Comstock Resources Inc (CRK) 2011 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2011 Comstock Resources earnings conference call. My name is Jeremy, and I'll be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions)

I would now like to turn the conference over to your host for today, Mr. Jay Allison, President and CEO. Please proceed, sir.

Jeremy, thank you, and thank you for all those that are attending the conference call. We changed up the format a little bit. Traditionally we put our results out at the end of the day, and then we would visit with analysts or whatever, and then we would have the conference call the next morning. I think this format may serve us better. We are flying to a conference tomorrow. We'll have 24 meetings on Tuesday/Wednesday, so that's why we changed this format.

I would like to welcome everyone to the Comstock Resources fourth-quarter and year-end 2011 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockResources.com and clicking Presentations. There you'll find a presentation titled Fourth Quarter 2011 Results.

I am Jay Allison, President of Comstock, and with me this morning is Roland Burns, our Chief Financial Officer, and Mark Williams, our VP of Operations. During this call, we will review our 2011 fourth quarter financial and operating results, report on the results of our 2011 drilling program, and discuss our plans and outlooks for 2012.

Please refer to slide 2 in our presentation, and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

The 2011 highlights. Please refer to page 3 of the presentation where we summarize the highlights of 2011. In 2011, we had a very strong production growth, with production increasing 31% over 2010. The successful Haynesville Shale program drove most of the production gains, while the Eagle Ford Shale program is allowing us to increase our oil production, which made up 16% of our production on the last day of the year, as compared to only 4% on the first day of 2011. We had strong growth in our financial results in 2011, despite the 10% drop in natural gas prices, by increasing production and lowering our operating cost.

Revenues in 2011 were up 24% to $434 million, EBITDAX was up 35% to $336 million, and operating cash flow was also up 35%, increasing to $298 million, or $6.25 per share. We had a loss of $33 million in 2011 due to property impairments that we had which totaled $46 million after tax. We had very strong results in our 2011 drilling program. We drilled 87 successful wells, including 62 Haynesville Shale wells and 20 Eagle Ford Shale wells. The drilling program was one of the drivers of our 25% growth in proved reserves that we achieved in 2011. It added 228 Bcfe of new reserves, and increased our proved developed reserves by 170 Bcfe.

We ended 2011 by closing an acquisition that established a new core area in the oil-rich Permian Basin. As we have shifted most of our resources this year to growing our oil production, this acquisition gives us a low risk vertical drilling program to complement our successful Eagle Ford Shale program in South Texas. We also think we're very well positioned to be a significant player in the emerging horizontal Wolfcamp Shale in the Permian Basin.

I'll turn it over to Roland to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. On slide four, we show our oil and gas production on a daily basis, the last four years, and we also separate it by operating region. Production from the Haynesville Shale program on the chart is shown in blue, and now we're showing the contribution from our Eagle Ford program in yellow. In the fourth quarter of this year, our production averaged 277 million cubic feet of natural gas equivalent per day, 48% increase over the fourth quarter of last year, but about 3% lower than production in the third quarter this year. Oil production of 3,800 barrels per day in the fourth quarter was up 78% from the third quarter, and oil now makes up 8% of our total production as compared to only 4% in the previous three quarters.

Eagle Ford averaged 20 million per day in the fourth quarter, as compared to about only 9 million a day in the third quarter of this year. On December 31, we estimated that oil made up 16% of total production, which we put in the press release, when taking into account the Permian properties that we closed on, on December 29.

Our Haynesville production in the quarter decreased to 184 million per day as compared to the 200 million a day we had in the prior quarter because we had very little completion activity in the fourth quarter. Next quarter we expect our Haynesville production to increase as we're completing the 14 wells that we carried over from last year.

Production from our Cotton Valley wells decreased slightly in the quarter to 37 million per day. In the South Texas region, when you exclude the Eagle Ford, also decreased slightly to 29 million per day, and our other regions remained unchanged at 7 million per day.

Looking to this year, we believe production will come in between 106 Bcfe and 110 Bcfe in 2012, which is 11% to 15% higher than 2011's production. More importantly, we estimate that 14% to 16% of 2012's production will be oil, as compared to only 5% in 2011. This will give us stronger revenue growth in 2012 than we had in 2011.

Oil prices continued to be very strong in the fourth quarter, which we cover on slide 5. Our realized average oil price increased 34% in the fourth quarter of 2011 to $100.18 per barrel as compared to $74.75 per barrel in the fourth quarter of 2010. For all of 2011, our average oil price was $95.73, which was 40% higher than our average oil price of $68.35 in 2010. Our realized oil price in the fourth quarter averaged 107% of the average benchmark NYMEX WTI price. Improvements to our Eagle Ford differentials account for this premium to WTI. Our Eagle Ford oil is being priced more on the Louisiana Gulf Coast market than it is to the WTI index prices. As Brent prices and WTI come back closer together, we expect this premium will come down in future quarters.

Natural gas prices continue to slide in the quarter as shown on slide 6. Our average gas price decreased 9% in the fourth quarter to $3.40 per Mcf, as compared to $3.73 in the fourth quarter of 2010. For all of 2011, our average gas price decreased 10% to $3.91 per Mcf, as compared to $4.35 per Mcf in 2010. Our realized gas price is averaging 96% to 97% of the average NYMEX Henry Hub gas price index.

On slide 7, we cover our oil and gas sales. Driven by the 48% production increase, and the higher oil composition, our sales increased 58% to $114 million in the fourth quarter. For all of 2011, our sales increased 24% to $434 million, as compared to $349 million in 2010, as weaker natural gas prices offset some of the 31% production increase we achieved in 2011.

Our earnings before interest, taxes, depreciation, amortization and exploration expense, and other non-cash expenses, or EBITDAX, in the fourth quarter increased by 75% to $90 million, as shown on slide 8. For all of 2011, EBITDAX increased 35% to $336 million.

Slide 9 covers our operating cash flow. Stronger revenues and lower per-unit costs caused our operating cash flow for the quarter to increase 75% to $79 million as compared to the $45 million we had in the fourth quarter of 2010. In 2011, operating cash flow totaled $298 million, which was 35% higher than our cash flow of $220 million in 2010.

On slide 10, we outline our earnings. We reported a net loss of $41.1 million or $0.89 per share as compared to the net loss we had of $20.6 million or $0.45 per share, in the last quarter of 2010. The fourth-quarter results include a $39.5 million after tax impairment charge, which makes up $0.86 of the $0.89 loss in the quarter. We also had a gain of $2.9 million, or $1.9 million after tax, or $0.04 per share, on the sale of our marketable securities. Excluding these items, our loss would have been $0.07 per share this quarter. For the year 2011, we reported a net loss of $33.5 million, or $0.73 per share, as compared to a net loss of $19.6 million, or $0.43 per share, in 2010.

The 2011 annual financial results include several unusual items. A charge of $1.1 million, or $0.7 million after tax, or $0.02 per share, relating to the early redemption of our 2012 senior notes. Impairments of $70.6 million, or $45.9 million after tax, or $1 per share. And a significant gain on the sales of marketable securities of $35.1 million, $22.8 million after tax, or $0.50 per share. Without these items, the net loss for the year would have been $0.21 per share.

On slide 11, we show our lifting cost per Mcfe produced for the last two years, by quarter. Our lifting costs are comprised of three elements -- production taxes, transportation costs, and then other field level operating cost. Our total lifting costs continue to improve, falling to $0.77 per Mcfe this quarter as compared to $1.02 per Mcfe in the fourth quarter of 2010, and $0.79 per Mcfe in the previous quarter. Production taxes this quarter were $0.06 per Mcfe, and our transportation averaged $0.32 this quarter. Field operating costs averaged $0.39 this quarter as compared to $0.71 in the fourth quarter of 2010, and $0.47 in the third quarter of this year. Higher production rates, combined with the absence of the high-cost properties we sold in the fourth quarter of last year, allowed us to achieve the lower lifting rates in 2011. The fourth-quarter lifting rate was also benefited by certain ad valorem tax credits, which lowered the rate by about $0.08 per Mcfe.

On slide 12, we show our cash G&A per Mcfe produced by quarter, excluding stock-based compensation. Our G&A cost decreased to $0.20 per Mcfe in the fourth quarter, as compared to $0.23 per Mcfe in the fourth quarter of 2010, and $0.18 per Mcfe in the previous quarter. The improvement is due to our higher production levels combined with lower cost overall in 2011.

Our depreciation, depletion and amortization per Mcfe produced is shown on slide 13. Our DD&A rate in the fourth quarter increased to $3.07 per Mcfe from our $2.96 rate in the third quarter of 2011, and from the $2.91 rate in the last quarter of 2010. The increase this quarter is due to higher production from our Eagle Ford properties, which have a higher DD&A rate than the Haynesville properties.

On slide 14, we detail our drilling expenditures made in 2011 as compared to 2010. We spent $573 million in 2011 on drilling activities as compared to $399 million that was spent in 2010. We spent $368 million in our East Texas/North Louisiana region, with $203 million in our Eagle Ford program in South Texas, and then just $2 million in our other regions. These amounts do not include the $219 million we spent to acquire proved properties through acquisitions, and the $256 million we spent on purchasing exploratory acreage.

We have a slide on our proved reserves and finding cost on page 15 of the presentation. Our proved reserves at the end of 2011 were estimated at 1.3 Tcfe compared to 1.1 Tcfe at the end of 2010. At the end of the year, our reserves were 85% natural gas, and 15% were oil, as compared to only 2% of our reserves being oil at the end of 2010. We operate 88% of our proved reserve base, and our 2011 drilling program combined with our Permian Basin acquisition allowed us to increase our proved reserve base by 25% in 2011, and also replaced 372% of our 2011 production of 96 Bcfe. The drilling program added 228 Bcfe reserves, with 140 Bcfe of that related to the Haynesville Shale program, and about 10.6 million barrels coming from our Eagle Ford Shale program. We also had a small downward revision of 36 Bcfe off of last year's reserve base.

We spent $573 million on exploration development activities in 2011, and then we spent another $219 million to acquire proved reserves for a total of $792 million, which relate to our 2011 reserve additions. Our finding costs, excluding the amount we spent on exploratory acreage, calculates at $2.23 per Mcfe. Also, our drilling program in 2011 added 170 Bcfe to our proved developed reserves, which increased 15% over proved developed reserves at the end of 2010.

Slide 16 recaps our balance sheet at the end of last year. We had $8 million in cash, and $48 million in marketable securities on-hand, which represent the 1.8 million shares we hold in Stone Energy. We also had a total of $1.2 billion of total debt comprised of $300 million of our 7.75% senior notes, $297 million of our 8.375% senior notes, and $600 million outstanding under our revolving bank credit facility.

On December 29, in connection with the acquisition we made in the Permian Basin, the borrowing base for our bank credit facility was increased to $700 million. $610 million of the borrowing base is based on the value of our producing reserves, and $90 million of the borrowing base is available for one year. At our next redetermination, we expect our borrowing base to increase based on the growth we see in our proved producing reserves since our last bank review. Overall, our net debt made up 51% of our total capitalization at the end of 2011.

Referring to slide 17, we want to point out that we plan to maintain that conservative financial profile, given the extra acquisition debt that is now outstanding. We have plans to sell certain non-core properties this year, including certain oil and gas properties, and our shares of Stone Energy. These divestitures should generate proceeds of $150 million to $190 million to Comstock. We've also implemented a hedging strategy to protect us from a decline in oil prices in the next two years. And as we have shown recently, we will maintain flexibility in what we plan to spend on this year's drilling program. We recently cut back drilling activity to respond to the impact that the lower natural gas prices will have on our 2012 cash flow.

On slide 18, we outline our oil hedge position. We have 4,000 barrels a day hedged at $99.17 per barrel in the first quarter this year. This position increases to 5,000 barrels a day at $99.53 for the next three quarters of the year. In 2013, we currently have 2,000 barrels a day hedged at $100 per barrel. We plan to continue to add to these hedge positions as the year progresses, and we bring on more oil production with our drilling program.

I'll now turn it over to Mark Williams to provide an overview of the recently completed acquisition that we made, and to update you on our operating activities.

Thank you, Roland. On slide 19, we have an updated map of our holdings in the Haynesville Shale play in North Louisiana and in East Texas. You can see our acreage highlighted in blue. We have increased our acreage to 96,000 gross acres, and 82,000 net acres, that we believe are prospective for Haynesville Shale development. With better natural gas prices and expected well spacing of 80 acres, and an expected per well recovery of 6 Bcfe per well, our acreage could have 4.6 Tcfe of resource potential.

On slide 20, we also outline our Bossier Shale acreage. And that basically the same acreage that's prospective for Haynesville is also prospective for the Bossier Shale development, which could add another 2.7 Tcfe of potential, as shown on this slide.

On slide 21 (Company corrected after the conference call), we recap our activity in our East Texas/North Louisiana region for 2011. Our activity in this region was primarily focused on developing our Haynesville and Bossier Shale properties. We drilled 64 wells, 28.3 net, in this region in the six different fields, and all but two were Haynesville or Bossier Shale wells, and all of these wells were successful. We completed 84 wells, or 42.3 net wells, of our Haynesville and Bossier Shale wells in 2011. The wells drilled and completed in 2011 were put on production at an average per-well initial production rate of 10.7 million cubic feet equivalent per day, under our restricted choke program. Since we initiated our Haynesville Shale program in 2008, we have now drilled a total of 180 wells, and 105.6 net wells.

On slide 22, we provide an update of our backlog of uncompleted Haynesville and Bossier Shale wells. We've been talking about this all year, since late 2010, when we had the shortage of frac services. As you can see, in the fourth quarter, the number of uncompleted wells decreased from 21 to 14, while the number of net wells increased slightly from 8.9 to 9.8. And the main reason the net increase is because of our 10-well development project where it's ongoing. Most of the remaining wells are scheduled to be completed in the first quarter of this year. Given the current natural gas price, we plan to move all our rigs out of this region by early March, and focus for the remainder of this year on our Eagle Ford Shale program in South Texas, and our Wolfbone program in West Texas.

Going to slide 23. We're going to discuss our South Texas region. All of our South Texas activity in 2011 has been focused on our Eagle Ford program. We drilled 20 Eagle Ford Shale wells in 2011, 19.2 net wells. We have completed 17 of these wells, and that's 17 net, including a well drilled in 2010, which had an average per-well initial production rate of 820 barrels of oil equivalent per day.

On slide 24, we focus on our Eagle Ford Shale play in South Texas. We increased our holdings in the Eagle Ford in 2011 to 35,000 gross acres and 28,000 net acres. In using a conservative 100-acre spacing assumption, we believe our acreage, which is all in the oil window of the Eagle Ford, has the potential to recover 83 million barrels of oil equivalent net to our interest.

Slide 25 shows the results of the 19 wells which we have completed and which are currently producing. Since our last update in early December, we have completed an additional four wells. The Gloria Wheeler A#1H was drilled to a vertical depth of 11,358 feet, with a 6,725-foot lateral, and was tested at an initial rate of 1,070 barrels of oil per day and 1.1 million cubic feet of natural gas per day, or 1,254 BOE per day. The Gloria Wheeler B#1 was drilled to a vertical depth of 10,908 feet, with a 5,175-foot lateral, and we tested this well at an initial rate of 916 barrels of oil per day and 1.0 million cubic feet of natural gas per day, or 1,085 BOE per day.

The Donnell A#1H was drilled to a vertical depth of 9,404 feet, with a 6,481-foot lateral. This well was tested at an initial rate of 646 barrels of oil per day, and 200 Mcf per day, or 686 BOE per day. The Cutter Creek #2H was drilled to a vertical depth of 10,013 feet, with a 5,541-foot lateral. This well was tested at an initial rate of 471 barrels of oil per day, and 400 Mcf of natural gas per day, or 541 BOE per day. And as we have stated before, all these reported well results were obtained while following our restricted choke program where we managed the choke size and the pressure to improve our EURs.

I'll turn this over to Jay to discuss our -- he wants me to talk about it. Okay. So, next is on slide 26, we're going to discuss -- we closed on the acquisition of the properties in Reeves County in West Texas from Eagle Oil and Gas, and certain of their partners, on December 29. We acquired 70,000 gross acres and 44,000 net acres in Reeves County, Texas in the Delaware Basin prospective for the Bone Spring Wolfcamp development, which we and everybody else are calling the Wolfbone play. The acquisition included 35 producing wells, 22.4 net wells, and 4 wells that were in the process of being completed, or 2.5 net wells to be completed. Current net production is around 1,300 BOE per day.

The final adjusted purchase price was $345.5 million. We allocated $201.7 million to the 25,200 MBOE of proved reserves we acquired, and $143.8 million to exploration acreage -- undeveloped acreage. We estimate that these properties have total resource potential of 178 million barrels of oil equivalent based on drilling 935 net vertical wells, and we strongly feel there's additional upside in this acreage with horizontal development.

Slide 27 is a subsurface topographic view of our Wolfcamp formation, with Comstock acreage shown in yellow. As you can see, the Eagle acreage is located in the bottom of the Delaware Basin on the west side of the Permian Basin, which is the optimal location for the basin-centered hydrocarbons that we are targeting in the Wolfbone. The primary Wolfbone section runs from about 10,000 feet to 11,500 feet in depth. Also shown here on the east side of the Permian Basin, in the Midland Basin, is our Gaines County exploration acreage, which is located in the deeper part of the Midland Basin, again, in the lower part of the basin where it's optimal for basin-centered hydrocarbons. We currently own about 11,000 net acres in this exploration play, and we'll be targeting the Wolfcamp Shale at a depth of 10,000 to 11,000 feet.

Slide 28 shows a geologic cross section from the Delaware Basin in the west to the Midland Basin in the east. The Wolfbone in the Delaware Basin to the west and is an emerging resource play, and that's where our acreage is located. As you can see, it is equivalent to the Wolfberry play in the Midland Basin, which is the Spraberry and Wolfcamp Shales, and this play is very active with significant vertical and horizontal development.

On slide 29, we show Comstock's Permian Basin acreage position with 90,000 gross acres and 55,000 net acres under lease. As I previously stated, the Reeves County acreage provides over 900 net vertical locations targeting the Wolfbone, with 178 million barrels equivalent of resource potential. There is also horizontal development potential in the Bone Spring and Wolfcamp formations on the Reeves County acreage. Now, our Gaines County acreage to the northeast is primarily targeting the Wolfcamp Shale, and we expect this to be a horizontal play, but we plan to drill a vertical well first to test this section and acquire as much information as possible.

Slide 30 shows the calculated ultimate recoveries of recently drilled wells in the Wolfbone play in and around our acreage. As you can see, our acreage has been largely derisked, and the results shown bracket our expected average EUR of just over 200,000 BOE per well. And this was one of the key reasons we liked and targeted this acquisition, because it was largely derisked.

Slide 31 illustrates our 2012 drilling plans for Reeves County. The current wells are shown in yellow, and the 2012 scheduled wells are shown in red. We plan to drill 43 gross wells and 33 net wells in 2012 on our Reeves County acreage. Drilling and completion costs should range between $4 million and $4.5 million, and our expected EURs are in the range of 180,000 BOE to 250,000 BOE per well, with 30-day IPs expected to be 150 BOE to 300 BOE per day. As I said before, we are primarily targeting vertical Wolfbone completions at this time at a depth of 10,000 feet to 11,500 feet.

Okay, slide 32. What I want to leave you with is where we think the Wolfbone play is going. On this slide, the various potential oil targets in Reeves County are shown on the left. Primarily for us, it's the Bone Spring and the Wolfcamp section. Also shown are the potential completion types that we anticipate will be prospective on our acreage. On the left side is a conventional vertical Wolfbone well showing the primary 1,500 feet of completion interval in green -- with the little green boxes where the completions would be. And an additional 1,000 feet to 1,500 feet of completion potential in the Upper Bone Spring, shown with the little red boxes.

In addition to that, we believe there are several horizontal targets in the Bone Spring and Wolfcamp that may significantly improve the economics of this play. We have one horizontal Wolfcamp well scheduled this year, and other operators in the area are actively pursuing horizontal opportunities in both the Bone Spring and the Wolfcamp. The horizontal aspect of this play is just emerging, so there's much science to be applied before it can be verified, but we are very excited to have such a prime position in this basin.

Now I'll turn it over to -- back to Roland to go over our 2012 drilling program.

All right. Thanks, Mark. On slide 33, we outline what we expect to spend in 2012 on our drilling program. So, as Mark said with the continued weakness of natural gas prices, which have worsened in January compared to where we thought they were in December, we did recently re-evaluate our drilling plans in 2012 to further de-emphasize natural gas drilling and to reduce the overall drilling expenditures that we're going to incur in 2012. So we're now down to two rigs drilling for natural gas in North Louisiana as compared to the seven operated rigs we were running in 2010. Last year, we moved two of these rigs to our oil-focused Eagle Ford Shale drilling program, and we also released three rigs. We plan to move the remaining two natural gas directed rigs to our Permian properties in February, and then also in early March of this year. Our revised drilling plans now call for us to spend approximately $458 million in 2012, which would draw 84 wells, or 60.6 net wells, as well as complete an additional 29 wells, or 19.1 net wells, that we drilled in 2011.

We'll spend $158.3 million to drill the 43 wells, or 38.8 net wells that Mark talked about on our Delaware basin properties in West Texas, and then we'll also complete the 4 wells, or the 2.5 net wells that were drilled before we completed the acquisition. We'll spend $165.2 million in our South Texas region to drill 24 wells, or 21.7 net wells, in our Eagle Ford Shale horizontal program in 2012, and $27.7 million to complete the 4 wells, or 3.2 net wells, that we drilled in 2011 in South Texas.

In the East Texas/North Louisiana operating region, we'll spend the remaining $45.4 million to drill 17 wells, but this is only 5.1 net wells, and all of these will be Haynesville or Bossier Shale wells. Only three of these wells are operated wells that Comstock is drilling, but the remaining of the net wells being just estimated wells that we think will be drilled by our other operators where we have a small interest in the units.

Our largest expenditure in this region will be the $61.4 million that we're spending here, mostly in the first quarter to complete the wells that we drilled in 2011. So, under the revised 2012 drilling plan that we put forward here in our press release we did a week or so ago, 92% of the net wells that we're going to drill in 2012 will be oil wells, and then 77% of our budget will be spent on oil projects.

Now, I'm going to turn it back over to Jay to summarize our results.

If you look at the 2012 outlook, and again, Mark, thanks for going over again the transformational event that we've had in the acquisition of the Permian and also the Eagle Ford. But again, if you look at catalysts for transformational events, I think toward the end of last year we demonstrated that we had those. If you kind of take a capsule of 2011 in a paragraph before you get to 2012, 2011 is history for the most part. In 2011, we had very strong production growth, 31% over 2010, very strong oil production growth, which made up 16% of oil production at year-end 2011 versus only 4% on the first day of 2011. We had strong growth in our financial results, as Roland told you, we increased production, we lowered our operating costs. Revenues were up 24%, EBITDAX up 35%, operating cash flow's up 35%, we had 25% production growth proved reserves, and our total cost structure continued to be among the lowest of the E&P sector. So, now that that is for the most part history, what about 2012? Where are we?

If you look at slide 34, despite the dismal outlook, which we're aware of for natural gas prices with a very warm winter we're having, we're more excited than we've ever been about the prospects for Comstock this year, 2012. We expect the strong growth in our oil production will be more than offset, the lower natural gas prices to allow us to have higher revenues and cash flow, and be a much more profitable company in 2012. We expect oil to comprise 14% to 16% of 2012's production, and over 20% of production at the end of the year. Oil now makes up 15% of our proved reserve base, as compared to only 2% at the end of 2010. 92% of the net wells we'll drill in 2012 will be oil wells, and 77% of our budget will be spent on oil projects.

We expect our total production to grow by 11% to 15% this year, while all of the growth coming exclusively from higher return oil drilling. Our Eagle Ford Shale program will be our largest growth engine this year in 2012. The recently completed Permian acquisition established a new core area for us, which is focused on oil, and it adds a low-risk vertical oil-focused drilling program. We see tremendous upside in future horizontal development in the emerging Wolfcamp Shale.

We continue to have one of the lowest overall cost structures in the industry. We plan on maintaining a conservative financial profile, as Roland told you, to improve our liquidity post the Permian acquisition, which was in December. We will reduce leverage this year with the asset divestitures that we have underway, and we'll utilize an oil pricing strategy, hedging strategy to protect the acquisition of our oil-focused drilling program.

For the rest of the call, I'll take questions only from the research analysts who follow the stock. So, Jeremy, we'll turn it back over to you for Q&A.

(Operator Instructions)

Our first question comes from the line of Brian Corales with Howard Weil. Please proceed.

Good afternoon, guys. And good quarter.

Hi, Brian.

How are you? One quick question, the drilling budget, do you all have a budget for what's not drilling? I mean, any lease hold estimates or -- for 2012?

Yes, this is Roland, Brian. We really don't expect to spend any significant amount for leases in 2012. We've really -- we did a lot of that in 2011, really have a lot of stuff on our plate, so we have no leases expiring in 2012 so it's --.

Okay, so that's a total budget, the $458 million?

Right.

Yes, Brian, I think if you look at the Haynesville Bossier, we have say 140,000 net acres which 82,000 of that is Haynesville and 58,000 is Bossier and it's overlapping. We've got the 7.3 Tcfe of upside there as far as reserve potential. We'll drill three net wells this year that we operate and that's it. Come March, we won't have any wells drilling for gas, and all that will be held for 2012. And maybe we have to drill a couple wells in 2013 for that 140,000 net acres. So in order to hold acreage, it's a very nominal program this year and next year. So we've kind of inventoried that. We've put all that on the shelf.

So now what do you do? Well, you have to have a couple rigs drilling for oil in the Eagle Ford which we've got two rigs now. If we could ramp up to three or four, that would be good. But in our budget we have two rigs and that answers your question. That will hold that acreage. And I think in the Permian we've got two rigs now. We'll add a third and then a fourth, and I think as the years go by, we'll ramp that up to maybe a six-rig, seven-rig program. But in order to hold acreage, the rigs that we've told you we would use to drill wells in those three basins this year completely satisfies all of our 2012 obligations.

Okay. Thanks. And the 10 well pad that -- in the Haynesville, when do you all -- is that online or is that about to come online? When should that come online?

Brian, this is Mark. We have -- all the wells have been fraced. One of them is flowing back, cleaning up. The other nine, we're in the process of drilling out the frac plugs. So we expect those to start coming online over the next week and a half, two weeks to start cleaning them up.

Okay. And then one final question. Looking at the Eagle Ford, I mean, it looks like that central McMullen acreage that you have has been very, very impressive with the rates. What are you all seeing kind of from Northern McMullen, or even as you get north of McMullen versus the central portion? What are you all seeing? Is there a cost difference? Is the rock not as good? What is the difference between that acreage?

Brian, generally as you go from north to south over here, you get a little improvement in rock quality, but it's really a pressure difference. The wells to the south, the Swenson, the Hill, the Gloria Wheeler wells, they have more reservoir pressure, a little more energy so you get a higher IP. What we have seen on our production declines, though, is even the wells kind of in the middle, the Cutter Creek, the Carlson, the Donnell, they don't IP as high but they EUR almost as high as the wells to the south. So you get about the same amount of oil out. You just don't get it out quite as fast. And so that's really the difference as you go from north to south.

And if you had to take an over-under on that 400,000 EUR, what would you estimate?

For us, I think on a weighted average, it's over. We feel that's a good, conservative weighted average type curve. But everything so far we look at on our wells has been meeting or exceeding our type curves.

I think to the south, Brian, you're going to get the plus 400,000, to the north you might get a little less than that. But I don't know that you'd get that much less. Mainly because of what Mark had said. You have a higher IP to the south, but your decline rate's a little steeper to the south than it is to the north.

Right. Okay. Thanks so much, guys.

Thank you, Brian.

Our next question comes from Ron Mills with Johnson Rice. Please proceed.

Hey, guys. Question on the Permian. The two rigs are currently drilling the Wolfbone, I assume. Is the plan to take the other two rigs to -- and just drill Wolfbone as well? And at what point do you think you'll start to -- when do you think you'll drill your horizontal Wolfcamp?

Ron, it's Mark. The other two rigs that we're moving from the Haynesville, one of them is in the process of rigging up in West Texas. The other one will move in about, about the first of March. And they are all scheduled to drill vertical Wolfbone's this well, except right now we have one horizontal well scheduled in the second quarter. And then we're going to look at those results and we're doing a lot of science, micro seismic, coring, additional logging, some modeling. And so as we gain this information, we'll build our horizontal program kind of out of our vertical program, but we just aren't quite ready to, science-wise, to do that yet.

And when you look at the offset operator activity and with the prior drilling programs and your 2012 plans, it looks like almost all your acreage is going to be derisked from the Wolfbone standpoint. Have any of the offset operators started testing the horizontal Wolfcamp offsetting you in Reeves?

Not in our immediate area. There's activity just across the river in Ward County. It's mostly third Bone Spring. But that's right at the top of the Wolfcamp and we think that's really Wolfcamp fracing. Also to the northwest of us, kind of along around our farthest northwest acreage, Petrohawk is very active. They just started. We don't have any results from that yet. I think they're testing various intervals in the section. Several of the other independent operators around us are talking about doing this but nobody's drilled one yet. They're really vertical players and they're just not -- they're going to step out into it here shortly, but they haven't done it yet.

Okay. And can you refresh our memory in terms of what agreements you have in place from a completion standpoint, both for the Eagle Ford and the Permian and the status of those contracts? Just given all the talk on pressure pumping prices coming down, what kind of outlook do you have on that cost side?

On the Eagle Ford, we used our Haynesville crew and we made a deal to rotate that crew back and forth to cover the Eagle Ford and the Haynesville. And so that contract is for this year, it actually runs out in June, at the end of June with Schlumberger. It adjusts quarterly to market conditions.

In West Texas we don't have a contract signed yet. We're working on building our schedule. We've talked to various service providers. I'm very encouraged. There's more interest and capacity than we even thought there might be out there. Seemed like we've got a good number of providers that are very interested in the work at this point.

And in terms of overall savings and in terms of a well cost in the Eagle Ford, what do you expect potential savings on the drill cost to be?

As far as just going forward?

Going forward, right.

Right.

Given the pricing pressure.

We think we can get 10% to 20% of our frac cost going forward as more people move their crews down there and that supply outruns the demand. And then one of the largest savings for us is going to be when we really go to pad drilling, to full development. We've seen savings in the $0.5 million to $1 million per well range in our Haynesville, and we expect those same types of savings to occur in the Eagle Ford.

What are you expecting your typical -- what is your typical Eagle Ford well costing right now?

They're around $8.5 million now. So in development mode I think we're looking at in the $7.5 million range.

Okay. Then Roland, you mentioned the pricing differentials, or the oil realizations for your Eagle Ford production. Are you selling all of that on spot? Sounds like you're getting Gulf Coast pricing. Do you have marketing arrangements in place? And prospectively, how much -- do you think it can come back to where you've been averaging 100%, 101% of WTI? Or do you think it will be somewhere between that and 107% that you had there in the fourth quarter?

Well, I think the pricing in the Eagle Ford is going to be, in the future, is going to be more tied to Gulf Coast, Louisiana, Gulf Coast type pricing because that's where the oil is all going and that's where the new marketing arrangements will be. Now the relationship of those index prices to WTI is all based on what happens with those indexes. They've tightened up a lot from the huge disconnect they had in especially early fourth quarter. So if that trend continues and they don't separate back apart, we would expect our Eagle Ford oil production to still be a little premium to WTI, but maybe not as large as the $6 per barrel type premium we were getting in the fourth quarter.

Okay. Great. Thanks, guys.

Thank you, Ron. Ron, as far as service completion providers, we are working with our service provider in the Eagle Ford to maybe come down and do some wells, if not a lot of wells in the Permian. That relationship carries to a different region too, as you know.

Our next question comes from Kim Pacanovsky with MLV and Company. Please proceed.

Hi, good afternoon, everybody.

Hi, Kim.

Hi. How many wells do you have 90-day rates on now in the Eagle Ford?

Gosh, Kim, probably about 10 or 12, but I don't have 90-day rates in front of me.

Okay. And I'm just curious if they came in where you had anticipated, and if you take the Jupe out of the picture, what your lowest IRR at a $90 price, or $100 price is, whatever number you might happen to have, if you have a number like that off the top of your head?

I really don't, Kim. Yes, I don't have what the -- I'm sure that our NWR well would be our lowest IRR, but I don't have that number in front of me.

Okay. Could I get that later after the call, just curious? I'm just curious what the worst well is as we look at the acreage.

Let's talk about the best well, Kim.

(laughter) Sorry.

Kim, we'll get that to you. That's a great question.

Okay. And then --

$100 oil plus the premium makes a lot of them pretty good.

Yes, I'm sure. And then in Gaines County, in the exploration program there, can you just detail a time line of what you're going to do when there? And also what other operators are near you? And how far away, and what kind of results they've seen?

Kim, as far as other operators, this is really a little exploration play and there's barely any activity in the near vicinity of us. All the activity would be Wolfberry, but it would be 10 miles to 20 miles to the south.

Okay.

And so it's really an exploration play based on log properties and our knowledge of what we like to see in a shale play.

Okay. And when will you be drilling your first well there?

We haven't finalized anything. We may discuss drilling one this year in place of one of our Reeves County wells, but we don't need to with all these -- all these leases are really fresh, and so we don't know that we really need to go over there and drill one. We've got a big (inaudible) we want to talk about a deal with and kind of run the gamut on making sure we own all the leases that we want to own before we go forward with drilling.

Okay. And what's your tolerance for hedging? I was pleased to see some of these oil hedges coming in. How, how high of a percentage of the oil production do you think that you're going to hedge if you have opportunities for attractive prices?

Kim, this is Roland. I think we'll be hedging between 50% to 75% of our oil volumes going forward.

Okay.

And --

Wow, this is like the new you.

Well, you know we, our, if you look at our 2012 business plan, we're most vulnerable to oil prices falling off.

Absolutely.

People would think -- they think it's gas prices, but gas prices are already bad. We're not drilling hardly any gas wells. And they have a more limited impact, gas prices, I think will come back in the long run, but for oil prices to drop and we made a large oil acquisition and have the Eagle Ford program. So we definitely want to protect that part and let that part of the Company grow. We're seeing just, with current prices out there now, oil will make up 50% of our entire revenues this year. That's a very dramatic change from when it only made up -- 2011, it was only 18% of our revenues.

Yes.

The future for the Company, the next two years, while gas is out of balance, is oil and we'll aggressively protect it. Especially when we can lock in this near $100 plus area because that's very strong returns.

Right.

For all of our programs, even the -- maybe even the far north Eagle Ford wells, would be very good at these kind of prices.

Okay. Alright. Well, that's great. What is the current Eagle Ford production running today? Do you have a number on that? I didn't hear it, unless I missed it.

Kim, gross it's about 6 or -- between 6,000 barrels and 7,000 barrels per day.

Okay.

So, if you take about --.

Between 5,000 and 6,000.

Yes, 75% of that to get closer to our net. Yes.

Okay. Super. Thanks.

Thank you, Kim. I think you'll be pleased with this IRR at $90 when we get that for the 10 to 12 Eagle Ford wells that have been producing for 90 days. And on the Gaines County, again over a year ago we had been acquiring acreage in Gaines County and then once we were able to acquire the bigger footprint in the Permian, we disclosed that we had added the Gaines County. And then if you look at our balance sheet, what we're trying not to do is overspend our operating cash flow, plus the divestitures that we'll have this year. That's why when you asked Mark we may drill a well in Gaines County, those leases are new. They're three plus year leases. So we don't have to drill any wells this year in Gaines. It would be nice if we could drill one or two that would be vertical wells, and then like Mark said you can -- there's a little bit of science to that. But there is a big mineral owner. The big mineral owner would participate and maybe we could have a pretty good program there.

But our goal is to continue to stay financially sound, as you know. And then as far as the hedging, your comment, we always try to hedge if we have a big acquisition and a $340 million some odd acquisition in the Permian, even though it was 1,300 plus barrels of net oil a day, that's a big acquisition. So, hopefully you can see that we demonstrate that to protect that acquisition and even to make the acreage a little more valuable to the north in the Eagle Ford, we go ahead and put these hedges in. If oil stays up and our oil production continues to grow, which we expect, then we'll continue to add hedges on. So hopefully they'll give the market some comfort in what we're doing.

And our next question comes from Dan McSpirit with BMO Capital Markets. Please proceed.

Gentlemen, good morning, or good afternoon.

Hi, Dan.

Just referring to slide 31 in your corporate presentation in today's presentation, which illustrates the locations of wells you'll drill this year in Reeves County, I notice the two northernmost wells that may be off a little bit outside the concentrated area. Any thoughts on what your expectations are for those two wells and the amount of surrounding acreage involved in those, or approximate to those two wells? And maybe the timing of those results?

Dan, I'm not really sure when those two wells are scheduled. I'll tell you they're sometime this year, but I'm not going to guarantee when. As far as expected results, we haven't seen much change in rock properties going north, looking at logs and other activity. So we really expect them to perform very similarly to the other acreage that we have.

Okay. And then staying in Reeves County, what development spacing will you test this year?

We really don't have any plans this year to test a development spacing. Our drilling program in Reeves is focused on maintaining our lease schedule. And so it's really -- you can look at it. It's really spread out.

Okay. Very good. And then just turning to the subject of natural gas. Maybe one that all would like to forget, I guess, but if we look at 12-month strip pricing today it's closer to $3 per MMBtu versus, say, $4 per MMBtu. What might that mean for reserve bookings going forward as much of your proved reserves are still weighted toward natural gas? And any thoughts on what impact that might have on your redetermination regarding your own bank borrowing base, and how that might be offset by reserve bookings associated with oil and your liquids assets?

Well, I think that, Dan, if you're looking at especially SEC reserves the way that that's calculated kind of a 12 month kind of historical price, that if those low prices stay in effect, I think that the undeveloped gas reserves will be the most challenged to still be economic. I think that the positives are that we've seen some big reductions in total development costs for those type reserves, that may help them stay economic as the price maybe moves down on the SEC side. But a lot of the -- of course, it doesn't really have any impact on the developed producing reserves because the lifting costs are so low on those type properties.

Okay. Great. And then two -- quickly, two modeling questions here. I notice that LOE lifting costs continue to trend lower, at least on a per unit basis. What should we expect over the next, say, 12 months, 18 months as more oil and liquids hit the P&L?

The -- we'll see especially production taxes which is where the oil has a much higher production tax rate on a unit of production because a lot of our natural gas qualifies for some exemptions or relief for tight gas in Texas and Louisiana, and oil does not. So we do expect to see our lifting cost rates which have dropped below in this quarter, below $0.80 per Mcfe, trend up a little bit, more so in the second half of 2012 because in the first half we still have some growth in the gas side that will come through. So in the second half of 2012, we would expect to be averaging for all-in lifting costs which we would count production taxes, the direct field cost and transportation, will be a little over -- potentially a little over $1 or so per Mcfe in the second half of the year with most of that change coming in the production tax side.

Right. Okay. Great. And then one last one. Turning to the Eagle Ford and the EUR of 400 MBOE, what is the B factor behind that cumulative production estimate?

Dan, I believe it's about 1.2. I didn't run those [numbers], but I'm pretty sure it's -- the B factor is around 1.2. 1.1 or 1.2.

Very good. Thank you.

Thank you, Dan.

Our next question comes from Jack Aydin with KeyBanc Capital Markets. Please proceed.

Hey, guys. Most of my questions are answered. Thank you.

Thank you, Jack.

(Operator Instructions)

Our next question comes from Leo Mariani with RBC. Please proceed.

Hey, guys. In the Delaware Basin, obviously you guys announced the acquisition a couple months back. Have you guys not had any completed wells during the last couple months?

Leo, we got two but they just -- they're still flowing back and they haven't IP'd yet.

Okay.

We really took it over December 29, 2011.

We closed on the 29th.

So we had two -- we have two we fraced late in January but they're just not cleaned up and flowing fully.

Leo, it takes about 30 days to drill one of these wells. They're vertical. You'll go down to, again, the pay goes anywhere from 10,000 to 11,500 feet, and then you probably have 10 days to mope time. So we're saying from well to well it's about 40 days to 45 days, that's spud to spud. We closed this on the 29th. Took it over. We kept the two rigs. In fact, we changed out one of the two rigs and we'll move again a third rig in and a fourth rig in, in the next couple months, and we've completed the two. That's all we could do in the 35 days or so.

Okay. And in terms of your oil percentage, you guys talked about 14% to 16% oil in 2012. And then you guys also said that your year-end '11 percentage was around 16% oil. Can you just kind of walk us through the math there? I guess I thought maybe it would be a little higher on average this year.

I think, Leo, this is Roland, in the fourth quarter, our gas production was down a little bit and we had a lot of -- of course, made an acquisition of the 29th and had some new Eagle Ford wells coming on in late December. So I think that that number was the actual number on that day, but then as the gas production grows some in the next two quarters, it will just push that percentage down based on that. But now the second half of the year when gas is no longer growing, that's when the oil percentage of the Company probably starts to exceed that number.

Okay.

It's all relative, on kind of how you're measuring it.

Yes the second quarter this year will probably be our big production for gas.

Right. It will be peaking -- it hasn't peaked yet, so that's the --.

Okay. And in terms of Eagle Ford, you guys talked about 24 wells this year in your program. How many of those are going to be on pad drilling?

Really not any. If we have a pad it's only because we're drilling in opposite directions. We have -- I think there's 3 of those pads, so there's 6 of the wells of the 24 that we're drilling, 2 different units and obviously directions from one location. But we're not doing any what I'd call development where you're drilling multiple wells in the same unit from one pad.

We're using the two rigs, Leo, this year just to hold acreage.

Okay. And then I guess you guys talked about $8.5 million current well costs, but then you said you thought you would average closer to $7.5 million, but it doesn't sound like you're doing a lot here on pads which seem like the bulk of the savings. So, really, is most of the savings you expect this year, then, just going to be from lower service costs?

Lower service cost and improved efficiency. But really that's more of an all-in average well from here to the end of the program. When we get them all drilled it's going to be more like that.

Okay. And in terms of the Wolfcamp, you guys obviously want to drill a horizontal well here in the Delaware Basin. What's got you particularly excited about that? I guess you said that there weren't really any offset wells nearby that you guys are aware of. So why is that a high priority for you here?

Leo, when we looked at this deal, the first thing we saw were multiple shale intervals that looked very appealing for horizontal development. They have the rock properties, the porosity, the thickness, the continuity that would be similar to our Haynesville or our Eagle Ford. And we saw more than one. So we say, wow, that -- this needs to be developed as a horizontal play. It just hasn't been done yet because the players that were in the area were vertical players and they were being successful drilling the wells vertically. It's also much easier to put your units together, to stay ahead of your lease schedule doing vertical wells than it is horizontal wells. So we'll still have a lot of that holding our acreage and testing areas.

You can't develop the whole vertical section with a horizontal lateral. So we'll still have the need for a lot of vertical wells also, but as soon as we get our comfort factor on which interval we want to target, then we do plan on ramping up the horizontal program.

Okay. And what do you think a well cost would be there?

Construction-wise it's going to be very similar to the Eagle Ford. It will take a little bit longer to drill, but some of the other costs like surface locations and other things like that are going to be less expensive. So I think it's going to be very similar to our Eagle Ford cost.

All right, and I guess lastly, what's the timing on your asset sale program here?

Leo, this is Roland. We expect to complete most of these asset sales by early second quarter.

Okay. Thanks, guys.

Thanks, Leo.

Our next question comes from John Freeman with Raymond James. Please proceed.

Good afternoon, guys.

Hi, John.

The only questions I had on the -- in the Eagle Ford, the -- I believe the only area that you all haven't drilled on yet of your acreage is that southeastern portion of Atascosa. Is there any plans to drill that this year?

We have drilled one well, John, and we haven't completed yet and I think we have six more scheduled to drill there in 2012.

Okay. Great. And then just a last question I had, in that central McMullen area where you all had really strong results, can you remind me what's the acreage number there?

I think, John, we have about 8,000 acres in that area.

8,000 acres. Great. Thanks a lot, guys.

Thank you, John.

Our next question comes from Michael Hall with Robert W. Baird. Please proceed.

Thanks, guys. Just a couple quick, quick follow-ups. I guess first in the Eagle Ford, I'm just curious a little more detail maybe on the restrictive rate program, how hard you're choking those back? And also just what sort of variance and pressures you're seeing across north to south, but particularly as it relates to the decline curves. Are you seeing meaningfully different decline curves from north to south? I guess what are your thoughts on that?

As far as the choke back program, we have a very standard program now so we can compare well to well. They flow them on a certain size choke for a certain number of hours or days and we end up on a 16 inch choke. We're not going above a 16/64 inch choke.

Okay.

So I don't have the exact schedule with me. Our engineers worked it up. And that's how we're doing it. We're very pleased with the result. We still only have one well on artificial lift and we think that's part of the reason that we've been so successful flowing these wells naturally is because we don't pull them real hard.

As far as pressures go, on the very north end, the Donnell and the Carlson, they all flow. They'll come down to about 2,000 pounds pretty quickly. And on the south end in the Hill and the Gloria Wheelers, those wells are between 3,500 and 4,000 pounds initially. And then they'll just slowly decline from there.

Okay.

Decline curves, I think we're using five different decline curves.

Okay.

Or type curves, depending on which acreage. But they're not that different. I mean, like I said the EURs are pretty similar, maybe ranging from 375,000 up to 450,000. It's almost surprising to me even that these lower IP wells do so well, but they do. They, they -- and then typically, they're trending above our type curves.

That's helpful. Thanks. And I guess just follow up a little bit on Leo's question, on the cost front, I mean it seems like also just on those uncompleted wells you had, what, 3.2 wells net, looks like $28 million-ish. It's quite a bit per well. Is there something going on in those particular wells? I guess why are the completions running so high?

I think what happens is there's never a great cutoff between years between the budgets and with all the rigs down to a stop on December 31, and it's all ongoing. So -- and capturing when a well is actually counted is -- that accounts for those differences. So looking at them on a per well number is not really that meaningful.

Okay.

So --

How many do you expect to have completed and tied in in 2012 I guess in the Eagle Ford then? Tied in to sales.

What do we have, 19 on our list so far and then we're going to drill 24 and we should have all but maybe three of those completed and tied in.

Okay.

So that's about 40. About 40 producing by year end.

Especially now that we're not -- before we were -- we were using the same completion crew in the Haynesville and the Eagle Ford program, and I think that caused kind of some wells to stack up in both programs, kind of waiting for the opportune time to move back and forth. With the Haynesville program wrapping up, I think we'll see the Eagle Ford wells completed more closely after they're drilled and going forward. So like Mark said we'll complete most of the wells drilled in 2012 in '12 plus any carryover from 2011.

Remember, the Schlumberger swing crew, they've been out of the Eagle Ford, they've been over at the Haynesville/Bossier completing the 9 or 10 wells there. They'll swing back over this month and then they'll start completing these Eagle Ford wells and I think your numbers will be a little better.

That makes sense. And I guess the only last thing I had, I'm just curious, as you look at your portfolio as a whole now you've got clearly some good options on the oil front. Might be a ways off, not on everyone's radar, but I guess what price would get you to start swinging capital back towards gas? I mean, we know kind of where the Haynesville maybe becomes economic. But I'm assuming there's some price above and beyond that to actually bring capital away from your oil projects at this point. Any thoughts on that or any --?

I think first, we, we're committed to maintaining a conservative financial profile. We need to see where we are in our balance sheet, our debt to cap needs to be reduced. We need to monetize some of the Stone shares, and we need to divest of some non-core properties. Then we need, I think in 2012, we need to, to really understand the value of the Permian that we bought including a horizontal well or so. I think, our value from the two oil plays will materially increase in 2012 so then let's just say you have $85, $90, $95, $100 oil, I mean Boone Pickins said $300, $300 per barrel. Who knows? It's just insanity out there.

Sure.

But let's just say you have a $80, $90, $100 oil price, I mean, if we've got programs going into Eagle Ford that are successful and we've got programs going in the Delaware Basin that are successful --.

Yes.

We've got over 900 vertical locations plus you may be drilling these wells on 20s and 10s and who knows. I mean, the single most active basin in North America is the Permian Basin. It doesn't get the most visibility, but it definitely is the most active.

So I think if those basins are working, which they should and they have --.

Yes.

In order for us to start a -- even though I think we're one of the lowest, if not the lowest producer of dry gas, that's the deal dry gas in North America which is the Haynesville, because the acreage that we captured, I think you'd have to look at a $5 plus gas price for us to even materially start looking at adding rigs and drilling in that area. It's all, it's all going to be based upon where oil prices are, what kind of hedging program we have in, what kind of rate of return we get in, and on an annual basis, the reservoir group comes in, the G&G group comes in, Mark comes in as VP of Operations, Roland runs the numbers and we say well, here's our inventory of prospects in all three major regions, where can we get the highest rate of return with the least amount of risk. And that's how we come up with our programs.

We're very clear to the point that sometimes we literally are shorted to death because we're so transparent. We say we're really a natural gas Company. We're in a Tier 1 area in the Haynesville and the Bossier. We really want to stay there. Had we been Tier 2 I think we would have left the Haynesville/Bossier a little earlier, but we were committed to creating value there. And we did. And you can see the production growth. You can see the profile. Even, I know Dan McSpirit asked about some upside reserve, proved undeveloped reserves. Well, I think that we probably have reduced our cost to drill and complete the Haynesville/Bossier by at least $1 million, so I think we'll preserve those. We'll have to see what the commodity price is.

But we look at all that. And now we're committed, kind of like we announced at Thanksgiving, we said well, we've been looking -- and we advertised this -- we've been looking to add another core oil basin. We said within our core area, we didn't say where. And that was the Gaines County acreage. We kept adding, adding, adding, but we were looking. Then all of a sudden the Permian acquisition came up. We didn't know that we would be the owner of that. We're very pleased that we are.

And now that we've turned the corner and we've got a catalyst and we have made a transformational move of Comstock in 2012, what are we telling you we're doing? Well, we're going to inventory our gas properties. Fortunately, we've been so fortunate, we don't have any production payments that we have to honor. We don't have any JV partners that we have to honor. Those are things that we've got flexibility. Flexibility is a key thing if you're in a horrible gas market.

Yes.

So we're there. So what are we doing? I mean, we're pulling in our gas program, materially. We'll have zero rigs that we operate after March.

Alright.

And we're going to focus. You put your money where your mouth is. So where are we putting our money? 92% of all the wells we'll drill this year are oil. That's where we're putting it.

Yes.

And I think we'll turn the corner. I think we're going to have stellar results. It's a gauntlet. We're getting beat up, but we're doing it with clarity. We're telling you what we're doing.

Great. I appreciate that color. I was more curious, big picture, as it relates to the gas market as a whole. So appreciate that color. Thank you.

Thank you.

And our next question comes from John Seltzer with IB Capital Partners. Please proceed.

Yes, good afternoon, gentlemen. Could you all talk a little about IP rates? It seems like, through the industry and through the publicly traded companies, it just -- you get a lot of differences in the timing and how long oil's tested and chokes and different things. Can you just talk kind of about the method and what you all have chosen to do and how your rates might compare to others that might do it a different way?

Sure. I'm not going to venture to say how other people are doing it, John, but we flow the wells on that restricted choke until we get a stable, stabilized flow rate that's really steady and then that's what we call our IP rate. It typically is very close to the 30-day rate because these wells just continue to clean up for such a long period of time and they, and they -- when you're flowing them on that restricted choke they kind of just work their way up and level off for a little while before they start coming down. It's pretty close to a 30-day rate. But we try to got our IPs filed sooner than that because it's, otherwise you're struggling, getting your production clearances to sell your oil and everything. So the sooner we can get our completions filed the easier it is on everybody. So that's kind of how we, that's kind of how we do it.

Okay. And then in your -- in the Delaware Basin, the rigs you have running there, I guess those were the Eagle rigs and those were probably drilling vertical wells. I know they attempted a horizontal there. The rigs that you're moving in, those I assume are going to be bigger rigs and more capable of successfully getting a horizontal well drilled versus some of the smaller rigs?

That's correct. One of the -- Eagle had two rigs running. One of them was a little smaller. And we have replaced it with another rig just for performance issues. What the other rig that they had, an Aquila rig, is a pretty big rig but it's a mechanical rig and it doesn't normally have a top drive so it's not as efficient for horizontal drilling as the rigs we're moving. It's about the same size as the two rigs we're moving out there, but it's just not set up the same way. The two rigs we're moving are both electric rigs with top drives and they've had them on there since the beginning, and that's all they've been doing for us for several years is drill horizontal wells. So we'll, we'll use them to drill vertical wells and they'll do a good job at that, but it will be nice to have them out there when we get ready to test a vertical concept.

Right. Okay. Congratulations on the quarter. Thank you.

Thank you, John. Again, we're going to have two conventional mechanical rigs in the Delaware Basin. And then, like Mark said, we'll have two that are capable of drilling horizontal wells.

Our next question comes from Mike Kelly with Global Hunter Securities. Please proceed.

Hi, guys. You mentioned the flexibility in your CapEx program for this year. I was just hoping to ask you a what-if question, and that pertains to if we see gas prices persist here, the $2.50 range, what do you think you do in terms of that drilling CapEx from where it is right now?

Well, we'll continue to of course monitor the overall cash flow we'll generate this year and we have more flexibility to -- we could reduce our capital budget if we see lower gas prices or something that would change that cash flow expectation, so.

Like every rig that we're using right now currently, we'll roll off the contract this year. So I think that gives us some flexibility if we need to reduce it by another rig or so. I mean, hopefully that doesn't happen, but we do have tremendous flexibility.

When do you think you have to make that call? Say if we had $2.50 gas through the summer, when do you think you decide to potentially let a rig or two go?

We'll look at every month, we look at that. There's not a time. So we continue to look at our program forward. So it's an ongoing, it's an ongoing question. This is where we think it looks like right now.

You even noticed that we reduced our budget that we put out in December, we reduced it again in January. Because we needed to. Because gas, the gas market's terrible right now. So we pulled it in and quite frankly, if we had known the gas market would be where it is today we would have probably deferred completing the pad locations that we had already contracted to complete in the Haynesville but there was already commitment that we had. We don't have any other commitments like that. That's quite a bit of capital that we don't expose our self to in the future either. So there's a lot of things that are kind of cleanup items on the gas side of the balance sheet that won't reoccur now.

Got it. Okay. And was hoping, if you will, can you identify the assets you have for sale and what the current production is coming from them?

We did that on our last call. But we basically -- no one is being real specific about talking about the assets, but they're generally conventional assets. They're the ones we said were wet and I think the major property in that group is the AA Wells field. Overall, they have about 10 million a day of production associated with them, both oil, gas and NGLs. So we've already kind of included that in our production guidance like we said in our last call.

Okay. Great. That was my follow-up question. Thanks a lot, guys.

Our next question comes from Jeff Robertson with Barclays Capital. Please proceed.

Thanks. My questions have been answered.

Thank you, Jeff.

Our next question comes from Kelly Krenger with Bank of America-Merrill Lynch. Please proceed.

Hi. Good afternoon. Thanks for taking my question. Most of mine have been answered. But just, Roland, a quick one on the balance sheet. You noted that the borrowing base was at $700 million, $610 million on producing reserves, then I think you said $90 million available for a year. Then you said that you were of the belief that that would grow as you -- when your next redetermination is done based on the oil reserves, that sort of thing. Is that growth on I guess the entire amount of it, or the $610 million, or how should we look at that?

Well, that's hard to say. But when we look at our proved producing reserves at year end that we've wrapped up here and using the new price deck which have lower expectations for gas, we have some nice growth still in our proved producing reserves. So how that all kind of filters down, we have a lot of confidence we don't see it shrinking at all and think it ought to grow, so.

Okay.

And then that's just the first redetermination which is completed in May, then the one that's going to be in the fall later on will be October, November-ish. That's where we would expect to be really a lot of significant growth given the drilling we're doing especially on the oil, all-in oil projects, so.

Right. Okay. And then I think you mentioned that you wanted to spend within cash flow plus asset sales. Does that include the Stone shares, or are those considered kind of separate? Do you consider those an asset sale or are those separate?

They're considered part of our asset sale. That's how we kind of show -- those assets, plus what we consider kind of our wet conventional properties that we had on the divestiture list, that's what we picked. Because they're -- we picked those even before gas fell to these lower levels because we felt like they would be something we would realize very large gains with by selling, and we didn't go and look at our conventional gas assets that we may want to divest of in the future because we figure we could not realize big gains from selling those. So I think that given that the strength in oil prices, that all those asset sales look like they're very doable still.

And the -- I think you said this already, or on the last follow-up question, but the asset sales out of your guidance and as well as the kind of the percent of production that's oil and liquids, the asset sale's already been factored into the guidance on that as well?

Right. I think that may be part of what maybe dilutes a little of the -- as you go ahead and you're saying what's our total guidance for oil and you say well, you're already there, well part of it is we factored all these things in. But we've also been pretty conservative in our expectations for the new oil properties and even the Eagle Ford because they don't have the, they don't have the long-time history that the Haynesville gas projects do. So when we're looking ahead, we're being very conservative and hopefully our oil production outperforms our guidance here. The gas production became so predictable that we were very good at predicting that. So over time I think that these are two unconventional oil projects will start to become just as predictable.

Okay. Okay. Thank you.

Thank you, Kelly.

Ladies and gentlemen, at this time we ran out of time for questions. I'd like to hand it back over to Jay.

Jeremy, in probably the last 23 years that I've been the CEO of this Company I've never had a year-end call of an hour and 43 minutes. All of you that are still there, I mean, it's unbelievable. Thank you for your time. Hopefully, we've informed you as to what we're doing and we've been very clear about it. We'll be on the road the next two days, telling the story to 24 different accounts. Hopefully, that will show up in the value of the Company, which you own. Thanks for your time and God bless.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.