Jeffrey R. Leitzell
Executive Vice President and Chief Operating Officer at EOG Resources
Thanks, Ann. We delivered another outstanding quarter, thanks to our employees and their consistent execution acrossed our multi-basin portfolio. Their focus on continued improvement through innovation, technology advancements and operational control is why our third quarter volumes and per unit cash operating costs beat expectations. Oil volumes beat our forecast primarily due to better-than-expected productivity from new wells, driven by continuous improvement to our completion designs. Year-over-year, we have increased our maximum pumping rate capacity by approximately 15% per frac fleet on average. The benefit is twofold, faster pump times and better well performance. Higher pumping rates provides our team with the flexibility to tailor each high-intensity completion design around the unique geological characteristics of every target. This in-turn has helped to maximize the stimulated rock volume in the reservoir, resulting in improved well performance.
Efficiency improvements due to faster pump times combined with stronger well performance have more than offset the additional cost for these increased pumping rates. As a result of third quarter volume performance beats, we are once again raising full-year guidance. Our oil production midpoint has increased by 800 barrels per day, natural gas liquids by 2,800 barrels per day and natural gas by 24 million standard cubic-feet per day. We also beat per unit cash operating cost targets during the third quarter. The primary drivers were lower lease operating expense due to less workover expense and fuel savings. We now expect our full-year per unit cash operating cost to be lower than forecasted and have reduced guidance accordingly.
Our capital expenditures in the third quarter were in line with our forecast with only minor differences primarily due to timing of operations. In addition, well cost deflation, driven primarily by efficiencies is playing out as we had forecasted at the start of the year, resulting in a 3% to 5% year-over-year decrease in well costs. As a result, our expectations for full-year capex remained unchanged at $6.2 billion at the midpoint. The efficiency gains we continue to realize this year demonstrate the value of our multi-basin portfolio and decentralized structure. Ideas born in one operating area are replicated across multiple basins through technology transfer.
Two examples of innovation expanding through our portfolio and driving efficiencies this year are extended laterals and our in-house motor program. Average lateral lengths for our domestic drilling program continue to increase. In the Delaware Basin, we now expect to drill more than 73-mile laterals this year, compared to our original forecast of 50. We've also set a new lateral length record in the Eagle Ford, not only for EOG, but for all of Texas. Our Aspen A 1H well was drilled in our Western acreage and has a lateral length of over 22,000 feet. As we highlighted last quarter, longer laterals allow for more time focused on drilling down-hole and less time moving equipment on surface, decreasing overall downtime and days to drill.
In addition, longer laterals help unlock new potential from acreage that might not otherwise meet our economic thresholds. EOG's in-house motor program also continues to pay dividends. In the Delaware Basin, we are testing the limits of our drilling motors in the shallower Leonard Shale and Bone Spring formations. While drilling the production hole section, we attempt to drill as much of the vertical curve and lateral portions of the wellbore with one motor run. Historically, this operation requires a minimum of three motor runs and two trips, which is a pause in drilling to pull a motor out-of-the wellbore and replace it with a new one. As a result, we have eliminated over one full trip per well in the shallower Delaware basin targets. Given that each trip can cost $150,000 or more, the cost savings and efficiency gains from using better designed higher-quality motors continues to add significant value to our drilling program. This is just one of several examples of the value the EOG motor program has created.
Looking company wide, since the start of 2023, we have increased our drilled footage per motor run by over 20% versus third party rental options. As we continue to test, learn and redesign our drilling motors, we see substantial upside to our future drilling performance as we expand motor innovation throughout our multi-basin portfolio. In Ohio, we've made significant progress this year transitioning the 225,000 net acres of the volatile oil window in the Utica play from delineation into development. We now have five packages online and producing for more than 100 days, three of which have been producing well over 180 days. Both oil and liquids performance continues to meet or exceed expectations, demonstrating the premium quality of this play. We are also capturing sustainable operational efficiencies through multi-well pad development and continuous operations.
On the drilling side, the Utica provides an ideal operational environment to make significant gains quickly. We have decreased drilling days to drill three mile laterals 29% year-over-year and have already achieved a record of drilling more than two miles in a single day. We also have made significant gains on the completion side, achieving a nearly 13% increase in completed lateral feet per day compared to last year. Over the next few years, activity in the Utica will continue to be primarily focused in the volatile oil window where we anticipate our well costs will average less than $650 per effective treated lateral foot with finding cost and development costs in the range of $6 to $8 per barrel of oil equivalents.
For 2025, we anticipate a 50% increase in Utica activity as we continue to leverage consistent operations to achieve additional economies of scale. Our large contiguous acreage position lends itself to developing a long-life, repeatable low-cost play competitive with the premier unconventional plays across North America. Previewing 2025 company wide, with the outstanding performance we have delivered this year, we do not see a need to significantly adjust activity next year. We do, however, expect very minor shifts in activity between basins with a continued increase in activity in the Utica and another year of actively managing our Dorado investment with a one rig program. This will allow us to continue to capture some economies of scale across our emerging assets and advance our technological understanding of these plays, while delivering the operational and financial performance that our shareholders appreciate.
Now here's Ezra to wrap-up.