Callon Petroleum Co (CPE) 2012 Q1 法說會逐字稿

Good day, and welcome to the Callon Petroleum first-quarter 2012 results conference call. All participants will be in a listen-only mode.

(Operator Instructions)

After today's presentation, there will be an opportunity to ask questions.

(Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Fred Callon, Chairman and CEO. Please go ahead.

Thank you. Good morning, and thank you for taking time to call into our first-quarter 2012 results conference call. Before we begin the formal portion of our presentation this morning, I'd like to ask a Joe Gatto, our Senior Vice President of Corporate Finance, to make a few comments.

Thanks, Fred. We'd like to remind everyone this conference call contains the forward-looking statements, which may include statements regarding reserves as well as statements including the words believe, expect, plan and words of similar meaning. These projections and statements reflect the Company's current views with respect to future events and financial performance. Actual results could differ materially from those projected as a result of certain factors. Some of these factors are discussed in our filing with the Securities and Exchange Commission, including our annual report on Form 10-K available on our website or the SEC's website at www.SEC.gov.

We may also discuss non-GAAP financial measures, such as a discretionary cash flow. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our first-quarter 2012 results news release and our filings with the SEC, and can be referenced there on our website at www.Callon.com for subsequent review.

Thank you, Joe.

I'll start the call this morning with a few comments on the Company and then turn the call over to Gary for an operations update. Bob will then discuss our financial results for the quarter, and then, we will open the call up for question and answer. During operations update in February, we discussed the evolution of our Permian operations into a horizontal program that combined elements of being both a fast follower in the Wolfcamp B and an early mover in the Cline Shale. We continue to progress our execution on the timeline we presented at the time, and we're looking forward to our drilling results in the coming quarters.

In terms of recent activity on that front, as well as our broader Permian operations, I'd like to highlight the following. Our first-quarter 2012 Permian Basin production increased nearly 150% compared to the first quarter of 2011, as our vertical Wolfberry program evolves. As discussed previously, we are currently high grading that vertical program and complementing our legacy Permian drilling focus with near-term horizontal initiatives, which we expect will further improve our capital efficiency and growth potential in the Basin.

Here in April 2012, we accepted delivery of a fit-for-purpose drilling rig under a two-year contract to support the horizontal drilling program we initiated for the Wolfcamp shale on our southern Midland Basin properties and for the Cline in the northern part of the basin. We spud our first Wolfcamp B horizontal well on April 20 at East Bloxom, and we are currently on schedule with our anticipated timeline. We expect to finish drilling of this horizontal oil well by the end of May, and fracture stimulate the well in June. We have commenced production on four wells drilled to date at the Pecan Acres Field.

The first two wells have demonstrated initial 24-hour production rates of 200 barrels of oil equivalent a day and are averaging 90% oil. The other two wells are currently flowing back and overall results from this field are exceeding initial type curve expectations. After finalizing our drilling locations following additional technical work, we've begun the permitting process and initial infrastructure work for one vertical and three horizontal wells we plan to drill on our Borden County acreage starting in July.

Moving to our offshore operations, as announced in February, our Medusa and Habanero Fields will be experiencing scheduled downtime. While this will cause a drag on production growth in 2012, we expected that 2013 production from these combined fields will be back to levels approaching what we experienced in 2008. Following the completion of a Habanero #2 sidetrack. In addition, we are scheduled to review future drilling locations at our Medusa Field with our partners this month and are excited about the incremental opportunities that our deepwater position continues to provide.

On a financial side, we are pleased to report we've received a commitment letter from $200 million credit facility with a maturity of July 2014. In addition, our borrowing base would be increased to $60 million under letter agreement, doubling the level that was in place in 2010. We view this liquidity and conservative capital structure as a significant asset for the execution of our new initiatives in the Permian, as well as for the pursuit of additional acquisition opportunities to grow and complement our core on-shore areas of operation.

I'll now turn the call over to Gary to discuss operations.

Thank you Fred, and good morning.

I'll start with the Permian production update, focusing on our first four Pecan Acres wells. The first two wells had peak production rates of 200 gross barrels of oil equivalent per day each. And we now have all four wells of flowing back through the tank battery. Average production for the last week from all four wells was 723 gross barrels of oil equivalent per day, with the last two wells continuing to clean up following fracture stimulation.

Production is 90% oil and 10% gas. Early results are exceeding our type curve for the area and validate our expectations for 150,000 barrels of oil equivalent per well. We have drilled the fifth well and are currently drilling to sixth well. The fifth, sixth and seventh wells are being drilled from the same in surface pad and are scheduled to be fracture stimulated in July. The balance of our vertical Permian program has been focused on our Bloxom and Carpe Diem Fields, stimulating 11 wells since the beginning of the year as we continue to work down our inventory of wells waiting on completion. Net production from the Permian Basin is now averaging 1,500 net barrels of oil equivalent per day, or 12% higher than 2011 year-end exit rate.

Moving to our new drilling initiatives in the Permian basin. We mobilized our new generation drilling rig to our Bloxom Field in Upton County and spud our first horizontal well on April 20. We have drilled and set intermediate and are currently drilling the curve section of the well in preparation for drilling 7,500 feet of horizontal section. We are currently on track to complete the drilling in May and fracture stimulate the well in June. The six contiguous sections of East Bloxom are ideally situated to accommodate a lateral length of 7,500 feet with a north-south orientation and a minimum of 30 fracture stimulation stages.

A full-development program at Bloxom has the potential to include 24 horizontal wells on 160-acre spacing. Recent industry results suggest IP rates of 350 to 1,000 barrels of oil equivalent per day with EURs ranging from 350,000 to 500,000 barrels of oil equivalent per well. We expect the first two wells to cost $7.5 million to drilling complete as we work through new rig start-up issues, as well as build crew continuity and teamwork on the new rig. Future wells are expected to cost $6.5 million per well as we enter the program development phase.

We plan to drill two Wolfcamp B wells at East Bloxom prior to moving the rate to our newly acquired acreage in Borden County. As previously announced, we recently acquired 14,500 contiguous net acres in Borden County, which we believe to be prospective in horizontal Cline development. We estimate that our 100% operated position in Borden County has the potential for approximately 120 horizontal Cline wells with up to 7,500 feet horizontal laterals. Cline wells in the Midland Basin are currently estimated that they will have EURs of 350,000 to 600,000 barrels of oil equivalent per day, with IPs ranging from 300 to 700 barrels of oil equivalent per day.

We expect to be drilling the initial vertical well in Borden County in July or August, followed by three horizontal Cline wells across the acreage position to fully define our target zones prior to moving the drilling rig back to Bloxom to drill the remaining horizontal wells. This allows us to compare early performance of our Bloxom wells with other industry Wolfcamp results prior to full-field development and allows us to plan for optimum development of our newly acquired acreage in 2013. Assuming successful evaluation of the Borden acreage, our plan envisions a two-rig horizontal program starting in 2013, with the opportunity to ramp up activities as necessary to efficiently develop the assets.

Moving to the Gulf of Mexico, natural gas production from our East Cameron Block 257 Field remains a shut in due to a pipeline leak in a section of line upstream of East Cam 257. Stingray Pipeline Company is working through the regulatory requirements to abandon the damaged section of the pipeline upstream of East Cam 257. Once this process is complete, production is now expected to be restored by year-end 2012. Prior to the pipeline failure, East Cam 257 contributed gas production of 1,800 net MCF per day.

Regarding our deepwater properties, we've received final confirmation that the planned downtime at Medusa will begin May 15. Production is scheduled to be down for 28 days due to planned construction activities on the West Delta 143 oil pipeline system. At Habanero, the scheduled 60 days of downtime to accommodate construction activities on Shell's auger platform has been scheduled to begin June 15.

These fields contributed 1,500 net barrels of oil equivalent per day and 500 net barrels of oil equivalent per day in the first quarter of 2012 from Medusa and Habanero, respectively. Finally, in the Gulf of Mexico, the drilling of the Habanero #2 sidetrack targeting up-dip proved, undeveloped reserve volumes remains on track to commence during the fourth quarter of 2012 with first production targeted for first quarter 2013.

Turning to our quarterly comparisons. Our net production in the first quarter of 2012 averaged 4,308 barrels of oil equivalent per day, which was comprised of 62% oil and 38% natural gas and NGLs. This compares to production in the fourth quarter of 2011 of 4,652 barrels of oil equivalent per day, which was 58% oil and 42% natural gas and NGLs.

The negative variance in the first quarter of 2012 is due to downtime associated with East Cam 257 and the Haynesville well, and declines related to the Medusa A1 well. This declines were partially offset by growth in the Permian Basin. Production in the first quarter of 2011 averaged 4,713 barrels of oil equivalent per day, which was comprised of 47% oil and 53% natural gas and NGLs.

The negative variance in the first quarter of 2012 is due to downtime in the Haynesville well and downtime on East Cam 257, partially offset by growth in the Permian Basin. On the expense side, LOE including severance for the first quarter of 2012 was $8.8 million or $22.41 per BOE. This includes the negative effects of $2.9 million cost associated with a remedial workover to restore production at the Haynesville well due to interference from an offset well. Including this one-time event, LOE would have been at $15.10 per BOE.

LOE including severance for the fourth quarter of 2011 was $4 million, or $9.40 per BOE. This includes the positive effects of a $1.2 million credit associated with a downward adjustment of a prior accrual on two legacy assets. Actual cash costs for the fourth quarter was $5.2 million, or $12.26 per BOE. Higher LOE expense was associated with the Haynesville remediation work and added wells in the Permian Basin. LOE during the first quarter of 2011 was $5 million, or $11.89 per BOE. Higher LOE in the first quarter of 2012 was associated with the Haynesville remediation work and added operated wells in the Permian Basin.

Now, turning to our 2012 guidance. Our current estimate for 2012 capital expenditures remains unchanged at $139 million. As I highlighted earlier, our non-operated production from East Cam 257 will be delayed longer than we anticipated when we initially issued guidance for the first quarter and full-year 2012. Due to this deferral of gas production and additional declines from two of our non-operated shelf properties and Medusa, we are currently estimating full-year production to range between 4,500 and 5,000 net barrels oil equivalent per day.

Production for the second quarter 2012 will be impacted by the continued downtime at East Cam 257 and the planned downtime at Medusa and Habanero, and is expected to range between 4,000 and 4,400 net barrels oil equivalent per day. LOE including severance packages guidance for the year remains unchanged at $28 million to $32 million for 2012. This range includes the $3 million of remediation costs we incurred to restore production at the Haynesville well.

While we have experienced some unforeseen operational events at our Haynesville and East Cam 257 properties better that have been outside our control, I'm excited about the production growth potential and opportunities for improved capital efficiency from our core focus areas, including horizontal drilling initiatives in the Midland Basin, as well as the productive capacity available from further exploitation of our deepwater assets in the Gulf of Mexico.

Importantly, we have established the strong working relationships and credibility with service providers and landowners in the Permian Basin required to be a successful operator and feel we are well positioned to deliver on continued growth in that region. In addition, our technical and A&D teams remain focused on growth opportunities in the Permian Basin along with bolt-on acquisitions that complement our current asset base and firmly establish footprint in the basin.

I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO.

Thank you, Gary.

Before I review our first-quarter 2012 results of operations and provide guidance for the second quarter of 2012, I would like to highlight a few points regarding our liquidity and capital structure as we continue to pursue our growth initiatives. As Fred mentioned earlier, we've recently received a commitment to increase the size of our secured credit facility from $100 million to $200 million, and an increase in our borrowing base with Regions Bank to $60 million from $45 million. The maturity is also been extended to July 31, 2014. We are of course pleased with this increase in our liquidity and believe this shows further confidence in Callon's successful transition from an offshore-focused company to an on-shore operator. The facility remains undrawn at the present.

In addition, our capital structure is in a solid position. Total debt-to-trailing 12-month EBITDA is 1.1 times, and total debt-to-book capitalization is 35%. Overall, we believe our current financial position and operating cash flow provides us with a high degree of flexibility as we execute on our horizontal drilling and acreage evaluation initiatives in 2012, 2013. However, we will not be complacent, and will continue to monitor opportunities to accelerate our growth plans through drilling or acquisition opportunities. We have several options for funding such accelerated growth, and will continue to evaluate them as needed.

Now, let me discuss the first-quarter 2012 results of operation, as we reported in yesterday's earnings release. For the quarter ended March 31, 2012, oil and gas revenue totaled $29.3 million an increase of 15% over the first quarter 2011 revenues, up $25.4 million. Net income was $500,000, or $0.01 per diluted share. Excluding the impact of the remediation operations at our Haynesville well that Gary discussed, we estimate that earnings per share for the first quarter of 2012 could have been $0.06 per diluted share. This is compared to first quarter of 2011 net income of $4.2 million, or $0.12 per diluted share.

The realized average price per barrel of oil received during the first quarter of 2012 increased 14% to $106.84, compared to $93.78 for the corresponding quarter 2011. First quarter's realized price continued to reflect the pricing benefit we enjoy from our offshore oil production, which reflects LLS-comparable pricing. Conversely, the average price received during the first quarter of 2012 per thousand cubic feet of natural gas decreased 21% to $3.92, compared to $4.95 for the corresponding quarter of 2011. However, given the NGL content of our offshore and Permian natural gas volumes, our realized price on a per MCF basis was 56% greater than the (9x) average for the first quarter of 2012.

On a combined commodity basis, realized prices during the first quarter of 2012 of $74.73 represent a 25% increase over the corresponding 2011 first-quarter realized prices on a BOE basis. Compared to the first quarter of 2011, oil production increased 20% in the first quarter of 2012. However, natural gas production decreased 33% period-over-period, resulting in a net 8% decrease in production on an equivalent basis.

Oil production was up primarily as a result of higher production from our Permian Basin properties, which, as Fred mentioned earlier, are up 150% period-over-period. As we have previously discussed, gas production in the first quarter was negatively impacted by downtime experienced at our Haynesville and East Cam 257 wells. Overall our production for the quarter was 62% oil, 38% natural gas, which includes natural gas liquids.

Our first-quarter 2012 results include $300,000 of unrealized hedge-related benefits, including $230,000 related to our collar contracts, designated as hedges for accounting purposes, and $70,000 unrealized mark-to-market adjustments related to our 2013 oil collar contracts, which elected not to designate for accounting purposes. As we discussed in our recently filed 2011 Form 10-K, we elected to discontinue hedge accounting on future derivative contracts, which will result in mark-to-market adjustments flowing through our statement of operation compared to other comprehensive income, as with our designated accounting Hedges.

In terms of our risk management program, we currently have approximately 1,650 barrels of oil per day for the remainder of 2012, hedged with a weighted average ceiling and floor of approximately $92.50 and $123.50, respectively. For 2013, we currently have 1,300 barrels of oil per day hedged with an average ceiling and floor of approximately $90 and $116, respectively. We continue to monitor available hedging positions, and as has been our practice in the past, we have a target of hedging approximately 50% of our anticipated proven production. Presently, we have no natural gas or NGL hedges in place for either '12 or '13.

Lease operating expense increased to $8.8 million for the three-month period ended March 31, 2012, compared to $5 million for the same period in 2011. As noted, the increase was almost entirely due to $3 million associated with the remediation work required at our Haynesville gas well, as discussed. Also, there was $1.5 million of cost attributable to an almost doubling in our well count to 78 operated producing wells in the Permian Basin. These two increases were partially offset by a $600,000 decline in LOE at our deepwater property.

On the BOE basis for 2012, depreciation, depletion and amortization, or DD&A, was $31.09 per barrel equivalent, an increase of 35% over the first quarter of 2011. This increase is due primarily to a normalization of our DD&A rate over the past three years following the significant reduction in our DD&A rate beginning in 2009 following an impairment charge we recorded at the end of 2008. In addition, ongoing development costs increases primarily in the Permian contributed to the year-over-year rate increase.

General and administrative expenses net of amounts capitalized increased to $5 million in the first quarter of 2012 from $4.2 million for the same period of 2011. The increase relates primarily to non-cash accruals of mark-to-market adjustments for certain liability-based incentive compensation instruments. Interest expense on Callon's debt obligation decreased 26% to $2.6 million for the first quarter of 2012 compared to $3.5 million for the same period of 2011. The decrease relates to the redemption of $31 million principal of our senior notes during March 2011. Please review our earnings release for further results of operations details for the first quarter 2012.

Now, I'll take a minute to discuss guidance for the second quarter and full year 2012. As Gary mentioned earlier, we project daily production for the full year to be 4,500 to 5,000 barrels equivalent per day, with oil accounting for approximately 61% of the projected production. Including NGLs, we expect total liquids production to be in excess of 70% for 2012. For the second quarter, we are projecting a range of 4,000 to 4,400 barrels equivalent per day. We are projecting general and administrative expenses to be in a range of $18 million to $20 million for the full year 2012 and $4.6 million to $5.1 million for the second quarter.

Interest expense is forecast to be $11 million to $12 million for the year and $2.7 million to $3 million for the second quarter. For the full year 2012, the amortization of the deferred credit, which was recorded as a reduction to interest expense, will approximate $2.6 million to $3 million. We are projecting a DD&A rate of $29 to $32 per BOE for the full-year, and the second quarter should be in the range of $32 to $33 per barrel. Equivalent.

Please refer to our guidance press release, which provides additional details regarding guidance for the second quarter and full year 2012. This guidance will be posted on our website in the Investors section. At this point, I believe, we will open the meeting for questions.

We will now begin the question-and-answer session.

(Operator Instructions).

Neal Dingmann, SunTrust.

Good morning, guys. Just trying to get an idea, maybe from you, Fred, just on the guidance. Couple of questions around maybe the Pecan Acres. Obviously, initial production looked quite good on those wells. I was wondering, number one, if production continues on those wells, is there thoughts about accelerating that side? And then, just wondering on the guidance that's out there, how much you are included in this play in that guidance?

Yes, Neal, we are very happy with the initial results of the wells. They're doing quite well. 200 barrels of oil equivalent per day per well is quite good. We've got indications that even they may well be performing a little higher than that. But, the early production stage, if you recall, was a little delayed because we had a gas pipeline delay, and we had to shut the initial wells then, again, in order to frac the two wells that were next to them. So, we are getting close to a 30-day rate on the first two wells, and they seem to be holding in there, even after 30 days, at about 175 to 200 barrels of oil equivalent per day, so we're pretty excited about that.

As far as acceleration of this play, we don't plan to, because we've got one vertical rig operating today, and we will continue to operate that rig at Pecan acres. We're happy with our 50% position there. We're happy with our working relationship with our other partner. And, we're really happy with really the reputation and the relationship that we worked out with the city of Midland.

The way we are doing things our permits are getting approved in a timely manner, and we seem to be well received by the land owners or the homeowners there in the nearby residential area. So, we will just keep one rig active for those two sections for the rest of this year as well as into next year.

Okay. And then, really just the follow-up I had for turnover. On the Borden County, would you say Gary, as far as I know you're targeting both that Wolfcamp B and the Cline shales, again, is it something you see already from the seismic that you'll -- I guess the question is how will you tackle both of those or how do you see that playing out?

Again, just for clarification, Neal, we're targeting the Wolfcamp B and the current well that we are drilling in Upton County. And we're real excited about the potential for the Wolfcamp B and the Upton County, simply based on all the great results that we've seen in northern Upton County, and even on the adjoining rig in Irion Counties. So, we see significant potential in Wolfcamp B there. We're excited about even additional layers of Wolfcamp development in that area.

As far as to your question about Borden County, the extensive mapping we have done throughout the northern part of the Midland Basin has us pretty excited about the analogy and the similarities that the Cline has in Borden County to the good results being reported from the Cline production in Glasscock County. The section that we have in the Cline is thicker in Borden County, and at least the petrophysical analysis that we've done, it has a higher porosity, so we have even a higher target for original oil in place in Borden County, so we expect some very good results there.

Also in the Borden County, there a couple of operators that are targeting Wolfcamp horizontal development, and we're actively watching that. And St. Mary's is actually focused on horizontal development of the Mississippian line, which is below the Cline, and we're actually watching that. When we drill our first vertical well, Neal, we will take cores in the Wolfcamp, we will take whole cores in the Cline, we will likely take sidewall cores in the Mississippian and we'll drill that first vertical well all the way to the Ellenberger on an established high that we see on the seismic data.

So, we will know a lot more after we drill that first well and certainly, after we get results later in the year from our first horizontal well in the Cline. But, we're primarily focused on the Cline initially, but we see opportunity for multiple levels of horizontal development in that area also.

That's great color. Thanks Gary.

Richard Tullis, Capital One Southcoast.

Thank you, good morning. Gary, what is the current well cost for those Wolfberry verticals?

The Wolfberry verticals that we're seeding right there at Pecan Acres are right around -- a vertical well is costing us about $2.4 million. At Pecan Acres, just for full transparency, we are having to drill a couple of wells that are deviated wells simply in order to access the reserves under some of the established areas that have been developed in the homeowners' area. And, those deviated wells are costing us about $400,000 more, so it's about $2.4 million per vertical and $2.8 million for a deviated well.

Okay. What percentage do you expect the deviated wells to make up of say that -- what do you have about 129 locations, potential locations left to drill?

Well, at Pecan Acres we have about 25 locations yet to drill.

Okay.

We have the 129 locations just throughout all of our remaining Wolfberry legacy production, and again, we've high graded our current activities simply to Pecan Acres because we see that to be our best value opportunity today. Of the 25 wells at Pecan Acres, I would say six of them will be deviated wells.

Okay. What's the oil/gas split you're seeing in that initial production from those couple of wells you just drilled?

It's primarily oil. It's 90% oil, Richard. So we're pretty excited about it. As the production gets further on the life, we'd expected it to get a little gassier, but we're real excited about the 90% oil that we're getting today.

Okay. The one slide in the presentation from a couple weeks ago that points to potential of 1,000 barrels a day -- no, excuse me guess it was about 1 million barrels for the year, from Habanero and Medusa combined, getting you back to a level that you produced back in 2008. What has to happen for you to get to that level, and is there any upside to that forecast?

I guess for the year, Richard, what I'd say is that once we -- as we are going through the downtime for Medusa, what we plan to do is actually go in do some remedial work on the A1 well, which I referenced in my discussion earlier. The A1 well is a well similar to A6, which we talked about late last year that has a plug set that between the T4C and T4B. Late February, that well made a few solids, so they restricted the rate on that well.

We expect to go in and clean that well out with coiled tubing and reset that isolation plug during the downtime. With that resetting of that plug, we would hope to be able to open that choke back up, eliminate the fines of production and then increase production from that well. Hopefully, we would have up to maybe a 600 barrel oil per day increase gross, which is important to us. Beyond that, we don't have much else planned for Medusa this year.

So, the important thing about the A1 work over with the coiled tubing, that would give us some confidence that that might be the preferred route to repair the A6, which is what we talked about later, which has had the most significant impact on our production this year. And if we can get all the partners onboard and actually excited about the low mechanical risk associated with doing the coiled tubing work and setting those plugs for coiled tubing, we could potentially restore production on the A6, which is a significant impact to us.

If you recall, late last year or third quarter, we actually lost about 4,000 gross barrels a day from that well because of a similar issue. A little premature talking about this because it's still being discussed with the partners, but you asked what might happen in order to get us to that number, and that's possible.

The A6 upgrade is included in that 1 million barrel potential for the year?

No, it was not. We had not planned to do anything in the A6 at the time when we put that guidance together. And then Habanero, of course, we still have Habanero planned to do a re-drill late this year of the #2 well to get that up dip, and we still haven't changed the timing for that well, but the timing for that well may potentially move up a month. But, if it does, then perhaps we will get to that number or exceed it.

Okay. And then, finally for me, Gary, could you give the details on the Haynesville remediation work? What were your options there, and what is the payback expectations?

First of all, we're very disappointed that we actually had to do it at all. When we realized we had been impacted by a fracture stimulation job on an offset lease, unfortunately that just happened. It was our only well producing on the lease, we elected to go ahead and do the workover to restore production and preserve the lease. We expected, and in our guidance, we had about $1 million net to Callon to do that work.

We got into a difficult fishing job. These are very difficult remediation jobs. They're high pressure, they're are still high temperature, you have to take a lots of the safety precautions to maintain well control. Got into a very difficult fishing job on that well that took us significantly more time and effort to get that work done. The good thing is we successfully completed the work. Finished it without anyone getting hurt, and we were able to restore production, which on some of these wells that have been impacted by fracture stimulations from offset wells, I guess from the research that we had done in the things we had heard from the Corporation Commission, was that many wells sometimes don't even -- you're not even able to restore production.

We've got it back. It came on like we expected. It's performing similar to the way it was expected to perform prior to the impact from the fracture stimulation. It's currently producing 2.5 million cubic feet a day, casing increasing pressure is still pretty high. So, we're going to watch the casing pressure to continue to decline for another month or so, and then, we will put a packer and tubing in the ground and finish that complete job the way we had it planned.

So, again we are very regretful that it ever happened, but once we got into the workover, got into the fishing job, we had to finish it. Cost significantly more than we expected and just to work -- I think you asked about payout expectation. The workover itself will pay out given current forecasted gas prices in about five years. What it did was it preserved the lease for us for future development, and these are 7 BCF wells that are in the heart of Haynesville development, which has seen some appreciation in gas price. Our development plan is to come back to here once prices resume, or at least are restored to some level that justified the future development of those wells, but 7 BCF for another six wells provide significant reserve opportunity as well as growth potential for us in the future.

Alright, Gary. Appreciate the color. Thanks a bunch.

Hsulin Peng, Robert W. Baird.

Good morning everyone, this is Hsulin. Question. I want to make sure that I heard you right. So, right now you are running one rig for Wolfcamp and Wolfcamp B, and also the Cline shale, and a did you say that you are thinking about running two rigs in 2013? So that's number one, and number two is, how do you think about balancing the CapEx need with the financing liquidity that you currently have?

Yes, Hsulin, thanks for the question. We are currently running two rigs. One targeted on vertical Wolfcamp development at Pecan Acres and one targeted on Wolfcamp B development at Upton County and then, later in the year, to horizontal Cline development in Borden County.

We have enough inventory of well at the Pecan acreage to carry this rig forward to another year. So, through 2013. As well as, given success at Borden County, we will be looking to pick up a second horizontal rig very similar to the new generation rig that we currently have in order to operate two horizontal rigs in 2013. So, in summary two rigs throughout 2012, one vertical one horizontal, three rigs throughout 2013, one vertical and two horizontal. Bob, you want to address the issue of capital and liquidity?

Sure. I think that if you plan for success, which is what Gary is talking about, I think we'd run two horizontal rigs if we wind up being very successful in Borden County and want to move ahead. I think the end result of being successful in seeing anywhere near the flow rates that we are seeing on the horizontal wells that Gary is planning on now, plus the impact Gary has alluded to at both Habanero and Medusa in '13 returning or exceeding their previous levels, of course, and Pecan Acres production.

We look for a significant increase, or you would anticipate a significant increase, in production and cash flow into '13 that would go largely towards helping funding an increased CapEx budget. Additionally, we will set, we will monitor it in terms of what our plans becomes, probably looking at it in the late third quarter after we get some of these results, but I think we will be a good shape to finance the program as we go into '13 and even into '14.

Okay. Got it. And then, two other quick questions. Can you just give us your current or your permanent exit rate currently? And also, the oil differential, because I noticed that this quarter was a bit lower than before. And, I was wondering if that was just a function of higher Permian oil production, so the oil differential came down, and how should we think about the rest of 2012 with that?

Hsulin, as far as production rate goes, we exited 2011 right at 1,300 net barrels of oil equivalent per day. We averaged in the month of April, 1,500 net barrels oil equivalent per day from the Permian Basin. That included an impact of around 1 million cubic feet of gas that was shut in or curtailed because our DCP in our Bloxom Field had a compressor station that went down, so we were curtailed at Bloxom. We had probably a little bit higher than that real production capacity, we're just telling you what we actually produced for the month of April. We're excited about the growth potential, continued growth potential in pecan acres, so we see continued growth in the Permian especially with the expected results of our Bloxom wells coming on in June and July. As far as the question about differentials I'm not sure.

Give me your question again about differentials, Hsulin.

I think this quarter, well it would be the first quarter, the oil differential was lower than -- because you guys usually get a pretty decent premium because of the LLS pricing, but this quarter was lower. So, I was wondering if that's a function of the increase of oil -- Permian oil production using certain -- that would make that differential less, and how should we about 2012 going forward? Should we anticipate a lower oil differential going forward?

I think that question is yes, the Permian production, which is up -- we've talked about being up significantly, and we look for that to continue hopefully with our -- we plan on it with particular production at Pecan Acres and the growth we see. We look for more Permian oil. So therefore, on an overall basis we anticipate seeing the differentials come down fourth quarter. The pricing we get, LLS-comparable pricing, we get offshore, particularly in the first quarter of this year, was up -- I think I've noticed lately that it has tended to come back off a little bit. But, I think it will continue to have a positive impact of on us throughout the year.

Okay. Sounds good. Thank you.

Dan Morrison, Global Hunter.

Thanks, and good morning. Could you provide a little color on the assumptions that are imbedded in your guidance for horizontal drilling? You've got a considerable amount of capital and activity tied up in those programs. What are you all baking into your guidance?

I can tell you what we expect from those wells and about when they are coming on, Dan. We are expecting, at least the way we forecasted, was 600 barrel a day IPs for the two Bloxom wells coming on in late June and July. And then, later in the year, the Borden County wells, we have those IPs at 500 barrels a day. So, last half of the year impacted by two good wells at Bloxom. Last quarter of the year impacted by additional wells coming on in Borden County.

Okay. Perfect thanks.

Rhys Williams, Johnson Rice.

Good morning, gentlemen. I was just wondering if you could talk about the speed of completions at the Permian with Halliburton, and how many fracs you're getting off per month, and as well as if you're looking to expand the agreement with Halliburton to your horizontal wells.

Yes. Rhys, we've actually been a continuing -- as we've actually high graded our vertical program in just to Pecan Acres, but we've actually slowed our development plan, or at least the rate of drilling in our vertical program. We've begun to work off our inventory of wells that we mentioned last year that we thought we'd be finished sometime about this year given the pace of development.

We fracture stimulated a total of 15 wells year-to-date, so it was four wells a month January, February, March, and then it was three wells in April. And, we only have a couple of wells in our legacy program remaining to fracture stimulate. And then we will just be focused on the new wells at Pecan Acres. We're very happy with the relationship we've had with Halliburton. They've done us a very good job keeping us on pace and working that inventory down.

We have discussed extending that agreement to make certain that we cover our horizontal development program, and they will actually fracture stimulate our first well at Bloxom and our second well at Bloxom. We're very encouraged by the interest that other pumping services companies have actually expressed in working with us. The reputation we have developed in the Permian Basin of planning the work, efficiently executing the work, and allowing the pumping services group to come in and efficiently do their job and move on to the next job has kind of gotten out.

We've been approached by three other companies recently suggesting that they want to be part of that agreement in the future as we continue to grow and expand in the Permian Basin. We are having meetings with those other companies to see what type of bundled services they can provide as well as the full discount opportunities that they can give us for those bundled services. So, we've got some real competition coming to us now, given our future growth potential in the Permian, so we're excited about that.

Alright. Thank you.

Liam Kelly, Howard Weil.

Good morning, gentlemen. I was wondering if you could expound on what caused the downtime at your East Cam 257 Field for this past quarter.

Sure, Liam. What happened in, I think it was October of last year, we experienced a minor pipeline leak. It was a gas pipeline leak in the Gulf of Mexico. That East Cam 257 pipeline is owned and operated by Stingray Pipeline Co., and upstream of East Cam 257 are two additional assets that flow through that section of line. Then, it gets to East Cam 257 and then goes on to the market.

Stingray Pipeline Co. repaired that section of line upstream of 257 three different times, and it failed in the same place immediately after the repair. We had hoped, as we had developed guidance for 2012, that those of repairs would work, and so we'd expected that asset to be back online by the end of the first quarter. Stingray has now said that -- hey, we are going to abandon that upstream section of line, and then we are going to tie back in the pipeline system at East Cam 257, so that we can then operate after they efficiently and effectively abandon the upstream section.

What's taken some time is to get FERC approval, and then independent of FERC approval is BSEE approval, which is the new regulatory agency in the Gulf of Mexico, to abandon that upstream section of line. So, they can't do the remedial work to hook us back up until that is finished. It looks like that's going to take a few months, and then it'll take some time to abandon the line and then cut and cap and then hook back in 257, but we're now expecting that to come on at the end of the year.

Okay great. Thank you, very much. That's great color. Just a second question from me. We were looking this morning at your press release, and the 24-hour IPs from your vertical Pecan Acres wells, and taking a first flush that those were kind of modest rates for a 24-hour rate, but now hearing your commentary on your thoughts for the 30-day -- projection for a 30-day average IP would be in the 175 BOE to 200 BOE range. Those are really quite impressive compared to other nearby vertical Wolfberry operators. Can you just kind of expound on why you seeing so flat a decline in those wells, or maybe why -- just in case whether you were choking back production for the first 24 hours or whatever it might be?

No. Again, as I mentioned, we were somewhat delayed in getting those wells on because of a couple of different issues, but we're pretty excited about this area. We see this area has the potential easily for 150,000 barrels of oil equivalent per well, and perhaps, even higher. If we look at the surrounding area, there is some very good wells that are just offsetting these leases, and I believe, at least, the early results of our -- the early results we're seeing from the four wells that are currently producing are going to achieve those similar-type results.

It's a good area for Wolfberry development. It's been undeveloped for some time. We are glad to have it, and I think we as the operator, we can officially get it done even though we are in the city of Midland proper and working through the city of Midland permitting process. So, we have the potential here to exceed our expectations. We're just being cautious. We've got four wells down. We're happy with those four wells, and hopefully, we will give you even better results sometime in the future.

Okay great. And then just how do you think of -- what is your targeted 30-day IP for the Pecan Acres. I know for your legacy acreage, it's 75,000 BOE to120,000 BOE per day. Is it closer to that 175,000 BOE to 200,000 BOE mark were you thinking of, in terms of that 150,000-BOE type curve for the first three days, or is it closer 75,000 BOE to 120,000 BOE that you're targeting?

I think will be in excess of 150,000 BOE.

Okay.

So, if that helps you.

That's great. And sorry, one last question for me. I was wondering if you guys had any incremental commentary in your plans for your Permian acreage in Crockett and Glasscock Counties.

Well, we're watching the Crockett County acreage, the 2,200 net acres that we have in Crockett County, we are encouraged about having that because we actually see Wolfcamp potential heading that direction. We actually acquired that acreage with our initial purchase in 2009, and we're just kind of watching activity move toward us. Conoco Phillips is actually starting their drilling program and permitting process, which is -- and they're immediately to the east of us. So, we are going to continue to watch what they do.

We see Wolfcamp potential in the area on the [logs], but we would like to at least see some well results as it the moves that direction. I think we've told -- in some of the various meetings we've had, we've actually said that we see that maybe on the edge of Wolfcamp B potential, even though we see the good well result. We see the Wolfcamp B, organic-rich Wolfcamp B gradating into a dolomite in that direction, which may well still produce, given the types of results that we are seeing in other areas of the basin. So, we are still on a wait-and-see mode in our Crockett County acreage, but we're excited about where it's located.

As far as Glasscock County, we only have a small interest in -- we only have a small acreage position in Glasscock County, its 320 acres. It certainly prospective for vertical Wolfcamp, Wolfberry production. We see that area very similar to Pecan Acres as being 150,000 barrels of oil equivalent per day well for vertical development, but we also see that acreage as highly prospective for horizontal Cline development.

Now, if we get an opportunity even -- we'll actually think about moving our Pecan Acres rig over to drill at least one well on that acreage late this year or early next year, just to, again, fully define the potential there. Then, we will get right back to Pecan Acres. It's a small position. We're excited about having it because we see it as highly prospective. We wish we just had more.

That's great. Thank you very much. Sounds like your Permian acreage is really coming on nicely. It's a great job there. Thank you very much, gentlemen.

Our next question is from Dan Morrison of Global Hunter.

Thanks, one quick follow-up, I know it's getting late here. Devon, on their call, announced a Wolfcamp horizontal in southeastern Ector County. Can you comment on how that relates to your acreage in Midland, and if you've got any Ector County acreage in proximity there.

Yes, Dan, thanks for that. That well is located about six miles due north of our 100% operated 640 acres in Ector County. The [Kaylee] Field. So, we're excited about seeing that well result. It was a relatively short horizontal. It had a nice IP. You can scale that up to 5,000 or 5,500 foot lateral and see some pretty good results. They are currently drilling another well that's even closer to Kaylee, and so we're kind anxious to see the results of that.

The well results that they announced is 10 miles south of our Carpe Diem acreage in western Midland County. So, we have 85% of four sections there. We know that a couple other companies are talking about drilling a Wolfcamp horizontal soon near our Carpe Diem acreage. As we map the Wolfcamp, we see it as prospective, certainly, in northern Midland County. So, moving it further north is exciting to us. We're glad to have acreage position that we have. And, we see that as certainly prospective in the acreage position that we currently hold.

Thanks.

This concludes our question-and-answer session. I would like conference back over to Fred Callon for any closing remarks.

Once again, we appreciate everyone taking time to call in. In the meantime, if anyone has any questions, please do not hesitate to give us a call. Thanks so much.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.