Callon Petroleum Co (CPE) 2011 Q4 法說會逐字稿

Good morning and welcome to the Callon Petroleum fourth-quarter and full-year 2011 results of operations conference call. All participants will be in 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 Chief Executive Officer. Please go ahead.

Thank you Laura. Good morning and thank you for taking time to call into our year-end conference call. Before we begin I'd like to ask Terry Trovato who heads our Investor Relations to make a few comments.

Thank you Fred. We'd like to remind everyone that this conference call contains forward-looking statements which include statements regarding our 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 including future prices for oil and gas, unanticipated downtime affecting our production, operating hazards inherent to our development activities, and environmental regulations. Additional factors are discussed in our filings 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 will also discuss the non-GAAP financial measure PV-10 value. We believe PV-10 value to be an important measure for evaluating the relative significance of our oil and gas properties because it excludes income taxes which may vary materially among companies. PV-10 is not however a substitute for standardized measure. Finally, today we will be discussing 2011 cash flow which is consider a non-GAAP financial measure. Reconciliation and calculation schedules for the non-GAAP financial measure were stated in our fourth-quarter 2011 results news release and can be referenced there on our website at www.Callon.com for subsequent review. Fred?

Thank you, Terry. As you know three years ago we decided to diversify our operations back on short into the Permian basin. During that time we have grown our crude reserves by 65% to 16 million barrels of oil equivalent as of year end. And our onshore from 0% to 61% of our proved reserves are now onshore. During 2012 we expect over 40% of the Company's total production will be coming from onshore. With our recent acreage acquisition, we now have over 24,000 net acres in the Permian to help continue to grow our onshore reserves and production. As we discussed in last month's conference call, we are particularly excited about potential for horizontal drilling in the Midland basin. We will begin next month drilling our first horizontal well on our legacy property in East Bloxom and later in the year we will move the rig to the northern part of the Midland basin and begin drilling on our newly acquired acreage.

As we've transitioned back onshore we've also continued to strengthen our balance sheet; over the last three years we have significantly reduced debt, the debt-to-book capitalization was less than 35% at year end. With $44 million of cash at year-end combined with our expected operating cash flow in 2012 and an unused $45 million borrowing base, we have more than sufficient liquidity to fund our 2012 capital budget of $139 million. Now I'd like to ask Gary Newberry, our Senior Vice President of Operations to discuss operations including our ongoing development in the Permian basin. Following Gary's operations update, Bob Weatherly, our Executive Vice president and Chief Financial Officer will read financial results for 2011 and guidance for 2012.

Thank you Fred and good morning. I will start with an update to our operations call last month, in which we announced significant growth from horizontal drilling opportunities on Callon's legacy acreage in Upton and Crockett counties and newly acquired acreage in the Northern Midland basin. Recent industry announcements highlight solid economic well results for both the horizontal Wolfcamp B play in the Southern Midland basin as well as the horizontal Cline play in central Midland basin. As industry activity continues to confirm consistent results in these plays, we believe that our acreage offers compelling returns to complement our existing vertical drilling program in the Permian basin. As previously announced we have recently acquired 14,500 contiguous net acres and continue to have an ongoing dialogue with other land owners in the Northern Midland basin. The new acreage is located in Borden County, Texas and has both horizontal and vertical development opportunities. Our technical analysis indicates this acreage to be perspective for horizontal development of the Cline shale and our target zone has geophysical properties comparable to or better than recent wells drilled in Glasscock County with favorable results. Importantly the Cline section is thicker on our perspective acreage with higher indicated porosity on logs which provides for higher oil-in-place targets for horizontal development.

We estimate that our 100% operating position in Borden County has the potential for approximately 150 horizontal climb wells with 5,000 feet horizontal laterals. Based on our work to date combined with increasing data related to horizontal climb wells, we currently estimate that these wells should cost approximately $6.5 million per well, with IP rates ranging from 300 to 700 barrels of oil equivalent per day and EURs ranging from 350,000 to 600,000 barrels oil equivalent per well. This acreage acquisition allows Callon to be an early mover in the horizontal development of the Cline shale in the Midland basin. Also there other emerging plays like the horizontal Mississippian development in the area along with the vertical development of the Ellenberger, Mississippian, Strawn, and Spraberry formations.

We are also excited about the opportunity for the Wolfcamp B development in our legacy East Bloxom field in Upton County, in which Callon operates 33,800 net acres. The six contiguous sections of East Bloxom are ideally situated to accommodate the 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 conclude 24 horizontal wells on a 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 day. We expect the first two us to cost $7.5 million. The drilling complete as we work through new rigs start up issues, as well as build crew continuity and teamwork on the new drilling rig. Future wells are expected to cost $6.5 million per well.

Callon has secured a new generation drilling rig under a two-year contract and we will take delivery of the rig in April 2012. This rig will be a key asset as we execute our East Bloxom development and evaluate the horizontal potential on our Borden County assets. We will drill two Wolfcamp B horizontal wells at East Bloxom and then move the rig to our newly acquired acreage. We will then drill one vertical well and three horizontal wells on the new acreage to delineate the horizontal climb and other vertical zone potential prior to moving the 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 developments. And allows us to plan for optimum development of our newly acquired acreage in 2013. This plan envisions a two rig horizontal program starting in 2013 with the opportunity to ramp up activities as necessary to efficiently develop the assets.

We are currently operating two rigs in the Permian, drilling vertical wells at Pecan Acres in East Bloxom. We have drilled and stimulated two Pecan Acres wells and we are currently flowing these wells back after stimulation. The flow back and cleanup of these wells was delayed due to timing and construction associated with the gas sales line but we do not have updates to share with you during this call. We plan to fracture stimulate the third and fourth Pecan Acres wells next week. As we high-grade our vertical drilling efforts and introduce a balanced horizontal drilling program on our asset base, we will release one of the existing drilling rigs next month after we take delivery of the new generation rig and focus our vertical development primarily on our Pecan Acres field.

As mentioned in our operations update call last month, in the Gulf of Mexico, production from the Medusa A-6 well has stabilized at approximately 2,900 barrels of oil equivalent per day following the drop in the third quarter 2011 associated with the down hole mechanical failure of the isolation plug between the T4C and the T4B producing zones. In the near time we plan to continue to monitor the performance of the well. Also in the Gulf of Mexico, natural gas production from our use East Cam Block 257 field was shut-in in October 2011 due to a pipeline leak in a section of line upstream of East Cam 257. The Stingray Pipeline Company repaired one leak in late December and subsequent to our operations call last month, we repaired a second leak in the same section of line. While pressure testing the line, a third leak was discovered and the field remains shut-in. Stingray has scheduled a meeting later this month with all interested parties to review options to repair the line. We expect to restore natural gas production from this asset by July 2012. Prior to the pipeline failure, East Cam 257 contributed 1,800 net Mcf per day.

Production has been restored from Callon's one producing well in Haynesville shale and we are monitoring performance. As previously announced the well was shut-in for 35 days in the fourth quarter of 2011 due to well interference from the offsetting well. Prior to the interference the well contributed 1,300 net Mcf per day and initial rates [all in to work over] are 2,300 net Mcf per day. In summary, production in the fourth quarter 2011 was impacted by downtime at East Cam 257 and the Haynesville well. These wells will continue to have an impact on a portion of 2012 that will also be impacted by scheduled downtime at Medusa and Habanero as we discussed in our operations call. Looking forward I'm excited about the production growth and value-creation opportunities from our horizontal drilling initiatives in the Midland basin as well as the productive capacity available from further exploitation of our deep-water assets in the Gulf of Mexico.

Now turning to our quarterly and annual comparisons for 2011, our net production of the fourth quarter 2011 averaged 4,652 barrels of oil equivalent per day comprised of 1.1 Bcf of natural gas and 250,000 barrels of oil. This compares to production in the third quarter 2011 of 5,261 barrels of oil equivalent per day comprised of 1.3 Bcf of gas and 270,000 barrels of oil. The negative variance in the fourth quarter of 2011 is due to downtime associated with East Cam 257 and the Haynesville well, and decline in the Medusa A-6 well. Production in the fourth quarter of 2010 averaged 5,087 barrels of oil equivalent per day comprised of 1.5 Bcf of gas and 213,000 barrels of oil. The negative variance in the fourth quarter of 2011 is due to base decline and downtime on the Haynesville well, downtime on East Cam 257. These impacts are partially offset by growth in the Permian, increased production from the Medusa A-6 well, and a full quarter of production at East Cam 2 in 2011 versus a partial quarter in 2010.

Our net production averaged 5,049 barrels of oil equivalent per day for the year 2011, comprised of 5.1 Bcf of natural gas and 996,000 barrels of oil. This compares to 2010 which averaged 4,587 barrels of oil equivalent per day. The positive variance in 2011 is due to growth in the Permian basin, increased rate from the Medusa A-6 well, and a full year production at East Cam 2 which more than offset the natural decline of our offshore assets.

On the expense side, 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 the downward adjustment of a prior accrual on two legacy assets. Actual cash cost for the fourth quarter was $5.2 million or $12.26 per BOE. LOE for the third quarter 2011 was $6 million or $12.35 per BOE. The lower expense in the fourth quarter of 2011 was a result of the previously mentioned accrual adjustment. Prior LOE expenses associated with added wells in the Permian and cost incurred for the Haynesville work over to restore production were offset by reduced production handling fees at Medusa.

LOE during the fourth quarter of 2010 was $4.7 million or $10.06 per BOE. A lower per-unit cost for the fourth quarter 2011 is due to the positive impact of the accrual adjustment and reduced production handling fees at Medusa offset by increased costs associated with added wells in the Permian and work over costs for the Haynesville well. LOE for the year 2011 was $20.3 million or $11.04 per BOE. This compares to 2010 of $17.7 million or $10.58 per BOE. The higher per-unit cost is due to increased wells and increased production taxes in the Permian and a full year of LOE at the Haynesville well.

Turning now to our 2012 guidance, our estimate for 2012 capital expenditures are $139 million, which includes $110 million to drill wells and acquire new leases in the Permian basin, $14 million for the redrill of the Habanero #2 and production enhancements at Medusa, $1 million for P&A, and $14 million in capitalized G&A and interest. Our focus throughout 2012 will be continued development in the Permian basin where we plan to drill and complete 21 gross vertical wells and 7 horizontal wells. We will high-grade our vertical development programs while delineating the growth potential associated with horizontal Wolfcamp B on our Legacy Bloxom acreage and horizontal climb on our newly acquired acreage. Also we will fully participate in the planned up-dip redrill of the Habanero #2 well in the fourth quarter 2012.

We're estimating full year production to range between 4,700 and 5,300 net barrels of oil equivalent per day. LOE including severance will range between $28 million to $32 million for the full year, which reflects an increase associated with added wells and increased production taxes in the Permian basin and work over costs to restore production at the Haynesville well. We are excited about the increased production growth opportunities and value creation related to horizontal development in the Permian basin. We have established relationships with service providers in the Permian basin and feel we are well-positioned to deliver on continued growth in the region. We remain focused on growth opportunities in the Permian basin along with bolt-on acquisitions that complement our current asset base and critical technical skill set. I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO.

Thank you Gary. Before I review our full-year 2011 results of operations and provide guidance for 2012, I'd like to highlight several meaningful accomplishments we achieved during 2011. Collectively these events have significantly improved our liquidity and strength in our balance sheet. In February 2011 we raised $73.8 million of new equity net of offered costs due to successful public offering of 10.1 million shares of common stock. Following the offering we used a portion of the proceeds to redeem $31 million face amount of our 13% senior notes due 2016. This redemption reduced the Company's annual cash interest by just over $4 million per year through the 2016 due date. During 2011, we had the borrowing base under our credit facility with Regions Bank increased to $45 million, representing a $15 million or 50% increase over the previous borrowing base. Simultaneously we received a reduction in the facilities minimum interest rate from 6% to 3%.

At year-end we recorded an income tax benefit of $67 million primarily as a result of the reversal of the valuation allowance previously recorded in 2008 against our net deferred tax assets. We expect to fully utilize all of the deferred tax assets prior to their expiration. In summary, we believe we are well positioned to continue to grow our asset base and drilling inventory. Our strong balance sheet combined with strong cash flows from our high-margin deep-water assets and growing liquids production from our Permian assets, provide Callon with the flexibility to initiate an impactful horizontal drilling program as well as react to additional opportunities that may arise.

As Gary discussed earlier in 2012 we plan to continue active development of our Permian basin assets by committing approximately 80% of our $139 million capital expenditures budget to the Permian. The 2012 CapEx program includes plans for 28 gross oil wells including 21 vertical wells. 20 of these wells are development wells that will be drilled on our southern Midland basin acreage. One exploratory well will be drilled in or newly acquired Northern Midland basin acreage. Our 2012 CapEx program also anticipates drilling seven horizontal wells, four will be development wells on our Southern Midland basin acreage, the remaining three are exploratory wells on our Northern Midland basin acreage. Capital expenditure budget includes $14 million for further development and maintenance of our Gulf of Mexico properties. Our activities in the Gulf of Mexico include drilling at Habanero a sidetrack to the number 2 well, targeting up-dip PUD reserves of an estimated value of 1.2 million BOE.

Now let me discuss the full-year 2011 results of operations as we reported in yesterday's earnings release. For the year ended December 31, 2011, oil and gas revenue totaled $127.6 million, an increase of 42% over 2010 revenues of $89.9 million. Net income was $104.1 million or $2.70 per diluted share, this compares to 2010 net income of $8.4 million or $0.28 per diluted share. Net income for 2011 includes the previously mentioned $67 million income tax benefit primarily related to the reversal of our deferred tax asset valuation allowance. The realized average price per barrel of oil received during 2011 increased 33% to $101.34 compared to $75.97 for 2010. Additionally the average price received during 2011 per 1,000 cubic feet of natural gas which includes the value of their produced NGLs, increased 4% to $5.25 compared to $5.04 for 2010. Combined, realized prices in 2011 increased 29% over 2010 realized prices on a BOE basis. Production also improved year-over-year with oil production up 16% and natural gas production up 4% compared to 2010.

Our 2011 results include only minor hedge-related benefits, as our NYMEX pricing fell largely within the range of our established collars. We currently have approximately 53% of our estimated 2012 oil production hedged with a weighted average ceiling and floor of approximately $92.50 and $123.50, respectively. For 2013, we currently have approximately 27% of our estimated oil production hedged with a weighted average ceiling and floor of approximately $90 and $116, respectively. Presently we have no natural gas or NGL hedges in place for either 2012 or 2013. 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. On a BOE basis, 2011 depreciation, depletion, and amortization, or DD&A, was $26.42 which is 39% higher than DD&A in 2010. This increase is due primarily to normalization of the DD&A rate over the past three years following the significant reduction in the DD&A rate beginning in 2009 after we recorded the $486 million oil and gas property impairment charge at the end of 2008. In addition, ongoing development costs increases primarily in the Permian basin contributed to the year over year rate increase.

2011 G&A expense net of capitalized amounts of $16.6 million was relatively flat as compared to $16.5 million in 2010. Interest expense decreased net 12% to $11.7 million in 2011 compared to $13.3 million in 2010. The decrease in interest expense is primarily due to the previously mentioned $31 million principal reduction in our 2016 senior notes in March 2011. Offsetting this decline as interest expense is a $1.4 million drop in capitalized interest in 2011 compared to 2010. Further offsetting the decline discussed above are slight decreases in the deferred credit amortization recorded in 2011 compared to 2010.

Earlier I mentioned that net income for 2011 benefited significantly from the reversal of our deferred tax valuation allowance. The reversal, which is reported as an income tax benefit of $67 million resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets following the 2008 year-end $486 million ceiling test impairment charge. Because we reported net income from 2009 through 2011 and achieved income on an aggregate basis for the three-year period ended December 31, 2011 and because we expect to fully utilize the entire deferred tax asset prior to the expiration of its components, we reverse the entire valuation allowance at year end. In the process of completing the accounting interest required to reverse the full valuation allowance we discovered that in 2008, we should have recorded the transaction slightly differently. We will be filing the necessary Form 8-K today at the same time we file our 2011 10-K to correct the previous entry. This is a non-cash entry that does not impact total shareholders equity in that year and that affects our 2009 statements only. Please review our earnings release for further results of operations details for the full year 2011.

Now we will take a minute to discuss guidance for the first quarter and the full year of 2012. As Gary mentioned earlier, we project the daily production rate for the full year to be between 4,700 and 5,300 BOE per day with oil accounting of approximately 62% of the projected production for the full year, including NGLs we expect total liquids production to be in excess of 70% for 2012. For the first quarter we are projecting a rate of 4,300 to 4,500 BOE per day. We have in place hedges for approximately 53% of our crude production for '12, however we do not yet have any hedges in place for natural gas. We will continue to monitor the markets and add hedges as appropriate. Please refer to our press release for more details regarding our hedges.

We are projecting G&A expense to be in a range of $16.6 million to $18.4 million for the full year 2012 and $4.1 million to $4.6 million for the first quarter. Interest expense is forecasted to be $11 million to $12 million for the year and $2.5 million to $3 million for the first quarter. For the full year 2012, the amortization of the deferred credit which is recorded as a reduction of interest expense will be approximately $2.6 million to $3 million. We are projecting a DD&A rate of $29 to $32 per BOE for the full year 2012 and the first quarter should be in the range of $30 to $32 per BOE. Please refer to our guidance press release which provides additional details regarding guidance for the full year 2012. Now I will turn the call back to Fred for his final comments.

Thank you Bob. We will now open the call to questions.

(Operator Instructions)

Dan Morrison, Global Hunter.

A couple of quick ones -- I think you previously mentioned the exit rate for the Permian that was over 1,300 barrels a day. Do you have a total Company exit rate that you could share? Just a total year-end exit rate?

Remember, we were impacted by downtime on East Cameron 257, the Haynesville well; both of those were out at the end of the year so we were right around 4,200 barrels a day equivalent for coming into January.

That's helpful in getting a bead on all those outages. You said that is about 1,800 a day for Stingray and 1,300 a day for the Haynesville?

Yes, so on an equivalent basis it's just slightly over 500 barrels a day.

Okay. Perfect. The acreage in Borden County -- can you ballpark that as to what part of the County, or quadrant, or more specific?

Dan, we still have ongoing dialogue. We haven't been able to tie up the additional acreage that we had hoped at this point in time yet, but we promised you that we would at least put a bullseye around a smaller area than just the Permian basin last call, so we wanted to give you the County. But we're not prepared at this point in time to give you exactly where it is at in the County, because we are out there trying to lease additional acreage.

I appreciate that.

The embedded cycle time in your seven-well forecast -- is that the 45 days still?

Actually, we feel we can do better. The embedded cycle time for us is 45 days for the first well, 35 days for the second well, and then we're talking about 30 days a well after that; so we are being aggressive. We think we've got the right rig to do it, if we build the right crew continuity around it and learn from well to well, we'll perform quite efficiently.

Great. Final question -- on the frac service agreements that you have in place, will that existing arrangement accommodate your horizontal drilling program? Or will you need to expand that? How does that work?

We have had discussions with Halliburton, Dan, and they are quite pleased with the direction we are headed with our horizontal wells. They say they can manage at least the pace we intend to run this year, and they're looking to manage the pace we will intend to run next year. So the existing agreement is quite capable of handling what we want to have done this year.

The important thing is that, hey, other companies are actually coming to us and saying -- Hey, we want to frac some of your wells, too. So either there's growing capacity in the Basin, which is good, that might perhaps take off some of the pressure on increased costs; or they are just liking the way we do our business, and there might be a combination of both. We have plenty of positive relationships in the Basin to do the work we have planned.

Great. I will add one more quick one. I think you -- $7.5 million on the first well -- are you all coring that at all, or is that just anticipating getting the kinks worked out on the rig?

We are not coring that, and we don't have a pilot hole there, Dan; we have plenty of vertical correlation points now that we've done our vertical development at Bloxom, so we know right where to land the lateral. Just for your information, technology does matter to us, and so we did spend some time on our last vertical well getting some good open hole logs, some core data on that well, so we will be a little bit out in front of understanding what that looks like before we get out there with the horizontal well next month.

Perfect. Thanks a lot.

Ron Mills, Johnson Rice.

Gary -- on the Borden County acreage, can you talk through where you gathered your data? You made the comment that you would expect the Cline shale to be comparable or even better from a technical standpoint versus some of the Glasscock activity. Are you keying that off of vertical wells through? Or what kind of well-controller data are you using for that comment?

Ron, that's a good question, thanks for asking it.

We've actually taken a good hard look at our 12 to 14 vertical wells in and around the area that we have leased. We have done our own internal analysis and we've actually hired a company outside to do some independent petro-physical analysis. We have looked at available drill cuttings, some of those vertical wells. So we don't have any whole core.

But given what we see, based on log analysis and cuttings analysis and actual drill reports, when they drilled those wells with gas content, or gas shows while they were drilling them; we clearly see a thicker section, a higher net pay section within that gross interval, based on the cut-offs that we would use for porosity, resistivity, clay content, and we see a higher porosity throughout the zone. That in total provides a higher oil-in-place target for our development.

Okay. Based on the numbers I didn't run through -- I didn't really run through the math -- but it sounds like you're talking about plus or minus 100-acre spacing up there, versus 160 at Bloxom. What is driving that?

What we will end up doing, Dan, is what we've given you, is what we would actually do if we drilled all of those wells on just six wells per single section. Fortunately, as this acreage plays out quite nicely, for longer horizontal wells, we'll likely extend that spacing to similar to what we have been doing.

At the end of the day, we have the potential and the capability, once we get up there and drill the wells and understand some of the mechanical challenges of going 7,500 feet in decline, we would likely reduce the number of wells, reduce the capital required to develop the whole acreage, and increase the spacing to 160 like we would do at Bloxom. But I didn't want to overpromise that at this point in time.

In terms of the well costs, what is the difference in terms of depth of decline up in Borden County versus the Wolfcamp down at East Bloxom, given that you would expect both well costs after the first couple to be in that $6.5 million range? Can you just talk about some of those differences?

First of all, the depth at East Bloxom, the vertical depth of that zone, is right around 8,800 feet. So it's a little deeper than what the Wolfcamp is being developed on the east side. It is similar in depth to the Pioneer development that was recently announced to the north of us, and very similar in depth to the Pioneer work that's going on right now in southeastern Upton County.

The depth in -- the decline is a little shallower in Borden County. Until we get up there and start drilling those wells and understand some of the mechanical challenges of even getting through the vertical section to properly case off and stabilize that section while we are drilling the horizontal, we are projecting very similar well depths and well control that we see in Glasscock County. And we have done a lot of work with what Laredo has done in Glasscock County, and understand their drilling practices and their completion practices. So we're forecasting essentially the same.

Okay. I think, Bob, you mentioned the oil breakdown and the liquids breakdown -- a couple questions on that. Are you going to continue to report your NGLs as a component of your gas price, or are you contemplating breaking out the NGLs, given you provided that breakdown?

For the near term, Ron, we will probably continue what we've done in the past, which is to take the NGLs, and they impact the realized price of gas. As we move ahead, and if the NGLs become a more significant piece of it, which obviously we hope and anticipate will happen, we will begin to break them out.

Ron, if I could just add something on that -- I have asked my team to take a look at that. We understand that we could probably increase our overall bookings if we broke them out, but we just weren't quite prepared to do that yet. We've got a study going on right now on how that might lay out, and how we would move forward in the future; and we would probably do something midyear if we do anything.

Okay. And to that end, are you seeing any limitations or restrictions due to gas processing capacity in your activity? Or are you forecasting any as you move up into Borden County? I'm just not sure of the infrastructure up in that area. I know it has been tight down in other portions of the Permian.

We aren't forecasting any restrictions at this point in time, Ron. We haven't been restricted yet, but again, we are seeing capacity build out or expand as the industry continues to grow. There's tremendous opportunity here in this Wolfcamp section down in Southern Midland basin. They're talking about Wolfcamp A, Wolfcamp B, Wolfcamp C wells. So if that explodes over the next several years, which it possibly could, then we may well get into some capacity issues, but we haven't been restricted yet, and we're not forecasting that at this point in time.

Okay, great. Let me let someone else jump in. Thank you.

(Operator Instructions)

Richard Tullis, Capital One Southcoast.

Just a couple questions -- looking at the production guidance for '12, how do you see the ramp-up proceeding over the year to get you to the midpoint of 2012 guidance?

I will go quarter-to-quarter. This quarter we have been impacted by the downtime we've talked about, and next quarter we will be impacted by the downtime we've discussed on our operations call, by downtime associated with Medusa, some maintenance work, or some additional construction work activity on the pipeline that Medusa uses; so we'll be down for about 25 days. Habanero will be down about 50 days next quarter due to some maintenance work and construction work planned on Auger to bring in another facility or another field to process on Auger.

So the first and second quarter will be challenged because of the downtime we've discussed and we would present it to you. The third quarter we should be fully operational, fully up on all of our assets. We should have East Cam 257 back at that point in time. The third quarter we should be bringing on our first horizontal well at Bloxom. And so I would see a significant ramp up in third quarter, and then continuing to grow into the fourth quarter. The fourth quarter will only be impacted by minor downtime associated with taking Hab #2 off, to go ahead and execute on that plan to redrill late in the year.

The other thing that is a positive impact to us is that we're now starting to bring on our Pecan Acreage wells throughout the year. We'll have two wells on here now, we'll have two additional wells on in a month. We expect, simply because of the nice sweet spot that, that's in within the Wolfberry trend, that we would expect some additional production contribution from that throughout the year.

I would say the first and second quarter will be somewhat challenged; the third quarter will be full up with just everything that we've got plus growing rates at the horizontal wells; and then fourth quarter should be a good quarter and then slightly impacted by minor downtime.

Thank you for that, Gary. How much storm downtime do you have built into the guidance at this point?

We don't build storm downtime into the guidance at all, Richard.

Okay. What gets you to the high end of guidance for the full year?

What we did for that would be a quick resolution to 257. The Haynesville well staying up on production; we are just monitoring it because we just got it back online a week ago. We hope we don't have to do another well intervention on that well. Good performance from the Pecan Acres wells; those wells could be quite nice. We just don't have anything to tell you about them at this point in time. They're offset by very nice wells. And then high end performance from our horizontal wells.

Other than that, our deepwater assets will just perform as steady as they can with some decline throughout the year. So our growth comes from horizontal development in Pecan Acres.

Gary, what is the expected oil/gas ratio in those Cline wells?

I expect it to be 70% oil, 30% gas, and some of that gas will have high liquids content in it. So I'm going to guess it's going to be, at the end of the day, a minimum of 80% liquids priced.

Okay. This might be a question for Bob -- looking at the cash flow gap that estimated, used in different price scenarios for 2012 -- as you look forward into next year, I know it's still a ways off, but if you have a similar-type capital program, do you see your current liquidity being able to fund that? Or expanded borrowing base? How do you look going forward handling funds?

I think if you did a same CapEx budget as next year rolled forward -- if you did that, then I think, as Gary said, beginning of the third quarter ramping up into the fourth quarter, production is moving up nicely. Also, with the Habanero up-dip well that is being drilled in the fourth quarter, that production should come online in the first quarter of next year.

The impact of the horizontal wells, which we're drilling seven that we've got in the plan now -- those will be coming on, and by the first quarter of next year should be having a good impact. So we look for ramping production, therefore, once again remembering that a good bit of our production is LLS-based offshore. We look for increasing cash flow, obviously, going into next year.

As a corollary, as we continue to prove up DDP reserves, we would anticipate that there we would hopefully would see some improvement in our borrowing base, which I think would be appropriate. I think between the cash flow increases, and if acquired, the line on that basis would be fine.

Okay. You look at a decent-size acquisition, or in total, they come up to a decent amount. How would you look to fund that? Or even smaller ones, combined total, a decent amount compared to your --

I think what we would have to do is just look at our overall CapEx budget in total, and just look at what was available to us to fund it. But I think in terms of just our line of sight development, as we move ahead, we are certainly okay. I think any specific acquisition we would have to assess on its own.

All right. Thank you, Bob. Appreciate it.

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

Thank you, Laura. Once again we appreciate everyone taking the time to call in; and as always, if you have any questions, please do not hesitate to give us a call. Thank you.

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