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Callon Petroleum (NYSE:CPE)

Q4 2012 Earnings Call

March 15, 2013 11:00 am ET

Executives

Fred L. Callon - Chairman, Chief Executive Officer, President, Chief Executive Officer of Callon Petroleum Operating Company and President of Callon Petroleum Operating

Joseph C. Gatto - Senior Vice President - Corporate Finance

Gary A. Newberry - Senior Vice President of Operations

Bobby F. Weatherly - Chief Financial Officer, Executive Vice President and Director

Analysts

Will Green - Stephens Inc., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Operator

Good morning, and welcome to the Callon Petroleum Fourth Quarter 2012 Results Conference Call. [Operator Instructions] Please note this event is being recorded. And now I would now like to turn the conference over to Fred Callon, Chairman and CEO. Please go ahead.

Fred L. Callon

Thank you and good morning. We appreciate you taking time to call into our fourth quarter year-end conference call.

Before we begin, I'd like to remind everyone that presentation slides accompanying this call were put together and are available on our website under the Events and Presentations section, if you'd like to refer to that.

Now I'd like to ask Joe Gatto, our Senior Vice President, Corporate Finance, to make a few comments. Joe?

Joseph C. Gatto

Thank you, Fred. We'd like to remind everyone that this conference call contains forward-looking statements, which may 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. Some of these factors are discussed in our filings with the Securities and Exchange Commission, including our annual reports 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 discretionary cash flow, PV-10 measure and adjusted net income. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our fourth quarter 2012 results news release and our filings with the SEC, and can be referenced there or on our website at www.callon.com for subsequent review.

Fred, I'll turn it back to you.

Fred L. Callon

Okay. Thank you, Joe. I'll begin on Slide 4 of the materials and touch on a couple of highlights. As most of you know, for the past 3.5 years, we have been building the foundation of an onshore asset base, most importantly bringing together the right skill sets for an operated Permian focus. We've assembled an acreage position of over 36,500 acres in the Midland Basin and largely pursued a Wolfberry-type development program that was funded in large part by cash flows from our offshore production.

Over the last year, we shifted some of our focus to horizontal development in the Permian, and we're -- been evaluating several different play types. As you will see in the following slides, we've assembled a large inventory of identified projects for the coming years. However, getting to this point has not been a straight line, as we experienced the typical delays in getting up the horizontal learning curve while mixing exploration with development to expand the portfolio on a cost-effective basis.

As we move into 2013, we have clear priorities for the business after a year characterized mostly by resource, capture and testing: Number one, transition to development mode for our de-risked Wolfcamp B asset base using pad development schemes and optimizing water sourcing and disposal. This should provide us with a baseline of production and reserve growth as the year progresses.

Number two, continue to advance the value of our other components in the portfolio. This includes our testing of the Wolfcamp A shale in the Southern Midland Basin, which continues to show promising results from other industry wells and finalizing our horizontal drilling plans for the Central and Northern areas of the basin. It also includes applying new completion concepts and deeper target zones to our legacy Wolfberry program.

We believe these focus areas will not only improve overall returns but position our Permian assets to evolve from being a replacement of our Gulf of Mexico [indiscernible] in the near future.

Turning to Slide 5. We provided a snapshot of our inventory of drilling -- drillable locations in the Permian Basin. This identified opportunity set is in various stages of development and will continue to be advanced during 2013 in an effort to add to additional program development in the Permian. As can be seen on the chart, our transition to a horizontal focus has clearly increased the potential impact of our drilling program, with the potential to add over 45 million barrels of oil equivalent reserves from the Wolfcamp Shale and the Mississippi Lime alone.

I would like to point out a few steps, I believe, highlight the strength of our operating model and the opportunity for continued onshore growth: over 14 million barrel equivalent reserves, with 2/3 located in the Permian Basin and having 77% oil content; the potential to add over 4 million barrels of PDP reserves in 2013 based on Wolfcamp Shale type curve and current drilling plans; net cash flow margins of $37 a barrel equivalent produced in 2012, providing financial flexibility for our growth initiatives; and finally, access to a large acreage position that is well positioned to participate in the new development concepts that continue to emerge in the Permian Basin.

I'll now turn the call over to Gary Newberry for an operations update and a preview of our 2013 drilling plans.

Gary A. Newberry

Thank you, Fred, and good morning. Fred described the significant growth potential from our current inventory of drillable well locations, and I will start with a description of our proved reserves at year end on Slide 7. Year-end 2011 proved reserves were 15.9 million barrels oil equivalent, which included the Habanero Deepwater asset, which was sold in the fourth quarter 2012. Adjusting for the sale of Habanero, proved reserves at year end of 2011 on a pro forma basis would have been 14.6 million barrels oil equivalent.

Proved reserve additions associated with our 2012 capital added 3.2 million barrels of oil equivalent, finding a development cost of $24 per barrel of oil equivalent and replaced 222% of our 2012 production.

Downward revisions included 1.8 million barrels of oil equivalent due to the reduced realized gas prices in the Haynesville and other downward revisions of 0.5 million barrels of oil equivalent related to the Gulf of Mexico shelf and Permian performance, resulting in a proved reserves at year end 2012 of 14.1 million barrels of oil equivalent.

As Fred has mentioned, our proved reserve base at year end was 77% oil and 67% located onshore in the Permian Basin, providing a solid base for future reserve growth.

Moving to Slide 8. The Southern Midland Basin will be our key focus area for our 2013 horizontal development program. Our first 2 horizontal wells drilled on our East Bloxom field have averaged 24-hour IP rates of 801 barrels of oil equivalent per day, with average 30-day rates of 576 barrels of oil equivalent per day. More importantly, these 2 wells have continued to perform well over time, with average cumulative production of 55,000 barrels of oil equivalent per well in their first 5 months of production.

Our 2013 capital plan includes the drilling and completion of 6 additional horizontal wells at our East Bloxom field, targeting both the Wolfcamp A and B zones. Two Wolfcamp B wells and one Wolfcamp A well have already been drilled and are awaiting completion, with the first well scheduled to be fracture stimulated beginning on Monday, March 18.

Moving east from Upton County to Southern Reagan County is our Taylor Draw field, where we are targeting the Wolfcamp A and B shales. The Pembrook 9121H well was drilled late 2012 to a lateral length of just over 5,000 feet and was fracture stimulated in February 2013. The well continues to clean up with 12% load recovery. The well is performing similar to nearby wells to the Northwest, which have produced results that support EURs in the range of 375,000 to 400,000 barrels of oil equivalent. Our 2013 capital plan includes the drilling of 8 horizontal wells and completing 7 wells at Taylor Draw, targeting the Wolfcamp B in a program development effort. The drilling rig is currently drilling the first of 4 wells from the same pad.

Turning to the Central Midland Basin on Slide 9. Pecan Acres and Carpe Diem will be the focus of our 2013 vertical drilling program, with plans to drill 8 vertical wells to deeper horizons. We are encouraged with the performance of the Pecan Acres 23 3 well, which was completed in deeper zones from the Atoka to the Woodford, with incremental rates of 100 barrels of oil equivalent per day and incremental estimated reserves of 30,000 barrels of oil equivalent.

Future wells at Pecan Acres will be drilled to these deeper depths, and we will test these deeper horizons at our Carpe Diem field. We're also encouraged with the performance of the last 3 Pecan Acres wells completed in the typical Wolfberry zones, which had averaged 24-hour IP rates of 224 barrels of oil equivalent per day and average 30-day rates of 166 barrels of oil equivalent per day.

In addition to these vertical results and implications for our remaining inventory of vertical locations, we have been closely monitoring recent results of horizontal wells targeting the Wolfcamp B near our Carpe Diem field. This activity has confirmed our technical assessment of the area's horizontal potential and has largely de-risked both Carpe Diem and Pecan Acres for horizontal development, adding 30 locations to our horizontal inventory.

On Slide 10, I will now discuss our Northern Midland area, which added a meaningful exploration component to our portfolio in 2012. Our initial evaluation efforts in this area included 1 vertical well and 2 horizontal wells in Borden County. The first exploration well targeting the Cline shale, the Vickie Newton 3801 #1H, was drilled to a lateral length of 6,769 feet and was fracture stimulated with 25 stages using slickwater. The well had a peak rate of 97 barrels oil per day and has been temporarily abandoned. We will continue to monitor industry activity, which includes 2 horizontal Cline wells approximately 10 miles south of our acreage, prior to drilling another Cline test.

Our second exploration well in Borden County, the Shirly Newton 2301 #1H, was drilled in the Mississippian formation with a lateral length of 4,107 feet and was fracture stimulated with 14 stages in January, 2013. The flowback was delayed due to stuck coiled tubing during the drill-out of the plugs. The well is producing hydrocarbons and continues to clean up during the early stages of flow back operations, with less than 10% of load recovery to date.

We remain encouraged about the potential for horizontal development of the Mississippi Lime given the technical data gathered from our drilling efforts along with results of ongoing activity in the area. We currently plan to provide an update on our future plans for this play on our first quarter 2013 earnings call.

The vertical science well, the Shirly Newton 4801, will test several prospective zones in the Wolfcamp, Spraberry and Clearfork formations during the second quarter 2013 as we evaluate the potential for future vertical development in the area.

Looking forward to our planned drilling activity in 2013 on Slide 11. We plan to complete 14 horizontal wells and 12 vertical wells for a total of drilling and completion cost of $86 million. Activity will increase as the year progresses, as efficiencies in pad drilling and batch completions are achieved in the Southern Midland Basin.

As you can see, in the fourth quarter of 2012 and the first quarter of 2013, we slowed our pace of completion activity. This was a conscious decision to defer production rate in order to pursue significant cost reductions in our well cost. We deferred 2 horizontal completions from the fourth quarter 2012 to the first quarter 2013 in order to allow time to bid our drilling and completion services, including fracture stimulations. This activity has effectively reduced our cost of services by approximately 30%.

Moving to Slide 12. The left-hand chart illustrates the efficiencies achieved in drilling 7,000-foot horizontal wells at our East Bloxom field utilizing pad drilling. The last 3 wells were drilled from spud to rig release in an average of 21 days. This significantly improved performance, combined with the reduced overall cost of services I previously mentioned, has lowered our expected drilling and completion cost to $6.5 million per well at the East Bloxom field and to $6 million per well at Taylor Draw.

Going forward with reduced drilling and completion cost, Slide 13 illustrates the type of production we expect to achieve from our Wolfcamp B drilling program. As shown on the left-hand graph, the results from our producing Wolfcamp wells have continued to exceed our planning type curve over the first 5 months of production. Using this planning case of 450,000 barrels of oil equivalent combined with a $6.5 million drilling complete cost and assuming the current commodity price environment, we estimate returns of approximately 30% from efficient program development at our de-risked Southern and Central Midland Basin assets. In addition, results from the 2 Wolfcamp B wells waiting to be fracture stimulated, along with results from the Wolfcamp A test, may support an improved type curve for the area over time.

Turning to production guidance for 2013, shown on Slide 14. The top line includes our forecast of total production, and the bar graph is our forecast growth in the Permian. As shown on the graph, we will be providing guidance separately for the Permian and the total company on a go-forward basis as the Permian begins to drive overall company production.

Starting with the fourth quarter of 2012, which is pro forma for the sale of Habanero, Permian production will take a step downward in the first quarter of 2013 due to planned completion deferral associated with our service provider changeover in the Permian. In addition, we have experienced production deferral in our vertical wells at East Bloxom due to fracture stimulations of offset horizontal wells. Nearby vertical wells temporarily water out or experience increased fluid levels, which dampens the expected rate of growth from new completions until the vertical wells are dewatered and production returns to normal.

To partially mitigate this impact, we will plan to shut in nearby vertical production at East Bloxom while we are fracture stimulating our horizontal wells. We currently have 200 barrels of oil equivalent per day shut in, in preparation for fracture stimulation scheduled for Monday, March 18. We will continue to assess this impact as we fracture stimulate horizontal wells, and we estimate the vertical impact could be as much as 10% to 15% of our vertical production throughout the year.

Looking beyond these first quarter impacts, we expect to see the impact of our increasing Permian activity in the second quarter, which will accelerate throughout the year from our increasing efficiencies, the program development over time.

Overall, we expect to grow Permian production by approximately 65% from the fourth quarter of 2012 to the fourth quarter of 2013 and exit the year at 3,000 barrels of oil equivalent per day. This type of growth will deliver 15% top line growth for the entire company despite the normal declines seen in the offshore.

Equally as important, our improved cost structure will position us to target this rate of Permian production growth with only a 5% increase in drilling and completion expenditures.

In summary, after assembling a solid inventory of projects in 2012 from our drilling and evaluation activity, 2013 operations will be centered on a transition to efficient horizontal program development in the Southern Midland Basin and optimizing our vertical drilling program. In parallel, we will also be progressing plans for future horizontal development in the Central and Northern Midland Basin.

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

Bobby F. Weatherly

Thank you, Gary. I will now use Slide 16 to discuss the fourth quarter 2012 results of operations as we reported in yesterday's earnings release.

For the year 2012, the company reported net income of $0.07 per share in discretionary cash flow, a non-GAAP measure of $1.38 per share. Excluding mark-to-market derivative positions, impairment of assets acquired and gains on debt retirement, net income after tax was $0.04 per share for the year.

Operating revenues for the 12 months ended December 31, 2012, included oil and natural gas sales of $110.8 million from average daily production of 4,303 BOE per day. These results compare with oil and natural gas sales of $127.3 million from average production of 5,049 BOE per day during the comparable 2011 period.

Slide 17 discusses the components of revenue for the year. Starting with oil, which represents 62% of our total hydrocarbon production for the year, production decreased 2% in 2012 compared to 2011, primarily due to downtime at the Habanero and Medusa fields and normal expected declines from our other offshore properties. These production declines were offset by production from our new Permian wells, 22 vertical and 2 horizontal, which were rolled on to production during 2012.

The average oil price realized in 2012 decreased 2% to $98.86 per barrel compared to $101.34 for the same period of 2011. These realized prices reflect the pricing for our deepwater production that includes a premium over NYMEX pricing.

Moving to natural gas. Total production decreased 29% in 2012 versus 2011, driven primarily by downtime at our Haynesville well, which was shut in for 70 days during the first quarter of 2012 due to well interference from an offsetting well.

Also, we experienced downtime at our East Cam 257 well. Production here was suspended in the fourth quarter of 2011, and this well did not produce for the full year 2012. Prior to the shut in, this well was producing a net 1,650 Mcfe per day and is now expected to return to production in the next few weeks. After -- also contributing to the decline was the previously discussed downtime at our Habanero and Medusa deepwater fields and normal unexpected declines.

In addition to production decreases, the average realized price for natural gas decreased $0.25 to $3.94 per Mcf compared to an average realized price of $5.25 per Mcf in 2011. However, our natural gas prices on an MMBtu equivalent basis exceeded NYMEX prices, primarily due to the value of the NGLs in our natural gas stream, primarily from our Permian Basin and deepwater production. On an overall basis, we received $70.31 per BOE of production in 2012, an increase of 2% from 2011 and 8% over benchmark pricing for the same commodity profile without the benefit of offshore oil pricing and liquids-rich gas.

Before I leave this page, I would like to address one additional point. These numbers reflect the results of our Habanero Field through December 28, 2012, the day at which closing of the sale occurred. Pro forma for this sale, total company production would have been 3,937 barrels of oil equivalent per day. In addition, Permian production would have represented over 40% of Callon's total production for the year and 60% of total company production would have been crude oil on a pro forma

[Audio Gap]

Slide 18 lays out our expenses for the year and shows a comparison relative to guidance. We are within or below guidance on all of these measures with the exception of cash G&A, which increased $3.7 million to $20.4 million and from $16.6 million for the same period in 2011. The increase is due primarily to $1.6 million in cost for nonrecurring employee-related expenses, including early retirements and severance packages for which we had no expense during 2011.

Additionally, there was an increase in noncash charges of $1.2 million, which was related to incentive compensation-based instruments, which we must mark-to-market each quarter. The remaining increase was largely composed of personnel expenses related to the costs associated with hiring experienced technical staff to support our onshore growth and 100% operated Permian production, as well as relocation and other related cost.

I'll now turn to 2013 and our capital budget for the year on Slide 19. Our planned capital expenditures for the year have been set at approximately $125 million, representing a decrease of 15% from 2012. As Fred and Gary have discussed, 2013 is a year for converting our acreage and inventory into cash flow and reserves.

As a result, we have increased our drilling and completion budget by almost 10% while eliminating any budgeted acquisitions of leasehold, as was planned last year to increase our footprint in the Permian Basin. We do plan to spend an additional $10 million on Permian infrastructure in 2013 to support the long-term development of our core fields on a more cost-efficient basis.

Also in 2013, we have budgeted increased Gulf of Mexico expenditures to fund long lead time items associated with the Medusa subsea program. We understand that drilling may commence in early 2014 for this project.

Moving to Slide 20. We have outlined our financing thoughts for our 2013 capital budget. Given the financial flexibility that the Habanero sale provided, combined with a reduced capital budget for 2013 that is focused on organic drilling, we expect to fund our 2013 expenditures from a combination of cash flow from operations and borrowings under our existing senior secured credit facility.

We also recently restructured our previous oil collars for 2013. This transaction has the net impact of hedging over 45% of our anticipated oil volumes at $101.30 per barrel NYMEX for 2013 and providing additional cash flow certainty.

As you can see -- as you can appreciate from Fred and Gary's discussions, we continue to progress several drilling opportunities outside of our base horizontal Wolfcamp B and vertical Wolfberry development programs. We continue to evaluate the opportunity to accelerate these base programs in the coming months and need to make sure we have the financial flexibility to pursue them once they have been advanced.

Given the strength of our balance sheet and long-term capital position, we believe a large portion of any additional capital could be provided in the form of a fixed income instrument, depending on the size of the additional activity. In addition, as we have discussed in the past, sales of non-core assets similar to the sale of Habanero are always an option as we allocate capital to the projects within the portfolio with the best, best risk-adjusted returns.

Now I'll take a minute to discuss guidance for the first quarter and full year 2013, which is on Page 21. As Gary mentioned, we project the total production rate for the first quarter to be 3,400 to 3,600, for the full year to be 3,800 to 4,200 BOE per day, with oil accounting for 65% of these volumes. In addition, we are introducing separate guidance for our Permian assets, which we have established at 1,500 to 1,600 BOE per day for the first quarter and 2,000 to 2,300 BOE for the full year. The midpoint of our 2013 guidance would represent a 33% increase over full year 2012.

Please refer to our guidance press release, which provides additional details, regarding guidance for these periods in 2013. The guidance will also be posted on our website in the Investors section.

I will now turn the call back over to Fred for any final comments.

Fred L. Callon

Thank you, Bob. I think we'll now open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from Will Green of Stephens.

Will Green - Stephens Inc., Research Division

I wonder if we could start maybe with the Cline test up in Borden County. Did you guys get all the stages off? And I guess, looking back now, anything that was an obvious problem with the well that maybe could be corrected on the next go-around? Or just any additional color would be helpful.

Gary A. Newberry

Yes, Will, this is Gary. We've asked ourself that question ourselves. And frankly, we got the frac off, the well drilled fine, drilled it in good order, got all the stages away, got them all drilled out and flowed it back. So I can't tell you that mechanically on the Cline well, that there's anything there that would have us second-guessing that result.

Will Green - Stephens Inc., Research Division

Got you. And then maybe jumping over to the vertical test. Anything that you saw there that keeps you guys encouraged about the development up there that you could maybe expand on?

Gary A. Newberry

Well, again, on the -- remember, the vertical well, Will, was primarily a science well to get core. We're still having that core analyzed even as we speak now. We'll get the final result in a couple of months to help us understand even better, potentially, the performance of the Cline. But vertically in the well that we have, we tested it in the Ellenberger and it was noncommercial. But right now, we're looking at trying to do several additional Wolfberry-type test up hole in order to establish some commercial production. We see 4 zones that are prospective in the Wolfcamp, Spraberry and Clearfork. And if we can make those work, we could put together probably a fairly low-cost shallow vertical program in some parts of that acreage. That's kind of what we see from the vertical well.

Operator

Our next questions is from Hsulin Peng of Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

So a quick follow-up to the Cline. I just wanted to see -- so I know you said you are monitoring 2 offsetting wells 10 miles south. And I was just wondering, what are you -- I guess, what would you need to see for you to continue your Cline development or test there?

Gary A. Newberry

Well, I guess the simple answer to that, Hsulin, would be better flowback results than what we have received because we were clearly very disappointed in our own results. But that's what we're looking for. Our Cline test was really one of the first ones in the area, but we'd love to think that we can learn from others, just like we always do.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Right. No, okay. No, that sounds good. And then second question is, in Pecan Acres field, I was just wondering what your current well cost is for the vertical well and for the deeper zones where you've got the incremental initial production rate? How much incremental cost was that?

Gary A. Newberry

Yes, we think we can get to that with just another couple hundred thousand dollars, Hsulin. But our current estimated cost to get to the full section now, all the way through the Woodford, is really about $2.6 million. And of course, we would stimulate that now with up to 10 to 12 fracture stimulation stages. So some of the efficiencies we've gained in drilling, as well as our reduced services, we've added back in with additional zones because we're getting significantly more recovery.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. Great, sounds good. And then my next question is just regarding your volume base because I know you've said, for your 2013 funding plan, expect the increases as part of the source. And I was wondering if you -- well, first of all, your current volume base of $65 million, is that from reserves from October or December at year end, and how much do you -- do you have any early indication as to when your volume base could increase come April?

Bobby F. Weatherly

Hsulin, you're right. If you remember, the volume base in October when we added banks to our facility increased to $80 million. And then when we sold the Habanero interest, there was a reduction in that back down to $65 million. We have not met yet with the -- our bank -- lead bank or the bank group. We have got the year-end reserve reports, started providing them the information. And I believe that over the next couple of weeks, we will be meeting with them. Obviously, we believe that rolling forward, we've added some additional reserves. And certainly, as Gary has laid out his drilling plans and development of the horizontal wells through the year, is we would look -- we were very positive about where the borrowing base will wind up when we look at it again, which probably will be in August. So we feel very good about it. And some of the issues of having offshore assets maybe go away a little bit when we have more solid PDP reserves onshore.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. So you think that the increased volume base will be sufficient to fund the $125 million CapEx budget for now, right?

Bobby F. Weatherly

Yes we do. We feel very good about that.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then so the options you laid out for additional sources of cash, that's for increased Permian drilling?

Bobby F. Weatherly

Well, yes, we've -- as Gary has described, is that we -- I think we all are very excited and very impressed with the great strides that the operations have made on reducing our drilling base, which reduces cost. And on top of that, the negotiation that Gary was very successful at doing right at year end to reduce significantly our completion cost. And looking at that and our ability to drill wells and as some of this other information in Central and Northern develops, we do have the flexibility to move ahead. And that's really more of what I've said about additional capital resources.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And I guess I'll just ask another one, if common equity is on the table for additional source of cash?

Bobby F. Weatherly

Not at this moment with the plan we have, no.

Operator

Our next question is from Ron Mills of Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Gary, a couple of questions. One, on the Cline, any other information in terms of -- I know you had a cores and then it sounded like you had evaluated the core before drilling that well. How did it meet your bogeys in terms of porosities or pressures or thermal maturity, or at least from your early read?

Gary A. Newberry

Yes, Ron, again, if you remember back the whole model, we kind of correlated all the petrophysical work between Glasscock and Borden County, felt really good about the prospect. The real question was, where were we on the thermal maturity curve? And we knew we were shallower in Borden County and what impact that might have, and we won't know all the answers until we get our full data set back from the core consortium in another 1.5 months. But it's likely mostly attributed to thermal maturity because everything else seemed to correlate quite well from the petrophysical results we got from our vertical well.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And going down to East Bloxom, you talked about shutting in vertical wells as you're going through the completion process off the well pad. Did you also have to shut in some of those vertical wells while you were drilling the horizontal leg, or only during the completion?

Gary A. Newberry

Yes, Ron, when we drill past the vertical well, we actually shut it in while we're drilling past so that we don't take too much risk with lost circulation and potentially loosing that lateral wellbore. But that's only for a matter of a week or so. So that impact is less than the impact that I've mentioned associated with frac-ing a nearby horizontal well. That impact has been significant to us in the first quarter simply because we've had a well from an offset operator frac right next to our lease line and impact several of our lease line wells. So we've since got that back, but it was a bit painful.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And when you have the 3-well pad, you're competing one -- at least one beginning next week. Are they all going to be back-to-back? Or are you going to just do one and then be able to bring the vertical wells back on before you come back in? I'm just trying to get a sense of the timing there. And also, what do you expect to do at Taylor Draw? Are you going to drill all 4 before you begin any completion operations? Or are they going to be staggered?

Gary A. Newberry

Yes, when we do pad drilling, we'll drill all the wells before we do any completion activity, to answer your question about Taylor Draw. And the timing for the completions will accelerate in the last half of the year, primarily because we've still got to build a little bit of infrastructure in order to do them back-to-back-to-back. So just to give you a sense for what's going to happen next week is we're only going to fracture stimulate one Wolfcamp B well. And then we're going to go ahead and bring all those vertical wells back on and -- at least near that well and drill that well out and bring it on. And then about a month later, we will fracture stimulate a second well, and the wells that are along that line will have to shut in just prior to frac-ing and then fracture stimulate and drill that well out. And then it will be actually be 1.5 months before we fracture stimulate the third well, which will be the Wolfcamp A test, sometime in June simply because it's a water-sourcing issue. By the last half of the year, we'll have that all fixed with additional capacity by being able to recycle and recirculate and utilize produced water in our fracture stimulations versus just freshwater deliverability capacity. Now Taylor Draw, just to carry this on a little further so, again, you can get a sense for when we'll frac these wells, we have capacity now to fracture stimulate 2 of the wells back-to-back, and that's what we'll do. And then we'll have to wait about 20 days before we fracture stimulate the other 2, again, because of the water-sourcing capacity. So -- and I'll just clarify one more point about this production delay. It's clear and evident that we're experiencing it at Bloxom, which is a well developed vertical area. We will not experience that when we fracture stimulate at Taylor Draw because that's not a vertically developed area.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay, good. And 2 real quick ones. When you -- Mississippi Lime up in Borden County, you talked about in your presentation having about 74 potential locations. Now that's roughly double what you had talked about 3 or 4 months ago on your conference call. What additional information did you gather to increase your Mississippi Lime locations up there?

Gary A. Newberry

I guess what we've looked at is just additional seismic around porosity development within the chat of the Mississippi Lime, as well as slightly different spacing of the wells, Ron.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then the last one is on Carpe Diem/Pecan Acres area between Diamondback and RSP's horizontal wells. It sounds like you're now, I think, feeling better about the de-risking of that area. At this point, are any horizontal wells included in your 2013 budget for that portion of the play?

Gary A. Newberry

No, we have no wells planned this year. Of course we'd love to be able to get very efficient this first half of the year, focus on what we're going to do in Bloxom and Taylor Draw. And as Bob mentioned, other -- potentially other financial instruments, whatever it might be, to generate more revenue, we might well accelerate that later in the year. But I can tell you, operationally, we're probably 6 months out anyway to do anything to do it very efficiently. To give you a little color on the activity level, there's 3 or 4 wells that have been drilled, and results will be coming out over the next several months. That's either been drilled by RSP or by Diamondback in and around that area that we can get very encouraged with.

Operator

Our next question is from Richard Tullis of Capital One Southcoast.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

A couple of questions. The 2013 guidance, does that already factor in all the vertical well shut-ins that you expect related to the horizontal frac-ing?

Operator

Please hold...

[Technical Difficulty]

Pardon me, I have rejoined the speakers' line.

Gary A. Newberry

I think we were in a question with Richard.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Yes, sorry about that.

Gary A. Newberry

We apologize.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

And these were all going to be easy questions. So the 2013 guidance, it already includes all the vertical well shut-ins that you expect related to the horizontal pad drilling.

Gary A. Newberry

It does, and it does at least to the estimate that we think we'll experience throughout the year. And that will be a -- likely a full year impact, as we've seen at Bloxom. Again, I'll just give you a little bit of color around that. When we drilled -- when we fracture stimulated our first well, it was to the south, center and south on the Eastside, and that's an area that is less dense than vertical wells. So we had minimal impact on our first well that we drilled pre-21. Our second well, going from the center on the west side to the north, which is a more dense area, we actually saw an impact on a couple of our wells and quickly got in and de-watered that area by increasing the pump rates on several wells to mitigate it. And then the more recent impact was, again, from an offset operator frac-ing right next to the lease line that impacted us pretty hard. And it took us about, even though we upsized our pumps and we pumped them harder, it took about 1.5 months to actually get that rate back. So I think we're going at it in the right way by shutting wells in early on, mitigating a little bit the impact of the frac, making certain we quickly accelerate the pump rates to get the water off those vertical wells to return it to production. But yes, to the best of our ability at this point, given the knowledge we've had, we've factored that into our guidance.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay, Gary. And the write-downs at the Haynesville, I know they're not that material, I guess, on a PV-10 basis. But how many PUDs were there associated with that write-down, and what was the average write-down per well?

Gary A. Newberry

From a reserve perspective, we had 7 Bcf a well gross, and there were 3 PUDs. There were 2 right next to the well that we had drilled, and there was one on the opposite edge next to a petro-flex well -- a petro-hub well. And so there were 3.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. And those have been totally written off at this point?

Gary A. Newberry

They have. At the realized gas prices over the last year, there was no way we could make that work.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. I know you mentioned that you may look to do something with Medusa, your interest in Medusa. What's the potential timeline with that? I mean, when could we hear something? How do you think you'd work that?

Fred L. Callon

Richard, this is Fred. I think in terms of Medusa, I think questions come up with the Hab sale. And I think, as we mentioned before, at the right price, we would certainly consider a sale of Medusa. But we don't have a specific timeline. And as we've said before, I mean, it would -- we kind of view Medusa differently than Hab with the behind pipe and the development potential and the 8 wells versus 2 wells. So we don't have a specific timeframe. Again, if we receive the right offer, we'd certainly take and consider it.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. So it's nothing that you're actively working on?

Fred L. Callon

I mean, we -- no, we -- as we've said before, like Hab and Medusa, I mean, periodically, we may have inquiries, and we'll certainly consider those and talk to folks. But until we get an offer that we really think represents some of the value beyond the current production, we feel like it's going to be better to hold on to Medusa and continue to use that cash flow.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. It sounds like the board and -- well, you're going to take some time before you put another update out on that. As far as well news over, say, the next couple of months, what can we expect? Is it wait until the next quarterly update, or you think you'll have something out before then?

Fred L. Callon

I'm thinking it's going to probably be the next update because I was going to say the...

Bobby F. Weatherly

It's 2 months.

Fred L. Callon

Yes, we're looking at like 60 days out. And hopefully, at that point, we'll be able to give you an update on production on all the areas by then.

Operator

[Operator Instructions] And our next question will come from Ron Mills of Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Bob, just to clarify something you had said, I think, in response to Hsulin. Just in terms of your current availability of $55 million under the revolver, plus your anticipated cash flows, do you think that, that is ample to fund the full $125 million? Or do you -- which you should have some borrowing base increases as you bring these -- both the pads at both Bloxom and Taylor Draw on. Do you require some of those borrowing base increases to help fund it?

Bobby F. Weatherly

Well, the availability is actually $65 million, and we had some drawn. I think that's where the $55 million number comes from. But the answer to your question is yes, we feel very good about the PDPs that we're going to be adding to the reserves. And we -- obviously, we've stayed in good contact with the -- Regions is our lead bank, and keep them advised on where we are. And we have not any specific discussions, of course, with them because they really don't have all the data they need. But as you can imagine, we do our own calculations internally, trying to replicate what we believe the borrowing base might be given various combinations of PDP additions. And we feel very good about the fact we can fund the $125 million between the expected cash flow and borrowing base.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Including the anticipated increases?

Bobby F. Weatherly

Yes.

Operator

Having no further questions, this does conclude our question-and-answer session. I would like to turn the conference back over to Mr. Callon for any closing remarks.

Fred L. Callon

Once again, thank you. We do appreciate everyone's calling in. And as always, if you have any questions in the meantime, don't hesitate to give us a call. Thank you so much.

Operator

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

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