Generating $240 million in free cash flow exceeded probably all estimates and is a testament to the SM team, achieving that during a very challenging 2020.
Debt reduction of nearly $500 million was also a significant achievement.
Compared with the original February 2020 plan, we reduced capital by nearly 30%, while delivering production in 2020 within the original guidance range.
Midland Basin flaring was reduced 75% compared with the prior year, which is in part attributable to the construction of interconnections that enable gas production to be redirected in the event an individual third-party processor cannot receive it.
On top of the nearly $500 million overall debt reduction, we reduced near-term maturities through 2024 by more than $600 million and ended the year with nearly $1 billion in liquidity and reduced our leverage, net debt to adjusted EBITDAX from 2.8 to 2.3 times.
Here we graphically present the five-year plan and the financial priorities, which are: first, to maximize free cash flow over this five-year period; second, continue strengthening the balance sheet by applying free cash flow to debt reduction, which targets less than two times leverage by the end of next year 2022 and close to one time leverage by the end of the five-year period; and third, achieve a consistent, sustainable reinvestment rate south of 75% in the years 2022 through 2025.
Specifics of the 2021 plan include delivering positive free cash flow, which we estimate will approach $100 million at current strip, capital expenditures of $650 million to $675 million consistent with preliminary discussion last fall.
Total production of approximately 47 million to 50 million BOE or 129,000 to 137,000 BOE per day, with oil volumes at 52% to 53% of total production.
So regarding the current quarter, we are estimating capital of about $180 million.
Slide 10 includes a little more detail on 2021 capital allocation, which we expect to be 90% DC&E and allocated roughly 70% to the Midland Basin.
The plan includes drilling net 55 wells in Midland and 39 in South Texas and completing net 72 wells in Midland and 21 wells in South Texas.
So comparing that with preliminary guidance, our drill pace is now about 17% faster, which results in more wells drilled as we optimize efficiency under our drilling contracts, also compared with preliminary guidance, fewer completions are largely the result of timing differences.
We go into 2021 with about 75% to 80% of oil hedged and about 85% of gas.
Capital expenditures reflected further capital efficiencies in Midland, where DC&E costs averaged less than $500 a foot for the quarter.
The larger proppant loadings were included in the less than $500 per lateral foot average for the quarter as we realized further cost efficiencies on completions.
The majority of our activity in 2021 is directed at the Midland Basin, where the drilling program has very robust economics with an average 10% IRR breakeven flat price of $16 to $31 per barrel.
Costs are now expected to average $520 per lateral foot, and we expect to drill an average lateral length of around 11,300 feet.
Just in the past month, they drilled and cased the longest lateral in Texas at about 20,900 feet or almost four miles, and did it in 20 days.
That is almost 3,000 feet longer than the previous record also in Howard County.
It shouldn't surprise you then that we have drilled 25 of the 50 longest laterals in the Midland Basin.
And we are now pumping an average of about 10 stages a day per frack spread in the Midland Basin with our primary pumping service provider.
Approximately 30% of our capital is allocated to South Texas in 2021, and it will primarily target the Austin Chalk.
Projected well costs are down to $520 per lateral foot, with an average lateral length of around 12,000 feet.
The plan includes 21 South Texas net completions, of which 18 are Austin Chalk.
They also have a favorable cost structure, about 35% to 40% lower per BOE produced.
As you know, this year, SEC reserves were run at very low commodity prices, sub $40 oil and sub $2 gas.
Because of the robust economics of our wells, the negative proved reserves impact of price revisions totaled only 33 million barrels equivalent, and this was predominantly from Eagle Ford gas wells.
The wells underpinning these reserves that were moved are robust with an estimated average IRR of nearly 70% at $50 per barrel oil and $2.50 per Mcf gas.
You may wonder by how much we scaled back activity, for the planned period 2021 to 2025, we reduced the number of turn-in-lines by 29% compared to last year's plan.
We have over 13 years of total company inventory and nine years in the Midland Basin.
It's important to highlight this inventory has an average IRR of more than 50% when run at a price deck of $50 per barrel and $2.50 per Mcf gas and current costs.
The chart on this slide reflects Enverus data published last week indicating about eight years of inventory at sub $40 and $2.25 gas, underscoring the quality of our inventory base.
We include this to simply make the point about quality, meaning robust inventory even at that very low price deck, $40 and $2.25 gas.

Summary:
Total production of approximately 47 million to 50 million BOE or 129,000 to 137,000 BOE per day, with oil volumes at 52% to 53% of total production.
So regarding the current quarter, we are estimating capital of about $180 million.