Callon Petroleum Co (CPE) 2010 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Callon Petroleum first quarter 2010 results conference call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded, Friday, May 7th, 2010.

I would now like to turn the conference over to Mr. Fred Callon, Chairman and Chief Executive Officer. Please go ahead, sir.

Good morning and thank you for taking time to call into our 2010 first quarter results conference call. Before we begin this morning the formal portion of our presentation, I'd like to ask Terry Trovato, who heads of Investor Relations, to make his comments.

Thank you, Fred. We'd like to remind everyone that some of the comments made during this call will be considered forward-looking statements. As such, no assurances can be given that these events will occur or that the projections will be attained. Please refer to the cautionary language included in our news release and in the risk factors described in our SEC filings. We undertake no obligation to publicly update or revise such forward-looking statements. It should be pointed out that as of January 1st, 2010 the SEC changed its rules to permit oil and gas companies in their filings with them to disclose not only proved reserves but also probable reserves and possible reserves.

Proved oil and gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produceable from a given date forward from known reservoirs and from under in existing economic conditions, operating [limits] and government regulations prior to the time at which contracts provide the right to operate expire. Probable reserves include those additional reserves that the Company believes or is likely as not to be recovered. And possible reserves include those additional reserves that are less certain to be recovered than probable reserves.

Finally, today we will be discussing 2010 cash flow which is considered a nonGAAP financial measure. Reconciliation and calculation schedules for the nonGAAP financial measure were stated in our first quarter 2010 results news release and can be referenced there on our website at www.callon.com for subsequent review. Fred?

Thank you, Terry. And again, we appreciate you taking time to call in. Callon entered 2010 with both renewed excitement and the capital necessary to continue to execute the Company's new strategic vision, looking to emphasize long-term growth through the acquisition and development of lower risk, high impact owned shore assets and funding the development of these assets with a stable cash flow from our deep water Gulf of Mexico properties. With no debt maturities for six years and good liquidity, we're well positioned to fund our 2010 Permian Wolfberry development drilling program and our North Louisiana Haynesville Shale program as well as continue to look for new acquisition opportunities.

I'd like to begin this morning by asking Steve Hinchman, our Chief Operating Officer, to discuss our operations, including our increased drilling activity, the development status of our Permian basin asset then the Haynesville Shale play, and review our operations for the first quarter of 2010. Bob Weatherly, our Chief Financial Officer, will then review our financial results for the same period including a discussion of first quarter highlights related to our further improved balance sheet and liquidity positions. Steve?

Thank you, Fred and good morning. I'll begin with a brief operations review for the first quarter 2010. As always, I'll begin with safety. Year-to-date Callon has not incurred any recordable safety instances. We're committed to a strong safety culture, and I believe that good safety performance translates to a strong operating performance.

In mid-February Callon began its Wolfberry development program in the Permian Basin. We acquired our Permian Basin properties in October of 2009 and have a drilling inventory of over 300 wells. We have drilled four wells and are currently drilling the fifth. Our last well was drilled in 14 days and we expect that it will take on average 12 to 15 days to drill and set the production casing. We've completed and fracture stimulated three wells using six to eight stages. Each stage is completed using limited entry perforating, which assures that a fracture is initiated and placed in the desired interval. Our fracture modeling and tracer analysis confirm that we are executing effective fracture placement and getting good vertical coverage. In fact, our flow back rates have been twice as high as existing offset wells indicating improved productivity.

The three wells which have been completed are continuing to clean up. You typically begin to see oil cut after we recovered about 30% of the fluid pumped in the stimulation and oil rate continues to increase for a month or two. Our first well was placed on production in mid-March and is currently producing 120 barrels of oil per day and 100 Mcf per day of gas, while still continuing to clean up. This has exceeded our initial expectation of peaking around 100 barrels of oil per day three months after it's hook up. Our total well costs are coming in between $1.3 million and $1.5 million, in line with our expectation. Although it is still early in the program, our initial results are certainly encouraging and overall we're executing well.

Turning our attention to the Haynesville Shale. In 2009 we acquired a 70% working interest in operatorship in a Haynesville Shale gas unit located just south of the Elm Grove Field in Bossier Parish, Louisiana. This unit is surrounded by 20 million a day initial rate wells with an expected recovery of 7.5 Bcf per well. We have contracted a drilling rate, which has been drilling Haynesville Shale horizontal wells, and is currently completing a lateral section. After it completes this well, it will be available to Callon. We're building our drilling pad and will be ready to receive the rig in three weeks. We have all the necessary contracts, permits and most importantly the personnel to execute on this well.

Callon's Gulf of Mexico operations have not and we do not expect that they will be impacted in any way by the release of oil from Mississippi Canyon 252. Medusa and Mobile Bay 864 are the only two facilities even close to the release. Medusa is over 70 miles south and west of the release and current [NOAH] projections do not place any oil in this area. We're in contact with the operator who also expects no impact. Mobile 864 is 100 miles north of the release and current NOAH projections do not place any oil in this area, at least over the next 72 hours. Callon operates this facility and if the slick were to move into the vicinity, we would closely monitor for VOCs and shut in only if necessary. We have been in contact with operators in the main pass area which have had oil move through and there have been minimal vapors measured and it did not impact their operations. Of course, we remain in contact with the MMS.

And finally in the Gulf of Mexico our East Cameron 2 production remains shut in. An incident which occurred in February on the non-operated host facility for production from East Cam 2 is expected to continue to defer production of 2.5 million cubic feet equivalent-- net equivalent, which is mostly all gas until October based on the best estimates from the operator to restore the facility to operations.

Turning now to our quarterly comparisons. Our net production averaged 27.8 million cubic feet equivalent gas per day in the first quarter of 2010. This is comprised of 1.25 Bcf of natural gas and 223,000 barrels of oil. This is in line with our first quarter guidance of between 27 and 29 million cubic feet equivalent gas per day.

Production in the first quarter of 2009 was 1.4 Bcf of gas and 263,000 barrels of oil or 33.6 million cubic feet of gas equivalent per day. The negative variance in the first quarter of 2010 is due to the shut in at East Cam 2, the downward interest reversion at Habanero #1, which occurred at the end of June 2009, and natural decline. And this is partially offset by High Island A-494 which was brought back online in July of 2009 and the Permian acquisition, which was closed in October of 2009.

Production in the fourth quarter of 2009 was 1.5 Bcf of gas and 288,000 barrels of oil or 35.4 million cubic feet equivalent gas per day. The negative variance in the first quarter of 2010 is also due to the shut in at East Cam 2, and in addition to Medusa's royalty volumes which were booked in the fourth quarter of 2009 that were associated with Court's upholding of the 1995 Royalty Relief Act.

On the expense side, lease operating expense including severance for the first quarter of 2010 was $4.65 million or $1.86 per Mcf equivalent, in line with our guidance of $4 million to $5 million. Lease operating expense for the first quarter of 2009 was $4.04 million or $1.33 per Mcf. The higher expenses in the first quarter of 2010 were due to additional expenses associated with the new Permian Basin properties and increased insurance costs partially offset by higher working interests in Habanero and hurricane repair cost that occurred in the first quarter of 2009. Lease operating expense in the fourth quarter of 2009 was $4.8 million or $1.47 per Mcf equivalent. The lower expense in the first quarter of 2010 were due to work over expenses which occurred in the fourth quarter of 2009 at Medusa, partially offset by the additional cost of a full quarter being booked in the Permian Basin.

Now turning our attention to our 2010 guidance. In the Permian Basin we've initiated our development program, and as discussed, we're off to a good start. Our original plan was to utilize one drilling rig and drill 16 wells in 2010. Our execution performance has been very good and with higher oil prices we plan to add a second rig in mid-July, which will allow us to drill and complete up to ten additional wells for a total of 26 gross wells which nets to 24 wells in 2010. This program will triple production in the Permian Basin over 2010 with an exit rate of approximately 1,000 net barrels of oil equivalent per day. In addition due to the lower gas prices, we will defer a planned second well in the Haynesville Shale and redeploy the capital to fund the additional rig in the Permian Basin.

We are estimating the second quarter production to range between 25 and 28 net million cubic feet of gas equivalent per day. Second quarter production is being negatively impacted by some unplanned pipeline maintenance, which shut in and curtailed Medusa production for eight days in April, and the continued shut in of the East Cam 2 host facility. On an equivalent gas base, our full year production guidance remains at 27 to 31 net million cubic feet of gas equivalent per day. However this shift in the capital to the Permian Basin will allow us to produce more oil. Oil production will now range between 840,000 and 970,000 barrels of oil and gas will range between 5 to 5.6 Bcf. Of course, any acquisition in 2010 would positively contribute to these estimates.

Our LOE, lease operating expense including severance, will range between $5 million and $6 million in the second quarter 2010. Costs will be slightly higher in the second quarter due principally to maintenance and workovers planned at Medusa. Our full year guidance of $18 million to $22 million remains unchanged. In 2010 we'll continue to focus on our transition, execute on our operations and development, and deliver on what we say. I'll now turn the call over to Bob Weatherly, our Executive Vice President and CFO.

Thank you, Steve. Before I review our results of operations for the first quarter of 2010 and provide guidance for the second quarter and remainder of 2010, I would like to highlight several meaningful events that occurred in the first quarter. Collectively these events have significantly improved our liquidity and strengthened our balance sheet. On April 30th, we completed the redemption of the remaining $16.1 million of the 9.75 senior notes due in December 1910-- in 2010. As a result of this redemption, we will realize approximately $800,000 of cash interest savings in 2010 and further delever our balance sheet. Our only remaining long-term debt is $138 million of senior notes, which will be due in September 2016.

On January the 1st 2010, under revised accounting rules, we were allowed to deconsolidate our special purpose subsidiary Callon Entrada. This change resulted in an approximate $85 million reduction in consolidated current liabilities and a corresponding $85 million increase in consolidated shareholders equity. Additionally, the current quarter and future financial results will exclude the interest expense associated with this non-recourse debt. A detailed discussion of the amended accounting standard, and our application of that standard, is included in Note 2 of our Form 10-Q which we expect to file later today with the SEC.

As previously reported in January, we received $44.8 million from the MMS as a recoupment of royalties paid since 2003 on our Medusa Field. In April we were notified that $7.9 million of interest due on this recoupment has been processed for payment. We anticipate this payment in the second quarter.

Also in January we completed an amended $100 million credit agreement with Regions Bank. It has an initial borrowing base of $20 million. This facility represents a continuation of our long-term business relationship with Regions. No borrowings are currently outstanding under this facility.

Lastly we were pleased to report that on April 23rd we were notified by the New York Stock Exchange that we had regained full compliance with the Exchange's continued listed standards five months ahead of plan.

In summary, both our liquidity and balance sheet have been greatly improved by these events, particularly with the restructuring of our 9.75 senior notes. Consequentially we entered 2010 with our debt significantly reduced and our consolidated shareholders equity substantially increased. Callon has the financial resources, liquidity, assets and team to pursue our business strategy of reinvesting the cash flow generated from our Gulf of Mexico properties into lower risk, longer life onshore assets.

As Steve discussed earlier, we have decided to accelerate the development of our Permian Basin assets. We plan to increase the number of Permian wells drilled by seven to ten increasing the originally planned 16 well program to a revised 23 to 26 well program. This acceleration will be accomplished by adding an additional rig in the second half of the year. The capital required to drill these additional wells will be reallocated from funds already included in our 2010 capital expenditures budget. Our planned capital expenditures for 2010 of approximately $63 million are up slightly from our previously announced budget. As we have noted in the past, our current 2010 capital expenditures program can be fully funded with expected cash flow from operations and cash on hand. Our current financial projections, which include all currently planned capital expenditures, anticipate Callon ending 2010 with strong liquidity.

Now let me discuss the first quarter's results of operations as we reported in our earnings release. Oil and gas revenue for the first quarter of 2010 totaled $23.4 million. The Company reported net income of $3.9 million or $0.13 per diluted share versus a consensus estimate of $0.09 per diluted share. These first quarter 2010 results compared to oil and gas revenues, net income and earnings per diluted share of $24.8 million, $2.4 million and $0.11 respectively for the same quarter 2009. Contributing to the slight decrease in revenue in 2010 was a first quarter decrease in average daily production on an Mcfe basis and a 6% decrease in realized natural prices after hedging. However, these decreases were significantly offset by a 23% increase in the average sales price of oil after hedging.

Highlights for the period are as follows. Our 2010 results include only minor hedge-related benefits as the current NYMEX pricing fell largely within the range of our established collars. For the remainder of 2010, we have hedging positions on 43% of estimated crude oil production and 20% of estimated natural gas production. For 2011, we have approximately 28% of estimated oil production hedged. 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.

Depreciation, depletion and amortization of $6.8 million in the first quarter is $2.6 million less than DD&A in the corresponding quarter of 2009. This period-over-period decline was due both to a lower DD&A rate and slightly lower production in 2010 versus 2009. The lower DD&A rate is the result of a downward revision during the second quarter of 2009 of the cost estimate for plugging and abandonment of the Entrada Field and an increase in the 2009 proven reserves. Depreciation, depletion and amortization were recorded at a rate of $2.72 per Mcfe compared to a rate of $3.11 for the same period of 2009. DD&A for the first quarter of 2010 was slightly below the guidance range of $7 million to $8 million.

I will now discuss details of LOE, as Steve has already discussed this in detail in his comments. G&A expense in the first quarter of 2010 was $4.3 million as compared to $1.8 million for the same period of 2009. The major variation between years relates primarily to the timing of adjustments to our incentive compensation plan accruals and expenses related to continuing realignment of our operations and technical staff to meet our new strategic initiatives. Interest expense was $3.6 million for the first quarter of 2010 compared to $4.8 million for the same period of 2009. The amortization of the deferred credit related to the restructuring of our senior notes reduced interest expense by $889,000 in the first quarter. Please review our earnings release for further details of operations for the quarter ended March 31.

Now I would like to take a minute to discuss guidance for the second quarter and the remainder of 2010. As Steve mentioned earlier, the daily production guidance for the second quarter of 2010 is projected to be 25 to 28 million cubic feet a day equivalent for the full year guidance is unchanged at 27 to 31 million cubic feet a day. Oil accounts for approximately 52% of the projected production in the second quarter and approximately 51% for the full year. As previously discussed, we have added hedges for part of our legacy production for 2010. Please refer to our press release for more details on hedging. As mentioned earlier, we will continue to monitor the markets and add hedges as appropriate.

We are projecting G&A expenses to be in the range of $3.4 million to $3.8 million for the second quarter and $13 million to $15 million for the full year 2010. Interest expense is forecasted to be $3.5 million to $3.8 million for the second quarter and $12.7 million to $13.6 million for the year.

Earlier I discussed the deferred credit related to the restructuring of our senior notes due 2010-- 2016. The $31.2 million deferred credit on our balance sheet will be amortized over the term of the 2016 notes. This amortization will be-- will continue to be recorded as a reduction to interest expense each period. In 2010 the amortization will be $3.7 million. We are projecting a DD&A rate of $2.75 to $2.80 per Mcfe for the second quarter and $2.70 to $2.80 per Mcfe for the full year 2010. Please refer to our guidance press release which provides additional details regarding our guidance for the full year. Now I'll turn the call back over to Fred for a few final comments. Fred?

Thank you, Bob. And again, we appreciate you taking time to call in this morning. And so we'd now like to open the call up for questions.

(Operator Instructions) Our first question coming from the line of Ron Mills from Johnson Rice. Please proceed with your question.

Good morning.

Good morning.

Steve, maybe for you to start on the Permian Basin on that first well. You said it's currently producing the 120 barrels a day, still cleaning up. Can you tell- do you have any ideas yet in terms of how much of your fluid has already been recovered relative to that 30% bougie that you state when you reach your peak production? And where the second and third wells that are currently flowing back, where are they in the process?

Ron, the first well that we drilled that's producing 120 barrels per day, it started to get an oil cut at around 35% of the load, it ramped up fairly quickly. And over the last couple of weeks it moved up from about 70 to 120 barrel per day. It's still cleaning up, at 100 Mcf a day the GOR is at about 1,000. Typically the gas continues to improve and it brings a little bit more oil with it. And how these wells will typically behave is as they reach their peak production, they'll stabilize for a short period of time, maybe a few weeks maybe as much as a month, and then they go on decline. And after about first year of production they'll be down to 40 or 50 barrels per day and then get pretty flat after that. With roughly at that sort of rate probably about 100,000 barrels of oil recovered.

The second well that's been completed is just at around 30% of its load returned and it's currently producing about 25 barrels per day of oil. So it's pretty much in line with the way the first well kind of behave and we expect that'll ramp up relatively quickly. The third well essentially has just been hooked up, and it's just starting to see a trace of oil, but it's probably recovered less than 10% of its load at this time.

And so those are the three wells under production and we're prepared to frac the fourth well that's just been drilled and production casing set and we're drilling on our fifth. So and as I said, I think right now from a production performance basis, it's behaving about as we expected, perhaps a little better. I think I shared with you before that we felt the wells would cleanup and peak at between 70 and 100 barrels per day after three months. So the first well is actually over 120 barrels of oil per day really only after about a month-and-a-half, two months. So it's done better than what we thought.

Okay and I know that you've broken your Permian down into three areas-- three project areas with almost all the activity in the Carpe Diem and the Kayleigh areas. With you adding the second rig earlier, where do you plan on putting that third rig potentially on that farmed acreage?

Yes, Ron, the original plan had us drilling 11 wells at Kayleigh. That will basically develop Kayleigh on 40-acre spacing. It had us drilling two wells on Carpe Diem, a little more of an evaluation on there, and that's all we would expect to drill this year is two wells on Carpe Diem. The third area that we have is called Bloxom, and the original plan had three wells to be drilled on Bloxom. What we are going to do is basically leave that rig down there and let it drill all of the additional wells on Bloxom. Bloxom is a little further, it's just south of Carpe Diem, south of Odessa. You have Concho actively drilling the sections just to the west and north of us, you have Windsor drilling the sections west and south of the Bloxom area and you have Pioneer drilling all to the east of the Bloxom area.

Essentially this is a six section position where you had tremendous activity with all around these six sections with only one Wolfberry well drilled to date in those six sections. So we're very excited about the Bloxom opportunity. The first well we drilled is just cleaning up, as I spoke, and we think it has some real potential and we're excited about getting busier down in that area.

And were the other two wells that you brought online, were those both at Kayleigh?

You got one well at Kayleigh, one well at-- a second well at Kayleigh, one well at Carpe Diem, and we're just frac-- we're just stimulating the well at Bloxom. I'm sorry, we're just fracing that well.

Okay and just to make-- I understood if you keep a rig there, then you would-- that what it sounds like what you would do is with the two rig program probably drill more wells--- or the incremental wells at Bloxom, is that fair?

Yes, I'm sorry Ron just to be clear, all the incremental wells this year would be at Bloxom. All the additional wells are at Bloxom.

Okay and then the funding of that, basically you take your 70% of the cost of the Permian well, or I mean the Haynesville well, the second well you were planning on drilling and you're just allocating it out to the Permian?

Yes, by deferring that second well then we'll deploy that capital into the Permian.

And then one, can you give one final thing on the Permian, a lay of the land? I know you've continued to look at additional opportunities both in the Permian, Haynesville and maybe even other areas, but a lay of the land in the Permian especially in light of transactions going back to late last year where you've seen a number of properties change hands, both big and small.

Yes, late last year and into 2009 deal flow was low, it's was probably at 75% of the average sort of deal flow-- 25% of the average kind of deal flow you'd see in the Permian. And I think you had a big gap between sellers expectations and buyers expectations. As we move now into the first quarter, the deal flow is up tremendously. And I think it's partly because with the higher prices, suddenly the buyer and the seller are getting closer together and the gap is closing. So you do see evaluations going up, the cost going up, but you're seeing tremendously more deal flow happening in the Permian today than you did just six months ago.

All right, I'll jump back in queue. Thanks,guys.

Thank you. Our next question coming from the line of Richard Tullis from Capital One Southcoast. Please proceed with your question.

Thank you, good morning.

Good morning.

I know you guys aren't the operators in the Gulf of Mexico, it's Shell and Murphy. But what do they have planned for the rest of this year on those properties, Habanero and Medusa?

Really at Habanero we'll just be really producing the two existing wells. There's no major activity planned at Habanero. There is a potential that a well could be drilled next year at Habanero. But the partnership hasn't agreed to that at that time. In preparation, Shell has asked that the partnership put some money in for long lead items. But that's still to be determined.

At Medusa, Medusa as I mentioned has a-- is moving forward in the second quarter with some minor kind of workovers, mostly just some well optimization work there. Not a major lot of activity. We had originally thought that there could be a recompletion, the operation of a selective completion, which is a completion that's already built and constructed in the well bore that you actuate through slick line. But with these oil prices, that more and more likely looks like it'll move out into 2011 at this time. But from a capital expenditure standpoint, there's minimal to no real investment expected in 2010.

Okay, very good. How much are the wells costing today in the Permian?

Well we've seen our wells-- we've said that the wells will cost around $1.5 million of the three wells that we've drilled and completed and with a fourth well, we're running under $1.5 million. We've seen it start to move towards $1.3 million. I'm reluctant to say it's going to be $1.3 million per well for the whole year just because with the activity increasing, we're-- there's some concern we'll see some escalation in some of the service cost out there. For our 16 well program though, we are under a turnkey, we did contract for a turnkey on the drilling side early on. And so we were able to control any potential escalation through that turnkey for the most part. But $1.3 million to $1.5 million is what we're estimating and $1.5 million based on what we've seen right now would certainly probably be on the high end of that.

Okay. And how many net wells are you adding to the program for this year?

About eight net wells.

Okay, good.

We got pretty reasonable-- we got reasonably high interest across all of the development area.

Okay.

About eight net wells.

Okay. And going back to the acquisitions landscape, with oil prices pulling back a little bit, I mean do you-- are you going to look in any other areas? I'm guessing you're still oily focused. But any other areas you might be interested in looking at?

Well Richard, we'll keep our peripheral vision out there because in one hand you've got to be somewhat opportunistic driven. So we'll maintain our peripheral vision for those sorts of opportunities. But we want to be pretty laser-focused on the Permian and just continue to build our expert-- our knowledge, our expertise and our competencies in that area./ So our strategic focus will be in the Permian, but we'll be keeping a lookout for other opportunities that may exist.

Okay. Well I think that's all I have. I appreciate it. Thanks a bunch.

Thank you. (Operator Instructions) Our next question coming from the line of Michael Anthony, private investor. Proceed with your question.

I really don't have any questions. I want to congratulate you all in your progress and you all have a total of eight wells really and how many more are you all going to drill? That's the only question I really have.

Yes, Michael, we have-- we had originally 16 gross wells scheduled for the Permian Basin this year and we could drill up to ten. On a net basis, we would likely-- that would be around 24 net wells in the Permian this year and we'd drill one well in the Haynesville Shale gas unit. So a total of around 25 wells this year.

All right, thank you very much, gentlemen.

You bet.

Thank you, Michael.

Thank you. Our next question is a follow-up question coming from the line of Ron Mills from Johnson Rice. Please proceed with your question.

Okay just one question on the recent staff additions that you've made, starting with you Steve, last summer and more recently this year. Can you just provide a little bit of color on the new technical teams background in terms of history in drilling horizontal wells and onshore activity as you move into those types of developments?

Yes, sure. We've brought in Gary Newberry.Gary is the Vice President for Production and Development. Gary was 33 years with Marathon Oil. He had run our-- most of our US operations and onshore and was involved in Marathon's activity around the resource plays including the coalbed methane in Powder River, the Bakkan Shale in North Dakota, the Marcellus Shale in Pennsylvania, the Woodford and the Haynesville Shale. So from a management and leadership feel he's been intricately involved in many of the shale plays around the country.

We also added additional technical staff. We have a reservoir engineer, Greg Hepguler, who came to us from Southwestern as a reservoir engineer, and so he brings some really good shale experience from the reservoir side.

We've brought in John Becher who came from Range, who really brings in some great shale experience coming from Range as really a new venture geologist who was involved in evaluating most of the shale plays around the country either shale plays under development or emerging shale plays. So he has been a bid lift to our geo expertise around shale.

We brought in John Beddo who was a private consultant for 17 years but had worked principally in the Haynesville and spent time in the Permian. He is our Drilling and Completion Superintendent. So he's the guy in the field trying to make sure that these things get executed correctly.

We brought in April Coker who the Geologist who, we seem to be getting a theme here a little bit, who worked for Marathon, who was the geologist who was working principally in the Permian Basin. So she brings to us a good geo background for the Permian Basin.

We've hired some pretty really good field people too, both out in the Permian and in the Haynesville that have been experienced folks operating that area for many years. Our production superintendents who really make sure the day-to-day interruptions making it to the sales tank. And so I think we're in good shape. We brought in the right personnel. Where we have any gaps, I think we have some of the best consultants in the businesses to help us close those gaps. So I feel real confident about where we are in terms of our personnel to be able to execute this program.

Of course, Ron, as you know, I was an Executive Vice President for Marathon, I was responsible for their worldwide production operations and I've been involved in most all of these plays from a leadership level for many years. So it's not my first time around the block here either. So we're in good shape, I'm highly confident.

It sounds-- I mean the experience is definitely rounded out and it sounds like you've built a staff where you can really meaningfully add to positions in these onshore properties without running into a human capital shortfall?

That's correct. No doubt about it.

Great, thank you.

Thank you. Mr. Callon, there are no further questions at this time. I will now turn the call back to you. Please continue with your presentation or closing remarks.

Thank you. Once again, we appreciate everyone taking time to call in. As always, between these calls, feel free to give us a call here at the Company if there's anything we can do. Thank you.

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your line. Have a great day.