Comstock Resources Inc (CRK) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the Q4 2013 Comstock Resources, Inc's conference call. My name is Sue, and I will be your operator for today.

(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.

Thank you, Sue, and again, welcome, everybody. I know we have 30 slides or so to go over, but I want to have a brief opening statement to be accountable, as management, to you, the stakeholder.

What a year, you, the stakeholder, have seen at Comstock. We started out, in 2013, telling you we spent, in 2012, $200 million in 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 2013, we announced the sale of that property, which closed May 2013.

As a result of the sale, 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 three rigs to six 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 the 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 South Texas Eagle Ford acreage, as well as add the 21,000 net acres we have that 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. It allowed us to give a dividend with a 3% yield. It allowed us to safely hold our large inventory of Haynesville gas, where we have over 6 Tcf of upside, 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 transitioned to a balanced company, with a proper balance of oil and gas production, a proper balance of inventory for both oil and gas wells to be drilled, with a strong balance sheet, and material liquidity.

With that, I will 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 will find a presentation entitled Fourth-Quarter 2013 Results.

I am Jay Allison, Chief Executive Officer of Comstock. 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, 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% overall, 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 per-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 costs have decreased by 12% from 2012.

We have a very strong balance sheet after the West Texas divestiture, which closed in the second quarter. The divestiture allowed us to retire $735 million of debt this year, including the October 15 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 will have Roland Burns provide more detail on our financial results. Roland?

Thanks, Jay.

On slide 4 of the presentation, we show our oil production from continuing operations, broken out by region on a daily basis for this quarter and 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 fell short of our expectations. We expected to complete 18 Eagle Ford shale 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, resulting in the first production for many of the new wells occurring 3 to 4 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 are expecting oil production to average 11,200 to 12,600 barrels per day in 2014, which would be 77% to 99% higher than 2013.

Slide 5 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 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 wells, 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 to 120 million cubic feet per day, or 21% to 29% less than 2013.

Slide 6 shows our realized oil prices relating to our continuing operations in the fourth quarter. Our oil price realizations in South Texas continued 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 in 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 $96.31 per barrel. This represents almost half of our planned 2014 production. We will 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 the $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 the 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 decreased by 7% to $423 million for all of 2013, as compared to $395 million in 2012.

Our earnings before interest, taxes, depreciation, amortization, and expiration 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 the discontinued 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 the $65 million we had in 2012's fourth quarter. Cash flow attributable to our continuing operations this quarter, 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 from cash flow of $261 million in 2012. The continuing operations 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 outlined 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 $77 million from continuing operations, or [$1.66 per share] in the fourth quarter of 2012.

We had several unusual items in the fourth quarter, including unrealized gains related to our oil hedges, impairments on unevaluated leases, and a loss from the early retirement of our debt, which totaled $35 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 a recurring loss from continuing operations of $0.53 per share in 2012's fourth quarter.

For all of 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 $148 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 on selling our marketable securities, we would have reported a net loss relating to continuing operations of $1.43, as compared to a recurring loss from continuing operations of $1.88 per share for 2012.

On slide 14, we show our lifting costs for Mcfe produced by quarter, relating to our continuing operations. Lifting costs of this chart are comprised of three components; production taxes, transportation costs, and other field-level operating costs. Our total lifting cost increased $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 and the fixed nature of much of our lifting costs, plus the higher cost of our oil production. Production taxes were $0.26 per Mcfe in the fourth quarter, and our transportation costs also averaged $0.26 in the fourth quarter. Field operating costs 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 quarter, as compared to $0.21 per Mcfe in the fourth quarter of 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 relating to our continuing operations. We spent $344 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 the $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 are expecting to spend $450 million for drilling activity this year. $264 million will be spent in our South Texas Eagle Ford program to drill 40 net wells, and then we'll 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 2 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 at 585 Bcfe, 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 in South Texas added 5.3 million barrels of oil and 5 Bcf of natural gas, or 6.1 million barrels of oil equivalent, to our proved reserves in 2013. We were able to replace 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 costs for 2013, excluding the exploratory acreage costs, calculates to $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 total capitalization, as compared to the 59% at the end of the first quarter of 2013.

On [October] (corrected by company after the call) 15, we redeemed our 8.375% 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 costs the Company around $6 million a quarter. As shown on slide 21, only one-third of the 61 E&P companies we survey actually pay a dividend. Of those 61 companies, we have the second-highest dividend yield of 2.7% as of December 31.

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

Thanks, Roland.

On slide 22, we cover our South Texas operations, where all of our current drilling activity is 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 2013, we have drilled 129 of the locations.

Slide 23 shows the 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 6, or 3.8 net wells, that were drilled in 2012. These wells had an average 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 IP 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 tracked 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. Costs have been reduced to an average of $7.9 million per well this year. Faster drilling times and lower well stimulation costs account for much of the savings.

We expect the 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 costs. The effective average well cost in 2014 to Comstock on an eight-eighths basis improves to $6.4 million with the joint venture.

On slide 26, we show the progression of 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 was 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 lateral 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 pump 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 Ford 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 IP'd at greater than 1,000 BOE per day, as shown by the red dots on the map. Our first well will likely be located near the western edge of our acreage, and we will test the rest of the acreage during the year.

We have planned to drill 10 gross wells on the acreage during 2014. We are targeting $9.5 million per well for the initial wells, as we'll 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 29, 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 in Mississippi, and East Feliciana 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 on this map show recent TMS wells initial production rates over 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 will now turn it back over to Jay.

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 rates of 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 declines we are facing to allow us to have higher revenues and cash flow and be a much more profitable company this year.

Oil now comprises more than 26% of production, even after the sale of our Permian Basin properties, and will 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 have expanded our inventory of oil-drilling locations by completing bolt-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. We now have a very strong balance sheet after the west Texas divestiture. We have over $400 million in liquidity, after the retirement of our 2017 bonds that we completed on October 15.

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

(Operator Instructions)

Your first question comes from Amir Arif, Stifel. Your line is open. Please go ahead.

Good morning, guys. I don't know if I missed it, but can you give us the timing of when you're going to start growing the East Texas Eagle Ford?

This is Mark. Our goal is to have a rig moving over there in March. And, that's what we're shooting for right now.

Okay. And then, so the first production result may be in 2Q?

It could be June, July. We'll spud our first TMS well in June, July. So I think first production from East Texas Eagle Ford, maybe June -- late June, about the same time that we spud our first TMS well.

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

This is Roland. I think that -- basically, longer-term prices that we can hedge at $5. We don't have a specific, exact number. But, that's where we have competitive returns from the natural gas projects in the Haynesville to the oil.

To the extent that we get that type of a market that we'll look to potentially hedge that price. And then, look at -- of course, using the additional revenue from the higher gas prices would help support some of the drilling costs. And then, we'll weigh whether or not we want to reduce any oil drilling, based on the price for oil is at that time.

Okay. Thanks, guys.

Your next question is from Don Crist, Johnson Rice. Your line is open.

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

Yes, Don, this is Mark. That well was completed in September, and it's producing about 200 barrels a day right now. Last time I looked at it, that's about where it was.

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

So, your well that you're getting ready to drill in March should be considerably longer -- what was the lateral length of that well? And, what are you looking to drill on this next well?

I believe that was about a 4,500-foot lateral. Our goal is to average in the 6,500 to 7,000-foot range. You know, it is Texas, so every unit is shaped a little differently, so there will be some variation in length out here. We'll have some longer ones, we'll some a little bit shorter, but that's our goal.

Okay. And, what do the prospects looks like out there? Is there acreage for sale out there at a decent price? Or, is it pretty much leased up for now?

By and large, it's leased up. It sits underneath the Giddings Austin Chalk field, so much of the acreage is held by production by mature Austin Chalk wells. There is a little bit of open acreage, but we feel like the parties that are involved have picked up most of it at this time.

Okay, and --

The acreage we picked up was about [30,000] (corrected by company after the call) acres. It was a big block. We don't see any more big blocks available. I think we were fortunate, as Mark said, to get our interest in that block. We are still shopping for acreage that we think is, quote, core.

And then I think, pertaining to our location, Clayton Williams has hit a pretty good well, as you have probably followed. Our well will probably be as close to that well as possible, our first well. That's where we're looking. And I think Halcon is about 1.5 miles away. I think Clayton is about three miles away. Some of Halcon's leases are 5 miles away.

But, we certainly like what we've seen from the well results from Clayton and others. We think it will be a pretty aggressive area in 2014. So, we're -- I think we're fortunate to have paid the prices that we 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 de-risked 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 until 2015. We have to drill two or three wells by the end of 2015. But, we have 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 are going to see some activity in the TMS, of course from Goodrich and from Encana, Sanchez and others. So, I think what we're looking for is good performance in the East Texas Eagle Ford, this year, continued performance in our South Texas Eagle Ford. Then, at the end of 2014, early 2015, I think you will see a budget that will emphasize the East Texas Eagle Ford a little more, and it will emphasize the TMS if that continues to be de-risked. That's our business plan right now.

Okay, thanks for the color, Jay. And, you recently -- I mean earlier in the call talked about 600 added locations. Is there any way you can break that out between the TMS and East Texas Eagle Ford?

No, but you know if you look at what we look at now, it's early on in the game. We're seeing our East Texas Eagle Ford be a 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, when we look up on our drill sites there, maybe 250.

If you go over 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 there. I threw out a 600 number to be in the middle of all that. I think it could be materially higher than that. I think what you've seen is -- and I started out the conversation telling you that in the West Texas area, we spent that $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, and a 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 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 as many drill sites in our East Texas Eagle Ford and the TMS that we, quote, had sold when we divested ourselves in the West Texas properties.

And you notice at the very end of that 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, 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 dance, and have a balance of locations for both oil and gas. And, you know what, today, 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. If you look at where gas prices were average in 2012, the $2.50; 2013, they average $3.40 or $3.50; today, they are like $4.50, $4.60. We truly sit on, almost an HPB'd 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, we have pretty much an A-plus going today, versus a year ago.

I appreciate all the color, Jay. I will turn it back, thanks.

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

I had a question about the 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, is a lot of the production growth going to be front-end loaded this year?

Again, we answered what we might be the future of the East Texas Eagle Ford. It's a guess, so based upon our best guess, we answered that. And then, Mark, you want to answer them?

Yes, Ray, as far as production goes, we're 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. We jumped up at the beginning, and our goal is to maintain that or build it a little bit as we go. So, yes, you're right, it is pretty front-end loaded.

Got it. Great, thank you.

Your next question comes from Rehan Rashid, FBR. Please proceed.

Morning. Jay or Roland, maybe a quick question on gas prices first. Henry Hub has been hanging in there much stronger than NYMEX. Maybe a quick reminder as to how you sell your gas? How much per week; how much every day? And then, I've got a follow-up question.

Sure, Rehan, this is Roland. We typically are selling only 10% to 15% of our gas on the spot market, which is really where you see the daily index prices that you've 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.

Got it. Okay. Good. Thank you.

And then, on East Texas, maybe Mark, what incremental technical work, maybe in broad strokes, has been done since we picked up the acreage and the 10-well program, is that dependent on successes? How much of it is dependent on successes? And that should be good.

Yes, Rehan, as far as incremental technical work, we're monitoring all the activity and what's being done in terms of results from Clayton William, 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, where they're landing. We have met with a couple of the 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 where we will get full suites of logs. We'll probably core one well. We aren't sure which one yet, but we will probably core a well to try to gather some technical information that will help us 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 the South Texas Eagle Ford, so a lot of the information we've learned down there will apply here, but there's always some nuances that we'll need to adjust as we go forward on that.

Okay. Good. Real quick one, Roland, did we buy back any stock in the fourth quarter?

No, Rehan, 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 markets. It's not an automatic plan. So, what happened in the fourth quarter, a good bit of the fourth quarter, we were really blacked out from making purchases, because we had the normal blackout periods around operating results.

We also had a fair amount of press releases around acquisitions, so we really didn't have much opportunity to look at that. As the window opens back up for us later on this month, we'll go back to looking at where we might want to purchase shares. We still have the $90 million of the plan still available to us.

Remember, Rehan, like Roland said, in the fourth quarter, we announced the TMS, and then we came back several weeks later (inaudible -- technical difficulties) where we announced the East Texas Eagle Ford. So, as we added those, we were blacked out before and after that, so --

Yes, makes sense.

Again, I'd like to comment that at this time last year, February of last year, I don't think any analyst 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 toward natural gas is probably looking to be correct.

We're seeing (inaudible -- background noise) numbers; we're seeing gas spike up. We've seen cold weather. So, I hope you're right in your forecast that we are going to see almost a $5 gas this year. If that happens, like Roland said earlier (multiple speakers).

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, where we can hedge that and put a real program in that complements our East Texas and our South Texas Eagle Ford, then that's what we're really wanting to do.

We want to continue to keep a sound, solid balance sheet. If we see the East Texas Eagle Ford be de-risked 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 out of that program, or looking at the Haynesville, et cetera.

But, I think our bumper guards are we're going to have material liquidity and a strong balance sheet. We're going to have -- our goal is to have the 77% to 100% growth in oil. And then, if we want to add the Haynesville -- and it's if we want, not that we have to drill wells because of some throughput contract we've signed, then we can drill Haynesville wells. That's how we've looked at it.

Got it. Thanks, Jay.

Your next question comes from Kim Pacanovsky from Imperial Capital.

Good morning, Jay.

Hi, Kim.

Hi. I have a question on your EURs, you have 450 to 550 MBOE on your presentation, and I was wondering if -- 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'm assuming the 450 MBOE is probably up in Atascosa and the closer to 550 MBOE is McMullen. 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?

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

Okay. One of the reasons I'm asking the question is Carrizo, who has acreage in LaSalle close to you, has increased their type curve from 495 to 523. They're using an average number, and not giving us a range. I guess if you weighted the acreage, where -- let's look at it this way, if you weighted the acreage, where would that number fall out, on the higher side or the lower side?

It probably should fall out in the middle, that's how we like to give --

Okay. All right (laughter).

As far as -- it's a very profitable program and has met all our expectations. We're not a company that likes to tout EURs and to take them to the maximum possibility that some companies do.

A lot of that, Kim, goes also to downspacing. In other words, do you (multiple speakers) oil downspacing. We want other companies to be successful in downspacing to 30s and 40s and 80s and whatever. And if we can get there, believe me, let them drag us across the finish line.

We would like to be there. It's not that we're not trying to get in the same area they are at, but we just haven't gotten there yet. I hope they're right and we'll be right after a while. And, that means you can double our drill sites, but we don't believe that right now.

And your location count is on what spacing?

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

Right. Anywhere from 80 -- it depends on the length of the laterals --

Got it, okay --

100 acres per well.

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 you've met with some of them. Is there anything you've 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 data coming out recently, but just in maybe 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?

Let me comment, globally, and then let Mark, if he wants to comment. 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 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 on the learning curve to decrease the cost, to get this in the $10 million range, not $11 million or $12 million or $13 million drilling complete range.

But, get the cost down, because if we can get the costs down, which in every other play we've ever seen, we've reduced the cost. You take the South Texas Eagle Ford, we were at $11.4 million, now we're at $7.4 million to drill and complete a well that's much longer and has more proppant.

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

And, the oil is in place. We don't -- with the 1,500 wells that penetrated this, we don't have any question that on the acreage the oil is not in place. 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 to make it extremely competitive in South Texas. Mark, do you want to have any other comments, things that have happened out there?

Kim, this is Mark.

I guess the thing that's just a continued encouragement that we had when we bought this a few months ago were that 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.

We also know that Goodrich was able to successfully drill their latest well by drilling under the, quote, rubble zone, and get the well drilled to TD and get it cased. That's very encouraging, and we like that. Getting up that learning curve is going to help us a lot, and everybody is going to work together to do that. We have spoken with several of the operators. Everybody is very amenable to share data and to collaborate on operations.

We saw that being very successful in the Haynesville. There was probably less of it in the Eagle Ford, from our perspective, just because we were such a small player compared to some of the other operators. But I think that's going to be a key here, is the collaboration of the four or five key operators.

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

No, Roland is shaking his head the wrong way (laughter) --

Sorry, Roland. I had to ask. All right, guys, thanks very much.

Your next question is from Dan McSpirit, BMO Capital Markets. Please proceed.

Thank you, folks, good morning.

Good morning.

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 those plays to generate returns competitive with what you're drilling in South Texas?

Dan, this is Mark. On the East Texas Eagle Ford, we were looking at a type curve of 400 MBOE, and that gives us at the well cost of starting out at $9.5 million, but really development costs being around $8.5 million. That gives us very competitive returns with our South Texas program.

And then, in TMS, obviously, it's going to take a little bit more than that because the well costs are probably going to be in the $11 million to $12 million range, so we probably need to be in the 500 to 550 MBOE range for that to play to work as well. Still, we are going to work -- even at 400 to 450 MBOE, it's going to give you good returns, but maybe not quite as competitive as it would if it was the 500 MBOE range.

Okay, great. Thanks. And then, just on the subject of the dividend, how do you look at the dividend in light of drilling 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?

Yes, Dan, this is Roland. It's here to stay. We're very committed to maintain that dividend, not necessarily on a yield-percentage basis, but on the $0.50 a year, given that we don't have a lot of shares outstanding, is $6 million a quarter.

It's not really going to -- we're not tied to our own liquidity, where $24 million is going to really change our drilling budget one way or another. It's given that's -- we don't have a lot of shares outstanding. Yes, we're committed to maintaining that dividend. And, we don't really view it as competing with anything in the Company, given it's not a very large expenditure.

Okay. Great. And then, a question was asked earlier, with respect to acquiring additional leaseholds 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?

Both of those areas and South Texas, we continue to look for acreage that will complement our existing footprint -- all three of those areas.

We'll continue, and we've budgeted to fill in acreage, especially as we build units in the new plays. 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 plates really full.

And, we like the way that we don't have acreage with short expiration dates that's driving aggressive drilling beyond our cash flow. So, we like how the Company is positioned. But that doesn't mean we're not going to continue to add acreage in both these new plays, especially as we build up the units and we fill in acreage, we think it's -- especially in the TMS, that can be done at very attractive costs right now.

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

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

Got it.

Those will be -- they're definitely booked way below our target numbers, so with performance, they can positive revisions.

Right. Thanks, again.

Thank you.

Your next question comes from Leo Mariani, RBC Capital Markets. Please go ahead.

Just a follow 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 were all in one area of the play. Is it just kind of geography that's driving the better results there, or is there any changes in completion practice or drilling practice here?

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. We've tested them on both the Gloria Wheeler and one of our other leases, and we're monitoring the results right now to determine if we want to adjust our frac design, going forward, or keep it where it's at.

Leo, if you take the Oil and Gas Investor, there's about a four- or five-page story highlighting the South Texas Eagle Ford. Our completion crews are there. Mark's picture is there. They talk about how to frac it and stimulate it in zipper fracs. It's pretty good reading for anyone on the call if you have the Oil and Gas Investor. There' a lot of information about Comstock, and particularly the Gloria Wheeler area in McMullen county.

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

Leo, there wasn't any down time. 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.

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

I think the average of real similar of between the -- consistently through the year. The only thing that's -- this year compared to prior years, we just don't have many liquids that we would count in our gas prices. It's very dry gas out there. But nothing has really changed very much.

As you have lower volumes, you're just going to see more fixed cost that has an impact on that, where you have transportation going on and stuff. You have a lot of the cost of -- costs, even though they're modeled on a variable basis, they really are very fixed. As you have lower volumes, you are just going to have higher per-unit costs and higher transportation costs, et cetera.

Okay. Apart from the cost side of the equation, what type of pricing differential should we expect, say versus Henry Hub in 2014, if we eliminate costs and think about price here?

The 93% has been pretty consistent throughout all of 2013, as far as what we have averaged on Henry Hub. I think the pricing hasn't been that variable, really.

All right, thanks.

Thank you, Leo.

Your next question is from [Ryan Zurney], Raymond James.

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

Yes, this is Mark. I don't think we have any Atascosa wells planned in 2014. Everything is either in LaSalle or McMullen.

Right.

Okay, great. Thank you.

Thank you.

Your next question comes from Marshal 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 price was lower than what was I was expecting. What sort of differentials are you seeing now? What would be good guidance heading forward? And, what's your average API gravity for your liquids production in the Eagle Ford?

Right, as far as the gravity, it's probably going to be in the low 40s, that's probably our average. It goes anywhere from about 35 to about 48 or 49, I believe, so probably low-40s on average.

Our oil realizations are really based on LLS. The difference between if you model it off the WTI, we're not going to track WTI, we are going to track LLS because we're consistently there. It's going to be LLS minus $6 or $7 for transportation.

The API gravity is averaging in the low 40s and that's fairly consistent through quarter to quarter?

Yes, it is.

Okay, thank you. And, in terms of expense guidance, would you walk through that for 2014?

Why don't you get with Gary for real specific modeling questions after the call, if you could?

Will do, thank you.

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

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

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