back to the lower 48. Is that what I heard?

Well, yes, the point is Grizzly is going to monetize, but the cash that they raise would be kept at the Grizzly level for that development. What we're suggesting is we would not have to deploy any more capital to Grizzly out of our lower 48 activity, so that money can be redirected to Utica or any of our other areas that we want to ramp up. That's what we're suggesting.

So you still hang on to your 25% of Grizzly, that's what you're saying?

That's right.

Our next question comes from the line of Biju Perincheril with Jefferies.

A couple of questions. First of all, your drilling program this year, what's the mix of PUD locations that you'll be drilling this year versus what it was last year?

I don't have an answer for you, Biju, because it changes during the year. So as the year develops, we decide which wells we're going to drill. Each time we drill a well, we learn something new, and so I just -- I don't have that specific mix of PUD versus unbooked PUDs that we're going to drill this year. All Utica is not PUD. So again, I don't have a specific number for you. That kind of evolves as the year goes by.

Okay. And then in the Permian, I know it's very early for the horizontals, but do you guys have a number in mind as to how many locations you might have horizontally?

Well, it's -- we haven't really laid it out to that detail, but one thing to keep in mind is that when we drill this first location here, and we're in this lower middle Wolfcamp shale member, that doesn't mean that's the only well that we would drill, the only horizontal well that we'd drill off of that same pad. We might scoot over and decide to drill a horizontal Atoka off of that one, or some of the others. So we don't know yet what the spacing is going to be exactly. We're going to have to figure out as we drill them on how far -- how close you can drill and not interfere with the well next to you. So there's a lot of things we're all trying to figure out. But there's going to be many, many of them.

Do you think all your acreage has some sort of horizontal potential?

Biju, that particular shale that's being drilled in, as I said, I've seen that one, you can follow it all the way up to Andrews County. So at this point, I don't know of any well out there that, that wouldn't be a good place to drill. We may find that it doesn't work everywhere, but the shale's everywhere. So then you've got that formation or that particular shale, then you've got the Cline, you got the others. So some of them will be different. That particular one, though is consistent across that whole basin.

Got it. And then moving over to Utica. As you start to bring on some of these wells, thinking there will be a pretty good portion of ethane production with it, could that be a constraint near term? Is there enough demand locally until some of these ethane projects will come onstream?

Well, it's not a constraint in the sense that it would keep you from drilling the wells, but you do have to give it away at first until you've got the processing capability in there. But as markets are developed for it, and as the plants are put in to handle it, then it's going to start being a revenue producer. So initially, we don't get any value for it. We just have to give it away, but we want to see the value and so do these midstream companies. They want to get the value for it. So they're working as hard and fast as they can to be able to extract the value out of it, and that benefits both them and us.

So just to clarify, Biju, it's not just us, it's everyone in Utica. Everyone has the same issue. But it's all part of our long-term solution than we mentioned earlier with our midstream partner.

And in the near term, can you leave ethane in the gas stream, or do you need to get a waiver from pipeline companies to do that?

No, you can leave it in there and they blend it with other. But it's something that they'll work as quick as they can to get value for instead of just having to give it away and blend it with other dryer gas.

Okay, and then how many -- you mentioned 20 wells you're going to be drilling, how many of that you think you will get completed and producing by the end of the year?

Well, I would say anything we drill in the fourth quarter will probably not be producing. And of course, we will be bringing on -- we'll start off with 1 or 2 rigs going pretty soon, but those last wells, let's say, if we figure a month apiece, there might be 6 of them that we won't get producing. But I'm sure we're going to experience some delays in getting pipeline takeaway and things, so don't count on them all producing the day we TD them and frac them the next week. There will be delays, there's challenges in there. But this is a really exciting development that we've got with a midstream partner in there, and it's going to put Gulfport in really good shape as compared to other companies that have been able to take all of our products away.

So if I heard you correct before and told us your new partner has therefore some of these up and running, you have some interim solutions in place to be able to sell the product. Is that how I understood your previous comments?

That's right.

That's correct.

Our next question comes from John Healy with Berlian [ph] Capital.

Just a kind of a macro level question here for the company. By my math over the last 7 years, there's been over $0.5 billion spent to grow production 4,700 BOE per day. That seems pretty low to me. Can you kind of explain that?

Well, I would say certainly, we've grown production significantly, but I think you have to step back and think about the reserves that we added and that future value that we're creating, it's tremendous so...

Let me just clarify. That was drilling and completions CapEx and maintenance CapEx. It was not spent on land acquisition.

Right.

I think if you look at the proved, developed, producing, you'll see that there's been a nice growth in that. And in fact, that's being reflected in our borrowing base. Mike, you want bring him up-to-date on some of those numbers?

Yes. We've just -- we've grown PDP and PDMP, and we now have $150 million of availability under our line of credit.

Yes. And another thing is that in South Louisiana, one of the strengths of our company is that we have a lot of reserves that are behind pipe. And if you look at -- say you go to Hackberry, over there, this last year, we spent a lot of time drilling new fault blocks. Because of our reprocessed seismic and things, that allowed us to drill a lot of locations. In my opinion, we really don't get full value for what we drill over there because we only get -- in a new fault block, all you get to count is what's on the log. So if you got a sand that's crammed full of oil, you only get to count the reserves to the base of that electric log. And so in the areas that we drill, I think we're finding. And then we've seen this historically. We actually produce a lot more reserves than we get booked by the engineering firm.

Yes, we've actually done studies. So I think as the study suggests that we never get all the reserves that we find, I think it's less than 40% or 50%. So when you look at our proved reserves, it's actually much greater than that. We just never get to book a lot of those reserves. But we -- when you look at the production that we actually get, the EURs, it's much greater.

[Operator Instructions] Our next in line, we have Ron Mills with Johnson Rice.

Jim, can you expand a little bit on what you said about the Niobrara? You've drilled 3 wells. And apparently, you've had commercial quantities from the vertical wells. I know you had some sloughing problems. But compare that to, I think, it's Quicksilver has drilled a horizontal well not far from your acreage and just increasing activity levels, or is there an increasing activity level in that area?

Well, Quicksilver has apparently been doing some good. They are drilling wells in the same area and have drilled a horizontal well. Of course, they keep the information pretty tight about that, so I really don't want to try to compare theirs to ours. Ours are vertical. Of course, we drilled these 3. Again, they're kind of science wells without the seismic that we've got. I think that Ron, we've got 2 wells producing out there that one of them started off about 50 barrels a day 40 years ago, and it's still producing over 40 barrels a day today. The other has been about 2 years with 40 barrels flat. So those kind of vertical wells are real commercial. These that we drilled, I think we may have actually gotten into a little bit better area with these. I think that we may have some more fractures, that may be why we don't have quite the hole stability that they did there. We would start producing them, and we might see 50 barrels on a test, and then within a couple of days, we have dropped off and we would go in with a bit. And we would find that we had fill that was substantially filling up our 1,500 feet of open hole that we had opened. So we cleaned that out, we tried that a couple of times and became convinced that we were just going to have to put a slotted liner in there to keep it open so we would keep the production constant. So we're in the process of doing that now, but every one of them had great shows while we drilled them, had really nice starts on short times before we got plugged up again. So we're optimistic that we're on to something good. And with the seismic we've got when we start drilling these other vertical wells, we'd know we'll really be in a place that ought to be chock-full of fractures. So we're optimistic about what the future is going to hold, too.

And is the plan on your 5 to 7 wells, you're going to drill these wells or all of those going to be vertical? I know you had talked in the past about potentially taking one horizontal.

Well, I think these will be vertical. But keep in mind when -- let's say, you've got 40 barrels a day or 50 barrels a day in a 1,500-foot vertical section, where is it coming from? If you're going to drill a horizontal well, where do you want to go? And so I think some of the next steps we'll take with these new wells, we'll probably start running some swell packers in there and maybe we'll just isolate that 1,500 feet into 3 or 4 intervals where we can test them individually and determine where the good place is. And we might rather drill a horizontal well where it's a little tight instead of drilling it where there's already a fracture network. So there's a lot of stuff we've got to resolve yet, but we don't plan initially though to start drilling horizontal wells. We're going to do a little more science with the vertical wells.

There's a lot of competitor activity up there as well that we'll monitor, and that information that we get from them could help as well.

And I'm showing no further questions in the queue. I'd like to turn it over to our speakers for any closing remark.

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

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may all disconnect. Everyone, have a great day.