Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2021 Earnings Conference Call. If at any time during this call you require assistance, please press star zero for the operator. I would now like to turn the conference over to Ms. Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Good morning, everyone, and thank you for joining us on our fourth quarter earnings call today. Joining us is Roger Jenkins, President and Chief Executive Officer, along with David Looney, Executive Vice President and Chief Financial Officer, and Eric Hambly, Executive Vice President, Operations. Please refer to the informational slides we have placed on the investor relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves, and financial amounts are adjusted to exclude non-controlling interest in Gulf of Mexico. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. As such, 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, see Murphy's 2020 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statement. With that, I will now turn the call over to Roger Jenkins.
Good morning, everyone. Thank you, Kelly. Turning to slide two, we'd like to continue to remind our investors of our story as Murphy continues to deliver a strong value proposition. Our ongoing execution of three producing areas proves we're a long-term sustainable company, and as discussed later, we had our best year ever on protecting our environment. Our competitive advantage of executing in offshore is illustrated by the outstanding progress in our Khaleesi, Mormont, and Samurai fields and the King's Quay project. We've maintained strong cash flow due to capital discipline that covers our planned spending and debt reduction goal, as well as enhancing our supportive shareholders through our multi-decade dividend, of which today we declared a 20% increase. Lastly, our meaningful level of board and management ownership highlights our personal interest in the company's long-term success.
On slide three, we established a focused three-tiered strategy in early 2021, and I'm very pleased at how the team and the company have remained in alignment with these priorities throughout the year. In the fourth quarter, we redeemed $150 million of our 2024 senior notes, which marked the achievement of our long-term debt reduction goal of $300 million in the second half of 2021. Overall, in 2021, we significantly deleverage our company with 17% total debt reduction during the year, a great first step toward our larger goal of $1.4 billion reduction by the end of 2024 at what we are using as very conservative prices. It's important to know that without our strong execution across our company in 2021 and continued controllable cost focus, we'd not have generated sufficient cash flow to achieve our deleveraging goal.
Our focus in the fourth quarter is to maintain timing and schedule of Khaleesi, Mormont, and Samurai in the Gulf of Mexico, as well as transport the King's Quay floating production system to its final location in advance of receiving first oil in the second quarter of this year. Additionally, our operating partner transported the Terra Nova FPSO to Spain to begin dry dock work as part of its asset life extension project. The third priority in our strategy is exploration, timing shift on spudding our non-operated Cutthroat exploration well in Brazil in the fourth quarter into first quarter 2022 due to COVID-19 delays in Brazil. However, we remain excited about the wells we prepare to spud with the rig on location. Also, during the fourth quarter of 2021, Murphy participated in the Gulf of Mexico federal lease sale and was named the apparent high bidder on three deepwater blocks.
On slide four, Murphy made tremendous progress this year as we advanced our 2021 priorities. We achieved the first step in our deleveraging plan by reducing debt $531 million or 17%, in part through redemption of $300 million of 2024 notes. We remain on track for reaching $1.4 billion debt by the end of 2021. 2024 rather, I'm sorry. Our team continued reducing costs throughout the year with record low G&A of $122 million, a 13% decline from 2020, an LOE of $8.65/bbl , which is 5% less than the prior year. Their strong execution efforts were further highlighted by maintaining schedule on our major operating Gulf of Mexico projects as well as maintaining our asset base with 102% total reserve replacement.
I'm also pleased at the success we had on sustainability efforts as we continue achieving excellent safety metrics while accomplishing significant environmental milestones of record low emissions intensity and zero LPG spills in 2021. Lastly, we continue to manage our exploration program in preparation for drilling key wells in 2022. In slide five, on the fourth quarter production, Murphy achieved guidance for the fourth quarter with production of 150,000 bbl equivalents per day, while CapEx of $140 million was $9 million below our guide. Liquids volumes were 6% for the quarter. High realized prices enabled us to achieve nearly $700 million in revenue for the quarter.
As to slide six, for all of 2021, we produced 158,000 bbl equivalent per day with 87,000 bbl of oil per day, which was 6% above our original pre-hurricane guidance due to our outstanding Eagle Ford Shale execution. Total CapEx for the year was $671 million compared to our $680 million midpoint. It's important to note that our CapEx guidance originally did not include the $20 million Lucius working interest acquisition that occurred in the first quarter. When we account for the non-budgeted accretive A&D, we were still able to lower our spending for the year from the original guidance. Overall, we reported $2.6 billion in revenue for the year due to improved commodity prices. Now I'm gonna turn the call over to our CFO, David Looney, to give a further financial update.
Thank you, Roger, and good morning, everyone. Slide seven, proved reserves. We achieved 102% reserve replacement in 2021, with 699 million bbl of oil equivalent in total proved reserves, compared to 697 million BOE at year-end 2020. At year-end 2021, our proved reserves were 58% proved developed and 45% liquids weighted. Geographically, 25% of reserves were located in U.S. onshore, 26% offshore, primarily in the Gulf of Mexico, and 49% in our onshore Canadian assets. We also maintained a healthy reserve life index of more than 12 years.
Overall, we're pleased to have held proved reserves flat the past two years while maintaining an average of only $400 million of capital spending dedicated to generating immediate production, with the remainder of our CapEx in 2020 and 2021 being allocated to long-term projects and exploration, neither of which provided production or reserve benefits in those two years. Slide eight, financial results. For the fourth quarter, we reported net income of $168 million, or $1.08 net income per diluted share. Certain after-tax adjustments included a $24 million non-cash impairment of non-core assets, $92 million mark-to-market non-cash gain on derivatives, and $33 million mark-to-market non-cash gain on contingent consideration. As a result, we reported adjusted net income of $62 million or $0.40 adjusted net income per diluted share for the quarter.
Cash from operations for the quarter totaled $331 million, including the non-controlling interest. After accounting for net property additions and dry hole cost of $106 million, we achieved positive adjusted cash flow of $225 million in the quarter. For the full year 2021, we reported a net loss of $74 million or $0.48 net loss per diluted share. I would remind everyone that in the first quarter, we took a $170 million pre-tax impairment on Terra Nova, as it looked like we were going to abandon the field at that time. Subsequent to that decision, the ownership group worked out a deal with the government, and we are now looking to bring that asset back online next year.
Without that charge, we would have easily achieved a positive net income for the year. After adjusting for this, as well as other non-cash charges on the year, we reported adjusted net income of $200 million or $1.29 adjusted net income per diluted share. Cash from operations totaled over $1.4 billion for the year, and we achieved adjusted cash flow of $734 million, including the NCI. Slide 9, a s we've often stated, our company is focused on deleveraging. With strong operational and financial execution, we achieved the first steps in 2021.
As of December 31, we were able to reduce our total debt by $530 million or 17% from the prior year-end, while also building cash and equivalents on the balance sheet up to $521 million, thereby achieving total net debt of $1.9 billion. We plan to continue deleveraging in 2022 and beyond as we generate significant free cash flow. With our previously established target of $1.4 billion in debt by year-end 2024, likely achieved at least 12 months earlier at today's strip prices. With that, I'll turn it back over to Roger.
Thank you, David. On slide ten, Murphy's been increasingly focused on operating sustainably while still producing and exploring for oil and natural gas. I'm pleased that in 2021, we were in line with top quartile of our peers as we achieved the lowest carbon emissions intensity in corporate history. We're on track to achieve easily our 15%-20% emission intensity reduction goal by 2030 from 2019. We continue to protect our communities by having 0 LPG spills during the year, which is a massive feat. We had one of our top years in protecting our employees as we maintain low recordable incident rates along with COVID-19 protocols to keep our people safe and operations ongoing. We're excited that our efforts are being recognized as Newsweek named our company one of America's Most Responsible Companies for 2022.
Additionally, our ESG ratings have improved across key raters ISS, Sustainalytics, and MSCI, with our governance score from ISS remaining at a top level since 2018. Now I'm gonna turn the call over to our Executive Vice President of Operations, Eric Hambly, to provide an operational update. Thank you.
Thanks, Roger. Slide 12, i n the fourth quarter, we brought four wells online in the Eagle Ford Shale and produced 33,000 bbl equivalent per day with 69% oil and 85% liquids. For the full year, we produced slightly higher at 36,000 bbl of oil equivalent per day with 87% liquids and brought online 23 operated and 45 gross non-operated wells. The team has done a tremendous job on managing our production with excellent engineering work, resulting in much lower downtime during the year, as well as achieving a base decline rate of only 1.5% in the fourth quarter. Overall, our pre-2021 wells declined only 21% for full year 2021.
We had another successful year in our drilling completions program, achieving an average well cost of $4.7 million compared to $6.3 million in 2018. Overall, our completions costs are down 40% from 2018. Our team has done an excellent job in enhancing efficiencies as well, and have improved our days spud to rig release by 19% while increasing the lateral length by 35% since 2020. I'm pleased with these accomplishments as they set the foundation for a strong 2022 program. Slide 13, a s mentioned previously, we brought four Eagle Ford Shale wells online in our Catarina acreage during the fourth quarter with average 84% oil weighting.
The two upper Eagle Ford Shale wells and one Austin Chalk well all performed in line with our existing type curves, while the lower Eagle Ford Shale well was significantly above our type curve. In particular, the Austin Chalk well has achieved a preliminary IP rate of 900 bbl of oil equivalent per day when normalized to a 10,000 foot lateral length, along with 76% oil weighting. Overall, the results of these four wells continue to de-risk our Catarina acreage, in particular our 100 Austin Chalk locations, as well as align with production results noted by adjacent operators. Slide 14, i n the fourth quarter, Murphy produced 263 MMcf/ day in Tupper Montney, with 259 MMcf/ day produced for the year.
In our 2021 wells, which came online mid-year, achieved record high IP 30 rates for the company and in comparison to the industry through modifications in flow back facilities and wellhead equipment and procedures. Overall, our IP rates are more than 50% higher than the previous three years and a 19% CAGR since 2013. When combined with our base production optimization, I'm pleased at the improvements we've seen in production volumes from lower decline rates the past few years. Slide 16, o ur Gulf of Mexico wells produced 61,000 bbl of oil equivalent per day in the fourth quarter and 66,000 bbl of oil equivalent per day for full year 2021, averaging 79% oil at 85% liquids for the year.
Notably, our full-year production was only 700 bbl of oil equivalent per day below our original 2021 forecast due to above-plan well performance, which offset the significant impact from Hurricane Ida in 2021 of 4,100 bbl of oil equivalent per day. Minimal production from one facility remains offline through first quarter of 2022 as third-party downstream repairs are completed. Our major projects continue moving forward as we began completions on the seven-well Khaleesi/Mormont/Samurai project during the fourth quarter, with the first well finishing within the next few days. The King's Quay floating production system was transported to its final location in the Gulf of Mexico. Mooring installation was completed this month, while infield pipeline installation work progressed, and we remain on track for first oil in the second quarter of 2022. The non-operated St.
Malo water flood project is also ongoing, with installation of the multi-phase pump to occur in the first quarter 2022, followed by water injection next year. Slide 17. As announced previously, the partner group came to an agreement on the Terra Nova asset life extension project. The project has progressed on time, and the FPSO is now in Spain for dry dock work before an anticipated online date in late fourth quarter 2022. With that, I will now turn the call back over to Roger.
Thank you, Eric. On slide 19, our operating partner originally planned to spud the Cutthroat exploration well in Brazil in the fourth quarter of 2021. However, due to COVID-19 delays, the rig arrived on location. We anticipate this well to spud in the first quarter for a total cost of $28 million. On slide 21, involving critical capital allocation. Before going through capital spending details, a key of our capital allocation includes a 20% increase in our dividend, detailed in a separate press release this morning. We're pleased to provide a higher cash return to our shareholders while continuing to delever our balance sheet. For 2022, we forecast a CapEx range of $840 million-$890 million.
While higher than the past years, we note that 2022 is the peak year of spending through 2025, as we prioritize $265 million to complete the operated Khaleesi, Mormont, and Samurai project in the Gulf, with first oil flowing in the second quarter of the year and advance the non-operated St. Malo water flood project. Our spending is again weighted to beginning of the year, with 60% of the capital plan forecast through the second quarter. Overall, our capital plan and dividend increase for 2022 is funded by approximately 65% of our operated cash flow at $65 oil prices. As to production on slide 22, we anticipate first quarter of 2022 production volumes of 136-142 thousand bbl equivalents per day, with approximately 53% oil and 60% liquids.
This production range is reduced by planned downtime of 2,700 bbl equivalent per day on our operated facilities, 2,600 bbl equivalent per day on non-operated offshore. Some 3,000 bbl equivalent per day for onshore downtime. Almost 70% of this total downtime for the quarter is to support planned maintenance activities. This will be our lowest quarter of production for the full year. Full year 2022 production is forecast at 164,000-172,000 bBL equivalent per day, comprised of 52% oil and 57% liquids. Of note, the oil production for this year is practically the same as 2021 as production total efforts are higher. With our offshore projects on track and significant onshore spending coming online in middle 2022, we see production increasing each quarter this year with our exit rate far ahead of 2021.
Our 2022 oil rate is planned to be the highest in over three years in the fourth quarter. With our plan on Khaleesi, Mormont and Samurai project to achieve first oil in second quarter of this year, with seven wells brought online sequentially over the year. Our onshore drilling and completion program will result in majority of the wells coming online in the second and third quarters of this year. As to our North American onshore capital on page 23, we plan to spend a total of $360 million across our onshore assets this year with total production forecast at approximately 95,000 bbl equivalent per day, with 30% oil and 34% liquids weighting. This volume reflects an 8% increase from 2021.
We forecast $2,220 million of CapEx in the Eagle Ford Shale to bring online 27 operated wells in Karnes and Catarina and 32 gross non-operated wells in our Karnes and Tilden area during the year. We note that while this level of spending is $50 million higher than 2021, we've started 2022 with only six drilled and uncompleted wells in comparison to a high DUC count in 2021. Our onshore Canada program includes $120 million of CapEx to bring online 20 wells in Upper Montney, as well as $19 million in the Kaybob Duvernay to bring online three wells and support field development. Overall, our onshore well cadence is heavily weighted to second quarter 2022, with additional wells brought online in the third quarter. As to offshore capital plans on page 24.
As previously stated, capital spending is heavily weighted toward our Gulf of Mexico major projects. Completions on the seven-well Khaleesi, Mormont, Samurai project began in the fourth quarter and are expected to take 40-45 days per well, with the first well finalizing in the next few days. We plan for an additional $65 million of CapEx allocated to the Gulf of Mexico to support development and tieback projects, specifically drilling an operated development well at Dalmatian to come online in 2023 and executing two non-operated subsea tiebacks at the Lucius field. Approximately $55 million is allocated to the non-op Terra Nova FPSO asset life extension, which is anticipated to return to operations at year-end 2022. While we've also allocated $15 million to non-operated Hibernia to support drilling campaign there with first oil in the fourth quarter of this year.
Offshore production is forecasted at approximately 73,000 barrels of oil equivalent per day in 2022, a 6% increase from 2021 with 80% oil weighting. On slide 25, our 2022 program plans spending of $75 million, targeting approximately 200 million barrel of oil equivalent in net unrisked resources. As I mentioned previously, the Cutthroat well in Brazil is expected to spud in the near term at Sergipe zone location. The operator is working on final preparation and obtaining permits. In the Salina Basin of offshore Mexico, we're targeting drilling Tulum. This well being located in a proven oil basin near multiple discoveries. We're progressing approvals ahead of drilling in the third quarter.
We also intend to participate in drilling another non-operated well in Brunei in 2022, and partners are currently finalizing well objective plans and evaluating prospectivity ahead of the final location selection. As we turn to our long-term value and discipline strategy slide on page 27, our discipline throughout 2021 has enabled us to maintain a long-term strategy through 2024 with minimal change from previous disclosures. We continue to target a debt level of $1.4 billion by the end of 2024, which is likely achieved 12 months earlier in today's strip prices. We forecast reinvesting approximately 40% of operating cash flow to deliver average production of 188,000 equivalents per day at a CAGR of 7%, with an average of 52% oil weighting through 2024.
Additionally, our offshore production is maintained during this period of 80,000 bbl of oil equivalent per day. Exploration program remains another focal point, with portfolios of approximately 1 billion barrels of oil equivalent on our net risk basis. Overall, the plan is achieved by remaining disciplined in our spending, averaging $650 million annually in this period, which will provide excess cash flow targeted toward enhancing our payouts to shareholders, increasing the dividend, and accomplishing our debt reduction goals. As we look longer term in 2025 to 2028, we forecast that our current portfolio produces average annual volumes of 195,000 bbl of oil per day with approximately 50% oil weighting as we target a corporate investment-grade rating.
This production level is achieved by reinvesting a maximum of 60% of operating cash flow, assuming a long-term price of just $55 oil. During this period, we forecast generating ample free cash flow, which funds further debt reductions, continuing cash returns to shareholders and accretive investments. Slide 28, o ur three-pillar strategy remains as we begin 2022. As we advance our deleveraging goal, we've established a debt reduction target of $300 million for the year, assuming $65 oil, which will get us one step closer to our conservative $1.4 billion debt target by the end of 2024. Notably, this plan may be accelerated or increased longer term at higher oil prices.
The team remains focused on quality execution this year, targeting first oil in the second quarter on our operated project in the Gulf of Mexico, as we look forward to continued cost efficiencies and achieving our drilling and completion programs onshore, along with further emissions intensity reductions. Overall, the health and safety of our employees and contractors is paramount. We intend to continue executing our operations in a manner that protects our people and the environment. Lastly, we continue to target exploration program and look forward to our planned wells this year. In closing, I'd like to thank our dedicated employees for their tremendous effort in remaining focused on our strategy throughout 2021. Their hard work has positioned us well for an exciting year ahead across all of our business units as we continue to progress our priorities and achieve our long-term goals.
With that, I'll turn the call back over to our operator this morning for questions. Thank you.
Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press star followed by one on your touchtone phone. You will hear a three-tone prompt acknowledging your request, and your questions will be pulled in the order they are received. Should you wish to decline from the polling process, press star followed by two. If you're using a speakerphone, please lift your handset before pressing any keys. One moment for your first question. Your first question comes from Arun Jayaram with JPMorgan. Please go ahead.
Yeah, good morning. Roger, I was wondering if you could provide-
Good morning, Arun.
Yeah, good morning, sir. I was wondering if you could provide some more details on your updated three-year outlook, which you put out on slide 27. Looks to be a bit more capital efficient than the street. $650 million of CapEx, 188,000 BOEs of output and about 98,000 bbl of oil. Can you give us a sense of what's gonna drive the growth over the next couple of years? You know, given that 40% reinvestment rate, how are you thinking about allocating the excess free cash flow between the dividend as well as some potential A&D opportunities, including the Petrobras assets which could come on the block near term?
Thank you, Arun, for that question. We are quite proud of our plan, and it's a great question, and thank you for highlighting that. What we have here is a long-term situation Gulf of Mexico capital that's coming to fruition, with our projects this year flowing as planned in the second quarter. It's a great feat for us to achieve this first oil right on target, right on sanction through COVID, as you know. St. Malo water flood's a significant project for us, where Chevron's done an outstanding job. We're really happy with the subsurface there. That should flow with the subsea pumps on this year, increasing production slightly, as well as, you know, keeping this big asset flat longer, starting in 2023.
Real solid onshore business where we try to keep our Eagle Ford Shale flat. Capital will get stabilized here at that level, just over 30,000 bbl a day, making enormous free cash flow for us there, especially at these prices. Many of these things are the same as we had a few months ago, Arun, actually, as to capital efficiency. We're working very hard to honor and to keep our plan. We have onshore fields coming on, which increased our oil weighting, increasing our oil exit weight to higher probably than four years. We have ever-increasing quarterly production this year, which is not common for us with front-end loaded onshore production, which is different. Those things are helping us out a good bit there, and I appreciate you noticing that.
Of course, with these type of prices today, as probably predicted by your firm and other major firms, we will have a massive amount of free cash flow here. Again, we started off with a debt goal of halving our debt. We see that can be done a year earlier now, surely at these prices. Even 65/65, we'll have enormous debt reduction. What we're trying to do as we've noticed today is increase our dividend along the way while we de-lever. That's news today. That's new information. It was thought that we were gonna wait till we halve our debt to do that, but we went ahead, and we see our efficiency and everything working to raise our dividend or target to raise our dividend as we de-lever now.
Our first goal is to get our dividend back to pre-COVID levels, matching that with our de-levering goal, and then go on from there with continued dividends because we're a dividend player. We've been paying a dividend for 60 years, and that's what we wanna do. We can probably as well further reduce our debt even lower or possibly the need to not go to the bond market again for a very long time. That's our goals, Arun. That was a long question and a long answer, and if I didn't get something, please remind me.
Okay. Yes, sorry for the long question.
No, no. That's my long answer. No problem.
My follow-up is I did wanna ask you about some of the regulatory concerns in the Montney kind of expressed by the buy side and one of your peers in BC. Can you just give us an update on your read of the situation in BC and how you're positioned from a permit position as we think about you executing your Tupper Montney program this year?
Thank you, Arun, for that question, and appreciate you bringing it up. You know, we've been in Canada for over 60 years. We're very familiar with regulatory, also regulatory situations all over the world in our corporate history. I think what's a little bit different about what we're doing is Murphy's, we're able to execute our Tupper Montney plan as expected. We believe we can. Over the past few months, we've been in close contact with senior officials in BC and the BC Oil and Gas Commission regarding our Tupper Montney expansion plans, and we're closely monitoring these developments, as you would anticipate. It's really down to the type of things we're doing with the location of our wells, where they're located, and what we're doing in our development plan.
Within that, we believe that we'll be able to execute our 2022 program in the Montney based on discussions and what we're doing. It's also important to note that for our plan this year, we hold 85% of our well permits in our hands. Also, if delays persist, we could execute our program at a slower pace, but be within our production guidance to do that. As you know, as we focus on de-lever, execute, and explore in our company, it's really all about free cash flow, and we would see the free cash flow from these possible permit delays to be de minimis on any of our free cash flow goals going forward in our debt reduction targets. That's where we are on that matter today, Arun.
Thanks for the update, Roger. Take care.
Take care. Appreciate it.
Your next question comes from Charles Meade with Johnson Rice. Please go ahead.
Morning, Charles.
Morning, Roger. Good morning, Roger, David, and the rest of the team there. Roger, I'd like to, I guess, revisit my question to you from last quarter on King's Quay. I think Eric mentioned that you guys are wrapping up completion of the first well today. Can you give us a sense of what's happening today, not just on well operations, but with any subsea construction? Is there a key date or event that we should be looking for?
I appreciate that question, Charles, about our key project in the Gulf. What I'd like to highlight today is that, you know, we're in the middle of it. You gotta have everything to flow the field. The first step is to safely moor the facility on location. There's 12 large mooring lines involved with this operation. Those are installed and facilities secured in great shape. Today, we'll be picking up risers that are located on the sleeve floor and attaching them to the facility, and we're completing wells with our drill ship. And we have seven of them to go, and we'll be bringing those on sequentially when we have the risers installed and commissioned and our export pipelines installed, which are nearby to long-term pipelines that are located in the Gulf.
We have our export pipelines to do, our risers, and complete our wells, and then flow the wells that we have. The more wells we have online when the facility's ready, the higher the production will be, and we're in the middle of doing that today. We're very happy with how we're going, and we finished our first well here in just a few days. It's practically finished now, with six wells to go.
Thank you for that detail, Roger. If I could ask a question about the Eagle Ford well that you guys brought on this quarter that was so strong. Did you guys do something different with that well, or is this alternatively maybe just a case, you know, sometimes you reach in and you pull the long straw?
Oh, it's more than that, and I'll let Eric elaborate on that for you, Charles. Thank you.
Yeah.
Thanks. That's a great question. Obviously, our Eagle Ford program is critical to our execution focus, and the team has been working to improve and enhance our completion through a number of things. We have been optimizing our landing zones and improving how we're drilling our wells to be more consistently in exactly the target we want, optimizing exactly where we're landing within the Lower Eagle Ford. We've been optimizing our completion designs to get the most cost-effective, most free cash flow-generating completions. With that, we've seen some strong results. Earlier in the year, in 2021, we reported the results from three cone wells in Catarina acreage, which had more than 50% exceeded type curve. They were nice long lateral wells. The well in the fourth quarter was over 50% above our type curve.
Again, just getting solid performance with a lot of work to optimize landing zone completion design, and we're really pleased with the results, and how that's contributing to our ability to generate free cash flow from the asset.
Got it. Thanks for that detail, Eric.
Thanks, Charles. Talk to you soon.
Your next question comes from Neal Dingmann with Truist Securities. Please go ahead.
Morning, Neal.
Morning. Thanks for the details so far, Roger. My first question I think is maybe drilling a little bit more on shareholder return and really around this. You all have done a great job, obviously, of reducing debt to now what I'd call quite a low level. Really, my question on this is, could y'all discuss
Really your plans is, you know, how you plan to distribute what we show to be massive free cash flow, specifically the second part of this year. You know, I guess where I'm going with this, Roger, is at this point, maybe why pay down any more debt? Secondary, you all said to be a dividend player. I'm just wondering if you considered buybacks as well. I guess my question is around debt and buybacks.
Thank you for that question, Neal. Yes. You know, depend on how you model it. With the oil price you're using, it is significant free cash flow, especially at strip prices today, probably around $87 in the prompt month, I think this morning. So of course, doing that, we work with our board to increase our dividend in December. We are planning a $65 price here, where we like to work. We just announced today our increase of our dividend. That will be an ongoing thing going forward with any company that's having well above planned oil prices as to dividend, there, Neal, 'cause we are a historic dividend player. But we do want to continue to de-lever for sure, high debt at least.
It's the way it shakes out in a planning model, which is targeting, and we do not have our board's consent as to. You don't wanna get ahead of the board on dividends and things of that matter, as you know, Neal. But we can really get below 60 pretty easily and have really nice dividends. As to other cash returns to shareholders as part of your question, naturally, buybacks do come into play if this type of oil price comes for a long time.
First we got to get back to our dividend, where it was, and gotta get dividend to where it was before 2016, and then get to those levels and be able to be sure that a buyback program can be consistent, and last longer and be a part of the typical capital allocation. Gotta get these wells on, gotta get our program further executed, gotta continue to see these prices and continue to model toward that effort, Neil.
Got it. My second question really, Roger, for you. You guys continue to do a great job on having sort of diverse both what I'd say, you know, onshore Eagle Ford Canadian onshore production as well as, you know, a lot of this offshore coming on. My question is really twofold here. One, do you all anticipate that Eagle Ford continue to be sort of that steady growth or, you know, do you or Eric see that starting to maybe decline a little bit? You know, would you? I guess my question more specifically, would you intentionally have it decline as you start to bring more of these offshore wells online?
You know, you've got some good slides out just showing how meaningful, you know, around King's Quay and a lot of those start coming on, how that production is really gonna start ramping. My question, I guess, is as that offshore and potentially other offshore production ramps, would you still continue to keep this Eagle Ford production flat?
Thank you for that, Neal. Follow-up on the Eagle Ford, a great asset for one. You know, we bought it ourselves probably 12 years ago now. The idea at Murphy is to keep this production level in the low 30s and make sure we have a consistent level of capital and keep it there, really no matter what. We're trying to improve our Montney production into a level that will happen at the end of this year, keep that flat for a while, keep our Eagle Ford flat for a long while, making very nice free cash flow, and let our offshore operate as it's been operating well and have exploration success, prop that up in future years and keeping Eagle Ford flat is our game plan. That's what's really in that long-term slot on page 27 today, Neal.
Yeah. Love the diverse plan. Thank you, Roger.
No, thank you. Appreciate it.
Your next question comes from Paul Cheng with Scotiabank. Please go ahead.
Good morning, Paul.
Good morning. I think the first one is really just I want to make sure I didn't read it wrong. A little bit confusing. The press release, you say the first quarter production guidance is 133-139, and in the presentation it's 136-142. Is it just the press release a typo or there's any differences? Why the differences here?
It's 136- 142, and we apologize if there's an error on that, Paul.
Okay. We should ignore in the press release that number. All right.
The press release must have had a bad version. I apologize.
No, no problem. My understanding. [crosstalk]
Hang on, Paul. What was that, David? Hang on, Paul, a second.
136-142 in the press release.
The press release is 136-142, Paul, but that's what we're gonna make.
Okay. That's fine. That somehow I looked at that, the one that I looked at is 133- 139. Anyway,
Apologies for that.
Maybe that was the next one is for David. In the cash tax in the U.S., how that is going to progress over the next two or three years? I assume that this year you guys not going to pay cash tax, but starting in 2023, we assume majority of them is going to be cash tax. Also, that in terms of the hedging strategy, what's your philosophy with that? I mean, with your balance sheet, you're in a much better shape, your production is going up, your breakeven coming down. Say, outside this year, is there any reason why we maintain such a heavy or large hedging program at all?
I'll take that, David. Thank you for that question, Paul. If you look back on hedging in our company, it was around buying significant assets in the Gulf. It's around protecting covenants in our unsecured revolver when times are much more difficult a couple years ago. We have some hedging positions in that effort today. We did take some costless collars this year to protect a high range of production, 70-80, noted in our release today. In general today with where we're going and how we're executing and our cost structure, we're not looking for additional hedges at this time.
Should we assume that?
Let me answer the tax question with David here, Paul.
Okay.
Yeah, Paul, great question. Great question on the taxes. Obviously, with prices increasing as they have, I think all of us in this sector are gonna be looking at some higher pre-tax income numbers. I will tell you though that, you know, largely based on the fact that we, you know, we do have a pretty large NOL carry forward in our modeling. We're not showing paying any cash taxes in the U.S. probably for about four or five years at this point. That's sort of the up-to-date number based on current level of prices.
Okay, thank you. A final one for me. Roger, previously, I think in your presentation, you sort of always show the four-year from 2021- 2024 CapEx, say, roughly around in the $600 million kind of range.
Yeah.
In this presentation you then show, should we assume that outlook is still remaining intact or that has been changed also?
In the presentation, Paul, for the next few years, our CapEx average for that period is now $650. It's up a little bit from the prior, but it's written on page 27 there, Paul, this morning.
Okay. Will do. Thank you.
No problem. Appreciate you, Paul. Thank you.
Ladies and gentlemen, as a reminder, if you do have any questions, please press star one. Your next question comes from Neil Mehta with Goldman Sachs. Please go ahead.
Good morning, Roger and team.
Morning, Neil. Thank you for calling.
Thank you. The first question was just on the drilling program at Cutthroat. It looks like the rig is on location and you guys are preparing to spud. Just any thoughts from your perspective on that asset, and confidence intervals that you have around success?
Thanks for that question, Neil. Of course, that's an important well in our program. We have many wells in our program, including a nice well in Mexico this year and really late in the year, early 2023, a very nice well. A couple of nice wells to drill in the Gulf. It's a little better than a one in three type of a thing, the way we do our internal planning here at Murphy as a success. That's how that is, Neil. You know, it's a very large well, very high in size and has all the attributes of a very nice exploration opportunity, and we're looking forward to our operating partner getting going down there.
Thanks, Roger. Another big picture question. You've been in the industry for a long time. You've seen the birth of shale, and we're getting to another phase of it, which is it looks like closer to shale maturity. Just your thoughts on what inning are we in as it relates to productivity in shale, and how does cost inflation that we're gonna see across some of these basins affect your outlook for the ability of the sector to grow in the U.S.?
Thank you, Neil. Of course, we have been in shale for a long time. We have been, like I said earlier this morning, probably about 10 or 12 years in the Eagle Ford. You know, I think it's not so much what the shale will deliver, it's more of a disciplined, flatter shale making more free cash flow, which fits well with Murphy, very well actually, and we appreciate that. But as I look at shale in this new flat world, and I look at when we cut our CapEx back, our team was able to do incredible production engineering efforts, which allowed us to really improve our base production.
Did a lot of work on downtime involving compressors and some facility engineering that we did and had our best base production ever and our lowest decline ever in the Eagle Ford due to our base and our outstanding engineering work. I see that getting better. I see big data. I see remote operating centers. I see continuing cost reductions and efficiencies all the time that we feel that Murphy can overcome the inflation because we're continuing to see improvements. We're targeting $5 million well drilling complete costs throughout North America no matter what. We're able to do that, and we think we can make a lot of money doing that. I also see a lot of technology into re-fracking. I see a lot of technology into gas injection later in the development cycle.
I see a lot of engineering and technology keeping these fields flatter longer and delivering a lot of free cash flow. Eric and his team's done a great job of doing that, and that's kind of where we're positioned today on that need.
Thanks, Roger.
Your next question comes from Leo Mariani with KeyBanc. Please go ahead.
Morning, Leo.
Morning. I wanted to ask a little bit more about the Gulf of Mexico. You've got these seven wells you're gonna be bringing on, you know, sounds like in succession starting in 2Q. Do you guys have an estimate of what the total, say, net benefit is of those seven wells to Murphy in terms of like, you know, BOE per day and roughly how much of that is oil?
It's really kind of averages out to about high 3,000s- 4,000 net a well for us, because we have a different working interest at Samurai. We feel that's what we're looking at there, Leo. It's very high oil, I'd say. How old is it, Eric? High 80s. 82% oil.
Yeah.
This is an oil field for sure, and looking forward to bringing it on.
Okay, great. Just a question about Tupper Montney. What are you guys forecasting for the production out of that asset, in 2022, at this point in time?
Go ahead, Eric, with that.
Okay. For the full year, we're looking at Tupper Montney production to, let me make sure I get you the right number here, to be 55.7 thousand daily per day.
Okay. I guess just, you know, looking at a presentation you guys had earlier in the year, I think you guys had production, which was a fair bit higher than that. Just wanted to get, you know, if my numbers are right, you know, by roughly, I don't know, 15%, earlier in 2021 in terms of presentations. I just wanted to get a sense of what's going on there. Maybe there have been some delays in bringing the wells online. Can you talk a little about the shape of the production build in 2022? You know, I'm guessing it's probably pretty back half weighted with a big ramp in the second half.
I'll let Eric go ahead with that. We don't have that presentation handy that you focused on this morning, Leo. I'm sorry. We feel we're executing pretty well there, and we've had the highest IPs we've ever had and the highest IPs in public data in that area. Go ahead, Eric, with further color on that.
For 2022, we have a program to bring online 20 new wells, which will offset our base decline and add significant volumes through the year. Our new wells will contribute in the 18,000-19,000 BOE for the annual average, so the exit rate will be quite strong. Production growth will happen in the second quarter and the third quarter as the wells come online about half in the second quarter, half in the third quarter. We're pretty excited about the asset and how it's performing. The rates we've been achieving are really strong, and our base decline has been shallow. We're pretty confident that we have a nice program here in 2022.
Got it. Okay. Lastly, just on CapEx. You obviously have this kind of three-year outlook you provide from 2022 through 2024. I guess, you know, clearly 2022 is the high number, let's just call it, you know, around $870 million or whatever. Looking at 2023 and 2024 to get to the $650 million, looks like you gotta be kind of in the high fives, around $600 million maybe in CapEx in 2023 and 2024. Does that sound about right? We should see around $600 million, you know, next year. Is there any material difference in 2023 and 2024 CapEx, or is it about the same, as y'all look at it?
Thank you, Leo, for that question on our tight budgeting here, which we're quite proud of. Next year, what you said in low $600s is accurate to our plan. 2024 should be a bit lower, as we're able to execute this full year of King's Quay and St. Malo coming on. It's gonna kinda drop $800, $600s, high $400s, and move on from there.
Okay. Thanks, guys.
Thank you. Appreciate it.
There are no further questions from our phone lines. I'd now like to turn the call back over to Mr. Roger Jenkins for any closing remarks.
Appreciate everyone calling in on our call today. If you need any further information, please contact Kelly or Megan in our IR team, and we look forward to speaking to you at the end of our next quarter. Thank you and appreciate it. Goodbye.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Have a great day.