Overall, we achieved a total of $233 million of debt reduction or 8% of our total debt since year-end 2020 from these transactions.
Our current strip prices are maintaining the goal of reducing debt by an additional $200 million in 2021 for a total 15% debt reduction this year.
Our oil production beat guidance by 7% this quarter while our Eagle Ford Shale assets, in particular, were 4% above guidance despite experiencing impacts from the winter storm in Texas.
On Slide 4, getting to the details of the quarter, Murphy produced an average of 155,000 barrels equivalent per day with approximately 63% liquids production.
Significantly, our oil production was 88,000 barrels per day, which beat our guidance of 82,000 barrels per day.
As shown in our 2021 quarterly well cadence, accrued capex with first quarter weighted and totaled $230 million net to Murphy.
This amount excludes King's Quay spending but includes our $20 million acquisition of an additional 3.5 working interest in the non-operated Lucius field.
Commodity prices rebounded significantly in the first quarter with oil realizations averaging $58 per barrel, slightly above the WTI benchmark, which we haven't seen since before the pandemic.
Our natural gas realization prices averaged $2.55 per thousand cubic feet.
For the quarter, we recorded a net loss of $287 million or $1.87 net loss per diluted share.
After adjusting for several one-off after tax items, such as a $128 million non-cash impairment charge on Terra Nova and a $121 million non-cash mark-to-market loss on crude oil derivatives, we reported adjusted net income of $10 million or $0.06 adjusted net income per diluted share.
Cash from operations for the quarter totaled $238 million, including the noncontrolling interest.
After accounting for property additions of $258 million and proceeds from asset sales of $268 million, we achieved a positive adjusted cash flow of $248 million for the quarter.
As Roger mentioned, our 2021 capex plan is heavily weighted toward the first quarter with $230 million in total accrued capex or 33% of the annual total.
Approximately 44% of total Eagle Ford Shale capex for the year was spent in the first quarter, while nearly 40% and 35% of the annual planned capex were spent in the Gulf of Mexico and offshore Canada, respectively -- onshore Canada, I'm sorry, respectively.
Overall, we're maintaining our capex plan of $675 million to $725 million for 2021.
However, we are tightening our production guidance range to 157,000 to 165,000 barrels of oil equivalent per day for the full year.
For the second quarter of 2021, we're forecasting a production range of 160,000 to 168,000 barrels of oil equivalent per day.
Importantly, our oil production is forecast at 95,000 barrels of oil per day for the second quarter.
In addition to cash from operations, nearly covering our regular capex, we received funds of $268 million from monetizing the King's Quay floating production system.
We use these funds to pay off the $200 million outstanding on our revolving credit facility as well as $18 million in King's Quay capex that was incurred during the quarter.
We also issued $550 million of new senior notes, raising proceeds of $542 million.
This was used to pay off $576 million of 2022 notes.
Once you take into account the $34 million of early redemption cost related to the payoff of those notes and account for dividends and other amounts, we ended up with an $80 million cash deficit, which was covered from cash on hand.
At the end of the first quarter, we had $231 million of cash and equivalents available and had repaid a net $233 million or 8% of total debt, as Roger mentioned.
At current commodity prices, we have a goal to repurchase an additional $200 million of senior notes later this year for a total debt reduction of approximately 15% for the full-year 2021.
Additionally, 16 non-operated Eagle Ford Shale wells came online at the end of the quarter, ahead of schedule.
Overall, we remain on track to bring online three remaining operated wells and 29 gross non-operated wells in the Eagle Ford Shale and 10 operated Tupper Montney wells in the next two quarters.
Our drilling and completion teams have worked hard to reduce the company's environmental impact by using clean-burning natural gas instead of diesel in drilling and completion activities, not only where emissions reduced, but Murphy saved $1.3 million in cost for the quarter, while bringing online 20 wells across North America onshore.
We utilized approximately 800,000 barrels of recycled water across our completions programs, which Tupper Montney completions consume nearly 75% recycled water, saving $3 million in disposal costs.
On Slide 10, our Eagle Ford Shale production of 30,000 barrels equivalent per day exceeded the midpoint of our guidance for the quarter despite more than 2,000 barrel equivalent per day of impact from February winter storm.
Our first-quarter online wells, IP30 rate averaged 1,400 barrels of oil equivalent per day with the IP of the two best wells, reaching 2,000 barrels equivalents per day.
In 2018, our average well cost has dropped from approximately $6.3 million per well to now $4.5 million per well in first quarter of '21, with stand-alone completion costs down 40% during that period.
Our Tier 2 wells have outperformed our Tier 1 type curve and achieved an average IP rate of 1,400 barrels equivalent per day, and our recent Tier 1 Austin Chalk wells continue to perform in line with the type curve.
Murphy produced 234 million cubic feet per day in the first quarter in Tupper and brought online four wells as planned.
Drilling and completion costs continue to improve for this asset as well with an approximate 28% reduction since 2017.
Average total well costs are now approximately $4.1 million in the first quarter of '21 as compared to $5.5 million in 2019.
The top hole sections have been drilled at all three wells as part of Khaleesi/Mormont, Samurai and the Samurai-3 well is currently drilling as the first well in the drilling campaign.
Our 10% non-operated working interest provides access to 12 blocks with potential for an attractive play-opening trend and is adjacent to a large position currently held by Murphy and our partners.
Today, we're highlighting our view of the resource potential at 500 million to 1 billion barrels.
Murphy, along with the operator, ExxonMobil and partners plan to spud the Cutthroat well in the second half of '21, which is approximately net cost to Murphy of $15 million.
By maintaining average capex spend of $600 million annually, we forecast a production CAGR of approximately 6% through '24, with oil weighting averaging 50% and offshore production averaging 75,000 barrels equivalent per day.
An average WTI price of $60 per barrel enables Murphy to reduce its total debt level to $1.4 billion by 2024 while maintaining a quarterly dividend to shareholders.
Further, we remain focused on executing our exploration program with a portfolio of more than 1 billion barrels of oil equivalent on a net risk resource basis.
After we have our debt levels, we have the option to reduce debt further toward $1 billion.
With current strip prices above $60 per barrel and strong production volumes, we're on target for an additional $200 million of debt repurchases later this year, resulting in a 15% reduction for all of '21.
By maintaining conservative capital spending, we project the total debt to be $1.4 billion by 2024, with potential for further reductions beyond that level.

Summary:
On Slide 4, getting to the details of the quarter, Murphy produced an average of 155,000 barrels equivalent per day with approximately 63% liquids production.
For the quarter, we recorded a net loss of $287 million or $1.87 net loss per diluted share.
After adjusting for several one-off after tax items, such as a $128 million non-cash impairment charge on Terra Nova and a $121 million non-cash mark-to-market loss on crude oil derivatives, we reported adjusted net income of $10 million or $0.06 adjusted net income per diluted share.
Overall, we're maintaining our capex plan of $675 million to $725 million for 2021.
Once you take into account the $34 million of early redemption cost related to the payoff of those notes and account for dividends and other amounts, we ended up with an $80 million cash deficit, which was covered from cash on hand.