Further, we were able to increase our cash position this quarter by nearly 190 million, which allows us to accelerate our delevering plans.
After our initial delevering event, we repaid our revolver in full in Quarter 1.
We stated our goal of reducing long-term debt by $200 million by year-end 2021.
We recently announced the redemption of 150 million of 6.875% senior notes due in 2024.
And now today, we're able to increase increased our delevering goal to 300 million assuming a $65 oil price for the remainder of 2021.
Additional cash flow has been accomplished, not only through stronger oil prices, but also ongoing operational excellence as we've achieved less operated downtime offshore while experiencing the benefits of our optimization efforts and upgrades completed over the previous 18 months.
Additionally, we produced 100,000 barrels of oil per day in the second quarter, topping our guide by 5%.
We've now established a goal of zero routine flaring by 2030 and obtained third-party assurance of our 2020 scope one and scope two greenhouse gas emissions.
Statistical highlights include receiving a 47% reduction in scope one and scope two greenhouse gas emissions since 2016 and a 10% decrease in greenhouse gas emissions from 2020 -- from 2019 to 2020, excuse me.
On Slide 5, our second-quarter production volumes of 171,000 barrels of oil equivalent per day were 4% above our guidance midpoint for the quarter.
Accrued capex for the quarter was $198 million, revenue of near 700 million, which is the highest in a year was achieved through strong realized pricing of $65.53 per barrel for oil.
In the second quarter, we reported a net loss of $63 million or $0.41 per diluted share.
After adjusting for certain after-tax items, such as 103 million non-cash mark-to-market loss on crude oil derivatives and a $49 million non-cash mark-to-market loss on contingent consideration, we reported adjusted net income of $91 million or $0.59 per diluted share.
Cash from operations for the quarter totaled $449 million, including the noncontrolling interest.
After accounting for net property additions of $203 million, we achieved positive adjusted cash flow of $246 million.
Our 2021 capex plan is heavily weighted toward the first half of the year with 198 million total accrued capex in the second quarter.
Overall, our ongoing disciplined spending has led us to tighten our capex guidance for the year, now ranging from 685 million to $715 million, with $700 million maintained as the midpoint.
Approximately 63% has already been spent in the Eagle Ford Shale as of June 30th, and 66% has been spent in the Gulf of Mexico, while 76% of onshore Canada capex has been spent by that date.
Since 60% of our 2021 capital plan is complete, and key contracts are in place for the remaining plan, we have minimal near-term supply chain risk to our capital spending.
Our third-quarter production guidance range of 162 to 170,000 a barrels of oil equivalent per day includes 4,100 barrels of oil equivalent per day of assumed Gulf of Mexico storm downtime.
Additionally, we are adjusting our full-year production guidance range to 157.5 thousand barrels of oil equivalent per day to 165.5 thousand barrels of oil equivalent per day, which includes fourth-quarter impacts of 1,300 barrels of oil equivalent per day for assumed Gulf of Mexico storm downtime and 7,900 barrels of oil equivalent per day for net planned offshore downtime.
On Slide 9, in the second quarter, we brought online three operated and 29 gross non-operated wells in the Eagle Ford Shale, 10 wells are brought online in the Tupper Montney, that wraps up our activity in offshore Canada for the year.
Our Eagle Ford Shale wells produced 42,000 barrels equivalent per day in the second quarter in process of 75% oil and 88% liquids.
For the remainder of the year, we plan to drill and complete 4 wells in the fourth quarter, I just mentioned, in our Catarina acreage, all within our planned annual capex of $170 million.
The team continues to execute and generate efficiencies as evidenced of our 25% improvement in our rate of penetration completion cost per lateral foot since 2019.
Overall, we've achieved a 40% reduction in completion costs in four years.
And making operational improvements, our average per well drilling and completion costs has improved to 4.7 million from 6.3 million in 2018.
As a result, we are now achieving well payouts of approximately nine months on our 2021 program at oil prices averaging nearly $62 per barrel in the first half of this year.
On Slide 12, the Tupper Montney, we produced 248 million cubic feet per day in the second quarter.
10 wells are brought online, which completes all well activity for the year.
we've seen a 24% reduction in drilling and completion costs since 2017 while achieving a total well cost of just 4.4 million in 2021, compared to 5.5 million in 2019.
The -- In particular, our completion cost per lateral foot have improved 25% since 2019 through lower nonproductive time, optimized wireline operations, enhanced water handling, and natural gas-powered frac pumps.
Further, our average pumping average per day has increased more than 50% since 2017 from almost 12 hours to 18 hours per day, the ability to lower our cost per well by nearly $1 million will add significant value to our Tupper Montney project and represents the tremendous work of our drilling and completions team in that area.
3 well was drilled in the quarter, and we're now drilling the Khaleesi 3 well.
Our next well is Samurai 4, which is planned for later in the third quarter before we begin completions work on all seven wells that make up the Khaleesi/Mormont, Samurai development.
In Brunei, on Slide 17, in the quarter, we participated in the drilling of discovery well in Block CA1 in Brunei with the Jagus SubThrust-1X well for a total cost of Murphy of just $2.8 million at approximately an 8% working interest.
Post this well, we reclassified our working interest in Block CA-1 of Brunei has not held for sale any longer.
This exploration in the Gulf of Mexico in the second quarter on Page 18, and drilling was commenced at the Chevron-operated sale back prospect in the Gulf, which we anticipate finishing this month.
Our participation provides access to 12 blocks with potential for attractive play opening trend and is adjacent to the large position Murphy holds with our partners.
Murphy along with the operator, ExxonMobil, and partners planned to spud the cut through one well in the fourth quarter of 2021 and approximate net cost of Murphy of just $15 million.
I'm pleased with our excellent production results this quarter and our oil production exceeded by 5% has remained consistent in our ever-improving operations and operated offshore and in the Eagle Ford Jail.
We remain on track with our full-year production at our midpoint of 161.5 thousand barrels equivalent per day with 55% oil weighting.
As such, we affirm the 700 million midpoint of capex for 2021 and have announced today that we're tightening the range around this midpoint.
Our continued execution and capital discipline laid in maintaining our capital spend of 600 million from '21 through 2024 with a production CAGR of approximately 6% through that period.
Of course, we're trending well in our current oil weighting and are above the plan for 2021 at 55%.
Assuming an average long-term WTI price of $60 per barrel, Murphy is able to -- will be able to cut its debt in half to less than 1.4 billion by the end of '24 while maintaining a quarterly dividend payment to shareholders.
We note that this plan accelerates using an average price of $70 per oil in '23, enabling us to reach the debt reduction by just mid-2023.
Beyond delevering, we remain focused on our exploration program and portfolio of over 1 billion barrels of oil equivalent and net risked resource potential.
We decided to accelerate our long-term debt reduction goal for 2021 to 300 million from 200 million, assuming an oil price of $65 for the rest of the year, and look forward to achieving our goal of 1.4 billion in long-term debt reduction by '24 with a long-term average price of $60 per barrel.

Summary:
In the second quarter, we reported a net loss of $63 million or $0.41 per diluted share.
After adjusting for certain after-tax items, such as 103 million non-cash mark-to-market loss on crude oil derivatives and a $49 million non-cash mark-to-market loss on contingent consideration, we reported adjusted net income of $91 million or $0.59 per diluted share.
Our third-quarter production guidance range of 162 to 170,000 a barrels of oil equivalent per day includes 4,100 barrels of oil equivalent per day of assumed Gulf of Mexico storm downtime.
Additionally, we are adjusting our full-year production guidance range to 157.5 thousand barrels of oil equivalent per day to 165.5 thousand barrels of oil equivalent per day, which includes fourth-quarter impacts of 1,300 barrels of oil equivalent per day for assumed Gulf of Mexico storm downtime and 7,900 barrels of oil equivalent per day for net planned offshore downtime.
We remain on track with our full-year production at our midpoint of 161.5 thousand barrels equivalent per day with 55% oil weighting.