Our acreage provides a long runway of drilling locations with multiple avenues for expansion.
We have assembled a deep inventory of drilling locations situated in some of the best rock in North America. We have more than 2,200 net drilling locations in our inventory, with more than 1,200 of these located in the Eagle Ford Shale and more than 240 located in the Delaware Basin. In the Eagle Ford Shale alone, that equates to 10-15 years of inventory at our current drilling pace.
While an E&P company’s drilling program naturally depletes its inventory each year, we have historically been able to add more locations than we drill. We have accomplished this through both acreage acquisitions as well as organic inventory expansion. For example, during 2016, we were able to expand our inventory in the Eagle Ford Shale by more than 30% despite drilling 5%-10% of our year-end 2015 inventory during the year. We remain focused on continuing this trend.
Our well spacing optimization tests continue to drive our location count higher as we seek ways to more optimally develop the reservoirs. In the Eagle Ford Shale, our prior development plan incorporated a combination of 330 ft. and 500 ft. lateral spacing. But in 2015, we began testing the viability of drilling two layers of wells within the Lower Eagle Ford section. This has tested effective lateral spacing ranging from 165 ft. to 285 ft. To date, we have successfully tested nine pilots incorporating this stagger-stack development. We plan to continue testing this concept across our acreage during 2017, and we have five additional pilots being drilled, completed, or in early flowback. We have also tested the viability of drilling between existing wells. Our initial infill test was located between two five-year-old wells and yielded encouraging results.
Our acreage position also provides us with stacked-pay potential, much of which is not included in our current estimate of de-risked drilling locations. In the Eagle Ford Shale, industry activity has targeted the Upper Eagle Ford and the Austin Chalk across the trend, in addition to the primary development in the Lower Eagle Ford. We drilled our initial Upper Eagle Ford test in 2015. In the Delaware Basin, our initial development has targeted the Wolfcamp A formation, but we see potential in five to seven layers on our acreage position across the Bone Spring and Wolfcamp formations. And in the Niobrara trend, recent industry success in the deeper Codell formation could add another layer of development beyond the existing Niobrara A, B, and C benches.
We strive to be the most efficient operator in the industry.
A lofty goal, we admit, but one that we view as achievable. We have been a leader in unconventional drilling for nearly 15 years, and this has provided us with an in-depth understanding of the plays in which we operate. This knowledge allows our talented team of technical professionals to continuously refine our drilling and completion techniques in order to deliver further efficiency gains. In doing so, we expect to remain a low-cost producer of crude oil and natural gas.
By leveraging new ideas and technology, we have been able to achieve significant drilling efficiencies over the past few years. In early 2015, we took delivery of two custom-built Generation 3 drilling rigs for our Eagle Ford Shale operations. Since that time, we have more than doubled the effective lateral footage that each rig drills in a month, and each of our rigs has recently been drilling more than 3.5 wells per month. These cycle time reductions translate directly to lower well costs. And with continuous advances in directional motor and bit technology, we expect to push drilling cycle times down even further in the future.
Drilling a well is only half the battle (or closer to a third when the capital split between drilling and completion is considered), so we also strive to complete our wells as efficiently as possible. In 2016, our dedicated Halliburton frac crew completed more than 1,900 frac stages in the Eagle Ford Shale. This was up from approximately 1,800 frac stages in 2015 and marked the fifth consecutive year that our crew has ranked as one of the most efficient crews in Halliburton’s fleet.
Another way we seek to increase efficiencies is through drilling longer lateral wells. Since we began horizontal development of resource plays in 2004, we have observed a strong correlation between the lateral length in a well and the amount of hydrocarbons it will recover. As a result, we seek to drill long laterals wherever possible. This allows us to spread the fixed cost of the vertical wellbore across more reserves and production, lowering the unit cost and enhancing the economics. Longer laterals have the additional benefit of requiring fewer wells to develop a property, minimizing surface impacts and saving facility costs. Our land team works diligently to bolt-on acreage to our existing position or execute acreage swaps with nearby operators in order to further expand the average lateral length of our drilling inventory.
We constantly seek new ideas and techniques that can improve the performance of our wells.
We have drilled and completed more than 800 horizontal wells since we began developing unconventional resources in the early 2000s, and we have been a leader in practices that are common today. Some of these include targeting a specific, narrow section of the formation with the lateral portion of the wellbore, using state-of-the-art directional drilling techniques to keep the drill bit within the target interval, and utilizing a large volume of proppant in the completion of our wells. As a result, our per-well reserves have consistently ranked among the best in the industry in our core areas. In order to maintain this leadership position, we continuously test new techniques that can further enhance the results from our drilling program.
In 2015, we began to explore new proppant diversion technologies with Halliburton through a large-scale field trial. The results showed that the test wells consistently outperformed the nearby control wells. By late 2015, we began using the diversion technology in the majority of our wells. Throughout 2016, we have noticed higher flowing pressure in these wells, which should translate to higher recoveries.
In 2016, we began to test tighter frac stage spacing in our Eagle Ford Shale wells. We reduced the stage spacing in our wells to approximately 200 ft., which translates into a 20% increase in the number of stages per well. As a result, we have seen an approximate 10% increase in the performance of our wells, which easily offsets the added capital cost of the incremental stages. As an added bonus, tighter stage spacing also appears to minimize frac interference between the new wells and the offsetting parent wells, which should further enhance the economics of our development program. Based on the strong results seen thus far, we plan to test even tighter frac stage spacing in the future.
Our assets support a strong multi-year production growth profile.
Our portfolio of low-cost, high-return assets has allowed us to consistently deliver growth in both reserves and production throughout multiple industry cycles. Over the last five years, a period that includes an upcycle as well as an extreme downcycle, we have grown our total reserves and production at a compound annual rate of 5% and 15%, respectively. And this growth came despite monetizing our Barnett Shale and international assets over the period. Looking just at domestic crude oil, we have grown reserves and production at a compound annual rate of 39% and 64%, respectively, over the period.
Our deep inventory of low-risk, economical drilling locations provides us with excellent visibility into our future growth. As a result, we recently provided our first ever multi-year production growth outlook. We currently expect to grow our crude oil production at a compound annual rate of more than 20% over the next three years. We currently expect this growth to be anchored by a three-rig drilling program in the Eagle Ford Shale, which continues to offer some of the best returns in North America, complemented by activity in our other areas.
In addition to ample drilling locations, we also have the balance sheet to support our future growth. Despite enduring a multi-year commodity price downcycle that was more severe than most energy companies expected, we exited 2016 with very manageable leverage levels and a senior credit facility that remained largely undrawn. While we remain bullish on the long-term direction of oil prices given the lack of industry investment over the past several years, our balance sheet provides us with ample financial flexibility to execute our three-year plan even if commodity prices fail to cooperate in the short term.