Billy Helms
President and Chief Operating Officer at EOG Resources
Thanks, Tim. EOG's operating performance continues to improve with the first quarter generating outstanding results. Our first quarter volume, capital expenditures and total per unit cash operating cost performance came in better than our forecasted targets. I'd like to thank our employees for their dedication and outstanding execution, giving us a great start to 2023.
Our full year 2023 capital and production plans are unchanged. We forecast a $6 billion capital program to deliver 3% oil volume growth and 9% total production growth. We maintained the pace of activity from the fourth quarter of last year in the Delaware Basin and Eagle Ford, our core foundational plays and continue to expand development in our emerging Powder River Basin, Ohio Utica combo and South Texas Dorado plays. Well productivity and cost performance are meeting or beating expectations across our portfolio as each play sustains sufficient activity to support continued innovation.
As Ezra mentioned, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well and were a big part of our overall strong first quarter results. Sustaining a consistent level of activity in these core plays is driving operational improvements and continues to be one of the primary hedges to offset areas of cost inflation. We are excited about the outlook for these assets in the years ahead. Even as these assets mature, we can apply technical learnings, operational innovation and leverage prior infrastructure investments to continue to improve the operating margin and capital efficiencies of these world-class assets.
In the Delaware Basin, we expect well performance will continue to improve this year, delivering productivity and returns well above the premium hurdle rate. Last year, our Delaware Wolfcamp wells delivered an average six month cumulative production of about 34 barrels of oil equivalent per foot and are expected to improve this year. See Slide 10 of our updated investor presentation for details. While well mix can impact the relative contribution of oil, NGLs and natural gas, overall performance is improving in large part due to continued innovations like our new completion design. We have now tested 39 wells in the Wolfcamp that are yielding an average increase of 22% in the first year production with a 20% uplift in the estimated ultimate recovery compared to the similar wells and targets using our previous completion design.
With these encouraging results, we now expect to deploy this new design on about 70 wells this year. This new design is continuing to show promise as we expand the number of wells and test the design across different targets and basins. Operationally, maintaining a consistent level of activity in the Delaware Basin, combined with our culture of continuous improvement is generating noticeable results. Drilling times continue to improve and are generating peer-leading performance aided by our drilling motor program and high-performing staff. The amount of footage drilled per motor run improved by 11% in the first quarter as compared to last year.
Similar progress is being achieved with our completion operations with the expansion of our Super Zipper technique. These efforts, combined with the opportunities that codevelop multiple targets in the stacked pay resource by using our existing surface footprint and in infrastructure are expected to drive significant efficiency gains and continue to improve our margins in the Delaware Basin for years to come. We first introduced the Super Zipper completion technique in the Eagle Ford in 2020. Since then, we have expanded its use throughout the play and have more than doubled completions efficiency as measured by completed lateral feet per day. As indicated on Page 12 of our quarterly investor slides, the amount of lateral completed per day year-to-date has increased by another 18% compared to last year.
In the first quarter, we also set a record in the Eagle Ford drilling our longest well to date, reaching a measured depth of nearly 26,500 feet with a lateral length of over 15,500 feet. We expect to continue to see completion efficiency improvements as we extend laterals in the Eagle Ford to three plus miles where feasible. As a core operating area that has been under development for more than a decade, the Eagle Ford also benefits from our existing infrastructure from over 3,700 producing wells. Leveraging existing investments made in strategic water, oil and gas infrastructure minimizes future capex needs and lowers operating costs. Ongoing improvements to completion operations and leveraging the benefit of existing infrastructure, enable our Eagle Ford finding and development costs to continue to decline. Last year, the Eagle Ford's rate of return was the highest in the place history. Longer term, we have over a decade of drilling inventory in the Eagle Ford, allowing us to maintain the current production base while generating high returns and lowering breakevens.
As previously mentioned, we are maintaining activity in our core plays and progressing our newer emerging plays. This year's plan in Dorado contemplates eight additional wells completed compared to 2022 in order to achieve a consistent level of activity to drive performance improvements. Our drilling operations are realizing a 29% improvement in the footage drilled per day since 2021. Completion operations will be conducted on a few wells in the second quarter. However, we are evaluating options to delay additional completions originally scheduled later this year due to the current natural gas price environment. To date, operational progress towards improvements and Dorado's well performance is meeting or exceeding our early expectations.
Activity in the Utica combo play is just commencing yet we are already witnessing the compounding effects of sharing technology across our multiple plays. For example, drilling performance for recent wells is improving on the order of 20% to 30% compared to last year's results with the benefit of our proprietary drilling motor program and precision targeting. We expect similar levels of improvement from our completion program once we begin completing wells in the third quarter.
Now for a little color on inflation and industry service costs. As we had anticipated in building this year's plan, the upward inflationary pressure that we witnessed last year appears to have plateaued, which still leaves us confident that our average well cost should increase no more than 10% compared to last year. Early indicators are showing signs of service cost moderation, which is more prevalent in some basins and less than others. We would expect that any softening of service and tubular costs will be slow to manifest into lower well cost and cash operating costs until much later in the year or more likely in 2024.
As the year unfolds, we will continue to look for opportunities to leverage our scale and the flexibility of our multi-basin portfolio to manage costs across all operating areas. We also remain highly focused on sustainable cost reductions through innovation, operational performance and execution improvements to mitigate inflation and further drive down our cost structure.
Now I'll turn it back to Ezra.
