マーフィー・オイル（MUR）2026年第3四半期決算説明会：ババレ評価とベトナムでの成長

マーフィー・オイル（NYSE: MUR）は2026年第3四半期の決算説明会において、ガイダンスの上限を上回る生産量、5億1,500万ドルの四半期営業キャッシュフロー、ならびにコートジボワール、ベトナム、アメリカ湾における進捗状況を強調した。経営陣の議論の中心は、ブバレ（Bubale）の商業化の可能性と、同発見の規模を確定するために必要となる設備投資であった。

要点

• 第3四半期の生産量は、イーグルフォード、アメリカ湾、タッパー・モントニーに支えられ、マーフィー・オイルのガイダンス上限を超過した。四半期営業キャッシュフローは総額5億1,500万ドルに達した。
• チヌーク8号井（Chinook #8）は9月22日、自社保有のパイオニアFPSOを通じて生産を開始した。経営陣は、同坑井が2026年第4四半期に日量約9,000バレルの原油生産に寄与すると見込んでいる。
• ラック・ダ・ヴァン（Lac Da Vang）は予定通りのスケジュールおよび予算内でファーストオイル（初期生産）を達成した。マーフィーは2027年の持分生産量を日量3,000〜5,000バレル、年末時点では日量7,000〜12,000バレルに達すると予想している。
• ブレント原油価格が1バレル＝80ドルの場合、経営陣の試算によれば、ラック・ダ・ヴァンとチヌークにより今後5年間で合計約10億ドルのフリーキャッシュフローが生み出される見通しである。
• 経営陣によると、ブバレのチュロニアン（Turonian）層はマーフィーの予備的な商業化基準をクリアした。初期スクリーニングでは、単独の大水深開発を行うには概ね1億5,000万バレル超の可採埋蔵量が必要であることが示されている。
• マーフィーは2027年第2四半期にブバレの次回評価試掘プログラムを開始する予定である。坑井1本あたりのコストは8,000万〜1億ドル、広範な評価作業を実施した場合は約1億1,000万ドルに達する可能性がある。

主要財務データ

事業および操業業績

コートジボワール：商業化の定義に向けて前進するブバレ

ブバレ・ウェスト1X（Bubale West 1X）坑井は、最初の発見地点から傾斜下部（ダウディップ）にあたるチュロニアン層で原油を確認し、より深部のアルビアン（Albian）層でも炭化水素層に遭遇した。圧力データは、約8マイル離れ、約1,100フィートの構造上の深度差がある2つのチュロニアン層坑井間に連続性がある可能性が高いことを示している。

マーフィーはチュロニアン層について、API度37の軽質原油を含み、ガス油比が1バレルあたり約1,500〜2,000立方フィートの高品位な貯留層であると説明した。初期のコア分析では、平均浸透率が約100〜数百ミリダルシーの範囲にあり、一部の層区間では1ダルシーを超えていることが示された。

経営陣はチュロニアン層が経済性のある開発を裏付けると考えているものの、更新された資源量レンジの提示については時期尚早としている。同社はチュロニアン層、セノマニアン（Cenomanian）層、アルビアン層にわたり、5〜6カ所の潜在的な評価坑井の地点を検討している。評価プロセスは18〜24カ月間継続する見込みである。

マーフィーは、評価試掘で原油の確認が続けば、ブバレにさらに3億〜4億ドルが投資される可能性があると試算している。同社は開発着工前に地下の不確実性をすべて排除するのではなく、FPSOの規模を適切に決定するのに十分なデータを収集することを目指している。

ベトナム：開発ハブを確立するラック・ダ・ヴァン

ラック・ダ・ヴァンは、プロジェクト認可から3年足らずでファーストオイルに到達した。同プロジェクトはベトナムにおけるマーフィー初の操業主体（オペレーター）案件であり、ラック・ダ・チャン・ノース（Lac Da Trang North）やその他の近隣の発見油田を含む、将来的なタイバック（既存設備への接続）に向けたインフラを構築する。

経営陣によると、直近のラック・ダ・ヴァンの積荷はデーテッド・ブレントに対して1バレルあたり10ドル超のプレミアムで販売された。2026年には2本目の坑井が予定されており、2027〜2029年にかけて追加の坑井が計画されている。持分ピーク生産量は2028年または2029年に日量10,000〜15,000バレルに達する見込みである。

ラック・ダ・チャン・ノースは、評価坑井を掘削することなく海底タイバックとして進められる可能性が高い。また、マーフィーは2027年または2028年にラック・ダ・カム（Lac Da Cam）複合地域で探鉱井を掘削する可能性がある。

ハイ・スー・ヴァン（Hai Su Vang）の開発プロセスは、パートナー企業およびベトナム政府とともに進展している。経営陣は引き続き2027年第4四半期のプロジェクト認可を目標としている。

アメリカ湾およびイーグルフォード

チヌーク8号井がパイオニアFPSOを通じて稼働を開始したことで、マーフィーは新規インフラを建設することなく、原油主体の生産を追加することが可能となった。第4四半期の海洋生産量には、修繕作業（ワークオーバー）、計画されたデルタ・ハウス（Delta House）の保守点検、天候不順による操業停止も反映される。修繕作業の大部分は2027年第1四半期初頭に完了する予定で、その後、湾岸地域の生産量は回復する見込みである。

イーグルフォードにおいて、マーフィーはより安定した掘削計画に支えられた複数年にわたる増産を計画している。2026年終盤に掘削された坑井は2027年の平均生産量を大幅に押し上げると見込まれており、生産量は第4四半期にピークを迎える見通しである。

経営陣の予備的な見解では、イーグルフォードの設備投資額は近年の約3億ドルに対し、2027年には約5億ドルに増加する可能性がある。最終的な設備投資ガイダンスは第4四半期決算発表時に提示される予定である。

経営陣のガイダンス

リスク要因および注視すべき点

• マーフィーはブバレの更新された資源量レンジを確定していない。主な不確実性としては、チュロニアン層の水平方向の油充填状況、貯留層の層厚、品質のばらつき、ならびにウェスト1X坑井が油田全体の油水境界（OWC）を特定したかどうかが挙げられる。
• セノマニアン層はチュロニアン層よりも浸透率が低い可能性がある。アルビアン層のデータは有望であるものの依然として限定的であり、より深部に位置するこれら2つの貯留層はいずれもさらなる評価が必要である。
• ブバレの評価試掘支出は、試掘結果、掘削箇所の数、評価作業の範囲によって大きく変動する可能性がある。
• 将来のコートジボワール開発に向けた資金調達の決定は未定のままである。経営陣はファームダウン（権益の一部譲渡）、一時的な負債調達、陸上資産の売却、またはこれらの選択肢の組み合わせを検討する可能性がある。
• 自社株買いは、評価試掘の資金手当てとバランスシートの保護とのバランスを考慮して進められる。経営陣は、株価が保守的に見積もった本源的価値を大幅に下回る水準まで下落した場合、自社株買いを実施する可能性があることを示唆した。

アナリスト質疑応答（Q&A）の要点

• ブバレの商業化基準：マーフィーの予備的スクリーニングによると、単独のFPSO開発には概ね1億5,000万バレル超が必要とされる。経営陣はチュロニアン層がこの基準をクリアしたと考えているが、資源量レンジを公表するにはさらなるデータを必要としている。
• 評価試掘の順序：候補となる坑井には、傾斜上部（アップディップ）でのセノマニアン層の試掘、アルビアン層の傾斜上部または傾斜下部（ダウディップ）の地点、ならびに既存の2坑井の間または周辺でのチュロニアン層の追加坑井が含まれる。最初の掘削場所はまだ選定されていない。
• 資本配分：経営陣は、同プロジェクトの不確実性と重要性を考慮し、2027年の基盤事業の設備投資について比較的狭いレンジを設定し、ブバレの評価試掘支出はそれとは別に区分して明示する方針である。
• イーグルフォードの選択肢：マーフィーは、将来的に同資産の全部または一部を現金化する選択肢を残しつつ、イーグルフォードの増産とキャッシュフローの増加分を評価試掘やその他の優先課題の資金調達に充てる意向である。
• モーリタニア参入：マーフィーは大水深の原油をターゲットとしている。短期的な支出は地震探査データの再処理や各種調査に集中させ、探鉱井の掘削については2029年頃より前になる可能性は低い。

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 morning. My name is Erica, and I will be your conference operator today. Welcome to Murphy Oil Corporation Third Quarter 2026 Earnings Call. [Operator Instructions] Thank you.

I will now turn the call over to Atif Riaz, Vice President of Investor Relations and Treasurer.

Atif Riaz

Thank you, Erica. Good morning, and welcome to our third quarter 2026 earnings conference call. Joining me today are Eric Hambly, President and CEO; Tom Mireles, Executive Vice President and CFO; and Chris Lorino, Senior Vice President of Operations.

Yesterday, after market close, we issued our third quarter earnings release, a slide presentation and a stockholder update. These documents can be found on Murphy's website, and we will reference them today throughout our call.

As a reminder, today's call contains forward-looking statements as defined under U.S. securities laws. No assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, please refer to our most recent annual report filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements, except as required by law. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of America.

I will now turn the call over to Eric for opening remarks.

Eric Hambly

Good morning, everyone, and thank you for joining us. When we spoke in August, I mentioned that years of technical work were starting to translate into multiple pathways for growth. This quarter, several of those opportunities materialized across our portfolio. Over the past 3 months, we advanced the appraisal program at Bubale, made a new discovery in Vietnam, delivered first oil at Lac Da Vang, brought Chinook 8 online and beat the top end of our production guidance. Our letter and earnings release cover these results in detail.

What I want to focus on this morning is how these results and the strategy behind them are creating lasting value for our shareholders. Starting in the Gulf of America, we acquired the Pioneer FPSO in 2025 with opportunities like Chinook # 8 in mind. On September 22, Chinook 8 came online through the Pioneer facility, adding oil-weighted production without the cost or lead time of new infrastructure. Because we own the FPSO, those incremental barrels now benefit from stronger economics and higher returns.

Five days after bringing Chinook 8 online in the Gulf, we achieved first oil at Lac Da Vang in Vietnam. This was our first operated development in the country and not that I was counting, we brought it online in 2 years, 11 months and 23 days from project sanction, safely, on time and on budget.

Beyond that strong project execution and initial start-up, Lac Da Vang creates value for Murphy in multiple ways. First, it gives us local operating and development experience that we can build on as we grow our business in Vietnam. Second, it adds attractive oil barrels with some recent cargoes selling at a premium of more than $10 per barrel to Dated Brent. As production ramps up, Lac Da Vang's cash flow contribution becomes material.

And third, Lac Da Vang establishes the infrastructure to support our broader hub-and-spoke strategy in the country. With a hub now in place, our Lac Da Trang North, White Camel North discovery, and other nearby opportunities can benefit from a lower economic threshold and a more capital-efficient path to production.

Turning to Côte d'Ivoire. The Bubale West 1X well confirmed oil in the Turonian reservoir, downdip from the original discovery and also encountered hydrocarbons in the deeper Albian reservoir. We're encouraged by the Bubale exploration, appraisal and analysis work completed so far. The information from the Bubale West 1X well give us even more confidence that the likely range of resources in the Turonian reservoir supports an economic development of the Turonian and help narrow the range of uncertainty in the recoverable resources.

I think it will help investors if I characterize the Turonian reservoir at a high level based on the data we have from the 2 Bubale wells and our seismic data set. The Turonian reservoir is a generally east to west trending deepwater channel system, which is narrower at the discovery location and widens to the west and downdip for the West 1X location.

Pressure data from the wells indicate likely reservoir continuity between the 2 wells. Recall that the 2 wells are about 8 miles apart and the West 1X well is about 1,100 feet structurally downdip from the discovery well. The Turonian appears to be a high-quality reservoir that contains high-quality oil. The Turonian oil is 37 degrees API and the gas-oil ratio is around 1,500 to 2,000 cubic feet per barrel.

We collected a whole core at the discovery location and are analyzing the core now. The preliminary work indicates that the average reservoir permeability is in the 100 to hundreds of millidarcy range with some reservoir over a Darcy. More work is necessary to determine the variability of reservoir quality throughout the field.

The West 1X well encountered oil-bearing and water-bearing Turonian reservoir sands. The water encountered in the West 1X well may represent a definitive Turonian-wide oil-water contact, but we need to do more work to confirm that. The fluid PVT properties suggest that the reservoir does not have a gas cap.

In addition, as we previously disclosed, we encountered high-quality oil in the deeper Cenomanian and Albian reservoirs, which will need to be appraised. We clearly know much less about the Cenomanian and Albian reservoirs at this point, but here's how we're thinking of them. The Cenomanian is the same type of channel system as the Turonian and it widens updip to the north and is narrower at the discovery location and downdip south.

The Albian extends updip to the Northeast and downdip to the Southwest from the West 1X location. We believe the West 1X well encountered an oilfield sand at the edge of the Albian channel system. We're currently working to incorporate all the Cenomanian and Albian well and seismic data to improve our understanding of the reservoir and help determine the optimal locations for future appraisal wells.

I recognize that's a fair amount of technical detail, but many of you have asked for greater visibility into what we're seeing at Bubale. We want to be transparent about what we know today and what we're still working through. There is more work ahead, but each appraisal well gives us a clearer picture of what we have and helps guide where we go next.

Our key achievements this quarter are not isolated events, and I'm proud of what our teams delivered. We were simultaneously bringing offshore projects online on opposite sides of the world, exploring and appraising in shallow and deepwater across multiple basins and operating our producing assets above expectations. This breadth of execution reflects capabilities built over decades, and those capabilities are creating significant value.

At $80 Brent, Lac Da Vang and Chinook are expected to generate approximately $1 billion of combined free cash flow over the next 5 years, while the exploration and appraisal opportunities we advanced this quarter represent resource potential roughly twice the size of our current offshore reserves.

The base business also continues to deliver with Eagle Ford, Gulf of America and Tupper Montney all contributing to production above the high end of guidance and $515 million of operating cash flow in the quarter. Our results this quarter add both cash flow today and a broader set of investment choices for the future. As those opportunities mature, we will remain selective, prioritize the investments with the most compelling returns, sequence capital with discipline and maintain an uncompromising commitment to financial strength.

With that, we're ready to take your questions.

Operator

[Operator Instructions] Your first question comes from the line of Arun Jayaram with JPMorgan.

質疑応答

Arun Jayaram

I appreciate some of the key technical details around Bubale. I was wondering if you could maybe think about the bigger picture here. You mentioned that you believe that you've already reached a minimum threshold for development. I was wondering if you could maybe help us think about big areal extent about the size of the recoverable resource range and a little bit more on the next steps in the appraisal program.

Eric Hambly

Arun, thanks for that. I know everyone is anxious for us to give a new resource range for Bubale. What I'll tell you is, from where I'm sitting, we have 2 wells in the reservoir and still a fair bit of remaining uncertainty about the range of resources. Like you pointed out, I think we have quite a bit of confidence that we have derisked, through our appraisal program, a volume that clears an economic development threshold, but I'm not really yet ready to describe a new range of resources from the Turonian. And we have a lot of work to do before we're ready to talk about the other reservoirs.

And so what I expect is as we progress our appraisal program over the next 18 to 24 months, we'll be in a better position to give a new updated resource range. I just don't know it yet. There's still quite a bit of uncertainty that we have. Obviously, from our release materials and my comments just now, we've learned quite a bit about the Turonian, but there's still quite a bit of uncertainty. How much of the Turonian system is filled in a lateral extent is still something that we have to think about.

As we indicated, we don't expect that the reservoir above the discovery location in Turonian should contain anything other than oil, but we have 2 data points. We expect, in these type of systems, that we would have variability of reservoir thickness, quality, et cetera, and we need to know more before we pin down our resource range. I'm excited that we believe that we're at the point where we have a project to develop here, but I don't have confidence in a new range yet. So we'll be working on that.

Obviously, we haven't described that we have an active appraisal program coming up. There are quite a few remaining things to learn. I anticipate that we will -- between now and probably the second quarter next year, we will kind of hone in on the most impactful and helpful wells to drill to reduce our remaining uncertainty in all the reservoirs.

So the things that we're thinking about, we have about 5 to 6 locations that make sense today to learn more, and we're continuing to incorporate the data that we have recently collected from the wells. We're relooking at our seismic data set and incorporating the well data into the seismic data set and doing additional work to decide where to put the well locations to continue to reduce uncertainty in the most capital-efficient way.

And so the kinds of wells we may drill in next year's program, the things that make the most sense would likely be an updip Cenomanian that would be heading north of the discovery location. In the Albian, we could move updip or downdip in the Albian from the West 1X location. In the Turonian, there's still a potential to have a well north or south of the West 1X location, so testing lateral extent of the channel system. There's a possibility of a Turonian well between the 2, the discovery and the West 1X location.

And there's still a possibility of a downdip Turonian well, although I think that's less likely now with the results of our West 1X well. It's still possible, but it's something we would pursue if we conclude that we have not encountered a definitive Turonian-wide oil-water contact, we might be chasing oil downdip in some of the stacked Turonian channel sands.

So there's still a lot of work to do. The team, I'm really proud of. They're doing a great job of incorporating all the data, but we just are not yet ready to give a new resource range. And we're trying to -- as you've heard from us this morning, we're trying to tell everybody what we know and what we don't know and be pretty transparent about it. And I know it's closely watched for the company. It's a pretty big deal for us.

We're excited that this field, as we learn more about it, is looking more and more -- giving us more and more confidence that we have a project here because the project here is significant for our shareholders as we exit this decade, head into the next decade as we're likely looking to bring it online about 6 years from discovery to coming online first oil.

Arun Jayaram

Great. My follow-up is on Vietnam. You're approaching an FID decision in about 12 months from now at Hai Su Vang, Golden Sea Lion. Could you give us a little bit of an update on just general thoughts around how that project is developing?

Eric Hambly

Yes. That's a really great question. What I'm really happy to tell you is that we are advancing our assessment and working with our partners and government at a faster pace than we have seen other companies be able to accomplish in the past in Vietnam. We have indicated that Vietnam is very supportive of our work there and they want to push to move things faster, and we are seeing that happen.

There are several steps in the process of going from discovery to an approved development and then executing it. The steps that we're executing there, we're moving through very rapidly. So I think we're on track for a project sanction at the end -- let's say, the fourth quarter of 2027. It's moving along very well with partners and government and no reason to have anything but happiness about how it's progressing.

Operator

Your next question comes from the line of Doug Leggate with Wolfe Research.

Douglas George Blyth Leggate

Eric, a lot of geometry in your description this morning. I wonder if I could ask you to go a little deeper, pardon the pun, on the Albian feature. You haven't really talked anything about the extent of how that compares to the shallower test you've already done. So can you offer any color, you say -- it sounds like you're saying it's an oil-filled sand. So it sounds like no oil-water contact in the Albian. What does that feature look like in terms of the scale?

Eric Hambly

The areal extent of the Albian and the Cenomanian, assuming that they are filled and our current seismic interpretation is correct, which is a big leap from where we are today, are similar in extent to the Turonian. We think the Turonian is potentially longer and narrower and the Albian could be shorter and wider. But we did sample oil in the Albian, like we indicated, we think it's on the edge of the channel system. We confirmed that we sampled oil. It's a nice-looking oil with a low GOR or moderate GOR.

Douglas George Blyth Leggate

I hate to press on this a wee bit, but you did give some permeability data on the Turonian, but you didn't mention anything about the sand quality in the deeper sections. Can you offer anything there? And I wonder if -- what's behind my question really is, as we think about this moving towards a commercial development, one of the big challenges that, that area has had in the past was the number of wells required to develop. So I'm trying to -- just thinking in terms of what the capital intensity would be to bring something like this to market. So any color you can offer there would be great.

Eric Hambly

Yes, Doug, so we are thinking about the same things that are on your mind, and that's why we're working through all the data. I'm not yet ready to share the data on the deeper horizons because we haven't yet done the work. So we've collected core. We will analyze it. It's being analyzed. We haven't yet done that work. I think it is normal to expect in many cases that you would have lower reservoir quality, the deeper you go.

I think we have some indication that the Cenomanian, while not comprehensively yet assessed, the Cenomanian may be lower permeability than the Turonian. The limited data we have from the Albian -- very limited data we have from the Albian suggests that we found what maybe surprised us as even better reservoir quality than we would anticipate at this depth. So still a lot of learn, not yet ready.

I'm very encouraged by the reservoir quality we've encountered in the Turonian with respect to how to efficiently and economically develop the field. We have more work to do before we have that same confidence in the other 2 reservoirs.

Douglas George Blyth Leggate

Eric, would you mind if I just tagged on a quick follow-up? In your original range, was the Albian included in your original resource range?

Eric Hambly

So the range that we provided, the only range we provided so far was our pre-drill range for the Cenomanian. And what we have said so far is we're not -- I don't want to reference that range anymore. That was before you had any data drilled here, we said the Cenomanian might have a certain range of mean to upside volumes, not the range, the full range. And that was for one reservoir.

Like I said earlier, we don't yet know what the new range is. We contemplated one reservoir that was significant in its potential extent, and we encountered that reservoir, which is still significant in its potential extent, along with the Turonian and now in Albian that are significant in their extent. So we have a lot of work to do. What I would hesitate to say or have anyone think is we gave you a range for one that was a mean to upside, and now we have 3 reservoirs, and it's going to be 3x that big. I don't expect that to be the case.

I think we're honing in on a commercial scale development with a very large range of uncertainty of how large this resource is. And I don't want anyone to start multiplying things by 3, 4 or 5. I think we have to just do the work, make an assessment, progress through the appraisal program, give a new range. Again, I'm excited that I believe we have a commercial development at Turonian, more resource to be fine-tuned in the other reservoirs. That's kind of what we know now, and we'll tell people more when we know more.

Operator

Your next question comes from the line of Chris Baker with Evercore ISI.

Christopher Baker

Eric, I appreciate all the detail. I guess maybe just a different angle on the same topic that's been asked. As you think about sort of a minimum resource you would need for the stand-alone development, given the encouraging signs that you've seen to date, what would that look like? And I guess, in terms of the time line, when would it make the most sense to potentially bring on a partner, given your 85% to 90% working interest there?

Eric Hambly

Chris, great questions. Obviously, as we learn more about the Turonian, it will influence our exact assessment of the resource we need to be commercial. The better the quality, the more continuous, et cetera, the less wells are required for the development to recover the same volume. So there's certainly work to be done to fine-tune.

Our screening numbers suggest we need over 150 million barrels roughly to make it work. And that's just developing, stand-alone, a typical deepwater field with an FPSO and a number of wells. So that's a fairly low bar, but it's actually a pretty significant amount of volume. So that's kind of where we're sitting in terms of early screening number of what we need to clear a commercial threshold.

Christopher Baker

That's great. And I also wanted to touch base on the Eagle Ford. Just curious how you're thinking about that within what seems like an opportunity-rich '27 outlook here. In terms of the step-up in capital and the timing, anything you can share there in terms of what the growth profile could look like and what CapEx cadence could end up being?

Eric Hambly

Yes. So we indicated a couple of months ago that we were intending to ramp up our Eagle Ford. We added capital this year to resume drilling, which will allow us to accelerate bringing online wells earlier next year than our original plan for the year. That's the beginning of what I anticipate will be a multiyear ramp-up to some new plateau rate for the Eagle Ford.

So we will not bring online this year more wells in the Eagle Ford than our original plan, but we will have wells ready to be completed late this year, heading into early next year, which will increase our annual average production rate next year materially, and we're planning next year to run a steady program, which would have a ramp through the year with the peak production in the fourth quarter, which is different than what we've done really for the last 5 years, where we are practically done with our program by the third quarter.

So that will lead to more capital deployment to Eagle Ford. Obviously, we haven't yet formulated our budget. We're going to work on that between now and the end of the year, and we'll present that in our fourth quarter earnings call in late January. But I think, directionally, we're looking at Eagle Ford capital increasing from sort of the plus or minus $300 million mark in the last year or 2 to around $500 million, somewhere in that ballpark in 2027. Again, more fine-tuning to be done. That's kind of how we're thinking about it.

Operator

Your next question comes from the line of Leo Mariani with ROTH Capital Partners.

Leo Mariani

Just wanted to follow up on some of the comments that you made around Côte d'Ivoire. If I kind of heard you right, it sounds like still a lot of analysis to go, but perhaps you guys don't get to kind of the next appraisal well maybe until sometime in the second half of '27. Is that reasonable? It sounded like you guys do really take your time and be thoughtful about where that next well goes.

Eric Hambly

Leo, we are actively working to secure a rig to conduct that appraisal program. We're in an advanced stage on our tender process. We have uncertainty about when, specifically, it arrives. I expect now that we would start that program sometime in the second quarter of next year, but I'll know a lot more when we actually tender the rig.

Leo Mariani

Okay. And I just wanted to follow up on Lac Da Trang North. Have you guys been able to do some more work on that discovery? Obviously, it's a good-sized discovery. Do you have a sense of whether or not you guys need to drill an appraisal well? Or do you think, at this point, it's just going to progress towards a subsea tieback? Just any more color would be great.

Eric Hambly

The way we're thinking about it now is it's likely to be progressed as a subsea tieback without an appraisal well. We are likely to drill some exploration wells north of Lac Da Trang in the future, let's say, in '27 or '28 in the Lac Da Cam complex, that's Orange Camel. And depending on how those wells come in, either would -- we would either develop Lac Da Trang, Lac Da Trang North, Lac Da Cam as a new hub or more likely, they would be tied back to the Lac Da Vang infrastructure. And we'll know more about that as we continue to progress our evaluation.

We're happy with our Lac Da Trang, Lac Da Trang North discoveries. I think that their nice tieback scale will be developed very capital efficiently and likely will not have an appraisal well on Lac Da Trang North.

Leo Mariani

Okay. That's helpful. And then on Eagle Ford, you obviously mentioned that you're going to spend more money next year. I think that's been very well socialized by you folks for a continuous program. It makes sense. And just how about any of the other kind of moving pieces? Do you see kind of the exploration and appraisal budget up a decent amount year-over-year as well in '27? It sounds like you're geared for more activity. It sounds like at least a couple of wells in Côte d'Ivoire, maybe 2 or 3 there and several more wells in Vietnam. Just kind of any high-level color you could provide on kind of activity set in some of the bigger offshore stuff next year versus this year?

Eric Hambly

Sure. As we're thinking about our program next year, I expect our exploration program, which includes all of our seismic acquisition reprocessing data, all that kind of -- and drilling wells will be in the 10% to 15% of our total capital program. But our appraisal program at Bubale will be significant investment.

The wells that we will drill appraising Bubale are likely in the $80 million to $100 million range per location, and that's assuming that we don't conduct an extensive evaluation program. If we conduct an extensive evaluation program, that could easily get to be $110-million-type range per location.

So depending on the number of wells and how we progress them, there's significant uncertainty about our appraisal spend at Bubale and that will drive the bulk of our range of uncertainty in our capital program next year. What I can tell you, as I'm thinking about, we're setting our budget for the year, communicating it in January, we're likely to give capital guidance next year differently than we have historically.

We're likely to give you a range that's reasonably tight for sort of our -- the base business and then indicate the range of Bubale appraisal spend, again, because it's material and every well we drill in Bubale will inform whether we want to drill more and how much they'll be and just that range of uncertainty is today significant, will likely continue to be significant as we head into the early part of next year, and we'll try to communicate that a bit differently.

Operator

Your next question comes from the line of Noah Hungness with Wells Fargo.

Noah Hungness

For my first question here, I did want to touch on kind of the potential funding requirements for a CDI development and just how you're thinking about that. And in the event of a potential farm-down or asset sale, if you were to explore those options, could you maybe talk about the decision tree between those? And if a farm-down would be a farm-down of the CDI asset or a farm-down of some of your currently producing assets?

Eric Hambly

I would tell you that where we're sitting today, we don't have an answer of our best outcome for our shareholders, but that's how we'll be thinking about it. As we learn more about what we found in Côte d'Ivoire, we will form a view of do we want to keep all of the ownership we currently have in Bubale and the associated potential other discoveries on the blocks? Or do we want to do something else with our assets?

We're coming into this with a great balance sheet, a lot of liquidity and a really good financial position to figure out what we have and decide the best outcome for shareholders. We're aware that we have assets that other people would like. So asset monetizations are something that we will think about.

We're not yet in a position where we need to make those choices. We're conducting an appraisal program over the next 18 to 24 months. And at the end of that program, we'll probably have a better view for funding needs, size of the opportunity, size of the capital program and then determine, does it make most sense to farm down what we found in Côte d'Ivoire? Or does it make sense to take on temporarily a bit of debt? Or does it make sense to sell, potentially, assets in our onshore business or potentially a combination of all those things?

We're looking at that. We're modeling that. We don't have an answer to what the problem is yet, but we're aware that we have quite a few options to do it, and we're really excited to have all those options.

Noah Hungness

Okay. And then for my second question, I was wondering if you could talk about some of the exploration projects in the Gulf of America. Would these be greenfield exploration developments, brownfield expansions? Just some of your latest thoughts on that asset.

Eric Hambly

Yes, great question. So the way we think about our opportunity set in the Gulf, we have a handful of hub-scale prospects and quite a few tieback-scale opportunities that are near our existing infrastructure, mostly that we operate. And so you'll see us, over the next 3, 4 years in the Gulf, conduct a program that occasionally tests a hub-scale opportunity, exploration well, and more often does tieback-scale things near our existing infrastructure.

As we're thinking about our program next year, we have choices to make. I anticipate next year's program in the Gulf of America will feature a hub-scale test, but we haven't formalized that yet. When we announce our budget in January, we'll let you know what our program is. But I think we're likely to test one hub-scale prospect in the Gulf and in Vietnam, some tieback-scale opportunities in our -- the block that contains Lac Da Vang, 15-1/05 .

Operator

Your next question comes from the line of Phillip Jungwirth with BMO. Your next question comes from the line of Josh Silverstein with UBS.

Joshua Silverstein

I wanted to touch on the cost structure. LOE was very low this quarter, and you reduced the full year rate to the bottom end of that $10 to $12 per BOE range. Can you just talk about how this is trending into next year? I don't know if there were any one-off items in there, but clearly, a good result this quarter.

Eric Hambly

Josh, thanks for that. Obviously, we haven't set our program for next year definitively. This quarter, we are choosing to have a pretty active workover program in the Gulf. We identified a number of wells that were either -- had a potential to produce at higher rates or in the case of one well, not producing that we're able to go into some workover activity and add volumes as we either exit this year or head into next year.

I think we'll see some of that activity continue into the first quarter of next year, but then the rest of the year is likely not to have significant workover activity. Again, we still haven't set our budget for next year, but I expect that some of the work we're doing in this quarter will carry into the first quarter next year. And again, we've been communicating probably for a few years now that we anticipate operating expenses to be in the $10 to $12 per barrel range. I would expect that, that's a reasonable number for 2027 as well. So yes, that's kind of where we are.

Joshua Silverstein

Got it. Okay. And then just curious about the shareholder return thoughts as well. Obviously, there's a bit of uncertainty as to what the CapEx budget looks like for next year and what the long-term budget may be around potential development there. Are the buybacks on hold for now as you just kind of look to keep the balance sheet in good shape for potential bigger CapEx opportunities for you guys? I know you had previously done them, but you want to make sure the dividend is paid and keep the balance sheet in good shape. So just curious on that front, too.

Eric Hambly

Yes, that's a great question. And it's something that I think about, about 12 times a day, Josh. The way I think about it is that we believe that our shares do not reflect the value of some of our expansion opportunities that we see in front of us for Hai Su Vang, does not reflect any value for Côte d'Ivoire. They probably don't reflect value for Côte d'Ivoire because we haven't been able to tell you how big it is, so how would anyone value it? I understand that.

As we learn more, we will probably conclude that we anticipate a period of time between learning about the field and trying to communicate the potential value of it that our share price may not move to reflect that because of discounting, risking, et cetera. It probably will encourage us to buy our shares because they'll be cheap relative to what we think intrinsic value will be. If we see periods in the next year or so that our share price pulls back significantly lower than even a fairly conservative view of intrinsic value, we're likely to buy back stock.

I would like to reward our long-holding shareholders by concentrating the value of the company in less shareholders that are long holders and buying back stock is a nice way of doing that. Having said that, we will protect the balance sheet. We'll be careful about debt level. That's very important for us.

So we have a bit of tension in the system between funding the appraisal program and understanding what we have, buying back stock. Those are in tension, and we'll be thinking about that and we'll be monitoring oil price because our share price moves a lot with oil price and be thinking about how do we win for our shareholders.

Operator

Your next question comes from the line of Phillip Jungwirth with BMO.

Phillip Jungwirth

You made some really good progress on Eagle Ford well costs this quarter, and I was just hoping you could hit on the drivers there. And then as you look to run a larger and, I assume, more level-loaded program next year, do you think there could be incremental efficiencies that come out of it as a result? And then just what are you seeing on the cost side inflation at the moment?

Eric Hambly

Thanks, Phil. Let me give you kind of a high-level view, and I'll ask Chris Lorino to provide maybe a little bit of additional color. This year's program, we're really excited about our well costs coming down materially. We reduced our cost per foot to drill and our cost per foot to complete. The drilling work was about 5 different things the team really focused on.

Completion, we are getting very efficient at how we're pumping these frac jobs, and we're also tailoring every stage of the frac job to be the most capital efficient possible, operationally efficient and a 26% reduction year-over-year in well costs, drill and complete, it's pretty impressive.

As I was prepping for our call this morning, I noted that our completion cost per foot realized in '26 is the lowest completion cost per foot we have seen in our Eagle Ford business to date, lower than 2016 when service costs were very low, lower than '21 when service costs were low. We really [ nailed ] it out of the park. Part of that is long laterals, but it's not just long laterals; it's also operational efficiencies.

Chris, I don't know if you have any color to add to that.

Chris Lorino

Yes, you hit on it. The combination from the longer laterals and the completions efficiency, we keep continuing to be creative on how we get our cost per foot down and really tailoring each pad to the best outcome and the best plan to get the BOEs out. So we continue to see that improve, and you think it would flatline, start to flatline, but we're continuing to see improvement there by tailoring each one. And it is a combination of the longer laterals with our completions efficiency.

Phillip Jungwirth

That's great. And then a bit more frontier than Côte d'Ivoire, but I was hoping you could talk about the entrance into Mauritania and what drew you to this area, next steps after signing the PSC and just confirm, is the objective here oil just because the country does have a large LNG project also?

Eric Hambly

Yes, great questions. Mauritania is, to us, what we've been communicating our portfolio needs, which is low-cost entry into material opportunities that we can assess relatively cheaply and test relatively cheaply. And we're really happy with our entry here into Mauritania. We are exploring for oil. We do recognize there are gas discoveries in the area. We are looking for oil in the deepwater in Mauritania, and we think it checks the box of those things: low cost of entry, low cost to assess, relatively low cost to test, good financial -- good fiscal regime, et cetera.

After we sign up -- after signing the PSC, which we've just done this week, we'll move forward to do some seismic reprocessing and studies work, and we'll decide at some point if our thoughts around our prospectivity are confirmed by reprocessed seismic and more assessment, and we'll make a decision about a potential well in the future. I would guess at this point that a well being drilled -- exploration well is probably not something we do until perhaps 2029 or that kind of time frame. So very limited spend, mostly around seismic reprocessing and assessment work here over the next 2 years or so.

Operator

Your next question comes from the line of Charles Meade with Johnson Rice.

Charles Meade

I'd like to go back to the question around Côte d'Ivoire appraisal. And you've got a really interesting challenge here in front of you and probably no one path that's going to please everybody or satisfy all of the kind of the competing priorities. But I wondered if you could talk about your philosophy for the appraisal, maybe the relative priority of establishing a minimum threshold in the Turonian versus sizing an eventual development. And I'm really wondering how that plays into your current thinking about perhaps the sequencing of the appraisal wells, like if you're more interested in clearing that minimum threshold upfront or rather you're more interested in sizing it perhaps with a Cenomanian or Albian test before then.

Eric Hambly

Yes, that's a really good question. And it gives us a chance to talk about how we think about our development strategy here as it relates to appraisal. What we have done with most of our developments over the last 2 decades at Murphy is appraise enough to get to a point where we have confidence that we're not materially over or undersizing the development to efficiently develop the resource, but also not appraised to the point where we have no remaining uncertainty.

So what I would expect us to do here is to learn enough that we can build -- we can design an FPSO that is not significantly too large or too small; it addresses a reasonable range of outcomes, both in total resource size and productivity of the wells. And we move forward with development while we continue to learn more about the full potential of all the reservoirs in the field. So we're going to get to a point where we're not committing large capital that is misdesigned for the resource that we have and the rates we can produce it.

And if you think about that, we're spending significant money appraising. Let's just say we'll spend another $300 million, $400 million at Bubale. That's an estimate. I don't know if we'll do that, but if we keep finding oil, we'll keep doing that. That is a lot of money, but it's not of the same magnitude as a $10 to $20 per barrel capital development of a material resource.

So it's important to us to get right the large capital investment by learning enough that we don't make a mistake and be significantly too big or too small. But we're not going to appraise and reduce all uncertainty and then commit to a development. We're going to, at some point, decide we have enough that we can be flexible and we can move forward, and we'll learn as we develop the field.

Charles Meade

Got it. That's helpful for the generalities. I'm going to try to drill in maybe one step further. Does that -- is your next appraisal going to be that Turonian in between the discovery and the 1X, which would -- you mentioned in your prepared comments, you think you're in [ pressure ] communication, but I imagine that a test there could confirm that possibly, which really raises the low end of the bar. And perhaps also, there is some potential for appraisal in the Cenomanian and Albian if you choose that in between location. Is that next?

Eric Hambly

So as I mentioned earlier, we don't yet know the sequence of wells that -- or which exact locations. We're doing that work now. By the time we start our appraisal program in the second quarter, we'll have an order that we'll know and we'll act on. I can't yet tell you what the next one will be because we're doing the work. I think, again restating, Cenomanian updip, Albian updip or downdip, a Turonian well between a Turonian well north of the West 1X, those are all likely places where we would drill the first well.

Your assessment of the ability to learn more about the Turonian by putting a well in between is valid, and we are thinking about it the same way. I don't yet know if that's the next well. It's a well that we are considering doing. We're going to do more work to figure out the optimal thing to advance the project in the most capital-efficient way. And I don't have an answer yet, unfortunately.

Charles Meade

No, that's great color, Eric. It's going to be really interesting to watch this unfold.

Operator

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

John Cavanagh

I wanted to start on Lac Da Vang. It's a great milestone to bring online in 3Q. But I was wondering if you could speak to the shape of what that ramp looks like to peak production in '28, '29 as well as the timing on when you could develop any one of these tieback opportunities in the area.

Eric Hambly

At Lac Da Vang, we anticipate adding a second well this year. We'll continue to deliver more wells through '27, '28 and '29. Next year, production rate is probably -- net to us, probably 3,000 to 5,000 barrels a day. Exit rate is probably in the 7,000 to 12,000 barrel a day range -- I'm sorry, exit of 2027, to be clear. And we anticipate peak production of 10,000 to 15,000 barrels a day net to us probably in '28 or '29.

John Cavanagh

Got it. Appreciate that. And maybe reflecting on the Devon Eagle Ford sale process. Just curious what that told you about the market value of your asset and if that changes any of the way you view kind of the optionality of holding that asset within your longer-term vision for the portfolio.

Eric Hambly

I think what we learned from Devon's process was that the Eagle Ford is attractive to even more potential buyers than we might have previously thought, and confirms that we have an asset that other people value. We like our asset. We are happy that we have an ability to use the Eagle Ford to ramp it up to generate more free cash flow to help fund our appraisal program and other priorities for our company.

We're very aware that it's valuable, and we're happy to have the flexibility that if, in the future, we chose to sell our Eagle Ford or part of our Eagle Ford, it could be a nice place of funding if we determine that's the best outcome for our shareholders and the most value creating. And so yes, I think it's interesting to see an asset of that scale have so much attention from so many players, and reconfirms that we have a great asset here.

Operator

Your next question comes from the line of Betty Jiang with Barclays.

Wei Jiang

I want to ask about GoA. You guys delivered a pretty strong quarter in 3Q. But I think 4Q guide is not -- there are some changes in the 4Q guide. So can you just maybe speak to the quarter-on-quarter variations, how much of the Chinook start-up you're baking in? And how should we be thinking about the GoA production trajectory into next year?

Eric Hambly

Yes. Thanks, Betty. I'll let Chris address that.

Chris Lorino

Yes. So just looking at our offshore only, we do -- obviously, we're very excited about the Chinook 8 well being online, and it's going to provide about 9,000 barrels of oil per day for the quarter. So really strong well, and excited about that. But that was -- as far as quarter-on-quarter, that was offset a little bit by the weather and the hurricane that happened in the beginning of the quarter, which was around 3,700 BOE.

And then in addition to that, Eric mentioned some of the workovers that are happening. Some of them are getting -- do have production. So while we work on those wells, they'll be shut in as well. And that includes a nonoperated workover at Kodiak as well. So that kind of offsets the impact -- the big impact from the Chinook 8 well, which kind of gives you kind of a flattish or up about 1,200 BOE per day quarter-on-quarter for offshore. In addition to that, we also have some planned maintenance at Delta House that kind of also offsets that.

Wei Jiang

So then I will assume the first half of next year, we'll start seeing the volumes go back to a higher level after the workover?

Chris Lorino

Yes. So we'll be done, but all but one of the workovers, one will go into first quarter. And so we'll be done with them, and that will be early first quarter is what it looks like. So we'll have all that behind us very early in the year, and then we'll ramp back up for our Gulf production.

Wei Jiang

Great. And then my follow-up on LOE. I think the production cost management has been coming consistently lower. Maybe just speak to what's driving that lower LOE cost and how you think about the LOE cost range going forward, especially with the Eagle Ford expected to ramp into next year.

Eric Hambly

Thanks, Betty. Our operating expenses offshore, excluding workover activity, tend to be very steady. Our onshore teams have been very focused, particularly our Eagle Ford team, on continuing to lower operating expenses to be more competitive. I'm proud of the work they've done. They have addressed that across multiple categories. They focused on labor costs. We optimize our labor costs all the time. They focused on equipment rental, water disposal, chemicals. We have a remote operations center that we deployed in 2017 and continue to enhance its capability every year. They are focused on minimizing downtime by maximizing the best wells coming online when we do have upsets and all of that's contributing to Eagle Ford operating costs improving materially.

Within the Eagle Ford from quarter-to-quarter, we have variability in the dollar per barrel OpEx, mostly driven by variability in our production profile with a very nice effort from our team to lower total dollar operating expenses there. That's really the story.

Operator

[Operator Instructions] There are no further questions at this time. Mr. Hambly, I turn the call back over to you.

Eric Hambly

Thank you, operator. As we close today, I just want to thank our employees for their hard work and dedication. They've done a great job. We had excellent execution throughout the quarter across our entire organization, and I'm really proud of what we delivered.

As always, to our shareholders, we appreciate your continued trust and support, and that concludes our call for today. Thanks so much.

Operator

This concludes today's call. You may now disconnect.