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Text: On behalf of the, say, 204 or 205 Comstock employees and the board of directors, I'll make a few opening comments, and then we'll go to the results.
First, Comstock's shift, I think as Ron Mills has talked about to the analysts, I think Comstock's shift to longer laterals, the 10,500-foot laterals in 2022 versus the 8,800-foot laterals in 2021, you should all know that it's expected to create a great value on a per well basis going forward.
We have better cost efficiencies.
We should have a lower decline curve, thus an increase in well performance.
The higher capital efficiencies associated with the longer laterals did allow us to more than offset the impact of higher service costs in the fourth quarter of 2021.
You can see that in the numbers.
And we have seen higher service costs.
We will use commitment from the board and from management.
We'll use the free cash flow to pay off the revolver and redeem the remaining $244 million of the 2025 bonds.
We do have a target, continue to have this leverage ratio at 1.5 or less.
We think we can get there in the second half of 2022.
And that does open discussions up on returning capital to shareholders.
I know we may have that question.
Our drilling inventory, which is the holy grail of E&P companies, I think that's why you have a lot of M&As in the last year or two years.
But our drilling inventory has never been more valuable or stronger.
Because in 2021, we made great strides in extending our lateral length per location by 25% from our average lateral length at the end of 2020 it was 6,840 feet, and today, it's about 8,520 feet.
If you look at that, 25 years' worth of drilling inventory based upon our 2022 activity, we've got 1,633 net locations.
53% of those were Haynesville, 47% were Bossier.
And just think, I mean 902 net locations with lateral lengths 8,000 feet or longer.
On the operational front, which is I think that's the nucleus of this company, on that front we increased our drilling footage per day by 25%.
We went from 800 feet to 1,001 feet per day, and that's how you make money.
Our average lateral length at the wells in the fourth quarter, 11,443 feet.
And the reason is we drilled four 15,000-foot lateral wells, two Haynesville, two Bossier.
Again, in spite of higher service costs, we're able to lower our drilling and completion costs due to improved operational performance and improved capital efficiencies associated with the longer laterals drilled in the fourth quarter of 2021, which that will be carried over into 2022.
We have a few slides to take you back to 2018 and be accountable for our performance.
That was kind of a turnaround year.
That's the year that Jerry Jones and his family invested in Comstock.
And since that time, Comstock has surfaced as the only pure-play Haynesville producer.
I'm Jay Allison, chief executive officer of Comstock.
With me is Roland Burns, our president and chief financial officer; Dan Harrison, our chief operating officer; and Ron Mills, our VP of finance and investor relations.
While we believe the expectations and such statements will be reasonable, there could be no assurance that such expectations will prove to be correct.
Our fourth quarter 2021 highlights, Slide 3.
We cover the highlights on the fourth quarter on Slide 3.
In the fourth quarter, we generated $105 million of free cash flow from operating activities, increasing our total free cash flow generation for 2021 to $262 million.
Including the impact of our acquisition and divestiture activity, our total free cash flow for the year was $343 million.
For the quarter, we reported adjusted net income of $99 million or $0.37 per diluted share.
Our operating cash flow for the quarter was $250 million or $0.90 per diluted share.
Our revenues, including our realized hedging losses, increased 37% to $380 million.
Our adjusted EBITDAX in the fourth quarter was $297 million, 41% higher than the fourth quarter of last year.
Our production increased 12% in the quarter to 1.348 Bcf a day.
In the fourth quarter, we completed two 15,000-foot Haynesville wells, which had IP rates of 48 million and 41 million cubic feet equivalent per day, both of which are new corporate records that Dan Harrison will review in a moment.
During the quarter, we also closed on the sale of our Bakken properties and closed a bolt-on acquisition for $35 million.
If you'll flip over to Slide 4, we'll go over some of the major accomplishments in 2021.
We significantly reduced our cost of capital by refinancing $2 billion of our senior notes in March and June, which saved us $48 million in cash interest expense and extended our average maturity from 4.7 years to 7.1 years.
We also reduced the amount outstanding under our bank credit facility by $265 million with our free cash flow and asset sale proceeds and improved our leverage ratio to 2.2 times as compared to 3.8 times in 2020.
With another successful year in our Haynesville Shale drilling program, we drilled 64 gross or 51.9 net wells, including four 15,000-foot laterals.
On the wells we put to sales at an average IP rate of 23 million cubic feet equivalent per day, we grew our SEC proved reserves by 9% to 6.1 Tcfe with a PV-10 value of $6.8 billion.
We replaced 199% of our production at a low all-in finding cost of $0.60 per Mcfe.
Highlighting our attractive cost structure, we achieved a 78% EBITDAX margin, one of the highest in the industry.
In addition, we achieved a 12% return on average capital employed and a 27% return on average equity.
In 2021, we added 49,000 net acres to our acreage position prospective for the Haynesville and Bossier through a leasing program and acquisitions totaling $57.7 million or $1,178 per acre.
We took several big steps in 2021 on the environmental front.
Early in 2021, we partnered with BJ Energy Solutions to deploy its next-generation natural gas-powered Titan Frac Fleet, which is expected to be put in service in April.
The most significant step we took was to partner with MiQ to certify our natural gas production under the MiQ methane standard.
Flip over to Slide 5 and we recap the bolt-on acquisition in East Texas that we did close late December for a purchase price of $35 million.
The acquisition included 18.1 net producing wells and 17,331 net acres in Harrison Leon, Panola, Robertson and Rust counties.
With the acquisition, we added 57.9 net drilling locations which represents approximately one year's worth of our drilling inventory.
The acreage is 94% held by production, but the acquisition also added the lateral lengths on 44 of our existing drilling locations to be increased.
Our production increased 12% to 1.35 Bcfe a day.
Adjusted EBITDAX grew 41% to $297 million.
We generated $250 million of discretionary cash flow during the quarter, 62% higher than 2020's fourth quarter.
And our adjusted net income totaled $99 million during the quarter, a 186% increase from the fourth quarter of 2020.
We generated $105 million of free cash flow from operations in the quarter or $204 million if you include the impact of the acquisition and divestiture activity, which most of that occurred in the fourth quarter.
This free cash flow contributed to an improvement in our leverage ratio, which improved to 2.2 times, down from 3.2 times at the end of 2020.
Our cash flow per share during the quarter was $0.90 per share, up from $0.56 in the fourth quarter of 2020, and adjusted earnings per share was $0.37 per share as compared to $0.14 in the fourth quarter of 2020.
On Slide 7, we show how much Comstock has changed since 2018 when Jerry Jones and his family invested in the company.
Production growth has averaged 117% over the last three years.
EBITDAX has gone from $287 million to $1.1 billion at a compounded annual growth rate of 97%.
Cash flow has grown from $206 million back in 2018 to $908 million this year in 2021, averaging 114% over the last three years.
Adjusted net income has grown from $29 million to $303 million at a compounded annual growth rate of 319% and free cash flow from operations has grown to $262 million, and our leverage ratio has improved from four and a half times to 2.4 times.
On a per share basis, cash flow has gone from $1.96 to $3.29 and earnings has gone from $0.27 to $1.16.
On Slide 8, we provide a breakdown of our natural gas price realizations.
And this is an important slide to understand the quarterly results as we've had a very volatile NYMEX contract during the fourth quarter which has continued into the first quarter of this year.
On this slide, we show how the NYMEX contract settlement price, and we show the average NYMEX spot price for each quarter.
During the fourth quarter, there was a very significant difference between the quarter's NYMEX settlement price of $5.83 and the average Henry Hub spot price of $4.74.
During the quarter, we nominated 67% of our gas to be sold at index prices, which are more tied to the contract settlement price or the final price that the contract comes off the market at.
And then we also sold 33% of our gas in the daily spot market.
If you use those percentages, the approximate NYMEX reference price for looking at our activity in the fourth quarter would have been $5.47, not $5.83.
Our realized pricing from the fourth quarter averaged $5.22, which reflects a $0.25 differential from that reference price, which is fairly in line with our historical results.
In the fourth quarter we were also 72% hedged, so that reduced our final realized gas price to $3 per Mcf.
On Slide 9, we detailed our operating cost per Mcfe and the EBITDAX margin.
Operating costs per Mcfe averaged $0.67 in the fourth quarter.
That was $0.02 higher than the third quarter rate.
Our lifting cost and gathering costs were both up by $0.01, but production taxes were down by $0.03.
Higher G&A costs of $0.08 was also higher in the quarter, and that's primarily related to year-end adjustments for bonuses.
We do expect our G&A to go back to average somewhere between $0.06 to $0.07 per Mcfe in 2022.
Our EBITDAX margin including hedging came in at 78% in the fourth quarter, unchanged from our third quarter margin.
On Slide 10, we recap our fourth quarter and full year 2021 drilling and completion costs.
In the fourth quarter, we spent $140 million on development activities, $114 million of that related to our operated Haynesville and Bossier Shale properties.
We also spent $8 million on non-operated wells, and we had $15 million that we spent on other development activity in the Haynesville, in our Haynesville operations.
We spent an additional $3 million for our properties outside of the Haynesville.
For the full year, we spent $628 million on development activities.
$554 million was related to our operated Haynesville and Bossier Shale properties.
We also spent $74 million on non-operated activity and for other development activity outside of just drilling and completion.
We drilled 51.9 net operated Haynesville horizontal wells, and we turned 54.2 net wells to sales in 2021.
We also had an additional 2.2 net wells from our non-operated activity.
In addition to funding our development program, we also spent $58 million on acquisitions.
Most of those acquisitions related by an undrilled Haynesville shale acreage.
Slide 11 covers our proved reserves at the end of 2021.
We grew our SEC proved reserves from 5.6 Tcfe to 6.1 Tcfe in 2021, and we replaced 199% of our production.
Our 2021 drilling activity added 797 Bcfe to proved reserves, and we had about 89 Bcfe of positive price-related revisions.
We also added 203 Bcfe of proved reserves through our acquisition activity.
The reserve additions were offset by a divestiture of 100 Bcfe, which is primarily our Bakken shale properties.
Our all-in finding costs for 2021 came in at a very attractive $0.60 per Mcfe.
Our drill pit finding costs for '21 came in at $0.71 per Mcfe.
Our reserves are almost 100% natural gas following the sale of our Bakken properties.
The PV 10 value of our proved reserves at SEC pricing was $6.8 billion at the end of last year.
In addition to the 6.1 Tcfe of SEC proved reserves, we have an additional 2.4 Tcfe of proved undeveloped reserves which are not included in that number as they are not expected to be drilled within the five-year window required by the SEC rules.
We also have another 4.4 Tcfe of 2P or probable reserves, and we have 7.2 Tcfe of 3P or possible reserves for a total overall reserve base of 20.1 Tcfe on a P3 basis.
Slide 12 shows our balance sheet at the end of 2021.
We had $235 million drawn on our revolving credit facility at the end of the year after repaying $265 million during 2021.
The reduction in our debt and the growth of our EBITDAX drove a substantial improvement to our leverage ratio, which was down to 2.2 times in the fourth quarter on a stand-alone basis as compared to 3.8 times in 2020.
We plan on retiring $479 million of debt in 2022.
That would include redeeming our 2025 senior notes.
We are targeting to be below 1.5 times levered in 2022, and we ended 2021 with financial liquidity of almost $1.2 billion.
Flip over on Slide 13.
This is where we show our average lateral length we drilled by year going back to 2017 along with our estimated average lateral length for this year and also our record longest lateral that we've completed to date.
In 2017, our average lateral length was 6,233 feet as we were drilling primarily a mix of 4,500-foot and 7,500-foot laterals, and we had just started drilling our first 10,000-foot laterals.
In subsequent years through 2020, we slowly increased the number of 10,000-foot laterals that we were drilling, which allowed us to gradually increase the average lateral length.
In late 2020, we successfully drilled and completed our first lateral exceeding 12,500 feet, and our average lateral length in 2020 had increased to 8,751 feet.
Now, through the end of 2021, we have successfully drilled and completed four 15,000-foot laterals with two drilled to the Haynesville and two drilled into the Bossier.
In 2021, our average lateral length increased to 8,800 feet.
Our record longest lateral to date is 15,155 feet and was drilled and completed in the Haynesville in late 2021.
Building on the success of our 15,000-foot laterals, we now anticipate our average lateral length to increase by 19% in 2022 up to 10,484 feet.
In 2022, we anticipate drilling approximately 21 wells with laterals longer than 11,000 feet and nine of these being 15,000-foot laterals.
By continuing to execute our long lateral strategy, we'll be better able to maintain our low-cost structure into the higher price environment.
On Slide 14, we highlight the improvement in our drilling performance, which is based on the total footage drilled divided by the number of days from spud to TD.
Our drilling performance was relatively stable from 2017 through 2019 in the 700-foot per day range.
In 2020, our drilling performance improved 15% to 800 feet a day.
And in 2021, our drilling performance improved an additional 25% to just over 1,000 feet per day, while our record fastest well to date was drilled last year at an average rate of 1,461 feet a day.
The performance improvements have been achieved via drilling the longer laterals combined with sound drilling practices, improved tool reliability and execution at the field level.
With our goal of drilling longer laterals in future years, we expect to maintain our drilling performance at a very high level.
On Slide 15 is our updated D&C cost trend for our Bismarck long lateral wells.
These are wells with an average lateral length greater than -- with a lateral greater than 8,000 feet.
Our D&C cost averaged $1,027 a foot in the fourth quarter, which is a 2% decrease compared to the third quarter and flat compared to our full year 2020 D&C costs.
Breaking this down, our drilling costs remained essentially unchanged for the quarter at $413 a foot, while our completion costs were down 4% quarter over quarter to $615 a foot.
In spite of the higher service costs we began to experience during the last quarter, we were still able to achieve the slightly lower D&C cost due to improved operational performance and improved capital efficiency associated with the longer average lateral length that we drilled during the quarter.
Our average lateral length for the quarter was 11,443 feet.
This is the longest quarterly average lateral length we've achieved to date and was accomplished primarily due to the completion of our first two 15,000-foot laterals that were turned to sales during the fourth quarter.
The higher capital efficiencies associated with the longer laterals allowed us to offset the impact of the higher service costs during the quarter.
While we do continue to see service costs further increase into this year, our ability to execute on the longer laterals with the more robust economics will help cushion and partially offset the negative effects of the higher service costs.
On Slide 16 is a map outlining our fourth quarter well activity.
Since the last call, we have completed and turned 16 new wells to sales.
The wells were drilled with lateral lengths ranging from 8,504 feet to 15,155 feet with an average lateral of 10,508 feet.
The wells were tested at IP rates that range from 12 million up to 48 million a day with a 23 million cubic feet per day average IP.
The results this quarter include our first two planned 15,000-foot Haynesville laterals, the Talley 32-29-20 HC number one and number two wells.
These wells were completed with laterals of 14,685 feet and 15,155 feet and tested at rates of 41 million and 48 million cubic feet a day.
The seven wells with the lower IP rates are in Panola County in the liquids rich area of the Haynesville.
The high BTU gas in this area will generate a yield of 25 to 40 barrels of plant products, which will enhance the economics from a dry gas well with similar production by 20% to 30%.
Also during the quarter, we successfully drilled two additional 15,000-foot laterals into the Bossier as mentioned earlier.
These two wells were turned to sales late last night, and we'll be reporting on those on the next call.
Regarding activity levels, we did finish out 2021 running five rigs and three frac crews.
We're in the process now of adding two rigs, increasing our rig count to seven and will remain at the seven-rig count throughout the remainder of this year.
We plan to continue running three full-time frac crews throughout the rest of the year.
On Slide 17, this is the detail of the 2021 drilling inventory.
The drilling inventory is split between the Haynesville and Bossier locations.
It is divided into four categories.
We've got our short laterals up to 5,000 feet, median laterals at 5,000 to 8,000 feet, our long laterals at 8,000 to 11,000 feet, and we've got a new extra-long category now for the wells beyond 11,000 feet.
Our total operated inventory currently stands at 1,984 gross locations, 1,420 net locations, which represents a 72% average working interest across the operated inventory.
Based on -- our non-operated inventory currently stands at 1,425 gross locations and 213 net locations and this represents a 15% average working interest across the non-operated inventory.
Based on the recent success of our new extra-long lateral wells, we've modified the drilling inventory to take advantage of our acreage position, and where possible, we have extended our future laterals out further to the 10,000 to 15,000-foot range.
In our new extra-long lateral bucket, we capture all our wells that now extend beyond 11,000 feet long, and in this bucket, we currently have 397 gross operated locations and 287 net operated locations.
These are split 50-50 between the Haynesville and the Bossier.
To recap our total gross inventory, we have 436 short laterals, 392 medium laterals, 759 long laterals, and now 397 extra-long laterals.
The total gross operated inventory is split 53% in the Haynesville and 47% in the Bossier.
Also, by extending our laterals, we have increased the average lateral length in the inventory from 6,840 feet now up to 8,520 feet, which is a 25% increase.
And in addition to the uplift in our economics, the longer laterals will help to reduce our surface footprint on future activity and also further reduce our greenhouse gas and methane intensity levels.
In summary, our current inventory provides us with over 25 years of future drilling locations based on our planned 2022 activity levels.
With our ability to execute on the new ultra-long laterals, our drilling economics are more robust and it enhances the value of our acreage position.
I'm going to turn it now back over to Jay to summarize the outlook for 2022.
Well, like we said earlier, our drilling inventory, which Dan just said, it is the holy grail of E&P companies.
It's never been more valuable or stronger than it is today.
If you go to Slide 18, I'd direct you to kind of the summary of our outlook for 2022.
We expect our 2022 drilling program to generate 4% to 5% production growth year over year, and we would expect to generate in excess of $500 million of free cash flow at current commodity prices.
In 2022, the lateral length of the wells in this year's program is expected to be 19% longer than the 2021 wells.
The additional investment we are making this year in our drilling program will pay off in the future years as our lateral length per well will have a lower decline rate than the shorter laterals.
In 2022, our operating plan is focused on repaying $479 million of debt, including redeeming our 2025 senior notes.
We continue to have an industry-leading low-cost structure, which gives us best-in-class drilling returns.
We are working on the certification of our natural gas production as responsibly sourced gas under the MiQ standard.
At the end of 2021, we had financial liquidity of almost $1.2 billion, which is expected to increase further in 2022 as we repay the remaining borrowings outstanding on our bank facility.
On Slide 19, we provide the financial guidance.
As shown on the slide, first quarter production guidance of 1.24 to 1.29 Bcf a day, and the full year guidance is 1.39 to 1.45 Bcf a day.
During the first quarter, we only plan to turn to sales about 15% of the planned wells to be turned to sales for the year.
And those wells have a little bit lower working interest than the wells later in the year.
As a result, the majority of our wells turned to sales and production growth are expected to occur during the second and third quarters of this year.
Development capex guidance is $750 million to $800 million, which is based on a similar number of turned to sales wells as last year, and incorporates an expected 10% increase in service costs and the impact of our average lateral lengths being 19% longer this year.
As a result, if you factor in the 10% inflation and the 19% longer laterals, the midpoint of our guidance would actually represent about 3% to 5% of an improvement in efficiencies, mostly related to the longer laterals.
We've also budgeted for $8 million to $12 million of additional leasing costs.
Our LOE expected to average $0.20 to $0.25 in the first quarter and $0.18 to $0.22 for the full year, while our gathering and transportation costs are expected to average $0.23 to $0.27 in the first quarter and $0.24 to $0.28 for the year.
Production and ad valorem taxes expected to average $0.10 to $0.14 a year based on current price outlook.
Our DD&A rate is expected to average $0.90 to $0.96 per Mcfe.
Cash G&A is expected to total $7 million to $8 million in the first quarter and $29 million to $32 million in 2022, with noncash G&A expected to average almost $2 million a quarter.
Cash interest is expected to come in around $38 million to $45 million in the first quarter and $152 million to $162 million -- $160 million in 2022, and that incorporates the planned redemption of our 2025 notes later this year.
From a tax standpoint, the effective tax rate of guidance of 22% to 27% is in line with what we've been reporting.
And going forward, we expect to defer 90% to 95% of the taxes with the cash taxes being related to state taxes.

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compname reports q4 adjusted earnings per share of $0.37.
q4 adjusted earnings per share $0.37.
qtrly revenues, after realized hedging losses, were $380 million, 37% higher than 2020's q4.

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