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Text: As customary with year-end reporting, we have a lot to cover here today.
As we review the results and plan, I hope you'll see why we believe that we are a premier operator of top-tier assets.
I'll start with Slide 3 and the highlights of 2020.
Our focus on free cash flow involved a companywide effort to reduce costs and increase efficiencies.
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.
Not only did we apply free cash flow funds to debt reduction, but the total reflects the outcome of the exchange offer launched in April, as well as market purchases of our bonds throughout the year, buying them back at a discount.
Turning to Slide 4.
Exceptional results in 2020 were supported by a number of factors.
Capital efficiency tops the list with faster drill times, faster completions, rebidding and deflation across nearly all service lines and generally a focused effort to improve in all areas within our control.
Well performance was particularly strong with Midland Basin wells outperforming early year expectations and Austin Chalk delineation wells exceeding expectations.
Compared with the original February 2020 plan, we reduced capital by nearly 30%, while delivering production in 2020 within the original guidance range.
Year-end inventory and reserves, which I will speak to later, reflect the exceptional quality of our assets and the success of our delineation work in the Austin Chalk.
With respect to ESG, we notably increased our disclosure, publishing both SASB and CDP/TCFD to our website, but more importantly, establish the oversight of a board ESG committee, a management ESG committee and put processes in place to collaborate and engage relevant functional areas to ensure ESG priorities are actionable throughout the organization.
Our safety metrics continue to improve and are outstanding, top quartile among our peers and notably not a single recordable incident in South Texas in 2020, and that includes employees and contractors.
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.
Now turning to Slide 5.
A better balance sheet is another successful outcome of 2020.
We both reduced debt and manage the maturity schedule.
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.
I'm going to start on Slide 7.
So despite the macro challenges, 2020 was an exciting time for the company as our multiyear portfolio transition to top-tier assets turns from high oil growth to free cash flow positive, setting the foundation for sustainable free cash flow going forward.
As we put together our five-year plan, the core objectives were to set activity levels appropriate to optimize free cash flow over the plan period, which should enable us to reduce leverage significantly and move the company into a very sustainable reinvestment rate going forward.
This optimal plan involves a returning activity in 2021 after the severely contracted level in 2020.
In addition to these financial objectives, we believe inventory depth and ESG stewardship are key components of our sustainable long-term plan.
So now moving to Slide 8.
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.
These priorities also deliver free cash flows that exceed all debt maturities due through 2024.
Now on Slide 9.
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.
Again, this is a return to what we view as the optimal activity level for achieving those five-year plan objectives, mainly maximizing free cash flow generation and leverage reduction.
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.
I believe the other line items are self-explanatory and includes slightly higher LOE with increased oil in the production mix and decreased transportation due to the favorable change in terms for South Texas gas that go into effect in the second half of 2021, as well as lower South Texas gas production volumes.
So regarding the current quarter, we are estimating capital of about $180 million.
Therefore, it's premature to provide first-quarter production guidance until we can assist and quantify the extent of the impact over the next few days.
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.
We've increased the allocation to South Texas Austin Chalk given the excellent results we're seeing to date.
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.
A few Midland Basin wells were accelerating in 2020.
We entered into the South Texas JV and modified the timing of several 2021 completions to turn in line in early 2022.
Looking beyond 2021, the chart to the right indicates a flattening in total capital going forward corresponding to a low growth, sustainable reinvestment rate.
Now turning to Slide 11 and hedging.
Our hedge strategy is to protect downside risk and is correlated to our leverage.
We go into 2021 with about 75% to 80% of oil hedged and about 85% of gas.
Looking ahead to 2022, as leverage metrics have improved, assuming no significant macro change, in general, you could anticipate a lower targeted hedge level as we approach next year, especially considering the risk that continued upward price movements could ultimately result in rising costs.
It was a great way to end a very challenging 2020.
The details in the release and slide deck, generally self-explanatory.
We had a nice production beat versus guidance, the higher production, higher oil production was due to better performance from our base production in the Midland Basin.
We simply have not brought our models up to fully reflect improved base well performance there.
At the same time, capital expenditures were well below expectations.
Capital expenditures reflected further capital efficiencies in Midland, where DC&E costs averaged less than $500 a foot for the quarter.
As noted last quarter, while we were seeing improved D&C costs, the fourth-quarter plan included testing significantly larger completions at certain Midland wells.
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.
In addition, we deferred the completions of five Austin Chalk wells in South Texas due to casing problems identified in the vertical sections of certain wells.
We're currently working to better understand and rectify the issues.
Those wells were planned to turn in line in 2021, the plan now assumes those wells will turn in line in 2022.
I'm now on Slide 13.
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.
We've increased our completion intensity this year, and that cost is reflected in this estimate.
Turning to Slide 14, which shows our drilling and completion efficiencies.
This is just such a great slide.
Each year, I think it will be hard to beat our past performance, and yet we do it again and again.
Speaking of that, we have an outstanding drilling team, and they just set a new record.
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.
As you all know well by now, longer lateral lengths translate to improved capital efficiency and returns.
It shouldn't surprise you then that we have drilled 25 of the 50 longest laterals in the Midland Basin.
Not mentioned in the slide, but in 2020, we also implemented dual fuel on some of our rigs partly for cost efficiency gains but also for emissions reduction.
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.
Moving to Slide 15 in South Texas.
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.
From our delineation program over the past couple of years, we believe that our Austin Chalk wells have competitive returns with co-development in the Midland Basin.
In 2021, we have designed a program that is partly delineation and partly development.
The plan includes 21 South Texas net completions, of which 18 are Austin Chalk.
Also in South Texas, we have been testing an electric frack fleet and during the second quarter, plan to increase the number of stage pumped fully electric.
Slide 16 provides an update on the performance of our Austin Chalk wells to date.
Our newer wells target a better landing zone than some of our earlier wells.
We have some older DUCs that landed in the original landing zone that will be completed this year, along with several new wells that are in the new landing zone.
It is worth emphasizing that the economics of Austin Chalk wells are superior compared to legacy Eagle Ford wells.
The Austin Chalk has substantially higher revenue per BOE due to the liquids content.
They also have a favorable cost structure, about 35% to 40% lower per BOE produced.
We have added a slide in the appendix that compares new Austin shot cost per BOE with our historical Eagle Ford averages so that you can see the breakdown there.
Slide 17 puts SM's Austin Chalk well performance into context versus the historical Austin chalk wells some of you may remember.
Just for perspective, we also showed a comparison to the historical average Delaware Basin horizontal well performance.
On Slide 19, let's turn to year-end reserves.
The waterfall here is generally self-explanatory but let me point out a few important takeaways.
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.
Reserve revisions due to the SEC five-year rule are a result of scaling back activity in our five-year plan, corresponding to the lower reinvestment rate that Wade just talked about.
These are absolutely economic wells but are now moved away from the proved category in our development plan.
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.
Scaled back activity over the five-year plan period provides for a longer duration inventory of high-quality wells.
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.
The reserve additions and performance revisions originate from the Midland Basin, the Austin Chalk and Eagle Ford.
Turning now to Slide 20, regarding inventory.
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.
This is very high-quality inventory and is not necessarily comparable to other companies' inventory reports, which may use higher price decks, lower return thresholds, shorter lateral lengths or include all contingent resources.
We do have additional potential inventory on our existing acreage in the contingent resources category from potential additional intervals and/or spacing changes at various price points.
And these are not reflected in the years of inventory I just talked about.
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.
We put forth a few years ago that our objective was to be a premier operator of top-tier assets and I believe others can concur that we have solidly achieved that as we show in Slide 21.
Before closing, I will reiterate the strategic priorities of our five-year plan, which are to: optimize free cash flow; reduce absolute debt and improve leverage metrics; achieve a sustainable reinvestment rate 2022 and beyond; and demonstrate measurable top-tier ESG stewardship.
With that, we look forward to our live Q&A call on Thursday.

user
guidance full year 2021: production: approximately 47-50 mmboe or 129-137 mboe/d at 52-53% oil.
guidance q1 2021: capital expenditures: about $180 million.

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