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Comstock Resources, Inc. (NYSE:CRK)

Q4 2013 Results Earnings Conference Call

February 11, 2014 11:00 AM ET

Executives

Jay Allison - Chief Executive Officer

Roland Burns - President and CFO

Mark Williams - Chief Operating Officer

Analysts

Amir Arif - Stifel

Don Crist - Johnson Rice

Ray Deacon - Brean Capital

Rehan Rashid - FBR

Kim Pacanovsky - Imperial Capital

Dan McSpirit - BMO Capital Markets

Leo Mariani - RBC Capital Markets

Marshall Carver - Heikkinen Energy Advisors

Operator

Good day, ladies and gentlemen, and welcome to the Q4 2013 Comstock Resources, Inc. Conference Call. My name is Sue, and I will be your operator for today. At this time all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this call is being recorded for replay purposes.

I would like to turn the call over to Mr. Jay Allison, CEO. Please proceed, sir.

Jay Allison

Thank you, Sue. And again welcome everybody. And now we have 30 slides or so to go over but I want to have a brief opening statement to be accountable as management to use a stakeholder. What a year you, the stakeholder have seen at Comstock. We started out 2013 telling that we spent in 2012 of $200 million and capital expenditures on our West Texas property and we had received only $27 million operating cash flow from the same properties that we had owned. Then in February in 2013 we announced to settle that property which (inaudible) May 2013.

As a result of the sale of Comstock realized the following, which is a change of our business plan. One, we realized a record $231 million profit. Two the sale of the Permian assets allowed us to double our Eagle Ford rig count from 3 rigs to 6 rigs which resulted in 15 plus net more Eagle Ford wells being drilled in 2013 versus our original business plan, which enabled us to be at the 10,000 plus barrels of oil production today that we have in Eagle Ford. It also allowed us to have significant liquidity which we were lacking.

Today we have over $400 million undrawn on our revolver and in fact our revolver went up by 33% at year end to be a $1 billion facility. The divestiture allowed us to acquire more of South Texas, Eagle Ford acreage as well as add the 21,000 net acres we have we think is the core of the East Texas Eagle Ford and the 51,000 net acres that we think are in the core of the TMS.

Potentially adding over 600 drilling locations in the future to Comstock. So quality inventory was added at very fair prices. The divestiture of the Permian properties allowed us to have a share repurchase program and allowed us to give a dividend with a 3% yield, it allowed us to safely hold our large inventory of Haynesville gas, we have over 6 Tcf of upside of upside, a 1,000 locations. And above all it gave us the financial freedom to spend dollars according to our wishes, not mandated by expiration of leases that had to be drilled or lost.

We now have transition to a balance company with a proper balance of oil and gas production of proper balance of inventory for both oil and gas wells to be drilled, with a strong balance-sheet and material liquidity.

So with that I’ll open up the meeting. Welcome to Comstock Resources fourth quarter 2013 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 entitled Fourth Quarter 2013 Results. I am Jay Allison, Chief Executive Officer of Comstock. And with me this morning are Roland Burns, our President and Chief Financial Officer and Mark Williams, our Chief Operating Officer.

During this call, we will discuss our 2013 fourth quarter operating and financial results. 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 could be no assurance that such expectations will prove to be correct.

Now slide 3, 2013 highlights. Slide 3 summarizes our financial results for 2013. Our financial results in 2013 are shaped by the strong growth in our oil production, the improved natural gas prices and declines in our natural gas production. Our oil and gas sales were $423 million in 2013, 7% higher than 2012 despite the low gas production. Our total EBITDAX was $331 million and our total cash flow from operations were $254 million or $5.47 per share.

Our Eagle Ford drilling program provided strong oil production growth in 2013. Overall, our oil production increased 29% from 2012 and is up 11% from the third quarter and is up 69% over last year's fourth quarter. Oil made up 20% of our production in 2013 and was 26% of our total production in the fourth quarter. In 2013 we drilled 75 successful Eagle Ford wells and also completed 63 wells, which had an average pro-well initial production rate of 780 barrels of oil equivalent per day.

Our results in our Eagle Ford program have improved considerably since last year. Our 2013 completions have 30-day initial rates that are 28% higher than the 30-day rates in 2012 while at the same time our average well cost had decreased by 12% from 2012.

We have a very strong balance sheet after West Texas divestiture, which closed in the second quarter. The divestiture allowed us to retire $735 million of debt this year including the October 15th redemption of our 2017 bonds. At the end of the fourth quarter our net debt has improved from 59% to only 45% of our total capitalization.

With that I’ll have Roland Burns provide more detail on our financial results. Roland?

Roland Burns

Thanks Jay. On slide four of the presentation we show our oil production from continuing operations working out our region on a daily basis for this quarter end the last three years. Our oil production this quarter increased to 7,600 barrels per day and was up 700 barrels per day or 11% over 2013’s third quarter. Oil production this quarter was also 69% higher than our fourth quarter production in 2012.

Our Eagle Ford properties in South Texas accounted for most of our oil production at 7,300 barrels per day and even though this quarter showed good growth, it felt short of our expectations. We expected to complete 18 Eagle Ford shell wells in November and December of last year and we expected to have all those wells producing in the month of December.

The planned completion activity encountered significant delays from the original schedule resulted in the first production for many of the new wells occurring three to four weeks later than we originally anticipated. We also shut in our existing oil production in December longer than anticipated for the ongoing frac activity.

During January we caught up on our completion schedule and our net oil production is averaging over 10,000 barrels per day. We’re expecting oil presentation to average 11,200 to 12,600 barrels per day in 2014 which should 77% to 99% higher than 2013.

Slide five shows our natural gas production from continuing operations on a daily basis. Our natural gas production climbed by 10% to 133 million cubic feet per day as compared to the 148 million per day that we produced in the third quarter. Production from our Haynesville and Bossier wells shown in dark blue on the chart declined by 15 million per day to 88 million per day this quarter.

Production from our Cotton Valley well shown in green averaged 22 million per day and our South Texas gas production shown in light blue was 19 million per day. Other gas production shown in purple decreased to 4 million per day in this most recent quarter. We expect our natural gas production to decline further in 2014 and to average approximately 110 million to 120 million cubic feet per day or 21% to 29% less than 2013.

Slide [six] shows our realized oil prices relating to our continued operations in the fourth quarter. Our oil price realizations in South Texas continue to weaken in the fourth quarter as the NYMEX-WTI contract outperformed the LLS Gulf Coast market. We realized $92.64 per barrel for our oil production as compared to $98.06 per barrel we realized in the fourth quarter of 2012. With the Gulf Coast premium failing to keep up, with the WTI contract our realized price averaged 95% of the average benchmark NYMEX WTI price.

77% of our production was hedged in the quarter at a NYMEX WTI price of $98.67. After considering gains from the hedging program, our realized price increased to $93.58 per barrel, which was 15% lower than the after-hedging oil price we averaged in the fourth quarter of 2012 of $110.42 per barrel.

On slide 7 we show our realized oil prices for all of 2013. We realized $100.20 per barrel in 2013, down 1% from the $101.09 we realized in 2012. Our realized price was 102% of the average WTI price for all of 2013. 81% of our oil production was hedged last year at a NYMEX WTI price of $98.69. After our hedging program, our realized price improves to $101.19 per barrel, 5% lower than our after hedging oil price we averaged for 2012 of $106.53.

Slide 8 shows our current oil hedges that we have in place for 2014. We currently have 5,500 barrels per day of our oil production hedged at $96.33 per barrel. This represents almost half of our planned 2014 production. We'll look to add more oil hedges should oil prices continue to improve from the current levels.

Slide 9 shows that our average gas price improved by 12% in the fourth quarter to $3.36 per mcf as compared to $3 that we averaged in the fourth quarter of 2012. Our average gas price improved by 36% for all of 2013 to $3.38 per mcf as compared to $2.49 we averaged in 2012. Our realized gas price averaged 93% of the NYMEX-Henry Hub gas price in 2013.

On slide 10, we cover our oil and gas sales, including realized hedging gains or losses. Our decline in natural gas production was offset by our growth in oil production and improved natural gas prices in 2013. Sales related to our continuing operations increased by 8% to $107 million in the fourth quarter as compared to $99 million in 2012’s fourth quarter. Oil production made up 61% of our total sales as compared to 46% in the fourth quarter of 2012. Sales related to our continuing operations increased by 7% to $423 million for all of 2013 as compared to $395 million in 2012.

Our earnings before interest, taxes, depreciation and amortization and exploration expense and other non-cash expenses or EBITDAX decreased by 4% to $79 million from the $82 million we had in 2012’s fourth quarter as shown on slide 11. $8 million of the EBITDAX in the fourth quarter of 2012 was related to discontinuing West Texas operations and $74 million was attributable to our continuing operations, so EBITDAX from continuing operations increased by 7% in the fourth quarter. Our EBITDAX increased by 3% to $331 million for all of 2013 from $321 million in 2012. EBITDAX from continuing operations of $317 million in 2013 increased by 11% over the $286 million we had in 2012.

Slide 12 covers our operating cash flow. Our operating cash flow for the quarter came in at $64 million, a 1% decrease from $65 million we had in 2012's fourth quarter. Cash flow attributable to our continuing operations -- which was also $64 million, was 8% higher than the $59 million we had in 2012's fourth quarter.

Our operating cash flow for all of 2013 was $254 million, a 3% decrease in cash flow of $261 million in 2012. The continuing operation's cash flow of $249 million this year in 2013 increased 6% over the $234 million we had for the same period in 2012.

On Slide 13, we outline our earnings. We reported a net loss of $37 million or $0.79 per share this quarter relating to continuing operations as compared to a net loss of $77 million from continuing operations or $1.60 per share in the fourth quarter of 2012. We have several unusual items in the fourth quarter including the unrealized gains related to our oil hedges, impairments on our unevaluated leases and a loss from the early retirement of our debt, which totaled $25 million or $0.49 per share.

Excluding these items, we would have reported a net loss relating to continuing operations of $0.30 per share in the fourth quarter as compared to recurring loss from continuing operations of $0.53 per share in 2012’s fourth quarter. For all the 2013, our net income was $41 million or $0.85 per share as compared to a net loss of $100 million or $2.16 per share in 2012. Included in net income for 2013 was a gain in the related activity for our West Texas properties of $128 million or $3.07 per share.

We had a loss of $107 million or $2.22 per share relating to continuing operations. Excluding the same unusual items, plus the gain we had selling our marketable securities we would have a net loss relating to continuing operations of $1.43 per share as compared to recurring loss from continuing operations of $1.88 per share for 2012.

On Slide 14, we show our lifting cost per Mcfe produced by quarter, relating to our continuing operations. Lifting cost on this chart comprised of three components; production taxes, transportation and other field level operating cost. Our total lifting cost increased to $1.36 per Mcfe in the fourth quarter of 2013 as compared to $1.02 per Mcfe in the fourth quarter of 2012 and $1.24 that we realized in the third quarter of 2013.

The increase is mainly due to the lower gas volumes we produced in the fixed nature of much of our lifting cost plus the higher cost of our oil production. Production taxes were $0.26 per Mcfe in the fourth quarter and our transportation cost also averaged $0.26 in the fourth quarter. Field operating cost increased to $0.84 this quarter as compared to $0.74 in the third quarter.

On Slide 15, we show our cash, G&A expense per Mcfe produced by quarter, excluding stock-based compensation. Our general and administrative cost increased to $0.34 per Mcfe in this as compared to $0.21 per Mcfe in the fourth quarter 2012 due to the lower production volumes in 2013.

Our depreciation, depletion and amortization per Mcfe produced is shown on slide 16. Our DD&A rate in the fourth quarter averaged $4.94 per Mcfe as compared to the $4.43 rate we had in the fourth quarter of 2012 and the $4.93 that we averaged in the third quarter of 2013.

On slide 17, we detail our capital expenditures related to our continuing operations. We spent $324 million in 2013 on our drilling program as compared to $307 million that we spent in 2012. Capital expenditures in South Texas, shown in red relate to our Eagle Ford drilling program, which increased to $325 million this year as compared to $204 million we spent in 2012. With low natural gas prices, our spending for our natural gas properties in North Louisiana declined to only $19 million in 2013 as compared to the $103 million we spent in 2012.

On Slide 18, we show our budget for our 2014 drilling program. We're expecting to spend $450 million for drilling activity this year. $364 million we spent in our South Texas Eagle Ford program to drill 40 net wells and then we would also spend $80 million to complete wells in South Texas that we drilled in 2013. Another $25 million will be spent to install new facilities.

We will spend $50 million on drilling 5.6 net wells in our new East Texas Eagle Ford acreage and $27 million to drill two wells in our new Tuscaloosa Marine shale acreage. We have also allocated $28 million for fill-in acreage acquisitions during 2014.

We have a slide on our proved reserves and finding costs on page 19 of the presentation. Our proved reserves at the end of 2013 were estimated 585 Tcfe as compared to the 551 Bcfe at the end of 2012. Our reserves are 77% natural gas and 23% oil as compared to only 15% oil at the end of 2012. We operate 95% of our proved reserves and they were 73% developed at the end of 2013.

Our successful drilling program in the Eagle Ford Shale and South Texas added approximately 3 million barrels of oil and 5 Bcf of natural gas or 6.1 million barrels of oil equivalent to our proved reserve in 2013. We were able to place 233% of our oil production and 127% of our natural gas production in 2013. We spent $344 million on exploration and development activities and another $137 million to acquire leases in 2013. So, the finding cost for 2013 excluding the exploratory acreage cost calculates at $20 per BOE.

Slide 20 recaps our balance sheet at the end of 2013. We had $3 million of cash on hand and $799 million of total debt at the end of the year. Our net debt is 45% of our total capitalization as compared to the 59% at the end of the first quarter of 2013. On April 15th we redeemed our 8 and 3/8% bonds which were due in 2017, and in November we put in a new $1 billion five year bank credit facility that has a borrowing base of $625 million. We have $415 million available under that bank credit facility.

Starting in June of last year, we began paying a quarterly dividend of $0.125 per share. The dividend cost to company around $6 million a quarter. As shown on slide 21, only a third of the 61 E&P companies we serve, actually pay dividend. Of those 61 companies, we have the second highest dividend yield of 2.7% as of December 31st.

I’ll now turn it over to Mark to review our drilling results for last year.

Mark Williams

Thanks Roland. On slide 22, we cover our South Texas operations for all of our current drilling activity as focused on our Eagle Ford Shale play. We estimate that we have approximately 300 operated drilling locations on our acreage which could yield 70 million barrels of oil equivalent. Through the end of ‘13 we have drilled a 129 of the locations.

Slide 23 shows a location of the 75 producing wells that we drilled in 2013. We have completed 63 or 42 net Eagle Ford Shale wells in 2013 and so far in 2014 including six or 3.8 net wells that were drilled in 2012. These wells had average a per well initial production rate of 780 barrels of oil equivalent per day.

We have an additional 18 wells, 13.3 net wells that we drilled in 2013 that will be completed this year. Of the wells we completed in the fourth quarter, six of our Gloria Wheeler wells had a fee rates that ranged from 1,025 to 1,340 barrels of oil equivalent per day.

Slide 24 compares our 2013 completions to our 2012 completions. Our average 24 hour IP rates were up 21% to 780 BOE per day as compared to 647 BOE per day in 2012. More significantly, our average 30 day IP rates increased 28% to 659 BOE per day from 514 BOE per day in 2012.

On slide 25, we track the cost of our Eagle Ford wells which have decreased considerably since we started drilling in August of 2010. In 2010, our first two wells averaged $11.4 million, cost have been reduced to an average 7.9 million per well this year. Now, extra drilling times and lower well stimulation cost account for much of the savings. We expect to average Eagle Ford well to cost 7.4 million in 2014. On the far right, you can see the effect of the KKR promote on Comstock’s realized well cost. The effective average well cost in 2014 to Comstock on an 8H basis improved to $6.4 million with the joint venture.

On slide 26, we show the progression of later lateral length over time in our Eagle Ford wells. Even though costs have come down considerably, the lateral length has increased by 41% since our drilling program began. The average lateral length was 6,500 feet in 2013 as compared to 4,595 feet in 2010. This increase is a function of our increased confidence in executing longer laterals without complication and our goal of maximizing our rate of return as well as utilization of our acreage.

On Slide 27, we show the increase in proppant pumped since our program began in 2010. Half of this increase is due to the increasing lateral length. We pumped 8.1 million pounds of proppant per well this year as compared to only 4.4 million pounds per well in 2010. We have increased the amount of proppant per lateral foot by 35% since 2010.

On slide 28 we show a detailed map of the East Texas Eagle acreage which we acquired in the fourth quarter. We acquired 34,000 gross and 21,000 net acres for $67 million. There are several wells in the area that have IPed at greater than a 1,000 BOE per day as shown by the red dots on the map. Our first well will likely be located near the western hedge of our acreage and would do rest for the acreage during the year. We have planned to drill 10 growth wells on the acreage during 2014. We are targeting $9.5 million per well for the initial wells that will get a full suite of technical data when we drill these wells. We believe the well cost can be reduced significantly, once the play moves into full development mode as we have demonstrated in our South Texas Eagle Ford play.

On slide, we show a detailed map of the Tuscaloosa Marine shale play. In the fourth quarter, we acquired 53,000 gross, 51,000 net acres for $51 million. The leases are in Wilkinson and Amite Counties and Mississippi and East Louisiana and St. Helena parishes in Louisiana, and fall within, what we think will be the most prospective part of this play. The acreage acquired is near some of the best wells in the play. The red dots in this map show recent TMS wells, initial production rates over a 1,000 barrels of oil per day, including the very successful Goodrich Crosby well, in Wilkinson County. We expect to move a rig into the area in June or July and drill two wells in 2014.

I'll now turn it back over to Jay.

Jay Allison

Thanks Mark. The 2014 outlook, on slide 30 we focus on our outlook for this year. We plan to continue to focus on increasing our oil production this year. We will not start drilling natural gas wells until we can have high price return on those projects. To the extent longer-term natural gas prices approach $5; we will give consideration to adding some natural gas projects to our drilling plans. With that additional gas drilling, we expect that the strong growth in our oil production will more than offset the natural gas production times we are facing to allow us to have higher revenues and cash flow and be a much more profitable company this year. It now comprises more than 26% of production even after the sale of our Permian Basin properties and we’ll grow to 40% by mid-year.

All of the net wells we plan to drill in 2014 are oil wells and all of our budget will be spent on oil projects. We’ve expanded our inventory of oil drilling locations by completing both on acreage acquisitions around our Eagle Ford properties and by acquiring acreage in the East Texas Eagle Ford and the TMS. We continue to have one of the lowest overall cost structures in the industry, and we now have a very, very strong balance sheet after the West Texas divestiture. We have over $400 million in liquidity as of the retirement of our 2017 bonds that we completed on October the 15th.

For the rest of the call, we will take questions only from research analysts who follow the stock. So, I’ll turn it back over to you, Sue. Sue, are you there?

Question-and-Answer Session

Operator

Yes. Thank you. (Operator Instructions). Thank you. And your first question comes from Amir Arif, Stifel. Your line is open. Please go ahead.

Amir Arif - Stifel

Hey good morning guys. I don’t know if I missed it, but can you give us the timing of when you can be, when you are going to start growing the East Texas Eagle Ford?

Jay Allison

Mark, [can you explain]?

Mark Williams

Yes this is Mark. Our goal is to have rig moving over there in March and that's what we are shooting for right now.

Amir Arif - Stifel

Okay. And then so the first production result maybe in 2Q?

Jay Allison

Yes, it could be June, July we’ll spot our first TMS well in June, July. So I think first production from East Texas Eagle Ford may be June, late June that's same time the we spud our first TMS well.

Amir Arif - Stifel

Okay. And then just a final question, on the just on your comments on returning to some gas drilling with a long term price north of 5, are you thinking just a 12 month strip price of 5 or can you just give us some color on what price you are looking at and where you would allocate some of the capital front?

Roland Burns

Yes, this is Roland. I think that we don’t have, basically longer term prices that we can hedge at five, we don’t have a specific exact number. But I mean that's where we have competitive returns from the natural gas projects in the Haynesville to the oil. So I mean to extend that we can, that we get that type of a market then we will look to potentially hedge that price. And then look at using the additional revenue from the higher gas prices without support some of the drilling cost. And then we’ll weigh whether or not we want to reduce any well drilling, kind of based on what the price of oil as of that time.

Amir Arif - Stifel

Okay. Thanks guys.

Operator

Thank you. And your next question is from Don Crist with Johnson Rice. Your line is open please proceed.

Don Crist - Johnson Rice

Good morning guys. Starting in the East Texas Eagle Ford that you just acquired. Can you tell me what that well that you acquired is producing now and where in the life it was when you acquired it?

Mark Williams

Yes, Don it’s Mark. That well was completed in September and it’s producing about 200 barrels [Technical Difficulty] some outlook that’s about where it was.

It’s a short pretty lateral small frac, we didn’t feel like it was a very good test for what we are going to do out there and for what Halcon has been doing that it’s been so successful.

Don Crist - Johnson Rice

So your well that you are getting ready to drill in March should be considerably longer I mean what was the lateral length of that well and what are you looking to drill on this next well?

Mark Williams

I believe that was about a 4,500 foot lateral and our goal is to average in the 6,500 to 7,000 foot range. It is Texas, so every unit is shaped a little differently and so there would be some variation in the length out here. So we will probably have so longer ones we’ll have some little bit shorter but that’s kind of our goal.

Don Crist - Johnson Rice

Okay. And what are the prospects look like out there? Is there acreage for sale out there to decent price or is it pretty much leased up for now?

Mark Williams

By and large it’s leased up it sits under the biddings Austin Chalk field so unless the acreage is held by production by mature Austin Chalk wells, there is a little bit open acreage but we feel like the parties are involved and picked most of it at this time.

Don Crist - Johnson Rice

Okay. And…

Jay Allison

And the new acreage we have picked up was about 3,000 acre is a big block. We don’t see any more big blocks available I think we are fortunate as Mark said to get our interest on that block. We are still shopping for acreage and we think it’s core. And then I think pertaining to our location, like William says has hit pretty good well and as you probably followed. So our well will probably be as close to that well as possible our first well, that's kind of what we're looking. And I think Halcon is about a mile and half away, I think Clayton is about three miles away. So, Halcon’s leases are five miles away, but we certainly like what we've seen from the wells results from Clayton and others. We think it will be a pretty aggressive area in 2014.

So, I think we're forcing to have paid the purchase that we have paid to get in the area. Again our opinion is that is an extension of our South Texas Eagle Ford and that we'll have derisk a lot of this by year end 2014 in the East Texas Eagle Ford.

Then I think the long ball is TMS. We don't have to drill any wells in TMS till 2015. We have to drill 2 or 3 wells by the end of ‘15. But we've elected to go ahead and drill a couple of those this year, because we want our own people to drill wells there and complete them. In the interim you're going to see some activity on the TMS across from Goodrich and from EnCana, Sanchez and others. So, I think what we're looking forward is good performance in the East Texas Eagle Ford this year continued performance and our South Texas Eagle Ford at the end of ‘14, early ‘15 I think you'll see a budget that will emphasize the East Texas Eagle Ford a little more and it will emphasize TMS if that continues to should be derisk. That's our business plan right now.

Don Crist - Johnson Rice

Okay. Thanks for the color Jay. And you recently I mean early in the call talked about 600 added locations. Is there any way you can break that up between the TMS and East Texas Eagle Ford.

Jay Allison

No. If you look at what we look at now it's early on in the game. I think we are seeing our East Texas, Eagle Ford kind of via mirror image to our South Texas Eagle Ford. That’s what we think will happen. So if you’re looking at that you’re looking at 80s, you drill on 80s maybe 100 some are drilling on 50s and 60s. If you just use 80 acre spacing I mean we have a couple of hundred drill sites there by the 250.

If you look at to the TMS and you look what has been speculated, it’s anywhere from 100 acres to 160 acres. So you’ve got hundreds and hundreds of acres. I count it throughout a 600 number to be kind of in the middle of all that, I think it could be materially higher than that. But I think what you’ve seen is and I started out the conversion telling you that in the West Texas area, we spent $200 million on CapEx, we only received $27 million of operating cash flow. And yes we have hundreds of locations well.

What you’ve seen now is you’ve seen a transition to great liquidity that we have in a very balanced, firm balance sheet but you’ve also seen that we’ve doubled our rig count in Eagle Ford to give us the production we have today and we spent the profits, some of the profits that we realized from the divestiture of the West Texas property to add quality acres. And we think we’ve probably already added these many drill sites in our East Texas Eagle Ford and the TMS that we quote as sold when we divested ourselves at West Texas properties. And you now sit to very end of this I said above all what we have now which we didn’t have is some financial freedom to spend money where we think we can get the best returns and not mandated by some expiration of leases that you lose if you don’t drill.

We quite frankly didn’t like to be in that position. We wanted to have a balanced company that had great liquidity without issuing equity, without doing the convertible preferred [bench] and have a balance of locations for both oil and gas. And what we do have that we didn’t have that a year ago, we didn’t have that eight months ago, but we have that today. And not only do we have that, we also can buy shares back or we also give a dividend. So it’s pretty good and if you look at our gas prices were average in 2012, $2.50; 2013 average $3.40 or $3.50; today, they are like $4.50, $4.60. We truly sit on almost an HVPed inventory in the Haynesville of 75,000 net acres and over 1,000 drill sites. So versus where we were a year ago, versus today I mean we have a pretty much an A+ going today versus a year ago.

Don Crist - Johnson Rice

I appreciated all the color, Jay. I’ll turn it back thanks.

Jay Allison

Thank you.

Operator

Unqueuing your next question is from Ray Deacon, Brean Capital. Please proceed.

Ray Deacon - Brean Capital

I was just -- I had a question about that East Texas Eagle Ford and just was wondering if you could elaborate a little bit more on the number of locations you think you have there. And also a question about the production ramp and given the backlog of completions, it’s a lot of the production growth going to be run and loaded this year?

Jay Allison

Again we answered before eight month, the future the East Texas Eagle Ford, it’s a gas, so based upon our base gas, we answered that. And then Mark you going to answer them?

Mark Williams

Yes Ray. As far as production goes, we are between 10,000 and 11,000 barrels a day right now. I think our guidance for the year is about between 11,000 and 12,000 barrels a day. So we jumped up at the beginning and our goal to maintain that or build it a little bit as we go. So that you are right it is pretty front end loaded.

Don Crist - Johnson Rice

Okay. Got it. Great, thank you.

Jay Allison

Thank you, Ray.

Operator

Thank you. And your next question comes from Rehan Rashid FBR. Please proceed.

Rehan Rashid - FBR

Good morning Jay, Roland. Maybe a quick question on gas price as far as, so Henry Hub has been hanging in there much stronger than NYMEX. Maybe a quick reminder as to how you sell your gas how much good week how much everyday and then I have got a follow-up question?

Roland Burns

Sure Rehan, this Roland. We typically sell only 10% to 15% of our gas on the spot market, which is really where you see the daily index prices, which had some really run up in prices with all the cold weather. So, the majority of our gas is sold based on the monthly index average prices and it’s nominated the month before production.

Rehan Rashid - FBR

Got it. Okay good. Thank you. And then on East Texas maybe Mark, what’s incremental technical work maybe in broad strokes has been done since they picked up the acreage? And the 10 well program; is that kind of dependent on successes. How much of it is dependent on successes? Yeah, that should be good.

Mark Williams

Yes Rehan, I mean as far as incremental technical work, we are monitoring all the activity and what’s been done in terms of results from Clayton Williams from his recent well what was different there versus other wells, what Halcon has done differently than some of the previous operators and the job sizes and lateral lengths, weather landing.

We’ve met with couple of other operators about data trade agreements, which will allow us to access some of the data that will be helpful on advancing our learning curve in that play. And then our first few wells will have two or three pilot holes that we’ll drill we’ll get full [sweeps] of (inaudible) we’ll probably core one well, we aren’t sure which one yet, we’ll probably core well try to gather some technical information that will help us to design the frac jobs and pick the exact landing point that we want to land these wells.

We feel like it's very similar to South Texas Eagle Ford, so a lot of information we’ve learned down there would apply here, but there is always some entrants that we'll need to adjust as we go forward on that.

Rehan Rashid - FBR

Okay, good. Real quick one Roland, did we buyback any stock in the fourth quarter?

Roland Burns

No, right now we did not buy any shares back in the fourth quarter. Our share buyback plan is discretionary and based on specific actions we take in the market. It’s not an automatic plan. So, what happened in the fourth quarter, again that is a fourth quarter we were really blacked out from making purchases because we had normal black-out periods around operating results, but we also have fair amount of press releases around acquisition. So we're going to have much opportunity to look at that. And as the window opens back up for us later on this month, we'll go back to look at where we might want to purchase shares. We still have the $90 million of the plan still available to us.

Jay Allison

Remember Rehan like Roland said in the fourth quarter, we announced the TMS and we came back quite robust first we announced East Texas Eagle Ford. So, as we added those we were blacked out before and after that. So….

Rehan Rashid - FBR

Yes. Thanks Jay.

Jay Allison

And again I'd like to comment that this time last year, February last year I don't think any analysts thought that in the month of February that we would see withdraw on storage below the five year average and we did by the end of February of 2013. And I think Rehan your attitude towards natural gas is probably looking to be correct. I mean we've seen large numbers, we’ve seen gas pike up, we've seen cold weather. So, I hope you're right in your forecast; we're going to see mostly $5 gas this year if that happens.

Rehan Rashid - FBR

I think…

Jay Allison

We’ve got a new inventory, we’ve got a huge inventory of gas prospects we think at $4.30 we could start drilling and get a return. We also said that on the $4.75 to $5 range we can hedge that and put a real program in (inaudible) our East Texas and our South Texas Eagle Ford and that’s what we’re really wanting to do. We want to continue to keep a sound solid balance sheet.

And if we see the East Texas Eagle Ford be de-risk and our RoR go up materially, we see oil prices continue to hang in at the $90 plus price then we can look at ramping up (inaudible) that program we’re looking at Haynesville et cetera. But I think our (inaudible) we’re going to have material liquidity and strong balance sheet we’re going to have and our goal is to have the 77% to 100% growth in oil. And then if we want to have the Haynesville, let’s say if we won’t after we have to drill wells because of some throughput contract we signed, we can drill Haynesville wells that’s how we’ve looked at it.

Rehan Rashid - FBR

Got it, got it. Thank you, Jay.

Operator

Thank you. And your next question comes from Kim Pacanovsky from Imperial Capital.

Kim Pacanovsky - Imperial Capital

Hey good morning Jay.

Jay Allison

Hi Kim.

Kim Pacanovsky - Imperial Capital

Hi. I have a question on your EURs. You have 450 to 550 MBOE on your presentation. And I was wondering if -- I mean obviously you’ve had great improvement over the year in IP rates. If we look back a year what did you have as your EUR range a year ago?

And could you also just detail how -- it’s a wide range, so I am assuming like the 450 is probably up and out of course and closer to 550 is McMullen. But if you could go through how that breaks up and where you have the bulk of your undrilled and I should say undrilled and unbooked locations?

Jay Allison

Kim, we've seen -- we obviously have some wells that had exceeded our original EURs more 500,000 and then there are parts of our acreage especially that northern part that we have lower EURs. But we have not -- on an average, we think they’ve been relatively where we thought they would be in the long run.

Kim Pacanovsky - Imperial Capital

Okay. I’m -- one of the reasons I’m asking the question is [Caruso] acreage and La Salle close to you has increased their type curve from 495 to 523, I mean they are using an average number and not giving us the range. So, I guess if you weighted the acreage where -- let’s put it this way if you weighted the acreage where would that number sell out, on the higher side or the lower side?

Jay Allison

It probably should fall out in the middle that’s kind of how….

Kim Pacanovsky - Imperial Capital

Okay, all right.

Jay Allison

Of course we’re not -- as far as -- it’s a very profitable program and it set our expectations. We are not a company that likes to count EURs and take them to the maximum possibility that some companies did.

Roland Burns

Well, a lot of it Kim goes also down spacing. In other words you see oil down spacing, but we want other companies to be successful in down spacing to 30s and 40s and 80s or whatever. But, and if we can get there believe me, let them drag us across the finish line, we would lack to be there, it’s not that we are not trying to get in there, but we just hadn’t gone there yet. I hope they’re right and we’ll be right after a while. And that means you can double our drill size, but we don’t believe that right now.

Kim Pacanovsky - Imperial Capital

And your location count is on what spacing?

Roland Burns

It’s about 600 feet from well head to well head.

Kim Pacanovsky - Imperial Capital

Okay.

Mark Williams

Right. It’s anywhere from 80, it depends on length of the laterals.

Kim Pacanovsky - Imperial Capital

Got it, okay.

Mark Williams

100 acres per well.

Kim Pacanovsky - Imperial Capital

And on the TMS I know that some other companies in the TMS have reached out to you since you entered the area and I assume that you have met with some of them. Is there anything you have learned since you bought that acreage that makes you incrementally more positive on the play? I know there hasn’t been a whole lot of dates coming out recently, but just to may be some of the work that you’ve done since you’ve acquired the acreage and in some of the conversations you’ve had with other players there?

Jay Allison

Let me call it globally [midlife] market what’s coming I think the great thing about the TMS and really any of these plays now, Kim is that all the operators in the TMS, I mean we collectively want to reduce the cost. In other words it’s not that we’re playing the individual games out there it’s almost like a team effort operator saying okay what is it that we can do to help every other operator of a learning curve to decrease the cost to get this into a $10 million range not $11 million or $12 million or $13 million drill and complete range to get the cost down because if we can get the cost down which every other player we’ve ever seen we’ve reduced the cost. If you take the South Texas Eagle Ford we are at $11.4 million now we are at $7.4 million to drill and complete a well that’s much longer and has more profit.

So again I think if you go back to hire people internally what we’ve done in the Gulf, what we’ve in the Haynesville, what we’ve done in South Texas Eagle Ford I think if we can do that again in the TMS and it's a team effort now then you’ve had another big oil play.

And oils and plays we don't with -- 1,500 wells have penetrated this; I mean we don't have any question at on our acreage of oil is not like we believe it's in place, which is a great thing because you can check that box now, you just have to reduce the cost and make it extremely credit. So, Mark do you want to have any other comments things that happened out there?

Mark Williams

Kim it's Mark. I guess the thing that give us, just gives a continued encouragement that we had when we bought this deal a few months ago that's a data points on production have still maintained our projections on the wells, we haven't seen anything that has changed our opinion about EURs. So that’s probably the primary thing and we'd also know that Goodrich was able to successfully drill their latest well by drilling under the [trouble] zone and get the well drill to TD and get it cased that's very encouraging and things like that getting up that learning curve is going to help us a lot and everybody is going to work together to do that.

So, we spoke with several of the operators everybody here I mean are share data and to collaborate on operations. And that we saw that being very successful in the Haynesville. That was probably less evident in the Eagle Ford from our perspective, just -- of such a small player compared to so many other operators, but I think that's going to be a key here is the collaboration of the 4 or 5 key operators.

Kim Pacanovsky - Imperial Capital

Okay, great. That's great. And just one last quick question on you talked about where production is right now; would you hazard a exit rate guess for the first quarter?

Jay Allison

Well now Roland is shaking his head.

Kim Pacanovsky - Imperial Capital

Sorry Roland, but I had to ask. Alright guys. Thanks very much.

Jay Allison

Thanks Kim.

Operator

Thank you. And your next question is from Dan McSpirit, BMO Capital Markets. Please proceed.

Dan McSpirit - BMO Capital Markets

Thank you folks. Good morning.

Jay Allison

Good morning.

Dan McSpirit - BMO Capital Markets

If we could just touch on well economics again in the East Texas Eagle Ford as well as the TMS play, recognizing of course that it’s early innings. What do you need to see in terms of recoveries and costs for this play to generate returns competitive with what you’re drilling in South Texas?

Mark Williams

Dan, this is Mark. On the East Texas Eagle Ford, we were looking at a type curve of about 400 MBOE. And that gives us at the well cost of starting at $9.5 million but really development cost being around $8.5 million that gives us very comparative returns with those South Texas program. And then TMS, obviously it’s going to take little bit more than that because the well costs are probably going be in the $11 million to $12 million range. So we probably need to be in the 500 MBOE to 550 MBOE range for that play to work as a well. Still we’re going to work, even it’s 400 to 450, it’s going to give you good returns but maybe not quite as competitive as it would I think it was in the 500 MBOE range.

Dan McSpirit - BMO Capital Markets

Okay, great. Thanks. And then just on the subject of the dividend. How do you look at the dividend in light of drawing the opportunities under the new ventures, efforts? Is it here to stay or could it ever be reconsidered upon success in East Texas or the TMS?

Roland Burns

Yeah Dan, it’s Roland. It’s here to stay, I mean we’re committed to maintain that dividend, not necessarily on a year or percentage basis but on a -- the $0.50 a year given that we don’t have a lot of shares outstanding is at $6 million a quarter, it’s not really going to -- we’re not tying our liquidity where $24 million is going to really change our drilling budget one way or another. So, it’s given that we don’t have a lot of shares outstanding, we are committed to maintaining that dividend. And we don’t really view this competing with anything in the company given this -- it’s not a very (inaudible) expenditure.

Dan McSpirit - BMO Capital Markets

Okay, great. And then, a question was asked earlier with respect to acquiring additional leasehold in the East Texas for the Eagle Ford; what about the TMS, is there an opportunity there? IF so, how does that compete with accelerating growth elsewhere, say South Texas?

Jay Allison

Bulk of those areas and South Texas which continue to look for acreage that will complement our existing footprint, I hope three of those areas.

Mark Williams

So we’ll continue and we budgeted that to fill in acreage, especially as we build units in the new plays and so, we’re actively leasing acreage. We’re not looking for a very large additional amount of acreage right now as a company, because we have our place really fully and we like the way that you don’t have acreage for short exploration dates that’s driving aggressive drilling, beyond our cash flow and so we like with other companies position. So but it doesn’t mean, we are not going to continue to add acreage in both of these new plays especially as we build up the units and we fill in acreage and we think it’s especially in TMS that can be done at very attractive cost right now.

Dan McSpirit - BMO Capital Markets

Got it. And one last one, just on reserve bookings, what EUR were Eagle Ford Shale locations booked?

Mark Williams

Yes, I don’t have the exact number in front of me. But I think of course every wells, looked at how it’s performing but then we typically are looking at, if you look at undeveloped wells that we are we typically will book those at 25% less than a typical producing well. So, we think those undeveloped wells are always booked conservatively so we don’t have to worry about negative revisions.

Dan McSpirit - BMO Capital Markets

Got it.

Mark Williams

They are definitely way below our target numbers. With this performance they can have positive revisions.

Dan McSpirit - BMO Capital Markets

Right, thanks again.

Jay Allison

Thank you.

Operator

Thank you. And your next question comes from Leo Mariani, RBC Capital Markets. Please go ahead.

Leo Mariani - RBC Capital Markets

Hey guys. Just all up here on the Eagle Ford, I think you guys said in your comments here that your last six wells had kind of materially higher rates; I think those are all in sort of one areas of play. Is it just kind of geography that’s driving the better results there or is there any changes in kind of completion practice or drilling practice here?

Mark Williams

Leo, this is Mark. Primarily those six were all Gloria Wheeler wells so they were in the better part of our acreage position. We are testing some variations of our frac geometry and trying to see if we can squeeze a little bit more production out of these wells. So we tested them on both the Gloria Wheeler and our -- and one of our other leases and we are monitoring the results right now to determine if we want to adjust our frac design going forward or kind of keep to where it’s at.

Jay Allison

Leo if you take the oil and gas investor, there is about a four, five page story highlighting the South Texas, Eagle Ford. Our completion crews are there Mark [Victor] is there; they talk about how to frac and stimulate and simple fracs. And it’s pretty good reading for anyone on the call if you have the oil and gas investor. There is a lot of information about Comstock and particularly the Gloria Wheeler area and McMullen County.

Leo Mariani - RBC Capital Markets

Okay, that's helpful. I guess just turning to the Haynesville, just looking at your production in the fourth quarter versus 3Q. I think it was down about $15 million a day sequentially which is I guess almost 15% sequential decline, just looked a little bit steep there on the decline. Am I kind of reading too much into this, is there any downtime which can be associated with weather or something, just trying to get a sense of why the production decline was seem to be high?

Mark Williams

Leo, there wasn’t any downtime, there were two new wells that came on in the third quarter, so you probably had that flush production from those new wells and they were both 100% interest wells. So that was a pretty high little boost in the third quarter that probably attributed to that little steeper than normal decline.

Leo Mariani - RBC Capital Markets

Okay, that's helpful. And I guess just looking at your gas prices in the fourth quarter, I was noticing that the differentials also kind of widened out versus Henry Hub this quarter versus last quarter, just want to see if there is anything kind of in particular that sort of drove that and how we should expect the gas price dip sort of going forward?

Mark Williams

I think we averaged to drilled similar amount -- between the potentially through the year or so. I mean the only thing that's this year compared to prior year is we just don't have many liquids that we would count in our gas prices. It's very dry gas out there. But that hasn’t really changed very much. I mean as you kept lower volumes, you’re just going to see more fixed costs that have a impact on that, we have transportation going on in. So, a lot of the costs have -- that's in cost, even though their models on a variable basis, they really are very fixed. So, they kind of -- as you have lower volumes, just going to have higher per unit costs and higher transportation cost et cetera.

Leo Mariani - RBC Capital Markets

Well I guess apart from the cost side of equation, I mean what type of pricing differential should we expect say versus Henry Hub in 2014 if we just eliminate cost and just kind of think about price here?

Roland Burns

The 93% has been pretty consistent throughout all of 2013 as far as what we’ve averaged at Henry Hub.

Leo Mariani - RBC Capital Markets

Okay.

Roland Burns

Well, I think the pricing hasn’t been that variable really.

Leo Mariani - RBC Capital Markets

All right. Thanks.

Jay Allison

Thank you, Leo.

Operator

Thank you. And your next question is from [Ryan Berney,] Raymond James. Please go ahead.

Unidentified Analyst

Hi guys. This is Ryan in for John Freeman. I just wanted to ask a real quick; what percentage of your Eagle Ford well, especially South Texas, are you planning to drill in 2014 in Atascosa County? I know you guys have been focusing little more on McMullen?

Mark Williams

Yes. It’s Mark. I don’t think you have any Atascosa wells planned in 2014 whether it’s either in LaSalle or McMullen.

Unidentified Analyst

Okay, great. Thank you.

Jay Allison

Thank you.

Operator

Thank you. Your next question comes from Marshall Carver, Heikkinen Energy Advisors. Please proceed.

Marshall Carver - Heikkinen Energy Advisors

Yes, your oil differentials were a little higher than what I was expecting for the fourth quarter and your overall oil prices what I was expecting. What sort of differentials are you seeing now, what would be good guidance I think forward and what’s your average API gravity for your liquids production?

Mark Williams

Ryan, as far as the gravity, it’s probably going to be the low 40s is probably our average it goes anywhere from about 35 to about 48, or 49 I believe, so probably low 40s on average. And then our organizations are really based on LLS, so it’s a different mean -- if you are modeling off of WTI, the WTI, we’re not going to track WTI, we are going to track LLS, and we’re pretty consistently there. It’s going to be LLS minus (inaudible).

Marshall Carver - Heikkinen Energy Advisors

The [ATI] gravity is averaging in the low 40s and that's fairly consistent from quarter-to-quarter?

Mark Williams

Yes it is.

Marshall Carver - Heikkinen Energy Advisors

Okay. Thank you. And in terms of expense guidance, do you -- could you walk through that for ‘14?

Roland Burns

Yeah, why don’t (inaudible) for a very specific modeling questions after the call.

Marshall Carver - Heikkinen Energy Advisors

Okay. We’ll do, thank you.

Operator

Thank you. And I’d like to hand the call back now Jay Allison for closing remarks.

Jay Allison

Again, I want to thank everybody. I think there was competing conference call during our call and those of you that came over here chose to listen to Comstock one here, we’re very appreciative and thankful. So that concludes my remarks. Again, thanks everybody.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

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