Comstock Resources Inc (CRK) 2016 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Comstock Resources Inc. second-quarter 2016 earnings conference call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to turn the conference call over to Jay Allison, CEO. Please go ahead.

Abigail, thank you, and welcome to the Comstock Resources second-quarter 2016 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 downloading the quarterly results presentation. There you'll find a presentation entitled second-quarter 2016 results.

I am Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Burns, our President and Chief Financial Officer; and Mack Good, our Chief Operating Officer. During this call we will discuss our quarterly operating financial results and also the exchange offer we have launched today to further improve our balance sheet and liquidity.

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

Slide 3 -- a summary of our second quarter is outlined on slide 3. Oil and gas prices continue to be weak. Our realized oil price fell by 24%, and our average realized natural gas price declined by 16% in the second quarter as compared to 2015. Lower prices caused our oil and gas sales to fall by 46% to $42 million. EBITDAX came in at $19 million but was not high enough to cover our interest expenses this quarter of $29 million.

Our Haynesville drilling program continues to get better. All of the 13 wells drilled in 2015 and 2016 are performing above our 14 to 16 Bcf type curve. And the two additional wells we reported on today had an average IP rate of 24 million a day and added an additional 13 million a day from offset wells.

With low prices, we are very focused on improving our balance sheet. We have retired $107 million in long-term debt in 2016, which saves us $8.7 million in annual interest payments and $28.4 million in total interest.

We have total liquidity of $117 million and hope to add to that with our pending asset sale. We launched an exchange offer today to give us additional liquidity and flexibility to allow us to use our successful Haynesville drilling program to grow our revenues and cash flow to a level that works with our current leverage.

I will cover the exchange offer after Roland and Mack report on the second-quarter results. Roland will now go over the financial results. Roland?

Thanks, Jay. Slide 4 shows our natural gas production. Despite having limited capital available for drilling this year, we are expecting natural gas production to grow. We put a rig to work in March and drilled three 7,500 foot horizontal lateral wells, which have all now been completed. We recently released that drilling rig to conserve our liquidity.

Our natural gas production averaged 149 million cubic feet per day in the second quarter, which was 22% higher than the second quarter of 2015. 9 million cubic feet per day of our second-quarter production is from the South Texas gas properties that we plan to divest of this year. We expect our natural gas production in 2016 will average between 130 million and 145 million cubic feet per day, given effect of the divestiture, assuming we don't do any more drilling this year.

On slide 5, we summarized our oil production. Our oil production averaged 3,900 barrels per day in the second quarter, a 62% decrease from the second quarter of last year. The production decline is due to our sale of the Burleson properties in July of last year and also shutting down our oil drilling program at the end of 2014. With little drilling activity for this year, we expect oil production to decline further. We expect our oil production in 2016 will approximate between 3,800 and 4,100 barrels per day.

On slide 6, we summarize our second-quarter financial results. We had a 22% increase in gas production, offset by a 62% decrease in our oil production in the quarter. Production on an equivalent unit basis was also down 6%. Our oil and gas prices also declined; oil prices fell by 24%, and gas prices were lower by 16%. Oil and gas sales this quarter were down 46% to $42 million, and EBITDAX was down to $19 million.

We did see significant improvement on the cost side. Lifting costs in the quarter were down 26%, with lower production taxes and lower gathering costs and lower lifting costs from our properties. Our G&A costs were down 21% in the quarter; and our depreciation, depletion, and amortization was down 60% due to a large improvement to our DD&A rate. Our amortization rate in the quarter was $2.28 per Mcfe, which improved 58% from the 2015 second-quarter rate of $5.43 per Mcfe.

We did report a profit of $4.9 million in the quarter or $0.41 per share. The per-share numbers have been adjusted for our one-for-five reverse stock split, which went into effect today.

During the second quarter we had a small impairment of $1.7 million and a small loss in some property sales of $1.6 million. We also had a significant gain on the extinguishment of our debt of $56.2 million. If you exclude these items and other nonrecurring items, would have reported a net loss of $47 million or $4.05 per share.

On slide 7 we summarize the financial results for the first six months of this year. Our gas production increased by 42%, and our oil production decreased by 61%. Production on an equivalent unit basis was up 3%.

Lower oil and gas prices more than offset the production increase. Oil prices fell by 32%, and gas prices were lower by 20%. Oil and gas sales for the first half of this year were down 45% to $79 million, and EBITDAX was down to $34 million. But our costs also lower. Lifting costs in the quarter were down 20%, G&A costs were down 26%, and our DD&A was down 59%.

During the first six months of 2016, we had an impairment primarily related to the assets we're selling and also an impairment on some of the acreage that's expiring this year and next year totaling $32 million. We also recognized gain from the debt repurchases of a total of $90 million. Including these items, we reported a loss of $52 million or $4.82 per share for the first half of the year. If you exclude these items and other nonrecurring items, we would have had a net loss of $102 million or $9.52 per share.

We are providing a midyear update to our proved reserve estimates, which is detailed on slide 8. We grew our proved reserves from 625 Bcfe to 704 Bcfe during the first six months of this year through a combination of our drilling activity and the strong performance of our new Haynesville shale wells. The SEC prices that we had to use to determine proved reserves at June 30 were lower and fell to $37.86 per barrel as compared to $46.88 used in the year-end estimates for oil, and then $2.07 per Mcf for gas as compared to the $2.34 we used in the year-end estimates.

These lower prices caused downward revisions of about 35 Bcfe, and we also divested of about 5 Bcfe in the first half of the year. But our reserve additions, which were primarily from the Haynesville program, were strong, coming in at 151 Bcfe.

The level of proved undeveloped reserves that we can book continues to be very limited by our available capital which we have to drill these wells in the future. The midyear proved reserve estimate included only 32 Haynesville and Bossier proved undeveloped locations.

We have a total of 705 operating locations, including 345 extended lateral locations, which many of these otherwise might qualify as proved undeveloped locations. If you exclude the price-related revisions, we achieved an all-in finding cost of $0.20 per Mcfe by comparing the $30.3 million that we spent on our drilling program to the reserve additions of 151 Bcfe.

Slide 9 shows the balance sheet at the end of the second quarter. We have $67 million of cash on hand and $1.163 billion of total debt outstanding. Including our undrawn credit facility, our total liquidity is $117 million.

In the first quarter, we retired $40 million of our bonds by exchanging those for common stock. In the second quarter, we retired an additional $67 million of our bonds for $3.5 million in cash and shares of common stock valued at $6.9 million. To date, we've retired $237 million of our senior notes for $46 million in cash and 2.7 million shares of common stock. The repurchases have generated annual interest savings of $20.6 million, with total savings to maturity of $83 million.

I'll now hand it over to Mack Good to give you an update on our Haynesville drilling program.

Thanks, Roland. Good morning, everybody. If you flip to slide 10, you'll see a familiar map. It basically shows the location of our acreage, highlighted in blue, within the Haynesville and Bossier shale plays as well as the Cotton Valley trend that extends through East Texas and Northwest Louisiana. And as you can see, we have around 67,000 net acres within the Haynesville Bossier plays, and we have drilled 13 gross or 12.4 net horizontal wells within this region since the beginning of 2015.

I think most of you know already that all of the wells that we've drilled, all 13 of them, and completed since the start of 2015 have been extraordinary producers. Slide 11 gives you some information about why we have been able to be so successful.

First, we decided to extend the horizontal length of any Haynesville or Bossier well we drill from the traditional 4,500 foot length we had drilled before to something approaching 7,500 foot in length. We then changed our completion design to include less gel loading; fewer perforation clusters per stage; less distance between each cluster; and, last but not least, more profit.

This combination of changes, in a nutshell, has allowed us to reach rates of return between 49% to 79% at gas prices ranging from $2.50 to $3.00 per Mcf at current well costs. This type of economic benefit also extends to all the various horizontal wells that are in our drilling inventory, and I will give you some more detail on our project economics a little later.

This kind of economic benefit this obviously what we always target, and this is especially important within the very challenging market environment that exists today. Obviously, the more opportunities an operator has to create this kind of economic value within a challenging market, the better. And as slide 11 shows, we do have a large inventory of these opportunities within our acreage. We have mapped 393 future Haynesville and 322 future Bossier drilling locations with various lateral lengths within our shale play acreage position. That large drilling inventory is made even more attractive by the fact that Comstock has a very favorable gas marketing arrangement package for its shale play gas production.

Moving onto slide 12, you'll see the locations of the 13 wells we have drilled and completed since the beginning of our enhanced Haynesville and Bossier development program which we started in January of 2015. This slide also shows the two Haynesville wells we refracked during 2015. You might remember that the 11th well in our 13-well package was the Jordan well. This was our only Bossier test in the 13-well program, and it's noted at the bottom of the slide 12 mapped area. Keep in mind that this Bossier well is also an excellent performer, and it is producing well above our Haynesville type curve, just as all [of our other] wells are.

Also, since our last report to you, we've added a couple of new well completions to slide 12. During the second quarter, we drilled and completed two additional Haynesville wells as our 12th and 13th program wells. Our 12th well was the Harrison 30-31 #1, having a 7,063 foot completed horizontal lateral with initial potential of 24.4 million a day. We then drilled the Holmes 29-30 #1 as our 13th program well, and it had a 7,451 foot horizontal completion that tested at 24.3 million a day.

As you can see, these last two Haynesville wells are performing just like our first 11. Both of our last wells fell within our expected performance range and are also producing well above our Haynesville type curve.

Speaking of our Haynesville type curve, it's shown on slide 13, along with the production from all 13 of our program wells, and all of our wells are producing at or above the Haynesville type curve. In fact, most of them are producing well above our type curve. But I want to note that for our economic forecast, we're only using the type curve production rather than an average taken from our 13 wells. We like this conservative approach since it takes a lot of forecast risk right off the table.

I mentioned earlier that I'd give you some more detail on our project economics. Well, the next few slides will get that done. Slide 14 shows our current assumptions that are included in our project economics. For example, our current D&C costs are pegged at $8.5 million for our standard 7,500 foot horizontal Haynesville well, having a 20 million a day IP rate and a 15.5 Bcf EUR. All of this data and more is given for our 4,500 foot and 10,000 foot horizontal Haynesville wells.

All of the decline parameters and EUR forecast metrics are supported by the performance of our 13-well program. And again, I want to remind everybody that our economic forecasts are based on the production forecast by our established Haynesville type curve, and that all of our wells are producing at or well above that curve. So for this reason alone, we believe our economics are conservative.

Based on all this information, I'm going to throw a few economic indicator numbers at you. Slide 15 is a plot that shows how the rate of return varies with gas price for our various Haynesville horizontal completions. And as you can see, the 7,500 foot and 10,000 foot lateral length RoR curves are almost identical. This is basically because we have chosen to be conservative with our 10,000 foot horizontal well production forecasts.

You can read the graph for yourself, but you can see that even at a $2.00 gas price, both the 7,500 and 10,000 foot lateral wells still generate 25% RoRs. If you jump to a $2.50 gas price, keep it flat, you'll get a 49% RoR; and at $3.00 you get a 79% RoR for both of these horizontals. And even a 4,500 foot horizontal completion will generate a 30% RoR at a $2.50 gas price, and it will climb to a 53% RoR if the gas price is at $3.00. These economic results, along with our drilling inventory, speak for themselves.

Slide 16 is the same kind of plot as before, but it shows how the NPV varies with gas price for our various Haynesville horizontal completions. This time you can see that the 7,500 foot and 10,000 foot lateral length curves separate, and it's obvious that the 10,000 foot lateral will give you a higher NPV at [this same] flat gas price. Again, reading the graph, it's easily seen that at a $2.50 flat gas price, the 10,000 foot lateral gives around a $9 million NPV, while the 7,500 foot lateral gives you about a $6.5 million NPV. At that same $2.50 gas price, the 4,500 foot lateral generates a $2.8 million NPV. Bump the gas price to $3.00, keep it flat, the 4,500 foot lateral jumps to a little over $5 million NPV.

The biggest takeaway for me, after staring at all these economic indicators and numbers, is knowing that they are pretty conservative forecasts. And given our drilling inventory, we have a lot of different options for the kind of well we want to drill within different gas market conditions in order to maximize profitability. That kind of flexibility is exactly what any oil and gas operator wants and needs.

Moving on to the next slide, I want to briefly talk about some additional upside that we believe exists within our Haynesville development acreage. This slide shows the staggered lateral concept that we think will work and work very well within most of our Haynesville acreage position.

The Haynesville overall thickness approaches 200 feet throughout most of our acreage, and most of our legacy Haynesville wells are completions that target only the upper section of this thickness. Since the lower section of the Haynesville is also extremely prospective, we believe that it offers an excellent additional target for completion. Our preliminary staggered well development pattern would add an additional 83 Haynesville locations with extended laterals to our existing inventory.

And if you assume each well would produce 12 to 15 Bcf per well, this would add an additional gross reserve base between about 1 Tcf to 1.25 Tcf. So when we resume drilling in the Haynesville, one of the program wells we would like to drill will be our first staggered Haynesville 7,500 foot lateral well completion.

Slide 18 highlights our 26,000 gross/19,000 acre net position in the Eagle Ford shale play. Our acreage is not fully developed, and most of it resides within the Frio, LaSalle, and McMullen counties. Our map shows that most of our acreage has been the black oil window, with a small amount of acreage extending into the volatile oil area of play. Based on our current mapping, we think we have around 83 future drilling locations within our acreage position. I think it's pretty clear that since the beginning of 2015, we've been focused on our Haynesville and Bossier assets. But our Eagle Ford assets also offer us considerable additional development potential as the oil market improves into the mid $50 to upper $50 oil barrel range. And I would like to briefly tell you why we think this is so.

I think slide 19 tells the story. We believe that we have considerable stacked or staggered lateral development potential within our Eagle Ford acreage position. This is being supported by offset operator activity as well as our own internal evaluations.

As you can see in this slide, the Eagle Ford is about 130 foot thick throughout most of our acreage position, and our current completions mostly target the lower section of the Woodford. As a direct consequence, we believe the upper section of the Eagle Ford offers an opportunity for future development. A number of operators are successfully employing this staggered approach and are spacing their staggered wells much closer than our current plan suggests.

Our current staggered spacing plan calls for 325 feet between wells and could create an additional 253 locations with varying lateral lengths. If you assume 250,000 gross barrels of oil EUR per well, this would generate an additional gross reserves approaching 65 million barrels. Once the oil market improves, as I said, into the mid-$50s to high $50s per barrel oil range, Comstock has plans to drill a two-well pilot test of our staggered lateral concept to confirm the potential.

So I've gone from the Haynesville and Bossier to the Eagle Ford and back again. And so with that, I'll turn it back over to Jay.

Thank you, Mack; and also, Roland, thank you. Go to slide 20, if you would. Today, we announced that we are commencing an exchange offer of [no-secured] notes in exchange for all of our existing senior notes, as outlined on slide 20. The exchange offer was commenced following many, many months of dialogue with representatives of certain of our current noteholders.

Our existing senior secured notes are exchangeable into new first-lien secured notes with warrants for up to 1.050 million shares of common stock. Those secured notes allow the Company to pay in kind [to] interest payments. Our unsecured notes can be exchanged into new secured second-lien notes, which will be convertible into shares of the Company's common stock. These bonds require that all interest is paid in kind to maturity.

The total shares related to the convertible bonds in the warrants represent approximately 75.6% of the Company's total issued and outstanding common stock. The exchange is intended to improve our capital structure, decrease our cash interest expense, enhance our near-term liquidity, and allow us to resume our successful drilling program in the Haynesville shale.

The savings and interest expense, combined with our existing liquidity, provides us the cushion to build up cash flow and reserve value with our proven and very economic drilling program, as shown on slide 21. In order to preserve liquidity, we recently released our last operated rig after drilling three additional successful Haynesville shale wells in 2016. This will allow us to preserve more of the cash from our balance sheet, but it will result in future reductions to our natural gas production and proven oil and natural gas reserves.

With no additional drilling in 2016 in 2017, oil and gas production would continue to decline from 2016 levels of 2,800 to 3,100 barrels of oil per day and 90 million to 100 million cubic feet of natural gas per day. The expected production declines may offset the benefit of the recent improvement in natural gas prices.

We have plans to resume our Haynesville drilling program in October of this year. After returning one rig to service, we plan to add a second in late 2016 and operate a two-rig program in 2017. To the extent that the drilling program is restarted, our 2017 natural gas production could average between 190 million and 210 million cubic feet of natural gas per day in 2017 with this drilling program.

Capital expenditures for this program would approximate $46 million in the second half of 2016 and $147 million in 2017. With such a program, our gas production EBITDAX be almost double from where we are now.

On slide 22 we outline the rationale for this transaction that we've announced today. Our Haynesville, Bossier, and South Texas Eagle Ford assets are Tier 1 assets. In the Haynesville/Bossier we have spent the last 18 months successfully drilling 13 long-lateral horizontal wells, as Mack described earlier, that created tremendous value for us because of our inventory of over 700 operated locations. This marquee natural gas asset will be the driver of our growth.

In the South Texas Eagle Ford, we have drilled over 190 horizontal wells. We still have 83 future drilling locations and 253 potential additional infill locations with stacked, staggered lateral development. This marquee oil asset will be developed when oil stabilizes in the $50 range. But in order to properly develop our high-quality asset base, we have to rebuild our balance sheet.

Looking back 20 months ago, we were one of the first to release rigs and discontinue drilling for oil. And we're an early leader in transforming the Haynesville into one of North America's highest natural gas return basins.

Today we are taking another major step with this transaction that sets the stage to rebuild our balance sheet. This transaction, one, allows us to conserve cash from interest expense. Two, it allows us to enhance our liquidity. Three, it allows us to put rigs back to work. Four, it allows us to further delever through conversions of unsecured debt into equity. And finally, it allows us to have access to the capital markets in the future as we grow our EBITDAX, cash flow, and proved reserves.

This transaction at its very core allows every stakeholder to win -- either the secured, unsecured, or an equity stakeholder -- because it allows us to focus on our core strategy of drilling wells with competitive economics funded within cash flow. Our Haynesville shale wells have the attributes to deliver strong economic results, which we have proven with the 13 wells that we have drilled that Mack reported on.

With a vast inventory of 700 operated locations, we can scale the drilling activity based on the strength of the natural gas market. And again, we think this transition is fair to all the stakeholders who have continued to support us in this tough environment. The exchange would allow noteholders to retain their claim and preserve the asset value and equity in convertible noteholders to benefit from share recovery. Because of the exchange offer, will not be able to take questions today as we always do. So we apologize for that.

If you're a bondholder, we would be pleased to meet with you to discuss the transaction. If you would, please reach out to Gary Guyton in our office at 972-668-8834 to arrange the meeting.

Again, thank you for participating in the conference call.

Ladies and gentlemen, thank you for participating in today's call. This does conclude the program. You may all disconnect. Everyone, have a great day.