コムストック・リソーシズ (CRK) 2026年第3四半期決算説明会: SOCARとの16.5億ドル取引で債務削減へ

主要ポイント

• 第3四半期の平均生産量は日量13億立方フィート相当（Bcfe）となり、ヘインズビルでの新規坑井の稼働開始に伴い、前年同期比9%増、前期比8%増となった。
• ヘッジ後の石油・天然ガス売上高は3億5,900万ドルだった。EBITDAXは2億6,600万ドルに達し、運転資本変動前のキャッシュフローは2億800万ドル（1株当たり0.71ドル）となった。
• コムストックが発表した純利益は2,200万ドル（1株当たり0.08ドル）だった。ヘッジの時価評価益およびその他特定項目を除いた調整後純利益は600万ドル（1株当たり0.02ドル）となった。
• SOCARは、コムストックのレガシー・ヘインズビル、ウエスタン・ヘインズビル、およびピナクル・ガス・サービシズの資産権益取得に向けて16億5,000万ドルを出資することで合意した。コムストックはこの調達資金を負債返済に充てる計画で、これにより見積もりベース（プロフォーマ）の純負債は四半期末時点の34億ドルから約17億ドルへと減少する。
• ジョーンズ家のアルコマIII掘削ベンチャーは、2026年の設備投資のうち約3億ドル、2027年にさらに1億5,000万ドルを拠出する見通しである。経営陣は、この取り決めが第4四半期のフリーキャッシュフロー黒字化を下支えすると見込んでいる。
• ウエスタン・ヘインズビルの坑井は力強い初期生産量を記録した。当四半期中に稼働を開始した6本の坑井の平均生産量は日量3,300万立方フィート（MMcf）となり、レガシー・ヘインズビルの新規16坑井の平均（日量2,500万立方フィート）を上回った。

主要財務データ

2026年最初の9カ月間の平均生産量は日量12億立方フィート（Bcf）、ヘッジ後の石油・天然ガス売上高は計10億ドル、EBITDAXは7億6,300万ドルとなった。キャッシュフローは5億8,800万ドル（1株当たり2.02ドル）に達し、調整後純利益は5,400万ドル（1株当たり0.18ドル）となった。

事業および操業実績

コムストックは当四半期中にレガシー・ヘインズビルの16坑井を販売稼働させた。これらの坑井の平均水平坑井長は1万812フィート、初期生産量は日量2,500万立方フィート（MMcf）で、うち6坑井はホースシュー（U字型）坑井だった。

ウエスタン・ヘインズビルでは、新規6坑井の平均水平坑井長が9,829フィート、初期生産量が日量3,300万立方フィート（MMcf）となった。四半期末時点で同社がウエスタン・ヘインズビルに保有する生産坑井は47本で、さらに15本が開発の各段階にある。

コムストックは、レガシー・ヘインズビルで約26万2,000純エーカー、ウエスタン・ヘインズビルで54万7,000純エーカー超の鉱区を保有している。推定自社操業開発候補地（インベントリ）は、グロスベースでレガシー・ヘインズビルに899カ所、ウエスタン・ヘインズビルに3,255カ所存在する。

当四半期、レガシー・ヘインズビルの掘削効率が向上した。指標となる14本の長水平坑井（ロングラテラル）では、目標深度（トータルデプス）到達までの平均日数が22日、1日当たりの掘削長は前期比14%増の1,156フィートとなった。仕上げコストは5%増の1フィート当たり715ドルに上昇したものの、掘削コストは11%減の1フィート当たり634ドルに低下した。

ウエスタン・ヘインズビルの掘削コストは前期比11%増の1フィート当たり1,934ドル、仕上げコストは22%増の1フィート当たり1,959ドルとなった。経営陣はこのコスト上昇について、水平坑井長の短縮、水圧破砕処理の規模拡大、チュービングの設置、およびサービスコストの上昇によるものだとしている。

戦略的取引および経営見通し

SOCARは、レガシー・ヘインズビルの権益20%、ウエスタン・ヘインズビルの権益15%、およびピナクル・ガス・サービシズにおけるコムストック保有権益の15%を16億5,000万ドルで取得する。本取引は完了条件を満たすことを前提に、2026年末までに完了する見込みである。

5年経過後、かつSOCARがウエスタン・ヘインズビルへの投資で15%のリターンを達成した時点で、同上流資産における同社の権益は15%から7.5%に低下する。コムストックは引き続き操業主体（オペレーター）を務め、具体的な商業契約はまだ策定中であるものの、この提携が将来のLNG販売機会を創出すると期待している。

アルコマIII掘削ベンチャーに基づき、ジョーンズ家のパートナーシップはウエスタン・ヘインズビルの18坑井について掘削および仕上げコストの85%を、レガシー・ヘインズビルの9坑井について80%を負担する。所定のコスト回収およびアルコマIIIに対する15%のリターン達成後、これら27坑井の権益の50%がコムストックに返還される。

経営陣は、2026年中にウエスタン・ヘインズビルで19坑井を掘削し、20坑井を販売稼働させる見通しである。レガシー・ヘインズビルでは52坑井を掘削し、45坑井を販売稼働させることを見込んでいる。同社はウエスタン・ヘインズビルで5基、レガシー・ヘインズビルで4基のリグを稼働させている。

コムストックは、ジョーンズ掘削ベンチャーの下支えにより、第4四半期のフリーキャッシュフロー黒字化を見込んでいる。同社の信用枠（クレジット・ファシリティ）の満期は2028年11月に延長されており、SOCARとの取引完了後はさらに2031年11月15日まで延長される見込みである。

リスクおよび注視項目

天然ガス価格の下落により、第3四半期の増産による恩恵が一部相殺された。ヘッジ前におけるコムストックの天然ガス実現価格は、当四半期のNYMEX清算価格を0.34ドル下回った。

ウエスタン・ヘインズビルのコストは、サービスコストのインフレ、平均水平坑井長の短縮、および水圧破砕処理の規模拡大への移行による影響を受け続けている。経営陣によると、コストは第2四半期から第3四半期にかけて約8%〜10%上昇した。

大規模な水圧破砕設計による実績データはまだ初期段階にある。経営陣は、初期結果から推定回収率が少なくとも10%向上する可能性が示唆されていると述べたものの、より長期的な生産履歴の確認が必要であると強調した。

SOCAR関連のLNG販売機会はまだ最終決定されていない。経営陣は、SOCARが米国産LNGの引取容量（オフテイク・キャパシティ）を確保するにつれて、具体的な体制が構築されていくと見込んでいる。

経営陣は、配当の再開を検討する前提条件として、レバレッジ比率1.5倍未満という目標を設定した。配当の再開はまた、天然ガス価格、ヘッジ比率、ならびにウエスタン・ヘインズビルおよびミッドストリーム開発に必要な資金需要にも左右される。

アナリスト質疑応答の要点

• 大口径坑井設計：経営陣は、この設計により坑跡制御（ステアリング）が向上し、より長い水平坑井を目標層内に維持しやすくなったと述べた。この技術はいずれウエスタン・ヘインズビルの大半の坑井に適用される可能性があり、現在の適用分岐点となる水平坑井長はおよそ1万〜1万1,000フィートと推定されている。
• 水圧破砕処理の規模拡大：2026年のウエスタン・ヘインズビルの全坑井において、従来の標準であった1フィート当たり4,000ポンドに対し、5,000または6,000ポンドのプロパントが使用された。経営陣は、回収率の増加分が追加コストを正当化するために必要な水準を上回るはずだとみている。
• 開発と鉱区保持：ウエスタン・ヘインズビルにおける5基目のリグ導入により、コムストックは生産維持による鉱区保持（HBP）プログラムを継続しつつ、インフィル坑井や開発坑井を追加できるようになる。経営陣は、水平坑井長の延長と既存インフラの活用により、時間の経過とともに原単位コストが低下すると見込んでいる。
• 掘削技術：初の10,000 PSI対応リグが間もなく稼働を開始する見込みで、2027年第2四半期にはさらに2基のアップグレードが計画されている。経営陣は、流量の増加とドリルビットへの出力向上によって掘削速度が向上すると見込んでいるが、その具体的な効果については数値を明らかにしなかった。
• 天然ガス販売：コムストックは、SOCARを通じた将来的なLNGエクスポージャーの獲得と、発電事業者との直接長期供給契約の組み合わせを推進している。アンダーソン郡の発電プロジェクトへの初期ガス供給は2028年初頭に開始される見通しで、第1段階の発電規模は1ギガワット、長期的な設備容量は約5.2〜5.3ギガワットで設計されている。

決算説明会トランスクリプト全文

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決算説明会の完全なトランスクリプト

経営陣による説明

Operator

Good day, and thank you for standing by. Welcome to the Q3 2026 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Miles Allison

Thank you. I know that there are several companies presenting at the same time. So those of you that have joined this call, we're always appreciative and thankful.

So welcome to the Comstock Resources Third Quarter 2026 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 Third Quarter 2026 Results. I am Jay Allison, Chief Executive Officer of Comstock. And 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.

Please refer to Slide 2 in our presentations 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.

If you would turn to Slide 3, we summarize the highlights of the third quarter. Our production grew 9% from 2025 and was 8% higher than the second quarter, driven by new wells turned to sales from our drilling program.

In the quarter, 16 Legacy Haynesville wells were turned to sales with an average lateral length of 10,812 feet and an average per well initial production rate of 25 million cubic feet per day. Six of those were horseshoe wells.

We also turned 6 new Western Haynesville wells to sales in the third quarter with an average lateral length of 9,829 feet and an average per well initial production rate of 33 million cubic feet per day. The higher production drove our financial results, which Roland will go over in a few minutes.

Starting September 1, we entered into a drilling venture with Jerry Jones covering 27 wells. 18 of the wells are in the Western Haynesville with 9 in the Legacy Haynesville.

The new venture will allow us to generate free cash flow in the fourth quarter while also allowing us to continue our development and delineation program in the Western Haynesville. On November 9 (sic) [ November 4 ], yesterday, we entered into a definitive purchase and sale agreement with SOCAR for a $1.65 billion divestiture.

The proceeds from the transaction will substantially improve our balance sheet. We also just extended the maturity of our bank credit facility by a year, which will further extend an additional 4 years after closing the SOCAR transaction. I will cover all of those strategic transactions in the next slides.

Turning to Slide 4, we summarize the drilling venture with Jerry Jones. Beginning September 1, 2026, Arkoma III, a partnership owned by the Jones family, will fund the drilling and completion cost of 85% of 18 Western Haynesville wells and 80% of 9 Legacy Haynesville wells.

Arkoma III will fund an estimated $300 million of capital expenditures in 2026 and an additional $150 million in 2027 on these 27 wells. Prior to September 1, Comstock had spent $180 million on these wells, which will be recovered by Comstock from 100% of the net revenues from the first production of these 27 wells.

Arkoma III will receive the net revenues after the pre-venture costs are recovered until Arkoma III has recovered its cost and a 15% return. After the return on investment is achieved, 50% of the interest in the 27 wells revert to Comstock.

The drilling venture allows us to generate free cash flow in the fourth quarter while supporting the continued development and delineation of our 547,000 net acres in the Western Haynesville as well as providing volumes to Pinnacle Gas Service.

You'll turn over to Slide 5, we'll summarize the strategic partner with SOCAR. SOCAR is purchasing a 20% interest in our Legacy Haynesville, a 15% interest in our Western Haynesville and 15% of our interest in Pinnacle Gas Service for $1.65 billion.

We recently executed the definitive purchase and sale agreement and expect the transaction to close by year-end 2026. Proceeds from the transaction will be used for debt repayment. Comstock will remain the operator of the properties and Comstock and SOCAR will jointly participate in other leasing and acquisitions in the Haynesville.

SOCAR will offer Comstock future LNG marketing opportunities. SOCAR's 15% interest in the Western Haynesville reduces to 7.5% after 5 years and once SOCAR has achieved a 15% return on investment in those assets. As a result, Comstock will have an increased participation in the future upside of the Western Haynesville assets, creating a balanced structure that aligns both parties around the long-term performance of those assets.

Slide 6 shows the ownership interest in the Legacy Haynesville, the Western Haynesville and Pinnacle Gas Services upon closing of the SOCAR transaction. As previously mentioned, after 5 years and upon SOCAR achieving a 15% return on the investment in the Western Haynesville upstream assets, Comstock's interest in the Western Haynesville assets will increase from 85% to 92.5%.

Sixth Street owns the remaining 27% of Pinnacle Gas Services, which reduces to 19.5% after certain return hurdles are met. At that point, Comstock's interest in Pinnacle Gas Services will increase to 69.5%.

Please turn to Slide 7. I'll show you the key partnership impact of the SOCAR transaction to Comstock. The $1.65 billion purchase price provides strong validation of the value implied by the quality and longevity of Comstock's upstream assets in the Legacy Haynesville and Western Haynesville, while reaffirming our significant midstream value embedded within Pinnacle Gas Services.

SOCAR's investment-grade balance sheet and global LNG marketing operations should help create value for Comstock shareholders. Comstock will use the proceeds from the SOCAR transaction to repay the outstanding balance under Comstock's revolving credit facility with pro forma net debt decreasing to about $1.7 billion compared to $3.4 billion at the end of the third quarter.

The stronger balance sheet will support continued delineation and development of Comstock's 547,000 net acres in the Western Haynesville. Comstock remains operator of the properties and retains further upside in the Western Haynesville through the reversion provisions.

On Slide 8, we'll show you the benefits of the strategic partnership with SOCAR. The partnership with SOCAR combines Comstock's Gulf Coast location, access to significant gas reserves and midstream operations with SOCAR's LNG and trading platform.

The scale footprint across both the Legacy and Western Haynesville provides decades of drilling inventory. As a result, Comstock is positioned to maximize natural gas pricing netbacks across domestic and international markets while mitigating volatility via strategic partnership in power supply and midstream investments. Both the Jones family and SOCAR are aligned as long-term strategic stakeholders.

Lastly, the de-levered balance sheet provides development flexibility across our asset base.

I will now turn it over to Roland Burns to discuss the third quarter financial results. Roland?

Roland Burns

All right. Thanks, Jay. On Slide 9, we cover the third quarter financial results. Our production in the third quarter averaged 1.3 Bcfe per day, which was up 8% from the second quarter of this year and was 9% higher than the third quarter of last year.

Oil and gas sales after hedging were $359 million, reflecting the impact of the higher production being offset a little bit by lower natural gas prices in the quarter. EBITDAX in the quarter was $266 million, and we generated $208 million of cash flow or $0.71 per share before any working capital changes during the quarter.

We reported a $22 million profit for the quarter or $0.08 per share. Included in that number was a pretax $35 million mark-to-market unrealized gain related to our future hedges. So excluding the mark-to-market gain, exploration expense and other nonrecurring items and the related income tax impact of those, we reported net income of $6 million for the third quarter or $0.02 per share.

Slide 10 covers the year-to-date financial results. Production in the 9 months of the year averaged 1.2 Bcf per day. Oil and gas sales after hedging were $1 billion in that period, and EBITDAX was $763 million, and we generated $588 million of cash flow or $2.02 per share.

We reported a $138 million profit for the first 9 months of this year or $0.47 per share. That number included $119 million mark-to-market unrealized gain on our future hedges. So excluding that mark-to-market gain, exploration expense and other nonrecurring items and the related income taxes, we reported adjusted net income of $54 million for the first 9 months of this year or $0.18 per share.

Slide 11 breaks down our natural gas price realizations in the quarter. The quarterly weighted average NYMEX settlement price averaged $2.95 in the third quarter and the weighted average Henry Hub spot price averaged $2.87 in the quarter.

So we sold 1/3 of our gas in the spot market. So an appropriate NYMEX reference price for our quarter would be about $2.93. Our realized gas price averaged $2.61 in the quarter, reflecting a $0.34 basis differential compared to the NYMEX settlement price and a $0.32 differential compared to the reference price.

In the third quarter, we were 59% hedged, so that increased our realized price to $2.93. We also made an additional $0.02 per Mcfe from our third-party marketing activities.

Slide 12 details the operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.80 in the third quarter, up $0.03 from our second quarter rate. Lifting costs were down $0.02. G&A was down $0.01, both attributable to that higher production level we had in the quarter.

Production and Ad Valorem taxes increased by $0.03 in the quarter, really due to prior period true-ups and gathering costs were up $0.03. So overall, our EBITDAX margin was 73% in the third quarter.

On Slide 13, we recap the spending so far this year in our drilling activity and other development activity. We spent a total of $383 million on development activities in the third quarter and $1.1 billion during the first 9 months of this year.

In the first 9 months of this year, we drilled 39 wells or 28.6 net to our interest operated wells, and we -- those are in the Haynesville shale formation, and then we drilled another 16 or 10 net wells in the Bossier shale formation for a total of 55 wells or 38.7 net wells. We turned 52 wells or 44.7 net operated wells to sales so far this year with an average overall OP rate of 29 million cubic feet per day.

Slide 14 summarizes our capitalization at the end of the third quarter. We ended the quarter with $800 million of borrowings outstanding under our upstream credit facility. Our upstream borrowing base is $2 billion under the credit facility and the elected commitment under that facility is at $1.5 billion.

And all of that was recently reaffirmed in our early November bank meeting. The maturity date of our facility was recently extended also to November 2028. After closing the SOCAR transaction, the maturity will further be extended on our bank credit facility to November 15, 2031.

At the end of the third quarter, the midstream credit facility had no borrowings outstanding. Our last 12 months leverage ratio was 3.2x, and we ended the third quarter with over $850 million of financial liquidity.

Pro forma for the SOCAR transaction, our debt will be reduced by half and our leverage ratio improves to 2x. Given the impact of the Jones Drilling venture on the fourth quarter capital spending, we anticipate generating free cash flow in the fourth quarter, which will further reduce our debt before closing the SOCAR transaction.

I'll now turn it over to Dan to discuss the operations in more detail.

Daniel Harrison

Okay. Thanks, Roland. On Slide 15, this is our updated overview of our total acreage footprint in the Haynesville and Bossier shales, East Texas and North Louisiana. So overall, we currently have 1,084,812 gross acres and 809,883 net acres that are prospective for the commercial development of the Haynesville and Bossier shales.

We currently have just over 262,000 net acres across our Legacy Haynesville area, and our Western Haynesville footprint has grown to just over 547,000 net acres. Our producing well count now stands at 47 wells in the Western Haynesville. This is up 6 wells since our last call. We currently have another 15 wells that we have in various stages of development.

On Slide 16, this outlines the drilling inventory in our Legacy Haynesville area at the end of the third quarter. We have 899 gross operated locations with a 78% working interest or 698 net locations.

We have 770 gross non-operated locations with 12% working interest or 96 net locations. 442 of our 899 gross operated locations or nearly 50% have laterals exceeding 10,000 feet. The average lateral length in our inventory stands at 10,212 feet.

Our gross operated inventory is evenly split between the Haynesville and the Bossier. Also included in the Legacy Haynesville inventory is 108 gross horseshoe locations with 50% in Haynesville and 50% in the Bossier. We currently have 4 rigs, they're running on our Legacy Haynesville area, which provides us with a long runway of future drilling locations.

Slide 17. This outlines our estimated drilling inventory in the Western Haynesville. We have 3,255 gross operated locations and 2,507 net locations in the Western Haynesville, which equates to an average working interest of 77%. Our total net locations are estimated since much of the Western Haynesville acreage has not been unitized.

Roughly 40% of our 3,255 gross operated locations or 1,317 locations have laterals exceeding 10,000 feet. 61% of our gross operated locations have laterals exceeding 8,500 feet. And the average lateral in our Western Haynesville inventory is 8,884 feet.

Our Western Haynesville drilling inventory is more weighted to the Bossier formation with nearly 2/3 of the inventory in the Bossier and 1/3 of our inventory is in the Haynesville. And we currently have 5 rigs running on our Western Haynesville acreage today.

Slide 18 is an overview of our horseshoe well drilling program, which allows for extended reach and reentry opportunities for higher return drilling locations. The improved drilling economics of the horseshoe wells unlocks previously stranded acreage by converting 2 sectional laterals into a single 2-mile lateral.

Since starting the horseshoe program, we've turned 17 horseshoe wells to sales with an average IP of 29 million cubic feet a day and an average lateral length of 10,223 feet. The 2 most recent horseshoe wells have an average lateral length of 13,518 feet.

And as mentioned on the previous slide, we have 108 remaining horseshoe locations as of the end of the third quarter. In addition to the drilling of horseshoe wells, we've identified a number of enhancements to further improve returns, including the rotary steerable technology, redevelopment opportunities to longer laterals up to 15,000 to 20,000 foot and drill some drill-through applications.

Slide 19 outlines our average lateral length drilled based on the wells that we drilled to total depth. The average lateral lengths are shown separately for our Legacy Haynesville area and our Western Haynesville areas.

In the third quarter, we drilled 16 wells to total depth in the Legacy Haynesville area with an average lateral length of 11,905 feet. The individual laterals range from 6,050 feet up to a max 15,923 feet.

The longest lateral drilled to date in the Legacy Haynesville area still stands at 17,409 feet. In the third quarter, we also drilled 5 wells to total depth in the Western Haynesville with an average lateral length of 8,587 feet.

The individual laterals range from 6,936 feet up to max 10,920 feet. Our longest lateral drilled to date in the Western Haynesville is 14,783 feet. To date, we have drilled 54 wells to total depth in the Western Haynesville. 23 of these 54 wells have laterals exceeding 10,000 feet.

Slide 20 summarizes the 38 wells that we have turned to sales in our Legacy Haynesville area so far in 2026. The average lateral length was 11,530 feet and the individual laterals ranged on the low end from 8,497 feet up to a high of 15,772 feet. The average IP for the 38 wells is 28 million cubic feet per day. And included in these 38 wells is 14 horseshoe wells.

Slide 21 outlines the 17 wells that we have turned to sales on our Western Haynesville acreage so far in 2026. These 17 wells had an average lateral length of 10,153 feet and an average initial production rate of 31 million cubic feet per day.

Since our last call, we have turned 6 additional wells to sales with IP rates ranging from 26 million to 40 million cubic feet per day and an average IP of 33 million cubic feet per day. We have a total of 47 wells currently producing on our Western Haynesville acreage.

Slide 22 highlights our drilling efficiency in the Legacy Haynesville area. This is for our benchmark long lateral wells that have laterals over 8,500 feet long. In the third quarter, we drilled 14 of our benchmark long lateral wells to total depth in the Legacy Haynesville and averaged 22 days to total depth.

Correspondingly, we averaged 1,156 feet drilled per day on our Legacy Haynesville acreage, and this represents a 14% increase versus the second quarter of 2026. Five of the wells we drilled in the third quarter were horseshoe wells.

Slide 23. This highlights our drilling progress in the Western Haynesville. During the third quarter, we drilled 5 wells to total depth. This gives us a total of 52 wells drilled to total depth through the end of the third quarter. We averaged 56 drilling days for the 5 wells drilled to total depth during the quarter.

This is a decrease of 3 days compared to the second quarter. The drilling speed of 461 feet per day during the third quarter was 2% lower than the second quarter. The main reason the drilling speed decreased from the second and third quarter was the Dollie Jones. That was our first big hole lateral we drilled during the second quarter. And this well drilled 25% faster than our other wells. If we've taken the Dollie Jones, would have been excluded, our drilling speeds would have improved in the third quarter.

Slide 24 details our D&C costs through the third quarter for our benchmark long lateral wells in the Legacy Haynesville area. These costs reflect all of the wells with laterals over 8,500-foot long. The drilling costs are based on the quarter in which the wells were reached TD and the completion costs are based on the wells -- during the quarter on the wells that returned to sales.

During the third quarter, we drilled 14 of our benchmark long lateral wells to total depth, including 5 horseshoe wells. Our third quarter drilling costs averaged $634 a foot. This is an 11% decrease compared to the second quarter.

Our improved drilling performance in the third quarter can be attributed to much stronger lateral drilling performance compared to the second quarter, which outweighed the impact of the slightly higher service costs we did experience during the quarter.

The rotary steerable drilling technology being deployed in our Legacy Haynesville area, especially in our horseshoe wells, has continued to deliver superior results is driving our drilling efficiencies higher. During the third quarter, we also turned 15 of our [indiscernible] long lateral wells to sales on our Legacy Haynesville acreage, of which 5 were horseshoe wells.

The third quarter completion costs came in at $715 a foot. This is a 5% increase compared to the second quarter. And the higher completion cost in the third quarter is partially the result of completing 3 single well pads during the third quarter compared to 9 during the second quarter. We also experienced the higher service costs during the third quarter.

On Slide 25 is a summary of our D&C costs through the third quarter for all wells drilled in the Western Haynesville. During the third quarter, we drilled 5 wells to total depth in the Western Haynesville. Average lateral length was 8,587 feet.

The third quarter drilling costs averaged $1,934 a foot. This represents an 11% increase compared to the second quarter. The biggest factor in our higher drilling costs for the third quarter was the shorter average lateral length of 8,587 feet for the wells in this quarter.

And to a lesser extent, the higher service costs we experienced also contributed to the higher drilling costs for the quarter.

During the third quarter, we drilled our second big hole lateral. This time, we drill it to a more challenging lateral target in the Haynesville, but again, our results met our expectations.

During the third quarter, we also turned 6 wells to sales in our Western Haynesville acreage that had an average lateral length of 9,829 feet. The third quarter completion cost averaged $1,959 a foot. This is a 22% increase compared to the second quarter, and we had several drivers affecting the higher completion costs during the quarter.

The primary driver has been the transition to pumping the larger fracs. This led that we had a 12% higher proppant loading in the third quarter compared to the second quarter. Couple that with the higher service costs that we had. We also [indiscernible] up all but one of our third quarter wells as opposed to only tubing up one of our wells in the second quarter.

Back to the drilling side, we've been very pleased with the results of our first 3 big hole lateral wells, and we're planning more of these wells for the future. The bigger hole in the lateral creates the lower downhole temperatures, and we're seeing longer, more reliable runs from our downhole drilling assemblies and it has also provided us with much better steering ability so that we can keep our laterals on target.

One last item I want to update from our last call, we should be deploying our first 10,000 PSI rig in the Western Haynesville towards the end of this month, which we fully anticipate will lead to faster drill times, and we're planning to upgrade 2 additional or 2 more of our rigs to 10,000 capability in the second quarter of next year. I'll now turn the call back over to Jay.

Miles Allison

Dan, great job. Roland, great job. If you'll go over Slide 26, we'll summarize our outlook for 2026. Again, our primary goal continues to be advancing our Western Haynesville that will position Comstock to benefit from the longer-term growth in natural gas demand.

We have 5 operated drilling rigs in the Western Haynesville to continue to delineate the new play. We expect to drill 19 wells and turn 20 wells to sales in 2026, and we expect drilling efficiencies and changes to our completion design to continue to drive up productivity and drive down D&C cost.

We have 4 operated rigs drilling in Legacy Haynesville to support production growth in 2026 and 2027 and expect to drill 52 wells and turn 45 wells to sales in 2026.

The Jones Drilling venture allows us to generate free cash flow in the fourth quarter while supporting the ongoing delineation and development of the Western Haynesville. The SOCAR transaction will allow us to retire half of our debt outstanding, providing us a strong balance sheet as we enter 2027.

Comstock has captured the massive Western Haynesville footprint and been successfully drilling wells there since 2021. At the same time, we own Pinnacle Gas Services, our midstream to ensure takeaway. We believe natural gas will be undersupplied by 2029 with the demand growth of LNG going from about 20 Bcf a day now to 35 Bcf a day by 2032, plus the additional 12 Bcf needed to provide turbines -- power for turbines for data centers.

Where our Haynesville/Bossier leases are located is the sweet spot for demand. Our goal is to protect our natural gas assets, protect our midstream company, PGS, prudently develop our Western Haynesville footprint, and add to it monthly, protect our balance sheet and have the best partner in the world on our side.

With the addition of NextEra, Sixth Street and SOCAR, I believe we have the winning team. When Jerry Jones and his family touched Comstock in 2018, we became who we are today. That support 100% allowed us to purchase Covey Park in 2019, close the numerous acquisitions around the Western Haynesville, acquire PGS and lease thousands of acres in our Western Haynesville at a time of very low natural gas prices.

The Jones relationship also helped secure SOCAR as a forever partner that provides us LNG marketing opportunities in Europe.

And on September 1, 2026, the Jones DrillCo, $450 million allows us to generate free cash flow in the fourth quarter while supporting the continued development and delineation of our 547,000 net acres in our Western Haynesville as well as provide volumes to Pinnacle.

Jerry asked me to make this following comment. His commitment to Comstock is because of his unwavering faith in management and exemplary natural gas asset base that we control and the tremendous value of U.S. gas in the future.

That is why the Jones family have invested over $1 billion in Comstock equity. With that, I want to thank you for your time. Slide 28 provides guidance for the rest of 2026, which Ron can discuss with you directly. If you have questions for the rest of the call, we'll take questions from analysts who follow the company. I'll turn it back over to you.

Operator

[Operator Instructions] Our first question comes from the line of John Annis with Texas Capital.

質疑応答

John Annis

For my first one, the Dollie Jones well delivered a $40 million a day IP using the big hole design. And I think you're now drilling your fourth well with that design. What have you learned about the repeatability of results on drilling and well performance? And then ultimately, what portion of the Western Haynesville inventory could ultimately be developed this way?

Daniel Harrison

It's a really good question. So we are drilling our fourth well at the moment with the big hole design. We haven't seen anything to date that tells us that we have any concerns with that design.

We're just -- we really need to drill more wells to just hone in on where the breakover is between drilling a slim hole versus a big hole design. Right now, I'd probably just say it's somewhere between 10,000 and 11,000-foot lateral length.

Our goal is, of course, we had the shorter average lateral lengths that we reported for the quarter, and that's just due to where we're trying to hold acreage and the acreage layout and geology and some other things. But in the future, we'll definitely be getting the laterals longer in the years ahead.

So I would say probably the majority of all our future wells, maybe not within the next year or so, but further out, I'd say the majority of the wells will be drilled with the big hole design. So we just need some more data to just hone in on really just kind of where that crossover mark is.

But we've been super pleased with it. You asked about the Dollie Jones. That was the first one. That thing really drilled incredibly fast. That was drilled to the Bossier. Our second big hole that I kind of mentioned on one of the slides was drilled to the Haynesville.

The Haynesville, just on average out here is a little bit harder digging than it is in the Bossier. So we were -- the results from the second well were about right on par with what we expected. But I think maybe one of the things to drive home is the intangible benefit of drilling the big hole.

We can steer and keep the laterals on target much more easy than we can than when we're drilling with the slim hole. And when staying on target, this directly correlates to the performance of these wells. You want to keep that lateral right there in the best rock where you want it.

So not only can we drill long, but even when we're drilling long, we can still keep that thing on target way out there at the end, which the slim holes, they'll start walking and we have a lot more difficulty keeping them on target when the wells get long. And then that just leads to other issues that add drilling days. So happy with the big holes. I see that as the bulk of the future.

John Annis

Appreciate all that color. Maybe staying on completion design. Last quarter, you noted the 2Q wells were the first full batch completed with 5,000 to 6,000 pounds of proppant per foot and said their early pressures look encouraging.

With another quarter of production history, are you seeing a measurable improvement in expected EURs? And is that uplift in your view, sufficient to justify the 12% or so higher proppant loading?

Daniel Harrison

Definitely, absolutely. So we actually transitioned -- our standard frac design when we started out and really for a lot of early wells was 4,000 pounds per foot. We did have one big job we pumped back early on, on one of the Robertson County wells. But other than that, they were all 4,000 pounds per foot.

We transitioned to the bigger fracs really starting in December of '25 when we started popping them. So every well in 2026 is either moving 5,000 or 6,000 pounds per foot. And when you run the math on the economics, I mean, you only need maybe an incremental like 0.2 Bcf per 1,000 to justify adding another 2,000 pounds per foot.

And when you look at the well performance we have today, which is early on some of these wells, but they do look really good. So when you take that early data and combine it with the modeling and stuff that the reservoir group has done, we easily should surpass that 0.2 Bcf per 1,000 incremental. So that's definitely -- that's the direction we're going.

Operator

Our next call comes from the line of Carlos Escalante with Wolfe Research.

Carlos Andres E. Escalante

Wanted to ask on your HBP program in light of the now 9 rigs you have running across your operations where 5 are now in the Western Haynesville. Because I don't think that when you gave preliminary outlook of when you thought the HBP program would be done that you contemplated 5 rigs in the basin or at least as quick as you did.

So I wonder if you can remind us or reframe for us when do you think you would hit your threshold? And how do you foresee that transition from HBP-driven wells move over to value-driven or return-driven operations? And should we see or should we expect perhaps a quicker inflection on D&C per foot when that does happen anytime sooner?

Roland Burns

I'll let Dan answer most of it. But I would just say that what the fifth rig is going to allow us to do is to put some more development wells into the program and not have to 100% keep all the projects on HBP acreage.

So I think we are still on the same kind of time frame because we're very comfortable with that time frame to HBP the acreage. But with the additional rigs, we can now drill some more wells on the same pad, also drill in areas where we've already really spent a lot of money to figure out the area really well.

So I think the ability to drill some development wells will definitely start to see a positive impact on the overall program as far as cost. And so that's kind of the direction. So more -- we'll probably use the additional drilling rig there this now. And now that we have support of other partners, such as the Jones partnership in SOCAR to probably to add infill development wells along the way in the program and meet our HBP goals with the overall drilling program.

Miles Allison

I think we'll have a dual program, which we needed. We're to the point after -- I think we'll have drilled 60 wells at the end of this year in the Western Haynesville. I think our time frame, even though we add acreage every month, our time frame to hold all of it with the 4-plus rigs is still the same.

But now we have a dual goal, we can come in and the millions of dollars that we have spent for gathering and takeaway and the pads, we can now drill additional wells on those pads. And I think you'll see material cost savings. And now that we have drilled around a bunch of these wells, we understand where we should keep the lateral.

And you add all the new drilling tools that we have, I think you'll see the costs come down. I think you'll see the productivity go up, particularly with the choke management that we're using now. We'll blossom on some of the production rates we'll be giving you in the future.

Daniel Harrison

I think Jay and Roland gave you a pretty good answer. I don't really have a lot to add to that. We are blending in some infill development wells a little bit in 2027, which allowing those wells we can set up with the longer laterals in the areas where we already have proven offset well performance to kind of help balance out that the HBP program.

Carlos Andres E. Escalante

Sure. That sounds a solid answer, I think. And then on productivity, just going a step further perhaps on the prior question. If I look at your -- particularly one of the Kretzschmar, and I'm sure I'm botching that name, Kretzschmar wells, your normalized initial production rate at a very quick and dirty metric looks to have jumped and actually posted one of the highest numbers in the 2 years you've been doing a lot of the drilling.

So just wondering, that's obviously just one piece of the puzzle, initial production. But what states are you taking or what of the completion design tweaks you've done, give you confidence that you can flatten the decline rate or said another way, can lead to maximization of your EUR and really keep that production up the same way that you perhaps did with some of the earlier wells alongside that Circle M trend line?

Daniel Harrison

Yes. So yes, you got the names right, Kretzschmar. I think everybody struggles with that a little bit. But we -- the answer without getting real -- making it real complicated is the larger fracs, definitely believe in the larger fracs like we talked about earlier, it just takes minimal incremental EUR, which we should easily surpass and the conservative drawdown strategy.

You just want to -- you're contacting a lot more rock, you're creating a lot more -- stimulating a lot more reservoir volume. And with the conservative drawdown, you keep that open, that's going to lead to the bigger EURs.

The early data that we've got on the wells that we've fracked in the last year with the larger fracs are showing that we're heading in that direction. We do need longer-term production to prove that out, but it's all pointing to where we expect it to go.

Miles Allison

I think the good thing on your question is, if you go probably 90 miles north to south, that's kind of a guess number, but the rock that we have found, I mean, it is consistent quality resource rock.

And all we're doing now is we've extended it to the north and south, starting with the Circle M, going to Elijah 1, even extended it to the north. Now we're going a little bit west. It is not the inventory, the 2,500 locations is not the rock. It is now really what Dan has spoken, that is we're getting to the point where we can have some repeatability. And that's another reason we're going to go in and drill some of these infill wells and why? Because of the demand for natural gas for the future.

Operator

The next question comes from the line of Paul Diamond with Citi.

Paul Diamond

Just real quick on the SOCAR deal. Can you guys put some, I guess, details around the potential marketing opportunities that you referenced? Are those long-term supply agreements or direct sales? Just any detail you have available there?

Roland Burns

Thanks, Paul. We'd like to, but a lot of that is being developed. And I think our future partner, SOCAR is actually in the process of looking to buy offtake in the United States. They're buying their production first kind of the reverse order of some of the other entities that have come in and had the same strategy.

So as they lock that down, they'll be able to come up with specific opportunities for us to look at. And their whole reason to invest in the Haynesville Shale was to support their global LNG trading operations and have this gas available to export.

And so as they develop those -- that full value chain, they're going to offer us to kind of follow them on the same path, and we have the option to do that. But getting the full economic arrangements or stuff kind of in process that will kind of work themselves out over probably the next year or so.

Paul Diamond

Got it. Appreciate the clarity. And then talking a bit more about the rig upgrades you guys referenced going to 10,000 TSi, potentially go to 20,000, 1 on the way, 2 more being considered. Can you talk about how like tangibly or quantitatively that actually translates into higher drill speeds? I guess where does the -- kind of where does the clip-off go? How much faster do we see?

Roland Burns

Good question. I guess we really don't know exactly what this will turn out to look like, but we do have the first one. Actually, we got a rig move probably coming up in a couple of weeks, and that's when the first 10,000, the first pad we drilled with the 10k rig will be spudding hopefully here in a couple of weeks.

But I think if you just basically mathematically right, the higher pump pressures, the higher flow rates you can pump, get better efficiency out of the motors, you get more horsepower to the bit. Basically, those just conventional thinking that's going to transfer into higher ROPs.

Some of the motors we run in the laterals, specifically like on slim holes, sometimes we don't get quite the GPMs or flow rate to the motors to have them operating at their peak efficiency. So the 10k rig being able to pump faster will let us achieve those things.

So very comfortable. I know there's some other operators that have already taken some 10k rigs. And that are adding more 10k rigs. So I think we're going to see that even industry-wide. I think you'll see this pick up a little bit more also as everybody gets comfortable with the higher performance.

Operator

Our next question comes from the line of Jacob Roberts with TPH Research.

Jacob Roberts

I wanted to start on the Western Haynesville. And when we look at the 2025 and 2026 vintages and the performance we're seeing out of those against, let's call it, a $35 million to $40 million cost per 10,000-foot lateral, can you speak to where you see the full cycle breakeven gas price today and then ultimately, where you would like to see that head over the coming years?

And I say all that, and we do appreciate that this is a longer-term plan, but I just wanted to get a sense of where we're at now versus where we could be in a few years from now.

Daniel Harrison

I think we're -- with the cost that we have today with where we're at, I mean, I think we're in that ballpark, just straight up breakeven. We've had a lot of inflation this year, just obviously, with the diesel prices driving up the cost of everything that we're doing, we're -- just from the second quarter to the third quarter, we're up 8% to 10% overall on our cost.

Hopefully, that's going to flatten out in Q4. We don't see a whole lot of an increase and maybe hopefully, it retreats a little bit next year. Obviously, what happened with the elections and everything, it's kind of who knows really where that's may be headed.

But -- so I think we're -- the breakeven price is there. And as we get into the future, I think that will be still somewhere in the same ballpark. And as the performance gets better with the higher fracs should push that down a little bit.

Jacob Roberts

Okay. I appreciate that. Then maybe just to follow up on that performance comment. So the 2025 and 2026 vintage goods, we're starting to see that longer production history. Our conversations with investors would point toward folks modeling a pretty big range of outcomes and some are probably below the 3.5 Bcf per 1,000 that we talked about at the initial onset of this play.

So I was wondering if you could give any color on how the recent wells are performing on an EUR per foot basis, you should think about the change across the vintages per year or even per quarter.

Daniel Harrison

Well, I think since we've been pumping the larger fracs, like I said, we started in December of '25. So all of the 2026 wells have pumped the larger fracs. The early data is definitely pointing to much improved EURs.

I don't know if I would put a certain number on them, but we're -- I mean, percentage-wise, 10% easily increase in EURs. Just what we've seen to date, everything is fitting the way that we got to model. So we're just really comfortable with the bigger fracs. We definitely need more data to basically pinpoint what the numbers are going to end up being.

Operator

Our next question comes from the line of Jack Cavanagh with Goldman Sachs.

John Cavanagh

I would love to focus on the cost in the Western Haynesville. I know you touched on it a little bit in the call, but can you speak to kind of the trends seen in D&C costs over the last few quarters? And also expand maybe on the puts and takes on how you're thinking about the outlook to get those costs lower in the context of some of these rig upgrades and kind of the things you guys are doing with the big hole design?

Daniel Harrison

I think if you take inflation out of the mix, the cost and the change in the frac design, basically, I think our costs have been pretty flat. If you normalize all of that and took it out, I think the -- we got the -- the 10k rigs come, we definitely feel like we're going to shave some days off.

That's going to drop our cost a little bit. And I think in the future long term, we are looking at some rotary steerable technology, but that's a little bit further out in the future. And you also have looked -- we're still looking at the 20,000 frac fleets, I think, would definitely help us there, even though I think that's probably out further on the time line.

Roland Burns

Yes. The major driver of cost on the shale wells is lateral length. And you've seen the Legacy Haynesville achieve these great cost levels because we're now just drilling 15,000-plus wells. So the Western Haynesville is going to get there, but it's going to take a longer period to get there.

So I think the overly focused on the cost of short laterals and the legacy is expensive, too. And I think as we improve these drilling and completion techniques and we get the laterals long, which is going to happen in the future, the costs are going to start to look more similar to the legacy.

So it's just a different stage of development. So I think that the overall focus of the cost is a little bit -- you have to have a little patience. There's a lot of exploration costs. There's a lot of single-well pad.

There's a lot of things in the Western Haynesville in its early development stage that the Legacy Haynesville has the exact same thing, and they're just at different time stages. But it's trending there and all the initiatives for the higher-powered rigs, the higher-powered completions, the better motors, development infill drilling, those are all going to drive those costs way down from where they are today.

And -- but the best thing is that the large reserves in place in the Western Haynesville make it all worth it. They are definitely much higher than the Legacy Haynesville across the board, usually twice as much.

Miles Allison

We went back to 2008, '09, '10 and compared the core, which was iffy in 2008, '09, '10 and the result, and you had to have $5.15 gas to have a 30% IRR. And those were 4,500-foot laterals. I mean, we really didn't start drilling extended laterals even in the core till probably 2015.

And it's only been the last several years that we've been able to drill 15,000-foot laterals in the core. And so to Roland's point, if you compare where we were in the core, they call it the core back in '08, '09, '10 and the first 3 or 4 years of the core versus where we are in the first few years of the Western Haynesville, we are light years ahead in the Western Haynesville where we were in the core to create value with the reserve potential that you have maybe 200 feet of pay in the core, and you may have 1,500 to 2,000 feet of prospective pay in the Western Haynesville.

So it's a completely different game and the price is multiple times more valuable in the Western Haynesville. So the question is, do you have 1,100 penetration for that 90 miles? Do you have the seismic? Do you have the balance sheet and the partners in order to derisk this unlike it didn't happen in the core, there was recklessness when gas hit $6 to $8.

We've not been reckless in the Western Haynesville. We have an exemplary partners and we didn't have back then, we didn't have LNG and demand for natural gas to power the turbines. That is the game changer. That 30, 40, 50 Bcf a day that they've spent trillions of dollars investing in takeaway infrastructure, we didn't have that back then. We have it today.

Jacob Roberts

Got it. That's all super helpful color. So appreciate that, team. Then maybe for my follow-up, just maybe following up on the earlier kind of gas marketing discussion. With the SOCAR relationship, obviously, gives that access to international LNG markets. Just kind of how meaningful could you see that exposure become relative to kind of the current domestic marketing portfolio?

Roland Burns

Well, obviously, today, there's a significant premium to those markets compared to our domestic markets. So there's a very wide huge margin there. And so you don't know what the future looks like if those are going to more align with each other.

But I think having that optionality with a strong partner and will be a great asset to our overall marketing portfolio opportunities. Today, we're putting in place several long-term arrangements where we're going to supply natural gas to power generators.

And those create much higher margins for us because we're able to get those contracts done with much better prices and also have a very long-term great customer. So I think that it's a balance of those 2 trends in our gas marketing to be able to sell more directly to power generators, including the Anderson County power generation hub that the federal government is putting in on our Western Haynesville footprint in addition to other long-term power generation deals that we're going to supply directly to other power generators. So the combination of those 2 will be kind of a great add to our marketing portfolio.

Miles Allison

And for LNG, you need really if you can have it, you really want location closer to the Gulf Coast, and that's just a transportation cost issue. If you want that and we have it. You want an established production base, we have that. You want a balance sheet because you can't do without a balance sheet and you need decades upon decades of inventory.

We have all that. So you've got to check those off and most of them don't have that, and we have all that. And you need to bring a SOCAR in, we have everything plus a big plus sign on it.

Operator

Our last question comes from the line of Tim Moore with Clear Street.

Unknown Analyst

This is [ Paul ] on for Tim. Just want to go back to the balance sheet. It's great that you have SOCAR signed and you're taking net debt down to around $1.5 billion once that closes. But I'm just curious how you're thinking about the dividend from there. What leverage level would you want to see before bringing it back?

Miles Allison

Yes. Let me -- think about this question that you just asked. Now think about this. I mean this is like capturing, what is it, the end of the rainbow, which is a part of silver, gold, whatever, could be a big part of natural gas if prices are high.

Now just think, this is the most reverberating question I've ever had lately because we had 3-plus times the leverage ratio coverage. And now we've got 1.5, 1.7. The dividend -- that tells you that you see that we've controlled this balance sheet properly, and you're just asking if we're going to continue to do that.

Roland Burns

Yes. And I think that's a great question.

Miles Allison

Oh, it's great.

Roland Burns

I think that, yes -- I think our target leverage is to be below 1.5x leverage. So we would have to look over the horizon, do we have a gas price -- a stronger gas price market than we have right now? Do we have the hedge position that secures that prices?

Our #1 priority, as we've said always, is to continue to advance the Western Haynesville and advance the relationships we have that we're building out our midstream supporting the Anderson power hub, et cetera. So those are our top priorities.

And then if they're all met and there's a great gas price environment and our leverage can stay below our targets, then the dividend can come back. But we're not going to bring it back early. We're going to be very responsible to all our stakeholders because our majority of our stakeholders and partners are focused on the long-term future versus short-term return of capital.

Miles Allison

I think you add this fifth rig and you get infill drilling and you get very comfortable of repeatability, which is going to happen. And remember, you've got 2 Haynesville zones, you've got 2 Bossier zones. So it's not that we're trying to complete the same zone, that 90 miles.

We've got maybe 3 or 4 different zones that we're completing. And I think as Dan has told you for the last hour, they're getting better and better and better at what they're doing. And you can see the type partners that we have now. And I do believe that the demand for natural gas is real because of the investment that's been spent, and I believe that we're in the sweet spot for that demand.

So the future looks -- it's never looked better for us, period.

Unknown Analyst

Got it. That's very helpful. For my follow-up, I'd just like to shift back to the power hub. In your 10-K, you talked about an initial capacity of around 2 gigawatts and the Anderson County hub could go up to 5.2. I guess your supply is reaching close to 1 Bcf a day by 2031. So is 2 gigawatts, is that still the right way to think about that and how the volumes could start to grow from that point?

Roland Burns

Well, the very first stage of operations that comes in is a 1 gigawatt power facility. And then the longer term facilities they're building will be 5.2 gigawatts to 5.3. And so that is the plan, and that is what's being all designed.

So it's just the staging. So yes, and then there's the possibility that they expand beyond that if they want to. But that is the initial plans that are in the engineering phase right now. A lot of money is -- a lot of -- all the equipment has been ordered.

So it's off and going. So yes, the first phase that will be sometime in '28 is when we'll start providing gas under that contract, and we'll be constructing the facilities next year, especially on our midstream, we'll be constructing all the gas facilities for them that will need to hook up to the power generation facilities.

Miles Allison

Yes. You'll see first production early '28, and it will strengthen towards the latter part of '28. And on the acreage, they're spending the money, like Roland said. And really, the goal is to have the 5.2 gigawatt position to have that if that demand is there.

Operator

This does conclude the question-and-answer session. I would now like to turn it back to Jay Allison for closing remarks.

Miles Allison

Again, I know there were several competing companies out there, all great companies that you could have listened to. So we're always thankful if you listen to the full hour and 5 minutes of this. And I always want you to know that whether you're SOCAR or Sixth Street or NextEra or the Joneses, we, as a management group, there's about 255 of us, we will always give you our very best, and we'll always be very honest with you, and we expect to always deliver. So thank you.

Operator

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.