We are seeing deflation essentially across the board on larger items, with the exception of labor. As a result, well costs per foot to drill, complete and equip are expected to range in the low $800 with Midland and South Texas well costs being very similar. I will point out that our well costs per foot include our notably higher than average sand and fluid loadings, which we employ to optimize well performance and returns. We also report costs based on DC&E. This can be apples to oranges in comparing to D&C only. Together, these factors add approximately $130 per foot, which if normalized to peer metrics, would compare with a $700 per foot peer well. Assuming flat prices of $75 WTI, $2.75 Henry Hub and $27 for NGLs, the 2024 drilling program is expected to deliver an average return, including drill, complete equip and facilities, of around 55%-60%.
Total capital costs include facilities and infrastructure costs related to continued expansion of the South Texas oil and water handling facilities. They also include facilities upgrades and expansion in the Klondike area, such as improved emissions controls, saltwater disposal upgrades and a pipeline intended to reduce the operational footprint around the local community, which also reduces costs and emissions. Turning now to guidance on slide 11. Production guidance of 56-59 MMBoe for the year is an output of the capital program. This is an increase of 3-4% year-over-year on a Boe basis, while oil volumes are expected to increase around 6%. Production volumes are expected to average 44% oil and be split roughly 50:50 from the Midland Basin and South Texas on a Boe basis.
Production cadence is expected to increase each quarter through the year, based on the timing of completions. First quarter guidance is approximately 13 MMBoe, or 143 MBoe/d, which takes into account only 11 net wells turned-inline in the fourth quarter 2023, as well as the effect of adverse January weather. We are guiding LOE at $5.30 to $5.60 per Boe, which considers the need for temporary electric generators in the Midland Basin, due to increasing demand on the electrical infrastructure, as well as increased water handling costs. In regards to cash taxes, during last quarter’s call we talked about the significant R&D credits that we have earned. The carry forward of these credits are expected to reduce cash taxes for 2024 to around $10 million, which will likely carry through to 2025.
There is significant cash flow benefit here. Turning to the balance sheet, slide 12. I am very pleased to report we have achieved net debt of less than $1 billion and net debt-to adjusted EBITDAX of 0.57x. Low leverage affords flexibility in the allocation of free cash flow in 2024 and positions SM for continued growth in return of capital to stockholders. We ended the year with more than $600 million in cash, which gives us the flexibility to call the 2025 this year, if we choose. Skipping to yearend reserves on slide 14. Net proved reserves of 605 MMBoe are a company record. As Herb mentioned, proved reserves are up 13% year-over-year, and the net increase in reserves year-over-year replaced production by more than 2.2x. The net proved reserves to 2023 production ratio is 10.9 years.
Lastly for me, let’s look at inventory on slide 15. We ended 2023 with approximately 10 plus years of inventory, assuming 80 to 100 average completions per year. It is notable that the estimated average IRR of inventory is greater than 65%. In addition, more than 80% of inventory is categorized as 3P, which implies the inventory location count is very high quality. We believe our inventory calculations are potentially conservative compared to how other companies may calculate inventory. As a reminder, all wells within our 3P reserves estimate are economic, have an area specific type curve, a defined lateral length, are at optimized well spacing and have an assigned spot on the latest development schedule. At yearend 2023, the gross inventory in the Austin Chalk, including wells drilled to date, increased 16% to 465 locations, with more than 350 locations remaining.
This significant increase reflects our confidence given the excellent economic performance of the 106 Austin Chalk wells we have already brought into production over the past five years. We also added 40 wells so far from 2023 acquisitions, so delineation and development of new acreage offers upside to identify and add inventory in 2024 from those acquisitions. In 2023, we tested the Leonard in the RockStar area and determined that we can optimize capital efficiency by removing Leonard locations from inventory and instead drill more wells in the underlying Middle Spraberry, increasing Middle Spraberry locations, where some fracs will grow into the overlying Leonard. Long-term benchmark pricing used to calculate our inventory was $70 WTI oil and $3.50 Henry Hub gas.
So, in closing, I would like to say again how proud we are of the 2023 results and the corresponding outperformance in SM shares. Total shareholder return achieved for SM shares was positive 13%, despite oil being down 11% in 2023 and gas being down 44%. And 2024 appears to be set up for more of the same. Thanks for your support and I now turn the call back to Herb. Herb?
Herbert Vogel: Thanks Wade. Turning to slide 16. Let me wrap up the call by focusing on some specifics of what we’re doing to extend our high quality, low breakeven, and high-return inventory. At Klondike, the 20,700 net acres located in north Martin and Dawson counties, that we acquired last summer. We have drilled one science well from which we gathered log and core data, and plan to start acquiring 3D seismic in March. We conduct this work in order to optimize our development plans. Our 2024 program is expected to include development of three pads having a total of eight to nine wells. First completions are expected to come online in June, meaning we should have initial results to report by the end of the third quarter.
